Opinion for the Court filed by Circuit Judge SENTELLE.
SENTELLE, Circuit Judge:
The Federal Energy Regulatory Commission (“FERC” or “the Commission”) orders at issue require us to turn once again to certain aspects of the Commission’s Order No. 500, 52 Fed.Reg. 30,334 (1987),
record remanded sub nom. American Gas Ass’n v. FERC,
888 F.2d 136 (D.C.Cir.1989) (“AGA”). The orders before us implement the take-or-pay cost passthrough mechanism of Order No. 500. A host of natural gas pipeline companies, pipeline customers, local distribution companies (“LDCs”), industry associations, and state public service commissions petition for review.
Certain pipelines, customers, and LDCs argue that the Commission’s “purchase deficiency” allocation mechanism is unlawful because it violates the filed rate doctrine. We agree and therefore set aside the orders. As a result, disposition of most of petitioners’ other claims is not essential to relieving them of burdens they claim are illegal. Nevertheless, because the Commission will undoubtedly attempt to revamp its passthrough policy in light of this decision, we will address a number of subsidiary issues which appear virtually certain to arise under any passthrough scheme.
I. Background
We recently summarized the genesis of the orders presented to us for review:
The Federal Energy Regulatory Commission embarked in the early 1980s on an ambitious program to restructure the natural gas industry along lines more competitive than it had traditionally followed. One of the major components of this program, the encouragement of natural gas pipelines to adopt an “open access” transportation policy, failed to pass muster when we reviewed it, because the Commission failed to show either that it had authority to impose, or that it could rationalize the imposition of, a few of its components.
Associated Gas Distributors v. FERC,
824 F.2d 981 (1987) (AGD). Because these components were inseparable from the whole, we vacated and remanded the Commission’s Order No. 436 for the agency to cure the defects we had identified. The Commission promptly, in Order No. 500, issued an “interim rule,” and undertook to issue a final rule when it had collected and ana
lyzed certain information that it deemed essential.
AG A,
at 141.
Unhappily, we found in
AG A
that Order No. 500 failed to comply with the mandate in
AGD.
We retained jurisdiction but remanded the record to the Commission for issuance of a final rule within sixty days. The statutory, regulatory and economic context in which the Commission undertook to implement its open-access transportation policy is set out in detail in this Court’s opinions in
AGD
and
AG A.
The pass-through mechanism is described in
AG A,
at 143-144. We refer to this background only as the need arises.
The Commission orders at issue implement the take-or-pay cost passthrough provisions of Order No. 500, with its “equitable sharing mechanism.” This pass-through policy is part of a larger attempt by FERC to spread the costs of the take-or-pay problem over the whole industry, at least insofar as the open-access transportation policy has aggravated the problem. The mechanism at issue here attempts to shift some of the costs to the customers; the crediting system in
AG A,
on the other hand, attempted to shift costs to the producers. Under the passthrough mechanism, the cost of buyouts and buydowns is shared between the pipeline and its customers. If a pipeline agreed to absorb between 25% and 50% of its take-or-pay costs, the pipeline would be permitted to recover an equivalent amount through a fixed charge. Such a pipeline would also be allowed an opportunity to recover the remaining costs through a volumetric surcharge on sales and transportation. Moreover, where the pipeline absorbed between 25% and 50% of the costs, the Commission established a rebuttable presumption that the remaining costs that the pipeline sought to pass on to its customers were prudently incurred. A pipeline customer could still challenge the pipeline’s prudence, but it took a chance in doing so — it would have to pay its pro rata share of 100% of the costs ultimately found to have been prudently incurred.
To allocate the buyout and buydown costs among customers, FERC proposed the imposition of a demand surcharge on each pipeline customer. Customers’ purchases of natural gas decreased sharply during the period from 1983 to 1986 and thereby exacerbated the pipelines’ problems. FERC therefore proposed to base the charge upon the customer’s “deficiency” of purchases during this period. This “purchase deficiency” was to be calculated by measuring the customer’s purchases in the “deficiency period” (1983-86) against its purchases in a prior “base period” (1981-82).
In October of 1987, after promulgation of Order No. 500, Tennessee Gas Pipeline Company (“Tennessee”) filed a settlement proposal to resolve a previous Section 4 rate filing. The proposal called for direct charge recovery of 50% of Tennessee’s reformation and buyout costs. Tennessee would absorb the remaining 50%. Tennessee also agreed to render a limited-term standby sales service. In addition, Tennessee proposed a 31 December 1989 “sunset date,” which limited the time for filing for recovery under the “equitable sharing mechanism,” rather than Order No. 500’s original sunset date of 31 December 1988 (which the Commission subsequently extended to 31 March 1989 in Order No. 500-F). Five competing settlement proposals were filed.
The Commission modified and approved Tennessee’s proposed settlement.
