From: mike.mcconnell@enron.com
To: jeffrey.shankman@enron.com
Date: 2000-12-04 18:33:00+00:00
Subject: Re: Jose LNG - Crude Pricing

---------------------- Forwarded by Mike McConnell/HOU/ECT on 12/04/2000 
06:32 PM ---------------------------


Eric Gonzales
12/04/2000 06:45 AM
To: Eric Groves/HOU/ECT@ECT
cc:  (bcc: Mike McConnell/HOU/ECT)
Subject: Re: Jose LNG - Crude Pricing  


Our ability in crude is apparently very poor.  What can J Wilson do thru 
2010?  I want the crude desk to make us a price and present an acceptable 
volume.  

If we have to suggest to PDVSA only doing a crude index through 2012, I 
strongly believe we should try if we can create some additional value thru 
this structure.  Tell me if you would like me to give him a call to explain 
what the effort potentially create.

Thanks
Eric



   
	Enron Capital & Trade Resources Corp.
	
	From:  Eric Groves                           30/11/2000 17:04
	

To: Guido Caranti/ENRON_DEVELOPMENT@ENRON_DEVELOPMENT, Emilio 
Vicens/ENRON_DEVELOPMENT@ENRON_DEVELOPMENt, Eric Gonzales/LON/ECT@ECT
cc:  

Subject: Re: Jose LNG - Crude Pricing  

 Per a conversation I had with John Wilson the head crude oil trader in the 
Houston office, the feasability of hedging price risk linked to WTI or Brent 
on a 20 year deal is NOT a possibility.  If we had 1/3 of our GSA price 
linked to Brent our exposure for 20 years would be about 30 million barrels 
notional or about 14 million barrels PV.  At 5% our exposure would still be 5 
million notional or 2.3 million PV.  According to John, he would not be 
comfortable doing anything past 2012 and even out that far he would not 
consider doing more than about 1 million PV barrels in the years 2010 - 
2012.  Given these comments, I would say that the size of our deal basically 
precludes a look at Crude Oil hedges at this time.  As far as the economics 
of the deal are concerned, we basically cannot even get an Offer to use to 
figure out our economics.  I am confident that if we pushed the issue to see 
if we could get a 20 year offer even for a small portion of the volumes that 
the hedging costs would be too high, and therefore have left it at that for 
the time being.   Please advise if you have any thoughts on the issue.

Thanks,

Eric









Guido Caranti@ENRON_DEVELOPMENT
11/29/2000 09:27 AM
To: Eric Gonzales/LON/ECT@ECT
cc: Emilio Vicens/ENRON_DEVELOPMENT@ENRON_DEVELOPMENt@ECT, Larry 
Lawyer/NA/Enron@Enron@ECT, Cris Sherman/HOU/ECT@ECT, Brent A 
Price/HOU/ECT@ECT, Eric Groves/HOU/ECT@ECT, Daniel R 
Rogers/ENRON_DEVELOPMENT@ENRON_DEVELOPMENT 
Subject: Re: Jose LNG - Off-take Comments  

Eric, thanks for your comments. Please see below in blue our observations and 
answers. Let's talk later today if you have further questions.

Saludos

Guido and Emilio 


Enron Offtake Agreement

Section 2
Should this agreement start at commercial hand over of the plant under the 
EPC agreement.  Benefit here is LDs under the EPC for late delivery go to 
project company and project company has no obligation to lng buyers.  In 
addition it preserves your 20 year offtake which should still match your GSA.

 The agreement should start at commercial hand over of the plant as you say. 
The draft as it is now has only outer limits as to when that should happen 
(that being the earlier of 40 months after Financial  Close or NTP or Dec 31 
2004). We will add to this list "the earlier of" something like: "the date on 
which the plant has produced LNG at at least 90% of its capacity for a period 
of 10 consecutive days". We suggest putting something like this as opposed to 
"commercial hand over" because this is in the plant's/contractor's control 
and they could, for example, on purpose not meet a noise level requirement 
for 4 months  for example and delay commencement of the offtake contract 
while the project sells LNG at higher prices than in the term sheets.

