Ryan v. American Natural Energy Corp.

557 F.3d 1152, 171 Oil & Gas Rep. 243, 2009 U.S. App. LEXIS 5235, 2009 WL 500602

• Court: Court of Appeals for the Tenth Circuit
• Decided: March 2, 2009
• Docket: 08-5002, 08-5110
• Status: Published

Opinion

PAUL KELLY, JR., Circuit Judge.

In No. 08-5002, Plaintiff-Appellant Christopher J. Ryan (“Ryan”), in his capacity as the liquidation agent for a class of creditors in a confirmed chapter 11 reorganization plan, appeals from the district court’s judgment in favor of Defendant-Appellee American Natural Energy Corporation (“ANEC”). In this diversity case, the district court held a bench trial resulting in findings of fact and conclusions of law in support of the judgment awarding Ryan no relief. Ryan v. Am. Natural Energy Corp., No. 06-CV-022, 2007 WL 4285324 (N.D.Okla. Nov.30, 2007). In No. 08-5110, ANEC appeals from the district court’s order denying it attorney’s fees. Ryan v. Am. Natural Energy Corp., No. 06-CV-022, 2008 WL 2705462 (N.D.Okla. July 9, 2008). Our jurisdiction arises under 28 U.S.C. § 1291 and we affirm in part and reverse in part and remand on the merits; we affirm the district court’s denial of attorney’s fees.

Background

Ryan is the liquidation agent for the Class 7 creditors in the confirmed chapter 11 reorganization plan for the Couba Operating Co. As part of settlement negotiations in the bankruptcy case, Couba agreed to assign certain leases to ANEC. ANEC in turn conveyed to Ryan a net profits interest (NPI) and an overriding royalty interest (ORI) in a 23.5 square mile area surrounding these leases, known as the area of mutual interest or AMI. The parties settled their differences concerning the ORI. The meaning of the NPI conveyance is what remains.

Concerning the NPI, ANEC conveyed a 50% NPI to the oil and gas produced from existing wells on the leases; a 15% NPI in production from new wells on the leases; and a 6% NPI in production from new wells drilled in the AMI. Aplt.App. 358, §§ 2.2-2.4. Production periods are monthly. Aplt.App. 357 art. I (“Production Period”). Existing wells existed as of the effective date of the confirmed plan (November 16, 2001); new wells are those drilled thereafter. ApltApp. 356-57, art. I (“Effective Date,” “Existing Wells,” “New Wells,” “Plan”); Ryan, 2007 WL 4285324, at *2.

ANEC refurbished and restarted production on five to seven existing wells, drilled fifteen new wells on the leases, and attempted two wells on the AMI. Ryan, 2007 WL 4285324, at *2. In determining amounts due the Class 7 creditors on the NPI, Ryan contends that costs and proceeds (hence the NPI) should be calculated on a per-well basis and without any carry-forward of unrecouped direct costs. ANEC argues that costs should be allocated on a system-wide basis, i.e. aggregating all costs from existing and new wells, allowing carryforward of any unrecouped costs. Aggregate costs would then be deducted from aggregate revenues, and net profit would occur only after all costs had been recouped. ANEC also maintains that $1.1 million it spent to restore existing wells and evaluate the advisability of new drilling qualifies as a direct cost borne by the NPI; Ryan contends that such costs are lease acquisition costs not properly borne by the NPI.

The district court determined that the contract (conveyance) was ambiguous because it was susceptible to different interpretations as to net profits interest. Id. at *6. Accordingly, the district court considered extrinsic evidence. Id. at *7. It also mentioned the rule of contra proferentem, and concluded that the conveyance should be construed against Ryan and the Class 7 creditors as the drafters. Id. The court determined that ANEC’s interpretation of aggregating and allocating costs on a system-wide basis should obtain because (1) “direct costs” were broadly defined, (2) such costs could not be separated on a well-by-well basis, and (3) such an interpretation was consistent with the underlying negotiations — the Class 7 creditors knew that for the net profits interest to pay, substantial development was necessary, and accordingly also took an overriding royalty interest for a more direct payoff. Id. The district court also determined that ANEC’s $1.1 million spent to restore old wells and evaluate drilling prospects qualified as direct costs, as there was no indication in the plan that ANEC would forego such treatment. Id. at *10.

