
    In re: CALIFORNIA POWER EXCHANGE CORPORATION California Power Exchange Corporation, Petitioner, Pacific Gas and Electric Company; Western Power Trading Forum; New York Mercantile Exchange; Automated Power Exchange, Inc.; Southern Energy California, LLC; Southern Energy Potrero, LLC; Southern Energy Delta, LLC; San Diego Gas and Electric Company; Industrial Customers of Northwest Utilities, Intervenors, v. Federal Energy Regulatory Commission, Respondent. City of San Diego, Petitioner, Southern Energy California, LLC; Southern Energy Potrero, LLC; Modesto Irrigation District (MID); City of Redding, California; City of Santa Clara, California; Southern Energy Delta, LLC; County of San Diego, Intervenors, v. Federal Energy Regulatory Commission, Respondent.
    Nos. 00-71701, 01-70031.
    United States Court of Appeals, Ninth Circuit.
    Argued Feb. 7, 2001.
    Submitted March 27, 2001.
    Filed April 11, 2001.
    
      Carmen L. Gentile (argued) and James H. McGrew, Bruder, Gentile & Marcoux, LLP, for Petitioner California Power Exchange Corporation. Randolph Lee Elliott, Miller, Balis & O’Neil, P.C., Washington, D.C., for Petitioner City of San Diego.
    
      Dennis Lane (argued), Federal Energy Regulatory Commission, Washington, D.C., for Respondent.
    Before: O’SCANNLAIN, KLEINFELD and TALLMAN, Circuit Judges.
    
      
      The panel unanimously finds No. 00-71701 suitable for decision without oral argument. See Fed. R.App. P. 34(a)(2).
    
   O’SCANNLAIN, Circuit Judge.

We must decide whether a California municipality and a California public utility which operates an auction for trading electricity are entitled to extraordinary relief from nonfinal orders of the Federal Energy Regulatory Commission addressing the crisis surrounding California’s restructuring of its electricity market.

I

A

In 1996, the California legislature embarked upon a major restructuring of the California power industry with the passage of Assembly Bill 1890 (“AB 1890” or “Electricity Restructuring Act”). Act of September 23, 1996, 1996 Cal. Legis. Serv. 854 (A.B.1890) (West). Several features of this complex legislation and the decisions of the California Public Utilities Commission (“CPUC”) implementing the restructuring are relevant to the petitions before us.

First, AB 1890 provided for the creation of the California Power Exchange (“CalPX”), a nonprofit entity that would provide an auction market for the trading of electricity. Electricity Restructuring Act § 1(c). CalPX commenced operations in March 1998. Initially, it operated only a single-price auction for day-ahead and day-of electricity trading (the “CalPX spot markets” or the “CalPX Core markets”). CalPX would determine, on an hourly basis, a single market clearing price which all electricity suppliers would be paid based on short term demand and supply bids submitted by CalPX participants. In the summer of 1999, CalPX opened its CalPX Trading Services (“CTS”) division to operate a block forward market by matching supply and demand bids for long term electricity contracts (“CTS forwards market”). The CalPX is deemed a public utility under the Federal Power Act (“FPA”); hence, it is subject to the jurisdiction of the Federal Energy Regulatory Commission (“FERC”) and operates pursuant to a FERC-approved tariff and FERC wholesale rate schedules. Pacific Gas & Electric Co., 77 FERC ¶ 61,204, at 61,803-05, 1996 WL 680336 (November 26, 1996), reh’g denied, 81 FERC ¶ 61,122, 1997 WL 805937 (1997).

California’s restructuring plan called for the electricity generation assets of the state’s three main investor-owned utilities (“IOUs”), San Diego Gas and Electric Company (“SDG & E”), Southern California Edison (“SCE”), and Pacific Gas and Electric Company (“PG & E”), to undergo a process of market valuation, which resulted in the IOUs’ divestiture of a substantial portion of their electricity generation facilities. Order Instituting Rulemaking on Commission’s Proposed Policies Governing Restructuring California’s Electric Service Industry and Reforming Regulation (Cal. Pub. Util. Comm’n Decision 95-12-068), 1995 WL 792086, at *49 et seq., 64 CPUC 2d 1 (Dec 20, 1995). In turn, for a transition period, the IOUs were required to sell all of their remaining generation capacity into, and to purchase all of their required electricity supply from, the CalPX spot markets, and such purchases were deemed to be “prudent per se” by the CPUC. Id., 1995 WL 792086, at *26-*27; Pacific Gas & Elec. Co., 77 FERC ¶ 61,204, at 61,804; San Diego Gas & Elec. Co., 93 FERC ¶ 61,294, at 62,000-01, 2000 WL 1840337 (Dec. 15, 2000), reh’g pending (the “December 15 Order”). (We henceforth refer to this obligation as the “buy/sell requirement.”)