With regards to the EPC LDs we agree that they should go only to the project 
but we, as offtakers, can not wait for ever for the project to be completed 
with out receiving gas or damages for something that is somehow (directly or 
indirectly) under the project's control. We have 4 months limits to how much 
the project can be delayed on top of all the conservatism that EECC (or 
another EPC Contractor) already built in.  

Section 6
I would like to see some language in this section describing the pricing 
formula associated with expansions.  Structure could be set as in this 
contract where Pg is to reflect GSA costs and where the combined value of 
Pcpi and Pa should be derived to provide an equity return to the sponsors of 
18%.

 We agree that would be better, but we included this section knowing that is 
something that is going to be a very difficult sell with PDVSA, because they 
don't want us to sell down and then keep "controlling" new  LNG businesses in 
Jose. They will oppose this clause as they violently opposed the limited 
exclusivity at Jose that we managed to include in the GSA. We think that 
adding a restriction to the asset's returns now in the draft will make it 
very tough to sell to PDVSA the entire Clause. Thus, jeopardizing our chance 
to control the output of future plants or expansions. We never intended to 
use these off-take agreements as a vehicle to control future LNG volumes. 
Nevertheless, we felt it was a good chance for us to start getting partial 
control of the output. Pushing it too much will back fire and PDVSA will 
clearly realize what our intent is.

Section 7
Where is the bonus calculation?  We did not include it now on purpose. We 
will include it when ever they "remind" us to do so. We want to have another 
fight about the bonus.
Where is the min price? The minimum price is in. We say that one of the  
terms in the price is Pg x En where En is never less than one
I thought you guys were going to trade out CPI for a fixed number? We are 
going to try to do it, but that is first a GSA issue, and we don't want to 
put it here as something firm before we change it in the GSA. We precisely 
bracketed the CPI percentage in the formula because of our thought that we 
want to make it zero  
Have you decided that a WTI index percentage does not help the economics? No, 
we don't have the definitive answer from structuring yet, but our guess and 
based on our meeting with RAC the other day, in which they told us about the 
mess created by an oil escalation in Cuiba (Brazil power plant), we are 
pretty much convinced that oil escalation without oil based LNG sales is not 
convenient. But since we don't have a definitive answer yet we still included 
oil as a possible escalator with a zero weighting (that should have been 
bracketed in the term-sheet, though, and it will).  

Section 10
you have incorporated the GSA default rate for late payment as opposed to the 
Equilibrium rate.  Is this your intent to have a mismatch?
 Yes, we did it on purpose because this will apply also to PDVSA as 
off-taker, and they have a record of paying late so we want them to suffer if 
they do.

you have all new taxes being borne by the project company.  Will the banks 
accept this as the project company will be thinly capitalized.  See section 
18 of the Arcos CTA for ideas if this is an issue.
 The exporter of record will be the project, so the buyer has no business in 
Venezuela other than paying port fees. We do not see any kind of taxes that 
could be imposed on Buyer by Venezuela that would eventually be transferred 
to the project. Banks should be fine with this as this is a risk that 
projects typically take all the time (the heavy crude projects are some 
examples in Venezuela). In addition, the GSA provides for a number of reliefs 
for the Project Company that will help Banks and equity holders to feel 
safer. Although, a large portion of the underlying risk is always there. 

Other
where are the LD calculations explained?  I think you need LDs for GSA 
default and another for plant default.  GSA default should match LD's in GSA 
contract less compensation to plant debt recovery.
 In stead of writing an explicit LD calculation our lawyers suggested that 
the sole use of New York law to rule the deal was simpler and better. New 
York law provides for full market based damages (market price of commodity 
plus extra costs) which is the maximum you can get in a negotiation for an LD 
clause. So, from a legal and commercial point of view we much rather have it 
as it is. We are still discussing w/ Brent Price and Cris Sherman if this is 
sellable to AA for MTM, but our initial view is that it should be since the 
level of LD can not be better. GSA default is market based (provided that 
PDVSA, as we expect, accepts the change we will propose) so the Project 
Company will be able to pay market based damages. For interruption of gas 
supply from PDV for Force Majeure reasons our insurance team is finding out 
if the market will cover such risk so that the project can afford not being 
relieved from performance in such event (this will obviously be to a maximum 
dollar limit to be determined and for a maximum period of time, say 36 months 
- we need time to give you precision on this, but some sort of coverage will 
be available). 

