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2003-08-04 City Council (24)
City of Palo Alto City Manager’s Report TO: FROM: HONORABLE CITY COUNCIL CITY MANAGER DEPARTMENT: UTILITIES DATE: SUBJECT: AUGUST 4, 2003 CMR:354:03 FINANCE COMMITTEE RECOMMENDATION FOR APPROVAL 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 PERIOD [BLOCK 1 PURCHASES], PERIOD [BLOCK 2 PURCHASES], [BLOCK 3 PURCHASES] UNDER CONDITIONS DURING THE 2005-2007 DURING THE 2005-2006 AND THE 2005 PERIOD SPECIFIED TERMS AND RECOMMENDATION Staff and the Utilities Advisory Commission (UAC) recommend that the City Council: 1.Approve the Long-term 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 6C/kWh, 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:354:03 Page 1 of 2 bo Block 2: twenty-five MW of power not to exceed 6.7C/kWh and $5.4 million; and delivered during the on-peak hours only during the months of September through December for 2005 and 2006. In addition, staff recommends that the City Council authorize the City Manager to purchase the following block of energy at an average unit price not to exceed 6.5C/kWh, with an associated total cost not to exceed $7.98 million and complete all transactions associated with these purchases by June 30, 2004: Block 3: twenty-five megawatts (MW) of power delivered during the on-peak hours only during the months of January through December for 2005. COMMITTEE REVIEW AND RECOMMENDATIONS The Committee voted unanimously to accept staff’s recommendation and forward it to the full Council. ATTACHMENTS A: CMR:288:03 B: Finance Committee minutes excerpt from 7/15/03 TCHYE S~or Resource Planner DEPARTMENT APPROVAL: of Utilities CITY MANAGER APPROVAL: Assistant City Manager CMR:354:03 Page 2 of 2 TO:HONORABLE CITY COUNCIL ATTENTION:FINANCE COMMITTEE FROM:CITY MANAGER DEPARTMENT: UTILITIES DATE:JULY 15, 2003 CMR:288:03 SUBJECT:REQUEST FORAPPROVAL OF THE LONG-TERM ELECTRIC ACQUISITION PLAN IMPLEMENTATION PLAN AND ADOPTION OFAN 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], DURING THE 2005-2006 PERIOD [BLOCK 2 PURCHASES], AND THE 2005 PERIOD [BLOCK 3 PURCHASES] UNDER SPECIFIED TERMS AND CONDITIONS RECOMMENDATION Staff and the Utilities Advisory Commission (UAC) recormnend that the City Council: Approve the Long-term Electric Acquisition Plan (LEAP) Implementation Plan. Specific transactions will be brought to UAC and Council, as appropriate for approval. o 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, and complete all transactions associated with these purchases by June 30, 2004: a°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 3 go Block 2: twenty-five MW of power not to exceed 6.7C/kWh and $5.4 million; and delivered during the on-peak hours only during the months of September tlarough December for 2005 and 2006. In addition, staff reconmaends that the City Council authorize the City Manager to purchase the following block of energy at an average unit price not to exceed 6.5c/kWh, with an associated total cost not to exceed $7.98 million and complete all transactions associated with these purchases by June 30, 2004: Block 3: twenty-five megawatts (MW) of power delivered during the on-peak hours only during the months of January through December for 2005. 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 Conta’act 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. CPAU expected that, under the LEAP Implementation Plan, the City could and would execute one or more transactions for Block 3 (an additional block of power for the post- 2004 period) with counterparties by an arrangement with NCPA serving as our agent. CPAU has since determined that a new contract with NCPA will be required to effect those transactions. CPAU may complete the transactions using such a contract (to be negotiated in the furore) or directly from an approved supplier using a Master Agreement that will be approved by the Council. Authority for all specific short- and medium-term transactions identified in the LEAP Implementation Plan (Blocks 1, 2, and 3) is included in the recommended ordinance: BOARD/COMMISSION REVIEW AND RECOMMENDATIONS The UAC reviewed the recornmended LEAP Implementation Plan and a recommendation to approve the B!ock 1 and Block 2 purchases and approved the recommendations unanimously at its April 2, 2003 meeting. Subsequent to tlae April UAC meeting, staff detel-mined that it would seek authority from the Council for the Block 3 purchases as well as for Blocks 1 and 2. Although the UAC did not review that specific recommendation, the Block 3 purchase was part of the LEAP Implementation Plan that the UAC did approve. CMR:288:03 Page 2 of 3 ATTACH_lVIENTS A: 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], the 2005 - 2006 Period [Block 2 Purchases], and the 2005 Period [Block 3 Purchases] under Specified Terms and Conditions B:April 2, 2003 report to the UAC: LEAP Implementation Recommendations C:Minutes from the April 2, 2003 UAC meeting PREPARED BY: DEPARTIVIENT HEAD: CITY MANAGER APPROVAL: JApE RATCHYE ~S/ofiior Resource Plamaer ~or of Utilities Assistant