Court Opinion

ID: 8938291
Source: CourtListenerOpinion
Date Created: 2022-11-27 07:41:42.180174+00
Date Added: 2024-06-11T17:09:40.278625
License: Public Domain

SWYGERT, Senior Circuit Judge.
Three natural gas distribution companies, Northern Indiana Public Service Company (“NIPSCO”), Interstate Power Company (“Interstate”), and Iowa Gas Company (“Iowa Gas”), petition this court to review three orders1 and denials of petitions for rehearing of those orders2 of the Federal Energy Regulatory Commission (“the Commission”) that relate to the Commission’s approval of a new rate design for the Natural Gas Pipeline Company of America (“Natural”) system.3 NIPSCO complains that the new rate design is not supported by substantial evidence and results in rates that are unjust, unreasonable, and discriminatory. Interstate complains about the Commission’s refusal to reopen the record to reevaluate the rate design, and Iowa Gas argues that the Commission should have conducted an investigation into alleged irregularities in Natural’s implementation of the new rate design.
This court has jurisdiction to decide these petitions for review pursuant to section 19(b) of the Natural Gas Act (“the Act”), 15 U.S.C. § 717r(b) (1982). We affirm the Commission’s approval of the new rate design and its refusal to reopen the record. We vacate, however, the Commission’s order refusing Iowa Gas’ request for an investigation, and we remand for reconsideration.
I
Natural is a major interstate natural gas pipeline company serving markets in Indiana, Iowa, Illinois, and Missouri and is subject to the Commission’s jurisdiction under the Act. Natural sells gas to forty-nine wholesale (“jurisdictional”) customers under six different rate schedules (e.g., DMQ-1, G-l, E-l, AOR, WS-1, and WS-2).4 These customers are generally intrastate distribution companies that resell the gas to residential and commercial customers at rates regulated by state energy commissions. Of these forty-nine customers, fifteen are large purchasers under the DMQ-1 rate schedule, the rate schedule at issue in this case. These fifteen wholesalers under the DMQ-1 schedule (e.g., Illinois Power Co., Interstate Power Co., Iowa Electric Light and Power Co., Iowa-Ulinois Gas and Electric Co., Mississippi River Transportation Corp., North Shore Gas Co., NIGAS, NIPSCO, Peoples Gas, Associated Natutal Gas Co., Iowa Gas., Iowa Southern Utilities Co., Nebraska City, Nebraska, Salem, Illinois and Wisconsin Southern Gas Co.) account for approximately 93% of Natural’s sales of natural gas. Only one percent of Natural’s sales are to direct industrial customers, known as “non-jurisdictional” customers.
Natural contracts with each of its forty-nine customers to supply them a certain quantity on any particular day. These quantities are known as daily contract quantities, and they reflect the maximum amount of gas that Natural is required to supply to that customer on each day. Customers do not necessarily buy their full *733contract quantity every day, and they are not charged the full amount for gas for which they have contracted unless they purchase it. Because the demand for gas in Natural’s service area is temperature sensitive, Natural’s customers ordinarily purchase their daily contract quantity (or close to it) in the winter months (peak days), but purchase much less during the summer months.
In addition to contracting with Natural to supply gas service, each customer is required to provide Natural with the daily quantity entitlements and monthly quantity entitlements they want from Natural over the next three years. Entitlements are a concept developed as part of Natural’s curtailment plan. In the early 1970’s, Natural’s supplies were inadequate to meet the needs of its customers. A curtailment plan was developed as Sections 22 and 23 of Natural Gas’ General Terms and Conditions of its Gas Tariff. Under those sections, Natural’s customers “nominate” their expected daily and monthly gas purchases for a twelve-month period beginning April 1. These are known as daily and monthly entitlements. The sum of the monthly entitlements is known as a customer’s annual entitlement and can be no greater than 365 times the customer’s daily contract demand. Each customer’s Basic Annual Quantity is an annual amount that is used in the allocation of each DMQ-1 customer’s share of any curtailment imposed by Natural. It is an amount negotiated by Natural and the customer based on that customer’s end user profile. It is intended to reflect the amount of gas that each customer believes that “it can live with” on an annual basis.
Natural determines what it expects to be able to deliver of the amounts requested and files this with the Commission. Pursuant to Article 22.31 of the Tariff, if Natural projects daily and monthly deliverability sufficient to meet its total system nominations, each of Natural’s customers receives the daily quantity and monthly entitlement which it has requested. And, if Natural can satisfy all nominations, then the allocation provisions of section 22 are not applied. Under the curtailment plan, Natural may reduce the requested nominations only when its projected gas supplies will be less than,the total volumes requested by its customers. Only the first year’s nomination is binding on the customer. Because of the abundance of gas available, Natural has not implemented any type of curtailment since the late 1970’s, and Natural predicts that curtailment will not occur until 1990.
NIPSCO, Interstate, and Iowa Gas and the various intervenors in this action, Peoples Gas Light and Coke Company (“Peoples”), North Shore Gas Company (“NSG”),5 Northern Illinois Gas Company (“NIGAS”), Iowa Gas, and Natural,6 are, except for Natural, local distribution companies which purchase all or part of their natural gas supplies for resale from Natural. NIPSCO serves both residential and industrial customers in the northern one-third of Indiana. Interstate provides gas distribution services to customers (primarily one large industrial customer) in Illinois, Iowa, and Minnesota. Iowa Gas serves mostly residential and small commercial customers in central and southwest Iowa. Peoples sells gas exclusively, within the City of Chicago, and Northern Illinois serves the remaining portion of northern Illinois.
This case involves a challenge to a rate design adopted by the Commission. Under the Commission’s traditional ratemaking practice, a pipeline is permitted to recover in its rates its costs of service, including a reasonable rate of return on its investment. Hence, the pipeline’s total cost of providing *734service to its customers plus a reasonable rate of return on its investment must first be determined. In this case, there is no dispute concerning the amount of Natural’s cost of service plus a reasonable return on investment.
Once the cost of service is established, rates must be set to recover that cost from the pipeline’s customers. These rates are ordinarily determined by a four-step^ process: (1) cost functionalization; (2) cost classification; (3) cost allocation; and (4) rate design. Cost functionalization consists of separating the pipeline’s cost by the major functions performed by the pipeline system: production and gathering, storage, and transmission. Cost functionalization is not an issue in this appeal.