suppose the plant produces 5% less that it is supposed to due to design or 
tech problems (not a FM issue) at commercial hand over.  What happens under 
the offtake agreements?  Will the banks accept this revenue short fall?  Will 
we have to create a reserve?  This may be a big issue with the banks for 
technology reasons and lack of experience in this industry.
  Under the off-take agreements the project pays market based damages if it 
does not meet the contracted volume. We believe that the contracted volume 
that we included in the term sheets though has enough of a cushion for banks 
and equity holders to bear the risk. We are contracting for contractually 
guaranteed production under the EPC which is 3% lower than expected. On top 
of that we are considering LNG production with the richest inlet gas possible 
(meaning a lower LNG volume). This volume is 5% lower than the guaranteed 
production with "Normal" or expected feed composition. Combining these two we 
have a contracted quantity that is 8% lower than the expected production with 
expected feed. On top of this it is important to note that every single LNG 
plant in the world ended up with a production capacity that is at least 10% 
above what was expected (mostly due to EPC Contractors and tech partners 
making very safe assumptions on guaranteed volumes to avoid LDs). Also the 
EPC contract being negotiated provides for pretty severe LD in case of 
production shortfalls that are enough to pay for debt and make equity-holders 
whole. They don't provide though, for damages payable under off-take 
contracts (nobody will take this potentially huge exposure on LDs). However, 
as we explained, we believe that this is a risk that is typically taken by 
producers and that we have already taken a very conservative assumption in 
the volume contracted and that should be beard by the Project Co. Banks will 
most definitely also take a conservative volume assumption, as we already 
did. 

What happens if plant starts producing less for a few weeks until problem is 
resolved? what compensation do the offtakers get? do the banks suffer here as 
well?
 The term sheet establishes an annual quantity as the only standard to 
determine failure to deliver by Seller. It also establishes that deliveries 
should be at rates and intervals that are reasonably constant. The bottom 
line is that the termsheets do not go into all the detail about timing of 
defaults and price differentials. It sets, however, a reasonable standard by 
which if at the end of the year seller did not deliver the full annual 
quantity and a particular month can be identified where the deficiency occur 
based on the "reasonable constant deliveries" provision, damages will be 
payable based on prices during such month. Yes banks suffer here to the 
extent that the cause of the short fall is not insurable.  Nevertheless, 
short periods (weeks) of failures to deliver by seller will really not affect 
the Project Company ability to pay the Banks.  It will have to be some 
prolonged period for Banks to be affected.   

Under a plant FM issue you may not get BI cover for the first 60 days.  Will 
the banks accept this or will they want a reserve established.  Is this in 
your model?
 We are not sure off what the banks are going to require in this regard 
(although, we agree that some sort of reserve or LC is to be expected). Our 
model assumes the cost of an LC for 6 month debt service (which should be 
plenty). The issue here is if MTM is going to be able to live with the same 
or longer grace period for damages to kick in under the termsheet and weather 
damages (not BI) are insurable and to what extent if FM relief is not 
permitted for MTM reasons. The question that follows is: if damages exceed 
the insured limits in a FM event that does not relief the project from its 
obligation to deliver, have the damages have to be senior to debt payments 
for AA to allow MTM to be permitted? If this is so, are the banks going to be 
willing to live with this?, probably not.

insert something on planned maintenance timing and scheduling.
 It is briefly covered in section 9 second paragraph. This will be expended 
in later drafts once the PA is signed and we are home free with regard to 
PDVSA.

insert termination section
 In light of the fact that we will end up being more of an off-taker than an 
asset owner in this project our lawyers suggest that we will get better 
protection if early termination is ruled by what is provided under NY law 
than if we try to right an early termination clause. They point out also that 
90% of LNG contracts are done in this way, having NY law rule the game. They 
point out also that from the project point of view banks are very used to and 
prefer having early termination be ruled by NY law.
  
put something in about the buyer willing to accept entering direct agreements 
for financing requirements?
 We will




