# Anderson Living Trust v. WPX Energy Production, LLC

> District Court, D. New Mexico · March 19, 2015 · 306 F.R.D. 312

URL: https://www.frixlaw.com/law-library/cases/8772804

## Case

- **Full name:** The ANDERSON LIVING TRUST f/k/a The James H. Anderson Living Trust The Pritchett Living Trust Cynthia W. Sadler Robert Westfall Lee Wiley Moncrief 1988 Trust Kelly Cox Testamentary Trust 7/1238401 Minnie Patton Scholarship Foundation Trust and SWMF Properties, Inc. v. WPX ENERGY PRODUCTION, LLC f/k/a WPX Energy San Juan, LLC Williams Production Company, LLC and WPX Energy Rocky Mountain, LLC, f/k/a Williams Production RMT Company, LLC
- **Court:** District Court, D. New Mexico
- **Decided:** March 19, 2015
- **Citations:** 306 F.R.D. 312; 2015 U.S. Dist. LEXIS 37256; 2015 WL 1321479
- **Precedential status:** Published
- **Opinion:** Opinion of the court by Browning
- **Judges:** Browning
- **Cited by:** 28 later opinions in the Frix Law Library

## Citator (automated)

- No negative treatment found by the automated citator. That is not the same as a confirmation that the case is good law; read the citing cases.
- Full citator and citing cases: https://www.frixlaw.com/law-library/cases/8772804

## How later opinions describe it (automated extraction)

- finding tentatively for class certification purposes that “[i]n some quarters of the oil-and-gas industry, the term ‘as such,’ when used with reference to royalty based on ‘proceeds derived from the sale of gas, as such,’ means from the sale of the gas in the condition that it…
- concluding that, because the parties agreed upon the answer to many of the common questions, the Court would devote much more time to resolving individual questions, thereby defeating predominance
- noting that the difference between analyzing adequacy of class counsel under Rule 23(a)(4) or Rule 23(g) is not highly important, “except that now district courts should not refuse to certify a class on the basis of inadequacy of counsel alone”
- rejecting the defendants’ argument that the class representatives have to possess every category of lease form to ade quately represent the class members
- rejecting the defendants’ argument that the class representatives have to possess every category of lease form to ade *268 quately represent the class members

## Opinion text

MEMORANDUM OPINION AND ORDER
JAMES O. BROWNING, District Judge.
THIS MATTER comes before the Court on the Plaintiffs’ Motion and Supporting Brief to Determine That This Matter Proceed as a Class Action, filed January 6, 2014 (Doe. 194)(“Motion”). The Court held a two-part class certification hearing with its first portion on March 10,11, and 12, 2014, and its second portion on April 3 and 4, 2014. See Transcript of Hearing, taken March 10, 2014, filed June 26, 2014 (Doc. 254); Transcript of Hearing, taken March 11, 2014, filed June 26, 2014 (Doe. 255); Transcript of Hearing, taken March 12, 2014, filed June 26, 2014 (Doc. 256); Transcript of Hearing, taken April 3, 2014, filed June 26, 2014 (Doc. 257); Transcript of Hearing, taken April 4, 2014, filed June 26, 2014 (Doe. 258)(collectively, “Tr.”). 1 The primary issues are: (i) whether and to what extent textual variations among the leases within the proposed class defeat the commonality requirements of rule 23(a), or the predominance or superiority requirements of rule 23(b), of the Federal Rules of Civil Procedure; (ii) whether and to what extent ambiguity—and the need for parol evidence to resolve it—in the class leases defeats rule 23(a)’s commonality, or rule 23(b)(3)’s predominance or superiority requirements; (iii) whether and to what extent the class members’ potentially varying levels of actual knowledge and reasonable diligence in uncovering their claims—which, under the discovery rule, are determinative when the statutes of limitations accrue on these claims—defeats rule 23(b)(3)’s predominance or superiority requirements; (iv) whether and to what extent any difficulty in properly assigning damages among the class members defeats the predominance or superiority requirements; (v) whether rule 23(a)’s requirements—numerosity, commonality, typicality, and adequacy—and rule 23(b)(3)’s requirements—predominance and superiority—are otherwise met with regard to the proposed class; and (vi) whom to appoint as class counsel rule 23(g). Textual variations among the leases both destroy commonality and predominance, because the central issue in this ease—what royalty-payment methodology the Defendants owe the Plaintiffs—varies from lease to lease. Lease ambiguity does not destroy commonality, but it weighs against finding predominance. The class members’ potentially varying levels of knowledge likewise presents individual issues that cut against predominance. Problems in assigning damages can be overcome, and damages can be determined on a classwide basis. Therefore, the Court concludes that this pro *320 posed class action satisfies the rule 23(a) prerequisites of numerosity, typicality, and adequacy, and the rule 23(b)(3) requirement of superiority, but that it fails the rule 23(a)(2) commonality prerequisite and the rule 23(b)(3) predominance requirement. The Court, thus, denies the Motion.
FINDINGS OF FACT
Both the Plaintiffs and the Defendants have submitted proposed findings of fact. See Plaintiffs’ Proposed Findings of Fact and Conclusions of Law, filed May 6, 2014 (Doc 240) (“Plaintiffs’ PF”); Defendants’ Findings of Fact and Conclusions of Law Relating to Class Certification, filed May 6, 2014 (Doc. 241) (“Defendants’ PF”). The parties have also stipulated to several facts for the purposes of the class certification determination. See Stipulation for the Purposes of Class Certification, filed March 10, 2014 (Doc. 223)(“Stipulation”). The Court has carefully considered all proposed facts, and accepts some of them, rejects others, and finds some facts that no party brought to its attention. 2 The Court also liberally judicially notices background facts. See Fed.R.Evid. 201. All of these findings of fact are authoritative only on the question of class certification, and the parties may relitigate any of them at the merits stage. See Abbott v. Lockheed Martin Corp., 725 F.3d 803, 810 (7th Cir.2013); In re Hydrogen Peroxide Antitrust Litig., 552 F.3d 305, 313 (3d Cir.2008); Gariety v. Grant Thornton, LLP, 368 F.3d 356, 366 (4th Cir.2004). The Court applied the Federal Rules of Evidence at the class certification hearing, ruled on several evidentiary objections, and considered only admissible evidence in finding these facts. See note 39, infra, and accompanying text.
The Court organizes this portion of its Memorandum Opinion and Order into eight parts. First, it will define some of the more esoteric terms applicable in this ease. Second, it will introduce the important players in this action: the Defendants and their corporate affiliates, the named Plaintiffs, the absent class members, and a few important independent entities. Third, the Court will explain the process of producing, gathering, and processing or treating natural gas, including the transfer-of-title process in this case. Fourth, the Court will describe the breakdown of the different textual royalty provisions in the class leases. Fifth, it will describe the different textual overriding royalty provisions among the class. Sixth, the Court will describe how the Defendants have paid royalties and overriding royalties to the class, including the costs that they have deducted and their timeliness. Seventh, it will describe the evidence that the Defendants have put forward regarding various class members’ actual knowledge of or due diligence toward learning of their claims, which is relevant to the delaying of the accrual of the statutes of limitations. Eighth, and last, the Court will summarize a few key pieces of evidence relating to the parties’ and the Court’s ability to construct a classwide damages-distribution model.
1. Definitions: The Terminology Applicable in This Case.
1. The Court will first define the operative terms used throughout this Memorandum Opinion and Order. The Court divides the definitions into three sections: one on lease terminology, which defines the terms that relate to the legal relationship between the Plaintiff-lessors and Defendant-lessees; a second on oil and gas production, gathering, and processing, which defines the terms that relate to the working relationship between the Plaintiff-landowners and Defendant-oil companies; and a third on royalty accounts ing, 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 sub *321 sequent sections, explain how these concepts relate to this case, but includes this section as both a preface and a reference.
a. Lease Terminology.
2. A “mineral lease,” is “[a] lease in which the lessee has the right to explore for and extract oil, gas, or other minerals”; it splits land into a working interest and a royalty interest. Black’s Law Dictionary 971 (9th ed.2009).
3. A “mineral deed” is “[a] conveyance of an interest in the minerals in or under the land.” Black’s Law Dictionary 477 (9th ed.2009).
4. A “working interest” includes “[t]he rights to the mineral interest granted by an oil-and-gas lease, so called because the lessee acquires the right to work on the leased property to search, develop, and produce oil and gas, as well as the obligation to pay all costs”; a working interest in land entails the right to drill and remove oil and gas from the land, subject to burdening royalty interests. Black’s Law Dictionary 1745 (9th ed.2009).
5. A “royalty interest” is “[a] share of production—or the value or proceeds of production free of the costs of production—when and if there is production.” Black’s Law Dictionary 1466 (9th ed.2009).
6. The word “production,” generally, in the oil-and-gas industry, has numerous meanings, but they typically revolve around the well, and not around subsequent processing: a “production” can refer to the well itself, to the fresh-out-of-the-ground product that the well produces, or to the act of drawing said product out of the ground. 8 Howard R. Williams, Charles J. Meyers, Patrick H. Martin & Bruce M. Kramer, Williams & Meyers Oil and Gas Law 816-18 (2013TWilliams & Meyers ”).
7. “Authorities are split over what costs are the costs of production,” Black’s Law Dictionary 1466 (9th ed.2009), and, under Colorado law, production “end[s] when a first-marketable product has in fact been obtained,” which often only occurs after processing, Rogers v. Westerman Farm Co., 29 P.3d 887, 904 (Colo.2001) (en banc).
8. An “overriding royalty” is “[a] share of either production or revenue from production (free of the costs of production) carved out of a lessee’s interest under an oil-and-gas lease----An overriding royalty interest ends when the underlying lease terminates.” Black’s Law Dictionary 1446 (9th ed.2009).
9. An overriding royalty interest is considered a subcategory of royalty interest. See Garman v. Conoco, Inc., 886 P.2d 652, 657 (Colo.1994) (en banc) (“An overriding royalty is, first and foremost, a royalty interest.” (quoting 2 Williams & Meyers § 418.1)).
10. A “division order” is “[a] contract for the sale of oil or gas, specifying how the payments are to be distributed.” Black’s Law Dictionary 549 (9th ed.2009).
11. “Royalty owners enter into division orders to sell minerals and to instruct how payments are to be made under a mineral lease.” Black’s Law Dictionary 549 (9th ed.2009).
12. “Working-interest owners also commonly sign division orders to instruct purchasers how payments are to be divided.” Black’s Law Dictionary 549 (9th ed.2009).
13. A division order cannot modify the terms of the underlying mineral lease. See Tr. at 922:10-20 (McNamara, Terry).
14. A “division order is typically terminable at the will of either party.” 8 Williams & Meyers at 272.
15. A “transfer order” is an instrument conveying a royalty interest to another person. Tr. at 46:20-23 (Brickell); id. at 304:24-305:2 (Westfall).
b. Natural-Gas Terminology.
16. “Hydrocarbons” are a class of chemical compounds composed exclusively of hydrogen and carbon; it is also a generic term for petroleum products such as oil and natural gas. 3
*322 17. “Natural gas” is a gaseous mixture of hydrocarbons, the primary one being methane (CH4), commonly used as fuel in homes and businesses. Glossary, United States Energy Information Administration, http:// www.eia.gov/tools/glossary/index.cfm?id=N (“EIA Glossary”).
18. Natural gas must generally be treated or processed—to remove waste products such as water vapor, sulfides, carbon dioxide, nitrogen, and other impurities, as well as valuable, heavier hydrocarbons such as ethane, butane, propane, and pentane—before it can be put into a pipeline system or marketed as a fungible commodity. See 30 C.F.R. § 1206.171 .
19. Natural gas can be obtained as a byproduct of oil drilling, retrieved using standard drilling techniques in natural gas fields or coalbeds, or obtained through hydraulic fracturing—also known as fracking—in shale deposits. See EIA Glossary.
20. “Conventional gas” is natural gas obtained from natural-gas fields, which are typically sandstone depositions. Tr. at 79:14-19 (Reineke).
21. Conventional gas typically undergoes processing to remove impurities, separate out valuable NGLs, and render the gas into marketable condition. See Expert Witness Report of Randy Kaplin at 2 (Plaintiffs’ Ex. 194).
22. “Coalbed methane” or “CBM” is natural gas obtained from coal seams. EIA Glossary.
23. Coalbed methane is typically just methane and carbon dioxide, and is generally only treated for carbon dioxide removal and possibly water-vapor removal—rather than being processed—before it is placed in a pipeline. See Tr. at 83:1-21 (Reineke, Bric-kell).
24. “Shale gas” is natural gas obtained— almost always by the process of hydraulic fracturing—from shale. EIA Glossary.
25. “Casinghead gas,” also known as “oil well gas” or “associated gas,” is natural gas obtained from an oil well. EIA Glossary.
26. The term “natural gas liquids” (“NGLs”) refers to hydrocarbons heavier than methane that can—either on their own via condensation or through processing—be drawn from natural gas, converted into the liquid state, and sold as fuel. 30 C.F.R. § 1206.171 .
27. The constituent “liquefiable hydrocarbons” in NGLs include propane, butane, pen-tane, and hexane. EIA Glossary.
28. Among NGL compounds, heavier compounds are typically more valuable than lighter ones. See Tr. at 559:1-10 (Sutphin, Emory).
29. “Heavier,” in this context, refers to the compound’s molecular weight, which, for alkane hydrocarbons, equates to the magnitude of the n term in the generic chemical formula Cn HCf. Tr. at 559:5-10 (Emory).
30. For example, pentane (C5H12) is heavier than butane (C4H10), which is, in turn, heavier than propane (C3H8). Cf. Tr. at 559:5-10 (Emory).
31. All of the constituent compounds of NGLs are heavier than methane (CH4), which is the primary component of natural gas. Cf. Tr. at 559:5-10 (Emory).
32. NGLs are commonly entrained in—or entrapped and carried along with—natural gas. See Tr. at 104:2-4 (Briekell, Reineke).
33. “Natural gasoline” refers to a mixture of natural gas liquid products manufactured from natural gas. Tr. at 407:10-20 (Sheridan, Anderson); id. at 795:9-796:1 (Sheridan, Terry).
34. Natural gasoline is not the same substance as automotive gasoline. 4 See Tr. at 795:9-796:1 (Sheridan, Terry).
*323 35. “Wet gas” is natural gas entrained with a significant amount of NGLs. EIA Glossary.
