opinion: CONSOLIDATED GAS SUPPLY CORPORATION, Petitioner, v. FEDERAL POWER COMMISSION, Respondent, United Gas Pipeline Company, Memphis Light, Gas & Water Division, New Orleans Public Service, Inc., Public Service Commission of the State of New York, Texas Gas Transmission Corporation, Entex, Inc., State of Louisiana and Louisiana Municipal Association, Louisiana Gas Service Co., Intervenors. COLUMBIA GAS TRANSMISSION CORPORATION, Petitioner, v. FEDERAL POWER COMMISSION, Respondent, Memphis Light, Gas & Water Division, United Gas Pipeline Co., the Public Service Commission of the State of New York, Texas Gas Transmission Corporation, Entex, Inc., New Orleans Public Service Inc., the State of Louisiana and Louisiana Municipal Association, Southern Natural Gas Company, Intervenor. MEMPHIS LIGHT, GAS & WATER DIVISION, Petitioner, v. FEDERAL POWER COMMISSION, Respondent, United Gas Pipeline Company, the Public Service Commission of the State of New York, Texas Gas Transmission Corp., Entex, Inc., New Orleans Public Service, Inc., the State of Louisiana and Louisiana Municipal Association, Texas Eastern Transmission Corporation, Laclede Gas Company, Louisiana Gas Service Company, Intervenors. STATE OF LOUISIANA and Louisiana Municipal Association, Petitioner, v. FEDERAL POWER COMMISSION, Respondent, Texas Gas Transmission Corporation, United Gas Pipeline Co., Entex, Inc., Mississippi River Transmission Corporation, Louisiana Gas Service Company, Intervenors. UNITED GAS PIPELINE COMPANY, Petitioner, v. FEDERAL POWER COMMISSION, Respondent, New Orleans Public Service, Inc., Public Service Commission of the State of New York, Entex, Inc., Louisiana Gas Service Company, State of Louisiana and Louisiana Municipal Association, Intervenors.
  Nos. 74-1343, 74-1393, 74-1395, 74-1463, 74-1489.
  United States Court of Appeals, District of Columbia Circuit.
  Argued April 29, 1975.
  Decided Oct. 9, 1975.
  Charles R. Brown, Washington, D. C., of the bar of the Supreme Court of Wisconsin, pro hac vice by special leave of court with whom Norman A. Flaningam, Washington, D. C., George L. Weber, Washington, D. C., Daniel L. Bell, Jr., and Giles D. H. Snyder, Charleston, W. Va., were on the brief, for petitioner in No. 74-1343 and 74-1393.
  Reuben Goldberg, Washington, D. C., with whom George E. Morrow, Memphis, Tenn., was on the brief for petitioner in No. 74-1395 also entered an appearance for intervenor Memphis Light, Gas and Water Division.
  Arnold D. Berkeley, Washington, D. C., with whom David R. Straus, Washington, D. C., was on the brief for petitioners in No. 74-1463, also entered appearances for intervenors State of Louisiana and Louisiana Municipal Assn.
  Stephen A. Wakefield, Washington, D. C. , with whom Robert A. Webb, Alvin M. Owsley, Jr., William B. Cassin, Phillip D. Endom and I. Jay Golub, Houston, Tex., were on the brief for petitioner in No. 74-1489 and intervenor United Gas Pipeline Co.
  Charles E. Bullock, Atty., Federal Power Commission, with whom Drexel D. Journey, Acting Gen. Counsel, George W. McHenry, Jr., Solicitor and Richard A. Oliver, Atty., Federal Power Commission, were on the brief for respondent. William M. Sawyer, Atty., Federal Power Commission, also entered an appearance for respondent.
  Peter H. Schiff, Gen. Counsel, Public Service Commission of the State of New York, Albany, N. Y., and Richard A. Solomon, Washington, D. C., were on the brief for intervenor Public Service Commission of the State of New York.
  Christopher T. Boland, Washington, D. C., was on the brief for intervenor Texas Gas Transmission Corp.
  William W. Bedwell and John J. Mullally, Washington, D. C., were on the brief for intervenor Mississippi River Transmission Corp.
  Platt W. Davis, III, Washington, D. C., and J. Evans Attwell, Houston, Tex., were on the brief for intervenor Texas Eastern Transmission Corp.
  Clayton L. Orn, Houston, Tex., was on the brief for intervenor New Orleans Public Service, Inc.
  Jefferson D. Giller, Houston, Tex. and Michael J. Manning, Washington, D. C., entered appearances for intervenor Entex, Inc.
  Philip C. Wrangle, Birmingham, Ala., entered an appearance for intervenor Southern Natural Gas Co.
  J. David Mann, Jr., Washington, D. C., entered an appearance for intervenor Laclede Gas Co.
  H. Sloan MeCloskey, New Orleans, La., entered an appearance for intervenor Louisiana Gas Service Co.
  Before BAZELON, Chief Judge, FAHY, Senior Circuit Judge, and LEVENTHAL, Circuit Judge.
  Opinion for the. Court filed by Circuit Judge LEVENTHAL.
