Opinion
No. 88-4348.
February 7, 1990.
Joanne Levegue, Jerome M. Feit, Sol., F.E.R.C., Washington, D.C., for F.E.R.C.
Michael W. Hall, Kenneth T. Maloney, Cullen Dykman, Washington, D.C., for Brooklyn Union Gas Co.
John S. Schmid, Schiff, Hardin Waite, Washington, D.C., for Delmarva Power Light Co.
Barbara K. Heffernan, McCarthy, Sweeney Harkaway, Washington, D.C., for Consol. Edison Co. of N.Y., Inc.
John E. Holtzinger, Jr., John T. Stough, Jr., Newman Holtzinger, Washington, D.C., for Atlanta Gas Light Co.
Michael J. Fremuth, Andrews Kurth, Washington, D.C., for Transcontinental Gas Pipe Line Corp.
Gregory Grady, Richard H. Davidson, Washington, D.C., for N.C. Natural Gas Corp. and Public Service Co. of N.C., Inc.
Morton L. Simons, Washington, D.C., for N.C. Utilities Com'n.
Petition for Review of an Order of the Federal Energy Regulatory Commission.
Before CLARK, Chief Judge, BROWN, and JOHNSON, Circuit Judges.
As a fallout from FERC Opinions 260 and 260A the issue is whether the Commission could properly impose on Transco the mandatory use of a "3-day Peak" in cost allocation for D-1 charges. We hold FERC could not do so and vacate the order and remand to the Commission for further proceedings.
The term "fallout" is deliberately used since, as later discussed, the issue of 3-day Peak was neither considered nor acted upon by the Commission (or parties) in ops. 260 and 260A.
Op. 260. Transcontinental Gas Pipe Line Corp., 37 FERC ¶ 61,328 (1986).
Op. 260A. Transcontinental Gas Pipe Line Corp., 40 FERC ¶ 61,188 (1987).
In the Beginning
Way back in March 1942, Transco filed a proposed general rate increase under § 4(e) of NGA ( 15 U.S.C. § 717c). In its filing Transco allocated peak demand costs to its 3 rate zones on the basis of customer contract entitlements, the same method consistently used by Transco for many years. By an order April 1982, FERC accepted and suspended the filing and set the case for a hearing. After settlements not an issue herein there was reserved for hearing issues related to cost classification, cost allocation and design of Transco's basic sales rates. At the hearing held concerning these issues no party proposed a change in Transco's longstanding method of allocating peak demand cost on the basis of customer's contract entitlement.
Zone 1: Extends from the Louisiana/Mississippi border to the Georgia/South Carolina border. Atlanta is the largest sales customer in Zone 1 accounting for approximately 70% of all Zone 1 sales.
Zone 2: Extends from Georgia/South Carolina border to the Virginia/Maryland border.
Zone 3: Extends from the Virginia/Maryland border to the terminus of the pipeline system in the New York City metropolitan area.
Transcontinental Gas Pipe Line Corp., 19 FERC ¶ 61,083 (1982).
22 FERC ¶ 61,238.
Maximum daily contract entitlement represents the quantity of gas the firm customer has nominated based upon the customer's own individual assessment of the quantity of gas that will be used by the markets it serves on the coldest days. Since, on the Transco System, it is the customers' daily firm service reservation, rather than their annual reservations that determines the size, configuration, and cost of the facilities Transco installed and must maintain, providing firm services to Zones 1, 2, 3 amounts to the sum of customers nominated maximum daily contract entitlements that Transco has designed its system to provide.
The process of allocating costs to each zone is an important step in determining a pipeline's rates. Since each customer's contract gives the customer the right to demand service up to the contractual level, Transco has consistently allocated peak demand costs to each of its zones on the basis of sales customers' peak contract entitlements.
Time Marches On
Progress was being made. The ALJ issued the initial decision September 1984. The ALJ made no findings that Transco's longstanding method of allocating peak demand costs based on contract entitlements was unjust, unreasonable or otherwise violated the NGA.
Transcontinental Gas Pipe Line Corp., 28 FERC ¶ 63,068 (1984).
On December 30, 1986, FERC issued op. 260 (n. 2, supra) in which it adopted a Modified Fixed Variable (MFV) method of cost classification and rate design. The Commission in Op. 260 did not in any way indicate that it intended to alter Transco's longstanding method of allocating peak demand costs. Indeed, it stated:
The demand costs allocated on the basis of peak usage would be assigned to D-1 and the demand cost allocated on the basis of annual usage would be assigned to D-2.
