HighMount Exploration & Production LLC, and Dominion Oklahoma Texas Exploration & Production, Inc. v. Harrison Interests, LTD., Dan J. Harrison III, and BFH Mining LTD.

Summarize Case

Related Cases

05/13/2015 Cause No. 14-15-00058-CV IN THE FOURTEENTH COURT OF APPEALS HOUSTON, TEXAS ________________________________________________________ HIGHMOUNT EXPLORATION & PRODUCTION, INC., AND DOMINION OKLAHOMA TEXAS EXPLORATION & PRODUCTION, INC. Appellants, v. HARRISON INTERESTS, LTD., DAN J. HARRISON, III, AND BFH MINING, LTD., Appellee. _________________________________________________________ On Appeal from Cause No. 2009-06060 In the 190th Judicial District Court of Harris County, Texas The Honorable Patricia J. Kerrigan Presiding APPELLANTS’ BRIEF FARNSWORTH & vonBERG, LLP T Brooke Farnsworth brooke@fvllp.com ORAL ARGUMENT State Bar No. 06828000 REQUESTED Bennett S. Bartlett bennett@fvllp.com State Bar No. 01842440 333 North Sam Houston Parkway, Suite 300 Houston, Texas 77060 (281) 931-8902 – telephone (281) 931-6032 – facsimile ATTORNEYS FOR APPELLANTS IDENTITY OF PARTIES AND THEIR COUNSEL The following is a complete list of the names and addresses of all parties to the trial court's final judgment, or their successors in interest, and the names and addresses of all trial and appellate counsel: APPELLANTS: APPELLEES: EnerVest Operating, LLC, Harrison Interests, Ltd., (successor in interest to HighMount Dan J. Harrison, III, and Exploration & Production LLC), and BFH Mining, Ltd. EnerVest Energy Institutional Fund XIII-A, L.P., EnerVest Energy Institutional Fund XIII-WIB, L.P., and EnerVest Energy Institutional Fund XIII-WIC, L.P. (successors to HighMount Exploration & Production Texas LLC). COUNSEL: COUNSEL: T Brooke Farnsworth Charles S. Kelley State Bar No. 06828000 State Bar No. 11199580 Bennett S. Bartlett Quinncy N. McNeal State Bar No. 01842440 State Bar No. 24074690 Farnsworth & vonBerg, LLP Mayer Brown LLP 333 North Sam Houston Parkway 700 Louisiana Street Suite 300 Suite 3400 Houston, Texas 77060 Houston, Texas 77002 telephone: 281-931-8902 telephone: 713-238-3000 facsimile: 281-931-6032 facsimile: 713-238-4703 www.farnsworthvonberg.com www.mayerbrown.com TRIAL JUDGE: Patricia J. Kerrigan 190th Judicial District Court i TABLE OF CONTENTS IDENTITY OF PARTIES AND THEIR COUNSEL. . . . . . . . . . . . . . . . . . . . . . . . i TABLE OF CONTENTS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ii INDEX OF AUTHORITIES. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . iv STATEMENT OF THE CASE. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . vi STATEMENT ON ORAL ARGUMENT. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . vi ISSUES PRESENTED FOR REVIEW. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . vii STATEMENT OF FACTS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 ARGUMENT SUMMARY. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 ARGUMENT.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 I. STANDARD OF REVIEW.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 II. KEY PROVISIONS OF THE ROYALTY AGREEMENT.. . . . . . . . . . . . . . . . . . . . . 7 A. The royalty calculation methodology in the agreement. . . . . . . . . . . . 7 B. The post-production cost-sharing methodology in the agreement.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 III. THE TWO ISSUES CHALLENGED IN THIS APPEAL. . . . . . . . . . . . . . . . . . . . . . 13 A. Harrison's simplistic reading of the fuel gas provision is contradicted by other specific provisions of the agreement, and by an integrated reading of the agreement as a whole. . . . . . . . . . . . . . 13 ii B. Because the majority of the natural gas from the Subject Interests is compressed "downstream" from components of a "central facility," HighMount's compression charges are permissible "Marketing Costs" under the royalty agreement. . . . . . . . . . . . . . . . 20 CONCLUSION. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25 PRAYER. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25 CERTIFICATE OF COMPLIANCE.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27 CERTIFICATE OF SERVICE. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27 iii INDEX OF AUTHORITIES Cases: Alamo Nat'l Bank v. Hurd, 485 S.W.2d 335 (Tex. Civ. App.— San Antonio 1972, writ ref'd n.r.e.). . . . . . . . . . . . . . . . . 1 Atlantic Richfield Co. v. Holbein, 672 S.W.2d 507 (Tex. App.—Dallas 1984, writ ref'd n.r.e.) .. . . . . . . . . . . 13 Bendigo v. City of Houston, 178 S.W.3d 112 (Tex. App.— Houston [1st Dist.] 2005, no pet.). . . . . . . . . . . . . . . . . . . . . . 6 Birnbaum v. SWEPI, LP, 48 S.W.3d 254 (Tex. App.—San Antonio 2001, pet. denied). . . . . . . . . . . 13 Cigna Ins. Co. v. Rubalcada, 960 S.W.2d 408 (Tex. App.— Houston [1st Dist.] 1998, no pet.). . . . . . . . . . . . . . . . . . . . . . 6 Comm'rs Ct. v. Agan, 940 S.W.2d 77 (Tex. 1997). . . . . . . . . . . . . . . . . . . . . . . . . . 6 Forbau v. Aetna Life Ins. Co., 876 S.W.2d 132 (Tex. 1994). . . . . . . . . . . . . . . . . 19 Heritage Resources, Inc. v. NationsBank, 939 S.W.2d 118 (Tex. 1996). . . . . . 9, 10 MMP, Ltd. v. Jones, 710 S.W.2d 59 (Tex. 1986). . . . . . . . . . . . . . . . . . . . . . . . . . . 6 Read v. Britain, 414 S.W.2d 483(Tex. Civ. App.— Amarillo), aff'd, 422 S.W.2d 902 (Tex. 1967). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 Royal Indem. Co. v. Marshall, 388 S.W.2d 176 (Tex. 1965). . . . . . . . . . . . . . . . . 19 Santanna Natural Gas Corp. v. Hamon Operating Co., 954 S.W.2d 885 (Tex. App.— Austin 1997, pet. denied). . . . . . . . . . . . . . 18 iv Other Authorities: Edward B. Poitevent, II, Post-Production Deductions from Royalty, 44 S. Tex. L. Rev. 709 (Summer 2004). . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 Ernest E. Smith and Jacqueline Lang Weaver, Texas Law of Oil and Gas (2nd ed. 2014 LexisNexis). . . . . . . . . . . . . . . . . . 9 Patrick H. Martin and Bruce M. Kramer, Williams & Meyers, Oil and Gas Law (LexisNexis 2014).. . . . . . . . . . . . . 10 Williams & Meyers, Manual of Oil & Gas Terms (14th ed. 2009). . . . . . . . . . . . 17 v STATEMENT OF THE CASE Nature of the Case: Appellee royalty interest owners brought suit alleging that the appellants breached an oil and gas royalty agreement by improperly deducting post-production costs from appellees' royalty payments. Trial Court: The 190th Judicial District Court of Harris County, Texas The Honorable Patricia J. Kerrigan presiding. Trial Disposition: Trial court granted summary judgment finding that appellants (1) improperly deducted marketing charges from appellees' royalty payments, and (2) failed to pay royalties to appellees on natural gas used as fuel in compressors necessary to transport natural gas to third party lines. The final judgment awards specific damages. STATEMENT ON ORAL ARGUMENT How the parallel natural gas streams at issue in this appeal are gathered, transported, treated, and processed, particularly in light of industry custom and practice, bears heavily on the legal questions in this appeal. HighMount believes oral argument will assist the court in understanding the facts underpinning the parties’ legal arguments. vi ISSUES PRESENTED FOR REVIEW Issue No. 1: Payment of royalty on gas consumed as fuel. The royalty agreement between HighMount as producer and Harrison as royalty owner requires HighMount to pay royalties on the "gross proceeds" received for gas remaining after processing. Did the trial court err in ordering HighMount to pay royalty on gas used as fuel prior to processing when HighMount receives no payment for natural gas used as fuel prior to processing? Issue No. 2: Deduction of marketing costs. The same agreement allows HighMount to charge Harrison 10 cents per MCF of gas to recoup capital costs for equipment installed "downstream" from a defined type of gas production facility. Did the trial court err in disallowing all of HighMount's charges when only a small portion of the gas does not pass through equipment installed downstream from such a facility? vii STATEMENT OF FACTS Introduction This appeal asks the court to construe an oil and gas royalty agreement.1 The agreement was written in 1990 in conjunction with Harrison Interests' sale of mineral interests to Meridian Oil Production Inc. R 9. As part of the consideration for the sale, the appellees (collectively, "Harrison") reserved a 5% non-participating royalty interest in conveyed properties and a 5% overriding royalty interest in conveyed leases.2 R 9. The agreement defines the conveyed properties and leases together as the "Subject Interests." R 19. HighMount acquired Meridian's interest in 2007 from Dominion, also an appellant. R 499. Based upon a review of audited royalty payment records, it appears that HighMount was using the same accounting practices (at least up to the time Harrison brought this suit) for royalty payments under the parties' agreement that both Dominion and the earlier royalty payors had been using. R 324, 499-500. 