
    PANHANDLE EASTERN PIPE LINE COMPANY, Petitioner, v. FEDERAL ENERGY REGULATORY COMMISSION, Respondent, Union Electric Co., et al., Intervenors.
    Nos. 87-1431, 87-1539, 87-1579, 87-1584, 87-1648, 87-1659, 87-1780, 87-1835, 88-1002, 88-1145 and 88-1149.
    United States Court of Appeals, District of Columbia Circuit.
    Argued March 29, 1989.
    Decided Aug. 1, 1989.
    
      Brian D. O’Neill, with whom Raymond N. Shibley and Bruce W. Neely, Washington, D.C., were on the brief, for Panhandle Eastern Pipe Line Co., petitioner in Nos. 87-1431 & 87-1780 and intervenor in Nos. 87-1539, 87-1579, 87-1584, 87-1835, 88-1002, 88-1145 & 88-1149.
    Philip B. Malter, with whom Charles F. Wheatley, Jr., Deerfield, Ill., was on the brief, for Municipal Defense Group, petitioner in Nos. 87-1584 & 88-1002 and inter-venor in No. 87-1431. Timothy P. Ingram, Arlington, Va., also entered an appearance for Municipal Defense Group.
    Linda Gillespie Stuntz, Washington, D.C., with whom Richard D. Avil, Jr., Cleveland, Ohio, (for The East Ohio Gas Co.), and Jeffrey M. Petrash, Washington, D.C., and James H. Holt (for Michigan Consolidated Gas Co.) were on the brief, for petitioners/intervenors. Paul T. Ruxin and Carolyn Y. Thompson, Washington, D.C., also entered appearances for The East Ohio Gas Co.
    John R. Schaefgen, Jr., Washington, D.C., for petitioners General Service Customer Group, Indiana Gas Co., and supporting intervenor Citizens Gas & Coke Utility. Daniel W. McGill, Indianapolis, Ind., Tom Rattray, and Ronald E. Christian (for Indiana Gas Co.), Richard M. Merriman and Stephen L. Huntoon, Washington, D.C., (for General Service Customer Group), and William P. Diener and Steven M. Sherman, New York City, (for Citizens Gas & Coke Utility) were on the joint brief for petitioners/intervenor. J. Richard Tiano, Kenneth T. Rynne, and Perry D. Robinson, Washington, D.C., also entered appearances for petitioner Indiana Gas Co. in No. 88-1145.
    Richard A. Solomon, with whom Mary A. McReynolds, Washington, D.C., was on the brief, for Quantum Chemical Corp., petitioner in No. 87-1579, intervenor in Nos. 87-1431 and 87-1659, and for intervenor National Distillers & Chemical Corp. in Nos. 87-1539 and 87-1584. David D’Alles-sandro also entered an appearance for Quantum Chemical Corp. and National Distillers & Chemical Corp.
    
      Frank R. Lindh, Attorney, F.E.R.C., Washington, D.C., with whom Catherine C. Cook, Gen. Counsel, and Jerome M. Feit, Sol., Washington, D.C., were on the brief, for respondent. Dwight Alpern, Atty., F.E.R.C., Detroit, Mich., also entered an appearance for respondent.
    John R. Schaefgen, Jr., with whom Randall V. Griffin, Washington, D.C., (for Cent. Illinois Light Co.), William P. Diener, Steven M. Sherman, New York City, (for Citizens Gas & Coke Utility), Richard D. Avil, Jr., Cleveland, Ohio, Linda Gillespie Stuntz (for The East Ohio Gas Co.), Jeffrey M. Petrash, Washington, D.C., James H. Holt (for Michigan Consol. Gas Co.), Fredric J. George, Charleston, W.Va., Giles D. Snyder, Stephen J. Small, Boston, Mass., (for Columbia Gas Transmission Corp.), Richard M. Merriman, Stephen L. Huntoon, Washington, D.C., (for General Service Customer Group), and Daniel W. McGill, Indianapolis, Ind., Tom Rattray, and Ronald E. Christian (for Indiana Gas Co.) were on the joint brief, for intervenors in support of respondent.
    William A. Mogel, Washington, D.C., entered an appearance, for intervenor Union Electric Co.
    William M. Lange, Colorado Springs, Colo., entered an appearance, for inter-venor Michigan Gas Storage Co.
    William T. Miller, Susan N. Kelly, and Mark C. Darrell, Washington, D.C., entered appearances, for intervenor National Helium Corp.
    Dan L. Keskey and Henry J. Boynton, Lansing, Mich., entered appearances, for intervenors The State of Michigan, et al.
    Glen S. Howard, Washington, D.C., entered an appearance, for intervenors The Process Gas Consumers Group, et al.
    Daniel F. Collins, Washington, D.C., and Steven A. Taube entered appearances, for intervenor ANR Pipeline Co.
    Before RUTH BADER GINSBURG, BUCKLEY, and SENTELLE, Circuit Judges.
   Opinion PER CURIAM.

TABLE OF CONTENTS

Page

I. BackgRound.1104

A. Statutory Background.1104

B. Administrative Proceedings.1104

II. Discussion.1107

A. The “Sole Supplier” Issue.1107

B. The D-2 Charge.1110

C. The Minimum Commodity Bill.1113

D. The Imputed Load Factor for SG Customers.1115

E. The Effective Date of FERC’s Order.1118

1. Standard of Review.1118

2. The Settlement Agreement.1118

3. The Commission’s Rulings .1119

4. Analysis.1120

a. December Effective Date.1120

b. February vs. August Effective Date.1121

c. Minimum Bill Provisions.1122

III. Conclusion.1122

PER CURIAM:

Panhandle Eastern Pipe Line Company and several other petitioners seek review of a series of Federal Energy Regulatory Commission (FERC or Commission) orders requiring changes in Panhandle’s natural gas sales tariff. This appeal presents five major questions.

On two related issues, we grant the petition for review and remand to the Commission. First, FERC ordered Panhandle to offer its favorable G rate schedule, previously available only to “full requirements” customers who purchased gas exclusively from Panhandle, to its “partial requirements” customers as well, who nonetheless remained free to buy gas from sellers other than Panhandle. We conclude that the Commission has failed to explain the fairness of releasing customers from their obligation to take their total requirements from Panhandle, while simultaneously ordering Panhandle to continue to provide them with G schedule benefits.

Second, the Commission directed Panhandle to switch to a “modified fixed and variable” rate design and to implement a two-part demand charge, with the second charge based on a customer’s unilateral nomination (i.e., specification) of an annual level of natural gas service. Although FERC has the authority to mandate such changes, we do not find it reasonable on the present record for the Commission to permit Panhandle’s customers to nominate low levels of service (thereby reducing their demand charges), while at the same time requiring the pipeline to stand ready to serve them at the level described in its operating certificate.

On the remaining issues, however, we uphold the Commission’s judgment. FERC’s elimination of Panhandle’s fixed-cost minimum commodity bill is consistent with recent Commission decisions approved by federal courts. FERC also reasonably maintained the imputed load factor for certain small customers, based on Commission precedent. Finally, we conclude that FERC’s determination that its orders became effective on the date of its order on rehearing (August 19, 1987) rests on a reasonable contractual interpretation.

I. Background

A. Statutory Background

The Natural Gas Act, 15 U.S.C. §§ 717-717w (1982) (NGA) authorizes the Federal Energy Regulatory Commission to approve “just and reasonable” rates for natural gas sold or transported by interstate pipelines. Id. § 717c(a). Natural gas companies must file with FERC schedules showing all rates and must justify any proposed changes. Id. § 717c(c)-(d). Section 5(a), id. § 717d(a), provides:

Whenever the Commission, after a hearing had upon its own motion or upon complaint of any State, municipality ... or gas distributing company, shall find that any rate, charge, or classification demanded, ... charged, or collected by any natural gas company ... is unjust, unreasonable, unduly discriminatory, or preferential, the Commission shall determine the just and reasonable rate, charge [etc.] ... and shall fix the same by order.

Finally, section 7, id. § 717f, grants FERC the power to issue “certificate[s] of public convenience and necessity” authorizing qualified companies to transport and sell natural gas.

The energy crisis of the 1970’s exposed the failure of the NGA’s regulatory framework, through its price controls, to provide the economic incentives necessary to encourage development of new natural gas sources and to ensure an adequate supply of gas at reasonable prices. Congress responded by enacting the Natural Gas Policy Act of 1978, 15 U.S.C. §§ 3301-3432 (1982) (NGPA), which deregulated wellhead prices and established a market-based natural gas pricing system under the Commission’s general oversight. See Transcontinental Gas Pipe Line Corp. v. State Oil & Gas Bd., 474 U.S. 409, 420-21, 106 S.Ct. 709, 715-16, 88 L.Ed.2d 732 (1986). Over the past decade, FERC has sought to implement the NGPA’s policy of promoting competitive natural gas pricing through a series of rules and decisions, as exemplified by the orders now under review.

B. Administrative Proceedings

For over thirty years, petitioner Panhandle Eastern Pipe Line Company (Panhandle) charged its large resale customers for natural gas in accordance with the two rate schedules established in Panhandle Eastern Pipe Line Co., 10 F.P.C. 185 (Opinion No. 214), modified, 10 F.P.C. 322 (1951), further modified, 13 F.P.C. 53 (1954) (Opinion No. 269), rev’d in part, 230 F.2d 810 (D.C.Cir.1955).

