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HomeMy WebLinkAbout2003-06-03 City CouncilC ty Manager’s Report TO:HONORABLE CITY COUNCIL ATTENTION:FINANCE COMMITTEE FROM:CITY MANAGER DEPARTMENT: UTILITIES DATE: SUBJECT: JUNE 3, 2003 CMR:288:03 REQUEST FORAPPROVAL OF THE LONG-TERM ELECTRIC ACQUISITION PLAN IMPLEMENTATION PLAN AND ADOPTION OF AN ORDINANCE OF THE COUNCIL OF THE CITY OF PALO ALTO AUTHORIZING THE CITY MANAGER TO PURCHASE A PORTION OF THE CITY’S ENERGY REQUIREMENTS DURING THE 2005-2007PERIOD [BLOCK 1 PURCHASES]AND D URING THE 2005-2006PERIOD [BLOCK 2 PURCHASES]UNDER SPECIFIED TERMS AND CONDITIONS RECOMMENDATION Staff and the Utilities Advisory Commission (UAC) recommend that the City Council: Approve t he L ong-tem~. Electric Acquisition Plan (LEAP) Implementation Plan. Specific transactions will be brought to UAC and Council, as appropriate for approval. 2.Authorize the City Manager to purchase the following two blocks of energy at an average unit price not to exceed 6¢/k~Vh, with an associated total cost not to exceed $27.74 million, and complete all transactions associated with these purchases by June 30, 2004: go Block 1: twenty-five megawatts (MW) of power not to exceed 5.9C/kWh and $22.34 million; and delivered 24 hour/day during the months of January through March and September through December for 2005, 2006, and 2007; and CMR:288:03 Page 1 of 2 No Block 2: twenty-five MW of power not to exceed 5.9c/kWh and $22.34 million; and delivered during the on-peak hours only during the months of September through December for 2005 and 2006. DISCUSSION When the City’s current contract with the Western Area Power Administration (Western) expires at the end of 2004, it will be replaced by a new contract with Western - the Base Resource contract. The new contract will result in a significant electricity supply resource deficit for which staff and the Council has been preparing since committing to the Base Resource Contract in October 2000 (CMR:378:00). The proposed LEAP implementation plan was developed to be consistent with Council approved policies and guidelines. Additional detail is provided in the attached April 2, 2003 report to the UAC. BOARD/COMMISSION REVIEW AND RECOMMENDATIONS The UAC reviewed this recommendation and approved it unanimously at its April 2, 2003 meeting. ATTACHMENTS A:April 2, 2003 report to the UAC: LEAP Implementation Recommendations B:Ordinance of the Council of the City of Palo Authorizing the City Manager to Purchase a Portion of the City’s Energy Requirements during the 2005-2007 Period [Block 1 Purchases] and the 2005 - 2006 Period [Block 2 Purchases] under Specified Ternas and Conditions C: Minutes from the April 2, 2003 UAC meeting Resource~lanner DEPARTMENT HEAD: of Utilities CITY MANAGER APPROVAL: HARRISON Assistant City Manager CMR:288:03 Page 2 of 2 MEMORANDUM 3 UTiLiTiES ADVISORY COMMISSION FROM"UTILITIES DEPARTMENT SUBJECT" DATE: REQUEST: LEAP IMPLEMENTATION RECOMMENDATIONS APRIL 2, 2003 Staff recommends that the Utilities Advisory Commission (UAC) recommend that the City Council: 1.Approve the LEAP.Implementation Plan (Attachment A). Specific transactions will be brought to UAC and Council, as appropriate for approval. 2.Authorize the City Manager to purchase the following.two blocks of energy at an average unit price not to exceed 6C/kWh; with an associated total cost not to exceed $27.74 million dollars; and complete all transactions associated with these purchases by June 30, 2004" a. Block I twenty-five megawatts (MW) of power delivered 24 hour/day during the months of January through March and September through December for 2005, 2006, and 2007; and b. Block 2: twenty-five MW of power delivered during the on-peak hours only during the months of September through December for 2005 and 2006. BACKGROUND The City will experience a significant electricity supply resource deficit with the expiry of its current 40-year Western Area Power Administration Contract at the end of 2004. The recommendations made in this report build upon more than two years of staff work, UAC and public input, and Council approval of policies, guidelines and plans; all focused toward proactively responding to this energy deficit. The implementation plan proposed in this report - building on Council approved policies and guidelines - will have far reaching and long-term impacts on the cost, reliability and quality of electricity provided to the City’s residents and businesses. The plan was developed in a deliberate and step- wise manner in order that staff analysis would reflect and enhance direction from policy makers, advisers and t he public. T he following p ara~aphs replicate the four P rimary Portfolio Planning Objectives and the seven Long-term Electric Acquisition Plan Guidelines in order to provide rnn+~s’+ fOr the culminating Lo_~P~. ........~ ~-~ ~]plClliCntatloR Flail that is being presented %r approval in this repot. The City Council approved four Primary Pontfolio Planning Objectives on November t3, 2001 (CMR:425:01) to guide the development of strategies to fill this energy deficit. The City Council approved seven LEAP Guidelines on October 21, 2002 (CMR:398:02). These approved objectives and guidelines are attached for reference as Attachment B. The LEAP Implementation Plan analysis and report was presented to the UAC on March 5, 2003 for input and feedback (Attachment C). The UAC was supportive of the LEAP Implementation Plan presented and the recommendation to make certain block purchases. The UAC urged staff to actively pursue investment opportunities in power plants, and staff updated the UAC of the efforts undel-mken in this regard. The graphic below traces tile timeline for LEAP development and implementation: Post 2 04 Electric Portfolio Process Council approval- 11/13/00 & 5121/01, (c~lR: 418:00 and CMR: 223:01) Council approval of risk management policies, 2/20/01, (CMR: 103:01) Council approval- 1 1/13/01, (CMR: 425:01) 4. Council approval- 12/3/01, (CrvlR: 421:01) Council presentation - 3/18/02 (0MR:176:02 Public Energy Forum #4 - 8/1/02 l 9. Final LEAP Implementation Plan 10. Specific Deal Approval Requests approval - 10/21/02, (CMR: 398:02) Council approval 10/21/02 (CMR:400:02) I Todo ! Action from UAC requested in April Council action requested in May/June 2003 To UAC/Council, when required 2003-2004 2 DISCUSSION The recommendations made in this report represent a significant milestone in the sense that the City, upon approval of the LEAP Implementation Plan, will move more toward specific implementation stages and away from the broad planning phases of this sigT~ificant project. Overall Proposed Implementation Plan The recommended implementation plan (both for long- and for short- to medium-term) is Attachment A to this report. The following discussion adds to the discussion presented to the UAC at its March 2003 meeting. Lone-Term hnplementation Plan Discussion The results of the analysis and the market information staff has gained at this time indicates that a long-tem~ commitment to a large, efficient, gas-fired generation plant should be pursued. However, prior to making a specific recommendation several practical considerations and uncertainties need to be addressed. First, due to the City’s relatively small needs for thermal generation, the City is not in a position to individually drive the construction of a large thermal plant. Second, the economics of such a recommendation depends on various uncertainties including the higher cost of transmission to the City during times when the transmission lines into the City are ?ongested. Resolution of the uncertainty related to higher transmission related costs could greatly impact the City’s cost for many of the portfolio options. To date, efforts by NCPA with active support by the City to expand a plant in Lodi and to buy a power plant owned by a private plant developer in the Bay Area have not been successful. Staff continues to work with NCPA and merchant generators to investigate opportunities. Staff is participating in a joint request for proposal with other NCPA members to procure long-term renewable resources and is confident that, before the year-end, the City will be able to make a long-term commitment for renewable energy that will meet 5-10% or more of the City’s projected energy. The cost premium for this fraction of the total energy needs is expected to be 1 to 2C/kWh over market energy prices for a generic firm resource with a corresponding seasonal generation profile. This cost premium would comply with LEAP Guideline 6, which requires that the rate impact be less than 0.5¢lkWh. The analysis completed is representative of information known at this time about the resource options and possible states of the future (e.g. market price projections, congestion cost estimates, etc.). The analysis o fthe portfolio options w ill n ecessarily change as assumptions change and as new information on actual projects and products is established. Staff intends to use the analysis model, and especially the development of future scenarios, to evaluate new opportunities that arise and any products that are offered by suppliers for the City’s consideration. As such, the analysis model is a framework that will be utilized to assist in examining responses to requests for proposals that the City may issue in its quest to find supplies to fill the resource deficit after 2004 that meet the LEAP Guidelines. Short- and Medium-Term Implementation Plan Discussion LEAP Guideline 3 provides that a maximum of 90% of the projected load for 2 to 5 years out be filled with fixed price resource commitments. This translates into a minimmn market exposure of 10% of expected load for 2 to 5 years out. Since it is now year 2003, the guideline for 90% maximum of fixed-price resources applies until year 2008. There is no minimum target. However, the long-term resources already committed and the fixed-price renewable resource commitments act as a minimum of sorts. If no additional resources are acquired for the period 2005-2007, then only about 66% of the load is covered with fixed-price resource commitments in an average hydrologic year. In other words, the deficit is about 34%. The recommended block purchases for this period would reduce the remaining exposure (resource deficit) as follows: 2005 - Blocks 1, 2, 3 cover 26% --> remaining deficit = 7% 2006 - Blocks 1, 2 cover 15% --> remaining deficit = 19% 2007 - Block 1 only covers 11% --> remaining deficit = 23% To avoid higher transmission related costs that may be imposed in certain hours when the transmission lines into the City are congested, staff is beginning to evaluate the potential for a demand-response program that could incent customers to reduce or shift demand when requested by Utilities. These progratns present a very attractive, low-cost method to reduce exposure to congestion costs that could be very high until additional generation and/or transmission is built in the Bay Area. POLICY IMPLICATIONS AND UTILITIES STRATEGIC PLAN The recommended energy purchases and the proposed LEAP Implementation Plan confom~ to the Council approved LEAP Guidelines and do not represent any change to existing City policies. The LEAP Implementation Plan conforms to City’s Energy Risk Management Policies and supports the Utilities Strategic Plan: 1. Strategy 2 - Preserve a supply cost advantage compared to the market price; 2. Strategy 4 - Deliver products and services valued by our customers, and continue to build CPAU brand presence; 3. Strategy 6 - Maintain stable Genera! Fund transfers, and maintain financial strength; and 4. Strategy 7 - Implement programs that improve the quality of the environment. The proposed LEAP Implementation Plan furthers the City’s commitment to the Green Government Pledge by supporting the conservation of energy and investment in low polluting and renewable energy resources. RESOURCE IMPACT The LEAP Implementation Plan by itself does not have immediate resource impacts. Other elements of the LEAP hnplementation Plan, especially those related to supply resource acquisition, will have resource impacts. Specific recommendations resulting from the LEAP. Implementation Plan will be brought to the UAC and Council as appropriate. Any budget amendments or approvals that may be required to implement future recommendations will be brought to the Council for approval. Implementing the recommended energy block purchases is expected to cost about $19.75 million ($15.67 million for Block 1 and about $4.08 million for Block 2).. Staff is requesting authorization to spend up to $27.74 million to allow for changes in market price between the present time and the time the purchases are actually made. An estimate for the cost for these energy purchases has been included in long-term power. cost projections and in the proposed FY03-05 budget. The budgets for the years FY04- 05, 05-06, 06-07 and 07-08 either include an estimate or will include the actual costs for the Block 1 and Block 2 purchases. The following table provides an indication (calculated using market prices available at the time this report was written) of the estimated cost of these purchases, by fiscal year. ,4ll estimates in MS Estimated Block 1 cost Estimated Block 2 cost Estimated Total Cost Estimated Total 15.67 4.08 19.75 FY04-05 1.87 FY05-06 5.24 2.11 1.87 7.35 FY 06-07 5.20 1.97 7.17 FY 07-08 3.36 3.36 ENVIRONMENTAL REVIEW Approving the recommended block purchases and the LEAP Implementation Plan does not constitute a project under the California Environmental Quality Act (CEQA). NEXT STEPS !.The LEAP Implementation Plan and energy block purchase recommendations will be presented to the Council in May or June. 2.Council will be asked to approve master enabling agreements in September of 2003. 3.If Council authorizes the recommended block purchases, staff expects to execute the block purchase transactions under the enabling agreements prior to June 30, 2004. 4. The Block 3 purchase will be implemented by staff under existing authorities [On March ~, _00~, the City Council delegated to the City Manager the authority to execute transactions up to $20 million per fiscal year in conformance with the Northern California Power Agency (NCPA) Pooling Agreement (CMR:135:03)]. Council authorization will be sought as required for additional specific transactions that comply with the LEAP Implementation Plan. 5. The Energy Risk Manager will infom~ the Council and the UAC of the performance of the electric Supply portfolio with bi-annual risk management reports. 