NO. 07-09-00059-CV
IN THE COURT OF APPEALS
FOR THE SEVENTH DISTRICT OF TEXAS
AT AMARILLO
PANEL E
JANUARY 31, 2011
OCCIDENTAL PERMIAN LTD.,
APPELLANT/CROSS-APPELLEE
v.
THE HELEN JONES FOUNDATION, ET. AL.,
APPELLEES/CROSS-APPELLANTS
v.
BP AMERICA PRODUCTION COMPANY, ET. AL.,
CROSS-APPELLEES
___________________________
FROM THE 286TH DISTRICT COURT OF HOCKLEY COUNTY;
NO. 06-01-20302; HONORABLE ANDREW J. KUPPER, JUDGE
Before CAMPBELL and PIRTLE, JJ., and BOYD, S.J.[1]
OPINION
Owners of royalty interests[2] in lands in the Slaughter Field[3] brought suit seeking damages for underpaid royalties on casinghead gas[4] against the current lease operator, Occidental Permian Ltd. (“OPL”), and two former operators of the leases. The royalty owners also asserted a claim against OPL for royalties on carbon dioxide. The trial court granted summary judgment for the operators on some claims, and a jury heard the remaining claims. After a verdict in favor of the royalty owners, the trial court signed a judgment disregarding the jury’s award of attorney’s fees against OPL but otherwise awarding the damages found by the jury as to OPL. The judgment ordered that the royalty owners take nothing from the former operators.
The royalty owners appeal the trial court’s grant of summary judgment, its denial of their attorney’s fees and the take-nothing judgment against the former operators. OPL appeals the judgment against it.
We will render judgment that the royalty owners take nothing from OPL. We will affirm the summary judgment, the denial of attorney’s fees and the take-nothing judgment as to the former operators. We will remand the case for entry of a new judgment consistent with this opinion and law. We will otherwise affirm the judgment.
Background
As to the royalties on casinghead gas, six oil and gas leases are at issue. The parties agree that the royalty on casinghead gas under four of the leases is one-eighth of the “amount realized from such sale” when gas is sold at the wells. The other two leases, the parties also agree, provide a royalty on casinghead gas of three-eighths of its “market value in the field.”[5]
The six leases range in date from 1934 through 1944. The Slaughter Field is an oil-producing field, and the casinghead gas was flared until sometime in the 1940s when, according to testimony, the Railroad Commission prohibited the practice. In the late 1940s, eight lessees, including the defendants’ predecessor Stanolind Oil and Gas Company, jointly constructed the Slaughter Gas Processing Plant. The plant began operation in 1949.
The lessees individually entered into Casinghead Gas Contracts, beginning in 1947, by which they sold the casinghead gas produced on their leases to the plant owners. The gas contracts were “percentage of proceeds” contracts, by which the plant agreed to pay the lessees 50% of the proceeds from the sale of processed residue gas and 33.3% of the proceeds from the sale of natural gas liquids (NGLs) from the plant.[6] The term of these gas sales contracts was for the life of the Slaughter Plant.[7]
In the 1960s, units were formed for the purpose of conducting secondary recovery operations, such as waterfloods, to enhance production of oil in the field. Then in the 1980s tertiary recovery operations were commenced, by which carbon dioxide is injected into the producing formation, also for the purpose of maintaining and enhancing production of oil. The injected CO2 becomes commingled with hydrocarbons in the producing formation and comes back to the surface along with the casinghead gas.
High levels of CO2 interfere with the processing of gas in the Slaughter Plant.[8] As the CO2-injection program expanded in the field, levels of CO2 in the casinghead gas increased. And the injected CO2 migrated to nearby units, so casinghead gas produced from wells outside the units in which CO2 was being injected also experienced increased CO2 levels. During the mid-1980s, the owners of the Slaughter Plant constructed the adjoining Mallet Plant to process gas with high CO2 concentrations. The CO2 extracted from the gas at the Mallet Plant is returned to the unit operator for reinjection into the oil-producing formation. The CO2 thus follows a continuous cycle of injection, recovery, processing and re-injection. The casinghead gas, shorn of CO2, is piped from the Mallet Plant to the Slaughter Plant for further processing.
In 1996, BP America Production Company, then known as Amoco Production Company, became operator of the Slaughter and Mallet Plants and operator of the leases at issue in the litigation. It later was succeeded as operator of the plant and leases by Altura Energy Ltd. In 2000, OPL acquired both the leases and the plants. Thus, OPL now is both seller and buyer of the casinghead gas under the gas sales contracts.
Under the terms of the casinghead gas sales contracts, the casinghead gas is delivered to the buyer at or near the wellhead. Evidence showed that after the gas is gathered from the leases, and processed through the Mallet and Slaughter plants, the NGLs extracted from the gas stream, and the residue gas available for sale after processing, are transferred to OPL’s affiliated company Occidental Energy Marketing, Inc. (“OEMI”). OEMI markets the extracted NGLs at Mont Belvieu, Texas, near the Houston Ship Channel, and the residue gas at Waha, an El Paso Natural Gas Co. marketing hub in Pecos County.
In their suit against BP America Production Company, Altura Energy Ltd. (who we will refer to jointly as BP) and OPL, the royalty owners contended (1) BP and OPL breached the four amount-realized leases by failing to pay royalty calculated on the actual amount they realized from sale of casinghead gas; (2) BP and OPL breached an implied covenant in the amount-realized leases by failing to market the casinghead gas as would a reasonably prudent operator; (3) under the two market-value leases, BP and OPL did not calculate casinghead gas royalties on its market value in the field; and (4) OPL failed to pay a royalty on the CO2 separated from the gas at the Mallet Plant. The royalty owners moved for partial summary judgment seeking a declaration that OPL owed a royalty on CO2. By cross-motion, OPL sought a declaration that the CO2 was not subject to its royalty obligation. The trial court agreed with OPL and granted a partial summary judgment accordingly. The remaining issues were tried to the jury.
The jury found for the royalty owners on all liability theories submitted and awarded them attorney’s fees. The trial court granted judgment notwithstanding the verdict in favor of BP on its statute of limitations defense[9] and in favor of OPL on the award of attorney’s fees. The court then rendered judgment that the royalty owners recover $7,064,674 from OPL and take nothing from BP. As noted, both OPL and the royalty owners appeal.
Analysis
Issues Tried to Jury
Through three issues OPL contends no evidence supported the jury’s findings of liability and damages for: (1) the failure to pay royalties according to the amount-realized leases; (2) the breach of the implied duty to market in the amount-realized leases; and (3) the underpayment of royalties on the market-value leases. BP raises the same arguments in response to the royalty owners’ cross-appeal.[10] By cross-appeal, the royalty owners argue the trial court erred in granting judgment notwithstanding the verdict on BP’s statute of limitations defense and in favor of BP and OPL on the royalty owners’ request for attorney’s fees.
