This is the content of an email: Confidential - Attorney Client Privlege Please give me your thoughts on the attached proposal to resolve the "dangling chads" with AEP. I have attached the proposal and a "value analysis" of the proposal, both of which I propose to send to AEP. The key benefits of the proposal from Enron's perspective are the following: 1. Removes us from the vagueness and uncapped exposure of the Ducote deal with Entex for additional costs. AEP can capture the economics of future gas deliveres to Entex associated with this capital expenditure. 2. Captures the leverage that AEP will have in the Entex audit. I think for ENA to pursue Entex would be difficult/time consuming and may lead to a tortious interference suit from AEP. 3. Gives up the interest payment we think AEP owes us. This is true value we are giving up, but do we really want to fight with AEP in court over this (to the extent they are not bluffing)? 4. Removes us from having to process imbalances - saving manpower costs and further removing us from hassles with AEP. AEP is better able to capture value from these imbalances then we are, since they have the pipe. 5. Gets us out of the Coastline law suit. I'm pretty sure Coastline is at least owed the $1.4MM that we would contribute. AEP has a chance to minimize any further costs, which are capped by the value of the claim at a further $2.2MM. Please do not circulate this. Thanks,

Subject: CHAD - Attorney Client Privlege - Confidential

This is the content of an email: The model review meeting on Thursday went well, and the consensus was that = there are many changes to be made to the current Foothills economic model. = Many assumptions in the current model were challenged by the participant co= mpanies. Foothills agreed to reflect the suggested changes to the model (An= dy is supposed to send out a summary of the discussion) and provided an ele= ctronic copy of the model for withdrawn partners' review. Withdrawn partner= s agreed to give their comments/feedback on the model to Foothills until 11= /27/01 and another meeting to reach an agreement on economic model/toll was= scheduled for 12/03/01 or 12/04/01. The data from economic/toll model will= be used in commercial proposal/presentation to the ANS producers which ANN= GTC intends to have by 12/20/01. Tim and I will review Foothills' cash flow= and COS model and prepare comments. Overall, the participants though that the current Foothills model ($0.43/MM= Btu toll for Alaska section) has very aggressive assumptions in many ways, = and it is very likely that the toll will be increased significantly after a= ll the appropriate revisions are made. The following are the main discussio= n points of the meeting. Item 1 and 2 are expected to have a very large imp= act on the toll. 1) Capex and Opex need to have annual/monthly escalation (current model has= 0% escalation). For example, Foothills sensitivity analysis shows that 2.5= % Capex escalation would increase the toll by $0.20. Numbers such as 1.5% f= or Capex and 2.5% for Opex were thrown during the meeting, but more reviews= need to be done regarding appropriate escalation rates. Do you have any op= inion on this, Bryan? 2) Foothills is using Flowthrough method (using cash taxes in COS calculati= on) to calculate income taxes that go into the Cost of Service and might be= underestimating Cost of Service. Tim thought that the Flowthrough method w= ill not fly because of previous cases in which that method was not allowed = by IRS and FERC. Foothills said that they can still have same toll under No= rmalized tax method by changing the depreciation number, but Tim was concer= ned that it might force the partnership to record negative depreciation. Fo= othills declined our request to share their Cost of Service model and insis= ted that we calculate the toll ourselves based on the information in the ca= sh flow model. They agreed to provide a hard copy of their Cost of Service = model in the end, but Tim and I were under impression that Foothills was tr= ying to lower the toll as much as they can. Tim was also concerned about le= velized toll approach because of FERC might lower allowed return in the lat= er rate cases and more analysis needs to done regradign this. Please correc= t me if I am wrong here, Tim. 3) OM & A is currently estimated to be 1% of Capex but this might be too lo= w (OM&A in more latest cost estimate by Foothills is approx. 1.5% of total = Capex). 4) The Withdrawn Partners' historical contributions ($228 million) will be = added to the Rate Base, but this might be dropped if necessary. Success fee= of $40 million should be included in the project budget. 5) Working Capital will be added to the project cost. The Line Pack cost (1= 4.5 Bcf for the whole section) was assumed to be borne by ANS producers but= some participants highly doubted that that would be the case. The Line Pac= k gas might have to be bought by the Partnership or the Producers will at l= east demand certain return on their gas sitting in the pipeline for 25 year= s. 6) For Return on Capital and AFUDC, 14% ROE and 8% Interest on Debt assumin= g 30/70 capital structure is likely to be kept. However, the current drawdo= wn schedule assumes construction financing available from the very beginnin= g, which will not be true. Certain assumptions should be made on the financ= ial close date and commercial agreement/preliminary determination date to c= alculate AFUDC more accurately. 7) Current financing assumption in the model is a 25 year bank loan with ba= lloon amortization and DSCR of 1.6. In reality, the initial bank loans will= be of shorter maturity (5-15 years) and certain roll-over financing will b= e unavoidable. It is also likely that the loans will have multiple tranches= with different terms, interest rate, seniority etc.=20 8) There is significant currency risk associated with Canadian section of t= he ANGTS considering that some sources of capital, revenues and part of ope= rating expenses will be in Canadian dollars. A mechanis to mitigate currenc= y risk should be in place and there might be some costs associated with it. 9) Property taxes of 2% in Alaska seems high, but Property taxes during con= struction period should be added. Lastly, there is about $300 million difference ($4,336-$4035) between ETS c= urrent cost estimates and the cost estimate in the Foothills model, excludi= ng IDC and AFUDC. Another engineering estimate might have to be dome for la= rger pipe size (46 or 48 inch) as noted in Bryan's email. =20 Thanks,

Subject: Toll Model Review Meeting Updates

This is the content of an email: This is a very rough draft based on an agreement done previously with a jv company. I'm sending it for Enron review only, since I haven't even read the entire thing yet. I thought you might want to take a look at it to see what you think, and to consider the scope of the services to be provided. As for legal services, one alternative would be to have the services provided by an outside law firm, not associated with either principal. Could you forward me what you received from Clement regarding the corporate guaranty issue? I would like to see what's the latest in that regard. Thanks,
Subject: Services agreement