Ryan v. American Natural Energy Corp.

FILED
United States Court of Appeals
Tenth Circuit

March 2, 2009
PUBLISH Elisabeth A. Shumaker
Clerk of Court
UNITED STATES COURT OF APPEALS

TENTH CIRCUIT

CHRISTOPHER J. RYAN, as the
Liquidation Agent for the Class 7
Claimants of the Confirmed Chapter
11 Plan of Reorganization of Couba
Operating Company,

Plaintiff - Appellant,

v. No. 08-5002

AMERICAN NATURAL ENERGY
CORPORATION, an Oklahoma
corporation,

Defendant - Appellee.

CHRISTOPHER J. RYAN, as the
Liquidation Agent for the Class 7
Claimants of the Confirmed Chapter
11 Plan of Reorganization of Couba
Operating Company,

Plaintiff - Appellee,

v. 08-5110

AMERICAN NATURAL ENERGY
CORPORATION, an Oklahoma
corporation,

Defendant - Appellant.
 APPEAL FROM THE UNITED STATES DISTRICT COURT
FOR THE NORTHERN DISTRICT OF OKLAHOMA
(D.C. No. 06-CV-00022-TCK-SAJ)

W. David Pardue (Ronald R. Tracy, with him on the briefs) of Eagleton &
Nicholson, P.C., Oklahoma City, Oklahoma, for Plaintiff.

Ira L. Edwards (Sharon K. Weaver, with him on the brief) of Riggs, Abney, Neal,
Turpen, Orbison & Lewis, Inc., Tulsa, Oklahoma, for Defendant. *

Before KELLY, HARTZ, and O’BRIEN, Circuit Judges.

KELLY, 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

*
After examining the briefs and appellate record, this panel with agreement
of the parties has determined unanimously that oral argument would not
materially assist in the determination of the appeal 08-5110. See Fed. R. App. P.
34(a)(2); 10th Cir. R. 34.1(G). This case is therefore submitted without oral
argument.

2
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.

Aplt. App. 356-57, art. I (“Effective Date,” “Existing Wells,” “New Wells,”

3
“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 carryforward 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”

4
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(ii). 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

5
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; Aplt. App.

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

6
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 (1991); Anderson v.

City of Bessemer City, 470 U.S. 564, 574-75 (1985). The parties agree that

7
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.

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. Where there are two permissible views of the evidence, a

finding adopting one of those views cannot be clearly erroneous. See id. at 574.

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

8
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 contract. 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 recoupment 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

9
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-

10
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.” Aplt. App. 356, art. I (“Net Profits”). “Proceeds” applies to any

production period and means gross proceeds from oil and gas sales from existing

11
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, recompleting 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

1
“Little” is a scrivener’s error.

12
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

13
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.” Aplt. App. 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. Aplt. App. 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.

14
 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

15
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. Aplt. App. 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

proferentem. 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., 254 P.2d 775, 782 (Okla. 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

16
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

17
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 recouped 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,” Aplt.

App. 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. Aplt. App. 355-

57, art. I (“Direct Costs,” “Direct Costs Accounts,” “Existing Wells,” “New

18
Wells,” “Proceeds”); 358, § 3.2; 359, § 6.1; 360, § 6.3(ii). 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 carried 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. Aplt.

App. 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

19
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; Aplt. App. 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 COPAS 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

20
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.” Aplt. App.

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

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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.” Aplt. App. 357, § 2.1.

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 The district court disagreed, finding that direct costs included “costs

attributable to generating Proceeds.” Aplt. App., 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 § Aplt. App. 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,

Aplt. App. 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

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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 subaccounts; 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,

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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, 42 N.E.2d 568, 573 (Mass.

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.

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