Interstate Natural Gas Ass'n of America v. Federal Energy Regulatory Commission

285 F.3d 18, 350 U.S. App. D.C. 366

• Court: Court of Appeals for the D.C. Circuit
• Decided: April 5, 2002
• Docket: Nos. 98-1333, 98-1349, 00-1217, 00-1220, 00-1244, 00-1278, 00-1280, 00-1286, 00-1291, 00-1308, 00-1315, 00-1319, 00-1360, 00-1367, 00-1380, 00-1395, 00-1410, 00-1411, 00-1414, 00-1416, 00-1418 and 00-1419
• Status: Published

Opinion

Opinion for the Court filed by Senior Circuit Judge WILLIAMS.

TABLE OF CONTENTS

I. Rate Ceiling Issues.29

A. Waiver of the rate ceilings for short-term capacity releases by shippers.29

1. Expected range of market rates.31

2. Non-cost factors.33

3. Oversight.34

B. Retention of the rate ceilings for short-term pipeline releases.35

II. Segmentation.36

A. General validity.37

B. Specific defects.39

1. Primary point rights in segmented releases.39

2. Forwardhauls and backhauls to the same delivery point.40

3. Virtual pooling points.41

4. Reticulated pipelines.42 5. Discounts .43

III. Secondary Point Capacity Allocation .44

IV. Penalties.46

A. INGAA attack on penalty limits.47

B. Attacks on revenue-crediting provisions.49

V.The Right of First Refusal . O lO

A. Five-year matching cap and “regulatory” right of first refusal H lO

1. Five-year cap. 2. Right of first refusal trumping tariff provisions. B. Narrowing of the right of first refusal. (M CO N lO lO ID

VI. Discount Adjustments.56

VII. Peak/Off-Peak Rates.58

VIII. Limitations on PRE-ARranged Releases.61

STEPHEN F. WILLIAMS, Senior Circuit Judge:

The petitioners challenge the Federal Energy Regulatory Commission’s Orders Nos. 637, 637-A, and 637-B, in which the Commission extended its prior efforts to increase flexibility and competition in the natural gas industry. See Order No. 637, Regulation of Shortr-Term Natural Gas Transportation Services And Regulation of Interstate Natural Gas Transportation Services, FERC Stats. & Regs. [Reg. Preambles 1996-2000] (CCH) ¶ 31,091 (2000) (“Order No. 637”); Order No. 637-A, Order on Rehearing, Regulation of Shortr-Term, Natural Gas Transportation Services And Regulation of Interstate Natural Gas Transportation Services, FERC Stats. & Regs. [Reg. Preambles 1996-2000] (CCH) ¶ 31,099 (2000) (“Order No. 637-A”); Order No. 637-B; Order Denying Rehearing, Regulation of Shorb-Term Natural Gas Transportation Services And Regulation of Interstate Natural Gas Transportation Services, 92 FERC ¶ 61,602 (2000) (“Order No. 637-B”).

We deny the petitions for the most part, with the following exceptions: we reverse and remand with respect to the five-year cap on the mandatory right of first refusal and in part with respect to the limitations on pre-arranged releases (issues V.A.1 and VIII in the Table of Contents); we remand without reversing on forwardhauls and baekwardhauls to the same delivery point (issue II.B.2) and on the relation between the right of first refusal and tariff provisions (issue V.A.2); and we dismiss the petitions as unripe or for want of standing with respect to segmentation of reticulated pipelines and point discounts, secondary point capacity allocation, and peak/off-peak rates (issues II.B.4, II.B.5, III and VII).

I. Rate Ceiling Issues

A. Waiver of the rate ceilings for short-term capacity releases by shippers

The heart of Order No. 637 was the Commission’s decision to lift — for a two-year period — the cost-based rate ceilings that it previously imposed on short-term “releases” of pipeline capacity by shippers with long-term rights to that capacity. Order No. 637 at 31,263. At the same time the order retained the ceilings for similar sales by the pipelines themselves. Id. Both aspects are attacked: the experimental decontrol — by certain shippers (collectively, “Exxon”), the exclusion of pipelines — by certain pipelines.

The Natural Gas Act (“NGA”), 15 U.S.C. § 717, et seq., mandates that all the rates and charges of a natural gas company for the transportation or sale of natural gas “shall be just and reasonable.” 15 U.S.C. § 717c(a). (It is undisputed for the purposes of this appeal that a shipper reselling its capacity is a “natural gas company” to that extent and thus subject to FERC jurisdiction over such resales. E.g., Texas Eastern Transmission Corp., 48 FERC ¶ 61,248 at 61,873, J989 WL 262232 (1989); see also Order No. 636-A, Order on Rehearing, Pipeline Service Obligations and Revisions to Regulations Governing Self-Implementing Transportation Under Part 281 of the Commission’s Regulations, FERC Stats. & Regs. [Regs. Preambles 1991-1996] (CCH) ¶ 30,-950 at 30,551 (1992) (“Order No. 636-A”); United Distrib. Cos. v. FERC, 88 F.3d 1105, 1152 (D.C.Cir.1996) (“ÍZDC”).) In its prior rulemaking aimed at enhancing competition by unbundling various pipeline services, the Commission recognized that a significant percentage of pipeline capacity reserved for “firm” service often went unused. Order No. 636, Pipeline Service Obligations and Revisions to Regulations Governing Self-Implementing Transportation Under Part 281 of the Commission’s Regulations, FERC Stats. & Regs. [Regs. Preambles 1991-1996] (CCH) ¶ 30,-939 at 30,398-400 (1992) (“Order No. 636”); cf. UDC, 88 F.3d at 1149. It granted authority for the holders to release such capacity, but, concerned that capacity holders might be able to exercise market power, imposed a ceiling on what the releasing party could charge. Order' No. 636 at 30,418; Order No. 636-A at 30,553. The ceiling was derived from the Commission’s estimate of the maximum rates necessary for each pipeline to recover its annual cost-of-service revenue requirement, Order No. 637 at 31,270, which the Commission simply prorated over the period of each release, id. at 31,270, 31,271.

As the Commission observed activity in the market under this arrangement, however, it came to believe that the ceilings probably worked against the shippers they were designed to protect. With the rate ceilings in place, a shipper looking for short-term capacity on a peak day, and willing to offer a higher price in order to obtain it, could not legally do so; this reduced its options for procuring short-term transportation at the times that it needed it most. Order No. 637 at 31,275-76. So the Commission decided to grant a two-year experimental waiver of the ceilings on releases of firm capacity. For this limited period, “short-term” capacity releases (defined for these purposes as less than one year) may proceed at market rates. Order No. 637 at 31,263. Capacity sales by the pipelines themselves, both short and long-term, continue subject to the cost-based rate ceilings. Order No. 637-A at 31,572. We here address the claims of the shippers who object to the experiment itself and the pipelines who object to their exclusion from its opportunities.

Framing our consideration of the challenges are (1) the special deference due agency experiments, (2) the basic premise of the congressional mandate to FERC to regulate the rates of the interstate gas pipelines, and (3) a set of criteria, discussed exhaustively in Farmers Union Cent. Exch. v. FERC, 734 F.2d 1486 (D.C.Cir.1984) (“Farmers Union”), for review of decisions, undertaken by an agency having such a mandate, to choose a regime more “lighthanded” than traditional cost-based regulation.

Here of course the two-year waiver is explicitly experimental. As the Commission said, “No matter how good the data suggesting that a regulatory change should be made, there is no substitute for reviewing the actual results of a regulatory action.” Order No. 637 at 31,279. For at least 30 years this court has given special deference to agency development of such experiments, precisely because of the advantages of data developed in the real world. See, e.g., Public Serv. Comm’n v. FPC, 463 F.2d 824, 828 (D.C.Cir.1972); Paul Mohler, “Experiments at the FERC — In Search of a Hypothesis,” 19 Energy L.J. 281, 300 (1998). The petitioners do not contest this extra layer of deference.

Second, the basic premise of the NGA is the understanding that natural gas pipeline transportation is generally a natural monopoly, see, e.g., UDC, 88 F.3d at 1122, so that without regulation the rates of pipeline companies would exceed competitive rates, i.e., ones approximating cost, Elizabethtown Gas Co. v. FERC, 10 F.3d 866, 870 (D.C.Cir.1993). In dispensing with cost-based rate ceilings presumptively intended by Congress as a remedy, and supplanting those ceilings temporarily with market-based rates in a segment of the pipeline market, the Commission may be seen as facing a kind of uphill fight. Though the slope faced by FERC is perhaps uphill, however, it is not the almost vertical escarpment that Exxon seems to suppose. This is not Point du Hoc.

Third, our decision in Farmers Union, though addressing oil pipeline regulation under the Hepburn Act, sets out general guidance for our review of FERC’s decision to elect more relaxed (“lighthanded,” as we said) regulation than traditional cost-based ceilings, in the context of a mandate to set “just and reasonable” rates in an industry generally thought to have the features of a natural monopoly. 734 F.2d at 1510. The overarching criterion that we identified was (inevitably) that any such decision could be justified by “a showing that ... the goals and purposes of the statute will be accomplished” through the proposed changes. Id. To satisfy that standard, we demanded that the resulting rates be expected to fall within a “zone of reasonableness, where [they] are neither less than compensatory nor excessive.” Id. at 1502 (internal quotations omitted). While the expected rates’ proximity to cost was a starting point for this inquiry into reasonableness, id., we were quite explicit that “non-cost factors may legitimate a departure from a rigid cost-based approach,” id. Finally, we said that FERC must retain some general oversight over the system, to see if competition in fact drives rates into the zone of reasonableness “or to check rates if it does not.” Id. at 1509. We now apply this basic model.

1. Expected range of market rates. As competition normally provides a reasonable assurance that rates will approximate cost, at least over the long pull, Elizabethtown Gas Co., 10 F.3d at 870, Exxon argues that the Commission’s experiment cannot be sustained in the absence of data establishing the existence of competition. Presumably, for example, a calculation of Herfindahl-Hirschman indices for the capacity release market in all origin and destination pairs would do the job. The Commission has not undertaken such an enterprise. See, e.g., Order No. 637-A at 31,558.

But the Commission has other evidence. First, since capacity resales were authorized in 1992, the rates for such releases have on average been somewhat below the maximum tariff rates, both during off-peak and peak periods. Order No. 637-A at 31,563 & n.46. Second, the Commission has data from “the bundled market,” i.e., inferences as to transportation values drawn from comparison of the prices for gas sold at the field with the prices for gas sold in destination markets. As the Commission points out, if the difference between field prices and citygate prices in a particular pathway is only $.07, people will not pay more than $.07 for the unbundled transportation. Order No. 637 at 31,271. Only during the coldest times of some years has this inferred price exceeded the capped rate. Order No. 637-A at 31,563 & nn.47-48. Order No. 637’s Figure 6, found at 31,273, which we reproduce below, illustrates the pattern the Commission found.

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Thus the Commission had a substantial basis for concluding that the uncapped market price for capacity' — -which FERC concedes is likely to exceed the current maximum at certain times of the year — • will be roughly in line (at least annually) with the cost-based price. Order No. 637-A at 31,563-64.

Of course, one could argue that -this demonstrates only that in the periods where the ceilings are not binding, there is no problem for them to solve; thus it supplies no justification for removal of the ceilings for the (peak) periods where they are binding. But the data represented in the graph above do support the Commission’s view that the capacity release market enjoys considerable competition. The brief spikes in moments of extreme exigency are completely consistent with competition, reflecting scarcity rather than monopoly. See Order No. 637-A at 31,595. A surge in the price of candles during a power outage is no evidence of monopoly in the candle market.

Moreover, outside the spikes the rates were well below the regulated price, which in turn is based on the Commission’s estimates of cost. As prices would be above cost in the absence of competition and yet are not (putting aside the brief scarcity-related spikes), the Commission’s inference of competition appears well founded.

The Commission also considered two ways in which capacity resellers might exploit or extend such market power as they may possess — price discrimination and deliberate withholding of capacity to drive up prices — and found that neither presented much peril. Order No. 637-A at 31,564. FERC dismissed price discrimination on the grounds that, given the ease with which capacity can be transferred between shippers, resellers would have no way to prevent arbitrage. See Order No. 637 at 31,280, 31,282.

As to deliberate withholding of capacity, the Commission reasoned that this too was not within the power of capacity holders. If holders of firm capacity do not use or sell all of their entitlement, the pipelines are required to sell the idle capacity as interruptible service to any taker at no more than the maximum rate — which is still applicable to the pipelines. See Order No. 637 at 31,282. Even though interrup-tible service may not be as desirable as firm service, the Commission concluded that it would provide an adequate substitute, whose availability would place a meaningful check on whatever anti-competitive tendencies the resellers might have. See Order No. 637-A at 31,565. And because the pipelines continue to be bound by cost-of-service regulations, the agency suggested that they would have no incentive to collude with firm shippers to limit available capacity. Id.

