This case comes to us on petitions for review of a series of orders issued by the Federal Energy Regulatory Commission (“FERC”) relating to the energy crisis that occurred in California in 2000 and 2001. Nearly 200 petitions for review of the various FERC orders have been filed in our Court. We consolidated these petitions for administrative management.

On November 24, 2004, we issued a consolidated order in this case separating certain issues for decision in two consolidated proceedings, the first of which we termed the “Jurisdictional Cases”; the second we termed the “Scope/Transactions Cases.” In the Jurisdictional Cases, we considered whether FERC’s refund authority extended to certain governmental entities. We heard oral arguments on Jurisdictional Cases on April 12, 2005, and issued an opinion concerning the Jurisdictional Cases on September 6, 2005. Bonneville Power Admin. v. FERC, 422 F.3d 908 (9th Cir.2005).

The Scope/Transaction Cases before us here involve numerous questions pertaining to the proper scope of FERC’s refund orders, including the appropriate temporal reach and the type of transactions properly subject to the refund orders. We heard oral arguments on the Scope/Transaction Cases on April 13, 2005. This opinion covers the issues presented in the Scope/Transaction Cases.

We grant in relief in part and deny relief in part. In general, we hold that all the transactions at issue in this case that occurred within the California Power Exchange Corporation (“CalPX”) or California Independent System Operator (“Cal-ISO”) markets, or as a result of a CalPX or Cal-ISO transaction, were the proper subject of the refund proceedings instituted by FERC. Therefore, we deny the petitions for review that challenge FERC’s inclusion of such transactions; we grant the petitions for review that challenge FERC’s exclusion of such transactions.

We deny the petitions for review that seek to expand FERC’s refund proceedings into the bilateral markets beyond the CalPX and Cal-ISO markets. In particular, we hold that FERC properly excluded from the refund proceedings bilateral transactions between the California Energy Resources Scheduling (“CERS”) Division of the California Department of Water Resources and other entities that occurred outside the CalPX and Cal-ISO markets.

We hold that FERC properly established October 2, 2000 as the refund effective date for the § 206 proceedings, rather than October 29, 2000, as argued by some parties. However, we hold that FERC erred in excluding § 309 relief for tariff violations that occurred prior to October 2, 2000. We reserve consideration of all other issues raised in the various petitions for review for the next phase of our appellate proceedings.

The net effect of our decision is to preserve the scope of the existing FERC refund proceedings, but to expand those refund proceedings to include: (1) tariff violations that occurred prior to October 2, 2000, (2) transactions in the CalPX and Cal-ISO markets that occurred outside the 24-hour period specified by FERC, and (3) energy exchange transactions in the CalPX and Cal-ISO markets.

I

Parties and Claims

With that brief summary of the issues, we turn to the specific claims of the parties. The State of California and several intervenors (collectively, “the California Parties”) seek review of a number of FERC’s decisions, namely: (1) FERC’s denial of relief for sales of electricity made at unjust rates prior to October 2, 2000, the refund effective date set by FERC; (2) FERC’s denial of relief for energy sales in which CERS was the purchaser; (3) FERC’s refusal to order relief for energy exchange transactions; and (4) FERC’s refusal to order relief for certain forward market transactions.

A group of energy suppliers and generators called the Competitive Suppliers Group also petitions for review of several of FERC’s decisions, namely: (1) FERC’s decision to set the refund effective date at October 2, 2000, rather than October 29, 2000; (2) FERC’s order of refunds for transactions that took place during non-emergency hours, and (3) FERC’s inclusion of certain out-of-market transactions in its refund proceedings.

The Port of Oakland, along with other petitioners and intervenors, petitions for review of FERC’s decision to exclude certain bilateral transactions from its refund order.

Also before us in this case are the Public Entities’ and the Bonneville Power Administration’s petitions for review of FERC’s determination that it had authority to order relief for certain transactions known as “sleeve” and “multi-day” transactions, as well as transactions occurring under § 202(c) of the Federal Power Act. The California Parties have moved to strike, and El Paso Merchant Energy Company has moved to defer, consider ation of the arguments until the next phase of our consideration of the FERC orders.

II

Factual Background

During the mid-1990’s, FERC began examining whether the wholesale electric power industry should have been restructured and deregulated to separate generation, transmission, and distribution functions. Generation involves the production of power through a variety of means. Transmission generally refers to the conveyance of high voltage electric power from the points of generation to substations for conversion to delivery voltages. Distribution refers to the delivery of the converted low voltage energy from substations to individual consumers. The theory behind separating these functions, known as “unbundling,” was that wholesale power competition would be promoted, and consumers would benefit, if public utilities were required to provide nondiscriminatory, open access, transmission. See Promoting Wholesale Competition Through Open Access Non-Discriminatory Transmission Services by Public Utilities, 60 Fed.Reg. 17,662 (proposed April 7, 1995) (codified at 18 C.F.R. § 35.0 et seq.). This examination culminated in the issuance of FERC Order No. 888 in 1996. Order No. 888, Promoting Wholesale Competition Through Nondiscriminatory Transmission Services by Public Utilities, 61 Fed.Reg. 21,540, 21,541 (May 10, 1996) (“FERC Order No. 888”), on reh’g, 62 Fed.Reg. 12,274 (Mar. 14, 1997), on reh’g, 62 Fed.Reg. 64,-688 (Dec. 9, 1997), on reh’g, 82 F.E.R.C. ¶ 61,046 (Jan. 20, 1998), aff'd, Transmission Access Policy Study Group v. FERC, 225 F.3d 667 (D.C.Cir.2000) (per curiam), aff'd sub nom. New York v. FERC, 535 U.S. 1 , 122 S.Ct. 1012 , 152 L.Ed.2d 47 (2002). Among other provisions, FERC Order No. 888 included a series of regulations that provided for the creation of competitive markets for wholesale electric power, including the creation of independent regional transmission companies that would allow the development of a competitive electric transmission market.

Prior to these events, the California electricity market was composed of investor-owned utilities, whose generation, transmission, and distribution of electricity were vertically integrated and regulated by the California Public Utilities Commission (“CPUC”), the state agency charged with regulating retail electricity rates. Cal. Pub. UtiLCode § 451. The CPUC set retail electrical rates charged by the investor-owned utilities providing service in exclusive service territories. There are three major investor-owned utilities in California: Pacific Gas and Electric Company (“PG & E”), Southern California Edison Company (“Edison”), and San Diego Gas and Electric Company (“SDG & E”).

In response to FERC Order No. 888 and energy problems in 1995, the CPUC and the California legislature commenced initiatives to restructure the California electric energy industry. The aim was to convert California’s investor-owned, regulated utilities, to a deregulated market, in which the price of electricity would be established by competition, and consumers could select their electrical power supplier. The theory was that competition would lead to better service and a price reduction for consumers.

Toward this end, the California legislature enacted Assembly Bill 1890 (“AB 1890”). Act of September 23, 1996, 1996 Cal. Legis. Serv. 854 (codified at Cal. Pub. Util.Code §§ 330-398.5). The deregulation was to proceed in several phases, beginning with the deregulation of the wholesale electricity market. After a transition period during which the investor-owned utilities were to recover their “stranded costs” through fixed prices for electricity, the retail market was to be deregulated.

Under AB 1890, the major investor-owned, vertically integrated utilities were required to divest a substantial portion of their power generation plants, including fossil fuel generation plants (but excluding hydroelectric facilities and nuclear power plants), to unregulated, non-utility producers. This divestiture was accomplished by a process of market valuation, based on a discount of projected future revenue streams. See Order Instituting Rulemak-ing on Commission’s Proposed Policies Governing Restructuring California’s Electric Service Industry and Reforming Regulation, 64 CPUC 2d. 1, 1995 WL 792086 (Dec. 20, 1995) (“CPUC Decision 95-12-063”). Between 1998 and 1999, 22 electrical generation plants were sold.

After divesting the bulk of their generation assets, the investor-owed utilities were required to sell all of their remaining output to CalPX, a nonprofit wholesale clearing-house created by AB 1890. CalPX was to provide a centralized auction market for trading electricity. It was deemed a public utility pursuant to the Federal Power Act, see 16 U.S.C. § 824 (e), and thus subject to regulation by FERC, see 16 U.S.C. § 824 (b), (d). It operated pursuant to a FERC-approved tariff and FERC wholesale rate schedules. Pacific Gas & Elec. Co., 77 FERC ¶ 61,204 at 61,803-05, (1996), reh’g denied, 81 FERC ¶ 61,122 (1997). The investor-owned utilities were required to purchase all of electrical energy that they required from the CalPX markets and to conduct all of their sales through the CalPX market. Part of the underlying theory was that the investor-owned utilities could not exercise market power in a single transparent market, either as a buyer or a seller, because prices would be posted and all market participants would be paid the same price.

CalPX commenced operations in 1998. Initially, it operated only a single price auction for its “spot markets,” defined as “sales that are 24 hours or less and that are entered into the day of or day prior to delivery.” San Diego Gas & Elec. Co., et al., 95 FERC ¶ 61,418 at 62,545 (“June 19, 2001 Order”). The price in the CalPX spot market was determined by evaluating bids submitted by market participants. As we described the procedure in Public Utility Dist. No. 1 of Snohomish County v. Dynegy Power Marketing, Inc. (“Dynegy”), 384 F.3d 756, 759 (9th Cir.2004):

Once the market clearing price had been established, “every exchange would take place at the market clearing price, even though some buyers had been -willing to pay more and some sellers had been willing to sell for less.” Id.

The CalPX spot market, or “core market” as it is sometimes called, consisted of: (1) “day-ahead” trading, in which the market clearing price was derived from the sellers’ and buyers’ price and quantity determinations for the next day’s energy transactions and (2) “day of’ or “hour-ahead” trading, in which CalPX would determine on an hourly basis, a single market clearing price which all suppliers would be paid. Purchases made in the CalPX spot market were deemed by CPUC to be “prudent per se.” See CPUC Decision 95-12-063, 1995 WL 792086 at *26-*27.

In practice, the CalPX spot market generated considerable price uncertainty. Therefore, CalPX started a division, termed CalPX Trading Services (“CTS”), to operate a block forward market by matching supply and demand bids for long term electricity markets. In 1999, CalPX allowed the investor-owned utilities to purchase only a limited percentage of their combined load in the CTS forward market. They were required to purchase the balance of their load in the CalPX spot market.

AB 1890 created another nonprofit entity, the Independent System Operator (“Cal-ISO”), also subject to FERC jurisdiction, which was to be responsible for managing California’s electricity transmission grid and balancing electrical supply and demand. Although the investor-owned utilities continued to own the transmission facilities, Cal-ISO exercised operational control over the grid. The Cal-ISO grid included the transmission systems of PG & E, Edison, SDG & E, and the cities of Vernon, Anaheim, Banning, and Riverside, California. To maintain the grid, Cal-ISO was authorized to procure both energy needed to balance the -grid (“imbalance energy”) and operating reserves (sometimes referred to as “ancillary services”). The imbalance energy market is the so-called “real time” market, in which bids to supply energy were to be made no later than 45 minutes prior to the operating hour. Cal-ISO would rank the supply bids and purchase the required energy at the market-clearing price. Cal-ISO would then bill CalPX for electricity it required. CalPX would, in turn, bill the investor-owned utilities, who were forced to pay whatever price that Cal-ISO paid its suppliers, even though that price might have exceeded what the utilities could have charged their consumers as a consequence of the retail price freeze.

