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
21
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.
22
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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Ryan v. American Natural Energy Corp.
Court: Court of Appeals for the Tenth Circuit
Date filed: 2009-03-02
Citations: 557 F.3d 1152
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