After the costs have been divided by function, the next step is to classify the costs as fixed or variable. Fixed costs are generally considered to be related to customer demand for capacity which does not vary with the changes in the throughput of the system while variable costs are generally associated with the annual delivery and sale of gas. As a second part of the classification process, fixed and variable costs are classified as either demand or commodity-
Costs classified as demand are generally associated with a pipeline’s fixed costs, i.e., those costs incurred for providing peak day service; costs classified as commodity are associated with the volume of gas consumed by each customer.7 Historically, production and gathering fixed costs have been classified to the commodity component because such costs are related to the acquisition of gas supply. In the instant case, the Commission ruled that these production and gathering fixed costs should continue to be classified to the commodity component, and no party has objected to this ruling or to any other aspect of the cost classification process.
The next step, cost allocation, apportions the cost of service between jurisdictional and non-jurisdictional customers and also determines the cost responsibility between classes of jurisdictional customers. In the past, the allocation of the demand costs has been based on the average of the sustained three-day system peak demand. Commodity costs have been allocated on the basis of the annual use of the system. The allocation procedure can also be used, as in this case, to determine cost responsibility between jurisdictional customers in the same class and may be referred to as the rate design process.
The last step, the step at issue in this case, is rate design, the process by which costs are allocated to jurisdictional customers and translated' into unit charges.8 Commodity costs are recovered by a per million cubic feet (mcf) charge that is paid by all customers on the basis of the amount of gas they actually use (annual use); demand costs are recovered by a fixed monthly demand charge (imposed whether or not any gas is actually taken) paid by only those customers who have a contractual right to demand certain quantities of gas.
*735Demand charges are felt differently by high load and low load factor customers.9 Low load factor customers are those distribution companies that service primarily commercial and residential customers whose needs fluctuate considerably between the winter and summer months. As a result of these fluctuations, the proportion these particular distribution companies pay in demand charges is high compared to their commodity charges.
By contrast for high load factor customers, those who receive a relatively steady supply over the year, the demand component of their overall cost of gas is proportionately less. The high load factor customers’ needs do not tend to fluctuate either because they provide service to industrial users not subject to weather-related variations or because they have constructed storage facilities which they use to service customers in the winter months. Thus, any shift in costs towards the demand component increases (relatively) the burden borne by low load factor customers; any shift towards the commodity component increases the burden borne by the high load factor customers. In this case, it is essentially the high load factor customers (NIPSCO, NIGAS, and Interstate) that object to the Commission’s new rate design since the ultimate effect is to increase the significance of actual use for purposes of calculating the demand charge.
II
The present dispute began on March 1, 1981, when Natural filed a request for a general rate increase pursuant to section 4(e) of the Act, 15 U.S.C. § 717c(e), using a new method — the modified fixed-variable (“MFV”) — for cost allocation and rate design. The issue of the appropriate rate design for the Natural system was set for a full evidentiary hearing on July 14 through July 20, 1982. At that hearing five rate design methodologies were discussed. Natural, Peoples, NIGAS, and the Commission Staff (“Staff”) presented expert testimony and numerous exhibits in support of their rate designs. Interstate was granted leave to intervene.
At least two parties10 argued for the reinstatement of the United methodology, as defined in United Gas Pipeline Company, 50 F.P.C. 1348 (1973), reh’g denied, 51 F.P.C. 1014 (1974), aff'd sub nom. Consolidated Gas Supply Corp. v. F.P.C., 520 F.2d 1176 (D.C.Cir.1975). The United method was originally imposed on Natural’s system in 1976.11 See Natural Gas Pipeline Company of America, 56 F.P.C. 2976 (1976), reh. denied, 57 F.P.C. 2 (1977).
Iowa-Illinois argued, in the alternative, for a continuation12 of the Seaboard meth*736od, as defined in Atlantic Seaboard Corporation, 11 F.P.C. 43 (1952), aff'd sub nom. State Corp. Commission of Kansas v. F.P.C., 206 F.2d 690 (8th Cir.1953), cert. denied, 346 U.S. 922, 74 S.Ct. 307, 98 L.Ed. 416 (1954).13 Natural, supported by NI-GAS, presented its MFV wherein all costs classified as fixed were assigned to the demand component with the exception of Natural’s return on equity and related taxes which were assigned to the commodity component. The resulting demand and commodity costs were allocated to Natural’s customers on the basis of peak day volumes and annual volumes, respectively.14
The Staff proposed a “cost reflective” method in which the primary criterion for classifying costs as either demand or commodity was whether the costs were related to the supply (commodity) or transmission (demand) of gas.15 Peoples presented a Straight Fixed Variable (“SFV”) rate design in which all fixed costs, including return on equity and related taxes, were assigned to the demand component and all variable costs were assigned to the commodity component. Peoples’ method allocated demand costs to Natural’s jurisdictional customers on the basis of a Contract Right Equivalent (“CRE”). The customer’s CRE would be determined by taking the *737average of the customer’s annual entitlements and Basic Annual Quantity. Peoples argued that the basic annual quantity provides the best available measure of the permanent allocation of supply and that annual entitlements provide the best available measure of the limits of a customer’s short-term exercisable demand. Under People’s method, customers who took in excess of their entitlements would pay a substantial premium for that excess gas. Customer nominations were to be binding for three years.
On April 22, 1983, Administrative Law Judge Head issued his initial decision. The ALJ concluded that implementation of either the United or Seaboard methodology would be inappropriate. Regarding the other three rate designs presented, the ALJ adopted Natural’s MFV proposal. He rejected Peoples’ proposal primarily on the ground that the allocation of demand costs utilizing the CRE was inappropriate
[because] the CRE index is based on curtailment provisions that are no longer in effect on Natural’s system, ... [because] ... these figures are not arrived at by any relationship to the customer’s cost responsibility for the facilities put in place by Natural to provide service ... [and because] ... the CRE index [does not] give appropriate weighting to the peak winter demand on Natural’s system when the pipeline is totally utilized and all the facilities are in service.
He also rejected the Staff’s cost reflective approach on the basis that the Staff’s reasoning resulted in “an unwarranted redefinition of fixed and'variable costs” and its proposal was “too radical a departure from the [traditional] rate design principies____” 16