Eric Gonzales@ECT
11/28/2000 03:40 AM
To: Guido Caranti/ENRON_DEVELOPMENT@ENRON_DEVELOPMENT, Emilio 
Vicens/ENRON_DEVELOPMENT@ENRON_DEVELOPMENt
cc: Larry Lawyer/NA/Enron@Enron, Cris Sherman/HOU/ECT@ECT, Brent A 
Price/HOU/ECT@ECT, Eric Groves/HOU/ECT@ECT, Daniel R 
Rogers/ENRON_DEVELOPMENT@ENRON_DEVELOPMENT 

Subject: Re: Jose LNG - Off-take Comments  


Enron Offtake Agreement

Section 2
Should this agreement start at commercial hand over of the plant under the 
EPC agreement.  Benefit here is LDs under the EPC for late delivery go to 
project company and project company has no obligation to lng buyers.  In 
addition it preserves your 20 year offtake which should still match your GSA.

Section 6
I would like to see some language in this section describing the pricing 
formula associated with expansions.  Structure could be set as in this 
contract where Pg is to reflect GSA costs and where the combined value of 
Pcpi and Pa should be derived to provide an equity return to the sponsors of 
18%.

Section 7
Where is the bonus calculation? 
Where is the min price?
I thought you guys were going to trade out CPI for a fixed number?
Have you decided that a WTI index percentage does not help the economics?

Section 10
you have incorporated the GSA default rate for late payment as opposed to the 
Equilibrium rate.  Is this your intent to have a mismatch?
you have all new taxes being borne by the project company.  Will the banks 
accept this as the project company will be thinly capitalised.  See section 
18 of the Arcos CTA for ideas if this is an issue.

Other
where are the LD calculations explained?  I think you need LDs for GSA 
default and another for plant default.  GSA default should match LD's in GSA 
contract less compensation to plant debt recovery.
suppose the plant produces 5% less that it is supposed to due to design or 
tech problems (not a FM issue) at commercial hand over.  What happens under 
the offtake agreements?  Will the banks accept this revenue short fall?  Will 
we have to create a reserve?  This may be a big issue with the banks for 
technology reasons and lack of experience in this industry.
What happens if plant starts producing less for a few weeks until problem is 
resolved? what compensation do the offtakers get? do the banks suffer here as 
well?
Under a plant FM issue you may not get BI cover for the first 60 days.  Will 
the banks accept this or will they want a reserve established.  Is this in 
your model?
insert something on planned maintenance timing and scheduling.
insert termination section
put something in about the buyer willing to accept entering direct agreements 
for financing requirements?



Marketing Agreement
Lets talks about his one





Guido Caranti@ENRON_DEVELOPMENT
22/11/2000 23:34
To: Cris Sherman@ECT, Larry Lawyer@Enron, Brent A Price@ECT, Eric Groves@ECT, 
Eric Gonzales@ECT
cc: Les Webber/ENRON_DEVELOPMENT@ENRON_DEVELOPMENT, Nancy 
Corbet/ENRON_DEVELOPMENT@ENRON_DEVELOPMENT, Emilio 
Vicens/ENRON_DEVELOPMENT@ENRON_DEVELOPMENT 

Subject: Jose LNG - Off-take

I am enclosing a draft of the off-take termsheets to be included in the 
Participation Agreement between Enron and PDVSA Gas. These termsheets will 
rule the following transactions:

  a) Sale of LNG from the Project to an affiliate of  Enron for the plant's 
output minus PDVSA's off-take

  b) Sale of LNG from the project to and affiliate of PDVSA Gas for the share 
of volumes equivalent their equity participation in the Project Co

  c) Re-sale of LNG from the affiliate of PDVSA Gas to the Enron affiliate 
for the volumes purchased by PDVSA according to b) above

Please let Emilio and I know your comments about them at your earliest 
convenience. Please focus on issues with regard to our ability to MTM these 
contracts, such as the force majeure clause. If you have any comments or 
questions during the weekend you can reach me at 713 304-4264 or Emilio at 
011 5814 330-9016. Otherwise we would like to discuss this with you on Monday.

Thanks for your input and happy Thanks-giving

Guido