1 A copy of the agreement is included as appendix B. Because the only copies of the agreement in the record are degraded photocopies, we have retyped the relevant provisions of the agreement and have included them in appendix B 2 While there are distinctions between nonparticipating royalties and overriding royalties, those distinctions have no bearing on this dispute. See generally Alamo Nat'l Bank v. Hurd, 485 S.W.2d 335, 339 (Tex. Civ. App.— San Antonio 1972, writ ref'd n.r.e.) (discussing several Texas Supreme Court decisions holding that an overriding royalty is royalty). 1 Shortly after HighMount's acquisition of the Subject Interests in 2007, Harrison hired a valuation analyst named Alton R. Davis to audit HighMount's royalty payments. R 320. The audit process continued over the next two and a half years (that period included a litigation tolling agreement between the parties), and culminated in an audit report in the summer of 2010. Id. This appeal arises from a summary judgment against HighMount over two issues from the audit report that the parties could not resolve. Appx A. Gas Production from the Subject Interests The issues in dispute concern, first, HighMount's use of gas produced from the Subject Interests to power gas compressors and gathering equipment on the Subject Interests before the gas is sold to a third party, and second, a marketing charge of 10¢ per thousand cubic feet ("MCF") of gas that HighMount charges Harrison for preparing gas from the Subject Interests for market. A review of HighMount's post-production activities will help put these two issues in context. HighMount or its affiliate gathers gas from numerous wells on the Subject Interests and then transports the gas through a field separator where liquids (oil and water) are removed from the gas and sent to tanks. R 502-03. Approximately 95% of the gas produced from the Subject Interests is then sent to a central facility referred to as the Canyon Ranch DP-6 Station ("DP6"). Id. A diagram of wells and gathering 2 lines on the Subject Interests is attached as appendix C. See R 583. DP6 has been highlighted for the court's convenience. Two separate gas streams enter DP6, a "lean" gas stream and a "rich" gas stream. R 503. A diagram of the equipment and transmission lines at DP6 is included as appendix D. See R 584. The two separate intake lines have been highlighted in different colors, and the both lines begin at the top of the page. The lean gas comes into DP6 in an 8-inch pipeline and immediately goes through two compressors. R 503. After compression it goes through separators, an amine unit,3 and a heater, and is then delivered to a third party for transportation to market. Id. The rich gas comes into DP6 through a 20-inch pipeline, immediately goes through a separator and meter, and then flows through two compressors prior to delivery to a third party, DCP Midstream, LLP, for transportation to DCP's Sonora Plant. R 503. At the Sonora Plant, it is further compressed and processed to extract natural gas liquids such as ethane, propane, butane, and natural gasoline. Id. The remaining gas that then emerges from the plant outlet or "tailgate" of the Sonora plant, primarily methane, is referred to as "residue gas." The residue gas is delivered 3 Amine units are used to remove contaminants from a gas stream, most commonly hydrogen sulfide (H2S) and carbon dioxide (CO2). 3 at the tailgate to DCP Midstream for transportation to Katy, Texas where it is sold. Id.4 Thus, the rich gas—unlike the lean gas—is compressed by HighMount after it undergoes other processing steps rather than before. The crux of this appeal is whether or not HighMount is correctly paying royalties under the various inter-related terms of the royalty agreement. To answer that question, the Court will have to apply provisions of the royalty agreement to the processing steps just discussed. We will quote sections of the agreement below as they become relevant. ARGUMENT SUMMARY The first issue in this appeal invokes the well-established rule that courts must read a contract as a whole to ascertain the drafters' intent. Based on a single sentence in the royalty agreement, Harrison argues that HighMount must find some way to pay royalties on the small portion of gas from the gas stream that is consumed as fuel in gathering and compressing the rest of the gas stream for market. The trouble with that claim is that it runs counter to everything else in the agreement. It contradicts the instruction that the royalty obligation will only reach fuel gas for which HighMount alone receives "proceeds." It is incongruent with the fact that both parties share the 4 The remaining 5% of the gas goes through a facility named “DP2,” but Harrison has never complained about or taken issue with paying any charges associated with DP2. 4 burden of the compression and gathering costs if a third party compresses and gathers the gas. And it ignores the fact that royalties are paid on residue gas, which is the gas remaining after processing, meaning that the gas used as fuel for processing is excluded from the royalty calculation. Accordingly, this Court must reverse the summary judgment in Harrison's favor and render a decision holding that the royalty agreement does not require HighMount's successor in interest to pay royalties on gas used as fuel before the gas stream is processed downstream. The second issue, unlike the first, requires a remand because there is an open fact question. While it is unquestioned that gas enters DP6 in two streams, Harrison's expert witness discussed only the path taken through DP6 by the lean gas—the much smaller gas stream. He concluded that because the lean gas stream was compressed before undergoing the processes associated with a "central facility" (heating, separating, and metering), the compression did not occur "downstream" from a central facility and was therefore not eligible for the marketing deduction in the royalty agreement. In contrast, the larger rich gas stream, which Harrison's expert did not discuss, is compressed after it undergoes the processes associated with a "central facility." Consequently, that stream does qualify for the 10¢ per MCF marketing fee charged by HighMount. Determining the correct charges cannot be accomplished by this 5 Court, however, because the parties never undertook the necessary discovery to delineate the damages for rich gas from those for lean gas. Therefore, the trial court's damage calculation must be reversed and remanded for further findings. ARGUMENT I. STANDARD OF REVIEW. Because the trial court disposed of this case on summary judgment, its decision is to be reviewed de novo. Bendigo v. City of Houston, 178 S.W.3d 112, 113 (Tex. App.— Houston [1st Dist.] 2005, no pet.). When, as here, the parties filed competing summary judgment motions on the same issues, and the trial court granted one and denied the other, the court is to review the summary judgment evidence presented by both sides and if possible determine all questions presented. Comm'rs Ct. v. Agan, 940 S.W.2d 77, 81 (Tex. 1997); Cigna Ins. Co. v. Rubalcada, 960 S.W.2d 408, 411-12 (Tex. App.— Houston [1st Dist.] 1998, no pet.). At the same time, because HighMount was the losing party, this court must take all evidence favorable to HighMount as true, indulge every reasonable inference in its favor, and resolve any reasonable doubt in its favor as well. MMP, Ltd. v. Jones, 710 S.W.2d 59, 60 (Tex. 1986). 6 II. KEY PROVISIONS OF THE ROYALTY AGREEMENT. A. The royalty calculation methodology in the agreement. This appeal challenges two trial court rulings on the proper calculation of Harrison's royalties. Understanding the royalty payment method established by the royalty agreement is critical to understanding how the court erred in its rulings. Paragraph 4 of the agreement contains the royalty payment provisions and is divided into five subparagraphs. Subparagraph (a) provides that royalty payments are to be measured not by the volume of gas produced but on the gross proceeds from gas sold: (a) As to gas produced or to be produced from the Subject Interests under a Short Term Sale, the royalties shall be Owners' royalty share of the gross proceeds for the first sale or disposition of the gas from the Subject Interests, . . . . [Appx B ¶ 4 (emphasis supplied)].5 Subparagraph (c) provides that when produced gas contains liquid hydrocarbons that can be separated from the gas stream and sold profitably, royalties are owed on both the separated liquids and the residue gas, again, based upon on gross proceeds: (c) If the gas produced from any well situated on the Subject Interests shall contain in suspension condensate, gasoline or other natural gas liquid hydrocarbons that economically can be separated from 5 Subparagraph (b) is not relevant to this appeal because it only applies to long term sales arrangements and there are no such arrangements. 