6. Specific recommendations and approvals that will be required as per the LEAP Implementation Plan will be brought to the UAC and Council, as appropriate, starting as early as Fall 2003 and continuing for several years. APPENDIX: A.Proposed LEAP Implementation Plan B.Council Approved Electric Supply Objectives and Guidelines C.March 5, 2003 report to the UAC: Update on LEAP Implementation PREPARED BY:Shiva Swaminathan and Jane Ratchye Senior Resource Planners, Resource Management REVIEWED BY: Girish Balachandran Assistant Director, Resource Management APPROVED BY: John Ulrich Director of Utilities Attachment A Attachment A" Proposed LEAP Implementation Plan Recommended Implementation Plan - Long-Term Portfolio Acquire renewable energy resources to meet LEAP Guideline 6. The first step is to issue a Request for Proposals (R_FP) to potential suppliers. NCPA is coordinating this activity as many of its members have an interest in acquiring new renewables for the post-2004 period. The RFP was issued on March 11, 2003 with responses due in mid-April. Depending on the responses to the RFP, staff will request UAC and Council approval to execute long-term contracts for renewable supplies. Implementation of the Palo Alto Green program, a green pricing product available on a volunteer basis to customers who wish to purchase a greater fraction of green resources. This pro~am was reviewed and approved by the UAC at its February 2003 meeting and was approved unanimously by the Council Finance Committee on March 4, 2003. It is expected to go to the Council for approval on April 21, 2003 o Continue implementation of Public Benefits programs, which is funded by collecting a fee equal to 2.85% of the electric retail rate. These funds are partially used to demonstrate renewable resources or alternative technologies and to assist customers in pursuing efficiency improvements. Staff will continue to evaluate additional opportunities for investment in efficiency improvements. As appropriate, additional funding for cost-effective efficiency programs will be recommended. While continuing to monitor opportunities for participation in gas-fired generation as they arise through staff’s contacts in the market and at NCPA, prepare an RFP to fore, ally announce to the market Palo Alto’s interest in investing in thermal generation resources or its "look alike" (i.e. tolling contracts). Monitor technology costs and opportunities for smaller renewable technologies, cogeneration and gas-fired generation that can be located within Palo Alto and/or at customer sites. A study funded by the California Energy Commission, Palo Alto, and other municipal utilities is currently underway to identify sites within Palo Alto that have high value to the electrical distribution system. Continue to discuss gas tolling options with suppliers. Gas financial instruments will allow staff to most effectively use tolling contracts, therefore, staff will investigate using these products and, if attractive, will pursue approval from the A-1 Attachment A 10. 11. Council to add these products to the list of approved products in the Energy, Risk Management Policies. Pursue any low-cost, high value prospects to acquire supply-re!ated resources that may arise from time to time. Staff monitors on an ongoing basis any opportunities such as availability of additional below-market hydroelectric production or access to additional power or transmission due to ownership of existing assets. Refine the analysis and collect additional market infom~ation to evaluate scenarios when various portfolio elements would have value. Staff will solicit current market information on specific products such as hydro hedges. Additional analysis will include sensitivity analysis and stress testing of the portfolios. Monitor and participate in regulatory and legislative initiatives related to . transmission market design, support Bay Area transmission upgrades, and pursue alternatives to increase reliability at a reasonable cost Maintain adequate reserves by recognizing the degree of uncertainty the City faces in the future. Evaluate modifying the policy or targets to make certain that the Supply Rate Stabilization Reserve is adequate to ensure stable rates in an environment of uncertainty and consider potential guidelines such as being able to maintain stable rates in the event of two dry years in a row. Recommended Implementation Plan - Short- and Medium-Term Portfolio To reduce shoInt-term cost variability, and to ladder the purchase commitments, while leaving sufficient flexibility to commit to long-tema resources, three fixed- price block purchases are recommended for execution in year 2003" Block 1 (2005-2007) Block 2 (2005-2006) Block 3 (2005) Jan Feb Mar on-pk X X X off-pk X X X on-pk off-pk on-pk X X X I off-pk Apt I May !,Jun Jul Aug Sep X X X X X X X X X Oct Nov x x x x x x x x Dec Ix Ix Ix X At current market prices, the expected cost of the first two blocks of power is as follows: a. about $16.4 million for Block 1 (4.3 C/kWh); b. about $4.5 million for Block 2 (5.57 C!kWh); and c. about $6.3 million for Block 3 (5.1 C/kWh). This purchase will be completed A-2 Attachment A as a term transaction via the Northern California Power Agency (NCPA) under the authority delegated to the City Manager by Council to execute transactions up to $20 million per fiscal year in conformance with the NCPA Pooling A~eement (CMR: 135:03 on March 3, 2003). Seek Council approval of a set of master a~eements with suppliers by summer or fall 2003 with the authority to transact for terms of up to 3 years out. Any transactions outside this limit will be brought to the UAC and Council for approval. Develop short-term hedging strategies and operations plans with the objective off a. Clearly identifying and capt~ring supply needs and supply portfolio risks; b. Whenever possible, utilizing simple tools to manage risks and utilizing NCPA resources and expertise; and c. Managing the electric portfolio to achieve the portfolio objectives with streamlined operations to minimize overhead costs and to act expeditiously, while maintaining the appropriate level of oversight and control. Evaluate, design, and pilot a customer demand-response program. If such a program makes sense, develop and implement a customer demand-response pro~am to protect against high congestion costs and to be part of new capacity reserve requirements that are likely to be imposed. A-3 Attachment B Attachment B: Council Approved Electric Supply Objectives and Guidelines The City r~.~,~;~ approved fou.~ P .......~, Po~folio p~o.~n~.,~ Ob_lect~ves on November 13. 2001 (CMR:42f:01~ Objective 1:Ensure low and stable electric supply rates for customers. Objective 2:Provide supelJor financial performance to customers and the City by maintaining a supply portfolio cost advantage compared t o market cost and the retail supply rate advantage compared to PG&E. Objective 3:Enhance supply reliability to meet City and customer needs by pursuing oppommities including transmission system upgrades and local generation. Objective 4:Balance environment, local reliability, rates and cost impacts when considering renewable resource and energy efficiency investments. The City Council approved seven LEAP Guidelines on October 21 2002 (CMR:398:02). Guideline 1:Electric Portfolio Dependence on Western While maintaining the flexibility to adopt favorable ’custom products’ offered by Western, manage a supply portfolio independent of Western beyond the Base Resource Contract. Guideline 2:Hydro Risk Management Manage hydro production risk by: A.Planning for an average hydro year on a long-term basis; B.Diversifying to renewable and/or fossil generation technologies; and C.Maintaining adequate supply rate stabilization reserve. Guideline 3:Market Risk Management Manage market risk by adopting a portfolio strategy for electric supply procurement by: A. Diversifying energy purchases across commitment date, start-date, duration, suppliers, pricing terms and fuel sources; B. Targeting additional thermal plant ownership/investment commitment at ~25 MW but in no event more than 50 MW; C. Maintaining a prudent exposure to changing market prices by: 1.Procuring resources at fixed price for at most 90% of expected load for 2 or more years out, assuming average hydro conditions; and B-1 Attachment B Guideline 4: Guideline 5: 2.Procuring resources at fixed price for at most 75% of expected load for 5 or more years out, assuming average hydro conditions; and D.Avoiding contract-based fixed price energy purchases (except for contracts for renewable resources) for durations ~eater than 10 years. Retiable and Cost Effective Transmission Services Ensure the reliability of supply at fair and reasonable transmission cost by: A. Supporting, through political and technical advocacy and/or direct investment, the up~-ading of Bay Area transmission to improve reliability and relieve congestion; B.Participating in transmission market design to ensure that market design results in workable competitive markets and equitable cost allocation; C.Pursuing the option of forming and/or joining a Public Power Transmission Contro! Area to increase control over transmission operations and related costs; and D.Ensuring PG&E honors the Stanislaus Commitments by providing to us firm-transmission rights or equivalent. Local Generation Monitor the potential of local generation options to meet customer needs, improve local reliability, minimize congestion and wheeling charges, and stabilize/reduce costs. Guideline 6: Guideline 7: Renewable Portfolio Investments The City shallcontinue to offer a renewable resource-based retail rate for all customers who want to voluntarily select an increased content of renewable energy. In addition to the voluntary program, the City shall invest in new renewable resources to meet the City’s sustainability goals while ensuring that the retail rate impact does not exceed 0.5 C!kW on average. Pursue a target level of new renewable purchases of 10% of the expected portfolio load by 2008 and move to a 20% target by 2015, contingent on economic viability. The contracts for investment in renewable resources are not to exceed 30 years in term. Electric Energy Efficiency Investments Offer quality Public Benefits programs, utilizing funds collected through tl~e 2.85% Public Benefits charge embedded in electric retail rates, to meet the resource efficiency needs of customers. Additional funding for cost- effective programs will be recommended as appropriate. Pursue these investments by: B-2 Attachment B A.Providing expertise, education and incentives to support cost-effective customer efficiency improvements; B.Demonstrating renewable and/or alternative generation technologies and new efficiency alternatives; and C.Providing rate assistance and efficiency programs to low-income customers. B-3 Attachment B to April 2, 2003 UAC report: LE~P Implementation Plan MEMORANDUM TO: FROM: SUBJECT: AGENDA DATE: Utilities Advisory Commission Utilities Department Update on LEAP Implementation March 5, 2003 REQUEST: This report is provided for the Commission’s information and discussion only. No action is necessary. Staff plans to present specific recommendations at the Commission’s April meeting. Preliminary recommendations are made in this report and staff desires the Commission’s feedback on these recommendations. BACKGROUND The term of the current contract with the Western Area Power Administration (Western) ends on December 3 !, 2004. In October 2000 Council approved the 20-year Western Base Resource Contract (CMR:378:00) which will replace the existing Western contract in year 2005 At its October 4, 2000 meeting, the Utilities Advisory Commission (UAC) considered staff’s plan to investigate energy supply alternatives for the post-2004 period. The proposed approach was to evaluate a set of alternatives in a deliberate, orderly fashion and subject them to diverse scenarios of the future in order to develop a robust and value- added energy supply portfolio that meets our electric rate payer needs. In February 2001, the UAC approved an analysis and conceptual recommendations to fill the electric energy deficits expected to occur. In September 2001, a presentation was made to the UAC outlining strategies that could be adopted to meet the energy deficit. At that time, an initial 25 MW purchase to fill ~15% of the expected energy deficit projected in year 2005 and beyond was recommended. The UAC approved the purchase and a set ofprimar-y objectives to guide staff when developing and managing the electric supply portfolio. In November 2001, the City Council approved the 25 MW purchase and the primary objectives (CMR:425:01). Attachment B to April 2, 2003 UAC report: LEA_P Implementation Plan On October 3, 2001, the UAC received a report on the FY 2001-03 Demand-Side Management (DSM) and Public Benefits plan. The DSM and Public Benefits plan was reported to the Council on December 3, 2001 (CMR:421 01). On January 9, 2002, the UAC received an analysis of alternative energy resource options for the electl-ic supply portfolio plan. The report discussed both demand-side management initiatives (i.e. energy efficiency and load management) and renewable energy supply options. The Council received an informational report on alternative electric supplies on March 18, 2002 (CMR: 176:02). In June 2002 a comprehensive presentation was made to the UAC based on all prior analysis, customer surveys, and public input. A preliminary set portfolio acquisition guidelines xvere also proposed to direct staff in the acquisition efforts. After further discussion, the UAC approved a set of seven Long-term Electric Acquisition Plan (LEAP) Guidelines in August 2002. The City Council adopted the LEAP Guidelines on October 21, 2002 (CMR:398:02). Attachment A provides a complete listing of the 7 Guidelines. The following graphic shows the process for LEAP evaluation so far: Post 2004 Electric 1.Portfolio Analysis Presentations; Approval of Energy Risk tVlanagement Policies 2. Approval of Primary Portfolio P.lanning Objectives 3. Approval of Initial 25 MW Purchase 4. Renewable Resource Analysis 5. Portfolio Plan Update 6. Additional Public Input ~r 7. Final Plan & Implementation Process 8. Specific Deal Approval Requests Portfolio Process [Completed ] UAC analysis presentations:Feb 14 & Sept 15 2001; Council approval of risk management policies, Feb 20, 2001 (CIvlR: 103:01) UAC/Council approval - 9/25/01 & 11/13/01 (CMR:425:01) UAC/Council approval - 9/25/01 & 11/13/01 (CMR 425:01 ) UAC/Council presentation - 1/9/02 & 3/18/02 (CMR:176:02) June ’02 UAC presentation on LEAP Guidelines Council approved 10/21/02 (CMR:398:02) August 1, 2002 - Energy Forum #4 Today’s UAC presentation - Action from UAC requested in April 2003 To UAC/Council, when required 2003-2004 2 Attachment B to April 2, 2003 UAC report: LEAP Implementation Plan EN_ECUTIVE SUMMARY The City is moving from a position of electric load-resource balance over the past 40 years, with primary reliance on Western and NCPA~owned resources, to a position of a large energy deficit, multiple suppliers, and introduction of new risk elements. As the City makes this transition, staff is in the process of reformulating its operating strategy to ensure that adequate systems and controls are in place to plan and manage a more complex electric supply portfolio. A number of elements must be considered when making such a t~ansition. 