Message-ID: <19514627.1075843851126.JavaMail.evans@thyme> Date: Thu, 15 Feb 2001 08:42:00 -0800 (PST) From: jeff.dasovich@enron.com To: jdasovic@enron.com Subject: Mime-Version: 1.0 Content-Type: text/plain; charset=ANSI_X3.4-1968 Content-Transfer-Encoding: quoted-printable X-From: Jeff Dasovich X-To: jdasovic@enron.com X-cc: X-bcc: X-Folder: \Jeff_Dasovich_June2001\Notes Folders\Sent X-Origin: DASOVICH-J X-FileName: jdasovic.nsf Jim: It was a pleasure speaking with you yesterday. Based on our conversation,= =20 this email includes the following: An Enron contact to discuss developing small-scale, distributed generation = on=20 Tribal lands. Our views on the impediments to small scale, distributed generation and=20 suggestions on how to remove those impediments. A description of the credit issues that continue to impede DWR=01,s ability= to=20 sign contracts with power suppliers, and options to resolve them. Two=20 possible options for addressing the credit issue are 1) a California PUC=20 order clarifying that DWR will recover its power purchase costs through=20 rates, and 2) an amendment to AB1X designed to accomplish the same goal. I= =20 have attached talking points regarding the California PUC order and propose= d=20 amendments to AB1X. We believe that an amendment to AB1X is the preferable= =20 option. Our assessment of the supply/demand picture in California and the West. Our suggestions for a legislative package designed to solve both the near-= =20 and long-term electricity crisis in California. We will deliver to your=20 office tomorrow detailed legislative language. In those materials we will= =20 also identify existing bills that we believe can easily accommodate our=20 proposed language. I hope that the information is useful. Please do not hesitate to contact m= e=20 if you would like to discuss these materials further, or if there is anythi= ng=20 else that I can do to assist you. Regards, Ken 1. Contact Information to Discuss Interest Expressed by Native American=20 Tribes in Installing Small-scale Generation on Tribal Lands David Parquet, Vice-President Enron North America 101 California Street, Suite 1950 San Francisco, CA 94111 Phone: 415.782.7822 2. Key Barriers to Distributed Generation Excessive and Unnecessary Utility Stand-by Charges Solution: The executive orders issued by the Governor on February 14th took= a=20 step in the right direction. Utility stand-by charges have always been=20 designed by the utilities to protect their monopoly position, extract=20 monopoly prices from customers, or both. But there is no reason to limit t= he=20 elimination of these charges to generation facilities that are less than=20 1MW. These limits will only lengthen unnecessarily the time it takes for= =20 California to close the significant gap between supply and demand and reduc= e=20 the risk of black outs. We would propose lifting the cap through amendment= s=20 to SB27X, which is designed to facilitate development of distributed=20 generation. =20 Excessive delays and costs related to interconnecting facilities with=20 investor-owned and municipal utilities Solution: The Governor=01,s executive order regarding interconnection is = a=20 step in the right direction=01*D-D-26-01 requires utilities to complete=20 interconnection studies within 7 days. California should ensure that this= =20 requirement applies to all generation facilities, including distributed=20 generation. In addition, the financial conflicts the utilities face when= =20 interconnecting generation facilities are simply too powerful to overcome= =20 through executive orders or other regulations. To the greatest extent=20 possible, California should shift control over interconnection away from th= e=20 utility and place that control with the California ISO. This could be=20 accomplished through amendments to SB 27X. Permitting and Air Quality Issues Developers of distributed (i.e., =01&on-site=018) generation that is 50 MWs= or=20 greater must receive certification from the California Energy Commission an= d=20 therefore faces all of the impediments to development that large-scale=20 generation faces. =20 Solution: California should ensure that the executive orders (D-22-01 thru= =20 D-26-01) issued by the Governor to expedite plant siting and maximize plant= =20 output apply equally to smaller scale, =01&distributed generation=018 facil= ities.=20 In addition, distributed generation that is less than 50 MWs continues to= =20 face local opposition. The State should ensure that local, parochial=20 interests cannot block otherwise beneficial distributed generation projects= . =20 These objectives could be accomplished through amendments to SB27X. 3. Credit Concerns Regarding Authority Granted to DWR in AB1X to Purchase= =20 Electricity on Behalf of the Utilities=20 Enron responded to the RFP issued by DWR to enter into power contracts with= =20 suppliers. Enron is in active discussions with DWR to establish contract terms with th= e=20 goal of entering into a power purchase agreement as soon as possible. However, ambiguities contained in AB1X have created significant credit risk= =20 concerns that need to be resolved in order to finalize contract terms. We understand that the lion=01,s share of counterparties share Enron=01,s c= redit=20 risk concerns. Enron has proposed several options for resolving the credit risk issues and= =20 is working with DWR to arrive at a solution that is mutually agreeable to= =20 both sides and that might serve as a template for power purchase agreements= =20 going forward. Summary of the Source of the Credit Risk Issue Ambiguous Ratemaking Authority The language in AB1X leaves ambiguous whether DWR has any authority to char= ge=20 California ratepayers for the costs of purchasing power. From our analysis= =20 of the bill, the language in AB1X appears to leave intact the California PU= C=01, s exclusive jurisdiction over ratemaking in California. As such, suppliers= =20 have no assurance that the PUC will agree to include in rates adequate=20 charges to cover DWR=01,s costs of power purchases. Ambiguous Regulatory Authority Regarding Contract =01&Prudence=018 The language in AB1X leaves open the possibility that the California Public= =20 Utilities Commission could determine that power purchases made by DWR are= =20 =01&imprudent.