37 FERC at ¶ 61,959.
With no challenge on rehearing to the method of allocation of peak costs, the Commission in op. 260A (n. 3, supra), made clear that no alteration in Transco's longstanding peak demand cost allocation was intended or determined with respect to D-1 costs. As FERC stated:
Under Opinion No. 260, the fixed costs in the D-1 component are to be allocated on the basis of peak demand entitlement (contract billing units) and the fixed costs in the D-2 component are to allocated on the basis of test year volume.
40 FERC at ¶ 61,584.
The Commission expressly reversed its earlier decision that D-2 costs be allocated on the basis of test year volumes by requiring D-2 costs to "be allocated on the basis of the annual right to demand service", 40 FERC at ¶ 61,585, which meant allocation on the basis of customer's maximum contract entitlements on an annual basis.
Petitions for rehearing op. 260-A were overruled. 41 FERC of ¶ 61,018 (1987) with the Commission reiterating its previous statement that allocation of peak demand costs would be allocated on the basis of contract entitlements. See, 41 FERC at ¶ 61,040 and ¶ 61,048.
Finally, 3-day Peak
Following the issuance of Opinion No. 260-A, Transco filed revised tariff sheets. Transco's compliance filing provided for the allocation of peak demand D-1 costs on the basis of customers' contract entitlements.
By a Letter Order October 19, 1987, the Director of the Commission's office of Pipeline and Producer Regulation (DOPPR) rejected Transco's filing for the reason that Transco has not:
(1) allocated transmission demand costs (D-1) to each zone under the MCF-mile methodology based on 3-day Peak volumes as required by Commission policy.
Petitioners filed an appeal of Staff action which appeal was denied by the Commission January 1988.
Transcontinental Gas Pipeline Corp., 42 FERC ¶ 61,053 (1988).
In response to then petitioners (which included Brooklyn Union Gas Co.) the Commission adopted the view of those supporting the Director's Letter Order which followed the Commission's claimed practice of allocating fixed transmission costs on the basis of peak day factors. Denying the appeal from the District Director's letter order, the Commission stated:
Historically, it has been an established Commission policy that allocation of D-1 cases should be on the basis 3-day peak usage. There is no reason to alter that Commission policy here. Opinion No. 260 states that `the demand costs allocated on the basis of peak usage would be assigned to D 1 . . . the resulting D 1 and D 2 amounts would then be used to design rates for Transco's customers, with D-1 charges determined on the basis of contract billing units. Petitioners incorrectly characterize the quoted language. Opinion No. 260 differentiated between cost allocation and rate recovery; the Commission held that D-1 demand cost would be allocated to customers on the basis of peak usage and that the D-1 charges would be recovered from customers on contract billing units.'
On the basis of this the Commission then summarized:
While the language and Opinion No. 260-A should have been more precisely written, it is clear, given the well-documented Commission policy on this issue and the fact that there was no D-1 cost allocation issue in Opinion Nos. 260 and 260-A, that the language in Opinion No. 260-A did not signal a change in Commission policy.
And then, the Commission, probably unaware that it was about to concur in the petitioner's contentions that cost classification and cost allocation are utterly different, concluded:
Rather, the language in Opinion No. 260-A should be construed as referring to the billing determinants to be used to recover D-1 cost from customers, not cost allocation issues.
Little in Controversy
In the analysis of the Commission's action we are in essential agreement with the petitioners that there is no serious dispute with respect to the following material facts and circumstances:
1. Implementation of the 3-day Peak formula of allocating peak demand D-1 costs on the Transco system will produce a significant monetary cost shift from sales customers in Zone 1 to sales customers in Zones 2 and 3.
2. Transco's longstanding practice of allocating peak demand costs on the basis of customers' maximum daily contractual entitlements was the "norm" or "policy" on the Transco system for many years.
3. Transco's rate increase filing proposed no change in the longstanding contract entitlements method of allocating peak demand costs.
4. All the witnesses who testified on cost classification, allocation, or rate design matters, including the staff witness, used Transco's "traditional contractual entitlement basis" of allocating peak demand costs as a part of the exhibits and analyses showing what the results of adopting their various recommendations would be.
See R. 8179, n. 22.
5. No peak demands (D-1) cost allocation issue was addressed in either Ops. 260 or 260-A.
6. In contrast to the total absence of controversy regarding allocation of peak demand (D-1) costs, issues respecting the allocation of annual demand (D-2) costs were fully litigated.
7. Unlike other pipeline systems where the Commission has prescribed use of the 3-day peak formula, the Transco system is designed and constructed to meet the maximum daily contract entitlements of all its firm customers at the same time.
In this analysis we also reject any suggestion that the Commission's use of general terms "peak usage" or "peak volumes" are synonymous with and can only mean "3-day Peaks."