One of these, a limited service (LS) rate schedule, applied to “partial requirements” customers who bought gas from Panhandle and other sellers. See Panhandle Eastern Pipe Line Co., 38 F.E.R.C. ¶ 61,164, at 61,465 & n. 54 (1987) (Opinion No. 265) (describing section 1.10 of Panhandle’s tariff, which defines a “Limited Service Buyer”). The LS schedule fixed two payment obligations: a “demand charge” based on “contract demand” (i.e., a customer’s maximum entitlement to a certain volume of gas on any given day) and a “minimum commodity bill” requiring a customer to pay for 75% of its contract demand for a year, regardless of whether the gas was actually taken.

The second schedule, a general service (G) rate schedule, was available only to “full requirements” customers who agreed to buy gas from Panhandle alone. A G rate customer was permitted to purchase gas from another supplier only if Panhandle rejected that customer’s request for an increased contract demand level. See generally id. at 61,465 & n. 53 (discussing Panhandle tariff section 1.9, which defines a “General Service Buyer” eligible for G rate schedule). Customers using Panhandle as a sole supplier received certain benefits: they paid no minimum bill, they could nominate reduced contract demand levels for the off-peak months (mid-April through mid-October), and they paid only 90% of monthly demand charges if their highest daily demand in any month fell below 90% of the contract demand level. Id. at 61,465.

A final category of customers, small general service (SG or SGS) customers, consisted of small “full requirements” buyers (usually municipalities) whose contract demand did not exceed a certain level and who had low “load factors” (average daily gas requirement divided by maximum daily requirement). See infra section II.D. Because SG customers provide gas mainly to residential and light commercial users whose needs fluctuate with the weather, and because they lack the flexibility of large industrial customers, the Commission has traditionally given them favorable treatment in the SG rate schedule, which features an imputed load factor higher than their actual load factor and contains neither demand charges nor minimum bills. Id.

The instant litigation resulted from certain changes in Panhandle’s ratemaking structure. On March 31, 1982, in accordance with section 4 of the NGA, 15 U.S.C. § 717c, Panhandle filed revised tariffs seeking to increase its rates for sales of natural gas for resale and to include a “sole supplier” provision. See FERC Docket No. RP82-58. A month later, the Commission accepted Panhandle’s proposal, suspended it to become effective October 1, 1982 (subject to refund), and ordered hearings. 19 F.E.R.C. 1161,080, reh’g granted, 20 P.E.R.C. ¶ 61,021, further reh’g denied, id. II 61,244 (1982).

On June 10, 1982, pursuant to NGA section 5, 15 U.S.C. § 717d, Central Illinois Light Company (CILCO), a Panhandle G schedule customer, filed a complaint alleging that the “sole supplier” provision contained in section 1.9 of the tariff was discriminatory and anticompetitive. See Complaint and Request for Evidentiary Hearing, F.E.R.C. Docket No. RP82-105. CILCO argued that Panhandle’s tariff effectively prevented it from purchasing cheaper gas from an alternative supplier, because were it to do so, it would forfeit its G schedule benefits (e.g., the option of stepping down demand levels in off-peak months). FERC consolidated CILCO’s complaint and Panhandle’s rate request. Central Illinois Light Co. v. Panhandle Eastern Pipe Line Co., 21 F.E.R.C. ¶ 61,147 (1982).

On December 14, 1983, Panhandle filed a “Stipulation and Agreement” (Agreement) with the Commission. Article III of that settlement contract resolved all cost-of-service disputes. Part 4.A of Article II, however, reserved the issues of cost classification, cost allocation between jurisdictional and non-jurisdictional sales and services, the tariff rate design (including minimum bill matters), and CILCO’s complaint (the “sole supplier” issue). Any resultant rate changes were to be “made effective only prospectively from and after a Commission order disposing of these issues.” FERC approved the Agreement on March 19, 1984. Panhandle Eastern Pipe Line Co., 26 F.E.R.C. ¶ 61,342, reh’g granted, 27 F.E.R.C. ¶ 61,233 (1984).

The reserved issues were first referred to an administrative law judge (AU), who issued a decision on September 6, 1985. Initial Decision, Panhandle Eastern Pipe Line Co., 32 F.E.R.C. ¶ 63,085 (1985) (ALJ Decision). The Commission reviewed the AU’s findings and conclusions on February 20, 1987 in its Opinion No. 265, 38 F.E.R.C. 1161, 164.

The Commission affirmed three parts of the AU’s decision, two of which are relevant here. First, FERC agreed that Panhandle must adopt the modified fixed and variable (MFV) rate design approved in Texas Eastern Transmission Corp., 32 F.E.R.C. ¶ 61,056, modifying 30 F.E.R.C. ¶ 61,144 (1985). See Opinion No. 265, 38 F.E.R.C. at 61,452-53; see also ALJ Decision, 32 F.E.R.C. at 65,272-84, 65,296. Under the MFV method, a company is guaranteed recovery of its “variable” costs (which depend on the volume of gas moving through its pipeline) and certain of its “fixed” investment costs (e.g., fixed production expenses, return on equity, related income taxes), which are “classified” (i.e., assigned) to the “commodity” component (the natural gas) and allocated to customers based on annual usage; remaining fixed costs and billed demand costs, however, are classified to a two-part “demand” component. Id.; see also Texas Eastern, 32 F.E.R.C. at 61,149. The “D-1 charge” is based on a customer’s daily contract demand, which cannot be reduced; the “D-2 charge” is based on a customer’s maximum annual service entitlement. Opinion No. 265, 38 F.E.R.C. at 61,452-54; see also ALJ Decision, 32 F.E.R.C. at 65,293-96, 65,312-14.

Second, FERC found Panhandle’s fixed cost minimum commodity bill to be anti-competitive and ordered it eliminated from the LS rate schedule, but did not specify the effective date for this termination. See Opinion No. 265, 38 F.E.R.C. at 61,455-56; see also AU Decision, 32 F.E.R.C. at 65,-308-12.

FERC reversed the AU on two issues. First, the Commission reduced the discount that the AU had given SG customers; the Commission adhered to a 52.5% imputed load factor (closer to the SG customers' actual load) in place of the AU’s suggested 65% figure, see id. at 65,300-01. Opinion No. 265, 38 F.E.R.C. at 61,454.

Second, the AU had declined to modify the tariff’s “sole supplier” restriction on the availability of the G rate schedule, finding that this limitation was not anti-competitive because G customers had the option of switching to the LS rate schedule if they wished to purchase gas from another supplier. AU Decision, 32 F.E.R.C. at 65,319-27. FERC rejected this conclusion, holding that the “sole supplier” provision was unjust and unreasonable because it deprived G customers (e.g., CILCO) of the freedom to purchase lower-priced gas from competing suppliers. Opinion No. 265, 38 F.E. R.C. at 61,465-71.

In view of the new flexibility given to G customers, the Commission decided that LS customers (who already could buy gas from alternative suppliers) should receive the rights formerly confined to G customers (e.g., the right to reduce contract demand in off-peak months). Id. at 61,470. Accordingly, FERC eliminated the former distinction in Panhandle’s tariff between general service (section 1.9) and limited service customers (section 1.10) — although the G and LS rate schedules themselves remained intact and separate. Id. at 61,470-71. The Commission also “require[d] that Panhandle’s tariff be modified prospectively from the effective date of the order.” Id. at 61,470. FERC rejected Panhandle’s claim of injury as speculative, asserting that the new scheme would increase the pipeline’s incentive to reduce costs in order to maximize sales. Id.; see also id. at 61,455-56.

The Commission denied petitions for rehearing filed by Panhandle and six other parties, but clarified its decision. See 40 F.E.R.C. II 61,189 (1987) (Opinion No. 265-A). Regarding the rate design methodology, FERC stated that the D-2 charge must be based on customers’ unilateral annual nominations and concluded that overrun penalties in Panhandle’s tariff would deter customers from deliberately underno-minating annual demand. Id. at 61,596-97. Turning to the “sole supplier” issue, the Commission characterized the switching of LS customers to G rate schedules as involving merely a “rate adjustment,” not a change in “certificated levels” (i.e., the amount of gas the pipeline is authorized to provide under the certificate issued by FERC). Id. at 61,601. Finally, FERC ruled that the effective date for elimination of the minimum commodity bill was August 19, 1987 (the date of Opinion No. 265-A) rather than February 20, 1987 (the date of Opinion No. 266), based on its view that the Agreement’s provision stating that rate changes would be made “prospectively from and after a Commission order disposing of [the reserved] issues” referred to the agency's final order on rehearing. Id. at 61,599.

Upon receiving further petitions, FERC issued an order on November 4, 1987 denying rehearing in part (for example, on the D-2 charge) and granting rehearing in part. 41 F.E.R.C. ¶ 61,125 (1987) (November 4 order). The Commission reiterated its conclusion that the Agreement’s “order disposing of issues” language meant an order on rehearing, and ruled that the rehearing order date (August 19) would serve as the effective date for all the reserved issues, not just the minimum commodity bill. Id. at 61,308-09.

FERC denied further requests for rehearing. 42 F.E.R.C. ¶ 61,038 (1988). Panhandle and many other parties have petitioned this court for review of the Commission’s orders pursuant to 15 U.S.C. § 717r(b).

II. Discussion

A. The “Sole Supplier” Issue

We address first FERC’s elimination of the condition that made Panhandle’s G schedule available only to customers as to which Panhandle was the “sole supplier.” The condition at issue here requires the customer to purchase only from Panhandle and permits the customer to purchase gas in excess of its contract demand volume from another source only if Panhandle refuses to increase the customer’s contract demand. Panhandle has no express contractual obligation to provide the increased volume. The “sole supplier” label distinguishes the provision from “full requirements” provisions under which a pipeline undertakes to provide all of the customer’s requirements. See Opinion No. 265, 38 F.E.R.C. at 61,471. Panhandle argues that the condition is not in fact anti-competitive; that FERC erred in permitting Panhandle’s “partial requirements” LS schedule customers to switch to its G schedule; and that FERC failed to consider the consequences of the change it imposed. We must remand this issue because the Commission’s opinion does not establish adequately the justness and reasonableness of its result.