1.There must be a clear understanding of the City’s primary portfolio planning objectives and long-terna supply options that will be considered by the City. This to a large part has been achieved with the City Council’s approval of the 4 Primary Portfolio Planning Objectives and the 7 LEAP Guidelines. 2. The development of short- (- 1 year) and medium- (-3 years) term plans to implement elements of the approved long-term supply options to ensure that the goals of reliable supply at low, stable and competitive retail rates are achieved. 3.The assurance that the City has adequate operational expertise and systems to manage a more complex electric supply portfolio in a streamlined manner. \~q~ile constantly monitoring gas and electric market prices, staff is in ongoing discussions with suppliers, potential partners, and NCPA to gain an understanding of resource options and strategies. In addition, staff continues to monitor other situations that have an impact on any future decision, including regulatory proceedings Such as those related to transmission access, pricing and policies. Using that information, staff conducted evaluations and analysis of many resource and portfolio options in the.context of the many remaining uncertainties. This report outlines staff’s analysis, recommendations and implementation strategies for the long-tern~ and the sh0rt-term electric supply portfolios. Lon~-tern~ Supply Portfolio Implementation Recommendations The implementation plan at this time for the long-tenon supply acquisition consists of the following elements: Begin acquiring renewable energy resources to meet LEAP Guideline 7. The first step is to issue a Request for Proposals (RFP) to potential suppliers. NCPA is coordinating this activity as many of its members have an interest in acquiring new renewables for the post-2004 period. Continue to monitor opportunities for participation in gas-fired generation as they arise. This occurs through staffs contacts in the market and at NCPA. Monitor teclmology costs and opportunities for smaller cogeneration and gas-fired generation that can be located within Palo Alto and/or at customer sites. Attachment B to April 2, 2003 UAC report: LEAP Implementation Plan Continue to discuss gas tolling options with suppliers. To effectively use tolling contracts, Palo Alto may need to be able to purchase gas financial products. Staff will investigate using these products and, if attractive, will pursue approval from the Risk Oversight Commi~ee and the Council to add these products to the list of approved products in the Energy Risk Management Policies. Short-term Supply Portfolio hnplementation Recommendations The short-term implementation plan consists of the following elements To reduce cost variability and to diversify the purchase commitments in tenor and timing, while leaving sufficient flexibility to commit to long-term resources, three fixed-price block purchases are being contemplated for execution in year 2003: a. Block 1 - 25 MW, around-the-clock for the months September through March for 2005-2007. b. Block 2 - 25 MW for peak periods only for the months September through December for 2005-2006. c. Block 3 - 25 MW for peak periods only for all months for 2005. Seek Council approval of a set of master agreements with suppliers by summer 2003 with the authority to transact for terms of up to 3 years out. Any transactions outside the 3-year limit, although still able to be executed under the master a~eements, will be brought to the UAC and Council for approval. The Block 3 purchase can be executed using these master agreements since its term is within the 3-year allowable term if executed in 2003. The Block 1 and Block 2 purchases are outside the 3-year term limitation, therefore, staff expects to seek specific Council approval of those purchases in the next six months. Planning and Management of Supply Procurement Operations The City expects to utilize its master agreements with suppliers to contract for supplies for terms greater than approximately a year or when there are no benefits of transaction tbaough NCPA. As the number of transactions and the complexity of the electric portfolio increases, the need to closely monitor and report transactions increases, too. Utilities plans to compare skill sets needed for the future with those of existing staff and address any gaps with training and to evaluate the potential of utilizing alternative software tools. In addition, Utilities must be ever vigilant to control overhead costs with the goal of remaining competitive. Costs from within Utilities and from other City departments and NCPA bear constant monitoring. In summary, the planning and management of short- and long-term supply procurement operations is expected to be undertaken at the present staffing levels with the objectives of: ~ Clearly identifying and capturing supply needs and supply portfolio risks; 4 Attachment B to April 2, 2003 UAC report: LEAP Implementation Plan \Vhenever possible, utilizing simple tools to manage risks and utilizing NCPA resources and expertise; and Managing the electric portfolio to achieve the portfolio objectives with streamiined operations to n~inimize overhead costs and to act expeditiously, while maintaining the appropriate, leve! of oversight and control. DISCUSSION Long-term Supply Portfolio Development There are many portfolios that can be developed that fall within the Council-approved LEAP Guidelines. To be in compliance with those guidelines, each portfolio must have the following common elements: 5. 6. 7. 8. Maintaining adequate supply rate stabilization reserve Assuming average hydrologic condition, be exposed to market prices for a minimum of 10% of expected load for 2 to 5 years out Assuming average hydrologic condition, be exposed to market prices for a lninimum of 25% of expected load for 5 to 20 years out Target ther~nal plant ownership (or equivalent) of between 25 and 50 MW Maximum term of ! 0 years for fixed-price energy purchase contracts Ensure the reliability of supply at fair and reasonable transmission cost Monitor the potential of local generation options Procure 10% new renewables by 2008, 20% new renewables by 2015 provided that the rate impact does not exceed 0.5C/kWh Continue to fund energy efficiency programs using the 2.85% Public Benefits charge if these components are combined, the base portfolio for the next thirty years is shown in the chart below: Attachment B to April 2, 2003 UAC report: LEAP Implementation Plan 1200 Electric Resources in AVERAGE Hydro Year 1000 8OO ~-" 600r-- 400 Deficit to remain exposed to market (Spot)prices : "~ 200 OOOOOOOOOOOOOOOOOOOOOOOOOOOOOO The long-term deficit remaining to be filled over the next 20 years is most acute in the years 2005-2010 as the investment in new renewables is ramping up. There are many potential portfolios that comply with the LEAP Guidelines. A range of portfolios with different "themes" has been identified. They include the following: Do Nothina Portfolio - this portfolio assumes that no new long-term commitments are made for the post-2004 period except for complying with the new renewables guideline. This alternative is included as a baseline for comparison. Base Portfolio - make no additional commitments beyond the 25 MW thermal generation. This portfolio has the maximum exposure to market prices. The deficit will be filled in with short-term prochases of less than a year length to real- time spot market purchases. The gas purchased for the 25 MW of thermal generation is assumed to float with market prices. Maximum Fixed-Price Market Purchases - commit to fixed-price contracts with different terms (2-, 3-, 5-, and 10-year contracts) totaling the maximum allowable without violating the minimmn exposure to market requirements of the guidelines. In addition, purchase the gas for 25 MW of thermal generation on a fixed-price basis. Attachment B to April 2, 2003 UAC report: LEAP Implementation Plan 10. Maximum Thermal Portfolio - con-Lmit to 50 MW of thermal generation ownership. The gas purchased for the generation is assumed to float with market prices. Maximum Tollin~ Po~folio - commit to 25 M~;V of short-term (maximum 10- year) of round-the-clock thermal tolling contracts. The gas purchased for the generation is assumed to float with market prices. Maximum Local Resources PortfoIio - commit to a total of 50 MW ownership of gas-fired generation within the City of Palo Alto. This could take the.form of joint ownership of combined cycle, co-generation, or other efficient-low emission technologies or siting 2-5 MW generation and co-generation plants at customer facilities dispersed around the City. The gas purchased for the generation is assumed to float with market prices. Minimum Hydro Portfolio - divest all of the 54 MW Calaveras resource. Fill in greater deficit with 25 MW of fixed-price contract commitment (maximum term = 10 years). The gas purchased for the 25 MW of thermal generation is assumed to float with market prices. Super Green Portfolio - all new commitments made are for green resources. Maximize demand-side efficiency programs and customer site co-generation. Minimum Exposure to Cono, estion Portfolio - Commit to ownership of 25 MW of large generation plant in Bay Area. Commit to ownership of 25 MW of generation sited within Palo Alto. The gas purchased for the generation is assumed to float with market prices. Hydro Hedze - in this portfolio, it is assumed that Palo Alto could find a partner who would be willing to take the hydrologic risk in the Western Base Resource product. The City would pay the partner an annual fee and in remm would get the average year output from the Western Base Resource every year regardless of hydro conditions. The gas purchased for the 25 MW of thermal generation is assumed to float with market prices. Long-term Supply Portfolio Analysis The ten portfolios were developed so as to test a wide range ofpotentia! strategies. The evaluation plan was to look at results from the tested portfolios and determine the expected costs and mark-to-market valuations as well as the risks of, or uncertainty around, those results. To evaluate the portfolios, a spreadsheet model was developed to calculate the monthly cost for each of the portfolios. Attachment C describes the assumptions used to characterize the resource options and for the uncertain variables. Attachment D provides a synopsis of the analysis approach and results. Furore Uncertainties Assumptions were made for every uncertain variable. "Base" projections", or "50%" values, were developed for the key uncertain variables. In addition, "low" (10%) and "high" (90%) values were developed. The ranges used for each key uncertain variable are st~own in the chart below: Attachment B to April 2, 2003 UAC report: LEAP Implementation Plan Uncertain Variable Low (10%)Base (50%)High (90%) Value Value Value Hydrologic Year Dr-);Average Wet Electric Market Prices Low Base I High Gas Market Prices Low Base I High Western.Annual Cost $6 million $7.25 million I $10 million Western Cost Escalation Rate l%/year I 3%/year I 5%/year Western Availability Degradation 0%/year I l%!year I 3%/year Congestion Cost - Outside Bay Area *$1/MWh I $3/MWh ! $5/MWh Congestion Cost- Inside Bay Area *I $0/MWh I $0.50/MWh t $1/MWh * Congestion costs are highly uncertain and could be much higher than the values used in this analysis. Congestion cost outside the Bay Area could be as high as $20/MWh. Congestion costs inside the Bay Area could be as high as $10~Wh. Results of Analysis An expected value of the annual average cost of each portfolio was calculated given the assumptions for each uncertain variable and the probabilities assigned to the low, base, and high values. Attachment D provides a brief account of the major results. In summary, the portfolio with the lowest expected cost was the "Maximum Thermal Portfolio", the portfolio with 50 MW of gas-fired generation located outside the Bay Area. The results of the analysis comparing the portfolios over a 20-year period is shown in the following graph: LEAP Portfolio Results Cost to Serve Load (sorted by Expected Value) oJ o o oo o 95 90 85 8O 75 70 65 60 - 55 ..... 