Moreover, the availability of the bundled sales mentioned above (where a holder of capacity buys gas in the field and sells it in a destination market, with no explicit sale of the necessary capacity itself) further reduces the possibility that the waiver policy would significantly change the firm shippers’ ability to increase their rates for capacity releases. Order No. 637 at 31,-276. And, if pipelines should observe high prices in the secondary market, they will — • despite their capped rates — often have adequate incentives to add capacity, which they can do even in the relatively short-term by adding compression. Id. at 31,-282.

Thus we think the Commission made a substantial record for the proposition that market rates would not materially (considering degree, volume and duration) exceed the “zone of reasonableness” required by Farmers Union. Any flaws in its showing must be evaluated, of course, in light both of the experimental nature of the two-year removal of ceilings and of the non-cost factors discussed below.

2. Non-cost factors. The Commission pointed to a number of advantages of lifting the ceilings on short-term capacity releases, tending to offset whatever harm the occasional high rate might entail. We discuss them, concentrating on the highlights.

First, because the rule applies only to the secondary transportation market, the primary intended beneficiaries of the NGA — the “captive” shippers, typically operating under firm contracts — continue to receive whatever benefits the rate ceilings generally provide. See Order No. 637 at 31,284-85 (alluding to the continued protection of the Commission’s “primary constituency — captive long-term firm capacity holders”). Indeed, these holders actually reap the benefits of FERC’s new rule, in the form of higher payments for their releases of surplus capacity. See id. at 31,-281; see also Order No. 637-A at 31,562.

Second, the rate ceilings on short-term capacity releases were fundamentally ineffective. We’ve already described the market for bundled gas and transportation, by means of which a holder of surplus capacity can take advantage of the real market value of transportation by going into the gas market itself, buying in an origin market and selling at the destination. Although all hands recognize that during peaks the market value of the transportation can far exceed the FERC-imposed maximum tariff rate, see Order No. 637 at 31,273-74 & figs. 6-7, neither the Commission, nor any of the parties, has proposed extending price regulations to cover the bundled sales market, id. at 31,275.

Third, removal of ceilings facilitates the movement of capacity into the hands of those who value it most highly. See Order No. 637 at 31,280. With the rate ceilings in place, the options of a shipper looking for short-term capacity on a peak day are only to enter a bundled transaction with a holder of firm capacity (at a price that includes the market value of transportation), or to “take the gas out of the pipeline and pay the pipeline’s scheduling or overrun penalties,” which, the Commission observed, may “compromise the operational integrity of the pipeline’s system.” Order No. 637 at 31,276; see also id. at 31,280. Thus the rate relaxation reduces transactions costs and increases transparency, helping economic actors make rational decisions for other aspects of their operations, e.g., decisions on how much firm capacity they really need, and, for example, for a fuel-switchable industrial user, whether to use or sell some of its capacity. Id. at 31,276.

It might be argued that these efficiency values are ubiquitous and might justify any deregulation of any rates mandated by Congress to be held at “just and reasonable” levels. Not so. Cost-based rate regulation of a natural monopoly (if accurately done — a big “if’) is consistent with efficiency. The special phenomenon here is congestion in the peaks; it is only the inefficiency produced by rates based solely on the cost of supply — and in complete disregard of the opportunity cost of the capacity' — ’that the Commission has set out to remedy. Compare Order No. 637-A at 31,595 (expressing view that peak prices simply reflect scarcity rents).

The presence of these non-cost factors here distinguishes the present case from prior decisions cited by Exxon, see Farmers Union; Elizabethtown Gas, 10 F.3d 866; Tejas Power Corp. v. FERC, 908 F.2d 998 (D.C.Cir.1990), where we set aside FERC departures from cost-based rate ceilings.

3. Oversight. As to monitoring and assurance of remedies in the event of insufficient competition, on which Farmers Union set great store, see 734 F.2d at 1509, the Commission identifies three safeguards.

First, release prices and availability must be publicly reported in compliance with FERC’s current posting and bidding requirements. This will increase the information available to buyers and, the Commission believed, reduce any ill effects of market power, while at the same time making it easier for FERC to identify situations in which shippers were abusing their market power. Order No. 637 at 31,283; Order No. 637-A at 31,558. FERC also noted that it retained jurisdiction under § 5 of the NGA, 15 U.S.C. § 717d, to entertain complaints and to respond to specific allegations of market power on a case-by-case basis if necessary. See Order No. 637 at 31,286 (stating that specific abuses of market power “can be addressed on an individual basis”); see also FERC Br. at 54 (citing Transmission Access Policy Study Group v. FERC, 225 F.3d 667, 689 (D.C.Cir.2000) (“TAPS”)), aff'd sub nom., New York v. FERC, — U.S. —, 122 S.Ct. 1012, 152 L.Ed.2d 47 (2002), (“[I]f [a party] has evidence that the tariff results in undue discrimination in its individual circumstances, [that party] remains free to file a petition under FPA § 206 [the equivalent of NGA § 5] for redress, and FERC will consider its claim.”). Finally, the Commission pointed out that this mitigation mechanism, however reactive and limited to forward-looking remedies, is complemented by its continued regulation of pipeline penalty levels, which establish de facto rate ceilings for release transactions, as would-be purchasers of capacity would not pay a price greater than the penalty for overuse of their regular pipeline capacity. See Order No. 637-A at 31,558.

Given the substantial showing that in this context competition has every reasonable prospect of preventing seriously monopolistic pricing, together with the non-cost advantages cited by the commission and the experimental nature of this particular “lighthanded” regulation, we find the Commission’s decision neither a violation of the NGA, nor arbitrary or capricious.

B. Retention of the rate ceilings for short-term pipeline releases

Having been attacked for going too far with its waivers, FERC is also challenged for not going far enough. A group of four pipelines argues that the Commission’s decision to retain the price ceilings on pipelines, while removing them from short-terms resellers of capacity, is discriminatory and arbitrary and capricious. We do not find the Commission’s gradualism fatally flawed.

We start, of course, from the premise that the Commission is free to undertake reform one step at a time. Maryland People’s Counsel v. FERC, 761 F.2d 768, 779 (D.C.Cir.1985). We can overturn its gradualism only if it truly yields unreasonable discrimination or some other kind of arbitrariness.

In fact the Commission’s distinction is not unreasonable. Despite the absence of Herfindahl-Hirschman indices for non-pipeline capacity holders, there seems every reason to suppose that their ownership of such capacity (in any given market) is not so concentrated as that of the pipelines themselves — the concentration that prompted Congress to impose rate regulation in the first place. See FPC v. Texaco, 417 U.S. 380, 398 n. 8, 94 S.Ct. 2315, 2327 n. 8, 41 L.Ed.2d 141 (1974). The petitioning pipelines assert that pipelines hold only about 7% of pipeline transportation capacity, while shippers hold the remaining 93%. This is classic apples and oranges. The Commission points out that whereas the uncontracted capacity of a pipeline is presumptively available for the short-term market, no such presumption makes sense for the non-pipeline capacity holders: they presumably contracted for the capacity in anticipation of actually using it.

Second, the Commission made clear that pipelines do have options for a switch to market rates. A pipeline may sell at such rates either by demonstrating that there is enough competition in the short-term market to preclude market power, or by securing FERC permission for sale of capacity by auction. The Commission recognized that such auctions were to a degree hampered by its own regulations, and expressed a readiness to waive some of the burdens. See Order No. 637-A at 31,572; Order No. 637 at 31,295.

The pipelines make the interesting point that continued subjection of their short-term rates to FERC ceilings will skew the prices in the decontrolled market. The Commission’s brief writers profess to be “bafflfed]” by this argument, but its opinion writers understood the principle perfectly well, in fact invoking it in another context. See Order No. 637-B at 61,164 n.8. The basic proposition asserted by the pipelines (and, as we say, recognized by the Commission) is that where (1) a portion of the supply of a good or service is subject to price controls, and (2) demand exceeds (the price-controlled) supply at the fixed price, the market-clearing price in the uncontrolled segment will be normally higher than if no price controls were imposed on any of the supply.

This is so because — unless there is a system of rationing the price-controlled supply that in some way exactly matches the would-be buyers’ willingness to pay (an improbable scenario) — buyers whose demand would have been completely foreclosed if the entire market had been uncontrolled will in fact use up some of the price-controlled supply and thus (obviously) some of the aggregate supply. In the price-controlled segment higher-value de-manders will to a degree be supplanted by lower-value demanders. The presence of the extra unsatisfied higher-value demand alters the demand-supply ratio in the uncontrolled market, which will therefore clear at a higher price than if the entirety were uncontrolled. For example, consider a good that sells for $1.25 in an open market. The market is then split and a ceiling of $1 is set in the controlled sector. As some users of the controlled supply would only have been willing to pay, say, $1.10, and thus would have consumed none before, their usage will displace demanders willing to pay $1.25 or more; the displaced demanders will drive up the uncontrolled price. Compare National Regulatory Research Institute, State Regulatory Options for Dealing with Natural Gas Wellhead Price Deregulation 40-51 (1983).

This is surely a potential price of gradualism. But distortions of this sort seem likely in any such compromise, and compromise — going one step at a time — is within the Commission’s purview so long as it rests on reasonable distinctions. Here, the distinction between pipelines and other holders of unused capacity, based on probable likelihood of wielding market power, seems to us to pass muster.

II. Segmentation

As part of Order No. 636, FERC established two related policies — segmentation and flexible point rights' — that it thought were important to enhancing the value of firm capacity and to promoting competition in the secondary market between firm shippers releasing capacity and pipelines, as well as between releasing shippers themselves. Order No. 636 at 30,428, 30,420-21; see also Order No. 637 at 31,300-01. Segmentation refers to the ability of firm capacity holders to subdivide their capacity into separate parts, either for their own use or for release to replacement shippers. Order No. 637 at 31,303; see also Order No. 637-A at 31,-591. Flexible point rights, on the other hand, enable firm capacity holders to change the primary receipt or delivery point — the points with respect to which shippers are guaranteed to have firm service for their shipments — so that they can receive and deliver gas to or from any point within their firm capacity rights. Order No. 637 at 31,301.

Not having included its segmentation policy in any regulations issued as a result of Order No. 636, see Order No. 637 at 31,301, the Commission later found that in the process of approving individual pipeline restructurings it had not implemented the policy uniformly. See Order No. 637 at 31,301, 31,303. Compare, e.g., Texas Eastern Transmission Corp., 63 FERC ¶ 61,100 at 61,452, 1993 WL 168160 (1993) (segmentation allowed), with Koch Gateway Pipeline Co., 65 FERC ¶ 61,338 at 62,631, 1993 WL 590494 (1993) (no segmentation); see also Order No. 637 at 31,301; Order No. 637-A at 31,590.

Concerned with this lack of consistency, it responded in Order No. 637 by codifying a requirement that pipelines “permit a shipper to make use of the firm capacity for which it has contracted by segmenting that capacity into separate parts for its own use or for the purpose of releasing that capacity to replacement shippers to the extent such segmentation is operationally feasible.” Order No. 637 at 31,303; 18 C.F.R. § 284.7(e). It directed each pipeline to make a pro forma tariff filing showing how it intended to comply with the new regulation, or explaining why its system’s configuration justified curtailing segmentation rights to ensure operational integrity. Order No. 637 at 31,304. Moreover, at least in the context of segmented transactions, limitations on flexibility in changing primary points would now also have to be based solely on the operational characteristics of pipeline systems. Order No. 637-A at 31,595.

Interstate Natural Gas Association of America and several pipelines (collectively, “INGAA”) now challenge the new segmentation rule both on its face and, in the alternative, as it applies to a number of factual scenarios. We deal first with the general attack, then with specifics.

A. General validity

Section 5 of the Natural Gas Act requires that when the Commission seeks to replace an existing rate or practice with a new one, it must demonstrate by substantial evidence that the existing rate or practice has become unjust or unreasonable, and that the proposed one is both just and reasonable. 15 U.S.C. § 717d; Western Res., Inc. v. FERC, 9 F.3d 1568, 1580 (D.C.Cir.1993). INGAA raises both a procedural and a substantive attack on the adequacy of FERC’s findings in the present orders.

INGAA claims that the Commission must make a detailed showing “that every pipeline’s [existing] tariff [was] unjust and unreasonable,” or that the new policy is “just and reasonable for any pipeline.” INGAA Segmentation Br. at 14-15. But § 5 imposes no such requirement. Our cases have long held that the Commission may rely on “generic” or “general” findings of a systemic problem to support imposition of an industry-wide solution. See TAPS, 225 F.3d at 687-88; Wisconsin Gas Co. v. FERC, 770 F.2d 1144, 1166 & n. 36 (D.C.Cir.1985). Here, the Commission has made a “generic determination” that a pipeline’s refusal to permit segmentation where it could “operationally” do so would be unjust and unreasonable. Order No. 637-A at 31,590. And the Commission explained that it was not making a § 5 determination that any particular pipeline’s tariff was unjust or unreasonable, but that it would defer such an inquiry to individual compliance proceedings, where the applicable standard would be operational feasibility. Id. at 31,590-91.

