W.W. McDonald Land Co. v. EQT Production Co. (983 F. Supp. 2d 790, 2013)

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 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.

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 wellhead 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 wellhead 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.

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 cents per one thousand cubic feet. (Mem. of Law in Supp. of Pis.’ Mot. for Partial Summ. J. [Docket 132], at ll). 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 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,” 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.

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, 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.

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, 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 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.

a. Leases (a), (b), (c), (d), (e), (f), and (i)

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