Court Opinion

ID: 7859538
Source: CourtListenerOpinion
Date Created: 2022-09-08 17:51:23.401369+00
Date Added: 2024-06-11T16:30:11.119444
License: Public Domain

Opinion for the Court filed by Circuit Judge STEPHEN F. WILLIAMS.
Opinion concurring in part and dissenting in part filed by Circuit Judge MIKVA.
STEPHEN F. WILLIAMS, Circuit Judge:
We deal here with complications arising from a change in the way the Federal Energy Regulatory Commission treats pipeline-produced gas as a component of an interstate pipeline's sales rates.
Under the Natural Gas Act of 1938, 15 U.S.C. § 717 et seq. (1988), the Commission sets the sales prices of interstate pipelines selling natural gas at wholesale. From the start, its predecessor (the Federal Power Commission) used the historical cost of pipeline-produced gas as a component of the ceiling price for a pipeline’s final sales. FPC v. Hope Natural Gas Co., 320 U S. 591, 607-15, 64 S.Ct. 281, 290-94, 88 L.Ed. 333 (1944); Colorado Interstate Gas Co. v. FPC, 324 U.S. 581, 597-604, 65 S.Ct. 829, 837-40, 89 L.Ed. 1206 (1945). Later, of course, as a result of the Supreme Court decision in Phillips Petroleum Co. v. Wisconsin, 347 U.S. 672, 74 S.Ct. 794, 98 L.Ed. 1035 (1954), the Commission started to regulate independent gas producers’ wellhead sales, initially with the same historic cost method. For independents’ sales it soon moved to a system of regional and then national price ceilings, based only indirectly on cost. It made a similar shift for most pipéline-produced gas, but retained the his*335toric cost system for “old gas” (measured by date of well or lease).
Passage of the Natural Gas Policy Act of 1978, 15 U.S.C. §§ 3301 et seq. (1988), explicitly transformed the treatment of independents’ wellhead sales. It replaced the Commission’s system with a complex schedule of congressionally fixed prices (incorporating the Commission’s regional and national rates for some categories); it also provided for gradual deregulation. But the NGPA did not explicitly resolve how to treat a pipeline’s own gas in computing its selling price. The Commission originally believed that pipeline-produced gas was not covered by the NGPA at all and that for “old gas” it should continue to use the historic cost method. In Public Service Commission of New York v. Mid-Louisiana Gas Co., 463 U.S. 319, 103 S.Ct. 3024, 77 L.Ed.2d 668 (1983), however, the Supreme Court held that Congress intended to include pipeline-produced gas under the NGPA. That still left open whether the historic-cost figures used for pipeline-produced “old gas” were “just and reasonable” rates, as the term was used in § 104 of the NGPA, 15 U.S.C. § 3314. If so, § 104 required the pipeline to use those figures, as in effect on April 20, 1977, adjusted for inflation. If not, then the pipeline could use the ceiling that would have been applicable on that date if it had been buying from an independent, i.e., a regional or national rate, similarly adjusted for inflation. The second method would usually lead to a higher figure. The Commission ultimately adopted it. See Order No. 391-B, First Sales of Pipeline Production under Section 2(21) of the Natural Gas Policy Act of 1978, 40 FERC ¶ 61,174 (1987), reh’g denied, Order No. 391-C, 42 FERC ¶ 61,145 (1988), aff'd, Midwest Energy, Inc. v. FERC, 870 F.2d 660 (D.C.Cir.1989).
El Paso Natural Gas Company has made “purchased gas adjustment” filings under § 4 of the NGA, effective starting October 1, 1983, under which its production is to be “costed” at the rates applicable to independent producers. Two issues have arisen. First, though it is now common ground that the figure for its own gas is to come from a hypothetical sale from an independent to El Paso, there is dispute over what kind of sale. Should El Paso receive the higher prices that the Commission allowed independents who signed “replacement” contracts for expired ones, hoping thereby to give pipelines the leverage to prod independents into dedicating more gas to the interstate market? Second, El Paso in the era of historic costing enjoyed certain accelerated tax deductions, i.e., was able to deduct certain items for income tax purposes sooner than for regulatory accounting purposes, but of course at the expense of being unable to deduct them later. The sums saved in the short-run went into a deferred tax account, earmarked for future tax liabilities. However, now that El Paso has switched away from cost-of-service pricing for its gas production to ceiling prices under the NGPA, the “turnaround” anticipated under tax normalization will never come to pass. The question therefore arises as to the proper disposition of the remaining funds in El Paso’s deferred tax account. Can (or must) the Commission use that account to reduce El Paso’s current rates?
An earlier Commission stab at these issues came before this court in Public Utilities Commission of California v. FERC, 817 F.2d 858 (D.C.Cir.1987). We remanded FERC’s decision on the deferred tax reserve fund for want of reasoned decision-making, and found the pricing issue unripe for judicial review. FERC readdressed both issues in light of this court’s remand. El Paso Natural Gas Company, 43 FERC ¶ 61,272 (“Order ”), reh’g denied, 44 FERC ¶ 61,073 (1988) (“Order on Rehearing ”). El Paso appealed certain aspects of these latest orders; the California Public Utilities Commission (which we here call just “California”), the representative of some of El Paso’s customers, appealed the rest. For the reasons discussed below, we must once again remand the case to the Commission.
