Case Information
*1 Opinion filed October 31, 2012
In The
Eleventh Court of Appeals
__________
No. 11-10-00282-CV
__________ OCCIDENTAL PERMIAN LTD., Appellant
V.
MARCIA FULLER FRENCH ET AL., Appellees
On Appeal from the 132nd District Court
Scurry County, Texas
Trial Court Cause No. 22397 O P I N I O N
This is а suit to recover certain royalty payments under two leases. Marcia Fuller French and other royalty owners sued Occidental Permian Ltd., the operator of the Cogdell Canyon Reef
Unit, and alleged that Occidental had underpaid royalties due under the leases. Following a nonjury trial, and after the trial court refused to allow the royalty owners’ request to reopen to present evidence of market value, the trial court rendered judgment for the royalty owners. We reverse and render.
Appellees [1] are royalty owners under two separate oil and gas leases covering lands in Scurry and Kent Counties. Both leases are subject to a unitizatiоn agreement; appellant’s predecessor, as lessee of both leases, was a party to the unitization agreement. Appellant is the current lessee under the leases and is the operator of the Unit pursuant to the terms of the unitization agreement. Appellant is the only party against whom recovery has been sought in this lawsuit.
Following the decline of production in the Unit, in 2001, appellant initiated a CO [2] tertiary recovery operation in order to enhance the production from the Unit. The recovery operation involved injecting CO [2] purchased from Kinder Morgan CO [2] Company into the Unit wherein, generally stated, the CO [2] mixes with the oil in the reservoir and thereby causes more oil to be produced. A result of this type of recovery operation is that the well produces, along with the oil, casinghead gas that, in addition to impurities normally associated with production in the absence of this type of operation, is heavily laden with CO [2] —in this instance about 85% of the casinghead gas stream.
After the casinghead gas stream from the Unit is measured, Kinder Morgan takes possession of the stream and transports it fifteen miles to its Cynara facility. At Cynara, the stream is processed and a majority of the CO [2] is extracted from the stream, as well as two-thirds of the natural gas liquids (NGLs). The extracted CO [2] is then sent back to the Unit for reinjection. As a result of the activities at Cynara, the remaining stream is composed of not more than 10% CO [2] . The remaining gas stream and separated NGLs are sent to the Snyder Gas Plant (SGP) where the remaining CO [2] is extracted, the NGLs are stabilized, and the stream is processed for sale. The CO [2] extracted at the SGP is also sent back to the Unit for reinjection.
In order to initiate this CO tertiary recovery operation, appellant entered into a Treating and Processing Agreement with Kinder Morgan, which covered all of the gas produced from the Unit. In the contract, appellant agreed to pay Kinder Morgan two types of fees each month: (1) a monetary fee and (2) an “in-kind” fee. The monthly monetary fee has dеcreased over time *3 as Kinder Morgan has recovered its cost of capital for certain investments; the fee is not charged against royalty owners. The in-kind fee amounted to 30% of the NGLs and 100% of the residue gas extracted from the casinghead gas stream produced from the Unit. Because no royalty is paid on this in-kind fee, the in-kind fee is, in effect, deducted in calculating royalty payments.
The contract also required Kinder Morgan to enter into a Gas Processing Agreement with Torch Energy Marketing, Inc., the operator of the SGP. The contract required the SGP to complete the activities described above. For these services, Kinder Mоrgan would pay a processing fee of 25¢ per mcf of the gas entering the SGP. Beginning in 2006, this fee escalated annually. Kinder Morgan received 100% of the residue gas and 100% of the NGLs—70% of the NGLs were to be allocated to appellant pursuant to the terms of appellant’s contract with Kinder Morgan described above.
The royalties paid by appellant are based on the NGL proceeds appellant received from
Kinder Morgan under their agreement. Thus, because the in-kind fee is assigned to Kinder
Morgan as compensation under appellant’s contract with Kinder Morgan, appellant paid royalties
on 70% of the NGLs produсed from the Unit and did not pay any royalties on the residue gas.
Royalty is commonly defined as the landowner’s share of production, free of expenses of
production.
Heritage Res., Inc. v. NationsBank
,
At trial, appellees argued, and the trial court agreed, that the entire CO [2] project—the transportation of the CO [2] -laden stream fifteen miles to Cynara and then to the SGP, the extraction of CO at both places, and the return of the CO -permeated stream to the Unit for reinjection—was all a production activity. That a bulk of the NGLs ultimately produced was also separated from the casinghead gas stream at Cynara was “merely incidental to this overall production process.” The deduction of the in-kind fees paid by appellant to Kinder Morgan (100% of the residue gas and 30% of the NGLs) improperly imposed part of the expenses of production upon appellees. The trial court concluded that, because appellant did not pay royalties on 100% of the NGLs and residue gas ultimately produced from the Unit, appellant underpaid its royalty obligatiоns.