  LEVENTHAL, Circuit Judge:
  Petitioners seek review of Opinion No. 671 of the Federal Power Commission and its Opinion No. 671 — A and order on rehearing which establish principles for the setting of rates for jurisdictional sales of natural gas by the United Gas Pipeline Company. In evaluating the rate tariff proposed by United, the FPC made marked revisions in the method of cost allocation and rate design it has used since its 1952 decision in Atlantic Seaboard Corp. Specifically, the FPC shifted a significantly greater proportion of fixed costs from the demand component to the commodity component of its two-part cost allocation and rate design structure. Whether this departure is justified under present conditions of supply shortage is the major issue raised by United and other Petitioners — Memphis Light, Gas & Water Division, Columbia Gas Transmission Corp. and Consolidated Gas Supply Corp. Intervenors Mississippi River Transmission Corp., Texas Eastern Transmission Corp., Texas Gas Transmission Corp., and the Public Service Commission of New York join in attacking the allocation formula adopted by the Commission.
  Memphis also challenges the FPC’s elimination of the demand charge adjustment clause, which required that the demand charge due from a customer of United be credited for those amounts demanded by the customer but not delivered by United. The state of Louisiana, and the Louisiana Municipal Association would have us overrule the Commission’s systemwide allocation of costs attributable to United’s storage facilities; historically those costs had been allocated solely to the Northern Zone, the area in which the facilities are located and which they directly serve. Louisiana also contests the Commission’s increase of the penalty for unauthorized overruns from $3 to $10 per Mcf. We affirm the Commission’s orders.
  I. DEPARTURE FROM THE ATLANTIC SEABOARD FORMULA FOR CLASSIFYING FIXED COSTS
  A. Background
  1. The Atlantic Seaboard Formula
  The process of setting rates under the Natural Gas Act for jurisdictional sales of natural gas has three distinct stages. First, the total cost of service is determined at a level sufficient to embrace return (profit) and taxes payable. The different elements of the cost of service are classified to either a commodity or a demand category. This interrelates with the formation of a two-part rate: a fixed demand component related to the customer’s basic entitlement to receive gas from the natural gas company; and a commodity component with a rate specified for each unit of gas received. Variable costs are assigned to the commodity or volumetric component because they fluctuate according to the volume of gas delivered. Fixed costs, which are incurred in advance to provide the capacity to supply customers’ peak demand, as well as to service nondemand volumes, have been divided equally between demand and commodity components under the Atlantic Seaboard method.
  In the second stage of the process, the total costs are allocated between jurisdictional and non-jurisdictional customers. Demand costs may be allocated on the basis of peak-day or peak-period demands, while commodity costs are allocated according to the percentage of test-year sales attributable to each class of customers.
  Rates are then designed to recover the costs allocated to jurisdictional customers. Commodity costs are recovered by a cents-per-mcf commodity charge, which is paid by all customers on the basis of the total volume of gas actually delivered (annual use). Under Atlantic Seaboard the commodity charge recovers all variable costs and half of the fixed costs. Demand costs are recovered by a fixed monthly demand charge paid by those who have a contractual right to demand specified quantities of gas on peak days. The demand charge may be calculated according to the maximum amount that the customer has a right to demand as specified in the service agreement, or on the basis of the highest daily take for each customer during the past twelve months. United switched from the former to the latter method in April of 1974.
  Demand charges fall most heavily on city-gate customers, typically local distribution companies that take gas at the “city gate,” for sale primarily to commercial and residential customers. They usually take at a low load-factor; that is the volume of purchases of the city-gate customers tends to fluctuate considerably, between the cold winter season of high demand and the slack summer season. Because of these fluctuations the proportion they pay in demand charges is high compared to their commodity charges. In contrast, commodity charges are relatively more significant for high load-factor customers — pipeline customers, who receive a relatively steady supply throughout the year, either because they service industrial customers not subject to the weather-related fluctuations characteristic of human needs, or because they have constructed storage facilities to which they can route any summer receipts in excess of their customer’s summer requirements. Any shift towards the commodity component of the tariff increases the relative burden borne by the high-load customers. In the decision under review, the FPC revised its approach to cost classification and allocation and rate design, attributing only 25% of United’s fixed costs to demand and 75% to commodity.
  The decision in Atlantic Seaboard to devise a two-part formula was based on the Commission’s recognition that the facilities responsible for the fixed costs “perform both a capacity and a volumetric function.” The facilities are built to supply maximum demand, for the pipeline must always have the capacity available to meet those requirements, whether or not it is used on any given day. However, the Commission pointed out that
  pipelines are built to supply service not only on the few peak days but on all days throughout the year. In proving the economic feasibility of the project in certificate proceedings, reliance is placed upon the annual as well as the peak deliveries. Stated another way, the capital outlay for the pipeline facility is made — and justified — not only for service on the peak days but for service throughout the year. ... If fixed expenses are assigned wholly to the demand or capacity function, then gas service which is interrupted on peak days will not share in any of the fixed costs.
  In Atlantic Seaboard, the FPC acknowledged that the exact division of fixed costs between demand and commodity components involved a pragmatic judgment, for “the facts upon which the determination must be made are not susceptible to mathematical computation.” The Commission pointed out that “both functions are . . . significant” and found that a 50%-50% weighting both recognized the higher costs of peak service and imposed some responsibility for fixed costs on off-peak service.