I. Replacement Contract Rate
The parties agree that the gas is covered by § 104 of the NGPA, 15 U.S.C. § 3314(a) (1988), but disagree as to the proper subca*336tegory within § 104. El Paso seeks to price its gas at the “replacement contract” rate. Roughly speaking, this applies to gas sold under a contract replacing a previous contract which had expired by its terms. 18 C.F.R. § 271.402(b)(4).1 California, on the other hand, argues that El Paso is entitled only to the “flowing gas” rate, a catch-all category within § 104 that applies to any gas (not covered by any other category) which was “produced from a well the surface drilling of which commenced prior to January 1, 1973.” 18 C.F.R. § 271.402(b)(8). It is the rate that would be applicable to an independent’s sales where they were made under a “life-of-the-lease” contract, i.e., one which could not expire by its own terms until the well ceased production. The replacement contract rate is nearly double the flowing gas rate.2
Of course El Paso never had contracts with itself. As the controlling categories depend on contracts, however, they must be imputed. El Paso argues for using replacement contracts, saying that this is necessary in order to fulfill the Commission’s conclusion in Order No. 391-B that there should be “parity of pricing between pipeline producers and other producers, both independent and affiliate.” 40 FERC at 61,546. More concretely, it argues that since most of its contracts with independents were 20-year contracts, one should treat its transfers to itself as if they had been governed by the same kind of contract.3 The Commission, as we understand it, bought the substance of that argument. If all El Paso’s contracts with independents were 20-year contracts, then El Paso’s view would prevail entirely. But the Commission held that the imputation should occur “in accordance with [El Paso’s] contracting pattern,” so that if El Paso bought 80 per cent of its independent-supplied gas under fixed-term contracts, then 80 per cent of its own gas would enjoy replacement-gas rates (at least assuming passage of 20 years). If 20 per cent of its purchases from independents were under “life-of-the-lease” contracts, then 20 per cent would receive the flowing gas rate. It ordered hearings before an administrative law judge to secure the facts needed to apply this principle of proportionality. Order on Rehearing, 44 FERC at 61,205.
El Paso suggests offhandedly in a footnote that this remand makes it “premature” for the court to review the Commission’s decision. See Brief of Intervenor El Paso at 7 n. 6. Although El Paso never makes clear the exact nature of its claim here, we must address it to the extent that it questions the finality of the orders under review, as finality is necessary to our jurisdiction. See, e.g., Bell v. New Jersey, 461 U.S. 773, 777-80, 103 S.Ct. 2187, 2190-92, 76 L.Ed.2d 312 (1983).4
*337The Natural Gas Act simply provides that a “party ... aggrieved by an order” of the Commission may seek review, § 19(b), 15 U.S.C. § 717r(b) (1988),5 but the Supreme Court as early as 1938 found a requirement of finality in the parallel provision of the Federal Power Act, FPC v. Metropolitan Edison Co., 304 U.S. 375, 384, 58 S.Ct. 963, 967, 82 L.Ed. 1408 (1938), and the lower courts extended the requirement to the NGA. See Atlantic Seaboard Corp. v. FPC, 201 F.2d 568, 572 (4th Cir.1953). This court has consistently noted that the finality inquiry is to be a pragmatic one. See, e.g., United Municipal Distributors Group v. FERC, 732 F.2d 202, 206 n. 4 (D.C.Cir.1984); Delmarva Power & Light Co. v. FERC, 671 F.2d 587, 592 (D.C.Cir.1982); Papago Tribal Utility Authority v. FERC, 628 F.2d 235, 239 (D.C.Cir.1980).
Here there is little practical concern pointing against review. There is no suggestion that immediate review would interfere with or frustrate the administrative process. Indeed, the AU has proceeded with the task and found that 98.5% of El Paso’s contracts with independent producers were fixed-term contracts, 89.3% of which were 20-year contracts. Compare Metropolitan Edison, 304 U.S. at 383-84, 58 S.Ct. at 966-67 (expressing concern over “constant delays” that review of procedural orders would entail). As FERC has already finally decided the substantive issue on appeal to us, review now does not prevent it from bringing its expertise to bear. See, e.g., ASARCO, Inc. v. FERC, 777 F.2d 764, 772 (D.C.Cir.1985) (distinguishing cases where judicial review “involve[d] no pre-emption of the agency’s primary jurisdiction”). Indeed, the Commission itself wants us to review the replacement contract issue now. Cf. NRDC v. EPA, 859 F.2d 156, 167 (D.C.Cir.1988) (giving weight to agency position on ripeness); United Municipal Distributors Group v. FERC,
732 F.2d 202, 207 n. 6 (D.C.Cir.1984) (same). A possible benefit for the agency is that our resolution of the merits may moot the ongoing proceedings before the agency. See Parks v. Pavkovic, 753 F.2d 1397,1402 (7th Cir.1985) (“if this appeal is allowed and the state persuades us that no damages should be awarded, an expensive computation involving thousands of bills will be avoided”).
