Summary
finding no basis "for concluding that Transco incurs more upstream costs in serving zone 3 than zone 2 customers.... [I]t would appear that costs incurred upstream of Transco's first customer vary little, if at all, with the comparative distances of Transco customers."
Summary of this case from Public Service Co. of N.C., Inc. v. F.E.R.COpinion
Nos. 79-2182, 79-2183, 79-2184, 79-2195, 79-2213 and 79-2322.
Argued April 10, 1980.
Decided September 24, 1980. Rehearing Denied December 18, 1980.
Joseph P. Stevens with whom Michael W. Hall and Steven L. Zelkowitz, Brooklyn, N. Y., were on brief, for The Brooklyn Union Gas Co. et al., petitioners in No. 79-2213 and intervenors in Nos. 79-2182, 79-2183, 79-2184, 79-2195 and 79-2322.
Richard A. Solomon, Washington, D.C., with whom Peter H. Schiff, Gen. Counsel, Public Service Commission of the State of New York, Albany, N. Y., and Dennis Lane, Washington, D.C., were on brief, for Public Service Commission of the State of New York, petitioner in No. 79-2182 and intervenors in Nos. 79-2183, 79-2184, 79-2195, 79-2213 and 79-2322.
Morton L. Simons, Washington, D.C., with whom Barbara M. Simons, Washington, D.C., was on brief, for North Carolina Utilities Commission, petitioners in No. 79-2184 and intervenor in Nos. 79-2195 and 79-2213.
Thomas F. Ryan, Jr., Washington, D.C., with whom Richard T. Boone and David J. Evans, Washington, D.C., were on brief, for Transcontinental Gas Pipe Line Corp., petitioners in No. 79-2322 and intervenors in Nos. 79-2182, 79-2183, 79-2184, 79-2195 and 79-2213.
Gregory Grady, Washington, D.C., with whom Donald W. McCoy, Fayetteville, N.C., and F. Kent Burns, Raleigh, N.C., were on brief, for North Carolina Natural Gas Corp. et al., petitioners in No. 79-2183 and intervenors in Nos. 79-2184, 79-2195, 79-2213 and 79-2322.
Barbara J. Weller, Atty., Federal Energy Regulatory Commission, Washington, D.C., with whom Jerome Nelson, Sol., Joshua Z. Rokach, Andrew M. Zack and Howard Shapiro, Attys., Federal Energy Regulatory Commission, Washington, D.C., were on brief, for respondent.
William I. Harkaway and G. Douglas Essy, Washington, D.C., were on brief, for Consolidated Edison Co. of New York, Inc., petitioner in No. 79-2213 and intervenors in Nos. 79-2182, 79-2183, 79-2184, 79-2195 and 79-2322.
Francis J. McShalley, Washington, D.C., was on brief, for Nat. Fuel Gas Supply Corp., petitioner in No. 79-2213 and intervenor in Nos. 79-2182, 79-2183, 79-2184, 79-2195 and 79-2322.
John T. Miller, Jr., Washington, D.C., was on brief, for Elizabeth Gas Co., petitioner in No. 79-2213 and intervenor in Nos. 79-2182, 79-2183, 79-2184, 79-2195 and 79-2322.
Ira G. Megdal, Cherry Hill, N. J., was on brief, for South Jersey Gas Co., petitioner in No. 79-2213 and intervenor in Nos. 79-2182, 79-2183, 79-2184, 79-2195 and 79-2322.
William R. Duff, Washington, D.C., was on brief, for Public Service Elec. and Gas Co., petitioner in No. 79-2213 and intervenor in Nos. 79-2182, 79-2183, 79-2184, 79-2195 and 79-2322.
Eugene J. Bradley, Associate Gen. Counsel, Philadelphia, Pa., was on brief, for Philadelphia Elec. Co., petitioner in No. 79-2213 and intervenor in Nos. 79-2182, 79-2183, 79-2184, 79-2195 and 79-2322.
Robert C. Richards, Mineola, N. Y., was on brief, for Long Island Lighting Co., petitioner in No. 79-2195 and intervenor in Nos. 79-2182, 79-2183, 79-2184, 79-2213 and 79-2322.
John E. Holtzinger, Jr., Paul H. Kirk and John T. Stough, Jr., Washington, D.C., were on brief, for Atlanta Gas Light Co., intervenor in Nos. 79-2182, 79-2183, 79-2184, 79-2195 and 79-2213.
Stephen J. Small, John M. Hill and Giles D. H. Snyder, Charleston, Va., were on brief, for Columbia Gas Transmission Corp., intervenor in Nos. 79-2183 and 79-2184.
Stanley M. Morley, Washington, D.C., for Carolina Pipeline Co., intervenor in Nos. 79-2182, 79-2183, 79-2184, 79-2195 and 79-2322.
Stephen H. Watts, II, Richmond, Va., for Commonwealth Gas Pipeline Corp., intervenor in Nos. 79-2182, 79-2183, 79-2184, 79-2195 and 79-2213.
Lewis Carroll, Birmingham, Ala., for Washington Gas Light Co., intervenor in Nos. 79-2182, 79-2183, 79-2184, 79-2195 and 79-2213.
Thomas R. Hendershot was on brief, for Philadelphia Gas Works, petitioner in No. 79-2213 and intervenor in Nos. 79-2182, 79-2183, 79-2184, 79-2195 and 79-2322.
Petition for Review of an Order of the Federal Energy Regulatory Commission.
Before McGOWAN, WILKEY and WALD, Circuit Judges.
Opinion for the court filed by Circuit Judge McGOWAN.
These direct review proceedings under the Natural Gas Act involve two separate orders entered by the Federal Energy Regulatory Commission (FERC)-the successor agency to the Federal Power Commission (FPC), 42 U.S.C. § 7172(a)(1)(C). One of those orders, reflecting the Commission's consideration of rate increases filed in 1976 by Transcontinental Gas Pipe Line Corporation (Transco) with the FPC under section 4 of the Act, is challenged in respect of the 14% rate of return on equity allowed by it. The other order, entered by the Commission after a hearing initiated by it under section 5(a) of the Act, is attacked, on both procedural and substantive grounds, for its imposition of a new basis for allocating Transco's costs attributable to distance. For the reasons appearing hereinafter, we affirm with respect to the rate of return issue, but set aside the second order relating to cost allocation.