Because Cal-ISO was responsible for ensuring that all electricity demand was met, Cal-ISO was required to buy energy outside the CalPX market to make up the energy shortfall if sellers in the CalPX market were unable or unwilling to provide enough supply to meet California’s demand during a particular period. Cal-ISO acquired operating reserves, constituting capacity that could be converted to energy and delivered to the grid in response to unexpected events, such as power outages, from ancillary services suppliers who would agree to reserve capacity during the specified period. The ancillary suppliers would agree to supply the required electricity during the specified period on demand from Cal-ISO, and were to be paid regardless of whether their capacity was used. All of these operations were to be governed by a tariff and protocols filed with FERC.

As we now know, something happened on the way to the trading forum, and the best laid regulatory plans went astray. The plan to establish a competitive market, while keeping the exercise of monopoly and monopsony power in check, failed to account for energy economics and the sophistication of modern energy trading. As became clear in hindsight, even those who controlled a relatively small percentage of the market had sufficient market power to skew markets artificially. In short, the old assumptions, based on antitrust theory, that market power could not be exercised by those who possessed less than 20% of the market share proved inaccurate in California’s energy market.

With the new structure, over 80% of the transactions were being made in the spot markets — the converse of most other electricity markets, in which more than 80% of transactions are made through long term forward contracts, lending stability to the markets. Sellers quickly learned that the California spot markets could be manipulated by withholding power from the market to create scarcity and then demanding extremely high prices when scarcity was probable. The energy market is highly dependent upon weather; heat waves or cold snaps inevitably produce demand. Thus, it was quickly apparent to sellers that there was little risk and great profit in withholding capacity when high demand was anticipated based on weather forecasts. In addition, traders soon developed other purely artificial means of market manipulation, such as shutting down power plants when electric demand was high in order to destabilize the electric grid, and to increase prices. In order to maximize profit, traders engaged in anomalous bidding practices, including “hockey-stick bidding,” in which an extremely high price is demanded for a small portion of the market, and “round trip trades,” in which an entity artificially creates the appearance of increased revenue and demand through continuous sales and purchases.

Enron Corporation allegedly gamed the California markets with impunity, using manipulative corporate strategies, such as those nicknamed “FatBoy,” “Get Shorty,” and “Death Star.” Under the “Death Star” strategy, Enron allegedly sought to be paid for moving energy to relieve congestion without actually moving any energy or relieving any congestion. All of the demand was created artificially and fraudulently, creating the appearance of congestion, and then satisfied artificially, without the company providing any energy. “Fat-Boy” refers to a strategy through which Enron allegedly withheld previously agreed-to deliveries of power to the forward market so that it could sell the energy at a higher price on the spot market. The company would over-schedule its load; supply only enough power to cover the inflated schedule, and thus, leave extra supply in the market, for which Cal-ISO would pay the company. Via the “Get Shorty” strategy, traders were able to fabricate and sell operating reserves to Cal-ISO, receive payment, then cancel the schedules and cover their commitments by purchasing through a cheaper market closer to the time of delivery.

The California Parties allege that Enron was not alone, and criminal charges have been filed against a number of energy traders and executives. For example, the California Parties allege that Powerex Corporation engaged in fraudulent power scheduling to serve false load schedules. The Vice President of Powerex’s Western Trading Desk pleaded guilty to wire fraud for submitting false Cal-ISO schedules. According to the California Parties, executives of Reliant Energy Services, Inc. directed traders to engage in manipulative strategies.

Beginning in May 2000, energy prices in California began to escalate dramatically. Low cost hydroelectric power from the Northwest was not available in the volume of previous years, and wholesale electricity prices skyrocketed, particularly in the CalPX spot markets. In May 2000, the average prices in the CalPX spot market were double those of May 1999.

On June 14, 2000, energy consumers in Northern California experienced their first wave of rolling blackouts. The California Parties allege that this occurred because of market manipulation. They claim that the data indicates that the large California generators utilized economic or physical withholding strategies 94% of the time during the May through November 2000 period.

Under its operating procedures, Cal-ISO would declare a “System Emergency” when its operating reserves dipped below a predetermined percentage of its projected demand. Whenever reserves in California fell below seven percent, the ISO declared a “Stage 1 System Emergency.” June 19, 2001 Order, 95 FERC ¶ 61,418 at 62,546. The hours during which Cal-ISO declared a system-wide emergency are also called “reserve deficiency hours.” San Diego Elec. Co., et al., 97 FERC ¶ 61,275 at 62,246 (2001) (“December 19, 2001 Order”). During the summer of 2000, high temperatures and lack of supply forced the Cal-ISO to declare system emergencies 39 times. See San Diego Elec. Co., et al., 93 FERC ¶ 61,121 at 61,353 (2000).

In addition to blackouts, brownouts, and system emergencies, the crisis proved enormously expensive to purchasers of retail power, who were unable to pass along the increased cost to their consumers. In June 2000, California spent more on purchasing energy than in the entire summer of 1999. This increase occurred despite the fact that peak demand was lower in 2000 than in 1999. The California investor-owned utilities, who were still subject to the price freeze that was supposed to lock in their profits, lost billions of dollars. Cooler weather in the fall did not cool prices. Prices continued to escalate throughout the last quarter of 2000.

In August 2000, SDG & E filed a complaint under § 206 of the Federal Power Act, 16 U.S.C. § 824e(a), against all sellers of energy and ancillary services in the CalPX and Cal-ISO markets. SDG & E requested that FERC impose a price cap on sales into those markets. Other parties, including PG & E and the State of California, joined the complaint.

On August 23, 2000, FERC issued an order denying the relief requested by SDG & E, but determining that it was appropriate to investigate the justness and reasonableness of the rates for all sales in the CalPX and Cal-ISO markets. San Diego Gas & Elec. Co., et al., 92 FERC ¶ 61,172 (2000) (“August 23, 2000 Order”). Therefore, it established its own investigatory proceeding in FERC Docket Nos. EL-00-95 and EL00-98 (“the Remedy Proceedings”). The August 23, 2000 Order established October 29, 2000 as the refund effective date, which was determined by calculating the date sixty days after publication of notice of the order in the Federal Register. Id. at 61,608 .

On November 1, 2000, FERC issued an order proposing structural changes to the operation of the CalPX and Cal-ISO markets. San Diego Gas & Elec. Co., et al., 93 FERC ¶ 61,121 (2000) (“November 1, 2000 Order”). In the November 1, 2000 Order, FERC concluded that:

Id. at 61,349 .

FERC concluded that there was “clear evidence” that sellers could “exercise market power when supply is tight” and produce “unjust and unreasonable rates” for wholesale power sales. Id. at 61,349-50 .

The November 1, 2000 Order proposed, effective sixty days after the date of the order, to (1) eliminate the requirement that the investor-owned utilities buy and sell power exclusively through the CalPX; (2) require market participants to schedule 95 percent of their transactions in the day-ahead market or be subject to a penalty charge; (3) replace the existing CalPX and Cal-ISO stakeholder boards with independent non-stakeholder boards; and (4) require the filing of generator interconnection procedures.

In addition to ordering structural and rule changes, FERC ordered an evidentia-ry healing to determine the appropriate refund. At the behest of the California Parties, FERC changed the refund effective date from October 29, 2000 to October 2, 2000, based on the filing of the SDG & E’complaint. FERC also limited the refund to Cal-ISO and CalPX spot market transactions completed during the period from October 2, 2000 through June 20, 2001 (hereinafter referred to as the “Refund Period”).

Emergency conditions continued following the issuance of the November 1, 2000 Order, requiring Cal-ISO to serve increasingly larger portions of its load through the real time imbalance energy market and depleting Cal-ISO’s operating reserves. As a result, Cal-ISO proposed changes to its tariff, which FERC approved in an order dated December 8, 2000. Cal. Indep. Operator Corp., et al., 93 FERC ¶ 61,239 (2000).

One provision of this order lifted the Cal-ISO price caps, with the goal of attracting more supply into the auction markets. On December 15, 2000, FERC issued an order substantially adopting the remedies proposed in the November 1, 2000 Order. San Diego Gas & Elec. Co., et al., 93 FERC ¶ 61,294 (2000) (“December 15, 2000 Order”). The December 15, 2000 Order attempted to reduce the reliance on spot markets by terminating CalPX’s wholesale rate schedules, thereby eliminating the requirement that the investor-owned utilities buy and sell all generation through CalPX. CalPX sought a writ of mandamus from our Court challenging the December 15, 2000 Order’s prohibition of the investor-owned utilities’ selling power on a voluntary basis in the CalPX market and the termination of the wholesale tariff. The City of San Diego also challenged the December 15, 2000 Order by writ of mandate, arguing that FERC had unreasonably delayed taking action on the purchasers’ requests for refunds. We denied those petitions on April 11, 2001. In re Cal. Power Exch. Corp., 245 F.3d 1110 (9th Cir.2001).

On December 26, 2000, Edison filed a suit against FERC, alleging that it had failed in its responsibility to ensure that wholesale electricity was sold at reasonable rates.

The CalPX market began to collapse and the investor-owned utilities were fast becoming insolvent. On January 17, 2001, the Governor of California declared a State of Emergency and ordered the California Department of Water Resources to purchase energy on behalf of California consumers to halt the rolling blackouts. Sub sequently, the California legislature on February 1, 2001 enacted Assembly Bill 1 of the 2001-2002 First Extraordinary Session authorizing the Department of Water Resources to purchase power until December 31, 2002. Cal. Water Code § 80000 , et. seq.

Following the Governor’s declaration, CERS began buying power on January 18, 2001. Energy sellers began refusing to sell to Cal-ISO, and instead sold directly to the investor-owned utilities and CERS through bilateral contracts. Most sales after January 18, 2001 were made directly to CERS, rather than through CalPX or Cal-ISO. CalPX ceased market operations on January 30, 2001 and filed for protection under Chapter 11 of the Bankruptcy Code on March 9, 2001. The California Parties allege that from January 18, 2001 to June 18, 2001, CERS purchased more than $5 billion of energy in the spot market.

On March 1, 2001, the California Electricity Oversight Board (“Cal-EOB”) filed a motion with FERC, asking FERC to clarify that the Remedy Proceedings included CERS transactions outside of the CalPX and Cal-ISO markets. The Cal-EOB contended that the sellers that had manipulated the markets were now charging the same or higher rates for the CERS sales.

On March 9, FERC issued an order establishing a provisional formula governing refunds during the January 2001 period. San Diego Gas & Elec. Co., et al., 94 FERC ¶ 61,245 (2000) (“March 9, 2001 Order”). The order directed wholesale sellers to provide refunds or, alternatively, to justify their charges and costs for transactions made during power emergencies that were above a rate it calculated as appropriate. FERC estimated that approximately $69 million in January 2001 electricity sales would be subject to refunds.