There appears little risk that immediate review will increase the burden on the courts. There is no possibility that the remaining proceedings might moot the case by giving victory to the loser on other grounds. See FTC v. Standard Oil Co. of California, 449 U.S. 232, 242, 101 S.Ct. 488, 494, 66 L.Ed.2d 416 (1980); Ciba-Geigy Corp. v. EPA, 801 F.2d 430, 434 (D.C. Cir.1986); Papago, 628 F.2d at 240. The only remaining concern is that immediate review will increase the risk of multiple reviews where one would be more economical. See Standard Oil, 449 U.S. at 242, 101 S.Ct. at 494. Two aspects of the remand to the AU suggest the risk is modest. First, the task before the AU appears to have been somewhat mechanical and thus unlikely to generate issues for judicial review at all. Second, even in the event of a second appeal, it does not appear that any such issues would be analytically entangled with the present, one, which involves solely the basic principle of how best to analogize El Paso’s role as a producer for itself to the role of independents selling to interstate pipelines. See Parks, 753 F.2d at 1402 (relying on similar features «f residual issues in finding finality under 28 U.S.C. § 1291); see also Boeing Co. v. Van Gemert, 444 U.S. 472, 479 & n. 5, 100 S.Ct. 745, 749-50 n. 5, 62 L.Ed.2d 676 (1980) (reviewing as final a money judgment against the defendant in class action in which the damages against the class as a whole had been determined, but the claims by individual absentee class members re*338mained to be addressed); Love v. Pullman Co., 569 F.2d 1074, 1076 (10th Cir.1978) (reviewing as final a “formula” for determining back pay in a successful class action Title VII case, even though computation of actual damages was referred to a master); cf. St. Louis Shipbuilding and Steel Co. v. Casteel, 583 F.2d 876, 876 n. 1 (8th Cir.1978) (decision of Benefits Review Board, reversing AU and supplying a new formula to be used in determining benefits to be awarded, is final under 33 U.S.C. § 92(d)). Compare Liberty Mutual Ins. Co. v. Wetzel, 424 U.S. 737, 744, 96 S.Ct. 1202, 1206-07, 47 L.Ed.2d 435 (1976) (order deciding liability but leaving damages to be computed at later proceeding not final). We note that Commission rate orders often appear to leave detail issues to “compliance” filings, without anyone supposing that this deprives them of finality. See Union Electric Co. v. FERC, 890 F.2d 1193, 1197 (D.C.Cir.1989).
On the merits, we find no adequate explanation of the Commission view that El Paso’s pattern of contracting with independents should govern the classification of the gas it produces. On rehearing, for example, it said, “Complete parity requires looking to substance and not form by pricing pipeline production as if the gas had been produced by an independent producer.” 44 FERC at 61,204. Neither this nor anything the Commission has said explains why El Paso’s conduct as buyer should govern the classification of its gas for purposes of fixing its revenues as seller.
More important, FERC’s theory does nothing to address California’s argument that it should place El Paso’s gas into the (imputed) contract category that best corresponds to the economic realities of pipeline-owned gas. That correspondence, it argues, depends on the Commission’s purpose in allowing enhanced rates for replacement-contract gas but not for gas sold under an original, unexpired contract (or, indeed, a contract negotiated to replace a life-of-the-lease contract).
The Commission’s apparent theory in allowing increased prices for replacement contract gas was that expiration of a contract in accordance with its terms gave the pipeline an opportunity to tempt the producer to dedicate additional acreage and commit itself to more exploration and development activities. Evidently the Commission reasoned that only where the pipeline could refuse to renew a contract, leaving the producer’s gas dedicated to interstate commerce but unsold, would it be able to extract additional drilling or acreage commitments in exchange for higher prices. See Opinion No. 699-H, Just and Reasonable National Rates For Sales of Natural Gas, 52 FPC 1604, 1632 (1974); Opinion No. 770-A, National Rates for Jurisdictional Sales of Natural Gas, 56 FPC 2698, 2717-20 (1976). Whatever the precise theory, California makes the seemingly persuasive argument that since El Paso necessarily drilled all the wells in question with the expectation of receiving only the historic cost rate for pipeline-produced gas, none of the gas can possibly be a response to the incentive price created for “replacement gas.” In any event, we think the Commission must try to relate its current imputation process to the theory of its earlier distinction. In particular, it must respond to California’s contention that gas should not receive the replacement contract rate in the absence of some reason to associate the gas with the incentives that that rate was intended to afford.
While we seriously doubt whether the Commission can justify allowing El Paso replacement contract rates for its company-produced gas under any theory, we remand this aspect of the case to the Commission rather than reverse.