In 1999, the CPUC permitted the IOUs to purchase a limited percentage of their combined load in the CTS forward contract market; the balance of their load was to be purchased in the CalPX spot market. But CalPX was to continue to operate as the exclusive market for the IOUs’ electricity needs and its spot markets would continue to provide the benchmark for the CPUC’s prudence review. See Act of July 10, 2000, 2000 Cal. Legis. Serv. 127 (A.B. 2866) (West), codified at Cal. Pub. Util. Code § 355.1, repealed by Act of February 1, 2001, 2001 Cal. Legis. Serv. 1st Ex. Sess. 4 (A.B.1) (West); Opinion Regarding Bilateral Contracts (Cal. Pub. Util. Comm’n Decision 00-09-075), 2000 WL 1914013, at *3-*4 (Sept. 21, 2000).

AB 1890 also called for the creation of the California Independent System Operator (“Cal-ISO”), a nonprofit entity charged with managing the state’s electricity transmission grid. Electricity Restructuring Act § 1(c). As manager of the grid, the Cal-ISO also operates a real time imbalance energy market to ensure that electricity supply meets demand at the time of delivery.

Finally, AB 1890 provided that the deregulation of the California power industry would proceed in several phases. The deregulation of the wholesale market — or, more properly, the partial deregulation of the wholesale market, considering that the IOUs’ wholesale purchases were constrained by the buy/sell requirement, the CPUC’s limitations on forward contracting, and the CalPX monopoly — was the first phase of the scheme. Deregulation of the retail market was to come later. AB 1890 provided for a ten percent retail rate reduction for certain customers and a retail rate cap through 2002, or until the IOUs recovered their stranded costs, whichever came first. Electricity Restructuring Act § 1(b)(2), (e).

B

The summer of 2000 witnessed significant increases in the wholesale price of electricity. Prices in the CalPX spot markets spiked particularly sharply. San Diego Gas & Electric Co., 93 FERC ¶ 61,121, at 61,353, 2000 WL 1637060 (Nov. 1, 2000) (the “November 1 Order”). Retail rates for SDG & E customers rose 200 to 300 percent, while PG & E and SCE, which were still subject to the AB 1890 rate freeze, incurred billions of dollars of debt because they were unable to pass their wholesale power costs onto their customers. See id. In addition, the Cal-ISO declared 39 system emergencies during the course of the summer. See id.

A series of FERC proceedings followed, culminating in several orders directly relevant to the petitions before us. In its November 1 Order, FERC specifically found that, under certain conditions, short-term wholesale power rates in the California market were “unjust and unreasonable” within the meaning of § 206(a) of the FPA, 16 U.S.C. § 824e(a). 93 FERC ¶ 61,121, at 61,349, 61,366, 61,370. While observing that certain external factors, such as an increase in natural gas costs and a general electricity supply shortage, contributed to the summer 2000 wholesale electricity price spikes, id. at 61,366, n. 79, FERC concluded that the electricity market structure and market rules devised by California’s restructuring plan were “seriously flawed” and a significant cause of the unjust and unreasonable short-term rates in California, id. at 61,349. Further, FERC found “clear evidence” that California’s market rules and structures provided electricity wholesale sellers the opportunity to exercise market power during periods of tight supply, although there was insufficient evidence at the time for FERC to come to definitive conclusions concerning the actions of individual sellers. Id. at 61,350.

The central structural flaw of the California restructuring plan, according to FERC, was its over-reliance on the spot market. The CPUC’s mandatory buy/sell requirement, which forced the IOUs to sell all of their generation capacity into, and to purchase all of their electricity supply needs from, CalPX, coupled with the CPUC’s limitations on the IOUs’ forward contracting, exposed the IOUs to volatile spot market price spikes and prevented them from managing their risks more effectively through long-term contracting. Id. at 61,359-62. Over-reliance on the spot market also exposed the IOUs to the possible exercise of market power in the CalPX by wholesale sellers during periods of short supply. Finally, CPUC limitations on long-term contracting in favor of the CalPX day-ahead and day-of markets produced a chronic underscheduling of electricity supplies, turning the Cal-ISO’s real time imbalance energy market, the market of last resort, into a significant market participant by forcing the Cal-ISO to make last minute purchases for up to 15 percent of total statewide electricity needs — far in excess of the maximum five percent total statewide load which the Cal-ISO’s imbalance market was originally intended to handle. 93 FERC ¶ 61,294, at 61,995.

In its December 15 Order, FERC adopted a number of remedies to address these flaws in the California electricity market rules and structures. First, and most importantly, it eliminated the CalPX buy/sell requirement. FERC stated that “eliminating any mandated reliance on the spot market represents the single most important aspect of wholesale market reform and is one of the most critical components of all the immediate market reforms necessary to correct the problems in California electric markets and provide long-term protection of customers.” Id. at 61,-999. This measure, which took effect immediately, permitted the IOUs to manage their risks more effectively through forward contracting, decreasing their exposure to spot market price spikes. Id. at 61,982. In addition, it further reduced the IOUs’ exposure to the spot market by returning to them 25,000 megawatt hours (“MWh”) of their own generation capacity. Indeed, the December 15 Order actually precluded the IOUs from selling all but their surplus generation into the CalPX (or any other wholesale) markets. Id. at 62,-001 (“Effective on the date of this order, the IOUs are no longer authorized to sell their resources into the PX.... [However, ] [t]o the extent the IOUs’ resources exceed their load at various times, they are free to sell any surplus at wholesale, pursuant to their Commission-filed rate schedules.”).