On April 6, 2001, PG & E filed a voluntary petition in bankruptcy pursuant to Chapter 11 of the Bankruptcy Code. Although Edison and SDG & E were in similar financial peril, they avoided bankruptcy filings through arrangements with creditors.

On April 26, 2001, FERC issued an order establishing a prospective mitigation and monitoring plan for wholesale prices through the real time markets operated by Cal-ISO. San Diego Gas & Elec. Co., et al., 95 FERC ¶ 61,115 (2001) (“April 26, 2001 Order”). The April 26, 2001 Order established a pricing mechanism for sales by California generators made to Cal-ISO when reserves fell below seven percent. The order also established conditions, including refund liability, for market-based rate authority with the goal of preventing anti-competitive bidding behavior in the real time Cal-ISO market.

On June 19, 2001, FERC issued an order reaffirming that “as a result of the seriously flawed electric market structure and rules for wholesale sales of electric energy in California, unjust and unreasonable rates were charged, and could continue to be charged during certain times and under certain conditions, unless certain targeted remedies were implemented.” June 19, 2001 Order, 95 FERC at ¶ 62557.

The June 19, 2001 Order imposed price caps on all spot market sales from June 20, 2001 through September 30, 2002, and imposed a “must-offer” obligation on generators to prevent them from withholding supply. The prospective price mitigation plan applied to all sellers that voluntarily sold power into the Cal-ISO and other designated spot markets, or that voluntarily used Cal-ISO’s or other interstate transmission facilities subject to FERC jurisdiction. According to the California Parties, the effect of the June 19 Order was to put an end to the rolling blackouts, catastrophically high prices, and near-continuous power emergencies.

On July 12, 2001, the Administrative Law Judge (“ALJ”) issued a report and recommendation to FERC regarding a refund methodology to govern sales during the Refund Period. San Diego Gas & Elec. Co., et al., 96 FERC ¶ 63,007 (2001). In response to the report and recommendation, FERC issued an order on July 25, 2001 in the Refund Proceedings establishing the framework for refunds of past sales in the spot markets operated by CalPX and Cal-ISO. San Diego Gas & Elec. Co. et al., 96 FERC ¶ 61,120 (2001) (“July 25, 2001 Order”). FERC ordered limited refunds for the rates it had determined to be unjust and unreasonable and established a mitigated market clearing price (“MMCP”) in an attempt to replicate what it believed to be the just and reasonable rates that an unmanipulated competitive energy market would have produced. Under the MMCP methodology, refunds were to be determined by the difference between the market clearing price, which was the price charged by all electricity suppliers at a given time, and the MMCP calculated for each hour of the Refund Period, subject to certain adjustments. FERC also ordered an evidentiary hearing to calculate the appropriate MMCPs for each hour of the Refund Period and the amount of refunds owed.

However, FERC declined to order refund relief for sales that occurred before the Refund Period, or for any sales outside of the CalPX and Cal-ISO markets. FERC also excluded transactions of more than twenty-four hours in length, even if those sales were made in the CalPX and Cal-ISO markets within the Refund Period. The California Parties contend that refunds for sales prior to the Refund Period would total $2.3 billion in seller overcharges; that refunds for emergency purchases made by CERS would total $3.5 billion in seller overcharges; and that other improperly excluded transactions would amount to over $200 million in seller overcharges.

On December 2, 2001, Enron Corporation filed a voluntary petition in bankruptcy under Chapter 11 of the United States Bankruptcy Code.

On December 19, 2001, FERC issued another order addressing mitigation of the California spot market prices and conditions. December 19, 2001 Order, 97 FERC ¶ 61,275 , et. seq. The order clarified that the price mitigation plans applied to all sales into the FERC-regulated spot markets and provided further explanation for why FERC chose October 2, 2000 as the refund effective date. FERC issued an order denying rehearing of the December 19, 2001 Order on May 15, 2002.

On February 13, 2002, FERC opened a non-public investigation (“FERC Enforcement Proceeding”) pursuant to 18 C.F.R. § lb.l et. seq. into seller market manipulation of the energy markets in the Western United States. Fact-Finding Investigation of Potential Manipulation of Elec. & Natural Gas Prices, 98 FERC ¶ 61,165 at 61,614 (2002). FERC noted that allegations had been made in the Enron bankruptcy that Enron had used its market position to distort electric and natural gas markets. FERC directed its staff to investigate “whether any entity, including Enron Corporation (through its affiliates or subsidiaries), manipulated short-term prices in electric energy or natural gas markets in the West or otherwise exercised undue influence over wholesale prices in the West, for the period January 1, 2000, forward.” Id.

In June 2002, some of the California Parties moved this Court for permission to present additional evidence of market ma nipulation in the Remedy Proceedings. FERC opposed the motion. On August 21, 2002, we directed FERC to allow the parties to present evidence of market manipulation in the Remedy Proceedings, to reconsider its earlier orders denying relief, and to provide to the Court supplemental findings of fact and any recommended modifications to FERC’s orders on the basis of such new evidence.

On March 20, 2002, the State of California, through its Attorney General, filed a complaint alleging that generators and marketers selling power into markets operated by CalPX and Cal-ISO, as well as those making spot market sales of energy to CERS, violated § 205 of the Federal Power Act by failing to comply with various filing requirements. The complaint also challenged FERC’s approval of market-based tariffs. On May 31, 2002, FERC dismissed the complaint as constituting a collateral attack on prior FERC orders and denied the complaint with respect to the allegations that FERC’s market-based rate filing requirements violated the Federal Power Act as a matter of law. State of California ex rel. Lockyer v. B.C. Power Exch., et al., 99 FERC ¶ 61,247 (2002) (“May 31, 2002 Order”). California filed a petition for review of the May 31, 2002 Order.

In December 2002, the ALJ determined that suppliers owed approximately $1.8 billion to Cal-ISO and CalPX for sales at rates in excess of a just and reasonable rate. San Diego Gas & Elec. Co., et al., 101 FERC ¶ 63,026 (2002). FERC adopted in part, and modified in part, the ALJ’s proposed findings in an order issued March 26, 2003 Order, 2003. San Diego Gas & Elec. Co., et al., 102 FERC ¶ 61,317 (2003) (“March 26, 2003 Order”).

In its March 26, 2003 Order, FERC stated that it would not alter any of its previous orders in the Remedy Proceedings concerning the time or transaction limitations in light of the evidence presented to the ALJ. This position was reaffirmed in subsequent FERC orders on October 16, 2003, which also clarified some refund calculation issues. San Diego Gas & Elec. Co., et al., 105 FERC ¶ 61,066 (2003); San Diego Gas & Elec. Co., et al., 105 FERC ¶ 61,065 (2003). Subsequently, FERC issued a number of orders pertaining to calculation of refunds during the Refund Period. San Diego Gas & Elec. Co., et al., 107 FERC ¶ 61,165 (2004); San Diego Gas & Elec. Co., et al., 107 FERC ¶ 61,166 (2004); San Diego Gas & Elec. Co., et al., 108 FERC ¶ 61,311 (2004), and San Diego Gas & Elec. Co., et al., 109 FERC ¶ 61,078 (2004), order on reh’g, 109 FERC ¶ 61,074 (2004).

On September 9, 2004, we granted in part California’s petition for review challenging the May 31, 2002 Order. State of California ex rel. Lockyer v. FERC, 383 F.3d 1006 (9th Cir.2004) (“Lockyer ”). We held that FERC’s decision to approve market-based tariffs in the wholesale electricity market did not violate the Federal Power Act. Id. at 1013 . We also held that FERC erred as a matter of law in concluding retroactive refunds were not available under § 205. Id. at 1015. We remanded the case to FERC for further proceedings.

Before us in the instant case are those portions of the petitions for review that involve the Scope/Transaction issues. We review FERC orders to determine whether they are “arbitrary, capricious, an abuse of discretion, unsupported by substantial evidence, or not in accordance with law.” Cal. Dep’t of Water Res. v. FERC, 341 F.3d 906 , 910 (9th Cir.2003). FERC’s factual findings are conclusive if supported by substantial evidence. 16 U.S.C. § 825 l (b); Bear Lake Watch, Inc. v. FERC, 324 F.3d 1071 , 1076 (9th Cir.2003). Substantial evidence “means such relevant evi dence as a reasonable mind might accept as adequate to support a conclusion.” Id. (quoting Eichler v. SEC, 757 F.2d 1066, 1069 (9th Cir.1985)). “If the evidence is susceptible of more than one rational interpretation, we must uphold [FERC’s] findings.” Id. We review questions of law de novo. Am. Rivers v. FERC, 201 F.3d 1186, 1194 (9th Cir.1999). We review FERC’s interpretation of the FPA under the familiar analysis established in Chevron U.S.A., Inc. v. Natural Res. Def. Council, 467 U.S. 837, 842 , 104 S.Ct. 2778 , 81 L.Ed.2d 694 (1984) and its progeny. Bonneville Power Admin., 422 F.3d at 914 .

Ill

Temporal Scope of Refunds

Under § 206(a) of the Federal Power Act, FERC may investigate whether a particular rate or charge is “just and reasonable.” 16 U.S.C. § 824d(a). If FERC finds a rate unreasonable, it must order the imposition of a just and reasonable rate. Id. § 824d(d). FERC may then order refunds for any period subsequent to the “refund effective date,” a date FERC establishes that must be at least sixty days after the filing of the complaint. Id. § 824e(b). Under the express language of § 206, however, FERC may not order refunds for any period prior to the filing of the complaint. Id. Section 309 of the Federal Power Act, on the other hand, gives FERC authority to order refunds if it finds violations of the filed tariff and imposes no temporal limitations. Consol. Edison v. FERC, 347 F.3d 964, 967 (D.C.Cir.2003); 16 U.S.C. § 825h.

In its August 23, 2000 Order, FERC established October 29, 2000 as the refund effective date pursuant to § 206. In its November 1, 2000 Order, FERC modified the refund effective date to October 2, 2000. The Competitive Suppliers Group argues that October 29, 2000 was the proper refund effective date. The California Parties do not dispute FERC’s establishment of October 2, 2000 as the refund effective date for the § 206 proceedings, but argue that FERC arbitrarily and capriciously refused to order refunds for tariff violations under § 309 for periods prior to October 2, 2000.

A

We conclude that FERC’s order establishing October 2, 2000 as the refund effective date for the § 206 Refund Proceedings was not arbitrary or capricious, an abuse of discretion, unsupported by substantial evidence, or not in accordance with law.

SDG & E filed its initial § 206 complaint on August 2, 2000. In its response to SDG & E’s filing, FERC, in its August 23, 2000 Order, announced that it would commence its own investigation and set the refund effective date sixty days after FERC published an announcement of the investigation. The notice was published August 29, 2000; therefore, the refund effective date was set as October 29, 2000.