Six separate petitions for review were filed, and have been consolidated by the court for hearing and disposition. In No. 79-2322, Transco has appealed the rate of return determination of the Commission as too low, whereas North Carolina Utilities Commission (NCUC) in its petition in No. 79-2184 asserts that it is too high. In No. 79-2182, the New York Public Service Commission (NYPSC) challenged FERC's cost allocation determination; and several North Carolina utilities in No. 79-2183, NCUC in No. 79-2184, Long Island Lighting Company (LILCO) in No. 79-2195, and a group of eight utilities in Pennsylvania, New Jersey and New York in No. 79-2213, have also petitioned for review of that decision.
I
Transco operates a major long-line natural gas pipeline system running from its sources of supply in Texas and Louisiana through the southern and mid-Atlantic states to its terminus in the New York metropolitan area. Its service territory is divided into three sales rate zones: Mississippi, Alabama, and Georgia are in zone 1, the Carolinas, Virginia, and the District of Columbia in zone 2, and Maryland, Delaware, Pennsylvania, New Jersey, and New York in zone 3.
A 1962 settlement between Transco and its customers provided that customers in zone 2 would pay 2.8 cents per thousand cubic feet (Mcf) more than zone 1 customers, and that zone 3 customers would pay 3.6 cents per Mcf more than zone 2 customers. The 1962 settlement and subsequent rate settlements incorporating these cost allocations were approved by the FPC, and the rate differentials have been embodied in Transco's legally effective rate schedules.
On July 30, 1976, Transco filed with the FPC an application for $81.3 million in higher rates (Docket RP76-136). On December 30, 1976, Transco, in Docket RP77-26, proposed an increase in interruptible service rates. No change in the zone rate differentials was proposed by Transco in either of these filings. The FPC consolidated the two petitions. The parties were able to reach a partial settlement on issues not contested here that was approved by the Commission on June 27, 1978. During the interim, Transco has applied for new rates to take effect on January 1, 1978. This meant that Transco's 1976 request for a higher rate of return was limited, or locked in, to the eleven months between February 1 and December 31, 1977.
Order Granting in Part Motion for Reconsideration, Accepting Settlement Agreement in Part, and Remanding for Procedures on Contested Zoning Issue, Docket Nos. RP76-136 and RP77-26 (June 27, 1978), reprinted in Record at 4133-35.
The cost allocation issue, however, is unaffected by the later filing.
After a hearing, a FERC administrative law judge issued an initial opinion establishing 14% as a reasonable rate of return on Transco's equity for the locked-in period. The opinion also stated that the zone of reasonableness for this rate lay between 13.5 and 14.3%. This initial opinion was adopted by the Commission on August 30, 1979. The ALJ relied heavily upon testimony of the Commission's expert witness, who compared Transco's risks and rate of return to those of similar investments such as other pipelines and electric utilities. Record at 160-68. Transco's witness also compared Transco to such investments, but suggested that the Commission's witness had underestimated the risks facing Transco and concluded that from 16 1/2% to 17% would be a more reasonable rate of return. Record at 29-42, 45-51, 473.
Initial Decision on Reserved Issues, Docket Nos. RP76-136 and RP77-26 (Feb. 13, 1978), reprinted in Record at 3937-49 [hereinafter referred to as Initial Decision].
Id. at 9-10.
Order Affirming and Adopting Initial Decision, Docket Nos. RP76-136 and RP77 26 (Aug. 30, 1979), reprinted in Record at 4728A. The Commission slightly modified this order by changing the amount of interest Transco was to pay on refunds, Order Amending Prior Order, Docket Nos. RP76-136 and RP77-26 (Sept. 27, 1979), reprinted in Record at 4829-30.
The refunds were ordered because Transco has been charging rates based upon its requested 17% return on equity. Under the Natural Gas Act, a petitioning company may put into effect its requested rates subject to refund, although FERC may suspend the higher rate for up to five months. Natural Gas Act § 4(d), (e), 15 U.S.C. § 717c(d), (e) (1976). See note 13 infra.
FERC denied rehearing on the rate of return issue. Notice of Denial of Application for Rehearing and Motion for Stay, Docket Nos. RP76-136 and RP77-26 (Oct. 24, 1979), reprinted in Record at 4839.
Although Transco had not proposed any change in the 1962 zone allocations, the parties found themselves unable to agree on a method of cost allocation during settlement negotiations. Accordingly, the Commission, confronted with a claim that no change in the existing zone differentials could be made in the absence of a finding under section 5(a) of the Act that they were unlawful, ordered a hearing on this question, and, on December 19, 1978, an administrative law judge handed down an initial decision endorsing the 1962 zone differentials. However, in Opinion No. 59, the Commission rejected the decision and, without having found the existing differentials to be unlawful, ordered cost allocation not by zones but by the Mcf-mile method, which attributes cost according to volume and mileage. The change from zones to Mcf-mile would transfer about $15 million in fixed costs from customers in zones 1 and 2 to those in zone 3.
Initial Decision on Zone Rate Differentials, Docket Nos. RP76-136 and RP77-26 (Dec. 19, 1978), reprinted in Record at 4468-75.
Opinion No. 59, Opinion and Order Reversing Initial Decision and Establishing Zone Rates Based Upon Fully Allocated Costs. Docket Nos. RP76-136 and RP77-26 (Aug. 6, 1979), reprinted in Record at 4706-28 [hereinafter referred to as Opinion No. 59]. The Commission denied a motion for rehearing on this issue, Notice of Denial of Application for Rehearing and Motions for Stay, Docket Nos. RP76-136 and RP77-26 (Oct. 4, 1979), reprinted in Record at 4869.
Opinion No. 59 at 19.