36. “Dry gas” is natural gas that is mostly devoid of NGLs. EIA Glossary.
37. Almost all coalbed methane is dry gas. See Expert Report of Randy Kaplin at 2 (Plaintiffs’ Ex. 194).
38. Gas must be in a dry state before it can be placed into an interstate pipeline; when gas is dry after being processed, it is referred to as “residue gas.” EIA Glossary.
39. “Natural gas condensate,” or just “condensate,” refers to natural gas liquids recovered at the surface without resorting to processing. 30 C.F.R. § 1206.171 .
40. “Condensation,” generically, is the physical phase change where a gas is converted to a liquid. The American Heritage Dictionary of the English Language 277 (William Morris ed., New College ed.1976).
41. “Well condensate” or “wellhead condensate” is condensate recovered at the wellhead. Tr. at 37:2-9 (Sheridan).
42. A “wellhead” is the point where hydrocarbons are taken out of the ground, but the term is sometimes used to refer to anywhere hydrocarbons go while on the lease plot. EIA Glossary.
43. A “separator” or “production unit” is a device at the wellhead that separates liquids—namely water and well condensate— from the gas. Tr. at 96:12-16 (Reineke).
44. A “facility measurement point” is the point where a “measurement device is located for determining the volume of gas removed from the lease.” 30 C.F.R. § 1206.171 .
45. “The facility measurement point may be on the lease or off-lease,” but is intended to measure the natural gas attributable to a specific lease before it is eomingled with gas from other leases in a gathering system. 30 C.F.R. § 1206.171 .
46. A “ ‘completion’ refers to a well that has been completed,” i.e., perforated and isolated in the well bore, such that gas is capable of being produced from the well. Emory Expert Report ¶ 23, at 13.
47. “Lease use” gas is gas that the working interest owner uses—to power machinery, fuel heaters, et cetera—on the lease. Tr. at 443:3-7 (Briekell, Emory).
48. A “gathering system” is the system of low-pressure lines that transport natural gas from the lease site, i.e., the wellhead, to a processing plant or other central point. EIA Glossary. See 30 C.F.R. § 1206.171 .
49. “Drip condensate” is any natural gas condensate “recovered downstream of the facility measurement point [the wellhead] without resorting to processing.” 30 C.F.R. § 1206.171 .
50. “Drip condensate includes condensate recovered as a result of its becoming a liquid during the transportation of the gas removed from the lease or recovered at the inlet of a gas processing plant by mechanical means, often referred to as scrubber condensate.” 30 C.F.R. § 1206.171 .
51. Drip condensate, put simply, is NGLs that condense into liquid form in the gathering system, i.e., after the gas has left the wellhead, but before it gets processed. See 30 C.F.R. § 1206.171 .
52. A “pig” is a term for a mechanical device that pushes drip condensate sitting in a gathering system’s lines out into a receptacle for eventual sale. Tr. at 39:2-6 (Sheridan).
53. A “fractionator” is a machine that separates NGLs into their constituent parts—such as propane, butane, and pen-tane—after they are removed during processing. EIA Glossary.
54. A “processing plant” is a facility that takes impure, unmarketable natural gas from *324 a gathering system, and converts it—by removing impurities and NGLs—into pipeline—quality natural gas, which can then be compressed and sent into the interstate pipeline system. Tr. at 39:7-13 (Sheridan).
55. A processing plant is typically connected to a gathering system on the input end and a pipeline system on the output end. See Tr. at 99:16-100:11 (Reineke).
56. A “treatment plant” is a facility that is fundamentally similar to a processing plant—ie., it takes impure gas from a gathering system and renders it into marketable condition—but it does not remove NGLs from the gas. See Tr. at 619:15-20 (Emory, Brickell).
57. Treatment removes carbon dioxide and often dehydrates the gas—ie., it removes the water vapor—but, unlike processing, it does not extract NGLs. See Tr. at 619:15-20 (Emory, Brickell).
58. Gas that is relatively clean—ie., free from impurities—and dry—ie., free from NGLs—may need only to be treated, rather than processed. See Tr. at 619:15-20 (Emory, Brickell).
59. Coalbed methane typically requires only treatment to remove carbon dioxide, which it tends to contain in higher quantities than conventional gas. See Tr. at 83:1-21 (Reineke, Brickell).
60. “Bypassing” is when raw gas is delivered by a gathering system to a processing plant but is not processed, and instead is mixed with processed gas in such proportions that the resultant product is still of pipeline quality. Tr. at 554:15-555:4 (Emory, Sut-phin).
61. In New Mexico, “the term ‘post-production costs’ refers to costs associated with making the natural gas marketable after the gas is severed or removed from the ground.” Schroeder v. Terra Energy, Ltd., 223 Mich.App. 176 , 565 N.W.2d 887, 890 (1997); 8 Williams & Meyers at 787. See CononoPhillips Co. v. Lyons, 2013-NMSC-009, ¶ 11 ,-N.M. -, 299 P.3d 844 , 850 (2012) (endorsing this definition).
62. “Marketable condition means a condition in which lease products are sufficiently free from impurities and otherwise so conditioned that a purchaser will accept them under a sales contract typical for the field or area.” 30 C.F.R. § 1206.171 .
63. For the class wells, natural gas generally comes into marketable condition when it is of sufficient quality to be accepted into the interstate pipeline system. 5 See Foster *325 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 bane)(“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 (N.M.Ct.App.2003) (“ ‘[Processing’ is that which takes place in order for the gas to be marketable or acceptable to interstate pipelines.”); Parry v. Amoco Prod. Co., No. CIV 94-0105, 2003 WL 23306663 , at *1 (Colo.Dist. Ct. Oct. 6, 2003) (“[T]he Court concludes that the gas in question is marketable only at the inlet to the interstate transmission pipe-line____”). But see Creson v. Amoco Prod. *326 Co., 2000-NMCA-081 , ¶ 24, 129 N.M. 529 , 10 P.3d 853, 859 (N.M.Ct.App.2000) (repeating the parties’ undisputed agreement that gas is marketable at the wellhead where it is “actually marketed at the wellhead,” circumstances which do not apply in this case).
64. “Residue gas” refers to post-processing, pipeline-quality natural gas. 30 C.F.R. § 1206.171 .
65. An “MCF” is a unit of volume used to measure natural gas; it stands for 1,000 cubic feet, which is equivalent to a cube that is 10-feet high, 10-feet wide, and 10-feet deep. Frequently Asked Questions, United States Energy Information Administration, http:// www.eia.gov/tools/faqs/faq.cfm?id=45&t=8 (“EIA FAQs”).
66. A “Btu” is a unit of energy equal to approximately 1,055 joules; 6 it is the amount of energy needed to heat—or the amount of energy released by cooling—one pound of water by one degree Fahrenheit. EIA Glossary; EIA FAQs.
67. An “MBtu” or “MMBtu” is 1,000,000 Btus. 7 EIA FAQs.
68. A “Btu factor” is a ratio describing the energy per volume of natural gas. EIA Glossary; EIA FAQs.
69. In this case, Btu factors are quoted in units of MMBtus per MCFs.
70. The Btu factor of pure methane— perfectly dry natural gas—is 1.01. See Emory Expert Report ¶ 31, at 16.
71. Gas’ Btu factor rises as the amount of entrained NGLs increases, and drops as the number of entrained, inert impurities—such as carbon dioxide and gaseous nitrogen— rises. See Emory Expert Report ¶¶ 30-31, at 16.
72. The average Btu factor of processed natural gas in the United States is 1.025. See EIA FAQs.
73. The Btu factors of the gas produced from the class wells in this case vary from .69 to 1.4. See Emory Expert Report ¶32, at 16-17.
74. As natural gas is valuable, ultimately, for its energetic potential—i.e., the amount of heat it produces when burned—its price is based not only on the volume of natural gas being sold, but also that natural gas’ Btu factor. See EIA FAQs.
75. “GPM” stands for “gallons [of NGLs] per MCF [of gas],” and is a characteristic that reveals the quantity of entrained NGLs that can theoretically be extracted from the gas via condensation and processing. Natural Gas Liquids at 5, Brookings Energy Security Initiative Natural Gas Task Force (Mar. 2013), available at http://www. brookings.edu/% EB/media/research/files/reports/2013/04/01-natural-gas-ebinger-ava-sarala/natural-gas-briefing-l-pdf.pdf. See Emory Expert Report ¶ 28, at 15.
76. When NGLs are removed from natural gas, it causes a “shrink” in the energy content—the number of MMBtus in—the resultant natural gas. Tr. at 194:4-7(Ley).
c. Royalty Distribution and Accounting Terminology.
77. The “netback” or “workbaek” method is a method of determining the wellhead price of gas by starting with the downstream (processed) sale price of the ultimate product, and deducting the costs—such as those for transportation, processing, and manufacturing—of converting the gas from the condition at the wellhead to the condition at final sale. See 8 Williams & Meyers at 643-644; 30 C.F.R. §§ 1206.151 ,1206.171.
*327 78. The netback method “is widely accepted as the best means for estimating the market value of gas at the well where no such market exists.” Abraham v. BP Am. Prod. Co., 685 F.3d 1196, 1199-1200 (10th Cir.2012) (Kelly, J.)(joined by Murphy & Hartz, JJ.).
79. This case involves a somewhat ambiguous term: “weighted average sales price” (“WASP”).
80. A “weighted average method” is a method of paying royalties in which each royalty owner is paid based on a predetermined portion—usually determined by lease acreage—of the sales revenue from several pooled leases’ productions. 8 Williams & Meyers at 1139.
81. For example, if a pool of leases totaling 1,000 acres produced $1,000,000.00 in natural gas, a 250-acre lease would receive $250,000.00, regardless whether that lease actually produced $250,000.00 in natural gas.
82. “WASP,” as used in this ease, however, might refer, not to a pooling of royalties, but to a pooling of arm’s length sales revenue on the front end—e.g., if the Defendants sold two MMBtus of residue gas to one buyer at $1.00/MMBtu and on MMBtu of residue gas to another buyer at $2.00/MMBtu, then they would pay royalties to all wells based on a WASP of $1.33/MMBtu, without attempting to break down which wells produced the gas sold for $2.00/MMBtu and which wells produced the gas sold for $1.00/MMBtu. See, e.g., Tr. at 138:15-20 (Berge, Reineke)(“Q: [Y]ou know what an index is----[I]t’s average—weighted average compiled by a service that reflects the prevailing—the weighted average prevailing price in a particular market, right? A: Of residue gas, correct.”); id. at 947:21-24 (Terry)(describing an index price as “representing a weighted average price”).
83. An “index price” or “posted price” is a price for natural gas that a major industry publication publishes; royalties paid on the basis of index prices are not, themselves, based on the actual sale price of the gas, but, rather, on an average of arm’s length transactions within a particular geographic area. See 8 Williams & Meyers at 496.
84. A “keep whole” contract is one that requires the processor to compensate the royalty owner for any loss in thermal potential (energy) that natural gas undergoes from processing—namely, the Btu factor of gas decreases when NGLs are removed. See 8 Williams & Meyers at 533.
85. What the Defendants call their “keep whole basis” of paying royalties is tantamount to basing royalty payments on the natural gas’ energy—measured in MMBtus—at the wellhead. Tr. at 91:25-92:5 (Reineke); 199:12-200:2 (Berge, Ley)(“I’ve heard people use the term ‘keep whole.’ So I think it means different things to different people.”).
86. “Whole stream valuation” is a manner of paying royalties in which the working interest owner compensates the lessor for entrained NGLs by paying them a fraction of the sale proceeds of the NGLs, rather than simply compensating the lessors on an MMBtu basis at the wellhead, when NGLs are still entrained. 8 Tr. at 659:22-668:12 (Griffin, Berge).
*328 87. An “arm’s length” transaction is a transaction between entities that are not corporate affiliates of one another. Tr. at 87:15-23 (Reineke).
2. The Principals: The Parties and Other Important Entities.
88. The Defendants and their relationships to both one another and certain non-Defendant corporate affiliates are important in this case, because one of the Plaintiffs’ contentions is that the Defendants paid their royalties on the basis of affiliate sales prices rather than on arm’s length sales. See, e.g., Complaint ¶ 33, at 14.
89. The named Plaintiffs—ie., the proposed representatives of the proposed class—are important, because they must adequately represent the entire class, and their claims must be common to and typical of those of the entire class. See Fed.R.Civ.P. 23(a).
90. The Court notes at the outset that, although it has tried to be meticulous throughout this Memorandum Opinion and Order in specifying which Defendant or corporate affiliate of a Defendant handled which functions, the precise identity of each actor is not extraordinarily important.
91. Every entity with “Williams,” “WPX,” or “WFS” in its name was, until 2012, a corporate affiliate of every other similarly named entity—almost always a “full-blooded” affiliate, ie., a successor or predecessor, a wholly-owned subsidiary or parent, or a sibling subsidiary with 100% overlap in ownership.
92. Although there was a corporate spinoff in January, 2012, that broke these entities into two camps with separate public ownership, this break is not especially important to this case, both because of how late it came in the class time period and because the contracts between the now non-affiliates that cover this case were executed at a time when the parties to the contracts were corporate affiliates, and, thus, transaction under these contracts are still considered affiliate transactions even after the spinoff. See Tr. at 474:19-24 (Brickell, Ward).
a. The Defendants.
93. There are two Defendants in this ease: WPX Energy Production, LLC (“WPX Production”) and WPX Energy Rocky Mountain, LLC (“WPX Rocky Mountain”). See Corporate Disclosure Statement ¶¶ 1-2, at 1, filed January 27, 2012 (Doc. 8).
94. The other names listed in the caption are former names. See Complaint ¶¶ 5-6, at 3.
95. WPX Production was formerly named WPX San Juan, LLC (“WPX San Juan”), until it changed its name on January 13, 2012. See Corporate Disclosure Statement ¶ 1, at 1; Certificate of Amendment of WPX Energy San Juan, LLC at 2 (Plaintiffs’ Ex. 77).
96. The former WPX San Juan was previously named Williams Production Company, LLC (“Williams Production LLC”), until it changed its name on December 31, 2011. See Corporate Disclosure Statement ¶ 1, at 1.
97. Williams Production LLC was previously named Williams Production Company (“Williams Production Co.”), until it changed its name and was re-chartered as a limited-liability company in 1998.
*329 98. WPX Production is a wholly owned subsidiary of WPX Energy, Inc. (“WPX Energy”). See Corporate Disclosure Statement ¶ 1, at 1.