On September 22, 2000, some of the California Parties, notably PG & E and Edison, requested that FERC establish an earlier refund date based on the filing of the SDG & E complaint, rather than on FERC’s commencement of the Enforcement Proceedings. Given SDG & E’s August 2, 2000 filing date, the earliest possible refund effective date was October 2, 2000. In the November 1, 2000 Order, FERC granted the request and reset the refund effective date to October 2, 2000.

Thus, the question at issue here is whether FERC properly tethered the refund effective date to the SDG & E complaint. Although FERC denied the remedy sought by SDG & E in its complaint, it did not dismiss the SDG & E complaint; rather, it consolidated the SDG & E complaint with its own investigation “for purposes of hearing and decision in view of their common issues of law and fact.” December 19, 2001 Order, 97 FERC ¶ 61,275 at 62,198. Despite consolidation, FERC made it clear that the August 23, 2000 Order “established two separate, but related, investigations.” Id. at 62,197 . According to FERC, the investigation into the “justness and reasonableness of sellers’ rates in the ISO and PX markets” that resulted in the refund order grew out of SDG & E’s complaint. Id.

In addition, FERC noted that its policy “is to establish the earliest refund effective date allowed in order to give maximum protection to consumers.” Id. at 62,198 . This interpretation is consistent with FERC’s “primary purpose” in “protecting consumers.” Lockyer, 383 F.3d at 1017 .

The Competitive Suppliers Group argues that the SDG & E complaint cannot form the basis for establishing the refund effective date because SDG & E did not seek refunds pursuant to § 206 in its complaint, and third-party FERC complaints must specify relief sought. To be sure, § 206(a) requires third-party complaints to FERC to “state the change or changes to be made in the rate, charge, classification, rule, regulation, practice, or contract then in force.... ” 16 U.S.C. § 824e(a). It is also quite true that SDG & E did not seek a refund remedy in its initial complaint. SDG & E’s complaint sought an emergency order capping prices in the CalPX and Cal-ISO markets and a ruling enforcing the cap through limitations on market-based authorizations.

However, the relief sought in the initial complaint is not dispositive of this issue. The key question is whether the SDG & E complaint afforded sufficient notice to alert market participants that sales and purchases might be subject to refund. The gravamen of the SDG & E complaint was that the rates charges by sellers were unjust and unreasonable. As FERC points out, a complaint challenging the reasonableness of the rates can lead to a refund under § 206, even if a refund remedy is not specifically designated in the initial complaint. FERC is empowered to investigate the reasonableness of a rate either in the context of a third-party complaint or sua sponte. Indeed, as we have noted, the Federal Power Act requires FERC to establish a refund effective date whenever it institutes a § 206 investigation. 16 U.S.C. § 824e(b).

Further, some of the California Parties promptly sought rehearing of FERC’s initial determination of the refund effective date in its August 23, 2000 Order. In short, market participants were quickly apprised that the original refund effective date might be subject to revision. As FERC noted: “Requests for rehearing of the August 23 Order raising the refund effective date issue were timely filed. Thus, any reliance by sellers on the October 29 refund effective date prior to the issuance of a final order was at their own risk.” December 19, 2001 Order, 97 FERC ¶ 61,275 at 62,198. Therefore, because SDG & E’s § 206 complaint unquestionably could have led to a FERC refund order, because the original FERC order establishing the refund effective date was not final, and because rehearing petitions were timely filed challenging the refund effective date, SDG & E’s filing of its complaint provided sufficient notice to the market to satisfy § 206.

The fact that two investigations were initiated by FERC does not alter this conclusion. The investigation initiated by SDG & E’s complaint focused on whether the sellers’ rates in the CalPX and Cal-ISO markets were just and reasonable; the separate FERC investigation focused on whether the CalPX and Cal-ISO market rules and institutional factors required modification. As FERC noted in its August 23, 2000 Order:

92 FERC ¶ 61,172 at 61,606.

In short, FERC launched a § 206 investigation into the justness and reasonableness of the rates pursuant to the SDG & E complaint and initiated its own investigation into the CalPX and Cal-ISO tariffs and agreements to determine whether market rules required modification. The Competitive Suppliers Group argues that the § 206 investigation became subsumed into the market investigation. However, this contention contradicts the plain language employed by FERC when it established the two investigations and the subsequent treatment of the investigations in later FERC orders. No substantive consolidation was ever ordered. Even if the cases had been substantively consolidated, consolidation would not necessarily eviscerate a validly established refund effective date based on the original SDG & E complaint. Refunds were eventually ordered as a direct result of the SDG & E complaint. Given all these considerations, we conclude that FERC did not act arbitrarily or capriciously, abuse its discretion, or act in violation of law in setting the refund effective date based on the SDG & E complaint.

B

FERC’s authority to order refunds for filed rates that are later determined to be unjust, unreasonable, or discriminatory derives from §§ 205 and 206 of the Federal Power Act. FERC also has remedial authority to require that entities violating the Federal Power Act pay restitution for profits gained as a result of a statutory or tariff violation. Consol. Edison, 347 F.3d at 967 ; Towns of Concord, Norwood & Wellesley v. FERC, 955 F.2d 67 (D.C.Cir.1992), S. Cal. Edison Co. v. FERC, 805 F.2d 1068, 1071-72 (D.C.Cir.1986). This authority derives from § 309 of the Federal Power Act, which authorizes FERC “to perform any and all acts, and to prescribe, issue, make, amend, and rescind such orders, rules, and regulations as it may find necessary or appropriate to carry out the provisions of this Act.” 16 U.S.C. § 825h. Unlike refund proceedings commenced under § 206, no time limits apply to remedial actions filed pursuant to § 309.

In its July 25, 2001 Order, FERC declined to award any relief pursuant to § 309. The California Parties sought review of that decision. We granted the California Parties’ motion for an order requiring FERC to entertain further evidence of market manipulation and tariff violation and to reconsider its orders limiting remedies. After receiving further evidence, FERC ruled that it would not consider further remedies. March 26, 2003 Order, 102 FERC ¶ 61,317 at 62,083. The California Parties petition for review of FERC’s refusal to consider § 309 remedies.

We conclude that FERC’s decision not to consider a § 309 remedy for tariff violations was arbitrary and capricious, an abuse of discretion, and not in accordance with law. On appellate review, FERC “must be able to demonstrate that it has made a reasoned decision based upon substantial evidence in the record.” N. States Power Co. v. FERC, 30 F.3d 177 , 180 (D.C.Cir.1994) (internal quotations omitted). FERC must “articulate a satisfactory explanation for its action including a rational connection between the facts found and the choice made.” Motor Vehicle Mfrs. Assn. of the U.S., Inc. v. State Farm Mut. Ins. Co., 463 U.S. 29, 43 , 103 S.Ct. 2856 , 77 L.Ed.2d 443 (1983).

In this case, FERC offers several rationales for refusing to grant tariff relief. First, it claims that § 206 precludes refunds prior to the refund effective date. Second, it contends that no tariff violations occurred. Third, it argues that it need not provide remedies to the California Parties because it has commenced prosecutorial investigations into the question of whether tariff violations occurred, and those investigations may result in remedies which would make the market whole. None of these justifications is sufficient to sustain FERC’s decision under the applicable standard of review.

First, FERC’s claim that it is precluded from ordering pre-Refund Period relief under § 206 may be quickly dispatched. The relief sought by the California Parties in this part of the proceeding is based on § 309, not § 206. Although the § 206 proceedings seeking refunds because of unjust and unreasonable rates are limited to the Refund Period, § 309 proceedings based on tariff violations are not. FERC’s apparent conclusion that the time limits applicable to § 206 proceedings also apply to § 309 proceeding is incorrect as a matter of law. Indeed, FERC emphasized as much in its own filings in the investigatory proceedings:

Enron Power Mktg., Inc., 103 FERC ¶ 61,346 at 62,351 (2003). To the extent that FERC is claiming that the § 206 time limits apply to § 309 proceedings, FERC is wrong.

Second, FERC alleges there were no tariff violations, contending that “there is no basis for finding that the sellers acted inconsistently with Commission-filed tariffs or with specific requirements in their filed rate authorizations.” July 25, 2001 Order, 96 FERC at 61,508. This conclusion is flatly inconsistent with FERC’s commencement of the FERC Enforcement Proceeding, which was initiated to investigate and prosecute tariff violations. It contradicts the conclusion of FERC staff, accepted by FERC, that bid prices in the pre-Refund Period were “excessively elevated solely for the purpose of raising prices” in violation of the Cal-ISO and CalPX rules. Investigation of Anomalous Bidding Behavior and Practices in the Western Markets, 103 FERC ¶ 61,347 at 62,360 (2003). FERC concluded that “the remedy for these tariff violations, if found to exist, would be the disgorgement of any unjust profits attributable to these tariff violations.” Id. at 62,359 .

FERC’s assertion in this proceeding that there were no tariff violations prior to the Refund Period is contravened by its own findings in American Electric Power Service Corp., to wit:

103 FERC ¶ 61,345 at 62,328 (2003). See also Enron Power Mktg., Inc., 103 FERC ¶ 61,346 .

In addition to FERC’s own conclusions, the California Parties also presented significant evidence of pervasive tariff violations during the pre-Refund Period. In sum, there is no support for FERC’s second rationale for denying the California Parties’ request for pre-Refund Period relief.

FERC’s third stated reason for denying the request is that it is pursuing tariff violations in the separate FERC Enforcement Proceeding. Obviously, this rationale contradict’s FERC’s second rationale — that no tariff violations exist. This reason for rejecting the California Parties’ request for § 309 relief is also unsupportable.

In explaining its third reason for denying the request, FERC describes at length its broad investigatory and prosecutorial authority under § 307(a) ( 16 U.S.C. § 825 (f)) and § 309 (16 U.S.C. § 825h). However, no one disputes this authority. What FERC fails to explain, or support, is how its inherent authority to commence investigations and enforcement proceedings under 18 C.F.R. § lb.l et. seq. precludes a civil proceeding instituted by third party complaint.

The two types of proceedings are quite distinct. One is investigative and prosecu-torial; the other is a contested proceeding. FERC enjoys broad discretion in the management of its own § lb prosecutorial investigations. FERC “[investigations may be formal or preliminary, and public or private.” 18 C.F.R. § lb.4. In contrast to an adjudicated, contested proceeding, in a § lb proceeding, FERC may settle claims without review, and need not justify its decision to order refunds, or to decline to order refunds.

Because § lb investigations are prosecu-torial in nature, third parties do not participate. 18 C.F.R. § lb.ll. For example, in this case FERC denied the California Parties’ motion to intervene in the FERC Enforcement Proceeding, explaining:

Fact-Finding Investigation of Potential Market Manipulation of Elec. & Natural Gas Prices, 105 FERC ¶ 61,063 at 61,352 (2003)

Commissioner Massey dissented from this decision, writing:

Id. at 61,353 .