5O 45 E-xpeeted-Value- Medium (50%) Cost L-6W-(T0 %)-C6~t Attachment B to April 2, 2003 UAC report: LEAP Implementation Plan Long-term Implementation Plan The results of the analysis and the market information staff has gained at this time indicates that a long-term commitment to a large, efficient, gas-fired generation plant be pursued. However, there are many options and uncertainties that remain that make staff shy away from pursuing such a commitment at this time. First, Palo Alto is not in a position to drive the construction of such a plant. Second, the cost of congestion is not t~aown at this time and the resolution of that issue could greatly impact Palo Alto’s cost for many of the portfolio options. Efforts by NCPA with active support by Palo Alto to build a plant in Lodi and to buy a merchant plant in the bay area have not been successful. However, staff is participating in a joint request for proposal with other NCPA members to procure long-term renewable resources and is confident that, before the year end, the City will be able to make a long- term commitment for renewable energy that wil! meet 5-10% of the City’s projected load. The cost premium is expected to be -1 ¢ik\Vh over market energy prices for a generic firm resource with a corresponding seasonal generation profile. The implementation plan at this time for the long-term supply acquisition consists of the following elements: 3. Preferred Recommendations for Long-term Portfolio Begin acquiring renewable energy resources to meet LEAP Guideline 7. The first step is to issue a Request for Proposals (RFP) to potential suppliers. NCPA is coordinating this activity as many of its members have an interest in acquiring new renewables for the post-2004 period. Continue to monitor opportunities for participation in gas-fired generation as they arise. This occurs through staff’s contacts in the market and at NCPA. Monitor technology costs and opportunities for smaller cogeneration and gas-fired generation that can be located within Palo Alto and/or at customer sites. Continue to discuss gas tolling options with suppliers. To effectively use tolling contracts, Palo Alto must be able to purchase gas financial products. Staffwill investigate using these products and, if attractive, will pursue approval from the Council to add these products to the list of approved products in the Energy Risk Management Policies. The analysis completed is representative of information known at this time about the resource options and possible states of the future (e.g. market price projections, congestion cost estimates, etc.). The analysis of the portfolio options will necessarily change as assumptions change and as new information on actual projects and products is established. Staff intends to use the model, and especially the development of future scenarios, to evaluate new opportunities that arise and any products that are offered by suppliers for the City’s consideration. As such, the model is a framework that will be 9 Attachment B to April 2, ~00~ UAC report: LEAP Implementation Plan utilized to examine responses to requests for proposals that the City may issue in its quest to find supplies to fill the resource "hole" after 2005 that meet the LEAP Guidelines. The long-term portfolio plan was developed with a long-term view, and it includes, by desig-n, exposure to market prices of at least 10% of the load (LEAP Guideline 3). Therefore, staff will need to actively manage the portfolio in the short term (0 to 3 years out) to fill the expected deficits in average hydro years and to make adjustments as actual availability of Western and Calaveras is better "known. As explained in the long-term implementation plan, it is not expected that the 25-50 MW of thelTnal generation identified in the long-term plan will be in place by 2005, or even 2007. To limit exposures and to provide rate stability, staff recommends a laddering approach tO fill the expected deficits over the next three years. Since the time of the year of most need in all hydro year types is the fall and winter, the purchases are heavily weighted to those time periods. Tkree energy blocks are contemplated to fill the deficits in the coming months include: o Short-term Purchases (2005-2007) A fixed-price purchase of 25 MW, around-the-clock during Q1 (January, February, and March), September, and Q4 (October, November, and December) for three years (2005 through 2007). A fixed-price purchase of 25 MW, during the heavy load period for 4 months (September through December) for two years (2005 and 2006). A fixed-price purchase of 25 MW, during the heavy load period for every month of the year for calendar year 2005. 10 Attachment B to April 2, 2003 UAC report: LEAP Implementation Plan Assuming average hydrologic conditions and that 10% new renewable resources (shaped like wind, the most likely renewables purchase in the short-term) are in place, the portfolio for the next three years is shown in the following chart: L0ad/Res0urce Balance - 2005-2007 100,000 .i-~t 80,000 2005: 7% exposed ~2006: 19% exposed ~_--4 2007: 23% exposed =60,000o 40,000 20,000 0ooo9oo0o,o,ooo90,o,o0oooooo0ooooooooooo............... Short-term Supply Portfolio Analysis The cost of the portfolio for years 2005-2007 was modeled with and without the three block purchases. The model calculated the expected costs and mark-to-market valuations as well as the risks around those results. As in the long-term analysis, assumptions and ranges of values were made for key uncertain variables: hydrologic year, electric market prices, and wind year. The results showed that, as expected, the three proposed block purchases would reduce the risk (cost variability). The hydrologic year is the uncertainty causing the greatest cost risk. The results show that the cost to serve the load ranges~ from about $29 to $67 ~ The ranges used here span 90% of the distribution, or from the 5% to 95% of the cumulative distribution of the cost. 11 Attachment B to April 2, 2003 UAC report: LE_~P Implementation Plan million/year (with an expected value of about $,43 million/year) for 2005-2007 if no commitments are made. Note that the range from low to high is about $38 million/year. If the three block purchases are made, the cost to serve the load ranges from about $30 to $62.5 million/year, a reduction in the range of cost by about $5.5 million/year. The chart below indicates the sources of the risk in cost that can be attributed to hydrologic year, electricity market prices, and both together. Source of Cost Risk 90% Range of Average Cost of 2005-2007 with and without 3 block purchases 4O o = 30E o, 25 £ 20 N 15 Without Block Purchases--i----~ 4 With Block Purchases hydro/elect price hydro only elect, price only hydro/elect price hydro only elect, price only Uncertainties Included The City should ensure that the Supply Rate Stabilization Reserve (SRSR) is adequate to ensure stable rates in such an environment of uncertainty. For example, if the hydrologic year is dry, the expected value of the average annual cost is about $56 million, or about $13 million more than an average hydro year. Staff is conducting analysis on the proper target for the SRSR and considering potential guidelines such as being able to maintain stable rates in the event of two dry years in a row. Short- and Medium-term Implementation Plan Guideline 3 sets the upper limit for fixed price resource commitments in the medium term, with a minimum market exposure of 10% of expected load for 2 to 5 years out. Given that we are in year 2003, this guideline provides the 90% maximum fixed price resource targets until year 2008. It, however, does not provide a minimum target, except 12 Attachment B to April 2, 2003 UAC report: LEAP Implementation Plan the long-term resource already available and the fixed-price renewable resource commitments. Staff wi!! unde~ake ana!yses of a!tematives taking in to consideration the City’s resource balance, retail rate targets, and reserve positions before making resource procurements in the short- to medium-term that fit under the LEAP Guidelines. The short-term implementation plan consists of the following elements: Preferred Recommendations for Short-term Portfolio To reduce this cost variability and to ladder the purchase commitments, while leaving sufficient flexibility to commit to long-term resources, three fixed-price block purchases are being contemplated for execution in year 2003: Block 1 (2005-2007) Block 2 (2005-2006) Block 3 (2005) on-pk off-pk on-pk off-pk on-pk off-pk X X X X X X X X X X X X X X x x x Oct I Nov I Dec X X X X X X X X X X X XX Seek Council approval of a set of master agreements with suppliers by summer 2003 with the authority to transact for terms of up to 3 years out. Any transactions outside this limit will be brought to the UAC and Council for approval. The Block 3 purchase can be executed using these master agreements since its term is within the 3-year allowable term if executed in 2003. The Block 1 and Block 2 purchases are outside the 3-year term limitation, therefore, staff expects to seek specific Council approval of those purchases in the next six months. Planning and Management of Supply Procurement Operations The functions of electric procurement, supply risk management, contracting, resource and contract optimization, balancing, coordination of dispatch and scheduling functions with NCPA, and billing and settlement functions of the City are primarily organized under the Assistant Director of Utilities Resource Management. The City achieves large economies of scale by leveraging NCPA’s contracting and market expertise when procuring resources. The City expects to utilize its master agreement with suppliers to contract for supplies for terms greater than approximately a year or when benefits of transaction through NCPA are non-existent. The additional cost associated with closer monitoring and control of long-term supply contracts may be justified for these contracts with a term of a year or 13 Attachment B to April 2, 2003 UAC report: LEAP Implementation Plan longer based on higher likelihood of supplier default, value loss that may be associated with defaults, and the higher dollar amount associated with such transactions. The City’s present electric portfolio modeling efforts are centered around interlinked spreadsheet based models with optimization routines. As the number of transaction and complexity of the electric portfolio increases and the need to closely monitor and report transactions arise, the City will be evaluating the potential of utilizing other software tools. The City’s Energy Risk Management Policies and Guidelines along with Portfolio Planning Objectives and LEAP Guidelines provide the framework for operations and control. The recent addition of a dedicated Energy Risk Manager will strengthen oversight and control and will facilitate reporting procedures to the Risk Oversight Committee and to the UAC and Council. In summary, the planning and management of short- and long-tel-m supply procurement operations is expected to be undertaken at the present staffing levels with the objectives of: -Clearly identifying and capturing supply needs and supply portfolio risks; *Whenever possible, utilizing simple tools to manage risks and utilizing NCPA resources and expertise; and o Managing the electric portfolio to achieve the portfolio objectives with streamlined operations to minimize overhead costs and to act expeditiously, while maintaining the appropriate level of oversight and control. NEXT STEPS The final LEAP Implementation Plan will be presented to UAC at its April 2003 meeting. Council will be asked to approve the plan in May or June. Council will be asked to approve master enabling agreements in the June or July of 2003. Council authorization will be sought as required for specific transactions. ATTACHMENTS: A.LEAP Guidelines approved by the City Council B.Description of Existing Supply Resources C.Portfolio Modeling Assumptions D.Portfolio Modeling Results PREPARED BY: Shiva Swanainathan and Jane Ratchye 14 Attachment B to April 2, 2003 UAC report: LEAP Implementation Plan Senior Resource Planners, Resource Management REVIEWED BY: Girish Balachandran Assistant Director, Resource Management APPROVED BY: John Ulrich Director of Utilities 15 Attachment B to April 2, 2003 UAC Report: LEAP Implementation Plan Attachment A Attachment A: LEAP Guidelines approved by the Ci%~ Council (Octobe.r 21, 2002 - CMR:398:02) Guideline 1 : Electric Portfolio Dependence on Western - x,\~i!e maintaining the flexibility to adopt favorable ’custom products’ offered by Western, manage a supply portfolio independent of Western beyond the Base Resource Contract. Guideline 2: Hydro Risk Management - Manage hydro production risk by: A. Planning for ma average hydro year on a long-term basis; B. Dix, ersifying to renewable and!or fossil generation technologies; and C. Maintaining adequate supply rate stabilization reserve. Guideline 3: Market Risk Management - Manage market risk by adopting a portfolio strategy for electric supply procurement by: A. Diversifying energy purchases across commitment date, start-date, duration, suppliers, pricing temls and fuel sources; B. Targeting additional thernaal plant ownership!investment conmaitment at ~25 M% but in no event more than 50 MW; C. Maintaining a prudent exposure to changing market prices by: 1. Procuring resources at fixed price for at most 90% of expected load for 2 or more years out, assuming average hydro conditions; and 2.Procuring resources at fixed price for at most 75% of expected load for 5 or more years out, assuming average hydro conditions; and D.Avoiding contract-based fixed price energy purchases (except for contracts for renewable resources) for durations greater than 10 years. Guideline 4: Reliable and Cost Effective Transmission Services - Ensure the reliability of supply at fair and reasonable transmission cost by: A. Supporting, through political and technical advocacy and!or direct investment, the up~ading of Bay Area transmission to improve reliability and relieve congestion; B. Participating in transmission market desig-n to ensure that market desig-n results in workable competitive markets and equitable cost allocation; C. Pursuing the option of forming and/or joining a Public Power Transmission Control Area to increase control over transmission operations and related costs; and D.Ensuring PG&E honors the Stanislaus Commitments by providing to us finn- transmission rights or equivalent. Guideline 5: Local Generation - Monitor the potential of local generation options to meet customer needs, improve local reliability, minimize congestion and wheeling charges, and stabilize/reduce costs. Attachment B to April 2, 2003 UAC Report: LEAP Implementation Plan Attachment A Guideline 6: Renewable Portfolio Investments - The City shall continue to offer a renewable resource-based retail rate for all customers who want to voluntarily select an increased content of renewable energy. In addition to the voluntary pro~am, the City shall invest in new renewable resources to meet the City’s sustainability goals while ensuring that t_he retail rate impact does not exceed 0.5 C/kWh on average. Pursue a target level of new renewable purchases of 10% of the expected portfglio load by 2008 and move to a 20% target by 2015; contingent on economic viability. The contracts for investment in renewable resources are not to exceed 30 years in term. Guideline 7: Electric Energy Efficiency Investments - Offer quality Public Benefits progams, utilizing funds collected through the 2.85% Public Benefits charge embedded in electric retail rates, to meet the resource efficiency needs of customers. Additional funding for cost-effective pro~ams will be recommended as appropriate. Pursue these investments by: A. Providing expertise, education and incentives to support cost-effective customer efficiency improvements; B. Demonstrating renewable and!or alternative generation tectmologies and new efficiency alternatives; and C. Providing rate assistance and efficiency programs to low-income customers. 