II. Deferred Tax Reserve Fund
Under cost-of-service pricing, a utility’s rates are set to allow recovery of all costs of production. Income taxes are among the costs recoverable. A problem arises when the tax code allows a firm to deduct an expense for income tax purposes sooner than the Commission allows it to .charge its customers with the item. Thus, while the federal income tax laws allow immediate expensing of certain “intangible drilling costs” of a well, they are for regulatory *339accounting purposes treated as a capital item, and recovered by an annual depreciation charge over the life of the well. In such a case a question arises as to how to time the tax benefit (i.e., the tax reduction resulting from the accelerated, non-conforming deduction of costs for tax purposes).
Under the “flowthrough” method, a utility must pass the tax benefit on to customers in the year received under the tax laws. Under “normalization” — the method applied to El Paso before the switch to NGPA pricing — the utility spreads the tax benefit over the life of the relevant asset, so that a customer, in any given year of the asset’s life, will both bear the burden of depreciation allocable to that year and enjoy whatever tax benefit is associated with that depreciation. This is known as the matching principle. See Public Systems v. FERC, 709 F.2d 73, 76 (D.C.Cir.1983) (Public Systems II).
Normalization thus allows a utility to charge its customers more in tax costs in the early year(s) of an asset’s life than the firm pays out in taxes. The tax savings of course are temporary. Assuming no change in rate or other disturbance, the utility must make it up in later years of the asset’s life. In the meantime it builds up funds that are reserved for the later taxes. The Commission requires a utility to deduct the amount of the fund from its rate base, in order to reflect the fact that with respect to a certain portion of its rate base the utility has no interest cost. While this has the effect (roughly) of giving customers the benefit of the interest or other earnings on the fund, the Commission has flatly rejected the notion that normalization can properly be analogized to a loan from customers to the utility. See Order No. 144, Regulations Implementing Tax Normalization for Certain Items Reflecting Timing Differences in the Recognition of Expenses or Revenues for Ratemaking and Income Tax Purposes, FERC Stats. & Regs. [1977-1981] ¶ 30,254 at 31,539, Order No. 144-A (Order Denying Rehearing), FERC Stats. & Regs. [1982-1985] ¶ 30,340 (1982), aff'd, Public Systems v. FERC, 709 F.2d 73 (D.C.Cir.1983).
In the case of El Paso’s gas production assets, the reserve amounted to about $100 million dollars as of October 1, 1983, the date of El Paso’s switch to NGPA pricing. See Order on Rehearing, 44 FERC at 61,-207. The switch of course wiped out the premise of tax normalization — that the price of natural gas would be tied to historic cost and that El Paso would directly charge its customers the annual depreciation on its gas production assets. Thus the matching principle has ceased to operate as an explicit guide. Both El Paso and its customers claim the tax reserve. California argues also that even if El Paso may keep the fund, its customers should enjoy its earning power as it is gradually drawn down for payment of deferred taxes.
FERC originally determined that the fund and its earnings should remain with El Paso. The previous panel remanded on the grounds that FERC had inadequately explained the decision. It left the Commission free to proceed on remand as it saw fit (within the bounds of the law). On remand, the' Commission split the baby. While adhering to its original decision on the fund, it ordered that El Paso’s customers should receive its earnings so long as it existed. (The Commission assumed it would be drawn down to pay deferred taxes associated with income from the relevant production assets.) See 44 FERC at 61,207. This credit to the customers was to be achieved, as before 1983, by deducting the fund balance from El Paso’s rate base.
We find the Commission’s credit for the fund’s earnings not in accordance with law. (The reasons will make apparent why its disposition of the principal is correct.) The fundamental difficulty with the credit of the fund’s earnings is that it is not attached to, derived from, or related to any service that El Paso provides or has provided in the periods covered by the PGA filings, i.e., October 1, 1983 and thereafter. It is plain that the credit does not attach to El Paso’s transmission service. It does not in any logical sense apply to El Paso’s *340current gas costs: as to those, § 601 of the NGPA, and the Supreme Court’s decision in Mid-Louisiana, entitle the pipeline to NGPA rates—not NGPA rates reduced by a credit to adjust for tax controversies related to prior years. Finally, if the credit rests on a Commission view that the rates collected for gas prior to October 1983 were in retrospect too high, then the credit violates the rule against retroactive rate-making.