In accepting Natural’s MFV method, however, the' ALJ imposed one modification. He rejected Natural’s proposal that demand costs be allocated among and recovered from jurisdictional customers solely on the basis of peak day demands. Rather, he accepted Peoples’ contention that Natural’s allocation procedure did not give enough recognition to the annual use of Natural’s system.17 He therefore ruled that demand costs should be allocated among classes of jurisdictional customers on a basis which gives equal weight to peak day volumes and annual volumes. The peak demand component of the index was to be based on Natural’s existing method of calculating peak responsibility, (i.e., the ratio of the peak demands of a class of customers to the total peak demands of all classes of customers), and the annual use component was based on a ratio of the total annual purchases of all customers within each class of service divided by the total annual system sales for the test year. Demand and commodity rates for each class of service would be computed using daily contract quantities and annual sales, respectively.18
Numerous parties filed exceptions to the Initial Decision. On November 4, 1983, the Commission issued its order modifying the AU’s decision in two respects: the Commission accepted the Staff’s proposal that fixed costs associated with Natural’s production and gathering facilities should be classified as part of the commodity component; it also ruled that
*738[w]ith respect to the allocation of costs classified to the demand component, half of the costs should be allocated between classes of customers and recovered from customers on the basis of daily contract quantities. The remaining costs classified to the demand component should be allocated between classes of customers on the basis of Annual Quantity Entitlements and recovered from customers on the basis of Monthly Quantity Entitlements through a separate demand charge.
Several parties, including NIPSCO, Natural, and NIGAS filed applications for rehearing of the Commission’s November 4, 1983 decision, which were denied by the Commission on February 17, 1984.
On March 5, 1984, under cover letter dated March 2, 1984, Natural filed with the Commission its customers’ entitlement nominations19 pursuant to section 22 of the General Terms and Conditions of its Gas Rate Tariff for the service year April 1,
1984 through March 31, 1985.20 In its filing letter, Natural requested a waiver of-the General Terms and Conditions of its Gas Rate Tariff to permit the revised tariff sheets to become effective April 1, 1984.
On March 20, 1984 Natural, pursuant to Article II of the Agreement, see supra note 12, filed revised tariff sheets reflecting the rate design ordered by the Commission on November 4, 1983 including the allocation of demand costs on the basis of entitlements filed March 5, 1984.21 Natural Gas proposed that the revised rates become effective May 1, 1984.
On April 5, 1984, after NIPSCO had already appealed to this court, Interstate filed a “Motion to Reopen to Consider New Evidence,” pursuant to section 19(a) of the Act, 15 U.S.C. § 717r(a). Interstate requested that the Commission reopen the record to consider the impact of its November 4, 1983 decision created by the alleged shifting of cost responsibility as reflected in Natural’s March 5, 1984 entitlements filing. Interstate asserted that, as a result of the Commission’s November 4, 1983 decision, it would be assigned an additional $1.2 million in demand costs. On April 23, 1984 NIPSCO filed its answer to Interstate’s motion and informed the Commission that NIPSCO’s demand cost responsibility under the Commission’s November 4, 1983 decision would increase by approximately $4.7 . million annually if Natural’s March 5, 1984 entitlements were used to allocate fixed costs. The Commission denied Interstate’s motion on April 27, 1984.
Iowa Gas requested the Commission to reject Natural’s March 5, 1984 filing on the ground that implementation of the new rate design using the new entitlements would result in unreasonable and unjustifiable cost shifts among Natural’s customers. In support of its request, Iowa Gas argued that the renominations made by several of Natural’s partial requirements customers (e.g., Peoples and NIGAS) were anomalous when compared with Natural’s sales projections in its latest general rate *739increase filing and the entitlements which were already a part of Natural’s tariff. Iowa Gas noted that North Shore Gas, NI-GAS, and Peoples Gas had all reduced their entitlements from 86, 135, 371 mcf to 30,-455,518; 381,080,514 to 330,061,552; and 278,033,637 to 220,893,622, respectively, although projected annual sales for the three companies remained the same. Iowa Gas asked the Commission to investigate the propriety of these entitlements and whether they reflected the actual needs of Natural’s customers.
NIPSCO, Interstate, and Iowa Gas also protested Natural’s March 20, 1984 filing. Iowa Gas objected to the rates filed by Natural because they were designed to use the entitlement quantities filed by Natural on March 5, 1984. Iowa Gas reiterated its concern that the renominations made by some of Natural’s partial requirements customers were out of line with Natural’s sales projections and the entitlements which were contained in Natural’s tariff. Iowa Gas claimed that an unduly discriminatory impact would result from the use of the entitlements filed on March 5, 1984. NIPSCO and Interstate also objected to the “unreasonable impact” that would result from the use of the new nominations.
On May 18, 1984 the Commission rejected all of these arguments and permitted the tariff sheets to become effective on April 1, 1984 and May 1, 1984, as Natural had requested, and granted Natural’s request for waiver of section 22 of the General Terms and Conditions of Natural’s Gas Rate Tariff. The Commission acknowledged that certain customers would experience higher rates as a result of the use of the new nominations. In response to the argument that some customers had substantially reduced their entitlements to take advantage of the Commission’s November 4, 1983 decision with little risk since large quantities of AOR gas were available or since they had alternative sources of supply, the Commission did find that Peoples Gas and NIGAS had reduced their entitlements by 20.1% and 13.4%, respectively, and that Natural had large quantities of AOR volumes for sale. Nonetheless, the Commission rejected these arguments on the grounds that all customers had the opportunity to nominate new entitlements and that the risk of the possibility of inadequate supplies was sufficient that the nomination procedures “would not be abused by Natural’s customers so as to result in inappropriate shifts in demand costs among Natural’s customers.” On June 15, 1984 Iowa Gas filed an application for rehearing of the Commission’s May 18, 1984 order which the Commission denied on June 21, 1984.
Ill
At the outset, we note that our review of the Commission’s orders “is essentially narrow and circumscribed.” In re Permian Basin Area Rate Cases, 390 U.S. 747, 766, 88 S.Ct. 1344, 1359, 20 L.Ed.2d 312 (1967). Section 19(b) of the Natural Gas Act, 15 U.S.C. § 717r(b) requires that “[t]he finding of the Commission as to the facts, if supported by substantial evidence, shall be conclusive.” And, as the Court in Permian Basin observed “Congress has entrusted the regulation of the natural gas industry to the informed judgment of the Commission, ... [and therefore] a presumption of validity ... attaches to each exercise of the Commission’s expertise, ...” Id. at 767, 88 S.Ct. at 1360. Thus, because the Commission is not required to adopt any particular rate design, “[o]ur review of [the] Commission's] decision ... is limited to assuring that ... [it is] reasoned, principled, and based upon substantial record evidence.” Peoples Gas Light & Coke Co. v. F.E.R.C., 742 F.2d 1109, 1111 (7th Cir.1984).