=018 On the basis of such a finding, the CPUC could then ref= use to=20 allow DWR to collect from ratepayers the costs associated with its power=20 purchases. Consequently, suppliers have no assurance that the PUC will agr= ee=20 to include in rates the charges to cover the costs of power contracts that= =20 DWR has entered into with suppliers. =20 Ambiguous Language Regarding the Ratemaking Mechanism that Will Be Used to= =20 Recover DWR=01,s Costs of Power Purchases In addition to the ambiguity regarding ratemaking and regulatory authority= =20 noted above, the language in the bill is equally ambiguous with respect to= =20 the specific ratemaking =01&mechanics=018 that AB1X directs the PUC to empl= oy to=20 permit DWR to recover its power purchase costs. Based on our analysis, it i= s=20 extremely difficult to determine how the PUC would design the rates to ensu= re=20 DWR recovers its power purchase costs. Moreover, as currently drafted, it = is=20 difficult to determine whether AB1X would even permit the PUC to include in= =20 rates all of the charges necessary to fully recover DWR=01,s power purchase= =20 costs. Again, this ambiguity raises significant credit risk concerns since= =20 suppliers have little assurance that DWR will have the ability to recover= =20 from ratepayers the costs of purchasing power. Options to Resolve Concerns Regarding Credit Risk=20 We have been working diligently with DWR officials to resolve the credit ri= sk=20 issues. We have identified three options: Amend AB1X The amendments, which are attached to this email, would clarify that a) the= =20 PUC would accept as =01&prudent and reasonable=018 all purchase costs incur= red by=20 DWR, and b) the PUC is obligated to include in rates the charges necessary = to=20 ensure that DWR fully recovers its costs of power purchases. This is the= =20 preferred option, though we understand that the there may be some political= =20 challenges standing in the way of amending AB1X. (See attached file=20 entitled, =01&XXXX=018.) Clarify the Ambiguities in AB1X through an Order Issued by the PUC, and=20 through Contract Language This is the option that we are currently working with DWR officials to=20 implement. However, it is more complicated and could take significantly mo= re=20 time to implement than the "legislative" fix. We have attached electronic= =20 copies of the talking points related to the order that the California PUC= =20 would need to issue under this option. (See attached file entitled, =01&XX= XX.=018) Make Use of Other Instruments Designed to Address Credit Risk As indicated in our letter responding to DWR=01,s RFP, we are willing to ac= cept=20 other forms of credit from DWR. Those options include a letter of credit,= =20 cash prepayment, or an acceptable form of collateral. DWR officials have= =20 indicated to us that it prefers to pursue the second options, that is,=20 clarifying the ambiguities in AB1X through a PUC order and through contract= =20 amendments. 4. California=01,s Supply-demand Picture Heading into Summer 2001 Both the California Energy Commission and Cambridge Energy Research=20 Associates, a private sector energy think tank, have issued reports showing= =20 that California faces a severe supply-demand imbalance. They differ only o= n=20 how much and how soon additional supply will be made available. All credib= le=20 sources agree supply supply will be very tight throughout the Summer of=20 2001. =20 CEC and CERA both forecast that California will be this summer short by=20 approximately 5,000 MW. These numbers are in line with our estimates. =20 California=01,s supply base currently has a 6% capacity margin, well below = the=20 average 15-20% which is recommended for reliable system operation in the=20 West. Since the West relies more heavily upon hydroelectric power than oth= er=20 regions, reserves are particularly important, owing to the unpredictability= =20 of the weather and the dry year the West has had thus far. In the event of a low rain and snow period, the system must possess the=20 flexibility to respond to the reduced availability of power supply. =20 California=01,s very low reserve margin makes it especially susceptible to= =20 this. Other reasons for reduced supply for the Summer of 2001 include the= =20 early draw down of reservoirs close the supply-demand gas this summer,=20 emissions restrictions on existing plants, and a reduced number of customer= s=20 who can be curtailed. Cambridge Energy Research Associates asserts that at= =20 the current pace of siting, permitting and construction, adequate supplies= =20 will not be added to correct the market imbalance until 2003 at the earlies= t. CERA predicts that California is likely to face approximately 20 hours of= =20 rolling black outs this summer. The CEC paints a considerably more=20 optomistic scenario, banking that California will bring an additional 5,000= =20 MWs on line to meet peaking summer demand. It is our view that the=20 California should view the CEC's predictions regarding increased supply wit= h=20 considerably skepticism. 