At various times, FERC has stated that it reserves the right to impose market-wide inquiries in the FERC Enforcement Proceedings; however, in these proceedings to date, it has only pursued “company-specific” investigations into the actions of various market participants, rather than conducting a market-wide inquiry. San Diego Gas & Elec. Co., et al., 105 FERC ¶ 61,066 at. 61,385. FERC itself casts its company-specific approach as supplemental to the adjudicative refund proceedings undertaken pursuant to § 206. See, e.g., San Diego Gas & Elec. Co., et al., 105 FERC ¶ 61,066 at 61,391 (“Any such company-specific disgorgement or other appropriate remedies would be in addition to the refunds associated with the mitigated market clearing prices developed pursuant to this order and could apply to conduct both prior to the Refund Period and during the Refund Period.”); 102 FERC ¶ 61,108 at 61,289 (2003) (“The payment to be made by Reliant will be in addition to any refund ultimately owed by Reliant as part of the refund proceeding in Docket No. EL00-95, et al.”).

In contrast, the California Parties seek a market-wide refund remedy for tariff violations pursuant to § 309 through its adjudicative filing. The fact that FERC may be seeking similar remedies against specific companies in its § lb investigations does not justify its denial of the California Parties’ request for § 309 relief. When parties seek adjudicative relief from an agency, they are entitled to a reasoned response from the agency. Here, the California Parties filed a cognizable request for relief and tendered credible evidence in support of their request. A party’s valid request for relief cannot be denied purely on the basis that the agency is considering its own enforcement action that may impart a portion of the relief sought. If an aggrieved party tenders sufficient evidence that tariffs have been violated, then it is entitled to have FERC adjudicate whether the tariff has been violated and what relief is appropriate.

In sum, none of the reasons given by FERC for refusing to adjudicate whether tariffs were violated is sustainable. Sec tion 309 relief is not limited by § 206. FERC’s determination that no tariff violations occurred is not supported by the record. FERC cannot avoid adjudicating a third-party petition because it may or may not choose to commence a separate enforcement action. For these reasons, we conclude that FERC’s categorical rejection of the California Parties’ request for § 309 relief was arbitrary, capricious, and an abuse of discretion. Therefore, we grant the petition for review as it pertains to the California Parties’ challenge to FERC’s foreclosure of relief for tariff violations. We deny the California Parties’ petition insofar as it calls for us to decide the merits of its request for § 309 relief. We do not prejudge how FERC should address the merits or fashion a remedy if appropriate. FERC cannot, however, categorically refuse to entertain the application; it must address the merits.

IV

Out of Market Spot Transactions

FERC’s July 25, 2001 Order mandated retrospective relief for sales to Cal-ISO, including out-of-market (“OOM”) transactions. These purchases were made by Cal-ISO from sellers outside the Cal-ISO single price auction market within 24 hours or less of delivery, and served to stabilize the grid when supply was insufficient to meet demand. Because Cal-ISO had no choice but to buy energy to ensure grid reliability, potential sellers were in a position to exercise improper market leverage by exploiting the structural flaws in the market. FERC concluded that the OOM transactions provided the best opportunity for extracting unjust and unreasonable rates and therefore, made them subject to potential refunds.

The Competitive Suppliers Group petitions for review of FERC’s decision to include OOM sales into the Cal-ISO because (1) FERC made no express finding that the rates charged for OOM sales were unjust and unreasonable and (2) the Remedy Proceedings had been limited since their inception to the Cal-ISO/CalPX single-price auction market. We deny this petition for review.

A

Section 206(a) of the Federal Power Act requires that before FERC can exercise its remedial power to mitigate an existing rate, it must find an existing rate “unjust, unreasonable, unduly discriminatory or preferential.” 16 U.S.C. § 824e(a); Fed. Power Comm’n v. Sierra Pac. Power Co., 350 U.S. 348, 353 , 76 S.Ct. 368 , 100 L.Ed. 388 (1956). The Competitive Suppliers Group argues that although FERC made a finding that prices within the auction markets were unjust and unreasonable, they never made such a finding with respect to OOM sales to Cal-ISO.

In its July 25, 2001 Order, FERC adopted the MMCP to calculate just and reasonable rates for Cal-ISO and CalPX. The MMCP was the benchmark for determining the amount of refunds that sellers had to pay — FERC simply looked at their transactions during the refund period then ordered them to pay the difference between the rate and the MMCP.

Application of the MMCP was a determination that a rate was unjust and unreasonable. As FERC explains in its brief,

FERC Br., citing July 21, 2001 Order.

FERC’s analysis of this issue is correct. The Federal Power Act does not require the detailed individualized finding that Competitive Suppliers Group requests, nor does it require a showing of market power abuses, and no court has held that it does.

FERC found that there was systemic dysfunction in the wholesale energy market and that, during the time that Cal-ISO was making OOM purchases, it was in an emergency must-buy situation, which gave the sellers even greater market power, and thus increased the likelihood that the rates were unjust and unreasonable. These facts constituted a sufficient finding that the rates were unjust and unreasonable. FERC was not required to make an additional individualized finding, in addition to the imposition of the MMCP, that rates for Cal-ISO OOM transactions were unjust and unreasonable.

B

Contrary to the Competitive Suppliers Group’s argument, the Remedy Proceedings were not limited to the Cal-ISO and CalPX single-price auction markets. First, nothing in the language of the August 2, 2000 complaint or early orders necessarily limited the Remedy Proceedings to the Cal-ISO and CalPX in-market transactions. Indeed, the SDG & E complaint was “directed against all sellers in the ISO and PX markets.” FERC did not add the Cal-ISO OOM transactions to the proceeding. Rather, it clarified in its orders that the transactions were encompassed in the scope of the SDG & E complaint proceeding.

Second, FERC offered a sufficient explanation as to why the Cal-ISO OOM transactions were subject to refunds, namely that the purchases, like in-market purchases, were made to “procure the resources necessary to reliably operate the grid.” July 25, 2001 Order, 96 FERC ¶ 61,120 at 61,515. Therefore, there was no meaningful distinction to be drawn between the in— and out-of-market transactions. FERC further noted that the Cal-ISO OOM transactions were contemplated in the Cal-ISO tariff as a backstop to the Cal-ISO auction market.

The Competitive Suppliers Group points out that OOM transactions made by Cal-ISO are fundamentally different from those made in the Cal-ISO market. Certainly, there are significant differences. The OOM transactions at issue here were bilaterally negotiated sales of power at different prices than the market clearing price established in the auction market. However, as FERC points out, these bilateral transactions were closely intertwined with the Cal-ISO single price auction spot market because manipulation of the single price auction market could create artificial market forces, making it probable that rates charged in the OOM transactions were unjust and unreasonable. Although different in form, both the single price auction purchases and Cal-ISO OOM purchases occurred in the same market, so the structural flaws that allowed unjust and unreasonable prices to be charged in the single-price auction also allowed unjust and unreasonable prices to be charged in the Cal-ISO OOM transactions. Given this structural relationship, it was reasonable for FERC to examine those Cal-ISO OOM transactions that were affected by the manipulated market conditions and order refunds when appropriate.

It is also significant to note that FERC did not order refunds for all Cal-ISO OOM transactions. Rather, FERC ordered all Cal-ISO OOM spot transactions to be examined to decide which ones would be subject to potential refund. An agency’s discretion is at its zenith when it is “fashioning [] policies, remedies and sanctions, including enforcement and voluntary compliance programs in order to arrive at maximum effectuation of Congressional objectives.” Niagara Mohawk Power Corp. v. Fed. Power Comm’n, 379 F.2d 153, 159 (D.C.Cir.1967). Given this level of deference, coupled with FERC’s reasoned explanation of its decision, we conclude that FERC did not act arbitrarily, capriciously, or in abuse of its discretion when it included the Cal-ISO OOM transactions in the Remedy Proceedings.

V

Non-Emergency Hours Transactions

A

In its initial mitigation orders, FERC limited price mitigation only to “emergency hours” when supply was deficient and suppliers knew that their bids, however high, would be accepted. June 19, 2001 Order, 95 FERC ¶ 61,418 at 62,546-62,547. FERC believed that during hours when there were sufficient energy reserves to ensure that the Cal-ISO controlled grid would remain reliable, called “non-emergency hours,” suppliers would be motivated to bid competitive prices. FERC reasoned that with excess supplies in the market, suppliers would bid competitively because they ran the risk that their bids would not be accepted. See id. at 62,547 .

Over time, however, FERC observed that because energy supply was generally low, suppliers could count on their bids being accepted in both emergency and non-emergency hours. So, the incentive to bid high prices was as evident during non-emergency hours as it was during emergency hours. See December 19, 2001 Order, 97 FERC ¶ 61,275 at 62,247 (“[During non-emergency periods where there were no excess supplies in the market and all suppliers would be dispatched, the incentive to bid high prices remained.”). Although FERC’s targeted remedies had improved the wholesale power market to some extent, see June 19, 2001 Order, 95 FERC ¶ 61,418 at 62,546, the market remained generally dysfunctional, id. at ¶ 62,556 .

Thus, in an attempt to provide “the incentives needed to correct the [remaining] market dysfunctions,” FERC expanded the market monitoring and mitigation plan to address all operating hours. Id. at ¶ 62,547 . FERC implemented prospective relief for non-emergency hours by modifying the formula it had used to set the market clearing price in emergency hours. Id. at ¶ 62,558 . Recognizing that rates should decrease in non-emergency hours due to an increase in supply, FERC set the market clearing price for non-emergency hours at 85 percent of the market clearing price established during the last system emergency. Id. at ¶ 62,548 . FERC would permit a higher bid only if justified by the supplier. Id. at ¶ 62,558 . FERC’s intention was to “emulate ... a competitive market,” and “prevent possible abuses that could lead to unjust and unreasonable rates.” Id. at 62,558 .

In its July 25, 2001 Order, FERC declined to order refunds because it felt that an evidentiary hearing was necessary to resolve “material issues of fact” before deciding whether to order a refund. July 25, 2001 Order, 96 FERC ¶ 61,120 at 61,519- 61,520. FERC ordered Cal-ISO to apply the MMCP to each operating hour and report the data to an ALJ. Id. at ¶ 61,520 . FERC then directed the ALJ to

Id.

FERC explained that its decision to review rates in all operating hours was based on its original finding of systemic market dysfunction, which “was not limited to reserve deficiency periods.” December 19, 2001 Order, 97 FERC ¶ 61,275 at 62,246. Referencing the finding in its November 1, 2000 Order that the market was structurally flawed, FERC stated: “We determined that structural problems, which existed in all hours, had the potential to cause market prices to exceed that which one would expect in a competitive market. While our solution requires review for all hours, that does not mean that this will result in refunds for all hours.” Id.

The Competitive Suppliers Group petitions for review of FERC’s decision to apply the MMCP to non-emergency operating hours. It argues that FERC’s decision to order mitigation for non-emergency hours was arbitrary and capricious because FERC did not expressly find that rates during non-emergency hours were unjust and unreasonable.

B

As we have noted, before FERC can exercise its remedial powers under FPA § 206, it must find that the rate at issue is unjust and unreasonable. 16 U.S.C. 824e(a). The Competitive Suppliers Group attacks the adequacy of FERC’s general finding of systemic market dysfunction, arguing that it did not satisfy the condition precedent to § 206(a) authority.