99. WPX Rocky Mountain was formerly named Williams Production RMT Company, LLC (“Williams RMT”), until it changed its name on December 31, 2011. See Corporate Disclosure Statement ¶ 2, at 1.
100. WPX Rocky Mountain is a wholly owned subsidiary of WPX Energy Holdings, LLC (“WPX Holdings”). See Corporate Disclosure Statement ¶ 2, at 1.
101. WPX Holdings is a wholly owned subsidiary of WPX Energy. See Corporate Disclosure Statement ¶ 2, at 1.
102. WPX Energy ultimately wholly owns both Defendants, and has throughout the time period applicable to this case.
103. WPX Energy is a publicly held corporation. See Corporate Disclosure Statement ¶¶ 1-2, at 1.
104. WPX Production is the lessee on the class leases in New Mexico, and WPX Rocky Mountain is the lessee on the class leases in Colorado. 9 See Tr. at 6:12-17 (Brickell).
105. The Court -will refer to WPX Production and WPX Rocky Mountain, collectively, as “the Defendants.”
b. The Defendants’ Corporate Affiliates.
106. Until a January, 2012, spinoff, Williams Companies, Inc. (“Williams Companies”) owned all the companies that WPX Energy currently owns. See Deposition of Morris Miller at 25:1-6 (taken December 4, 2013)(Plaintiffs’ Ex. 48)(Brickell, Miller); id. at 55:8-25 (Brickell, Miller).
107. Williams Companies also owns the general partner interest and the majority of the limited partner interest in Williams Partners LP (“Williams Partners”). Form 8-K for Williams Companies, Inc., Securities and Exchange Commission (Oct. 27, 2014), available at http://biz.yahoo.com/e/141027/wmb8-k.html.
108. Williams Four Corners, LLC (“Williams Four Corners”) is a wholly owned subsidiary of Williams Partners. Form 8-K for Williams Companies, Inc., Securities and Exchange Commission (Oct. 27, 2014), available at http://biz.yahoo.com/e/141027/wmb8-k.html.
*330 109. Williams Four Corners owns all the assets that Williams Field Services Co. (“Williams Field Services”) formerly owned; Williams Field Services assigned all its interest to the newly created Williams Four Corners on June 20, 2006. See Notification of Assignment (Plaintiffs’ Ex. 136).
110. Williams Field Services was formerly named Northwest Pipeline Corp. (“Northwest Pipeline”), until it changed its name in 1992. See Tr. at 85:17-19 (Reineke).
111. Williams Companies acquired Northwest Pipeline in 1983. See Emory Expert Report ¶ 19, at 12.
112. WPX Gas Resources Company (“WPX Gas Resources”) is a wholly owned subsidiary of WPX Energy. List of Subsidiaries of WPX Energy, Inc., Securities and Exchange Commission, available at http:// www.sec.gov/Archives/edgar/data/1518832/ 000119312513084857/d448908dex211.htm.
113. WPX Gas Resources was formerly named WFS Gas Resources Company (“WFS Gas Resources”), until it changed its name on December 1, 1998. See Certificate of Amendment of Certificate of Incorporation at 2 (Plaintiffs’ Ex. 60).
114. WPX Energy Marketing, LLC (“WPX Energy Marketing”) is a wholly owned subsidiary of WPX Energy. List of Subsidiaries of WPX Energy, Inc., Securities and Exchange Commission, available at http://www.sec.gov/Arehives/edgar/data/ 1518832/000119312513084857/d448908dex211. htm.
115. WPX Energy Marketing was formerly named Williams Gas Marketing, Inc. (“Williams Gas Marketing”), until it changed its name on June 20, 2011. See State of Delaware Certificate of Conversion from a Corporation to a Limited Liability Company Pursuant to Section 18-214 of the Limited Liability Act at 3 (Plaintiffs’ Ex. 65).
116. Williams Gas Marketing was formerly named Williams Power Company, Inc. (“Williams Power”), until it changed its name on November 16, 2007. See Certificate of Amendment of Certificate of Incorporation at 3 (Plaintiffs’ Ex. 66).
117. Williams Power was formerly named Williams Energy Marketing & Trading Company (“Williams EMT”), until it changed its name on August 6, 2003. See Certificate of Amendment of Certificate of Incorporation at 3 (Plaintiffs’ Ex. 63).
118. Williams EMT was formerly named Williams Energy Services Company (“Williams Energy Services”), until it changed its name on October 26, 1998. See Certificate of Amendment of Certificate of Incorporation at 2 (Plaintiffs’ Ex. 64).
119. Williams Energy Services was formerly named Williams Energy Derivatives and Trading Company (“Williams EDT”), until it changed its name on September 26, 1995. See Certificate of Amendment of Certificate of Incorporation at 2 (Plaintiffs’ Ex. 62).
120. Any transactions between the two of the following list of entities is considered an affiliate transaction 10 and not an arm’s length sale: WPX Production, WPX Rocky Mountain, WPX San Juan, Williams Production LLC, Williams Production Co., WPX Energy, Williams RMT, WPX Holdings, Williams Companies, Williams Partners, Williams Four Corners, Williams Field Services, Northwest Pipeline, WPX Gas Resources, WFS Gas Resources, WPX Energy Marketing, Williams Gas Marketing, Williams Power, Williams EMT, Williams Energy Services, and Williams EDT. See Miller Depo. at 55:8-25 (Brickell, Miller).
121. The Court will refer to these entities, generically, as “WPX affiliates.”
c. The Named Plaintiffs, i.e., the Proposed Class Representatives.
122. Plaintiff Anderson Living Trust (“Anderson Trust”) owns royalty and overriding royalty interests that burden WPX Production’s and WPX Rocky Mountain’s working interests in natural gas production from the New Mexico and Colorado portions *331 of the San Juan Basin. 360:23 (Anderson, Branch). See Tr. at 359:7—
123. James Anderson is a trustee of the Anderson Trust. See Tr. at 359:7-360:22 (Anderson, Branch); Anderson Trust Creation Document at 1 (Plaintiffs’ Ex. 3).
124. Anderson is willing to serve as class representative in this case and represent the class’ interests as well as his own. See Tr. at 373:4-13 (Anderson).
125. Anderson has some knowledge of the oil-and-gas industry; he receives royalty payments from seven different oil-and-gas companies, has been a class member in another royalty class action, and was formerly a member of the National Association of Royalty Owners. See Tr. at 409:15-410:21 (Anderson, Sheridan).
126. Anderson’s father, John Russell Anderson, who originally acquired the mineral interests that Anderson Trust currently holds, owned a company that built oil-and-gas gathering systems for large corporations such as El Pas Natural Gas Company and Pacific Northwest Pipeline. See Tr. at 400:12-402:25 (Anderson, Sheridan).
127. Based on the Court’s in-person evaluation of Anderson during his testimony, Anderson appears competent and well-informed regarding the facts and the law governing this case.
128. Plaintiff Pritchett Living Trust (“Pritchett Trust”) owns royalty interests burdening WPX Production’s working interests in oil and natural gas production on leases in the New Mexico portion of the San Juan Basin. See Pritchett Trust Division Orders at 3-4 (Plaintiffs’ Ex. 6); Pritchett Trust Cheek Stubs (Plaintiffs’ Ex. 5).
129. Plaintiff Cynthia Sadler owns overriding royalty interests burdening WPX Production’s working interests in natural gas production on leases in the New Mexico portion of the San Juan Basin, having received said interests from the Zela D. Wood Living Trust in 1993. See Title Chain for Cynthia W. Sadler Overriding Royalty Interest at 1 (Plaintiffs’ Ex. 8).
130. Plaintiff Robert Westfall owns a royalty interest burdening WPX Production’s working interests in natural gas production on leases in the New Mexico portion of the San Juan Basin, by virtue of mineral deeds that his father, Archie Westfall, acquired in 1952. See Tr. at 321:8-325:19 (Westfall, Aubrey); Robert Westfall WPX Check Stubs (Plaintiffs’ Ex. 9).
131. Westfall is willing to serve as class representative and represent the interests of the class, as well as his own interests. See Tr. at 315:21-316:11 (Aubrey, Westfall).
132. Based on the Court’s in-person evaluation of Westfall during his testimony, Westfall appears competent and well-informed regarding the facts and the law governing this case.
133. Plaintiff Lee Wiley Moncrief 1998 Trust (“Moncrief Trust”) owns royalty interests burdening WPX Rocky Mountain’s working interests in the Colorado portion of the San Juan Basin. See Moncrief Trust Cheek Stubs (Plaintiffs’ Ex. 22).
134. Plaintiff Kelly Cox Testamentary Trust 7/1238401 (“Cox Trust”) owns royalty interests burdening WPX Rocky Mountain’s working interests in the Colorado portion of the San Juan Basin. See Cox Trust Check Stubbs (Plaintiffs’ Ex. 14); Cox Trust Transfer Orders (Plaintiffs’ Ex. 16).
135. Plaintiff Minnie Patton Scholarship Foundation Trust (“Patton Trust”) owns royalty interests burdening WPX Rocky Mountain’s working interests in the Colorado portion of the San Juan Basin. See Patton Trust Check Stubs (Plaintiffs’ Ex. 25).
136. Bank of America, NA, is the Patton Trust’s trustee. See Tr. at 184:16-17 (Bric-kell).
137. Rolando Munoz is the .Bank of American representative in charge of managing the Patton Trust’s oil-and-gas interests. See Munoz Depo. passim.
138. Munoz has fifteen years of experience in the oil-and-gas industry. See Oral Deposition of Rolando Munoz at 4:10:3-11:18 (taken January 23, 2014)(Plaintiffs’ Ex. 276) (Munoz, Sheridan). 11
*332 139. Plaintiff SWMF Properties, Inc. (“SWMF Properties”) owns royalty interests burdening WPX Rocky Mountain’s working interests in the Colorado portion of the San Juan Basin. See SWMF Properties Cheek Stubs (Plaintiffs’ Ex. 25).
140. All named Plaintiffs are within the proposed class definition, i.e., even if they were not named Plaintiffs, they would still qualify as class members. Cf. Stipulation ¶ 7, at 2.
141. The named Plaintiffs own a total of ninety-six wells, thirty-eight of which are in New Mexico and fifty-eight of which are in Colorado. See Emory Expert Report ¶ 22, at 13.
142. Nineteen of the ninety-six named-Plaintiff wells are coalbed methane, with fourteen located in New Mexico and five in Colorado. See Emory Expert Report ¶ 22, at 13.
143. Seventy-seven of the ninety-six named-Plaintiff wells are conventional wells, with twenty-four of them located in New Mexico and fifty-three in Colorado. See Emory Expert Report ¶ 22, at 13.
d. The Proposed Class Members.
144. Per the class definition, the proposed class members—a/k/a the absent Plaintiffs—are those individuals and entities, not otherwise excluded, who own wells operated by WPX Production and/or WPX Rocky Mountain in the San Juan Basin. See Motion at 3.
145. In addition to its interests in the approximately 500 private leases in which class members own royalty and overriding royalty interests, the Defendants also own working interests in 229 federal oil and gas leases and eighty-six state leases in the San Juan Basin. See Tr. at 836:17-837:9 (Terry, Sheridan).
146. The proposed class definition excludes federal leases and Indian-owned leases. See Motion at 3.
147. The proposed class definition also excludes interests encompassed by a pending class action in Colorado state court, Lin-dauer v. Williams Production RMT Co., No. 2006 CV 317 (Garfield Cnty., Colo.). See Motion at 3.
148. The exclusions result in 299 WPX Production-owned wells in the San Juan Basin being excluded from the class. Compare Emory Expert Report ¶ 22, at 13, and Stipulation ¶ 2, at 1, with Emory Expert Report ¶ 42, at 22.
149. The San Juan Basin covers the northwest corner of New Mexico and the southwest corner of Colorado. See Tr. at 78:19-79:3 (Reineke).
150. The proposed class definition covers approximately 3,157 wells, about 268 of which are in Colorado and roughly 2,889 of which are in New Mexico. See Emory Expert Report ¶ 22, at 13; Stipulation ¶ 2, at 1.
151. There is often more than one well on a lease. See Stipulation ¶ 2, at 1; id. ¶ 4, at 2.
152. The class definition covers 507 leases. See Stipulation 114, at 2.
153. A lease can have more than one royalty owner; there can be co-royalty owners and overriding royalty owners. See Stipulation ¶¶ 4, 6, at 2.
154. The class definition covers approximately 1,466 royalty interests and 909 overriding royalty interests. See Stipulation ¶ 6, at 2.
155. There are, thus, over 2,300 members of the class. See Stipulation ¶ 6, at 2.
156. Of the 3,157 class wells, 1,481 of them are coalbed methane wells, and 1,676 of them are conventional wells. 12 See Emory *333 Expert Report ¶ 22, at 13; Tr. at 79:21-23 (Reineke).
157. Of the 1,481 class coalbed methane wells, ninety-three of them are in Colorado and 1,388 of them are in New Mexico. See Emory Expert Report ¶ 22, at 13; Tr. at 79:21-23 (Reineke).
158. Of the ninety-three class coalbed methane wells in Colorado, 32 of them deliver their gas to the Williams Four Corners gathering system, and sixty-one of them deliver their gas to an independent, third-party gathering system. See Tr. at 79:24-80:2 (Reineke).
159. Of the 1,388 class coalbed methane wells in New Mexico, 816 of them deliver their gas to the Williams Four Corners gathering system, and 572 of them deliver their gas to an independent, third-party gathering system. See Tr. at 80:3-7 (Reineke). See also Expert Report of Barbara Ley at 10 (Plaintiffs’ Ex. 195).
160. Of the 1,676 conventional class wells, 1,501 of them are in New Mexico, and 175 of them are in Colorado. See Emory Expert Report ¶ 22, at 13.
161. Of all 3,456 wells in which the Defendants own the working interest, 13 2,582 of them, or 74.7%, are gathered by Williams Four Corners. See Emory Expert Report ¶ 42, at 22.
e. Independent Entities.
162. Enterprise San Juan Gathering (“Enterprise”) is an independent, third-party gathering company, unrelated to the WPX affiliates. See Emory Expert Report ¶ 42, at 22.
163. Independent entities operate the gathering systems that control a number of class well gathering contracts, including Burlington 3816, Red Cedar 2584, BP 100274-A6, BP 1002474, Red Cedar 07-300, Cedar Hill 183085, Decker 148473, Burlington 3854, and Elm Ridge. See Emory Expert Report ¶ 42, at 22.