Because the IOUs participate in both the California retail as well as interstate wholesale markets, however, they fall within the jurisdiction of both the CPUC as well as FERC. FERC noted that its proposal to eliminate the mandatory buy/sell requirement had received overwhelming support from almost all interested parties except the CPUC. In fact, the CPUC specifically declared that FERC’s “elimination of its ‘Buy’ requirement does not eliminate the California Commission’s ‘Buy’ requirement,” and emphasized that its buy requirement would remain in place until the CPUC itself removed it. Id. at 61,999.

Faced with the CPUC’s refusal to abandon its reliance on the spot market — indeed, in the face of the CPUC’s explicit declaration that it would continue to require, whether directly or indirectly, that the IOUs continue to procure the bulk of their power needs through the CalPX spot markets — FERC was forced to take “the unusual step” of terminating the CalPX’s wholesale tariff and rate schedules, including its CTS forwards market rate schedule, effective April 30, 2001. In this way, FERC eliminated CalPX’s ability to operate as an exclusive mandatory exchange. Id. at 61,999. At the same time, FERC explicitly invited CalPX to reconstitute itself as an “independent exchange with no regulatory mandated products and offer the services needed by market participants.” Id. at 62,000, n. 46. See also Order Clarifying Order Directing Remedies for California Wholesale Electric Markets, 94 FERC 61,005, 2001 WL 15773 (Jan. 8, 2001) (explaining that “[t]he PX is free to revise its CTS tariffs to remove the spot market components of its existing rate schedules, and to file them pursuant to FPA section 205 and, if appropriate, to seek waiver of the ... 60-day notice period”).

One other prospective structural remedy instituted by FERC in its December 15 order is relevant to the petitions before us: its imposition of a temporary $150 MWh breakpoint in the CalPX spot markets and the Cal-ISO real time imbalance energy market through April 2001. Rejecting SDG & E’s request for a $250 MWh wholesale price cap, FERC instead imposed a “soft cap” in the CalPX and Cal-ISO short-term markets as both a price mitigation measure and a market monitoring device. Under the soft cap, any trades above $150/MWh will not set the single market clearing price for all buyers. The $150 breakpoint thus represents a limitation on the single price auction format of the CalPX spot markets. The soft cap does not, however, preclude individual suppliers and purchasers from entering into transactions in excess of $150/MWh, and sellers will continue to receive their as-bid amounts. 93 FERC ¶ 61,294, at 61,996. At the same time, the December 15 order subjects transactions in excess of $150/ MWh to certain reporting and monitoring-requirements to facilitate FERC’s on-going investigation into exercises of market power by wholesale sellers. Id. at 61,983, 61,996-97.

C

In addition to its prospective structural remedies, FERC intimated in both its November 1 and December 15 orders that retroactive relief — refunds from wholesale sellers of electricity subject to FERC’s jurisdiction — might also be warranted. In its November 1 order, FERC provisionally established October 2, 2000, as the “refund effective date,” i.e., the terminus post quern for the transactions subject to potential refund liability pursuant to the provisions of the FPA. 93 FERC ¶ 61,121, at 61,370-71, 61,376-82. Further, FERC ruled that, henceforth, all sales of electricity into the California market through December 2002 would likewise be subject to potential refund liability. Id. at 61,370. However, FERC declined to require immediate refunds in either order, finding that it could not yet “reach definite conclusions about the actions of individual sellers” and intimating that further fact-gathering would have to be undertaken before it could rule on the refund requests. Id. at 61,350; see also 93 FERC 1(61,294, at 61,998 (observing that FERC had not yet made “findings about whether particular rates charged by specific sellers” were unjust and unreasonable).

On March 9, 2001, FERC issued its first order concerning refunds in the California wholesale power market. See Order Directing Sellers to Provide Refunds Of Excess Amounts Charged, 94 FERC 61,245, 2001 WL 406581 (March 9, 2001) (“March 9 Order”). This order was limited to the January 2001 period. Relying largely on Cal-ISO and CalPX filings, FERC for the first time established a provisional formula governing refunds. The March 9 Order directs wholesale sellers of electricity into the California market to provide refunds or offsets or, alternatively, to justify their charges and costs, for transactions made during Stage 3 emergencies that were above a “rate screen,” which for the January 2001 period FERC calculated at $273/ MWh. FERC estimated that some $69 million in January 2001 electricity sales would be subject to refunds and stated that it would use this same methodology to calculate potential refund obligations for the period from February to April 2001. At the same time, FERC again declined to rule on retroactive refund requests for the October 2, 2000, to December 31, 2000, period.

D

Meanwhile, claiming that it could not comply with the $150 MWh breakpoint or attendant reporting and monitoring requirements in a cost effective manner, CalPX suspended operations in its spot markets at the end of January 2001. In addition, facing the imminent termination of its CTS forwards market rate schedule and unwilling to file new rate schedules which would allow it to operate a bilateral forwards market, CalPX saw trading in its CTS division come to a virtual halt since the December 15 order. On March 9, 2001, CalPX filed for protection under Chapter 11 of the Bankruptcy Act.

