
    201 F.3d 497
    WASHINGTON WATER POWER COMPANY, et al., Petitioners v. FEDERAL ENERGY REGULATORY COMMISSION, Respondent Great Lakes Gas Transmission Limited Partnership, et al., Intervenors
    No. 98-1245, 98-1249, 98-1251 and 98-1274.
    United States Court of Appeals, District of Columbia Circuit.
    Argued Nov. 23, 1999.
    Decided Feb. 1, 2000.
    
      Joshua L. Menter argued the cause for petitioners Sierra Pacific Power Company, et al. With him on the briefs were John P. Gregg and Charming D. Strother, Jr.
    Thomas W. Wilcox argued the cause and was on the briefs for petitioner Washington Water Power Company.
    MaryJane Reynolds argued the cause and filed the briefs for petitioners Apache Corporation and DEK Energy Corporation.
    Timm L. Abendroth, Attorney, Federal Energy Regulatory Commission, argued the cause for respondent. With him on the brief were Jay L. Witkin, Solicitor, and John Conway, Deputy Solicitor.
    Elias G. Farrah argued the cause for intervenors. With him on the brief were Joseph H. Fagan, Paula E. Pyron and Harvey Y. Morris.
    Bruce W. Neely, Michael C. Dotten, James C. Moffatt, Theresa I. Zolet, John R. Staffier, David W. Anderson, Patrick G. Golden, David L. Huard, G. William Stafford, James D. McKinney, Jr., John J. Wallbillich, James H. Holt, Sandra E. Rizzo, James F. Walsh, III, Nicholas W. Fels, Lee A. Alexander, Stefan M. Krantz, Rebecca A. Blackmer and Peter G. Esposito entered appearances.
    Before: SILBERMAN, GINSBURG and TATEL, Circuit Judges.
   Opinion for the Court filed by Circuit Judge TATEL.

TATEL, Circuit Judge:

These consolidated petitions seek review of the Federal Energy Regulatory Commission’s approval of a settlement resolving a rate case filed by a natural gas pipeline serving parts of Oregon, Washington, and California. Finding petitioners’ various challenges without merit, we deny the petitions.

I

Intervenor PG&E Gas Transmission-Northwest Corporation (“the pipeline”) has owned a natural gas pipeline running from near British Columbia down through Oregon since the 1960s. For many years, its parent company, Pacific Gas & Electric (“PG&E”), was the main shipper on the line. In 1980, and again in 1991, FERC granted certificates to expand the pipeline’s capacity. The 1991 expansion, which increased the pipeline’s mainline capacity by approximately 75 percent, went into service in 1,993.

Historically, the pipeline used a rate system in which shippers who entered into contracts for capacity after expansion (“expansion shippers”) bore the entire cost of the expansion; shippers who held capacity on the pipeline prior to expansion (“original shippers”) paid only for the costs associated with the original pipeline, including any unrecovered costs of-building the original pipeline, depreciation, and associated tariffs. According to FERC, this so-called “incremental” or “vintaged” rate structure is justified because it allows original shippers to “fully benefit from their earlier long-term agreements with the pipeline .... [Sjhippers pay[ ] higher rates in the early years which are offset by lower rates in the later years.” Great Lakes Transmission Ltd. Partnership, 62 FERC ¶ 61,101 at 61,718 (1993).

Not surprisingly, the expansion shippers preferred a different rate structure: a “rolled-in” rate system in which the costs of the expansion and any unrecovered costs associated with the original pipeline are rolled together and divided equally so that all shippers pay the same rate regardless of when they obtain their capacity. In late 1992 and early 1993, when the pipeline filed its tariff sheets addressing other rate issues, some of the expansion shippers filed comments arguing that the pipeline should adopt a rolled-in rate structure. FERC, agreeing with the pipeline that the incremental rate structure should be temporarily maintained, deferred resolution of the issue raised by the expansion shippers until the pipeline’s next general rate filing. Less than fourteen months later, the pipeline submitted a rate filing pursuant to section 4 of the Natural Gas Act, 15 U.S.C. § 717c, in which it proposed the rolled-in rate structure the expansion shippers had requested. When PG&E, the primary original shipper, and its customer, Intervenor the California Public Utilities Commission (“CPUC”), opposed the proposed rolled-in rate structure, the issue was set for litigation before FERC.