Tennessee Gas Pipeline Co.,
42 FERC ¶ 61,175 (1988). The Commission disallowed Tennessee from recovering through a fixed charge take-or-pay prepayments or any costs owed to affiliates. The Commission established a sunset date of 31 December 1988 for the filing of settlement costs for recovery. It purported to distinguish Tennessee’s proposal from
Columbia Gas Transmission Corp. v. FERC,
831 F.2d 1135 (D.C.Cir.1987),
modified on reh’g,
844 F.2d 879 (D.C.Cir.1988), wherein this Court struck down as retroactive ratemaking Commission orders that allowed direct billing of certain costs based on past purchases, on the grounds that the Tennessee proposal involved merely the proper allocation
of current settlement costs rather than a retroactive rate change.
On rehearing in May of 1988, FERC altered Tennessee’s cost-allocation formula on the grounds that the formula in Order No. 500 relied solely on the “purchase deficiency” method, whereas the Tennessee formula combined the purchase deficiency method and a method based on the customer’s annual quantity limitations.
Tennessee Gas Pipeline Co.,
43 FERC ¶ 61,329 (1988). The Commission directed Tennessee to apply the purchase deficiency method to all buyout and buydown costs. The Commission also insisted on the 31 December 1988 sunset date (not 1989, as Tennessee requested).
Various petitioners filed for review in this Court on and after 27 May 1988.
In June of 1988, Tennessee filed tariff sheets that incorporated a 1989 sunset date. In July of 1988, the Commission accepted the tariff sheets and allowed Tennessee to begin direct billing its customers as of 1 July 1988 (subject to refund).
Tennessee Gas Pipeline Co.,
44 FERC ¶ 61,039 (1988). The Commission still rejected the 1989 sunset date, and it did so again at the next Tennessee filing in September of 1988.
Tennessee Gas Pipeline Co.,
44 FERC ¶ 61,401 (1988). In December of 1988, citing its Order No. 500-F, FERC extended the sunset date to 31 March 1989 and created the litigation exception (i.e., that take- or-pay liabilities in litigation as of 31 March 1989 were exempt from the deadline). Petitions for review of the Commission’s orders were consolidated and are now before us.
II. Analysis
A.
Filed Rate Doctrine
The Commission has allowed Tennessee to directly bill its customers surcharges proportional to the customers’ purchase reductions during the 1983-86 “deficiency period,” reductions calculated on the basis of the customers’ purchases from Tennessee during the “base period” of 1981-82. According to petitioners, the charges constitute a retroactive change in rates without advance notice and therefore violate the filed rate doctrine as expressed in
Arkansas Louisiana Gas Co. v. Hall,
453 U.S. 571, 578, 101 S.Ct. 2925, 2930, 69 L.Ed.2d 856 (1981)
(“Arkla”),
and
Columbia Gas.
Petitioners point out that
Columbia Gas
recognizes “predictability” as the fundamental policy underlying the filed rate doctrine and that the Commission’s approval of the Tennessee settlement contravenes that policy: had Tennessee’s customers known of these charges, they could have either purchased less gas from Tennessee during the base period or more gas during the deficiency period (or both) and could have thereby reduced their gas costs. In
Columbia Gas,
we struck down a direct billing mechanism where “the effect of the orders [was] quite clear: downstream purchasers [were] expected to pay a surcharge, over and above the rates on file at the time of sale, for gas they had already purchased.”
Columbia Gas,
831 F.2d at 1140.
The Commission claims that
Columbia Gas
is inapposite because the pricing mechanism at issue here does not really affect rates retroactively; rather, “what is involved here is simply a legitimate Commission decision to allocate
current
take-or-pay expenses in a fair and equitable fashion consistent with the Commission’s broad discretion.... All that the agency has done here is to utilize a calculation of a customer’s past purchasing patterns in order to allocate its share of a
current
expense.” Brief for Respondent FERC at 44 (emphases in original). The Commission argues that in
Columbia Gas
the direct bill charged customers for additional costs of producing gas that the customer had already purchased during a past period, whereas this case involves no “deferred costs” assessed for gas already purchased. Thus, according to the Commission, prior notice is not critical here because the charge does not recoup preexisting costs or prior losses. The Commission argues further that its actions with regard to minimum bills and gas curtailment programs have all involved use of a pipeline’s purchasing pattern within an historical base period, and that this Court approved those
actions.
See Wisconsin Gas Co. v. F.E. R.C.,
770 F.2d 1144 (D.C.Cir.1985),
cert. denied sub nom. Transwestern Pipeline Co. v. FERC,
476 U.S. 1114, 106 S.Ct. 1968, 90 L.Ed.2d 653 (1986) (minimum bills), and
City of Willcox v. FPC,
567 F.2d 394, 408-12 (D.C.Cir.1977),
cert. denied,
434 U.S. 1012, 98 S.Ct. 724, 54 L.Ed.2d 755 (1978) (curtailment plans during natural gas shortages of the 1970s);
cf. North Carolina v. FERC,
584 F.2d 1003 (D.C.Cir. 1978) (remanding curtailment plan because of inaccurate base period). The filed rate doctrine is designed to prevent the utility’s recovery of past losses, the Commission concludes, but it does not bar the imposition of current costs.
