
    CHEVRON USA PRODUCTION CO, Plaintiff, v. U.S. DEPARTMENT OF INTERIOR Defendant.
    No. CIV. A. 01-1577 (RCL).
    United States District Court, District of Columbia.
    March 26, 2003.
    
      L. Poe Leggette, Kerry E. Larsen, Fulbright & Jaworski, LLP, Washington, for Plaintiff.
    Thomas L. Sansonetti, Lori Caramanian, U.S. Department of Justice, Environmental and Natural Resources Division, General Litigation Section, Washington, for Defendant.
   MEMORANDUM OPINION

LAMBERTH, District Judge.

This comes before the Court on Chevron’s motion for summary judgment [11], the Department of Interior’s opposition and cross-motion for summary judgment [16], Chevron’s response [19/20], and Interior’s reply [22],

I. Background

Before the natural gas market was deregulated, companies entered into long-term fixed-price contracts for the delivery of natural gas. These contracts were employed for mineral reserves located on federal lands leased to producers (“lessees”) under various federal statutes. The contracts provided that the purchasing party would either take the gas at a certain price, or pay the lessee in lieu of taking the production; this is a “take-or-pay” clause. When the market for natural gas was deregulated, the price of gas dropped below the contract price, driving many purchasers to breach their contracts or fall behind on payments under the “pay” portion of the take-or-pay clause. Many lessees and purchasers entered into settlement agreements to resolve several types of contract issues: past-pricing disputes over whether the full contract price had been paid for gas already taken, take-or-pay disputes regarding unpaid “pay” liability, and reformation of the future terms-including price-under which gas was to be taken (if at all). It is the latter that is at issue here.

The terms under which federal land is leased for mineral extraction include .the payment of royalties to Interior on the minerals taken from the land. See, e.g., 30 C.F.R. §§ 206.152, 206.153 (requiring the payment of royalties on gross proceeds from the production of natural gas). When the settlements were first effected, Interior sought to receive a royalty on the settlement proceeds. In Independent Petroleum Ass’n of Am. v. Babbitt, 92 F.3d 1248 (D.C.Cir.1996) (“IPAA J”), the D.C. Circuit faced a challenge to Interior’s efforts to collect royalties on a settlement that was made to resolve past and future take-or-pay liability and in exchange for termination of the contract. After settlement and termination of the contract, the lessee and the purchaser severed their business relationship and the gas that had been the subject of the contract was sold entirely to third parties. IPAA I, 92 F.3d at 1254.

In holding that no royalty was due on the settlement, the D.C. Circuit focused on the statutory language providing that royalties were to be based on the “ ‘amount or value of the production’ saved, removed, or sold by the lessee.” Id. at 1257. It reasoned that because the payment was not tied to any production-the purchaser received no gas from the producer after the settlement was effected and the contract terminated-the settlement payment did not fall within the statutory scheme and Interi- or could not assess royalties on it. Unless “funds making up the payment actually pay for any gas severed from the ground,” royalties are not due on the funds. Id. at 1260. Thus, IPAA I requires a nexus between a payment and the production of gas.

The next year the Sixth Circuit faced a variation on the IPAA I situation. In In re Century Offshore Management Corp., 111 F.3d 443 (6th Cir.1997), the lessee accepted a settlement payment from the purchaser to cancel the existing take-or-pay contract and simultaneously replace it with a new contract that did not require a minimum quantity, contained no take-or-pay provision, and provided for a floating rather than a fixed price. Century Offshore, 111 F.3d at 447. The parties continued to do business, and the purchaser “purchased virtually all of the gas identified in the original agreements, within the same time period.” Id. The Sixth Circuit found that the two transactions-cancellation of the old contract and execution of the new-were “one transaction for the purposes of the instant [royalty] dispute,” and that the situation was “akin to a substituted contract.” Id. at 448. Given this business reality, “[t]he lump sum payment behaved as an advance payment under a substituted requirements contract,” and consequently “the payment was for ‘production sold’ under the statute, and the royalty was payable when the gas was produced.” Id. at 449.