3. The Process: Natural Gas Extraction, Gathering, Processing, Transfer, and Sale.
164. Raw natural gas exiting the wellhead contains substances such as NGLs, water, carbon dioxide, nitrogen, and other contaminants, some of which must be separated before the gas is suitable for insertion into a pipeline. See Expert Report of Daniel Rei-neke at 2 (Plaintiffs’ Ex. 196).
165. Raw natural gas is typically not of sufficient quality to be placed into an interstate pipeline; it must first be treated for removal of at least carbon dioxide, and usually water vapor and NGLs. See Tr. at 101:11— 13 (Reineke).
166. All gas produced from class wells is either coalbed methane or conventional gas; none of the class wells are oil wells, and thus none of the gas is casinghead gas. See Tr. at 249:13-250:1 (Brickell, Kaplin); Stipulation ¶ 1, at 1.
167. As working-interest owner on the class leases, WPX Production and WPX Rocky Mountain—in New Mexico and Colorado, respectively—and their predecessors own title to all natural gas and NGLs as they come out of the ground. See Tr. at 95:2-25 (Reineke, Brickell). But see note 9, supra.
168. The gas is run through a separator, which removes the liquid water and NGLs. See Tr. at 96:12-20 (Reineke).
169. No gaseous-phase natural gas from the class wells—during any time period—was sold at arm’s length from the wellhead; all of it goes into a gathering system. See Tr. at 86:6-10 (Brickell, Reineke).
*334 170. Some NGLs condense at the wellhead; these are known as well condensate. See Tr. at 440:25-441:4 (Sutphin, Ward).
171. Not all of the class wells produce well condensate; coalbed methane wells, for example, never do. See Stipulation at 3 n. 4.
172. For “several years,” the Defendants have sold their well condensate to an independent party—currently Western Refining, and, before that, a company called “Gaval-on.” 14 Tr. at 441:5-442:7 (Sutphin, Ward). See WPX Party Transaction Report (Defendants’ Ex. 139).
173. After liquids are separated from the gas, the gas is transmitted from the wellhead to a gathering system—which, as explained earlier, is an affiliate company for some leases and an independent, third-party gatherer for others, depending purely upon location— and is metered before it leaves the lease. See Reineke Expert Report at 3.
174. No liquid—meaning free liquid, not entrained NGLs or water vapor—flows through the meter. See Tr. at 96:21-97:12 (Brickell, Reineke).
175. Metering establishes the volume of gas that the lease produces—measured in MCFs—its thermo-energetic potential— measured in MMBtus—and its NGL content—measured in GPM—as well as the carbon-dioxide content. See Emory Expert Report ¶28, at 15; id. ¶¶ 34-35, at 18-19; id. ¶¶ 36-37, at 19-20.
176. The meter uses ordinary mechanical mechanisms—not fundamentally unlike water meters outside a home—to measure the natural gas’ volume, and gas chromatography to measure its energetic content. See generally Gas Meter, Wikipedia.org, en.wikipe-dia.org/wiki/Gas_meter.
177. Gas chromatography is an analytical chemical technique whereby the natural gas mixture is placed into a column filled with an inert carrier gas, and a liquid or polymer “stationary phase” coating the column’s walls; the different chemical compounds in the natural gas elute—i.e., travel from one end of the column to the other—at different speeds, which correspond to their level of interaction with the stationary phase, and the various “retention times” of the different chemicals in the gas indicate the chemical identity of each compound in the gas. See, e.g., Gas Chromatography, Wake Forest University Department of Chemistry, available at http://www.wfu.edu/chemistry/eourses/ organie/GC/index.html. See generally Gas Chromatography, Wikipedia.org, available at en.wikipedia.org/wiki/Gas_chromatography.
178. Once each compound—and its proportion in the gas by weight and volume—is determined, the known energetic properties of each compound are multiplied by that compound’s proportional presence in the gas, and the overall thermo-energetic potential of the gas is determined. See Gas Chromatography, Wake Forest University Department of Chemistry; Gas Chromatography, Wikipe-dia, org.
179. This metering thus makes it possible to determine the potential production value attributable to each individual lease.
180. On leases that contain free-use clauses, the working interest owner siphons off lease-use gas before metering the gas and uses it to power pumping units, heaters, and other machinery on the lease. See Tr. at 148:14-20 (Reineke).
181. The amount of gas used on a lease is typically not metered. See Tr. at 148:20-21 (Reineke).
182. In- the gathering system, the natural gas—which, at this point, is still impure and not in marketable condition—is eomingled with gas from other leases. See Reineke Expert Report at 4.
183. Gas is then transmitted through the gathering system—which is a network of relatively low-pressure pipes—to one of several processing or treatment plants. See Tr. at 97:19-98:2 (Reineke); See Reineke Expert Report at 4.
*335 184. The gas is compressed in the gathering system by compressors that use a small portion of the natural gas in the lines as fuel. See Tr. at 100:12-23 (Brickell, Reineke).
185. On the way into the processing or treatment plant, the gas is first dehy drated—i.e., the water vapor is removed— and compressed to a higher pressure. See Tr. at 99:21-100:4 (Reineke).
183. Coalbed methane wells—for the most part, but not entirely—flow to the Mi-lagro treatment plant, not to one of the processing plants, because coalbed methane lacks NGLs to extract but it does need to have carbon dioxide removed from it before being placed into the interstate pipeline system. See Tr. at 105:6-106:6 (Brickell, Rei-neke).
187. Conventional gas wells—for the most part, but not entirely—flow to processing plants, because conventional gas has NGLs that can be removed and sold for a greater value than the value they add to the gas as entrained NGLs, which increase the gas’ Btu factor. See Tr. at 105:6-106:6 (Brie-kell, Reineke).
188. At a processing plant, the gas is cleaned of impurities, and any NGLs that are still entrained in the gas—i.e., those NGLs that did not condense naturally at the wellhead as well condensate or in the gathering system as drip condensate—are removed. Cf. Tr. at 619:15-20 (Emory, Brickell).
189. Processing does not create new NGLs, nor does it change their constituen cy—i.e., the proportion of the NGLs that are propane, butane, pentane, et cetera; it merely extracts them from the gas in which they were entrained. See note 34, infra.
190. NGLs removed during processing are sent to a fractionator and separated—or “fractionated”—into their constituent compounds. See Tr. at 104:6-21 (Reineke, Bric-kell).
191. The fractionated NGLs are then sold—at arm’s length during some time periods and to a corporate affiliate during others. See Tr. at 104:6-21 (Reineke, Brickell).
192. At a treatment plant, the gas is cleaned and impurities are removed, and the resultant, marketable gas is pressurized and put into the interstate pipeline system. See Tr. at 619:15-20 (Emory, Brickell).
193. The only process always undergone at a treatment plant is the removal of carbon dioxide, which can cause freezing issues in piping; water vapor may or may not be removed in treatment. See Emory Expert Report ¶ 39, at 21.
194. The residue gas is then pressurized and placed into the interstate pipeline system. See Tr. at 100:5-9 (Reineke).
195. The point at which residue gas is placed into the interstate pipeline system is the point of the first arm’s-length sale. See Tr. at 101:9-102:1 (Reineke).
196. When the title holder of residue gas contracts to sell a quantity of natural gas to a consumer across the country, the title holder does not place a quantity of gas into the pipeline and have the consumer wait for those specific molecules to make their way across the country; rather, the title holder places a certain number of MMBtus of residue gas into the pipeline, and the consumer takes an equivalent number of MMBtus out of it, and that is considered a transfer of natural gas, even though the actual molecules put in the pipeline are not the same ones removed. See Tr. at 101:9-102:1 (Reineke).
197. Pipeline-quality residue gas is, thus, fungible—only its volume, in MCFs, and energy content, in MMBtus, determines its value; it is not otherwise qualitatively different from other pipeline-quality residue gas. See Tr. at 101:9-102:1 (Reineke).
198. Williams Four Corners owns four plants to which class wells flow: the Lybrook processing plant, the Kutz processing plant, the Ignacio processing plant, and the Milagro treatment plant. See Tr. at 98:10-11 (Rei-neke); id. at 98:20-24 (Brickell, Reineke).
199. Williams Four Corners also owns the gathering lines connecting the class wells to those four plants. See Tr. at 98:25-99:1 (Brickell, Reineke).
200. Some class wells also flow to the Cedar Hill plant and the Florida River plant—both of which BP owns—and the Cha-co plant and the Val Verde plant—both of *336 which Enterprise owns. See PWM Master Well Completion Data (Defendants’ Ex. 168).
201. The NGL recovery rate of each plant is different. See Emory Expert Report ¶¶ 39-40, at 21-22.
202. The operational costs and efficiency of each plant is different, and changes over time. See Tr. at 566:11-567:8 (Sutphin, Emory).
203. Not all gas that goes to a processing or treatment plant is processed or treated; some can be “bypassed” around processing or treatment and then blended with processed or treated gas in proportions that ensure that the final mixture is of pipeline quality. Emory Expert Report ¶ 41, at 22.
204. Some NGLs condense in the gathering system; these are known as drip condensate. See Tr. at 123:4-19 (Reineke).
205. The drip condensate is collected from the gathering system periodically and sold. See Tr. at 123:4-19 (Reineke).
206. Drip condensate is sold at oil prices. See Tr. at 123:4-9 (Reineke).
207. Only conventional gas, not coalbed methane, yields drip condensate, as coalbed methane is dry gas, i.e., it does not contain NGLs. See Tr. at 128:1-6 (Briekell, Reineke).
208. When the natural gas changes hands among WPX affiliates, no money changes hands; the transactions are essentially treated the same as an intra-company, inter-division transfer would be. See Tr. at 164:25-165:20 (Ley, Briekell).
209. Royalty owners have no decision-making authority with regard to what happens to hydrocarbons once they are removed from the wellhead; the working interest owner has sole authority to transport, process, and dispose of them. See Tr. at 95:16-96:3 (Briekell, Reineke).
210. The Court will now outline the process by which the title to the class’ gas changed hands among WPX affiliates at various stages of the class time period for wells in the New Mexico on the Williams Four Corners gathering system. 15
a. The Process from 1988 to 1995, i.e., Who Held Title on the Natural Gas at Each Stage.
211. From 1988 to 1995, Williams Production Co. was the lessee on the class leases, meaning that it held title to all natural gas produced at the wellhead. See Tr. at 85:11-86:1 (Briekell, Reineke)(referring to Plaintiffs’ Demonstrative Ex. 5).
212. Williams Production Co. would transfer title to the natural gas to Williams Gas Marketing as it transferred physical possession of the gas to an affiliate gathering company, known as Northwest Pipeline until 1992, and Williams Field Services thereafter. See Tr. at 85:11-86:1 (Briekell, Reineke)(re-ferring to Plaintiffs’ Demonstrative Ex. 5).
213. During this time period, the class wells were each subject to one of six gathering contracts: J38, J99, U99, 114, 129, and K82. See Tr. at 86:17-24 (Briekell, Reineke).
214. The J99 contract covered wells connected to the Williams Four Corners gathering system. See Ley Expert Report at 10.
215. Williams Gas Marketing would then sell the gas at arm’s length after the gathering affiliate finished processing it. See Tr. at 85:11-86:1 (Briekell, Reineke)(refemng to Plaintiffs’ Demonstrative Ex. 5).
b. The Process from 1995 to August, 2010.
216. From 1995 to 2010, Williams Production Co. and its post-1998 successor, Williams Production LLC, were the lessees on the class leases, meaning that they held title to all natural gas produced at the wellhead. See Tr. at 87:2-14 (Reineke)(referring to Plaintiffs’ Demonstrative Ex. 6).
*337 217. The lessee would transfer title to the natural gas to WFS Gas Resources as it transferred physical possession of the gas to an affiliate gathering company, Williams Field Services. See Tr. at 87:2-14 (Reineke).
218. The same five gathering contracts that existed from 1988 to 1995 continued to govern the class wells during this period, and J99 continued to govern all wells on the Williams Four Corners gathering system. See Tr. at 87:2-88:5 (Reineke, Briekell)(refer-ring to Plaintiffs’ Demonstrative Ex. 6).
219. After Williams Field Services finished processing the gas, WFS Gas Resources would then transfer title to the residue gas to Williams Gas Marketing and title to the processed NGLs to Williams Power. See Tr. at 87:2-88:5 (Briekell, Reineke)(refer-ring to Plaintiffs’ Demonstrative Ex. 6).
220. Williams Gas Marketing and Williams Power would then sell their respective products to arm’s-length buyers. See Tr. at 87:2-88:5 (Briekell, Reineke)(referring to Plaintiffs’ Demonstrative Ex. 6).
c. The Process from August, 2010, to July, 2011.
221. From August, 2010, to July, 2011, Williams Production LLC was the lessee on the class leases, meaning that it held title to all natural gas produced at the wellhead. See Tr. at 88:6-12 (Briekell, Reineke)(refer-ring to Plaintiffs’ Demonstrative Ex. 7).
222. The lessee would transfer title to the natural gas to WPX Gas Resources as it transferred physical possession of the gas to an affiliate gathering company. See Tr. at 88:6-20 (Briekell, Reineke)(referring to Plaintiffs’ Demonstrative Ex. 7).
223. In 2011, in preparation for the upcoming spinoff of various WPX affiliates, a new set of gathering contracts were executed. See Tr. at 88:6-20 (Briekell, Reineke)(re-ferring to Plaintiffs’ Demonstrative Ex. 7).
224. Gathering agreement J99M replaced J99 and U99, and gathering agreement 170 replaced agreements 114, 129, and K82. See Tr. at 88:9-89:4 (Briekell, Reineke)(referring to Plaintiffs’ Demonstrative Ex. 7).
225. These new gathering agreements run for a term of eleven-and-a-half years— from July, 2011, to December, 2022—and, despite being executed before the spinoff, continue to bind the spunoff companies. See Tr. at 88:6-89:4 (Briekell, Reineke).
226. Transactions under the new gathering agreements are, thus, affiliate, non-arm’s length transactions, because at the time they were executed, all parties to them were corporate affiliates. See Tr. at 91:16-92:19 (Briekell, Reineke).
227. After processing, WPX Gas Resources would transfer title to the gas and NGLs to Williams Gas Marketing, which would then sell the gas at arm’s length. See Tr. at 88:6-20 (Briekell, Reineke)(referring to Plaintiffs’ Demonstrative Ex. 7).