1. Transmission service. It hardly seems worth arguing that El Paso’s gas production facilities do not contribute to its provision of gas transmission service, but the Commission’s order (at least in form) pretends otherwise. The credit is given customers by deducting the fund from the rate base. But with the switch to NGPA pricing, the only investments in that rate base are ones relating to gas transmission. As the Commission noted in another case: “To the extent that the Mid-Louisiana decision requires [a natural gas company’s] production to be priced under the NGPA, the decision simply results in removal of [its] production plant from the rate base so it is nonjurisdictional for purposes of this rate proceeding.” Consolidated Gas Supply Corp., 24 FERC ¶ 61,283 at 61,584 (1983).
 It would seem to go without saying that the Commission cannot simply lop money out of a company’s jurisdictional rate base in order to dole out a credit intended to solve some problem extraneous to the rate base. Not surprisingly, the very FERC regulations establishing the mechanism of a rate base adjustment for deferred tax reserves require that the tax reserve adjustments to rate base be related to jurisdictional assets. See 18 C.F.R. § 154.63a(b)(2)(ii) (“Such rate base reductions or additions must be limited to deferred taxes related to rate base, construction or other jurisdictional activities.”); see also Order No. 144, FERC Stats. & Regs. [1977-1981] ¶ 30,254 at 31,558 (1981) (rate base adjustments must “aris[e] from construction-related timing differences and from other jurisdictional activities”). This requirement is not just a technical accounting principle. It ensures that the tax benefits flowing from a given asset accrue only to customers who also bear the costs associated with that asset.
In explaining its rate base adjustment, the Commission acknowledged that “accounting principles” required discontinuance of the rate base credit once the relevant facilities were out of the rate base. (It did not refer explicitly to its override of § 154.63a(b)(2)(ii).) But it asserted that “[t]he relevant point is that El Paso has the use of cost-free capital generated from past rates.” Order, 43 FERC at 61,748. Although the presence of “cost-free” capital was relevant while a pipeline’s gas was priced under cost-of-service principles, it loses meaning under the shift to NGPA prices. Accordingly, we cannot be certain what the Commission intends by the phrase. Whatever the explanation’s meaning, it cannot possibly turn a production-related deferred tax fund into something transmission-related.
Indeed, in its first pass at the issue, the Commission expressed concern that applying the fund (or its earnings) to El Paso’s rates would effectively enable El Paso to “cross-subsidize” its transmission services with the funds. El Paso Natural Gas Co., 33 FERC ¶ 61,099 at 61,210 (1985). The remark was an odd one, as El Paso had never shown any desire to offer such a subsidy. But the underlying point, that the fund was completely unrelated to El Paso’s transmission service, was clearly correct. No reason appears why current users of El Paso’s transmission service, who may take no El Paso gas at all, should receive credits based on earlier El Paso gas service.
2. Current gas supplies. In enacting the NGPA, Congress took away from the Commission the power to determine just and reasonable rates for wellhead sales of gas (including, under Mid-Louisiana, intracompany wellhead transfers). Instead it set ceiling prices itself. Section 601 addresses the downstream impact of the wellhead ceilings, entitling a natural gas company to pass on NGPAcomplying costs. (§ 601(b)(1) states that amounts paid that comply with Title I of *341the NGPA shall be deemed just and reasonable for Natural Gas Act purposes, and § 601(c)(2) states that the Commission may not deny a pipeline recovery of amounts deemed just and reasonable under § 601(b)(1), subject to exceptions not relevant here). 15 U.S.C. § 3431 (1988). Thus, if the rate El Paso is passing on to customers is a lawful rate under the NGPA, the Commission is powerless to reduce it.
Although El Paso’s only jurisdictional transactions are its provision of gas or transmission service, the Commission asserts that its credit “has no impact on El Paso’s receiving NGPA prices for NGPA sales.” Commission Brief at 25 (quoting Order on Rehearing, 44 FERC at 61,206). This seems utterly fictional. If the credit does not relate to transmission, which is plain enough, it must relate to gas. As El Paso points out, “the Commission [may not] pick the pipeline pocket but point to the producer pocket as still full.” Initial Brief of Petitioner El Paso at 22.
California argues both that the NGPA pricing scheme allows the Commission to distribute the fund (and its earnings) to customers and that it requires it to do so. The two arguments coalesce. Both start with the proposition that the deferred tax fund is derived from customer charges and that the Commission’s tax normalization regulations contemplated its use for future tax payments. Thus, according to California, if El Paso keeps the fund, it is really “charging” the customers an “add-on” to the NGPA prices.