In addition to the different NPI percentages based upon the type of well, the conveyance repeatedly distinguishes between new wells and existing wells insofar as payment and recordkeeping requirements, including a requirement of sub-accounts for costs. Aplt.App. 356, art. I (“Direct Costs Accounts”); 357, art. I (“Proceeds”); 358, § 3.2; 359, § 6.1; 360, § 6.3(h). The district court determined that although sub-accounts were called for in the conveyance, they are only necessary in the event aggregate costs for all wells are recouped (and profit results). Ryan, 2007 WL 4285324, at *8. The sub-accounts would then be used to allocate net profits in accordance with the different percentages, 50% for existing wells on leases, 15% for new wells on leases, and 6% for new wells drilled on lands located within the AMI. Id. The district court reasoned that because the sub-accounts are tied to the definition of new wells and existing wells, the sub-accounts do not support a well-by-well calculation, with only profitable wells considered for payments. Id. The district court also explained that monthly production and payment periods did not mean that costs cannot be carried forward and aggregated because the conveyance allows for recoupment. Id.

The district court concluded that all existing and new wells whether drilled on leases or the AMI were a “net profit system” and profits only occur after ANEC recoups all system costs. Id. at *9. It then determined that the system had as of October 2006 incurred a net loss of approximately $8.65 million, after trimming the direct costs claimed by ANEC of $6.3 million related to the Couba acquisition. Id. at *9-10. Thus, ANEC has substantial costs (reflected in a net loss of $8.65 million as of October 2006) that it can recoup before paying Ryan on the NPI. On the other hand, Ryan’s expert CPA, Walter Thomas, found that $1.4 million was due to Ryan based upon five profitable new wells; that calculation was based upon revenues and expenses per well, not including field start-up costs which he did not consider a direct cost. Aplt. Br. 12; ApltApp. 167-68; 380.

After the judgment in ANEC’s favor, ANEC sought attorney’s fees pursuant to Okla. Stat. Ann. tit. 12, § 936, claiming that the lawsuit was a civil action to recover upon an open account or an account stated and it was a prevailing party. The district court denied the motion, holding that the conveyance was neither an open account nor an account stated. Ryan, 2008 WL 2705462, at *3-5.

As framed by Ryan, the merits appeal presents the following issues: (1) whether ANEC is allowed to recoup its entire aggregate costs of developing and operating the leases and AMI acreage prior to paying any net profits to Ryan and the Class 7 creditors; (2) whether it is not possible to separate certain expenses listed as “direct costs,” i.e. marketing, transportation of oil and gas, etc., on a well-by-well basis, (3) whether ANEC was properly allowed to designate some $1.1 million as a direct cost for the restoring of existing wells to production and evaluating the advisability of new wells, under the NPI conveyance, and (4) whether the NPI conveyance should have been construed against Ryan and the Class 7 creditors. We consider issue (4) concerning ambiguity first and reach the others in turn. Thereafter, we turn to the attorney’s fees appeal in which ANEC argues that the district court erred in holding that Okla. Stat. Ann. tit. 12, § 936 is inapplicable to this case given its unique facts.

Discussion

A. Standard of Review

We review the district court’s legal conclusions in a bench trial de novo; findings of fact will not be set aside unless clearly erroneous. Fed.R.Civ.P. 52(a)(6); Salve Regina Coll. v. Russell, 499 U.S. 225, 232-33, 111 S.Ct. 1217, 113 L.Ed.2d 190 (1991); Anderson v. City of Bessemer City, 470 U.S. 564, 574-75, 105 S.Ct. 1504, 84 L.Ed.2d 518 (1985). The parties agree that Oklahoma law applies, and that the conveyance is ambiguous. Aplt. Br. 15-17; Aplee. Br. 9. We pay deference to the district court’s findings based upon its observation of the testimony as well as documentary evidence. Anderson, 470 U.S. at 574, 105 S.Ct. 1504.