In Issues Two, Three, and Five, appellant challenges the legal and factual sufficiency of the evidence offered to show that appellant underpaid royalties owed to appellees.
In an appeal from a bench trial, the trial court’s findings of fact have the same force and
effect as jury findings.
Anderson v. City of Seven Points
,
We review a trial court’s conclusions of law de novo.
BMC Software Belgium, N.V. v.
Marchand
,
In this case, there are two different leases controlling the payment of royalties—the Fuller Lease and the Cogdell Lease. The gas royalty provision of the Fuller Lease provides the following:
4. The royalties to be paid lessor are: . . . (b) on gas, including casinghead gas or other gaseous substance produced from said land and sold or used off the premises or in the manufacture of gasoline or other product therefrom, the market value at the well of one-eighth (1/8th) of the gas so sold or used, provided that on gas sold at the wells the royalty shall be one-eighth (1/8th) of the amount realized from such sale.
The gas royalty provision of the Cogdell Lease provides the following:
3. The lessee shall pay to the lessor for gasoline or other products manufactured and sold by the lessee from the gas produced from any oil well, as royalty, [one-fourth] 1/4 of the net proceeds from the sale thereof, after deducting cost of manufacturing the same. If gas is sold by the lessees, the lеssor shall receive as royalty [one-fourth] 1/4th of the market value at the field of such gas.
Additionally, the unitization agreement prohibits imposing any part of the cost of production operations on the royalty owners:
22. No part of the costs and expenses incurred in the development and operation of the unit area, including secondary recovery and pressure maintenance costs, shall be charged to any royalty owner unless such royalty owner is already obligated to pay such costs or expenses by the terms of other agreements. Such costs and expenses shall be borne by the working interest owners as provided in thе Unit Operating Agreement.
The key dispute we must resolve is whether the evidence sufficiently shows that appellant underpaid royalties by deducting the in-kind fees from its royalty calculation.
It is commonly understood that a royalty is a share of production that is free from the expenses of production. Heritage , 939 S.W.2d at 121–22. This concept is exemplified in the quoted portion of the unitization agreement above. Whereas the amount of the royalty may not be reduced by production costs, postproduction costs are typically deducted prior to calculating royalty. at 122. Postproduction costs include taxes, treatment costs to render the hydrocarbons marketable, and transportation costs. Id.
Appellees contend that this case is unlike virtually all other reported cases in that appellees do not challenge the value of the royalty payments but, rather, claim the volume of production on which appellant pays royalties is deficient. As described above, because of the in- kind fee of 30% of the volume of NGLs and 100% of the residue gas produced from the Unit (part of the consideration paid to Kinder Morgan by appellant under their contract), appellant only pays royalties to appellees on 70% of the NGLs produced, saved, and sold from the gas produced from the Unit and on none of the residue gas remaining after separation of the NGLs. Appellees argue that the in-kind fee is not chargeable to appellees because it is a payment made for production operations. Their assertion that, because royalties were not paid based on 100% of the volume of NGLs and 100% of the residue gas, appellant breached its royalty obligations.
However, in order to determine whether appellant breached its royalty obligations, we
must first look to the clauses in the leases under which those obligations arise.
Tana Oil & Gas
Corp. v. Cernosek
,
Under the Fuller Lease, royalties are to be dеtermined based on the “market value at the
well.” As we stated in
Carter v. Exxon Corp.
,
In its findings, the trial court found that “[t]he market value of NGLs per gallon for royalty purposes is the value per gallon paid to [appellant] by Kinder Mоrgan.” “The market value of the [Unit] residue gas is its value ‘at the well.’” The trial court then reasoned that “[t]he best evidence of the market value of the native [Unit] gas stream”—a hypothetical stream at the well containing less than 2% CO that would exist but for the injection of the CO during the tertiary recovery operation, not the casinghead gas stream that actually is measured at the well— “is the value received by Kinder Morgan under the [Kinder Morgan/Torch] Contract, under which Kinder Morgan receives 100% delivery of both NGLs and residue gas at the tailgate of the SGP, for which it pays the SGP a 25¢ processing fee (escalated annually and now approximately 32¢).” In its determinatiоn of how to compensate appellees for the alleged underpayment of royalties, the court found that “the best measure of the value of these NGLs and residue gas is the terms of the [Kinder Morgan/Torch Contract], less the agreed processing fee, calculated at the values used by [appellant] for NGL royalty payments and Kinder Morgan for the value of the residue gas at the SGP.”