The Commission justified its decision by reference to Northern Natural Gas Co., 14 F.P.C. 11 (1955), aff'd sub nom. Interstate Power Co. v. FPC, 236 F.2d 372 (8th Cir. 1956), cert. denied, 352 U.S. 967, 77 S.Ct. 352, 1 L.Ed.2d 321 (1957), where it concluded that distance was the prime determinant of the cost of transporting natural gas. Having decided on that basis that the Mcf-mile method was superior to zone allocations, the Commission then considered whether the cost-shifting effects of the Mcf-mile system should be mitigated because of (1) the historical basis of the Transco system, (2) load concentration and load factor in zone 3, and (3) storage facilities in zone 3 which benefit zone 2 consumers. NYPSC and the zone 3 customers had argued that these factors militated against using the Mcf-mile method.
Id. at 5-6.
It is perhaps worth noting that this conclusion led the FPC, in Northern Natural Gas, to allocate costs not by the Mcf-mile method, but by zones. 14 F.P.C. at 36. The Northern Natural Gas system had formerly not allocated costs by distance. Id. at 20. See section III, B infra.
These parties contend that cost allocations on the Transco system should reflect the fact that the pipeline was built thirty years ago to serve customers in zone 3 and that it would not have been built when it was without those customers. The FERC staff recommended, on this ground, to calculate costs half on the zone method, more favorable to zone 3, and half on the Mcf-mile method. Opinion No. 59 at 7.
The Commission chose not to mitigate the 100% mileage cost allocation on this ground because it found that the capacity of the pipeline had increased by a factor of eight or nine since its construction and therefore the historical roots of the Transco system were of little contemporary relevance. Id. at 7. It also commented that it could not impose costs on zone 1 and 2 customers because of factors unrelated to cost. Finally, the Commission observed that the price increase attributable to mileaging in zone 3 would not render Transco's gas less saleable. Id. at 8-9.
The zone 3 interests also argued that considerations of load concentration and load factor in their zone should be used to lessen the effect of Mcf-mile cost allocation. The pipeline's ratio of sales in zone 3 to total sales, or load concentration, was 75%, indicating that zone 3 customers accounted for 3/4 of Transco's sales. A high load concentration in zone 3 suggests that the pipeline's economies of scale, such as the use of larger-diameter pipe, are largely attributable to zone 3 customers. These customers argued that they should receive the benefit of costs avoided mostly through their use of the Transco pipeline. But the Commission declined to modify the Mcf-mile method, stating that all zones contribute to economies of scale on the Transco system. Opinion No. 59 at 15.
The Commission likewise did not give any weight to the heavier load factor in zone 3. The load factor, which is the ratio of average daily demand to maximum daily demand, was 52% in zone 3, compared to 50% in zone 1 and 36% in zone 2. Opinion No. 59 at 9 n. 13. A higher load factor suggests a more efficient use of resources, an effect that one expert source states is "quite pronounced" at load factors up to 60%. The FERC opinion said that the 50% difference in load factors between zones 2 and 3 was not "extreme" enough to warrant a departure from the Mcf-mile method. Id. at 14.
This definition is found in P. Garfield W. Lovejoy, Public Utility Economics 175 (1964).
Id.
A final consideration offered by zone 3 parties was the use of storage facilities in zone 3 to benefit zones 1 and 2. To meet peak demands for gas, Transco pipes gas sold to zones 1 and 2 in summer into storage in zone 3. In the winter, this gas is used in zone 3, and gas sold to zone 3 is delivered to customers in zone 1 and 2. The storage facilities in zone 3 provide systemwide savings because they obviate the need for increased capacity to meet peak winter demand. The Commission chose not to give this factor any weight because it found that this displacement procedure involved no physical transport of gas and therefore no material cost. Opinion No. 59 at 16.
Both zone 2 and zone 3 parties question the Commission's determination of which costs will be included in the Mcf-mile method and thus vary with distance. The Commission included in its Mcf-mile mile calculations Transco's costs of gathering and transmitting its gas before it reaches the first customer in zone 1, although it did not provide any reasons for that allocation in its opinion. At stake is the proper allocation of $30.5 million in gathering costs. Record at 292. Both Transco and the zone 3 petitioners assert that the cost of these gathering facilities upstream of Transco's closest customer cannot possibly vary with distance.
II
Judicial review of orders such as these is a delicate task. In the Permian Basin Area Rate Cases, 390 U.S. 747, 88 S.Ct. 1344, 20 L.Ed.2d 312 (1968), Justice Harlan said that reviewing courts must carefully scrutinize the Commission's decisionmaking process, but defer to its expert judgment:
The Court's responsibility is not to supplant the Commission's balance of these interests with one more nearly to its liking, but instead to assure itself that the Commission has given reasoned consideration to each of the pertinent factors. Judicial review of the Commission's orders will therefore function accurately and efficaciously only if the Commission indicates fully and carefully the methods by which, and the purposes for which, it has chosen to act . . . .
390 U.S. at 792, 88 S.Ct. at 1373. However, Justice Harlan also cautioned courts to remember 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. . . .
. . . [C]ourts are without authority to set aside any rate selected by the Commission which is within a "zone of reasonableness." FPC v. Natural Gas Pipeline Co., 315 U.S. 575, 585, 62 S.Ct. 736, 742, 86 L.Ed. 1037. No other rule would be consonant with the broad responsibilities given to the Commission by Congress; . . .
Id. at 767, 88 S.Ct. at 1360 (1968).
We think the same balance should be struck in this case. While we must pay proper deference to the expertise of the agency entrusted with administering the Natural Gas Act, and while we cannot substitute our judgment for the Commission's in weighing the relevant factors and the proffered evidence, we cannot, as some of the parties have suggested, limit ourselves to looking at the result. Our responsibility under the Natural Gas Act, § 19(b), 15 U.S.C. § 717r(b) (1976), is to determine whether the Commission, in either of these orders, exceeded or misinterpreted its authority under the Act, and to ensure that "each of the order[s'] essential elements is supported by substantial evidence." 390 U.S. at 791-92, 88 S.Ct. at 1373.
III
In 1976, when Transco filed for rate increases, it did not propose any change in the allocation of costs according to distance. It was willing to continue using the 1962 differentials that had been included in many prior rate settlements approved by the FPC. The Commission's decision, because it did not determine that the old zone rates were unjust or unreasonable and because it did not provide a reasoned explanation for the departure from settled practice, cannot withstand our scrutiny.