Where interpretation of an ambiguous contract is aided by extrinsic evidence, the resulting interpretation is factual and cannot be set aside unless clearly erroneous. Morrison Knudsen Corp. v. Ground Improvement Techniques, Inc., 532 F.3d 1063, 1069 n. 3 (10th Cir.2008); Valley Improvement Ass’n, Inc. v. U.S. Fid. & Guar. Corp., 129 F.3d 1108, 1115 (10th Cir.1997). A finding is clearly erroneous when the reviewing court has a definite and firm conviction that it is mistaken, even though there may be some evidence to support it. Anderson, 470 U.S. at 573, 105 S.Ct. 1504. Where there are two permissible views of the evidence, a finding adopting one of those views cannot be clearly erroneous. See id. at 574, 105 S.Ct. 1504.

Initially, the parties seemed to agree that the clearly erroneous standard applies to the first three issues in this case because the court relied on extrinsic evidence to interpret an ambiguous conveyance. Aplt. Br. 15-16; Aplee. Br. 9-10. ANEC argues that the fourth issue, whether the conveyance should be construed against the drafter, and presumably the predicate question of whether a conveyance is ambiguous, is a legal issue. Aplee. Br. 10, 22-23.

By the time of the reply brief, Ryan determined that all issues should be reviewed de novo because whether a contract is ambiguous is a question of law and contract construction is a legal issue, according to Oklahoma authority. We agree with the parties that whether a contract or provision is ambiguous is a question of law to be determined only with reference to the contract itself. See Otis Elevator Co. v. Midland Red Oak Realty, Inc., 483 F.3d 1095, 1101 (10th Cir.2007); M.J. Lee Constr. Co. v. Okla. Transp. Auth., 125 P.3d 1205, 1210 (Okla.2005). In determining ambiguity, we look at the entire con tract. Pitco Prod. Co. v. Chaparral Energy, Inc., 63 P.3d 541, 546 (Okla.2003). Merely because the parties offer different interpretations of a contract does not make it ambiguous; the relevant inquiry is whether the contract is reasonably susceptible to more than one construction such that reasonable persons could honestly disagree as to the meaning. Otis Elevator Co., 483 F.3d at 1102; M.J. Lee Constr. Co., 125 P.3d at 1213. Once a contract provision is determined to be ambiguous, the trier of fact resolves its meaning, and the trier of fact’s construction ought not to be set aside unless clearly erroneous. Otis Elevator Co., 483 F.3d at 1101-02; Fowler v. Lincoln County Conservation Dist., 15 P.3d 502, 507 (Okla.2000).

Although we find that the conveyance is ambiguous regarding aggregation and re-coupment of costs, it is unambiguous concerning the need for allocating proceeds and costs to new wells and existing wells. Though the process of allocating proceeds and costs as a practical matter is done well-by-well, there must be aggregation of these amounts within the two categories prior to any payout of NPI. Thus, we reject the contention that only profitable wells within a category may be considered. Accordingly, we will affirm the district court’s conclusion that costs must be aggregated and carried forward, but reverse its conclusion that all proceeds and costs are part of a “net profits system.”

B. Ambiguity

The conveyance conveys a net profits interest “in and to all of the Oil and Gas produced from the Leases, if, as, and when Oil and Gas are produced during the terms of the Leases ...” Aplt.App. 357, § 2.1. The net profits interest is a “right to receive payments of proceeds,” and “does not represent a working interest or other participating cost-bearing interest.” Aplt. App. 357, § 2.1; see also 358, § 3.4 (“The Liquidation Agent shall not be responsible for payment of any Direct Costs or any other costs of any nature.”).

A net profits interest is “a non-working interest” that

is similar to a royalty interest or an ORI [overriding royalty interest] except that the amount to be received is a specified percentage of net profit from property versus a percentage of gross revenues from the property. The allowed deductions from gross revenues to calculate the net profit are usually specified in the lease agreement. While net profits interest owners are entitled to a percentage of the profits, they are not responsible for any portion of losses incurred in property development and operations. These losses, however, may be recovered by the working interest owner from future profits.