7 the gas by the installation by Producer of traps, separators or other mechanical devices, then Producer shall install such devices on the surface of the Property, and Owners shall receive royalty on the condensate, gasoline or other natural gas liquids so recovered in accordance with the terms of paragraph 3 [regarding royalties on oil], together with royalty on the residue gas in accordance with the terms of paragraphs 4(a) and 4(b) of this Royalty Agreement. [Appx B ¶ 4 (emphasis supplied)]. When produced gas, including previously separated gas, is processed6 for the purpose of removing not only liquid hydrocarbons but other elements of value such as sulfur, helium, and carbon dioxide, subparagraph 4(d) allows HighMount to deduct processing costs from the royalty on the separated elements, while royalty on residue gas is again measured on gross proceeds: (d) If gas or casinghead gas or separated gas resulting from field separation produced from the Subject Interests is processed at any location by or for the account of Producer, or by or for the account of any affiliate of Producer, for the recovery and sale or other disposition for value of liquid hydrocarbons, helium, carbon dioxide, sulfur, or any other elements of the gas steam, then in lieu of royalties on gas provided in paragraphs 4(a) and 4(b), the royalties shall be Owners' royalty share of the gross proceeds less Owners' royalty share allocable portion of the reasonable, direct costs . . . of processing such gas in the plant for the recovery of such liquid hydrocarbons, helium, carbon dioxide, sulfur and other elements, and the royalties on the residue gas resulting from such processing operation attributable to gas produced from the Subject 6 The royalty agreement defines "treating" to refer to the removal of contaminants from the gas stream, explicitly stating that the term shall not refer to "processing" gas to remove valuable liquid hydrocarbons for later sale. See Appx B ¶ 2 ("treating"). 8 Interests shall be in an amount and determined as provided in paragraphs 4(a) and 4(b) above;7 . . . . [Appx B ¶ 4 (emphasis supplied)]. Because all of the gas that enters DP6 is separated to remove valuable liquids, and the rich gas is also later processed at the Sonora plant (R 500), subparagraphs 4(c) and 4(d) are the provisions applicable to this case. And both calculate royalty as a proportion of the "gross proceeds" received for "residue gas." B. The post-production cost-sharing methodology in the agreement. Royalty calculation disputes like the one presented here are common in Texas jurisprudence.8 In the case of natural gas royalties in particular, disputes arise because gas producers and royalty owners share rights to the same undivided gas stream, yet only the producer controls how the gas is marketed and sold. And while the established rule burdens the producer alone with the cost of bringing the gas to the surface, royalty owners bear their proportionate share of the post-production costs 7 Notably, the final sentence of paragraph 4(d) protects the owner by insisting that its combined royalties for the residue gas plus the separated and sold liquid hydrocarbons shall never be less than the royalty that would have been paid if the liquids stayed in the gas stream and royalty was paid on the unprocessed gas. Thus, Harrison suffers no loss if HighMount’s use of fuel to process the gas does not result in an increased royalty. Appx B ¶ 4. 8 See generally Edward B. Poitevent, II, Post-Production Deductions from Royalty, 44 S. Tex. L. Rev. 709, 713 (Summer 2004). 9 incurred between the mouth of the well and the eventual point of sale absent an agreement to the contrary.9 Post-production costs are incurred because natural gas is almost never ready for sale as it leaves the wellhead. By the time natural gas is sold, it has been treated to remove constituent elements, compressed, and transported to the point of sale. Each of these procedures has an associated cost. While parties are free to divide the cost of those operations as they wish, the traditional approach divides the cost proportionally between the parties based upon the parties' ownership percentages.10 The disputes in this appeal arise from a detailed agreement which bears all the earmarks of sophisticated industry players who recognized that their gas would need to undergo various post-production procedures before being transported to a downstream point of sale. Before we turn to the two specific issues in this appeal, it is important to look at the agreement as a whole to understand the overall cost-sharing scheme that they applied to post-production costs. 9 See Ernest E. Smith and Jacqueline Lang Weaver, Texas Law of Oil and Gas, §4.6[C] (2nd ed. 2014 LexisNexis) (The royalty “must bear its proportionate share of costs incurred subsequent to production.”) citing Heritage Resources, Inc. v. NationsBank, 939 S.W.2d 118 (Tex. 1996). 10 See generally Patrick H. Martin and Bruce M. Kramer, Williams & Meyers, Oil and Gas Law, § 645 (LexisNexis 2014) (costs incurred subsequent to production are to be borne on a pro rata basis between operating and nonoperating interests). Royalty is usually subject to post-production costs, including taxes, treatment costs to render it marketable, and transportation costs. See also Heritage Resources v. Nationsbank, 939 S.W.2d at 122. 10 Following customary practice, the parties decided that the royalty owner would bear its fair share of those costs. The agreement's "General Terms" allow the producer to deduct marketing costs from the owner's royalty up to a maximum of 10¢ per MCF: (b) All royalties shall be determined and delivered or paid to Owners after deducting therefrom the following costs: (i) as to gas produced from the Subject Interests, Owners' royalty share of Producer's monthly Marketing Costs for such gas; however, for purposes of this paragraph 7(b), Producer's monthly Marketing Costs (whether actually incurred by Producer or an affiliate of Producer or charged to the Producer by a third party) shall not exceed ten (10) cents per MCF . . . [Appx B ¶ 7.(b)(i)]. "Marketing Costs" includes post-production processes necessary to make the gas marketable, and the parties burdened the royalty owner with its proportional share of those costs up to a 10¢ per MCF maximum. The agreement also allows the producer to deduct post-production costs associated with extracting liquid hydrocarbons from the owner's royalty. Paragraph 4(d) of the agreement, which we quoted above, addresses the royalty to be paid on both the extracted elements of the gas stream and the residue gas. The royalty on the extracted elements is subject to a deduction for "[o]wners' royalty share allocable portion of the reasonable, direct costs . . . of processing such gas in the plant for the 11 recovery of such liquid hydrocarbons, helium, carbon dioxide, sulfur and other elements, . . . ." [Appx B ¶ 4(d)]. Again, the parties proportionately share those costs. Transportation costs are yet another expense that may be deducted from the royalty payments under the agreement. As we discuss in more detail in section III of this brief, the parties chose to measure the owner's royalty percentage not by the market value of the gas sold, but by the "gross proceeds" received for the gas. The definition of "gross proceeds" instructs that third-party transmission fees are deductible from royalty payments: In the event Producer transports, or causes to be transported, gas production from the Subject Interests on a gas transmission line to a market or sale "gross proceeds" for such gas shall be determined after deducting any fees or charges incurred by Producer from the owner of the gas transmission line for such delivery or transportation to such market or sale; [Id. ¶ 2 ("gross proceeds")]. Thus the agreement allows deduction of Marketing Costs, certain processing costs, and transportation costs from the owner's royalty payments. These post-production deductions share a common feature: they each benefit the parties jointly. Compression makes gas marketable for both parties' benefit. Extracted liquid hydrocarbons are sold for both parties' credit. Transportation takes gas in which both parties have an interest to a location for sale. The agreement, in other words, has a 12 basic approach to post-production procedures: where the benefits are shared, the costs are shared. This cost-sharing arrangement can also be seen in the alternative marketing arrangement the agreement permits (but that