A. The Commission's Authority Under Section 5(a) of the Natural Gas Act
Section 5(a) of the Natural Gas Act, 5 U.S.C. § 717d(a) (1976), provides in pertinent part:
Whenever the Commission, after a hearing had upon its own motion or upon complaint . . . shall find that any rate, charge, or classification . . . collected by any natural-gas company . . . or that any . . . practice . . . affecting such rate . . . is unjust, unreasonable, unduly discriminatory, or preferential, the Commission shall determine the just and reasonable rate, . . . classification, [or] practice, . . . and shall fix the same by order . . ..
The Commission, then, has the power under the Natural Gas Act to impose its own rates or methods for their calculation upon regulated companies only after finding an existing or proposed rate unjust or unreasonable. The Commission argues that it need not make a section 5(a) determination because Transco itself has filed for new rates under section 4 of the Act. The zone 3 petitioners argue that the Commission must comply with section 5(a) and that its failure to do so denies "Transco's existing zone differentials the substantive consideration they deserved." Zone 3 Customers' Br. at 12. We agree.
The relevant portions of section 4 of the Natural Gas Act, 15 U.S.C. § 717c (1976), provide:
(a) All rates and charges made, demanded, or received by any natural-gas company for or in connection with the transportation or sale of natural gas subject to the jurisdiction of the Commission, and all rules and regulations affecting or pertaining to such rates or charges, shall be just and reasonable, and any such rate or charge that is not just and reasonable is declared to be unlawful.
(b) No natural-gas company shall, with respect to any transportation or sale of natural gas subject to the jurisdiction of the Commission, (1) make or grant any undue preference or advantage to any person or subject any person to any undue prejudice or disadvantage, or (2) maintain any unreasonable difference in rates, charges, service, facilities, or in any other respect, either as between localities or as between classes of service.
The Commission seems to be operating under the notion that it has the choice of proceeding under section 4 or section 5 of the Act. But this court and others have consistently interpreted the Natural Gas Act as offering no such choice. Justice Harlan said, almost a quarter of a century ago, that
. . . the very premise that §§ 4(d) and (e) and 5(a) are alternative, rate-changing "procedures" is itself based on a misconception of the structure of the Act. These sections are simply parts of a single statutory scheme under which all rates are established initially by the natural gas companies, . . . and all rates are subject to being modified by the Commission upon a finding that they are unlawful. . . .
The powers of the Commission are defined by §§ 4(e) and 5(a). The basic power of the Commission is that given it by § 5(a) to set aside and modify any rate or contract which it determines, . . . to be "unjust . . .". This is neither a "rate-making" nor a "rate-changing" procedure. It is simply the power to review rates and contracts made in the first instance by natural gas companies and, if they are determined to be unlawful, to remedy them.
United Gas Pipe Line Co. v. Mobile Gas Service Corp., 350 U.S. 332, 340-41, 76 S.Ct. 373, 379, 100 L.Ed. 373 (1956). This interpretation is in accord with the legislative history of the Natural Gas Act, which states that it is section 5(a) that "authorizes the Commission . . . to fix charges and reasonable rates. . . ." H.R. Rep. No. 709, 75th Cong., 1st Sess. at 5 (1937).
The decisions of this and other courts and of the Federal Power Commission itself have recognized that the Commission's power to set rates or their method of calculation is derived from section 5(a). This court has said, in the context of gas supply curtailment, that "[f]or the purpose of imposing an alternate plan, section 5 is necessary . . . . [N]owhere in section 4 is there granted the power to impose alternate rates." City of Willcox v. FPC, 567 F.2d 394, 402 (D.C. Cir. 1977), cert. denied, 434 U.S. 1012, 98 S.Ct. 724, 54 L.Ed.2d 755 (1978). The Fifth Circuit, in Southern Natural Gas Co. v. FPC, 547 F.2d 826, 832 (5th Cir. 1977), declared that the FPC "had no statutory authority to impose its own curtailment plan . . . absent its compliance with the procedural and substantive standards of section 5." The Commission itself, in its landmark case establishing zoned cost allocations, Northern Natural Gas Co., 14 F.P.C. 11 (1955), recognized that its power to reject NNG's existing uniform rates and substitute its own zone rates was based upon section 5(a). 14 F.P.C. at 19. The FPC also said that "[t]he fact that this proceeding was initiated under the primary authority of section 4(e) of the Act is immaterial." Id. at 19 n. 8.
For other cases following this interpretation of section 5(a), see, e. g., FPC v. Louisiana Power Light, 406 U.S. 621, 92 S.Ct. 1827, 32 L.Ed.2d 369 (1972); Sebring Utilities Comm'n v. FERC, 591 F.2d 1003 (5th Cir.), cert. denied, 444 U.S. 879, 100 S.Ct. 167, 62 L.Ed.2d 109 (1979); State of Louisiana v. FPC, 503 F.2d 844, 861 (5th Cir. 1974); American Smelting and Refining Co. v. FPC, 494 F.2d 925, 933 (D.C. Cir.), cert. denied, 419 U.S. 882, 95 S.Ct. 148, 42 L.Ed.2d 122 (1974).
The confusion over the statutory powers of the FPC and its successor, FERC, is perhaps based upon the curtailment cases and the context in which they arose. The FPC, to avoid the delays in processing curtailment plans that would be engendered under section 5, had ordered natural gas companies to file their own curtailment plans under section 4, giving itself the option of converting the section 4 filing to a section 5(a) proceeding if it found the proposed plans unfair or discriminatory. FPC v. Louisiana Power Light Co., 406 U.S. 621, 643-45, 92 S.Ct. 1827, 1839-1840, 32 L.Ed.2d 369 (1972). In later years, the FPC continued this practice, but reviewing courts closely monitored the Commission's orders to file plans to ensure that they were not so "coercive" as to dictate a particular plan to a natural gas company. See, e. g., Sebring Utilities Comm'n v. FERC, 591 F.2d 1003, 1015-16 (5th Cir.), cert. denied, 444 U.S. 879, 100 S.Ct. 167, 62 L.Ed.2d 109 (1979). The courts were concerned lest the Commission impose its own curtailment plans without following the formalities prescribed by section 5(a). To prevent section 5(a) from being undermined, reviewing courts approved curtailment plans filed under section 4 only if they were the product of the company's own decision. When reviewing courts found that the plans had in fact been dictated by the Commission and that section 5(a) procedures had not been followed, they did not hesitate to vacate those plans. See, e. g., State of Louisiana v. FPC, 503 F.2d 844, 861 (5th Cir. 1974). The Commission, therefore, never had the choice of imposing its own curtailment plans under section 4 or section 5(a). The curtailment cases approved only the Commission's authority to order regulated companies to file their own, not the Commission's, plans under section 4.