When conducting a legal sufficiency review, we view the evidence in a light most favorable to the judgment and indulge every reasonable inference to support it, crediting favorable evidence if a reasonable factfinder could, and disregarding contrary evidence unless a reasonable factfinder could not. City of Keller v. Wilson, 168 S.W.3d 802, 807, 822 (Tex. 2005). Anything more than a scintilla of evidence is legally sufficient to support the finding. Cont’l Coffee Prods. Co. v. Cazarez, 937 S.W.2d 444, 450 (Tex. 1996). When evidence is so weak as to do no more than create “a mere surmise or suspicion” that a fact exists, the evidence does not exceed a scintilla. Ford Motor Co. v. Ridgway, 135 S.W.3d 598, 601 (Tex. 2004) (quoting Kindred v. Con/Chem, Inc., 650 S.W.2d 61, 63 (Tex. 1983)).
The Amount-Realized Leases
As noted, the royalty clause of the four amount-realized, or proceeds, leases specifies a royalty on casinghead gas sold at the wells of one-eighth of the amount realized from the sale. OPL contends the evidence conclusively shows it paid royalties in accordance with the royalty clause, and we agree.
An oil and gas lease is a contract and interpreted accordingly. Tana Oil & Gas Corp. v. Cernosek, 188 S.W.3d 354, 359 (Tex.App.--Austin 2006, pet. denied). It is a basic tenet of our law that competent parties enjoy the utmost freedom of contract and courts will enforce a contract freely and voluntarily made for a lawful purpose. Crutchfield v. Associates Investment Co., 376 S.W.2d 957, 959 (Tex.Civ.App.--Dallas 1964, writ ref’d). Contract terms are given their plain, ordinary, and generally accepted meanings unless the contract itself shows them used in a technical or different sense. Valence Operating Company v. Dorsett, 164 S.W.3d 656, 662 (Tex. 2005).
It is undisputed that the casinghead gas is sold at the wells, and that the lessor is entitled to royalties based on the amount realized from the wellhead sale. See Tana Oil & Gas Corp., 188 S.W.3d at 360 (applying amount-realized royalty provision); see generally Exxon Corp. v. Middleton, 613 S.W.2d 240, 242-44 (Tex. 1981) (construing “gas sold at the wells” royalty provision). “Amount realized” means the proceeds received from the sale of gas or oil. Tana Oil & Gas, 188 S.W.3d at 360. “At the well” means before value is added by processing the raw gas for market. Id.
It is further undisputed that, at all times pertinent to this litigation, the life-of-the- plant gas sales contracts for the sale of the casinghead gas at the wellhead have remained in place, and that the lessees have paid royalties to the lessors based on the proceeds received by the lessees for the casinghead gas in accordance with the terms of the contracts. Nevertheless, the royalty owners contend, and the jury found, that the lessees failed to pay royalties in accordance with the leases.
The royalty owners’ expert Charles Graham testified to his opinion that the amount OPL truly realizes for the casinghead gas is not the proceeds it receives under the wellhead gas sales contracts.[11] His opinion focused on the circumstance that OPL, through its acquisition of sole ownership of both the leases and the Slaughter Plant, is both seller and buyer of the casinghead gas. It follows, according to Graham, that the determination of the amount realized by OPL is no longer limited to that received under the gas sales contracts. His opinion was that the amount OPL realizes for the gas at the wellhead, properly calculated, equals 100% of the proceeds of the downstream sales of the extracted NGLs and residue gas less certain costs.[12] One eighth of that amount, Graham testified, is the royalty owed by OPL.
We find Graham’s testimony provided no evidence OPL failed to pay royalties as required by the leases. First, his theory simply does not comport with the plain language of the leases. Under the four “amount-realized” leases, royalty is calculated on the amount realized from sale only if the gas is sold at the well; otherwise, royalty is payable on the market value of the gas. The gas royalty language from the 1934 Christine DeVitt “B” lease is typical of the four amount-realized leases, stating that the royalty is “on gas produced from said land and sold or used off the land or in the manufacture of gasoline, including casinghead gas, the market price at the well of one-eighth of the gas so sold or used, provided that if and when lessee shall sell gas at the wells lessor’s royalty thereon shall be one-eighth of the amount realized from such sales.” There is no dispute that the “such sales” referred to are the sales of gas at the wells. Graham’s theory necessarily makes use of the gas sales contracts to establish that the casinghead gas is sold at the wellhead (thus triggering the obligation to pay royalty on the amount realized from “such sales”), then ignores the provisions of the contracts[13] when determining the amount realized from the sale.[14] The royalty owners cannot have it both ways. If the gas sales contracts are effective to establish that the lessee is selling the gas at the wells, so as to trigger the obligation to pay royalty on the amount realized from “such sales,” the terms of the same contracts cannot be disregarded in the determination of the amount realized from “such sales.”
Moreover, the proceeds to which Graham pointed as the basis for his theory were not proceeds of the sale of gas as produced at the wellhead, but those of the sale of natural gas liquids and residue gas after processing. Graham testified that the amount OPL realized from the wellhead sale equaled the proceeds of OEMI’s sale of the NGLs at Mont Belvieu and its sale of the residue gas at Waha, less transportation and fractionation costs. Graham’s version of the amount realized thus includes amounts OPL realized from its activities beyond the wellhead, including its gathering of the gas, its processing of the gas at the Mallet and Slaughter Plants and its marketing of the extracted liquids. Cf. Tana Oil & Gas Corp., 188 S.W.3d at 360-61 (phrase “at the well” means before value is added by preparing the gas for market). Evidence of proceeds received by OEMI, an affiliated but different company, from sales of NGLs and residue gas at locations far removed from the wellhead is not evidence of the amount realized by OPL from a sale of raw gas at the well.[15]
We agree with OPL the undisputed evidence that royalties have been paid in accordance with the proceeds received under the casinghead gas sales contracts is conclusive evidence that royalties have been paid as required by the leases. See Keller, 168 S.W.3d at 814-15 (discussing conclusive evidence).
The Implied Duty to Market Gas
BP and OPL next challenge the legal sufficiency of evidence supporting the jury’s findings of liability and damages for failure to reasonably market gas produced under the amount-realized leases.