Harrison never opted to take advantage of). The agreement allows the owner to take its gas in kind for short-term sales.11 If Harrison did so, it would bear the costs of compressing and treating its own gas and transporting that gas to market. Thus when, as here, the producer takes those steps for the owner, it does so for both parties' benefit, and the parties share the agreed-upon post-production costs proportionately. III. THE TWO ISSUES CHALLENGED IN THIS APPEAL. A. Harrison's simplistic reading of the fuel gas provision is contradicted by other specific provisions of the agreement, and by an integrated reading of the agreement as a whole. The first issue in this appeal is whether or not Harrison should be paid royalties on gas used as fuel to operate HighMount's compressors and gathering equipment in the field. Compression and gathering are necessary steps in preparing the gas for market, and HighMount's compressors and gathering equipment obviously require an 11 The relevant language in paragraph 7(g) of the agreement begins: In the event that Owners' royalty share of gas is not committed to a Long Term Sale in accordance with the provisions of this Agreement, then at any time and from time-to-time Owners make elect to take Owners' royalty share of gas production in kind and use or market same for their own account . . .. 13 energy source. Following industry custom, HighMount uses gas from the wells it operates to run its compressors and gathering equipment.12 There is no question that the gas consumed as fuel improves the value of the remaining gas by making it available for subsequent sale. And because the parties have proportionate interests, the reduction in the gas quantity reduces the parties' interests proportionately. Therefore, given the royalty agreement's cost-sharing approach to post-production procedures, it follows that the parties would jointly shoulder the loss of gas consumed for their mutual benefit. Harrison nevertheless complains that it should be paid royalty on the gas used as fuel. Its argument rests upon a selective reading of the single sentence that constitutes paragraph 4(e) of the agreement: (e) Owners shall receive their royalty share of the gross proceeds for gas used or utilized on or off the Subject interests, such as gas used for fuel. Harrison's deceptively simple conclusion from this sentence is that HighMount must find some way to pay Harrison for gas consumed in compression and gathering. 12 It is common industry practice to use gas as fuel to run treatment equipment on the lease premises. See, e.g., Atlantic Richfield Co. v. Holbein, 672 S.W.2d 507, 516 (Tex. App.—Dallas 1984, writ ref'd n.r.e.) (“uncontroverted testimony was that it is an industry-wide practice to deduct the allocated volume for fuel gas before computing the settlement owed to royalty owners); Birnbaum v. SWEPI, LP, 48 S.W.3d 254, 255 (Tex. App.—San Antonio 2001, pet. denied) (trial court's summary judgment finding that no royalties were due on gas used as plant fuel and compressor fuel affirmed). 14 When this sentence is put in the context of the rest of the agreement, however, it becomes clear that the drafters of the royalty agreement never intended for royalties to be paid on fuel gas used in compression and gathering and there are several reasons for this conclusion. To begin with the most obvious, HighMount did not receive any "proceeds" from the gas used to run the compressor or the gathering lines. We acknowledge that the agreement defines the term "gross proceeds" quite broadly in an effort to reach the different kinds of commercial arrangements a producer might make to sell the produced gas: "gross proceeds" shall mean the entire economic benefit and all consideration in whatever form received by or accruing to Producer or an affiliate of Producer, including but not limited to sales proceeds or proceeds or benefits of an exchange, prepayments for future production, reimbursements for severance taxes or for other taxes or costs, settlements or payments for the release or amendment of a sales contract or arrangement, and take-or-pay payments or settlements and the like, and any insurance proceeds from lost or destroyed oil and gas, . . . . [Appx B ¶ 2]. But even under that broad definition, HighMount's use of gas in compressing and gathering does not qualify as the sort of "proceeds" that the parties intended to reach. The sort of consideration that they did intend to reach can be discerned from the subsequent sentences of the definition. Each example of the type of economic benefit that the parties envisioned as "gross proceeds" is one in which the 15 producer—and the producer alone—would receive an economic benefit in a quid pro quo exchange with another party other than the royalty owner: transactions such as a prepayment for future production, a recovery under a take-or-pay arrangement, a payment for the release of a contract, a payment of insurance proceeds for lost or damaged gas, or the benefit of an exchange of some sort. Unlike all of those examples, HighMount's use of gas for fuel does not arise from any sort of exchange, sale, or other payment. HighMount receives nothing in the way of proceeds or other direct consideration from any other party when it uses gas for fuel. Instead, the gas consumed as fuel to compress and gather the rest of the gas stream is a post-production "cost" to HighMount and Harrison alike rather than a "proceed" of any sale or exchange. Furthermore, the economic benefit that does flow from the use of gas as fuel does not accrue exclusively "to Producer" as required by the definition of gross proceeds. Appx B ¶ 2. Both parties obtain the benefit of the gas reaching a market as a result of compression and gathering. If HighMount paid royalty on that gas, Harrison would get a windfall, a double dip of sorts, because both parties would be paid for gas sold at market, but only Harrison would also be paid for the gas consumed in making the remaining gas marketable. This uneven treatment is at odds with both the specific language of the agreement and the drafters' well-expressed 16 intent that the jointly-benefitting parties share in the post-production costs required to obtain those benefits. A further problem with Harrison's reading becomes apparent when one is confronted with the difficulty of putting a value on gas used as fuel. There are no proceeds received for the gas from which one could calculate Harrison's royalty. Nor is there any sort of exchange or trade that one could look to as a relative value. The sale price many miles downstream is not directly helpful because the gas has a very different value at that location, having been augmented by compression, processing, and transportation. Royalty could be calculated based on the downstream value by "backing out" the specific charges for treatment and transportation (as is typically done for so-called "market value" leases). But under the parties’ agreement here there are no such charges to back out. Even Harrison's own expert never identified a value for the gas used to fuel the compressors, simply using the sales price at Katy, Texas. R 440, 757. That price is not comparable, however, because the gas that is sold in Katy has traveled several hundred miles and has been compressed more than once along the route. In short, there is simply no metric for measuring the "proceeds" value of gas burned up in the process of compressing, treating, and thereby enhancing the value of the rest of the gas that is then sold at a distant location. 17 Finally, and most significantly, the parties' decision to assess royalties on "residue gas" shows that they never intended for royalties to be paid on gas consumed in the treatment and processing steps. While "residue gas" is not defined in the royalty agreement, it has a well-defined meaning in the industry. Residue gas means “[g]as remaining after processing in a separator or other plant which removes liquid hydrocarbons contained in the gas when produced.”13 By definition, then, any volume of gas that enters a separator or plant is reduced by the time it comes out of the separator or the tailgate of the plant. This reduction in volume is the key to understanding the parties' agreement on gas used as fuel. The parties' decision to base royalty payments on gross proceeds received for "residue gas" is a designation of the volume of gas on which royalties would be due: namely, the volume of gas leaving a separator or processing plant. Because the parties had a sophisticated understanding of oil and gas operations, they knew that the volume of gas would be reduced between the mouth of the well and the exit, or "tailgate," of a processing plant due to the loss of the liquid hydrocarbons 13 Williams & Meyers, Manual of Oil & Gas Terms, 835 (14th ed. 2009). Accord Amerada Hess Corp. v. Conrad, 410 N.W.2d 124, 131 (N.D. 1987) (citing 8 Williams and Meyers, Oil and Gas Law, Manual of Terms, at p. 528 (1984)); Read v. Britain, 414 S.W.2d 483, 487 (Tex. Civ. App.