Charlotte J. Wright & Rebecca A. Gallun, Fundamentals of Oil & Gas Accounting 15 (5th ed.2008). Again, losses are the responsibility of working interest owners “but may be recovered by the working interest owner from future profits.” Id.; Charlotte J. Wright & Rebecca A. Gallun, International Petroleum Accounting 37-38 (2005).

ANEC must pay “by check an amount equal to the Net Profits Interest payable with respect to the Oil and Gas produced from the Leases during the current Production Period.” Aplt.App. 358, § 3.1. Production periods are monthly. Aplt. App. 357, art. I (“Production Period”). Payment dates are 30 days thereafter. Aplt.App. 357, art. I (“Payment Date”). The conveyance requires “a detailed statement” on or before each payment date “clearly reflecting, for Existing Wells and New Wells separately, Proceeds, Direct Costs, credits and debits against the Direct Costs Account for the Production Period, and the balance of the Direct Costs Account as of the close of[] business on the last day of the preceding Production Period.” Aplt.App. 358, § 3.2. ANEC is required to keep sufficient books and records to determine amounts payable to Ryan on existing wells and new wells, including “information relating to the calculation of Proceeds, Direct Costs, the balance of the Direct Costs Accounts.” Aplt. App. 359, § 6.1. ANEC is also required to provide an annual report showing production, a computation of proceeds and direct costs, producing wells and wells completed during the calendar year, and classification of the wells as existing or new wells. Aplt. App. 360, § 6.3.

The conveyance defines “Net Profits” as “Proceeds reduced by Direct Costs.” ApltApp. 356, art. I (“Net Profits”). “Proceeds” applies to any production period and means gross proceeds from oil and gas sales from existing well and new wells. Aplt.App. 357, art. I (“Proceeds”). The definition also requires that proceeds from new and existing wells “be determined separate and apart.” Aplt.App. 357, art. I (“Proceeds”).

The direct costs definition also employs the distinction between new wells and existing wells. ‘“Direct Costs’ means for any Production Period, on the cash method of accounting, all little 1 direct costs attributable to generating Proceeds including the following costs attributable to the working interest of ANEC or its Affiliates in Existing Wells or New Wells[.]” Aplt. App. 355, art. I (“Direct Costs”). The definition then provides specific guidance as to what direct costs are:

(i) production and severance taxes, ad valorem taxes, royalties, overriding royalties, and other burdens upon production (excluding the burden established by this Agreement);

(ii) operating expenses incurred in accordance with the applicable Joint Operating Agreement, or in the event no such Joint Operating Agreement can be located, then those costs of operation set forth in the most recent version of the COPAS Accounting Procedures Exhibit to the AAPL Model Form Operating Agreement^]

(iii) drilling and completion costs, and costs of plugging back, reworking, re-completing and plugging and abandoning after commercial production;

(iv) costs of marketing, transportation, and treatment of Oil and Gas.”

Aplt.App. 356, art. I (“Direct Costs”).

The “Direct Costs Accounts” definition provides for separate sub-accounts to record direct costs for new and existing wells:

“Direct Costs Accounts” means a[sic] bookkeeping accounts established by ANEC to record the aggregate amount of unrecouped Direct Costs attributable to the interest of ANEC or its Affiliates in Existing Wells or New Wells. Direct Costs for Existing Wells and New Wells will be recorded in separate sub-accounts. Each account shall have an initial balance of zero and shall be increased at the close of each Production Period by Direct Costs (if any) incurred during such Production Period, and shall be decreased at the close of each Production Period by the amount of Net Proceeds received from the sale of Oil and Gas during such Production Period. The balance of the Direct Costs Account shall never be less than zero.

Aplt.App. 356, art. I (“Direct Costs Accounts”). Thus, the conveyance endeavors to spell out how the NPI should be calculated. See Wright & Gallun, Fundamentals of Oil & Gas Accounting 549 (“The calculation of net profits, i.e., the allowed deductions from gross revenue to compute net profit, should be clearly indicated in the contract.”).