Petitioners respond that characterizing the costs as “current” is disingenuous because “[t]he level of the surcharge to each Tennessee customer is determined without reference to current or future purchases or service levels.” Joint Reply Brief of Certain Petitioners and Intervenors in Support of Petitioners in Opposition to Orders Under Review at 5-6 (“Joint Reply Brief”). Petitioners do not argue that the Commission is prohibited from using accurate historical data in the course of determining future rates; rather, the Commission may not impose a direct surcharge geared to past gas purchases.
The Commission also argues that Tennessee’s customers had sufficient notice of deficiency billing from the language of Order No. 380.
See
Order No. 380, FERC Stats. & Regs. ¶ 30,571 [Regulations Preambles 1982-1985] (1984),
aff'd in part, remanded in part sub nom. Wisconsin Gas Co. v. FERC,
770 F.2d 1144 (D.C.Cir. 1985),
cert. denied sub nom. Transwestern Pipeline Co. v. FERC,
476 U.S. 1114, 106 S.Ct. 1968, 90 L.Ed.2d 653 (1986). Although petitioners acknowledge the theoretical possibility that advance notice could avoid the retroactivity problem, they claim that the Commission’s approach is without foundation. First, they point out that Order No. 380 was published in June of 1984; thus, they claim, the Order could not have provided any notice for the 1981-82 base period and could have provided only partial notice for the deficiency period. Second, Order No. 380 noted that carrying charges on prepayments “may require special consideration” but stated that “[n]o conclusion is reached on this point today.... ” FERC Stats. & Regs. ¶ 30,571 at 30,971. Petitioners urge that this notice is impermissibly vague under case law,
United Gas Pipe Line Co. v. FERC,
597 F.2d 581, 587 & n. 27 (5th Cir.1979),
cert. denied,
445 U.S. 916, 100 S.Ct. 1276, 63 L.Ed.2d 600 (1980), and under Commission precedent,
Mid-Louisiana Gas Co.,
36 FERC ¶ 61,194 at 61,493 (1986), and that it is even less sufficient than the notice rejected in
Columbia Gas.
In addition, they point out that although the Order speaks of a “different allocation methodology,” there was no suggestion that the methodology would be applied retroactively, and in any event the passage is not addressed to reformation and buyout costs. Indeed, although the matter is far from clear, the Commission itself seems to have recently eschewed the notion that Tennessee’s customers received sufficient prior notice.
See National Fuel Gas Supply Corp.,
45 FERC ¶ 61,269 at 61,839 (1988).
We agree with petitioners that the purchase allocation mechanism and its direct charge violate the filed rate doctrine. The Commission’s attempted distinction of
Columbia Gas
is unpersuasive. Under
Columbia Gas,
the relevant question is not which costs are “current” and which are “past.” Rather, the appropriate inquiry seeks to identify the purchase decisions to which the costs are attached. After making this inquiry, we have little doubt that the mechanism at issue violates the filed rate doctrine. Indeed, the Commission now even forces past customers who no longer purchase
any
gas from Tennessee to pay their share of the take-or-pay liability.
See United Gas Pipe Line Co.,
47 FERC ¶ 61,163 (1989). On the other hand, current customers who did not buy gas from Tennessee until after 1986 would not have to pay any part of the take-or-pay liability. As in
Columbia Gas,
“the effect of [these orders] is quite clear: downstream purchasers [such as petitioners here] are expected to pay a surcharge, over and above
the rates on file at the time of sale, for gas they had already purchased.”
Columbia Gas,
831 F.2d at 1140.
The Commission’s assertion that Order No. 380 provided sufficient notice is equally unavailing. Order No. 380 post-dated the entire base period and half of the deficiency period. The Commission can perhaps assume that petitioners have some acquaintance with regulatory changes in the natural gas industry, but it cannot require them to be clairvoyant. Upon consideration of the text of Order No. 380, we conclude that FERC’s indication that carrying charges on prepayments “may require special consideration” is delphic at best; in any event, the reference is irrelevant in light of the Commission’s explicit statement in Order No. 380 that it was making no final disposition of the issue.
The Commission asserts that a significant factual difference between
Columbia Gas
and the present case is that the direct charge in
Columbia Gas
was for gas
taken
whereas the direct charge at issue here is for gas
not taken.
This, of course, is only one way of looking at the basis of the charge in the present case. As a mathematical fact, the charge is as much a result of gas taken during the base period as it is of gas not taken during the deficiency period. In other words, the volume of gas that actually generates the specific charge, being the difference between base-period gas taken and deficiency-period gas not taken, is actual gas taken.
