So far there's Wild Goose, but there in Northern California--have to go 
through the Wheeler bottleneck--so that likely won't hunt.  Lodi's a 
possibility, but it's well inland, unlike the significantly more strategic 
storage assets on the coast.  In addition, Lodi's in the process of selling, 
so there's some uncertainty in the short run.  Bottom line, folks are trying 
to build competitive storage, but it's in the "emerging" phase in a very 
hostile environment.  We should discuss further, though; very interesting 
idea.

Best,
Jeff  



	James D Steffes
	05/22/2001 08:45 AM
		
		 To: Robert Neustaedter/ENRON_DEVELOPMENT@ENRON_DEVELOPMENT, Jeff 
Dasovich/NA/Enron@Enron
		 cc: 
		 Subject: Re: California LNG

Robert & Jeff --

Is there some other (competitive) storage that would want to work with our 
deal in CA other than SocalGas?  Maybe find someone adding some new storage.

Jim




Robert Neustaedter@ENRON_DEVELOPMENT
05/16/2001 10:20 AM
To: Kurt Lindahl/ENRON_DEVELOPMENT@ENRON_DEVELOPMENT, Jody 
Crook/Enron@EnronXGate
cc: Harry Kingerski/NA/Enron@Enron, James D Steffes/NA/Enron@Enron 

Subject: California LNG

In response to your request to review the SoCalGas tariff with respect to 
storage service for quantities of  gasified LNG in excess of market I present 
the following.

SoCalGas has various storage rate schedules available to its customers, 
including forms of interruptible storage service.

Because of the long-term nature of the proposed project and firm injection 
requirements I focused on Schedule No. G-LTS (firm Long-Term Storage Service).

Pricing under this schedule is very flexible (both upwards and downwards).  I 
have used the rates included in the tariff which are suppossed to closely 
correspond to utilty cost of providing such service and are also consistent 
with rates previously supplied for economic modeling purposes.  Keep in mind, 
these are benchmark costs, and may be subject to downward or upward 
negotiation.

Because of the magnitude of the injection quantities, it was advised that 
some expansion of storage capabilities may be required.

Fixed charges consist of an annual inventory capacity charge, and annual 
withdrawal capacity charge and a monthly firm injection charge.  The monthly 
firm injection charge is the largest cost component.  Based on conversations 
with SoCalGas, firm injection rights (similar to pipeline capacity) would be 
sold on a monthly basis.  Consequently, in order to have firm rights to 
injection capacity, it would have to be reserved 365 days out of a year.  
During the off-peak season, "as-available" injection rights may be used that 
could substantially lower the cost, but given the inflexibility of unloading 
of the LNG ships, this was not considered.

Variable costs would consist of injection and withdrawal charges in the 
applicable periods (peak and off-peak) for injection and withdrawal 
quantities.

A fuel retention factor of 2.44% would be applied to injections during the 
peak period.

While not necessarily affecting the overall costs, a transmission charge on 
injections and withdrawals would also be assessed.  A transmission charge on 
injections would appear as a debit on the invoice, and an equal transmission 
charge on withdrawals would appear as a credit, effectively resulting in a 
wash.  However, for cash flow purposes it should be considered.  The 
transmission charge is approximately 57 cents per dekatherm.

Transportation from storage would require a separate contract.

A spreadsheet is attached that quantifies the storage cost on an annual basis 
utilizing the injection/ withdrawal and inventory assumptions provided.  
Again, please keep in mind that the actual costs are negotiable.

I hope this helps in your analysis, and please feel free to call and discuss 
further.

Robert