II

CalPX petitions for a writ of mandamus staying three components of FERC’s December 15 Order: (1) the prohibition on the IOUs from selling power on a voluntary basis into the CalPX markets; (2) the termination of its wholesale tariff and CTS rate schedule, effective May 1, 2001; and (3) the imposition of the interim $150/MWh “breakpoint” in its Core markets. CalPX does not, however, challenge FERC’s elimination of the mandatory buy/sell requirement.

The gravamen of the City of San Diego’s (the “City’s”) petition for mandamus, on the other hand, is that FERC has unreasonably delayed taking action on California wholesale power purchasers’ requests for refunds, particularly for the October 2, 2000, to December 31, 2000, period.

We consolidated these petitions because they each, at root, challenge FERC’s authority to address conditions creating unjust and unreasonable market-based rates by altering market rules and structures. In essence, both CalPX and the City seek to limit FERC to the traditional panoply of remedies appropriate for cost-of-service-based rate regimes.

A

Judicial review over final orders of FERC is governed by Section 313 of the FPA, which provides:

Any party to a proceeding under this chapter aggrieved by an order issued by the Commission in such proceeding may obtain a review of such order in the United States Court of Appeals for any circuit wherein the licensee or public utility to which the order relates is located or has its principal place of business, or in the United States Court of Appeals for the District of Columbia, by filing in such court, within sixty days after the order of the Commission upon the application for rehearing, a written petition praying that the order of the Commission be modified or set aside in whole or in part.... No objection to the order of the Commission shall be considered by the court unless such objection shall have been urged before the Commission in the application for' rehearing ....

16 U.S.C. § 8251 (b). Thus, pursuant to § 8251 (b), a FERC order is not final for purposes of our review until FERC has ruled on an application for rehearing. See Reynolds Metals Co. v. FERC, 111 F.2d 760, 762 (D.C.Cir.1985) (jurisdiction lacking in court of appeals until after FERC rules on application for rehearing). Because applications to rehear the November 1 and December 15 orders are still pending before FERC, we do not yet have jurisdiction to review them pursuant to § 8251 (b).

The All Writs Act, however, authorizes us to issue mandamus relief necessary to protect our “prospective jurisdiction.” 28 U.S.C. § 1651; FTC v. Dean Foods Co., 384 U.S. 597, 604, 86 S.Ct. 1738,

16 L.Ed.2d 802 (1966); Pub. Util. Comm’r v. Bonneville Power Admin., 767 F.2d 622, 630 (9th Cir.1985). The writ of mandamus is, however, an extraordinary remedy justified only in “exceptional circumstances.” Gulfstream Aerospace Corp. v. Mayacamas Corp., 485 U.S. 271, 289, 108 S.Ct. 1133, 99 L.Ed.2d 296 (1988) (internal quotations omitted). The party seeking mandamus relief must establish that its right to issuance of the writ is “ ‘clear and indisputable.’ ” Id. at 289, 108 S.Ct. 1133. (citation omitted). We have remarked that “[u]se of the All Writs Act in connection with agency matters has been even more rare and the scope of relief granted in these cases has been narrow.... The circumstances that will justify our interference with nonfinal agency action must be truly extraordinary .... ” Bonneville Power Admin., 767 F.2d at 630.

We generally employ a three-part test to determine whether to grant mandamus relief: “(1) the plaintiffs claim is clear and certain; (2) the duty is ministerial and so plainly prescribed as to be free from doubt; and (3) no other adequate remedy is available.” Or. Natural Res. Council v. Harrell, 52 F.3d 1499, 1508 (9th Cir.1995) (quoting Fallini v. Hodel, 783 F.2d 1343, 1345 (9th Cir.1986)) (internal quotations omitted).

B

We first address CalPX’s petition for mandamus.

1

CalPX asks us to stay FERC’s termination of its wholesale tariff and rate schedules, particularly its CTS forwards market rate schedule. CalPX argues that FERC may not simply eliminate existing tariffs and rate schedules found to be unjust and unreasonable, but must instead modify them so that they become “just and reasonable” rates under § 206(a) of the FPA. Section 206(a) provides, in pertinent part:

Whenever the Commission, after a hearing had upon its own motion or upon complaint, shall find that any rate, charge, or classification, demanded, observed, charged, or collected by any public utility for any transmission or sale subject to the jurisdiction of the Commission, or that any rule, regulation, practice, or contract affecting such rate, charge, or classification is unjust, unreasonable, unduly discriminatory or preferential, the Commission shall determine the just and reasonable rate, charge, classification, rule, regulation, practice, or contract to be thereafter observed and in force, and shall fix the same by order.

16 U.S.C. § 824e (emphasis added). Under CalPX’s reading of the statute, if FERC terminates a tariff or rate schedule as unjust or unreasonable, as it did in its December 15 Order, it must then substitute^ new tariff or schedule. CalPX emphasizes the “unprecedented” nature of FERC’s termination of its tariff and rate schedules. The precedent to which CalPX refers us, however, arose in the context of traditional cost-based regulatory regimes.

