Recent Cases Affecting the Energy Industry. Carrie J. Lilly Bowles Rice LLP Morgantown, West Virginia

Recent Cases Affecting the Energy Industry Carrie J. Lilly Bowles Rice LLP Morgantown, West Virginia

Recent Cases Affecting the Energy Industry A. Oil and Gas Royalties - Responsibility for Post-Production Costs 1. Kansas Fawcett v. Oil Producers Inc. of Kansas 302 Kan. 350, 352 P.3d 1032 (2015) Supreme Court of Kansas 2. Kentucky Baker et al. v. Magnum Hunter Production, Inc. 473 S.W.3d 588 (2015) Supreme Court of Kentucky 3. West Virginia Leggett, et al. v. EQT Production Company 2016 WL 297714 Supreme Court of Appeals of West Virginia - Certified Questions from the United States District Court for the Northern District of West Virginia 4. Texas Chesapeake Exploration et al. v. Hyder, et al. 59 Tex. Sup. Ct. J. 290, 483 S.W.3d 870 (2015) Supreme Court of Texas 5. Colorado Lindauer v. Williams Production RMT Company 2016 WL 908452 Colorado Court of Appeals B. American Energy Marcellus, LLC v. Poling, et al. Circuit Court of Tyler County, West Virginia, Civil Action No. 15-C-34 H C. Schoene v. McElroy Coal Company United States District Court for Northern District of West Virginia, on appeal to United States Court of Appeals for the Fourth Circuit Case No. 16-1788 (5:13-cv-0095-JPB) D. Contraguerro et al. v. Gastar Exploration, et al. Circuit Court of Marshall County, West Virginia, on appeal to Supreme Court of Appeals of West Virginia, Case # 14-C-89 E. Corban v. Chesapeake Exploration, L.L.C. et al. Supreme Court of Ohio - Certified Questions from U. S. District Court for the Southern District of Ohio, Eastern Division, Slip Opinion No. 2016-Ohio-5796 Energy & Mineral Law Foundation - Kentucky Mineral Law Conference - October 2016 Carrie Lilly - Bowles Rice LLP

A. Oil and Gas Royalties - Responsibility for Post-Production Costs 1. Kansas: Fawcett v. Oil Producers Inc. of Kansas 302 Kan. 350, 352 P.3d 1032 (2015), Supreme Court of Kansas Issue: Where a lease provides for royalties based on a share of proceeds at the well and where gas is sold at the well, is the operator solely responsible under the common law marketable condition rule for the costs of third-party purchasers to process the gas for the interstate pipeline, or can an operator deduct such costs when calculating royalties? Does marketable condition mean interstate pipeline quality? The case involved a class action for underpayment of royalties claimed under 25 oil and gas leases entered into between 1944 and 1991. Lessee/operator sold raw natural gas at the wellhead to third parties, who transported and processed the gas before it entered the interstate pipeline system. The price the operator was paid, and upon which royalties were calculated, was based on a formula involving the price the third parties received for the processed gas, less processing costs. The leases at issue generally took two forms: 1. lessee [Oil Producers, Inc. of Kansas OPIK ] shall pay lessor [Fawcett] as royalty 1/8 of the proceeds from the sale of the gas as such at the mouth of the well where gas only is found; or 2. lessee shall monthly pay lessor as royalty on gas marketed from each well where gas only is found, one-eighth (1/8) of the proceeds if sold at the well, or if marketed by lessee off the leased premises, then one-eighth (1/8) of its market value at the well. (emphasis added) Plaintiffs contended that, under the marketable condition rule, the operator was required to bear the entire expense of transforming raw natural gas for transmission into the interstate pipeline system, and that raw natural gas sold at the well is not marketable until it is processed and enters an interstate pipeline, so its royalties cannot be reduced by the processing costs set out as deductions in purchase agreements with third parties. The marketable condition rule is a corollary of the duty to market, and requires operators to make gas marketable at their own expense. 1 The Supreme Court of Kansas disagreed with the plaintiffs equating of marketable condition with interstate pipeline quality. The court recognized Gilmore and 1 Fawcet at 352, 1034, 1035, citing Sternberger v. Marathon Oil Co., 257 Kan. 315, 330, 894 P.2d 788 (1995): The lessee has the duty to produce a marketable product, and the lessee alone bears the expense in making product marketable. 2