If silent on the subject, an oil and gas lease includes an implied covenant by the lessee to manage and administer the lease. Yzaguirre, 53 S.W.3d at 373. This implied covenant places on the lessee the duty to market the oil and gas reasonably. Id.; Amoco Prod. Co. v. Alexander, 622 S.W.2d 563, 568 (Tex. 1981) (conduct of lessee is measured by that of reasonably prudent operator under same or similar circumstances). The focus in an action for breach of the duty to reasonably market is on the conduct of the lessee and not other sales. Union Pac. Res. Group, Inc. v. Hankins, 111 S.W.3d 69, 71 (Tex. 2003).
We begin our discussion by noting our disagreement with one position taken by OPL. It argues that the Texas Supreme Court has limited breaches of the implied covenant to market to instances in which the proceeds received by the lessee were the result of fraud or sham. OPL relies on language in Hankins, 111 S.W.3d at 74, for this proposition. We do not agree that Hankins so held. As the court pointed out in Bowden, 247 S.W.3d at 700, the issue with which the court dealt in Hankins was whether there was a common legal question within a class consisting of lessors of market-value and proceeds leases. The court began its analysis of that issue in Hankins by listing the common issues the trial court had identified. 111 S.W.3d at 73. Searching the list for at least one issue of law or fact that both inhered in the complaints of all proposed class members and was subject to generalized proof, the court divided the trial court’s list into a group of issues it found questioned whether the defendants breached the implied covenant by failing to obtain arm’s length prices and a group it characterized as questioning whether a defendant had engaged in a sham transaction with an affiliated company. Id. at 74. Reiterating the holding of Yzaguirre that no covenant to reasonably market is implied in market-value royalty leases, and finding that market-value royalty owners are protected from the effects of inter-affiliate transactions by their entitlement to receive royalty based on the “objective market value,” the court went on to hold that none of the trial court’s listed issues had application to market-value leases, depriving the proposed class of commonality. Id. at 74-75. The statement to which OPL points, “the question under a proceeds lease would be whether the proceeds actually received by the lessee were a fraud or a sham,” id. at 74, must be seen in its context of the court’s discussion of the issues identified by the trial court in that case. We do not believe the Supreme Court intended by the statement to limit the duty to reasonably market, when implied, to a duty in all cases simply to avoid fraudulent or sham marketing transactions. Nor do we see anything in the court’s opinion in Bowden, which OPL also cites, to suggest such a limitation applicable in all cases. 247 S.W.3d at 700 (noting that “Hankins did involve similar allegations that the lessee’s intra-affiliate sales transactions were a sham”).
We agree, though, with OPL that in an evaluation of the sufficiency of the evidence it breached its duty to reasonably market the casinghead gas, our inquiry must focus on its behavior, not on evidence of other sales. Hankins, 111 S.W.3d at 71. And we agree that the evidence of its breach of the duty is legally insufficient.
The charge asked whether BP and OPL failed to reasonably market gas produced from the proceeds leases. In conjunction with the question, the trial court instructed the jury that BP and OPL had “a duty to act as a reasonably prudent operator would act under the same or similar circumstances.”
The royalty owners argue the evidence showed that selling the casinghead gas for such “meager proceeds,” that is, a third of the liquids and half the residue gas, “breaches the duty to market because [a reasonably prudent operator] would not sell gas to a plant on such low proceeds – particularly when the [reasonably prudent operator] owns and controls the plant.” But, as noted, it is undisputed that OPL has paid royalties according to the proceeds under the percentage gas sales contracts put in place by its predecessors. Moreover, no witness opined that the percentage sales contracts were unreasonable when signed. Graham testified that the lessees’ entry into the percentage sales contracts when the Slaughter Plant was built was reasonably prudent. It is undisputed also that the terms of those contracts extended for the life of the plant. The allegedly breaching behavior of OPL, then, does not consist of any action on its part but merely its failure to change the terms of contracts that came with the properties it purchased.
The royalty owners emphasize the self-dealing nature of the gas sales contracts, referring to the contracts as OPL’s “left hand” selling the gas to its “right hand.” As a pattern for their implied covenant analysis, the royalty owners point to Harding v. Cameron, 220 F. Supp. 466 (W.D. Okla. 1963), a diversity case applying Oklahoma law. Id. at 467. The royalty owners correctly note that Harding involved a lessee who occupied both the selling and buying sides of an arrangement for the compression of natural gas. On a complaint by his lessors of underpaid royalties, the court held the lessee had breached duties to exercise the diligence of a prudent operator and to obtain a market for the gas at the best price obtainable. Id. at 470. Citing his self-dealing, the court found that the lessee had acted primarily in his own interest and without regard to his obligations to the lessors. Id.
We do not find Harding persuasive authority on the issues involved here. First, under Oklahoma law, royalty was payable on the “value” or “market price” of the gas, and Texas does not recognize an implied duty to market under a lease with a market-value royalty provision. Hankins, 111 S.W.3d at 72; Yzaguirre, 53 S.W.3d at 374.[16] Second, the actions of the lessee in Harding involved setting up the offending gas marketing arrangements, not simply acquiring both sides of arrangements that were prudent when established.[17]
Certainly Texas implied covenant law takes self-dealing into account. The Texas Supreme Court has noted that the implied covenant to reasonably market oil and gas serves to protect a lessor from the lessee’s self-dealing or negligence. Yzaguirre, 53 S.W.3d at 374. But the royalty owners here seem to assume that a showing of self-dealing is all that is required to show a breach of the implied covenant. In fact, their evidence of OPL’s breach of the duty to reasonably market the casinghead gas is dependent on its self-dealing. Under the royalty owners’ theory, OPL has breached its duty to reasonably market by failing to modify the terms of the gas sales contracts precisely because it, acting alone, has the ability to do so. The royalty owners presented no evidence that a reasonably prudent seller of casinghead gas in OPL’s position would have any ability to terminate or modify the life-of-the-plant gas sales contracts if it were not also the plant owner, nor did they present any evidence that the terms of a re-negotiated or modified gas sales contract for gas in the Slaughter Field, negotiated at arms-length, would be better for the seller than those of the existing contracts.[18] While the royalty owners produced substantial blocks of expert testimony and documentary exhibits supporting their claims, we agree with OPL there was no proof of what different marketing action was required of a reasonably prudent operator under the same or similar circumstances. See Migl v. Dominion Oklahoma Texas Expl. & Prod., Inc., 2007 Tex. App. Lexis 1179, at *18-*19 (Tex.App.--Corpus Christi 2007, no pet.) (mem. op.) (considering evidence of breach of implied covenant to reasonably market).
Underpayment of Royalties on Market-Value Leases
By their third cause of action, the royalty owners claimed BP and OPL failed to pay royalties based on the market value of gas in the field under the market-value leases. As noted, the royalty clauses of these leases provide a three-eighths royalty of the market value in the field of gas sold. The jury gave a positive answer to the question asking whether OPL failed to pay royalty based on market value.