FERC’s authority under § 206(a) to remedy rules and structures adversely affecting market-based rate regimes cannot be read so narrowly. Indeed, as the Supreme Court has held in the context of the Natural Gas Act, the counterpart to the FPA, “agencies created to protect the public interest must be free, within the ambit of them statutory authority, to make the pragmatic adjustments which may be called for by particular circumstances.... Surely the Commission’s broad responsibilities therefore demand a generous construction of its statutory authority.” FPC v. La. Power & Light Co., 406 U.S. 621, 642, 92 S.Ct. 1827, 32 L.Ed.2d 369 (1972) (internal quotations and citations omitted).

We are unconvinced that CalPX has presented a “clear and certain” claim that FERC violated § 206(a) by terminating its tariff and rate schedules. Pursuant to § 206(a), FERC may eliminate “rule[s], regulation^], [or] practice^] ... affecting ” rates, and then establish a new “rule, regulation, [or] practice,” 16 U.S.C. § 824e(a) (emphasis added), that will assure just and reasonable rates in the future. It is at the very least arguable that the language of § 206(a) is sufficiently broad to permit FERC to eliminate a tariff or rate schedule entirely, particularly in the context of a market-based rate regime, if it also establishes rules, regulations, or practices that will result in just and reasonable rates. FERC contends that it did just that with the entire range of remedies in its December 15 Order.

We agree that the remedial measures contained in the December 15 Order must be construed as a whole in assessing FERC’s compliance with § 206(a). As discussed above, according to FERC, over-reliance on spot markets, i.e., the CalPX Core and the Cal-ISO real time imbalance markets, “lies at the very heart of the high prices in California.” December 15 Order, 93 FERC ¶ 61,294, at 61,993. The remedies crafted by FERC in its December 15 Order, taken together, eliminated a number of market “rules” and “practices” responsible for such undue reliance on volatile spot markets and replaced them with new “rules” and “practices” designed to mitigate short-term price volatility risks through forward contracting. These remedies included: eliminating the mandatory CalPX buy/sell requirement to permit risk management through forward contracting, instituting the $150 MWh breakpoint to mitigate the potential of the single price auction format to magnify spiraling spot markets prices, returning 25,000 MWh of their own generation to the IOUs to reduce further their exposure to spot market price volatility, and terminating CalPX’s tariff and wholesale rate schedules to prevent it from continuing to operate as a mandatory exclusive exchange. FERC’s actions, taken together, appear to be fully consistent with § 206(a).

According to FERC, among the features of the California electricity restructuring plan responsible for unjust and unreasonable short-term wholesale electricity rates were direct and indirect CPUC rules forcing the IOUs into the CalPX spot markets. Elimination of the mandatory buy/sell requirement, which CalPX does not challenge here, was not sufficient to redress the problem, however. Indeed, the CPUC affirmatively represented to FERC that it would persist with its own “buy” requirement for the IOUs and would continue to look to the CalPX spot markets as the benchmark against which to measure the prudence of the IOUs’ long-term contracts. 93 FERC ¶ 61,294, at 61,999. FERC reasonably concluded that termination of the CalPX tariff and rate schedules was necessary to facilitate forward contracting by the IOUs free from the chilling effect produced by the CPUC’s continuing reliance on the CalPX spot markets as the benchmark for prudence. Id. at 61,994, 61,999.

Given that certain delivery, bid, and settlement provisions of the current CTS rate schedule are dependent upon the CalPX spot markets, termination of the CTS rate schedule was the inevitable result of the termination of the CalPX Core market schedules. See Jan. 8 Order, 94 FERC ¶ 61,005. Indeed, CalPX itself has emphasized the connection between the CTS forwards market and the CalPX day-ahead and day-of markets, stating that the “efficacy of the CTS depends on a robust near-term forward market (like the CalPX day-ahead market) to serve as a benchmark for pricing the value of forward transactions at or near the time of physical delivery.” We recognize the importance of properly functioning near-term markets for valuing forward transactions. CalPX, however, overlooks the fact that FERC specifically found that its near-term markets were not functioning properly, but were instead vulnerable to the exercise of market power and, indeed, producing unjust and unreasonable short-term rates under certain conditions. CalPX does not challenge the factual basis of this finding. The fact that the flawed CalPX Core markets continued to serve as benchmarks for forward contracts simply underscores the over-reliance placed on spot markets by the California restructuring plan and the CPUC in particular. FERC has established a provisional benchmark for forward contracts based on pre-restructuring rates and has invited CalPX to file a new CTS rate schedule that is not dependent upon spot markets. CalPX so far has declined FERC’s invitation.

CalPX complains that it has been essentially caught in the cross-fire between the CPUC and FERC. We do not dispute this point. See, e.g., 93 FERC ¶ 61,294, at 61,999. Nevertheless, CalPX is not thereby entitled to mandamus relief. In light of what it regarded as the recalcitrance of the CPUC, FERC concluded that termination of CalPX’s tariff and rate schedules was necessary to address defective market rules and structures skewing the wholesale markets under FERC’s own jurisdiction. While FERC’s termination of CalPX’s rate schedules was perhaps unprecedented, we are not convinced that FERC lacks authority under § 206(a) of the FPA to address the structural flaws of a market-based rate regime through the termination of a public utility’s wholesale tariff and rate schedules in circumstances such as these.