4. The Language in the Class Leases: The Breakdown of Textual Royalty Formulations.
228. The class leases were executed in the 1940s and early 1950s, and, in all known instances, the original lessors and the original lessee representatives—the original lessees on these leases was not WPX Production—are unavailable. See Expert Report of James Griffin ¶ 6, at 3-4 (Defendants’ Ex. 135).
229. The leases were executed under competitive conditions. See Griffin Expert Report ¶ 6, at 3-4.
230. The class leases typically distribute either one-eighth or, less commonly, three-sixteenths of the value of the gas—and the terminology used to convey the concept of the “value of the gas” is spelled out in different ways in different leases—to the royalty owner, leaving either seven-eighths or thirteen-sixteenths to the Defendant-lessee. See Tr. at 94:17-95:10 (Reineke); Tr. at 238:1-5 (Kaplin).
231. Every lease has a paragraph devoted to how royalty is to be computed and paid. See Tr. at 241:12-16 (McNamara, Kaplin).
232. The class leases provide that royalty is to be valued based on the following language: (i) “gross proceeds,” without reference to being “at the well,” “at the wellhead,” or “at the mouth of the well”; (ii) “proceeds at the mouth of the well”; (iii) “proceeds on *338 the sale of gas, as such”; (iv) “price” or “market price” “at the well”; (v) “net proceeds at the well”; (vi) “gross proceeds received when sold at the mouth of the well, market value if not sold at the mouth of the well”; (vii) “gross proceeds received for gas sold, used off the premises or in the manufacture of products therefrom, but in no event more than the actual amount received”; (viii) “proceeds if sold at the well, or if marketed off the premises, market value at the well”; (ix) “market value at the well of the gas sold or used, provided that on gas sold the market value shall not exceed the amount received for such gas computed at the mouth of the well”; (x) “market value at the well if sold or used to manufacture products; on gas sold at the well, net proceeds realized; each after deduction of post-production costs”; and (xi) “market value at the well of the gas sold or used, provided that on gas sold the market value shall not exceed the amount received for such gas computed at the mouth of the well.” 16 Lease Language Chart (Defendants’ Ex. 191).
233. Textual formulations (i), (ii), (iii), (iv), and (v) are “single-prong” royalty provisions, meaning that they pay the same regardless whether the gas is sold at the wellhead or off-site. Lease Language Chart (Defendants’ Ex. 191).
234. Textual formulations (vi) through (xi) are “two-pronged” royalty provisions, meaning that they describe the value upon which royalty is to be paid in different terms, depending upon whether the gas is sold at the wellhead or off-site. Tr. at 793:6-794:8 (Sheridan, Terry); id. at 799:15-800:5 (Sheridan, Terry).
235. Fifty-five of the leases containing textual formulation (iii)—thirty-one of which are in Colorado and twenty-four of which are in New Mexico—contain specific, separate royalty provisions relating to casinghead gas, which the class wells, being gas wells, do not produce. See Lease Language Chart (Defendants’ Ex. 191).
236. Some of the leases that refer to royalty being paid on the basis of “market value” also refer to paying on the “amount realized from such sales,” but the Court cannot determine how many. 17
*339 237. The majority of the leases are form contracts—with Form 88-42 from the Kansas Blueprint Company being among the most common—altered only to include the relevant individual information—the parties’ names, the location of the lease, et cetera—and are therefore textually identical within their respective textual-formulation categories. See Tr. at 239:8-18 (McNamara, Kaplin). See generally Spreadsheet of Lease Language (Plaintiffs’ Ex. 428)(categorizing each lease by its form number).
238. The form contracts are identifiable— i.e., they are identifiable as being form contracts, and their corporate author and model number are identifiable—by numbers stamped on the leases, typically in the top corners. See Tr. at 241:18-242:2 (McNamara, Kaplin).
239. None of the leases expressly provide for payment on the basis of a WASP or an index price. See Tr. at 112:13-15 (Briekell, Reineke); id. at 259:9-18 (McNamara, Kap-lin); Lease Language Chart (Defendants’ Ex. 191).
240. The class leases contain “free use clauses” that allow the working interest owner to use gas on the lease free of charge, i.e., without paying a royalty on the gas used. 18 Tr. at 148:7-149:1 (Sheridan, Reineke). See Tr. at 326:1-327:24 (Westfall, Sutphin); Selected Lease (Defendants’ Ex. 7).
241. Some of the leases use two different royalty terms—e.g., “proceeds” versus “market value”—to described royalties owed on gas sold from the well and those owed on gas sold off the leased premises; these leases are referred to as “double-pronged” or “two-pronged” leases, while leases that use a single royalty term for gas are “single-pronged” or “one-pronged” leases. 19 Lease Language Chart (Defendants’ Ex. 191).
242. Of the 507 total class leases, 224 are single-pronged, and 256 are double-pronged; twenty-seven are illegible as to their royalty provisions. See Lease Language Chart (Defendants’ Ex. 191).
243. Of the 480 leases with legible royalty provisions, 381 are in Colorado, and ninety-nine are in New Mexico. See Lease Language Chart (Defendants’ Ex. 191).
a. The Royalty-Provision Breakdown of the New Mexico Leases.
244. Sixty-eight of the ninety-nine total New Mexico leases are single-pronged, and thirty-one are double-pronged. See Lease Language Chart (Defendants’ Ex. 191).
245. Sixty-seven of the sixty-eight double-pronged New Mexico leases pay based on “proceeds on the sale of gas, as such” and the other lease pays on the basis of “net proceeds at the well.” Lease Language Chart (Defendants’ Ex. 191).
246. Twenty-four of the thirty-one double-pronged New Mexico leases pay on the basis of “proceeds if sold at the well, or if marketed off the premises, market value at the well.” Lease Language Chart (Defendants’ Ex. 191).
247. Six of the thirty-one double-pronged New Mexico leases pay on the basis of “gross proceeds for gas used off the premises” and, “if used in the manufacture of gasoline, prevailing market rate.” Lease Language Chart (Defendants’ Ex. 191).
248. One of the thirty-one double-pronged New Mexico leases pays on the basis of “market value at the well of the gas sold or used, provided that on gas sold the *340 market value shall not exceed the amount received for such gas computed as the mouth of the well.” Lease Language Chart (Defendants’ Ex. 191).
b. The Royalty-Provision Breakdown of the Colorado Leases.
249. One-hundred fifty-six of the 381 total Colorado leases are single-pronged and 225 are double-pronged. See Lease Language Chart (Defendants’ Ex. 191).
250. One-hundred forty-three of the 156 total single-pronged Colorado leases pay on the basis of “proceeds on the sale of gas, as such.” Lease Language Chart (Defendants’ Ex. 191).
251. Eight of the 156 total single-pronged Colorado leases pay on the basis of “proceeds at the mouth of the well.” Lease Language Chart (Defendants’ Ex. 191).
252. Four of the 156 total single-pronged Colorado leases pay on the basis of “price [or market price] at the well.” Lease Language Chart (Defendants’ Ex. 191).
253. One of the 156 total single-pronged Colorado leases pays on the basis of “gross proceeds,” without reference to the mouth of the well. Lease Language Chart (Defendants’ Ex. 191).
254. Eighty-five of the 156 total double-pronged Colorado leases pay on the basis of “proceeds if sold at the well, or if marketed off the premises, market value at the well.” Lease Language Chart (Defendants’ Ex. 191).
255. Seventy-five of the 156 total double-pronged Colorado leases pay on the basis of “market value at the well of the gas sold or used, provided that on gas sold the market value shall not exceed the amount received for such gas computed at the mouth of the well.” Lease Language Chart (Defendants’ Ex. 191).
256. Thirty-four of the 156 total double-pronged Colorado leases pay on the basis of “gross proceeds received for gas sold, used off the premises or in the manufacture of products therefrom, but in no event more than the actual amount received.” Lease Language Chart (Defendants’ Ex. 191).
257. Twenty-three of the 156 total double-pronged Colorado leases pay on the basis of “market value at the well if sold or used to manufacture products; on gas sold at the well, net proceeds realized; each after deduction of post-production costs.” See Lease Language Chart (Defendants’ Ex. 191).
258. These 23 leases are the only leases to disclaim or negate Colorado’s marketable-condition rule. See Lease Language Chart (Defendants’ Ex. 191).
259. Five of the 156 total double-pronged Colorado leases pay on the basis of “gross proceeds for gas used off the premises. If used in the manufacture of gasoline, prevailing market rate.” Lease Language Chart (Defendants’ Ex. 191).
260. Three of the 156 total double-pronged Colorado leases pay on the basis of “gross proceeds received when sold at the mouth of the well, market value if not sold at the mouth of the well.” Lease Language Chart (Defendants’ Ex. 191).
c. The Named Plaintiffs’ Royalty Provisions.
261. Anderson Trust is the royalty owner of a lease that pays royalty on “gross proceeds ... for the gas from each well where gas only is found ... and if used in the manufacture of gasoline,” royalties are to be paid “at the prevailing market rate for gas.” Selected Lease at 1 (Defendants’ Ex. 4).
262. The Anderson Trust also has overriding royalty interests paid on the “value [of gas] on the leased premises or, if marketed, of the proceeds derived from the sale, at the well or wells.” Selected Assignment (Defendants’ Ex. 25).
263. Westfall is a royalty owner in a lease that pays royalty on the basis of “proceeds from the sale of the gas, as such, for gas from wells where gas only is found.” For “gas produced from any oil well and used by the lessee for the manufacture of gasoline or any other product,” royalties are to be paid on “the market value of such gas at the mouth of the well.” If the gas used to manufacture gasoline is sold by the lessee, royalties are to be paid on “the proceeds of *341 the sale contract." Selected Lease at 2 (Defendants’ Ex. 7).
264. The Patton Trust is a royalty owner in a lease that pays royalty on “the market value at the well ... of the gas sold or used, provided that on gas sold at the wells the royalty shall be one-eighth of the amount realized.” Selected Lease at 1 (Defendants’ Ex. 13).
d. The Meanings of the Varying Language in the Leases.
265. As a matter of oil-and-gas industry custom and usage, “proceeds” and “gross proceeds” mean the same thing. Tr. at 247:7-248:16 (McNamara, Kaplin).
266. In the oil-and-gas industry, “proceeds” and “amount realized” mean the same thing. Tr. at 816:9-14 (Sheridan, Terry).
267. In the oil-and-gas industry, the term “gas used in the manufacture of gasoline or other product therefrom” refers to the volume of gas that is converted from the gaseous state into a liquid state through plant processing. Tr. at 787:4-20 (Terry, Sheridan); id. at 795:9-796:22 (Terry, Sheridan).
268. In the oil-and-gas industry, the terms “proceeds” and “market value” do not necessarily mean the same thing. See Tr. at 794:9-795:8 (Terry, Sheridan); id. at 816:3-817:12 (Terry, Sheridan).
269. In the oil-and-gas industry, “proceeds” refers to the amount of money realized by the lessee from the sale of gas. Tr. at 794:9-795:8 (Terry, Sheridan); id. at 816:3-817:12 (Terry, Sheridan).
270. In the oil-and-gas industry, “market value” or “prevailing market rate” refers to the price received, not by any one lessee, but by other lessees from the sale of gas of similar quality, in the same location, taking into account pressure, marketing outlets and other market factors. See Tr. at 794:9-795:8 (Terry, Sheridan); id. at 816:3-817:12 (Terry, Sheridan).
271. The market value of gas may be calculated independently of proceeds, and may be greater or less than the proceeds from sale of gas depending upon particular contract prices and changes in the market for the sale and purchase of gas. See Tr. at 794:9-795:8 (Terry, Sheridan); id. at 816:3-817:12 (Terry, Sheridan).
272. In some quarters of the oil-and-gas industry, royalty has been paid differently depending on whether it is payable on market value or proceeds. See Tr. at 817:13-16 (Terry, Sheridan).
273. The Defendants, however, used a uniform methodology to pay royalty to lessors with varying lease languages. See Stipulation ¶ 9, at 2-3; Deposition of Julie Mathis at 32:2133:12 (taken December 6, 2013)(Plaintiffs’ Ex. 52)(Brickell, Mathis); Kaplin Expert Report at 4-5.
274. In some quarters of the oil-and-gas industry, when used in a royalty clause, the term “at the well” or “at the mouth of the well,” refers to the location and the condition of gas for purposes of royalty valuation, that is, at the well or on the lease, and not at a downstream sales point. See Tr. at 788:2-20 (Terry, Sheridan).
275. In some quarters of the oil-and-gas industry, the term “as such,” when used with reference to royalty based on “proceeds derived from the sale of gas, as such,” means from the sale of the gas in the condition that it is as it emerges from the well. See Tr. at 780:11-23 (Terry, Sheridan).
276. As most oil-and-gas leases were executed many decades ago, the industry’s usage of these terms has largely developed after the leases in this case were executed. See Griffin Expert Report ¶ 6, at 3-4. Cf. Tr. at 114:24-115:10 (Brickell, Reineke)(noting that the federal government used to set gas prices).
277. The oil-and-gas industry has a self-evident incentive to develop trade usages for lease terms that are more favorable to the lessee than the lessor.
278. Often, including in this ease, 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 *342 the oil and gas business ... be regarded as a ‘merchant’ knowledgeable about oil and gas production and marketing practices. Typically, the lessor is a farmer or a laborer, someone engaged in an unrelated business or profession, or a retired person.”). Cf. Tr. at 298:25-299:5 (Aubrey, Westfall)(describing himself as a retired owner of a small business that sells school and office supplies); Tr. at 358:19-359:1 (Branch, Anderson)(describing himself as a self-employed architectural designer).
279. The leases are, in virtually all, if not all, cases, form contracts, and are not the product of meaningful negotiation of any term except the magnitude of the fractional royalty share. See Tr. at 239:8-18 (McNamara, Kaplin); Anderson, supra, at 612 (“Regarding the lease royalty clause, about the only item negotiated may be the fraction or percentage of royalty.”).
280. The magnitude of the royalty—e.g., one-eighth versus three-sixteenths—is sometimes negotiated between the parties. See Tr. at 802:24-806:1 (Terry, Sheridan)(discussing Selected Leases at 313 (Plaintiffs’ Ex. 427)); Tr. at 806:2-25 (Terry, Sheridan)(discussing Selected Leases at 451 (Plaintiffs’ Ex. 427D)); Tr. at 807:7-809:11 (Terry, Sheridan)(discussing Selected Leases at 211 (Plaintiffs’ Ex. 427E)); Tr. at 809:12-810:22 (Terry, Sheridan)(discussing Selected Leases at 80 (Plaintiffs’ Ex. 427E)); Tr. at 810:23-812:17 (Terry, Sheridan)(discussing Selected Leases at 293 (Plaintiffs’ Ex. 427D)); Tr. at 812:18-813:16 (Terry, Sheridan)(diseussing Selected Leases at 72 (Plaintiffs’ Ex. 427D)).