Since El Paso’s switch to NGPA pricing, it has passed on to its customers no more than the ceiling prices that Congress set. On its face, therefore, El Paso has been complying with the NGPA. Rather than end the inquiry there, however, California’s argument would engage us in an analysis of El Paso’s costs after its switch to NGPA pricing. However, it is precisely such an inquiry which Congress sought to foreclose by adopting ceiling prices which were “wholly divorced from the traditional historical-cost methods applied by the Commission in implementing the [Natural Gas Act].” Mid-Louisiana, 463 U.S. at 333, 103 S.Ct. at 3032-33. Simply because these funds were collected in contemplation of future tax liabilities does not authorize us or the Commission to embark anew on the cost-based analysis that Congress sought to avoid through passage of the NGPA.
California is therefore reduced to arguing that until October 1983 El Paso was merely a “custodian” of the tax funds, Initial Brief of Petitioner California at 46, so that when it uses or retains them after the switch to NGPA it is really charging for them (or for its current tax costs) during the post-switch period. In fact, however, the fund was generated from past rates which have long since been finally approved as just and reasonable and collected. As the Commission noted, 44 FERC at 61,205, just because El Paso may draw on these funds to pay future costs does not mean that the funds should be treated as having been collected in the period in which they are spent. Moreover, the argument appears to rest on the notion that under normalization accounting customers enjoy an equitable interest in a utility’s deferred tax account, a notion that the Commission and this court have both rejected. See Order No. 144, FERC Stats. & Regs. [1977-1981] ¶ 30,254 at. 31,539 (1981); Public Systems v. FERC, 709 F.2d at 86 n. 30. California’s approach not only plays games with the ordinary meaning of words but invites a wholesale destruction of the rule against retroactive ratemaking.
California notes that in a case sustaining normalization prior to Order No. 144, this court rested its affirmation on the concept that there would be no “permanent tax savings” accruing to producers but not to the benefit of customers. American Public Gas Ass’n v. FPC (“APGA ”), 567 F.2d 1016, 1042 (D.C.Cir.1977). Moreover, the court said that the legitimacy of the Commission’s method depended on the assumption of its being applied consistently in the future; if it adopted another method, “the producers could indeed achieve a tax ‘savings’ that is permanent and would not inure to the benefit of consumers.” Id. But the APGA decision will not support the inferences California would draw. The statement quoted was obviously not made *342in contemplation of Congress’s later enactment of the NGPA. Nor could it have meant that the validity of tax normalization depends on its indefinite continuation, regardless of changing circumstances. Tax normalization sought to “match” the timing of a customer’s contribution toward a cost with enjoyment of any offsetting tax benefit. In the pre-1983 period El Paso’s rates did just that. Enactment of the NGPA, however, mooted the whole question to which normalization was an answer. The logic of California’s argument in fact requires that if the NGPA had completely deregulated wellhead prices,6 the Commission would have to keep soldiering on with stray remnants of the prior learning. APGA cannot have intended that.
Finally, California’s “windfall” argument overlooks the reality that every pre-1983 purchaser received the full tax benefit associated with every expense that it bore. El Paso’s enjoyment of the deferred tax reserve is a “windfall” only if one assumes that the accounting system used by the Commission for regulatory purposes (i.e., capitalizing intangible drilling expenses and providing for periodic recovery through depreciation charges) was the one true way. In fact, however, that method was simply one policy choice out of several. Congress in its tax provisions allowed an immediate tax benefit for certain types of investment in order to encourage them. The Commission might itself have similarly allowed immediate recovery of the drilling expenses. Had it done so, the two accounting systems would have “matched,” and El Paso would have recovered the entire cost of the items in the first year. Compared to that scenario, cessation of the historic cost system has given the customers a “windfall.” The reason we would reject any such argument by El Paso is simply that we take as given, as the baseline for reasoning, the accounting system that the Commission happened to employ for regulatory purposes in the period of historic costing. Similarly, if FERC had formerly employed the flow-through method of passing on tax breaks to consumers, followed by an El Paso switch to NGPA pricing, we would allow no current adjustment in its rates to offset the customers’ “windfall” of receiving the entire tax break from assets of which they would have paid for only a part. We must take the prior system as given, for to do otherwise would open the door to endless retroactive ratemaking. As that principle would foreclose El Paso from claiming (under either of the above hypotheticals) that complete cessation of the system in 1983 gave its customers a windfall, so it prevents the customers from claiming that cessation of the prior system conferred a windfall on El Paso.