To decide if the Commission’s orders can be sustained under this narrow review, the court must determine “(1) whether the Commission abused or exceeded its authority; (2) whether each essential element of the Commission’s order is supported by substantial evidence; and (3) whether the Commission has given reasoned consideration to each of the pertinent factors in balancing the needs of the indus*740try with the relevant public interests.” Peoples Gas Light & Coke Co., 742 F.2d at 1111-12 citing Permian Basin, 390 U.S. at 791-92, 88 S.Ct. at 1372-73. The Commission must also “articulate the critical facts upon which it relies” in making its decision, particularly when it exercises its expertise to “reallocate fixed cost responsibility.” Columbia Gas Transmission Corp. v. F.E. R.C., 628 F.2d 578, 593 (D.C.Cir.1979).
Natural and NIPSCO argue that there is no substantial evidence to support the Commission’s finding that annual and monthly entitlements represent a limitation on Natural’s customers’ right to demand service, and hence the Commission’s use of entitlements as a basis for allocating and recovering costs through the demand charge cannot be sustained. They contend that the demand charge is intended solely to recover those costs from customers that are incurred by Natural to maintain that customer’s reserve capacity on the system, which, in effect, is its right to demand each day of the year its daily contract quantity. Therefore, the customer should be required to pay a demand charge that fully reflects its reserve capacity. In support of their argument that daily contract quantities and not entitlements are a proper measure of a customer’s right to demand service (i.e., reserve capacity), they point to section 22 of Natural’s tariff which provides that “[t]he conditions of this Section 22 and of Section 23 of the Tariff shall not affect the Daily Contract Quantities of the Buyers but shall limit Natural’s obligations to deliver such quantities if Natural is unable to deliver volumes requested by its Buyers within certificated Contract Demand Quantities.”
We hold that the Commission’s decision to allocate and recover one-half of the costs classified to the demand component on the basis of maximum daily quantity entitlements (daily contract quantities) and to allocate the other half on the basis of annual entitlements and to recover that half on the basis of monthly quantity entitlements is supported by substantial evidence. In its decision, the Commission essentially agreed with NIPSCO that the demand charge should reflect a customer’s right to demand service, but it decided that that right was no longer accurately reflected solely by the' daily contract quantity. The Commission found that the customer’s right to demand service was limited by entitlements, particularly monthly entitlements because Natural had absolute discretion to sell any amounts over entitlements.
This finding by the Commission is supported by provisions of Natural’s tariff that indicate that the daily contract quantities are not the only measure of a customer’s right to demand service. Section 2.4 provides that during the months of the summer period, “[a] [b]uyer may request deliveries in excess of its daily and monthly quantity entitlements, ... and Natural may make such excess deliveries if it has gas not required by it to meet its other delivery obligations and company requirements, ...” The delivery of “excess” gas is to be made only pursuant to advance operating agreements between Natural and the buyer. Thus, as the Commission pointed out, at least in the summer months customers have no absolute right to receive their full daily contract quantity, although they may demand that quantity. Any demands for gas above the daily and monthly quantity entitlements are only requests that will be filled only if Natural chooses to do so. True, because of its desire to sell all the gas that it has on hand, Natural may choose to sell the customers additional gas; but the terms of the tariff are clear that the customer cannot force Natural to deliver those amounts in the summer months, even absent curtailment. Delivery of AOR gas is “available on Natural’s system [which] in Natural’s sole judgment is not required by Natural to meet its other delivery obligations and company requirements____” If Natural refuses to sell AOR gas, the customer does incur a sub*741stantial penalty if it purchases unauthorized overrun gas.22
In addition, it is relevant that any amount of gas over entitlements is referred to as “excess” gas. “Excess” gas implies gas in amounts greater than that which the customers are entitled to receive. Authorized and unauthorized overrun gas are also defined as gas taken in excess of daily and monthly quantity entitlements, and these terms also apply even in the absence of curtailment. See Rate Schedule AOR-1 (“This Rate Schedule is available to any ... Buyer of natural gas under Rate Schedules DMQ-1 and G-l ... provided, however, that, during any month when Participating Buyers are being curtailed, pursuant to Sections 22.33 or 22.34 of the General Terms and Conditions of this Tariff, service under this Rate Schedule shall be offered first to the Participating Buyers to the extent of such curtailment.”).
In support of their argument, NIPSCO and others also point to the fact that the ALJ rejected Peoples’ CRE Index primarily on the basis that entitlements were developed in the context of providing for curtailment. But as the Commission aptly noted, the mere fact that a concept was developed to deal with a particular situation does not mean that it cannot acquire significance in another context.
Petitioners also argue that entitlements lack significance because even a customer’s right to receive daily quantity entitlements is determined by reference to maximum daily contract quantity. Section 22.32 provides that if a customer’s daily quantity entitlement for any month exceeds Natural’s peak day pipeline delivery capability under Schedules DMQ-1 and G-l for that month (“as determined by Natural”), the customer’s new daily quantity entitlement is computed by multiplying the customer’s daily contract quantity by the ratio of the peak day pipeline delivery capability for that month by the customer’s maximum daily contract quantity. But that provision also states that should the newly-computed daily quantity entitlement exceed the original daily quantity entitlement, the customer is only entitled to receive the original daily quantity entitlement. Thus the nominated daily quantity entitlement represents the maximum amount of gas that a customer may receive if Natural determines that it cannot meet the total of a customer’s requested daily quantity entitlement for any given month.