— Amarillo), aff'd, 422 S.W.2d 902 (Tex. 1967). 18 removed and sold, the loss of gas used to run compressors and gathering equipment, and other shrinkage.14 The parties could have very well specified that royalties would be paid on gross volumes. They chose instead to use gross proceeds, and to tie the calculation of proceeds to the sale or other disposition of the volume of gas leaving a tailgate or separator outlet after processing. By choosing that measurement method, the parties agreed that no royalty is due on any natural gas consumed or used as fuel in any operation prior to that point. Consequently, the parties never intended for royalties to be paid on gas consumed in the preliminary steps required to make the gas marketable. Harrison will contend that our reading makes the language requiring royalty payments on fuel gas meaningless. That is not at all the case. As one example, the provision would apply to a lessor's use of gas. It is not unusual for lessors to ask to use gas produced from their land as fuel for heating their homes, running equipment, etc. In exchange, the lessor might accept a lower royalty or grant an easement. The 14 See generally Santanna Natural Gas Corp. v. Hamon Operating Co., 954 S.W.2d 885, 889 n. 8 (Tex. App.— Austin 1997, pet. denied) ("Gas accounting is difficult because gas volumes and energy content fluctuate from day to day and a certain amount of volume shrinkage in the pipeline and plant is normal."). 19 value of the lesser royalty, or the value of the easement, would be the measure of the royalty owed by HighMount for fuel gas under paragraph 4(e). The choice between the parties' competing explanations of the fuel gas provision is stark. Harrison's reading, which focuses solely on a single sentence in the agreement divorced from context, and which ignores the definition of the word "proceeds" in that sentence, runs contrary to the proper task of interpretation. Courts must give effect to the expressed intent of the parties' agreement as a whole, rather than interpret one provision in isolation.15 “Courts must be particularly wary of isolating from its surroundings or considering apart from other provisions a single phrase, sentence, or section of a contract.”16 By contrast, HighMount's reading of the fuel gas sentence squares with the agreement as a whole: it comports with the overall intent of the parties to proportionately share post-production costs; it gives meaning to the term "proceeds" in the fuel gas sentence; and it finds support in the parties' decision to base "gross proceeds" on "residue gas" remaining after separation, treatment, and other gas loss. 15 See Royal Indem. Co. v. Marshall, 388 S.W.2d 176, 180 (Tex. 1965); Forbau v. Aetna Life Ins. Co., 876 S.W.2d 132, 135 (Tex. 1994). 16 Forbau, 876 S.W.2d at 133. 20 Accordingly, the court must reverse the trial court's ruling in Harrison's favor and render a decision that the parties' royalty agreement does not require royalty payments on gas used as compressor and gathering fuel. B. Because the majority of the natural gas from the Subject Interests is compressed "downstream" from components of a "central facility," HighMount's compression charges are permissible "Marketing Costs" under the royalty agreement. The trial court’s other ruling held that HighMount was not allowed to deduct gas compression charges from Harrison's royalty payments. HighMount deducts those charges pursuant to two interrelated provisions of the agreement. The first provision is found in the "General Terms" section and allows HighMount to deduct up to 10¢ per MCF for "Owners' royalty share of Producer's monthly Marketing Costs." Appx B ¶ 7. The second provision is the definition of "Marketing Costs," which reads in relevant part: "Marketing Costs" shall mean: (i) the reasonable, capital costs of property actually installed by Producer or an affiliate of Producer after the Effective Time, which property: * * * (b) is required to be installed downstream from a central facility in order to deliver gas produced from the Subject Interests to a gas transmission line or otherwise to a market; and 21 (c) is part of a facility to transport gas produced from the Subject Interests from a central facility to a gas transmission line or is part of a facility compressing or treating such gas as required for deliver to such a gas transmission line; and [Appx B (emphasis supplied)]. The Marketing Costs deductions HighMount takes are consistent with the parties' agreement. There is no question that compressing the gas mutually benefits the parties by making the gas marketable. It is equally clear that the compressors were, in the language of the agreement, "required to be installed . . . in order to deliver gas produced from the Subject Interests to a gas transmission line." Appx B. But based upon the physical location of some of the compressors vis-a-vis other gas treating equipment, Harrison found a sort of "gotcha" argument that appears to have swayed the trial court. Harrison's argument rests upon the language in the Marketing Costs definition that requires a compressing facility to be "installed downstream from a central facility." R 686, 749. While the trial court did not explain its ruling, Harrison's primary argument17 for rejecting compression charges was that the compressors were not physically located "downstream" from a "central facility," as the latter term was 17 Harrison's motion concluded with an accusation that HighMount failed to prove it built the compressor facilities in accordance with the Marketing Costs definition. R 555. If Harrison, as the movant, wanted to shift the burden of proof to HighMount, it needed to follow the procedure to file a no-evidence summary judgment motion, which it did not do. 22 defined in the agreement. Therefore, in Harrison's view, compression costs could not be deducted as Marketing Costs. To the extent the judgment below rests on this argument, it is error because the record reflects, at the very least, a genuine unresolved fact question, and at the most, a set of facts inconsistent with the trial court's ruling. A "central facility," from which compressors must be downstream, is defined in the royalty agreement as follows: "central facility" shall mean the final set of heaters, separators, meters and tanks that are operated as a unit and into which production from more than one oil or gas well on the Subject Interests is gathered for final treating and measurement prior to delivery to a gas transmission line owned or operated by a principal purchaser of gas in the Permian Basin. [Appx B ¶ 2]. With this definition as the touchstone, the evidence submitted to the trial court to explain the location of the compressors at issue consisted solely of a diagram of DP6, and brief statements in two expert reports. But even this limited information demonstrated that the rich gas did qualify for the Marketing Costs deduction even under Harrison's argument. The opinion from Harrison's expert, Don Rockwell, is the starting point because it makes HighMount's case. R 560. Rockwell looked at the diagram of DP6 and apparently missed the fact that there are two different gas inlets. Without 23 distinguishing which gas stream he was addressing, Rockwell explained that the gas is compressed at DP6 for delivery to a high pressure gas line. Based on that fact he opined that because the gas underwent additional treatment after leaving the compressors, the compressors were not downstream from a central facility: 4. Once the gas leaves the compressors, it then goes through other vessels on the facility, such as a filter separator, an eight-inch discharge meter, an amine contactor, a heat exchanger, a recovery separator, and a dehydration tower, before it flows to sale. Thus, downstream from these compressors are a series [sic] heaters, separators, meters, tanks and other vessels, where the gas is further treated and eventually sent to market. From my understanding of the Royalty Agreement, none of these compressors are downstream from a central facility, as that term is defined. [R 561]. The upshot of his analysis is telling. Rockwell concludes that because the gas flows through other treatment devices after being compressed, it can't be downstream of a central facility. By that reasoning, if the compressors are the last stop for the gas after going through other treatment devices but before it flows on to a third-party pipeline, the compressors are downstream from a central facility. HighMount's expert, Allen Cummings, recognizing that there are two streams of gas flowing into DP6, reached just that