Panhandle argues that FERC erroneously determined that the “sole supplier” limitation on the availability of the G schedule is anticompetitive, but we find no error in this respect. FERC based its decision in part on the inconsistency of the “sole supplier” provision with FERC’s policy in recent years of encouraging price competition within the natural gas industry, as we noted in section I.A. of this opinion. That policy has been shaped and evidenced not only by Congress’ deregulation of producer sales under the Natural Gas Policy Act of 1978, but also by FERC’s Order No. 380 eliminating variable costs from minimum commodity bills, by its Order No. 380-C eliminating minimum physical take provisions, by its Order No. 436 implementing non-discriminatory open-access transportation, and by “other factors” tending to permit pipeline customers to make gas-purchase decisions primarily on the basis of commodity price. Opinion No. 265, 38 F.E.R.C. at 61,470 (citing NGPA, 15 U.S.C. §§ 3301-3432; Elimination of Variable Costs from Certain Natural Gas Pipeline Minimum Commodity Bill Provisions, 27 F.E.R.C. ¶ 61, 318 (Order No. 380), modified, 27 F.E.R.C. ¶ 61,077 (Order No. 380-C), reh’g denied, 29 F.E.R.C. ¶ 61,332 (1984) (Order No. 380-D), aff'd in pertinent part sub nom. Wisconsin Gas Co. v. FERC, 770 F.2d 1144 (D.C.Cir.1985); Regulation of Natural Gas Pipelines After Partial Wellhead Decontrol, 50 Fed.Reg. 42,408 (1985) (Order No. 436), vacated sub nom. Associated Gas Distribs. v. FERC, 824 F.2d 981 (D.C.Cir.1987), cert. denied, — U.S. - 108 S.Ct. 1468, 99 L.Ed.2d 698 (1988), modified on remand, 52 Fed. Reg. 30,334 (1987) (Order No. 500), appeal pending sub nom. American Gas Ass’n v. FERC, No. 87-1588 (D.C.Cir. filed Oct. 19, 1987)).

FERC found that Panhandle’s “sole supplier” provision inhibited CILCO, the complaining customer, from purchasing lower-priced gas from a competing pipeline because to do so would disqualify CILCO from continued use of Panhandle’s G schedule. Without the G schedule’s summer step-down in contract demand levels, CILCO would have to contract for demand upon Panhandle (if at all) at a constant monthly contract demand level under Panhandle’s “partial requirements” LS schedule. In reliance on the G schedule’s step-down, CILCO had not developed sufficient storage capacity to coordinate its seasonal variations in need with the program of level monthly deliveries necessary to take advantage of the LS schedule. The prospect of such level contract demand charges exerted, and the actuality of such charges would continue to exert, an inhibiting influence on CILCO’s consideration of otherwise price-competitive gas sources. Such inhibitions plainly are evils under current FERC policy, and FERC has adequately identified that policy and demonstrated how the “sole supplier” provision tends to thwart that policy. Cf. Tennessee Gas Pipeline Co. v. FERC, 860 F.2d 446, 458 (D.C.Cir.1988) (Commission failed to demonstrate that alternative schedule was “effectively unavailable”).

Panhandle’s protests do not call into question the fundamental soundness of this aspect of FERC's decision. Panhandle is correct that Order No. 436-A contemplated that a former “full requirements” customer might become a “partial requirements” customer by using Order No. 436 transportation and declined to prevent that result by rule. Order No. 436-A, 50 Fed.Reg. 52,217, 52,240, reprinted in FERC Stats. & Regs., [1982-85 Transfer Binder] Regs. Preambles H 30,675, at 31,669. FERC’s action there, however, does not endorse the validity of “sole supplier” clauses and does not insulate particular “sole supplier” clauses from review. See Order No. 436, 50 Fed.Reg. 42,408, 42,445, reprinted in FERC Stats. & Regs., [1982-85 Transfer Binder] Regs.Preambles ¶ 30,665, at 31,530. Nor is Panhandle correct that FERC’s decisions in Consolidated Gas Transmission Corp., 38 F.E.R.C. ¶ 61,150, modified, 41 F.E.R.C. ¶ 61,130 (1987), and Transcontinental Gas Pipe Line Corp., 38 F.E.R.C. H 61,165 (1987), are inconsistent with the decision under review. It is true that FERC permitted those pipelines, over the objections of affected customers, to require their “full requirements” customers seeking open-access transportation to switch from “full requirements” schedules to less advantageous “partial requirements” rate schedules. The schedules at issue in Transcontinental and Consolidated Gas, however, were one-part volumetric rates that exposed the pipelines to the risk of fixed cost under-recovery if the “full requirements” customers swung off system. Consolidated Gas, 38 F.E.R.C. at 61,404-OS; Transcontinental, 38 F.E.R.C. at 61,-489-90. Panhandle’s contract demand charge, on the other hand, assures substantial recovery of its fixed costs even when a customer fails to purchase the reserved volume. See Tennessee Gas, 860 F.2d at 459-60. The distinction is not an arbitrary one, and passes our review for purposes of determining that a restraint exists.

The existence of a restraint, however, does not settle the matter. See Transwestern Pipeline Co. v. FERC, 820 F.2d 733, 740 (5th Cir.1987), cert. denied, — U.S. -, 108 S.Ct. 696, 98 L.Ed.2d 648 (1988). FERC has disclaimed announcing a per se rule against “sole supplier” clauses. Opinion No. 265, 38 F.E.R.C. at 61,471. See also Tennessee Gas, 860 F.2d at 460 (“Panhandle does not support the broad holding that the provision is unjust and unreasonable per se .... ”); Consolidated Gas, 38 F.E.R.C. at 61,404-05 (sustaining use of “sole supplier” clause where pipeline met customers’ full requirements without contract demand limitation and set rates accordingly); Transcontinental, 38 F.E.R.C. at 61,489-90 (sustaining use of “sole supplier” clause on schedule with favorable one-part volumetric rate equal to contract demand rate at 100% load factor). The Commission must establish, then, that in this case the provision constitutes an unreasonable restraint. As FERC previously has acknowledged, such rule-of-reason analysis “must rest on a careful balancing of the competitive harm the term causes against the term’s objectives in light of the alternatives available.” Kentucky Utilities Co., 23 F.E.R.C. ¶ 61,317, at 61,675 (1983) (footnote omitted), remanded on other grounds, 766 F.2d 239 (6th Cir.1985). The decisions before us for review, however, contain no adequate rule-of-reason analysis. Because this issue arose on CILCO’s complaint, it is one on which FERC bears the ultimate burden of demonstrating the unjustness and unreasonableness of the provision. 15 U.S.C. § 717d; see Sea Robin Pipeline Co. v. FERC, 795 F.2d 182, 183-84 (D.C.Cir.1986); see also Tennessee Gas Pipeline Co. v. FERC, 871 F.2d 1099, 1104 (D.C.Cir.1989) (FERC established pri-ma facie case that minimum bill was anti-competitive; therefore, production burden shifted to pipeline to justify bill; but ultimate burden of proving existing bill (which pipeline itself did not propose to change) unlawful remained with Commission). Accordingly, the issue must be remanded for reconsideration by FERC.

In particular, FERC has failed to explain why the unique benefits offered G schedule customers do not render reasonable the imposition of the “sole supplier” clause; nor does FERC adequately explain the justness and reasonableness of the tariff it has dictated. The Commission bears the burden of demonstrating that its remedy is just and reasonable, see Tennessee Gas, 860 F.2d at 457, and it was incumbent on the Commission to demonstrate affirmatively that it is just and reasonable to release all of Panhandle’s customers from the G schedule’s “sole supplier” condition while permitting them to receive the undoubted benefits of its customer-designated contract demand step-down and contract-demand billing ratchet.

In this connection, we note that the Commission contends that there is no relation between the “sole supplier” limitation and the G schedule’s benefits because Panhandle did not seek the limitation in exchange for the benefits when the basic structure presently under review was established. See Opinion No. 265, 38 F.E.R.C. at 61,469. It is true that Panhandle sought the summer step-down so it could meet a particular customer’s need for summer gas. It does not follow, however, that the “sole supplier” limitation and the summer step-down are unrelated. Panhandle sought a summer step-down fixed at 30% and apparently applicable to all customers. Opinion No. 214, 10 F.P.C. 185, 193 (1951). The Federal Power Commission, FERC’s statutory predecessor, instead imposed the instant customer-designated step-down program— and expressly limited its availability to customers on the general service schedule subject to the “sole supplier” condition. Id. at 197. (At the same time, in order to “permit orderly planning,” id. at 200, on a system that had experienced problems of excessive demand upon its capacity, the FPC approved the “reasonable peak volumetric limitations,” id., now cited by FERC to distinguish the instant case from the “full requirements” schedules in Consolidated Gas and Transcontinental. See Opinion No. 265, 38 F.E.R.C. at 61,471.) The FPC’s opinion is not express, to say the least, but there is a discernible linkage between the “sole supplier” clause and the Commission-created customer-designated step-down mechanism.