In arguing that the Commission’s rate design order is not supported by substantial evidence, NIPSCO and other parties are implicitly asserting that any rate design that does not allocate and recover fixed costs on the basis of peak day demands is unlawful.23 These parties state *742repeatedly that a pipeline’s fixed costs are only put into place to service a customer’s reserve capacity, and reserve capacity is measured by a customer’s daily contract quantity. But the Commission long ago with judicial approval rejected the argument that fixed costs should only be allocated and recovered solely on the basis of peak day demands. See supra note 14. And there is evidence in the record, see supra note 15, that fixed costs are not incurred solely to maintain reserve capacity. See also infra note 24. Moreover, in reviewing these cost-allocation decisions, the courts have recognized that the “[a]llocation of costs is not a matter for the slide rule. It involves judgment on a myriad of facts. It has no claim to an exact science.” Colorado Interstate Gas Co. v. F.P. C, 324 U.S. 581, 589, 65 S.Ct. 829, 833, 89 L.Ed. 1206 (1945); see also Consolidated Gas Supply Corp. v. F.P.C., 520 F.2d 1176, 1185-86 (D.C.Cir.1975). Thus, it is a little late in the day for some parties to be arguing that any allocation and recovery of fixed costs cannot be on a basis other than daily contract quantities.24
Even if some parties are correct that fixed costs are incurred solely to provide and maintain reserve capacity, the Supreme Court has indicated that there exists a “zone of reasonableness” in ratemaking within which the Commission may design rates. Permian Basin, 390 U.S. at 796-98, 88 S.Ct. at 1375-76. This “zone of reasonableness” has been defined by the courts, to integrate cost factors with non-cost factors and policy considerations. F.P.C. v. Conway Corp., 426 U.S. 271, 277-79, 96 S.Ct. 1999, 2003-05, 48 L.Ed.2d 626 (1976).
In this case, the ALJ specifically observed that the rate design process serves functions in addition to establishing a customer’s cost responsibility. See supra note 8. The Commission added that one reason it was adopting entitlements as a partial measure of the demand charge was to provide customers with an incentive to make more realistic nominations. All parties to the proceedings appeared to concede that, except for the winter months, nominations were not realistic. Natural also appeared to concede that, at least to some extent, it used nominations to plan and that it would be happier with more realistic nominations. Peoples presented credible evidence that realistic nominations would give Natural an incentive to better manage its gas acquisition with long-term system requirements and long-range supply circumstances. Peoples presented uncontradicted evidence that the largest component in Natural’s wholesale price was the price Natural had to pay for the gas at the well-head; it argued that any incentive Natural had to reduce its acquisition of gas would reduce gas prices and Natural’s take-or-pay obligations. Thus there is substantial evidence in the record to support the Commission’s conclusion that the use of entitlements would result in more realistic nominations and increase the efficiency of Natural’s service.25
Another one of the Commission’s goals was to make natural gas more marketable *743by reducing the commodity charge by unloading fixed costs from that charge. Under United seventy-five percent of fixed costs were recovered through the commodity charge; under Seaboard fifty percent of fixed costs were recovered through the commodity charge; under the system adopted in the present case, only thirty-five percent of fixed costs would be included in the commodity charge, although sixty-five percent of such costs would be recovered through some measure of annual use. By adopting this system, the Commission was able to unload the commodity charge, without substantially increasing the burden to be borne by load low factor customers. See discussion supra at 8. This too is a proper exercise of the Commission’s discretion to set rates to achieve purposes in addition to cost recovery.
We admit that there is some contrary evidence in the record that supports NIPSCO’s position that, in the absence of curtailment, entitlements do not affect Natural’s customers’ rights to demand their full daily contract quantity every day of the year.26 See also New Orleans Public Service, Inc. v. F.E.R.C., 659 F.2d 509, 519 (5th Cir.1981); Columbia Gas Trans. Corp., 628 F.2d at 582 n. 12. But that does not mean that the Commission’s order is not supported by substantial evidence. In most administrative proceedings, particularly complicated rate design proceedings such as this one, the evidence is bound to be contradictory, and the parties are likely to disagree over the significance of certain evidence. The function of the Commission is to employ its expertise to sort out such evidence and to reach a result that is consistent with the evidence on which it relies. It does not matter that this court might have reached a different result were it reviewing the record de novo. As long as the evidence on which the Commission relies is “such relevant evidence as a reasonable mind might accept as adequate to support a conclusion,” Refrigerated Transport Co., Inc. v. I.C.C., 616 F.2d 748, 751 (5th Cir.1980), the Commission’s order will be enforced. As we have already indicated, we are convinced that the Commission’s decision to use entitlements was based on “such relevant evidence.”27
In deciding that the Commission’s order is based on substantial evidence, we also reject NIPSCO’s argument that the new rate design results in “unjust and unreasonable rates,” or rates that are discriminatory and preferential, see 15 U.S.C. § 717c(a), since that argument is based on the contention, which we have previously rejected, that the Commission’s allocation procedure does not accurately reflect demands a customer places on the system or its basic entitlement to receive gas. Our conclusion is supported by the ALJ’s determination that all of the methods presented at the evidentiary hearing, including Peoples’, would result in just and reasonable rates.
We also agree with the Commission that it did not abuse its discretion by refusing to grant Interstate’s motion to reopen the record underlying the November 4, 1983 order to consider the 1984-85 entitlements nominations as a basis for reconsidering the new rate design for Natural’s system.
Pursuant to its own regulations, the Commission under certain circumstances will reopen the evidentiary record in a proceeding. • 18 C.F.R. §§ 385.716(a), (d) (1984). It will reopen the record “for good cause if it has reason to believe that reopening is warranted by any change in *744conditions of fact or of law or by the public interest.” Id.
Interstate recognizes that the Commission has broad discretion not to reopen an evidentiary record in a proceedings. See Bowman Transp., Inc. v. Arkansas-Best Freight System, Inc., 419 U.S. 281, 294-95, 95 S.Ct. 438, 446-47, 42 L.Ed.2d 447 (1974); Public Service Co. of Indiana, Inc. v. F.E. R.C., 575 F.2d 1204, 1217 n. 20 (7th Cir. 1978). Indeed, the courts “consistently have subscribed to the rule that administrative agencies are not to be required to reopen their final orders except in the most, extraordinary circumstances.” RSR Corp. v. F.T.C., 656 F.2d 718, 721 (D.C.Cir.1981). This rule evidences a strong preference for finality of agency proceedings; otherwise, the agency could never consummate any administrative proceeding. See also Mobil Oil Corp. v. I.C.C., 685 F.2d 624, 631-32 (D.C.Cir.1982). Notwithstanding, Interstate argues that the Commission abused its discretion by refusing to reopen the record because the 1984-85 entitlement nominations were prima facie evidence that the Commission ordered rate design produced unjust and unreasonable rates and because the Commission completely failed to explain why it rejected Interstate’s allegations of undernomination of entitlements. See Permian Basin, 390 U.S. at 792, 88 S.Ct. at 1373; Carolina Power & Light Co. v. F.E.R.C., 716 F.2d 52, 55 (D.C. Cir.1983).