The Competitive Suppliers Group claims that FERC was required to make explicit findings that specific rates charged in each operating hour were unjust or unreasonable. However, as we have noted, no such requirement exists. FERC “may rely on ‘generic’ or ‘general’ findings of a systemic problem to support imposition of an industry-wide solution.” Interstate Natural Gas Ass’n of Am. v. FERC, 285 F.3d 18, 37 (D.C.Cir.2002). “[P]roportionality between the identified problem and the remedy is the key.” Id.

To be sure, if FERC found isolated problems within the wholesale electric energy market, its market-wide remedy would have been inappropriate. See Assoc. Gas Distribs. v. FERC, 824 F.2d 981 , 1019 (D.C.Cir.1987) (“Neither Wisconsin Gas nor any other case of which we are aware supports 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.”). However, faced with a market plagued by structural problems and operating under “seriously flawed” rules, FERC could have reasonably considered a market-wide remedy necessary.

FERC’s response was proportional to the identified problem: It ordered wholesale review of a market that it had identified as wholly dysfunctional. Moreover, the method FERC used to review the system resulted in an individualized analysis of the rates charged in each operating hour. FERC explained that its expansion of mitigation measures over time was a reflection of both the “rapidly changing circumstances” during the refund period and its attempt to balance competing interests while fulfilling its FPA obligations:

December 19, 2001 Order, 97 FERC ¶ 61 ,-275 at 62,246.

Given all of these considerations, we cannot say that FERC’s decision to include non-emergency hours transactions in its market mitigation orders was arbitrary, capricious, or an abuse of discretion.

VI

Spot Market Limitation (24-Hour Limit)

A

In it July 25, 2001 Order, FERC restricted the refund proceedings to “spot transactions in the organized markets operated by the ISO and PX during the [Refund Period].” July 25, 2001 Order, 96 FERC ¶ 61,120 at 61,499. In its June 19 Order, it defined the spot market at issue as constituting “sales that are 24 hours or less and that are entered into the day of or day prior to delivery.” June 19, 2001 Order, 95 FERC ¶ 61,418 at 62,545. By these two orders, FERC excluded sales made in the Cal-ISO and CalPX spot markets of greater than 24 hours. Although this limitation was made without explanation, it apparently was based on FERC’s construction of the original SDG & E complaint. The California Parties petition for review of this limitation.

In order to analyze this issue properly, a brief procedural review is appropriate. In the original complaint, SDG & E asked FERC to put a price cap on all sales into the Cal-ISO and CalPX markets and urged FERC to enter into a “full examination of the reasons why the ISO/PX markets are not workably competitive.” In its August 23, 2000 Order, FERC instituted hearing proceedings to “detect and ... to resolve as expeditiously as possible, any defects in the operation of competitive power markets in California.” 92 FERC ¶ 61,172 at 61,603.

Although FERC mentioned the “spot market” in the body of its August 23 order, it did not explicitly define spot transactions or limit its investigation to transactions of a certain length. See id. at 61,605, 61,607 . FERC did inform interested parties that it may “further refine” or “narrow the focus” of the hearing after it reviewed its own staffs investigative findings. See id. at 61,603, 61,609 .

On November 1, 2000, after FERC’s staff issued its findings, FERC issued an order identifying serious market flaws that had caused and “ha[d] the potential to cause, unjust and unreasonable rates for short-term energy (Day-Ahead, Day-of, Ancillary Services and real-time energy sales) under certain conditions.” November 1, 2000 Order, 93 FERC ¶ 61,121 at 61,349. FERC proposed remedies designed to “facilitate forward contracting” and discourage an “over reliance on spot markets.” Id. at 61,359 .

On December 15, 2000, FERC again stressed that high prices were mostly due to over-reliance on short-term contracts, and encouraged market participants to acquire both short-term and long-term contracts. December 15, 2000 Order, 93 FERC ¶ 61,294 at 61,993-61,994. Although market participants expressed concerns that long-term contracts would be affected by the “spiraling spot prices” from the previous summer, FERC assured them that it would “monitor prices in [long-term] markets and also adopt a benchmark that we will use as a reference point in addressing any complaints regarding the pricing of long-term contracts negotiated over the next year.” Id. at ¶ 61 ,-994.

FERC first explicitly limited refunds to spot markets in its July 25, 2001 Order, stating, “[t]he Commission makes clear that transactions subject to refund are limited to spot transactions in the organized markets operated by the ISO and PX during the [refund period].” July 25, 2001 Order, 96 FERC ¶ 61,120 at 61,499. FERC used the same description for “spot market” as it had in its June 19 order. Id. at ¶ 61,515-61,516 .

In contesting this limitation, the California Parties offered testimony from economist Dr. Peter Fox-Penner and Director of Market Monitoring and Analysis for Southern California Edison Dr. Gary A. Stern to support their claim that sellers manipulated both short-term energy markets and forward markets and succeeded in raising rates above just and reasonable levels in both. Dr. Fox-Penner testified that sellers had purposefully manipulated short-term energy markets to cause an increase in forward rates by withholding supply from the short-term market, forcing Cal-ISO to buy necessary energy outside of the spot market at higher prices and for longer contract periods. Dr. Stern testified that if the MMCP mitigation method were applied to Cal-ISO’s forward contracts, refunds would exceed $54.5 million.

Despite this testimony, FERC continued to limit refunds to “spot market” transactions as described in its June 19, 2001 order. See March 26, 2003 Order, 102 FERC ¶ 61,317 at 62,084. The California Parties requested rehearing of FERC’s decision, arguing that after they had submitted additional evidence showing that the sellers’ insistence on longer duration sales was often an element of the exercise of market power, and that FERC should have reconsidered its decision to exclude forward contracts from the monitoring and mitigation plan. The California Parties argued that FERC should include in the Remedy Proceedings all sales up to one month in duration. FERC responded on October 16, 2003, by rejecting the California Parties’ arguments as being “identical to those they have already raised,” and stating that it had “already thoroughly considered and rejected” the same arguments. San Diego Gas Elec. Co., et al., 105 FERC ¶ 61,066 , 61,365 (2003).

B

FERC’s primary reason for excluding the forward market transactions is that, in its view, these transactions were not included in the original SDG & E complaint. It notes that its § 206 refund authority “is discretionary and limited to those rates challenged as the subject of a proceeding.” Thus, FERC argues that it was prevented from mitigating forward transactions because the original complaint limited the scope of the proceeding to only “spot market” transactions.

The record does not support FERC’s conclusion. The original complaint explicitly referred to both short-term and forward sales in the Cal-ISO and CalPX markets. SDG & E expressed concern about the “day-ahead, hour-ahead, and block forward markets conducted by the PX.” The complaint clearly challenged rates for forward transactions, asserting that “until workable competition is established, supply bids into the California forward and real-time markets should be capped at $250 per Mwh.” (emphasis added). The complaint logically did not reference sales outside the ISO and PX’s formal markets because SDG & E was, at that time, required to purchase energy through the formal spot markets. However, within that limitation, SDG & E cast as wide a net as possible, including challenging those forward transactions it was allowed to enter. The original complaint did not limit FERC’s section 206 refund authority to only “spot market” transactions. Thus, the primary reason given by FERC for excluding the transactions is without adequate foundation in the record.

FERC does not offer any other justification for excluding the transactions. Significantly, even in the face of new evidence concerning forward markets, FERC simply reiterated that the issue was outside the scope of the original complaint. FERC’s failure to even address the additional evidence is another reason that we reject its exclusion of these transactions.

FERC initially thought spot prices would discipline forward prices, and that more forward contracting was the answer to the market dysfunction. Thus, early in the Remedy Proceedings, FERC focused its mitigation measures on short-term sales and actually encouraged market participants to acquire more forward contracts. See December 15, 2000 Order, 93 FERC ¶ 61,294 at 61,993-61,994. However, later evidence suggested that forward prices had not been reigned in by FERC’s mitigation of the spot markets, and that sellers had successfully manipulated forward markets to raise prices.

In denying rehearing of its continued exclusion of forward transactions, FERC did not explain why the new evidence had no effect on its decision. See 105 FERC ¶ 61,066 at 61,365-61,366. FERC merely referenced its previous explanation, from its December 19, 2001 Order, in which it found that only the rates in “spot markets” were potentially unjust and unreasonable. However, FERC issued that order before the California Parties had offered additional evidence to support their claim. FERC never explained why the additional evidence did not affect its decision to limit mitigation procedures to only “spot market” transactions.

We should uphold FERC’s decision if its path to making that decision “may reasonably be discerned.” See Motor Vehicle Mfrs. Ass’n, 463 U.S. at 43 , 103 S.Ct. 2856 . However, it is difficult, if not impossible, to discern FERC’s analytical path here, particularly when its decision is viewed in light of its simultaneous decision to expand mitigation measures to include other previously excluded categories of transactions.

For instance, FERC expanded its mitigation measures to include non-emergency hours, even though it had earlier believed that rates in non-emergency hours would be sufficiently disciplined by its mitigation measures in emergency hours. See December 19, 2001 Order, 97 FERC ¶ 61,275 at 62,247. FERC later recognized new evidence that refuted its earlier belief and acted accordingly, expanding its mitigation measures to include all operating hours. When sellers argued against this expansion, FERC responded:

Id. at 62,218 .

FERC’s explanation applies with equal force here. Throughout the proceedings, FERC emphasized that it was engaged in a continuing examination of all market forces. Its investigation was not static and yet it proffered no reason for rejecting the new evidence that suggested that the forward market was affected by market manipulation that may have produced unjust and unreasonable rates. When faced with a similar situation in which FERC acted differently in two related situations without offering a reasoned explanation, we have granted a petition for review. See Cal. Dep’t of Water Res. v. FERC, 341 F.3d 906 , 910 (9th Cir.2003).

FERC’s decision to foreclose relief in the forward markets cannot be sustained. Its cramped reading of the original SDG & E complaint is not supported by a close examination of the record, and FERC does not offer any other explanation for its decision. In view of the evidence tendered by the California Parties that sellers manipulated both the short term and long term spot markets, FERC’s limitation of remedy without a reasonable explanation was arbitrary, capricious, and an abuse of discretion.

VII

Energy Exchange Transactions A

Exchange transactions involved two different sellers. The first seller, the “Exchange Seller,” agreed to provide Cal-ISO with energy in exchange for an in-kind return of the same amount of energy-plus an additional agreed-upon amount. See March 26, 2003 Order, 102 FERC ¶ 61 ,317at 62,083-62,084. Cal-ISO then purchased energy from the second seller, the “Spot Seller,” on the spot market and used that energy to pay back the Exchange Seller. In a typical exchange transaction, an Exchange Seller would provide Cal-ISO with one unit of power in exchange for Cal-ISO’s promise to return two units of power at a later time. Cal-ISO would use the one unit of power to supply its power grid. Then Cal-ISO would buy two units of power from a Spot Seller in order to pay back the Exchange Seller. Exchange transactions had varying return ratios. At times, the parties agreed that Cal-ISO must return the ener gy in “like time,” for instance in “on-peak” hours.