Schupbach 2, which addressed an operator s duty to prepare the gas for market, and concluded that those cases demonstrate that when gas is sold at the well it has been marketed; and when the operator is required to pay royalty on its proceeds from such sales, the operator may not deduct any pre-sale expenses required to make the gas acceptable to the third-party purchaser. 3 But post-sale post-production expenses to fractionate raw natural gas into its various valuable components or transform it into interstate pipeline quality gas are different than expenses of drilling and equipping the well or delivering the gas to the purchaser. 4 The court held that when a lease provides for royalties based on a share of proceeds from the sale of gas at the well, and the gas is sold at the well, the operator s duty to bear the expense of making the gas marketable does not, as a matter of law, extend beyond that geographical point to post-sale expenses. 5 The producer satisfied its duty to market the gas when the gas was sold at the wellhead. When calculating the royalty, post-production, post-sale processing expenses deducted by the third-party purchasers are shared. 6 The court noted that the plaintiffs did not challenge the producer s good faith or prudence in entering into the purchase agreements. Key Considerations: Does the lease provide for royalties based on a share of proceeds from the sale of gas at the wellhead, and is the gas sold at the wellhead? Were the producer s actions in good faith, and did the producer market the gas on reasonable terms? A. Oil and Gas Royalties - Responsibility for Post-Production Costs (continued) 2. Kentucky Baker et al. v. Magnum Hunter Production, Inc. 473 S.W.3d 588 (2015), Supreme Court of Kentucky Issue: Responsibility for post-production costs under market price at the well royalty clauses. Lessors brought suit in Harlan County Circuit Court seeking a declaration that the lessee production companies had miscalculated and underpaid royalties, or alternatively, that the leases had expired. The trial court and the Court of Appeals 2 Gilmore v. Superior Oil Co., 192 Kan 388, 388 P.2d 602 (1964); Schupbach v. Continental Oil Co., 193 Kan. 401, 394 P.2d 1(1964). 3 Fawcett at 364, 1041, citing Coulter v. Anadarko Petroleum Corp., 296 Kan. 336, 362, 292 P.3d 289 (2013), and Wellman v. Energy Resources, Inc., 210 W. Va. 200, 211, 577 S.E.2d 254 (2001). (emphasis added) 4 Fawcett at 364, 1041, 1042. (emphasis added) 5 Id. at 365, 1042. (emphasis added) 6 Id. at 365, 366, 1042. 3

dismissed the lessors claims on the basis that Kentucky law does not embrace the marketable product approach to royalty calculation. On appeal, the lessors contended that the lower courts had misconstrued Kentucky law. The Supreme Court of Kentucky rejected the lessors contentions, and affirmed the decision of the lower court. 7 The leases provided that Lessee covenants and agrees:... To pay Lessor one-eighth of the market price at the well for gas sold or for the gas so used from each well off the premises. Gas was not sold at the well. Lessee gathered, compressed, and treated the raw gas, then transported it to purchasers downstream from the well. Lessee deducted from the downstream price its gathering, compression, treatment, and transportation costs, and other post-production costs, before calculating the royalty. Lessors contended that the royalty provision should be understood to contemplate the sale of gas made marketable. Lessors distinguished between transportation costs and processing costs, and contended that the royalty should be calculated by deducting transportation costs from the sales price received downstream from the well, but any other costs necessary to render the raw gas marketable were the producer s responsibility and could not be deducted in the calculation of royalty. Lessors contended that the marketable product approach was necessary to give meaning to the lease terms market price at the well because until a product is marketable, it cannot have a market price. The court cited Reed, Warfield, and Rains, 8 and concluded that all understand royalty, absent an express contrary provision, as the lessor s cost-free share of production, with production understood, in the case of gas, as the raw gas captured at the well. 9 The court discussed that under the marketable product approach contended by the lessors, royalty is still thought of as the lessor s cost-free share of production, but production is understood as extending to the production of a marketable product, rather than simply as the initial capture of the raw mineral. The court held that: Our law requires that, absent clear provision otherwise, royalty be based on the value (or price or proceeds) of the raw gas first produced, a value (or price or amount) that can be determined, if the raw gas was not actually sold, by means of the work-back calculation. 10 7 The Court of Appeals noted the definition for market value (price) at the well in Black s Law Dictionary to be [t]he value of oil or gas at the place where it is sold, minus the reasonable cost of transporting it and processing it to make it marketable. 8 Reed v. Hackworth, 287 S.W.2d 912 (Ky. 1956); Warfield Natural Gas Co. v. Allen, 261 Ky. 840, 88 S.W.2d 989 (1935); Rains v. Kentucky, 200 Ky. 480, 255 S.W. 121 (1923). 9 Baker at 594. 10 Id. at 595. 4

The court further reasoned that, if the royalty was calculated on the amount received downstream less only transportation costs, the lessor would receive one-eighth of the value of the enhanced processed gas product (rather than the raw gas produced), without having borne the costs to turn the raw gas into the more valuable product. The court held that Kentucky is an at the well state with respect to gas lease royalty valuation, and that under standard market price (value) at the well royalty clauses, the lessee is solely responsible for the costs of production - of bringing the gas to the well - but post-production costs for such marketing-related enhancements as accumulating, compressing, processing, and transporting the gas may be deducted from gross receipts before calculation of the royalty share. 11 (emphasis added) Key Considerations: Does the lease provide for valuation of the gas at the well? Is the cost a production cost, involved with bringing the gas to the well, which must be borne by the lessee, or a post-production cost, which lessee may deduct when calculating royalties? A. Oil and Gas Royalties - Responsibility for Post-Production Costs (continued) 3. West Virginia Leggett, et al. v. EQT Production Company 2016 WL 297714 Supreme Court of Appeals of West Virginia - Certified Questions from the United States District Court for the Northern District of West Virginia Issue: Interpretation of the West Virginia flat rate statute in light of Tawney: Where a flat-rate lease has been converted to a volumetric-based royalty lease pursuant to West Virginia Code 22-6-8 (the flat rate statute ), does Tawney affect a lessor s ability to deduct post-production expenses from a lessor s royalty? Does West Virginia Code 22-6-8 abrogate flat-rate leases in their entirety? This case involves two questions certified to the Supreme Court of Appeals of West Virginia: 1. Does Tawney v. Columbia Natural Resources, decided in 2006, after the enactment of West Virginia Code 22-6-8, have any effect upon the Court s decision as to whether a lessee of a flat-rate lease, converted pursuant to West Virginia 22-6-8, may deduct post-production expenses from his lessor s royalty, particularly with respect to the language of 1/8 at the wellhead found in West Virginia Code 22-6-8? (i.e., 11 Id. at 596, 597. 5