City Manager CMR:288:03 Page 3 of 3 ORDINANCE NO. ORDINANCE OF THE COUNCIL OF THE CITY OF PALO ALTO AUTHORIZING THE CITY MANAGER TO PURCHASE ~ PORTION OF THE CITY’S ENERGY REQUIREMENTS DURING THE 2005 2007 PERIOD [BLOCK I PURCHASES], THE 2005 - 2006 PERIOD [BLOCK 2~ PURCHASES],AND THE 2005 PERIOD [BLOCK 3 PURCHASES]UIVDER SPECIFIED TERMS AND CONDITIONS The Council 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 low 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.On October 21, 2002, the Council by minute order approved seven electric portfolio planning and management guidelines to guide staff in dev~loping 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 three 25 MW b!ocks ("Block 1 purchase," "Block 2 purchase" and "B!ock 3 purchase") of energy and capacity at fixed market-based prices and other terms and conditions. The purchases are-intended to fill a portion of an anticipated, shortfal! in the City’s energy 1 030630 s)ql 0072279 needs that will arise after 2004, consistent with the Objectives and LEAP Guidelines. 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 will occur after 2004. G.The City will purchase energy and capacity directly from suppliers, and it may indirectly purchase from suppliers with the assistance of the Northern California Power Agency acting as agent for the City. The total authorization for the Block 1 purchase shall be $22,340,000. The total authorization for the Block 2 purchase shall be $5,400,000. The tota! authorization for the Block 3 purchase shall be $7,980,000. 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, Block 2 and Block 3 purchases with qualified power suppliers, as fol!ows: BLOCK i PURCHASE genera! terms and conditions: Quantity. Total purchases for on-peak and off-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 exceed a term of three (3) years and shall 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) (5) Delivery Point. Each contract shall specify COB or NP- 15, or equivalent location, as the delivery point. Price. Each contract shal! establish fixed prices for energy and capacity, and the average price of all contracts entered into and executed by the City shal! not exceed $59 per megawatt-hour. 030630 syn 0072279 BLOCK 2 PURCHASE general terms and conditions: Quantity. Total purchases for all on-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 two (2) years and shall not extend beyond 2006. (3 Delive[y Period. The delivery of energy shall occur at any time during a four-consecutive-month period, commencing September !~ and ending December 31, inclusive, during the term of any contract. (4 Delivery Point.. Each contract shal! 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. BLOCK 3 PURCHASE general terms and conditions: (1)Quantity. Total purchases for all 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 exceed a term of one (i) year and shall~ notextend beyond 2005. (~)Delivery Period. The delivery of energy shall occur at any time during, a twelve-consecutive-month period, commencing January 1 and ending December 31, inclusive, during the term of any contract. (4)Delivery Point. Each contract shall specify COB or NP:I5 (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 shall not exceed $65 per megawatt-hour. SECT!ON 3. No contract for any Block i 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, 2007. No contract for any Block 2 purchase entered into and executed by the City 030630 syn 0072279 Manager or his designated representative and approved as to form by the City Attorney under this authority may~extend beyond December 31, 2006. No contract for any Block 3 purchase entered into and executed by the City Manager or his designate~ representative and approved as to form by the City Attorney under this authority may extend beyond December 31, 2005. SECTION 4. The Council hereby finds that this ordinance is exempt from the provisions of the California Environmental Quality Act pursuant to Section 1506!(b) (3) of the California Environmental Quality Act Guidelines, because it can be seen with certainty that there is no possibility of significant environmental effects occurring as a result of the adoption of this ordinance. 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 FORM: Mayor Senior Asst. City Attorney APPROVED: City Manager Director of Utilities Director of Administrative- Services 030630 syn 0072279 4 MEMORANDUM 3 TO:UTILITIES ADVISORY COMMISSION FROM: UTILITIES DEPARTMENT SUBJECT: DATE: LEAP IMPLEMENTATION RECOMMENDATIONS APRIL 2, 2003 REOUEST: Staff recommends that the Utilities Advisory Commission (UAC) recommend that the City Council: 1.Approve the LEAP.hnplementation Plan (Attachment A). Specific transactions will be brought to UAC and Council, as appropriate for approval. 