  The Seaboard 50%-50% formula' has not been adhered to rigidly. Although the Commission has not completely departed from the two-part design, it has, on an ad hoc basis, tilted the distribution of fixed costs by increasing the amount assigned to the demand component in response to competition from alternative fuel sources or competition between pipelines, as well as to maintain more efficient use of a pipeline’s facilities by encouraging the construction of storage facilities or increasing off-peak industrial sales. This practice was upheld by the Seventh Circuit as within the Commission’s discretion “ ‘to make the pragmatic adjustments which may be called for by particular circumstances.’ ”
  2. The Administrative Law Judge’s Decision
  In the proceeding under review, United filed a tariff essentially based on the traditional Seaboard formula. The Commission’s staff argued that Seaboard should be replaced by a strictly volumetric method of cost allocation and rate design, on the ground that the gas supply shortage had removed the close relationship between actual peak-day use and pipeline capacity that had existed in 1952. Two-part rates, the staff argued, encourage large-volume consumption of gas inappropriate in a time of curtailments. Administrative Law Judge (ALJ) Kaplan refused to adopt a strictly volumetric allocation on the ground that it failed to recognize both the continuing existence of some (albeit reduced) peak demand and the lower costs “long recognized” to be associated with high load-factor service. Instead, he increased the percentage of fixed costs attributed to the commodity component from 50% to 67%, an action he deemed appropriate in the light of his finding that 17% of the total available capacity had in fact been idled because of unanticipated supply problems.
  3. The FPC’s Orders
  The FPC agreed with ALJ Kaplan that the Seaboard method should be revised to allocate more fixed costs to the commodity component because the decrease in peak day deliveries required “that greater emphasis ... be placed upon the annual use of United’s pipeline system.”
  The FPC went on to say that in its view a straight volumetric system could be justified under present conditions because “the limiting factor in the operation of United’s pipeline system is the quantity of gas available and not the capacity of the pipeline.” Under this approach all costs — including all fixed costs — would be allocated to customers solely on the basis of volume of gas used. This single rate structure could be expressed in percentage terms as assigning 100% of fixed costs to commodity and zero to demand.
  Despite its finding that a volumetric allocation and one-part rate structure would be proper, the FPC decided that an abrupt shift of that magnitude would be “disruptive to United’s system.” Since the Seaboard opinion had explicitly said that the allocation of fixed costs could not be determined by mathematical computation and had based its decision instead on a pragmatic judgment, the Commission said that the ALJ’s effort to compute the proper deviation from Seaboard “on the basis of a technical calculation of unanticipated unutilized capacity” lacked “a logical foundation.” Instead, the Commission chose a “ratio that is midway between the Seaboard 50 — 50 ratio and the volumetric method,” that is, 75% to commodity and 25% to demand.
  B. The Commission’s Authority To Discourage End Use
  The ALJ rejected the contentions of certain intervenors that a departure from Seaboard could be justified solely by the need to discourage low-priority industrial uses. He cited F.P.C. v. Hope Natural Gas Co., 320 U.S. 591, 64 S.Ct. 281, 88 L.Ed. 333 (1944), in which a challenger sought to set aside an order by the FPC on the ground inter alia that the Commission was required to set a rate that would discourage industrial users. The Supreme Court had said, “we fail to find in the [§ 4] power to fix ‘just and reasonable’ rates the power to fix rates which will disallow or discourage resales for industrial use.” 320 U.S. at 616, 64 S.Ct. at 294. This holding was referred to and followed in Fuels Research Council, Inc. v. FPC, 374 F.2d 842, 854 (7th Cir. 1967); which distinguished the Commission’s authority to weigh end use in deciding whether to issue a certificate under section 7 of the Natural Gas Act.
  The FPC was not willing to accept the limitations on its authority that the ALJ found in Hope:
  An important consideration [in shifting fixed costs to the commodity category and requiring the rate design to reflect this shift] is to increase the cost to low priority direct and interruptible customers, who are able to use competitive fuels. We do not think that in the light of the exigencies of present circumstances the narrow holding in Hope prevents our accomplishing a result which we are convinced is in the national interest. In any case the history of litigation under the Gas Act shows that the Courts have given a broad interpretation to our rate-making powers under the Gas Act . . .
  However, the Commission found that “such a conclusion of law is not required to support our finding that a revision of rate design and cost classification is just and reasonable,” and that “the record . calls for a change in the method of cost classification entirely apart from the question of end use.”
  The petitioners purchasing from United, directly or indirectly, contend that the ALJ was correct in holding that the Hope decision precludes the design of rate structures that set high rates in order to restrict the use of natural gas for certain purposes, and that this rationale has vitality under today’s condition of shortage, just as it did when we lived in an age of Hope and ample supply, because the Commission has authority to impose direct restrictions on the use of gas for industrial purposes, and therefore has no need to warp traditional costing and pricing procedures.
  In its analysis, the Commission recognized that any reallocation would have only a limited effect on end use. Its opinion pointed out that the cost of alternative industrial fuels is so much greater than that of natural gas that the reallocation of fixed costs cannot of itself raise natural gas rates to the level where other fuels become competitive. It stated that a change in the direction of volumetric allocation would nevertheless narrow the gap between gas and other fuels, eliminate price discounts for large gas customers, and tend to stabilize rates of residential and commercial customers at a time when price incentives are raising the price of gas.
  In seeking reconsideration, United’s pipeline customers and those who purchase from them attacked the conception that enhancing their burden through increasing commodity charges can be justified as increasing the burden on ultimate industrial purchasers. Consolidated and Columbia, for example, pointed out that it is their storage facilities that enable them to buy at high load-factors and that they resell at low load-factors to commercial and residential consumers. They argued that the rate increase created by shifting more of United’s costs to its interstate transmission pipeline customers like Texas Eastern and Texas Gas will be passed on by those pipeline companies, under their fuel adjustment clauses that automatically flow through increased purchased gas costs, on an “across-the-board basis,” so that the same increase in unit cost will be experienced by all ultimate consumers, whether they are commercial, residential, or industrial. In its opinion denying rehearing, the Commission acknowledged this problem and stated: “Such operation of the purchased gas adjustment clauses will be subject to our review and approval.” It expressed its objective that the new rate design would encourage successive sellers to tilt their own rates toward the commodity component.