We have reviewed the record to determine whether the market value at the well found by the trial court is supported by evidence under the comparable sales method. Under the comparable sales method, the sale price is cоmpared to other sales that are “comparable in time, quality, quantity, and availability of marketing outlets.” At trial, appellees’ expert Charles Kuss was called to testify about “the market value of the native [Unit] gas[] and what a *7 reasonably prudent operator could expect to receive in an arm’s length, negotiated contract for gas that’s not subject for dedication and free for sale.” He testified generally as to the usual or typical brackets in sharing percentages to producers under a percentage-of-proceeds contract in west Texas and offered his opinion on the market value of the casinghead gas. However, Kuss stated that his opinion was not based on any specific gas contract in the Permian Basin as a comparable sale but, rather, was based on his “historical knowledge in dealings in the business in the industry.” Kuss also acknowledged that he had no experience in selling gas that had a higher CO [2] content as a result of a CO [2] tertiary recovery operation than it initially had in the ground.
After reviewing the record, we hold that the trial court’s findings on the market value are
not supported by any evidence under the comparable sales method. As stated above, “[a]
comparable sale is one that is comparable in time, quality, quantity, and availability of marketing
оutlets.” Here, the record contains no evidence of any specific sales, much less any specific
sales of gas heavily laden with CO
[2]
as a result of a CO
[2]
tertiary recovery operation. The
consideration of contracts for sale of gas with high CO
[2]
content like that present in the
casinghead stream from the Unit is “a material step in the quality analysis required by the
comparable sales” method.
Occidental Permian Ltd. v. Helen Jones Found.
,
In their brief, appellees contend that the actual sales value of the gas at issue as set forth in the Kinder Morgan/Torch Contract is a perfect comparable sale and that, therefore, the trial court properly found it to be “[t]he best evidence of the market value of the native [Unit] gas stream.” Even if only one contract could be sufficiеnt evidence under the comparable sales method, the contract between Kinder Morgan and Torch is not sufficient because it is not a contract for sale of gas at the well. This contract amounts to no evidence under the comparable sales method because it is not a contract for sale of gas with high CO content; instead, it is a contract for the processing of the gas stream after the bulk of the CO has been stripped at Cynara.
Having concluded that no evidence exists to support the trial court’s determination of
market value at the well, we next must examine whether that value is supported by evidence
under the net-back method. We do so without deciding whether appellees proved that
information about comparable sales was not readily available.
See Heritage
,
As noted above, the trial court found that “the best measure of the value of [the] NGLs and residue gas is the terms of the [Kinder Morgan/Torch] Contract [100% NGLs/100% residue gas split], less the agreed processing fee, calculated at the values used by [appellant] for NGL royalty payments and Kinder Morgan for the value of the residue gas at the SGP.” Appellees contend that this formula properly supports the determination of market value at the well under the net-back method. The processing fee, they claim, accounts for the postproduction activities of the costs of transportation from the well to the SGP and the processing at the SGP, and therefore was deducted from the net sales values at which the NGLs and residue gas were sold in order to arrive properly at the market value at the well under the net-back method.
Appellant argues that appellees’ net-back analysis is incorrect because it fails to subtract the costs of any activities at Cynara. We agree. In оrder for us to hold otherwise would require that we agree with appellees’ contention that all of the activities that take place at Cynara are properly classified as production, the cost of which is not chargeable to royalty owners. We do not. As stated above, appellees bore the burden of proving market value at the well. Appellees’ damage models included values of NGLs and residue gas at the tailgate of the SGP, with the costs of transportation from the well to the SGP and processing at the SGP netted out by deducting the SGP processing fee. They claim that the net-back of the prices at the SGP tailgate by deducting this fee brings the value of the native Unit gas back to the gas value at the well. However, this assumes that the only allowable postproduction costs that may be deducted are the costs for the activities at the SGP and none at Cynara. Because appellees contend that all of the activities that take place at Cynara are production activities, they did not offer any evidence allocating the costs for the various activities that take place at Cynara. Therefore, if any of the activities that take place at Cynara are postproduction activities, there is no evidence in thе record to support the market value at the well under the net-back method because there are some *9 postproduction costs that have not been deducted, and we could not ascertain those costs from the record. See id. at 123.