281. Approximately forty of the class leases show signs of alteration from the standard form, ie., were subject to individualized negotiation. See Tr. at 814:17-20 (Terry).
282. The federal government provides detailed instructions about how working interest owners must pay royalty interests—ie., 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. pt. 1206 (titled “product valuation,” and containing subparts on “Indian oil,” “federal oil,” “federal gas,” and “Indian gas”).
283. Some private leases have effectively adopted the federal regulations by including “same as fed” clauses in them leases. Tr. at 207:5-18 (Sheridan, Ley).
284. There do not appear to be any “same as fed” royalty provisions among the class, although there are some “same as fed” overriding royalties. See Tr. at 207:19-21 (Sheridan, Ley).
285. The Defendants operate many wells on federally owned land, and, when paying those royalties, they typically pay on the sale value of the NGLs rather than on a keep-whole basis. See Miller Depo. at 42:12-43:4 (Brickell, Miller).
286. For federal leases on the J99M gathering contract, however, the Defendants have, since 2011, begun paying federal royalty on the same keep-whole basis that they have paid the private lessors—ie., the class—throughout the class time period. See Tr. at 520:13-521:10 (Sutphin, Miller).
287. The Defendants used to pay their federal government royalties in the same manner they pay the class—the keep-whole methodology—but a federal audit in the mid-1990s forced the Defendants to change. See Tr. at 215:5-219:14 (Brickell, LeyXreviewing Miller Depo. at 42:12-45:20 (Brickell, Miller)).
5. The Overriding Royalty Interests.
288. Overriding royalty interests are common in New Mexico where there are numerous federal and state oil-and-gas leases. See Tr. at 830:14-24 (Terry, Sheridan).
289. Overriding royalty interests typically are created by reservations or grants contained in assignments of oil-and-gas leases. See Tr. at 830:6-13 (Terry, Sheridan).
290. Overriding royalty interests can be created a number of ways, many of which are situation-specific. See Tr. at 230:9-12 (Kap-lin).
291. One common way overriding royalty interests are created is that a non-landowner will aggregate plots of land from numerous landowners and lease them to an oil company, and cut an overriding interest for itself *343 as, effectively, payment for the aggregation. See Tr. at 229:21-230:1 (Kaplin).
292. Another common way overriding royalty interests are created is that a working interest owner on a lease will want to drill another well on a lease, but, lacking the resources to do so itself, will “farm it out to a third party and tack an override on it.” Tr. at 230:3-8 (Kaplin).
293. A third common way an override can be created is that a royalty owner will assign their lease to a new lessor—or sell their land—and reserve an overriding royalty in the lease. See Tr. at 230:13-20 (McNamara, Kaplin).
294. Overriding interests can also be conveyed to, e.g., consulting geologists who assist a prospective producer, as a form of payment. See Tr. at 230:21-231:4 (McNamara, Kaplin).
295. Overriding royalty interests generally are not created through the use of form contracts. See Tr. at 830:25-831:7 (Terry, Sheridan).
296. Overriding royalty interests often are created in individualized circumstances and business transactions, and the agreements contain unique royalty valuation terms. See Tr. at 832:7-16 (Terry, Sheridan).
297. There are a wide variety of express terms among the class members’ overriding royalty agreements, and there is no standardization in the overriding royalty interest terms. See Defendants’ Exhibit 196; Tr. at 835:5-836:6 (Terry, Sheridan).
298. Overriding royalty instruments are “not generic like leases are,” and the terms of each individual overriding royalty instrument are “unique.” Tr. at 230:21-230:4 (Kaplin, MeNamara)(“The terms on [overriding royalties are] kind of unique.”).
299. Overriding royalty instruments are “individualized agreements,” and all of them are “a little bit different” from one another. Tr. at 257:10-18 (Kaplin, McNamara).
300. The Court has a list of some of the textual provisions found in the class overriding royalties, see Overriding Royalty Language Used in Various Assignments at 1-12 (Defendants’ Ex. 196), the list contains far more textual permutations than the eleven that exist for royalty interests, and even that list is illustrative, not exhaustive, of all the overriding royalty provisions among the class, see Tr. at 832:3-16 (Sheridan, Terry)(“I simply was trying to come up with what I believed were some examples of the type of instruments that are going to be at issue in this matter.”); id. at 832:23-833:7 (Sheridan, Terry)(“Did we pull every one? ... [W]e didn’t begin to get through all the files.”).
301. The parties have been unable to locate many of the overriding royalty interests that the class definition would cover. See Tr. at 254:9-255:3 (McNamara, Kaplin).
302. Among the leases in Colorado in which class members own royalty and overriding royalty interests, there are leases that permit the deduction of post-production expenses in haec verba. See Tr. at 855:12-856:18 (Terry, Sheridan).
303. Overriding interests appear to entitle their owners to a smaller portion of the value of production than standard royalties do; overriding royalties exist for 0.25 percent and 2.5 percent. See Tr. at 267:12-18 (McNamara, Kaplin); id. at 268:10-15 (McNamara, Kaplin).
304. Like the royalty provisions, no overriding royalty instruments explicitly provide that the working interest owner is not required to pay royalty on NGLs. See Tr. at 268:16-21 (McNamara, Kaplin).
305. Assignments of overriding royalty interests in which class members acquired their interest subsequent to creation of the override offer contain assignment language that is inconsistent with the express terms of the instrument that created the override. See Tr. at 839:2-844:5 (Terry, Sheridan).
306. In addition to its interests in the approximately 500 private leases in which class members own royalty and overriding royalty interests, the Defendants also own working interests in 229 federal oil-and-gas leases and eighty-six state leases in the San Juan Basin. See Tr. at 836:17-837:9 (Terry, Sheridan); Database of WPX State and Federal Leases (Defendants’ Ex. 200).
*344 307. There are some “same as fed” overriding royalty interests in the class, but the Court does not know how many. See Tr. at 255:24-256:3 (McNamara, Kaplin).
308. There are also some overriding royalty interests that provide that payments be made on the same formula that the State of New Mexico uses—effectively making them “same as state” clauses. See Tr. at 255:17-23 (McNamara, Kaplin).
309. Overriding royalty interests that burden the Defendants’ working interests in federal and state leases, do not necessarily provide for royalty on the same terms payable in the same manner as the royalty due the federal and state governments under such leases—except, of course, for the “same as fed” overriding royalties. See Tr. at 837:10-14 (Terry, Sheridan).
6. The Defendants’ Royalty-Distribution System.
310. The Defendants use a different royalty-payment system for wells on their own gathering system, ie., the Williams Four Corners gathering system, than the one they used for wells on an independent, third-party gathering system. See Tr. at 80:14-18 (Rei-neke).
311. The Defendants did not base royalties on—ie., they did not vary their payouts to the class on the basis of—the individual leases’ language. See Stipulation ¶ 9, at 2-3; Mathis Depo. at 32:21-33:12 (Brickell, Mathis); Kaplin Expert Report at 4-5.
312. The Defendants had a policy of reviewing leases only when the royalty owner for that lease makes a direct inquiry concerning his or her royalty payment. See Kaplin Expert Report at 5.
313. Even when royalty owners contacted the Defendants about their royalty, the Defendants did not ultimately adjust or individualize that royalty owner’s payouts on the basis of his or her lease’s language. See Tr. at 163:9-13 (Brickell, Ley); Kaplin Expert Report at 5.
314. The generally applicable master equation that the Defendants uses to determine royalty payouts is: Price Quantity-Applicable Posb-Production Deductions = Royalty Value. See Stipulation ¶ 10, at 3.
315. Before 2000, the “price” term was determined using a WASP; since 2000, it has been determined using an index price. See Tr. at 108:6-13 (Reineke);
316. The “quantity” term is determined using an MMBtu measurement at the wellhead as described above. Stipulation ¶ 13, at 3.
317. For Colorado wells, the “applicable posbproduction deductions” includes only taxes. See Stipulation ¶ 14, at 3.
318. For New Mexico wells, the “applicable post-production deductions” are described below. See Findings of Fact 366-384, Part 6d (Cost Deductions) supra.
a. Payments on NGLs, Including Drip Condensate.
319. The Defendants pay the class members’ royalties on the basis of MMBtus at the wellhead, known as a keep-whole basis. See Stipulation ¶ 18, at 4; Tr. at 440:7-17 (Sut-phin, Ward); Kaplin Expert Report at 6.
320. This practice of paying a per-MMBtu-at-the-wellhead royalty compensates the class members partially, but not fully, for the value of entrained NGLs. See Kaplin Expert Report at 6.
321. Gas with a higher NGL content has a higher MMBtu factor than gas with a low NGL content; thus, paying on the basis of MMBtus at the wellhead results in higher payments for wet gas—which will ultimately yield NGLs—than for the same volume of dry gas. See Aggregate Royalty Payments: Whole Stream Value Minus Keep Whole Value (Defendants’ Ex. 149); Kaplin Expert Report at 6.
322. NGLs, however, are more valuable than a thermally equivalent quantity—ie., an equal MMBtu amount—of natural gas, so this payment mechanism results in the class members being paid less than they would be if they were paid their royalty share of the sold NGLs and the residue natural gas separately. See Comparison of NGL and Residue Natural Gas Prices (Left Scale) and Relative Prices (Right Scale) (Defendants’ Ex. 146)(graphing, over the time period 1994 to *345 2013, the price of NGLs, the price of San Juan Basin residue gas—ie., the index price—and the difference between the two, in dollars per MMBtu); 20 Aggregate Royalty Payments: Whole Stream Value Minus Keep Whole Value (Defendants’ Ex. 149); Kaplin Expert Report at 6.
323. For example, consider a volume of gas A, which is dry gas and has 90 MMBtus of energy at the wellhead, and an identical volume of gas B, which is wet gas and has 120 MMBtus of energy at the wellhead. Gas B will, downstream of the wellhead, yield NGLs whose market value, when added to the market value of the residue—ie., dry, post-processing—gas B, be worth greater than one-third more than gas A, despite that the gas B only had one-third more energy at the wellhead. The Defendants, however, only pay one-third more royalty for gas B than for gas A, effectively treating an MMBtu of natural gas as financially equivalent to an MMBtu of NGLs—even though the Defendants sell an MMBtu of NGLs for a higher price than they sell an MMBtu of natural gas. 21
324. Unlike the Plaintiffs’ issues with the WASP method—which, by definition, will pay out the appropriate total amount among all wells, even if it shorts some wells some months and overpays others—the Defendants’ keep-whole methodology pays the class less overall than the whole stream methodology. See Aggregate Royalty Payments: Whole Stream Value Minus Keep Whole Value (Defendants’ Ex. 149); Difference Between Whole Stream Value and Keep Whole Value (Defendants’ Ex. 147).
325. If costs of NGL extraction are not passed on to the royalty owner, or if NGL extraction were costless, then the whole stream valuation method would always benefit royalty owners over the keep-whole method that the Defendants used. See Tr. at 705:8-23 (Briekell, Griffin); Difference Between Whole Stream Value and Keep Whole Value (Defendants’ Ex. 147).
326. When NGL extractions—ie., processing—costs are passed on to the royalty owner, however, a great number of the class wells—but not the majority—would get a higher royalty from the keep-whole methodology. See Aggregate Royalty Payments: Whole Stream Value Minus Keep Whole Value (Defendants’ Ex. 149)(presenting data, that the Defendants’ expert compiled, indicating that over the period from 1985 to present, fifty-two wells of a 100—well sample 22 would have benefitted from whole *346 stream methodology, while forty-eight wells of the sample benefited from the use of keep-whole methodology).
327. That being said, the whole-stream approach—as the Defendants’ expert, Dr. James Griffin defines it—does not pay royalty on drip condensate, see Tr. at 685:6-12 (Sutphin, Griffin), and it is not, in fact, the royalty-calculation methodology to which the Plaintiffs contend they are entitled, see Tr. at 705:25-706:6 (Brickell)(“[W]e’re not asking for a whole stream approach.”). See also note 8, supra (describing how Dr. Griffin apparently invented the whole stream valuation method, and suggesting that it may be a strawman methodology).
328. The Defendants do not pay royalties on drip condensate—except to the extent that, when what will become drip condensate is entrained in the gas at the wellhead, it causes the gas to have a higher MMBtu factor. See Deposition of Sheryl Ward at 201:14-202:2 (taken March 1, 2013)(Plaintiffs’ Ex. 29)(Briekell, Ward)(‘Tm not aware of any payments for drip condensate.”).
329. The Defendants do not pay royalties on processed NGLs—except to the extent that, when what will become drip condensate is entrained in the gas at the wellhead, it causes the gas to have a higher MMBtu factor. See Stipulation ¶ 18, at 4; Tr. at 440:7-17 (Sutphin, Ward); Kaplin Expert Report at 6.
330. The industry practice regarding paying lessors for the value of drip condensate is in a state of flux. See Tr. at 195:1-10 (Brie-kell, Ley); id. at 858:15-24 (Sheridan, Terry); id. at 858:24-859:11 (Sheridan, Terry); Kaplin Expert Report at 3.
331. ConocoPhillips also has working interests in the San Juan Basin, and pays its burdening royalty owners for both gas proceeds and NGL proceeds. See Kaplin Expert Report at 3.
332. For example, Westfall, who owns royalties burdening ConocoPhillips as well as WPX Production, receives over fifty percent more per MMBtu from ConocoPhillips than he does from WPX Production. See Tr. at 195:1-10 (Brickell, Ley).
333. Enterprise has gathering contracts that provide that it—Enterprise, rather than the well-lessors—gets to keep the full value of all drip condensate recovered. See Tr. at 858:15-24 (Sheridan, Terry).
334. Arrangements such as Enterprise’s “ha[ve] become more common over time.” Tr. at 858:24-859:11 (Sheridan, Terry).
335. Williams Four Corners has “keep whole” contracts with producers in addition to WPX Production and WPX Rocky Mountain, including large unaffiliated producers like ConocoPhillips, BP, XTO, and Devon, as well as, with smaller independent producers. See Tr. at 580:3-16 (Emory, Sutphin); Chart of Williams Four Corners Keep Whole Agreements (Defendants’ Ex. 201)(listing thirty-eight keep-whole agreements).