As INGAA correctly points out, the Commission cannot enact “an industry-wide solution for a problem that exists only in isolated pockets. In such a case, the disproportion of remedy to ailment would, at least at some point, become arbitrary and capricious.” INGAA Segmentation Br. at 16 (quoting Associated Gas Distributors v. FERC, 824 F.2d 981, 1019 (D.C.Cir.1987) (“AGD”)). According to INGAA, the Commission’s vague observation that “some pipelines” do not permit segmentation where it is operationally feasible, Order No. 637 at 31,301, does not sufficiently illustrate the existence of an industry-wide anti-competitive practice that the Commission purports to seek to eliminate with its broad rule. INGAA Segmentation Br. at 16.

INGAA somewhat misinterprets the law when it insists that a problem must necessarily be widespread to permit a generic solution. The very quotation from AGD on which INGAA relies shows that proportionality between the identified problem and the remedy is the key. See also AGD, 824 F.2d at 1019 (holding that the Commission could not rely on “generic” analysis where it expressly found that only a limited segment of the industry was affected by the problem it sought to address, while the remedy adopted would necessarily impact other segments).

Here the Commission could reasonably consider the remedy proportional to the identified problem: it requires segmentation only where it is operationally feasible, since in that situation, the Commission found, the failure to permit segmentation is unjust and unreasonable because it restricts efficient use of capacity without adequate justification. See Order No. 637 at 31,304; Order No. 637-A at 31,591.

Insofar as INGAA makes a general attack on the substance of the generic finding, it is unconvincing. It says that a pipeline may resist even operationally feasible segmentation “for a host of ... contractual, and financial reasons.’’INGAA Segmentation Br. at 15-16. This is surely true. But pipeline contracts are subject to modification by the Commission on findings that their terms are unjust or unreasonable, and we have long taken the view that the Commission may use this power to apply “whatever pro-competitive policies are consistent with the agency’s enabling act.” AGD, 824 F.2d at 1018. As a general matter, INGAA simply fails to make the case that the flexibility on which the Commission insists (subject to operational feasibility concerns) is not necessary for reasonable pursuit of the Commission’s policy of enhancing competition by increasing the flexibility of capacity releases.

INGAA makes a related claim that by forcing pipelines to submit pro forma filings, the Commission has impermissibly shifted onto them the burden of proof that segmentation is indeed infeasible for a particular pipeline, evading its duty to carry the burden of supporting any change implemented via § 5. According to INGAA, the Commission has in essence required pipelines to make § 4 filings to defend their current rates; § 4 proceedings presuppose that it is the company that seeks a rate change and they therefore allocate to the company the burden of justifying new tariffs. See Public Serv. Comm’n v. FERC, 866 F.2d 487, 488 (D.C.Cir.1989).

Indeed, certain language in the orders and even in the Commission’s brief supports INGAA’s claim. For example, the Commission at one point says that it will “require the pipelines to show why their existing tariffs should not be considered unjust and unreasonable,” Order No. 637-A at 31,591, and that “individual pipelines [will have] an opportunity to demonstrate that their own circumstances justify deviation from the general conclusion that segmentation is appropriate,” FERC Br. at 101. INGAA’s suspicion is also fueled by the fact that on several previous occasions the Commission had impermissibly blurred the distinction between § 4 and § 5, see Western, Res., 9 F.3d at 1578 (“We now make it an even six” times that the Commission failed to respect this distinction), or tried to use another section of the NGA to “trump” its § 5 obligations, see Pub. Serv. Comm’n, 866 F.2d at 491 (holding that § 16 of the NGA, which grants the Commission the right to require filings needed to exercise its powers under the NGA, did not permit FERC to require a company to make periodic § 4 re-filings).

Nonetheless, the orders contain some express language supporting the position of the Commission’s counsel at oral argument that FERC will indeed shoulder the burden under § 5 of the NGA to show the requisite operational feasibility. See Order No. 637-A at 31,590-91 (suggesting that pro forma compliance filings are not § 4 filings, and that FERC “will be acting under Section 5 to implement changes”); Order No. 637-B at 61,165. Given that the character of § 5 is well established, we feel reasonably confident that the Commission will hew to its constraints; if not, obviously a judicial remedy would follow any individualized abuse.

As to the Commission’s determination to extract information from pipelines relevant to the practical issues, we see no violation of the NGA. The Commission has authority under § 5 to order hearings to determine whether a given pipeline is in compliance with FERC’s rules, 15 U.S.C. § 717d(a), and under § 10 and § 14 to require pipelines to submit needed information for making its § 5 decisions, 15 U.S.C. §§ 717i & 717m(c). See also Order No. 637-B at 61,165.

B. Specific defects

INGAA contends that, although FERC expressly limited its new segmentation rule to capacity “for which [the shipper] has contracted,” 18 C.F.R. § 284.7(d), the orders actually increase shippers’ transportation rights beyond their contractual scope, thus amounting to an unlawful abrogation of contract, and that the orders are otherwise arbitrary and capricious.

1. Primary point rights in segmented releases. In the Commission’s view, segmentation must be coupled with flexible point rights in order to create effective competition between pipeline services and released capacity. Order No. 637-A at 31,594. Take the Commission’s own example of a shipper holding firm capacity between the Gulf of Mexico and New York. That shipper could release the portion or segment of its firm capacity between the Gulf and Atlanta to a replacement shipper, permitting the replacement shipper to use the segment to deliver gas to Atlanta; meanwhile the releasing shipper would retain its firm capacity between Atlanta and New York, allowing it to ship gas from Atlanta to New York. Order No. 637 at 31,301. In this situation, both the releasing and the replacement shippers need to have the ability to change their primary receipt and delivery points from the ones designated in their contracts so as to be able to effectively make use of the segmented capacity; for instance, the replacement shipper needs to designate Atlanta as its primary delivery point, now that it has acquired rights to capacity in the mainline segment terminating there. If the replacement shipper were limited to less-than-primary rights at Atlanta, then the releasing shipper could not compete effectively with the pipeline as a seller of capacity, because the pipeline would have the right to sell capacity to the Atlanta point on a primary basis. See Order No. 637-A at 31,594.

INGAA objects to the Commission’s requirement that pipelines automatically grant shippers primary treatment at multiple points, subject only to operational constraints, saying that such a rule effectively abrogates pre-existing contractual arrangements — which limit primary rights to specific points — by endowing shippers with rights they have never bargained or paid for. Assuming the shippers’ rights are so limited, INGAA claims that the Commission has not met the standard under § 5 for abrogation of the pipeline’s rights. See Permian Basin Area Rate Cases, 390 U.S. 747, 822, 88 S.Ct. 1344, 1389, 20 L.Ed.2d 312 (1968) (abrogation permitted “only in circumstances of unequivocal public necessity”).

It is not clear, however, that there are any pre-existing contract rights to be “abrogated.” FERC’s policy tying flexible primary points with segmentation rights dates back to Order No. 636, which started the restructuring process; thus, it presumably governs the currently applicable contracts. In the Order No. 636 restructuring proceedings, the Commission generally permitted more than one approach by pipelines to granting shippers flexible point rights, but observed repeatedly that in the segmentation context, flexibility in point rights was required in order for segmentation to be a “meaningful option” or a “meaningful mechanism.” See, e.g., Transwestern Pipeline Co., 62 FERC ¶ 61,090 at 61,658, 1993 WL 73769 (1993); Northwest Pipeline Corp., 63 FERC ¶ 61,124 at 61,807, 1993 WL 186447 (1993). In some instances, the Commission did permit pipelines to limit shippers’ flexibility in choosing primary points, based on pre-existing tariff provisions. For example, in Tran-swestem Pipeline, the Commission approved a pipeline tariff that continued a pre-existing provision limiting a shipper’s primary point rights to the same level as its total mainline contract demand, based on a concern over hoarding of primary point rights. 62 FERC at 61,659; Order on Rehearing, 63 FERC ¶ 61,138 at 61,911-12, 1993 WL 291702 (1993). But even then the Commission noted Transwest-ern’s remark that it had a lot more primary point capacity than mainline capacity, and so acknowledged that perhaps the restriction would prove unneeded. Id., 62 FERC at 61,659; 63 FERC at 61,911-12. Thus, its practice appears to have been in effect an application of the operational feasibility principle, and this typically led to tariff rules broadly protecting releasing and replacement shippers’ interest in points along their respective segments. See, e.g., Northwest Pipeline, 63 FERC at 61,806-08. In the restructuring in Texas Eastern Transmission Corp., 63 FERC ¶ 61,100, 1993 WL 168160 (1993), for example, FERC stated its policy to be:

The releasing and replacement shippers must be treated as separate shippers with separate contract demands. Thus, the releasing shipper may reserve primary points on the unreleased segment up to its capacity entitlement on that segment, while the replacement shipper simultaneously reserves primary points on the released segment up to its capacity on that segment.

Id. at 61,452 (quoted verbatim in Order No. 637 at 31,302). See also El Paso Natural Gas Co., 62 FERC ¶ 61,311, 1993 WL 130322 (1993). Thus the new segmentation rule represents a continuation of past policy rather than a break with it, and no further special showing was required for the continuation of that policy.

2. Forwardhauls and backhauls to the same delivery point. INGAA also challenges what the Commission viewed as a clarification of prior policy for the situation where releasing and replacement shippers, in a combination of forwardhaul and back-haul, make deliveries to a single point in an amount greater than the shipper’s contracted-for capacity at the delivery point.

First, we need to develop a clear picture of a backhaul transaction. Suppose a pipeline runs from A to B to C, and has 10,000 dekatherms of daily capacity, all of which is contracted for from A to C and of which X holds 1000. X’s market at C declines, and X would like to ship only to B and to release the 1000 in B-C capacity. X learns of another possible shipper, Y, who has a right to 1000 dekatherms at C and would like to sell it at B. Can X release its B-C capacity to Y, even though the nominal “flow” of Y’s intended shipment is against the A to C stream?

So far as mainline capacity is concerned, we understand the parties to agree that this is permissible. Given that the gas actually will not and cannot be moved upstream, the deal appears to force the pipeline to carry an extra 1000 from A to B (the basic 10,000, plus the 1000 to be delivered at B on behalf of Y). But because of gas’s fungibility the appearance is false. The pipeline will now deliver 9000 at C, and it will rely on Y’s supply for 1000 of that. As a result, it still need carry only 10,000 from A to B, where it will dispense 1000 for X’s account and 1000 for Y. On the B-C leg it need carry only 8000. Thus the transaction does not violate FERC’s rule that segmentation may not result in shipments exceeding the shippers’ contracted-for capacity rights on any segment. Order No. 637-A at 31,591.

But the parties are in dispute over the delivery point. Suppose that point B, instead of being the same physical delivery facility, were really two nearby points, Bx and B2, the latter a bit downstream of the former. Both sides agree that the above transaction would be all right, subject to the operational feasibility constraint, even though deliveries are now being made at those two sites that were not specifically contracted for. But INGAA balks at the original hypothetical (where both new deliveries are at B), because of the alleged excess beyond X’s contract rights.

Some decisions prior to the present orders suggest that the Commission too disapproved of such a transaction. In at least one case the Commission said that such a transaction produced a fatal “overlap” at the single point of delivery. “A shipper may segment its capacity rights, but it cannot exceed its contractual service levels at any point.” Iroquois Gas Trans. Sys., L.P., 78 FERC ¶ 61,135 at 61,523-24, 1997 WL 233953 (1997). But a few years later the Commission allowed what appears to be substantially similar, a combined “for-wardhaul and backwardhaul to a series of 23 meter stations considered as a single point for nomination purposes,” Order No. 637-A at 31,593, citing Transcontinental Gas Pipe Line Corp., 91 FERC ¶ 61,031, 2000 WL 377683 (2000).

Finding that its prior policy was based on a “metaphysical distinction” between a single point and two points adjacent to each other, FERC decided in the present orders that, to advance its new segmentation policy, it would no longer apply “prior restrictions” on using forwardhauls and backhauls to the same point. Order No. 637-A at 31,592-93.

The Commission’s characterization of the distinction as “metaphysical” may in the end be correct, but it is not self-evident: The number of angels that can stand on the head of one pin seems physically (rather than metaphysically) different from the question how many can stand on two. Although the Commission observed that the pipelines seeking rehearing had not shown that they faced “any operational problems in permitting such flexibility,” Order No. 637-B at 61,166, that issue is distinct from the problem of an inadequately supported contract modification. Accordingly, we remand this issue to the Commission so that it can more clearly confront the question of whether this aspect of the orders can stand without additional findings.