In addition to the separation of the majority of the CO from the casinghead gas stream, the following also occur at Cynara: compression, dehydration, separation of hydrogen sulfide, separation of two-thirds of the total created NGLs, and transportation of the remaining stream and NGLs to the SGP. Appellant does not dispute that production activities, which are not properly chargeable to royalty owners, occur at Cynara; however, appellant argues that the record contains no evidence that the monetary fee paid to Kinder Morgan, which is not charged against royalties, does not cover the cost of all of the production activities. Thus, appellant argues, there is no evidence that it underpaid royalties.
In
Cartwright v. Cologne Production Co.
,
We agree with the Corpus Christi court that the removal of hydrogen sulfide from the casinghead gas stream is a postproduction activity done to render the stream marketable. Because the costs of separating the hydrоgen sulfide were not deducted in the trial court’s determination of market value at the well under the net-back method, we hold, without even addressing the other activities at Cynara, that the evidence does not support the trial court’s determination of market value.
The trial court found that both the monetary and in-kind fees paid by appellant to Kinder Morgan cover all of the services provided by Kinder Morgan and that neither is “allocable to any of the many services provided by Kinder Morgan, or between production and post-production expenses.” However, appellees had the burden of proving the market value at the wеll under the net-back method. Heritage , 939 S.W.2d at 122. To do so, they were required to subtract reasonable postproduction costs from the market value at the point of sale. Appellees’ expert Wayman Gore testified that, if he “had the information on which to make a reasonable allocation” of the costs of the various services, he could do so. Appellees failed to offer evidence to show that the costs of all postproduction activities had been deducted; therefore, the trial court’s determination of the market value at the well was in error. Because neither method of proving market value at the wеll is properly supported by evidence, the evidence is not sufficient to show that appellant underpaid royalties under the Fuller Lease.
We next turn to the Cogdell Lease. Under the Cogdell Lease, royalties are to be
determined based on “the net proceeds from the sale . . . , after deducting cost of manufacturing.”
“If gas is sold by the lessees, the lessor shall receive as royalty [one-fourth] 1/4th of the market
value at the field of such gas.” “‘Proceeds’ or ‘amount realized’ clauses require measurement of
the royalty based on the amount the lessee in fact receives under its sales contract for the gas.”
Bowden v. Phillips Petroleum Co.
,
We have alreаdy held that, at least, the removal of hydrogen sulfide from the casinghead gas stream is a postproduction activity done to render the stream marketable. Because we have held that it is necessary to render the stream marketable, we also hold that it is a cost of manufacturing that must be deducted in order to determine the net proceeds from the sale, and thus the royalty, under the Cogdell Lease. Because the trial court’s royalty calculation does not include the deduction of the cost of the removal of hydrogen sulfide, we hold that the evidence is insufficient to prove that appellant underpaid royalties under the Cоgdell Lease.
Appellant’s Issues Two, Three, and Five, concerning whether the evidence sufficiently showed that appellant underpaid royalties under the Fuller and Cogdell Leases, are sustained. In appellant’s first issue, it argues that the CO separation activity is a postproduction activity, the cost of which is properly shared with royalty owners, because the separation activity is necessary to obtain marketable products from the casinghead gas. Because we have held that the evidence is insufficient to prove that appellant underpaid royalties, we do not need to decide and do not *11 decide aрpellant’s first issue concerning whether any or all of the costs of separating CO from the casinghead gas stream is a postproduction expense. T EX . R. A PP . P. 47.1.
In his fourth and sixth issues, appellant contests the trial court’s conclusion that appellant
breached an implied duty to market. In the fourth issue, appellant challenges part of the trial
court’s conclusion of law that provides that appellant “has an implied duty to market gas
production from the [Unit] as a reasonably prudent operator” and that appellant breached this
duty. Specifically, appellant challenges whether Texas law recognizes an implied duty tо market
in a market-value lease. Appellant contends that Texas law does not. We agree. In
Bowden
, the
Texas Supreme Court recognized its conclusion in two of its previous cases that a duty to market
cannot be implied in a market-value case.
Appellant’s sixth issue challenges the legal and factual sufficiency of the evidence that
appellant violated the duty to market implied in the Cogdell Lease. The Texas Supreme Court
has recognized that a duty to market may be implied in some “proceeds” leases.