does Tawney affect the interpretation of W. Va. Code 22-6-8 and alter the point of valuation to a location other than the wellhead?) 2. Does West Virginia Code 22-6-8 prohibit flat-rate royalties only for wells drilled or reworked after the statute s enactment and modify only royalties paid on a per-well basis where permits for new wells or to modify existing wells are sought, or do the provisions of West Virginia Code 22-6-8 abrogate flat-rate leases in their entirety? Plaintiffs asserted that defendants failed to pay the full amount of royalties due under the terms of an oil and gas lease. The primary dispute concerned the interpretation of at the wellhead under the flat rate statute. EQT contended that the West Virginia statute identifies the wellhead as the point of distribution at which the royalty amount is calculated, such that the costs of production should be deducted from the royalty payment starting from the wellhead. Plaintiffs contended that West Virginia has adhered to the marketable-product rule, derived from the lessee s implied covenant to market, and that EQT should bear all costs in obtaining a marketable product, and should not be allowed to deduct post-production costs until a marketable product is obtained. The District Court concluded that the phrase at the wellhead under the West Virginia flat rate statute had not been interpreted or defined and that at first glance, it appears that West Virginia would be an at the well state based on the language of the statute, but that Tawney casts some doubt over this conclusion. 12 The original lease was entered into on October 31, 1906, and was amended and ratified four times, once for each of the plaintiffs in the case. 13 The 1906 lease stated: And it is agreed, that the lessee shall pay to the lessor for each and every well drill[ed] upon said land which produces Natural Gas, in a quantity sufficient to convey to market, a money royalty computed at the rate of Three Hundred Dollars ($300.00) per annum[.] W. Va. Code 22-6-8, enacted in 1982 (the flat rate statute ), provides: (b)... the Legislature hereby declares that it is the policy of this state, to the extent possible, to prevent the extraction, production or marketing of oil or gas under a lease or leases or other continuing contract or contracts 12 Id. at 10. 13 The District Court concluded that the amendment agreements did not appear to affect the royalty provision, and that the amendments primarily addressed utilization and pooling, which were not relevant in the case. 6

providing a flat well royalty or any similar provisions for compensation to the owner of the oil and gas in place, which is not inherently related to the volume of oil or gas produced or marketed, and toward these ends, the Legislature further declares that it is the obligation of this state to prohibit the issuance of any permit required by it for the development of oil or gas where the right to develop, extract, produce or market the same is based upon such leases or other continuing contractual arrangements [providing a flat well royalty or any similar provisions for compensation to the owner of the oil and gas in place].... (d) Unless the provisions of subsection (e) are met, no such permit shall hereafter be issued for the drilling of a new oil or gas well, or for the redrilling, deepening, fracturing,... of an existing oil or gas production well, where or if the right to extract, produce or market the oil or gas is based upon a lease or leases... providing for flat well royalty or any similar provision for compensation to the owner of the oil and gas in place which is not inherently related to the volume of oil and gas so extracted, produced and marketed. (e) To avoid the permit prohibition of subsection (d), the applicant may file with such application an affidavit which certifies that the affiant is authorized by the owner of the working interest in the well to state that it shall tender to the owner of the oil or gas in place not less than one eighth of the total amount paid or received by or allowed to the owner of the working interest at the wellhead for the oil or gas so extracted, produced or marketed before deducting the amount to be paid to or set aside for the owner of the oil and gas in place, on all such oil or gas to be extracted, produced or marketed from the well. (emphasis added) The District Court gleaned three key points from the holding of Tawney: 14 1. The general rule under West Virginia law is that the lessee bears all costs of marketing and transporting the product to the point of sale (citing Tawney), and pursuant to that rule, West Virginia appears to apply the marketable product rule albeit in a modified and more extensive manner. 2. The phrase at the wellhead was found to be ambiguous in the context of a lease, not in the context of the flat rate statute, and that the court in Tawney never 14 Leggett at 10. 7

mentioned the flat rate statute, although it had been enacted before Tawney was considered. 3. If a lessee seeks to deduct post-production costs, it must do so expressly, with particularity as to what deductions will be made and how the resulting royalty will be calculated in light of those deductions. The District Court determined that the phrase at the wellhead under the flat rate statute was just as ambiguous as the language in the Tawney leases, reasoning that the Supreme Court of Appeals of West Virginia determined that identical language did not authorize the deduction of post-production costs by the lessee. In determining that applicable law was unsettled and that questions should be certified to the Supreme Court of Appeals of West Virginia, the District Court reasoned as follows: 15 1. The context of the holding in Tawney and the context of the issue in this case were significantly different. The leases in Tawney contained at the wellhead language; however, in this case, the at the wellhead language was contained in the flat rate statute. 2. The court in Tawney did not mention the flat rate statute or indicate how its use of the at the wellhead language could impact existing leases. 3. [I]t is unclear whether the flat rate statute particularly applies to whether deductions for post-production costs are permitted. The statute appears to apply to the awarding of permits for oil and gas operations, and does not state that such provision or phrase generally applies to oil and gas royalties. 4. [T]he legislative findings and declarations within the statute appear to permit the abrogation of leases containing a flat well royalty. The court determined that the question becomes whether the 1906 flat rate royalty lease should be abrogated in favor of one that permits deductions of post-production costs, or one that does not so provide? 5. The legislative findings and declarations within the flat rate statute acknowledge that currently existing lease obligations should be respected and not impaired. Key Considerations: Should Tawney be applied to interpret the West Virginia flat rate statute? Consider the practical implications to operators if the flat rate statute is construed under the marketable product rule. 15 Leggett at 11. (emphasis added) 8