The royalty owners relied at trial on the testimony of their market value expert, Christopher Kay Alguire. BP and OPL objected in the trial court and argue here that Alguire’s testimony was irrelevant and unreliable, and therefore provided no evidence. Of the positions they advance supporting their argument,[19] we address two: that Alguire’s definition of market value does not comport with Texas law, and that the gas sold under the contracts on which she formed her market value opinion was not comparable in quality to the gas produced on the OPL leases at issue in this litigation.
The market value of property is the price it would bring when offered for sale by one desiring, but not obligated, to sell and bought by one under no necessity of buying it. Yzaguirre, 53 S.W.3d at 374 (citing Middleton, 613 S.W.2d at 246). Texas law recognizes two methods to determine market value of gas sold at the well. Heritage Res., Inc. v. Nationsbank, 939 S.W.2d 118, 122 (Tex. 1996). The preferred method, and that used by the royalty owners’ expert Alguire, is that of examining comparable sales. See id. at 122; Texas Oil & Gas Corp. v. Vela, 429 S.W.2d 866, 872 (Tex. 1968). To determine its market value, gas is valued as though it is free and available for sale. Middleton, 613 S.W.2d at 246.
“Market value is generally determined by comparing the sale price to other sales ‘comparable in time, quality, quantity, and availability of marketing outlets.’” Hankins, 111 S.W.3d at 71 (quoting Heritage Res., 939 S.W.2d at 122). A sale of gas of comparable quality involves gas with similar physical properties such as sweet, sour, or casinghead gas. Middleton, 613 S.W.2d at 246. Proper expert testimony may make adjustments between sales of gas with differing physical properties so that the sales being compared truly are comparable. See id. at 247 (referring to adjustments for gas of differing BTU content).
One presenting expert testimony must be properly qualified and her opinions must be relevant and based on a reliable foundation. See Tex. R. Evid. 702; Gammill v. Jack Williams Chevrolet, Inc., 972 S.W.2d 713, 720 (Tex. 1998) (citing E.I. du Pont de Nemours & Co. v. Robinson, 923 S.W.2d 549, 556 (Tex. 1995)). In determining whether an expert’s testimony constitutes some evidence, “an expert’s bare opinion will not suffice” rather “the substance of the testimony must be considered.” Merrell Dow Pharms., Inc. v. Havner, 953 S.W.2d 706, 711 (Tex. 1997). The expert must explain the basis of her statements to link her conclusions to the facts. Earle v. Ratliff, 998 S.W.2d 882, 890 (Tex. 1999). “[A] claim will not stand or fall on the mere ipse dixit of a credentialed witness.” Burrow v. Arce, 997 S.W.2d 229, 235 (Tex. 1999).
It is the burden of the proponent of scientific or technical evidence to demonstrate the opinions of its expert are reliable. See Kerr-McGee Corp. v. Helton, 133 S.W.3d 245, 254 (Tex. 2004). Determining reliability of the expert’s opinions focuses on the principles, research and methodology underlying the conclusions of the expert. Exxon Pipeline Co. v. Zwahr, 88 S.W.3d 623, 629 (Tex. 2002). “[E]xpert testimony is unreliable if it is not grounded in the methods and procedures of science and is no more than subjective belief or unsupported speculation.” Kerr-McGee, 133 S.W.3d at 254 (internal quotation marks and citation omitted). Expert testimony is also unreliable if there is “too great an analytical gap between the data and the opinion proffered.” Id. (quoting Gammill v. Jack Williams Chevrolet, Inc., 972 S.W.2d 713, 726, (Tex. 1998)). “If the expert’s testimony is not reliable, it is not evidence.” Kerr-McGee, 133 S.W.3d at 254 (citing Havner, 953 S.W.2d at 713).
Unlike the market-value studies reflected in other reported Texas cases, the market-value study to which Alguire testified was not conducted by comparing the dollars-per-Mcf or dollars-per-MMBTU values of the prices on which the royalty owners received royalty with royalties paid for comparable gas. See, e.g., Middleton, 613 S.W.2d at 247-48; Amoco Prod. Co. v. First Baptist Church, 579 S.W.2d 280, 282 (Tex.App.—El Paso 1979), writ ref’d n.r.e., 611 S.W.2d 610 (1980) (per curiam). Like their claims under the amount-realized leases, the royalty owners’ case under the market-value leases complained of the percentages of the post-processing sales prices allocated to the wellhead sale, not the product sales prices themselves. Their contention is not that OPL paid royalties based on below-market prices for casinghead gas but that the allocation of only 33.3% of the NGL revenue and 50% of the residue gas revenue to the wellhead under the percentage of proceeds contracts resulted in royalties being paid on something less than the market value of the casinghead gas at the wellhead. Accordingly, Alguire testified she compared the 33.3% of NGLs, 50% of residue gas percentage of proceeds terms in place here with percentages of proceeds being paid under other contracts for casinghead gas gathered to a gas processing plant. As Alguire described it, her assignment from the royalty owners was “to provide, annually, percentage of proceeds that were representative of market value for the casinghead gas in the area.”
The results of Alguire’s study were described in the royalty owners’ exhibit 296, which consisted of charts on which were plotted the percentages of the downstream resale prices for NGLs and residue gas received by the sellers under various contracts Alguire had reviewed. By plotting the contracts according to their date of signing, Alguire calculated a “market value” for percentages of proceeds for each year during the period 1990 through 2007. As an example, the chart for 1990 shows six contracts signed during that year for the sale of casinghead gas to a processing plant operator on a percentage of proceeds basis. Under one contract, the seller received for its casinghead gas 50% of the proceeds of the downstream sale of NGLs and 75% of the proceeds of the sale of residue gas. Other percentages reflected on the 1990 chart ranged from 35% to 75% of NGL proceeds. Based on those results, Alguire determined that the “market value” for such proceeds in 1990 was 60% of NGL proceeds. By her determinations, the “market value” proceeds ranged from 60% in the earlier years of her study to 80% in the years 2001 through 2007. Her conclusion was that “the 33 percent basis for the percentage of proceeds [under the OPL contracts] was below the range observed for comparable casinghead gas sales in the area.”
As OPL points out, Alguire’s study never resolves itself to a market value for the casinghead gas stated in dollars and cents. The study’s premise is that there is a “market value” for percentages of proceeds. We agree with OPL that Alguire’s study and testimony provide no evidence OPL failed to pay royalties based on the market value of the gas in the field.
