Full opinion text
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. 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: 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 tradabl