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Enron Mail |
---------------------- Forwarded by Christi L Nicolay/HOU/ECT on 10/03/2000=
=20 06:40 PM --------------------------- Christi L Nicolay 10/03/2000 06:49 PM To: Tom Briggs/NA/Enron@ENRON cc: James D Steffes/NA/Enron@Enron, Richard Shapiro/HOU/EES@EES, Joe=20 Hartsoe/Corp/Enron@Enron=20 Subject: Re: Draft Questions for Hoecker =20 Tom--[[For your background information for Senator Gordon--you will need to= =20 edit out the information on the part Enron played, but I thought you would= =20 want the entire picture]]. Until the Tennessee Power case issued in March, most utilities considered= =20 interconnection issues and procedures to be within their discretion. The= =20 only FERC approved policies were in PJM and NEPOOL. These policies are=20 fairly idiosyncratic to those pools. Since Enron began siting merchant=20 generation with our 1999 peaking plants in TVA, we had told FERC that there= =20 were problems in getting utilities to be responsive. The main problem was= =20 failure to provide study results in a timely manner. I think it is important to note that merchant facilities are a fairly new= =20 idea. They are not rate-based, and have no guaranteed return paid for=20 directly by retail customers (except perhaps to the extent that a utility= =20 signs a deal to purchase capacity and/or energy from the merchant.) Plus, = I=20 think the utilities are incentivized under the current vertically integrate= d=20 structure to benefit their own merchant plants or their utility plants (les= s=20 supply). ? TENNESSEE POWER ORDER ON INTERCONNECTION POLICY -- FERC issued an order o= n=20 3/15/00 clearly expressing its policy on interconnection issues. The order= =20 is significant because it was issued in large part due to the lobbying=20 efforts of EPMI and other generator members through Enron's membership in t= he=20 Electric Power Supply Association ("EPSA"). =20 In mid-January, EPSA arranged all-day meetings for Sarah Novosel (Enron) an= d=20 other EPSA members to meet with the FERC Commissioners and staff to discuss= =20 interconnection issues. Fourteen EPSA member-companies were represented at= =20 these meetings, and we expressed to the Commissioners and FERC staff the=20 problems we are facing in our efforts to successfully negotiate=20 interconnection agreements with utilities. We urged the Commission to, at = a=20 minimum, develop procedures that will make requesting and negotiating=20 interconnection agreements less time consuming and more even-handed. The= =20 Commission had assumed that the procedures laid out in the pro forma tariff= =20 for requesting transmission service also applied to requests for=20 interconnection, and they were surprised to learn that most utilities do no= t=20 abide by the procedures for interconnection requests. =20 In the Tenn. Power order (that dealt with a complaint filed by Tennessee=20 Power Co. against Central Illinois, which FERC dismissed), FERC clarifies= =20 that the pro forma tariff procedures established for transmission requests= =20 apply equally to interconnection requests. Furthermore, FERC states that a= =20 utility may not require a generator to submit a request for transmission=20 service along with its request for interconnection service, stating that=20 these are separate services and should be treated separately by the utility= . =20 (Many generators have found that utilities are requiring them to submit=20 transmission requests at the time they submit interconnection requests, and= =20 then the utility insists on performing costly and time-consuming system=20 impact studies for the transmission service, even if the generator does not= =20 want the transmission service). By applying the pro forma tariff procedure= s=20 to interconnection requests and by requiring utilities to accept=20 interconnection requests without transmission service requests, FERC is=20 eliminating many of the roadblocks currently encountered by generators in= =20 attempting to obtain interconnection from utilities. FERC also states that= =20 if the parties to an interconnection agreement fail to agree on the rates,= =20 terms or conditions of the interconnection, the transmission customer may= =20 direct the utility to file within 30 days an unexecuted agreement with FERC= . =20 FERC will then have 60 days to determine the just and reasonable rates, ter= ms=20 and conditions for the interconnection service. =20 During the FERC agenda meeting on 3/15, Commissioner Massey was very please= d=20 with the order and congratulated his colleagues on providing the industry= =20 with needed guidance. Commissioner Massey then encouraged utilities to eac= h=20 develop their own standard interconnection agreement that applies to all=20 generators requesting interconnection service, and he also encouraged the= =20 industry to work together to develop an industry-wide pro forma=20 interconnection agreement. EPMI