Bowden
, 247
S.W.3d at 701. “‘[T]he standard of care in testing the performance of implied covenants by
lessees is that of a reasonably prudent operator under the same or similar facts and
circumstances.’” at 699 n.4 (quoting
Amoco Prod. Co. v. Alexander
,
The trial court held that the 25¢ per mcf processing fee covered all postproduction expenses. Therefore, the trial court concluded that, by deducting the in-kind fee paid to Kinder Morgan from its royalty payments and thus forcing the royalty owners to bear a portion of the expenses of production, appellant breached the implied duty to market because it obtained for itself a financial benefit that was not shared with the royalty owners. In other words, the trial court’s conclusion, and appellees’ argument, is based on the supposition that appellant was not entitled to the benefit of passing on any of the costs of the activities at Cynara becausе this breached the royalty clauses of the respective leases. We have already held that the evidence at trial was insufficient to show that appellant breached its obligations under the royalty clauses. *12 However, we still must examine the evidence in order to determine whether there is sufficient evidence to support the trial court’s conclusion that appellant breached the implied duty to market under the Cogdell Lease.
At trial, appellees asked Kuss the following: “In your opinion would a reasonably prudent
operator having in mind the interest of the lessor and the lessee accept this 70/0 split under a
POP contraсt or a gas processing agreement for the native gas available at [Unit] Central Tank
Battery 1?” Kuss responded, “No.” In this question, when appellees’ counsel referred to “native
gas,” he was referring to the casinghead gas with the injected CO stripped out of the quantity
and quality. Appellant objected to the use of this term on the ground that there was no native gas
available at the well that met those qualities because, at that point, the produced gas still included
the CO and other impurities. Appellees also asked, “Mr. Kuss, with respect to your opinions
under POP contracts, what POP contract in your opinion would a reasonably prudent operator
having in mind the interest of the lessor and lessee obtain for the native [Unit] gas at [the well]?”
Kuss answered, “I would say an 85 percent of proceeds to the producer would be reasonable --
what a reasonably prudent operator could receive for gas for sale at that point, or the 100/100 gas
processing agreement. Either one of those would be reasonable. I would give weight to the gas
processing agreement, because it covers the exact gas we’re talking about.” This is inapposite
here because the testimony does not address the casinghead gas that is actually produced at the
well. “An expert’s opinion might be unreliable, for example, if it is based on assumed facts that
vary from the actual facts, or it might be conclusory because it is based on tests or data that do
not support the conclusions reached.”
Whirlpool Corp. v. Camacho
,
In addition to the award of damages for breach of the royalty provisions and the implied duty to market, the court also awarded appellees attorney’s fees and entered a declaratory judgment ordering appellant to pay royalties on future production in compliance with the respective leases and in the same fashion as embodied in the trial court’s judgment for past *13 production. In its seventh and eighth issues, appellant challenges the award of attorney’s fees and the grant of declaratory relief. Because both awards were based on alleged contractual breaches, which we have now held to be unsupported by evidence, we also hold that the award of attorney’s fees and declaratory relief were improper. See T EX . C IV . P RAC . & R EM . C ODE A NN . §§ 37.004(b), 38.001 (West 2008). Appellant’s seventh and eighth issues are sustained.
The judgment of the trial court is reversed, and we render judgment that appellees take nothing.
JIM R. WRIGHT CHIEF JUSTICE October 31, 2012
Panel [2] consists of: Wright, C.J., McCall, J., and Hill. [3]
Notes
[1] Appellees are Marcia Fuller French; Gillian Fuller; French Capital Partners, Ltd.; Lesa Oudt; Connie Delle Cogdell, individually and as trustee of the David M. Courtney Trust, and as trustee of the John Cogdell Courtney Trust; John Courtney, trustee of the Carol C. Courtney Disclaimer Trust; Penny Cogdell Carpenter, individually and as co-independent executor of the Estate of William Munsey (“Billy”) Cogdell and as co-trustee of the Cogdell Marital Trust; Billy Rank Cogdell, individually and as co-independent executor of the Estate of William Munsey (“Billy”) Cogdell and as co-trustee of the Cogdell Marital Trust; Dick Munsey Cogdell, individually and as co-independent executor of the Estate of William Munsey (“Billy”) Cogdell and as co- trustee of the Cogdell Marital Trust; Jim David Cogdell; and Happy State Bank and Trust Company, as trustee for the Martha Ann Cogdell Hospital Trust.
[2] Eric Kalenak, Justice, resigned effective September 3, 2012. The justice position is vacant pending appointment of a successor by the governor or until the next general election.
[3] John G. Hill, Former Chief Justice, Court of Appeals, 2nd District of Texas at Fort Worth, sitting by assignment.