17 Attachment B to April 2, 2003 UAC Report: LE:~P Implementation Plan Attachment B Attachment B: Description of Existing Supply Resources The table below shows CPAU’s inventory of existing generation and transmission resources that wil! be available in year 2005. Inventory of CPAU’s Existing Generation Asset or Resource Term! Nominal Western Base Resource Calaveras Hydroelectric plant SCL receipt (June-Oct) SCL return (Nov-April) 25 MW, Q1 & Q4 contract COTP Transmission TOTAL ExpiW Capacit y (Mw9 2024 -175 2032 54 2014 10 2014 (9) 2009 NA 50 and Transmission Portfolio, Year 2005 Expected Energy’ (GWh/yr) 130 16 (21) 110 NA 618 Dry Year Energy’ (GWh/yr) 222 48 16 (21) !10 NA 375 * The average unit cost is shown for average hydrologic conditions and can vary depending on the hydro conditions. Wet Year Unit Cost (after Energy ’removing (GWh/yr)stranded cost) 568 $19/MWh* 235 $o2/MWh 16 NA (21)NA 110 $36.60/MWh NA $! .7millionJyr 908 $25/MWh (energy only) widely Description of the Western Base Resource Western’s Base Resource is a very different product than the cm-rent Western Commercial Finn product. Currently, Western provides a capacity and energy allocation with minimum and maximum hourly, monthly, and yearly entitlements. Begimaing in 2005, Palo Alto must commit to pay an 11.62024 percentage share of Western’s costs (Palo Alto share is expected to be ~$9 million per year) in exchange for the same percentage of the daily output from the Base Resource. Therefore, the Base Resource is essentially a slice of the available hydroelectric resource. As such, it is a non-finn2 product and is subject to uncertain water supply conditions and uncertain water pumping load obligations. Western’s Base Resource is defined as the resource "avai]able after meeting the requirements of Project Use [water pumps for the Central Valley Project (CVP)] and First Preference customers [customers from the ’counties of origin’, where the CVP Trinity and Ne~v Melones dams are located] and any adjustments for maintenance, reserves, transformation losses and certain ancillary services". The generation designated as the Base Resource consists of: 1) CVP generation, which provides the majority of the energy produced; 2) a power purchase contract for 50 megawatts (MW) of peak load hour, market-priced energy that terminates in 2014; and 3) generation from the Washoe project, which is a small project located in northeast California producing an average annual generation of 10 gigawatt-hours (GWh). Western is currently negotiating with the supplier for the 50 MW of peak load power to te~Tninate that contract in exchange for a lump sum payment. Therefore, staff expects that this power will not be part of the Western Base Resource. 2 Firm supplies are those whose delivery can be counted on. Non-finn supplies can be interrupted for any reason (e.g. unit outage, hydrologic conditions, or economics). 18 Attachment B to April 2, 2003 UAC Report: LEAP Implementation Plan Attachment B Additionally, though not included in staff’s interpretation of the Base Resource contract, Western is proposing to include a several year, fixed-price, 4- to 6-month purchase of-200 GWh/year to help meet Project Use obligations. If implemented, Pato Alto will be allocated its share (11.62%) of this purchase. The estimated average am~ual energy available from Western’s Base Resource (CVP generation less Project Use o.bligations) is expected to be -3,300 G\,~. CVP generation is highly dependent on water supply conditions. During a dry year, the conesponding energy available is 1,900 GWh!year. A wet year is expected to produce 4,900 GWh!year. CVP generation is also dependent on enviro~nental regulations and constraints and water delivery obligations to CVP water customers and can change periodically. The potential impact of Trinity River restoration issues could reduce Base Resource energy availability by -10% from projected levels (CMR:423:02, October 21, 2002). Due to a variety of reasons, staff expects that the output fl-om the Western Base Resource will ~-aduatly decade over time. Continuing regulatory pressure, environmental issues and pressure from new users are expected to increase over time and, thereby, reduce the amount of power available for Western’s Base Resource product. Palo Atto’s Base Resource Allocation and Cost Since Palo Alto’s Base Resource allocation is about 11.6 percent, the energy available should be approximately 380 GWh/year in an average year. ~a~mual energy available to Palo Alto in dry and wet years are expected to be 220 GWh and 570 GWh, respectively. This compares to Palo Alto’s energy entitlement of 1000 GWh/year in the current Western contract and Palo Alto’s fiscal year 2001-02 load of approximately 1100 GWh. Western’s Base Resource (without the 50 MW power purchase) is expected to cost about $62 million/year. This means that Palo Atto’s 11.6 percent obligation ~vill be about $7.25 millions/year regardless of how much of the Base Resource is available and utilized by Palo Alto. Thus, in an average hydrologic year, the cost of Base Resource energy in 2005 is expected to be about $19 per megawatt-hour (MWh). In a dry year (10th percentile), the 2005 cost of Base Resource energy could be $33/MWh. Extremely dry years could increase costs even more. A wet year would yield more energy (90th percentile), at an estimated cos{ of onty $13/MWh in 2005. These cost, even in a dry year, compare favorable to the estimated market value of energy for 2005 of approximately $40-45/MWh. Description of the Calaveras Resource The 250 MW Calaveras hydroelectric power plant is situated along the North Fork of the Stanislaus River in Calaveras County. The Northern California Power Agency (NCPA) owns and operates this power plant. The City of Palo Alto has a permanent share of 21.6%, or 54 MW. The City temporarily divested 16 MW of the plant ownership; however, this capacity reverts back to the City in January 2005 so that the City will again have access to its pern~anent share of 54 MW of the plant output. 19 Attachment B to April 2, 2003 UAC Report: LETUP Implementation Plan Attachment B As with the Western Base Resource product, output from the Calaveras project is subject to hydro conditions. Pato Alto’s share of the expected output in an average hydro year is 130 GWh!year with dry and w:et hydro years )delding 48 GWh!year and 235 GWtfyear, respectively. The Calaveras project, coupled with the Western Base Resource, makes the bulk of the existing supply portfolio highly subject to variable hydro conditions. The bulk of the cost of the Calaveras project consists of debt payxments. The variable operational and maintenance costs are small, as are the.annual fixed maintenance costs. The City pre- collected part of the investment cost of the Calaveras project that were deemed "stranded costs" associated with this plant via increased retail rates during the 1997-1999 period. Thus, the remaining costs result in this resource being competitively priced at the prevailing electricity prices. Seattle City Light Energy Exchange Contract This 10 MW contract with Seattle City Light (SCL) was entered into in 1994 and is expected to end in 2014. Through this contract the City receives energy from June through October, and returns energy to SCL from November to April. This contract, though a very small portion of the supply portfolio, has served Palo Alto well in meeting the City’s energy needs, which are ~eater in the summer period of energy receipt than in the winter return period. Description of the Council-approved 5-year, 25 MW Q1/Q4 Contract Since the post-2004 deficit is so pronounced in the fall and winter months, staff desired to partially fill the "hole" with a medimn-tenn purchase after market prices had fallen significantly from the highs of 2000 and 2001. On November 13, 2001, the City Council approved staff’s proposal to purchase 25 MW of round-the-clock energy for the months of January, February, and March (Quarter 1, or Q1) and October, November, and December (Quarter 4, or Q4) for a five year term between years 2005 and 2009 (CMR:425:01). On August 13, 2002, a contract was executed with Coral Power, LLC for the approved product for a price of$36.60/MWh. COTP Transmission The California-Oregon Transmission Project is a 500 kV/1,600 MVA high voltage, 350 mile transmission line from the Oregon border to Northern California. The City owns 50 MW of this transmission line and utilizes it for access to generation resources in the Pacific Northwest. For example, the SCL contract energy receipts and deliveries are transmitted via this line. The City pre-coltected part of the investment cost associated with COTP that were deemed "stranded costs" via increased retail rates during the 1997-1999 period. With the creation of the Independent Systems Operator in California (CAISO), the transmission grid operator, there is a possibility that Palo Alto may turn over the operation of the transmission line to the CAISO. Palo Alto will, in turn, be provided first preference for the use of the line. ~other option being considered is to utilize the transmission to facilitate a new transmission control area for municipal utilities in conjunction with Western. 20 Attachment B to April 2, 2003 UAC Report: LEAP Implementation Plan Attachment B Load and Resource Balance Adjusting the load by the SCL contract obligations, the figure below shows the stack of supply resources available to meet load in an average hydro year for the years 2005-2009. Included in this stack is the 10% new renewables target for 2008 that is found in LEAP Guideline #6. That guideline also proposes a 20% new renewables fraction by 2015 120,000 100,000 Resource Deficit in 2008 AVERAGE Hydro Year Load (SCL adjusted) 80,000 --60 000 40,000 20,O00 0 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 21 Attachment B to April 2, 2003 UAC Report: LE.~P Implementation Plan Attachment B Supply Variability due to Hydrologic Conditions The monthly energy availability of the existing generation portfolio, its variability based on hydro conditions, and the energy deficit that needs to be filled to meet City load is shown below. 2008 Supply Resources 1 60,000 -! 140,000 J- 1 20,000 100,000 801000 60,000 40,000 20,000 Jan Feb Mar Apt May Jun Jui Aug Sep Oct Nov Dec Existing Energy Portfolio Characteristics The existing resource portfolio can be characterized as follows: a.There are insufficient energy resources to meet the City’s armual energy needs of-l,100 OWh in the 2005. The projected sho~-ffal] in an average hydro year is ~500 GWh, or of the total annual needs. b.The energy deficit is highly variable by month with gTeater deficits in the fall and winter than in the spring months. c.The total existing generation is highly variable and dependent on annual hydro conditions. In a normal hydro year the total energy available (given 10% renewables in place) is ~730 GWh/year, while wet and dr), year generation are 490 GWh/year and 1020 GWh!year respectively. d. The total generation capacity~ is close to the City’s capacity needs; hence, the deficit is mainly related to energy and not capacity. 3 Generation capacity is the rated load-carrying capability, typically expressed in megawatts (MW). Capacity is the peak amount of instantaneous’production a generator can supply. It is analogous to peak demand on the demand side. The City must have sufficient supply generation capacity to meet its peak demand. 22 Attachment B to April 2, 2003 UAC Report: LEAP Implementation Plan Attachment B e.The energy limited hydroelectric resource capacity is well suited to provide ancillary services. The City is expected to have an overall surplus of ancillary service provision capability. f.The portfolio contains some diversity in that it has access to Pacific Northwest resources due to ownership of COTP transmission. o The existing non-new renewable resources are low cost resources, with an average unit cost of-$25/MWh compared to current market energy prices of-$45/MWh. h.Hydro variability is lowest in fall months when deficits are the greatest. The ~eatest hydro variability is in the winter and spring months (December-May). 23 Attachment B to April 2, 2003 UAC Report: LEAP Implementation Plan Attachment C Attachment C: Portfolio Modeling Assumptions Evaluation of the LEAP portfolios requires making many assumptions about the future. This attactzrnent is a brief documentation of the key variables used in the spreadsheet model. Portfolios A set of portfolios consisting of a ~-oup of resources was developed. The portfolios included: 10. Do Nothin~ Portfolio - this portfolio assumes that no new long-term commitments are made for the post-2004 period except for complying with the new renewables guideline. This alternative is included as a baseline for comparison. Base Portfolio - make no additional commitments beyond the 25 MW thermal generation. This portfolio has the maximum exposure to market prices. The deficit will be filled in with short-term purchases of less than a year length to real-time spot market purchases. The gas purchased for the 25 MW of thermal generation is assumed to float with market prices. Maximum Fixed-Price Market Purchases - commit to fixed-price contracts with different terms (2-, 3-, 5-, and 10-year contracts) totaling the maximum allowable without violating the minimum exposure to market requirements of the guidelines. In addition, purchase the gas for 25 MW of thermal generation on a fixed-price basis. Maximum Them~al Portfolio - commit to 50 MW of thermal generation ownership. The gas purchased for the generation is assumed to float with market prices. Maxfinum Tolling Portfolio - commit to 25 MW of short-term (maximum ! 