has been working with EPSA on a pro forma= =20 interconnection agreement, so Commissioner Massey's comments could encourag= e=20 the utility sector to begin negotiating an industry-wide standardized=20 agreement. However, even without a standardized agreement, we hoped that= =20 FERC's order will help remove many of the obstacles currently used by=20 utilities to delay (sometimes indefinitely) the citing of new generation. ? TECO HOURLY IMBALANCE FILING -- TECO made a FERC filing to require minute= =20 by minute balancing for generators that interconnect to the transmission=20 system. EPMI protested through EPSA and asked for hourly balancing. Befor= e=20 an order was issued (somewhat unprecedented behavior before FERC), TECO=20 withdrew its minute filing and refiled for hourly imbalance calculations. = =20 At this time, FERC has not accepted requests by EPSA and others to create = a=20 "standard" generator imbalance schedule for the OATT. FERC has said it wou= ld=20 review the filings on a case by case basis. FERC has not required utilitie= s=20 to file imbalance schedules -- it "encourages" them to do so. At this time= ,=20 only Entergy, SOCO, TECO and several other utilities have filed imbalance= =20 provisions as amendments to their OATTs. Most utilities require this to be= =20 "negotiated" (not much room for negotiation) in the interconnection=20 agreements. While FERC requires interconnection agreements to be filed at FERC and the= y=20 can be filed "unsigned," and then protested, this can be an impractical=20 solution when building a peaker in less than one year, such as Enron has=20 done. A merchant power producer is more likely to move the project to a mo= re=20 friendly utility forum or accept some provisions that may be somewhat onero= us=20 in order to site and build the plant for summer start dates. ? ENTERGY INTERCONNECTION FILING =01) On 3/1/00, Entergy filed a proposed= =20 interconnection policy and procedure at FERC. EPMI protested various aspec= ts=20 and we assisted EPSA on its protest. Before the order was issued (again=20 fairly unprecedented), Entergy agreed to make certain changes to its propos= ed=20 interconnection procedure and interconnection agreement in response to=20 protests. (Entergy asked FERC to delay an order until it could make this= =20 filing.)=20 Entergy agreed to change: Defines "required" system upgrades as those required to simply interconnect= . =20 (EPMI and EPSA issue). ("Required" are those such as resulting from the=20 Short Circuit/Breaker Rating Analysis and Transient Stability Analysis--lik= e=20 circuit breakers, relaying devices, system protection equipment.) Customers are not required to supply reactive power except when "in service= "=20 (did not go as far as EPMI argued -- that we should not be required to=20 provide it or should receive the cost of our liquidated damages if we have = to=20 cut our deal. Entergy said it will pass through amounts it receives.) Adopted EPMI's proposed "Emergency" language that loss of Entergy's=20 generation and inability to meet its load requirements is not an Emergency. Agreed that Entergy cannot interrupt generator for "non-emergencies" except= =20 when "complying with reliability protocols or procedures established by NER= C=20 or SERC or reg. agency (EPMI issue). Changed force majeure language to match OATT. Entergy also states that it will not include generators in Short=20 Circuit/Breaker Analysis and Transient Stability Analysis until an=20 interconnection agreement is signed, although the generation projects will= =20 remain in the queue. This can cause the costs to vary from the 1st estimat= e=20 to time of actual interconnection. On 5/18/00, FERC issued an order accepting Entergy's pro forma=20 interconnection agreement ("IA") and procedures subject to modification. A= s=20 I mentioned above, Entergy had adopted some of EPMI's suggestion (in EPMI's= =20 comments), including limiting emergencies to not include Entergy's loss of= =20 generation. All transmission must be separately arranged through OASIS -- it is not=20 included with an interconnection request. Entergy's interconnection policy will apply to generators that will serve= =20 wholesale, as well as unbundled retail. Dismisses EPSA's call for a "model" and approves Entergy's pro forma=20 interconnection agreement, subject to modification.