conclusion. Observing that the definition of a "central facility" does not include any reference to compressors or compression, he pointed out that the compressors at DP6, by definition, cannot be part of a central facility. R 753-54. He concluded, therefore, that because the compressors of the rich 24 gas, unlike the lean gas, are located "downstream" from the other facility components that operate as a unit, the compression charges for rich gas satisfy the Marketing Costs definition in the royalty agreement. Id. Cummings's conclusion is confirmed by the flow chart put into evidence by Harrison's expert, Don Rockwell. See R 772, 775. The print on the chart is so small that it is difficult to follow the path of the gas as it flows through the facility. To aid the Court's understanding of the schematic, HighMount highlighted the 20-inch line through which the rich gas flows, and the 8-inch line through which the lean gas flows, in different colors to make it easier to follow the path followed by the gas, and added colors for the other processing equipment on DP6 as well. See R 752, Appx D. As one can see from the diagram, the compressors for the rich gas are downstream from any other equipment, and are the last processing step for that gas prior to delivery to a gas transmission line. Accordingly, by Harrison's own argument, the rich gas is eligible for the 10¢ per MCF charge for Marketing Costs. Because the trial court's judgment makes no distinction between the funds that HighMount owes to Harrison on lean gas versus rich gas, the trial court's summary judgment must be reversed and the case remanded for further factual findings on the quantity of gas qualifying for the Marketing Costs deduction. 25 CONCLUSION The drafters of the royalty agreement went to considerable effort to narrowly circumscribe the post-production costs that the parties would share. In deciding which costs would qualify, the drafter's litmus test was mutual benefit: where the treating or processing undertaken would improve the gas for the benefit of both parties, the cost was to be shared. Nevertheless, on the basis of a single sentence in the agreement, the trial court concluded that the parties did not intend to share fuel gas. The trial court's misreading of that sentence ignores the meaning of the term "gross proceeds," misses the import of paying royalties on "residue gas," and stands at odds with the ethos of the agreement as a whole. As for the question of marketing costs, Harrison's own expert’s position on the concept of "downstream" compression demonstrates that HighMount is allowed to deduct costs on the rich gas stream flowing through DP6. PRAYER For the reasons presented, HighMount asks the Court to (1) reverse the trial court's summary judgment, (2) render a decision that HighMount has no obligation to pay royalties on gas it uses for compression and gathering fuel, (3) hold that HighMount is entitled to charge up to 10¢ per MCF for Marketing Costs for rich gas, 26 and (4) remand the case to the trial court for further findings on the amount of rich gas subject to that marketing charge. Respectfully submitted, FARNSWORTH & vonBERG, LLP By: /S/ T Brooke Farnsworth T Brooke Farnsworth State Bar No. 06828000 Bennett S. Bartlett State Bar No. 01842440 333 North Sam Houston Parkway Suite 300 Houston, Texas 77060 Telephone No. (281) 931-8902 Facsimile No. (281) 931-6032 ATTORNEYS FOR APPELLANTS 27 CERTIFICATE OF COMPLIANCE The forgoing brief was generated by computer-based word-processing software, and I certify that the total number of words counted by that software, excluding those parts of the brief to be excluded under Rule 9.4(i), totals: 6,419. /s/ Bennett S. Bartlett Bennett S. Bartlett CERTIFICATE OF SERVICE I hereby certify that a true and correct copy of the foregoing document was served via e-service to the parties listed below on May 13, 2015. Charles S. Kelley ckelley@mayerbrown.com Quinncy N. McNeal qmcneal@mayerbrown.com MAYER BROWN LLP 700 Louisiana Street, Suite 3400 Houston, Texas 77002 Facsimile: (713) 238-4703 ATTORNEY S FOR APPELLEES /s/ Bennett S. Bartlett Bennett S. Bartlett 28 APPENDIX A fa.5- 12/2/2014 616 02 PM ChllS Daniel • Otstncl Clerl< Hams County Envelope No 3354569 By CAROL WILLtAMS l.J(/\ Filed 12/2/2014 6 16 02 PM CAUSE NO. 2009-06060 ( b (p\ 213 HARRISON INTERESTS, LTD., DAN J. § IN ml!! DISTRJCt cot RT OF HARRISON Ill, AND BFH MINING § LTD., § § Plaintiffs. § § HARRIS COUNTY, TEXAS vs. § § § HIGRMOUNT EXPLORATION & § PRODUCTION, INC. AND DOMINION § 190rn JUDICIAL DISTRICT OKLAHOMA TEXAS EXPLORATION & § PRODUCTION. INC., § § Defendanu. § § FINAL JUDGMENT THE COURT, having considered the parties' pleadings. including the cross-motions for summary judgment, the summary judgment evidence attached thereto, the responses to the summary judgment motions, and the arguments of counsel for Plaintiffs Harrison Interests, Ltd., Dan I. Harrison, TU and BFH Mining. Ltd. ("Plaintiffs") and Defendants HighMount Exploration & Production LLC ("HighMount") and Dominion Oklahoma Texas Exploration & Production, Inc. (collectively, the "Defendants.,). is of the opinion and has ruled that Defendants have breached that certain Royalty Agreement, dated May 22 1 1990, the subject of tbis litigation, by withholding payment of royalties for gas production used for fuel on those properties located in Annexes I and 2 of the Royalty Agreement in Sutton and Edwards Counties, Texas (the "Subject Interests'') and by assessing improper marketing costs on the gas volwnes produced on the Subject Interests, a.s described in Plaintiffs' motions for summary judgment and more fully below. IT IS FURTHER, RECORDER'S MEMORANDU.M This Instrument Is ol poor quehty at the time of Imaging 843 ORDERED that, pursuant to the Court's signed orders ofJune 4, 2014 granting summary judgment in favor of Plaintiffs as to Plaintiffs' Motion for Summary Judgment for Royalties on Gas Used for Fuel and as to Plaintiffs' Motion for Summary Judgment for Reimbursement of Marketing Costs, Defendants are required (i) to pay royalties to Plaintiffs on all production used as fuel on the properties to which the Royalty Agreement relates. and (ii) to remove any marketing deduction as none is entitled lo be applied in light of the operations as they exist as of the date of this judgment; it is FURTHER ORDERED that Plaintiffs shall recover from Defendants all principals sums owed based on improper royalty withholdings and inappropriate marketing deductions made on royalty payments that were made (or should have been made) on or before November 30, 2014 (including a missed royalty payment in its entirety for the production month of August 2014 which is not the subject of this suit and may have been missed accidentally), in addition to prejudgment interest (as provided for under the parties' contract) calculated at the Prime Rate (as announced by Texas Commerce Bank-Houston, N.A.) plus two percent (2%) from January l, 2004 onward; it is FURTHER ORDERED that, because Plaintiffs have incWTed the attorneys fees and coW1 costs in filing the action to enforce its right of payment, they shall additionally recover these reasonable and necessary attorneys fees and costs arising out of the prosecution of this matter, as provided under Texas Civil Remedies and Practice Code § 38.001 (8) for actions in breach of contract. and the parties have announced their stipulation that, through the date of entry of this judgment only, the amount of such fees and costs that shall be payable by Defendants to Plaintiffs are $325,000, plus costs in an amount ofSl 1,200.00; it is THEREFORE, 2 844 ORDERED. ADJUDGED and DECREED that Plaintiff Harrison shall recover from Defendants, either jointly or severally, the sum of $218,637.16 in principal damages for reimbursement of improper marketing cost deductions; the sum of $68,063 .90 in principal damages for reimbursement of royalties on fuel gas use; and the sum of $100,697.03 in pre- judgment interest for payments that should have been made on or before November 30, 2014 under the royalty agreement between the parties, together with daily interest accruing on this combined amount at the rate of $55.72 per diem each day thereafter until entry of this judgment. Accordingly, Plaintiff Harrison shall recover the total of $387,398.09 from Defendants. either jointly or severalJy. in principal damages and interest, plus the additional accrued pre-judgment interest; it is FURTHER ORDERED, ADJUDGED and DECREED that Plaintiffs Dan J. Harrison, 111 and BFH Mining, Ltd., ~ shall recover from Defendants. either jointly or severally, the sum of $6,641 .27 in principal damages for reimbwsement of improper marketing cost deductions; the sum of $2,202.07 in principal damages for reimbursement of royalties on fuel gas use; and the sum of $3,023.94 in