In sum, because the “sole supplier” clause is linked to provisions favorable to customers, as were the “full requirements” schedules in Consolidated Gas and Transcontinental, the clause may be reasonable despite the restraint it effects. Even if Panhandle did not originally offer the step-down provisions in exchange for the “sole supplier” obligation, as FERC maintains, under present market conditions those provisions may now be of such benefit to G schedule customers that it is not unreasonable for Panhandle currently to tie them to the “sole supplier” clause. The present Commission should give additional consideration to this subject on remand.

B. The D-2 Charge

In Opinion No. 265, 38 F.E.R.C. at 61,452-53, the Commission ordered Panhandle to adopt the MFV rate design approved in Texas Eastern Transmission Corp., 32 F.E.R.C. ¶ 61,056, modifying 30 F.E.R.C. 1161,144 (1985). Although the MFV method is complicated (see supra section I.B), its key change for present purposes may be expressed simply: a pipeline must shift certain fixed costs from the commodity component to a two-part demand component in order to make recovery more dependent on its ability to compete in the market-place. Texas Eastern, 32 F.E. R.C. at 61,149-53; 30 F.E.R.C. at 61,282-84. The first demand charge (D-l) is intended to enable a pipeline to recover 50% of its demand costs based on a customer’s contract demand (i.e., entitlement to receive gas service on any given day); the D-2 charge seeks to ensure recovery of the remaining 50% based on a customer’s maximum annual service entitlement. See Texas Eastern, 32 F.E.R.C. at 61,149, 61,152-54; see also Opinion No. 265, 38 F.E.R.C. at 61,452-53. Acknowledging that the D-2 billing determinant used here — customers’ yearly service entitlements set forth in their contracts with Panhandle — might be based on historical figures that did not accurately reflect current needs, FERC urged affected customers to

renegotiate their contracts ... to include realistic reservations of the amount of annual service to be provided. If [they] are unable to reach a satisfactory resolution with [the pipeline] they should so inform us. We will then determine what, if any, adjustments should be made to the contracts.

Opinion No. 265, 38 F.E.R.C. at 61,453 (quoting Texas Eastern, 32 F.E.R.C. at 61,-154).

In Opinion No. 265-A, however, the Commission ruled that the D-2 charge should be based not on renegotiated annual entitlement ceilings, but rather on a customer’s unilateral renominations; FERC required Panhandle “to accept any level nominated ... that is equal to or less than the level which would be reached if the customer took its existing contract demand every day.” 40 F.E.R.C. at 61,596-97. The Commission justified this change by noting that “Panhandle has no procedures in its tariffs for making changes to the D-2 level” and asserting that independent customer reno-minations were “consistent with” Columbia Gas Transmission Corp., 37 F.E.R.C. ¶ 61,068 (1986), reh’g granted in part, 38 F.E.R.C. ¶ 61,342 (1987). Opinion No. 265-A, 40 F.E.R.C. at 61,596. FERC also concluded that a customer’s deliberate undern-omination of its actual annual needs (to reduce its D-2 charges) would be deterred by allowing Panhandle to impose “substantial” overrun penalty charges. Id. at 61,597 & n. 17 (citing ANR Pipeline Co., 37 F.E.R.C. ¶ 61,263, at 61,747 (1986)).

In its November 4, 1987 order on rehearing, the Commission reiterated this rationale, and added that

the renomination of billing determinants may affect the rate the customer pays, but will not affect Panhandle’s service obligation.... [T~]he pipeline still [must ] stand ready to serve its customers at the certificated level regardless of the change in entitlements. The only consequence [is] a possible increase in rates due to penalties for taking above the entitlement.

41 F.E.R.C. at 61,307 (emphasis added) (citing Columbia Gas, 37 F.E.R.C. 11 61,068).

On appeal, Panhandle does not seriously dispute FERC’s authority to command adoption of the MFV rate design and use of a two-part demand charge. We have previously upheld the Commission’s determination that this new methodology was necessary to help pipelines cope with an increasingly competitive environment. See East Tenn. Natural Gas Co. v. FERC, 863 F.2d 932, 939 (D.C.Cir.1988) (FERC’s policy judgment that MFV method would promote competitiveness among pipelines by placing certain fixed costs at risk was “well within its discretion”); see also Texas Eastern, 32 F.E.R.C. at 61,149-52 (explaining why MFV procedure would replace traditional method of cost classification, allocation, and rate design formulated in Atlantic Seaboard Corp., 11 F.P.C. 43 (1952), and method of distributing cost responsibility outlined in United Gas Pipe Line Co., 50 F.P.C. 1348 (1973), reh’g denied, 51 F.P.C. 1014 (1974), aff'd sub nom. Consolidated Gas Supply Corp. v. FPC, 520 F.2d 1176 (D.C.Cir.1975)).

Rather, Panhandle argues that FERC failed to provide an adequate rationale for changing the basis of the D-2 charge from renegotiated contractual entitlements (Opinion No. 265) to customers’ unilateral nominations (Opinion No. 265-A). Indeed, Panhandle asserts that the latter procedure, coupled with the Commission’s November 4 order requiring the pipeline to continue providing customers with the full certificated service level regardless of the amount each customer nominates, is indefensible because it undercuts Texas Eastern’s rationale for D-2 charges.

In Texas Eastern, FERC justified the new two-part demand charge on two grounds. First, creating a separate demand component would mitigate the cost-shifting from high to low load factor customers that resulted from adoption of the MFV rate design, which reduced the fixed costs to be recovered through the commodity charge and increased those to be recouped through the demand charge. 32 F.E.R.C. at 61,152.

Second, the demand charge would enable a pipeline to recover the costs both of building facilities adequate to provide service during peak demand periods and of acquiring gas supplies sufficient to meet overall consumer demand. Id. Although the latter “sales service” function had become increasingly important because demand had replaced capacity as the principal market constraint, the Commission noted that pipelines persisted in obtaining gas supplies based on customers’ reservations of the amount of service they desired, rather than on actual market demand. Id. at 61,152-53. In FERC’s view, the D-2 charge would rectify this situation: it would recognize that pipelines incur costs when customers reserve the right to receive a specified amount of service, and it would give customers the incentive to make realistic reservations by tying their D-2 payment rate explicitly to the amount of service they reserved. Id.

Thus, in Texas Eastern the Commission concluded that the determinants used to allocate costs in the D-2 charge should reflect a customer’s reservations; conversely, a customer’s right to receive service should be limited to those amounts. Id. at 61,153. The determinants would initially be established by using a customer’s historical maximum annual entitlement. Where this figure no longer reflected the amount of service desired, however, FERC instructed customers to renegotiate their contracts with the pipeline to include accurate reservations of service, with intractable disputes referred to the Commission for final resolution. Id. at 61,153-54.

Panhandle argues that FERC’s orders here contradict Texas Eastern because customers lack any incentive to make realistic reservations of annual service: the amount of service they nominate unilaterally does not constitute the limit they may receive; rather, customers retain the right to take the quantity of annual service set forth in Panhandle’s certificate, without paying for this security. Panhandle claims that its customers (especially those with alternative suppliers) will deliberately undernominate in order to lower their demand charges, thereby shifting fixed costs to “full requirements” customers.

We conclude that the Commission properly exercised its discretion in resolving the D-2 charge issue in Opinions No. 265 and No. 265-A, but erred in its November 4, 1987 order on rehearing. In its first two opinions, FERC simply chose different means to achieve the same legitimate objective: to induce Panhandle’s customers to make accurate reservations. Panhandle apparently concedes that the Commission’s use of the Texas Eastern method of determining D-2 charges by reference to annual entitlements, as in Opinion No. 265, would have been appropriate. Panhandle cites nothing in Texas Eastern, however, to suggest that FERC bound itself to use this procedure in every succeeding case. Rather, the Commission had the discretion in Opinion No. 265-A to choose the Columbia Gas procedure based on customers’ unilateral nominations. See Columbia Gas, 38 F.E.R.C. at 62,076 (approving customer’s unilateral nominations of seasonal entitlements).

Furthermore, FERC could properly rely on overrun penalties to protect against customers’ deliberate under-estimation of their actual service needs. See ANR Pipeline Co., 37 F.E.R.C. 61,263, at 61,747 (1986). Panhandle argues that the penalty charge, which is the sum of the commodity rate plus the unit charges of the two demand components calculated at a 100% load factor rate, will be an ineffective deterrent because it represents the ordinary per unit cost that a firm sales customer would incur if it used its full entitlement. As the Commission stated in its November 4 order, however, this excess charge has proven useful in other proceedings because it “effectively imposes the D-l charge twice on any customer taking more than its D-2 nominated level.” 41 F.E.R.C. at 61,308. Moreover, in the event Panhandle could later demonstrate that the overrun penalty was not preventing abusive undernomina-tions by its customers, Panhandle could propose a higher charge. Id.

In short, we conclude that although FERC could have based the D-2 charges on renegotiated entitlements, as it did in Texas Eastern and Opinion No. 265, the Commission had the discretion to devise a system featuring unilateral customer specifications with overrun penalties for undern-ominations, as in Opinion No. 265-A. The agency did not depart from its Texas Eastern policy of ensuring realistic reservations merely by determining that a different method would better effectuate that policy in this particular case.

The Commission erred, however, in its November 4, 1987 order by allowing customers to specify unilaterally their annual demand, while simultaneously requiring Panhandle to stand ready to provide each customer with its full requirements at the certificated level, even where this is higher than the renominated level. 41 F.E.R.C. at 61,307. This requirement unreasonably whipsaws Panhandle and totally vitiates FERC’s repeated rationale that Panhandle remains free to protect itself through cost-cutting and other measures to attract additional customers. See, e.g., Opinion No. 265, 38 F.E.R.C. at 61,455-56, 61,470; Opinion No. 265-A, 40 F.E.R.C. at 61,598. If a pipeline must set aside an amount of gas equal to the difference between the customer-nominated and certificated levels, it obviously cannot prudently offer this same gas for sale to third parties. See Texas Eastern, 32 F.E.R.C. at 61,152-53 (D-2 charge acknowledges that pipelines incur costs by agreeing to provide a certain quantity of service to customers).

