3. Benefits of Self Scheduling

We reaffirm in this order the central piece of our proposed price mitigation, which is the elimination of the requirement for the IOUs to sell all of their generation into and buy all of their energy needs from the PX. This requirement caused the over reliance on spot markets, which lies at the very heart of the high prices in California. By eliminating this restriction, we will release the entirety of the IOUs' 40,000 MW of peak load from the PX. In every real sense, the IOUs will be free to mitigate their own spot price exposure by meeting their requirements (under long-term contracts in the bilateral markets). Just as significantly, the IOUs will be able to use the 25,000 MW of generation which they still own or have under contract to serve their load without having to contract with anyone. 30 This places 25,000 MW of resources directly under the jurisdiction of the California Commission. Thus, the California Commission is free to price these MWs at cost or any way it sees fit for setting retail rates. IOUs will no longer be required to bid in their own resources and buy the energy back at the market clearing price. This is a comprehensive measure which will mitigate the spot market exposure of most of the peak load in California.

The IOUs will need the ability to mitigate their exposure by using their considerable portfolio of owned generation to serve their load and by contracting for the supply of the rest of their load with a balanced portfolio. While we do not in this order prescribe a particular maximum level of purchases from spot markets, or short-term purchases in the bilateral markets, we strongly urge the IOUs to move their load to long-term contracts of two years or more. While there is certainly no single right answer as to what the balance between long and short-term purchases should be, the short-term and spot markets should be used to shape a portfolio, not to define it. Instructive in this regard is that other ISO markets (e.g. NEPOOL, NYISO, and PJM) maintain less than 20 percent in the ISO spot markets.

We cannot emphasize enough that the California Commission must act decisively and immediately to eliminate the requirement for the IOUs to buy the balance of their load from the PX. 31 This is the most serious flaw in the market design created by AB1890 and the California Commission's implementing orders. Continued delay in making this fundamental change places all other aspects of our remedial plan at risk, and prolongs the dysfunction of this market. In addition it is crucial that the California Commission move quickly to provide the IOUs with approval of their forward purchases. The specter of after-the-fact disallowance for transactions other than PX purchases has certainly chilled the decision making process and continues to subject California's ratepayers to the volatility of spot prices. California is in a state of economic emergency, and there is little chance that the IOUs will rise to the task if they are not afforded certainty. 32.

4. Functioning Forward Markets Will Be There for California

Some parties in this proceeding argue that the prices in the forward markets will be affected by last summer's spiraling spot prices and should therefore be deemed unreasonable. We do not agree. Sellers will certainly be aware that supplies of power are tight and that the IOUs are now aggressively seeking to avoid the exposure of the spot markets. Under these circumstances, as discussed below, we will be vigilant in monitoring the possible exercise of market power. However, suppliers also benefit from the stable revenue stream of forward markets and have every bit as much incentive to avoid the volatility of the spot markets as do purchasers.33 Moreover, suppliers will bargain knowing that the spot market's size will be greatly reduced and that next summer's spot prices will therefore not be fueled by frenzied buyers whose over-reliance on last minute purchases have forced them to bid up the prices to obtain needed supply. Suppliers, of course, will be influenced by their best projection of next summer's gas and NOx prices. The cost of these vital inputs has risen steadily from about $2 MMBtu and $6/lb in 1999 to well over $50 MMBtu and nearly $50/lb now.34 Estimates of the cost of these inputs will heavily influence forward prices more than anything else. The rise in the cost of these critical elements will inevitably affect forward prices, but this will be based on analysis and expectations for next summer, and not last summer. Therefore, as discussed later in the order, we will not mandate forward contracts at specified prices. Moving to forward markets, a buyer's willingness to pay and a seller's ability to demand high prices is greatly reduced compared to real-time. Generators have made it clear in this record that they have a strong preference for long-term markets and we emphasize that we expect them to respond accordingly. Their participation in long-term markets is crucial to mitigating prices in the near term. Of course, the long-term solution is to build generation and transmission additions.