A. Oil and Gas Royalties - Responsibility for Post-Production Costs (continued) 4. Texas: Chesapeake Exploration et al. v. Hyder, et al., 59 Tex. Sup. Ct. J. 290, 483 S.W.3d 870 (2015) Supreme Court of Texas Issue: Whether the overriding royalty was free of post-production costs. The Hyder family leased 948 acres in the Barnett Shale. Chesapeake Exploration acquired the interest of the original lessee. There were twenty-nine (29) producing gas wells on the leased or pooled land, seven (7) of which were directional wells bottomed on and producing from lands not subject to the lease. Chesapeake Exploration sold produced gas to an affiliate, Chesapeake Energy Marketing, Inc. ( Chesapeake Marketing ), which gathered and transported the gas through both affiliated and interstate pipelines for sale to third-party purchasers in distant markets. Chesapeake Marketing paid Chesapeake Exploration a gas purchase price for volumes determined at the wellhead based on a weighted average of the third-party sales received less post-production costs. The overriding royalty paid to the Hyders was 5% of the gas purchase price. The trial court rendered judgement for the Hyders, awarding $575,359.90 in postproduction costs that Chesapeake had deducted from overriding royalty payments. The court of appeals affirmed. The lease contained three royalty provisions: 1. Oil Royalty Clause: 25% of the market value at the well of all oil and other liquid hydrocarbons. No oil was produced from the lease. The oil royalty bears postproduction costs because it is paid on the market value of the oil at the well. The market value at the well should equal the commercial market value less the processing and transporting expenses that must be paid before gas reaches the commercial market. 16 2. Gas Royalty Clause: 25% of the price actually received by Lessee for all gas produced from the leased premises and sold or used, free and clear of all production and post-production expenses, and provides examples of various expenses. Gas royalty does not bear post-production costs because it is based on the price Chesapeake actually receives for the gas through its affiliate, Chesapeake Marketing, after post-production costs have been paid. 16 Chesapeake Exploration L.L.C. et al, 483 S.W.3d 870, 873. (emphasis added) 9

Often referred to as a proceeds lease, the price-received basis for payment is sufficient in itself to excuse the lessors from bearing postproduction costs. 17 Although the royalty provision expressly added that gas royalty is free and clear of all production and post-production costs and expenses, and listed expenses, this additional language had no effect on the meaning of the provision. 3. Overriding Royalty Clause (In Dispute) a perpetual, cost-free (except only its portion of production taxes) overriding royalty of five percent (5.0%) of gross production obtained from directional wells drilled on the lease but bottomed on nearby land. Issue: What does the overriding royalty clause mean with regard to postproduction costs? The Hyders contended that the requirement that the overriding royalty be cost-free can only refer to post-production costs, since the royalty is by nature already free of production costs without saying so. Chesapeake contended that cost-free overriding royalty is a synonym for overriding royalty. Additional relevant lease provisions: Disclaimer: Lessors and Lessee agree that the holding in the case of Heritage Resources, Inc. v. NationsBank, 939 S.W. 2d 118 (Tex. 1996) shall have no application to the terms and provisions of this Lease. 18 [E]ach Lessor has the continuing right and option to take its royalty share in kind. The court reasoned that [t]he exception for production taxes, which are postproduction expenses, cuts against Chesapeake s argument. It would make no sense to state that the royalty is free of production costs, except for postproduction taxes. 19 Chesapeake must show that while the general term cost-free does not distinguish between production and postproduction costs and thus literally refers to all costs, it nevertheless cannot refer to postproduction costs here. 20 Chesapeake argued that because the overriding royalty is paid on gross production, the reference was to production as the wellhead, which bears production costs. The court disagreed, and reasoned that: Specifying that the volume on which a royalty is due must be determined at the wellhead says nothing about whether the overriding 17 Id. 18 The court concluded that Heritage Resources holds only that the effect of a lease is governed by a fair reading of its text. A disclaimer of that holding... cannot free a royalty of postproduction costs when the text of the lease itself does not do so. Id. at 876. 19 Id. at 874. 20 Id. (emphasis added) 10

royalty must bear postproduction costs. 21 The gas royalty does not bear postproduction costs, not because it is based on a volume other than full production, but because the amount is based on the price actually received by the lessee, not the market value at the well. 22 Regarding the lease language about the lessors option to take the royalty in kind, the court stated: The overriding royalty provision reads as though the royalty is in kind, but Chesapeake does not argue that it must be, and in fact the royalty has always been paid in cash. Were the Hyders to take their overriding royalty in kind, as they are entitled to do, they might use the gas on the property, transport it themselves to a buyer, or pay a third party to transport the gas to market as they might negotiate. In any event, the Hyders might or might not incur postproduction costs equal to those charged by Chesapeake Marketing. The lease gives them that choice. The same would be true of the gas royalty, which is to be paid in cash but can be taken in kind. The fact that the Hyders might or might not be subject to postproduction costs by taking the gas in kind does not suggest that they must be subject to those costs when the royalty is paid in cash. 23 Holding: Ruling of the Court of Appeals affirmed. The lease frees the overriding royalty of post-production costs. Cost-free in the overriding royalty provision includes post-production costs. Chesapeake was not permitted to deduct postproduction costs from the Hyders overriding royalty payments. Key Considerations: Is the royalty based on the value at the wellhead? If so, a lessee can deduct post-production costs. Is the royalty based on the price actually received by the lessee? ( proceeds lease). If so, a lessee cannot deduct post-production costs. An overriding royalty is free of production costs, but must bear its share of post-production costs, unless the lease specifies otherwise. o Consider how the specific reference to production taxes (a post-production expense) may have affected the ruling. 21 Id. 22 Id. at 875. 23 Id. 11

