Columbia Gas Transmission Corp. v. Federal Energy Regulatory Commission

831 F.2d 1135, 265 U.S. App. D.C. 376

• Court: Court of Appeals for the D.C. Circuit
• Decided: October 27, 1987
• Docket: Nos. 85-1846, 85-1847, 86-1021, 86-1074, 86-1082, 86-1164 and 86-1187
• Status: Published

Opinion

BUCKLEY, Circuit Judge:

Petitioners challenge Federal .Energy Regulatory Commission orders permitting five pipelines to recover a surcharge from their customers on gas already sold to them. The amount of the surcharge would, in effect, reimburse the pipelines for the amounts that the pipelines had subsequently been required to pay to producers for certain deferred production-associated costs. The principal issue in these cases is the propriety, under the governing statutes, of such a surcharge.

We conclude that the Commission exceeded its authority when, without proper notice, it approved what in effect were retroactive increases in the price of natural gas previously sold by the pipelines to their customers.

I. Background

Under the Natural Gas Act (“NGA”), 15 U.S.C. §§ 717-717w (1982), natural gas companies are required to keep on file with the Federal Energy Regulatory Commission (“FERC” or “Commission”) “schedules showing all rates and charges for any transportation or sale [of natural gas] subject to the jurisdiction of the Commission.” 15 U.S.C. § 717c(c) (1982). Under the Natural Gas Policy Act of 1978 (“NGPA”), 15 U.S.C. §§ 3301-3432 (1982), Congress established ceiling prices for “first sales” (typically sales by producers to pipeline companies (“first purchasers”)) of various categories of natural gas. 15 U.S.C. §§ 3312-3319 (1982). In section 110 of the NGPA, Congress permitted natural gas producers to charge for certain production-related costs in excess of the ceiling prices established under the NGPA:

[A] price for the first sale of natural gas shall not be considered to exceed the maximum lawful price applicable to the first sale of such natural gas under this part if such first sale price exceeds the maximum lawful price to the extent necessary to recover.—

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(2) any costs of compressing, gathering, processing, treating, liquefying, or transporting such natural gas, or other similar costs, borne by the seller and allowed for, by rule or order, by the Commission.

15 U.S.C. § 3320(a) (1982).

Upon enactment of the NGPA, the Commission immediately issued, and at the same time sought public comment on, interim regulations to implement section 110. Interim Regulations Implementing the Natural Gas Policy Act of 1978 §§ 271.101-271.1106, 43 Fed.Reg. 56,448, 56,552-77 (1978). The Interim Regulations did not implement every provision of the NGPA, but merely proposed guidelines to deal with those areas demanding the most immediate attention. Id. at 56,452. Part 271 of the Interim Regulations specified the maximum lawful prices applicable to first sales of natural gas. Id. at 56,552. Subpart K prescribed “regulations under which a price for a first sale of natural gas shall not be considered to exceed the applicable maximum lawful prices set forth in Part 271 if such first sale price exceeds the maximum lawful price to the extent necessary to recover ... production related costs approved by order of the Commission under § 271.1105.” Id. at 56,574.

In 1980, FERC amended Subpart K to, inter alia, (1) allow sellers of committed or dedicated natural gas under the NGPA to apply for production-related costs in excess of NGA allowances, (2) permit certain sellers of natural gas to collect NGA allowances without applications, and (3) provide for a new category of production-related costs (“other costs”). Order No. 94: Order Amending Interim Regulations Under the Natural Gas Policy Act of 1978 and Establishing Policy Under the Natural Gas Act, 45 Fed.Reg. 53,099 (1980).

In the same order, the Commission announced that it would not accept applications for “compression costs” until the Commission completed proceedings to determine an appropriate generic allowance:

Compression is perhaps the single most complex cost category which we must consider for a production-related add-on. First, of the activities specifically listed under section 110, compression, more than any other, can be undertaken as a production or nonallocable activity. Second, no standard or prevailing industry practice now exists for determining the costs of compression. This means that a seller seeking to add-on compression costs must make a showing as to the costs incurred and the type of compression undertaken. If this must be done case-by-case for each seller there is a potential for long delay and inconclusive results. Rather than this approach (which was the approach of the interim regulations issued in December 1978), we believe that an appropriate allowance for compression can be determined which would apply for specific kinds of compression. To this end we will inaugurate a generic proceeding to determine the appropriate allowance____ During the pendency of the proceeding, in our exercise of discretion, we will accept no applications for compression costs.