3. Virtual pooling points. INGAA attacks the Commission’s decision that segmentation be permitted at “any transaction points on the pipeline system, including virtual transaction points, such as paper pooling points, as well as at physical interconnect points.” Order No. 637-A at 31,591-92. It argues that this provision grants rights to certain shippers that are detrimental to other shippers, and interferes with how such “virtual” points actually operate.

A “virtual point” is a paper or accounting point that does not physically exist on a pipeline. One kind of a virtual point is a “paper pooling point,” which is used for administrative purposes, i.e., to aggregate the receipt of gas from multiple physical points in a specific geographic area to simplify accounting.

INGAA reasons that because a paper pooling point does not physically exist, a shipper cannot purchase the right to transport gas to or from that point along an identifiable capacity path: a shipper that segments its capacity in relation to a paper pooling point could end up flowing gas on overlapping physical segments of the pipeline and thus in excess of its contracted-for capacity. For instance, if a pipeline runs from A to B to C to D, and B and C are physical points included in a single paper pool, then a shipper releasing the B-D capacity and retaining the A-C capacity would be making an overlapping use of the B-C segment.

In Order No. 637-B the Commission acknowledged such a possibility, but nevertheless thought that “[t]o the extent such difficulties [i.e., overlapping] exist, they are more appropriately examined in the compliance filings.” Order No. 637-B at 61,165. We understand this to mean that the Commission is serious in its commitment that it will not apply segmentation in a way that subjects pipelines to overlapping uses of mainline capacity. Oddly, the Commission’s brief writers seem to have adopted a rather in-your-face approach, declaring flatly that “[t]his type of segmentation does not result in the overlap of capacity and Petitioners have not explained otherwise.” FERC Br. at 111.

Despite the brief, we take the Commission at its word — namely, that in the compliance process it will not apply the orders in such a way as to violate the precept against forcing overlaps on a pipeline.

4. Reticulated pipelines. In contrast to linear pipelines, a reticulated pipeline has a web-like structure. Such pipelines are typically located in a single geographic area and have receipt and delivery points interspersed throughout the system. Gas flows are not unidirectional but instead reverse direction depending on supply and demand. They typically rely on “displacement” to make deliveries, that is, the substitution of gas at one point for gas received at another point.

In the orders, the Commission recognized that “permitting segmentation on a reticulated pipeline can result in operational difficulties” because unplanned changes in flow patterns might threaten their operational integrity. Order No. 637-A at 31,-591; see also Northwest Pipeline, 69 FERC ¶ 61,171 at 61,677, 1994 WL 614063 (1994) (“certain offsetting volumes must flow in one direction in order for customers shipping in the opposite direction to receive service,”). But it nonetheless said that these pipelines must “permit segmentation to the maximum extent possible given the configuration of [the] system,” Order No. 637 at 31,304, and must “optimize [their] system[s] to provide maximum segmentation rights while devising appropriate mechanisms to ensure operational stability,” Order No. 637-A at 31,591, a duty that may include “allowing segmentation on straight-line [non-reticulated] portions of the pipeline,” Order No. 637-B at 61,-165.

INGAA first contends that it is arbitrary and capricious for FERC to apply the segmentation rule to reticulated pipelines, because these pipelines have no identifiable capacity paths to segment, and therefore “segmentation is not possible on reticulated systems.” INGAA Segmentation Br. at 27. But the Commission’s only clear language requiring segmentation in this context explicitly focused on “straight-line portions of the pipeline.” Order No. 637-B at 61,165. Insofar as its other, vaguer language invites extreme interpretation, we understand it to be qualified as always by the operational feasibility criterion. As we cannot possibly divine the vague phrases’ operational meaning, the claim is now unripe. See Abbott Labs. v. Gardner, 387 U.S. 136, 149, 87 S.Ct. 1507, 1515, 18 L.Ed.2d 681 (1967) (stating that to evaluate ripeness, a court must consider “both the fitness of the issues for judicial decision and the hardship to the parties of withholding court consideration”), overruled on other grounds, Califano v. Sanders, 430 U.S. 99, 97 S.Ct. 980, 51 L.Ed.2d 192 (1977); Rio Grande Pipeline Co. v. FERC, 178 F.3d 533, 540 (D.C.Cir.1999) (“[A] case is ripe when it presents a concrete legal dispute [and] no further factual development is essential to clarify the issues ... [and] there is no doubt whatever that the challenged [agency] practice has crystallized sufficiently for purposes of judicial review.”) (internal citation and quotation marks omitted).

The same unripeness applies to IN-GAA’s claims regarding a special class of reticulated pipelines, those employing “postage stamp” rate structures. In such pipelines, as for first class mail in the U.S. postal system, the same transportation rate applies to all transactions. This contrasts with the usual rate structure for non-reticulated pipelines, and for some reticulated ones, under which the rate depends on the zones through which the gas passes. INGAA argues that in this context segmentation grants shippers extra-contractual rights and is an unexplained and, therefore, arbitrary and capricious departure from prior policy.

Order No. 637-A provides that, “[o]n reticulated pipelines with postage stamp rate structures, where shippers have no specifically defined paths, the pipeline should permit firm shippers to use all points on the system and to use or release segments of capacity between any two points, while continuing to use other segments of capacity.” Order No. 637-A at 31,591. The Commission justifies this policy on the ground that shippers on such pipelines pay “for the use of the entire pipeline in their rates.” Id. Finally, the Order notes that, if these pipelines find that providing segmentation “would be more feasible with a redesign of its rates, the pipeline can make a Section 4 filing to establish rates that it considers more consonant with segmentation.” Id.

INGAA suggests that under this language the Commission may intend to allow shippers “to multiply their capacity rights.” INGAA Segmentation Br. at 28. The language is indeed susceptible of such a reading; taken at the extreme, it is as if the Post Office, having agreed to carry letters anywhere for 34 cents, including from New York to San Francisco, could be obliged to carry one letter from New York to Chicago, and another from Chicago to San Francisco, all for one 34-cent stamp. The Commission’s allusion to new filings under § 4 only heightens the impression of overweening agency ambition. Can the Commission contemplate that it will use § 5 in compliance proceedings to compel costly changes in pipeline operation, leaving the pipeline to recover the resulting costs by filing under § 4? But to conjure up such activities is not to say that the Commission’s language compels them. Until the words are implemented, claims based on this language are unripe.

5. Discounts. Under typical discount agreements, pipelines agree to provide shippers with services at discounted rates, but with those rates limited to agreed-upon receipt and delivery points. Before these orders, the Commission’s policy was that “discounts granted with respect to specific points do not apply when shippers change points.” Order No. 637-A at 31,595. This meant that when a shipper released part of its capacity, the releasing or replacement shipper was subject to the non-discounted rate if it exercised its right to designate different receipt or delivery points. Id.

Some of the Commission’s language here appears to contradict the prior view. For example, the Commission said that “within the path” of a shipper’s contract, it “should be permitted to ... segment capacity along that [discounted] capacity path without incurring additional charges,” i.e., without having to pay the non-discounted rate. Order No. 637-A at 31,595. And it said that the reason a discount should apply to segmented transactions is that, once a long-line pipeline has discounted transportation to a downstream delivery point, “it has foreclosed the possibility of selling that capacity” at a higher rate to an upstream delivery point. “[T]he discount, therefore, should apply to all transactions within the capacity path.” Order No. 637-B at 61,167.

Several aspects of discounting are affected here. First, the Commission refers to discounts granted because of pipeline “underutiliz[ation],” Order No. 637-A at 31,595. When a pipeline discounts some capacity from A to C solely for that reason, presumably the discount is consistent, in the pipeline’s view, with the levels of demand in even the most heavily used segment. Thus the observation quoted above from Order No. 637-B.

But the Commission also recognized that discounts may be given because of differing competitive conditions. It said that pipelines “will still be able to discount transportation to a particular customer who has competitive options to stimulate throughput without necessarily offering the same discount to other customers who are not similarly situated.” Order No. 637-B at 61,168. The difference in conditions might be customer-specific (e.g., a fuel-switchable industrial user) or segment-specific (e.g., a pipeline might be subject to severe competition between points A and C, but to little between points A and B (the latter being an intermediate point between A and C)).

Finally, of course, the whole capacity release program as a general matter creates possibilities for arbitrage. If a high-elasticity customer is completely free to transfer capacity to a low-elasticity one, offering price variations not based on cost becomes a far less tempting pipeline strategy-

But again the issue is unripe, as the orders leave us quite unclear just what will emerge from all this. Besides the already quoted commitment to preserve at least some competition-based discounts, the Commission said that “it did not intend to change the rules regarding selective discounting.” Order No. 637-B at 61,168. We are in no position to assess the legality of the Commission’s intentions, which will only be revealed in future proceedings.

III. Secondary Point Capacity Allocation

In Order No. 637-A FERC changed the rule for allocating mainline capacity leading to secondary delivery points — the additional points to which a firm shipper may wish to deliver gas besides its primary delivery location. Order No. 637-A at 31,597. Because shipments to such secondary points are normally accorded lower priority than deliveries to primary points, this service is subordinate to “firm” service during periods of congestion. Order No. 637 at 31,304-05. In the past, the Commission’s rule governing secondary point capacity allocation during constrained periods was the pro rata method. Shippers whose primary delivery points were located in the same rate zone — a geographical area treated as a single point for rate purposes — had equal entitlements to the capacity needed to reach secondary points in that zone; if they requested more secondary point capacity than was available, it was allocated pro rata. Id.

The Commission illustrates the issue with the following diagram:

[[Image here]]

Order No. 637-B at 31,597. On the facts given, the old rule gave shippers 1 and 2 equal rights to the mainline capacity needed to ship to B, with their entitlements being inferior to shipper 3’s.

In Order No. 637-B, however, the Commission concluded that a different approach would better assure allocation of the capacity to the shipper valuing it most highly. Under its new “within-the-path” rule, all shippers for whom the point is within their capacity path — that is, the shippers whose primary delivery points are downstream of the point at which secondary rights are sought — receive preference over shippers for whom the point is not in their capacity path. In the example above, then, shipper 2 would have a straightforward priority over shipper 1, though even shipper 2 would be subordinate to shipper 3. Order No. 637-B at 31,597. The Commission’s theory was that the priority for shipper 2 would reduce transaction costs and, by establishing shipper 2 as a more vital competitor (with shipper 3) as a source of capacity, would enhance competition.

Two interstate pipelines owned by Enron (collectively, “Enron”) now challenge the new rule for allocating capacity at secondary points on a number of grounds. We do not reach those issues because Enron has not made an adequate showing that it is aggrieved by FERC’s ruling. As it lacks both statutory and constitutional standing to bring this petition, we dismiss it for lack of jurisdiction.

The NGA requires, as a precondition to judicial review, that a party be “aggrieved” by the order in question, 15 U.S.C. § 717r(b); El Paso Natural Gas Co. v. FERC, 50 F.3d 23, 26 (D.C.Cir.1995), and all parties trying to invoke the jurisdiction of federal courts must satisfy Article Ill’s requirements of constitutional standing. “Common to both of these thresholds is the requirement that petitioners establish, at a minimum, ‘injury in fact’ to a protected interest.” Shell Oil Co. v. FERC, 47 F.3d 1186, 1200 (D.C.Cir.1995). To show “injury in fact,” a litigant must allege harm that is both “concrete and particularized” and “actual or imminent, not conjectural or hypothetical.” Lujan v. Defenders of Wildlife, 504 U.S. 555, 559-61, 112 S.Ct. 2130, 2136, 119 L.Ed.2d 351 (1992).

Enron is a pipeline, not a shipper, so no injury leaps to the eye. But it proposes two theories of injury, one based on the effect of the rule on competition, the other on administrative burdens generated by the rule. Neither is persuasive.

First Enron suggests the new method will diminish competition in the supply of capacity by decreasing the number of possible suppliers. The reduced competition would cause higher gas prices in end-use markets, reducing overall gas consumption, and thereby reducing pipeline throughput.

Where a claimed injury stems from changes in levels of competition, this court ordinarily requires claimants to show that “a challenged agency action ... will almost surely cause [them] to lose business.” El Paso, 50 F.3d at 27 (emphasis supplied); see also D.E.K. Energy Co. v. FERC, 248 F.3d 1192, 1195 (D.C.Cir.2001). Enron relies on a simple account under which “eliminating competitors reduces competition.” Enron Repl. Br. at 5; Enron Br. at 11. Everything else being equal, that is likely a sound assumption. But the Commission here thought — and Enron has not shown the contrary — that matters were more complex.