3. Retroactive ratemaking. To the extent that the Commission’s credit is intended to implement a Commission perception that, in light of the October 1, 1983 switch, El Paso’s prior rates were unjust or unreasonable (FERC makes no such claim), it would violate the rule against retroactive ratemaking.7 The Commission made no such claim either in its opinions below or in its brief before us.
With limited exceptions inapplicable here,8 the Natural Gas Act allows the Com*343mission only to change rates prospectively. Where the Commission takes on the burden of showing that prevailing rates are unjust or unreasonable, § 5(a) of the Act allows it only to determine the “just and reasonable rate ... to be thereafter observed.” 15 U.S.C. § 717d(a) (1988) (emphasis added).9
Here the Commission has addressed itself to disposition of El Paso’s deferred tax fund, which is composed entirely of rate revenue that El Paso has already collected. See above at 17. Refund of such property, or its earnings, would effectively force El Paso to return a portion of rates approved by FERC and collected by El Paso. This kind of post hoc tinkering would undermine the predictability which the doctrine seeks to protect. See Columbia Gas, 831 F.2d at 1141. The Act’s limited provision for refunds reflects a congressional determination that parties in the industry need to be able to rely on the finality of approved rates, and that this interest outweighs the value of being able to correct for decisions that in hindsight may appear unsound.10 The rule against retroactive ratemaking also tends to make this highly regulated market approximate ordinary ones, where, for example, General Motors may not, after a sale, demand another $500 to cover its costs, and a buyer may not demand a refund because he just discovered that a competitor had.been offering similar cars for less. The doctrine is, of course, a two-way street. It bars “the Commission’s retroactive substitution of an unreasonably high or low rate with a just and reasonable rate.” City of Piqua v. FERC, 610 F.2d 950, 954 (D.C.Cir.1979); see also Arkansas Louisiana Gas Co. v. Hall, 453 U.S. at 576-79, 101 S.Ct. at 2929-31; Associated Gas Distributors v. FERC, 893 F.2d 349, 354-57 (1989) (disallowing $650 million sought by pipeline in excess of prior charges).
We note that in its orders on review here the Commission appeared to justify its baby-splitting position on grounds of equity, saying, for example, that “[t]he Commission believes that [its] treatment of El Paso’s deferred tax reserve is an equitable solution to an extremely difficult dilemma.” 43 FERC at 61,748. Part of this focus may have arisen out of references in our earlier opinion to equitable issues, such as a mention of the need to address “difficult issues of equity” posed by the transition. 817 F.2d at 862. But our previous decision only remanded the issue to FERC because it had failed to provide a reasoned explanation for what it. had done. The court obviously never intended to imbue the Commission with the authority to ignore the law in achieving an equitable result. Whatever hints the Commission may have found in the opinion that the issue was essentially an equitable one were not intended to relieve — and, indeed, could not have relieved — FERC of its duty to follow the law. The Commission had no legal right to reduce El Paso’s post-October 1, 1983 rates for gas transmission below levels found to be just and reasonable for that service, or to impair its right under § 601 of the NGPA to recover NGPA-complying amounts for its gas. Accordingly, the Commission’s adjustments of those rates *344were in substance a retroactive adjustment of prior rates based on normalization. The rule against such revision operates sometimes to protect customers from surcharges and at others to protect gas companies from refunds; its equity lies in its steady application regardless of what party is seeking to reexamine the past.
Our discussion has not focused separately on the fund or the interest. As noted above, see supra at 1380, we see no basis for distinguishing between the two.' Both elements equally lack any relation whatsoever to current transmission service. Similarly, with respect to current gas service, any reduction from current gas prices would undercut the pricing rules of the NGPA regardless of whether the fund or its interest was the source of the reduction. That the amount of the fund was formerly deducted from El Paso’s gas production rate base arose solely out of the Commission’s intention to match El Paso’s then-current gas prices with its then-current gas costs; with the application of NGPA pricing, the gas production rate base has disappeared, and the matching principle, while no longer explicitly operative, points against, not for, any such adjustment. Finally, the rule against retroactive ratemaking prevents the Commission not only from forcing a utility to disgorge the proceeds of rates that have been finally approved and collected, but also from denying a producer the fruits of those proceeds. A contrary result would make the prohibition against retroactive ratemaking a sham, by allowing the Commission indirectly to deny a party the benefits of filed rates despite the prohibition against doing so directly.