2.Authorize the City Manager to purchase the foll0wing 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 1" 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; al! focused toward proactively responding to this energy deficit. The implernentation 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 mariner in order that staff analysis would reflect and enhance direction from policy makers, a dviscrs and thc public. T he following p aragraphs replicatethe four Primary. Portfolio Plapming Objectives and the seven Long-term Electric Acquisition Plan Guidelines in order to provide context for the culminating LEAP Implementation Plan that is being presented foi approval in this report. The City Council approved four Primary Portfolio Planning Objectives on November 13, 2001 (CMR:425:01) to guide the development of strategies to fi!l 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 m~ March 5, 2003 for input and feedback (Attachrnent 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 undertaken in this regard. The graphic below traces the timeline for LEAP development and irnplementation: Post 2004 Electric Portfolio Process Council approval- 11113/00 & 5/21/01, (CMR: 418:00 and CMR: 223:01) Council approval of risk management policies, 2/20/01, (CMR: 103:01) Council approval - 11/13/01, (CMR: 425:01) Public Energy Forum #4 - 8/1/02 Council approval ~ 10/21/02, (CMR: 398:02) Council approval 10/21/02 (CMR:400:02) [ Todo Action from UAC requested in April Council action requested in May/June 2003 To UAC/Council, when required 2003-2004 ;. 9. Final LEAP Implementation Plan _10. Specific Deal Approval Requests Council 9resentation - 3/18/02 (0MR:176:02 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 significant project. Overall Proposed Implementation Plan The recommended implementation plan (both for long- and for short- to medium-term) is Attachment A to this repol-t. The following discussion adds to the discussion presented to the UAC at its March 2003 meeting. Long-Tem~ Implementation Plan Discussion 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 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 c.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 genetic finn 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 0.5C/kWh. 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 f t he portfolio o ptions w ill necessarily 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 tliat 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 minimum 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 f~xed-price resources applies until year 2008. There is no minhnum target. Howeyer, the long-term resources already committed and the fixed-price renewable resource commitments act as a minimum of sorts. If no additional resourees 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 programs 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 .PJan conform 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 General 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 Implementation 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 approvalsthat may be required to implement fi.~ture recommendations will be brought to the Council for approval. Implementing the recommended energy block purchases is expected to cost about $!9.75 million ($15.67 million for~Block 1 and about $4.08 million for Block 2). Staff is requesting authorization to spend up to $27.74 million to allow for changes in market price between the present time and the time the purchases are actually made. An estimate for the cost for these energy purchases has been included in long-term power. cost projections and in the proposed FY03-05 budget. The budgets for the years FY04- 05, 05-06, 06-07 and 07-08 either include an estimate or will include the actual costs for the Block 1 and. Block 2 purchases. The following table provides an indication (calculated using market prices available at the time this report was written) of the estimated cost of these purchases, by fiscal year. All estimates tEstimated in M$Total E~timated 15.67Block 1 cost Estimated Block 2 cost Estimated Total Cost 4.08 19.75 FY04-05 1.87 1.87 FY05-06 5.24 2.11 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 1.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 B purchase will be implemented by staff under existing authorities [On March 3, 2003, 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 fgr additional specific transactions that comply with the LEAP Implementation Plan, 5. The Energy Risk Manager will infol-m the Counc’~l and the UAC of the perfom~ance of the electric ~upply 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 arid 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 Uh’ich 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 (REP) 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 program 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 fllnded 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 formally announce to the market Palo Alto’s interest in investing in thennaI 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 I1. 