Neither of the Commission’s two justifications offered in support of this requirement withstands scrutiny. First, FERC’s argument that the penalty for under-nomination will discourage customer abuse is simply irrelevant to the issue of the reasonableness of forcing Panhandle to freeze a portion of its gas supply while receiving no corresponding economic benefit. Moreover, even assuming that the threat of penalties will result in a customer’s nomination approximating its actual use, if that use happens to fall below the certificated level, the Commission’s November 4, 1987 order indicates that the pipeline must hold excess capacity available to meet the customer’s contingent future needs at no cost to the customer. This cannot be reconciled with the free market principles reflected in Texas Eastern. If a customer miscalculates actual needs and has not paid for the availability of standby reserves, it must be prepared to bear the risk and cost of looking to the marketplace for additional supplies.

Second, the Commission relied on Columbia Gas, 38 F.E.R.C. ¶ 61,342 (1987). That case, however, involved a unique arrangement whereby a pipeline sought to reduce a large portion of its annual service obligation by imposing seasonal gas entitlement limits on each customer: if a customer purchased gas at its ordinary load factor over the course of the year, it would exceed these seasonal limitations and be subject to penalties. FERC concluded that the pipeline’s tactics did not constitute a partial abandonment of service because the pipeline remained obligated to serve customers at existing certificated levels, notwithstanding the change to seasonal entitlements at levels below existing contract demand for 365 days. Id. at 62,076. The only consequence, said the agency, was that a customer might pay increased charges due to the penalty provision. Nonetheless, as the pipeline had imposed seasonal limitations in a tariff that was being challenged as unjust and unreasonable, the Commission would allow customers to unilaterally renominate seasonal entitlements. Id.

Reading Columbia Gas in its factual context indicates that FERC was attempting to prevent a pipeline from using the “seasonal limitations” device to shirk its duty to provide its customers with the certificated level of annual service. To the extent that Columbia Gas suggests that a pipeline must always stand ready to serve a customer at the certificated level — even where this quantity exceeds the customer’s renominated level of service used to calculate D-2 charges — we reject it.

In conclusion, although the Commission’s disposition of the D-2 charge issue in Opinions No. 265 and No. 265-A represented permissible exercises of FERC’s discretion, we reject as unreasonable the Commission’s subsequent decision to require Panhandle to serve its customers at the certificated level regardless of the customers’ unilateral changes in their entitlements. We therefore remand the demand charge issue for further consideration.

C. The Minimum Commodity Bill

FERC adopted the ALJ’s findings and ruling on elimination of Panhandle’s minimum commodity bill. The AU declared the minimum bill “anticompetitive,” reasoning that “it discourages partial requirements customers from taking advantage of offers of lower priced gas from competing suppliers” and thus would “block price signals from getting to producers.” Opinion No. 265, 38 F.E.R.C. at 61,-455. The Commission explicitly embraced the following explanation from the AU’s decision: the MFV method placed certain elements of Panhandle’s fixed costs (return on equity, associated taxes, and production-related costs) in Panhandle’s commodity component “in the expectation that leaving Panhandle’s return at risk would give Panhandle incentives to lower gas costs so that it could maximize sales and thereby earn its allowed return”; “to turn around and allow Panhandle assured recovery of these same fixed costs via a minimum bill would defeat the purposes of the MFV method.” Opinion No. 265, 38 F.E.R.C. at 61,455. FERC accordingly concluded that the MFV method was discordant with minimum commodity bills, id., and correspondingly adjudged Panhandle’s minimum bills to be unjust and unreasonable. Opinion No. 265-A, 40 F.E.R.C. at 61,597.

This court, in East Tennessee, 863 F.2d at 937-38 & n. 9, acknowledged that FERC retains the ultimate burden of proving an existing minimum bill unlawful; we held, however, that the Commission could (1) reasonably conclude that minimum bills are anticompetitive and therefore prima facie unlawful, and accordingly (2) shift to the pipeline the burden of producing evidence that the minimum bill at issue meets at least one of the three remedial justifications set out in Atlantic Seaboard Corp., 38 F.P.C. 91 (1967), aff'd, 404 F.2d 1268 (D.C.Cir.1968). See Tennessee Gas Pipeline Co. v. FERC, 871 F.2d 1099, 1104 (D.C.Cir.1989). Atlantic Seaboard, 38 F.P.C. at 95, recognized that a minimum bill could rectify (1) the inadequate recovery of fixed costs; (2) the excessive shifting of costs to customers with no alternative supply; or (3) the inadequate recovery of take-or-pay obligations. A particular minimum bill may be justified if “specifically designed to achieve [one of the stated remedial ends], but nothing more.” Mississippi River Transmission Corp. v. FERC, 759 F.2d 945, 950 (D.C.Cir.1985). In this case, FERC rejected arguments based on each of the three Atlantic Seaboard justifications. Panhandle, in its challenges to FERC’s orders before this court, presses arguments only as to the first two justifications.

Concerning the first Atlantic Seaboard justification, the one based on inadequate recovery of fixed costs, the Commission stated: “Under the MFV method, the pipeline is assured recovery of all fixed costs for which a guarantee of recovery is appropriate through the demand component. A minimum bill, therefore, is unneces-sary_” Opinion No. 265-A, 40 F.E.R.C. at 61,598. This court, in East Tennessee, accepted the Commission’s logic: “FERC’s adoption of an ‘incentive theory,’ that exposure of the fixed costs attributable to a return on equity will improve the competitiveness of the natural gas industry, is a judgment well within its discretion in deciding what is a just and reasonable rate.” 863 F.2d at 939; see Tennessee Gas, 871 F.2d at 1104.

Panhandle argues, however, that the underlying rationale for putting recovery at risk does not apply to certain of its fixed costs. In particular, Panhandle maintains that FERC may place costs relating to gathering facilities at risk when such facilities are exempted from FERC jurisdiction and thus are not subject to FERC’s prior review in a certificate proceeding. Final Brief for Petitioner, Panhandle Eastern Pipe Line Company at 42-43. But Panhandle’s gathering facilities were subject to FERC’s prior review and certification, the pipeline alleges; thus there is no need to put recovery of these costs at risk to ensure prudent investment. FERC’s limited ability to check investments in production and gathering facilities, however, was merely a secondary factor in support of the Commission’s “long-standing policy of classifying all production and gathering costs to the commodity component”; the classification follows primarily from “the nexus between costs related to gas purchased and gas produced.” AU Decision, 32 F.E.R.C. at 65,285 (“production and gathering costs are directly related to the annual volumes of gas produced and sold”). That is, because gathering lines and other facilities associated with production are so closely related to the purchasing of gas from producers, the fixed costs attributable to these facilities should be classified as commodity costs just as purchased gas costs are so classified. See Texas Eastern, 30 F.E.R.C. at 61,269 (“the close nexus continues to exist between all costs related to purchased and produced gas and the commodity cost of gas itself”). FERC therefore properly rejected Panhandle’s arguments regarding the recovery of fixed costs.

As to the second Atlantic Seaboard justification, Panhandle maintained that it “will lose partial requirements customers, and the fixed costs that those customers would have paid will be shifted to full requirements customers”; FERC rejected these objections because they “assume that Panhandle will not take the steps necessary to keep its gas prices competitive.” Opinion No. 265, 38 F.E.R.C. at 61,455. “The record,” the Commission said, “supports the contrary conclusion, i.e., that the elimination of minimum bills will have the desired effeets[;] [t]he record fails to show that the load swings are likely as a consequence of the elimination of minimum bills.” Id. at 61,455-56 (footnotes omitted); accord Opinion No. 265-A, 40 F.E.R.C. at 61,598.

Panhandle asserts that FERC unreasonably “assumes that reductions in gas costs lead ineluctably to increased sales”; yet since 1982, even while Panhandle has reduced its costs, its sales have dropped. Final Brief for Petitioner, Panhandle Eastern Pipe Line Company at 44. The Commission, however, surely does not claim that its policies will, or indeed should, protect pipeline profits regardless of all exogenous market conditions. A drop in market demand, the Commission no doubt appreciates, may cause sales to drop even as costs fall; it suffices for FERC’s “incentive theory,” however, that lower costs lead to increased sales all other things being equal. Such assumptions are the type of “reasonable economic propositions” accepted in East Tennessee, 863 F.2d at 939-40, and in Associated Gas Distributors, 824 F.2d at 1008-09 (“Agencies do not need to conduct experiments in order to rely on ... predictions that competition will normally lead to lower prices.”).

Panhandle’s objection, FERC reiterated, assumes that "the fixed costs which are at risk in the minimum bill will necessarily be recovered from somebody.” Opinion No. 265, 38 F.E.R.C. at 61,456. “There is no reason to assume that the Commission will guarantee recovery of those costs [from remaining customers] in the event that the pipeline loses partial requirements customers. Indeed, if recovery ... were guaranteed, the Commission’s intention that these costs be at risk would be defeated....” Id. (footnote omitted). Under East Tennessee, 863 F.2d at 940, FERC’s arguments are “reasonable [ones] for rejecting the second Seaboard justification.”