0-year) of round-the-clock thermal tolling contracts. The gas purchased for the generation is assumed to float with market prices. Maximum Local Resources Portfolio - commit to a total of 50 MW ownership of gas- fired generation within the City of Palo Alto. This could take the form of joint ownership of combined cycle, co-generation, or other efficient-low emission teclmologies or siting 2-5 MW generation and co-generation plants at customer facilities dispersed around the City. The gas purchased for the generation is assumed to float with market prices. Minimmn Hydro Portfolio - divest all of the 54 MW Calaveras resource. Fill in ~eater deficit with 25 MW of fixed-price contract commitment (maximum term = 10 years), The gas purchased for the 25 MW of thern~al generation is assumed to float with market prices. Super Green Portfolio - all new commitments made are for ~een resources. Maximize demand-side efficiency programs and customer site co-generation. Minimmn Exposure to Cono, estion Portfolio - Commit to ownership of 25 MW of large generation plant in Bay Area. Commit to ownership of 25 MW of generation sited within Palo Alto. The gas purchased for the generation is assumed to float with market prices. Hydro Hedge - in this portfolio, it is assumed that Palo Alto could find a partner who would be willing to take the hydrologic risk in the Western Base Resource product. The City would pay the partner an ammal fee and in return would get the average year output from the Western Base Resource every year regardless of hydro conditions. The gas purchased for the 25 MW of thernqal generation is assumed to float with market prices. For purposes of modeling these portfolio options, the following thermal resources were assumed: 24 Attachment B to April 2, 2003 UAC Report: LEAP Implementation Plan Attachment C Description Outside Bay Area Generation Inside Bay Area Generation Local Generation Tolling Contract (take-or-pay) Heat Rate (Btu/kWh) 740O 7200 9000 7000 Fixed cost (capital and fixed O&M) ($EVlW-yr) $46,000 $67,000 $81,000 $6d,000 Variable O&M (S~lWh) $2.00 $3.00 $5.00 $2.00 A matrix of the resources in each portfolio is shown below: Resources Western Calaveras Coral Q1/Q4 ¯ purchase Seattle City Light Ren e’~,ables 2 Additional DSSt Programs 3 Forward Purchase Outside Bay Area l Generation IInside Bay Area Generation Local Generation Tolling Contract (take-or-pay) Gas Exposure 4 Notes: ! 3 4 X X X x lOO % float X X X x lOO % 25M W X X x lOO % float fix 25M W 25M W X X X x lOO % 50M W float x X X x lOO % 25M w I float X X X x lOO % 50M W float X layof f x x x x x X X X X X 1 O0 200 1 O0 %%% Yes Yes 25M W 25M W 25M w fl,)at I N/A float X1 X X x 10o % 25M W float Output = average year output every year (no hydrologic uncertainty from Western) Super Green Portfolio to have renewables at twice that required by LEAP Guidelines Enhanced DSM programs to reduce load by 5%. Whether to lock in the gas price for thermal generation or let it float at market prices 25 Attachment B to April 2, 2003 UAC Report: LEAP Implementation Plan Attachment C Resources Western The output from the Western Base Resource is assumed to be as estimated b.y Western and be dependent upon the hydrologic year type. This resource is a part ofa!l portfolios. For the "Hydro Hedge Portfolio", the output is assumed to be as for an average hydrologic year for every year. @alaveras The output from the Calaveras Hydroelectric Project is assumed to be as estimated by NCPA and be dependent upon the hydrologic year type. NCPA’s estimates are based on years of actual hydrologic data. This resource is a part of all portfolios except for the "Minimum Hydro Portfolio", in which the resource is laid off in order to reduce the hydrologic exposure for that portfolio. Seattle City Light Contract The SCL contract obligations are specified in the contract and are expected to expire when the contract expires in 2014. This resource is a part of all portfolios. 25 MW 01/04 Purchase This forward purchase is for 25 MW of energy round-the-clock for Quarter 1 (January, February, and March) and Quarter 4 (October, November, and December) for the years 2005-2009. The contract cost is $36.60/MWH for all hours of the contract. This resource is a part of all portfolios. New Renewables Pro~am The LEAP Guidelines require increased investment in new renewable technologies. The target of 10% of load by 2008 and 20% of load by 2015 is assumed in all the portfolios. The cost for these resources is assumed to cost $25/MWh above the cost of today’s forward cost for electricity in the market. This will result in an increased cost of about 0.5C/kWh as allowed by the LE~d~ guidelines. This resource is in all the portfolios except for the "Super Green Portfolio", which has twice as much new renewables as required in the guidelines. Fo~,ard Purchase Forward purchases are priced at the forward electric market prices at the time of the analysis. The "Maximum Fixed-Price Portfolio" has a fixed-price forward purchase for 25 MW of on- peak energy and 10 MW of off-peak energy. The "Minimum Hydro Portfolio" includes a fixed- price forward purchase for 25 MW of on-peak energy. No other portfolio includes forward purchases. Thermal Generation Sited outside the Bay Area This thermal generation, assumed to be combined cycle tectmology, has a 7400 Btu/kWh heat rate and a 95% availability factor (assumes it is unavailable due to maintenance, etc. 5% of the time). The annual fixed costs (capital and fixed O&M) are estimated at $3.83/kW-month, or $46,000~4W-year. This corresponds to $800/kW of fixed costs financed over 30 years at an interest rate of 4%/year. Variable O&M costs are assumed to be $2/MWh escalating at 3%/year. Twenty-five megawatts (25 MW) of this resource is a part of the following portfolios: "Base", 26 Attachment B to April 2, 2003 UAC Report: LEAP Implementation Plan Attachment C "Maximum Fixed-Price", "Minimum Hydro", and "Hydro Hedge". 50MW of this resource is pa~ of the "Maximum Thermal Portfolio". Gas costs are assumed to float with market prices for all portfolios except the "Maximum Fixed-Price Portfolio", which is assumed to fixed the gas prices for ~eater cost certainty. These cost estimates are supported from ongoing con~nunication with marketers, suppliers, NCPA, a recent Wall Street Journal report and the analysis of a municipal utility in the Central Valley considering such a generator. Them~al Generation Sited inside the Bay Area This combined-cycle thermal generation assumes a 7200 Btu/kWh heat rate and a 95% availability factor. It has a better heat rate than the outside Bay Area generation due to the more moderate temperatures in the Bay Area than in the Central Valley, the likely site for generation outside the Bay Area. Due to higher labor and pem~itting costs in the Bay Area, the costs of this generation are assumed to be higher than if located in the Central Valley. The annual fixed costs (capital and fixed O&M) are estimated at $5.58/kW-month, or $67,000/MW-year. This corresponds to $1150/kW of fixed costs financed over 30 years at an interest rate of 4%/year. Variable O&M costs are assumed to be $3/MWh escalating at 3%/year. Gas costs are assumed to float with market prices. Twenty-five megawatts (25 MW) of this generation resource is a part of the "Minimum Congestion Portfolio". These cost estimates are based on recent negotiations with a merchant plant developer in the Bay Area and discussions with a municipal utility building generation in the Bay Area. Locally Sited Generation Thermal generation sited locally is assumed to have a 9000 Btu/kWh heat rate and a 95% availability factor. Its heat rate is consistent with a combustion turbine teclmology for a 50 MW unit. The annual fixed costs (capital and fixed O&M) are estimated at $6.75/kW-month, or $81,000/MW-year. This corresponds to $1400/kW of fixed costs financed over 30 years at an interest rate of4%/year. Variable O&M costs are assumed to be $5/MWh escalating at 3%/year. Gas costs are assumed to float with market prices. The "Maximum Local Portfolio" has 50 MW of this resource. Gas Tollin~ Agreement A price for a gas-tolling contract was developed to try to reflect the costs of thermal generation. It is a take-or-pay type contract for round-the-clock energy. Its cost is $5.50ikW-month, or fixed costs of $66,000!MW-year. Variable costs are assumed to be $2/MWh, escalating at 3%/yea.r. The heat rate is 7000 Btu/kWh and the gas costs are assumed to float with market prices. The "Maximun~ Toll Portfolio" has 25 MW of this resource. Expanded DSM Program The load forecast in the model assumes ongoing Demand-Side Management pro~ams are in place. The "Super Green Portfolio" and the "Minimum Congestion Portfolio" are assumed to have an additional 5% of load reductions due to ag~essive DSM programs. The costs for these programs are estimated to cost $50/MWh above the costs of market priced electricity. 27 Attachment B to April 2, 2003 UAC Report: LEAP Implementation Plan Attachment C Hvdro!odc Hedge In the "HydroloNc Hedge Portfolio" a hedge for hydrologic risk is in place. This hedge assumes that the output from the Western Base Resource is constant at the average hydro year output. For this certainty, the City pays $5!Mv~_. This cost is assumed to escalate at 3%!year. Ranges for Key Uncertain Variables Hvdro!ogic Year Hydrologic condition is a key variable for Palo Alto’s post-2004 portfolios. Production from both the Western Base Resource and the Calaveras Hydroelectric Project change with hydrologic year. Production estimates in "wet" (90% of the time, it is expected to be drier than this), "average" (50%) and "dry" (it is only drier than this 10% Of the time) years were obtained from Western for the Western Base Resource and from NCPA for the Calaveras resource. Together the impact of hydrologic year on production from the hydro-based resources is shown on the following chart: Monthly Hydro-Based Resource Production versus Hydrologic Year Type 160,000 140,000 I20,000 100,000 80,000 60,000 40,000 20,000 in AVera Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Electric Market Prices. Electricity market prices were developed from on-peak market quotes as of the time of the analysis (January 31, 2003) through calendar year 2007. "Base" electric market costs were expected to increase at 3%/year after 2007. Off-peak prices were assumed to be priced at 30% discount from on-peak prices. This is in line with marketer quotes for off-peak energy tkrough calendar year 2007. A "high" electric spot price scenario was developed that used an escalation rate of 3.7%/year after 2007. Similarly, the "low" electric spot price scenario has a 1.3%/year escalation after 2007. The resulting range of electric prices is shown in the chart below: 28 Attachment B to April 2, 2003 UAC Report: LEAP Implementation Plan Attachment C Electricity Market Price Forecast at NP15 (round-the-clock) $120 $110 SlOO $9O $8O $7O $6O $5O Forward Price Low Spot Market High Spot Market i Base Spot Market i $40 $30 Due to the predominance of natural gas as a fuel source for electricity generation in California, long-term forward market prices during the fall and winter months have been higher than the summer months to reflect the higher gas prices during this period. In the uncertainty analysis, it was assumed that electric prices depend somewhat on hydrologic year. In a wet year, electric prices are more likely to be low than high and, conversely, more likely to be high than low in a dry year. Gas Market Prices Gas market prices were developed from market quotes as of the time of the analysis (January 31, 2003). Ranges were developed to capture the uncertainty in those estimates. A "high" range assumed prices 50% higher than the base and the "low" estimate was 30% lower than the base estimate. The resulting range of gas market prices is shown in the following chart: 29 Attachment B to April 2, .00a UAC Report: LEAP Implementation Plan Attachment C Gas Market Price Forecasts $11 $1o $9 $8 $7 $6 $5 $4 $3 $2 High Forecast Base Forecast L or.., Forecast In the uncertainty analysis, it was assumed that gas and electric prices are somewhat correlated. If electric prices are high, gas prices are more likely to be high than low and, conversely, if electric prices are low, gas prices are likely to be low than high. Western Amaual Cost The fixed annual cost of the Western resource is uncertain due to increasing O&M costs, different cost allocation schemes bet.ween water and power customers, etc. The cost for the Western Base Resource is assumed to be about $7.25 million/year without Westem’s Enron purchase contract included. This variable was assumed to be uncertain and in a range of $6 million to $10 million per year. Western Annual Cost Escalation Rate The cost for the hydroelectric part of the Base Resource is assumed to escalate at 3%/year. A range from 1%/year to 5%o/year was tested for this uncertain variable. Western Availability De~adation There is some uncertainty with regard to the long-term energy available under the Western Base Resource contract. These uncertainties include the extent of energy purchases by Western and included within the Base Resource, the long-term decline of electricity production due to various environmental considerations, the extent of project use and first preference customer energy delivery obligations, etc. The estimated decline in availability is about t %/year. A range from 0%/year to 3%/year was tested for this uncertain variable. 3O Attachment B to April 2, 2003 UAC Report: LEAP Implementation Plan Attachment C Congestion Cost for Outside Bay .’Area Due to Palo Alto’s location in the Bay Area, it is expected to pay congestion costs for brining resources located outside the Bay Area into Palo Alto. These costs are highly uncertain and could be as high as $20/MWh. For purposes of this analysis, the base vaIue for congestion costs was set at $3/MWh, escalating at 3%/year. A range offiom $!/MWh to $5iMWh was used to test the sensitivity of the variable. Congestion Cost for Ingide Bay Area The costs of congestion for resources inside the Bay Area are highly uncertain and could be as high as $10!MWh. For purposes of this analysis, the costs are expected to be between $0 and $t .00/MWH, with an expected cost of $0.50!MWH. The cost is estimated to increase at a rate of 3%/year. Miscellaneous Uncertain Variables Palo Alto Loads A long-term load forecast was developed using standard forecasting methodology. The load is not increasing and is lower than actual load in FY 99-00. It is assumed that DSM pro~ams that have been implemented would continue to hold down load growth as we!l as the fact that Palo Alto is basically built out. Discount rate The City’s discount rate is assumed to be 4%/year for the duration of the analysis period. Changing this variable will not change the outcome of the analysis. Transmission costs Transmission costs to the citygate are assumed to be $5.50/MWh, escalating at 3%/year for the duration of the analysis period. Changing this variable is not expected to change the outcome of the analysis. This cost is avoided for resources sited locally, including enhanced DSM programs. 