As the “rolled-in” versus “incremental” rate debate raged, PG&E permanently transferred or “released” part of its excess capacity to other shippers pursuant to 18 C.F.R. § 284.243. Section 284.243 provides the mechanism by which a shipper that has contracted for capacity it no longer needs (the “releasing shipper”) can reallocate that capacity to another shipper (the “replacement shipper”): “The pipeline must allocate released capacity to the person offering the highest rate (not over the maximum rate) and offering to meet any other terms and conditions of the release.” 18 C.F.R. § 284.243(e). Although “maximum rate” is not defined in the text of the regulation, Order No. 636, the preamble to section 284.243, explains that “[t]he regulations require the pipeline to allocate released capacity to the person offering the highest rate not over the maximum tariff rate the pipeline can charge to the releasing shipper.” Pipeline Service Obligations and Revisions to Regulations Governing Self-Implementing Transportation Under Part 28k of the Commission’s Regulations, and Regulation of Natural Gas Pipelines After Partial Wellhead Decontrol, 57 Fed.Reg. 13267, 13285 (1992) (emphasis added). Under the capacity release regulation, replacement shippers in this case obtained capacity at the rate that PG&E had been paying. As a result, replacement shippers on the incrementally priced pipeline paid significantly lower rates than expansion shippers even though those replacement shippers had obtained their capacity at a later date. This result conformed to FERC’s then-existing policy as set forth in Great Lakes Transmission Ltd. Partnership, 64 FERC ¶ 61,017 at 61,155, 61,157 (1993) (“Great Lakes I”). In that case, the Commission, rejecting complaints from expansion shippers that it was unfair to allow replacement shippers to pay less, held that the maximum rate for released capacity was “the applicable maximum tariff rate for the service being released” and that “[t]he expansion shippers are assessed an incremental rate because their service request caused facilities to be constructed for their benefit.” Id.

In 1996, the parties to the still-pending rate proceeding reached a settlement agreement under which the pipeline would phase in a rolled-in rate system. During the first (and uncontested) phase lasting until November 1, 1996, the existing incremental rate structure was maintained. During the second period, running from the later of November 1, 1996 or the date the Commission approves the settlement until the pipeline’s next rate filing, expansion costs are rolled in so that all shippers end up paying the same base rate — 26.28 cents per Decatherm (“cents/Dth”). Because that base rate represents a steep increase for PG&E and other original shippers who had not previously been paying for the pipeline’s expansion, the settlement provides for mitigation during the interim period: until November 1, 2002, PG&E pays only 75 percent of the base rate, or 19.91 cents/Dth. The settlement also provides for mitigation of replacement shippers’ rates, although less so: they pay approximately 92 percent of the base rate, or 24.28 cents/Dth. Expansion shippers pay the base rate plus a 6.5 cent surcharge to offset the rate mitigation provided to PG&E and replacement shippers, or a total of 32.74 cents/Dth. The settlement gives PG&E several other benefits, including rebates on certain surcharges that it had paid and an entitlement to obtain refunds when it permanently or temporarily releases capacity.

Most of the parties, including PG&E, CPUC and most expansion shippers, either supported the settlement or did not oppose it. Over the objections of several replacement shippers and petitioner Washington Water Power, FERC approved the settlement. Pacific Gas Transmission Co., 76 FERC ¶ 61,246 (1996). Replacement shippers filed a petition for rehearing, arguing that under FERC’s existing case law, primarily Great Lakes I, 64 FERC ¶ 61,017 (1993), they could not be charged rates higher than PG&E, the shipper from whom they obtained their capacity. Denying the petition for rehearing, the Commission not only overruled the part of Great Lakes I on which petitioners had relied, but also articulated a new policy: replacement shippers obtaining released capacity post-expansion on an incrementally priced system are similarly situated to expansion shippers, not to releasing shippers. PG&E Gas Transmission, Northwest Corp., 82 FERC 1161,289 at 62,123 (1998). Applying that new policy, the Commission rejected replacement shippers’ challenges.