The district court determined that the conveyance is ambiguous as to the proper calculation of NPI because certain provisions suggest that all costs must be recouped before any net profits are recoverable, and others suggest “that costs cannot ‘cross-over’ from well to well and cannot be carried forward from year to year.” Ryan, 2007 WL 4285324, at *6. According to the district court, two provisions suggest that costs for the entire operation should be aggregated before payment. First, direct costs are defined as “all direct costs” in existing or new wells, not just costs of a particular period. Id. Second, the definition of “Direct Costs Accounts” contains an explicit directive to record “the aggregate amount of unrecouped Direct Costs.” Id.; Aplt.App. 356, art. I (“Direct Costs Accounts”). To this we might add that both the direct costs accounts provision and the monthly statement provision of the conveyance speak to “direct costs accounts,” yet conclude with reference to just one “direct cost account.” ApltApp. 356, art. I (“Direct Costs Account”); 358, § 3.2 (“Statements”); see also id. 360, § 6.3(i).

On the other hand, some provisions suggested to the district court that costs should not be aggregated, and that payments should be based only on costs during the production period. First, the “Direct Costs Accounts” provision creates sub-accounts for new and existing wells to hold direct costs for new and existing wells. ApltApp. 356, art. I (“Direct Costs Accounts”). Second, by definition, proceeds and direct costs are tied to monthly production and payment periods. Aplt. App. 355, art. I (“Direct Costs”); 357, art. I (“Proceeds”).

We agree with the district court that the conveyance is ambiguous as to whether unrecouped direct costs may be aggregated and carried forward from period to period to be offset against proceeds in determining NPI. The “Direct Costs Accounts” definition plainly speaks to the “aggregate amount of unrecouped Direct Costs” and the “Direct Costs” provision also speaks to “all direct costs attributable to generating Proceeds.” On the other hand, there is no denying that the definition of “Proceeds,” “Direct Costs,” and “Payment Date,” are plainly tied to production periods suggesting a period-to-period approach to NPI.

That said, we do not agree that the conveyance is ambiguous as to the level of aggregation. There simply are too many provisions that suggest the NPI calculation must be done separately for existing wells and new wells. In all likelihood, this level of aggregation requires a well-by-well approach, with all existing wells combined, and then new wells, and separate NPI calculations. The district court’s finding/conclusion that it was not possible to allocate direct costs on a well-by-well basis is clearly erroneous for reasons we discuss below and no doubt contributed to its resolution of this issue. To effectuate the intent of the parties as reflected in the conveyance, ANEC must differentiate not only between existing wells and new wells, but also within the new wells category, between new wells drilled on the leases, and new wells drilled on the AMI. This will allow different NPI percentages to be paid on the three categories of wells in the event that the aggregate costs of the new wells are recouped.

C. Contra Proferentem

The district court found that the conveyance was drafted by the Class 7 creditor’s committee (and Ryan), and stated that it must be construed against Ryan and the Class 7 creditors as an ambiguous contract. Ryan, 2007 WL 4285324, at *4 (finding no. 27), *7 (conclusion no. 5). Although we take a narrower view of that ambiguity, we turn to Ryan’s arguments concerning whether the doctrine was properly invoked. Ryan first argues that although ANEC’s witnesses testified that he and the committee drafted the conveyance, no evidence supports their testimony because these witnesses also testified as to their involvement in the negotiations. Aplt. Br. 29. Ryan was chair of the unsecured creditors committee and testified as to his interpretation of the agreement; ANEC’s chief financial officer (Mr. Ensz) testified that the unsecured creditors committee drafted the NPI. ApltApp. 130, 239. Although the parties testified about negotiating the agreement, the district court’s finding that Ryan drafted the agreement does not need additional corroborating evidence and is not clearly erroneous. The fact that both sides participated in the negotiations does not undermine the district court’s finding.