The Commission’s stated rationale for adopting its new method was that the pro rata method “does not provide for the most efficient use of mainline capacity or promote capacity release because it creates uncertainty as to how much mainline capacity any shipper seeking to use secondary points will receive.” Order No. 637-A at 31,597. As a result the secondary rights were not tradable, and there was no effective competitor to the primary rights holder as a seller of secondary rights. Id. By comparison, under the within-the-path method, the fewer shippers to whom secondary rights would be awarded would hold — and thus be able to offer in the market — -a useful entitlement to service. Id. In FERC’s opinion, this increase in certainty of entitlement would actually improve competition. Id.

We need not pass on the ultimate merits of the Commission’s reasoning to say that Enron’s contrary theory fails to show the requisite probability of harm. Basically, the showing is far too conjectural to establish “a substantial (if unquantifiable) probability of injury,” D.E.K. Energy, 248 F.3d at 1195, as demanded by El Paso’s “almost surely” test.

Alternatively, Enron claims that that the company will incur “significant expense” in implementing the new method because it must modify its computer systems “in order to accommodate multiple levels of secondary point priorities.” Enron Repl. Br. at 3. While compliance costs often constitute an injury-in-fact, Enron’s argument here rests solely on a conclusory, vague and unsupported assertion of cost increases. See Enron Repl. Br. at 3. Compare Virginia v. American Booksellers Ass’n, Inc., 484 U.S. 383, 392, 108 S.Ct. 636, 642-43, 98 L.Ed.2d 782 (1988) (standing where plaintiff “will have to take significant and costly compliance measures or risk criminal prosecution”); see also id. at 389, 391, 108 S.Ct. at 640-41, 642 (detailing steps needed for compliance). Thus we dismiss the petition for want of jurisdiction.

IV. Penalties

Order No. 637 changed the rules governing what pipelines may do when shippers overrun their transportation entitlements (by shipping more gas than they have contracted for) or create physical imbalances in the pipeline system (for example, by withdrawing more — or less — gas from the system than they have tendered). Previously, in the interests of deterrence, see Order No. 636 at 30,424, pipelines were allowed to enforce their contractual rights by imposing appropriate penalties, that is, charges that “reflect[ed] more than simply the costs incurred as a result of the [shipper’s] conduct,” Order No. 637-A at 31,-610; cf. id. at 31,608; Order No. 637-B at 61,171. The penalties were enforceable whether or not the offending shipper’s behavior caused any actual harm to the pipeline’s system or threatened its reliability. See, e.g., Natural Gas Pipeline Co., 63 at 63,052, 1993 WL 218847 (1993).

Order No. 637 sharply restricted pipelines’ ability to assess penalties. FERC amended its regulations to provide:

Penalties. A pipeline may include in its tariff transportation penalties only to the extent necessary to prevent the impairment of reliable service. Pipelines may not retain net penalty revenues, but must credit them to shippers in a manner to be prescribed in the pipeline’s tariff.

18 C.F.R. § 284.12(c)(2)(v); Order No. 637 at 31,314. As FERC said, “This requirement may result in either no penalties for non-critical days [days when the pipeline is not expected to operate at or near full capacity] or higher tolerances and lower penalties for non-critical as opposed to critical days.” Order No. 637 at 31,317. In addition, the rule denies pipelines the right to retain revenues from penalties, instead requiring them to credit them to shippers. Id. at 31,309.

In addition, Order No. 637 required pipelines to provide “imbalance management services,” such as parking (i.e., temporary storage) and lending of gas, and greater information about the imbalance status of a shipper and the system as a whole, in order to give shippers positive incentives — in lieu of penalties — to manage or prevent imbalances. Order No. 637 at 31,309; 18 C.F.R. § 284.12(c)(2)(iii). The Order also allowed pipelines to retain revenues generated from these imbalance management services until the pipeline’s next rate ease, as would be true for other new pipeline services initiated between rate filings. Order No. 637 at 31,310. Thus it used carrots with the pipelines to encourage them to use carrots with their customers.

We deal here with a basic attack on FERC’s policy change, as well as specific claims relating to the treatment of revenues from such penalties as remain and to the new imbalance services.

A. INGAA attack on penalty limits

INGAA and several pipelines (again collectively, “INGAA”) claim that in adopting its new penalty rule the Commission did not make the required § 5 findings or exercise reasoned decisionmaking, and that the new rule unlawfully infringes on pipelines’ ability to enforce their contractual rights.

When FERC seeks affirmatively to displace a pipeline’s existing rates or tariff provisions, the previously stated requirements of § 5 of the NGA apply. But there is no requirement that FERC use the “magic words” of § 5 itself, Rhode Island Consumers’ Council v. Fed. Power Comm’n, 504 F.2d 203, 213 n. 19 (D.C.Cir.1974), and indeed one would search the relevant portions of Order No. 637 in vain for words such as “just” or “unjust.”

But the Commission did find that the existing penalty system was “not the most efficient system of maintaining pipeline reliability,” and that it “skewed” the market choices that shippers and pipelines would otherwise make. Order No. 637 at 31,-306-07. As we understand the core of the Commission’s analysis, it was that excessive pipeline penalties, and skimpy pipeline “tolerances” (i.e., allowances for contract excesses that would not generate penalties), made shippers unduly gun-shy. Excessive disincentives led them to oversubscribe to firm pipeline capacity, or un-deruse their entitlements, in order to assure a decent safety margin. Order No. 637 at 31,308; Order No. 637-A at 31,607 & nn.150, 152. Such consequences would seem to follow excessive penalties virtually as a matter of definition, but in addition there was testimony as to the behavior of prudent shippers. See, e.g., id. at 31,607 n. 152. And in fact INGAA does not even try to dispute that the pre-existing penalties produced these results.

Aside from being concerned with the adverse effects of the penalties, the Commission also concluded that the prior regime was ineffective in fulfilling what was supposed to be its “intended purpose,” Order No. 637-A at 31,608 — deterring shipper conduct that actually threatened the integrity of the pipeline system at critical times. Order No. 637 at 31,308; Order No. 637-A at 31,598, 31,607 & n.152. Because the penalty levels were disconnected from threats to reliability, they did not offer incentives in any way calibrated to those threats. Indeed, penalties were evidently often higher on systems where and at times when extra gas posed no threat to reliability at all, than on systems with such threats.

It was thus the Commission’s conclusion that it should henceforth tie the imposition of penalties to behavior actually causing a threat to system integrity. Order No. 637 at 31,308. And, to eliminate market distortions caused by “the use of penalties as a substitute for obtaining services,” id. at 31,314, the Commission believed that it was necessary for pipelines (or third parties) to directly provide shippers with the service flexibility they had been obtaining indirectly via their responses to the penalty regime; thus the requirement of separate imbalance management services at cost-based pricing. Id. at 31,309. Finally, the Commission’s new rules on disposition of the revenues — disallowing pipeline retention of penalties but allowing retention of the proceeds of new balancing services — obviously reinforced its basic policy judgment.

We are not altogether clear why the Commission’s response to excess penalties was to bar all penalties not directed to threats to reliability, and otherwise to switch to “carrots.” One might suppose that the most obvious response to excessive penalties would be to place ceilings on them — calibrated to the damage inflicted by the penalized behavior, whether it took the form of a threat to reliability or not. This option is not discussed, and petitioners neither suggest it nor fault the Commission for its failure to consider it. Perhaps the answer is that in fact there are no injuries other than the ones to system reliability. That in turn would seem to depend on the actual treatment of — and incentives facing — shippers who overrun their contract entitlements under circumstances posing no threat to reliability.

In fact, the Commission’s limits on penalties (as they are understood in this regulatory regime) appear to leave potential contract breaches covered by appropriate sanctions. When a shipper incurs a contract overrun, it must still pay for the interruptible service it has used for the surplus. Order 637-B at 61,172. Moreover, as was conceded by INGAA’s counsel at oral argument — and confirmed by Commission counsel — FERC’s current open access rules require a pipeline to make its spare capacity available to any shipper who desires it, at the interruptible rate. Tr. Oral Arg. at 106-07. Thus, a shipper that overruns its contract and suddenly seeks additional service is apparently treated (apart from penalties) just the same as any unscheduled interruptible shipper. “The capacity that a shipper would obtain by means of an unauthorized overrun is not firm service, but is interrup-tible service that is subject to bumping and is limited by the capacity available at the time.” Order No. 637-B at 61,171. Indeed, the firm shipper that overruns its entitlement in a non-peak time may be worse off than a garden-variety interrupti-ble shipper, as the latter may enjoy discounts evidently unavailable to the overrunning customer. Tr. Oral Arg. at 108.

Likewise, a shipper who runs an imbalance must either make-up or pay for the gas he took. Order No. 637-B at 61,171-72. Although the record seems not to explain what price will govern such a transaction, we were told at oral argument that the offending shipper might be obliged to pay a higher price than a user with similar needs who chooses instead to take advantage of the imbalance management services or avoids creating an imbalance altogether by purchasing excess gas from another shipper. Tr. Oral Arg. at 111.

Thus, even with penalties now largely gone, pipelines are no more forced to provide extra-contractual services under the new rule than they were under the old one. What has changed is merely the remedy for breach. Nor are pipelines turned into “common carriers” required to provide service to anyone regardless of whether they have a contract; their duties in this respect are set out in the previously adopted open access rules.

The rules governing shippers who exceed their contract entitlement also answer another concern of INGAA’s: that because of the limited availability of penalties, shippers will not contract and pay for an adequate level of firm service but instead will simply overrun their contract capacity as needed. In fact, in non-peak times such shippers will do no better than interrupti-ble shippers (and perhaps worse, because of the discount issue). And since overruns during peak times can still trigger penalties, shippers who need guaranteed service should not be tempted to contract for less capacity than what they expect to need. Order No. 637-B at 61,171.

INGAA also accuses FERC of failing to engage in reasoned decisionmaking because of what INGAA perceives as a logical disconnect between FERC’s stated goal — elimination of the inefficiencies of the pre-existing penalty system — and FERC’s adoption of carrots as the cure. INGAA suggests that the pipelines’ mandated proffer of imbalance services is hardly equivalent to penalties, for on noncritical days, when penalties are not an option, shippers will have no incentive to use or pay for imbalance services. As they will continue to engage in creating overruns and imbalances, the Commission’s rule is internally inconsistent and will not further FERC’s stated goals.

In large part this is answered by our earlier discussion of the incentives faced by shippers under the new regime; the Commission appears to have successfully rebutted INGAA’s prediction that the curtailment of penalties would harm any pipeline interest that deserved protection. That the Commission’s hope and expectation of a flourishing market in balancing-related services may prove unwarranted does not undermine that essential conclusion.

Thus the Commission made generic findings in support of its action under § 5, see TAPS, 225 F.3d at 687-88, which were backed by substantial evidence, and its conclusions met the standard for reasoned decisionmaking.

B. Attacks on revenue-crediting provisions

On one hand a group of pipelines (not joined by INGAA) attack the Commission’s requirement that they flow penalty revenues to non-offending shippers, and on the other several shippers and state consumer advocates argue that the pipelines should not be allowed to retain the revenues from the new imbalance services. Neither attack is well conceived.

The pipelines claim that (1) the Commission did not find that previously approved tariffs and settlements, which imposed no such refunding mechanism, were unjust and unreasonable; and (2) the Commission justified the refund requirement “as an incentive for pipelines not to impose penalties,” whereas pipelines should actually be given incentives to impose the penalties allowed by the new rule, as they necessarily apply only when shipper conduct threatens system reliability.

The first argument appears erroneously to assume that “magic words” are required under § 5; as we’ve said, they are not. And as we’ve already explained, the Commission’s discussion of penalties in Order No. 637 reflects compliance with § 5. In substance the Commission’s finding of unsound incentives, see Order No. 637 at 31,316, amounts to a finding that the prior method was unjust and unreasonable.

The pipelines’ critique of the Commission’s rationale misconceives its purpose. FERC’s goal here was not to discourage pipelines from imposing penalties at all but rather to motivate them “to impose only necessary and appropriate penalties,” and to develop non-penalty mechanisms to deal with imbalance problems. Order No. 637 at 31,316. Requiring refunds of penalty proceeds simply removes an incentive to impose unnecessary penalties. See Order No. 637 at 31,316 (stating that FERC was “requiring penalty revenue crediting not so much for the purpose of preventing penalties from becoming a profit center, but more for the purpose of eliminating any financial incentives on the part of pipelines to impose penalties that would naturally hinder the pipelines’ movement toward reliance on the provision of imbalance services.... ”).