The royalty owners argue that the downstream prices OPL receives for its processed residue gas and extracted NGLs were not at issue in the litigation and their amounts and sufficiency were not in dispute. The royalty owners insist that the only dispute with regard to the market-value leases was whether the 33.3% NGLs, 50% residue gas proceeds allocated to the wellhead by OPL constitute market value in the field. We recognize it is common for casinghead gas to be sold on percentage of proceeds terms,[20] and recognize the changes in recent decades in the marketing of natural gas and NGLs. Nonetheless, it seems to us that comparing percentages begs the question “percentage of what?” Without evidence of the downstream prices for which other gas plant operators sold their NGLs and residue gas, it seems to us impossible to reach a true market value conclusion. Evidence that a seller of gas received 50% of NGL proceeds is meaningless without knowledge of the amount of the proceeds.
OPL also contends Alguire’s testimony was unreliable, and thus provided no evidence, because the casinghead gas sold under other contracts she compared was not comparable in quality to that produced from the two Slaughter Field market-value leases. We agree with this contention as well.
One of the two market-value leases is a part of the Slaughter Estate Unit, the other a part of the Northwest Mallet Unit. For the period the royalty owners claimed damages, the Slaughter Estate Unit was under CO2 injection. A 2001 revenue audit report prepared by Alguire described the natural gas production as “extremely contaminated, mostly by carbon dioxide.” The report stated carbon dioxide levels exceeded 80% of metered production on the Slaughter Estate Unit and “‘roughly 40%’” on the Northwest Mallet Unit. Alguire’s trial testimony was consistent with her 2001 report. She said gas produced from the Slaughter Estate Unit during the period contained CO2 levels in the 80-90% range. The Northwest Mallet Unit was not under CO2 injection until the conclusion of Alguire’s survey period. But carbon dioxide in the gas produced from this unit increased from the 20-30% range in the mid-1990s to the 60-70% range by 2007. Before injection began on the Northwest Mallet Unit, CO2 migrated there from surrounding properties.
Alguire acknowledged that the comparable sales approach for obtaining market value requires consideration of the quality of the gas. But Alguire conducted her market value study on the premise that high levels of injected CO2 should not be included as a comparability factor in the market value analysis. She explained the rationale for her methodology:
I was hesitant about including injected CO2 in the comparability standards because it would be effectively charging the cost of the CO2 operations, either directly with the CO2 removal fees, which haven’t been charged, or indirectly by saying this gas isn’t worth anything because it has got all of this CO2 in it that we put there, even though, in this instance, in the Northwest Mallet Unit, it wasn’t even put there by the operators. It seeped in from surrounding areas.
Alguire’s intentional[21] omission of the high CO2 content of the gas from her comparability evaluation[22] improperly injects an entirely subjective factor into the search for what Texas law describes as an objective calculation. See Bowden, 247 S.W.3d at 709 (“[m]arket value leases provide an objective basis for calculating royalties . . . .”); Yzaguirre, 53 S.W. at 374; Hankins, 111 S.W.3d at 72 (both also referring to “objective basis for calculating royalties” provided by market-value royalty provisions). It represents, moreover, the kind of outcome-directed methodology condemned in Robinson. 923 S.W.2d at 559.
Alguire presented lengthy and detailed testimony. But by not considering contracts for sale of gas with high CO2 content in her evaluation of the market value of the Slaughter Estate and Northwest Mallet unit gas highly contaminated with CO2, Alguire omitted a material step in the quality analysis required by the comparable sales approach. Without a true comparison of hydrocarbon quality, too great an analytical gap stands between the data, assuming its accuracy, and Alguire’s market value opinion. See General Electric Co. v. Joiner, 522 U.S. 136, 146, 118 S.Ct. 512, 519, 139 L. Ed. 2d 508 (1997) (opinion evidence connected to existing data by nothing but credentialed expert’s ipse dixit is insufficient). Lacking reliability, the opinion is incompetent and amounts to no evidence that BP and OPL underpaid royalties on the market-value leases. In the absence of any additional evidence supporting the jury’s implicit finding of comparable quality, we conclude its market-value finding is not supported by any evidence.
Damages
Finding the jury’s affirmative responses to the three questions inquiring of the liability of BP and OPL were supported by legally insufficient evidence, we turn to the jury’s corresponding damage findings. “It is well established in Texas that no recovery is allowed unless liability has been established.” Mitchell v. Bank of Am., N.A., 156 S.W.3d 622, 627 (Tex.App.--Dallas 2004, pet. denied). In the absence of liability findings, damage findings are immaterial. Fire Ins. Exch. v. Sullivan, 192 S.W.3d 99, 107 (Tex.App.--Houston [14th Dist.] 2006, pet. denied). We therefore sustain OPL’s first issue concerning the proceeds leases, its sub-issue concerning the implied duty to market, and its second issue concerning the market-value leases.
The Royalty Owners’ Cross-Appeal
By their second issue on cross-appeal, the royalty owners contend the trial court erred in rendering judgment notwithstanding the verdict in favor of BP on its limitations defense. They argue the discovery rule tolls the applicable limitation period until each royalty owner knew or reasonably should have known facts giving rise to a cause of action. Because no evidence supports the three affirmative theories of relief the royalty owners asserted against BP, determining whether their claims were subject to a limitations defense or they could legally assert the discovery doctrine in avoidance of limitations are questions whose resolution is unnecessary to our disposition of this appeal. We, therefore, do not address the issue. See Tex. R. App. P. 47.1.
The royalty owners’ third issue on cross-appeal presents the contention the trial court erred in rendering judgment notwithstanding the verdict in favor of BP and OPL on the royalty owners’ claim for attorney’s fees, recovery of which they sought under Chapter 38 of the Civil Practice & Remedies Code. Tex. Civ. Prac. & Rem. Code Ann. §§ 38.001-38.006 (West 2008).
To recover attorney’s fees under § 38.01, a party must prevail on a cause of action authorizing recovery of attorney’s fees, and recover damages. Green Int’l, Inc. v. Solis, 951 S.W.2d 384, 390 (Tex. 1997); Brent v. Field, 275 S.W.3d 611, 621-22 (Tex.App.--Amarillo 2009, no pet.). Because we have concluded the royalty owners cannot prevail on a cause of action allowing recovery of attorney’s fees they are not entitled to recover attorney’s fees. For this reason, we overrule their third issue on cross-appeal.
The Cross-Motions for Partial Summary Judgment
By their first issue on cross-appeal, the royalty owners assert the trial court erred by denying their motion for partial summary judgment. The royalty owners and OPL filed cross-motions for partial summary judgment, each seeking a judgment declaring the character and ownership of CO2 that OPL injects into eight leases included in three units. Said simply, the royalty owners contended the CO2 was subject to a royalty; OPL argued it was not. The trial court agreed with OPL and rendered partial summary judgment in its favor.