In sum, Panhandle has failed to produce sufficient evidence to rebut FERC’s prima facie case. See Mississippi River, 759 F.2d at 954-55; Tennessee Gas, 871 F.2d at 1105. Here, as in East Tennessee, 863 F.2d at 940, this court owes deference to FERC’s regulatory expertise, reflected in its “prediction that, faced with the need to compete more effectively in order to recover its costs, [the pipeline] will take steps to reduce costs to attract new customers or retain its present ones,” bringing “benefits to all customers.” FERC’s predictions in this regard go to Panhandle’s claims on both the first and second Atlantic Seaboard justifications. The Commission’s position is adequately grounded; Panhandle has not provided persuasive evidence to show inadequate allowance of fixed cost recovery or excessive “cost-shifting” from “partial requirements” to “full requirements” customers.

D. The Imputed Load Factor for SG Customers

Municipal Defense Group (MDG) challenges, as arbitrary, capricious, and an abuse of discretion, FERC’s decision to set the imputed load factor for SG customers of Panhandle at 52.5%. MDG comprises a number of municipal utilities that buy from Panhandle and act as local distribution companies. The utilities that compose MDG pay only a one-part volumetric rate, with demand costs converted from a fixed charge to a volumetric charge using an imputed load factor. ALJ Decision, 32 F.E. R.C. at 65,300. The higher the imputed load factor, the lower the volumetric rate. These small customers historically have had a 52.5% imputed load factor, even though their actual load factor was lower. FERC has granted SG customers special treatment because they often “lack the flexibility to construct storage and lack industrial load to better balance their purchases,” Texas Eastern, 30 F.E.R.C. at 60,-288, and because they serve the distinct function of delivering gas primarily to residential and light commercial users. Third Initial Decision, Tennessee Gas Pipeline Co., 27 F.E.R.C. ¶ 63,090, at 65,375 (1984). The imputed load factor mitigates the disparity in unit costs between the SG customers and larger, more flexible customers.

When the MFV methodology replaced the prior, so-called United methodology in Panhandle's rates, SG customers incurred a heavier increase in costs than larger customers with higher load factors, because the MFV methodology placed more costs in the demand portion of the rate. AU Decision, 32 F.E.R.C. at 65,300. Reasoning that SG customers are “least able to absorb a major shift in cost responsibility, because they are less able than other customers to expand their loads,” the AU applied the principle that “the SG customers should bear approximately the same proportion of total costs as was borne by them under the previous methodology.” Id. (citing Opinion No. 269, 13 F.P.C. at 110). Following the staff recommendation, the AU determined that a 65% imputed load factor would achieve this result. Id. at 65,301.

FERC rejected the AU’s ruling and retained the 52.5% load factor. Opinion No. 265, 38 F.E.R.C. at 61,454. The Commission featured two precedents. In Transcontinental Gas Pipe Line Corp., 37 F.E.R.C. ¶ 61,328 (1986), FERC had reduced a 100% imputed load factor for a class of small customers to 80%, because “the 80 percent load factor [was] closer to the 46 percent actual load factor of the small customers in that case.” Opinion No. 265, 38 F.E.R.C. at 61,454. Earlier, in Texas Eastern, FERC had reduced the imputed load factor from 50% to 35% upon finding “no economic justification to require that [the] larger customers continue to subsidize the SGS rate schedule at the higher level.” In this case, FERC observed: “[T]he actual load factor for SG customers is 29.3 percent. The existing 52.5 percent load factor is closer to 29.3 percent than the proposed 65 percent load factor.” Opinion No. 265, 38 F.E.R.C. at 61,454. The Commission recapitulated:

[T]he two-part demand mechanism of the MFV (which we have adopted here) sufficiently protects low load factor customers against cost shifting. In other words, we do not believe that cost shifting is a valid complaint.... [W]e find no “economic justification” here for allowing subsidization at any level higher than 52.5 percent.

Opinion No. 265-A, 40 F.E.R.C. at 61,597 (footnote omitted) (quoting Texas Eastern, 30 F.E.R.C. at 61,289).

MDG claims that FERC acted arbitrarily because it did not address the AU’s grounds for adopting the 65% figure. Brief of Petitioner Municipal Defense Group at 9, 11. An agency’s “departure from the AU’s findings is vulnerable if it fails to reflect attentive consideration to the AU’s decision.” Citizens State Bank v. FDIC, 718 F.2d 1440, 1444 (8th Cir.1983). In particular, MDG points to the AU’s reference to Opinion No. 269, which purportedly established a principle that the share of total costs borne by SG customers should remain constant despite ratemaking changes. Reply Brief of Petitioner Municipal Defense Group at 6. But see infra note 10. MDG thus invokes this court’s repeated admonition: “An agency’s view of what is in the public interest may change, either with or without a change in circumstances. But an agency changing its course must supply a reasoned analysis indicating that prior policies and standards are being deliberately changed, not casually ignored_” Greater Boston Television Corp. v. FCC, 444 F.2d 841, 852 (D.C.Cir.1970), cert. denied, 403 U.S. 923, 91 S.Ct. 2233, 29 L.Ed.2d 701 (1971).

We may take as given that SG customers will bear a larger portion of total costs under the MFV method with the existing imputed load factor. FERC does not dispute this factual finding by the ALJ. Rather, FERC held that the cost-shifting against which MDG complained was not unfair, because SG customers still retained a substantial subsidy.

Assuming arguendo that the AU’s interpretation of Opinion No. 269 was correct, and that as a general matter SG customers should bear the same share of total costs despite ratemaking changes, the precedents cited in FERC’s orders nevertheless reveal that FERC has exercised authority, in particular cases, to reject as excessive an existing imputed load factor. Although FERC’s explanation in this case was skeletal, the Commission rested on agency adjudications, Transcontinental and Texas Eastern, which indicate that large subsidies of the type here at issue lack “economic justification” and have been reduced in the past when appraised by the Commission as unreasonable. In Texas Eastern, 30 F.E.R.C. at 61,288, FERC recognized that proponents of the reduction in question were urging a break from past practice, and the Commission acknowledged the modification it was ordering: “[E]ven though the SGS customers have historically been granted special treatment because of their small size, [that treatment] should no longer be allowed to operate to the detriment of other customers.” The appropriate size of the subsidy falls within the domain of FERC’s expert judgment in deciding what rates are reasonable.

Once it is seen that FERC retains discretion to reduce existing imputed load factors on the ground that they are excessive, it follows that the Commission may refuse to increase the existing imputed load factor on the same ground, despite cost-shifting effects of a change in rate design. SG customers are not entitled to a permanently guaranteed subsidy level and therefore are not entitled to complete and unconditional protection against cost-shifting. Consequently, we affirm FERC’s judgment on this issue.

E. The Effective Date of FERC’s Order

The final issue concerns FERC’s choice of an August 19, 1987 effective date for its orders, based on its interpretation of the parties’ settlement agreement.

1. Standard of Review

The Commission’s construction of contract language is entitled to judicial deference both because “Congress explicitly delegated to FERC broad powers over rate-making, including the power to analyze contracts,” and because the Commission has superior technical expertise. Tarpon Transmission Co. v. FERC, 860 F.2d 439, 441-42 (D.C.Cir.1988) (citing National Fuel Gas Supply Corp. v. FERC, 811 F.2d 1563, 1569-70 (D.C.Cir.), cert. denied, 484 U.S. 869, 108 S.Ct. 200, 98 L.Ed.2d 151 (1987)). Nonetheless, courts continue to play a “vital role” in ensuring that FERC’s contract interpretations are “amply supported both factually and legally.” Id. at 442 (quoting Vermont Dep’t of Pub. Serv. v. FERC, 817 F.2d 127, 134 (D.C.Cir.1987)). The agency’s determination must reflect reasoned deci-sionmaking that has adequate support in the record and must include an “understandable” agency analysis and rationale. Id. at 442 (citations omitted).

In this case, our remand on the “sole supplier” and D-2 issues narrows the scope of our review to the Commission’s choice of an effective date for the elimination of Panhandle’s minimum bill.

2. The Settlement Agreement

On December 14, 1983, Panhandle filed with FERC a “Stipulation and Agreement” it had reached with its customers. Article 11, entitled “Disposition of Issues,” is most relevant to the effective date question. Part 1 of Article II governs “Rates and Charges” and contains five key paragraphs. Paragraph A provides that Panhandle’s customers forfeit any claims to refunds retroactive to October 1, 1982 (the date the new rates proposed by Panhandle originally took effect, subject to refund):

With respect to Panhandle’s jurisdictional sales and services for the period October 1, 1982 through September 30, 1983, the rates set forth [in Appendices A and C to the Agreement] shall be applicable.

Paragraph B states:

With respect to ... sales and services for the period commencing October 1, 1983 until a Commission order concerning cost' classification, cost allocation, and rate design (including minimum bill) in this proceeding becomes effective, ... the rates set forth in [Appendices B, C, and D] shall be applicable; and the tariff provisions then in effect shall not be modified except to the extent required in settlements of [certain listed] complaint proceedings ....

Paragraphs C, D, and E specify the mechanisms for determining how and when changes in Panhandle’s rates and tariffs will be implemented, depending on the timing of the Commission order referred to in Paragraph B. First, Paragraph C provides that if the order becomes effective before the date a new Panhandle rate filing supersedes the rates contained in the Agreement’s appendices, any modifications specified in the order will be self-executing, applying “only prospectively from and after the first day of the month following such effective date.” Second, Paragraph D provides that if the order becomes effective within one year following the date that a new Panhandle rate filing supersedes the Agreement’s rates, the new tariffs will “be revised prospectively as necessary and appropriate to reflect the rulings in the ... order.” Third, Paragraph E provides that if the order is issued one year or more after the date of the superseding rate filing, then within forty-five days

any party may move for consideration of whether or not the tariff sheets then in effect should be revised prospectively as necessary and appropriate to reflect [the order,] and the Commission shall consider such motion.