On the other side, the shippers first object to pipeline retention of revenues from imbalance services on the theory that because Order No. 637 requires pipelines to develop such services in any event, no financial incentive is necessary. But the directive to develop such services is not inherently self-executable. Unless the Commission were ready to take on a large new program for micromanagement of pipelines, it makes complete sense for it to rely on positive incentives instead of punitive measures to promote compliance. Besides, as the Commission explained, its decision on this point is entirely consistent with its current general policy of allowing pipelines to retain revenues from “a new service initiated between rate cases.” Id. at 31,310.-

Finally the shippers assert that the Commission’s policy here is inconsistent with two recent Commission decisions requiring pipelines to share new-service revenues with shippers, citing Trunkline Gas Co., 79 FERC ¶ 61,326 at 62,427-28, 1997 WL 318098 (1997), and Columbia Gas Transmission Corp., 64 FERC ¶ 61,365 at 63,530, 1993 WL 385590 (1993). But these cases involved sharing interruptible service revenues under conditions where the Commission believed there was a substantial risk of overrecovery by the pipelines in question. The petitioners have not shown that any such conditions obtain here.

V. The Right of First Refusal

As part of its long-running effort to devise balanced rules to protect long-term capacity holders from abandonment of service when their transportation contracts with pipelines expire, FERC also made changes to its “right of first refusal” rules. In some respects, it narrowed those rights, limiting their benefit to long-term shippers paying the maximum tariff rate. In other ways, it expanded them, allowing incumbent shippers to exercise the right of first refusal by bidding for a mere five-year term. This contrasted with the 20-year term that it had set in Order No. 636, which gave the pipelines considerably more stability and which, in UDC, 88 F.3d at 1140-41, we found inadequately justified. Again, the agency’s actions have been challenged from both sides, as going too far and not far enough.

A. Five-year matching cap and “regulatory” right of first refusal

Section 7(b) of the Natural Gas Act generally prohibits “natural-gas companies]” from ceasing to provide service to their existing customers unless, after “due hearing,” FERC finds “that the present or future public convenience or necessity permit such abandonment.” 15 U.S.C. § 717f(b). Seeking to streamline the regulatory process, the Commission in Order No. 436 attempted to dispense with these individualized hearings by giving pipelines broad prospective authority to refuse shippers continued service on the expiration of them contracts (in the absence of a contractual right of renewal). See American Gas Ass’n v. FERC, 912 F.2d 1496, 1513-14 (D.C.Cir.1990) (“AGA”). Under this mechanism, the Commission makes ex ante generic findings of public convenience and necessity, and issues a blanket certificate that allows a pipeline to terminate service at the end of the shipper’s contract term. See 18 C.F.R. § 284.221(d); cf. Mobil Oil Exploration & Producing Southeast, Inc. v. United Distrib. Cos., 498 U.S. 211, 227, 111 S.Ct. 615, 625, 112 L.Ed.2d 636 (1991) (allowing the Commission to issue “general, prospective, and conditional” abandonment approvals under § 7(b)).

When this court addressed the merits of the issue in AGA, we remanded the rule for lack of an adequate explanation of how it could be squared with the Commission’s basic duty to protect gas customers from “pipeline exercise of monopoly power.” AGA 912 F.2d at 1518. But we noted that all parties recognized that such a procedure made sense for at least some transactions, most notably interruptible services and short-term contracts. See id.

In Order No. 636, the Commission responded to AGA and modified its earlier approach by supplementing pre-granted abandonment authority with a right of first refusal for those shippers the Commission considered to be captive and thus in need of protection — those operating under a firm contract longer than one year. Order No. 636 at 30,446-48. The right entitled a protected shipper with an expiring contract to retain its service from the pipeline under a new contract by matching the rate and duration offered by the highest competing bid — up to the maximum “just and reasonable” rate approved by FERC. On reconsideration, the Commission also adopted a 20-year cap on the length of the term that existing shippers may be required to match. Order No. 636-A at 30,631.

On review, though we generally upheld pre-granted abandonment as supplemented with the right of first refusal, see UDC, 88 F.3d at 1140, we thought that the 20-year cap was not justified by the record and remanded it for further explanation. Id. at 1140-41. We expressed concern that contract duration could become a surrogate for price (which, of course, is capped), thereby allowing new customers to outbid existing ones by offering longer terms than they would in a truly competitive market. Id. at 1140. In addition, while FERC had picked 20 years in reliance on actual contracts, we questioned whether the subset of contracts relied on— involving the construction of new facilities — was properly representative. Id. at 1141. But because the selection of any duration for the matching cap would be “necessarily somewhat arbitrary,” we said we would “defer to the Commission’s expertise if it provides substantial evidence to support its choice and responds to substantial criticisms of that figure.” Id. at 1141 n. 45.

On remand, FERC decided to reduce the 20-year cap to one of five years, pointing to what it perceived as the current industry trend in favor of shorter term shipping contracts. Order No. 636-C, Order on Remand, Pipeline Service Obligations and Revisions to Regulations Governing Self-Implementing Transportation Under Part 284 of the Commission’s Regulations, 78 FERC ¶ 61,186 at 61,773-74 (1997) (“Order No. 636-C”). Despite objections from the pipelines, FERC summarily affirmed its decision in Order No. 636-D, Order on Rehearing, Pipeline Service Obligations and Revisions to Regulations Governing Self-Implementing Transportation Under Part 281 of the Commission’s Regulations, 83 FERC ¶ 61,210 at 61,925, 1998 WL 327106 (1998).

In Order No. 637 the Commission again confirmed the five-year period. See id. at 31,339. And it made clear that right of first refusal “includes the right of the existing shipper to elect to retain a volumetric portion of its capacity subject to the right of first refusal, and permit the pipeline’s pregranted abandonment to apply to the remainder of the service.” Id. at 31,-341. Moreover, it said that the “regulatory” right of first refusal (i.e., the right supplied by this Commission mandate) was a minimum right, usable by an eligible shipper regardless of whether its contract provides a comparable right (by means, for example, of an “evergreen” clause), and that the shipper might exercise the regulatory right for part of the contract volume and any contract right for the rest. Id.-, Order No. 637-A at 31,647. It also specified, most clearly in Order No. 637-A, that the right trumped any inconsistent provision in a pipeline’s tariff.

A group of interstate gas pipelines, led by INGAA (collectively “INGAA”), attack both retention of the five-year period and the Commission’s explicit statement that the right of first refusal applies regardless of tariff provisions.

1. Five-year cap. In selecting a five-year cap on remand from UDC, the Commission gave little indication of why it thought that this new figure would appropriately balance the protection of captive customers with the furtherance of market values (putting capacity in the hands of those who value it most). It relied entirely on the fact that five years was about the median length of all contracts of one year or longer between January 1, 1995 and October 1, 1996. See Order No. 636-C at 61,774, 61,792. This contrasted with average durations of about 10 years in the period from April 8, 1992 to October 1, 1996.

Before confirming the five-year figure, the Commission itself raised doubt about its wisdom. In Order No. 636-D, it acknowledged that “the pipelines have raised legitimate concerns about the practical effects of the five year term matching cap on the restructured market as it continues to evolve.” Order No. 636-D at 61,926. At that point the Commission decided to defer a final decision about the length of the cap until “a new gas policy initiative” (which proved to be Order No. 637), because at the time it had “no information concerning current conditions in the natural gas industry.” Order No. 636-D at 61,926. In its NOPR for Order No. 637, FERC raised what it perceived were further problems with the five-year term, suggesting that it “provides a disincentive for an existing shipper to enter into a contract of more than five years, and results in a bias toward short-term contracts.” Notice of Proposed Rulemaking, Regulation of Short-Term Natural Gas Transportation Services, FERC Stats. & Regs. [Proposed Regulations 1988-1998] (CCH) ¶ 32,533 at 33,486 (1998). The Commission apparently was concerned that the cap would foster an “imbalance of risks between pipelines and existing shippers,” allowing shippers indefinite control over pipelines’ capacity, but giving the pipelines no corresponding protection. Id. at 33,486-87. Thus, it suggested, elimination of the cap would “foster efficient competition.” Id. at 33,487. Moreover, as the pipeline petitioners point out, an artificial, regulation-induced shift toward shorter contracts increases risk for the pipelines; this tends to raise their costs of capital and thus the overall cost of pipeline transportation. And, they note, it is odd — or at least requires explanation— why FERC should choose a median to function as a ceiling.

But when FERC ultimately elected to retain the five-year period, it addressed none of the difficulties that it (or the pipelines) had previously invoked. Instead, it simply referred back to Order No. 636-C’s evidence about median contract lengths and remarked that “[n]one of the commen-ters presented evidence to support the conclusion that a five year contract is atypical in the current market.” Order No. 637 at 31,339; see also Order No. 637-A at 31,664 (concluding simply that there “is no evidentiary basis at this time for changing the 5-year matching cap”). Thus the only evidence supporting FERC’s final decision to choose a five-year cap was the original record — which on the Commission’s own view was incomplete. There is neither an affirmative explanation for the selection of five years, nor a response to its own or the pipelines’ objections.

We therefore vacate the five-year cap and remand the issue back to the agency. The Commission may appear to be, vis-á-vis the court, like mankind to the gods: As flies to wanton boys, they kill us for their sport. Pick 20 years, and get reversed for failing to explain the length; pick five, and get reversed for failing to explain the brevity. But our acknowledgment of the difficulty of the policy choice, see UDC, 88 F.3d at 1141 n. 45, is fully intended. The record simply lacks indicators of the Commission’s seriously tackling that choice.

2. Right of first refusal trumping tariff provisions. Pipeline counsel accuse the Commission of wrongfully creating a “regulatory” right of first refusal in Order No. 637. We think their claim can better be comprehended as saying that the Commission in that order transformed its requirement of a right of first refusal, ensconced in the Commission’s regulations since April of 1992, see Order No. 636 at 30,446^48; see also § 284.221(d)(2)(ii), into a self-executing requirement. That is, their argument is comprehensible only as a claim that before Order No. 637 the right of first refusal had legal effect only to the extent that it was expressly embodied in a pipeline tariff. In fact, Order No. 637 and Order No. 637-A appear to be the Commission’s first express articulations of the idea that the regulatory right of first refusal trumps tariff provisions. The first declares that eligible shippers have “the right of first refusal as provided in the Commission’s regulations,” Order No. 637 at 31,341, and the second expressly says that the regulatory right of first refusal is effective “regardless of the terms of any tariff,” Order No. 637-A at 31,646-47.

The Commission says this was old hat, pointing to its statement back in August 1992, in the Order No. 636 series, when it said that shippers were assured the right to continued service “even if the parties do not include an evergreen or rollover clause in their contract.” Order No. 636-A at 30,628. But the language makes no mention of tariffs, and thus appears not inconsistent with a view that tariff language, mandated by the Commission’s regulations, is necessary to effect the right, or at least that inconsistent tariff language trumps. More confusing is the Commission’s decision in Algonquin Gas Transmission Co., 94 FERC ¶ 61,383, 2001 WL 323207 (2001). There it first pointed to the language quoted above from Order No. 637, see 94 FERC at 62,439; then, when its attention was called to contradictions between the regulatory right of first refusal as it conceived it, and the pipelines’ tariff provisions (which had been approved as “just and reasonable”), it said that the solution was proceedings under § 5 of the NGA to consider forward-looking modification of the tariffs, see id. at 62,446. Were the regulatory right self-executing, we do not understand why § 5 proceedings woijld be needed. The Commission’s brief on the issue sheds no light.

Accordingly, though not vacating this aspect of Order No. 637 or Order No. 637-A, we remand to the Commission for it to explain its current position, and, to the extent that language in the orders under review is legally unsustainable, to modify it.

B. Narrowing of the right of first refusal

At the same time that the Commission expanded the degree of protection offered by right of first refusal by decreasing the maximum term that a protected shipper might be required to match, it also narrowed the right’s scope in certain respects. Specifically, Order No. 637 denied the right to all shippers operating under discounted rate contracts, i.e., contracts with rates below the maximum approved by FERC. It also excluded “negotiated rate” contracts, i.e., ones whose terms differ in some respect from simple application of FERC-approved tariffs, and whose rates may fall below, at, or above the FERC-approved maximum rate. (Both parties assume the existence of contracts with rates above the FERC ceiling, but neither explains how such a contract would even be lawful.) Order No. 637 at 31,337; Order No. 637-A at 31,631-35. The order grandfathered “[e]xisting” discounted contracts, so as to protect expectations based on the prior rule. Order No. 637 at 31,341-42.

In support of this modification the Commission offered two general grounds. First, it portrayed the amendment as driven by the right of first refusal’s “original purpose” to protect “long-term captive customers from the pipeline’s monopoly power.” Order No. 637 at 31,337. “If the customer is truly captive,” the Commission reasoned, “it is likely that its contract will be at the maximum rate.” Id. And shippers who have alternatives in the marketplace, as typically evidenced by their ability to negotiate discounts below the “just and reasonable” rate, do not need this type of regulatory protection.