In any event, even if we were to recognize the difference asserted by the Commission, that recognition would not save the Commission because both the
Columbia Gas
orders and the mechanism before us undermine the purpose of the filed rate doctrine. As we said in
Columbia Gas,
“[providing the necessary predictability is the whole purpose of the well established ‘filed rate doctrine’.... ”
Columbia Gas,
831 F.2d at 1141 (quoting
Electrical Dist. No. 1 v. FERC,
774 F.2d 490, 493 (D.C.Cir. 1985)).
Accord Arkansas Louisiana Gas Co. v. Hall,
453 U.S. 571, 577-78, 101 S.Ct. 2925, 2930-31, 69 L.Ed.2d 856 (1981). We are not persuaded by the Commission’s reference to curtailment plans. The rule at issue is the filed
rate
doctrine, and a curtailment plan is not a
rate
change. The fact that we do not apply the filed rate doctrine to curtailments is not a reason why we should not apply it to rates.
The Commission’s attempt to analogize the passthrough mechanism to minimum bills is also misplaced. The two are similar insofar as they are both fixed charges imposed without reference to current purchases of gas, and can be avoided only by leaving the pipeline entirely through an abandonment proceeding or by a change of tariffs under Sections 4 or 5.
The pass-through mechanism differs from the minimum bills, however, in one crucial respect: the aggregate amount charged is calculated on the basis of past purchasing decisions, whereas minimum bills are generally based on current contract entitlement.
See
Order No. 380, FERC Stats. & Regs. [Regulations Preambles 1982-1985] ¶ 30,571 at 30,958-60 & n. 5 (1984) (eliminating minimum commodity bill provisions which had been generally based on a “specified percentage of [the customer’s] contract entitlement”). The Commission calls our attention to its own dicta concerning an earlier minimum bill based in part on historical data.
See Atlantic Seaboard Corp.
(Opinion No. 523), 38 FPC 91, 93-94 (1967),
aff'd,
404 F.2d 1268 (D.C.Cir.1968). The proposed bill effectively required a customer to pay for gas as if it took the same proportion of its current contract demand as it
had taken in the base period of its base-period contract demand. As the charge was avoidable simply by keeping current takes above the minimum bill volume, the link between the current charge and the prior purchase decisions was far more attenuated than in the present case.
B.
Title I
Title I of the Natural Gas Policy Act (“NGPA”), 15 U.S.C. §§ 3301-3333, establishes price ceilings (“maximum lawful prices” or “MLPs”) for first sales of natural gas. Section 504(a) of Title V of the NGPA, 15 U.S.C. § 3414(a), makes it unlawful for any person to sell natural gas at a first sale price in excess of any applicable MLP. All parties before us assume, and we do not doubt, that the wellhead sales in question were first sales. Under Section 601(b) of Title VI, 15 U.S.C. § 3431(b), payments made for natural gas that are not in violation of Title I are deemed just and reasonable, and they may be passed through, absent a showing of fraud or abuse; conversely, the Commission treats amounts not found to be just and reasonable under Section 601(b) as per se imprudent and therefore ineligible for pass-through.
Petitioners argue that this statutory structure means that “all forms of consideration received by the producer-seller must be added together to determine whether the total
value
received exceeds the MLP.” Joint Initial Brief of Certain Petitioners and Intervenors in Support of Petitioners in Opposition to Orders Under Review at 57 (emphasis in original). Petitioners complain that the Commission has allowed two loopholes to the MLP. First, in its 1985 policy statement,
Regulatory Treatment of Payments Made in Lieu of Take-or-Pay Obligations,
FERC Stats. & Regs. ¶ 30,637 (1985), the Commission indicated that take-or-pay buyout and buydown costs would not be considered part of a pipeline’s payments for gas, and therefore would not violate Title I. Second, in July of 1988, the Commission allegedly opened the second loophole by deciding in
ANR Pipeline Co. v. Wagner & Brown,
44 FERC ¶ 161,057 at 61,155 (1988),
reh’g denied,
FERC Docket No. GP86-54-001, slip op. (October 30, 1989), that nonrecoupable prepayments are not part of the consideration paid for gas and therefore do not violate Title I. Nonrecoupable prepayments are payments made by the pipeline to the producer for gas that the pipeline is not able to “make up” by taking amounts in excess of its take-or-pay option in a later year. The pipeline is usually given a certain period (a “make-up period”) in which to take the gas. The make-up period is an important feature of take-or-pay contracts because, to the extent the pipeline takes the gas during the make-up period, it reduces the real burden of such contracts to the time value of the prepayment. After the expiration of the make-up period, the producer is free to resell the gas. According to petitioners, the Commission’s argument that prepayments are irrelevant to Title I is disproved by pre-NGPA case law holding that advance payments to producers for gas were part of the price paid for the gas,