  Ultimately it appears that the FPC does not rely on any diminution of industrial uses to support the order under review, and would find the order sound even assuming the percentage of industrial use was unaffected. Since we find independent support in the record for the Commission’s result, we need not and do not rule on its authority to discourage end use when prescribing rates in a shortage situation.
  C. The FPC’s Finding that Its Revision of the Seaboard Formula is Just and Reasonable
  The 25%-75% formula devised by the FPC is primarily challenged by United’s high load-factor interstate transmission pipeline customers (Texas Eastern and Texas Gas) and by those who purchase gas from them (notably Consolidated and Columbia). The FPC’s order puts an economic burden on these customers, a burden shifted from United’s city-gate customers. And this comes at a time when the FPC’s curtailment orders have also operated to burden United’s pipeline customers more heavily than United’s city-gate customers. The increase in burden is not in dispute. The issue is whether the order is reasonable or whether it is arbitrary and capricious.
  1-. Standard of Review
  The court’s role in reviewing a rate order issued by the Federal Power Commission is “essentially narrow and circumscribed.” Permian Basin Area Rate Cases, 390 U.S. 747, 766, 88 S.Ct. 1344, 20 L.Ed.2d 312 (1968). The Natural Gas Act, in § 19(b), requires that “[t]he finding of the Commission as to the facts, if supported by substantial evidence, shall be conclusive.” And the Supreme Court has repeatedly stressed “that Congress has entrusted the regulation of the natural gas industry to the informed judgment of the Commission, and not to the preferences of reviewing courts. A presumption of validity therefore attaches to each exercise of the Commission’s expertise.” If “the order viewed in its entirety and measured by its end results” is not arbitrary or unreasonable, “judicial inquiry under the Act is at an end.”
  Finding it “obvious that reviewing courts will require criteria more discriminating than justicé and arbitrariness if they are sensibly to appraise the Commission’s orders,” Justice Harlan, in Permian Basin, outlined the responsibilities of the reviewing court more specifically — to “determine whether the Commission’s order . . . abused or exceeded its authority”; to “examine the manner in which the Commission has employed the methods of regulation which it has itself selected” and to “decide whether each of the order’s essential elements is supported by substantial evidence; ” and to “determine whether the order may reasonably be expected to maintain financial integrity, attract necessary capital, and fairly compensate investors for the risks they have assumed, and yet provide appropriate protection to the relevant public interests, both existing and foreseeable.” These three responsibilities coalesce in Justice Harlan’s insistence that the court “assure itself that the Commission has given reasoned consideration to each of the pertinent factors.”
  Within the limits imposed by the requirement of reasoned decision-making, the Commission is free to modify or even reverse its established policy.
  The legal system does not compel rigidity, or bureaucratic inflexibility, least of all in an area like energy policy where flexibility may be essential in the public interest. It is the genius of the administrative process to be flexible in response to observed developments, and an agency may “switch rather than fight the lessons of experience.”
  2. The 25%-75% Formula
  In reviewing orders concerning cost allocation the courts have been particularly reluctant to devise technical requirements that would impose unrealistic standards of precision on the administrative process. In Colorado Interstate Gas Co. v. FPC, 324 U.S. 581, 65 S.Ct. 829, 89 L.Ed. 1206 (1945), for example, the Supreme Court refused to require the segregation of physical property that functioned as an integrated whole but provided both jurisdictional and non jurisdictional service. Admitting that “[ajlloeation of costs is not a matter for the slide-rule,” but “[a] judgment on a myriad of facts,” the Court held that “the appropriateness of the formula employed by the Commission in a given case raises questions of fact not of law.”
  When Congress . . . fails to provide a formula for the Commission to follow courts are not warranted in rejecting the one which the Commission employs unless it plainly contravenes the statutory scheme of regulation. . Mr. Justice Brandéis, speaking for the Court in Groesbeck v. Duluth, S.S. & A.R. Co., 250 U.S. 607, 614-15, 40 S.Ct. 38, 41, 63 L.Ed. 1167, noted that “it is much easier to reject formulas presented as being misleading than to find one apparently adequate.”
  In setting rates the Commission is “free, within the ambit of [its] statutory authority to make the pragmatic adjustments which may be called for by particular circumstances.”
  The percentage distribution of fixed costs within the framework of a two-part allocation and rate structure has never been considered inviolate. In Atlantic Seaboard, the Commission, recalling the words of the Court in Colorado Interstate, stressed that it was making a “judgment determination” in deciding to divide the fixed costs equally between demand and commodity. The Seventh Circuit, rebuffing a challenge to a “substantial deviation” from the 50%-50% formula, noted that “the Commission’s orders have deviated markedly from Seaboard since that case was decided” and found “that the Commission is to be extended this discretion and ... we are not to substitute our judgment except in cases of clear abuse.”
  We cannot say that the result reached by the Commission in allocating one quarter of fixed costs to demand and three quarters to commodity is unreasonable. The Commission realistically acknowledged the conclusion in Seaboard that the assignment of costs “could not be done by mathematical computation but involves judgment.” The courts “cannot fairly demand the perfect at the expense of the achievable.”
  The development of extreme gas shortages and the resulting existence of large unused pipeline capacity provides a reasonable basis for reducing the demand component of the tariff charge and moving away from a marked peak differential.