A. Oil and Gas Royalties - Responsibility for Post-Production Costs (continued) 5. Colorado: Lindauer v. Williams Production RMT Company 24 2016 WL 908452 Colorado Court of Appeals Issue: Can the lessee deduct costs incurred to transport gas to downstream markets beyond the first commercial market? Are such transportation costs subject to the enhancement test? Plaintiffs/lessors owned royalty interests under oil and gas leases for wells operated by WPX/lessee. Plaintiffs asserted that WPX improperly deducted transportation costs incurred beyond the first commercial market when calculating royalties. Following a bench trial, the district court entered judgment against WPX for $5.1 Million, and WPX appealed. The Court of Appeals reversed and remanded, holding that the operator s reasonable costs of transporting gas to downstream markets were deductible from royalty payments. At issue in the case were costs incurred to transport the gas to downstream markets beyond the first commercial market. The case raised two undecided questions of Colorado law regarding payment of royalties to lessors of oil and gas leases: 1. Must costs incurred to transport natural gas to markets beyond the first commercial market enhance the value of that gas, such that actual royalty revenues increase, in order to be deductible from royalty payments? 2. If the enhancement test applies to such transportation costs, must the enhancement, and the reasonableness of the costs, be shown on a month by month basis? The court answered no to the first question, and did not reach the second question. The court concluded that transportation costs are not required to meet the enhancement test and that imposing such a requirement is inconsistent with marketplace realities. Transportation costs beyond the first commercial market need not enhance the value of the gas such that actual royalty revenues increase in proportion to those costs, to be deductible from royalty payments. Because plaintiffs conceded that the costs of transporting the gas to downstream markets were reasonable, those costs were deductible from royalty payments. WPX incurred costs to transport the natural gas from the wellhead to the point of sale, including costs for compressing the gas, gathering it through small pipelines, and processing it at a plant. Once processed, the gas reached the tailgate of the 24 Now known as WPX Energy Rocky Mountain LLC. 12

processing plant and entered a large mainline pipeline. The costs of processing and transporting the gas up to the tailgate were not deducted from royalties paid to plaintiffs. WPX sold some of its gas in downstream markets, for higher prices, which involved transporting the gas to the point of sale. WPX entered into long-term contracts with pipeline companies to reserve capacity on the mainline pipelines to transport the gas from the tailgate to the downstream markets. Downstream transportation charges involved two components: (1) a demand charge to reserve space on the mainline pipelines, paid by WPX regardless of whether it used the pipeline to ship gas; (2) a commodity charge paid by WPX per unit volume actually shipped on the pipeline. The leases were silent regarding transportation costs. The parties agreed that the tailgate of the processing plant was the first commercial market and that transportation costs incurred before that point were not deductible from royalty payments. Plaintiffs contended that the costs to transport the gas downstream could only be deducted if WPX could show (1) the costs were reasonable [which was not contested] and (2) actual royalty revenues increased in proportion with the costs assessed against the royalties ( enhancement ). Plaintiffs argued that WPX must show enhancement on a month by month basis, and that transportation costs are not deductible during any month in which additional transportation costs exceed any increase in royalty achieved from selling the gas downstream. WPX contended that the enhancement test did not apply to costs incurred to transport gas to downstream markets, and that the court should consider the overall reasonableness of the long-term transportation contracts, as well as long-term benefits to royalty owners as a result of WPX s downstream marketing strategy. At trial, WPX demonstrated that its downstream marketing strategy allowed it to substantially increase the volume of production from plaintiffs wells during the eightyear period, and that, in many months, the increase in royalties resulting from higher downstream prices exceeded the deduction for transportation costs, such that the overall revenues for the eight year period were approximately $6 Million higher than if the gas had been sold at the tailgate market. The lower court interpreted Garman and Rogers 25 (discussed below) to require that all costs incurred after the gas becomes marketable must meet the enhancement test to be deducted from royalty payments. The lower court held that WPX bore the burden of proving that its transportation costs were reasonable and resulted in an actual increase in royalty revenues, and required WPX to apply the enhancement test on a month by month basis. The lower court applied the enhancement test and concluded that WPX did not establish enhancement in thirty-five months during the 8-year period, and entered judgement against WPX for $5.1 Million. 25 Garman v. Conoco, Inc., 886 P.2d 652, 661 (Colo. 1994), Rogers v. Westerman Farm Co., 29 P.3d 887, 903 (Colo. 2001). 13