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-related 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 information 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 NIedium-Term Portfolio To reduce short-term cost variability and to ladder the purchase comrnihnents, while leaving sufficient flexibilify to commit to long-term resources, three fixed- price block purchases are recommended for execution in year 2003: Jan Feb Ma[Apr May Jun Jul Aug Sep Oct Nov Dec Block 1 on-pk X . X X X X X X (20,05-:2,007)off-pk X X X X X X X Block 2 o_2~k X X X X (2005-2006)off-pk Block 3 on-pk X X .......X X X X iX ......X x x x x (2005)off-pk ! 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 $5.3 million for Block 3 (5.1 #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 Agreement (CMR: 135:03 on March 3, 2003). Seek Council approval of a set of master agreements 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 of: a.. Clearly identifying and capturing 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 program 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 Council approved four Primary Portfolio Planning Obiectives on November 13, 2001 (CMR:425:01~ Objective 1:Ensure low and stable electric supply rates for customers. Objective 2:Provide superior financial perfom~ance to customers and the City by maintaining a s upply portfolio cost advantage c ompared 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 oppdrmnities including transmission system upgn-ades and local generation. Objective 4:Balance environment, local reliability, rates and cost impacts when considering renewable resource and energy efficiency investments. The City Councilapproved 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 cornmitment 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. M~intaining 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: Do 2.Procuring resources at fixed price for at most 75% of expected load for 5 or more years out, assuming average hydro conditions; and Avoiding contract-based fixed price energy purchases (except for contracts for renewable resources) for durations greater than 10 years. 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 upgrading 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 PubIic 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 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/kWh 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 progt:ams,-utilizing funds collected through t~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. 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 I, 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 adopt.ed 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 of primary 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). 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 electric 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 were also proposed to direct :;taffin 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 p~-ocess for LEAP evaluation so far: Post 2004 Electric 1.Portfolio Analysis Presentations; Approval of Energy Risk Management Policies 2. Approval of Primary Portfolio P!anning Objectives 3. Approval of Initial 25 MW Purchase 4. Renewable Resource Analysis 5. Portfolio UpdatePlan 6. Additional Public Input t7. Final Plan & Implementation Process 8. Specific Deal Approval Requests Portfolio Process I Completed UAC analysis presentations:Feb 14 & Sept 15 2001" Council approval of risk management policies, Feb 20, 2001 (CMR: 103:0!) 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 G~idelines 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 EXECUTIVE SUMIVIARY The Ci~ is moving from a position of electric load-resource balance over the past 40 years, with prima-y 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 refo!-rnulating 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 transition. !.There must be a clear understanding of the City’s primary portfolio planning objectives and !ong-te~Tn 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. While constantly rnonitoring gas and electric market prices, staff is in ongoing discussions with suppliers, potential pamaers, andNCPA 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 ~uch 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-ten-n and the sh0rt-term electric supply portfolios. Longr ten-n Sul~p!y P oft foli o Impl em entati on Recomm end ati on s The implementation plan at this time for the long-term supply acquisition consists of the following elements: o 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. 3 Attachment J~ to Aprll ;Z, ZuuJ UA(2 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 Convnittee and the Cou{~cil to add these products to the list of approved products in the Energy Risk Management Policies. Shore-term Supply Portfolio Implementation Recommendations The short-term implementation plan consists of the following elements: To reduce cost variability and to diversify the pin’chase 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 agreements, 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 tema if executed in 2003. The Block 1 and Block 2 purchases are outside the 3-year ten~a limitation, therefore, staff expects to seek specific Council approval of those purchases in the next six months. Planning and Management of Supply Procurement Operation~ 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 through NCPA. As the number of transactions and the complexity of the electric portfolio increa.ses, 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 Whenever possible, utilizing simple tools to manage risks and utilizing NCPA resources and expertise; and Managing the electric portfolio to achieve the portfolio objectives with streamlined operations to minimize overhead costs and to act expeditiously, while maintaining the appropriate, leve! of oversight and contro!. 