Id. at 53,107 (footnote omitted). The Commission initiated the same kind of proceeding to establish an appropriate generic allowance for “gathering costs.” Id. at 53,-108. The Commission assured first sellers that “a retroactive collection procedure will be provided under which the allowance for compression [and gathering] costs determined under the generic rulemaking will be applied to costs incurred with respect to gas delivered on or after the effective date of this Rule if collection of such costs is contractually authorized.” Id. at 53,107 (footnote omitted).

In the meantime, first purchasers of the gas had recourse to an existing method for recovering these additional estimated costs from their customers; namely, a system of prospective charges called “purchased gas adjustment clauses” (“PGA clauses”). 18 C.F.R. § 154.38(d)(4) (1987). PGA clauses, like rates, must be filed with and approved by the Commission before being put into effect. Proposed PGA clauses must also be accompanied by cost studies “based upon actual costs for the 12 months of most recently available actual experience.” 18 C.F.R. § 154.38(d)(4)(i). This mechanism thus permits pipelines to recover through prospective sales, on the basis of reasonably current calculations, the fluctuating production-related costs they are required to reimburse producers.

In 1983, the Commission issued Order Nos. 94-A, 48 Fed.Reg. 5,152 (1983), and 94-B, 48 Fed.Reg. 5,190 (1983), containing its long-promised regulations addressing generic compression and gathering cost allowances. These orders authorized natural gas producers to recover retroactively from first purchasers the costs incurred by the producers in the delivery and compression of natural gas (“deferred costs”) delivered to the pipelines prior to March 7, 1983 (the effective date of Order Nos. 94-A and 94-B), but after July 25, 1980 (the effective date of Order No. 94) or the date on which the producer filed an application with the Commission for reimbursement of the deferred costs, whichever was earlier. 18 C.F.R. § 271.1104(e) (1987).

A number of first purchaser pipeline companies sought to pass these costs on to their customers (“downstream purchasers”). To this end, they petitioned FERC for permission to bill their customers directly for the customers' pro-rata shares of these deferred expenses, such billing to take the form of a surcharge for gas purchased by each customer during the three-year period between the issuance of the interim order (Order No. 94) and the final orders (Order Nos. 94-A and 94-B). In five cases, the Commission issued orders

* granting pipeline companies permission to do so. The “direct billing” method for reimbursement is described in the proposal submitted by Transcontinental Gas Pipeline Corp. (“Transco”) and approved by the Commission. Under its terms, Transco undertook

to calculate each customer’s share of the retroactive allowances based on each customer’s actual purchases during each month to which the retroactive allowances apply. Each customer’s total amount due, plus interest, will then be billed and paid in equal installments over a twelve-month period, or paid in a single lump-sum payment at the customer's option.

32 F.E.R.C. 1161,230 at 61,543. Thus, in contrast with the prospective PGA clause mechanism, the direct billing procedure was designed to provide pipelines with a method for recovering retroactively, through a system of surcharges, the amounts the Commission determined they were required to reimburse producers for production-associated costs that had accrued during the three-year period.

Petitioners have appealed each of the five orders. Columbia Gas Transmission Corp. and the Municipal Defense Group (representing a number of distribution companies that purchase natural gas from pipeline companies) challenge the legality of direct billing on the ground that it constitutes retroactive ratemaking prohibited by the Natural Gas Act. Columbia Gas also asserts that the direct billing procedure is inconsistent with FERC’s own precedent, and that the PGA clause mechanism is the only method (aside from filing for rate increases) that is authorized for recovering such additional expenses.

The Commission, supported by various intervening pipeline companies, defends its approval of the direct billing procedure on the basis of its equitable results, as it would require customers to pay the actual cost of the gas they have purchased. The Commission also argues that its orders do not constitute retroactive rulemaking because the Commission’s 1980 and 1983 orders provided adequate notice that the deferred costs would be passed along to the pipelines and their customers.

Although Transco supports the concept of direct billing, it challenges FERC’s decision to apply a different rate of interest on amounts previously collected under PGA clauses that Transco must now refund to customers and the rate it may apply in calculating the total amount to be recovered from them through direct billing. The Commission has admitted that its consideration of this issue was based on error and, on November 24, 1986, it moved that we remand this one issue for further consideration.