Part 4 of Article II reserved four issues for resolution in the instant proceedings— cost classification, cost allocation, rate design (including minimum bill matters), and the “sole supplier” issue — “subject to the condition that any changes may be made effective only prospectively from and after a Commission order disposing of these issues” (emphasis added).

FERC approved the Agreement on March 19, 1984. 26 F.E.R.C. 1161,342, reh’g granted, 27 F.E.R.C. 1161,233 (1984).

3. The Commission’s Rulings

In Opinion No. 265, 38 F.E.R.C. 1161,164 (1987), the Commission failed to mention any effective date for the changes it ordered in Panhandle’s rates regarding cost classification, cost allocation, and rate design (including minimum bill). In upholding CILCO’s complaint seeking elimination of the “sole supplier” provision, the agency declared: “[W]e shall require that Panhandle’s tariff be modified prospectively from the effective date of this order” (i.e., February 20, 1987). Id. at 61,470. In the same opinion, however, FERC directed Panhandle to file a revised tariff (and any necessary amendments to its rate schedules) within forty-five days of the date the opinion issued, but provided that if applications for rehearing were still pending at that time, Panhandle’s submission “shall be made thirty days from the date of the Commission’s final disposition of applications for rehearing.” Id. at 61,472.

In Opinion No. 265-A, 40 F.E.R.C. ¶ 61,189 (1987), FERC considered a request for clarification by Michigan Consolidated Gas Company (MichCon) and a related motion by East Ohio Gas Company (East Ohio). These companies believed that the Commission’s order to eliminate Panhandle’s minimum bills took effect on February 20, 1987 (the date of Opinion No. 265) because, under 18 C.F.R. § 385.2007(c), FERC orders are effective on the date they issue unless the Commission directs otherwise. 40 F.E.R.C. at 61,599. East Ohio advanced two other arguments in support of a February 20 effective date. Id. First, Opinion No. 265 remained in force because no stay had been sought or granted; filing an application for rehearing did not stay the order under section 19(c) of the NGA, 15 U.S.C. § 717r(c). Second, Paragraph E of Article II, Part 1 of the Agreement mandated revision of tariff sheets upon issuance of any “Commission order concerning ... minimum bills,” not upon an order on rehearing.

Disputing this interpretation, Panhandle claimed that the effective date would occur when its rates were “fixed” within the meaning of Electrical District No. 1 v. FERC, 774 F.2d 490 (D.C.Cir.1985) — i.e., when FERC accepted Panhandle’s new rate filing that the pipeline was obliged, under Opinion No. 265, 38 F.E.R.C. at 61,472, to submit within thirty days of the date that the Commission disposed of all rehearing applications. Panhandle argued that Electrical District was consistent with Paragraph E, which also provided for a motion for prospective revision of tariff sheets after issuance of an order. See 41 F.E.R.C. at 61,309.

FERC denied MichCon and East Ohio’s motions and also rejected Panhandle’s argument. Instead, it concluded:

Electrical District No. 1 does not apply here because the settlement [agreement] is controlling. Specifically, Article II, Part 4.A provides that any changes to Panhandle’s tariffs, including minimum bill matters, be made effective “prospectively from and after a Commission order disposing of [the] issues_” [W]e interpret the provision to mean from the date the rehearing order is issued. We believe our interpretation best reflects the intent of the parties.

Opinion No. 265-A, 40 F.E.R.C. at 61,599. Accordingly, FERC ordered that “[elimination of the minimum bills takes effect upon the date this order on rehearing issues” (i.e., August 19, 1987). Id. at 61,601.

On November 4, 1987, the Commission reaffirmed Opinion No. 265-A. See 41 F.E. R.C. tí 61,125. FERC declared that Part 4.A of Article II, which establishes the effective date as the date of a Commission order “disposing of the issues,” could reasonably be construed as referring to an order on rehearing because “effectiveness and imposition of a remedy before final disposition would be interlocutory and would not ‘dispose of the issues if the order is subject to change.” Id. at 61,309. FERC deemed Panhandle’s reliance on Paragraph E “misplaced” because that provision did not set an effective date, and the agency accordingly rejected Panhandle’s attempt to invoke Paragraph E to trigger application of Electrical District. Id.

Denying further rehearing, the agency rejected the argument that it had modified the date without request by any party on the grounds that it has the power to modify its orders sua sponte. 42 F.E.R.C. ¶ 61,038, at 61,242 (1988). The Commission also summarily disposed of one petitioner’s claim that FERC only had the statutory authority to prescribe as an effective date “the issuance date of an order approving a utility’s compliance filing” (i.e., December 31, 1987). Id.

4. Analysis

All parties agree on two points. First, the settlement agreement was designed to ensure an effective date for prospective changes in Panhandle’s rates resulting from a Commission order concerning the reserved issues. Second, this date falls sometime in 1987. The dispute centers on which of the three FERC orders provides the effective date.

On appeal, the Commission defends its choice of August 19 (the date of Opinion No. 265-A denying rehearing). Various petitioners reject this date, but suggest two different substitutes — February 20 (the date of Opinion No. 265) or December 31 (the date FERC accepted Panhandle’s compliance filing). The latter claim, raised by Quantum Chemical Corporation, challenges the Commission’s very authority to impose an August effective date — not merely its contractual interpretation — and must therefore be considered first.

a. December Effective Date

Section 5(a) of the NGA provides that whenever, after a hearing, the Commission finds that a rate is unjust and unreasonable, it “shall fix ... by order” the rate determined to be “just and reasonable.” 15 U.S.C. § 717d(a). Construing a Federal Power Act section that contained language virtually identical to that in section 5(a), we held in Electrical District, 774 F.2d at 492-95, that FERC “fixes” a new rate on the date it approves a gas company’s compliance filing that specifies its exact rates — not on the date of an earlier Commission opinion describing the legal and accounting principles to be used in calculating the new rates.

Quantum maintains that FERC imposed prospective changes in Panhandle’s rate structure after a section 5 ratemaking proceeding (rather than simply approving the pipeline’s proposed rates), and thus Electrical District dictates an effective date of December 31, when the Commission accepted Panhandle’s new rates filed in compliance with FERC’s decision. In Quantum’s view, the Commission lacked the statutory authority to prescribe an earlier date.

FERC distinguishes Electrical District on the ground that the parties in that case had not executed a settlement agreement that would determine when the agency’s orders would take effect. According to the Commission, such an agreement, not Electrical District, controls the effective date issue, as held in Public Service Co. v. FERC, 851 F.2d 1548, 1556-57 (5th Cir.1988). See Opinion No. 265-A, 40 F.E.R.C. at 61,599.

Quantum responds that Public Service does not apply for two reasons. First, it contrasts the contract in Public Service — which referred specifically to the date of a FERC order requiring changes in ratemaking “methods and principles” (i.e., the initial decision), see 851 F.2d at 1556-57 — with the Agreement here, which focuses on the “Commission order disposing of [the] issues” (i.e., the date FERC “fixed” Panhandle’s rates by accepting the compliance filing per section 5). This argument, however, rests on the unfounded assumption that the parties intended the “disposing of” language to refer to a Commission order approving a compliance filing.

Second, Quantum asserts that a settlement document must clearly express the parties’ intent to waive their section 5 rights by establishing an exact effective date for ratemaking changes. As the Agreement does not identify which “Commission order disposing of [the reserved] issues” will provide the effective date, Quantum concludes that the date of FERC’s order accepting Panhandle’s compliance filing must be used.

Quantum, however, provides inadequate support for its theory. The Agreement addressed the effective date precisely because the parties wished to avoid the necessity of an independent Commission decision on this issue, which would have been unpredictable given certain legal uncertainties that existed in the early 1980’s. In particular, Panhandle sought assurance that any rate changes resulting from a FERC order would be prospective rather than retroactive, as would ordinarily be the case if the agency found a rate unreasonable. The Commission approved this settlement. Under these circumstances, a reviewing court’s role is to determine whether FERC’s choice of an August 19 effective date rests on a reasonable construction of the contract, not to discard the Agreement altogether by imposing a December 31 date.

b. February vs. August Effective Date

Article II, Part 4 of the Agreement provides that any changes in Panhandle’s rates resulting from a Commission decision on the four reserved issues (including minimum bills) “may be made effective only prospectively from and after a Commission order disposing of these issues.” FERC reiterates its position that this language may reasonably be construed as referring to a final decision “disposing of” such questions on the merits (i.e., the August 19 order on rehearing). Cf. Public Service, 851 F.2d at 1557 (FERC reasonably concluded that parties intended effective date of “Commission order” to refer to final disposition of issues settled on rehearing, absent clear language to contrary) (citing with approval Panhandle Eastern Pipe Line Co., 41 F.E.R.C. ¶ 61,018 (1987)).

MichCon assails FERC for focusing exclusively on the general statement in Part 4 while ignoring the specific provisions of Part 1, which describe the implementation of rate changes resulting from “a Commission order concerning Panhandle’s cost classification, cost allocation and rate design.” Paragraphs C through E explain the different consequences that would flow depending on whether FERC’s order concerning these reserved issues became effective before or within one year of the date Panhandle filed a rate that superseded the rate contained in the Agreement, or whether such order was issued over a year thereafter.

As Panhandle filed superseding rates in August 1985, more than one year before the issuance of FERC’s 1987 order on the reserved matters, Paragraph E applies:

Within 45 days following issuance of such Commission order, any party may move for consideration of whether or not the tariff sheets ... should be revised prospectively as necessary ... and the Commission shall consider such motion.