Cal-ISO’s purchases on the spot market were mitigated when FERC ordered Spot Sellers to refund amounts they had charged in excess of the MMCP. See id. at 62,084 . However, FERC declined to include Exchange Sellers in the Refund Proceedings.

The California Parties and Cal-ISO challenge the exclusion of Exchange Sellers, contending that they also should be liable for refunds because they used exchange transactions to exert market power by demanding exorbitant exchange ratios. The California Parties’ witness, Dr. Carolyn Berry, an independent economic consultant and former FERC economist, testified in support of their claim that Exchange Sellers had violated the Federal Power Act. Dr. Berry testified that “return ratios were excessively high.” She suggested that Exchange Sellers “may have been hoping to avoid refund liability by making sales in-kind rather than for explicit monetary payment.” Dr. Berry noted that some of the sellers’ internal emails supported her conclusion that those sellers were aware that using in-kind exchanges was a way for them to avoid FERC’s scrutiny.

Economist Dr. Peter Fox-Penner also testified on behalf of the California Parties regarding exchange transactions. He testified that “[t]here is no economic difference to a buyer between paying for a power purchase in dollars and paying for it in a commodity whose price is well-established in dollars in the marketplace .... [thus], there is no economic basis for excluding such transactions from mitigation.”

The Public Entities argue that Cal-ISO actually benefitted from exchange transactions because the Exchange Sellers offered desperately needed flexibility in a crisis situation. In support of their claim, the Public Entities referred to a Wall Street Journal article in which Cal-ISO Vice President Jim Detmers was described as praising exchange transactions because they were “a good deal” for California and “might even have saved [the state] money because daily peak prices were sometimes more than twice the off-peak prices the ISO paid for BPA’s replacement power.”

In its March 26, 2003 Order, FERC held that it would not subject the Exchange Sellers to refund liability for exchange transactions. The primary reason given by FERC in excluding Exchange Sellers from the Refund Proceedings was the difficulty in calculating a refund. March 26, 2003 Order, 102 FERC ¶ 61,317 at 62,084.

B

FERC improperly excluded the Exchange Sellers from the refund proceeding. There is no doubt that energy exchanges are considered sales, subject to FERC’s jurisdiction. 18 C.F.R. § 35.2 (a). By refusing relief simply because the calculation was difficult, FERC abandoned its duty under the Federal Power Act to ensure just and reasonable rates. See 16 U.S.C. § 824d(a). As we have previously stated, “[t]he FPA cannot be construed to immunize those who overcharge and manipulate markets in violation of the FPA.” Lockyer, 383 F.3d at 1017 . FERC is obligated to protect consumers from unjust or unreasonable rates, charges, or classifications, and any rules, regulations, practices, or contracts affecting such rates, charges or classifications. See 16 U.S.C. § 824e(a). Nothing in the Federal Power Act limits its application to those transactions that are easy to value. Although multiple variables may make certain transactions difficult to analyze, consumers must still be assured that those transactions are just and reasonable.

FERC’s approach to the exchange transactions created a loophole through which Exchange Sellers could exercise market power and manipulate the energy market without being subjected to the requirements of the Federal Power Act. FERC’s failure to exercise its broad remedial discretion to analyze exchanges of power during the Refund Period and address any unjust and unreasonable practices was arbitrary and capricious, and an abuse of discretion.

FERC argues that it is impossible to determine whether the Exchange Sellers demanded unjust and unreasonable exchange ratios because there is no way to assign a monetary value to exchange transactions. FERC claims that, because exchange transactions involved multiple variables like the shortage of hydro-electric generation power in the Pacific Northwest, it cannot determine whether Exchange Sellers demanded and received value in excess of what would have been just and reasonable under the circumstances. However, FERC did not conduct a specific analysis to conclude that the rates were just and reasonable, given the variables, nor did it make a finding that the variables showed that the rate was just and reasonable. FERC simply concluded that the calculation was too difficult.

The challenge of monetizing the transactions does not give FERC a safe harbor to throw up its hands and say it can’t be done. Significantly, FERC did not provide a reasoned explanation of impossibility, only a conclusory observation of difficulty. But saying so doesn’t make it so. Constructing a methodology did not prove too taxing for the California Parties, who tendered a mitigation methodology for examining the Exchange Sellers’ transactions. FERC rejected the California Parties’ proposed mitigation method because it did not account for all relevant variables. See March 26, 2003 Order, 102 FERC ¶ 61 ,317at 62,084 (“The CA Parties’ request to reform the exchange ratio completely ignores the severe energy shortfall in the Pacific Northwest, where most of these energy exchange transactions originated, during the 2001 time period.”).

The fact that FERC was dissatisfied with the California Parties’ proposed mitigation method does not justify its decision to exclude Exchange Sellers from the refund proceeding on a categorical basis. FERC’s own precedent shows that when parties have failed to propose an acceptable mitigation method, it may fashion a method on its own. See Re Green Mountain Power Corp., 61 FERC ¶ 61,203 (1992) (using the value of a contemporaneous cash sale from the same power unit to value an exchange of capacity for purposes of ordering a refund).

FERC also argues that because the energy exchanges were conducted over periods greater than 24 hours, the transactions cannot be considered spot market transactions subject to mitigation. However, we have already rejected this argument as a general matter, so it does not afford FERC a valid basis for excluding the transactions at issue here.

In sum, because FERC did not articulate a valid basis for excluding the energy exchange transactions from the Refund Proceedings, we conclude that its action was arbitrary, capricious, and an abuse of discretion.

VIII

Sleeve Transactions

“Sleeve transactions” were used when the investor-owned utilities were on the brink of insolvency and credit problems began to limit the ability of the inves tor-owned, utilities to purchase power. As FERC described it:

San Diego Gas & Elec. Co., et al., 107 FERC ¶ 61,165 at 61,640 (2004).

To obtain adequate supplies of energy to continue to power the grid, Cal-ISO entered into transactions whereby sleeving parties would buy power directly from energy sellers and then resell the power to Cal-ISO at a premium to reflect the credit risk.

Cal-ISO decided that certain sleeve transactions should not be subject to mitigation, but the ALJ reached the opposite conclusion. After considering the ALJ report, FERC determined that the sleeve transactions should be subject to mitigation; in other words, those transactions should not be excluded from potential refund liability. FERC concluded that the sleeve transactions were similar to other sales and that the sleeving parties assumed the same risks of making spot energy sales to Cal-ISO, including the risk of refund liability. Therefore, FERC adopted the ALJ’s findings and included the sleeve transactions as part of the refund proceedings. The Public Entities now petition for review of that decision, arguing that sleeve transactions were individually negotiated transactions outside the scope of the Remedy Proceedings.

The Public Entities contend that the sleeve transactions should not be included in the refund proceedings because the sleeving parties merely acted as financial intermediaries and facilitators. In their view, the sleeve transactions were individually negotiated transactions that did not take place in the single-price auction market. FERC contends that the parties saw the sleeve transactions, as comprising two sales: one from the supplier to the sleev-ing party and the second from the sleeving party to Cal-ISO. In FERC’s view, the sleeving parties were subject to Cal-ISO rules because all sellers in the Cal-ISO market had the responsibility to comply with market rules and the tariff. The final transaction of the two-step process occurred, according to FERC, in the Cal-ISO market.

The record supports FERC’s conclusion. All sleeve transactions that are subject to challenge here occurred as spot market transactions in the Cal-ISO market. The fact that the sleeving parties received a risk premium does not relieve them from liability if, independent of the risk premium, they charged an unjust and unreasonable rate in the spot market, which was part and parcel of the Cal-ISO market. Thus, FERC did not act arbitrarily or capriciously, or abuse its discretion in including the sleeve transactions in the refund proceeding.

IX

California Energy Resources Scheduling (“CERS”) Division Transactions

A

In its December 8, 2001 Order, FERC lifted the Cal-ISO price caps, hoping to attract more supply into the auction markets. December 8, 2000 Order, 93 FERC ¶ 61,239 . In its December 15, 2001 Order, FERC eliminated the requirement that the investor-owned utilities buy and sell all energy through CalPX. December 15, 2001 Order, 93 FERC ¶ 61,294 . As we have discussed, when these remedies did not stem the rise of electricity prices, and the investor-owned utilities were on the brink of insolvency, Governor Davis ordered CERS to enter into contracts to buy power directly on behalf of California consumers. These purchases were made in bilateral contracts outside the CalPX and Cal-ISO markets and totaled more than $5 billion of purchases.

On March 1, 2001, the Cal-EOB filed a motion with FERC, asking FERC to clarify that the Remedy Proceedings included CERS transactions. FERC denied the motion, concluding that the bilateral transactions were entered into outside the CalPX and Cal-ISO markets, and therefore, were outside the scope of the Remedy Proceedings. In its order, FERC noted that “if DWR or another party believes that any of its contracts are unjust or unreasonable, it may file a complaint under FPA Section 206....” CPUC and Cal-EOB filed such complaints, which are the subject of separate petitions for review before this Court. See Pub. Utilits. Comm’n of State of Cal. et al. v. FERC, nos. 03-74207, et al. In this case, the California Parties petition for review of FERC’s decision to exclude the CERS transactions from the Remedy Proceedings, and the various FERC orders denying rehearing. We conclude that FERC’s decision to exclude the CERS transactions was not arbitrary, capricious, or an abuse of discretion.

B

One of the fundamental tenets in FERC jurisprudence is the rule against retroactive ratemaking. Arkansas Louisiana Gas Co. v. Hall, 453 U.S. 571, 578 , 101 S.Ct. 2925 , 69 L.Ed.2d 856 (1981). This theory underpins the limitations on FERC’s remedies under § 206 to the post-complaint period. § 824e(b). Consol. Edison Co. of N. Y., Inc. v. FERC, 347 F.3d 964, 967 (D.C.Cir.2004). If FERC finds a rate unjust and unreasonable pursuant to a § 206 complaint, it must order imposition of a just and reasonable rate; however, the refund is limited to periods subsequent to the “refund effective date” established by FERC, which must be at least sixty days after the filing of the complaint. Id. By this procedure, once a complaint is filed, sellers are on notice that their sales may be subject to refund.

Thus, while FERC has considerable latitude in fashioning § 206 relief, the remedies afforded pursuant to a third party § 206 complaint must have a sufficient nexus to the substantive allegations of the complaint so that market participants are placed on notice that they are at risk for sales made after the refund effective date. We have already concluded that the substantive allegations of the SDG & E complaint were sufficient to put sellers on notice that the OOM, non-emergency, energy exchange, and sleeve transactions might be subject to refund. All of these transactions were directly associated with the CalPX and Cal-ISO markets. However, the bilateral CERS transactions occurred in a different market — one that did not even exist when the SDG & E complaint was filed. Thus, neither the SDG & E complaint nor the subsequent actions by FERC in establishing the Remedy Proceedings were sufficient to put participants in the CERS transactions on notice that their sales might be subject to refund.