  To the extent that fixed costs are attributed to demand, rather than to commodity, additional gas purchases are encouraged, for a customer paying a demand charge incurs, on an incremental basis, only the commodity charge as to any additional purchases. High load-factor buying is also encouraged, for high load-factor customers bear a relatively smaller share of the demand charges. In the past, all customers benefitted from these effects, for they led to a more efficient use of the pipeline facilities and a consequent reduction in unit costs for all. As gas prices increased relative to the costs of other fuels, the Commission found it necessary to depart from Seaboard and to increase the relative attribution of fixed costs to the demand side, in order to maintain high efficiency and retain industrial customers. Due to the increasing costs of coal and oil and the growing scarcity of natural gas, it is no longer necessary to lure industrial customers with relatively low commodity charges.
  Also, since some pipeline capacity now goes unused even on peak days, the demand charge no longer has the same vitality as a premium for reserving priority use of a scarce resource. A given customer may have a right to a greater share of the gas available on peak days, but that is subject, not only to the limitations of supply, but to the strictures of the curtailment programs. A customer does not pay a premium for the guarantee of a place when he knows that the train, or theatre, or whatever, will be partly empty in any event.
  Under these circumstances, we cannot say that the Commission’s increased allocation of fixed costs to the commodity component represents an abuse of discretion. Our ruling in this case affirming the 25%-75% classification of fixed costs decreed by the Commission does not require that we embrace or approve the Commission’s view that a 100% classification of fixed costs to the commodity component would be proper.
  3. Differentials in Load
  Petitioners argue that there is a need and justification for differentials between those customers who take large amounts at a single place on a high load-factor basis and those who take comparable volumes in small amounts at many delivery locations. The ALJ found that service to pipeline customers as a group is cheaper because it “is more efficiently performed via longer diameter pipes, to fewer delivery points.” He also found evidence that the average unit cost of transporting gas for high load-factor customers was significantly lower.
  However, on this record we cannot say that the FCP’s 25%-75% classification gives insufficient consideration to any such differences in cost. United is admittedly an integrated system, and there is some testimony that small diameter pipelines are not exclusively associated with city-gate customers, or large-diameter lines with pipeline customers. United’s proposed tariff continued the Seaboard approach of splitting fixed costs equally between demand and commodity components. Neither United nor any of its customers asked the Commission to adopt a differential based on greater volume at fewer delivery points. No developed cost studies have been presented to define the different costs associated with different customers.
  The formula adopted by the FPC provides for a peak differential that will, to some extent, reflect any cost savings attributable to high load-factor customers. The Commission has indicated that it will be open to receive properly framed evidence that that differential is inadequate to reflect differences in “physical factors of delivery.” We cannot assign error on the record as it stands.
  4. Differentials due to storage facilities
  A more difficult question is posed by those customers, particularly Columbia Gas and Consolidated Gas Supply, who have equipped themselves to take at high load factors by installing storage facilities.
  In measuring a change of agency policy, the Rule of Law requires not only that the new standards “flow rationally from findings that are reasonable inferences from substantial evidence,” but that “the agency give due consideration to the equities, if any, arising out of commitments based on previous rulings.” The Atlantic Seaboard formula encouraged the building of storage by offering a discount to high-volume purchasers.
  All of United’s customers benefitted when some of them constructed storage facilities rather than contract for demand levels that would require the addition of more expensive pipeline peaking capacity that would be idled during the summer slack. The ability of some customers to draw on storage volumes during peak periods also makes more gas available during peak seasons to those who do not have similar facilities. The Commission acknowledged analogous systemwide benefits in adopting the ALJ’s decision to allocate the costs associated with United’s own storage facilities, located primarily in the North, to the system as a whole.
  The FPC rejected the appeal of those who built storage facilities with a terse statement noting that they had been favored with lower unit costs under the Seaboard method: “We have determined that under United’s gas supply situation the cost of its pipeline system is more directly related to annual rather than peak day operations.”
  While we do not say that a claim based upon action taken in response to FPC encouragement (investing in storage facilities to produce high load-factors) is conclusive, we are concerned that it does not seem to have been given any consideration or analysis whatever. However, we cannot say on this record that the FPC order is unreasonable, for customers whose storage permits them to take at high load-factors still receive a significant price discount.
  Commissioner Moody, in his concurrence to Opinion No. 671, suggests a special rate for gas sold into storage. That alternative is not before us, for the Commission was not presented by the parties in this proceeding with a specific storage discount provision. Instead, it was urged to reject any departure from the 50%-50% formula, a step we cannot say was required as a matter of law.
  5. Underrecovery of Fixed Costs
  United argues that the Commission’s orders deprive United of a reasonable opportunity to recover fixed costs allocated to its jurisdictional customers, because volumes will shrink between the test year, when unit rates for commodity charges are calculated, and the actual sales which determine recovery through the commodity charge.
  This risk of underrecovery is inherent to some extent whenever any fixed costs are allocated to the commodity component. The Commission has leeway to protect pipelines by adjusting the test-period volumes for fluctuations that may reasonably be projected to occur in the future. We cannot say on this record that the FPC’s shift to a 25%-75% allocation will necessarily produce a confiscatory result.
  In a separate proceeding United has proposed a volume variation adjustment clause (VVAC), which would allow United to adjust its commodity component to reflect variations from test-year volumes. No similar proposal was included in the tariff submitted in these proceedings.
  II. OTHER CHALLENGES
  A. The Elimination of the Demand Charge Adjustment
  The FPC accepted United’s proposal that its tariff be modified to relieve it from the operation of the demand charge adjustment provisions in its service agreements during curtailment due to supply shortages. Under the adjustment provisions, the demand charge was credited for failures by United to deliver the gas requested by the customer on any given day, up to the maximum contractual demand. The Commission found the elimination of the adjustment necessary to ensure that United will “receive revenues to meet some of the fixed costs of its system” and will “remain a viable economic entity.”