31 Attachment B to April 2, 2003 UAC Report: LEptA-’ lmpiementanon t’lan Attachment D Attachment D: Portfolio Modeling Results Analysis Approach The ten portfolios were developed so as to test a wide range of potential Strategies. The evaluation plan was to look at results from the tested portfolios and determine the expected costs and mark-to-market valuations as we11 as the risks of, or uncertainty around, those results. To evaluate the portfolios, a spreadsheet model was developed to calculate the monthly cost for each of the portfolios. Assumptions were made for every uncertain variable and ranges were developed for the most significant variables. Attactmaent C lists all assumptions used to characterize the resource options and for the uncertain variables. Uncertain Variables Although there are many assumptions required to model the alternatives, some are expected to be the most significant for the purposes of the analysis. Those critical variables include: 7. Hvdrolo,~ic year - production from both the Western Base Resource and the Calaveras Hydroelectric Project change with water availability, or hydrologic year. Production estimates in "wet" (90% of the time, it is expected to be drier than this), "average" (50%) and "dry" (it is only drier than this 10% of the time) years were used in the analysis. Electric market prices - the long-term fo~,ard curve for electric prices was developed from on-peak market quotes through calendar year 2007 and estimated for the period after 2007. "Base" electric market costs were expected to increase at 3%/year after 2007. "High" and "low" electric spot price scenarios were developed to test sensitivity of the portfolios to unYmown future electric prices. Gas market prices - the long-tem~ forward curve for gas prices was developed from market quotes. Ranges were developed to capture the uncertainty in those estimates. Western ammal cost - consistent with a hydroelectric resource, the yearly cost for the Western Base Resource is largely independent from the output of the Base Resource. Western mmual cost escalation rate - since Western is such a large resource in the electric portfolio, the overall portfolio costs are expected to be dependent upon the assumption for future Western costs. Western long-term production degradation - due to regulatory, environmental and other pressures, the availability of Western is expected to decline over time. Congestion Cost for Outside Bay Area- the costs of congestion that must be paid to bring resources located outside the Bay Area into Palo Alto. ConRestion Cost for Inside Bay Area - the costs of congestion that must be paid to bring resources located inside the Bay Area into Palo Alto. Ranaes for Uricertain Variables "Base" projections", or "50%" values, were developed for the key uncertain variables. In addition, "low" (10%) and "high" (90%) values were developed. Attacbanent C provides additional detail for each uncertain variables. 32 Attachment B to April 2, 2003 UAC Report: LEAP Implementation Plan Attachment D The ranges used in the analysis for each uncertain variable are shown in the chart below: Uncertain Variable Hydrologic Year Electric Market Prices Gas Market Prices Western ~mual Cost Western Cost Escalation Rate Western Availability D,e~adation Congestion Cost- Outside B~y A.rea * Congestion Cost - Inside Bay Area * Low (10%)Base (50%) Value Value Dry Average Low Base Low Base $6 million $7.25 mi!lion 1%/year 3 %/year 0%/year 1%/year $1/MWh $3/MWh $0/MWh $0.50kVIWh High (90%) Value Wet High High $10 million ,5%/Year 3%/year $5/MWh $1/MWh * Congestion costs are highly uncertain and could be much higher than the values used in this analysis. Congestion cost outside the Bay Area could be as high as $20/M\~q~. Congestion costs inside the Bay Area could be as high as $10/MWh. Results The cost to serve the projected load was calculated for each portfolio using the assumptions and uncertainties described. In addition, the cost to serve the load from the market was also calculated so that each portfolio could be "marked-to-market", or compared to the cost to serve the load at electric market prices. An expected value of the cost and the mark-to-market valuation was developed given the assumptions for each uncertain variable and the probabilities assiom~ed to the low, base, and high values. Attachment B to April 2, 2003 UAC Report: LEAP Implementation Plan Attachment D Cost to Serve Load The cost to serve load includes all costs of the supply portfolio to meet the projected load in an average year over the 20-year modeling period. With the assumptions used in the analysis, including the uncertainties, the portfolio with the lowest expected value was the "Maximum Thermal Portfolio", the portfolio with 50 MW of gas-fired generation located outside the Bay Area. The expected value of the cost for an average year was about $64 milli0n/year. The range of cost, given the uncertainties, was from a low (10%) of $49 million to a high (90%) of $81 million. The results of the analysis comparing the portfolios is shown in the following graph: LEAP Portfolio Results Cost to Serve Load (sorted by Expected Value) ~.95 ®90 r-.o 85 80 75 o 70 65 6O o 55© ~6 50 m 45 Medium (50%) Cost Mark-to-Market Value Mark-to-market (MTM) value is a comparison of the cost to serve load to the cost to serve the load at market prices. For example, if it would cost $75 million to serve the load at market prices and the cost to serve the load of a particular portfolio was $65 million, that portfolio would have a MTM value orS10 million. It is important to calculate the MTM value of portfolios, especially the risk of having a negative MTM value, so that decision-makers can determine the risks to locking in to 10ng-term contracts or commitments under changing market conditions. With the assumptions used in the analysis, including the uncertainties, the portfolio with the highest expected value for MTM was the "Maximum Thermal Portfolio", the portfolio 34 Attachment B to April 2, 2003 UAC Report: LEAP Implementation Plan Attachment D with 50 MW of gas-fired generation located outside the Bay Area. The expected value of the MTM for an average year was about $64 million/year. The MTM ranged from a low (10%) of $49 million to a high (90%) of $81 million. The resutts of the analysis comparing the MTM of the portfolios is shown in the following gaph: 40 35 30 25 20 15 10 5 0 -5 LEAP Portfolio Results Mark-to-Market Value (sorted by Expected Value) E-×peeted-Value Medium (50 RisWReward Comparison - Cost to Serve Load As discussed in this analysis, the cost to serve load is uncertain and depends on many uncertain variables. The actual cost is expected to lie somewhere between the high (90% value) and low (10%value) cost. The plot below shows the expected value of the cost to serve load on the x-axis and the risk of the cost to serve load on the y-axis. The risk is the difference between the high and low values for cost. The chart below illustrates the relationship between cost to serve load and the risk on cost to serve load for all the portfolios except "Do Nothing"(which had extremely high risk) and "Super Green" (which was very costly). The best portfolio from a cost to serve load perspective would have low cost to serve load and tow risk of cost to serve load. The chart of cost and the risk in 35 Attachment B to April 2, 2003 UAC Report: LEAP Implementation Plan Attachment D cost shows that there are some portfolios that are superior to others since either their cost is lower at the same or less risk or the risk is less at the same or less cost. For example, the "Maximum Local Portfolio" is more costly and higher risk than the "Minimum Congestion Portfolio". While the "Maximum Thermal Portfolio" is the lowest cost, there are several portfolios with lower risk. Although the °’Minimum Hydro Portfolio" has the lowest risk, its expected cost is $2.25 million higher than the "Maximum Thermal Portfotio’s". 35 r- 33 O E 32 o ® 30 m 29 o m 28Oo o 27 c~ 26 25 LEAP Portfolio Analysis Results ~ Base +Max Toll Max. Local Max Thermal .... [] Min. Congestion Max. Fixed Price Max. Thermal []Min. Congestion i .... Max. Fixed Pricei :.., Min. Hydro IXMax. Local e Base ’+ Max. Toll -Hydro Hedge ..... :: Min. Hydro 64 65 66 67 68 69 Cost to Serve Load ($ million/year) 7O RisWReward Comparison - Mark-to-Market As discussed in this analysis, the mark-to-market value of each portfolio is uncertain and depends on many uncertain variables. The actual MTM value is expected to tie somewhere between the high (90% value) and low (10%value) MTM value. The plot below shows the expected value of the MTM value on the x-axis and the risk of the MTM value on the y-axis. The risk is the difference between the high and low values for MTM. The chart below illustrates the relationship between MTM value and the risk on MTM value for all the portfolios except "Do Nothing" (which had extremely high risk) and "Super Green"’ (which had extremely low MTM value). The best portfolio from a MTM perspective would have high MTM values and low risk of MTM value. The "Maximum Thermal Portfolio" has the highest expected value for MTM ($15.1 million), but a relatively high risk on MTM ($36. ! 36 Attachment/3 to April 2, 2003 UAC Report: LEAP Implementation Plan Attachment D million). The portfolio with the lowest risk ($28.2 million) on MTM is the "Hydro Hedge Portfolio", but it also has the lowest MTM value ($10.4 million). The Base Portfolio" is in between with a MTM value of $12.5 million and a risk on MTM of $31.2 million. LEAP Portfolio Analysis Results 4O ~5 38 O ~ 36 -~ 34 ~ 32 c~ 30 o m 28 26 10 Max. Fixed Price Min. Con.g_estion [] Max. Local Max Thermal Min. Hydro.i Max Toll + Base Hydro Hedge , Max. Thermal [] Min. Congestion Max. Fixed Price >.f Min. Hydro )K Max. Local @ Base + Max. Toll -Hydro Hedge 1!12 13 14 15 Mark-to-Market Value ($ million/year) 16 Sensitive Variables The variables with the greatest impact on the risk were hydrologic year, electric market price, and gas market price. Hydrologic year was by far the geatest source of risk, followed by electric market price. _Hydr01ovic Year Not surprisingly, hydro risk is the ~eatest source of risk for the portfolios. For example, if all other variables were held at their base values, the variation in hydrologic year type alone would cause the cost of the "Maximum Thermal Portfolio" to vary from $50 million to $74 million. Although the costs varied the most due to uncertainty around the hydrologic year, most of the portfolios don’t differ as to hydro resource content. Only the "Minimum Hydro" (laying off the Calaveras resource) and "Hydro Hedge" (purchase a hedge against Western Base Resource variability) portfolios show less risk than other portfolios. However, the reduction of that risk comes at a cost. 37 Attachment D Electric Market Prices The cost of the "Maximum Thermal Portfolio" varies from $57.5 to $70 millior~year if all other variables are held at their base values while the electric cost projection is varied from "low" to "high". This is less than the variation in hydrologic year, but still sig-nificant. Gas Market Prices The cost of the "Maximum Thermal Portfolio" varies from $58 to $67 million/year if all other variables are held at their base values while the gas cost projection is varied from "low" to "high". This is less than the variation in hydrologic year or electric market price uncertainty, but still si~aificant. This variation could be reduced if gas costs were fixed, instead of being allowed to float with the market. However, if allowed to float, the risk on Mark-to-Market valuation would increase. Portfolio Sensitivities Maximum Thermal Portfolio This portfolio is sensitive to both electric and gas market prices. The cost risk could be reduced if gas prices were locked in, rather than allowed to float. If the capital costs of the thermal generation increased from the assumed ammal fixed costs (capital and fixed O&M) of at $3.83/kW-month to ~ $7!kW-month, then the Minimum Congestion Portfolio is superior. Minimum Congestion Portfolio This portfolio is highly sensitive to the cost of congestion. This variable is a very uncertain one given the lack of consensus on the outcome of several ongoing regulatory initiatives. If congestion costs for outside and inside the Bay Area were .-~ $10-12/MWh and $2/MWh, respectively, then the cost of all the portfolios would increase and the Minimum Congestion Portfolio would be the lowest cost portfolio. Maximum Fixed Price Portfolio This portfolio has ~eater cost, but less risk than the Maximum Thermal Portfolio, but is superior to the Base Portfolio on both cost and risk. It is sensitive to electric market prices and if prices are lower than expected, then this has a greater risk of having a negative mark-to-market value. The reason that the Maxinmm Them~al Portfolio has a lower expected cost is that the spark spread encourages thermal generation. If gas prices rose with respect to electric prices, this would not be the case and 25 MW of generation would likely be superior to 50 MW. Minimum Hydro Portfolio This portfolio is quite sensitive to electric market prices as the Calaveras project is laid offat the current valuation, which is based on the forward curve for electric prices. If electric prices increase, then the layoff would have been unfortunate. However, the risk could be reduced by purchasing electricity at a fixed-price for the expected output from the plant. Maximum Local Portfolio This portfolio, as with the Minimum Congestion Portfolio, is sensitive to congestion costs. If congestion costs were higher than projected, this portfolio would become much more attractive. 