Ryan next argues that the district court failed to apply Oklahoma’s rules of contract construction to remove the uncertainty before applying the rule of contra prof-erentem. Okla. Stat. Ann. tit. 15, § 170 (“In cases of uncertainty not removed by the preceding rules, the language of a contract should be interpreted most strongly against the party who caused the uncertainty to exist.”); Cities Serv. Oil Co. v. Geolograph Co., 208 Okla. 179, 254 P.2d 775, 782 (1953). Ryan relies upon rules that (1) a contract is interpreted to give effect to the intent of the parties, Okla. Stat. Ann. tit. 15, § 152, (2) a contract should be interpreted as a whole, giving effect to every part if reasonably practicable, id. § 157, and (3) a contract may be explained by surrounding circumstances and the matter to which it relates, id. at § 163. Relying on McMinn v. City of Okla. City, 952 P.2d 517, 522 (Okla.1997), for the proposition that an ambiguous contract should be construed against the drafter, the district court did not expressly refer to the requirement that the other rules must be invoked first. It is of no consequence, however. First, the district court at the outset recited that (1) its primary purpose was to give mutual effect to the intention of the parties, and (2) because the conveyance was ambiguous, (a) consideration of extrinsic evidence was proper, and (b) it must be interpreted in a fair and reasonable manner. Ryan, 2007 WL 4285324, at *6-*7. Thereafter, it mentioned that the contract must be construed against the drafter. Second, and most important, the district court’s interpretation of contract (based upon the express language of its conclusions) does not appear to be based upon the rule of contra proferentem, but rather upon the language of the conveyance, a fair and reasonable reading of the conveyance, the negotiations between the parties, the purpose of the conveyance and its various provisions, and the trial testimony. Id. at *7-*10. Regardless, this case is easily resolved based upon the standard principles of contractual interpretation mentioned above, and it is unnecessary to resort to the rule of contra proferentem.

D. “Net Profits System ”

Ryan argues that the district court erred in holding that ANEC was allowed to recoup its entire aggregate costs of developing and operating the leases and AMI acreage prior to paying any net profits to Ryan. According to Ryan, the district court ignored significant portions of the conveyance — that proceeds and direct costs must be separated into existing wells and new wells, and that proceeds and direct costs are bounded by monthly production periods, with payment dates thirty days thereafter. Ryan also argues that the “net profit system” created by the district court is unworkable to the extent that all of the costs are ever re couped because, having aggregated all of the revenues and costs of all three categories of wells, any determination as to what category bears the NPI (50% on existing wells, 15% on new wells on leases, 6% on new wells on AMI) is unknowable. Ryan also points out that a net profits system on an aggregate basis provides incentive for ANEC to delay reporting of its costs and encourages it to incur direct costs to offset proceeds, regardless of the type of well involved.

In support of the “net profits system,” ANEC argues that the conveyance conveys a NPI “in and to all of the Oil and Gas produced from the Leases,” ApltApp. 357, § 2.1 (emphasis added), not from individual wells. While this is true, the conveyance also sets up three different NPI percentages, and contains direction on payment obligations and documentation, all of which sheds light on how the NPI is to be calculated.

The district court’s “net profits system” is difficult to reconcile with the repeated references to existing wells and new wells, suggesting that any net profits system must be for each of those two categories, not just “all wells.” The conveyance repeatedly references existing wells and new wells. ApltApp. 355-57, art. I (“Direct Costs,” “Direct Costs Accounts,” “Existing Wells,” “New Wells,” “Proceeds”); 358, § 3.2; 359, § 6.1; 360, § 6.3(h). We hold that the conveyance requires separation of proceeds and direct costs based upon the status of a well as new or existing. Further, given the three NPI percentages, proceeds and direct costs must be maintained for new wells on existing leases and new wells on the AMI.

Ryan also argues that the two categories of reporting, existing wells and new wells, together with monthly production periods suggest that all costs were never intended to be earned forward, let alone aggregated. Aplt. Br. 17-18. The problem with this interpretation is that the “Direct Costs Accounts” definition portends aggregating unrecouped direct costs, and offsetting them with net proceeds until extinguished. Likewise, two of the reporting provisions required by the conveyance envision a statement containing unrecouped direct costs. ApltApp. 258, § 3.2; 360, § 6.3(i). The permanency of the direct costs accounts (which carry forward from period to period) suggests that unrecouped costs within either category (existing wells and new wells) are carried forward. This is also consistent with the testimony that the district court credited: the Class 7 creditors were also given an ORI because it was apparent that significant start up costs had to ■ be incurred and recouped before the NPI would be profitable. Aplt. App. 209-10.