II

Several replacement shippers — petitioners Sierra Pacific Power Co., Sierra Pacific Resources, and Engage Energy US, L.P. (“replacement shipper petitioners”) — argue that FERC’s new policy is inconsistent with its price cap regulation, 18 C.F.R. § 284.243, as interpreted in Order No. 636. They also argue that application of the new policy to them is impermissibly retroactive and contrary to FERC precedent. FERC argues that replacement shipper petitioners cannot challenge the reasoning in the order denying rehearing because they failed to seek further rehearing of that order. FERC ignores our holding in Southern Natural Gas Co. v. FERC, 877 F.2d 1066, 1073 (D.C.Cir.1989). “[W]hen FERC makes no change in the result, but merely supplies a new improved rationale upon realizing that its first one won’t wash, it does not thereby transform its order denying rehearing into a new ‘order’ requiring a new petition for rehearing before a party may obtain judicial review. Otherwise, we would ‘permit an endless cycle of applications for rehearing and denials,’ limited only by FERC’s ability to think up new rationales.” Id. Here, too, although the order denying rehearing abandoned the reasoning of the earlier order approving the settlement, FERC reached precisely the same result. Replacement shipper petitioners therefore had no obligation to seek further rehearing.

On the merits, these petitioners fare less well. They challenge neither the logic behind FERC’s ruling that they are similarly situated to expansion shippers— the prior policy was unfair to expansion shippers — nor the Commission’s authority to overrule Great Lakes I. Instead, they complain that insofar as the new policy may require replacement shippers to pay more than releasing shippers, that policy conflicts with Order No. 636, the preamble to section 284.243 of the Commission’s regulations.

Replacement shipper petitioners read Order No. 636, which states that “the pipeline [must] allocate released capacity to the person offering the highest rate not over the maximum tariff rate the pipeline can charge to the releasing shipper” to require that they pay the same rate as PG&E. 57 Fed.Reg. at 13285 (emphasis added). According to the Commission, a subsequent order, Order No. 636-A, made clear that the sentence from Order No. 636 on which petitioners rely does not apply to incrementally priced systems. Because FERC’s position represents an interpretation of its own regulations, we give it “controlling weight unless it is plainly erroneous or inconsistent with the regulation.” Exxon Corp. v. FERC, 114 F.3d 1252, 1258 (D.C.Cir.1997) (internal quotation marks omitted). Petitioner's have not come close to meeting this heavy burden.

The Commission’s position rests on the following sequence of events. After FERC issued Order No. 636, several petitions for rehearing “raise[d] questions about the maximum rate for released capacity.” Order No. 636-A, 57 Fed.Reg. 36,128, 36,149 (1992). Those petitions observed that shippers holding expansion capacity on a pipeline with an incremental rate system would have a difficult time releasing that capacity because the maximum rate for capacity released by shippers on pipelines with rolled-in rates would be significantly lower. Id. at 36,150. Petitioners suggested several ways to address this problem, including giving priority to incremental releases or establishing a floor for prices at the incremental rate.

Responding to these comments in Order No. 636-A, FERC' refused to “make a generic determination on the various methodologies proposed [in the comments] since resolution of such issues may depend on the characteristics of the pipeline and the services it offers. The parties in restructuring proceedings involving incremental rates should consider and propose methodologies to ensure that the capacity release mechanism operates efficiently and that all parties are treated fairly and equitably, without undue discrimination.” Id. at 36,150. Order No. 636-A thus “left open the issue of how to price capacity releases in the context of a system with incremental rates.” PG&E Gas Transmission, Northwest Corp., 82 FERC ¶ 61,289 at 62,129. Put another way, Order No. 636-A made clear that Order No. 636’s definition of “maximum rate” does not apply to incrementally priced rate structures. Petitioners have given us no basis for concluding that the Commission’s interpretation of Orders Nos. 636 and 636-A is either “plainly erroneous” or inconsistent with section 284.243.

Equally without merit is replacement shipper petitioners’ argument that by adopting the new policy, the Commission impermissibly departed from prior cases in which it refused to remove or raise the section 284.243 rate cap in individual proceedings. See, e.g., Tennessee Gas Pipeline Co., 70 FERC ¶ 61,076, 61,200 (1995). As the Commission observed, it did not remove or raise the rate cap in this case; instead, it defined the term “maximum rate” in the context of an incrementally priced vintaged system as the maximum rate under the tariff sheets that the expansion shippers could be charged. PG&E Gas Transmission, Northwest Corp., 82 FERC ¶ 61,289 at 62,131. To be sure, the Commission held in Great Lakes I that the maximum rate was the releasing shipper’s maximum tariff rate, but the Commission has now overruled that part of Great Lakes I. See id. Because replacement shippers have not argued that the Commission could change the Great Lakes I policy only through notice and comment rulemaking rather than through adjudication, we have no reason to address that issue.