The Colorado Court of Appeals agreed with WPX that Garman and Rogers did not require post-marketability transportation costs to meet the enhancement test to be deducted from royalty payments, and concluded that post-marketability transportation costs are deductible if they are reasonable, and that lessees are not required to establish that such costs enhance the value of the gas or increase royalty revenues. In Garmin, the Colorado Supreme Court addressed a certified question of whether postproduction costs, such as processing, transportation, and compression, were deductible from royalty payments where the assignment creating the royalty interest was silent on the issue. In Garmin, the court stated that: 26 To the extent that certain processing costs enhance the value of an already marketable product the burden should be placed upon the lessee to show such costs are reasonable, and that actual royalty revenues increase in proportion with the costs assessed against the nonworking interest. We are not, however, called upon today to consider the reasonableness of [the lessee s] expenses incurred to process, transport or compress already marketable gas. (emphasis added) The Court of Appeals concluded that the court in Garmin recognized transportation costs and processing costs as separate categories, and that only the reasonableness required was mentioned in connection with transportation costs. Note that, in Garmin, the royalty owners conceded that the transportation costs associated with moving marketable gas from the tailgate of the processing plant where gas enters the interstate pipeline to the point of sale are properly deductible, and that the costs incurred to process raw gas into its component parts after a marketable product has been obtained are generally deductible to the extent they are reasonable, provided such operations actually enhance the value of the product. 27 The Court of Appeals also considered Rogers, and concluded that Rogers did not expressly state that the enhancement test applies to all post-marketability costs, but instead referred specifically to production costs incurred to enhance the value of marketable gas. The Court of Appeals interpreted production costs to mean the same category of costs to which Garman applied the enhancement test - certain processing costs that enhance the value of marketable gas. 28 In Rogers, the court stated: Absent express lease provisions addressing allocation of costs, the lessee s duty to market requires that the lessee 26 Lindauer at 4, citing Garman at 661. 27 Id. at 5, citing Garman at 665 n. 8. 28 Id at 5. 14

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. Once a product is marketable, however, additional costs incurred to either improve the product, or transport the product, are to be shared proportionately by the lessor and lessee. All costs must be reasonable. (emphasis added) 29 The Court of Appeals concluded that Rogers requires only that transportation costs be reasonable, and does not require that such costs enhance the value of the gas in order to be deducted from royalty payments. 30 The court cited several considerations that militate against requiring transportation costs to meet the enhancement test, including, without limitation: 31 Commercial realities of the marketplace should be considered in determining whether to require transportation costs to meet the enhancement test. An enhancement test which compares gas prices in downstream markets to those in the local market does not account for the significant increase in volume of gas produced from plaintiffs wells as a result of the downstream marketing. A monthly enhancement test fails to take into account the long-term nature of decisions to market gas downstream, such as investment in long-term transportation contracts to guarantee access to downstream markets and obtain higher downstream prices, and those decisions cannot be made or changed on a monthly basis. Requiring operators to prove that downstream marketing enhanced the value of the gas before deducting costs each month could discourage them from pursuing a downstream marketing strategy with long-term benefits for both operators and royalty owners. Requiring operators to refrain from deducting transportation costs based solely on a month by month comparison of prices would give plaintiffs a free ride by allowing them to enjoy the long-term benefits of a downstream marketing strategy in certain months, while avoiding paying their proportionate share of the costs in other months. Key Considerations: Where is the first commercial market for the gas? Transportation costs incurred before that point are not deductible from royalty payments. Are the costs to transport the gas from the first commercial market to downstream markets reasonable? 29 Id. at 5, citing Rogers at 906.(emphasis added) 30 Id. at 7, citing Rogers at 906. 31 Id at 7, 8. 15

B. American Energy Marcellus, LLC v. Poling, et al., Circuit Court of Tyler County, West Virginia Civil Action No. 15-C-34 H Issue: Is there an implied right to pool where an oil and gas lease does not contain an express pooling clause? Plaintiff was the successor in interest lessee to an 1894 oil and gas lease, which did not contain an express pooling clause. Plaintiff also owned approximately 65% of the oil and gas. Defendants were successors to the original lessor. The lease was held by production from shallow formations. The Plaintiff sought to conduct horizontal drilling. Plaintiff sought a declaratory judgment, declaring that the subject lease contained the implied right to pool or unitize the lease with oil and gas interests in other lands and to the develop the lands jointly, or, in the alternative, for partial allotment and residue sale of unpooled oil and gas interests. Plaintiff then sought summary judgment on the request for declaratory judgment. The court granted Plaintiff s motion for summary judgment, and declared that there is an implied right to pool or unitize the oil and gas at issue in this matter with other mineral and leasehold interests for the purpose of developing oil and gas. 32 The court found that the lease was silent as to a right to pool or unitize with other mineral interests and to develop them jointly; that traditional vertical wells cannot contact enough spatial area in the shale formations to make extraction of the oil and gas economically viable from the vertical wellbore; that horizontal drilling methods allow the shale formations to be penetrated a sufficient distance through the formation to contact enough spatial area to make extraction of the oil and gas economically feasible; that the portion of the oil and gas contained within shale formations cannot be economically produced unless it is developed as part of a unit or units large enough to accommodate horizontal well bore(s); and that the oil and gas necessarily must be combined - or pooled and unitized with - mineral leasehold interests in other tracts and developed in one or more units to provide sufficient horizontal wellbore length for development and production of the oil and gas. The court concluded that the Plaintiff, as owner of the leasehold rights and the right to drill, develop and produce the subject minerals, has the implied right to pool or unitize the subject lease with other properties because whatever is necessary to the accomplishment of what which is expressly contracted to be done is part and parcel of the contract, though not specified. The court further concluded that implied covenants and implied rights are an integral part of oil and gas law, and that the technology and methods used to extract oil and gas 32 American Energy - Marcellus, LLC v. Poling et al., Circuit Court of Tyler County, West Virginia, Civil Action No. 15-C-34 H, p. 2. (emphasis added) 16