Tennessee Gas Pipeline Co. v. FERC,
606 F.2d 1094, 1102-03 (D.C.Cir. 1979),
cert. denied,
445 U.S. 920, 100 S.Ct. 1284, 63 L.Ed.2d 605 (1980), and
cert. denied sub nom. Transcontinental Gas Pipe Line Corp. v. FERC,
447 U.S. 922, 100 S.Ct. 3012, 65 L.Ed.2d 1113 (1980), and that a take-or-pay prepayment was a sale even absent delivery.
Callery Properties, Inc. v. FPC,
335 F.2d 1004, 1021 (5th Cir.1964).
Petitioners seek to close the first of these asserted loopholes by having the Commission add together (1) buyout and buydown payments made for gas not taken under a contract and (2) all payments made for gas taken. The sum would be divided by the amount of gas actually taken, and petitioners would find a violation of the NGPA to the extent that the resulting “average price” exceeded the MLP. Petitioners argue further that the Commission’s reliance on a policy statement in approving a passthrough of Tennessee’s buyout and buydown costs violates
Pacific Gas & Electric Co. v. FPC,
506 F.2d 33 (D.C.Cir.1974) (policy statement requires independent justification when applied to particular circumstances), and that the policy statement is
conclusory and runs against the Commission’s earlier recognition of the complexity of this issue. Petitioners also claim that the Commission’s conclusion that these payments are not part of the price of gas disregards this Court’s decision in
Southern Union Co. v. FERC,
857 F.2d 812 (D.C.Cir.1988) (gas contract damages are damages for the price of the gas). Therefore, any such costs paid on a gas contract for regulated gas sold at the MLP must violate Title I. Moreover, petitioners claim that if buyouts and buydowns need not be generally counted for purposes of determining MLP compliance, one particular set of buyouts and buydowns must — those made in lieu of nonrecoupable prepayments which themselves would necessarily violate Title I. Invalidating this subset is allegedly necessary in order to avoid a “massive circumvention of Title I.” Joint Initial Brief at 63.
The Commission responds that the principles of its
Wagner & Brown
decision excluding nonrecoupable prepayments from the definition of “payments for gas” and therefore from Title I were confirmed in
Diamond Shamrock Exploration Co. v. Hodel,
853 F.2d 1159 (5th Cir.1988). In that case, the Fifth Circuit held that take- or-pay payments for gas not actually taken are not subject to royalty payments under the Outer Continental Shelf Lands Act, 43 U.S.C. §§ 1331-1336, because they are not “payments for the sale of gas.” The Commission argues further that under pre-NGPA law nonrecoupable take-or-pay payments “were never held to violate NGA [Natural Gas Act] area rate or national rate ceilings, even if they became non-re-coupable.... ” Brief for Respondent FERC at 32. The Commission also points out that the Tenth Circuit recently cited both
Diamond Shamrock
and
Wagner & Brown
when it held that take-or-pay payments are not payments for the sale of gas.
Kaiser-Francis Oil Co. v. Producer’s Gas Co.,
870 F.2d 563, 570 (10th Cir.1989). FERC claims that there is no case that requires the Commission to find a Title I violation in circumstances such as petitioners describe, where the pipeline never takes the gas and the producer later resells it.
Buyout and buydown costs fall within the same rule, according to the Commission, because “they also involve the situation in which payments are made to avoid obligations to buy gas, not to pay for gas.” Brief for Respondent FERC at 34. This Court’s
Southern Union
decision on gas contract damages can be readily distinguished, FERC claims, because that case involved a dispute over the price of gas actually sold, whereas the costs here are to reduce exposure for gas not taken or to reform the terms of future sales.
Petitioners attempt to distinguish
Diamond Shamrock
on the grounds that
Diamond Shamrock
addressed the issue of whether prepayments are subject to royalty payments, at least where the government is the claimant of the royalties. In petitioners’ view, the
Shamrock
court’s holding — that royalties are due only on gas actually produced and taken, not on prepayments — is irrelevant to the Title I question before us. Petitioners also claim that
Kaiser-Francis
relied on the flawed
Wagner & Brown
theory without making an independent judgment on the Title I question and should be rejected. Finally, petitioners argue that FERC misperceives their Title I attack: rather than being a situation where no gas has changed hands at all, as FERC would describe it, the problem arises precisely because the purchaser has taken some volumes of gas but has also made additional payments for the gas it could not take. Thus, the “sale” and the “prepayment” are part of the same contractual event. Petitioners assert that the prepayment (or the cost of buyouts and buy-downs) “plainly relates to the volumes delivered to Tennessee by that seller pursuant to that contract, and to none other.” Joint Reply Brief at 32. Those volumes are therefore necessary, petitioners conclude, “in order to determine whether the total payment per unit of volume received exceeds the maximum lawful price (MLP).”
Id.
at 33.