We reject Interstate’s argument for several reasons. First, by the time Interstate made its motion to reopen the record, the Commission’s November 1983 order had become final, the Commission had denied NIPSCO’s and Natural’s petitions for rehearing, and NIPSCO and others had already appealed that order to this court. Although the Commission had not yet transmitted the record, the order was final, see 15 U.S.C. § 717r(a), and all parties except Interstate were prepared to litigate the lawfulness of the Commission’s rate design order. Rarely should the Commission have to reopen the record after decisions have become final.
Second, the 1984-85 entitlements did not represent “new evidence” within the meaning of Rule 716. Although the particular 1984-85 entitlements did represent new evidence in the sense that these particular figures were unavailable to the parties either during the evidentiary hearing or before the Commission, they did not represent new evidence in the sense of being unexpected; most parties, as well as the Commission, anticipated substantial reductions in entitlements. In addition, at the initial hearing, Peoples submitted, along with its proposal to use annual entitlements as part of its allocation index, a proposal to curb “abusive” undernominations by charging those who purchased gas in excess of entitlements a substantial penalty. The Commission also rejected NIPSCO’s and Natural’s contentions in their petitions for rehearing that the “control mechanism” was necessary to deter undernominations. And Interstate’s arguments presented to this court regarding the unlawfulness of the rate design system are the same arguments presented by NIPSCO and Natural which the Commission rejected. Thus, it is simply untrue that the Commission never responded to the negative impact of “undernominations.” Interstate’s real dissatisfaction then is not with the Commission’s failure to respond, but rather with the Commission’s response to its argument. Hence, the 1984-85 entitlements, although perhaps representing concrete evidence of abuse, did not represent new evidence or any material change in any condition of fact. Moreover, Interstate had the same opportunity as NIPSCO and Natural to present additional arguments to the Commission regarding the unlawfulness of the rate design order. Thus there were no “extraordinary” circumstances that would require the Commission to reopen the record.
We now turn to the issue of whether the Commission was required to investigate the alleged abusive undemominations of several of Natural’s customers before *745accepting Natural’s March 5 and March 20 tariff filings.28
In denying Iowa Gas’ protests to the two tariff filings by Natural, the Commission rejected the argument that the use of entitlements permitted customers to shift their fixed cost responsibility by undernominating with little risk because large quantities of AOR gas were available. It held that “the risks of a possibility of inadequate supplies are sufficient to ensure that the nomination procedure of Section 22 of Natural’s tariff would not be abused ...,” and it noted that all customers had the opportunity to reduce their nominations. But as petitioners point out, there is simply no evidence in the record regarding inadequate supplies, and the Commission simply failed to respond to the assertion that only some customers (partial requirements customers) can, with little or no risk, undernominate. Indeed, the Commission itself recognized that Natural was faced with and would continue to face oversupply. The Commission also recognized that Natural had large volumes of AOR gas for sale. Thus, even the Commission’s own findings contradict its finding regarding the risk of inadequate supplies.
In its brief and at oral argument, the Commission argued that it considered the possibility of abusive undernominations and rejected it because no responsible distribution company would jeopardize its ability to provide service by taking the risk of undernomination. But this is simply a post hoc justification without foundation in the record. If the Commission and other parties are right, Natural has large volumes of AOR gas for sale. Some customers, particularly those with alternative suppliers, who could save millions of dollars by undernominating, might very well take this risk. Because Natural will recover all of its fixed costs under any rate design system, it will wish to make as many AOR sales as it can, and thus few if any customers will incur “substantial penalties” for undemominating. And given that nominations are only binding for one year, a customer who gets caught undernominating will only have to pay the penalties for one year. Thus the Commission’s finding that the rate design method will in essence be self-policing is sheer speculation. Our conclusion is supported by the Commission’s concessions in its brief that “games-playing” is endemic to the rate-design process and that the record in this case suggests that the customers will undernominate. If this is true, then more, not less, regulatory oversight is needed.
The Commission attempts to characterize Iowa Gas’ concerns as speculative. But the entitlements filed show that Iowa Gas’ concerns were not totally unfounded, and it defies common sense to believe that customers would not try to reduce their demand charges to the lowest possible level by lowering their nominations.»
The Commission also argues that its decisions not to investigate are essentially unreviewable. Although this may be true in general, see Cerro Wire & Cable Co. v. F.E.R.C., 677 F.2d 124, 128 (D.C.Cir.1982) (The Commission’s refusal to investigate may only be reversed if it constitutes an abuse of discretion); see also Heckler v. Chaney, — U.S.-, 105 S.Ct. 1649, 84 L.Ed.2d 714 (1985), we do not think that the Commission can essentially abandon its regulatory function of ensuring just, reasonable, and preferential rates to Natural under the guise of unreviewable agency inaction.29 This is particularly true in this *746case. The Commission’s November 4, 1983 order did not contain, as did the Peoples’ initial proposal, any mechanism to protect against abusive undernominations. Because the rate design method ultimately adopted by the Commission was not presented by any of the parties at the evidentiary hearing, there is little evidence regarding the use of entitlements to allocate and recover demand costs without any protective measure. Peoples’ expert witness did testify that he believed that re-, sponsible customers would not jeopardize their business by grossly undernominating. Nevertheless, Peoples did believe that a protective mechanism — i.e., greatly increased prices for gas purchased in excess of entitlements — was necessary.
It is well-settled that an agency must provide a sound, well-reasoned justification based upon evidence in the record for its action. See Columbia Gas Transmission Corp., 628 F.2d at 593. In this case, the reasons the Commission gave in its May 1984 order are simply inadequate to support its refusal to investigate. Thus, although we cannot say on the basis of the record before us that the Commission’s refusal to investigate was not an abuse of discretion, we simply cannot uphold its refusal to investigate based on the rationale that it gave. We therefore remand this case to the Commission for reconsideration of this issue and a more detailed statement of the reasons for its refusal to act.