The movant for summary judgment has the burden of showing there is no genuine issue of material fact and it is entitled to summary judgment as a matter of law. Tex. R. Civ. P. 166a(c). Reviewing a summary judgment, we take evidence favorable to the nonmovant as true, and indulge every inference and resolve every doubt in the nonmovant's favor. Nixon v. Mr. Property Management Co., 690 S.W.2d 546, 548-49 (Tex. 1985). A defendant “who conclusively negates at least one essential element of a cause of action is entitled to summary judgment on that claim.” IHS Cedars Treatment Ctr. of Desoto, Tex., Inc. v. Mason, 143 S.W.3d 794, 798 (Tex. 2004) (citing Sw. Elec. Power Co. v. Grant, 73 S.W.3d 211, 215 (Tex. 2002)). A plaintiff moving for summary judgment on its own cause of action must conclusively prove each element of the cause of action. MMP, Ltd. v. Jones, 710 S.W.2d 59, 60 (Tex. 1986) (per curiam).
When parties file cross motions for summary judgment, and one motion is granted and the other denied, the appellate court reviews the summary judgment evidence presented by both sides and determines all questions presented. Comm’rs Court of Titus County v. Agan, 940 S.W.2d 77, 81 (Tex. 1997). If the issue raised is based on undisputed and unambiguous facts, then the reviewing court may determine the question presented as a matter of law. Gramercy Ins. Co. v. MRD Invs., Inc., 47 S.W.3d 721, 724 (Tex.App.--Houston [14th Dist.] 2001, pet. denied).
According to the summary judgment record, the CO2 OPL injects into the hydrocarbon-producing formation to enhance oil recovery is transported to the Slaughter Field from New Mexico and Colorado.[23] The CO2 is extracted from the produced gas stream at the processing plants, returned to the leases, and reinjected as part of the recovery operation. While the royalty owners agree that the transported CO2 is OPL’s personal property before its injection, they theorize that the extraneous CO2 loses its personal property character on injection, is susceptible to capture in the producing formation, and OPL is authorized to capture, or recapture, the CO2 through the grant of the leases and provisions of the unit agreements. As captured, they contend, the CO2 is subject to OPL’s royalty obligation.[24]
The royalty owners’ claims to a royalty on the injected CO2 depend entirely on the correctness of their contention that OPL loses title to its personal-property CO2 when it introduces the substance into the subsurface producing formation. Although the unit agreements, to which the royalty owners are parties, contain express authorization for the unit operator to inject substances into the unitized formation,[25] and the unit agreements contain provisions concerning royalty payments, we do not understand the royalty owners to contend that the unit agreements contain a commitment by OPL to pay royalty beyond its royalty obligation under the leases. Before the trial court, the royalty owners asserted that the provisions of the unit agreements affecting royalties did not supersede the leases’ royalty clauses, but simply constituted an “overlay” addressing the manner in which royalty would be paid under unit operations.[26] Thus we consider it undisputed that the unit agreements do not require payment of a royalty not already required under the leases. Similarly, the royalty owners make no contention here that the terms of any of the leases entitle them to royalty on the injected CO2 whether or not it became subject to the rule of capture on its injection. Our inquiry, then, is whether, under Texas law, the rule of capture operates to subject extraneous CO2 injected and recovered by OPL to a royalty obligation under its leases.
The “rule of capture” is a well established doctrine in Texas which holds that a landowner is entitled to produce the oil and gas in place beneath his land, as well as the oil and gas which flows to the land as the result of physical conditions and natural laws relating to the migratory nature of oil and gas. Recognizing that oil and gas are fugitive minerals that will migrate throughout a reservoir without regard to property lines, the rule of capture provides that a landowner owns all the oil and gas produced by a legally drilled well located on his land, even though the well may be draining minerals from nearby properties.
SWEPI, L.P. v. Camden Resources, Inc., 139 S.W.3d 332, 341 (Tex.App.--San Antonio 2004, pet. denied) (citations omitted).
While no Texas case directly addresses title and ownership of extraneous CO2 injected into a formation for production enhancement, the ownership of extraneous natural gas injected into a storage formation was at issue in Humble Oil & Refining Co. v. West. 508 S.W.2d 812 (Tex. 1974). OPL urges that our analysis of the claims to royalty on the injected CO2 here should begin and end with Humble Oil, and a case on which it relied, Lone Star Gas Co. v. Murchison. 353 S.W.2d 870 (Tex.Civ.App.--Dallas 1962, writ ref’d n.r.e.).
In Humble Oil, deeds by the Wests to Humble in part recited “that the Wests ‘except from this conveyance and retain unto themselves. . . . those certain royalties on oil, gas and other minerals which may be produced and saved from the lands hereby conveyed.’” Concerning gas, the conveyances described the retained royalty as “‘a royalty equal to the market value at the well of one-sixth (1/6) of the dry gas so sold or used; provided that on such dry gas sold at the wells the royalties shall be one-sixth (1/6) of the amount realized from such sale.’” Id. at 813.
As the field reservoir approached depletion, Humble obtained Railroad Commission authorization to use the reservoir for gas storage. Id. The Wests sued Humble for injunctive and declaratory relief. The trial court ordered Humble to account to the Wests for their royalty interests in all gas produced irrespective of whether the gas was extraneous or native. Id. at 814. The court of civil appeals reversed with instructions for entry of a permanent injunction restraining Humble from injecting and storing gas in the reservoir until all native gas was produced. Id.
Before the supreme court, the Wests argued because of their royalty on all oil, gas and minerals produced and saved from the properties, Humble owed a royalty on all gas produced and saved, whether native or extraneous. Id. at 817. According to the Wests, a contrary holding would rewrite the conveyance documents. Id.
In its analysis, the court looked to Murchison, 353 S.W.2d 870. There, Murchison argued Lone Star lost title to extraneous gas it injected into a storage reservoir as the gas became like a wild animal, subject to capture. Rejecting the notion that the gas returned to its natural and wild state and was thus subject to the law of capture, the court in Murchison found the correct rule was “once [severed] from the realty, gas and oil, like other minerals, become personal property . . . title to natural gas once having been reduced to possession is not lost by the injection of such gas into a natural reservoir for storage purposes.” Humble Oil, 508 S.W.2d at 817 (quoting Murchison, 353 S.W.2d at 878 quoting White v. New York State Natural Gas Corp., et al., 190 F.Supp. 342, 347, 349 (W.D. Pa. 1960)) (additional quotation marks omitted).[27] Relying on Murchison, the Court in Humble Oil concluded the extraneous gas Humble injected into the storage reservoir was and remained the personal property of Humble.