We conclude that the Commission’s position on this issue, as evidenced by the
Wagner & Brown
proceedings, is final; we do not believe that the Commission has
deferred the question to a later date or has merely issued a policy statement. We also uphold the Commission on the merits of this issue. The amount paid under a contract (for gas taken and for gas not taken, which includes nonrecoupable prepayments as well as buyouts and buydowns), divided by the units of gas actually taken, may indeed yield a figure that is in excess of NGPA ceiling prices. Such a circumstance alone, however, does not violate Title I. For purposes of Section 504(a) of Title V of the NGPA, 15 U.S.C. § 3414(a), we agree with the Tenth Circuit’s conclusion in
Kaiser-Francis
that prepayments are not payments for gas to the extent that the gas is not taken. We will not impute to Congress an intent to preclude all sales at or below the lawful ceiling price that are coupled with other contractual obligations so as to yield an average price in excess of the MLP. Such a construction of Title I is what petitioners’ analysis requires. In the hypothetical situation of a gas buyer’s partial breach and the seller’s subsequent action for damages, we would not deny the seller a remedy because his damages award plus the amount paid for the gas taken, divided by the units of gas actually taken, yielded a quotient greater than the relevant NGPA ceiling price. Although take-or-pay contracts are not identical to the hypothetical contract damages situation, they serve the same purposes as other fixed contractual obligations, and petitioners’ theory would invalidate all take-or-pay contracts that involve sales at the ceiling price to the extent they become nonrecou-pable.
We find nothing in petitioners’ argument that warrants such a conclusion. The Fifth Circuit’s decision in
Callery Properties,
335 F.2d at 1021 (upholding the Commission’s jurisdiction under Section 1(b) of the NGA, 15 U.S.C. § 717(b), because a take-or-pay provision can be a “sale” within the meaning of that section even when no gas is delivered), is inapposite to the issue now before us. The construction of Section 1(b) of the NGA has no bearing on our interpretation of the phrase “any amount paid” under Section 601(b) of the NGPA. Our decision in
Tennessee Gas,
606 F.2d at 1102-03, can be distinguished because that case involved advance payments for gas that was actually taken: the prepayments were, essentially, “recouped.” Similarly,
Southern Union
is not controlling in this case because it involved an award of damages intended to increase the price of natural gas that had actually been taken by the purchaser. In the case before us, the issue arises precisely because prepayments are made for gas that is
not taken.
Our holding today is therefore entirely consistent with
Tennessee Gas
and
Southern Union.
C.
Tennessee’s Settlements with Equitable and Columbia
Equitable Gas Company (“Equitable”) and Columbia Gas Transmission Corporation (“Columbia”) are customers of Tennessee. Their petitions involve their Commission-approved take-or-pay settlement agreements with Tennessee. Columbia seeks “credit” for payments that it has already made to Tennessee, pursuant to its agreement, in order to reimburse Tennessee for take-or-pay costs. Equitable argues that its agreement with Tennessee was still in force until 31 October 1989 and that Tennessee cannot recover any amount from Equitable in excess of the amount specified in the settlement during the term of that settlement. Because the Commission did not give an adequate, reasoned basis for its treatment of these agreements under the purchase deficiency allocation, we vacate the orders on this point and remand to the Commission. On remand, the Commission is to justify in a rational and adequate fashion the effect of the purchase deficiency allocation on these agreements. Otherwise, the Commission must adjust any recovery from either Equitable or Columbia for any take-or-pay liability that is covered by the settlement agreements.
Tennessee and Equitable entered into a settlement agreement on 11 April 1986 (the “April settlement”). The Commission approved the April settlement.
Tennessee Gas Pipeline Co.,
40 FERC ¶ 61,145 (1987). The April settlement provided that Equitable and certain other customers would
be directly billed an annual amount for take-or-pay costs beginning 1 February 1986 and ending 31 October 1989. For the duration of the April settlement, Tennessee could not charge Equitable for any take-or-pay costs greater than those allowed by the settlement’s terms. By its own terms, the April settlement specifically prohibited termination by means of rate adjustment provisions and settlement agreements. Equitable argues that Tennessee’s settlement proposal of 14 October 1987 violated the April settlement by proposing to increase take-or-pay charges to Equitable prior to the expiration of the settlement. Equitable challenges the Commission’s authority to approve a modified Tennessee proposal in derogation of the April settlement.
Similarly, Columbia paid its proportional share of take-or-pay costs for the years 1982 and 1983 pursuant to a settlement agreement with Tennessee originally entered into in November of 1984 (the “November settlement”). The Commission approved the November settlement.
Columbia Gas Transmission Corp. v. Tennessee Gas Pipeline Co.,
29 FERC ¶ 61,203 (1984),
rek’g,
31 FERC II 61,053 (1985). This settlement was subsequently extended to include Tennessee’s take-or-pay costs through July of 1984.
Columbia Gas Transmission Corp.,
31 FERC ¶ 61,307 (1985). On rehearing of Tennessee’s allocation proposal, the Commission ordered Tennessee to use the purchase deficiency methodology exclusively, as opposed to a combination of purchase deficiency and contract demand levels.