  Memphis Light, Gas & Water Division argues that there is insufficient evidence that this step is necessary and that, in any case, the failure to recover costs due to supply shortages is a risk that should be borne by those who have invested in United rather than by those who purchase gas from it.
  In Rhode Island Consumers’ Council v. FPC, 164 U.S.App.D.C. 134, 504 F.2d 203 (1974), we upheld a similar change in the rate tariff of Texas Eastern Transmission Corp. on the grounds that it permitted “a de facto increase in the average price of gas” and that “the Commission was engaged in an exercise of discretion when it held that the emergency and severity of the shortfall warranted a price increase.” “Considerations like these,” we said, were “peculiarly a matter for appraisal by the administrative agency.”
  That case does not wholly settle the problem. Even if it be assured that this pertinent amount of current revenue is necessary in order to be reasonable to investors, there may be a question whether the method of achieving it is fair and reasonable.
  In Rhode Island we did not reach certain questions raised as to the discriminatory effects of the Commission’s order because they had not been presented in petitioners’ objections before the Commission. In this case, too, we must take the issues as they were shaped in the record, including the petition for rehearing, and we find no indication that the questions reserved in Rhode Island were fairly presented to the Commission.
  In fact, the concerns we expressed in Rhode Island have been diluted in this case by the FPC’s reduction of the demand charge. Our concerns are also diminished by United’s decision to calculate its demand charge according to actual peak deliveries made in the past twelve-month period, rather than according to maximum contractual demand. This at least avoids the inequity, of a demand charge assessed on the basis of contract entitlements that have become academic due to the FPC’s curtailment actions.
  B. Allocation of United’s Storage Costs
  United urges that we find error in the Commission’s systemwide allocation of the costs attributable to United’s storage facilities. United’s chief storage operations are in the Northern Zone, where seasonal variations play the largest factor. In its proposed tariff United allocated the associated costs solely to its Northern customers, following its historical zone-gate method. The FPC, adopting the ALJ’s decision and its staff’s recommendation, spread the costs system-wide on the ground that all the customers benefited from the facilities.
  The ALJ found that the “husbanding” of gas by putting it into storage in the summer makes more gas available to all United’s customers during peak periods. There is also evidence that the use of storage “reduces materially” the costs of transportation and “permits a more uniform daily rate of purchases by United from its suppliers, generally enhancing efficiency and minimizing costs.” With findings based on substantial evidence, and a rational use of the facts thus ascertained, there is no warrant for reversal.
  C. Increase in the Overrun Penalty
  Louisiana challenges the FPC’s approval of United’s proposal for an increase, from $3 to $10 per Mcf, in the penalty for unauthorized overruns, for gas taken by a customer in excess of its maximum contract demand. Although the ALJ rejected United’s proposal as “premature,” since there had not been even one winter’s experience after the $3 penalty had been approved in May of 1972, the FPC cited the use of a $10 penalty by a number of other pipelines, and approved it “in view of the importance of curtailment programs today.”
  While Louisiana urges that the $3 penalty is sufficient, it admits that alternative fuels are either so expensive or so scarce that city gate customers in Louisiana will be hard pressed to restrict themselves to contractual requirements. The Commission points out that United’s penalty provision does provide for a waiver, at the option of the seller, in the case of “an emergency beyond the control of” the buyer.
  This matter falls within the Commission’s discretion, to impose a stringent burden on those who appropriate excessive amounts of a scarce resource in emergency conditions.
  * * * * * *
  For the reasons stated, the Commission’s orders are
  Affirmed.
  . 50 F.P.C. 1348 (1973).
  . Opinion and Order No. 671-A Denying Rehearing, 51 FPC 1014 (1974).
  . 11 F.P.C. 43 (1952). The Seaboard formula was approved in State Corporation Comm'n of Kansas v. FPC, 206 F.2d 690 (8th Cir. 1953), cert. denied, 346 U.S. 922, 74 S.Ct. 307, 98 L.Ed. 416 (1954).
  . Memphis, a division of the City of Memphis, Tennessee, is a city-gate customer of Texas Gas Transmission Corp., a pipeline company that purchases a substantial portion of its gas from United.
  . Columbia and Consolidated purchase at high load-factors from Texas Eastern Transmission Corp. and Texas Gas Transmission Corp., both of which are high load-factor customers of United,
  . All three are pipeline companies which purchase gas for resale. Texas Eastern is United’s largest customer.
  . United is the principal supplier of natural gas within Louisiana. The Louisiana Municipal Association is a non-profit organization of cities and parishes; it represents the interests of its members as customers of United or as ultimate consumers of gas sold by United.
  . Variable costs include, e. g., the cost of gas purchased by a pipeline from its suppliers and fuel for compressor station use.
  . Fixed costs do not vary with volumes of gas transported or sold. They include, for example, return, depreciation, taxes, and other expenses relating to the investment, in pipeline facilities.
  . United makes direct, nonjurisdictional sales to approximately 200 industrial customers, who typically pay no demand charges.
  . 11 F.P.C. at 53.
  . Mississippi River Fuel Corp. v. FPC, 82 U.S.App.D.C. 208, 213, 163 F.2d 433, 438 (1947); State Corporation Comm’n of Kansas v. FPC, supra note 3, 206 F.2d at 708.
  . 11 F.P.C. at 54-55.