2

FERC’s December 15 Order not only eliminated the mandatory CalPX buy/sell requirement, it prohibited the IOUs from selling all but their surplus generation into wholesale markets. To the extent that FERC has thereby prohibited voluntary sales into the CalPX markets, CalPX challenges this provision as unduly discriminatory and arbitrary.

CalPX suggests that FERC’s restriction on the IOUs’ wholesale sales of their own generation applies only to sales into CalPX but not to sales into competing markets, such as intervenor Automated Power Exchange. Hence, according to CalPX, FERC’s order is unlawful because it is “unduly discriminatory” within the meaning of § 206(a) of the FPA, 16 U.S.C. § 824e. We find CalPX’s reading of the December 15 Order untenable. The stated purpose of the restriction was to “subject [the IOUs’ approximately 25,000 MWh of generation] to the state’s retail ratemak-ing authority instead of the Commission’s ratemaking authority ... [thereby] effectively ‘de-federalizing’ this portion of the market.” December 15 Order, 93 FERC ¶ 61,294, at 62,001. Clearly, FERC precluded the IOUs from selling their non-surplus generation into any FERC-juris-dictional (interstate wholesale) market. Moreover, FERC specifically permitted the IOUs to sell any surplus at wholesale “pursuant to their Commission-filed rate schedules.” Id. Such sales could be made through the CalPX or under any other wholesale rate schedule. CalPX has failed to present a “clear and certain” claim that the prohibition is unduly discriminatory.

Neither will we stay implementation of this provision on the purported ground that it is arbitrary. By prohibiting such non-surplus voluntary sales into the wholesale markets, FERC intended to reduce by approximately 60 percent the IOUs’ exposure to the volatile spot market during peak periods and to obviate the need for the IOUs to turn to the spot markets at all during certain off-peak periods. Thus, the measure was squarely addressed to the fundamental problem identified by FERC as distorting California wholesale electricity rates: aOer-reliance on the spot market. CalPX has failed to demonstrate a clear and certain claim that the prohibition is arbitrary.

3

Finally, CalPX requests us to stay application of the $150 MWh breakpoint. CalPX contends that the breakpoint, imposed only on the CalPX Core and Cal-ISO real-time imbalance energy markets, discriminates against it in favor of other competing near-term markets. CalPX overlooks the fact that it has been the largest and only mandatory exchange in California and that FERC specifically found that flaws in the rules and policies of CalPX (as well as the Cal-ISO) contributed to unjust and unreasonable short-term electricity rates under certain conditions. November 1 Order, 93 FERC ¶ 61,121, at 61,358. No other electricity exchange was found to have contributed to the problem. FERC thus had reason to focus its remedial efforts on CalPX. Indeed, imposition of the breakpoint on other power exchanges would have been arbitrary in the absence of any findings that structural defects in these exchanges contributed to the California electricity crisis.

FERC imposed the breakpoint in order to limit the tendency of the CalPX and Cal-ISO short-term markets’ single price auction formats to magnify spot market prices for all sellers during times of high energy demand. Sellers would continue to receive their as-bid amount, but transactions above the breakpoint would not set the single market clearing price and would be subject to additional reporting requirements to facilitate later FERC determinations as to whether prices over $150/MWH in individual cases were just and reasonable or indicated the exercise of market power. At the same time, FERC rejected the imposition of a price cap over wholesale prices because such a cap would stifle a competitive market in California. FERC thus imposed the $150/MWh break-point as a middle ground between the need for temporary price mitigation and the realization that competition must exist for the California energy market to survive in the long run. The formulation of this remedy, considering the competing interests involved, is neither arbitrary nor discriminatory.

Thus, • we conclude that CalPX is not entitled to mandamus relief because it has failed to establish that any of its three claims is at all “clear and certain.”

C

We turn next to the City’s mandamus petition. The City contends that FERC has unreasonably delayed taking action on requests for retroactive refunds from wholesale electricity sellers and asks us to order FERC to come to a decision as to wholesale sellers’ refund liability.

In certain, very limited, circumstances, issuance of mandamus relief may be warranted where agency action has been delayed to such an extent as to frustrate the court’s role of providing a forum for review. See, e.g., Telecomm. Research & Action Ctr. v. FCC, 750 F.2d 70 (D.C.Cir.1984) (“T.R.AC.”). While agencies cannot insulate their decisions from Congressionally mandated judicial review simply by failing to take “final action,” our authority to issue mandamus relief from agency inaction is narrow indeed. Drawing on case law interpreting section 706(1) of the Administrative Procedure Act, which authorizes courts to compel “agency action unlawfully withheld or unreasonably delayed,” 5 U.S.C. § 706(1), the Court of Appeals for the District of Columbia Circuit set out in T.R.A.C. the following guidelines for determining whether an agency’s delay in issuing a final order is so “egregious” as to warrant mandamus:

1) a “rule of reason” governs the time agencies take to make decisions; 2) delays where human health and welfare are at stake are less tolerable than delays in the economic sphere; 3) consideration should be given to the effect of ordering agency action on agency activities of a competing or higher priority; 4) the court should consider the nature of the interests prejudiced by delay; and 5) the agency need not act improperly to hold that agency action has been unreasonably delayed.