The Century Offshore court specifically acknowledged the requirement of a nexus between a payment and the production of gas, first announced by the Fifth Circuit in Diamond Shamrock Exploration Co. v. Hodel, 853 F.2d 1159 (5th Cir.1988), that had prompted the D.C. Circuit’s decision in IPAA I. The court reasoned that when the gas that was the subject of the first contract was taken by the purchaser at the lower price-a price that was reduced because of the settlement payment-the payment was linked with production, and royalties became due on both the settlement payment attributable to the produced gas and the (reduced) purchase price. Id. at 449-50. Century Offshore pointedly noted that IPAA I “addressed a situation in which a nexus with production did not exist.” Id. at 451.

II. Analysis

A. Standard of Review

This Court must review Interi- or’s decisions to determine whether they were “arbitrary, capricious, [or] an abuse of discretion.” 5 U.S.C. § 706(2)(B). This inquiry requires an examination of “‘whether the decision was based on a consideration of the relevant factors.’ ” Marsh v. Oregon Natural Resources Council, 490 U.S. 360, 378, 109 S.Ct. 1851, 104 L.Ed.2d 377 (1989) (citations omitted); ITT World Comm., Inc. v. FCC, 725 F.2d 732, 742 (D.C.Cir.1984). If it is determined that the agency did not consider all relevant factors, the court must remand to the agency for additional investigation or explanation. Florida Power & Light Co. v. Lorion, 470 U.S. 729, 744, 105 S.Ct. 1598, 84 L.Ed.2d 643 (1985). The court must assume the agency acted properly. ITT World Comm., 725 F.2d at 742.

B. Contract Buydown Payments

1. Calculating Royalties on Buydown Payments

The parties do not dispute the facts in this case. Chevron entered into numerous settlement agreements with purchasers to amend or replace take-or-pay contracts. A portion of each settlement payment at issue was attributable to the buydown of the contract price for gas. Rather than continuing to pay the higher set price contained in the original take-or-pay contracts, upon execution of the replacement or amended contracts, the purchasers were able to take the gas at a price tied to the market value of the gas when taken. After these settlements amended or super-ceded the previous contracts, the purchasers continued to take gas from the lessees.

MMS calculated the royalty due on the settlement payments attributable to buy-down of the contract price using the following method: First, it divided the buy-down payment by the number of gas units (MMBtu or Mcf) the purchaser was obligated to take under the take-or-pay contract, to determine the value of the buydown payment per unit. Then MMS determined how many units of gas the purchaser took during the remaining term of the original take-or-pay contract. Finally, MMS multiplied the value of the buydown payment per unit by the number of units taken by the purchaser at the reduced price. This yielded the final royalty number. See, e.g., Op. in MMS-98-0029-OCS at 7, A.R. Vol. 2, Tab 1. No royalty was assessed on units of gas that had been committed to the purchaser in the original take-or-pay contract but was taken by a third party under the amended/replacement contract, nor was royalty assessed on units taken by the purchaser after expiration of the time period of the original contract. In other words, the royalty was applied only to units of gas the purchaser would have taken under the more onerous price terms of the original contract. To state it another way, Chevron was ordered to pay royalty on the total of the reduced price purchaser paid for the gas and the price purchaser paid to receive that reduced price on that gas. See Century Offshore, 111 F.3d 443, 450 (6th Cir.1997) (finding royalty due “not merely on the price Enron ultimately paid, but on that price plus the amount of the lump sum payment allocable to the gas ultimately taken”).

2. IPAA I and Century Offshore: Buyout versus Buydown

Chevron argues that IPAA I requires an express statement in the settlement agreement that the settlement payment is re-coupable. Because the settlement contracts at issue were drafted to denominate the payments as “nonrecoupable,” Chevron reasons, the inquiry ends there. In actuality, IPAA I is more subtle, and counsels that “[t]he relevant question ... is whether or not the funds making up the payment actually pay for any gas severed from the ground.” IPAA I, 92 F.3d 1248, 1260 (D.C.Cir.1996). The inquiry is not limited to whether the settlement agreement contains the magic word “nonrecoupable,” but whether the settlement payment is linked to subsequent gas production.