38 ORDINANCE NO. ORDINANCE OF THE COUNCIL OF THE CITY OF PALO ALTO AUTHORIZING THE CITY MANAGER TO PURCHASE A PORTION OF THE CITY’S ENERGY REQUIREMENTS DURING THE 2005 -2007 PERIOD [BLOCK 1 PURCHASES]AND THE 2005 - 2006 PERIOD [BLOCK 2 PURCHASES]UNDER SPECIFIED TERMS AND CONDITIONS The Counci! of the City of Palo Alto does ORDAIN as follows: SECT!ON i. The City Council finds, as follows: A.In 1967, the United States entered into a Contract No. 14-06-200-2948A with Pacific Gas and Electric Company ("Integration Contract"). Under this contract, the Western Area Power Administration ("WAPA") provides electric capacity and energy to the City of Palo Alto ("City") over PG&E’s transmission system. It will expire in December 2004. B.In 2000, the City entered into a Contract No. O0- SNR-0033 with WAPA ("Base Resource Contract"). Under this contract, the City wil! receive less electric capacity and energy than is currently made available under the existing power purchase agreement. It will begin in January 2005 and will expire in December 2024. C.On November 13, 2001, the Council by minute order approved four primary energy portfolio objectives ("Objectives"), including the objective to ensure !ow and stable electric supply rates for customers, and it also adopted Ordinance No. 4724, authorizing a five-year purchase of energy and capacity during the 2005 - 2010 period. D.By minute order, dated October 21, 2002, the Council approved seven electric portfolio planning and management guidelines to guide staff in developing and managing the City’s !ong-term electric acquisition plan ("LEAP Guidelines"). One of the LEAP guidelines is to diversify energy purchases according to several factors, including, but not limited to, dates and terms of commitment, suppliers, prices and fuel sources. E.The City Manager seeks the authority to purchase two 25 MW blocks ("B!ock 1 purchase" and "Block 2 purchase") of energy and capacity at fixed market-based prices and other terms and conditions. The purchases are intended to fil! a portion of an anticipated shortfal! in the City’s energy needs that wil! arise after 2004, consistent with the Objectives and LEAP Guidelines. 030528 syn 0072279 F.If energy is not provided pursuant to contracts at specific prices, then purchases would be made at variable and potentially higher spot market prices. The public health, safety and welfare require the City to now implement price risk management principles in order that the City may purchase energy in a timely and cost-effective manner to meet the anticipated energy supply deficit that wil! occur after 2004. G.The City will purchase energyand capacity, either directly from suppliers or indirectly from suppliers with the Northern California Power Agency acting as agent for the City. H.The total authorization for the Block 1 purchase shall be $22,340,000. The tota! authorization for the B!ock 2 purchase shall be $5,400,000. SECTION 2. The Council hereby authorizes the City Manager or his designated representative, the Director of Utilities, by appropriate written delegation, to enter into and execute standardized form energy contracts (EEI or WSPP, or equivalent) to effect the Block i purchase and the Block 2 purchase with qualified power suppliers, as fol!ows: BLOCK 1 PURCHASE general terms and conditions: (i)Quantity. Total purchases for on-peak and off-peak energy contracts negotiated and executed by the City under this authorization shall not exceed 25 megawatts of energy for any hour. (2)Term. Each contract shall not exceed a term of three (3) years and shal! not extend beyond 2007. (3)Delivery Period. The delivery of on-peak and off-peak energy shal! occur at any time during a seven- consecutive-month period, commencing September 1 and ending March 31, inclusive, during the term of any contract. (4)Delivery Point. Each contract shall specify COB or NP- 15, or equivalent !ocation, as the delivery point. (5)Price. Each contract shall establish fixed prices for energy and capacity, and the average price of all contracts entered into and executed by the City shall not exceed $59 per megawatt-hour. 030528 syn 0072279 2 BLOCK 2 PURCHASE general terms and conditions: (!)Quantity. Tota! purchases for al! on-peak energy contracts negotiated and executed by the City under this authorization shal! not exceed 25 megawatts of energy for any hour. (2)Term. Each contract shall not exteed a term of two (2) years and shall not extend beyond 2006. (3)Delivery Period. The delivery of energy shall occur at any time during a four-consecutive-month period, commencing September 1 and ending December 31, inclusive, during the term of any contract. Delivery Point. Each contract shall specify COB or NP-15 (or equivalent location) as the delivery point. (5)Price. Each contract shall establish fixed prices for energy and capacity, and the average price of all contracts entered into and executed by the City shal! not exceed $67 per megawatt-hour. SECTION 3. No contract for any Block 1 purchaseentered into and executed by the City Hanager or his designated representative and approved as to form by the City Attorney under this authority may extend beyond December 31, 2007. No contract for any B!ock 2 purchase entered into and executed by the City Manager or his designated representative and approved as to form by the City Attorney under this authority may extend beyond December 31, 2006. SECTION 4. The Council hereby finds that this ordinance is exempt from the provisions of the California Environmental Quality Act pursuant to Section 15061(b) (3) of the California Environmental Quality Act Guidelines, because it can be seen with certainty that there is no possibility of significant environmenta! effects occurring as a result of the adoption of this ordinance. // // // // // // 030528 syn 0072279 SECTION 5. This ordinance shall be effective on the thirty-first day after the date of its adoption. INTRODUCED: PASSED: AYES: NOES: ABSTENTIONS: ABSENT: ATTEST:APPROVED: City Clerk APPROVED AS TO F0~f: Mayor Senior Asst. City Attorney APPROVED: City Manager Director of Utilities Director of Administrative Services 030528 syn 0072279 4 Utilities Advisory Commission April 2, 2003 Approved Minutes ROLL CALL 2 ORAL COMMUNICATIONS 2 AGENDA REVIEW 2 REPORT FROM COMMISSIONERS 2 DIRECTOR’S REPORT 3 BUDGET/CIP OVERVIEW 4 FIBER TO THE HOME, PHASE I 11 Break 38 NCPA MEMBER COST SHARING AGREEMENT FOR THE FINANCING OF THE PLANNING & DEVELOPMENT OF THE POE HYDROELECTRIC PROJECT 38 LONG-TERM ELECTRIC ACQUISITION PLAN (LEAP) IMPLEMENTATION RECOMMENDATIONS 43 RISK MANAGEMENT REPORT PRESENTATION 46 RENEWABLE RESOURCE IMPLEMENTATION PRESENTATION 47 ADJOURNMENT 52 4/2/03 UAC MINUTES APPROVED Page 1 of 53 market. There is no subsidy here. There is no PMA Act issue here, so the issues that may be in some people’s minds and other cases is not relevant to this situation: Carlson: Any more discussion? Bechtel: I’d just like to respond. I think I’m going to support the motion. When it comes to licensing, think about it also, the FCC. All stations, radio, television require an FCC license. It comes up for renewal and if they’ve not done a good job in serving their listener or viewer base, then the FCC does something about it. The airways were ruled many years ago, so I’ll look at it in this way, if they fail to file a license application on time, then I don’t think we’re doing anything wrong by competing in the open market for getting that license. Carlson:Any more discussion? All I favor say aye. Ferauson,Bechtel, Rosenbaum, Beecham: Aye Carlson: I’ll say aye too. Dawes is Nay. Motion passes. Thank you very much Hari. This is going to be fascinating. It is probably worth the $143,000 gamble. Ulrich: Thank you Hari for coming down. I appreciate it. LONG-TEI~’I ELECTRIC ACQUISITION PLAN (LEAP) IMPLEMENTATION RECOMMENDATIONS Carlson: The next item is electricity. The long term purchases, or the medium term purchases Ulrich: As you recall, at our last meeting, we came up with a number of discussion items and recommendations for the long range implementation plan for our future electric energy. This is of such significance, this will go down much like whoever’s on the City Council, and there wasn’t a Utility Advisory Commission, that I could imagine that the City Manager m aking a recommendation to purchase the W estern contract somewhere around 1964. We’re moving into that era again, because of the Western contract portion of that are going away at the end of 2004. We’re here tonight to present and formally make recommendation on the implementation plan and request that you approve our recommendations, and go with us to the City Council for their discussion and approval. Since you’ve been through most of this before, I think probably the best way would be for you to ask us some questions, or if you like us to focus on one of the attachments or some of the items, we’d be gtad to do that. Carlson: Go ahead Rick. 4/2/03 UAC MINUTES APPROVED Page 43 of 53 Ferguson: For the sake of meeting efficiency, we really have been together on this topic several times, so maybe I can lead off by asking: what is new in this proposal that we haven’t talked about before2 Is there a specific number that’s been in the air, that’s finally came to ~ound here? Balachandran: Actually there is nothing new. If there’s any-thing it’s very minor. Changing in the wording, the way in which it is presented. We’ve gone tt-a-ough a very deliberate process and we came to you in that manner last time, basically laying out all of these recommendations, including the block purchases, and the long-term and short-term. So we’ve changed the format Of how we’re presenting it, so you see that in the attachment but that’s gonna be our blueprint when we come back to you..The next item you’re going to be hearing about today -- the renewable resource implementation plan, so that’s gonna take a path of its own, that you’re gonna see. You’re gonna see a thermal plant ownership. That will take a path of its own. Certain DSM programs. That will take a path of its own. And we talked to all of you about these. So we just kind’a reformatted it in a way that we can look at that map as we go down the path. Ferguson: Thank you. Carlson: Any other questions on this one? We certainly have looked at it before but this is the final detail. Dexter? Dawes: More of a sort of administrative situation and that is we are going to be embarking on lots of purchases. It’s going to get very confusing about which purchase we’re talking about unless we come up with a nice way of identifying it. For instance, a month ago we talked about short-term purchases and we had 1, 2,3 and basically, we’ve done the one, which is the initial hole-filling purchase. Then we have these two additional ones, no, you’re already shaking your head. i’m already confused. Balachandran We came to you last time saying we planned on buying 3 blocks. The recommendation that we hope will go to council only requires two blocks to be approved by council. The third block council has already given the City Manager authority to do a 1-year deal. So that recommendation will be executed by staff. It doesn’t need to go to Council. Dawes: So you’ll be numbering them just by consecutive block purchases, so when we see things in the future, we’ll be talking about blocks 4 & 5, and we’ll be able to locate them on one of these wonderful charts here. Just so we can track it nicely. Balachandran: Well, I’ll tell you, we’ll look at that because you are going to see a number of reports, Risk Management reports which are gonna track power purchases and these are just the beginning. 4/2/03 UAC MINUTES APPROVED Page 44 of 53 Dawes: That’s right. Balachandran: Once you have, you’re getting to the basic hydro here, I mean you’re gonna get into a number of blocks. I think your comment is basically tracking the different recommendations as we go down. Dawes: And tracking the actual purchases you made. Balachandran: The purchases and how they perform. We plan on doing that. Dawes: Come up with serial number protocol. Balachandran: OK. We’ll take that as an idea and someway of easily identifying it and presenting that information to you. Dawes: Secondly, has this been run by our new Risk Management person? Balachandran: Yeah, the Risk Manager has reviewed this, as has senior management in different departments. Dawes: You’re capping the cost of this thing? Is that wise, given the fact that this may be 3-5 months out, that you’re actually going to make these? Balachandran: There’s a balance that we have to strike between how much flexibility we ask for, given the market price as it is today. I think we are comfortable with what we recommending at 6 cents. Dawes: Okay. I wanted to ask about the RFP for the windmills. That’s my terminology for the renewables. I’m a little unclear, maybe I shouldn’t even address that, because you’re really talking about just these 2 items. Balachandran: No it’s actually .... Dawes: Do talk about it. Balachandran: I’ll answer that actually. You’re gonna get much more information from Karl gmapp when he makes his renewable implementation plan. As far as authority we’re asking for, we’re asking for the two blocks and recommendation 1 is the approval of the plan as a whole. So the actual action item when it comes to buying, whether wind energy or any other renewable energy, that’s gonna come to you at a future meeting. So this is just the plan. The plan is one piece, which is the broad piece, and two specific transactions in that plan. Ulrich: You may want to refer to attachment ’~A" and the recommended implementation plan that is shown on that document. 4/2/03 UAC MINUTES APPROVED Page 45 of 53 Dawes: I couldn’t make some of the numbers come out. \Vhen you talked about, I guess, I don’t want to go into at this point. Balachandran: Commission Dawes, Karl K_napp will be here for the next item. He’ll give you information on the latest on the RFP, if that’s what your question is heading towards? Dawes: No it was more as to the what the coverage’s were? Block 1 looks like it’s about 11%, Block 2 is 4%, and Block 3 is 11% of our consumption. \Vhen you look at the table on Page 5, the costs don’t seem to reflect this. I guess it’s because one 24/7, one is On Peak, and so forth. OK, fine. That’s all I have. Carlson: George? Bechtel: Just a practical question on Block 1 and Block 2. Would those be 1 contract each or are we assuming multiple contracts under each of those, to total 25 megawatts? Is that how you would normally do it? I was just curious as to how the RFP process is. Balachandran: It could be multiple. Bechtel: Thank you. Carlson: Any more questions on this one? We need a motion. Go ahead, Rick. Ferguson: I move the staff recommendation. Carlson: Is there a second? Bechtel: I’ll second. Carlson: Any further discussion. All in favor? All: Aye Carlson: Go ahead. Good luck. Glad the prices are dropping. RISK MANAGEMENT REPORT PRESENTATION Ulrich: The next item 5, our Risk Manager is not available this evening and we recommend that we move that to the next meeting. Balachandran: Commissioners, could I just take a moment to introduce some of our staff over here who have worked on it - the previous report? We have Shiva Swaminathan, 4/2/03 UAC MINUTES APPROVED Page 46 of 53