Conclusion

We affirm the Commission’s decision to allow El Paso to retain the deferred tax reserve, and reverse its decision reducing El Paso’s rate base by the amount of the reserve. We reverse its decision on the replacement contract issue and remand the matter to FERC for it to resolve consistently with this opinion.

So ordered.

.Section 271.402(b)(4) provides in full:
“Replacement contract gas or recompletion gas” means natural gas to which this subpart applies which is:
(i) Sold under a replacement contract which was executed on or after January 1, 1973, but prior to November 9, 1978, where the prior contract expired by its own terms prior to January 1, 1973; or
(ii) Sold under a replacement contract executed prior to November 9, 1978, where the prior contract expired by its own terms after January 1, 1973; or
(iii) Sold under a contract for the sale of natural gas from well commenced prior to January 1, 1973, and not sold in interstate commerce prior to January 1, 1973, (excluding gas sold prior to such date under §§ 2.68, 2.70, 157.22 or 157.29 of this chapter); or
(iv) Produced as a result of a completion operation into a different formerly nonproductive reservoir, commenced on or after January 1, 1973, and produced through a well commenced prior to January 1, 1973.

. As of October 1983, flowing gas was priced at 47.5 cents per MMBtu, whereas replacemc. .it contract gas was priced at 84.9 cents per MMBtu. Joint Appendix ("J.A.”) 19.

. We gather that once the Commission imputes contracts, it would, for any given period, allow El Paso the replacement contract rate only for the proportion of gas that could be expected to be covered in that period by replacement contracts, i.e., the proportion of gas with respect to which the imputed original contracts would have expired and been replaced. But the orders under review do not explicitly address the issue.

. Unfitness of an issue for review, a matter normally considered under the head of ripeness, might also defeat our jurisdiction by negating the constitutionally required “case or controversy,” Action Alliance of Senior Citizens v. Heckler, *337789 F.2d 931, 940 n. 12 (D.C.Cir.1986), but here the issue is fit for review — "sufficiently ‘fleshed out’ that we may see the concrete effects and implications of what we do.” American Trucking Ass'n v. ICC, 747 F.2d 787, 789 (D.C.Cir.1984).

. Compare § 506(a)(4) of the NGPA, 15 U.S.C. § 3416(a)(4) (1988), which limits judicial review to "final order[s]."

. In fact, the Natural Gas Wellhead Decontrol Act of 1989, Pub.L. No. 101-60, 103 Stat. 157 (1989), provides for eventual complete deregulation.

. Neither the Commission nor any party here suggests that FERC might interpret the NGPA as allowing it to create an exception to the retroactive ratemaking rule of the NGA, solely for purposes of addressing transitional issues created by the need to use the NGPA in considering pipelines’ gas costs for ratemaking purposes. Compare Chevron U.S.A. Inc. v. NRDC, 467 U.S. 837, 104 S.Ct. 2778, 81 L.Ed.2d 694 (1984).

. When a natural gets company files new rates under § 4 of the Act, a limited form of retroactive rate collection may occur. The Commission may order the rates suspended for up to five months. If it is unable to resolve their validity within that period, it must let them go into effect. Then, if it ultimately finds them unjust or unreasonable, it may order the company to make refunds to customers. 15 U.S.C. § 717c(e) (1988). As we explained in East Tennessee Natural Gas Co. v. FERC, 863 F.2d 932, 941 (D.C.Cir.1988), this exception to the rule against retroactive rate changes is simply “a necessary compromise to accommodate delays in the approval process." See also Arkansas Louisiana Gas Co. v. Hall, 453 U.S. 571, 578, 101 S.Ct. 2925, 2930-31, 69 L.Ed.2d 856 (1981); Columbia Gas Transmission Corp. v. FERC, 831 *343F.2d 1135 (D.C.Cir.1987). There is also a limited exception where the Commission itself has illegally certificated sales under rates exceeding those in the public interest under § 7 of the Act. See United Gas Improvement Co. v. Callery Properties, Inc., 382 U.S. 223, 229-30, 86 S.Ct. 360, 364-65, 15 L.Ed.2d 284 (1965); see also Public Service Comm’n of New York v. FPC, 543 F.2d 757, 807 (D.C.Cir.1974).

. Cf. § 206(b) of the Federal Power Act, 16 U.S.C.A. § 824e(b) (1985 & 1989 Supp.) (allowing for refund of rates later determined to be unjust and unreasonable as of a date after the commencement of the proceeding leading to the finding but prior to the conclusion of the proceedings).

. We in no way mean to imply that the Commission’s decision to implement tax normalization is unsound even in retrospect. The Commission of course never found that any of El Paso's customers have paid or are paying unjust and unreasonable rates. Indeed, we would have been perplexed had it done so. Customers in the pre-NGPA period received the same percentage of total tax breaks associated with any given asset as they paid costs. Customers in the post-NGPA period have been paying NGPA ■ rates. It is hard to understand how the rates applicable to either of these groups could be termed "unjust.”