The Commission contends that it need not observe section 5(a) procedures because this case was commenced by Transco's filing for higher rates under section 4(e), which places the burden of proof upon the petitioner. But section 4(e) places upon the petitioner the burden of justifying its higher rates only when the petitioner has proposed an increase in rates. Therefore, we agree that Transco had the burden of proof on the rate of return question, but we cannot accept the proposition that because a company files for higher rates, it bears the burden of proof on those portions of its filing that represent no departure from the status quo.
See FPC v. Louisiana Power Light Co., 406 U.S. 621, 645, 92 S.Ct. 1827, 1840, 32 L.Ed.2d 369 (1972); FPC v. Tennessee Gas Co., 371 U.S. 145, 152, 83 S.Ct. 211, 215, 9 L.Ed.2d 199 (1962); American Louisiana Pipe Line Co. v. FPC, 344 F.2d 525, 529-30 (D.C. Cir. 1965).
See note 27 infra.
The Commission's reading of section 4(e) is inconsistent with the text of the statute, the legislative history, and sound regulatory policy. Section 4(e) states that "the burden of proof to show that the increased rate or charge is just and reasonable shall be upon the natural-gas company, . .". The emphasis is on making the petitioner justify the changes in rates, not the constant elements. With like import, the legislative history states that the "burden of proof is placed upon the natural-gas company to justify increase in rates." H.Rep. No. 709, 75th Cong., 1st Sess. at 5 (1937). The zone allocations in dispute here were no part of Transco's argument for higher rates. Forcing the petitioning company to justify not only the novel portions of its petitions but the unchanged parts as well would seriously increase the burden upon these regulated companies without any corresponding improvement in reasoned decisionmaking.
Transco's filing of a rate change continued to incorporate the existing zone rate differentials. Had Transco proposed any changes in them, the Commission, acting under section 4(e), could have approved the changes in whole or in part. Section 4(e), however, cannot be used by the Commission to institute any change in a rate-making component, such as cost allocation, that does not represent at least partial approval of the change for which the enterprise had petitioned in its filing. If the Commission seeks to make such changes, it has no alternative save compliance with the strictures of section 5(a).
We must decide whether the Commission followed the procedures of section 5 in replacing zoned cost allocations with the Mcf-mile method. Before the Commission, consistent with section 5(a), could move to the Mcf-mile method, it had to determine that the previous zone differentials were "unjust, unreasonable, unduly discriminatory, or preferential," a determination that must be supported by substantial evidence and in respect of which the Commission bears the burden of proof.
At the outset we are confronted by the Commission's failure in Opinion No. 59 to conclude explicitly that the old zone differentials are unjust or unreasonable. The opinion did state that "[t]he Commission . . . finds that no adequate or proper basis has been shown to justify the continued application of previously negotiated settlement rate differentials . . ." Opinion No. 59 at 5. We think that this statement does not qualify as a finding that the zone differentials can be voided under section 5(a), because section 5(a) places the onus of invalidating the existing method on the Commission. It is not enough that the petitioners failed to prove that the zone differentials are just and reasonable. It is the Commission which must adduce substantial evidence tending to show that the existing zone rates are unjust and unreasonable. Its failure to do so is fatal, because it lacks the authority to substitute one rate for another without adhering to the requirements of section 5(a).
The Commission argues on appeal that the zoned rates are facially unfair and unjust because they are nothing more than agreed-upon numbers without any basis in cost allocation methodology. The mere fact that these numbers resulted from settlement is not enough to prove that they are unjust or unreasonable when evidence has been introduced tending to show that they more accurately reflect cost incurrence on the Transco system than the Mcf-mile method. See section III, B infra.
In addition, we would have serious difficulty upholding the Commission on the basis of this argument, because it was first explicitly made by the Commission's lawyers on appeal. SEC v. Chenery Corp., 318 U.S. 80, 87, 63 S.Ct. 454, 459, 87 L.Ed. 626 (1943).
B. The Commission's Burden Under the Columbia Gas Rule
Last year this court held that the Federal Energy Regulatory Commission "bears the burden of explaining the reasonableness of any departure from a long standing practice, and any facts underlying its explanation must be supported by substantial evidence." Columbia Gas Transmission Corp. v. FERC, 628 F.2d 578, 586 n. 31 (D.C. Cir. 1979).
We are faced with the threshold issue of the relevance of the Columbia Gas rule to this proceeding. The Commission urges that Columbia Gas is inapplicable here because the 1962 differentials were merely numbers that did not reflect a recognized methodology and because Commission approval of settlements incorporating the zone allocations does not constitute a settled practice.
The purported distinction between a recognized method and an agreed-upon set of numbers cannot suffice to remove this case from the ambit of Columbia Gas, because the same type of agreed-upon numbers were at issue there. In Columbia Gas, the Commission had departed from use of the Seaboard method, which allocated costs equally between the demand charge, which is a fixed charge, and the commodity charge, which varies with the volume of gas consumed, and had instead adopted the United method, which changed the split to 25%-75%. Columbia Gas at 7 n. 12, 9-13. The FERC decision was remanded because this court found that the Commission had not provided a "reasoned explanation" for the switch. Id. at 14. But the Seaboard cost-allocation method is nothing more than the 50-50 split: an arbitrary number which has been criticized as having little relation to actual cost incurrence.
See Lorne, Natural Gas Pipeline, Peak Load Pricing, and the Federal Power Commission, 1972 Duke L.J. 85, 99.