will inevitably evolve of the life of a lease, and that certain terms and conditions should be rationally left to implication, and further operations should be reasonably calculated to effectuate the controlling intention of the parties as manifested in the lease, which was to make the extraction of oil and gas from the premises of mutual advantage and profit. 33 The court reasoned that [i]n the absence of pooling and unitization rights, the bargained-for leasehold benefits inuring to the lessor and lessee and their successors and assigns -- production of oil and gas and payment of royalties -- will be diminished and the purpose and intent of such Lease will be frustrated 34 ; that an implied right to pool is consistent with the public policy of the State; and that use of new technology not known at the time of the lease did not bar development or the right to pool and unitize. The court concluded that an implied covenant to pool and unitize promotes development, prevents delay and unproductiveness, implements the intents of the parties, and is consistent with public policy. The court ordered that, although the lease was silent on the subject of pooling and unitization, plaintiff has an implied right to pool and unitize the lease with other leaseholds and mineral interests in order to exercise its explicit rights to develop the oil and gas. The court specified contract terms applicable to pooling and unitization, found to be usual and customary, to govern the rights and obligations under the lease. Key Considerations: Economics, in light of the need to accomplish the purpose and intent of the lease, i.e., production of oil and gas and payment of royalties o Traditional vertical wells were not economical o To be economical, the oil and gas needed to be developed as part of a unit large enough to accommodate a horizontal well bore. Technology - Comparison to Schoene (discussed below) o Use of new technology not known at the time of the lease did not bar development or the right to pool and unitize the lease. o Technology and methods used to extract oil and gas will inevitably evolve of the life of a lease. o Certain terms and conditions should be rationally left to implication o Further operations should be reasonably calculated to effectuate the controlling intention of the parties as manifested in the lease, which was to make the extraction of oil and gas from the premises of mutual advantage and profit. 33 Id. at 10, citing Brewster v. Lanyon Zinc Co., 140 F. 801, 811 (9th Cir. 1905) and McCullough Oil, Inc. v. Rezek, 176 W. Va. 638, 346 S.E.2d 788, 792 (1986). 34 Id. at 9. 17

C. Schoene v. McElroy Coal Company United States District Court for Northern District of West Virginia, on appeal to United States Court of Appeals for the Fourth Circuit Case No. 16-1788 (5:13-cv-0095-JPB) Issue: Whether customary language waiving the right of subjacent support contained in a 1902 severance deed is a valid waiver against common law claims for subsidence damage caused by longwall mining. Plaintiffs/surface owners filed suit in Marshall County Circuit Court in June 2013. Defendants removed the case to the U.S. District Court for the Northern District of West Virginia. Plaintiffs own a home and 55.5 acres of surface property in Marshall County, West Virginia. Defendants conducted longwall mining beneath plaintiffs property. Plaintiffs claimed common law and statutory property damages resulting from subsidence, and alleged damages to their private use and enjoyment of the property, including damages for taking of coal interests, emotional and mental anguish, stress, and anxiety, and punitive damages. Defendants filed a motion for summary judgment, seeking to dismiss the common law claim for damages, and to limit the monetary claims under the federal and state SMCRA statutes to the diminution in value of the residence. Defendants argued that plaintiffs common law claims for support of the surface support should fail as a matter of law, because plaintiffs predecessors expressly waived the right of support and the right to recover any common law damage resulting from a loss of support. The 1902 severance deed provided as follows: Together with all the rights and privileges necessary and useful in the mining and removing of the said coal, including the right of mining the same without leaving any support for the overlying stratas and without liability for any injury which may result to the surface from the breaking of said strata... The District Court denied Defendant s motion for summary judgment, and concluded that [i]t is clear that mechanized longwall mining was not the type of mining contemplated by the parties to the 1902 deed. 35 In the January 29, 2016 Memorandum Order and Opinion Denying Defendants Motion for Summary Judgment, the District Court held: the broad form waiver of subjacent support is not a valid waiver against the subsidence damage caused by longwall mining. Longwall mining was unknown in Marshall County 35 Schoene, Memorandum Order and Opinion Denying Defendants Motion for Summary Judgment, January 29, 2016, p. 10. 18

and to the lessors at the time the instrument was executed. Longwall mining provides almost a certainty of significant subsidence and the loss of all natural water sources. On the other hand, room and pillar mining, that known in 1902, carries with it only the possibility of subsidence and not commonly the loss of water resources. 36 Footnote 9 of the January 29, 2016 Memorandum Order and Opinion states: This Court is not suggesting that the invalidity of the waiver prevents the mining of the coal. The Lessors clearly intended for the coal to be removed. This holding is limited to a ruling that the coal producer must pay the landowner for all of the damage caused by the mining operations. 37 In March 2016, the jury concluded that the pre-mining fair market value of plaintiffs home was $184,000, and that the post-mining fair market value with no repairs was $90,000, resulting in a diminution in value of $94,000. The jury also concluded that the cost to repair the plaintiffs dwelling was $350,000, that the cost to repair plaintiffs land was $172,000, and that $25,000 would compensate the plaintiffs for annoyance, inconvenience, aggravation, and/or loss of use. In the judgment order entered March 15, 2016, the District Court concluded that the awards under the statutory scheme and the common law will be the same, 38 and the District Court awarded $547,000 to plaintiffs, consisting of $350,000 to repair the dwelling, $172,000 to repair the land, and $25,000 for annoyance, inconvenience, aggravation, and/or loss of use. In April, 2016, Defendants filed a motion to alter or amend judgment, asking the District Court to limit the damages to $94,000. The District denied the Defendants motion. Regarding the issue of common law damages, the District Court concluded that Mining methods not contemplated at the time of the severance deed may not be utilized. 39 NOTE: The District Court granted Defendants Motion In Limine relating to punitive damages, on the basis that plaintiffs indicated they would not pursue punitive damages. The order does not address Plaintiffs right to recover punitive damages, if sought. Key Considerations: What was contemplated at the time of the severance deed - subsidence resulting from mining v. the mining method or technology? 36 Id. at 13. 37 Id. 38 Schoene, Judgment Order, March 15, 2016, p. 3. 39 Schoene, Order Denying Motion to Alter or Amend Judgment, p. 2. 19