II. Analysis

A. The Rule Against Retroactive Rate-making

Both Columbia and the Municipal Defense Group challenge direct billing as constituting retroactive ratemaking and therefore contrary to law. The Commission defends its decisions to allow pipeline companies to directly bill their customers for deferred production-related expenses on the basis of an equitable result:

The Commission ... determined that allocating these costs to the pipelines’ customers on the basis of volumes purchased at the time the costs were incurred “will equitably bill customers for the higher amounts they should have paid based on actual purchases during the past billing periods.” This is a sound reason for adopting the direct billing method; thus the Commission’s choice of that method is rationally based.

Brief for Commission at 13 (quoting Transco, reh’g and clarification denied, 33 F.E.R.C. 1161,213 at 61,443); see also, e.g., Transco, 32 F.E.R.C. 1161,230 at 61,543 (“[Transeo’s proposal] is administratively effective, equitable, and meets our concern that pricing signals not be distorted by the influx of substantial retroactive Order No. 94-A costs. Above all, it will break up the logjam that has existed and permit a relatively speedy passthrough of long overdue cost responsibility.”). The Commission further argues that “Order Nos. 94 and 94-A put everyone on notice that these compression and gathering costs would be retroactively collected, once the Commission determined the appropriate method and dollar amount.” Brief for Commission at 14 (citing Transco, 32 F.E.R.C. H 61,230 at 61,-544-45, and 33 F.E.R.C. H 61,213 at 61,443).

Although the parties have mounted an extensive semantic battle over whether the FERC orders amount to retroactive rate-making (or rate authorization), the effect of the orders is quite clear: downstream purchasers are expected to pay a surcharge, over and above the rates on file at the time of sale, for gas they had already purchased. However described, this constitutes a retroactive rate increase that we find to be prohibited by the NGA. While that prohibition might have been overridden through adequate notice that purchasers would be expected to pay the deferred charges at a later date, Order Nos. 94 and 94-A did not constitute such notice. Because they were addressed exclusively to first sales of natural gas, they cannot be deemed to have placed downstream purchasers on notice that they in turn would be expected to absorb those costs through a system of surcharges collected after the fact. Thus there is no support for the Commission’s assertion that its orders “put everyone on notice.”

The rule against retroactive ratemaking is derived from the provisions in the NGA requiring sellers of natural gas to file their rates with the Commission and defining its authority to modify them. The pertinent statutory language reads as follows:

Under such rules and regulations as the Commission may prescribe, every natural-gas company shall file with the Commission, ... and shall keep open in convenient form and place for public inspection, schedules showing all rates and charges for any transportation or sales subject to the jurisdiction of the Commission____

15 U.S.C. § 717c(c).

[T]he Commission shall have no power to order any increase in any rate contained in the currently effective schedule of such natural gas company on file with the Commission, unless such increase is in accordance with a new schedule filed by such natural gas company____

15 U.S.C. § 717d(a).

These provisions form the basis for the “filed rate doctrine.” In its discussion of the doctrine in Arkansas Louisiana Gas Co. v. Hall, 453 U.S. 571, 576-78, 101 S.Ct. 2925, 2929-30, 69 L.Ed.2d 856 (1981), the Supreme Court notes that

the [Natural Gas] Act bars a regulated seller of natural gas from collecting a rate other than the one filed with the Commission and prevents the Commission itself from imposing a rate increase for gas already sold.

Id. at 578, 101 S.Ct. at 2931. Moreover, the Court explicitly states, in a footnote, that “the Commission may not impose a retroactive rate alteration and, in particular, may not order reparations____” Id. at n. 8 (emphasis in original) (citing FPC v. Sun-ray DX Oil Co., 391 U.S. 9, 24, 88 S.Ct. 1526, 1534, 20 L.Ed.2d 388 (1968)).

We have recently had occasion to explain, in the case of electrical utilities, the rationale for prohibiting retroactive increases in filed rates:

The wholesale purchasers of electricity cannot plan their activities unless they know the cost of what they are receiving, particularly if they are retailers, who must calculate their appropriate resale rates, ... but also if they are large-scale purchaser-users. Providing the necessary predictability is the whole purpose of the well established “filed rate” doctrine, which “forbids a regulated entity to charge rates for its services other than those properly filed with the appropriate federal regulatory authority.”

Electrical Dist. No. 1 v. FERC, 774 F.2d 490, 493 (D.C.Cir.1985) (quoting Arkansas Louisiana Gas Co. v. Hall, 453 U.S. 571, 577, 101 S.Ct. 2925, 2930, 69 L.Ed.2d 856 (1981)). Although FERC claims that “Order Nos. 94 and 94-A gave notice that the prices paid for gas during the pendency of the Commission’s rulemaking were not final prices,” Brief for Commission at 16, the orders were explicitly concerned with first sales. Furthermore, even in that context, the Commission was careful to limit the application of Order No. 94-A to those cases in which first purchasers were contractually bound to pay the deferred costs.