Many pleadings argue that moving to forward markets, in and of itself, will dampen any seller's market power. We agree. However, we also recognize that the elimination of the PX buy/sell requirement will move a considerable amount of load from the spot to the forward market at one time and that some have argued that this will create yet another strong sellers' market. To address concerns about potentially unjust and unreasonable rates in the long-term markets, we will monitor prices in those 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, after which time the sudden increase in forward demand will have subsided. In determining an appropriate benchmark, we note that the average embedded generation cost component of the IOUs' rates, which were frozen when restructuring began, was about $67.45/MWh. 35 Moreover, since the $67.45 figure reflected a 10 percent rate reduction from pre-restructuring levels, the pre-restructuring rates were about $74/MWh. In November, Duke Energy reported that it had offered to supply SDG&E's entire 3,300 MWs of load for five years at a fixed price of $60/MWh (escalated at three percent per year).36 Since that time, gas prices have hit the $50/MMBtu level and Duke Energy is now considering a price in the $80/MWh range. We note that even this higher figure is close to the $74/MWh level of the pre-restructuring rates and is but a fraction of the current spot electricity prices. While we do not have jurisdiction over retail rates, it is our view that five-year contracts for supply around-the-clock executed at or below $74/MWh can be deemed prudent. 37

Given the current market conditions and the rising cost of generation inputs, we believe that negotiated long-term prices that are below the levels of the pre-restructuring rates are just and reasonable. We expect that buyers may elect to negotiate above those levels to the extent they believe the particular contract or supplier brings value which suits their needs (e.g. shorter-term contracts, favorable terms and conditions, assignment of the risk of variable cost exposure, the particular characteristics of the supplier or its resource portfolio, etc.). 38 Sellers of long-term service currently have market-based rate authorization. We are not establishing a new standard for market-based prices for long-term contracts. Rather, as discussed above, we are providing an advisory benchmark to assess potential complaints regarding long-term contracts. This will assist buyers and sellers over the next year when so many MWs will be entering the forward market at one time. This advisory benchmark should not be interpreted as establishing a price floor on forward contracts, which may justify a lower per MWh price. We also believe that concerns about the availability, pricing and prudence of forward contracts may be more quickly resolved if all affected parties - - buyers, sellers and state officials - - attempt to develop a mutually agreeable plan for the initial round of forward contracts. We believe that a conference may provide the best forum to reach agreement in the short time available, and we encourage the parties to explore these types of processes.

In order to corroborate our benchmark and to adjust it if necessary, we direct all sellers with market-based rate authority to report to this Commission no later than January 2, 2001, on a confidential basis, round-the-clock long-term products in annual increments between two and five years which they are willing to offer in California. These informational reports should include price, terms and conditions, and amounts. We will also rely on this data to assess the supply and prices in the forward markets. To the extent that parties prefer, for the purposes of transparency, to report on a non-confidential basis or to post these offers on their websites, they may so advise us.

Docket No. EL00-95-000, et al.

30 In response to a data request supplied by the ISO to FERC staff investigating the Summer price spikes and supported by our analysis of FERC Form No. 1 data, the IOUs own or control, under contract, approximately 25,000 MWs of resources.

31 We note that the California Commission has scheduled for its December 21, 2000 meeting consideration of a proposal to remove the requirement that the IOUs to purchase their power from the PX.

32 According to Governor Davis' December 1 comments, he has also asked the California Commission to develop benchmarks to provide assurance to the IOUs regarding the reasonableness of their forward contracts.

33 While suppliers clearly benefit on the upside of price volatility, the risks of price swings move in both directions. A supplier that relies exclusively on spot markets is exposed to the risk that, due to favorable weather or supply conditions, prices will be too low to cover its costs.

34 The California Commission argues that the cost figures cited by the Commission are inaccurate. We respond to these arguments later in this order.

35 Several parties (e.g. WPTF at 24) state that the average cost of generation under the cost-based rates at the time restructuring began in 1998 was $67.45/MWh.

36 SDG&E disputes these claims in a December 14, 2000 pleading in this proceeding.

37 Under long-standing Supreme Court precedent, our wholesale rates must be considered just and reasonable for purposes of flow-through in retail ratemaking. See, Nantahala Power and Light Co. v. Federal Power Commission, 384 F.2d 200 (4th Cir. 1967), cert. denied, 390 U.S. 945 (1968); Mississippi Power & Light Co. v. Mississippi ex rel. Moore, 487 U.S. 354 (1988).

38 For example, in times of increasing fuel costs, short term prices may be higher than reflected in a negotiated five year contract, while in times of decreasing fuel costs, short term prices may be lower. Also, parties may negotiate the allocation of risk that fuel prices may change and this risk allocation will be factored into the negotiated rate.