Towns of Wellesley, Concord, and Norwood, Mass. v. FERC, 829 F.2d 275, 277 (1st Cir.1987) (citing T.R.A.C., 750 F.2d at 80). We adopted the T.R.A.C. guidelines in Independence Mining Co. v. Babbitt, 105 F.3d 502, 507 (9th Cir.1997). Thus, the standards for mandamus governing the City’s petition are, at least in form, somewhat different than the traditional three-part mandamus test governing CalPX’s petition.

It is clear that, under the T.R.A.C. factors, FERC’s delay is not so unreasonable as to render the City’s remedy—to await a final order—inadequate. The cases in which courts have afforded relief have involved delays of years, not months. See, e.g., Potomac Elec. Power Co. v. ICC, 702 F.2d 1026, 1035 (D.C.Cir.1983) (eight year delay unreasonable); MCI Telecommunications Corp. v. FCC., 627 F.2d 322, 324-25 (D.C.Cir.1980) (four year delay unreasonable); Nader v. FCC, 520 F.2d 182, 206 (D.C.Cir.1975) (delay of ten years unreasonable). Compare T.R.A.C. 750 F.2d at 81 (delays of approximately five years and two years by the FCC did not warrant mandamus, but prompted the court to retain jurisdiction over proceedings); Towns of Wellesley, Concord and Norwood, Mass., 829 F.2d at 277 (delay of fourteen months “not so ‘egregious’ as to warrant mandamus”). A fortiori, FERC’s four-month delay does not run afoul of any “rule of reason.”

Further, as its March 9 Order demonstrates, FERC has taken action to develop both an empirical and methodological framework for addressing refund liability issues. While FERC has not yet addressed refund requests for the October 2, 2000, to December 31, 2000, period, we are confident that it will do so in due course.

FERC has focused its resources on formulating prospective remedies to correct the structural defects in the California electricity market, as we have outlined above. The City argues that FERC has thereby shirked its responsibilities under the FPA, stating that FERC “must determine the just and reasonable rate” for the California market, as it would in a cost-based regulatory regime, and it must do so immediately. Like CalPX, the City does not appear to appreciate the flexibility FERC has under the FPA to address conditions leading to unjust and unreasonable rates in a market-based system by reforming market structures. As we explained above, for purposes of the petitions of mandamus before us, we believe that FERC’s formulation of its prospective structural, remedies for the California wholesale market is consistent with its obligations under § 206(a) of the FPA, 16 U.S.C. § 824(e). Its decision to give higher priority to structural remedies over retroactive refund determinations does not in any way entitle the City to the mandamus relief it requests.

III

Given the mandamus nature of this proceeding, we must conclude that the scope of FERC’s authority to address structural flaws affecting market-based rates cannot reasonably be limited in the manner CalPX and the City propose. The petitions for writs of mandamus of the California Power Exchange and the City of San Diego are accordingly

DENIED. 
      
      . Under the FPA, FERC has jurisdiction over "the sale of electric energy at wholesale in interstate commerce,” i.e., sales of electricity for resale. 16 U.S.C. § 824(b), (d). A “public utility” is defined under the FPA as "any person who owns or operates facilities subject to the jurisdiction of the Commission under this part.” Id. § 824(e). The CPUC has jurisdiction over all retail sales of electricity in California.
     
      
      . For example, the monthly average market clearing price for May 2000 in the CalPX spot market represented a 100 percent increase over May 1999. 93 FERC ¶ 61,121, at 61,-353. The CalPX’s constrained day-ahead price peaked at $l,099/MWh on June 28, 2000 — an astounding 15-fold increase over the pre-restructuring average cost of $74/ MWh. Id.; 93 FERC ¶ 61,294, at 61,994.
     
      
      . The AB 1890 rate freeze terminated for SDG & E customers when the utility recovered its stranded costs in 1999. In response to the extraordinary increases in SDG & E customers’ rates, however, the California legislature passed AB 265, which imposed a temporary retroactive retail rate cap of 6.5 cents/ kWh for certain retail customers. See Cal. Pub. Util.Code § 332.1(2).
     
      
      . The IOUs’ peak load is 40,000 MWh.
     
      
      . By declaring IOUs' purchases of electricity in the CalPX spot market as presumptively prudent — essentially immunizing such purchases from further CPUC prudence review— the CPUC effectively imposed an additional indirect requirement that the IOUs continue lo procure the bulk of their power needs through the CalPX spot market. FERC’s termination of CalPX’s wholesale tariffs was thus designed to prevent either a direct or indirect CPUC requirement in favor of such market. 93 FERC ¶ 61,294, at 61,999. Following * FERC’s December 15 Order, the CPUC issued a decision on December 21, 2000, in which it reaffirmed its position that "reasonableness review of the [IOUs’] portfolio of bilateral forward contracts continues to be necessary" and submitted for comment certain criteria the IOUs should consider when entering into long-term electricity contracts. Order Proposing Clarifications And Modifications of D.00-08-023 And D.00-09-075, and Establishing Prudency Standards for Forward Electricity Contracts (Cal. Pub. Util. Comm’n Decision 00-12-065), 2000 WL 33147086 (Dec. 21, 2000). The parties have not briefed us on the relevance, if any, of this decision to the petitions before us.
     