pre-judgment interest for payments that should have been made on or before November 30, 2014 wider the royalty agreement between the parties, together with daily interest accruing on this combined amount at the rate of $1.71 per diem each day thereafter until entry of this judgment. Accordingly, Plaintiffs Dan J. Harrison, III and BFH Mining, Ltd. shall each recover the total of $11,867.28 from Defendants. either jointly or sevcraUy, in principal damages and interest. plus the additional pre-judgment interest; it is FURTHER ORDERED, ADJUDGED and DECREED that Plaintiff Harrison shall recover from Defendants, either jointly or severally, the amount of $325,000 in reasonable and necessary attorneys' fees and Sll.200 for disbursements for those fees and expenses incurred up through 3 845 November 30, 20141 and that, in the event of any further legal work necessitated by post- judgment motions or practice, together with any legal work in successfully defending this judgment on appeal 1 Plaintiffs will be pernlitted to recover their reasonable attorneys' fees and expenses on further application in any additional amowus to be detemiined in the future by this Court and all defenses to such additional amounts may be urged at such time; it is FURTHER ORDERED. ADJUDGED and DECREED that Defendants shall pay post-judgment compOlmd interest on the outstanding amounts due under the judgment pursuant to Tex.as Finance Code § 304.002 from and after the date of entry of this judgment until such amounts are paid in full, and such post-judgment interest shall accrue on all amounts required to be paid hereunder and be payable at a rate of the Prime Rate (as aMounced by Texas Commerce Bank- Houston, N.A.) plus two percent (2%) compounded annually from the date of entty of the judgment until the amounts required hereunder are satisfied; and it is FURTHER ORDERED! ADJUDGED and DECREED that Defendants shall bear all costs of court. All writs and processes for the enforcement and collection of this judgment may issue as necessary. The parties agree and acknowledge that Harrison has not been paid the sum of $31,988.41 in principal for the missing royalty check for August 2014 production, which HighMount will remit along with the December payment. AU other relief sought and not expressly granted herein is DENIED. SIGNED this I.it... day of December 2014. ~~ 4 846 AGREED AS TO FORM AND STIPUU TED AS TO FEES AND EXPENSES (through Nov. 30, 2014): By:ls/ Chnrle.5 S. Kelle11 Charles S. Kelley MA YER BROWN LLP 700 Louisiana St., Suite 3400 Houston, Texas, 77002 Tel. 713-238-3000 Fax. 713-238-4634 . ATTORNEY FOR PLAINTIFFS HARRISON INTERESTS, LTD., DAN J, HARRISON, III AND BFH MINING, LTD. By: /.VT. Brooke F'arn.\-wm•/h T. Brooke Farnsworth Farnworth &. vonBerg 333 North Som Houston Pkwy Suite 300 Houston. Texas 77060 Tel. 281-931-8902 Fax. 281-931-6032 AITORNEY FOR DEFENDANTS .HIGHMOUNT EXPLORATION A PRODUCTION LLC AND DOMINION OKLAHOMA TEXAS EXPLORATION & PRODUCTION, INC. s 847 APPENDIX B R0¥AJ.'l'Y 1.GBE£MEHT This Royalty Agreement is made and entered into to be eff ect:.iva all of th9 Effective Time stated below, by and between !L\R?!SON INTERESTS, LTD., a Texas limited partnership, DAN J. HARi- Oar.DI!:~ ~ 2050 90 56S CCSO & RGN'O Ry Co. Edwards 36 &: 825 91 566 CCSD & RON'O Ry Co. Sunon & Edw1rds 3S 105 573 CCSD & RONO Ry Co. Sutton 1714&2032 106 573 CCSD & RGNG Ry Co. Sunoo 4' Edwards 1595 107 574 CCSD & RONG Ry Co. Edwards 2506 112 576 CCSD de RONO Ry Co. Edwards 33 & 828 113 571 CCSD & RONO Ry Co. S1.1ttoll &. Edwards 1180 114 577 CCSD & RONO Ry Co, Sutton 34 115 578 CCSD & RONG Ry Co. Sutton 1185 126 583 CCSD & RGNG Ry Co. Sutton 31 127 584 CCSD & RONO Ry Co. Sutton 32 207 624 CCSO & RONG Ry C.O. Sutton ms &2049 208 624 CCSD & RONG Ry Co. Sutton &: Edwards 178 209 625 CCSD & RONG Ry CO. Edwards 2673 2602 El 2 wy.2 214 214 61:7 61:1 CCSD & RONG Ry CO. CCSD &. RONG Ry Co. Edwards Edwards 28 Ir, 781 21S 628 CCSD ct RONG Ry Co. Sutton & Edward5 1179 216 628 CCSD & RGNO Ry Co. Sutton 782 219 630 CCSO &: RONG Ry Co. Edwards Bein~ tbe lan4s covered by that ce1taia deed from Oscar Appelt et ~ as gr_an1or, 10 D. 1. Hamson. dated Se~tcmber 17, 194S of record in Vohune 42, page 360 of the Deed Records of Sutton Couniy, Texas, and in Volume JS, Page 4l9, Deed Records of Edwards County, Texas, as reswveyed. Said lands being subject to that cenain Boundary Agreement by and between O. J. Harrison and W. L Miers dated January 24, 1956, of record in Volume 40, Page 369, Deed Records of Edwards Couoty, Tcxa.s. i" 3 j 1 J l l NI of Sucve~ 8l(A-63) and 116 (A-1647), originally granted lo the CCSD &. RONG Ry. Co., located in Sutton ounty, Teus. jl/1U1lo/lloAI l:N!IZJ: :z (To RoJ•ltJ A()'re. .ent• OESCRIP1ION or t,EAses 1. Oil, qas and ~ineral le••• dated Novelllll•r 5, 1971, recorded in Voluae z-17, paqe 256 ot the Hiso•ll&neoua Records or Edward• County, Texas, froa W.L. Miers and vite, Martha Miera, aa le•aor, to R.c. Roberta, a• la••••• coverinq survey 4 (A- 1250), cert. Ho. 4, Menu·d County Sobool L4nd, Oriqinal Grantee, SAVB and EXCEPl' 320 acre• committed to the Nortl\ Aln•rican Royal tiG·S, Ino. No. :i Miera '"'" Well and 320 acres committed to th• North .a.i.erican Royaltiea, Inc. tlo. l 1t4• Well, containing a total of 4 1 428.4 acree, more or les•, sW>ject: to the tallowing r•l•a••• as to sl.lrfac• ar••• and subaur!ace depths: a. Partial r•l•H• Of oil, gaa and ainaral l•••• dated April 1, 1980, racordad in Volwoe .z-29, page 762 or th• Hiscellaneoua Deed Record• of E.dward• County, Toxa•1 and b. Partial r•l•••• ot oil, qaa and mineral leas• dated February 24, 1982, recorded in Volume Z-32, pag• 864 of th• Miscellaneous D•ed Record• of Edwards County, Texas. 2. Oil, gas and 1dneral lease dated November 18, 1971, recorded in Volume 92, paq• 156 ot th• Deed R•corda ot Sutton County, Texas, trom Larmon L. cox and wit•, Paarl cox, aa le.saor, to R.C. Roberts, as les•e•, only i.naofar as such lea•• covers the Northeast Quarter (NB/4) ot Section 70 (A-1039), ccso ' 'RGNG Railway co. survey, and the Soutllweat (SW/4) ot Section 70 (A- 1672), ccso" RGNG Railvay co. survey, botll in Sutton County, Texa•. l. Oil, qas and mineral lease dated June 16, 1971, recorded in VolU111e 90, paqe 23!! of the Deed Record• ot Sutton county, Te1Ca11, from L.L. HoCandle••• et al, a• le••or, to North .!Uaer:ican aoyaltiea, Inc., aa le•see, only inaofar ae such lease covera the southeast Quarter (SE/t) ot Section 83 (A- 38), Cartiticat• 562, ccso and RGNG Railway co. oriqinal Grantee, Sutton County, Texa•. 4. oil, 9a• and 111ineral lease dated June 20, 1972, recorded in Volume 96, paqe 494 ot the O••d Recorda ot Sutton county, Texa• fro• Harold c. Stuart and wit•, Joan Skelly Stuart, a• lesaor, to North Alll•rican Royal ti••• Inc., a• les•-· only insofar as such lease covers the south•a•t Quarter (SE/4) of section Bl (A-l8), ccso and RGNG Railway co. survey, Sutton county, Texas. 5. Oil, qas and mineral lease dated July 7, 1972, recorded in Volume 96, paqe 497 ot tbo Deed Record• of Sutton county, Texas, from Xirby Petroleum Co., as lessor, to North American Royalties, Ina., as les•ee, only insofar as aucll lea•• covers the Southeast Quarter (SE/4) ot Section BJ (A-38), CCSD and RGNG Railway co. survey, Sutton county, Texas: and 6. Oil, qas and mineral lease dated July 19, 1972, recorded in Volume 96, paqe 297 of the Oeed Records ot Sutton County , Texas trom Historical Preservation, Inc., as lessor, to HNG oil Company, as lessee, only insofar as such lea- covers the southeaat Quarter (Sl!:/41 Section 83 (A-38), ccso and RGNG Railway co. SUJ."Vey, Sutton county, Taxa:11. The interest in tile Uve (5) leaaea listed above as item nu'IDbers 2 throuqh 6, inclusive, is limited to depths from tne surface down to so !~et below the base of th• · canyon Sand Formation. ] tl l ~ 1. Oil, qas and ~inaral lea9• dated June 1, 1972, recorded in Vol um• 96, paq• 62 o! the Oeod Reco~d• or Sutton County, Texas, rrom Harvey ~. Heller and Kartey A. Heller, Jr., as lessor:, to Dan J. Harrison, Jr., aa le••••· coverinq Section 83, (A-697) , Certit'icat• Ho. 0/6J2, Block 14, TWNG Ry. Co. survey, sutton County, Texa•. Sl357(2) ANNW[3 (to Royalty /\gre~ent) A. All insO"l1111ents described below are dated May 22, 1990. B. The grancee or assignee in each insaument is Meridian Oil Production Inc. C. References below to volume and page recording dara IU'e to w Deed Rei:ord.s of Sucron County, Texas, and to the Deed Records or MiscellaneoU$ Deed Records of Edward County, Texas, as indicated below. O. "M/A" means not applicable. Recording Pata Edwards Sutton Gmntor!Assimo[ ~ f&!mlx 1. SpeciaJ Wa.tTanty Harrison lnterests, Ltd., Vol: Z-47 Vol: 244 Deed (Minerals) Dan J. Harrison Ul and Page: -MS Page; 48 Bruce P. Harrison. Misc. Deed R.ecords 2. Special Wammty Dan J. Harrison m Vol: Bl Vol: 244 Deed (Surface) Page: 791 Page: 37 Deed Recordll 3. Special Warnuny Bruce F. Harrison Vol: Bl Vol: 244 Deed (Surface) Page: 785 Pase: 26 Misc. Deed Records 4. Special Wanamy Dan J. Harrison Ill Vol: N/A Vol! 243 Deed (State Tract) Page: N/A Page: 389 5. Special Warranty Bruce F. Harrison Vol: N/A Vol: 243 Deed (State Tract) Page: N/A Page: 396 6. Assignmmr Harrison Interests, Ltd., Vol: Z-47 Vol: 244 Dan J .. Harrison !U and Page: 430 Page: 12 Bruce F. Hamson Misc. Deed Records 7. Quitclaim Deed Harrison Interests, Ltd., Vol: N/A Vol: 244 Dan J , Harrison Ill and Page: N/A Page: B Bruce F. Harrison Signed for Identifkation Purpo$es: ME~ OlL PRODUcnON INC. HARRISON INTERESTS, LTD. ar-.hhE. ~ . ,. Title: ~A • "· t:->_ ,(~di..,~,,- '"Name: Title: ux J. naqison General Partner H.