Century Offshore, 111 F.3d 443 (6th Cir.1997), provides more guidance in this situation than IPAA I. The facts in Century Offshore resemble the facts of this case in that the lessee and the purchaser entered into a settlement agreement in which the purchaser paid a lump sum and the parties entered into a new contract that, among other things, permitted the purchaser to pay floating market-value prices for gas (rather than the higher set price). Century Offshore, 111 F.3d at 447. Although the substitute contract did not require it, the purchaser took most of the gas that had been committed to it under the earlier take-or-pay contract. Id. at 450. The Century Offshore court concluded:

[W]e hold that the lump sum payment contemplated and was the cause of new gas sales to be delivered in the future, where the parties intended a continuing relationship, and where much of the gas identified in the original contracts was delivered under the replacement contracts. The lump sum payment behaved as an advance payment under a substituted requirements contract. As a result, the payment was for ‘production sold’ under the statute, and the royalty was payable when the gas was produced.

Id. at 449. Thus, Century Offshore supports the conclusion that the agency did not act arbitrarily or capriciously in assessing royalty on the amount of the settlement payment allocated to reducing the price of gas actually taken.

This Court has already examined the interplay between IPAA I and Century Offshore, and found the two opinions compatible. See Independent Petroleum Ass’n of Am. v. Babbitt, 971 F.Supp. 19, 32-33 (D.D.C.1997) (Lamberth, J.) (“IPAA II”). The Court noted that while IPAA I dictates “but one acceptable outcome of any case involving true nonreeoupable take-or-pay settlement payments,” Century Offshore did not involve a true nonreeoupable settlement payment. Id. at 32. Rather, “[t]he corporations involved in Century basically tried to avoid make-up contracts, which would be subject to royalties, by creating entirely new replacement contracts which differed little from make-up gas arrangements,” contracts “the Sixth Circuit saw through.” Id.

A sister court in this District has disagreed with IPAA II’s determination that IPAA I and Century Offshore are not in conflict. In EEX Corp. v. United States Department of the Interior, 111 F.Supp.2d 24 (D.D.C.2000) (Green, J.), the Court concluded that unless “there is some agreement or contractual arrangement that the settlement payment would be credited as an advance payment for gas to be taken in the future, as opposed to a payment to extinguish past or future contract obligations, the identity of the end purchaser of the ‘freed-up’ gas does not change the result dictated by IPAA [I ].” EEX, 111 F.Supp.2d at 33. Thus, the court felt it was bound by the express written terms of the contract that the settlement payment was not recoupable, and did not have the freedom to explore the nature of the parties’ transaction. However, courts are not bound by parties’ carefully-or carelessly-chosen words. See, e.g., Block v. Pitney Bowes, Inc., 952 F.2d 1450, 1452 (D.C.Cir.1992) (in a contract interpretation case, citing with approval the district court’s description of “the ‘magic word’ argument [as] ‘incomprehensible’ and ‘totally without merit’ ”) (citation omitted); see also Foucha v. Louisiana, 504 U.S. 71, 118 n. 13, 112 S.Ct. 1780, 118 L.Ed.2d 437 (1992) (Scalia, J., dissenting) (“It is surely rather odd to have rules of federal constitutional law turn entirely upon the label chosen by a State.”).