Second, because the right of first refusal necessarily creates a disincentive for a shipper to enter into long-term contracts with the pipeline, and thus tends to saddle the pipeline with an unshared and uncompensated long-term investment risk, see id. at 31,336, the Commission also thought that limiting the right of first refusal to those shippers paying the maximum rates was needed to “better balance the risks between the shipper and the pipeline,” id. at 31,337.

Petitioners objecting to the change assert that it is not supported by substantial evidence in the record, because the agency relied virtually entirely on its own supposition that “truly captive” shippers are “likely” to be paying maximum rates. Furthermore, they say, the Commission rejected their examples to the contrary, which indicated that pipelines do sometimes offer discounted or negotiated rates to captive shippers.

The FERC order indeed cited no studies or data. But its conclusions seem largely true by definition. Rate ceilings are set at the Commission’s estimate of cost, thus roughly paralleling what would occur in a competitive market. The rates protect shippers whose choices are, by hypothesis, so limited that otherwise they would be ready to pay supra-competitive rates. If they are paying even less than the cost-based rates, it appears a fair inference that they have better choices than are supposed by the system of agency-controlled rates.

Or so one would think in the absence of specific, compelling rebuttal evidence. What petitioners offer can hardly be called compelling, given the Commission’s need to devise rules of general application. To be sure, their comments listed several situations in which, they claimed, pipelines might offer long-term shippers discounted rate contracts even where they had market power. For instance, a discount may be given “in consideration of entering into a settlement of a rate case or complaint proceeding,” or “for an agreement of the shipper to shift to a less desirable or underutilized receipt point,” or “to sign a longer contract, or to take an additional volume,” or when a shipper is captive only for a part of his total load, or “to assist [an] industrial customer during times of financial troubles in order to keep the facility viable,” or “in response to a perceived competitive threat from the proposed construction of a new pipeline.” Order No. 637-A at 31,633 & n.218. Most of these appear to be cases that any shipper aware of FERC’s rule can readily avoid; this should be all affected shippers, as the rule applies only to contracts entered after its adoption.

Petitioners in fact offer us no reasons to believe that their counter-examples are anything more than sporadic exceptions to the general rule on which FERC relied. Generalizations are not automatically rendered invalid by examples to the contrary' — the Commission is plainly entitled to respond with a general solution to general findings of a systematic condition or problem, rather than proceed with a case-by-case approach. AGD, 824 F.2d at 1008 (stating that when FERC acts under its rulemaking authority to promulgate generic rate criteria, it is not required to adduce “empirical data for every proposition on which the selection depends”); TAPS, 225 F.3d at 687-88 (approving FERC’s open access rules on the basis of “general findings of systemic monopoly conditions and the resulting potential for anti-competitive behavior, rather than evidence, of monopoly and undue discrimination on the part of individual utilities”). As petitioners have presented no data on how widespread the occurrence of discounting unrelated to market power is, they fail to undermine FERC’s conclusion that “generally [ ] discounts are given to obtain or retain load that the pipeline could not transport at the maximum rate because of competition.” Order No. 637-A at 31,633 (emphasis added). Further, nothing they say suggests that shippers on notice of the rule will be unable to avoid its consequences and enjoy the right of first refusal — so long as they are willing to pay the price.

As to FERC’s second argument, relating to the balancing of risk, petitioners say only that they can see no problem in a pipeline being required to provide continuing service at maximum rates. Br. of Petitioners Opposing Limitations on the Right of First Refusal at 11. But the Commission apparently was persuaded by pipeline commenters, who asserted that the prior regime “place[d] disproportionate risks on the pipelines because the pipeline must bear the risk of standing ready to serve the existing shipper indefinitely, while the shipper has no such obligation.” Order No. 637 at 31,336. This seems clear to us: We see how the Commission could find imbalance where one party, even though ready to commit itself to only a relatively short term (one year), thereby secures a perpetual right to service. FERC clearly believed that limiting the right of first refusal to maximum rate contracts was a fair means of apportioning the risk, so that those customers who place a premium on the assured continuity of service must now pay for that protection by foregoing discounts, to which, of course, they have no regulatory entitlement. Order No. 637-A at 31,634.

Petitioners finally object that a discounted or negotiated rate is determined at the outset of the contract and thus has no relationship to the market the long-term shipper faces at its end. This seems to be beside the point. The risk that market conditions would change always exists— the only issue is how it should be divided. Under the new rules, any long-term shipper who wants the benefits of a right of first refusal can secure them by simply choosing to take service under the standard just and reasonable rates set by FERC. The same goes for negotiated rates — all shippers are entitled to service under the generally applicable maximum tariffs, and pipelines cannot require captive customers to enter into negotiated rate agreements. Order No. 637-B at 61,-173. No captive shipper is thus deprived of regulatory protection — all of them have the entitlement to place themselves within the protected class by simply paying agency-approved, cost-based rates. As these are designed around existing levels of pipeline risk, they presumably include something approximating the necessary premium for the long-term rights these customers prefer. ■

VI. Discount Adjustments

Standard FERC ratemaking, in its most simple form, involves projecting a “revenue requirement” for service on the pipeline’s facilities and dividing the sum by projected “throughput.” The quotient is a maximum unit rate. Although both the revenue requirement and throughput are largely based on past experience, both figures are projections. Where it is expected that some service will be sold at a discount from the maximum rate, there is obviously a problem with assuming that throughput — itself enhanced by discounts — will, when multiplied by the maximum rate, yield the revenue requirement. FERC’s solution to the problem has been to make an offsetting downward adjustment in projected throughput. Interstate Natural Gas Pipeline Rate Design, et al., 47 FERC ¶ 61,295, 1989 WL 418574 (1989) ("Policy Statement”), Order on Rehearing, 48 FERC ¶ 61,122, 1989 WL 262568 (1989) (“Policy Statement Rehearing”). In the rulemaking, and citing expert testimony in other proceedings, various shipper interests headed by Illinois Municipal Gas Agency (“IMGA”) attacked this policy. In the end FERC elected to do nothing on the subject; though not rejecting the petitioners’ claims on the merits, it concluded that the issue was better left to another day. IMGA and associated petitioners attack this decision not to act.

Apart from the simple arithmetic described above, the theory underlying FERC’s discount adjustment is as follows: By selectively discounting its services (at least so long as charging prices above marginal cost), a pipeline could increase actual throughput by attracting additional, non-captive customers; as the fixed costs of service will be spread over more units, captive customers themselves will benefit in the end. See Policy Statement Rehearing at 61,449.

IMGA and kindred opponents of the policy see it in an entirely different light. They argue that the demand for pipeline service is largely inelastic in the aggregate; as a result the rate discounts do not produce an overall increase in throughput but merely shift it around among pipelines. This is most plausible in the case of “gas-on-gas” competition, which does not involve luring any end-users away from competing fuels such as oil. The upshot is that the competitive customers enjoy a decrease in rates and, the captives, instead of enjoying the supposed benefit, actually experience higher rates as the aggregate contribution of the competitive customers is reduced.

Over the last eight years, and despite the efforts of captive customers such as those represented by IMGA, FERC has declined to rule on the issue in any kind of a comprehensive manner. Some of its conduct is suggestive of a shell game. Thus, in resisting an IMGA petition for mandamus, see In re Illinois Municipal Gas Agency, No. 98-1347, 1998 WL 846667 (D.C.Cir. Nov.24, 1998), FERC pointed to the fact that in its then-ongoing rulemak-ing proceedings, which were to eventually culminate in the order before us, the Commission was specifically considering whether it should change the policy. See Notice of Inquiry, Regulation of Interstate Natural Gas Transportation Services, IV FERC Stats & Regs. [Notices] (CCH) ¶ 35,533 at 35,744 (July 29, 1998). But when the order finally emerged, it contained no ruling on the matter, except for yet another promise to consider the arguments sometime in the indefinite future. Order No. 637 at 31,267.

IMGA and others here petition on the ground that FERC’s continuation of the discount adjustment policy is unsupported by substantial evidence. But this frames the issue imprecisely. The policy originates in past decisions; FERC did not here decide to continue it, in the sense of confronting the substance and making an affirmative decision; it decided only that it would defer substantive treatment to a different — and necessarily later — context. In essence, then, the claim is of a violation of the APA’s mandate that an agency decide matters “within a reasonable time,” 5 U.S.C. § 555(b), and calls on us to “compel agency action unlawfully withheld or unreasonably delayed,” id. at § 706(1). Our review is highly deferential. See, e.g., In re Barr Laboratories, 930 F.2d 72, 74 (D.C.Cir.1991).

The case is anomalous among wrongful delay cases in that every ratemaking where the policy is applied presents an opportunity for challenge and lawsuit by a party aggrieved by its continuation — parties whose name is legion if petitioners are correct. In fact, since 1993, the discounting practice has been challenged on at least four separate occasions. See, e.g., Southern Natural Gas, 65 FERC ¶ 61,347 at 62,830, 1993 WL 594416 (1993); order on reh’g, 65 FERC ¶ 61,348 at 62,843, 1993 WL 524982 (1993); Regulation of Negotiated Transp. Svs. of Natural Gas Pipelines, 74 FERC ¶ 61,076, 1996 WL 694658 (1996), clarified, 74 FERC ¶ 61,194, 1996 WL 78596 (1996); Tennessee Gas Pipeline Co., 76 FERC ¶ 61,224, 1996 WL 495597 (1996), modified, 77 FERC ¶ 61,215, 1996 WL 682411 (1996), reh’g denied, 81 FERC ¶ 61,207, 1997 WL 711267 (1997); Panhandle Eastern Pipe Line Co., 78 FERC ¶ 61,011, 1997 WL 6382 (1997), reh’g denied, 81 FERC ¶ 61,234 at 61,973, 1997 WL 796060 (1997). In none of these cases, however, did aggrieved parties seek judicial review of the policy’s continued application.

An agency undoubtedly enjoys broad discretion to determine its own procedures, Mobil Oil Exploration & Producing Southeast, Inc., v. United Distrib. Cos., 498 U.S. 211, 230, 111 S.Ct. 615, 627, 112 L.Ed.2d 636 (1991), including whether to act by a generic rulemaking or by case-by-case adjudication, NLRB v. Bell Aerospace Co., 416 U.S. 267, 293, 94 S.Ct. 1757, 1771, 40 L.Ed.2d 134 (1974). But here FERC’s arguments in justification of deferring the issue make reliance on individual pipeline ratemaking inappropriate — except perhaps as a palliative. Indeed, the Commission itself stressed some points strongly suggesting the advantage of treating the issue in a generic rulemaking format.

First, the Commission pointed out, Order No. 637 itself comprised a policy statement inviting pipelines to institute differentiated peak/off-peak rates. Order No. 637 at 31,263, 31,264, 31,288. Not only would such differentiated rates tend to optimize the allocation of pipeline capacity, id. at 31,288, but they would “reduc[e] the need to make discount adjustments,” id. By its own terms, however, this point is only a partial answer. On this issue Order No. 637 is only a policy statement, see Part VII, infra, and does not immediately introduce any seasonally differentiated rates. And even the Commission sees seasonal differentiation only as “reducing,” not extinguishing, the practice of discounted rates.

Second, the Commission explicitly treated the discount adjustment problem as linked to a host of other issues, to be examined together,

including the use of negotiated terms and conditions of service, changes to SFV [straight fixed variable] rate design, whether to permit discount adjustments, whether to adopt rate reviews or refreshers, and whether to permit more market-based rates.

Id. at 31,267. Though obviously comprehensive policymaking is to be desired — it is one of the supposed benefits of delegations to such an agency as FERC — the Commission risks letting the best be the enemy of the good. If the consequences of the discount adjustment are as drastic as petitioners claim, involving a tilt of billions of dollars of costs, see IMGA Br. at 15, then endless deferral of substantive consideration is hard to justify. This is especially true where the customer class burdened by the tilt — the captives — is exactly the class that is the primary intended beneficiary of the regulatory system. See UDC, 88 F.3d at 1123.

On top of FERC’s own stress on the case for comprehensive treatment, there are other points against sloughing the issue off to individual ratemakings. Such proceedings could well lead to inequities as a result of competition between pipelines denied the adjustment and ones still able to practice it. Although FERC could conceivably adopt some mechanism to handle such effects (such as, for example, starting § 5 proceedings against pipelines competing with one denied the right to adjust), this appears at best awkward, leaving comprehensive treatment markedly superior.

In the end, however, we must deny the petition. The Commission’s reasons for treating the issue in a new rulemaking with closely related issues are sound, even though tarnished a bit by the extensive prior delay. And the availability of individual ratemakings as a venue, though markedly inferior, is nonetheless a kind of safety valve. As time drags on, however, Commission failure to address the issue on the merits will virtually set it up for a successful claim for undue delay under Telecommunications Research & Action Center v. FCC & United States, 750 F.2d 70 (D.C.Cir.1984).

