W.W. McDonald Land Co. v. EQT Production Co.

MEMORANDUM OPINION & ORDER JOSEPH R. GOODWIN, District Judge. Pending before the court are the Plaintiffs’ Motion for Partial Summary Judgment [Docket 131], and multiple motions for summary judgment filed by the defendants [Dockets 133, 143, and 169]. For the reasons stated below, the following is ORDERED: With respect to Count II (breach of contract), the Plaintiffs’ Motion [795] for Partial Summary Judgment [Docket 181] is GRANTED in part and DENIED in part in accordance with this opinion; the Defendants’ Joint Motion for Summary Judgment [Docket 169] is GRANTED in part and DENIED in part in accordance with this opinion; and the Motion for Summary Judgment of Defendants EQT Corporation, EQT Energy, LLC, EQT Gathering, Inc., EQT Gathering Equity, LLC, EQT Investment Holdings, LLC, and EQT Gathering, LLC [Docket 133] is DENIED. With respect to Count III (breach of fiduciary duty) the defendants’ motions [Docket 133 and 143] are GRANTED. With respect to Count I (failure to account), Count IV (fraud), Count V (negligent misrepresentation), Count VI (civil conspiracy/] oint venture), Count VII (aiding and abetting a tort), and Count VIII (punitive damages), the defendants’ motions [Dockets 133,143, and 169] are DENIED. I. Background This case arises out of a dispute over royalty payments related to fourteen oil and gas well leases. The plaintiffs are owners of land subject to those leases. The plaintiffs contend that Estate of Tawney v. Columbia Natural Resources, LLC, 219 W.Va. 266, 633 S.E.2d 22 (2006), prohibits the defendants from deducting “post-production” costs from royalty payments. These costs include monetary expenses incurred by the defendants to transport and market the gas after production. Additionally, the plaintiffs contend that their royalties should be calculated based on the gas volume produced at the wellhead, not the smaller volume that is sold at an interstate pipeline connection.1 The undisputed facts are as follows. EQT Production purchased the leases in February 2000. Between February 2000 and January 1, 2005, EQT Production produced gas from the leased wells and transported it to an interstate pipeline connection where it was marketed to third parties. During this period, EQT Production paid the costs of transporting and marketing the gas. EQT Production passed some of these monetary costs on to the plaintiffs by charging them a flat rate per unit of gas. The parties dispute the particular rate that was charged. EQT Production also subtracted from the plaintiffs’ royalty what the plaintiffs call “volumetric deductions.” Essentially, EQT Production paid a royalty based on the volume of gas sold at the interstate pipeline connection, rather than the volume of gas produced at the wellhead. On January 1, 2005, EQT Production reorganized into separate entities, including EQT Gathering, Inc., EQT Gathering Equity, LLC, and EQT Gathering, LLC (collectively “EQT Gathering”), EQT Energy, LLC (“EQT Energy”), and EQT Corporation. EQT Production is a subsidiary of EQT Corporation. EQT Production is the only entity that is a party to the leases at issue. EQT Production sells the gas at the wellhead2 to EQT Energy. EQT Energy contracts with EQT Gathering to collect the gas and move it to the interstate pipeline connection, where EQT Energy sells the gas to third parties. EQT Production argues that since the 2005 reorganization, it has not deducted post-production monetary costs from royalties paid to lessors. Instead, it pays royalties based on the price it receives from EQT Energy. That price is a well [796] head price where gas is valued “at the wellhead at an index price less gathering charges and retainage.... ” (Mem. in Supp. of Defs.’ Joint Mot. for Summ. J. [Docket 170], at 5). The plaintiffs bring several counts collectively against the defendants: (I) failure to properly account for royalties, (II) breach of contract, (III) breach of fiduciary duties, (IV) fraud, (V) negligent “misrepresentation/coneealment,” (VI) “civil conspiracy/joint venture,” (VII) aiding and abetting a tort, and (VIII) “punitive damages.” (Am. Compl. [Docket 34], at 10-15). The plaintiffs move for summary judgment [Docket 131] on their breach of contract claim only. The defendants move for summary judgment in three separate motions. EQT Production moves for summary judgment on Counts III-VII [Docket 143]. The remaining defendants, EQT Corporation, EQT Energy, EQT Gathering, LLC, EQT Gathering, Inc., EQT Gathering Equity, LLC, and EQT Investment Holdings, move for summary judgment on all counts [Docket 133]. Finally, the defendants jointly move for summary judgment on all counts [Docket 169]. II. Legal Standard To obtain summary judgment, the moving party must show that there is no genuine issue as to any material fact and that the moving party is entitled to judgment as a matter of law. Fed.R.Civ.P. 56(a). In considering a motion for summary judgment, the court will not “weigh the evidence and determine the truth of the matter.” Anderson v. Liberty Lobby, Inc., 477 U.S. 242, 249, 106 S.Ct. 2505, 91 L.Ed.2d 202 (1986). Instead, the court will draw any permissible inference from the underlying facts in the light most favorable to the nonmoving party. Matsushita Elec. Indus. Co. v. Zenith Radio Corp., 475 U.S. 574, 587-88,106 S.Ct. 1348, 89 L.Ed.2d 538 (1986). Although the court will view all underlying facts and inferences in the light most favorable to the nonmoving party, the non-moving party nonetheless must offer some “concrete evidence from which a reasonable juror could return a verdict in his [or her] favor.” Anderson, 477 U.S. at 256, 106 S.Ct. 2505. Summary judgment is appropriate when the nonmoving party has the burden of proof on an essential element of his or her case and does not make, after adequate time for discovery, a showing sufficient to establish that element. Celotex Corp. v. Catrett, 477 U.S. 317, 322-23, 106 S.Ct. 2548, 91 L.Ed.2d 265 (1986). The nonmoving party must satisfy this burden of proof by offering more than a mere “scintilla of evidence” in support of his or her position. Anderson, 477 U.S. at 252, 106 S.Ct. 2505. Likewise, conclusory allegations or unsupported speculation, without more, are insufficient to preclude the granting of a summary judgment motion. See Felty v. Graves-Humphreys Co., 818 F.2d 1126, 1128 (4th Cir.1987); Ross v. Comm’ns Satellite Corp., 759 F.2d 355, 365 (4th Cir.1985), abrogated on other grounds, Price Waterhouse v. Hopkins, 490 U.S. 228, 109 S.Ct. 1775, 104 L.Ed.2d 268 (1989). III. Discussion A. Breach of Contract Both the plaintiffs and defendants move for summary judgment on Count II, the breach of contract claim. The plaintiffs argue that the language of the individual leases, interpreted pursuant to Estate of Tawney v. Columbia Natural Resources, LLC, 219 W.Va. 266, 633 S.E.2d 22 (2006), prohibits EQT Production from taking any post-production monetary deductions or “volume deductions” from royalty payments. [797] To understand the plaintiffs’ argument — and to resolve this case — it is necessary to survey relevant West Virginia gas law to the present. Early cases demonstrate that the duties of lessees go beyond merely paying the costs of production. Lessees must bear some portion of post-production expenses as well. The two most recent cases I survey, Wellman v. Energy Resources, Inc., 210 W.Va. 200, 557 S.E.2d 254 (2001), and Tawney, clarify this duty and demonstrate that lessees impliedly covenant to bear all post-production costs incurred in delivering the gas to market. In Kanawha Valley Bank v. United Fuel Gas Co., the Supreme Court of Appeals held that the lessee may not deduct production taxes from a royalty. See 121 W.Va. 96, 1 S.E.2d 875, 876 (1939). At dispute were royalty provisions very similar to those in this case. The lease obligated United Fuel Gas Co. (“United Fuel”) to pay a royalty “at the rate of one-eighth of the wholesale market value thereof at the well.” Id. However, United Fuel deducted from the plaintiffs royalty a one-eighth portion of state production taxes. Id. The plaintiff sued to recover the amounts withheld. Id. Looking to the language of the lease, the court found for the plaintiff. Id. The court stated that the lessee had “bound itself to pay the lessor a full one-eighth of the market price of gas at the well — not such price less one-eighth of the production tax.” Id. In 1962, the Supreme Court of Appeals held that a proceeds lease required United Fuel to pay a royalty based on the price it received from customers, free of post-production costs. See Cotiga Development Co. v. United Fuel Gas Co., 147 W.Va. 484, 128 S.E.2d 626, 630, 631-35 (1962). The royalty provision in Cotiga required United Fuel “to pay for one-eighth ... of the gas produced ... at the rate received by the Lessee for such gas____” Id. at 630. United Fuel, a public utility that delivered gas directly to consumers, paid royalties based on the wellhead market price of the gas. Id. at 633. United Fuel argued the wellhead price, not the ultimate price received, must have been the intention of the parties because the original lessee, Woods Oil and Gas Company, was not a public utility. Id. The plaintiffs, however, asserted that the lease required that royalties be calculated from the price received by United Fuel for the gas at the final point of sale. Id. at 632. The court agreed with the plaintiffs and found that the lease provisions unambiguously required United Fuel to pay a royalty based on the price it received at the end point of sale. Id. at 633. As the plaintiffs in the instant case point out, the price at the end of point sale was significantly higher than the wellhead price. This price difference was attributable to the post-production costs incurred by United Fuel delivering the gas from the wellhead to customers as a public utility. See id. at 634. Nonetheless, United Fuel was not permitted to factor those costs into royalty payments. In 1992, the United States Court of Appeals for the Fourth Circuit required a lessee to pay royalties based on the market price of gas, even though it received a lower, fixed contract price as payment for the gas. The royalty clause required the lessee to pay one-eighth of the “current wholesale market value at the well for all gas produced.” Imperial Colliery Co. v. OXY USA Inc., 912 F.2d 696, 699 (4th Cir.1990). The lessee, OXY USA, Inc. (“Oxy”), collected gas from fourteen of Imperial Colliery Co.’s (“Imperial”) wells, co-mingled it with gas from other wells, and transported it in a twelve-mile pipeline to the buyer, Equitable Gas Co. (“Equitable”). Id. at 699. Oxy sold the gas to Equitable at a fixed contract price of 32.74 [798] cents per one thousand cubic feet. (Mem. of Law in Supp. of Pis.’ Mot. for Partial Summ. J. [Docket 132], at ll).3 Oxy paid royalties on the proceeds it received from Equitable under this contract price, less costs for transportation, compression, and handling. (Id.). During the relevant period, the market value for the gas rose dramatically, even though Oxy continued to receive a fixed contract price for the gas and pay a royalty on this fixed contract price. (Id.). Imperial sued to force Oxy to pay royalties based on the higher market price of the gas, not the fixed contract price received from Equitable. Applying West Virginia law, the district court and the Fourth Circuit agreed with Imperial that Oxy should pay royalties based on the market price of the gas, which was calculated “by ascertaining the price that a willing buyer would pay a willing seller in a free market....” Imperial Colliery, 912 F.2d at 701. There is no indication from the court’s opinion in Imperial Colliery that deductions were allowed for post-production costs. Kanawha Valley Bank, Cotiga, and Imperial Colliery make plain that lessees operate under an implied duty to pay some post-production costs. However, these cases do not clarify the boundaries of this duty. The next two cases, Wellman and Tawney, specify that lessees impliedly covenant to bear all post-production costs incurred in bringing the gas to market. In Wellman, royalties under the leases were one-eighth “of the market value of such gas at the mouth of the well,” or if the gas was sold by the lessee, one-eighth “of the proceeds from the sale of gas as such at the mouth of the well.” 557 S.E.2d at 258. Lessee Energy Resources, Inc. sold the gas at $2.22 per one thousand cubic feet. Id. Rather than pay a one-eighth royalty based on that price, however, Energy Resources deducted post-production expenses to arrive at a sale price of $0.87, on which it then paid a royalty to the lessor plaintiffs. Id. The post-production expenses Energy Resources deducted included the cost of transporting the gas from the wellhead to a point of sale and the cost of treating the gas to bring it to marketable condition. See id. at 264. The court first recognized that “a distinguishing characteristic of such a [gas or oil] royalty interest is that it is not chargeable with any of the costs of discovery or production.” Id. at 263-64 (citing Davis v. Hardman, 148 W.Va. 82, 133 S.E.2d 77 (1963)). The court continued: In spite of this, there has been an attempt on the part of oil and gas producers in recent years to charge the landowner with a pro rata share of various expenses connected with the operation of an oil and gas lease .... To escape the rule that the lessee must pay the costs of discovery and production, these expenses have been referred to as “post-production expenses.” Id. at 264. After reviewing relevant decisions in other states, the court stated that “West Virginia holds that a lessee impliedly covenants that he will market oil or gas produced.... It, therefore, reasonably should follow that the lessee should bear the costs associated with marketing products produced under a lease.” Id. at 265. The court then held that “if an oil and gas lease provides for a royalty based on proceeds received by the lessee, unless the lease provides otherwise, the lessee must bear all costs incurred in exploring for, producing, marketing, and transporting [799] the product to the point of sale.” Id. Further, if a lease did in fact provide for the deduction of post-production costs, the lessee could deduct those costs “to the extent that they were actually incurred and they were reasonable.” Id. Because Energy Resources did not proffer evidence showing that its deductions were actually incurred or reasonable, the court did not allow post-production costs to be deducted from royalties. See id. at 265. Wellman accordingly stands for the proposition that unless a lease “provides otherwise,” lessees may not deduct post-production costs before calculating royalties. The court in Tawney took up the next question: how can a lease “provide otherwise”? That is, what lease language is necessary before a lessee may deduct post-production costs from royalties? In Tawney, a class of owners of oil and gas wells brought an action against Columbia Natural Resources (“CNR”) seeking damages for insufficient royalty payments. See 633 S.E.2d at 25. For more than a decade, CNR had deducted post-production expenses from the plaintiffs’ royalties. Id. These post-production costs included “both monetary and volume deductions.” Id. Monetary deductions included costs for transporting and processing the gas. Id. “Volume deductions” included the “losses of volume of gas due to leaks in the gathering system or other volume loss .... ” Id. The court in Tawney addressed only the following certified question: In light of the fact that West Virginia recognizes that a lessee to an oil and gas lease must bear all costs incurred in marketing and transporting the product to the point of sale unless the oil and gas lease provides otherwise, is lease language that provides that the lessor’s 1/8 royalty is to be calculated “at the well,” “at the wellhead” or similar language, or that the royalty is “an amount equal to 1/8 of the price, net of all costs beyond the wellhead,” or “less all taxes, assessments, and adjustments” sufficient to indicate that the lessee may deduct post-production expenses from the lessor’s 1/8 royalty, presuming that such expenses are reasonable and actually incurred. Id. at 24-25. The court held that the “at the wellhead”-type language was ambiguous because it did not indicate “how or by what method the royalty is to be calculated or the gas is to be valued.” Id. at 28. Further, the phrase “less all taxes, assessments, and adjustments,” was ambiguous •without additional language clarifying “what the parties intended.” Id. at 29. The court construed the wellhead-type language against CNR and provided the framework under which lessees can deduct post-production costs from royalties. Id. at 29-30. The court held that “language in an oil and gas lease that is intended to allocate between the lessor and lessee the costs of marketing the product and transporting it to the point of sale must” meet certain specificity standards. Id. at 30. First, the language must “expressly provide that the lessor shall bear some part of the costs incurred between the wellhead and the point of sale[.]” Id. Second, the language must “identify with particularity the specific deductions the lessee intends to take from the lessor’s royalty!.]” Id. Finally, the language must “indicate the method of calculating the amount to be deducted from the royalty for such post-production costs.” Id. 1. The Duty to Market Under Tawney and Wellman After Tawney, it was unclear whether lessees are required to bear post-production costs until the “point of sale,” [800] wherever that may be, or until the market. This is an important distinction. The market, as the parties stipulated at oral argument, is the first place downstream of the well where the gas can be sold to any willing buyer and title passed to that buyer. (See Tr. 11/4/2013, [Docket 211], 6:24-7:2, 31:1-9); cf. Imperial Colliery Co. v. Oxy USA Inc., 912 F.2d 696, 701 (4th Cir.1990) (“market value is computed by ascertaining the price that a willing buyer would pay a willing seller in a free market____”). But a point of sale may be at the wellhead (upstream from the market) or at a burner tip (downstream from the market). Therefore, determining the point until which lessees must bear post-production costs is crucial. The only support for the argument that the duty extends to the point of sale derives from syllabus point language in Tawney and Wellman. See Syl. Pt. 10, Tawney, 633 S.E.2d 22 (“Language in an oil and gas lease that is intended to allocate between the lessor and lessee the costs of marketing the product and transporting it to the point of sale must expressly provide that the lessor shall bear some part of the costs incurred between the wellhead and the point of sale....” (emphasis added)); Syl. Pt. 4, Wellman, 557 S.E.2d 254 (“If an oil and gas lease provides for a royalty based on proceeds received by the lessee, unless the lease provides otherwise, the lessee must bear all costs incurred in exploring for, producing, marketing, and transporting the product to the point of sale.” (emphasis added)). Conversely, when Tawney and Wellman are read in their entirety, it becomes clear that lessees must bear the costs of bringing gas to the market, not to a point of sale. First, the facts in Tawney support the existence of a duty to bear the costs of bringing gas to market, rather than to the point of sale. Tawney addressed only a specific set of costs — the costs of delivering gas to the Columbia Gas Transmission (“TCO”) line. Tawney, 633 S.E.2d at 25. At the TCO line, gas is commoditized and bought and sold by third parties. The TCO line is therefore a market. Thus, Tawney’s holdings are related to the duty to get the gas to market, not to a point of sale. Because there were 2,258 separate leases at issue in Tawney, it is almost certain that points of sale varied between the leases. In fact, the court stated that the leases were “of varying forms and types.” Id. It would have been impossible for the court to address CNR’s duties with respect to different points of sale for each lease unless the court addressed costs generally. But the Tawney court did not address costs generally. Rather, it addressed only the costs of delivering gas to one particular point in the stream of commerce — the TCO line. The only way to reconcile Tawney’s facts- — only the costs of bringing the gas to market were at issue— with the “point of sale” language in Tawney’s syllabus points is to assume that Tawney applies to the costs incurred in bringing the gas to market, not to a point of sale. Second, both Tawney and Wellman are premised on the implied duty to market gas produced: The rationale for holding that a lessee may not charge a lessor for “post-production” expenses appears to be most often predicated on the idea that the lessee not only has a right under an oil and gas lease to produce oil or gas, but he also has a duty, either express, or under an implied covenant, to market the oil or gas produced. The rationale proceeds to hold the duty to market embraces the responsibility to get the oil or gas in marketable condition and actually transport it to market. [801] Tawney, 633 S.E.2d at 27 (emphasis added) (quoting Wellman, 557 S.E.2d at 264). The court in Wellman explained that West Virginia law “holds that a lessee impliedly covenants that he will market oil or gas produced.” 