In EEX, the court proceeded on the factual premise that “[n]onrecoupable settlement payments, rather than serving as credits for make-up gas are, in the words of Judge Rogers [in her IPAA I dissent], payments for ‘freed-up’ gas, i.e., gas the lessee would not have been able to sell without the settlement.... The gas is ‘freed-up’ regardless of the identity of the subsequent purchaser.” Id. at 31 (citation omitted). Respectfully, EEX misconstrues Judge Rogers’ use of the term “freed-up.” EEX’s explanation, with its focus on the lessee, confuses the purpose of the buy-down portion of settlement payments. It is not the lessee paying a settlement to obtain the freedom to sell the committed gas, but the purchaser who is buying the freedom to pay market price rather than the higher contract price for the “freed-up” gas. Rather than viewing the buy-down settlement payment as freeing up gas, this Court understands that the function of a buydown payment is to reduce the price of gas taken in the future. Thus, this Court declines the adopt EEX’s rationale.

3. Interior Acted Properly

IPAA I decided that Interior acted improperly in assessing royalties on a nonrecoupable settlement payment because that position was arbitrary and capricious in light of Interior’s adoption of the Fifth Circuit’s Diamond Shamrock rule that royalties are not due on an unrecouped take-or-pay payment. See IPAA I, 92 F.3d at 1258; Diamond Shamrock Exploration Co. v. Hodel, 853 F.2d 1159, (5th Cir.1988) (“Royalty payments are due only on the value of minerals actually produced, i.e., physically severed from the ground. No royalty is due on take-or-pay payments unless and until gas is actually produced and taken.”). Thus, this Court’s inquiry is whether Interior acted arbitrarily or capriciously, in light of its adoption of Diamond Shamrock, in assessing these royalties. The Court finds that Interior acted reasonably. Interior’s has expressed its position as such:

When an arms-length purchaser makes payments to a seller with whom it has a contractual supply relationship and these payments effectively give that purchaser a right to pay a different price than originally promised, those payments represent the additional value necessary for the purchaser to acquire the production under the revised terms. The lessor is entitled to a percentage share of the total proceeds paid to acquire that production, and will look to the economic reality of transactions between buyers and sellers in identifying those proceeds.

Antelope Production Co., MMS-9600068-0 & G at 29. In limiting its royalty assessment to specific units of gas for which the purchasers had paid to reduce the price, Interior complied with the nexus-with-produetion requirement.

In Shell Offshore, Inc. v. Department of the Interior, 997 F.Supp. 23 (D.D.C.1998) (Lamberth, J.), this Court set forth a number of factors Interior should consider when analyzing a settlement payment to determine if it is royalty bearing. The factors include, but are not limited to: “[1] to whom was the gas subject to the settlement ultimately sold; [2] the quantity of the gas ultimately sold to the subsequent purchaser; [3] the date(s) of delivery of the gas identified in the settled contract; [and][4] the price per unit of the gas ultimately sold, and how that price compares with the open market price of gas at the time of the sale (or, more specifically to what extent the settlement payment appears to be part payment for gas actually delivered).” Shell Offshore, 997 F.Supp. at 29. The purpose of setting forth this nonexclusive fist of factors was to provide guidance to Interior as to what sort of factual record needed to be developed to properly assess whether royalties were due on any portion of a settlement transaction. Id. at 29-30. In these cases, Interi- or properly considered the Shell Offshore factors. The royalty assessments are (1) limited to gas sold to the original purchaser, (2) limited to the units of gas that were the subject of the original contract and were ultimately sold to the original purchaser, and (3) limited to the time period of the original contract.

Chevron makes much of Interior’s failure to find dispositive that under the replacement/superceding contracts the gas was sold at approximately market price, arguing that the fourth Shell Offshore factor mandates a reversal of Interior’s decision. This is not the case. First, the Shell Offshore factors were not promulgated as a rigid test, but as guidance in the “question of fact” of “[wjhether or not a lump-sum settlement payment is ‘recouped’ and royalty bearing,” a question that “depends upon the particulars of the individual transaction.” Shell Offshore, 997 F.Supp. at 29. Interior here delved deeply into that question of fact, sufficient to satisfy the requirement that it develop a complete factual record. Second, Interior did consider price, although not in the exact manner spelled out in Shell Offshore. Interior determined that the price at which the purchaser obtained the gas was less than the price set by the original contract, thus supporting the allocation of a portion of the settlement monies to contract buydown. The importance of this fact is illustrated by Black Butte Coal Co. v. United States, 38 F.Supp.2d 963 (D.Wyo.1999), where the court found a lump sum payment made to defer production was not royalty bearing when the coal was eventually produced because “[t]he payments were never recouped or credited against the future price of coal. Idaho Power still paid the full contract price for coal.” Black Butte, 38 F.Supp.2d at 971. Here, by contrast, the purchasers did not pay the “full contract price” after making a lump sum payment, leading to the inference that the payments were “recouped or credited against the future price” of gas.

