Message-ID: <17282636.1075843912937.JavaMail.evans@thyme> Date: Thu, 14 Dec 2000 05:41:00 -0800 (PST) From: mike.mcconnell@enron.com To: eric.gonzales@enron.com Subject: Re: Jose LNG - Crude Pricing Cc: jeffrey.shankman@enron.com Mime-Version: 1.0 Content-Type: text/plain; charset=us-ascii Content-Transfer-Encoding: 7bit Bcc: jeffrey.shankman@enron.com X-From: Mike McConnell X-To: Eric Gonzales X-cc: Jeffrey A Shankman X-bcc: X-Folder: \Mark_McConnell_June2001\Notes Folders\All documents X-Origin: MCCONNELL-M X-FileName: mmcconn.nsf Eric, is this still a problem or did you get what you needed? m 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