VII. Peak/Off-Peak Rates

In Order No. 637 FERC announced that it would permit pipelines to charge seasonally variable rates for short-term transportation service instead of the previously required uniform tariffs based on the average cost of providing service. Order No. 637 at 31,287. Demand for natural gas is strongest in the winter heating season, and the Commission thought that allowing prices to better reflect the differing peak and off-peak values of capacity would promote allocative efficiency and reduce the need for discounts. Id. at 31,287-88; Order No. 637-A at 31,574. But it didn’t commit itself to any one formula for these variations, leaving it instead up to individual pipelines to propose methods, either in general § 4 rate cases or in limited, pro forma tariff filings. Order No. 637 at 31,290. Further, pipelines taking the latter route — where FERC’s inquiry will be limited in scope to the question of whether the proposed peak/off-peak methodology (as opposed to the rates themselves) is just and reasonable, Order No. 637-A at 31,578 — were requested to include in their proposals a mechanism for sharing any resulting extra revenues with their long-term customers on a basis of at least equality. Id. at 31,292. The Commission also directed such pipelines to file a cost and revenue study within fifteen months of implementing a peak/off-peak regime, so as to enable the Commission to determine if further rate adjustments are necessary. Id.

A group of petitioners headed by Exxon Mobil Corporation (collectively, “Exxon”) now fault both the authorization of limited § 4 proceedings and the revenue-crediting mechanism as failing to comply with the APA’s notice and comment requirements. In addition, Exxon contends that (a) limited § 4 proceedings fail to satisfy FERC’s obligation under the NGA to ensure that the actual pipeline rates (and not only the methodology used for deriving them) are just and reasonable; and (b) the exclusion of short-term shippers from the revenue-sharing arrangement is arbitrary and capricious. FERC contends that its entire discussion of seasonal rates here represents only a policy statement and therefore is neither binding on any party nor ripe for judicial review. We agree.

There is a “strong norm” against our reviewing “tentative agency positions,” American Gas Ass’n v. FERC, 888 F.2d 136, 151-52 (D.C.Cir.1989), of which, of course, a policy statement is a prime example. In the orders under review, FERC explicitly casts the discussion of the peak/off-peak rates option as a policy statement rather than as “a rule that imposes any requirements on pipelines or changes current Commission regulations.” Order No. 637 at 31,289; see also Order No. 637-A at 31,576. Exxon disputes this characterization, saying that insofar as Order No. 637 establishes specific procedures that pipelines must follow in implementing the rates, it is really a substantive rule. We think that the Commission has the better argument.

The distinction between substantive rule and policy statement is said to turn largely on whether the agency position is one of “present binding effect,” i.e., whether it “constrains the agency’s discretion.” McLouth Steel Products Corp. v. Thomas, 838 F.2d 1317, 1320 (D.C.Cir.1988); see also Community Nutrition Institute v. Young, 818 F.2d 943, 946 & n. 4 (D.C.Cir.1987). The agency’s characterization, and its actual past applications of its statement (if any), are the key factors. McLouth, 838 F.2d at 1320; Community Nutrition, 818 F.2d at 946.

Here the Commission has contemporaneously characterized the policy as not encompassing an intent to issue any substantive rules on limitations on § 4 proceedings or on revenue-sharing schemes. Cf. Molycorp, Inc. v. EPA, 197 F.3d 543, 546 (D.C.Cir.1999) (focusing on whether agency intends to bind itself). Such a characterization comes at a price to the Commission; in applying the policy, it will not be able simply to stand on its duty to follow its rules. Compare American Mining Congress v. Mine Safety & Health Admin., 995 F.2d 1106, 1111 (D.C.Cir.1993) (explaining that if the agency succeeds in labeling a rule interpretive and thus shielded from judicial review at the outset, the rule will remain open to full scrutiny when agency action implementing the rule is challenged), with Grid Radio v. FCC, 278 F.3d 1314, 1320 (D.C.Cir.2002) (stating that an agency “need not reevaluate well-worn policy arguments each time it implements an existing [formal] rule in a narrow adjudicatory proceeding”). And if there have so far been any applications of the Commission’s policy, neither side has seen fit to bring it to our attention. So there is no basis here for any claim that the Commission has actually treated the policy with the de facto inflexibility of a binding norm. Compare McLouth, 838 F.2d at 1321.

To be sure, Exxon correctly argues that the effect of a nominal “policy” disclaimer can still be negated under McLouth when an agency appears to undermine its professed flexibility by using imperative language — words such as “will” or “must.” Exxon Br. at 7 (citing McLouth, 838 F.2d at 1320-21). To this effect, Exxon contends that FERC’s decision to allow pro forma tariff filing and its requirement for pipelines to share excess revenues in a certain way (“the pipeline must include in its proposal a revenue sharing mechanism,” Order No. 637 at 31,292 (emphasis added)) do not meet the criteria for a policy statement. Id. But given the Commission’s broad discretion to direct the conduct of its proceedings, Vermont Yankee Nuclear Power Corp. v. Natural Resources Defense Council, Inc., 435 U.S. 519, 524-25, 543, 98 S.Ct. 1197, 1202-03, 55 L.Ed.2d 460 (1978), and its insistent characterization of the statement as mere policy, we reject the suggestion that these expressions establish a meaningful “right” for a pipeline to secure approval of variable rate proposals in limited § 4 proceedings. See also Order No. 637-A at 31,576 (emphasizing Commission discretion over the conduct of its proceedings). Likewise, insistence that pipelines submit particular types of revenue-sharing proposals doesn’t give anyone a “right” to additional revenues, id. at 31,575; the Commission, obviously, is entitled to request from the applicants any information it thinks may be helpful in deciding on their applications. We thus agree with the Commission that its discussion of pro forma filings and revenue-sharing proposals was meant to merely give “guidance and direction [to pipelines] on how peak/off-peak rates could be implemented in the individual cases.” Id. at 31,575.

Apart from the implications of classifying the statement as merely one of policy, general concepts militate against viewing petitioners’ claims as ripe. Following Toilet Goods Ass’n v. Gardner, 387 U.S. 158, 164, 87 S.Ct. 1520, 1524-25, 18 L.Ed.2d 697 (1967), we have often postponed review for want of ripeness where “(1) delay would permit better review of the issues while (2) causing no significant hardship to the parties.” Northern Indiana Public Service Co. v. FERC, 954 F.2d 736, 738 (D.C.Cir.1992). Both of these criteria favor postponing review.

Because the Commission adopted no particular method of setting peak/off-peak rates but “left the details of the implementation” to be worked out in individual pipeline proceedings, Order No. 637-A at 31,574, we have no record on which to evaluate the nature — or indeed the existence — of Exxon’s conceivable injury. See Tennessee Gas Pipeline Co. v. FERC, 972 F.2d 376, 382 (D.C.Cir.1992) (“Whether any ... pipeline serving the petitioner will actually file the tariffs necessary to participate in this program, or assuming one does, the nature of any injury that the petitioner may in fact suffer, remains to be seen.”); cf. American Gas Ass’n, 888 F.2d at 152.

Nor does Exxon even try to show how continued uncertainty over the legality of the Commission’s policy would harm it or affect its day-to-day primary activities. Unless and until a particular pipeline chooses to implement peak/off-peak rates, and gets Commission approval, Exxon faces no actual or imminent injury. With this in mind, Exxon’s reliance on ANR Pipeline Co. v. FERC, 771 F.2d 507 (D.C.Cir.1985), Exxon Repl. Br. at 4-5, is misplaced. Quite apart from the fact that the court addressed only a concern about standing, it was certain that the carrier would file the rate increase that was implied by the contested order’s methodological change. ANR, 771 F.2d at 516. And whereas in ANR the court thought that the petitioner will “likely be bound by the Commission’s order in any subsequent filing,” id., here FERC’s disclaimer of a “substantive rule” status of the challenged provisions means that neither the agency nor Exxon will be bound by them in any future proceedings. This court will remain free to re-examine FERC’s policies “in another context if and when [Exxon’s] claims become justiciable.” Shell Oil Co. v. FERC, 47 F.3d 1186, 1202 n. 32 (D.C.Cir.1995).

Accordingly, Exxon’s claims are unripe and its petition is dismissed.

VIII. Limitations on Pre-Arranged Releases

Under the capacity-release regime initiated by Order No. 636, see Section I, supra, firm customers releasing short-term capacity were generally required to auction it off to the highest bidder by posting the terms and conditions of such releases on pipeline electronic bulletin boards. Order No. 636 at 30,418-21; see generally 18 C.F.R. § 284.8(c)-(e) (describing posting and bidding requirements). FERC permitted an exemption for so-called pre-arranged deals, however, allowing firm transportation customers to release capacity rights to a specific, preselected short-term shipper of their choice without prior posting and bidding, so long as the release was made at the maximum applicable tariff rate. 18 C.F.R. § 284.8(h). Given a pre-arranged sale at the ceiling rate, bidding and posting would have been largely an exercise in futility.

But with the elimination of the price ceiling for short-term capacity releases in Order No. 637, the general case for such an exemption was undermined. Order No. 637-A at 31,568-69. The Commission believed that once a market price was permissible and the ceiling rates moot, posting and bidding was as necessary for maximum-price releases as for any others: to “protect against undue discrimination and to ensure that capacity is properly allocated” to the shipper for which it was most valuable. Id. at 31,569.

Although abolishing the exemption, FERC provided a waiver procedure, primarily in the interest of a special class of capacity releasers. The former exemption for releases at the ceiling rate had been heavily relied upon by local distribution companies (“LDCs”) in states that sought to carry the unbundling process all the way down to the retail level. The idea of such programs has been to enable residential and small commercial customers, who had been traditionally served by LDCs making gas sales bundled with transportation, instead to secure gas through new competitive marketers, typically relying on the LDCs for transportation. Order No. 637 at 31,250, 31,261. To this end, these states have encouraged or required their LDCs to pre-arrange releases of portions of their firm transportation rights to the independent marketers at the pipeline’s maximum rates. See Request of Keyspan Gas East Corp. and the Brooklyn Union Gas Co. for Rehearing and/or Clarification at 25; Order No. 637 at 31,261.

So that such transactions might persist, the Commission provided that LDCs might seek Commission consent for making releases at the maximum rate that would have been applicable absent FERC’s present experimental policy. But to avail itself of such a waiver procedure, FERC said, the applicant “must be prepared to have all of its capacity release transactions ... limited to the applicable maximum rate.” Id. at 31,569 (emphasis added).

The petitioners here appear to seek a blanket exemption from bidding and posting for “maximum-price” releases prearranged under “state choice” plans. Their basic argument is that the ultimate end-users under such transactions are the same core, captive users for whom the LDC originally acquired the capacity under a long-term contract. They do not believe that states should be put to a choice of foregoing the benefits of retail unbundling, or, alternatively, of exposing such core end-users to the risk of having to pay a transportation rate higher than the prior legal maximum, presumably the one provided under the contract originally entered into for their benefit. Short of a blanket exemption, they seek a broadening of FERC’s conditions for waiver.

We cannot find the refusal of a blanket exemption arbitrary or capricious. At most petitioners have shown that the absence of such an exemption may undermine some state regulatory efforts. At the time Order No. 637 was adopted, 11 states evidently had unbundling programs, with another nine and the District of Columbia experimenting with pilot programs. Order No. 637 at 31,261. Absent a showing that these programs are so structured as largely to moot FERC’s concern with potential discrimination, or that the achievements of these programs are enough to offset whatever such risk may remain, FERC’s caution appears reasonable.

But we agree with petitioners that FERC has failed to support its rule conditioning any waiver on the applicant’s being “prepared to have all of its capacity release transactions ... limited to the applicable maximum rate.” Order No. 637-A at 31,569 (emphasis added). FERC imposed the condition to be sure that an LDC exempted from the posting and bidding rules could not “protect[] other favored shippers from the bidding process.” Id. But the Commission’s brief writers recognize that the Commission failed to make a case for insistence that the LDC commit to making all releases at the maximum rate. The Commission’s requirements of state regulatory endorsement of the plan seems to give FERC an avenue by which to verify that those authorities have addressed the discrimination risk, so much so that in its brief here, FERC, rather than truly defending its insistence on the releasing LDC’s commitment to do “all” releases at the maximum rate, instead argues that the language “ ‘must be prepared to accept’ ... differs greatly from mandatory language such as, ‘must accept.’ ” FERC Br. at 75. Accordingly, we reverse and remand for the Commission to review the matter and reframe the waiver conditions in terms that more aptly capture an intent apparently less Procrustean than what it expressed.

The petitions for review are denied except as noted above.

So ordered.