Petitioners’ remaining arguments with respect to the new policy relate to whether the Commission could apply it to their existing contracts. Having entered into contracts for released capacity prior to the settlement of this case, replacement shipper petitioners argue that applying the new policy to them now is impermissibly retroactive. Because petitioners have failed to establish that they relied on the Commission’s prior policy to their detriment — in other words, that they would not have entered into these contracts had they known that the Commission would change its policy — they cannot prevail on this argument. See Public Service Co. of Colorado v. FERC, 91 F.3d 1478, 1490 (D.C.Cir.1996) (in determining that it was permissible for Commission to apply new interpretation of law, “the apparent lack of detrimental reliance ... is the crucial point”). In February 1994, when petitioner Engage Energy, the first replacement shipper petitioner to contract for PG&E’s released capacity, executed its contract, FERC had already announced that the incremental versus rolled-in rate issue would be addressed when the pipeline submitted its next rate filing in late 1994 or early 1995. All replacement shipper petitioners therefore should have been fully aware of the possibility that the pipeline would adopt rolled-in rates. In fact, by the time petitioner Sierra Pacific executed its contracts in February and June 1995, the pipeline had already proposed rolled-in rates. Moreover, the mitigation replacement shippers receive during the interim period produces a lower rate than those shippers would have paid under a fully rolled-in rate system. Because they are paying rates lower than the rates to which they should have known they were exposed, they cannot show detrimental rebanee. The only plausible detrimental rebanee argument that these petitioners could have made is that by paying rates higher than PG&E, they suffered some sort of competitive injury vis-d-vis PG&E that they had not anticipated. But none of these petitioners abeges competitive injury; the only replacement shipper to have done so did not petition for review. By way of a record reference to a portion of a brief filed with FERC, petitioners suggest that they relied on PG&E to oppose vigorously and litigate the robed-in rate issue. Absent a more direct mention of this at best attenuated reliance interest, however, we see no need to address it. See Washington Legal Clinic for the Homeless v. Barry, 107 F.3d 32, 39 (D.C.Cir.1997) (refusing to reach issue where party offered only “bare-bones arguments”).

Replacement shipper petitioners fare no better with their argument that by applying the new policy to them, FERC departed from Great Lakes Transmission Ltd. Partnership, 72 FERC ¶ 61,081 at 61,427 (1995) (“Great Lakes IP7), petitions for review denied in part and granted in part, Southeastern Michigan Gas Co. v. FERC, 133 F.3d 34 (D.C.Cir.1998), where the Commission refused to apply a new policy retroactively. In denying rehearing in this case, FERC took great pains to distinguish Great Lakes II: The policy that the Commission changed in Great Lakes II had been “consistently applied” for thirty years, whereas the Commission’s new policy here overruled only one case, Great Lakes I, decided just five years prior to the decision in this case. 82 FERC ¶ 61,289 at 62,127. We agree with the Commission that these differences distinguish Great Lakes II from the situation presented in this case.

Replacement shipper petitioners next argue that even if replacement shippers as a general rule are similarly situated to expansion shippers, they are not so similarly situated in the circumstances of this case. This is because they contend, as replacement shippers they paid mihions of dollars in tariffs when the incremental rate system was in place — tariffs for which expansion shippers were not responsible. As intervenors point out, however, the rate paid by these replacement shippers under the incremental rate system, even including the additional tariffs, was stih significantly lower than the rate paid by expansion shippers. Since replacement shippers are similarly situated to expansion shippers for purposes of determining rates and since it is undisputed that they paid less than expansion shippers for the period in question, petitioners have no cause to complain now about the tariffs.