. Order Affirming in Part and Modifying in Part Initial Decision, 25 F.E.R.C; ¶ 61,176 (November 4, 1983); Order Accepting for Filing, Subject to Conditions Proposed Tariff Sheets and Granting Interventions, 27 F.E.R.C. ¶ 61,287 (May 18, 1984); Notice of Denial of Rehearing, 27 F.E. R.C. ¶ 61,429 (June 21, 1984).

. Order on Rehearing, 26 F.E.R.C. ¶ 61,203 (February 17, 1984); Order Denying Motion to Reopen Record, 27 F.E.R.C. ¶ 61,150 (April 12, 1984); Order Denying Request for Rehearing, 28 F.E.R.C. ¶ 61,137 (July 27, 1984).

. Pursuant to this court’s order of August 14, 1984, the three petitions were consolidated for review.

. Natural also provides storage and transportation to its customers. Transportation services are primarily provided for other interstate pipelines under various schedules and occur in the Gulf Coast area. Storage service is provided under separate rate schedules for thirty-five of Natural's forty-nine jurisdictional customers.

. Peoples and NSG are affiliated companies and have filed a consolidated brief.

. Central Illinois Light Company, Iowa-IUinois Gas and Electric Company, Iowa Southern Utilities Company, and Process Gas Consumers Group were all granted leave to intervene, but they did not file briefs. All but Process Gas are customers of Natural. Process Gas is a trade group of industrial users who use Natural for process and feedstock purposes, and it is a frequent intervenor in Commission proceedings.

. The definition of demand and commodity components most often cited is that given by the court in Columbia Gas Transmission Corp. v. F.E.R.C., 628 F.2d 578, 582-83 n. 12 (D.C.Cir. 1979):
The demand component of the two-part rate is related to the utility's fixed costs. These are costs associated with the customer’s basic entitlement to receive gas and with the system’s maintenance of capacity sufficient to serve maximum (or “peak") needs---- The commodity component relates more directly to the utility’s variable costs (e.g., the cost of the gas itself and the cost of compressor station fuel). These costs vary in relation to the volume of gas delivered to any customer.

. The rate design process serves functions in addition to establishing a customer’s cost responsibility. It is supposed to encourage maximum utilization of the system by both the pipeline and its customers, to assure a stable revenue flow, to provide correct market signals to producers and the marketplace, to assess similar rates for similar services, and to give incentives to the pipeline to manage gas acquisition consistent with long-term system requirements and market constraints. In considering these functions, one may take into account end-use, load loss, and the risk and costs of underutilization.

. "A customer’s annual 'load factor’ is the percentage relationship of its average daily demand [annual use/365] to its maximum daily demand [daily contract quantity].’’ Columbia Gas Transmission Corp., 628 F.2d at 584 n. 19.

. Iowa-Illinois Gas and Electric Company ("Iowa-Illinois”) and Iowa Power and Light Company ("Iowa Power”).

. This rate design method classifies twenty-five percent of Natural’s fixed costs associated with Natural’s investment in transmission and storage facilities as demand and seventy-five percent of those costs as commodity. The demand costs are allocated among the jurisdictional customers on the basis of peak demand volumes and the commodity costs are allocated on the basis of annual volumes. Iowa Power and Iowa-Illinois Gas argued that the United method was appropriate because, although Natural continued to meet its obligations on peak days, the Natural system overall suffered from underutilization. They rejected the argument that the United method resulted in the subsidization of low load factor customers by high load factor customers.

. A stipulation (the "Agreement”) entered into by Natural and the Commission providing for a full evidentiary hearing on a new rate design for Natural’s system also provided that should the Commission adopt the Seaboard rate design in any one of four rate proceedings then pending before the Commission, see Great Lakes Gas Transmission Co., Docket Nos. RP 79-10 and RP 80-134; Cities Service Gas Co., Docket No. RP 74-41; Texas Eastern Transmission Corp., Docket No. RP 75-19, rates on Natural’s system predicated upon the Seaboard rate design would supersede the United rates until the Commission ruled on the rate design issue. On February 15, 1982, the Commission issued orders in three of these cases approving the use of the Seaboard rate design. As a result, on February 18, 1983, Natural filed Seaboard rates in compliance with Article II of the Agreement, which the Commis*736sion accepted and ordered continued on April 1, 1983. Thus, during the pendency of the hearing, the Seaboard rate design governed Natural’s system.

. Under the Seaboard rate design, fifty percent of Natural’s fixed costs were classified as demand and fifty percent were classified as commodity, with the costs allocated among and recovered from Natural’s customers on the same basis as the United rate design. The Seaboard formula as initially applied to the Natural system was modified by “tilting.” See Natural Gas Pipeline Company of America, 28 F.P.C. 731, 733-35 (1962). "Tilting" is the process of returning to the demand component some of the fixed costs originally assigned to the commodity component in order to increase the marketability of gas by decreasing the commodity charge. Some customers taking gas on an interruptible ("off-peak”) basis were only required to pay the commodity charge. Hence, by "unloading” fixed costs from the commodity charge, the Commission hoped, to reduce the disincentives to "off-peak” use.

. Prior to using either the United or Seaboard rate designs, (see supra notes 11, 13) the Commission used a straight fixed-variable method where all fixed costs were classified to the demand component and allocated to peak day users. On many pipeline systems, the Commission switched to the Seaboard method, and then the United method, to discourage “end use sales" in a time of low supply and inexpensive gas prices. "End use sales” are those made directly to the user. By classifying more fixed costs to the commodity component, the commodity charge increased, thereby discouraging purchases by end users. The Commission reasoned that a pipeline is not built solely to provide service during periods of peak demand; that service to customers who do not require service on peak days also enters into system design and construction decisions; and that the "interruptible" customer who takes gas on an annual basis, but is cut off on the peak day, should also be assigned some of the fixed costs of the pipeline. Thus, the United and Seaboard methods reflected the Commission’s belief that a pipeline serves the dual purpose of supplying peak day needs and meeting annual use requirements. Seaboard, 11 F.P.C. at 53-55.

. The Staffs position was based on its beliefs that the primary goal of rate design was to assign costs to those customers who are responsible for causing them and that the pipeline’s fixed costs are incurred to provide both peak and annual use. The Staff observed that since the early 1970’s, a pipeline’s investments were made to attach new gas supplies to reduce curtailment not to increase delivery capacity. As a result, according to the Staff, costs associated with most of the post-1970 gas supply transmission facilities are most closely related to providing annual services. Thus, under the Staff’s approach, certain storage and transmission fixed costs would be classified to the demand or commodity component depending upon the purpose (supply or transmission) of the facilities that generate those costs. The remaining storage and transmission fixed costs are classified fifty percent to demand and fifty percent to commodity to reflect the dual purpose served by the pipeline. All production and gathering costs were assigned to the commodity component. The Staff recommended that with respect to Natural’s DMQ-1 customers, some of the costs in the commodity component should be unloaded, producing a disparity among these customers’ revenue responsibility and cost responsibility due to different load factors. To counteract this disparity, the Staff proposed that DMQ-1 customers be permitted to renegotiate contract demands on a monthly basis so that a customer’s demand costs more accurately reflected its actual use of the system.