  . Id. at 56. See also J. Bonbrisht. Principles of Public Utility Rates 354 n. 16 (1961).
  . 11 F.P.C. at 56.
  . Southern Natural Gas Co., 29 FPC 323, 351 (1963) .
  . Natural Gas Pipeline Co., 28 FPC 731, 735 (1962).
  . United Fuel Gas Co., 31 FPC 1342, 1348-49 (1964) .
  . Fuels Research Council, Inc. v. FPC, 374 F.2d 842, 852 (7th Cir. 1967), quoting, FPC v. Natural Gas Pipeline Co., 315 U.S. 575, 586, 62 S.Ct. 736, 86 L.Ed. 1037 (1942).
  . United proposed a “modified” Seaboard allocation, by which fixed costs associated with production, in addition to those associated with transmission, were divided equally between the demand and commodity categories. A.L.J. Opinion, 50 FPC at 1383.
  . 50 FPC at 1399.
  . On the peak day of January 15, 1972, United’s actual deliveries were 4,333,965 Mcf, with a total curtailment of 906,940 Mcf. The ALJ arrived at the 17% figure by dividing the unanticipated unutilized capacity, as measured by the curtailed volume, by the total available capacity of 5,240,905 Mcf. 50 FPC at 1402. The FPC pointed out that, under the ALJ’s principles, “the ‘used’ and ‘anticipated unused’ capacity (83 percent) should be allocated 50 percent to demand (41.5 percent) and 50 percent to commodity (41.5 percent) and the 17 percent representing unanticipated unused capacity should then be added to commodity making 58.5 percent rather than 67 percent.” 50 FPC at 1359 n. 22.
  . 50 FPC at 1361.
  . Opinion Denying Rehearing, 51 FPC 1016. See also 50 FPC at 1359-60:
  in a pipeline system where all the capacity is not being used the capacity of the system is not what limits sales to the pipeline’s customers, but the supplies of gas available is the controlling factor. Therefore there is much logic in imposing all costs, both fixed and variable, in proportion to the gas taken on the respective groups of jurisdictional and non-jurisdictional customers through volumetric allocations and on the various jurisdictional customers through a straight-line rate. In this way there will be no incentive to take as much gas as possible, up to contract demands, in order to reduce the unit costs.
  . The Commission accepted United’s argument that the volumetric system would add approximately $10 million to the pipeline and industrial customers’ gas costs. Of this, $4 million would apply to non-jurisdictional industrial sales with fixed rate contracts. 50 FPC at 1362.
  . Id.
  . Id. at 1361.
  . Id. at 1362.
  . This point was urged by New Orleans Public Service, Inc., the City of New Orleans, and Laclede Gas Company.
  . 50 FPC at 1355-56.
  . Id. at 1358.
  . 51 FPC at 1016.
  . See FPC v. Louisiana Power & Light Co., 406 U.S. 621, 92 S.Ct. 1827, 32 L.Ed.2d 369 (1972).
  . For example, Louisiana tells us that in 1974 steam-electric utility generating plants in the state paid an average of only 41.3 cents per million Btu for natural gas, while the average price paid for No. 2 fuel oil was $3.12 per million Btu. Louisiana Br. at 4, citing FPC, Report on Fuel Cost and Quality. March 1974.
  . 50 FPC at 1360.
  . Id.
  . 51 FPC at 1017.
  . Id.
  . For example, during the test year, when curtailment programs were in effect, United’s Northern Zone pipeline deliveries declined by about 15.8% on an annual basis, while Northern Zone city-gate deliveries fell only 9.5%. On a peak-day basis, sales to city-gate customers in the Northern Zone actually increased 24.25%, while sales to pipelines fell 19.93%. J.A. 19 (testimony of Mr. Benson).
  . 15 U.S.C. § 717 et seq. (1970).
  . Permian Basin Area Rate Cases, 390 U.S. 747, 767, 88 S.Ct. 1344, 1360, 20 L.Ed.2d 312 (1968). See also Mobil Oil Corp. v. FPC, 417 U.S. 283, 306-08, 94 S.Ct. 2328, 41 L.Ed.2d 72 (1974); FPC v. Hope Natural Gas Co., 320 U.S. 591, 602, 64 S.Ct. 281, 88 L.Ed. 333 (1944).
  . Colorado Interstate Gas Co. v. FPC, 324 U.S. 581, 605, 65 S.Ct. 829, 840, 89 L.Ed. 1206 (1945).
  . FPC v. Hope Natural Gas Co., supra note 40, 320 U.S. at 602, 64 S.Ct. at 288. See also FPC v. Natural Gas Pipeline Co., 315 U.S. 575, 586, 62 S.Ct. 736, 86 L.Ed. 1037 (1942).
  . 390 U.S. at 791-92, 88 S.Ct. at 1373.
  . Id. at 792, 88 S.Ct. at 1373. See also Public Service Comm’n. v. FPC, 167 U.S.App.D.C. 100, 107, 511 F.2d 338, 345 (1975), where we described the “requirement of ‘reasoned consideration’ ” as “the ultimate issue in judicial review of [the Commission’s] determinations.”
  . Public Service Comm'n v. FPC, supra note 44, 511 F.2d at 353-4. See also-Greater Boston Television Corp. v. FCC, 143 U.S.App.D.C. 383, 394, 444 F.2d 841, 852 (1970), cert. denied, 403 U.S. 923, 91 S.Ct. 2229, 29 L.Ed.2d 701 (1971).
  . SEC v. Chenery Corp., 332 U.S. 194, 67 S.Ct. 1575, 91 L.Ed. 1995 (1947).
