Message-ID: <20427693.1075846132182.JavaMail.evans@thyme> Date: Thu, 15 Jun 2000 10:41:00 -0700 (PDT) From: christi.nicolay@enron.com To: kay.mann@enron.com, heather.kroll@enron.com, ozzie.pagan@enron.com, jeffrey.keenan@enron.com, tom.chapman@enron.com Subject: Re: VEPCO PPA Mime-Version: 1.0 Content-Type: text/plain; charset=us-ascii Content-Transfer-Encoding: 7bit X-From: Christi L Nicolay X-To: Kay Mann, Heather Kroll, Ozzie Pagan, Jeffrey M Keenan, Tom Chapman X-cc: X-bcc: X-Folder: \Kay_Mann_June2001_4\Notes Folders\Vepco X-Origin: MANN-K X-FileName: kmann.nsf Several thoughts from federal reg./transmission side: I haven't worked with a VEPCO interconnection agreement yet, but many times there are requirements that the generator is required to provide emergency power to the interconnected transmission provider, in which case you would want the interconnection agreement to cover all costs you would incur to replace the energy at a different location (usually it is difficult to get this agreement, so you should check and then factor that into the equation). I would be happy to look at the interconnection agreement with you. Interconnection of generation is a separate process from requesting transmission. It appears that VEPCO has to buy the transmission (or use its network transmission) when the Delivery Point is the plant. Enron will have to purchase transmission on VEPCO if it is selling to third parties off the plant and will have to purchase transmission on other systems if it wants to supply at an alternate delivery point. Please discuss this with Kevin Presto's tranmission people (Bill Rust on 31). Enron cannot use VEPCO's network transmission to delivery to third parties. Is this plant in the VEPCO queue yet? Also, FERC has issued some recent rulings that deal with time limits on system impact studies, etc. While VEPCO is probably incentivized to get this built, you want to make sure that you do not lose optionality in selling to third parties from the plant due to transmission constraints. A request for transmission on OASIS is the only way to ensure deliverability to third parties. 3.5 (c) Intra-day scheduling--You may have hourly transmission risk for an increase. Unless you buy longer term firm, you will deliver from other sources using hourly non-firm, which is the lowest priority of transmission and subject to getting cut. You may want to consider doing this on best/reasonable efforts basis. (Also, even if you purchase daily/monthly/yearly firm to serve third parties, if you change the point of receipt or point of delivery temporarily, your request is treated as non-firm.) 12.4--Currently VEPCO is interested in joining the Alliance ISO (an RTO that has not been approved by FERC yet--competing ISO to Midwest ISO), but since FERC has not approved any RTO for VEPCO yet, there could be significant changes in the transmission charges/methods of obtaining transmission/grandfathering of current transmission, etc during this contract. Make sure with the ENA attorneys that this out/increase in price covers that circumstance. Underlying tranmission rates on VEPCO or any other provider can change at most any time, subject to the provider filing a rate case. Therefore, any current transmission rates shown on OASIS are not necessarily what you will pay over the term of any transmission that Enron may purchase to serve this contract. Generally, transmission providers will not agree to fixed rates. Tom Chapman 06/13/2000 06:07 PM To: Christi L Nicolay/HOU/ECT@ECT cc: Subject: VEPCO PPA Christi-- This is the note that I received on Tuesday June 13. This is a relatively early draft of the PPA. I think that we still have to purchase the land associated with the sites and do the due diligence on the site with regards to some of the siting issues. IN addition, in NC we are going to get a CPCN to site the plant to speed up the regulatory process in the NCUC. I think that this will make the issue less contentious because of the NCUC's acceptance of the Dynegy plant at Rockingham that had a PPA with Duke Power. Using the Dynegy plant as a guideline, their only stumbling block was their gas agreeement. They built a bypass off Transco. We would be taking gas from the LDC of Rocky Mount. Having talked with the regulatory folks at the NCUC who handle gas issues, this is the preferred route. So, I do not think that we have any major state issues. I think that right now we are simply working on some of the siting issues. That being said, I will let you take a look at the PPA and let me know or Jeff Keenan (or even Heather Kroll or Ozzie Pagan) if you think that there are some transmission issues or other issues on the federal level. Thanks. Tom ---------------------- Forwarded by Tom Chapman/HOU/ECT on 06/13/2000 06:04 PM --------------------------- Linda J Simmons 06/13/2000 08:45 AM To: Kay Mann/Corp/Enron@Enron, Heather Kroll/HOU/ECT@ECT, Ozzie Pagan/HOU/ECT@ECT, Jeffrey M Keenan/HOU/ECT@ECT, Tom Chapman/HOU/ECT@ECT cc: Subject: VEPCO PPA ----- Forwarded by Linda J Simmons/HOU/ECT on 06/13/2000 08:44 AM ----- "Nancy Wodka" <nwodka@bracepatt.com> 06/12/2000 04:20 PM To: <linda.j.simmons@enron.com>, <lisa.mellencamp@enron.com> cc: "William Frederking" <wfrederking@bracepatt.com> Subject: VEPCO PPA Lisa: Attached is a draft of the Power Purchase Agreement with VEPCO, based on the current version of the term sheet. In preparing the draft, we did encounter several additional questions for Enron's consideration. These are noted with brackets and, in some cases, italicized notes, in the draft and are also highlighted below. You may want to address these issues before this goes to VEPCO. Cover and first page-- Should the party to the agreement (for the moment) be ENA or a special purpose company? Definitions-- We included a defined term "Emergency Start-Up" (a start up or increase in energy scheduled during a day) and a place in Exhibit A to include a price for this, although this was not covered in the term sheet. Section 2.2-- We included a provision for VEPCO to take test energy (energy charge only; no demand charge)--do you want this? Section 2.3-- This was taken from the term sheet, but is it correct that COD will be July 1 (since the demand charge is supposed to start June 1?) Also, it would be best to define "commencement of construction" to avoid controversy down the road. We could either do this now or put in a placeholder that indicates it needs to be defined or be silent, whichever is your preference. Also, bear in mind that we have not included a specific remedy (e.g., liquidated damages) if the Seller does not achieve that milestone on time. Under the default provision (Section 8.1(c)), there would be a 30 day period to cure before Buyer could terminate (extendible to 90 days if a longer period of time is needed and Seller diligently pursues the cure). Would you prefer the right to pay ld's and extend the time period? Section 3.1(b)-- Should the 1400 hour limitation apply to all sales under this PPA or only sales from the Facility? I.e., would you use this Agreement to sell to VEPCO power in addition to what would be available from the Facility? Also, is this a calendar year limitation--i.e., could they take 1400 hours in the period June-Dec. 2001 or does the 1400 hours need to be pro-rated for the first year? Section 3.4-- Since this is not a base load plant, the normal definition of Availability as the number of hours in a year of operations compared to the total hours in the year would not seem to be applicable. Instead, we stated that the Facility would be capable of being available 92% of the year (other than due to Force Majeure and 336 hours (2 weeks) of scheduled maintenance)--i.e., that if they tried to schedule it, it is expected to be available. Is that what Enron intended? Additionally, the term sheet stated that a remedy for failure to meet Availability would need to be agreed--why wouldn't cost of cover damages be appropriate? Also, please note that we included language stating that Seller will not perform maintenance during peak periods. Section 3.5(b)-- Please note the bracketed language re taking Blocks of Energy. We have 50 MW minimum blocks but the capacity is 223--should we allow the last Block to be 23 if they've scheduled all the rest? Section 3.5(c)-- Please see the bracketed language at the end of this Section. Section 4.7-- Should there a required minimum take of Energy? Article 6-- The Genco/Santee Cooper form of PPA we used as a model did not have any provisions on metering. (See placeholder note in Article 6.) Do you want to add such a provision, ignore it or just include a placeholder for now? Section 9.1-- Is 30 days from invoice correct for the payment due date or would you prefer a shorter period? Article 15-- The Genco/Santee Cooper form had mediation as a required step prior to arbitration. Should we keep that? Also, the form of arbitration is "baseball" arbitration--i.e., the arbitrators have to chose one party's position or the other's. Is that what you want? Section 16.2-- We used New York for governing law, on the premise that it will be difficult to get VEPCO to agree to Texas law and we would not recommend Virginia law for this contract. Exhibit A-- There are a number of questions on the pricing exhibit--please see the bracketed notes therein. Please call and let us know how you would like to proceed on this draft. - VEPPPA.DOC