      
      . The California legislature has since repealed Cal. Pub. Util.Code § 355.1, which had prohibited the CPUC from "implementing] the part of any decision authorizing electrical corporations to purchase from exchanges other than the Power Exchange.” See Act of February 1, 2001, 2001 Cal. Legis. Serv. 1st Ex.Sess. 4 (A.B.1) (West). The record does not indicate how, if at all, the CPUC has responded in light of the repeal of § 355.1, nor have the parties briefed us on the relevance, if any, of this repeal to the petitions before us.
     
      
      . To calcúlale the rate screen, FERC estimated the costs for operating a simple-cycle combustion turbine unit based on the weighted-average of the least efficient gas turbines for each of the three California lOUs, in an attempt to reflect "the inefficient generation which operated on the margin in California” during Stage 3 emergencies. See March 9 Order at 4, 94 FERC ¶ 61,245.
     
      
      . In an order dated March 14, 2001, FERC established the rate screen for the February 2001 period, resulting in potential refunds of approximately $55 million.
     
      
      . CalPX also asserts that the FPA does not provide authority to FERC to terminate a public utility because the FPA, unlike the Natural Gas Act, see, e.g., 15 U.S.C. § 717f, does not permit FERC to issue "certificates of public convenience.” This argument is unavailing. FERC did not purport to deny CalPX a certificate of public convenience. Nor did it, in fact, terminate CalPX, despite CalPX’s contention that the effect of the December 15 Order is its death knell. Indeed, FERC specifically invited CalPX to file new rate schedules so that it could operate as a voluntary nonexclusive bilateral forwards market. See January 8 Order.
     
      
      . In its papers filed in these proceedings, CalPX at times suggests that FERC’s finding of unjust and unreasonable rates in the California short-term wholesale markets was limited to the Cal-ISO's real time imbalance energy market. As we summarized in Part I, this is not correct. Although FERC noted that the Cal-ISO real time market was especially volatile, FERC specifically found that structural flaws affecting the CalPX spot markets had caused, and continued to have the potential to cause, unjust and unreasonable short-term rates under certain conditions. December 15 Order, 93 FERC ¶ 61,294, at 61,998.
     
      
      . CalPX additionally contends that FERC’s termination of its rate schedules is "effectively a 'talcing' ” in violation of the Fifth Amendment because "FERC has ‘essentially dissolved’ CalPX without providing any means for it to recover its operating expenses.” Based on the record before us, we do not think CalPX’s takings claim is "clear and certain.” As discussed above, FERC explicitly invited CalPX to file a new CTS rate schedule not dependent upon its spot markets, but CalPX declined FERC’s invitation. FERC did not "dissolve” CalPX; it simply took certain steps it concluded were necessary to address flawed market structures leading to unjust and unreasonable short-term rales, as it is obligated to do under the FPA.
     
      
      . CalPX additional!}' contends that a break-point imposed on the Cal-lSO would suffice to constrain CalPX prices. If the contention is that FERC acted arbitrarily, it can hardly be said that FERC’s imposition of the break-point on both CalPX' and Cal—ISO was imprudent or arbitrar}'. Both markets are subject to very high spot market prices during times of peak demand, and FERC could have determined that a breakpoint imposed in both markets would tend to limit the instances of unjust or unreasonable prices. CalPX similarly argues that the reporting requirements are redundant as applied to itself, because FERC imposed the reporting requirements on Cal—ISO and power sellers. Mere redundancy, presumably in the effort to obtain accurate information, does not render the reporting requirements arbitrary.
     
      
      . Because we conclude that CalPX cannot meet the first element of the mandamus test, we need not address the somewhat more difficult issue of determining whether CalPX has suffered irreparable injury as a result of the December 15 order, or, rather, whether CalPX's apparently imminent dissolution is primarily the result of other, independent, causes.
     
      
      . As a threshold matter, FERC contends that the City does not have standing to pursue its petition. We disagree. As a retail customer of SDG & E beyond the scope of the limited, temporary rate freeze protection offered by AB 265, the City has been injured as a result of the unjust and unreasonable short-term rate conditions in California (in the form of higher electricity bills), and any refunds owed to SDG & E would redress the City's injury, insofar as such refunds would flow through to SDG & E customers in the form of rate reductions. AB 265 section 2 provides that "[i]t is ... the intent of the Legislature that to the extent that the Federal Energy Regulatory Commission orders refunds to electrical corporations pursuant to their findings, the commission shall ensure that any refunds are returned to customers.” Cal. Pub. Ulil.Code § 332.1(2).
     
      
      . We note that in its November 1 Order, FERC hinted at the possibility that wholesale purchasers might be eligible for unspecified equitable relief for 'transactions preceeding October i. 93 FERC ¶ 61,121, at 61,371 n. 91. FERC has not yet clarified this suggestion. Again, we have no reason to believe that FERC will not resolve this issue in due course. We will not require FERC to do so immediately.
     