There are fundamental differences between the CalPX/Cal-ISO markets and the bilateral contracts negotiated by CERS. As we have discussed, the CalPX and Cal-ISO markets were centralized, single-price, auction markets, involving multiple participants. In contrast, the CERS transactions were two-party contracts of varying prices, terms and duration that were mutually negotiated — ostensibly at arms-length — outside the CalPX and Cal-ISO markets. Unlike the Cal-ISO OOM and sleeve transactions that we have concluded were properly considered in the Refund Proceedings, the CERS transactions occurred in a market that was not directly influenced by the market manipulations in the Cal-ISO and CalPX spot markets.

The record reflects no direct nexus between the CERS bilateral transactions and the CalPX and Cal-ISO spot markets. Given these differences, and the fact that the entire focus of the SDG & E complaint and FERC’s orders creating the Remedy Proceedings were directed at the CalPX and Cal-ISO markets, it is clear that the substantive allegations of the SDG & E complaint did not bear a sufficient nexus to the bilateral CERS transactions to afford parties to the CERS contracts sufficient notice that their sales might be subject to refund.

Indeed, when the SDG & E complaint was filed, the investor-owned utilities were required to conduct all of their sales and purchases through the CalPX and Cal-ISO markets. It was not until FERC’s December 15, 2000 Order, some six months after the filing of the SDG & E complaint, that investor-owned utilities were free to conduct energy transactions outside the CalPX and Cal-ISO markets. And, it was not until January, 8, 2001 that CERS began to make its purchases.

Thus, FERC concluded that:

December 19, 2001 Order, 97 FERC ¶ 61,275 at 62,195.

We agree with FERC’s analysis. Because the SDG & E complaint was not sufficient to put the CERS transaction participants on notice, expanding the Refund Proceeding to include the CERS transactions would violate the rule against retroactive ratemaking.

The California Parties argue, with considerable force, that unjust and unreasonable rates were charged in the CERS transactions and that the transactions in substance were indistinguishable from transactions within the CalPX and Cal-ISO markets. However, FERC did not close the door on potential § 206 relief based on the CERS transactions; in fact, it invited aggrieved participants to file new complaints directed specifically at the CERS transactions. Thus, while the bilateral CERS transactions are beyond the scope of the Remedy Proceedings at issue here, those transactions may be the subject of other challenges, the posture and merits of which are beyond the scope of the instant case.

Given all of this, we conclude that FERC’s construction of the SDG & E complaint as not including the CERS transactions was.not arbitrary, capricious, or an abuse of discretion.

X

Port of Oakland and Other Bilateral Transactions

The Port of Oakland argues that its bilateral contracts with energy suppliers, entered into during the CERS period to meet the needs of Oakland’s airport, should also be subject to the Refund Proceedings. FERC denied the request on the same basis that it denied the California Parties’ entreaty to include the CERS transactions in the Refund Proceedings. The analysis of the CERS and Port of Oakland transactions is the same. We deny the petition for review filed by the Port of Oakland for the same reasons that we deny the petition by the California Parties for review of the CERS transactions.

XI

Section 202(c) Transactions

By December 2000, in the middle of the energy crisis, energy suppliers were reluctant to bid into the CalPX and Cal-ISO auction markets because the investor-owed utility buyers in those markets were verging on insolvency. In order to correct for this shortage of sales, Cal-ISO requested the United States Department of Energy to intervene. Pursuant to Cal-ISO’s request, the Department of Energy issued a series of orders under the emergency provisions of Federal Power Act § 202(c), which required energy suppliers to sell excess available power to Cal-ISO. The Public Entities were parties to some of these sales, .which were later exempted from a refund by FERC because of the fact that they were compulsory.

The Public Entities attack FERC’s affir-mance of the ALJ’s conclusion that certain of these sales were exempt from refund liability. The California Parties have moved to strike this argument on the basis that it constitutes an implementation issue to be decided in a different phase of this case, rather than an issue that concerns the scope of the refund proceeding.

No party challenges FERC’s determination that sales pursuant to § 202(c) are exempt from refund liability. The Public Entities do not argue that § 202(c) transactions categorically should or should not be included in the scope of the refund proceeding. Rather, the Public Entities contest the manner in which FERC determined the definition — the scope — of the § 202(c) exemption. The Public Entities do not argue that any particular category or subcategory of transactions should be considered § 202(c) transactions. Instead, they take issue with the methods and information FERC uses to determine what is a § 202(c) exemption. Thus, we conclude that the § 202(c) issues raised by the Public Entities should be considered an implementation issue, rather than a scope transaction issue. Therefore, we grant the California Parties’ Motion to Strike with respect to § 202(c) transactions.

XII

Conclusion

In general, we hold that all the transactions at issue in this case that occurred within the CalPX or Cal-ISO markets, or as a result of a CalPX or Cal-ISO transaction, were the proper subject of the Refund Proceedings. We deny the petitions for review that challenge FERC’s inclusion of such transactions; we grant the petitions for review that challenge FERC’s exclusion of such transactions. We deny the petitions for review that seek to expand the Refund Proceedings into the bilateral markets other than the CalPX and Cal-ISO markets. We hold that FERC properly established October 2, 2000 as the refund effective date for the § 206 proceedings. We hold that FERC erred in excluding § 309 relief for tariff violations that occurred prior to October 2, 2000.

Specifically, we (1) deny the Competitive Suppliers Group’s petition for review challenging FERC’s establishment of the effective refund date; (2) grant the California Parties’ petition for review of FERC’s decision to exclude § 309 relief; (3) deny the Competitive Suppliers Group’s petition for review challenging the inclusion of the OOM transactions in the Refund Proceedings; (4) grant the California Parties’ petition for review challenging FERC’s exclusion of forward market transactions from the Refund Proceedings; (5) grant the California Parties’ petition for review challenging FERC’s exclusion of the energy exchange transactions from the Refund Proceedings; (6) deny the Public Entities’ petition for review challenging FERC’s inclusion of sleeve transactions in the Remedy Proceedings; (7) deny the California Parties’ petition for review challenging FERC’s exclusion of the CERS transactions from the Remedy Proceedings; (8) deny the Port of Oakland’s petition for review challenging FERC’s exclusion of its bilateral CERS transactions from the Remedy Proceedings; and (9) grant the motion of the California Parties to exclude the Public Entities’ § 202(c) and challenges to the categorization of multi-day transactions from this proceeding. Each party shall bear its own costs on appeal.

PETITIONS GRANTED IN PART; DENIED IN PART; REMANDED FOR FURTHER PROCEEDINGS.

. We express our appreciation to Lisa Evans of the Ninth Circuit Court of Appeals Mediation Unit; Cole Benson, Supervisor of the Ninth Circuit Procedural Motions Unit; and our colleague Judge Edward Leavy for their extensive work with the parties in organizing judicial management of the cases. We also express our appreciation to the parties and their attorneys for their cooperation, professionalism, and the quality of their presentations. . The California Parties consist of the People of the State of California, ex rel. Bill Lockyer, Attorney General; the Public Utilities Commission of the State of California; the California Electricity Oversight Board; Pacific Gas and Electric Company, and Southern California Edison Company. . This group consists of Powerex Corp.; Avis-ta Energy, Inc.; Constellation Energy Commodities Group, Inc.; Coral Power, L.L.C.; Exelon Corporation on behalf of Exelon Generation Company, LLC; PECO Energy Company; Commonwealth Edison Company; IDACORP Energy LP; Portland General Electric Company; PPL EnergyPlus, LLC; PPL Montana, LLC; Public Service Company of New Mexico; Puget Sound Energy, Inc.; Sempra Energy Trading Corp.; TransAlta Energy Marketing (CA), Inc.; TransAlta Energy Marketing (US), Inc.; and Tucson Electric Power Company. .This group consists of municipal entities, including the Modesto Irrigation District, the City of Los Angeles Department of Water and Power, the Sacramento Municipal Utility District, the City of Redding, and the State Water Contractors/The Metropolitan Water District of Southern California (which represents 27 of the 29 California public entities that provide substantial funding for the California Department of Water Resources' operation of the State Water Project). . The California legislature recognized that the transition to a deregulated market would leave the investor-owned utilities with some unrecoverable "stranded costs.” "Stranded costs” are those costs, generally associated with facility construction, that cannot be recovered because either the charged rate is insufficient to cover the costs or the utility cannot sell enough power. In the case of sales made pursuant to the divestiture requirements, recoverable stranded costs meant the difference between the sales price and the book value of the assets. During the transition to a deregulated market, the investor-owned utilities were to recover certain stranded costs through individual cost-recovery plans, which provided that rates would be frozen for a period of time to allow the investor-owned utilities to generate sufficient profits to recover their stranded costs. . A brownout occurs when power is not lost completely, but is provided at reduced voltage levels. . As a threshold matter, FERC argues that the California Parties’ and Cal-ISO's arguments are procedurally defaulted because they were not raised on rehearing. 16 U.S.C. § 8251 (b) provides that a party may obtain review in this court by filing a petition "within sixty days after the order of the Commission upon the application for rehearing.” We, however, cannot consider an objection "unless such objection shall have been urged before the Commission in the application for rehearing.” Id. In their multiple requests for rehearing of FERC's orders, the California Parties fairly raised objections to FERC's limitation of price mitigation to the Cal-ISO real-time market, and its limitation of refunds to "spot sales.” Thus, FERC had the opportunity to address the California Parties’ challenges and we have jurisdiction to consider FERC’s limitation. See Transmission Access Policy Study Group, 225 F.3d at 685 n. 4. . The Public Entities argue that FERC erred in finding that some of the Public Entities' transactions with Cal-ISO were spot market transactions — not multi-day transactions— and thus subject to refunds pursuant to FERC's orders. The California Parties have moved to strike this contention because it involves implementation questions not appropriate for this phase of the proceedings. Given our decision that the forward market transaclions are subject to refund liability, the issues raised by the Public Entities are likely moot. However, to the extent that any issues remain, we grant the California Parties’ motion because the questions raised by the Public Entities are fact-specific inquiries as to the nature of particular transactions that are appropriately considered in conjunction with implementation issues. . The California Parties moved to strike the portion of Public Entities’ briefs addressing sleeve transactions, and El Paso Merchant Energy moved to defer consideration of sleev-ing issues. Both parties argue that consideration of sleeving is an issue of implementation, not an issue of scope, and therefore belongs in the next round of briefing. However, there is no principled way to distinguish a hypothetical exemption for sleeve transactions, as a distinct category, from the exemptions or non-exemptions FERC has considered, and we are now considering, for OOM, energy exchange, forward market, and other categories of transactions. Sleeve transactions appear to be a distinct category, subject to the same type of analysis as the other issues. We therefore deny the California Parties and El Paso Merchant Energy's motions as to sleeve transactions and consider the merits of Public Entities’s claim that sleeve transactions as a category should have been exempted. However, to the extent that the Public Entities are raising fact-specific issues related to implementation, as opposed to a categorical challenge, we grant the California Parties’ motion.