In the cases cited by the Commission in the Jan. 1988 Order (n. 9, supra), see, e.g., East Tennessee Natural Gas Co., 40 FERC ¶ 61,277, 61, 906-7 (1987); and Texas Eastern Transmission Corp., 30 FERC, ¶¶ 61,144, 61,273 (1985). When the Commission prescribed a 3-day Peak formula it utilized the specific term "3-day Peak."
To Invalidate Established Practice Put Burden on Commission
Transco's rate filing which precipitated the settlement, reserved issues and ultimately ops. 260 and 260-A were all bottomed on a continuation of its longstanding practice of allocating peak demand costs on the basis of customers' maximum daily contract entitlements. No change of these practices was ever called into question by Transco's customers, the Commission or its staff. For there to be any mandated change in these practices the Commission somehow articulately had to justify this departure. Whether, as most likely, this had to take the form of a finding by the Commission that the practice had become unjust and unreasonable under § 5 ( 15 U.S.C. § 717d) we do not need to precisely decide. At a minimum it had to reflect a reasoned decision. Permian Basin Area Rate Cases, 390 U.S. 747, 791-92, 88 S.Ct. 1344, 1372-73, 20 L.Ed.2d 312 (1968); New Orleans Public Service Inc. v. FERC, 659 F.2d 509, 515 (5th Cir. 1981).
See, Public Serv. Com'n. v. FERC, 642 F.2d 1335 (D.C. Cir. 1980), 1345:
[W]e 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.
Forcing the (filing) company to justify not only the novel portions of its petitions but the unchanged parts as well which seriously increase the burden upon these regulated companies without any corresponding improvement in reasoned decision-making.
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) 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).
Approved, New Orleans Public Service Inc. v. FERC, 659 F.2d 509, 523-4 (5th Cir. 1981).
A reasoned decision would have called for some notice that the matter of 3-day Peak was in dispute. It is uncontradicted that in the whole proceeding never was "3-day Peak" used or even mentioned in allocation of demand costs.
In response to the Court's questions on argument Counsel for the Commission advised that references were made to 3-day Peak at:
JA3
JA9
JA12
JA3357
JA3 referred not to cost allocation but whether the conditions existing in 1977 still prevailed. JA9 does not mention the term 3-day Peak at all. JA12 and JA 3357 referred to a separately different matter: The allocation to GSS Contract storage service of two distinct transmission line segments, the division of which occurs prior to the allocation of system cost to sales zones.
A reasoned decision would also have contained some discussion on why failure to employ 3-day Peak was objectionable or at least its use would have been preferable to the continuation of the practice of contract demand entitlements. Yet Ops. 260 and 260-A are completely silent on this and the first notice that 3-day Peak was involved was the Director's cryptic announcement and the Commission's denial of the appeal from the Director's letter order (n. 9, supra).
The FERC Solicitor conceded (Brief at 15) that the Commission never even acknowledged, in Ops. 260, 260-A or in the January 1988 Order, that Transco's consistent practice of many years was being changed by the Commission.
3-day Peak Policy Dubious
As to the Commission's asserted policy of 3-day Peak, questions exist whether (1) any such general policy exists and (2) if so, does it provide support for a Commission's action here.
First, contrary to the Commission's suggestion, this alleged policy is not set forth in the Commission's regulations. Second, the Commission has never used such policy to keep Transco from basing its rates on an allocation of peak demand costs on contract entitlements just as it has done in other cases:
See, e.g., Great Lakes Transmission Co., 17 FERC ¶¶ 63,028, 65095-96 (1981) (affrm. 24 FERC, ¶¶ 61,014, 61,063 (1983); Southern Natural Gas Co., 29 FPC 323, 343-45 (1963).
Reliance on the Commission's primary example of the policy, Texas Eastern Transmission Corp., 30 FERC ¶ 61,144 (1985), is misplaced. On Texas Eastern the 3-day Peak method of demand cost allocation has been the established practice. See, Texas Eastern Transmission Corp., 4 FERC ¶ 61,348 at ¶ 61,342 (1978) so too was its reliance on East Tennessee Natural Gas Co., 40 FERC ¶ 61,277 (1987).
Remand Necessary
Since, for the reasons outlined, the Commission erred in rejecting appeal from the Director's Letter Order requiring 3-day Peak, the cause must be remanded to the Commission. On remand the parties, after due notice of the contested issues, must be afforded the fullest opportunity to ascertain, pro and con, the issues of Transco's practices, the validity or invalidity thereof, and the correct method of allocation of peak demand costs.
We reject Atlanta's claim that petitioners lost the right to challenge the Commission action because it sought no rehearing of Ops. 260 or 260-A, or both, since the issue was in no way involved therein. Opinion No. 260-A made clear that the Commission was retaining the traditional contract demand allocation methodology for peak demand D-1 cost. Consequently, no petition for review was necessary or would lie.
VACATED AND REMANDED.