Replacement shipper petitioners also contend that the settlement is unduly discriminatory because PG&E enjoys a greater degree of mitigation and a number of other “special benefits.” In order to prevail on an undue discrimination claim, petitioners must demonstrate not only differential rates between two classes of customers but also “that the two classes of customers are similarly situated for purposes of the rate.” “Complex” Consolidated Edison Co. of New York v. FERC, 165 F.3d 992, 1012 (D.C.Cir.1999). Because replacement shipper petitioners are similarly situated to expansion shippers rather than to PG&E, and because their rates are lower than the rates of expansion shippers, the undue discrimination argument fails.

Finally, replacement shipper petitioners challenge a provision of the settlement agreement under which the pipeline will refund a certain percentage of the tariffs paid by PG&E in exchange for an agreement by CPUC, PG&E’s primary customer, to withdraw two appeals it had filed in this court challenging the Commission’s determination that the pipeline could recover certain transition costs. Petitioners maintain first that this provision is unfair because PG&E paid only a portion of the tariffs but receives all of the refund, and second that the Commission ignored Southern California Edison Co., 49 FPC 717, 721 (1973), a decision of the Commission’s predecessor refusing to approve a settlement that included a provision settling an ancillary appeal pending before this court. As the Commission pointed out in denying rehearing in this case, however, giving PG&E the benefit of the refund is consistent with its policy of facilitating settlements to resolve the difficult issues raised by transition cost disputes. See 82 FERC ¶ 61,289 at 62,142. Moreover, unlike in Southern California Edison Co., even with the refund provided under the settlement, PG&E still pays “a significantly higher proportionate amount” of the transition cost tariffs than any other shipper. See 82 FERC ¶ 61,289 at 62,143.

Ill

The remaining two petitions require only brief discussion. Claiming that a new volume-based charge included in the settlement will increase its rate by 16 percent and that FERC has a general policy of requiring mitigation where a shipper’s rate increases by more than 10 percent, petitioner Washington Water Power Co. maintains that FERC should not have approved the settlement without requiring additional mitigation. FERC responds that it has no such “general” rate shock policy. Denying rehearing, FERC explained that its rate shock policy applies only when the rate shock results either from a straight fixed-variable rate design or from a transition from incremental to rolled-in rates. 82 FERC ¶ 61,289 at 62,-144. Washington Water’s increased rate results from neither. Instead, the rate increase results from a new non-mileage based charge. Having cited no authority either supporting its assertion that the Commission has required mitigation in such a situation or leading us to question the Commission’s explanation that it has no general rate shock policy outside of the two situations mentioned above, Washington Water’s argument fails.

Petitioners DEK Energy Corp. and Apache Corp. (collectively “DEK”), expansion shippers who failed timely to file their comments on the settlement, now contest the settlement’s mitigation provisions. DEK participated neither in the litigation of the pipeline’s section 4 rate filing nor in the settlement negotiations. After submission of the settlement, DEK filed comments stating that it had no opposition to the rolled-in rate structure. It registered no opposition to the settlement’s mitigation provisions. Then, over two months alter the final deadline for filing comments on the settlement, DEK filed a “clarification,” asserting for the first time that the mitigation provided to PG&E and the replacement shippers under the settlement was unjust and unfair. Several parties opposed DEK’s “clarification” on timeliness grounds, and the Commission said nothing about DEK’s comments in its September 1996 order approving the settlement. Denying DEK’s petition for rehearing, the Commission found that DEK’s comments were untimely. 82 FERC ¶ 61,-289 at 62,138. Although the Commission also addressed the “factual inaccuracy underlying DEK’s position,” PG&E Gas Transmission, Northwest Corp., 83 FERC ¶ 61,251 at 62,066 (1998), it noted that

[aiddressing DEK’s opposition now, in light of extended settlement conferences and resolution of the case in a manner acceptable to all others similarly situated to DEK, would unfairly disrupt and detract from the compromises of parties that did participate. This is especially true considering that DEK’s initial comments were silent on the issues raised in its “clarification” and request for rehearing. Consideration of the late opposition would be similar to allowing an eleventh hour intervention by a person that had chosen not to comment at all, and would lend uncertainty to the settlement negotiation process which thrives, in part, on the timely filing of positions.

82 FERC ¶ 61,289 at 62,138. Agreeing with the Commission’s sound reasons for finding DEK’s opposition to the settlement untimely, we find it unnecessary to reach DEK’s arguments that the Commission erred in its assessment of the factual inaccuracies inherent in DEK’s position.

IV

The petitions for review are denied.

So ordered.  