5. Suggested Package of Legislative Proposals Designed to Solve California= =01,s=20 Electricity Crisis This email offers an overview of our proposed legislative solution. We wil= l=20 deliver to your office tomorrow specific legislative language and existing= =20 bills that we believe can accommodate our proposals. As we have suggested throughout the crisis, any solution to California cris= is=20 must focus on four issues: Increase supply Decrease demand Establish a truly competitive retail electricity market Return California=01,s Investor-owned utilities to solvency Increase supply--Legislative vehicle: SB28X (Sher) To site and construct a power plant in Texas takes approximately 2 years. = =20 Enron and others have completed the entire process in other states in less= =20 than a year. In California, complex and costly air quality regulations=20 exacerbate California=01,s inability to site power plants. =20 The Governor=01,s executive orders and Senator Sher=01,s siting reform legi= slation=20 are steps in the right direction. Our suggested amendments can improve tho= se=20 efforts by: Decrease demand=01*Legislative Vehicle: AB31X Because of the delay in implementing a solution to California=01,s electric= ity=20 crisis, closing the supply-demand gap through energy conservation and=20 efficiency offers the best chance of avoiding blackouts this summer. This= =20 can be accomplished most effectively and quickly in two ways: Buy-down demand California is tapping into an enormous amount of money from the General Fun= d=20 to finance DWR=01,s power purchases. California could likely reduce demand= more=20 cheaply by running an auction to determine the payments businesses would be= =20 willing to receive to reduce demand for a sustained period (e.g., through t= he=20 summer months). DWR could very easily run an on-line auction to determine= =20 the best price it could pay for these demand reductions. To participate,= =20 businesses would be required to have the metering equipment necessary to=20 monitor and verify that they are actually achieving the reductions. Enron= =20 has developed an on-line auction software package, =01&Dealbench,=018 that = it would=20 be willing to contribute to the effort. Use Price Signals to Incent Voluntary Curtailment To work, customers need access to the following key elements: An internet based hour-ahead price posting system to track the market price= =20 for hour-ahead power in real time.=20 Real-time metering systems for baseline demand and voluntarily curtailment= =20 verification. Settlement process that allows for market clearing prices of energy to be= =20 paid for load reduction (=01&Negawatts=018). The potential benefits of an effective demand response program would includ= e: =01&creation=018 of additional summer peaking capacity in California, parti= cularly=20 in the short term, without requiring construction of additional generation= =20 resources. reduction of peak or super-peak load on the over-stressed California=20 electric system, thus potentially reducing the overall cost of electricity = in=20 the state. fostering of demand elasticity without subjecting customers to the full ris= k=20 of hourly market price volatility by passing market price signals to=20 customers and allowing them to voluntarily shed load and be compensated for= =20 responding.=20 We estimate that we could generate a summer 2001 on-peak demand response in= =20 excess of 400 MW during certain high cost hours, and a demand response for= =20 summer 2002 on-peak hours that could exceed 1000 MW. We further estimate= =20 that the market response to this program from all ESPs who would also pay= =20 Access Fees could be 2 to 3 times that amount. We recommend that the State= =20 of California provide rebates directly to customers to fund the installatio= n=20 of advanced metering and control systems that would support load curtailmen= t=20 implementation. Establish a truly competitive retail electricity market=01*Legislative vehi= cle:=20 SB27X The only customers who were protected from price volatility in San Diego we= re=20 customers who chose Direct Access and signed fixed price deals with energy= =20 service providers. Ironically, AB1X takes that important option away from= =20 customers and businesses. It is critical that AB1X be amended to remove th= e=20 prohibition against Direct Access. In addition, California will only achieve a competitive retail market when= =20 the utility is removed completely from the procurement function. Procureme= nt=20 is not a utility core competency, as evidenced by the dire financial=20 condition in which the utilities now find themselves. California should=20 therefore begin now to gradually phase the utility out of the procurement= =20 function entirely, with the goal having all customers served by a non-utili= ty=20 provider within 36 months. To execute the transition, California should ho= ld=20 a competitive solicitation in which competing service providers would bid f= or=20 the right to serve segments, or =01&tranches,=018 of utility load. Return California=01,s Investor-owned utilities to solvency=01*Legislative = vehicle:=20 AB18X Utility bankruptcy will not increase supply and it will not decrease demand= . =20 In short, bankruptcy does nothing to solve California=01,s supply-demand=20 imbalance. In addition, bankruptcy increases the likelihood that consumers= =20 and businesses will bear the significant financial risks of having Californ= ia=20 State government assume the role of =01&electricity buyer=018 for an extend= ed=20 period of time. California can return the utilities to financial solvency by implementing a= =20 series of staged rate increases. California should design those rate=20 increases with the dual goal of returning the utilities to solvency without= =20 =01&shocking=018 the economy or consumers=01, wallets (e.g., amortize the r= ecovery of=20 the utilities=01, debt over a 5-10 year period). The magnitude of the rate= =20 increase can be reduced in two ways: First, the utilities could absorb some= =20 portion of their existing debt in recognition of the risk they accepted whe= n=20 they agreed to the structure of AB 1890. Second, California can =01&net=01= 8 the=20 revenues the utilities have received from selling electricity into the Powe= r=20 Exchange against the debts they have accrued due to the retail price cap.