IN: Most folks probably listened in to the press conference, but for those that didn't here's a summary of the ISO's proposal to FERC. The description of the proposal was vague and general, and Winters tends to speak in run-on sentences, so if I've gotten anything wrong, please chime in. $100 cap for "old" generation; "new" generation would be exempt. FERC would require generators and SCs to contract forward for at least 70% of their power. For those that meet the 70% requirement, they will be exempt from the $100 cap, and the $250 cap will apply. Winters believes that the 70% requirement, coupled with utility-controled gen, will result in the IOUs scheduling about 85% of load into the forward market. Load and supply that deviate from schedules and go to the real time market will be penalized (details to be "ironed" out). The ISO is supposed to make the filing at FERC today.

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OUT: ISO Proposal to FERC

IN: Harry: At the meeting yesterday, we concluded that it would be a good idea to take the proposal that you put together based on your meeting with EES and use it as the "base case" to start running the numbers. Idea being that before we shop anything around, we need to know what the numbers look like to determine whether the thing's got any legs. Once we have a clear understanding of how the base case numbers shake out, we thought we might then want do some sensitivity analyses around the variables, come up with a final proposal, and then go back to the commercial groups for buy-in. We hoped that your folks could get together with Roger Yang et al and provide some assessment of what the base case numbers look like by middle of next week. How's this plan sound? Few other points: We assume that bullet 6's reference to "net" means that the deferral is calculated by taking any "overcollections" and subtracting them from any "undercollections" over the entire 3 year period,not year-by-year. What is the significance of the 3.1 CTC roll-off date? We're assuming it's commercially driven. We correct? If so, what's the driver? Same goes for the 2004 ending date. Some tweeks were made to the proposal at the meeting to create an "Option 2" for folks to consider. (Though we don't think that any numbers need to be run on "Option 2" until after having completed the analysis on option 1, since those results could influence any scenarios we decide to construct). Option 2 would: Keep the hydro with the utility and apply Edison's proposed ratemaking treatment. Beginning 6.1.01, make large customers "noncore," similar to the gas model in California, and force those customers to choose an ESP. Beginning 1.1.03, introduce competitive default service for remaining "core" (i.e., rez and small commercial) customers. ++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++ ++++++++++++++++++++++++++++++++++++++++++++++++++++ Finally, couple of things that occurred to me after yesterday's meeting that I want to throw out for folks to react to: Seems that, to be successful, the proposal needs to remain as stripped down and simple as possible. When the proposal nets out the deferral costs, does it include the over/undercollections associated with utility residual generation? In option 2, by adding the "noncore" feature, and by implementing that feature and the default service feature prior to the 04 ending date, the proposal gets more complicated (and adds significantly more risk to the utility's position). This is not to say that the complications can't be worked out, or that the added risk can't be accounted for, but wanted to highlight it for folks to consider. Attached is the original, with just a couple of minor edits, and "Option 2." Best,

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OUT: PG&E Proposed Solution

IN: Hey Hunter, how's it going? Got a favor. I am sponsoring a "Summer Series" of presentations to select individuals in EES to get them more acquainted with the wholesale marketplace and other areas of Enron. I will be having these each Wednesday beginning June 13th. We're starting with US Power which Rogers Herndon is going to present. On June 20th, I'd like to have someone present US Gas. I'd really like to have you present if at all possible. We're doing these in 5C2 which holds about 100 folks. The EES groups will really benefit in gaining more insight into the wholesale markets. I'm basically wanting to give them an overview of the current fundamentals in the US Gas market, the influence from Canada/Mexico, an update of storage and transportation balances/concerns, our view of the forward market and the things that are influencing it, etc. We probably just need a 30-45 presentation with about 30 minutes for Q & A.

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OUT: A Favor!

IN: Began initial field confirmation of EOTT crude oil tanks and equipment in the MIdland Region. Five of the thirteen teams which have EOTT facilites have been inpsected and appropriate changes made to the database and spreadsheet. A meeting was held with the Midland field teams which have Title V facilities, to complete and submit the required annual certifications. All Title V locations in the MIdland region were in compliance for this year. Region IX EPA has made a determination that prior to issuance of the air permits for the Redrock turbine installation, Transwestern is to conduct an endangered species survey of C/S's 3 and 4. A contractor has been contacted and the surveys will be completed prior to September 15th. This is not a new issue, as EPA Region VI, Dallas required consideration of the Endangered Species Act to be completed at the Luguna C/S, which is on Laguna Indian Lands. The Title V permit will not be issued for the Laguna C/S until the EPA is satisified that endangered species are not a concern. Preliminary environmental and right of way field data are being provided to an environmental contractor to initiate a fatal flaw analysis of a proposed project for Transwestern Pipeline Company. Continued EOTT crude oil release data collections for forthcoming Sept. 27th NFL meeting in MIdland.

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OUT:
Weekly Activity Report, Roswell Area