As a general matter, the final rules will not operate to authorize the collection of amounts for production-related costs incurred prior to today. A basic principle of administrative procedure is that rules should operate prospectively only. We see no reason to depart from this principle in implementing these amendments. To the contrary, there is good reason to adhere to it.

48 Fed.Reg. at 5,161. In a footnote to the above-quoted section, the Commission stated:

An exception is made in the case of delivery or compression services. However, this exception is based upon the Commission’s notice in Order No. 94 that these costs could be recovered. In addition, this recovery is under particular safeguards to insure that amounts collected for these services may only be collected if contractual authority existed to collect them at the time they were incurred.

Id. at n. 89 (emphasis added); see 18 C.F.R. § 271.1104(c)(4)(H). It is thus clear that the notice provided by the two orders was limited to a highly restricted audience.

Furthermore, contrary to what the Commission suggests, Brief for Commission at 16 n. 10, notice may not be imputed as a result of the “passthrough” provision in section 601 of the NGPA, 15 U.S.C. § 3431(c). While section 601 permits a pipeline to recover any amount paid for natural gas that “is deemed to be just and reasonable for purposes of sections 4 and 5 of [the NGA],” id. § 3431(c)(2)(A), we read nothing in the language of the section to warrant a resort to retroactive as opposed to prospective rate increases.

We need not address whether the Commission might have accomplished the goal of permitting pipelines to pass these costs on to their customers (in proportion to their takes in the three-year period following Order No. 94) through a system of specific PGA clauses for each account because that issue is not before us. See Brief for Commission at 20. Such a device, in any event, would differ significantly from that selected by the Commission, as it would allow all surcharged customers to plan accordingly and would enable those with access to more than one pipeline to respond to the surcharges by reducing purchases from the pipeline(s) imposing the highest additional costs. Nor need we determine whether the Commission, in order to avoid unjust enrichment, might “have ordered pipelines to begin collecting production-related cost surcharges at the time of issuance of Order No. 94, subject to adjustment when Order No. 94-A specified the exact production-related cost allowances.” Joint Brief for Intervenor Pipelines at 22 (citing Kansas Cities v. FERC, 723 F.2d 82, 93 (D.C.Cir.1983)). As none of the parties has demonstrated that proper notice was afforded to pipeline customers that they might be subject to a surcharge on past purchases, we decline to address this hypothetical issue.

B. Prior FERC Precedent

Columbia Gas argues also that the Commission’s decision to permit direct billing for deferred expenses is inconsistent with prior Commission opinions, orders, and regulations, and that the Commission failed to provide an adequate explanation of why it departed from its prior rulings. Because we hold the Commission acted beyond its authority in approving the direct billing of deferred costs, we need not decide whether its explanation of its alleged departure from past practice was sufficiently reasonable.

C. The Interest Decision

Transco argues that it is being penalized in the amount of almost a million dollars by the FERC order allowing direct billing because it is required to pay customers a higher rate of interest on amounts it is required to refund from past PGA clause collections than it is allowed to charge those same customers on their shares of directly billed deferred costs. Because we find the FERC orders allowing direct billing to be ultra vires, the question of the interest differential is moot. Accordingly, we deny the Commission’s November 24, 1986 motion to remand that issue for further consideration.

III. Conclusion

The five orders on review violate the NGA’s prohibition against retroactive rate-making. We therefore strike the orders authorizing direct billing and remand to the Commission for further proceedings consistent with this opinion.

So ordered.

Transcontinental Gas Pipe Line Corp. ["Transco"], 32 F.E.R.C. ¶ 61,230, reh'g and clarification denied, 33 F.E.R.C. ¶ 61,213 (1985); Texas Eastern Transmission Corp., 32 F.E.R.C. ¶ 61,-493, reh'g denied, 33 F.E.R.C. ¶61,257 (1985); Texas Gas Transmission Corp., 33 F.E.R.C. ¶ 61,032, reh'g denied, 33 F.E.R.C. 1161,359 (1985); Panhandle Eastern Pipe Line Co., 33 F.E.R.C. ¶ 61,218 (1985), reh’g denied, 34 F.E. R.C. ¶ 61,231 (1986); and Trunkline Gas Co., 33 F.E.R.C. ¶ 61,217 (1985), reh'g denied, 34 F.E. R.C. ¶ 61,021 (1986).