~t1,.1 , ROYALTY AGREEMENT 2. Definitions. “central facility” shall mean the final set of heaters, separators, meters and tanks that are operated as a unit and into which production from more than one oil or gas well on the Subject Interests is gathered for final treating and measurement prior to delivery to a gas transmission line owned or operated by a principal purchaser of gas in the Permian Basin.. “gross proceeds” shall mean the entire economic benefit and all consideration in whatever form received by or accruing to Producer or an affiliate of Producer, including but not limited to sales proceeds or proceeds or benefits of an exchange, prepayments for future production, reimbursements for severance taxes or for other taxes or costs, settlements or payments for the release or amendment of a sales contract or arrangement, and take-or-pay payments or settlements and the like, and any insurance proceeds from lost or destroyed oil and gas, provided that “gross proceeds” shall not include any fee or charge for services (transportation, compression, treating and the like) relating to gas produced from the Subject Interests after such gas leaves the Subject Interests. In the event Producer transports, or causes to be transported, gas production from the Subject Interests on a gas transmission line to a market or sale “gross proceeds” for such gas shall be determined after deducting any fees or charges incurred by Producer from the owner of the gas transmission line for such delivery or transportation to such market or sale; such fees or charges shall be for transportation of gas after it leaves facilities to which Marketing Costs, if any, relate and shall exclude fees or charges of Marketing Costs. “Marketing Costs” shall mean: (i) the reasonable, capital costs of property actually installed by Producer or an affiliate of Producer after the Effective Time, which property: (a) is depreciable for purposes of the Internal Revenue Code of 1986, as amended; and (b) is required to be installed downstream from a central facility in order to deliver gas produced from the Subject Interests to a gas transmission line or otherwise to a market; and (c) is part of a facility to transport gas produced from the Subject Interests from a central facility to a gas transmission line or is part of a facility compressing or treating such gas as required for delivery to such a gas transmission line; and (ii) charges made by a third party that is not an affiliate of Producer directly attributable to property actually installed after the Effective Time, which property: (a) is installed downstream from a central facility in order to transport gas produced from the Subject Interests to a gas transmission line or otherwise to a market; and (b) is part of a facility required to transport gas produced from the Subject Interests from a central facility to a gas transmission line, or is part of a facility compressing or treating such gas as required for delivery to such a gas transmission line. As to property actually installed by Producer or an affiliate of Producer, Marketing Costs shall be calculated as a monthly charge on a per MCF basis for the facilities to which the Marketing Costs relate, with such Marketing Costs amortized on a straight-line basis for the expected life of such facilities and based on the entire design capacity throughput of the facilities. Marketing Costs charged to Producer by a third party shall be the rate actually charged to Producer. 4. Gas. (a) As to gas produced or to be produced from the Subject Interests under a Short Term Sale, the royalties shall be Owners’ royalty share of the gross proceeds for the first sale or disposition of the gas from the Subject Interests, provided that such royalties never shall be less than Owners’ royalty share of the aggregate sum derived by multiplying the Spot Gas Price of such gas for the month or months covered by the Short Term Sale by the respective volumes of gas sold in such month or months under the Short Term Sale. (b) In the event Producer intends to make gas produced or to be produced from the Subject Interests subject to a Long Term Sale, ... (c) If the gas produced from any well situated on the Subject Interests shall contain in suspension condensate, gasoline or other natural gas liquid hydrocarbons that economically can be separated from the gas by the installation by Producer of traps, separators or other mechanical devices, then Producer shall install such devices on the surface of the Property, and Owners shall receive royalty on the condensate, gasoline or other natural gas liquids so recovered in accordance with the terms of paragraph 3 of this Royalty Agreement, together with royalty on the residue gas in accordance with the terms of paragraphs 4(a) and 4(b) of this Royalty Agreement. (d) If gas or casinghead gas or separated gas resulting from field separation produced from the Subject Interests is processed at any location by or for the account of Producer, or by or for the account of any affiliate of Producer, for the recovery and sale or other disposition for value of liquid hydrocarbons, helium, carbon dioxide, sulfur, or any other elements of the gas steam, then in lieu of royalties on gas provided in paragraphs 4(a) and 4(b), the royalties shall be Owners’ royalty share of the gross proceeds less Owners’ royalty share allocable portion of the reasonable, direct costs (excluding amortization and depreciation on pipeline and plant investment and direct overhead associated therewith) of processing such gas in the plant for the recovery of such liquid hydrocarbons, helium, carbon dioxide, sulfur and other elements, and the royalties on the residue gas resulting from such processing operation attributable to gas produced from the Subject Interests shall be in an amount and determined as provided in paragraphs 4(a) and 4(b) above; provided, however, that in the event liquid hydrocarbons, helium, carbon dioxide, sulfur or any other elements of the gas stream are recovered and sold separate from the basic gas stream as contemplated in this paragraph, the total royalties paid to Owners on such production (after deduction of the above costs) never shall be less than would have been paid to Owners if the liquid hydrocarbons, helium, carbon dioxide, sulfur, or any other elements of the gas stream had remained in, and been sold as, part of the basic gas stream. (e) Owners shall receive their royalty share of the gross proceeds for gas used or utilized on or off the Subject Interests, such as gas used for fuel. 7. General Terms. The following general terms shall apply to the royalties covered by this Royalty Agreement. (a)... (b) All royalties shall be determined and delivered or paid to Owners after deducting therefrom the following costs: (i) as to gas produced from the Subject Interests, Owners’ royalty share of Producer’s monthly Marketing Costs for such gas; however, for purposes of this paragraph 7(b), Producer’s monthly Marketing Costs (whether actually incurred by Producer or an affiliate of Producer or charged to the Producer by a third party) shall not exceed ten (10) cents per MCF and shall be charged only as to gas production put through the facility for which the Marketing Costs are charged; and (ii) taxes applicable to Owners’ royalty share of production. Owners’ royalties shall bear no other costs or expenses of any kind: (g) In the event that Owners’ royalty share of gas is not committed to a Long Terms Sale in accordance with the provisions of this Agreement, then at any time and from time-to-time Owners may elect to take Owners’ royalty share of gas production in kind and use or market same for their own account or to elect to deem royalty percentage of gas as not being produced, to the end that Owners’ share of production is stored and covered under the Balancing Provisions provided below. APPENDIX C I I i 'I .. " ' - I ... ..... ' - . \ l l \, I -!\ \'\f· -- . --- ' /'\ .,/ : . I ' ' So11nr,< F-1e1d 583 APPENDIX D - >:____ -"" v ( ---- ~----