Tennessee Gas Pipeline Co.,
43 FERC 1161,329 at 61,931 (1988). Tennessee altered its methodology such that credit for payments made pursuant to the November settlement was eliminated. The Commission subsequently approved this compliance filing, subject to certain conditions not relevant here.
Tennessee Gas Pipeline Co.,
44 FERC ¶ 61,039 (1988). Columbia challenged as arbitrary and unsupported the Commission’s refusal to require credit for past take-or-pay payments pursuant to the November settlement. The Commission dismissed Columbia’s challenge on rehearing.
Tennessee Gas Pipeline Co.,
44 FERC ¶ 61,155 (1988).
Equitable argues that Tennessee’s unilateral imposition of the higher take-or-pay charges without a general rate filing under Section 4 of the NGA, 15 U.S.C. § 717c, violated both the
Mobile-Sierra
doctrine,
see FPC v. Sierra Pacific Power Co.,
350 U.S. 348, 76 S.Ct. 368, 100 L.Ed. 388 (1956), and
United Gas Pipe Line Co. v. Mobile Gas Corp.,
350 U.S. 332, 76 S.Ct. 373, 100 L.Ed. 373 (1956), and the express provisions of the April settlement. As to the Commission’s finding on rehearing,
Tennessee Gas Pipeline Co.,
43 FERC 11 61,329 at 61,935 (1988), that allowing the April settlement to stand would be “unduly discriminatory” in violation of Section 5 of the NGA, 15 U.S.C. § 717d, Equitable points out that the Commission failed to find that any of the parties that paid take-or-pay costs under the April settlement were victims of undue discrimination; failed to find that Tennessee’s customers not party to the April settlement would be affected if the settlement were not abrogated; and failed to find that imposing take-or-pay obligations on Equitable greater than those established by the settlement would either remedy the undue discrimination or work beneficent effects upon Tennessee’s customers or downstream consumers.
Columbia’s claim is also based on allegations that the Commission acted arbitrarily. Columbia argues that, by its own terms, the Commission’s use of the purchase deficiency mechanism was designed to rationally correlate take-or-pay cost incurrence with cost causation.
Tennessee Gas Pipeline Co.,
43 FERC 1161,329 at 61,930 (1988). According to Columbia, this approach should have led the Commission to require credit for take-or-pay payments made to Tennessee. Indeed, Columbia argues, it has already paid Tennessee for any take-or-pay costs Columbia may have generated by purchase cutbacks during the period from 1982 to 1984 that is covered by the November settlement. Columbia protests that the Commission has presented no reasoned explanation for denying credit and thus departing from the cost causation methodology expounded in its own orders. Columbia argues that the Commission’s analogy
of settlement payments to “released gas sales” (i.e., sales of gas directly to a customer by a producer after a pipeline has released the gas to the producer in exchange for take-or-pay credit), credit for which is denied as an “ ‘unwarranted double benefit,’ ”
Tennessee Gas Pipeline Co.,
46 FERC ¶ 61,264 at 61,776, is inapposite because customers in the released gas situation have already reaped the benefit of the lower price that flows from such releases, whereas the only benefit to Columbia from its settlement payments is a coordinate diminution of its take-or-pay exposure.
The Commission responds that Equitable’s argument is overly formalistic: when the Commission rejected Tennessee’s initial Section 4 filing and issued its own decision, the Commission argues, it implemented a rate change that was the result of a “proceeding instituted by the Commission pursuant to Section 5” as contemplated by the April agreement. According to FERC, its actions were therefore consistent with the settlement, and the fact that the rate change was not initiated by the
pipeline company
is irrelevant. The Commission argues further that Equitable’s argument is inconsistent with Equitable’s own prior conduct because Equitable allegedly recognized that the April settlement would be supplanted upon issuance of a decision on the merits in the present case. In any event, the Commission concludes, no different result is required here even if Equitable’s arguments are correct because the practical relief available to Equitable is minimal inasmuch as Equitable’s “overall allocation cannot be reduced merely because the payment level could not be applied to it until October 1989 [the date at which the April settlement expired].” Brief for Respondent FERC at 42.
As to Columbia, the Commission argues that if it were to approve the “credit” requested by Columbia, it would have to make a similar adjustment every time a pipeline and one of its customers entered into an agreement that could be read as relieving the pipeline of take-or-pay liability (as an example, FERC points to the so-called “released gas programs”). The Commission also claims that it has consistently denied such credits or adjustments on the grounds that a customer in Columbia’s position receives a number of additional benefits in such agreements, and that therefore Columbia’s request is merely an attempt to add extra terms to the original agreement.
Although the Commission correctly asserts that it is entitled to deference in the interpretation of settlement agreements before it,
National Fuel Gas Supply Corp. v. FERC,
811 F.2d 1563, 1569 (D.C.Cir.),
cert. denied,
484 U.S. 869, 108 S.Ct. 200, 98 L.Ed.2d 151 (1987), the Commission is obligated to provide us with a reasoned and consistent explanation to which we can defer.
