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Enron Mail |
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
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