E. Separating Out Direct Costs

The district court found that it was impossible to separate out direct costs such as marketing, transportation, and treatment of the oil and gas on a well-by-well basis because the leases are on a field underwater and all oil and gas must be transferred collectively by pipeline. Ryan, 2007 WL 4285324, at *7. Ryan argues that there is no support for this — and it is contrary to the “Direct Costs” provision which requires separation of costs between existing and new wells. Aplt. App. 355-56, art. I (“Direct Costs”). Additionally, Ryan argues that such costs would have to be allocated because ANEC was not the only working interest owner in the field, and such costs must be charged to the other working interest owners. Aplt. Br. 23-24; ApltApp. 263. Additionally, Ryan correctly notes that ANEC kept records on a well-by-well basis and that the provision requires operating expenses to be allocated in accordance with first, a joint operating agreement, and if no such joint operating agreement can be located, in accordance with the COPAS Accounting Procedure Exhibit to the AAPL Model Form Operating Agreement. Aplt.App. 356, art. I (“Direct Costs,” (ii)); see Wright & Gallun, Fundamentals of Oil & Gas Accounting 465-67, 491-538 (discussing joint interest accounting and the CO-PAS accounting procedure).

According to Ryan, ANEC has waived its right to argue that costs cannot be separated on an individual well basis and should be estopped from asserting it here. While the record certainly confirms that ANEC keeps records and sub-accounts on a well-by-well basis, we agree with ANEC that we should decline to consider Ryan’s waiver and estoppel argument. Such an argument does not appear to have been presented below (in those terms) and whether costs can be separated appears as part of the general issue that was tried.

That said, we agree with Ryan that proceeds and costs may be allocated on a per-well basis (though we differ on how that information factors into the NPI calculation). ANEC’s response to the merits of this issue is that Ryan simply cannot prove his contentions with trial evidence. Aplee. Br. 19. Yet it was undisputed that ANEC kept proceeds and costs on a per-well basis (subaccounts). Aplt. App. 161, 212-15, 234-36. The district court’s statement that costs cannot be allocated is incorrect. Allocation of operating costs for an oil and gas lease is frequently necessary because of contractual obligations and is typically done by individual wells or leases. Wright & Gallun, Fundamentals of Oil & Gas Accounting 286; see also id. at 517 (explaining that working interest owners have an obligation to pay costs and expenses and discussing direct and indirect costs). Indeed, ANEC’s Mr. Paulk testified that if certain new wells are drilled “if Exxon participates, they pay half the interest. They pay half of the costs.” ApltApp. 263. “Production costs can be divided into those that are directly attributable to a specific well or lease and those that must be assigned to the well or lease through some method of allocation.” Wright & Gallun, Fundamentals of Oil & Gas Accounting 286; id. at 517 (discussing direct and indirect costs).

When costs incurred benefit a number of wells or leases, costs must be “allocated to each well or lease on some reasonable basis. Common allocation bases include the number of wells or number of barrels produced.” Id. at 286; see also id. at 517. Other reasonable allocation bases for various types of allocable costs include direct labor hours or cost, number of miles driven for transportation and hauling, and gallons of water used for waterflooding. Id. at 286. Ryan suggests that “each well has its own pipes and ‘flow lines’ and oil and gas from each well has to be separately metered and accounted for before flowing into a collective tank.” Aplt. Br. 25. This can be explored on remand, but we must reject the notion that costs cannot be allocated merely because a field is underwater and oil and/or gas is transferred via pipeline.