336. There are technical challenges associated with paying exact well-by-well royalties on drip condensate.
337. Not all class wells produce drip condensate, because coalbed methane does not produce NGLs of any kind. See Tr. at 568:3-575:25 (Emory, Sutphin). See also Tr. at 136:2-137:1 (Reineke, Berge).
338. Gas’ chemical composition is also relevant to drip condensate production: only class wells that produce pentanes and heavier hydrocarbons have the potential to produce drip condensate. See Tr. at 568:3-575:25 (Emory, Sutphin). See also Tr. at 137:8-138:6 (Reineke, Berge).
339. Drip condensate production also largely depends on gas pressure and temperature in the gathering system. See Tr. at 568:3-575:25 (Emory, Sutphin).
340. Gas composition, pressure, and temperature vary over time, including during the class time period in this case. See Tr. at 568:3-575:25 (Emory, Sutphin).
341. A well’s gas composition, however, does not vary by much over time. See Tr. at 210:16-211:22 (Sheridan, Ley).
342. While the total amount of drip condensate produced in a gathering system is ascertainable, a detailed engineering analysis, on a well-by-well basis, is required to accurately allocate the drip condensate quan *347 tities among the various wells involved. See Tr. at 568:3-575:25 (Emory, Sutphin).
343. Such an engineering analysis must take into account gas composition, temperature and pressure. See Tr. at 568:3-575:25 (Emory, Sutphin). See also (Tr. at 642:10-643:25 Emory, Sutphin).
344. There is an exception to the general rule that the Defendants pay the class on a keep-whole basis: for “at least two wells committed to the 372K gathering contract”— which, between royalty and overriding royalty interests, affects 99 class members—the Defendants pay royalty on the basis of NGLs. See Stipulation at 4 n. 6; Tr. at 452:8-18 (Sutphin, Ward).
b. Compensation for Gas Used Off the Lease.
345. Production from all wells must be compressed to enter a gathering system and/or plant. See Tr. at 577:7-580:2 (Emory, Sutphin).
346. As the raw gas travels along the gathering system, it typically passes through one or more compressor stations, which increases the pressure of the gas to levels necessary to keep it moving along the gathering system and delivers it to a treating or processing plant. See Tr. at 100:12-23 (Bric-kell, Reineke).
347. These compressor stations are powered by gas within the lines, i.e., gas on which the class members are owed royalty. See Tr. at 100:18-23 (Brickell, Reineke).
348. Gas is also used on the lease itself; this gas is known as “lease use” gas. Tr. at 443:3-7 (Brickell, Emory).
349. WPX Production does not pay royalty on lease use gas, nor is it required to pay anything if the lease involved has a free use clause. See Tr. at 442:8-443:15 (Ward, Sut-phin).
350. The monthly check stubs issued that the Defendants issue to the class members do not report volumes of gas that the Defendant-lessees used. See Ley Expert Report at 8,12.
351. The check stubs reflect only the quantity of gas that the Defendants actually royalty on, which has—silently built into it— a reduction from the gross production quantity to account for “used” gas. COGIS— Monthly Well Production at 1 (Plaintiffs’ Ex. 231). See Tr. at 124:6-125:24 (Brickell, Rei-neke).
352. The result of this fact is that the royalty owners never know about the portion of gas that the Defendants use; they are only informed of, and paid on, an amount that has already had used gas deducted. See Tr. at 486:23-487:9 (Brickell, Ward).
353. The amount of produced gas deducted as being “used” is typically in the eight- and-one-half percent range. See Tr. at 126:8-17 (Reineke, Brickell).
354. There are technical challenges associated with paying exact well-by-well compensation on used gas.
355. The amount of compression required depends upon the individual well’s producing pressure. See Tr. at 577:7-580:2 (Emory, Sutphin).
356. The more compression required, the more compression fuel used, and thus more compressor fuel costs. See Tr. at 577:7-580:2 (Emory, Sutphin).
357. The pressure of class wells varies significantly from well to well. See Tr. at 577:7-580:2 (Emory, Sutphin).
358. For example, some wells produce at 5 psi 23 and others at 200 psi. See Tr. at 577:7-580:2 (Emory, Sutphin).
359. Compressor fuel costs cannot be determined on a class-wide basis, and such costs must be determined on a well-by-well basis, taking into account the actual volume and pressure from any given well. 24 See Tr. at 577:7-580:2 (Emory, Sutphin).
*348 c. Timeliness of Payments.
360. WPX Production has, at times, made late payments—ie., payments outside of the NMPPA’s forty-five day window—and declined to pay interest on the overdue amounts. See Tr. at 465:6-466:6.
361. Every month, WPX Production makes numerous adjustments to prior royalty and overriding royalty payments in the form of “prior-period adjustments.” See Tr. at 454:9-458:12 (Ward, Sutphin).
362. Many circumstances can prompt pri- or-period adjustments, some of which are beyond WPX Production’s control, including volume changes from the gathering systems, suspense payments, and unit expansions. See Tr. at 454:9-458:12 (Ward, Sutphin).
363. Some prior-period adjustments are occasioned by accounting errors that WPX Production makes. See Tr. at 454:9-458:12 (Ward, Sutphin).
364. WPX Production evaluates whether to pay interest on prior-period adjustments on a case-by-case basis and has, on at least some occasions, paid interest on prior-period adjustments. See Tr. at 454:9-458:12 (Ward, Sutphin); id. at 454:9-458:121 (Ward, Sut-phin); id. at 463:2-21 (Ward, Brickell).
365. It is more probable than not that WPX Production has withheld interest payments on grounds other than those that justify withholding interest under the NMPPA. 25 See Tr. at 465:6-14 (Ward).
d. Cost Deductions.
366. For royalties paid on New Mexico production committed to a gathering contract with parties other than Williams Four Corners, WPX Production deducts a proportionate share of actual charges assessed by the service provider for all post-production services, the amount for which is determined by contract, plus applicable state production taxes, and state and federal income tax, when required to be withheld. See Stipulation ¶ 19, at 4-5.
367. On independently gathered wells, if the gas is processed for the removal of NGLs, WPX Production deducts a proportionate share of any applicable processing fees, plant fuel, processing taxes, and costs associated with transportation and fractionation of NGLs from any royalty payment associated with said NGLs. See Stipulation ¶ 19, at 5.
368. For royalties paid on New Mexico production committed to a gathering contract with Williams Four Corners and its predecessors, WPX Production deducts a uniform cost of service (“COS”) charge per MCF from each New Mexico class member on the Williams Four Corners gathering system, regardless of the actual costs attributable to each well/lease of rendering the gas into marketable condition. See Mathis Depo. at 104:1-16 (Brickell, Mathis); Kaplin Expert Report at 5.
369. The Defendants assessed a COS charge throughout the entire class period— 1985 to present—although its magnitude fluctuated throughout the period. See Mathis Depo. at 107:13-20 (Brickell, Mathis).
370. Williams Four Corners computes the COS charge and relays it to WPX Production, who assesses it against the royalty. See Tr. at 511:9-23 (Sutphin, Miller).
371. The Defendants assess the same COS charge against the federal government that they do against private lessors; the class COS charge is calculated pursuant to 30 C.F.R. § 1206.157 (b), which regulates the expenses that working interests owners of federal land may deduct when the gas is sent to an affiliate. See Tr. at 504:17-22 (Sutphin, Miller).
372. Williams Four Corners recomputes the COS charge annually, and it is based on an even breakdown of: (i) the “hard” costs of gathering, compressing, treating and processing gas; and (ii) the “soft” costs of office overhead and depreciation on plant; and (iii) costs not actually sustained, i.e., profit. See *349 Tr. at 182:23-183:14 (Brickell, Ley); id. at 476:12-15 (Brickell, Ward); Kaplin Expert Report at 5.
373. The components of the COS charge are all permissible for federal royalties, but the class members are not the federal government, and the class members’ royalties are governed by their leases, and not by federal regulations. See 30 C.F.R. § 1206.157 .
374. The COS charge is enumerated on the cheek stubs as a “gathering” charge, even though it is not limited to the costs of gathering. See Tr. at 122:14-20 (Brickell, Reineke).
375. The COS charge does not include a component for any marketing expenses that WPX Production incurs; WPX Production does not pass on marketing expenses to the royalty owners. See Tr. at 453:22-454:8 (Ward, Sutphin)(“To my knowledge, we have never deducted marketing charges to San Juan royalty owners.”); id. at 466:10-18 (Ward, Sutphin).
376. WPX Production deducts federal and state taxes from their royalty payouts, in keeping with the law. See Stipulation ¶ 14, at 3.
377. The Defendants calculate the profit or “rate of return” component of the COS by multiplying the undepreciated balance of gathering assets times the Triple B bond rate, by a 1.3 percent inflation factor. Tr. at 181:17-182:3 (Brickell, Ley). See Tr. at 509:17-511:8 (Miller, Sutphin). See also 30 C.F.R. § 1206.157 .
378. The COS charge’s profit component comes out to around four-and-a-half percent of the total of the real-expense components. See Tr. at 510:11-20 (Sutphin, Miller).
379. The Defendants do not assess a COS charge on the Colorado wells. See Stipulation ¶ 14, at 3.
380. WPX Production does not assess a COS charge on the non-Williams Four Corners wells; rather, it passes on a proportional share of the charge that the independent gatherer invoice to it. See Tr. at 153:23-154:2 (Reineke, Brickell).
381. As a part of WPX Production’s affiliate gathering contract with Williams Four Corners, WPX Production pays Williams Four Corners a gathering rate that is typically higher than the COS charge it assesses against royalty owners. See Tr. at 449:7-19 (Ward, Sutphin).
382. In one month analyzed, the contract rate for gathering was $1.39 and the COS rate was $.85, approximately sixty-one percent of the contract rate. See Tr. at 449:20-451:25 (Ward, Sutphin); Electronic Mail Transmission from Sheryl Ward to Robert Sutphin at 1 (Defendants’ Ex. 131).
383. The WPX Production-Williams Four Corners contract is, however, an affiliate contract, as, even the contract now in place was executed at a time when both parties were owned by the same entity.
384. Moreover, contracts between WPX Production and a gathering company— whether Williams Four Corners or a third-party company—do not alter the royalty that WPX Production owes the class members under their leases.
e. Averaging of Payments Across Leases.
385. Before some point in 2001, the Defendants paid all royalty owners on the basis of a WASP. See Tr. at 170:10-171:2 (Brickell, Ley); Responses and Objections of WPX to Plaintiffs’ “Non-Prioritized” Interrogatories at 14 (Plaintiffs’ Ex. 221)(response to interrogatory no. 8); Mathis Depo. at 40:24-41:14 (Brickell, Mathis).
386. The WASP for the natural gas was based on the arm’s length sales at the pipeline, and not on any preceding affiliate transaction. See Tr. at 108:6-109:13 (Reineke, Brickell); Mathis Depo. at 40:24-41:14 (Brie-kell, Mathis).
f. Payments of the Basis of Index Price.
387. In 2000, the Defendants switched from using a WASP to using an index price to pay royalties on both well condensate and natural gas. See Responses and Objections of WPX to Plaintiffs’ “Non-Prioritized” Interrogatories at 14 (Plaintiffs’ Ex. 221)(re-sponse to interrogatory no. 8).
*350 388. The Defendants use the OPIS Mt. Belvieu index price—an oil index—for well condensate. See Stipulation ¶ 11, at 3.
389. For natural gas, the Defendants use the index price in the fírst-of-the-month Platt’s Inside FERC San Juan Gas Market Report for El Paso Natural Gas Company. See Stipulation ¶ 11, at 3. See also Tr. at 102:6-11 (Reineke).
390. An independent company, Platt’s, calculates the index and publishes it in Inside FERC Natural Gas Report. See Tr. at 817:17-823:20 (Terry, Sheridan). See also Tr. at 114:19-23 (Reineke, Brickell).
391. This index price is based upon actual reported sales and purchases of gas to be delivered by the seller at the El Paso pipeline location in the San Juan Basin in the particular month for which the index price is published. See Tr. at 817:17-823:20 (Terry, Sheridan). See also Tr. at 114:19-23 (Rei-neke, Brickell).
392. This price reflects the average arm’s length sale price of pipeline-quality gas, rather than wellhead-quality gas. See Tr. at 296:9-16 (McNamara, Kaplin).
393. Natural gas is regularly sold and pm-chased by unrelated sellers and buyers at the index price. See Tr. at 821:4-13 (Terry, Sheridan).
394. Within the oil-and-gas industry, it is generally believed that the index price reflects the market value of the gas delivered at the designated location in the month of publication. See Tr. at 823:21-824:2 (Terry, Sheridan); id. at 138:15-20 (Reineke, Berge); id. at 287:1-288:4 (Kaplin, Berge); id. at 289:3-11 (Kaplin, Berge).
395. To the extent that there is a “going rate” for natural gas, the indices reflect it; the federal government used to set the price of natural gas by fiat, but those days ended before the beginning of the class period. See Tr. at 114:24-10 (Brickell, Reineke).
396. In one comparison of the index price to the WASP, the index price was approximately $0.01 higher, and in another comparison, the WASP was slightly higher or the same. See Tr. at 523:20-526:6 (Miller, Sut-phin).
397. The Defendants pay their federal lease royalties on the basis of an index price. See Tr. at 525:24-526:2 (Sutphin, Miller).
g. Affiliate Versus Arms-Length Transactions.
398. The Plaintiffs’ affiliate-transactions claim is not an independent claim, but rather a rephrasing of the index-price claim and the claim that the Defendants fail to pay royalty on NGLs; those claims and the evidence relating to them are summarized above. See Findings of Fact 319-344, Part 6a, supra; id. 387-396, Part 6f, supra.
399. When the Defendant-lessee—either - WPX Production or WPX Rocky Mountain— transfers title to the gas to a gathering and/or processing affiliate—presently Williams Four Corners, see Findings of Fact 211-227, Part 3a-e, supra, the gathering affiliate “pays” the Defendant-lessee the index price, but no money actually changes hands, see Finding of Fact 208.
400. The Defendants never paid royalty on an affiliate sale value that is less than the value of the index price.
401. Additionally, when the Defendant-lessee transfers title to the gas to its gathering affiliate, it is transferring the unprocessed gas, which is effectively the gas on which it pays royalty when it pays via the keep-whole methodology.