Nor is it of any significance that the zone differentials in the instant case are the result of a settlement. The application of the Seaboard numbers to the Texas Gas Transmission Corp., the petitioner in the Columbia Gas case, was also a result of a settlement. See Texas Gas Transmission Corp., 52 F.P.C. 1930 (1974).
We can now turn to the Commission's Opinion No. 59 to search for the reasoned decisionmaking that justifies the deviation from zone allocations to the Mcf-mile method. Again, it is not sufficient that the petitioners have not justified the existing zone differentials. It is the Commission that must provide the substantial evidence to support its departure from long-standing practice.
The Commission tried to justify the switch to Mcf-mile by stating, as general principles, that "distance of transmission has long been regarded as having the most constant and predictable relation to cost," and that "distance is the prime determinant of . . . cost." Opinion No. 59 at 5-6. While this may well be true, it is simply not relevant to any discussion of the comparative merits of zone and Mcf-mile cost allocation on the Transco system. The question that the Commission faced was not whether it should allocate costs according to distance, but whether, given the particular circumstances of the Transco system, the Mcf-mile method did a better job of accurately reflecting those distance-related costs than did the existing zone differentials.
We do not wish to suggest that the Commission may only consider accurate reflection of costs in making these decisions. But if it wishes its order to reflect other ends it must so state. Opinion No. 59 suggests that the Commission was only interested in accurate cost allocation.
The proper place for considering the cost-based issues raised by zone 3 parties, such as load factor, load concentration, and zone 3 storage, is in choosing between zone allocations and some other method. In this case, however, the Commission decided first that the Mcf-mile method was superior and then rejected challenges to that. That technique begs the question to which all parties have a right to an answer: on the Transco system, were the zone allocations more accurate than the alternatives?
We can pretermit any extended discussion of the Commission's treatment of these mitigating factors because we cannot agree with its initial conclusion to move to Mcf-mile cost allocation. But we have reservations about the Commission's handling of some of these matters. While their conclusion that variations in load factor were not "extreme" enough to warrant a departure from Mcf-mile is an exercise of their expert judgment and thus difficult for us to disturb, their discussion of load concentration and zone 3 storage suggests flaws in the Commission's decisionmaking.
The Commission refused to attach weight to the 75% load concentration in zone 3 because it said that all zones contribute substantially to economies of scale on the Transco system. But this is not altogether responsive to the arguments of zone 3 customers, because the issue is not whether all zones contribute, but the relative contributions of the three zones. The inference that the economies of scale are mostly attributable to zone 3 remains unrebutted by the Commission's reasoning.
The Commission also refused to take the zone 3 storage facilities into account, stating that the displacement procedure involved no material cost. But the importance of the zone 3 storage lies not in costs incurred, but in costs avoided. The FPC has in the past, with the approval of this court, allocated terminal zone storage costs to all zones because the use of the facilities for displacement saved all customers money. Consolidated Gas Supply Corp. v. FPC, 520 F.2d 1176 (D.C. Cir. 1975). If these facilities save Transco and its customers money, it would seem proper that zone 3 customers get some of the benefits.
We do not concur in the Commission's argument on appeal that the zone allocations were obviously inaccurate because they were the result of a 1962 compromise, rather than of methodical calculation. The fact that parties with adverse interests agreed to those numbers, and continued to do so in later years give rise to the not unreasonable inference that many parties thought them fair at one time, although, of course, the inability of those numbers to win assent in this proceeding suggests that some of the parties now think otherwise. Further, we do not understand why the Mcf-mile method is obviously superior to the zone method when applied to Transco. While it may be true that cost increases with distance, the Mcf-mile method assigns cost by distance and volume. If there are any economies of scale on the Transco system, then the relationship between cost and distance will be far more direct than between cost and volume.
We recognize that the zone system also allocates costs by distance and volume. But the existence of economies of scale on the Transco system suggests that costs should not rise quite as rapidly for increases in volume as for distance. Thus, the lesser differentials of the zone system may reflect more closely, although still inaccurately, the ameliorative effect of economies of scale than would the Mcf-mile method.
In addition, the inclusion of upstream gathering facilities in the mileaging calculation appears to distort significantly the cost allocation imposed on the Transco system by Mcf-mile. The Commission, in its Opinion No. 59, does not provide any basis for concluding that Transco incurs more upstream costs in serving zone 3 than zone 2 customers. Although we remain deferential to reasoned decisionmaking by an expert agency, it would appear that costs incurred upstream of Transco's first customer vary little, if at all, with the comparative distances of Transco customers.
We need not decide the question of the allocation of administrative and general transmission costs by volumetric, rather than Mcf-mile, calculation, because we have not been able to uphold the Commission's determination that any form of Mcf-mile cost allocation is appropriate on the Transco system.
Finally, the record contains evidence that tends to prove the relative superiority of the zone allocation system as a more accurate reflection of cost incurrence. See Record at 1026-30, 2497. While this evidence is certainly open to dispute, it does suggest that the zone allocation figures are not facially absurd and that they deserve the reasoned consideration that the Columbia Gas rule seeks to provide.
We conclude, therefore, that the Commission's order directing the change to a mileage-Mcf allocation of costs is invalid. That is so in the first instance because of the Commission's disregard of the procedural requirements of section 5(a). The Commission erred in (1) placing the burden of proof on the opponents of the change in cost allocation rather than upon itself and (2) failing to make the findings that the existing zone rates legally in effect were unlawful. Without such findings, section 5(a) does not empower the Commission to prescribe a different method of cost allocation affecting differential rates. In any event, the evidence of record supporting that prescription falls short of substantiality.
IV
The Commission determination of 14% as a reasonable return on Transco equity for the eleven-month "locked-in" period faces attack from two sides. On one flank, NCUC argues that the rate of return is too generous because the decision did not take into account Transco's allegedly inept management and unused facilities. On the other, Transco contends that the Commission's determination is neither supported by substantial evidence nor consonant with Columbia Gas.
The Commission dismissed NCUC's contentions of inept management and unused facilities on the grounds that the petitioner had not introduced any evidence to support these claims. Initial Decision at 7 n. 5. NCUC had argued that the depth of curtailment of service on the Transco system suggested both conclusions, but the Commission concluded that mere curtailment, even to 50% of capacity, did not of itself establish bad management or idle facilities. We find nothing in the record to warrant our disturbance of the Commission's judgment.