. In rejecting these rate designs, the ALJ observed that in today’s market of excess supplies, the main goal of rate design should be to establish proper cost responsibility and to enhance gas marketability by reducing the commodity charge to sell the overabundance of gas supply, to prevent take-or-pay penalties, and to curb the loss of industrial sales. Thus, the current rate design should relieve the commodity component of the extensive costs placed therein by the United and Seaboard methods.

. The ALJ also observed that if demand costs are allocated solely on the basis of peak-day demands a customer could reduce its responsibility for demand costs by using storage or peak-shaving facilities.

. The ALJ noted that this dual index was "theoretically in line with Peoples’ suggested CRE index allocation system and with Staffs attempt to give weight to both peak and annual use." The peak annual index did not apply to rates for individual customers within a class; Natural’s method of recovering costs from individual customers on the basis of peak day demands was retained by the ALJ.

. Natural Gas Pipeline Co. of America’s Letter Submitting its Nineteenth Revised Sheet Nos. 301 and 302, et al., to its FERC Gas Tariff, Third Revised Volume No. 1 (GT 84-14), received March 5, 1984.

. Section 22 of the General Terms and Conditions of Natural’s Gas Rate Tariff provides, inter alia:
On or before September 30 of each year, Natural shall determine, based upon anticipated gas supplies, pipeline delivery capacity and in accordance with Paragraph 22.3 hereof, the Daily Quantity Entitlement and Monthly Quantity Entitlement which it will be able to deliver to each buyer in each of the next three Service Years. Natural shall furnish a schedule of such Entitlements and information showing the basis of determination of such quantities, to all Buyers. If any of such Entitlements for any Buyer for any month of the first, of said three Service Years (First Service Year), as so determined, is different from that shown for such month on the then effective Index, Natural, on or before October 1, shall file with the Federal Power Commission a revised Index which shall include such Entitlements determined for the First Service Year. The tariff sheets constituting such revised Index shall become effective on the next April 1.

. Natural’s Fifty-fifth Revised Sheet No. 5, et at, to its FERC Gas Tariff, Third Revised Volume No. 1, received March 20, 1984.

. There is no evidence in the record that in the past few years when curtailment has not been in effect that customers have demanded their daily contract quantities in the summer months and received it without reference to the overrun schedules. There is also no evidence that under the Service Agreement the buyer may force Natural to deliver its full daily contract quantity in the summer months. Absent such evidence, notwithstanding section 22, the Commission’s interpretation of other provisions of the tariff appears to be correct; at least during the summer months a customer’s right to demand service from Natural is limited by entitlements, even though as a practical matter that customer could, if it needed, receive gas under the AOR Schedule at no substantial penalty because of the oversupply.

. The parties who oppose the Commission’s rate design order somewhat misstate the Commission’s findings. The Commission did not find that contract demands were not a measure of Natural’s customer’s rights to demand service; rather, it found that the daily contract quantities were not the sole measure. Its rate design gives effect to the significance of daily contract quantities by employing the maximum daily quantity entitlements to allocate and recover demand costs. It should also be noted that a customer’s daily and monthly entitlements reflect, to some extent, a customer's daily contract quantity because ordinarily, in the winter months, daily entitlements and contract quantities are equivalent. Hence, the rate design adopted by the Commission, while not based solely on contract demand, is based heavily on figures that are nearly equivalent to using only contract demand. Thus, the use of daily entitlements to allocate Natural’s demand costs would render essentially the same result as using co'ntract demands. NIPSCO’s and Interstate’s claimed "losses” of $4.7 million and $1.2 million, respectively, are based on a comparison of cost responsibility under the Natural MFV and the Commission's rate design, and hence do *742not represent the so-called loss attributable to the new rate design as implemented by the 1984-85 entitlements.

. The AU expressly adopted a dual index, using daily contract quantities and annual volumes, for allocating costs, primarily because, in his view, the Commission had long ago decided that fixed costs were also incurred to provide annual service.

. NIPSCO and others argue that other functions are served by employing a rate design using only peak day demands, e.g., encouraging maximum utilization of the system. But as the AU observed the rate design process serves many functions and no single rate design can serve all of these functions. The assessment as to which functions need more attention is a matter left to the Commission’s informed judgment and its authority to make the "pragmatic adjustments” required to meet those functions. See F.P.C. v. Hope Natural Gas Co., 320 U.S. 591, 602, 64 S.Ct. 281, 287, 88 L.Ed. 333 (1944).
We do agree, however, with NIPSCO that even though rate designs involve "informed judgment" and “pragmatic adjustments," Commission orders still must be supported by substantial evidence. The Commission cannot adopt a rate design not supported by substantial evidence merely because the parties have failed to present it with a design it finds acceptable.

. Both Natural’s and Peoples’ expert witnesses stated that Natural’s customers have a right to their peak demands if Natural is not in curtailment and that absent curtailment entitlements have no effect upon Natural’s responsibility to provide service.

. Indeed, NIPSCO appears to concede that, in reality, Natural’s customers do not have a right to demand their full daily contract quantities every day of the year. Natural's system simply is not designed to serve all of its customers’ peak demands on every day of the year, although it is capable of providing such service during the winter months.

. We reject Iowa Gas’ other argument that the Commission acted improperly in accepting Natural’s late tariff filing. The Commission has the authority to waive filing deadlines where circumstances warrant it, and the Commission gave a reasoned explanation for waiving that deadline, i.e., that obsolete entitlements would be in effect and Natural would not be in compliance with the November 4, 1983 order. Thus the Commission did not act unlawfully in granting the waiver. See Port Angeles Telecable, Inc. v. FCC, 416 F.2d 243, 246 (9th Cir.1969).

. Although the rate design does not necessarily result in unjust, unreasonable, or discriminatory rates, the sole curbs on abuse and improper rates is Natural’s unilateral right to refuse to sell AOR gas. Thus Natural must enforce the rate design method by refusing to sell AOR gas to certain customers suspected of "cheating.”