  . Atlantic Seaboard Corp. v. FPC, 131 U.S.App.D.C. 291, 296, 404 F.2d 1268, 1273 (1968); City of Chicago v. FPC, 128 U.S.App.D.C. 107, 385 F.2d 629 (1967), cert. denied, 390 U.S. 945, 88 S.Ct. 1028, 19 L.Ed.2d 1133 (1968); Pinellas v. FCC, 97 U.S.App.D.C. 236, 230 F.2d 204, cert. denied, 350 U.S. 1007, 76 S.Ct. 650, 100 L.Ed. 869 (1956).
  . Public Service Comm’n v. FPC, supra note 44, 511 F.2d at 353, quoting New Castle County Airport Comm’n v. CAB, 125 U.S.App.D.C. 268, 270, 371 F.2d 733, 735 (1966), cert. denied, 387 U.S. 930, 87 S.Ct. 2052, 18 L.Ed.2d 991 (1967).
  . 324 U.S. at 589, 65 S.Ct. at 833.
  . Id. at 590, 65 S.Ct. at 833.
  . Id. at 589-90, 65 S.Ct. at 833.
  . FPC v. Natural Gas Pipeline Co., supra note 42, 315 U.S. at 586, 62 S.Ct. at 743.
  . 11 FPC at 56.
  . Fuels Research Council, Inc. v. FPC, supra note 9, 374 F.2d at 852.
  . 50 FPC at 1361.
  . Public Service Comm’n v. FPC (Texas Gulf Coast Area Rate Cases), 159 U.S.App.D.C. 172, 196, 487 F.2d 1043, 1067 (1973) (opinion concurring in part and dissenting in part), vacated and remanded sub nom., Shell Oil Co. v. Public Service Comm’n, 417 U.S. 964, 94 S.Ct. 3166, 41 L.Ed.2d 1136 (1974); on remand, sub nom., Public Service Comm’n v. FPC, 170 U.S.App.D.C. 153, 516 F.2d 746 (1975).
  . United has been affected by the shortage of natural gas more than any other pipeline. ALJ Decision, 50 FPC at 1375. United’s 1972 peak-day deliveries were approximately 600,000 Mcf lower than its 1970 and 1971 peak sales. In the 12-month test period ending August 31, 1971, the aggregate quantities curtailed were 52,076,942 Mcf (all of which occurred in the last ten months). In the twelve months immediately following this period, a total of 279,385,393 Mcf were curtailed. Id. at 1380-81.
  . 50 FPC at 1362.
  . However, since city-gate customers typically serve the residential and commercial needs that have highest priority under the curtailment programs they have been least affected by the shortages. See note 38 supra.
  . A different situation might arise if a pipeline that is operating well below capacity for the greater part of the year were to add new facilities in order to meet peak-day demands. For example, a pipeline that uses less than 90 percent of the capacity available during the year as a whole might find it necessary to install storage capacity near certain delivery points in order to increase its ability to deliver the largest possible amounts on peak days. The fixed cost associated with that capital investment might fairly be regarded as uniquely associated with peak day service. We are dealing, instead, with the allocation of fixed costs associated with facilities that have served both peak and annual uses in the past and are no longer fully utilized by either service.
  . 50 FPC at 1399. See also, id. at 1381.
  . Id. at 1381.
  . E.g., J.A. 25-26 (testimony of Texas Gas Transmission Corp.’s witness Mr. Benson); Texas Eastern Transmission Br. at 12.
  . J.A. 99 (testimony of Mr. Scarbrough).
  . 51 FPC at 1016.
  . City of Chicago v. FPC, supra note 47, 128 U.S.App.D.C. 107, 115, 385 F.2d 629, 637 (1967).
  . 50 FPC at 1365.
  . 51 FPC at 1017.
  . 50 FPC at 1371.
  . ALJ Decision, 50 FPC at 1394-95.
  . United does not raise the objection that, until there is renegotiation of its contracts with its nonjurisdictional customers (typically industrial, high load-factor purchasers who do not pay demand charges), United will have to absorb the increased costs allocated by the FPC to these nonjurisdictional customers.
  . United Gas Pipe Line Co., Docket No. RP 74-21.
  . The credit is generally calculated by multiplying a unit amount (about one-thirtieth of the monthly demand charge) by the total volume of gas which the customer requested but failed to obtain. ALJ Decision, 50 FPC at 1408.
  . 50 FPC at 1368.
  . Mississippi River Transmission Corp. suggested that the demand charge adjustment be retained, but that the payments required to be made by United be offset by a surcharge added to the commodity component. An arrangement of this sort was included in the settlement reached in United’s docket No. RP 71-41. However, an insufficient evidentiary base was laid in this case for the imposition of a similar surcharge. 50 FPC at 1368, 1408-09.
  . 164 U.S.App.D.C. at 142-143, 504 F.2d at 211-12.
  . 164 U.S.App.D.C. at 143, 504 F.2d at 212.
  . United’s system is divided into three zones: the connected Northern Zone (Shreveport and Jackson divisions) and Southern Zone (Victoria and New Orleans divisions), and the relatively small and isolated Northwest Mississippi Zone. ALJ Opinion, 50 FPC at 1382.
  . Id. at 1405.
  . That is, the state of Louisiana and the Louisiana Municipal Association.
  . An overrun penalty is levied against a customer for each Mcf of gas it takes in excess of its specified maximum contract demand.
  . 50 FPC at 1415.
  . 50 FPC at 1369.
  . Louisiana Br. at 11-13.
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