In support of its claim that the 14% is too low, Transco first argues that it is not possible to trace the path by which the ALJ, and thus the Commission by adoption of the ALJ initial decision, arrived at the 14% figure. We think it is. We begin with the testimony, on which the ALJ primarily relied, of the staff's expert witness, who had himself concluded that 14% was a reasonable figure.
The staff expert compared the risks facing Transco with those facing other regulated companies. He divided risks between the possibility of business reverses, which is called business risk, and financial risk, which varies with the amount of debt and preferred stock and thus with the size of the firm's interest and dividend obligations. Record at 163-64. While it is not in dispute that Transco's relatively thin equity ratio of 24.1% indicates a higher level of financial risk and thus justifies a higher level of return on equity than other pipelines, there is considerable disagreement concerning the degree of business risk that Transco faces.
Equity ratio is the percentage of common equity to total capital. Transco's capital structure in 1977 was 63% long-term debt, 13% preferred stock, and 24% common stock. Initial Opinion at 6 n. 4.
The staff witness suggested that the two types of risk are related: a regulated utility such as a pipeline company with a relatively low business risk but a relatively higher financial risk may still attract investors. Record at 164. This appears sensible, since a company looking forward to consistent profitability can worry less about high fixed interest charges or dividends that would constitute a threat to the solvency of the firm should profits evaporate. Thus, a high level of financial risk is relatively less important to a firm, such as a regulated pipeline, with a relatively low business risk.
The staff witness found that Transco's business risks, chiefly related to the possibility of gas supply shortages, were lessening because the company's exploration program was expected to produce improved supplies. Record at 167-68. However, the staff witness found Transco's business risks to be slightly above average. Having found Transco's business and financial risks to be somewhat higher, although not remarkably so, than other pipelines whose allowed rates of return fell between 13.5% and 13.75%, the staff witness recommended a rate of return of 14%. Record at 168; Initial Opinion at 9-10.
Transco assigns as error the ALJ's dismissal of Transco's evidence. The ALJ had refused to credit the Transco witness's comparison of Transco with electric utilities because, according to the ALJ, electric utilities are entitled to a higher rate of return because of their greater capital requirements. Transco on appeal claims that the Commission had traditionally thought of gas pipelines as riskier than electric utilities and thus the ALJ's reasoning is unsupportable.
We do not think that the ALJ's assertion, if it is in fact flawed, would be fatal to the Commission, because substantial evidence supports the portions of the ALJ's decision that justify a 14% return. The staff witness's estimate was adopted, and the Transco witness's estimate was not, because the ALJ and the Commission concluded in an exercise of their expert judgment that the staff witness's estimate of the risks facing Transco compared to those facing other gas pipelines was superior to the estimate made by Transco's witness. The dispute facing the ALJ turned on Transco's risk to investors, not whether this risk was more or less than that of electric utilities.
The Initial Opinion also takes note of Transco's "modest prosperity" despite chronic natural gas shortages as justifying a rate of return no higher than 14%. Id. at 9. By this the ALJ is apparently referring to Transco's earnings compared to those of other major pipeline companies. Except for 1974, an aberrationally bad year, Transco consistently earned more on its equity than the pipeline average, Exhibit No. 17 at 2. Its earnings per share also increased from 1974 to 1976. Record at 482.
There were two minor errors in the first version of this exhibit which, when corrected, indicated that comparable pipelines actually earned less on their equity than had been first stated. Thus, the corrected version makes Transco's performance relative to comparable pipelines look even better.
Transco presented its own witness who came to rather different conclusions. The Transco witness found the company's business risks related to gas supplies "five [or] ten-fifteen years down the road" more significant than had the staff witness. Record at 464. The ALJ, noting that the rates in question were locked in for only an eleven-month period, refused to attach weight to the possibilities of natural gas shortages five to fifteen years from the time when the rates in this docket were applicable.
Transco objects that the Commission is departing from past practices in refusing to consider long-term risks in a locked-in rate proceeding. We think that Transco misperceives the thrust of the relevant cases it cites. Those cases held that the Commission should look to the long-term cost of raising capital and other pertinent risks even when it is considering locked-in rates. The rationale of these cases is unexceptionable: a regulated company faces the same long-term problems regardless of the frequency of its rate filings. To look only at short-term risks and costs in considering a locked-in rate raises the possibility that the company will never be adequately compensated for long-term risks and costs present during the locked-in period.
See Municipal Light Boards v. Boston Edison Co., 53 FPC 1543, 1556 (1975); American Louisiana Pipe Line Co., 28 FPC 482, 486 (1962). It is also possible that the practice is not quite as settled as Transco contends, given the number of relevant cases to which it could point.
But the administrative law judge did not dismiss the risk of gas supply shortages solely because he was deciding a locked-in rate. He concluded that the risk was not likely to arise at all during the locked-in period. The long-term costs of raising capital and the pertinent risks of confronting the company when it makes its request are ongoing factors present during the locked-in period. The risk of gas supply shortages ten or fifteen years from the locked-in period may well not concern investors at all during the locked-in period. The ALJ's opinion also suggests that he found the risk to speculative and thus not pertinent to Transco's petition. Given the testimony of the staff's witness that Transco's supply situation should improve, the ALJ was acting well within his expert judgment in disregarding the conjectures of Transco's witness.
Transco also attempts to persuade us that the Commission's 14% determination is deficient under the Columbia Gas rule, because the Commission had thrice before approved Transco settlements that included a 14.75% rate of return and had allowed pipelines with thicker equity ratios returns between 13.5% and 13.75%. We do not think that Columbia Gas can be applied as Transco has suggested.
We think that the Commission complied with the requirements of sections 4(e) and 5(a) of the Natural Gas Act in making its rate-of-return determination. Reading sections 4(e) and 5(a) together, we conclude that the Commission is not obliged to bear the burden of proving a change resulting from higher rates unjust. It need only conclude that the petitioner has failed to carry its burden of proof. Against a background of obvious conflict in credible testimony, the conclusion that Transco failed to carry its burden is inherent in the Commission's determination that any rate higher than 14.3% falls outside the zone of reasonableness.