F. Field Start Up Costs as a Direct Cost

Ryan argues that the district court erred in allowing ANEC to designate $1.1 million as direct costs for restoring existing wells to production and evaluating the advisability of new wells. Ryan argues that this cost pertains only to existing wells and was a negotiated acquisition cost that could not be a direct cost. Thus, even if this amount was included, it should have been divided between new wells and existing wells. Ryan’s expert testified that while a working interest owner might expect to pay such costs when purchasing a lease, a net profits interest owner would never expect to pay lease acquisition costs. Aplt.App. 196-97. Ryan relies on the conveyance which makes it clear that the NPI “does not represent a working interest or other participating cost-bearing interest.” ApltApp. 357, § 2.1.

The district court disagreed, finding that direct costs included “costs attributable to generating Proceeds.” ApltApp., 355 art. I (“Direct Costs”); Ryan, 2007 WL 4285324, at *10. These costs are plainly in the nature of costs allowed in the Direct Costs provision. See § ApltApp. 355-56, art. I (“Direct Costs”) (such costs include “operating expenses” in accord with any joint operating agreement or COPAS accounting procedures and “drilling and completion costs”); Wright & Gallun, Fundamentals of Oil & Gas Accounting 517 (recognizing “exploratory drilling; development drilling; installation of production equipment; operation, maintenance, and repair of wells and equipment; and rentals” as direct costs in joint interest accounting). Like the district court, we do not read the ANEC’s commitment to spend up to $1.1 million to restore existing wells and evaluate drilling of new wells, contained in the Plan, ApltApp. 298, to preclude such costs from being recouped for purposes of calculating the NPI. Consistent with our analysis above, however, we agree with Ryan that such costs must be allocated between existing or new wells.

G. Attorney’s Fees

We normally review a district court’s denial of attorney’s fees for an abuse of discretion, however, the issue turns on construction of the statute, a legal issue reviewed de novo. Stauth v. Nat’l Union Fire Ins. Co., 236 F.3d 1260, 1263 (10th Cir.2001). Although we have reversed in part the judgment of the district court on the merits, we suspect that the attorney’s fees issue is likely to arise on remand. Okla. Stat. Ann. tit. 12, § 936 allows for attorney’s fees to the prevailing party in a suit to collect on open account or an account stated; this action is neither, rather it is a suit on an express contract. See Okla. ex rel. State Ins. Fund v. Great Plains Care Ctr., 78 P.3d 83, 86-90 (Okla.2003). We have noted the very specific and limited reach of the statute. Specialty Beverages, L.L.C. v. Pabst Brewing Co., 537 F.3d 1165, 1183 (10th Cir.2008).

The calculation of, accounting for, and payment of NPI is a product of express contractual provisions, not implied provisions which would be found in an open account. See e.g., Bickford v. John E. Mitchell Co., 595 F.2d 540, 545 (10th Cir.1979) (rejecting application of the statute to payment of royalties on a written contract); see also Kay v. Venezuelan Sun Oil Co., 806 P.2d 648, 652 (Okla.1991) (action to collect ORI was based on express contract). This is true even if the conveyance requires use of accounts and subac-counts; there were no open or concurrent dealings between the parties yet to be closed, rather the negotiated terms of conveyance applied. See Great Plains Care Ctr., 78 P.3d at 87 (an open account requires running or concurrent dealings which have not been closed and an open contractual term or further transactions between the parties). Likewise, this action is not one on an account stated — a contract where an agreement on a balance owed is transformed into a new and independent obligation that supercedes and merges the prior contractual obligation. See State of Okla. ex rel. State Ins. Fund v. Accord Human Res., Inc., 82 P.3d 1015, 1017-18 (Okla.2003) (defining “account stated”). We agree with the district court that prior to the bankruptcy there was no “balance owed” by ANEC that could become a new and independent obligation. Ryan, 2008 WL 2705462, at *5. Although ANEC relies upon Berwin v. Levenson, 311 Mass. 239, 42 N.E.2d 568, 573 (1942), for the proposition that an account stated can exist where one agrees to pay the debt of another before the account being stated, that is not what happened here because ANEC never assumed the debts of Couba to the Class 7 creditors.

The judgment in 08-5002 is AFFIRMED in PART, REVERSED in PART, and REMANDED. We deny the motion to supplement the record. The order in 08-5110 denying attorney’s fees is AFFIRMED.

1 . "Little” is a scrivener’s error.