IN: Attached is a listing of unresolved Issues between Tom and Greg Sharp. I have not included the facility charges - do you want me to add those? Please feel free to add on to my list anything that I have left off.

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OUT: Unresolved Tx/Prod Svcs Issues
IN: This is an email
Hi Andy. Here's my suggestion (actually it was yours): Product 1 Fin Power Swap Web Visible Offered Qty: 50 Qty Increment: 5 Min Qty: 5 (or whatever you want to use as a minimum) Product 2 Fin Power Swap Ghost Product - not web visible Offered Qty: 200 Qty Increment: 1 Min Qty: 1 Base Link to Product 1 with Bid = 0, Offer = 0, Offset to Last trade of 0 with reset qty of 200 NOT Auto-hedged to Product 1 Product 3 Fin Power Option Auto-hedged to Product 2. Here's what will happen: Suppose the option is traded and to hedge it requires a qty of 15. The actual hedge will be against Product 2. Product 2 offered qty will reduce to 185. Since Product 2 is not auto-hedged to Product 1, there will be no impact on the main swap. The prices for Product 2 will always be exactly those of Product 1 since the bid and offer are 0. Note: Eventually, the offered qty for Product 2 will reduce below the amount needed for hedging a particular trade (for instance, if every trade required a hedge qty of 15, then after 13 trades, your remaining qty would be 5). This is not a problem. The hedging model for options allows for not enough volume being available on the swap. The next trade would simply get fully hedged and pop the qty back up to 200. Since it has an offset to last trade of 0, the bid and offer prices would still be those of Product 1. Also Note: We will have to make sure the power IT guys are prepared to get essentially the same swap (Product 1 and Product 2) under two different product ids. Does this make sense?

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OUT: solution for hedging options that doesn't decrement swap volume
QUESTION: David: Could you please confirm the following for me: 1. With ACE USA, Inc., we confirm using the "deemed ISDA" format. For some reason they were on our Annex A list. Do you know why? 2. We only do physical deals with Northern Indiana Public Service Company and the "Columbia Gas" entities. Again, they too were on our Annex A list. Thanks.
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ANS: Annex A Questions
Joe, thanks for the assistance. We have a few items still outstanding on the Doyle (Georgia PPA with Ogelthorpe) unit; however, It looks like we have the '99 and '00 plants completed. The 2001 program is much smaller. I will follow up shortly. Regards
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answer: Weekend Activity
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,
Answer: PG&E Proposed Solution
Q: Greg, I can not even imagine all the tension and activity that have kept you busy these past weeks. Maybe you can give me a call when the dust settles a little. Sunday PM might be good, I will be at home. There is nothing critical just thought you might want to vent. Liz has been a champ and if anything went critical I would let her know. Cash margins are getting thin with all the rate cuts, but you are liquid and getting the best available. Ben
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A:
checking in