557 S.E.2d at 265. The court continued that “historically the lessee has had to bear the cost of complying with his covenants under the lease. It, therefore, reasonably should follow that the lessee should bear the costs associated with marketing products produced under a lease.” Id. The court explained in both the Tawney and Wellman that its decisions were predicated on the “duty, either express, or under an implied covenant, to.market the oil or gas produced.” Tawney, 633 S.E.2d at 27 (quoting Wellman, 557 S.E.2d at 264). Tawney and Wellman both cite Professor Robert T. Donley’s seminal treatise, which also discusses an implied duty to market gas produced: From the very beginning of the oil and gas industry it has been the practice to compensate the landowner by selling the oil and by running'it to a common carrier and paying to him one-eighth of the sale price received. This practice has, in recent years, been extended to situations where gas is found.... In the absence of an express covenant to market either oil or gas, the court implies one in order to effectuate the basic purpose of the lease.... Robert T. Donley, Law of Coal, Oil and Gas in West Virginia and Virginia § 104 (1951) (emphasis added). By basing the Wellman and Tawney decisions on the implied covenant to market, the Supreme Court of Appeals indicated that it was adopting a version of the “marketable product” rule. See 3 Eugene Kuntz, Law of Oil and Gas § 40.5 (Lexis 2013) (The Wellman decision “rel[ied] on the implied covenant to market [and] adopted a marketable product rule----”); Owen L. Anderson, Rogers, Wellman, and the New Implied Marketplace Covenant, 2003-1 Rocky Mtn. Min. L. Inst. 13A (2003) (“Wellman take[s] the view that royalty is owed on the value added by transportation incurred to move gas to a first market unless the lease expressly provides otherwise.”); cf. Appalachian Land Co. v. EQT Production Co., CIV. A. 7:08-139-KKC, 2012 WL 523749 (E.D.Ky. Feb. 16, 2012) (deciding whether Kentucky follows the marketable product rule or the “at-the-well” rule, and citing Taumey to show that West Virginia does not follow the “at-the-well” rule). Under the' marketable product rule, lessees impliedly covenant to bear the costs of getting gas into marketable condition and transporting it to market. See 5 Howard R. Williams and Charles J.- Meyers, Oil and Gas Law § 853, p. 396.3 (2012) (“[T]he implied covenant to market as a prudent operator includes an implied duty to prepare the natural gas for a market and even to transport the gas to a commercial market.”); Owen L. Anderson, Royalty Valuation: Should Royalty Obligations Be Determined Intrinsically, Theoretically, or Realistically? (Part 2), 37 Nat. Resources J. 611, 634 (1997) (implying that the marketable product rule requires lessees to bring gas to marketable condition and marketable location). Other cases applying versions of the marketable product rule hold the same. See, e.g., Rogers v. Westerman Farm Co., 29 P.3d 887, 906 (Colo.2001) (“Absent express lease provisions addressing allocation of costs, the lessee’s duty to market requires that the lessee bear the expenses incurred in obtaining a marketable product. Thus, the expense of getting the product to a marketable condition and location are borne by the lessee.”); TXO Prod. Corp. v. State ex rel. Comm’rs of Land Office, 903 P.2d 259, 262-63 (Okla.1994) (holding that post-production costs of compression, dehydration, [802] and gathering were not deductible from royalties because these costs were necessary to deliver the gas into a pipeline). Tawney and Wellman’s reliance on the implied duty to market gas, as well Tourney’s focus on the costs of bringing gas to market, convinces me that lessees have a duty to bear all costs incurred until the gas reaches market, not to a point of sale. I therefore FIND that lessees have an implied duty to bear all post-production costs incurred until the gas reaches the market, which is the first place downstream of the well where the gas can be sold to any willing buyer and title passed to that buyer.4 2. Royalties for Unsold Gas The parties differ whether Tourney’s heightened specificity requirements obligate lessees to pay royalties on unsold gas. According to the plaintiffs, “the Tawney prohibition against deductions for ‘post-production’ expenses specifically included both monetary expenses and volumetric losses.” (Mem. of Law in Supp. of Pis.’ Mot. for Partial Summ. J. [Docket 132], at 15). The plaintiffs would have lessees pay royalties on volumes of gas produced, not the smaller volume that is actually sold at the interstate pipeline connection. Essentially, the plaintiffs believe that Tawney obligates lessees to pay royalties on gas that is never sold. I disagree. First, Tawney’s heightened specificity requirements clearly apply to “the costs of marketing the product and transporting it to the point of sale.” Syl. Pt. 10, Tawney, 633 S.E.2d 22. Syllabus Point 10 is written in terms of monetary costs only, as the plaintiffs conceded at oral argument. (See Tr. 11/4/2013,, [Docket 211], 8:17-18). Therefore, volume losses are not part of the court’s holding. Second, and most significantly, requiring lessees to pay royalties on unsold gas is illogical and inequitable. Volume losses are not “deductions” of costs in the same sense as marketing or transportation costs. A deduction is the “act or process of subtracting or taking away.” Black’s Law Dictionary 475 (9th ed.2009); see also Webster’s Third New International Dictionary 589 (2002) (“an act of taking away”). Therefore, in order to have a deduction, there must be a starting value from which you take the deduction. Under Wellman and Tourney, the lessee has a general duty to market the gas produced, under which the lessee must bear all costs incurred in converting the product to a marketable condition and bringing it to a market. See Syl. Pt. 4, Wellman, 557 S.E.2d 254; Syl. Pt. 1, Tawney, 633 S.E.2d 22. The lessee does not receive payment for lost and unaccounted for gas that is not delivered to the market. Rather, the lessee receives payment only for gas that is actually sold. Therefore, when the lessee pays a royalty on those proceeds, there is nothing to deduct; the lessee was never paid for undelivered volumes of gas. Volume losses are not costs that are deducted from a royalty, unlike the monetary deductions that concerned the Wellman and Tawney courts. Under the plaintiffs’ interpretation of Tawney, lessees would be required to pay a royalty based on the value of gas at one point in the stream of commerce — the market — but on a volume of gas at an earlier point in the stream of commerce— the wellhead. To illustrate this point, assume a wellhead produced 1,000 cubic feet of gas, where it is worth $1.00 per cubic foot. The lessee then gathers the gas, [803] markets it, and delivers it to an interstate pipeline where it is now worth $3.00 per cubic foot. When the gas arrives at the pipeline, however, only 900 cubic feet of gas remain. Various volume losses contributed to the reduction of the gas volume by 100 cubic feet. Although only 900 cubic feet of gas reach the interstate pipeline and are sold, the plaintiffs would have lessees pay a one-eighth royalty at the market price on the entire 1,000 cubic feet that left the wellhead. The plaintiffs want to have their cake and eat it too. They seek a royalty based on the unit value of gas at market, to which they are generally entitled under Tawney, but they want this royalty to be paid based on the volume at the wellhead, where gas is considerably less valuable. Meanwhile, the lessee received no payment for the lost, unsold gas. Had the court in Tawney intended such a perverse result, it would have said so. Finally, other courts considering this question agree that royalties need not be paid on unsold gas. See, e.g., Amoco Prod. Co. v. Andrus, 527 F.Supp. 790, 794 (E.D.La.1981) (where Department of Interior administered leases on the Outer Continental Shelf, holding that the Department could not require payment of royalties for oil and gas flared, vented, used, or unavoidably lost); Marathon Oil Co. v. Andrus, 452 F.Supp. 548, 553 (D.Wyo.1978) (invalidating as arbitrary and capricious ruling by Secretary of Interior to require payment of royalties on unavoidably lost or used gas on onshore leases); Dynegy Midstream Sers., Ltd. P’ship v. Apache Corp., 294 S.W.3d 164, 168-69 (Tex.2009) (under “unambiguous” gas sale contract, gas processor had no obligation to pay gas producer for gas lost between the wellhead and the processor’s plant). Therefore, lessees have no general duty to pay for lost volumes. The plaintiffs may, understandably, be concerned about lessees losing large volumes of gas and therefore paying out smaller royalties. However, lessees have a duty to act as ordinarily prudent operators. Jennings v. S. Carbon Co., 73 W.Va. 215, 80 S.E. 368, 370 (1913); Grass v. Big Creek Dev. Co., 75 W.Va. 719, 84 S.E. 750, 754 (1915) (The duty is “that degree of diligence reasonably and ordinarily exercised by prudent operators engaged in the same line of business under the same or similar circumstances and conditions, keeping in view the covenants of the lease and the mutual benefit and advantage of the parties to the contract[.]”). Therefore, if the plaintiffs believe that the lessees are negligently losing gas between the wellhead and the market, the plaintiffs may sue to recover damages for unpaid royalties on that gas. Cf.id. In sum, the state of the law in West Virginia regarding royalty payments on gas leases is as follows. West Virginia recognizes an implied duty on the part of producers to market the gas produced. See Tawney, 633 S.E.2d at 27 (Lessees have a duty “to market the oil or gas produced.” (citing Wellman, 557 S.E.2d 254, 264)). This obligation to market gas “embraces the responsibility to get the oil or gas in marketable condition and actually transport it to market.” Id. The market is the first place downstream of the well where the gas can be sold to any willing buyer and title passed to that buyer. Unless a lease provides otherwise, lessees must deliver the gas to the market, , in a marketable condition, free of all costs of production. The costs of production include any “post-production” costs incurred to market the gas. In order to deduct any post-production costs from royalties, leases must adhere to the specificity requirements set out in Tawney. Finally, Tawney’s heightened specificity requirements [804] do not obligate lessees to pay royalties on lost volumes. 3. Tawney Applies Retroactively The defendants argue that Tawney’s heightened specificity requirements should not apply to their leases because they were executed decades before Tawney was decided. This retroactivity argument is without merit. “As a general rule, judicial decisions are retroactive in the sense that they apply both to the parties in the case before the court and to all other parties in pending cases.” Caperton v. AT Massey Coal Co., 225 W.Va. 128, 690 S.E.2d 322, 350 (2009). There are exceptions to this general rule, but they do not apply here. If the Supreme Court of Appeals intended Tawney to apply prospectively only, it could have said so. Instead, Tawney’s holding applied to the parties in that case — a class of approximately 8,000 plaintiffs holding 2,258 leases — -and to leases executed and conduct occurring more than a decade before the decision was announced. See Tawney, 633 S.E.2d at 25. 4. The Defendants Cannot Avoid Tawney by Using a “Work-back” Method Finally, the defendants argue that Tawney is inapplicable because EQT Production sells gas at the wellhead and, since 2005, has taken no monetary deductions from royalties. However, EQT Production sells the gas at the wellhead to EQT Energy, a sister company. The defendants cannot calculate royalties based on a sale between subsidiaries at the wellhead when the defendants later sell the gas in an open market at a higher price. Otherwise, gas producers could always reduce royalties by spinning off portions of their business and making nominal sales at the wellhead. I predict with confidence that, if confronted with this issue, the Supreme Court of Appeals would hold the same. See Howell v. Texaco, Inc., 112 P.3d 1154 (Okla.2004) (“an intra-company contract is not an arm’s length transaction, [and] it is not a legal basis on which [a producer] can calculate royalty payments”); Beer v. XTO Energy, Inc., CIV-07-798-L, 2010 WL 476715 (W-D.Okla. Feb. 5, 2010) (gas sale at wellhead between two controlled, affiliated companies not appropriate for royalty calculation). Further, in order to determine a wellhead price at which EQT Production sells gas to EQT Energy, defendants essentially admit they continue to deduct post-production expenses. To determine the wellhead price, the defendants use a “work-back method” which “involves subtracting post-production costs that enhance the value of the gas from the interstate connection price.” (Mem. in Supp. of Defs.’ Joint Mot. for Summ. J. [Docket 170], at 25). Absent lease language to the contrary, Tawney requires lessees to pay royalties free of these costs. The defendants cannot avoid Tawney by simply reorganizing their businesses and making intra-company wellhead sales. Accordingly, I FIND that Tawftey’s specificity requirements apply to royalty payments made under the defendants’ work-back method after 2005. 5.Individual Lease Analysis With the general legal framework set out above, I now turn to the fourteen leases at issue in the parties’ motions to determine whether they permit the defendants to deduct monetary costs or require the defendants to pay for lost' volumes. For efficiency, I will group leases with similar royalty provisions together. My analysis is two-fold. First, I will determine if the leases permit deductions for monetary costs. Next ■ I will determine whether the leases permit deductions for volume losses incurred between the wellhead and the market. [805] a. Leases (a), (b), (c), (d), (e), (f), and (i)5 Leases (a), (b), (c), (d), (e), (f), and (i) contain the following royalty provisions: —Leases (a) through (e): To Pay Lessors, should a well be found producing gas only as full consideration for such gas well and its products, a royalty payable ... beginning with the date the gas is first marketed therefrom and continuing so long as gas is produced and marketed or used off the premises equal to l/8th of the wholesale market value thereof at the well as represented by the prevailing purchase price currently paid at the well by purchasers of gas at wholesale in the field in which the well is located. (Exhibit 1 [Docket 131-1], at 3-4; Exhibit 2 [Docket 131-2], at 3; Exhibit 3 [Docket 131-3], at 2-3; Exhibit 4 [Docket 131-4], at 2-3; Exhibit 5 [Docket 131-5], at 3-4) (emphasis added). —Lease (f): [S]hould a well be found producing gas only ... a royalty [is] payable [to the lessor] ... so long as gas is produced and marketed ... equal to one-eighth (1/8) of the wholesale market value thereof at the well as represented by the prevailing purchase price currently paid at the well by purchasers of gas at wholesale in the field in ivhich the well is located; but such payment to Lessor shall be not less than One and seven-eighths (1-7/8) Cents for each [Mcf] of gas produced and sold in any month. (Exhibit 7 [Docket 131-7], at 3) (emphasis added). —Lease (i): [The lessee will pay] for each gas well from the time and while the gas is marketed, at the rate of One-eighth (1/8) of the wholesale market value thereof at the well, which value for the purpose of this lease shall not be less than [15<f] per [Mcf], payable each three months. (Exhibit 6 [Docket 131-6], at 3) (emphasis added). The royalty language in these leases is similar to the “at-the-wellhead”-type language examined in Tourney. Also like Tourney, these leases do not “expressly provide that the lessor shall bear some part” of the post-production costs, “identify ... specific deductions the lessee intends to take from the lessor’s royalty” or “indicate the method of calculating the amount to be deducted from the royalty for ... post-production costs.” Tawney, 633 S.E.2d at 24. Thus, I FIND the language in leases (a), (b), (c), (d), (e), (f), and (i) is insufficient to allow the defendants to deduct post-production monetary costs from the plaintiffs’ royalties. It is a separate issue whether the defendants are entitled to take “volumetric deductions.” As I previously explained, Tourney’s heightened specificity requirements do not obligate lessees to pay royalties on lost volumes. Accordingly, I look only to the language in the leases. At first glance, the leases appear to require royalty payments based on the volume extracted at the wellhead, without reference to the volume that makes it to the market: royalties are one-eighth of the “wholesale market value” “at the well.” However, the leases are written in the context of gas being “produced” and “marketed.” This means that royalties should be paid only on the gas actually delivered to market, even if this volume is smaller than the volume recorded at the wellhead. Gas is produced when it is extracted from the wellhead, but it is not produced and marketed until it is delivered and sold at a [806] market. I therefore FIND that royalties for leases (a), (b), (c), (d), (e), (f), and (i) are payable only on the gas actually sold and marketed. b. Leases (g) and (h) Leases (g) and (h) are unique because their royalty provisions distinguish between gas sold at the well and gas sold elsewhere. —Lease (g): (1) If measured and sold at the well, [royalty shall be] an amount equal to one-eighth (l/8th) of the price received by the Lessee from the sale of such gas. (2) If not sold at the well, then at the time gas is first marketed from each well completed on the leased premises, the royalty price for such well shall be established as one-eighth (l/8th) of the wellhead price then being paid by Lessee to producers in the general producing area of the leased premises for like gas from the same geological formation. (Exhibit 8 [Docket 131-8], at 1-2) (emphasis added). —Lease (h): If measured and sold at the well, [royalty shall be] an amount equal to one-eighth (1/8) of the price received by the Lessee for the sale of such gas.... [I]f not sold at the well, ... [royalty shall be] one-eighth (1/8) of the wellhead price being paid by Lessee to producers in the general producing area of the leased premises for like gas from the same geological formation. (Exhibit 9 [Docket 131-9], at 3) (emphasis added). It appears that these leases intend for royalties to be paid based on a wellhead price — as opposed to a downstream price — for the gas. These leases could be read to require that if the gas is sold at the wellhead, then royalty is one-eighth of that price. If not sold at the wellhead, then royalty is one-eighth of the price of comparable gas sold at the wellhead. Even so, this language is not precise enough to meet the Tawney standards. The leases do not “expressly provide that the lessor shall bear some part of the costs incurred between the wellhead and the point of sale,” or “identify with particularity the specific deductions the lessee intends to take.... ” Tawney, 633 S.E.2d at 30. I therefore FIND the language in leases (g) and (h) is insufficient to allow the defendants to deduct post-production monetary costs from the plaintiffs’ royalties. With respect to volume losses, leases (g) and (h) are written in the context of gas being “marketed” and “sold.” Therefore, I FIND that leases (g) and (h) permit the lessees to pay a royalty based on the volume of gas actually sold at the market, c. Leases (k), (l), and (m) Leases (k), (l), and (m) each contemplate specific post-production cost deductions for compression, desulphurization, and transportation of gas. —Lease (k): Lessee shall pay to the Lessors the sum of [2<t] per [Mcf] of gas produced and marketed from the leased premises, and, in addition thereto, one-eighth (1/8) of the selling price in excess of [16$] per [Mcf] received by the Lessee for any such gas sold by it at a higher price than [16<t] per [Mcf]; provided, however, that if, in order to market such gas more advantageously it shall be necessary or desirable, in the judgment of the Lessee, to do any or all of the following, i.e., to compress or desulphurize such gas or to construct a pipeline or pipelines off the leased premises, then the Lessee may deduct from the price received by it for such gas in excess of [16<t] per [Mcfj of the actual cost of such compression, of such desulphurization and of such [807] transportation; and, provided further that the Lessors shall always receive, regardless of the selling price received by the Lessee, at least one-eighth (1/8) of the wholesale market price or value at the well of said gas, that is to say, the usual or prevailing wholesale market price paid for gas at the well at the time in the general locality of the leased premises, or in the same or nearest gas field, whichever is higher____ (Exhibit 11 [Docket 131-11], at 7-8) (emphasis added). —Lease (l): [Lessee shall pay] the sum of One and Seven-eighths Cents (1 — 7/8<t) for each [Mcf] of gas produced and marketed from the leased premises, and in addition thereto, one-eighth (1/8) of the selling price thereof in excess of Fifteen Cents (15(C) per [Mcf] received by Lessee for the gas produced by it at and sold at a higher price than Fifteen Cents (15$) per [Mcf]. The selling price for gas on which royalty is based is the price at the well. If the gas should be sold at some point other than at the well, then any selling price in excess of Fifteen Cents (15(C) per [Mcf] received by the Lessee shall be adjusted downward to reflect a reasonable charge for compressing, desulphurization and/or transporting gas from the well to the point of sale. (Exhibit 12 [131-12], at 9) (emphasis added). —Lease (m): Lessee shall pay for the gas produced, saved and marketed therefrom, from the time and while the gas is marketed, as royalty, the sum of One and Seven-eighths Cents (1 — 7/8<C) for each [Mcf] of gas produced and marketed from the consolidated leased premises, and in addition thereto, one-eighth (1/8) of the selling price thereof in excess of Fifteen Cents (15(f) per [Mcf] received by Lessee for the gas produced by it at and sold at a higher price than Fifteen Cents (15<c) per [Mcf]. The selling price for gas on which royalty is based is the price at the well. If the gas should be sold at some point other than at the well, then any selling price in excess of Fifteen Cents (15<c) per [Mcf] received by the Lessee shall be adjusted downward to reflect a reasonable charge for compressing, desulphurization and/or transporting gas from the well to the point of sale. (Exhibit 13 [131-13], at 6) (emphasis added). The defendants argue that these leases specifically contemplate deductions for post-production costs, such as desulphurization, compression, and transportation. (See Mem. in Supp. of Defs.’ Joint Mot. for Summ. J. [Docket 170], at 19-22). With respect to lease (k), the plaintiffs refute this argument by pointing to the clause stating that lessees are to pay “at least one-eighth (1/8) of the wholesale market price or value at the well,” “regardless of the selling price received by the Lessee----” (Lease (k), Exhibit 11 [Docket 131-11], at 8). A contract is ambiguous where it contains language “reasonably susceptible of two different meanings or language of such doubtful meaning that reasonable minds might be uncertain or disagree as to its meaning.” Payne v. Weston, 195 W.Va. 502, 466 S.E.2d 161, 166 (1995) (internal quotations omitted). I FIND that lease (k) is ambiguous on the issue of monetary deductions because it contemplates specific deductions while simultaneously prohibiting the lessee from assessing them. In this situation, I would normally admit parol evidence to resolve the ambiguity. See Syl. Pt. 1, Lee Enters., Inc. v. Twentieth [808] Century-Fox Film Corp., 172 W.Va. 63, 303 S.E.2d 702 (1983). However, ambiguities in oil and gas leases are construed against the lessee. See Tawney, 633 S.E.2d at 29-30; Syl. Pt. 1, Martin v. Consol. Coal & Oil Corp., 101 W.Va. 721, 133 S.E. 626 (1926) (“The general rule as to oil and gas leases is that such contracts will generally be liberally construed in favor of the lessor, and strictly as against the lessee.”). Therefore, I FIND that lease (k) fails to meet Tawney’s specificity requirements for monetary deductions. Leases (l) and (m) do not contain a contradictory provision similar to that in lease (k). Nonetheless, the plaintiffs argue that leases (!) and (m) fail to meet Tawney’s specificity requirements because they do not describe the method of calculating deductions. I disagree. Leases (l) and (m) both specify that the lessor will bear some part of the costs of marketing the gas. The leases identify the particular costs that will be deducted — the costs of compression, desulphurization, and transportation. Further, leases (l) and (m) identify the method for calculating deductions because the lessee can only deduct “reasonable” costs. “Reasonableness” is a common legal standard that has been used by courts for more than a century. See, e.g., Robinson v. Lindsay, 92 Wash.2d 410, 598 P.2d 392, 393 (1979) (“In the courts’ search for a uniform standard of behavior to use in determining whether or not a person’s conduct has fallen below minimal acceptable standards, the law has developed a fictitious person, the ‘reasonable man of ordinary prudence.’ That term was first used in Vaughan v. Menlove, 132 Eng. Rep. 490 (1837).”). “The word[] ‘reasonable’ ... [is a] relative term[ ] with no fixed or rigid meaning; but [it is] not ambiguous. In ordinary use and common acceptation, the word ‘reasonable’ means fair; just; ordinary or usual; not immoderate or excessive; not capricious or arbitrary. It means what is just, fair and suitable under the circumstances.” Sydnor Pump & Well Co. v. Taylor, 201 Va. 311, 110 S.E.2d 525, 530 (1959) (internal quotations omitted). In fact, the court in Tawney used “reasonableness” as a legal standard in this context. See Syl. Pt. 2, Estate of Tawney v. Columbia Natural Resources, LLC, 219 W.Va. 266, 633 S.E.2d 22 (2006) (Lessees may deduct costs only “to the extent that they were actually incurred and they were reasonable.”). I therefore FIND that leases (l) and (m) meet Tawney’s specificity requirements for the deduction of costs for compression, desulphurization, and transportation to the extent they were reasonable and actually incurred. With respect to volume losses, each of the leases frames royalties in terms of a portion of the price “received” by the lessee. Lease (k) states that royalties will be paid based on gas “produced and marketed,” and “sold by [the lessee].” Lease (l) indicates that royalties will be paid on gas “produced and marketed.” Lease (m) states that royalties will be paid on gas “produced, saved and marketed.” Therefore, I FIND that leases (k), (l), and (m) permit the lessees to pay royalties only on the actual amount of gas sold at market, d. Lease (n) Lease (n) does not include any “wellhead” ■ language. It states that royalties will be based upon the proceeds received by the lessee: [Lessee agrees] [t]o pay Lessor for gas of whatsoever nature or kind (with all of its constituents) produced and sold or used off the Leased Premises, or used in the manufacture of products therefrom, one-eighth (1/8) of the gross proceeds received for the gas sold, used off of the leased premises or in the manufacture of products therefrom, but in no event [809] more than one-eighth (1/8) of the actual amount received by the Lessee.... (Exhibit 10 [Docket 131-10], at 1) (emphasis added). Lease (n) does not identify with particularity specific post-production costs to be deducted from royalties. Thus, I FIND that lease (n) does not meet Tawney’s specificity requirements to allow the defendants to deduct post-production monetary costs. With respect to volume losses, lease (n) specifically states that royalties will be paid based on gas “produced and sold” and on “gross proceeds received for the gas sold.” Thus, I FIND lease (n) permits the lessees to pay a royalty based on the volume of gas actually sold at the market, e. Lease (j) The plaintiffs state that lease (j) has “terminated” and therefore do not move for summary judgment on lease (j). (See Pis.’ Resp. to Defs.’ Joint Mot. for Summ. J. [Docket 176], at 16). The plaintiffs do not oppose the defendants’ motion for summary judgment on lease (j). Accordingly, with respect to lease (j), the defendants’ motion for summary judgment is GRANTED. 6. Non-Lessee Defendants EQT Corporation, EQT Energy, EQT Gathering, LLC, EQT Gathering, Inc., EQT Gathering Equity, LLC, and EQT Investment Holdings (collectively, the “non-lessee defendants”) move for summary judgment on the breach of contract claim [Docket 133], They argue that summary judgment is appropriate because they were not in privity of contract with the plaintiffs. (See Mem. in Supp. of Mot. for Summ. J. of Non-Lessee Defendants [Docket 134], at 5-6). EQT Production is the only defendant who is a party to the leases at issue. However, as I discuss below, there is a genuine dispute of material fact whether the non-lessee defendants are vicariously liable for the debts and obligations of EQT Production. Therefore, the non-lessee defendants’ motion for summary judgment [Docket 133] on the breach of contract claim is DENIED. 7. Conclusion On Count II (breach of contract), the Plaintiffs’ Motion for Partial Summary Judgment [Docket 131] is GRANTED in part with respect to monetary deductions in leases (a), (b), (c), (d), (e), (f), (g), (h), (i), (k), and (n); and DENIED in part with respect to monetary deductions in leases (Z) and (m) and with respect to volume losses on leases (a), (b), (c), (d), (e), (f), (g), (h), (i), (k), (Z), (m), (n). On Count II (breach of contract), the Defendants’ Joint Motion for Summary Judgment [Docket 169] is GRANTED in part with respect to lease (j) in its entirety, with respect to monetary deductions in leases (Z) and (m), and with respect to volume losses in leases (a), (b), (c), (d), (e), (f), (g), (h), (i), (k), (Z), (m), (n); and DENIED in part with respect to monetary deductions in leases (a), (b), (c), (d), (e), (f), (g), (h), (i), (k), and (n). B. Limitations on Tort Claims [19] The defendants argue that the plaintiffs’ following claims are partially barred by the statute of limitations: Count III (breach of fiduciary duty), Count IV (fraud), Count V (negligent misrepresentation/concealment), Count VI (civil conspiracy/]oint venture), and Count VII (aiding and abetting a tort). Under West Virginia law, a court must apply a five-step analysis to determine the validity of a statute-of-limitations defense. See Mack-Evans v. Hilltop Healthcare Ctr., Inc., 226 W.Va. 257, 700 S.E.2d 317, 322 (2010) (quoting Syl. Pt. 5, Dunn v. Rockwell, 225 W.Va. 43, 689 S.E.2d 255 (2009)). First, the court should identify the applicable statute of limitation for each cause of action. Second, the court (or, if material questions of fact exist, the jury) [810] should identify when the requisite elements of the cause of action occurred. Third, the discovery rule should be applied to determine when the statute of limitation began to run by determining when the plaintiff knew, or by the exercise of reasonable diligence should have known, of the elements of a possible cause of action.... Fourth, if the plaintiff is not entitled to the benefit of the discovery rule, then determine whether the defendant fraudulently concealed facts that prevented the plaintiff from discovering or pursuing the cause of action. Whenever a plaintiff is able to show that the defendant fraudulently concealed facts which prevented the plaintiff from discovering or pursuing the potential cause of action, the statute of limitation is tolled. And fifth, the court or the jury should determine if the statute of limitation period was arrested by some other tolling doctrine. Only the first step is purely a question of law; the resolution of steps two through five will generally involve questions of material fact that will need to be resolved by the trier of fact. Dunn v. Rockwell, 225 W.Va. 43, 689 S.E.2d 255, 265 (2009). Applying the first step, it is clear that a two-year statute of limitations applies to tort claims causing personal injury. That statute, West Virginia Code § 55-2-12(b), provides that “[e]very personal action for which no limitation is otherwise prescribed shall be brought ... -within two years next after the right to bring the same shall have accrued if it be for damages for personal injuries....” The plaintiffs do not dispute that this statute applies to their claims for breach of fiduciary duty, fraud, negligent misrepresentation/concealment, and aiding and abetting a tort. (See Pis.’ Resp. to Defs.’ Joint Mot. for Summ. J. [Docket 176], at 1-2). However, the plaintiffs argue that the ten-year statute of limitations for breach of contract, West Virginia Code § 55-2-6, applies to their civil conspiracy claim in Count VI. They point to authority stating that “the statute of limitation for a civil conspiracy claim is determined by the nature of the underlying conduct on which the claim of conspiracy is based----” Dunn, 689 S.E.2d at 269. According to the plaintiffs, the conduct underlying their civil conspiracy claim is the improper payment of royalties, which is a breach of contract claim, and therefore the ten-year statute of limitations should apply. (See Pis.’ Resp. to Defs.’ Joint Mot. for Summ. J. [Docket 176], at 6-7). However, the plaintiffs ignore other statements made by the court in Dunn that limit civil conspiracy to tort actions: “A civil conspiracy is ... a legal doctrine under which liability for a tort may be imposed on people who did not actually commit a tort themselves but who shared a common plan for its commission with the actual perpetrators).” Dunn, 689 S.E.2d at 269 (emphasis added); see also Kessel v. Leavitt, 204 W.Va. 95, 511 S.E.2d 720, 753 (1998) (“At its most fundamental level, a civil conspiracy is a combination to commit a tort.”) (internal quotations omitted). The plaintiffs have pointed to no contrary authority, and I have found none, where a West Virginia court applied a ten-year statute of limitations to a civil conspiracy claim. Accordingly, I FIND that the two-year statute of limitations for torts, West Virginia Code § 55 — 2—12(b), applies to the plaintiffs’ civil conspiracy claim. The plaintiffs also bring a claim for joint venture within Count VI. A joint venture “is an association of two or more persons to carry out a single business enterprise for profit, for which purpose they combine their property, money, effects, skill, and knowledge.” Syl. Pt. 5, [811] Armor v. Lantz, 207 W.Va. 672, 535 S.E.2d 737 (2000). Like civil conspiracy, joint venture is not a stand-alone claim, but a basis for vicarious liability. See id. at 742-43 (“[Mjembers of a joint venture are ... jointly and severally liable for all obligations pertaining to the venture, and the actions of the joint venture bind the individual co-venturers.”). Because joint-venture liability can arise out of “all obligations pertaining to the venture” and is not apparently limited to tort liability, I FIND that the plaintiffs’ joint venture claim is not automatically barred by the two-year tort statute of limitations. If the plaintiffs establish joint venture liability for claims other than torts, then their joint venture claim is not barred by the statute of limitations in West Virginia Code § 55-2-12(b). I therefore FIND that the two-year statute of limitations in West Virginia Code § 55-2-12(b) applies to the plaintiffs’ claims for breach of fiduciary duty, fraud, negligent misrepresentation/coneealment, civil conspiracy, and aiding and abetting a tort. Under the second step of the Dunn framework, I determine — as long as there is no genuine dispute of material fact — when the requisite elements of the causes of action occurred. It is undisputed that the plaintiffs had cause to sue as early as 2002. (See Mem. in Supp. of Defs.’ Joint Mot. for Summ. J. [Docket 170], at 9-10). However, the plaintiffs argue that the deductions, which have been taken periodically until the present, are a “continuing tort.” Under the “continuing tort” theory, “where a tort involves a continuing or repeated injury, the cause of action accrues at and the statute of limitations begins to run from the date of the last injury or when the tortious overt acts or omissions cease.” Graham v. Beverage, 211 W.Va. 466, 566 S.E.2d 603, 614 (2002). However, this theory does not apply “when .money recovery is sought on an obligation payable in installments.” G.T. Fogle & Co. v. King, 132 W.Va. 224, 51 S.E.2d 776, 784 (1949). Then, “the statute of limitations commences to run against each installment from the time it becomes due.” Id. The continuing tort theory will not apply to toll the statute of limitations, even though the plaintiff brings tort actions, where the injuries were multiple and periodic, not continuing. See, e.g., Copier Word Processing Supply, Inc. v. WesBanco Bank, Inc., 220 W.Va. 39, 640 S.E.2d 102, 109-110 (2006) (finding continuing tort theory inapplicable where. plaintiff sued for civil conversion related to hundreds of separate instances of embezzlement by the defendant). The court in Copier Word found that “while the multiple conversions were carried out repeatedly over time, each conversion was a discrete act, a single transaction involving a specifically individual negotiable instrument. Thus, each conversion, though similar, was a distinctly separate transaction.” Id. at 109. Similarly, each act of tortiously reducing royalty payments, though similar, is a separate act and separate transaction. Accordingly, I FIND that the continuing tort theory is inapplicable. The requisite elements of the plaintiffs’ causes of action accrued at the time of each allegedly deficient royalty payment. Third, I determine whether the discovery rule tolled the statute of limitations. Under the discovery rule, the statute of limitations will run, “where the injury is not apparent, from the date the plaintiff knows or reasonably should know of his claim.” Smith v. Raven Hocking Coal Corp., 199 W.Va. 620, 486 S.E.2d 789 (1997). “[Wjhether a plaintiff ‘knows of or ‘discovered’ a cause of action is an objective test.... This objective test focuses upon whether a reasonable prudent person would have known, or by the exercise of [812] reasonable diligence should have known, of the elements of a possible cause of action.” Dunn, 689 S.E.2d at 265. The plaintiffs knew as early as 2002 that deductions, at some amount, were being subtracted from their royalties. On September 25, 2002, Glenn T. Yost, in a letter on behalf of the plaintiffs, wrote to the defendants: For the last several months, your company has taken unexplained deductions from the gross revenue on each well on the various royalty reports from the period October, 2001, through June, 2002.... All of the various Leases which comprise the many wells on our property prohibit any kind of deductions from the gross revenue received by the Lessee. Unless a valid explanation for these deductions is received in writing from your company within 30 days or payment for the deductions, we will consider these deductions unallowable and a default under each of the various Leases. (Exhibit W [Docket 169-23], at 1). The parties agree that Mr. Yost referred only to monetary deductions, not volume losses, in this email. The plaintiffs contend that the discovery rule tolled the statute of limitations until they became aware of the volume losses on June 30, 2009. (See Pis.’ Resp. to Defs.’ Joint Mot. for Summ. J. [Docket 176], at 4; Exhibit A [Docket 176-1], at 1). With respect to monetary deductions, the undisputed facts establish that the plaintiffs were aware of the allegedly improper monetary deductions as early as Mr. Yost’s September 25, 2002 email. Therefore, I FIND that the discovery rule does not toll the plaintiffs’ claims as they relate to damages incurred from monetary deductions. I need not decide whether the discovery rule tolled the plaintiffs’ claims as they relate to volume losses because the plaintiffs cannot state any tort claim in relation to volume losses. As I explained above, the defendants are entitled to summary judgment on all of the leases with respect to volume losses. Therefore, the plaintiffs have not incurred any damages in relation to volume losses, and no tort will lie in relation to the volume losses. Under the fourth step of my analysis, I determine whether thfe defendants “fraudulently concealed facts which prevented the plaintiff[s] from discovering or pursuing the potential cause of action.... ” Dunn, 689 S.E.2d at 265. The plaintiffs argue that fraudulent concealment relates only to volume losses. (See Pis.’ Resp. to Defs.’ Joint Mot. for Summ. J. [Docket 176], at 5). They do not argue that the defendants fraudulently concealed the existence of monetary deductions. Because the plaintiffs’ tort claims cannot relate to volume losses, I FIND that the statute of limitations was not tolled by fraudulent concealment. At the fifth step of my analysis, I determine if the statute of limitations is affected by some other tolling doctrine. Here, the parties agree that a tolling agreement and previous class action litigation tolled the statute of limitations for particular defendants. 1. Tolling against EQT Production The plaintiffs were at one time members of a class action suit in this court styled Kay Co., et al. v. Equitable Production Company, Case No. 2:06-cv-00612. The plaintiffs eventually opted out of the class settlement of Kay Co. Pursuant to this court’s orders in Kay Co. ([Docket 169— 26], at 18), a tolling agreement ([Docket 169-27]), and a letter terminating the tolling agreement ([Docket 169-31]), the statute of limitations for claims against EQT Production tolled from June 13, 2006, [813] through the filing of this lawsuit. Accordingly, I FIND the statute of limitations bars the plaintiffs’ tort claims against EQT Production to the extent that they seek damages prior to June 13, 2004, two years prior to the filing of the complaint in Kay Co. 2. Tolling against EQT Corporation EQT Corporation was also a party to Kay Co., so the statute of limitations tolled from June 13, 2006, until May 29, 2010, the day after the Kay Co. tolling period ended. EQT Corporation was not a party to a separate tolling agreement. The plaintiffs did not file their Complaint in this action until June 16, 2011, 1 year and 18 days after the Kay Co. tolling period ended, leaving 347 days prior to the filing of Kay Co. for the plaintiffs to file claims that were not time-barred by the two-year statute of limitations. Accordingly, I FIND that the statute of limitations bars the plaintiffs’ tort claims against EQT Corporation to the extent that they seek damages prior to July 1, 2005, 347 days prior to the filing of Kay Co. 3. The Statute of Limitations Did Not Toll on Claims against EQT Energy, EQT Gathering, Inc., EQT Gathering, LLC, EQT Gathering Equity, and EQT Investment Holdings The defendants EQT Energy, EQT Gathering, Inc., EQT Gathering, LLC, EQT Gathering Equity, and EQT Investment Holdings were not parties to the Kay Co. suit or a separate tolling agreement. Therefore, I FIND that the statute of limitations bars the plaintiffs’ tort claims against defendants EQT Energy, EQT Gathering, Inc., EQT Gathering, LLC, EQT Gathering Equity, and EQT Investment Holdings to the extent that they seek damages for the period prior to June 16, 2009, two years prior to the filing of the Complaint in this action. Accordingly, the Defendants’ Joint Motion for Summary Judgment [Docket 169] regarding the limitations defense is GRANTED. The plaintiffs’ tort claims are partially barred according to the terms set out above. C. Breach of Fiduciary Duty Defendant EQT Production argues that the plaintiffs’ claim for breach of fiduciary must be dismissed because West Virginia law does not recognize fiduciary duties between a lessee of a gas well and a royalty owner. (See Mem. in Supp. of Mot. for Summ. J. of Def. EQT Prod. Co. with Respect to Counts III-VII [Docket 144], at 7). The West Virginia Supreme Court of Appeals long ago announced the duty owed between parties on an oil or gas lease does not rise to the level of a fiduciary relationship: ‘Where the object of the operations contemplated by an oil and gas lease is to obtain a benefit or profit for both lessor and lessee ... both are bound by the standard of what, in the circumstances, would be reasonably expected of operators of ordinary prudence, having regard to the interests of both.” Grass v. Big Creek Dev. Co., 75 W.Va. 719, 84 S.E. 750, 753 (1915). Further, this court has held that, although there may be extra-contractual duties owed by a gas well lessee to a lessor, the existence of these duties “does not create or imply a fiduciary relationship between lessor and lessee of mineral rights.” Wellman v. Bobcat Oil & Gas, Inc., No. 3:10-0147, 2010 WL 2720748 (S.D.W.Va. July 8, 2010) (Chambers, J.). Although the plaintiffs acknowledge this authority, they argue that it is limited to circumstances where the lessor and lessee share an overlapping pecuniary interest in production and marketing of gas. I need not resolve this issue because the lessors and lessees in this case clearly share an overlapping pecuniary interest in the mar [814] keting of their gas. Accordingly, I FIND that there was no fiduciary relationship between the lessors and EQT Production in this case. The plaintiffs argue that summary judgment on this claim is inappropriate because there is a genuine dispute of material fact. But where there is no cognizable claim, I need not decide if there is a genuine factual dispute. The failure to state a claim “is usually challenged by a motion to dismiss under Rule 12(b)(6), [but] it may also serve as a basis for summary judgment.” In re: Enron Corp. Sec., Derivative & ERISA Litigation, 610 F.Supp.2d 600, 607 (S.D.Tex.2009) (citing Whalen v. Carter, 954 F.2d 1087, 1098 (5th Cir.1992)); Ritter v. Dalton, 129 F.3d 117 (4th Cir.1997) (unpublished) (“[T]he district court properly granted summary judgment for ... failure to state a claim upon which relief could be granted.”). The remaining defendants, EQT Corporation, EQT Energy, EQT Gathering, LLC, EQT Gathering, Inc., EQT Gathering Equity, LLC, and EQT Investment Holdings (collectively, the “non-lessee defendants”), argue that they cannot owe a fiduciary relationship because they were not parties to any lease with the plaintiffs. (See Mem. in Supp. of Mot. for Summ. J. of Non-Lessee Defs. [Docket 134], at 6-7). The plaintiffs argue only that the non-lessee defendants are vicariously liable for breach of fiduciary duty because they participated in a joint venture or civil conspiracy with EQT Production. (See Pis.’ Resp. to Mot. for Summ. J. of Non-Lessee Defs. [Docket 173], at 5-9). However, if EQT Production, the only party to the leases, owed no fiduciary duty, then the non-lessee defendants cannot be vicariously liable for a breach of that duty. Accordingly, I FIND that the non-lessee defendants owe no fiduciary duty to the plaintiffs. Therefore, defendant EQT Production’s motion for summary judgment [Docket 143] with regard to Count III (breach of fiduciary relationship) is GRANTED. Additionally, the non-lessee defendants’ motion for summary judgment [Docket 133] with respect to Count III (breach of fiduciary duty) is GRANTED. D. Failure to Account, Fraud, Negligent Misrepresentation, Civil Conspiracy/Joint Venture, and Aiding and Abetting a Tort I have considered the briefing, the evidence presented, and counsel’s oral arguments. I FIND that a genuine issue of material fact exists as to the following claims against all of the defendants: Count I (failure to account), Count IV (fraud), Count V (negligent misrepresentation), Count VI (civil conspiracy/joint venture), and Count VII (aiding and abetting a tort). Accordingly, defendants’ motions on these counts [Dockets 133, 143, and 169] are DENIED. E. Punitive Damages The defendants additionally move for summary judgment on the issue of punitive damages. “Generally, punitive damages are unavailable in an action for breach of contract unless the conduct of the defendant constitutes an independent, intentional tort.” Hayseeds, Inc. v. State Farm Fire & Cas., 177 W.Va. 323, 352 S.E.2d 73, 80 (1986). “Punitive damages are allowed only where there has been malice, fraud, oppression, or gross negligence .... [P]unitive damages are generally unavailable in pure contract actions.” Warden v. Bank of Mingo, 176 W.Va. 60, 341 S.E.2d 679, 684 (1985). The plaintiffs do not bring a pure contract claim. They bring claims for fraud and negligent misrepresentation as well. Therefore, the defendants’ motions for summary judgment on the issue of punitive damages are DENIED. [815] IV. Conclusion With respect to Count II (breach of contract), the Plaintiffs’ Motion for Partial Summary Judgment [Docket 131] is GRANTED in part and DENIED in part in accordance with this opinion; the Defendants’ Joint Motion for Summary Judgment [Docket 169] is GRANTED in part and DENIED in part in accordance with this opinion; and the Motion for Summary Judgment of Defendants EQT Corporation, EQT Energy, LLC, EQT Gathering, Inc. EQT Gathering Equity, LLC, EQT Investment Holdings, LLC, and EQT Gathering, LLC [Docket 133] is DENIED. With respect to Count III (breach of fiduciary duty) the defendants’ motions [Docket 133 and 143] are GRANTED. With respect to Count I (failure to account), Count IV (fraud), Count V (negligent misrepresentation), Count VI (civil conspiracy), Count VII (aiding and abetting a tort), and Count VIII (punitive damages) the defendants’ motions [Dockets 133, 143, and 169] are DENIED. The court DIRECTS the Clerk to send a copy of this Order to counsel of record and any unrepresented parties. The court further DIRECTS the Clerk to post a copy of this published opinion on the court’s website, www.wvsd.uscourts.gov. CLARIFICATION OF MEMORANDUM OPINION AND ORDER Pending before the court is the plaintiffs’ Motion for Clarification [Docket 221], The plaintiffs seek clarification of my Memorandum Opinion and Order, 983 F.Supp.2d 790. For the reasons discussed below, the motion is GRANTED insofar as I offer the clarifications below. I. Background This case arises out of a dispute over royalty payments related to fourteen oil and gas well leases. The plaintiffs are owners of land subject to those leases. The plaintiffs contend that Estate of Tawney v. Columbia Natural Resources, LLC, 219 W.Va. 266, 633 S.E.2d 22 (2006), prohibits the defendants from deducting “post-production” costs from royalty payments. On November 21, 2013,1 held that “[ujnless a lease provides otherwise, lessees must deliver the gas to the market, in a marketable condition, free of all costs of production. The costs of production include any ‘post-production’ costs incurred to market the gas.” 983 F.Supp.2d at 803. I further held that “Taumey’s heightened specificity requirements do not obligate lessees to pay royalties on lost volumes.” Id. I then proceeded to analyze the individual leases at issue. I determined that two of the leases, (l) and (m), permitted the defendants to deduct monetary costs, specifically “compression, desulphurization, and transportation to the extent [that those costs] were reasonable and actually incurred.” Id. at 808. I also determined that each lease obligated the defendants to pay royalties only on the gas actually sold at market; the defendants were not obligated to pay royalties on unsold gas. See id. at 805-09. The plaintiffs seek clarification on two issues: (1) which monetary expenses the defendants may deduct under leases (l) and (m) and the manner in which those deductions may be taken, and (2) whether the defendants must pay royalties on gas used as fuel to run pipeline compressors. II. Monetary Deductions The plaintiffs present evidence that before 2004, the defendants took monetary deductions for “personnel costs, indirect costs, production management costs, depreciation and return on capital investment.” (See EQT Prod. Co.’s Supp. of [816] Disc. Resp. [Docket 222-1], ¶ 1). After 2004, the defendants have taken deductions for, among other things, “meals and entertainment,” “uniforms,” meter operation and repair, and “personal property taxes.” (See 2011 Gathering Cost of Service, Brenton District [Docket 222-2], at 2). The plaintiffs argue that these deductions are not specifically contemplated by leases (l) and (m). The relevant clauses in those leases, which are identical, read as follows: If the gas should be sold at some point other than at the well, then any selling price in excess of Fifteen Cents (15<t) per [Mcf] received by the Lessee shall be adjusted downward to reflect a reasonable charge for compressing, desulphurization and /or transporting gas from the well to the point of sale. (Lease (l) [Docket 131-12], at 9 (emphasis added)). “When the language of a written instrument is plain and free from ambiguity, a court must give effect to the intent of the parties as expressed in the language employed and in such circumstances resort may not be had to rules of construction.” Cotiga Dev. Co. v. United Fuel Gas Co., 147 W.Va. 484, 128 S.E.2d 626, 631 (1962). A lessee is not permitted to take deductions from royalties unless the lease, among other things, “identifies] with particularity the specific deductions the lessee intends to take from the lessor’s royalty[J” Syl. Pt. 10, Estate of Tawney v. Columbia Natural Res., LLC, 219 W.Va. 266, 633 S.E.2d 22, 24 (2006). The provisions at issue are not ambiguous. They permit deductions only for “compressing, desulphurization and/or transporting gas.” I FIND that meals and entertainment, uniforms, meter operations and repair, and personal property taxes are not costs of compression, desulphurization, or transportation. I further FIND that deductions for “personnel costs, indirect costs, production management costs, depreciation and return on capital investment,” are too vague to be specifically related to compression, desulphurization, or transportation. These costs are not identified with what I predict the Supreme Court of Appeals of West Virginia would find to be sufficient “particularity.” Accordingly, these costs may not be deducted pursuant to lease (l) and (m). The plaintiffs also complain that even for deductions particularly specified in leases (l) and (m), the defendants have taken them improperly by charging them as a flat rate. “[B]y allocating certain monetary deductions per district and estimating expenses, Defendants took monetary deductions beyond those contemplated under leases (l) and (m) and this Court’s order.” (Mem. in Supp. of Pis.’ Mot. for Clarification [Docket 222], at 4). The plaintiffs cite deposition testimony of Rick Crites, former EQT Production Director of Revenue Accounts, and Jimmie Sue Smith, former vice president for EQT Energy, to show that the EQT entities charge lessors a standard, flat rate for deductions, which they call a “gathering rate.” (See Crites Dep. [Docket 221-3], at 103-04; Smith Dep. [Docket 221-4], at 46-49). The plaintiffs argue that charging a standard gathering rate, rather than the particular costs associated with each individual well, violates Wellman’s holding that deductions must be “actually incurred” and “reasonable.” Syl. Pt. 5, Wellman v. Energy Res., Inc., 210 W.Va. 200, 557 S.E.2d 254, 256 (2001). I agree with the plaintiffs in theory. ■ Charging a flat rate for gathering costs is not permitted under Wellman because, where a lease permits deductions, a lessee may only deduct costs that are “actually incurred” with respect to those particular wells covered under the leases at issue. The charges reflected in the flat rate may or may not [817] have been actually incurred in order to produce gas from the wells included in leases (Z) and (m). But at this stage, I cannot determine whether the defendants’ method of assessing deductions is improper. At trial, the defendants must present evidence establishing that costs deducted with respect to leases (Z) and (m) were actually incurred and reasonable. See id. Therefore, I do not decide whether the defendants’ method of assessing monetary costs is permissible. III. Fuel Gas The plaintiffs also seek clarification on the issue of gas used as fuel to power the defendants’ compressors (“fuel gas”). Currently, the defendants operate a number of compressor stations along gathering lines in order to move gas from the wellhead to the interstate pipeline connection. The compressors consume the plaintiffs’ gas during their operation. The plaintiffs argue that the defendants should not be permitted to use fuel gas free of charge or royalty. This issue is subsumed in my holding that “lessees have no general duty to pay for lost volumes.” 