The Wests argued that the obligation of Humble in the conveyance document to pay a royalty on all gas produced and saved distinguished Murchison. 508 S.W.2d at 817. Disagreeing, the supreme court found to adopt such reasoning would implicitly recognize the doctrine of minerals ferae naturae that Murchison rejected. Id. Thus the court held, “Humble’s ownership of the gas as personal property is not altered either upon injection of the gas in the reservoir or upon later production of the gas. The language of the conveyance does no more than reserve the royalty interest in the native gas in the reservoir, and Humble’s ownership of the extraneous gas is unaffected thereby.” Id.
The analogy between stored natural gas and the injected CO2 described in this record is not exact, but we find Humble Oil and Murchison sufficiently analogous to guide our decision.[28] This record does not describe differences in the injection of extraneous CO2 to enhance oil production and the injection of natural gas for storage to require application of a different rule to the dispute before us.[29] Both involve injection of a gaseous substance into a well-defined underground formation with Railroad Commission approval.[30] Nothing suggests OPL has an intent to abandon the CO2 it injects and recovers. See Murchison, 353 S.W.2d at 870 (also finding no intent to abandon). Indeed, OPL’s recycling and reinjection of the CO2 removed at the Mallet Plant belies any intent to abandon the injected and recovered CO2.
The royalty owners’ heavy reliance on Corzelius v. Harrell, 143 Tex. 509, 186 S.W.2d 961 (1945) is misplaced. Corzelius concerns Railroad Commission orders regulating production of natural gas from a field in which a gas recycling operation was being conducted. 186 S.W.2d at 970. It was cited to the court in Murchison, which found it dealt with “the law of original capture,” and not applicable to stored extraneous gas. 353 S.W.2d at 870.
Corzelius is not mentioned by the court in Humble Oil. Corzelius is more often cited in cases concerning assertions of subsurface trespass. See, e.g., Coastal Oil & Gas v. Garza Energy Trust, 268 S.W.3d 1, 13 n.37 (Tex. 2008); Railroad Commission of Texas v. Manziel, 361 S.W.2d 560, 568 (Tex. 1962). Like the court in Murchison, 353 S.W.2d at 870, we find it inapplicable to the question before us.
For these reasons, we find the trial court did not err in granting OPL’s motion for partial summary judgment and denying that of the royalty owners.
Conclusion
Because no evidence supports the jury’s findings of liability by OPL, we reverse the judgment of the trial court and render judgment that the royalty owners take nothing against OPL. We remand the case to the trial court for the entry of a new judgment consistent with this opinion and law. We otherwise affirm the judgment of the trial court.
James T. Campbell
Justice
[1] John T. Boyd, Chief Justice (Ret.), Seventh Court of Appeals, sitting by assignment.
[2] The plaintiff royalty owners are: the CH Foundation; The Helen Jones Foundation, representing its own interests and by assignment those of Dorothy Gail Secrest Unitrust; James C. Arnold, Trustee for Arnold 2002 Trust; Wells Fargo Bank, Trustee and/or Agent with Power of Attorney for Frances Snyder Flood Testamentary Trust, Anne Snyder Testamentary Trust, and Dick Snyder Testamentary Trust; Cheryl Mattison, Executrix for Estate of Myron D. Mattison; LAGH, Ltd.; Community Bank of Raymore, Trustee and/or Agent with Power of Attorney for William L. Abernathy Trust, Abbie J. Burton Trust, Lynn G. Fayman Trust, Claudia Kenyon Trust, Kern E. Kenyon Trust, Milus D. Scruggs Trust, Thomas M. Scruggs, Jr. Trust, David L. Fayman Trust, and Faith Fayman Strong Trust; Texas Capital Bank Trustee and/or Agent with Power of Attorney for Dora Lee Langdon Mineral Trust, Jane Byars Roby Mineral Trust, and Dora Langdon Article V. Trust; Frost National Bank, Trustee and/or Agent with Power of Attorney for Johnson Oil Control (Trust Entity Incorporating Kathleen L. Webster Trust, Joseph M. Durkin Trust, Mark L. Johnson Trust, Sheila A. Johnson Trust, Catherine L. Johnson Tekstar Trust), Karen Hixon Trust, Dora Lee Langdon Article IV Trust, and Lee Kendall Langdon Trusts (F/B/O Clay Langdon and F/B/O Lee Kendall Langdon); Bank of America Trustee for J. Lee Johnson, Jr. Trust U/W F/B/O J. Lee Johnson, IV; Mark L. Johnson, Trustee for J. Lee Johnson III Descendants Revocable Trust and Executor for Estate of J. Lee Johnson III; KCJ Family Ltd. Partnership; Joseph A. Durkin, Executor and Trustee for Estate of Catherine J. Durkin; Kathleen D. Webster; Joseph M. Durkin; Teresa M. Durkin Wilkinson; Jack Wilkinson, Jr., Trustee for Teresa M. Durkin Wilkinson Trust; J.P. Morgan Chase, Trustee and/or Agent with Power of Attorney for Billie Lucille Parker Agency, Earle North Parker Irrevocable Trust, Lynsey Alison Edens Recovable Trust, and William Ashley Edens Recovable Trust; Pamela Allison Parker Clifton for Ruthie Young Parker Life Estate; Clay A. Parker; Albon Head, Jr.; Michael M. Gibson; David Chappell; Stanford Harrell; KHM Enterprises Ltd.; Martha Price; Jeanne Van Zant Sanders (Trustee of the Fred A. Sanders Testamentary Trust; Formerly, Est. of Frederick A. Sanders); Albert E. Sanders; Paula Day (Executrix of Est. of Sam J. Day); Winfred Hooper, Jr.; The Plum Foundation, representing the interests of Dorothy Gail Secrest; Olney Wallis, Trustee for Gary Macklyn Green Grantor’s Trust; William Jewell College.
[3] The leases at issue describe land located in Hockley, Terry and Cochran Counties, Texas.
[4] “Casinghead gas” is statutorily defined as meaning “any gas or vapor indigenous to an oil stratum and produced from the stratum with oil.” Tex. Nat. Res. Code Ann. § 86.002(10) (West 2001).
[5] See, e.g., Yzaguirre v. KCS Resources, Inc., 53 S.W.3d 368, 372 (Tex. 2001) (distinguishing “market value” and “amount realized” or “proceeds” royalty provisions).
[6] See Bowden v. Phillips Petroleum Co., 247 S.W.3d 690, 708 (Tex. 2008) (also describing percentage of proceeds contract).
[7] Gas from the six leases at issue here is sold under one of three Casinghead Gas Contracts, two dated in 1947 and the third in 1954. They have been amended but the amendments are not germane to the issues in this case. For our purposes, the three contracts may be considered identical.