Pursuant to Paragraph E, three days after Opinion No. 265 was published East Ohio moved to revise Panhandle’s tariff by eliminating the minimum bill provisions. FERC resolved this petition, as well as MichCon’s request for clarification filed March 23, through the issuance, on August 19, 1987, of Opinion No. 265-A.

On appeal, these two companies reiterate their argument that, under the terms of the Agreement, once the Commission published its decision concerning the reserved issues, it took effect immediately, and not at the time the Commission chose to issue an order on rehearing.

We find that Paragraph E does not require FERC’s orders to be effective upon issuance; but rather, it directs the agency to consider motions to revise tariff sheets — a task the Commission discharged within a reasonable time period. Indeed, Part 1 (which contains IIE) was designed not to establish an effective date, but to focus on the different scenarios that would result from the timing of FERC’s issuance of an order on the reserved issues, whatever its effective date.

Thus, the contract’s overall structure indicates that the Commission correctly concentrated on Part 4, which was intended to set the effective date. This conclusion is reinforced by contrasting the language of Part 1, describing a FERC order “concerning ” the cost and rate design issues (which could refer to any agency order on the merits) with Part 4’s reference to an order “disposing of” the issues (which suggests finality). Even if we assume that the parties employed the words “concerning” and “disposing” interchangeably, as some petitioners assert, the agency could place emphasis on either term. As the controlling Part 4 uses “disposing,” the Commission reasonably focused on this term and construed it sensibly.

Petitioners’ second textual argument is that if the parties had intended to make decisions effective upon the date of a rehearing order, they would have done so explicitly, as they did elsewhere in the Agreement. See, e.g., Article VI, 112 (“the Commission order ... no longer subject to rehearing”); Article XI, II1 (same). Although the cited provisions indicate the parties’ awareness of rehearing orders, these phrases refer to an anticipated FERC order approving the Agreement itself, not to the effective date of rate changes resulting from the Commission’s decision on the reserved issues.

c. Minimum Bill Provisions

The foregoing analysis indicates that FERC’s determination concerning the effective date for elimination of the “minimum bill” provisions must be upheld. Opinion No. 265 did not identify this date. In Opinion No. 265-A, however, the Commission made clear that this elimination would take effect “upon the date this order on rehearing issues” (i.e., August 19). 40 F.E.R.C. at 61,601. In its November 4 order, FERC reaffirmed its ruling in Opinion No. 265-A, id. at 61,599, that an order “disposing of [the] issues” meant an order on rehearing because “effectiveness and imposition of a remedy before final disposition would be interlocutory and would not ‘dispose of’ the issues.” 41 F.E.R.C. at 61,309.

MichCon and East Ohio challenge this conclusion based on their textual analysis of the contract (discussed above at 38-39, 43-44), and reiterate the arguments they advanced below. For example, these companies assert that 18 C.F.R. § 385.2007(c)(1) made the Commission’s order in Opinion No. 265 final and fully effective on the date of issuance (i.e., February 20) because FERC did not direct otherwise; thus, it was not “interlocutory” pending rehearing. They further contend that filing requests for rehearing did not stay the order under the NGA, 15 U.S.C. § 717r(c). They also emphasize that as minimum bills are anticompetitive, unjust, and unreasonable, the Commission should eliminate them at the earliest possible time to avoid saddling customers with demonstrably unfair costs.

While MichCon and East Ohio’s last point has some force as a policy matter, the Agreement alone determines the effective date of FERC’s orders. Although these companies have raised plausible arguments in favor of a February effective date, they have failed to show that the Commission's interpretation of the contract was unreasonable and unsupported, and we must defer to the agency’s construction. Tarpon, 860 F.2d at 441-42. As FERC’s opinions adequately addressed these petitioners’ other contentions based on alleged violations of statutory and regulatory provisions, we affirm its decision on the effective date issue.

III. Conclusion

For the reasons stated in sections II.A and II.B of this opinion, we conclude that the Commission has failed to explain adequately its treatment of (1) the “sole supplier” provision applicable to Panhandle’s G rate schedule customers and (2) the D-2 charge. We therefore remand those issues to FERC for further consideration consistent with this opinion. In all other respects we deny the petitions for review.

It is so ordered. 
      
      . The AU cited specific testimony in support of his determination, AU Decision, 32 F.E.R.C. at 65,309, 65,311, and thereby relied on the type of evidence approved in East Tennessee, 863 F.2d at 938-39.
     
      
      . Observing that "Panhandle’s minimum bill is not tailored” to ensure "that the revenues collected thereunder relate solely to the carrying charges associated with take-or-pay payments,” FERC properly rejected application of the third Atlantic Seaboard justification. Opinion No. 265-A, 40 F.E.R.C. at 61,598. Furthermore, take-or-pay concerns have been addressed by FERC in Order No. 500, 52 Fed.Reg. 30,334 (1987). See Tennessee Gas, 871 F.2d at 1106 (our concern “is relieved by [FERC's] actions in other proceedings," and "we suspect the third Seaboard justification will retain little vitality in the future”).
     
      
      . See also Transwestern Pipeline Co. v. FERC, 820 F.2d 733, 742 (5th Cir.1987) (under the MFV rate design, ”[t]he point of the Commission’s determination was to subject certain fixed costs to market risks,” thereby providing the pipeline “the appropriate incentive to run its business efficiently"; therefore “all the fixed costs which [the pipeline] should recover will be recovered through the demand charge without the imposition of a minimum bill”), cert. denied, - U.S. -, 108 S.Ct. 696, 98 L.Ed.2d 648 (1988).
     
      
      .Nor would FERC's prior review be inconsistent with the broader "incentive theory” that this court accepted in East Tennessee and Tennessee Gas. Furthermore, Panhandle’s argument would suggest that its gathering costs should be allocated to the demand component rather than the commodity component. Panhandle lost on that issue before the AU and does not seek review of that classification decision.
     
      
      . Notably, no customer of Panhandle asks this court to order FERC to reinstate Panhandle’s minimum bills.
     
      
      . The United methodology was first adopted in United Gas, 50 F.P.C. 1348 (1973).
     
      
      . In Transcontinental, FERC stated: "There is evidence in the record that the average annual load factor ... is 46 percent”; nevertheless, the Commission settled upon the 80% figure, stating: "while it is preferable to impute a load factor closer to the actual load factor ..., there is insufficient evidence in the record upon which to base such a decision.” Transcontinental, 37 F.E.R.C. at 61,972.
     
      
      . Texas Eastern, 30 F.E.R.C. at 61,289. FERC arrived at 35% in that case noting that the average load factor was "approximately 27 percent” and that "no SGS customer has a load-factor above 35 percent." Id.
      
     
      
      . As MDG notes, Texas Eastern, 30 F.E.R.C. at 61,289, indicated that the two-part demand mechanism "mitigates,” not eliminates, the cost-shifting adverse to small low-load-factor customers that results from a switch to the MFV methodology. Brief of Petitioner Municipal Defense Group at 11. FERC concluded, however, that mitigation is sufficient and that elimination is not mandated.
     
      
      . Opinion No. 269, 13 F.P.C. 53 (1954), approved a rate structure, including an imputed load factor, that was consistent with the finding: " ‘[T]he differentiation of [General Service] rates between the three zones should be approximately the same differentiation now obtaining in existing rates.'" Id. at 110 (quoting Opinion No. 214, 10 F.P.C. 185, 202 (1951)). Opinion No. 214 refers to the differentiation in rates between geographic zones, however, and does not state that the SG customers’ share of total cost should be maintained. Nor does Opinion No. 269 express such a principle.
      Indeed, the imputed load factor at issue in this case has been maintained through past rate-making changes, despite resulting cost shifts. The 52.5% figure has been used since 1961, when the rate design developed in Atlantic Seaboard, 11 F.P.C. 43 (1952), was applied to Panhandle, and the same figure was continued under the United rate design. Brief for Respondent Federal Energy Regulatory Commission at 48; see Initial Decision, 32 F.E.R.C. at 65,280; Panhandle Eastern Pipe Line Co., 25 F.P.C. 787, 857 (1961). The United method, compared with the Seaboard method, shifted costs from the demand charge to the commodity charge, see AU Decision, 32 F.E.R.C. at 65,273, so that maintaining the same imputed load factor during that change in methodology provided a windfall for SG customers.
     
      
      . MDG also claims that FERC is the proponent of change on this issue, and therefore has the burden of proof. Reply Brief of Petitioner Municipal Defense Group at 8. MDG denies that it seeks to increase its imputed load factor, characterizing the FERC decision as effectively reducing the previous imputed load factor. Id. at 2, 4. MDG, however, bore the burden of proving that the existing 52.5% figure was unjust and unreasonable and that the proposed increase to 65% was just and reasonable. MDG is the party proposing the change, albeit on the ground that adopting the MFV method makes retaining the existing 52.5% figure unfair. FERC carried its burden of showing the MFV method to be lawful; it does not have to show, in addition, that all unchanged provisions remain lawful despite the effects the MFV method may have on them. To impose such an exhaustive obligation on FERC would be inconsistent with the rationale set forth in ANR Pipeline Co. v. FERC, 771 F.2d 507, 514 (D.C.Cir.1985): "by requiring each proposed change to be justified by the proponent of the change, the focus of evidence and hearings will be trained on the provisions in fact in controversy."
     
      
      . As Panhandle filed a restatement of its rates on August 30, 1985 that became effective the next day, the date on which a new Panhandle rate superseded those contained in the Agreement is August 31, 1985. Thus, Paragraph E applies. See 32 F.E.R.C. ¶ 61,436 (1985).
     