The District Court initially acknowledged that defendants had the right to mine, but by what mining method? The District Court later concluded that mining methods not contemplated at the time of the severance deed may not be utilized. The ruling is arguably limited to damages, but mining had already occurred in this case. What if coal operators were required to obtain new waivers from all surface owners, expressly acknowledging longwall mining? How does this ruling affect an operator s statutory duty to restore land, and to repair structures or compensate for the diminution in value to structures? D. Contraguerro et al. v. Gastar Exploration, et al. Marshall County Circuit Court, on appeal to the Supreme Court of Appeals of West Virginia, Case # 14-C-89 Issue: Whether non-executory and/or non-participating royalty owners must ratify or approve pooling provisions in oil and gas leases in order for the pooling provisions, and the units created thereby, to be valid. Plaintiffs own a one-fourth non-executive, non-participating royalty interest in a single tract, containing 105.9 acres, which is part of a larger 700-acre unit. Defendants are PPG Industries, Inc. (lessor) and Gastar Exploration, Inc. (lessee). The lease at issue contains a provision permitting pooling or unitization of mineral estate interests. Plaintiffs are not parties to the lease. Plaintiffs filed a motion for summary judgment, seeking a declaration that the lease was invalid and void to the extent that it permitted Gastar to pool plaintiffs royalty interest with interests owned by others, and that the unitization or pooling of plaintiffs royalty interest in the unit without their consent was invalid. Plaintiffs predecessors in title were Mabell Thiess, widow, and Ada Parsons and her husband. Deed dated October 2, 1946, from Mabell Thiess, widow, and Ada Parsons and husband, to John K. Wenzel, contained the following reservation language: There is also excepted and reserved one-eighth (1/8) of the oil and gas underlying said land, which exception includes the one-sixteenth (1/16) of the oil and gas heretofore reserved... with the right to the party of the second part to lease said land for oil and gas purposes and receive any and all delay rentals that may be received under and by virtue of any lease executed by him, his heirs or assigns, covering said land. Plaintiffs acquired only those rights that were reserved in the 1946 deed. PPG acquired its interest through John Wenzel. PPG leased to Gastar the oil and gas of the subject 20

property, and oil and gas underlying more than 3,000 acres of surrounding property. Gastar unitized 700 acres, including the subject 105.9 acre tract. West Virginia case law recognizes that mineral deeds may create non-executory interests, either by express words, or by use of language such as when produced. 40 In Donahue v. Bills, the court held: [T]he reservation contained in the deeds to the plaintiffs reserving [to defendants] one-half of all minerals underlying the soil, with the right to lease, allows the defendants to enter into leases of that mineral without the consent or written signature of the plaintiffs to any lease thereof, and that the defendants have the right to execute leases for the plaintiffs one-half of the mineral underlying the soil; and that any other interpretation would make the reservation meaningless... (emphasis added) (ellipses in original). 41 Gastar argued that because the common law in West Virginia gives an executive rights holder the right to lease without the consent of the royalty interest holder, common law should also provide that the non-executive, non-participating royalty interest holder should not be required to consent to effectuate an agreement to pool or unitize a mineral estate interest subject to the lease. The court determined that [t]he present Court has been presented with no West Virginia precedent from any party herein regarding the specific issue of requiring an executive rights holder to obtain the consent of a non-participating royalty interest owner to pool or unitize their oil and gas interests. It would appear that said specific issue is one of first impression in the State of West Virginia. 42 Gastar asserted that Boggess v. Milam 43 stands for the proposition that West Virginia views pooling in solely a contractual sense, rather than a cross-conveyance sense. Under a contractual approach, after a pooled unit is created, the owners of the separate parcels making up the unit own their interests as they did prior to creation of the pooled unit, in contrast to a cross-conveyance approach, where all parties own undivided interests under the unitized tract. In Boggess, the plaintiff held a minor interest in oil and gas of a 116 acre tract, and withheld his consent to a unitization agreement involving the 116 acre tract and an adjoining 53 acre tract. The plaintiff contended that the unitization agreement, which had been executed by other oil and gas owners, destroyed the identity of the separate 40 Davis v. Hardman, 148 W. Va. 82 41 Donahue v. Bills, 172 W.Va. 354, 305 S.E.2d 311 (1983). 42 Contraguerro et al. v. Gastar Exploration, Inc. et al, Case # 14-C-89, Circuit Court of Marshall County, West Virginia, Order Regarding Motions for Summary Judgment, p. 9. 43 Boggess v. Milam, 127 W. Va. 654, 34 S.E.2d 267 (1945). 21