[8] According to the testimony of an OPL employee, the Slaughter Plant can handle gas bearing a “composite” carbon dioxide and hydrogen sulfide content up to 12%.
[9] The royalty owners filed suit in January 2006, seeking damages for the alleged wrongful conduct of BP from 1990 to 2000. They asserted the discovery doctrine in avoidance of the limitations defenses interposed by BP. OPL acquired the leases and plants in August 2000 but the royalty owners limited their claims against OPL to the period January 2002 through August 2008.
[10] On liability and damage questions like those submitted against OPL, the jury made affirmative findings against BP. While the jury made findings supporting application of the discovery doctrine, as noted, the trial court granted judgment notwithstanding the verdict in favor of BP on limitations grounds. On appeal, BP argues the trial court correctly disregarded the findings supporting the discovery doctrine’s application. BP further contends that even were this error, no evidence supported the liability and damage findings made against BP.
[11] Graham testified that to establish the amount OPL realized from its sale of the casinghead gas, he looked not to the gas sales contracts but “what the defendants really realized” less “some costs.”
[12] See Bowden, 247 S.W.3d at 702 (describing, in class action certification appeal, similar distinction between wellhead prices and those received from downstream sales after processing).
[13] Graham straightforwardly acknowledged that his analysis ignored the percentages stated in the gas sales contracts, opining that the contracts’ percentage of proceeds formula was “not binding on” the lessors.
[14] The royalty owners’ contention here is thus distinguished from that described in Texas Oil & Gas Corp. v. Hagen, 683 S.W.2d 24 (Tex.App.--Texarkana 1984), writ dism’d as moot, 760 S.W.2d 960 (Tex. 1988), in which the court of appeals affirmed trial court findings that a purported wellhead sale of gas by the producer to its wholly-owned pipeline subsidiary was a sham, and that the “true sale” of the gas was off the lease premises, making a market-value royalty provision applicable. Id. at 28.
[15] Note, for example, the issues recited in proposed class litigation brought by royalty owners against affiliated defendants as including the issue whether the “corporate separateness” of affiliated defendants should be disregarded. Union Pac. Res. Group, Inc. v. Hankins, 111 S.W.3d 69, 73 (Tex. 2003). Graham’s opinion testimony simply assumed that receipt of proceeds by OPL’s affiliate OEMI is to be equated with their receipt by OPL. The royalty owners do not support such an assumption by citation to Texas authority.
[16] As to the substantial differences in the approaches taken by Texas and Oklahoma courts to the lessee’s obligation to pay royalty on gas production, see John Burritt McArthur, A Minority of One? The Reasons to Reject the Texas Supreme Court’s Recent Abandonment of the Duty to Market in Market-Value Leases, 37 Tex. Tech Law Rev. 271, 274 (2005) (“Oklahoma requires the lessee to share the price it receives in any sales contract into which it enters in good faith”); Bruce M. Kramer, Interpreting the Royalty Obligation by Looking at the Express Language: What a Novel Idea? 35 Tex. Tech Law Rev. 223, 248-49 (2004) (discussing Tara Petroleum Corp v. Hughey, 630 P.2d 1296 (Okla. 1981)).
[17] See Bowden, 247 S.W.3d at 698 (in similar context, the litigation of disputes over natural gas agreements entered into in the 1940s, the court noting that despite the passage of decades and marked changes in the ways of marketing of natural gas, courts “interpret the obligations and rights of the parties according to their expressed intent when they entered the agreement”).
[18] The royalty owners do not contend that OPL’s predecessors acted unreasonably as operators by initiating the CO2 injection program or that OPL’s maintenance of the injection program is unreasonable. It would seem then that analysis of the casinghead gas marketing actions required of a reasonably prudent operator under the same or similar circumstances necessarily would take the consequences of that program, including the resulting high CO2 content of the gas, into account.
[19] OPL also presents arguments that Alguire’s opinions were based in part on sales too far removed geographically from those at issue here. We do not reach those arguments.
[20] See, e.g., Bowden, 247 S.W.3d at 708.
[21] Alguire’s testimony makes clear that her omission of the injected CO2 content from her analysis was intentional. It was a part of the instructions she received for preparation of her study.
[22] Alguire candidly acknowledged on cross-examination, for instance, that her study did not include a single contract for gas containing CO2 in the 50% range with a percentage of proceeds higher than the 33.3%, 50% percentages on which the royalty owners were paid royalty. Later in her cross-examination testimony, Alguire made reference to one contract in New Mexico under which gas containing 25% CO2 was sold for 88% of proceeds. She acknowledged the contract would not be comparable to the higher CO2 levels in the Slaughter Estate Unit gas.
[23] Our discussion of this issue applies to the extraneous CO2 transported to the field, injected by OPL into the producing formation and recovered along with the casinghead gas by OPL. The royalty owners contend the summary judgment evidence raised an issue of fact whether OPL is producing CO2 that is “native” to the leased lands. We have examined the documents on which the royalty owners rely for the contention, which are an affidavit of their expert Charles Graham and a memorandum of one of their attorneys. We do not agree that either of those documents provides evidence precluding summary judgment on their claims for royalty on CO2.
[24] As we understand their theory, the royalty owners contend they are entitled to royalty each time the CO2 is recycled through the producing formation.
[25] The unit agreement for the Slaughter Estate Unit, for example, gives the working interest owners the right to inject into the unitized formation “any substances in whatever amounts [they] deem expedient.”
[26] Unit agreements for the Central Mallet Unit and the Slaughter Estate Unit, for example, contain provisions limiting royalties on certain “outside substances” injected into the unitized formation until other events occur. The parties disagree on the effect of that language but, as noted, we do not read the royalty owners’ briefing to contend it would have the effect of requiring payment of royalty not required under the leases.
[27] Relevant to the present facts, the court in Murchison found the law of original capture, which in general gives the owner of land the right to produce all the oil and gas that will flow from a well on the land, inapplicable to gas that was originally captured and subsequently restored. Murchison, 353 S.W.2d at 880.
[28] And we emphasize that we deal here only with a claim for royalty by lessors on extraneous CO2 injected and recovered by OPL. This case does not involve claims of trespass or the like, nor does it involve claims to ownership of CO2 recovered by operators other than OPL. Any such case would involve considerations not present here.
[29] The royalty owners’ argument that language concerning gas or gaseous substances in the leases and unit agreements binds OPL to a royalty obligation for CO2, would seem to underscore the similarity between CO2 and natural gas for this purpose.
[30] See, e.g., Tex. Nat. Res. Code Ann. §§ 91.171, et seq. (West 2001) (underground natural gas storage); 16 Tex. Admin Code §§ 3.46 (fluid injection into productive reservoirs); §§ 3.50 (enhanced oil recovery projects).