In sum, the buydown portions of the settlement payments at issue in this case have a sufficient nexus with production to make them royalty bearing. As the IPAA I court noted of take-or-pay payments: “At the time of a settlement payment ... no production has occurred,” but when gas is taken, “[i]t is ... reasonable to collect royalties on these funds, which have just been transformed into payments for gas produced.” IPAA I, 92 F.3d at 1259 (emphasis original). That is the exact situation here. No royalties were due when the settlement payment was made, because there had been no production, but when gas was produced and purchased at the reduced price, the buydown settlement payment was transformed into a payment for gas produced. A company may not use “creative contractual devices to avoid make-up contracts that should be subject to royalties.” Shell Offshore, Inc. v. De partment of Interior, 997 F.Supp. 23, 35 (D.D.C.I998) (Lamberth, J.).

III. Conclusion

Artful drafting will not allow a lessee to escape its obligation to pay federal royalties on federal minerals extracted from federal lands. By entering into lease agreements with the federal government, Chevron obligated itself to compensate Interior-acting on behalf of the federal government and ultimately the American people-for the privilege of mining gas from federal lands. That is not an obligation that may be avoided merely by characterizing a lump sum payment to reduce the price of gas as “nonrecoupable.” Neither Interior nor this Court is obligated to accept Chevron’s characterization at face value, and the facts in this case demonstrate a sufficient nexus with production to belie that characterization. Where a purchaser has paid a settlement amount for the purpose of reducing the price of gas taken in the future, when that future gas is produced and sold to that purchaser at the reduced price the portion of the settlement payment attributable to obtaining the reduced price becomes royalty bearing. The fact that a purchaser receives a reduced price on gas the purchaser previously contracted to take at a higher price constitutes a nexus with production.

A separate order shall issue this date.

ORDER AND JUDGMENT

This comes before the Court on Chevron’s motion for summary judgment [11], the Department of Interior’s opposition and cross-motion for summary judgment [16], Chevron’s response [19/20], and Interior’s reply [22].

It is hereby ORDERED that Chevron’s motion of summary judgment [11] is DENIED in its entirety.

It is further ORDERED for the reasons set forth in the accompanying memorandum opinion that Interior’s motion for summary judgment [16] is GRANTED. Judgement is entered for Defendant and Plaintiffs complaint is DISMISSED WITH PREJUDICE.

SO ORDERED. 
      
      . The background of the take-or-pay contract disputes is more fully and ably explained in numerous other cases. See, e.g., Independent Petroleum Ass’n of Am. v. Babbitt, 92 F.3d 1248 (D.C.Cir.1996); Diamond Shamrock Exploration Co. v. Hodel, 853 F.2d 1159 (5th Cir.1988); Shell Offshore, Inc. v. Dep't of Interior, 997 F.Supp. 23 (D.D.C.1998) (Lamberth, J.).
     