However, when the Commission not only voids a proposed rate increase, but institutes a rate of its own under section 5(a) rather than continuing the old rate in effect, it must adduce substantial evidence to prove (1) that the old rate is unjust and unreasonable and (2) the Commission's proposed rate is just and reasonable. The Commission's conclusion that only rates between 13.5% and 14.3% are just and reasonable and the substantial evidence that supports it fulfill the requirements of section 5(a) on both necessary findings.
The contrast between the situation facing the decisionmaker in Columbia Gas and in this case is illuminating. In Columbia Gas, the Commission was choosing between present practice and a discrete alternative. Here the ALJ faced an infinitude of choices from a low of 13.5% to a high of 17% without any distinct point of departure. He was confronted with evidence and precedent suggesting that almost any figure he chose in that range would find some support. Based on expert testimony, he picked 14% as the most reasonable rate within a zone of reasonableness extending from 13.5% to 14.3%.
It could not be said that earlier practice had been opposed to his judgment. The Commission approved settlements at 14.75% as just and reasonable, but did not indicate that neighboring figures might not also be just and reasonable, or even more just and reasonable. The other cases all involved facts to some extent different from those at issue here; the weight to give those differences was ultimately unquantifiable and reserved for expert judgment.
The relevance of FERC approval of rates of return of between 13.5% and 13.75% on equity ratios of 36% to 37% in other cases is especially suspect. The staff's expert had said that variations in financial risk vary in importance with the degree of business risk. Having found Transco's business risk just slightly above average for pipelines, and thus far safer than unregulated enterprises, the ALJ acted reasonably in granting only a slightly higher rate of return for Transco's markedly thinner equity ratio.
Extension of Columbia Gas in the manner suggested by Transco would lead the Commission into a swamp of past decisions of varying degrees of relevance with widely scattered outcomes. The Commission could be caught in a withering cross-fire, with some litigants demanding adherence to past settlements involving this company, and others demanding adherence to rates involving similar firms, or even, as Transco asks here, substantial departure from rates granted to dissimilar firms on the grounds that failure to pay adequate heed to the differences constitutes departure from settled practices.
We think that the burden this court placed upon the Commission in Columbia Gas to explain its switch from one method to a discrete alternative was reasonable. We think that making the Commission explain why it did not choose every other plausible result when it is faced with a multitude of possible outcomes and with precedents whose relevance is a matter of judgment and which do not suggest any one settled practice is both unreasonable and unlikely to advance the cause of reasoned decisionmaking.
Our task in reviewing the reasonableness of a particular rate of return, therefore, is not to see whether it nestles closely to past decisions on a plot of rates of return against equity ratios, but to ensure that the Commission's judgment is supported by substantial evidence and that the methodology used in arriving at that judgment is either consistent with past practice or adequately justified under the Columbia Gas decision. Having concluded that the Commission decision was supported by substantial evidence, we need only examine whether the methodology used by the Commission was in keeping with past practice. In this case, there is no dispute that the Commission's expert witness used the traditional comparable earnings and risk tests. Indeed, Transco's witness used the same methodology, Transco Br. at 15-17, but arrived at different conclusions because he judged the risks rather differently. The Commission's reliance upon settled methodology is all that is required to fulfill the standards of Columbia Gas.
V.
The partial stay of December 11, 1979 provided that the higher rates collected from zone 3 customers would be held by Transco in an escrow fund, to be distributed to customers in zones 1 and 2 if Opinion No. 59 were to be upheld and to zone 3 customers if Opinion No. 59 were to be reversed. Since we have reached the conclusion that FERC's rate of return order may stand, while its cost allocation order and opinion must be reversed, the December 11 order requires those monies, plus earnings, held in escrow by Transco be distributed, as contemplated by the court, to the customers in sales zone 3.
Our reversal on the cost allocation issue allows us to pretermit resolution of the propriety of the exclusion of LILCO's marginal cost evidence from the proceedings leading up to the adoption of the Mcf-mile method. See Record at 745-46, 760-83. Similarly, we are not confronted with the Commission's refusal to apply the lower Mcf-mile rates retrospectively in zones 1 and 2.
It is so ordered.
. . . . .
(d) Unless the Commission otherwise orders, no change shall be made by any natural gas company in such rate, charge, classification, or service, or in any rule, regulation, or contract relating thereto, except after thirty days' notice to the Commission and to the public. Such notice shall be given by filing with the Commission . . . .
(e) Whenever any such new schedule is filed the Commission shall have authority, either upon complaint of any State, municipality, State commission or gas distributing company, or upon its own initiative without complaint, at once, and if it so orders, without answer or formal pleading by the natural gas company, but upon reasonable notice, to enter upon a hearing concerning the lawfulness of such rate, charge, classification, or service; and, pending such hearing and the decision thereon, the Commission, upon filing with such schedules and delivering to the natural gas company affected thereby a statement in writing of its reasons for such suspension, may suspend the operation of such schedule and defer the use of such rate, charge, classification, or service, but not for a longer period than five months beyond the time when it would otherwise go into effect; and after full hearings, either completed before or after the rate, charge, classification, or service goes into effect, the Commission may make such orders with reference thereto as would be proper in a proceeding initiated after it had become effective. If the proceeding has not been concluded and an order made at the expiration of the suspension period, on motion the natural-gas company making the filing, the proposed change or rate, charge, classification, or service shall go into effect. Where increased rates or charges are thus made effective, the Commission may, by order, require the natural-gas company to furnish a bond, to be approved by the Commission to refund any amounts ordered by the Commission, to keep accurate accounts in detail of all amounts received by reason of such increase, specifying by whom and in whose behalf such amounts were paid, and, upon completion of the hearing and decision, to order such natural-gas company to refund, with interest, the portion of such increased rates or charges by its decision found not justified. At any hearing involving a rate or charge sought to be increased, the burden of proof to show that the increased rate or charge is just and reasonable shall be upon the natural gas company, and the Commission shall give to the hearing and decision of such questions preference over other questions pending before it and decide the same as speedily as possible.