RE: Toll Model Review Meeting Updates ,
 Suggest asking Mike Smith also.  To me looks like the capex inflation and O=
&M inflation are backasswards.

-----Original Message-----=20
From: Hayslett, Rod=20
Sent: Sat 11/17/2001 9:32 AM=20
To: Lee, Jebong=20
Cc: Tu, Denis; Rosenberg, David E.=20
Subject: RE: Toll Model Review Meeting Updates


You should get these 2 experts in pipeline modelling and estimating involve=
d into the discussion.   They have years of experience in inflation and imp=
acts on pipeline economics.

-----Original Message-----=20
From: Lee, Jebong=20
Sent: Fri 11/16/2001 6:24 PM=20
To: Hill, Robert; Gadd, Eric=20
Cc: Ratner, Michael; Kissner, Tim; Reinecke, Bryan; Miller, Mary Kay; Haysl=
ett, Rod=20
Subject: Toll Model Review Meeting Updates



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ctronic copy of the model for withdrawn partners' review. Withdrawn partner=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.=20

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,=20

JB=20

Jebong Lee=20
713-853-9722 office=20
713-306-8658 cell
rod.hayslett@enron.com