402. The affiliate-transaction claim is, thus, a re-packaging of their other claims. 26
7. The Named Plaintiffs’ and Absent Class Members’ Knowledge of, and Diligence in Discovering, Their Causes of Action.
403. The only regular correspondence between the Defendants and the class members *351 are the cheek stubs that the Defendants send to the class members conveying monthly royalty payments.
404. The format of cheek stubs sent to each royalty and overriding royalty owner is uniform among the class, but has changed over time. See Stipulation ¶ 9, at 2-3.
405. Royalty and overriding royalty owners contact the Defendants on occasion with questions regarding their payments. See Tr. at 727:25-728:9 (Mathis, Sutphin).
406. The Defendants maintain a full-time position—currently filled by Karen Furland, a WPX Energy employee—for the purpose of receiving and resolving royalty-related questions, and maintains records detailing royalty owner inquiries regarding royalties. See Tr. at 725:3727:8 (Mathis, Sutphin); id. at 726:4-6 (Sutphin, Mathis).
407. Class members have, at times, in-, quired about issues relating to their royalty payments long before the Plaintiffs filed this lawsuit, including inquiries about information on cheek statements, see Customer Service Hotline Inter Office Call Sheet (Defendants’ Ex. 80), post-production deductions, see Customer Service Hotline Inter Office Call Sheet (Defendants’ Ex. 82), transportation charges and the COS charge, see Customer Service Hotline Inter Office Call Sheet (Defendants’ Ex. 85), whether condensate payments are made, whether payments are made for natural gas liquids, and the parties to whom WPX Production sells its natural gas production, see Tr. at 728:10-16 (Mathis, Sutphin); 728:17-736:19 (Mathis, Sutphin).
408. Anderson Trust never contacted WPX Production to ask about its payments, and never made an inquiry into whether it had a claim. 27 See Tr. at 419:1-420:9 (Anderson, Sheridan).
409. WPX Production did not dissuade Anderson from filing an action or from filing it before October, 2011. See Tr. at 421:11— 422:5 (Anderson, Sheridan).
410. Various persons from Bank of America, SWMF Properties, and Moncrief Trust called WPX Rocky Mountain seeking information, including with respect to adjustments to royalty payments, and the information contained in the check detail. See, e.g., Tr. at 729:24-730:16 (Mathis, Sutphin); Customer Service Hotline Inter Office Call Sheet (Defendants’ Ex. 80).
411. Munoz—the Bank of America representative in charge of managing the Patton Trust’s royalty interests—annually reviews the Patton Trust’s oil-and-gas properties and provides written comments and recommendations as a part of his job. See Munoz Depo. at 13:49:8-14:50:18 (Munoz, Sheridan).
412. Bank of America also employs division order analysts, title analysts and accountants in its oil and gas group; all of whom play a role in receiving cheeks, reviewing check stub detail, entering the information into the Bank of America system, and ensuring that its clients are paid properly. See Munoz Depo. at 16:60:7-61:10 (Munoz, Sheridan); id. at 24:92:18-93:7.
413. Bank of America reviewed royalty payments to the trust, but did not question or object to WPX Rocky Mountain’s royalty calculation methods. See Munoz Depo. at 5:15:1417:14 (Munoz, Sheridan); id. at 25:97:7-26:98:21 (Munoz, Sheridan).
414. Over the years, Westfall communicated by telephone and by letter with WPX Production and its predecessor, Williams Production Company, and never inquired about gas pricing, post-production deductions, or any other issues which are the subject of his claims in this ease. See Tr. at 307:12-308:10 (Westfall, Aubrey); id. at 312:20-24 (Westfall, Aubrey).
415. Westfall did not discover his claims until 2010, when he began working with class counsel. See Tr. at 337:15-338:10 (Westfall, Sutphin).
416. From 1999 to 2000, a Colorado royalty' owner and class member, Marshal Diggs, insisted that WPX Rocky Mountain 28 *352 was prohibited from deducting post-production costs from his royalty payments. See Royalty Owner Data Sheet and Correspondence with Marshal Diggs, filed February 21, 2014 (Doc. 212-8).
417. After multiple exchanges of letters, WPX Rocky Mountain advised on September 13, 2000, that the royalty owner was paid on the value of gas at the wellhead, and that the sales price on his check stub “is with costs included.” See Royalty Owner Data Sheet and Correspondence with Marshal Diggs.
8. Potential Damage-Calculation Models.
418. Computerized database records are still in existence for most, if not all, of Defendants’ accounting periods herein described for potential damages calculations. See Emory Expert Report passim.
419. Metering at the wellhead enables the Court to determine the actual (i) quantity/volume of gas produced by each well, in MCFs; (ii) energy content of gas produced by each well, in MMBtus; and (iii) quantity/volume of NGLs entrained in the gas produced by each well, in GPM. See Emory Expert Report passim.
420. It is possible to determine to which plant most gas from a given well flows, but practically impossible to determine where all of the gas flows, as the gathering systems are interconnected with one another. See Emory Expert Report ¶¶ 44-49, at 23-26.
421. There is already in existence a database that, among other things, matches each class well to the gathering system and plant to which the well’s gas flows; this database also contains the proportion of gas processed at each plant. See PWM Master Well Completion Database (Defendants’ Ex. 168).
422. Because not all NGLs entrained in gas at the wellhead are ultimately extracted from the gas—ie., some of it fails to condense into drip condensate and also gets bypassed from processing, thus remaining in the residue gas when it is put in the pipeline—it would require a well-by-well flow analysis to precisely attribute NGLs, including drip condensate, to the well from which they came. See Tr. at 137:8-138:6 (Sheridan, Reineke).
423. Late payments—ie., payments made outside of the NMPPA’s forty-five day window—can be easily identified, and those late payments that might potentially be justi fied—ie., those payments that are in suspense because of a title dispute—can also be identified through the use of a class-wide query. See Tr. at 178:18-179:8 (Briekell, Ley).
424. Barbara Ley—one of the Plaintiffs’ experts—has performed such a class-wide late-payments query in other oil-and-gas class actions. See Tr. at 179:1-8 (Ley, Bric-kell).
PROCEDURAL BACKGROUND
To frame the factual determinations and legal discussion, the Court will outline— briefly and in broad strokes—the basic factual allegations and legal arguments underlying the Plaintiffs’ ease, as well as the Defendants’ responses thereto. The Court will also briefly describe the—mostly expert— witnesses whom each side presented at the hearing, and their general topic of testimony. The Court will later make conclusions of law to rule on the Motion.
1. The Pleadings.
1. In ruling on a class certification motion, the Court does not accept the facts alleged in the pleadings as true, but must find all facts bearing on the question of certification, even if those facts also bear on the merits of the substantive claims. The Court is cognizant that it must not decide the merits at this stage of the case and expressly does not decide the merits of the ease. The above findings of fact are tentative and made solely to allow the Court to decide whether class certification is appropriate.
*353 a. The Complaint.
2. The Plaintiffs filed a proposed class action in state court on December 5, 2011, and the Defendants removed the ease to federal court pursuant to the Class Action Fairness Act, 28 U.S.C. § 1332 (d) (“CAFA”), just over a month later. Notice of Removal ¶ 1, at 1, filed January 12, 2012 (Doe. 1). See id. ¶ 5 , at 2. The Plaintiffs did not move to remand the case to state court, and—after several rounds of amended pleadings and motions to dismiss—they filed the current iteration of their Complaint in August, 2013. See Complaint ¶ 8, at 3 (conceding that the Court has subject-matter jurisdiction over the ease pursuant to CAFA). The Plaintiffs allege that they are non-cost bearing owners of oil and gas leases—landowners who leased their land to oil companies in exchange for a cut of any proceeds from hydrocarbons drilled out of the land—and that the Defendants are working interest owners—oil companies that drill on the Plaintiffs’ land, and pay the Plaintiffs an amount based on the profitability of the land. See Complaint ¶¶ 912. They seek to obtain class status under rule 23 to represent “themselves and ... all other owners of ‘non-cost bearing interests in the [class] wells.’” Complaint ¶ 13, at 6.
3. The Plaintiffs allege that the proposed class members, or their predecessors, acquired their interests in the hydrocarbon revenues from the subject wells through executing oil-and-gas mining leases or permits with the Defendants. See Complaint ¶ 11, at 4. The Plaintiffs assert that, under the leases, the Defendants owe the Plaintiffs a “duty to pay royalties on all hydrocarbons” for the value or price which the Defendants do or should receive from the “arm’s length” sale of the hydrocarbons. Complaint ¶ 12, at 5. The Plaintiffs argue that the leases give them a right to royalties in the “drip condensate,” a liquid product which is recovered during the Defendants’ oil and gas mining processes. Complaint ¶28, at 12-13. The Plaintiffs assert that the leases do not provide that the Defendants may calculate the Plaintiffs’ royalty payments using the average sale price of a mixture of hydrocarbons from wells in which the Plaintiffs own a royalty interest and other wells in which the Plaintiffs do not own royalty interests. See Complaint ¶ 12, at 5-6.
4. The Plaintiffs initially alleged numerous claims, but, after two partially successful motions to dismiss, see MO, 952 F.Supp.2d 979 ; MOO, 27 F.Supp.3d 1188 , only six causes of action remain: (i) the first cause of action, “failure to pay royalty on volumes of hydrocarbons, including drip condensate,” Complaint ¶¶ 22-30, at 10-13 (capitalization altered for readability); (ii) the second cause of action, “breach of the duty of good faith and fair dealing,” Complaint ¶¶ 31-42, at 14-17 (capitalization altered for readability); (iii) the fourth cause of action, violation of the NMPPA and “interest due under Colorado law,” Complaint ¶¶ 56-61, at 20-21 (capitalization altered for readability); (iv) the fifth cause of action, “bad faith breach of contract,” Complaint ¶¶ 62-66, at 21-22 (capitalization altered for readability); (v) the sixth cause of action, a claim for declaratory relief, see Complaint ¶¶ 67-70(b), at 22-23; (vi) the eleventh cause of action, “breach of the duty to market hydrocarbons—Colorado,” Complaint ¶¶ 98-101, at 30-31 (capitalization altered for readability).
b. The Answer.
5. The Defendants answered the Complaint after all briefing on the Motion was completed and the Court had already held the class certification hearing. See WPX Energy’s Answer to Plaintiffs’ Fourth Amended Complaint, filed June 16, 2014 (Doc. 249)(“Answer”). The Defendants deny almost all of the Plaintiffs’ allegations, see Answer ¶¶ 1-105, at 1-11, with the exception of a few background facts such as “that the named Plaintiffs own royalty and/or overriding royalty interests in leases on which WPX has drilled, operated and/or produced wells,” Answer ¶23, at 5. The Defendants admit “that the putative class, as defined by Plaintiffs, contains more than 1,000 members.” Answer ¶ 14, at 4.
6. The Defendants also assert thirty-five affirmative defenses. See Answer ¶¶ 1-35, at 11-13. First among them are two defenses, “failure to state a claim upon which relief can be granted,” Answer ¶ 1, at 11, and “statute *354 of limitations or the corresponding equitable doctrine of laches,” Answer ¶ 2, at 11, on which the Court has already ruled in some fashion. The Court has ruled on all arguments for failure to state a claim in two prior motions under rale 12(b)(6), resulting in the dismissal of several claims not listed here. See MO at 1060; MOO at 1250 . The Court also declined to dismiss any claim, in whole or in part, 29 on limitations grounds, because the Plaintiffs present a plausible claim that the discovery rale delayed the accrual of the statute. See MOO at 1227-28 ; id. at 1232-41 . The Court made clear, however, that the Plaintiffs carry the burden of establishing the applicability of the discovery rule at trial, and, thus, the Defendants’ time bar defenses remain viable. See MOO at 1238-39 .
7. The other defenses that the Defendants plead are: (i) that “[a]ll or part of Plaintiffs’ claims are barred by Plaintiffs’ own breach of contract or breach of their coxTesponding duty of good faith and fair dealing,” Answer ¶ 3, at 11; (ii) waiver doctrine, see Answer ¶ 4, at 11; (iii) estoppel, see Answer ¶ 5, at 11; (iv) that the express tex’ms of the contract control and bar all claims, see Answer ¶ 6, at 11; (v) that the Plaintiffs “acquiesce[d] in a continuous course of dealing, industry custom and pi’ac-tice and/or usage of trade,” Answer ¶ 7, at 12; (vi) that Plaintiffs were unjustly enx’iched by royalty overpayments, see Answer ¶ 8, at 12; (vii) that the Defendants are entitled to recoup royalty overpayments, see Answer ¶ 9, at 12; (viii) that the Defendants are entitled to a set-off against future payments, and presumably against any damages awarded against them, on the basis of past royalty overpayments, see Answer ¶ 10, at 12; (ix) accoi’d and satisfaction, see Answer ¶ 11, at 12; (x) collateral estoppel and/or res judicata, see Answer ¶ 12, at 12; (xi) that the Plaintiffs failed to meet conditions precedent of their leases, see Answer ¶ 13, at 12; (xii) election of remedies, see Answer ¶ 14, at 12; (xiii) that the Plaintiffs failed to fully perform under the leases, see Answer ¶ 15, at 12; (xiv) the impossibility doctx-ine, see Answer ¶ 16, at 12; (xv) that the Plaintiffs “are improper party plaintiffs,” Answer ¶ 17, at 12; (xvi) that the Plaintiffs lacked authority, see Answer 1118, at 12; (xvii) that the Plaintiffs lacked capacity, see Answer ¶ 19, at 12; (xviii) failure of eonsidei’ation, see Answer ¶ 20, at 12; (xix) lack of standing, see Answer ¶ 21, at 12; (xx) misrepresentation and/or fraud, see Answer ¶ 22, at 13; (xxi) lack of mutual consent, see Answer ¶ 23, at 13; (xxii) mistake, see Answer ¶ 24, at 13; (xxiii) “failure to name and/or join necessary and/or dispensable parties,” Answer ¶ 25, at 13; (xxiv) novation, see Answer ¶ 26, at 13; (xxv) payment, see Answer ¶ 27, at 13; (xxvi) “prior bx-each and/or abandonment,” Answer ¶ 28, at 13; (xxvii) ratification, see Answer ¶ 29, at 13; (xxviii) release, see Answer ¶ 30, at 13; (xxix) statute of frauds, see Answer ¶ 31, at 13; (xxx) unclean

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Source: Frix Law Library, https://www.frixlaw.com/law-library/cases/8772804. Public record. Not legal advice.