((The Commission stated= =20 "EPSA, Dynegy, and PG&E argue that the Commission should initiate a generic= =20 proceeding or industry collaborative to address interconnection=20 concerns....The Commission declines at this time to issue a policy statemen= t=20 or convene a industry collarboration to establish standardized IPs=20 (Interconnection Procedures) and IAs (Interconnection Agreements). With=20 respect to IPs, the Commission's recent findings in Tenn. Power amplify the= =20 Commission's findings in Order No. 888, which established standard procedur= es=20 for obtaining transmission service. It is our belief that no additional=20 standardized procedures are necessary at this time. We do, however,=20 encourage utilities to do as Entergy has done here and revise their OATTs t= o=20 include procedures for requesting interconnection services and the criteria= =20 for evaluating those requests. Because an RTO will administer its pro form= a=20 tariff, it is our hope that compliance with our RTO rulemaking will elimina= te=20 concerns about interconnection procedures." at p. 10.) Agreed with EPMI that billing disputes should be placed in escrow, not paid= =20 to Entergy subject to refund (FERC said that the IA should conform to other= =20 aspects of the Order No. 888 tariff--for example, Entergy and customer are= =20 responsible for their own negligence). Holds that all other terms of the Order No. 888 pro forma tariff apply to t= he=20 IA, even if the IA does not repeat all those provisions. Clarifies Tenn. Power case that if a generator connects first and another= =20 generator subsequently connects in the same local area and the grid cannot= =20 accommodate "receipt" of power without expansion, the new generator must pa= y=20 costs of expansion. Entergy is required to revise IA to make distinction as to which provisions= =20 are pure "interconnection" and which are applicable when=20 transmission/delivery is also requested (on OASIS). Entergy is required to attempt to complete the interconnection studies in a= =20 specific timeline (60 days for 1st iteration --system impact), and to provi= de=20 a statement that Entergy will notify applicant of any delay with an=20 explanation for the delay (Entergy had included no timelines). If applicant and Entergy cannot agree on IA terms, Entergy must file the=20 unexecuted agreement at FERC for FERC to decide. Approves Entergy's credits for "optional" upgrades (required to transport= =20 power away from the plant), but requires Entergy to file an explanation of= =20 how the credits work. Entergy will only include prior queued interconnection requests in subseque= nt=20 studies once they have signed an interconnection agreement (to show more=20 intent to actually complete the project). This does not mean that failure = to=20 execute an IA results in removal from the queue, just that the generator ma= y=20 be subject to different actual interconnection costs when it connects. Thi= s=20 is a risk that FERC says is inherent in interconnection. Entergy will also= =20 post its queue on OASIS. Reactive power must only be supplied when generator is operating. Per EPMI=01,s comments, Entergy cannot keep the initial $10,000 deposit, un= less=20 actual costs are $10,000 or greater (generator must pay actual costs of=20 studies). Per EPMI's comments, Entergy must pay for energy taken during an emergency= =20 (or explain why that is inappropriate). Per EPMI's comments, Entergy must explain the requirement that the generato= r=20 pays for subsequent changes to Entergy's transmission system. ComEd Interconnection procedures -- On 3/6/00, ComEd filed interconnection= =20 procedures. Enron's comments were included in EPSA's protest on the=20 following issues. Proposed procedures: 1. Submit valid request to interconnect (include # of generating units,=20 proposed max MW capacity and MVA, specific location, operational date). Da= te=20 and time of receipt by ComEd establishes queue position. This info will be= =20 posted on OASIS within 15 days (without listing the applicant's name). 2. Within 30 days of the request, LOI will be tendered. Applicant has 30= =20 days to respond or lose queue position. LOI authorizes commencement of=20 engineering work. 3. Within 45 days of LOI, ComEd will perform an Interconnection Study with= a=20 project diagram. Study assumes interconnection of all "competing" requests= =20 (that ask for a location that affects your interconnection costs) that have= =20 prior queue dates. 4. Within 30 of receiving the interconnection study, Applicant must decide= =20 whether to proceed. 5. After Applicant decides to proceed, Applicant may have a maximum of 90= =20 days for a ROFR against lower priority requests and to begin negotiating an= =20 Interconnection Agreement. Although somewhat unclear, if there is a=20 "competing" request, Applicant must exercise its ROFR within 15 days by=20 notifying ComEd of the desire to begin negotiating an interconnection=20 agreement. If Applicant doesn't negotiate an IA-- lose queue spot. 6. Once IA negotiations begin, Applicant has 90 days to execute it (or=20 submit dispute to arbitration). 