983 F.Supp.2d at 803. In my prior Memorandum Opinion and Order, I determined that [v]olume losses are not “deductions” of costs in the same sense as marketing or transportation costs____ Under Well-man and Tavmey, the lessee has a general duty to market the gas produced, under which the lessee must bear all costs incurred in converting the product to a marketable condition and bringing it to a market. See Syl. Pt. 4, Wellman, 557 S.E.2d 254; Syl. Pt. 1, Tawney, 633 S.E.2d 22. The lessee does not receive payment for lost and unaccounted for gas that is not delivered to the market. Rather, the lessee receives payment only for gas that is actually sold. Therefore, when the lessee pays a royalty on those proceeds, there is nothing to deduct; the lessee was never paid for undelivered volumes of gas. Volume losses are not costs that are deducted from a royalty, unlike the monetary deductions that concerned the Wellman and Tawney courts. Id. at 802. After finding that lessees have no general duty to pay for lost volumes, I reviewed each lease at issue to determine whether their individual provisions required royalty payments for lost volumes. I found that they did not. The lease provisions stated that royalties should be paid on gas “produced and marketed,” “marketed,” “sold,” “produced, saved and marketed,” or “produced and sold.” See id. at 805-09. Despite my holdings, the plaintiffs now argue that fuel gas should be considered a monetary cost of “producing, marketing, and transporting” gas, which West Virginia law obligates lessees to bear unless a lease provides otherwise. See Syl. Pt. 4, Wellman, 557 S.E.2d at 256. The plaintiffs then discuss whether the leases in question permit the use of fuel gas free of charge. To clarify my prior Memorandum Opinion and Order, lessees have no general duty to pay for unsold volumes. This includes fuel gas consumed in compressor stations. Like volumes of gas lost or unaccounted for due to pipeline leaks or metering inaccuracies, gas consumed as fuel to power compressors is not sold or marketed. Lessees are not generally obligated to pay royalties on unsold gas because lessees receive no payment for this gas. Further, the individual leases at issue each require payment of royalties only on volumes that are sold at market. See 983 F.Supp.2d at 805-09. Therefore, the holdings in my Memorandum Opinion and Order, 983 F.Supp.2d 790, relating to lost volumes apply equally to volumes con [818] sumed as fuel gas; the defendants are not obligated to pay royalties on these volumes. IV. Conclusion The plaintiffs’ Motion for Clarification [Docket 221] is GRANTED insofar as I have discussed above. The court DIRECTS the Clerk to send a copy of this Order to counsel of record and any unrepresented parties. The court further DIRECTS the Clerk to post a copy of this published opinion on the court’s website, www.wvsd.uscourts.gov. MEMORANDUM OPINION AND ORDER Before the court is the Defendants’ Joint Motion for Reconsideration [Docket 224]. For the reasons stated below, the motion is DENIED. I. Background This case arises out of a dispute over royalty payments related to fourteen oil and gas well leases. The plaintiffs are owners of land subject to those leases. The plaintiffs contend that Estate of Tawney v. Columbia Natural Resources, LLC, 219 W.Va. 266, 683 S.E.2d 22 (2006), prohibits the defendants from deducting “post-production” costs from royalty payments. On November 21, 2013, I held that “[u]nless a lease provides otherwise, lessees must deliver the gas to the market, in a marketable condition, free of all costs of production. The costs of production include any ‘post-production’ costs incurred to market the gas.” 983 F.Supp.2d at 803. I further held that “Tawney’s heightened specificity requirements do not obligate lessees to pay royalties on lost volumes.” Id. I then proceeded to analyze the individual leases at issue. I determined that two of the leases, (i) and (m), permitted the defendants to deduct monetary costs, specifically “compression, desulphurization, and transportation to the extent [that those costs] were reasonable and actually incurred.” Id. at 808. I also determined that each lease obligated the defendants to pay royalties only on the gas actually sold at market; the defendants were not obligated to pay royalties on unsold gas. See id. at 805-09. At a pretrial conference on December 10, 2013, the parties explained that they sought clarification on two issues: (1) which monetary expenses the defendants may deduct under leases (l) and (m); and (2) whether the defendants must pay royalties on gas used as fuel to run pipeline compressors (“fuel gas”). The parties were directed to submit briefing on each of these issues, which they did on January 10, 2014. After considering the parties’ briefs, I entered a Clarification of Memorandum Opinion and Order on January 21, 2014 [Docket 223]. I held that certain monetary costs identified by the plaintiffs could not be deducted under leases (l) and (m) either because they were not related to compressing, desulphurization, or transportation; or because they were not identified with sufficient particularity. I also held that the plaintiffs were not entitled to royalties for fuel gas. In the instant motion, the defendants ask me to reconsider my holding regarding monetary deductions under leases (l) and (m). The defendants argue that they did not have an opportunity to brief this issue. The defendants contend that it was their “understanding of the Court’s instruction at [the December 10, 2013 pretrial conference] that [fuel gas] was the only issue on which the parties should file supplemental memoranda.” (Defs.’ Mem. in Supp. of Mot. to Reconsider [Docket 225], at 2). The defendants ask that they be given an [819] opportunity to brief whether the monetary costs identified by the plaintiffs may be deducted under leases (l) and (m). The defendants further maintain that “whether the amounts and types of expenses charged for gathering rates were associated with the costs of compression, desulphurization and/or transportation and whether these charges were actual and reasonable are fact questions to be decided at trial.” (Id. at 3). II. Legal Standard for Reconsideration Federal Rule of Civil Procedure 54(b) provides that “any order or other decision, however designated, that adjudicates fewer than all the claims or the rights and liabilities of fewer than all the parties does not end the action as to any of the claims or parties and may be revised at any time before the entry of a judgment adjudicating all the claims and all the parties’ rights and liabilities.” Fed.R.Civ.P. 54(b). “Notwithstanding that precept, it is improper to file a motion for reconsideration simply to ask the Court to rethink what the Court had already thought through — rightly or wrongly.” In re: C.R. Bard, Inc., 948 F.Supp.2d 589, 649 (S.D.W.Va.2013). Although a “motion for reconsideration under Rule 54(b) is not subject to the strictures of a Rule 60(b) motion,” this district has been “guided by the general principles of Rules 59(e) and 60(b)” in determining whether a Rule 54(b) motion should be granted. Shrewsbury v. Cyprus Kanawha Corp., 183 F.R.D. 492, 493 (S.D.W.Va.1998) (Haden, J.). The Fourth Circuit has recognized three grounds for amending a judgment: “(1) to accommodate an intervening change in controlling law; (2) to account for new evidence not available at trial; or (3) to correct a clear error of law or prevent manifest injustice.” Pac. Ins. Co. v. Am. Nat’l Fire Ins. Co., 148 F.3d 396, 403 (4th Cir.1998). Motions to reconsider “may not be used, however, to raise arguments which could have been raised prior to the issuance of the judgment, nor may they be used to argue a case under a novel legal theory that the party had the ability to address in the first instance.” Id. Finally, “reconsideration of a judgment after its entry is an extraordinary remedy which should be used sparingly.” Id. (quoting 11 Charles Alan Wright and Arthur R. Miller, Federal Practice and Procedure § 2810.1, at 124 (3d ed.2012)). III. Analysis First, the defendants incorrectly maintain that they were deprived of an opportunity to brief monetary deductions under leases (l) and (m). At the pretrial hearing, two issues were discussed: whether royalties are payable for fuel gas, and what monetary deductions are permissible under leases (Z) and (m). I directed the parties to submit simultaneous briefs on these issues by January 10, 2014. The plaintiffs followed this instruction and briefed both issues. The defendants briefed only the fuel gas issue. Therefore, the defendants waived their opportunity to brief monetary deductions under leases (Z) and (m).1 Second, the defendants have not pointed to circumstances warranting re [820] consideration. The defendants merely ask that they be given an opportunity to submit briefing. The defendants do not point to an intervening change in controlling law, new evidence, clear error, or manifest injustice. At most, the defendants argue that my clarification order resolved factual issues that should go to the jury. That is incorrect. “It is the province of the court, and not of the jury, to interpret a written contract.” Syl. Pt. 9, Estate of Tawney v. Columbia Natural Res., LLC, 219 W.Va. 266, 633 S.E.2d 22, 24 (2006) (quotation marks omitted). My clarification order simply interpreted leases (l) and (m) and found that deductions for “meals and entertainment, uniforms, meter operations and repair, and personal property taxes are not costs of compression, desulphurization, or transportation.” (Clarification of Mem. Op. & Order [Docket 223], at 816). I further found that “personnel costs, indirect costs, production management costs, depreciation and return on capital investment, are too vague to be specifically related to compression, desulphurization, or transportation.” (Id). Only if these costs were deductible under the leases would it fall to the jury to determine whether they were actually incurred and reasonable. See Syl. Pt. 2, Tawney, 633 S.E.2d at 23. IV. Conclusion For the reasons stated above, the Defendants’ Joint Motion for Reconsideration [Docket 224] is DENIED. The court DIRECTS the Clerk to send a copy of this Order to counsel of record and any unrepresented party. Footnotes [1] As a result of numerous factors, the volumes of gas recorded at the wellhead necessarily differ from those recorded downstream at the interstate pipeline connection. [2] As I discuss, infra, this sale between affiliated companies is not a bona fide wellhead sale. [3] Plaintiffs' counsel was also counsel in the Imperial Colliery case. Therefore, I cite to the plaintiffs’ brief for facts not present in the Imperial Colliery opinion. [4] The duty to market is not implicated where, pursuant to the terms of a lease, gas is legitimately sold in an arm's length transaction at the wellhead. But that was not the case in Wellman and Tawney, and it is not the case here. [5] I refer to the leases as they appear on the Amended Complaint [Docket 34], at 6. [1] The defendants correctly note that parties generally have fourteen days to respond to a motion. See Local Rule 7.1. I entered my clarification order only eleven days after the plaintiffs filed their motion for clarification. Therefore, the defendants believe they were not afforded an opportunity to respond to the plaintiffs’ arguments with respect to leases (l) and (m). However, Local Rule 7.1's basic briefing schedule may be modified by the court. See Local Rule 7.1(a)(7). At the pretrial conference, I directed both parties to submit briefs by January 10, 2014. I did not contemplate, and I did not direct, the parties to submit response briefs. The defendants did not request leave of court to respond to [820] the plaintiffs' motion. Therefore the plaintiffs’ motion was ripe for resolution on January 10, 2014.