See Motor Vehicle Mfrs. Ass’n v. State Farm Mut. Automobile Ins. Co.,
463 U.S. 29, 43,103 S.Ct. 2856, 2866, 77 L.Ed.2d 443 (1983) (“[T]he agency must examine the relevant data and articulate a satisfactory explanation for its action including a ‘rational connection between the facts found and the choice made.’ ”) (quoting
Burlington Truck Lines, Inc. v. United States,
371 U.S. 156, 168, 83 S.Ct. 239, 246, 9 L.Ed.2d 207 (1962));
Panhandle Eastern Pipe Line Co. v. FERC,
881 F.2d 1101, 1118 (D.C.Cir.1989) (“The agency’s determination must reflect reasoned decisionmak-ing that has adequate support in the record and must include an ‘understandable’ agency analysis and rationale.”) (citing
Tarpon Transmission Co. v. FERC,
860 F.2d 439, 442 (D.C.Cir.1988)). The Commission’s findings and rationales with regard to the treatment of these settlements are largely non-existent. To the extent that they are discernible, they are generally unclear or contradictory. To the extent that they are unambiguous, they are unsupported. Such a state of affairs prohibits us from deferring to the Commission on this issue.
In particular, we find unpersuasive the Commission’s argument that its orders here do not violate the
Mobile-Sierra
doctrine with regard to Equitable and that its orders somehow come within the Section 5 language of the April settlement; as Equitable points out, the Commission seems to have made no finding that would justify a Section 5 rate change. Moreover, although Equitable does not make clear the exact sweep of its argument that its “liability during the ‘RP85-178 Period’ [ending October 31, 1989] is limited to the amount specified in the April 11 Settlement,” Reply Brief of Petitioner Equitable Gas Co. at 6, we take it to express a view that even new passthrough mechanisms created by FERC on remand might conflict with its settlement. If FERC implements another pass-through mechanism, it should either allow Equitable’s settlement with Tennessee to supercede any new passthrough mechanism for the period in which it was operative, or it should provide a more well-reasoned explanation for its decision not to do so.
As to Columbia, regardless of the fact that its settlement with Tennessee used a cost-causation approach similar to that used by the Commission here, it has already paid an amount agreed upon between itself and Tennessee for its share of take- or-pay liability for a specific period. It should be given credit for having done so, absent a good explanation.
D.
Section 5, the Sunset Provision, the Litigation Exception, and Implementation Issues
Petitioners argue that the Commission erred in failing to consider whether the buyout and buydown costs at issue were unjust and unreasonable and therefore violated Section 5 of the NGA, 15 U.S.C. § 717d. The Commission responds that this question should be considered in the generic Order No. 500 proceedings.
This issue is now mooted by our recent decision in
American Gas Ass’n v. FERC,
888 F.2d 136 (D.C.Cir.1989)
(“AGA
”). As we said in
AGA,
the Commission’s “half-explained cunctation” with regard to the Section 5 issue convinced us that it was engaged in dilatory tactics so as to avoid either exercising its Section 5 powers or explaining its inaction.
AGA,
at 148 (citing
Mid-Tex Electric Cooperative v. FERC,
822 F.2d 1123, 1132 (D.C.Cir.1987)). We therefore remanded the record to the Commission for promulgation of a final rule within sixty days. We trust that this Section 5 issue will be clarified and hopefully resolved upon the timely issuance of a final rule as a replacement for interim Order No. 500.
Various petitioners attack the deadline of 31 March 1989 for filing under the “equitable sharing mechanism” (the “sunset date”) and the Commission’s “litigation exception” to the sunset date (i.e., that take- or-pay liabilities in litigation as of 31 March 1989 are exempt from the deadline). Our decision in
AGA
invalidated the sunset provision as arbitrary and capricious.
AGA,
at 151. Because the litigation exception was merely a dispensation from the sunset date, that issue is now moot.
Finally, because of our conclusion that direct billing based on purchase deficiencies violates the filed rate doctrine, all implementation issues are moot.
III. Conclusion
The purchase deficiency allocation mechanism violates the filed rate doctrine. Because we find that prepayments are not payments for gas to the extent that the gas is not taken, we reject petitioners’ Title I attack on the orders before us. The Commission did not present a reasoned explanation with regard to the effect of its purchase deficiency allocation on Equitable and Columbia. On remand, the Commission must adequately and reasonably justify its orders, particularly with regard to the
Mobile-Sierra
doctrine, to findings necessary prior to Commission action, and to its refusal to grant Columbia “credit” for payments already made. Otherwise, the Commission must adjust any recovery from either customer for any take-or-pay liability covered by their respective agreements. Our recent decision in
AGA
moots various petitioners' claims as to Section 5,
the sunset provision, and the litigation exception. We vacate the orders at issue and remand to the Commission for proceedings not inconsistent with this opinion.