7. Before ComEd does inititates construction or installation of facilities= ,=20 IA must be executed. (if generator is to come on line in < 1 year, ComEd= =20 will negotiate an agreement (with appropriate financial safeguards) to=20 proceed before execution of the IA.) 8. ComEd will include "reasonable milestones" that must be met in order to= =20 maintain queue position. My specific comments for comment: Some items are unclear. (1) Whether the "Decision" to proceed is made in= =20 writing (which it should be); (2) The entire ROFR procedure (does it become= a=20 race to see who executes an IA faster?) The 90 day IA execution period is now inconsistent with FERC's new statemen= t=20 in Tenn. Power (30 days). If ComEd won't start work until after the IA is executed, then the 30 days= =20 needs to be adhered to (otherwise, the timetable seems too long before work= =20 begins). Milestones need to be specified (the current proposal contains "may" includ= e=20 milestones, and "may" include the following...) Also, ComEd wants to=20 "reasonably extend" the milestones. This must be done on a=20 non-discriminatory basis. ComEd allows itself 45 days to complete the Interconnection Study and this= =20 can be extended in ComEd's "sole judgment." I disagree and think it should= =20 only be extended if ComEd provides a reasonable explanation to FERC (simila= r=20 to the pro forma procedures now in section 19.3 re: system impact studies). On 4/26/00, FERC issued an order that again declined to initiate a generic= =20 interconnection proceeding, but "encouraged" utilities to revise OATTs to= =20 include interconnection procedures. FERC also stated that the timelines in= =20 the OATT for transmission system impact studies (60 days) and facilities=20 studies (60 days) are applicable to interconnection studies and that ComEd = is=20 required to provide an explanation for any delays past these deadlines. FE= RC=20 required ComEd to change some other procedures identified by the EPSA prote= st. ? FERC ORDER ON AEP=01,S INTERCONNECTION POLICY =01) On 6/29, FERC issued a= n order=20 on AEP's proposed interconnection procedures. EPMI participated in comment= s=20 through EPSA. While FERC largely reiterated its recent orders on Tenn Powe= r=20 and Entergy interconnection procedure, there are several items of interest: AEP said that it had a backlog of interconnection requests and needed more= =20 than 60 days to complete the System Impact Study. FERC held that AEP must= =20 commit to completing the SIS within 60 days (consistent with the pro forma= =20 tariff), but if AEP determines it needs more than 60 days, it is required t= o=20 notify the customer with the reasons for the delay. FERC further stated, "= We=20 expect AEP to dedicate sufficient resources to these interconnection reques= ts=20 to eliminate its backlog." FERC rejected AEP's proposal to only provide transmission credits for "firm= "=20 transmission (to a customer that is required to pay for system upgrades). = =20 FERC said credits must apply to firm PTP, non-firm PTP, or network. Allows AEP discretion on hiring third party contractors (since AEP would ha= ve=20 to spend time educating the third party contractors); however, FERC=20 reiterates that AEP must eliminate its backlog. ? SPP Interconnection procedures -- In 7/00, SPP filed clarifications to i= ts=20 interconnection procedures recently filed at FERC. EPMI participated in=20 EPSA's protest that the System Impact Study should be completed in 60 days= =20 (or SPP should provide an explanation for the delay), instead of the 90 day= s=20 requested by SPP. SPP has agreed to this change (which is also consistent= =20 with FERC's recent order on AEP's interconnection procedures.) Also, it=20 appeared that SPP wanted the Interconnection Agreement to be executed withi= n=20 15 days, which is close to physically impossible, especially when SPP has n= o=20 pro forma IA. SPP agreed to 60 days. CP&L interconnection procedures -- Most recently, CP&L filed interconnecti= on=20 procedures that ask for a 90 day study period despite the FERC orders in AE= P=20 and SPP stating that the deadlines are 60 days. EPSA protested with yet=20 another appeal to FERC to standardize these procedures. FERC has not issue= d=20 an order. =20 The lack of standardized procedures has become problematic in just the few= =20 months since Entergy's procedures were filed. We are required to constantl= y=20 monitor the notices for any procedures that have been filed, then check eac= h=20 one carefully to determine how it deviates from the Commission's orders in= =20 other cases. The utilities are not required to point this out in their=20 filings (ie, no redlining from an OATT, which is required in transmission= =20 OATT changes.) Tom Briggs@ENRON 10/03/2000 02:48 PM To: Richard Shapiro/NA/Enron@Enron, Mary Hain/HOU/ECT@ECT, Cynthia=20 Sandherr/Corp/Enron@ENRON, Sarah Novosel/Corp/Enron@ENRON, Christi L=20 Nicolay/HOU/ECT@ECT cc: =20 Subject: Draft Questions for Hoecker Attached please find draft questions to be provided to Sen. Gorton for his= =20 hearing on NW price spikes to be held Thursday. I hve tried to design=20 questions that focus on FERC jurisdiction. However, i may have med the=20 questions too specific and detailed. please give me your comments and idea= s.
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