      
      . While the contracts themselves generally do not state how the settlement monies are to be allocated, in most of the cases, Chevron and Interior reached undisputed conclusions about the amount of money allocable to buy-down. See, e.g., A.R. Vol. 1, Tab 1, Op. in MMS-98-0028-OCS at 2 ("Chevron allocated $360,999 of the $1.5 million it received from TGT to contract reformation. (The MMS accepted Chevron’s allocation as reasonable.)”); Op. in MMS-98-0029-OCS at 2, A.R. Vol. 1, Tab 1 (Chevron allocated $1.4 million to contract reformation); Op. in MMS-99-0217-O & G at 4, A.R. Vol. 4, Tab 1 ("It appears from the record that the allocation of Chevron's settlement proceeds has been agreed upon by the parties and is not at issue in this appeal.”); Op. in MMS-00-0005-OCS at 2-4, A.R. Vol. 5, Tab 1 (listing Chevron’s allocations in various settlement contracts).
      In only one of the opinions does the settlement amount allocated to price reduction appear to be in dispute. See Op. in MMS-98-0030-0 & G at 2-3, A.R. Vol. 3, Tab 1 (concluding that purchaser's waiver of right to recoup funds was consideration for reduction in future price where remaining settlement monies corresponded dollar-for-dollar with other settlement elements). However, Chevron did not present any specific arguments to the Court in its motion for summary judgment [11] or its attached statement of facts as to why Interior's final determination of the number was arbitrary and capricious. A review of Interior’s reasoning-logically deducing that because other settlement elements were fully satisfied the only remaining settlement element to which the disputed funds could be attributed was price and quantity reformation-shows that the number was not arrived at arbitrarily or capriciously.
     
      
      . The percentage of gas committed to the purchaser in the original contract that was taken by the purchaser under the amended/substitute contracts varied from 5% to 98%.
     
      
      . One statement of the IPAA I court could be construed to support Chevron’s position: “[A] nonrecoupable settlement payment is never credited as payment for any gas actually severed from the ground.” IPAA I, 92 F.3d at 1260 (emphasis original). However, this statement must be read in light of the one that follows: "When gas is actually severed and sold to a substitute purchaser, the settlement payment does not serve as payment for the gas.” Id. at 1260-61 (emphasis, added). Here, the gas at issue was sold not to a substitute purchaser, but to the original purchaser.
     
      
      . To the extent Chevron itself allocates portions of the settlement proceeds to buydown of gas prices, it could fall within EEX’s tightly circumscribed "agreement or contractual arrangement" requirement.
     
      
      . "Royalties therefore will be assessed on that portion of the payment attributable to gas produced after the settlement and sold to the same purchaser or its affiliate during the time frame of the original contract.” Op. in MMS-98-0028-OCS at 5, A.R. Vol. 1, Tab 1; Op. in MMS-98-0029-OCS at 6, A.R. Vol. 2, Tab 1 (same); Op. in MMS-98-0030-0 & G at 5, A.R. Vol. 3, Tab 1 (same); Op. in MMS-99-0217-0 & G at 7, A.R. Vol. 4, Tab 1 (same); Op. in MMS-00-0005-OCS at (9), A.R. Vol. 5, Tab 1 (same).
     
      
      . Chevron also attaches great importance to Interior’s lack of determination as to the purchasers' take-or-pay obligations. Chevron Statement of Material Facts [11] at ¶ 19, 34, 54, 72, 86, 92, 103. However, Interior has long had the policy that royalties are not due on take-or-pay payment. Furthermore, the reason that prompted the lessees and the purchasers to enter into settlement agreements (such as breach of take-or-pay obligations) is irrelevant to whether a portion of that settlement agreement is a royalty-bearing buydown payment that reduces the price of later-produced gas.
     
      
      . See, e.g., Op. in MMS-98-0028-OCS at 6, A.R. Vol. 1, Tab 1 (noting that the replacement contracts tied the new price for gas to the lower market price); Op. in MMS-98-0029-OCS at 7, A.R. Vol. 2, Tab 1 (same); Op. in MMS-00-0005-OCS at 9, A.R. Vol. 5, Tab 1 (same); see also Op. in MMS-98-0030O & G at 2, A.R. Vol. 3, Tab 1 (noting that settlement was entered in part "to obtain reduced prices on future purchases of gas”); Op. in MMS-99-0217-0 & G at 8, A.R. Vol. 4, Tab 1 ("[T]he parties amended their long-term gas purchase contracts to reduce the price term ....”).
     