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 marketprices 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 minimum of 25% of expected load for 5 to 20 years out Target thermal plant ownership (or equivalent) of between 25 and 50 MW Maximum te~Tn of 10 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% newrenewables by 2008, 20% new reriewables 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: 5 Electric Resources in AVERAGE Hydro Year 1200 1000 8OO 600 400 200 00000 000000000000000000000000 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 Nothing Portfolio - this portfolio assumes that no new long-term commitments are made for the p0st-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 po1~:folio has the maximum exposure to market prices. The deficit will be filled in with short-term pro-chases 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 maximmn allowable without violating the minimum exposure to market requirements of the guidelines. In addition, purchase the gas for 25 MW oftherrnal generation on a fixed-price basis. I0. Maximum Thermal Portfolio- commit to 50 MW of therma! generation ownership. The gas purchased for the generation is assumed to float with market prices. Maximum Tolling Portfolio - commit to 25 MW of short-term (maximum 10- year) ofround-the-c!ock them~al 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 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 Congestion Portfolio - Connnit to ownership of 25 M-W 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 annual 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 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 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 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. Future Uncertainties Assumptions were made for every uncertain vm-iable. "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 shown in the chart Below: " Uncertain Variable ,,Hydrologic Year ................ Electric Market Prices Gas Market Prices Western Annual Cost Western Cost Escalation Rate Western Availability Degradation Congestion Cost- Outside Bay Area * Low (10 %) Value Dry Low Low $6 million 1%!year O%/year $1 !MWh Base (50%) Value Average Base Base $7.25 million 3%/year 1%/year $3/MWh High (90%) Value Wet High ......... High $10 million 5%/year 3%/year $5/MWh Congestion Cost - Inside Bay Area * ! $0/MWh $0.50/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/MWh. Congestion costs inside the Bay Area could be as high as $10iMWh. 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) o__J o © High (90%) Cost Medium (50%) Cost .............. t. ~p~ ~1 ~, -,vuo t~ report: LEA~" Implementation Plan Long-term Implementation Plan The resutts 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, Pal0 Alto is not in a position to drive the construction of such a plant. Second, the cost of congestion is not known at this time and the resolution of that issue could greatly impact Pa]o 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- ten~ commitment for renewable energy that will meet 5-I0% of the City’s projected load. The cost premium is expected to be -1 C/kWh over market energy prices for a generic firm resource with a conesponding seasonal generation profile. The implementation plan at this time for the long-term supply acquisition consists of the following elements: 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. Staff will 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 info~xnation 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 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. Shor*-term Supply Po.’-ffo!io .~.~L~ ..... * The long-term poi-tfolio plan was developed with a long-term view, and it includes, by design, 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 thermal generation identified in the long-tema plan. will be in place by 2005, or even 2007. To limit exposures and to provide rate stability, staff recommends a laddering approach td 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. Three energy blocks are contemplated to fill the deficits in the coming months include: 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 monflas (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 Assuming average hydrolo~c 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: Load/Resource Balance - 2005-2007 100,000 80,000 60,000 40,000 20,000 2005: 7% exposed l~__~t 2006:19% exposed I~_N 2007: 23% exposed o 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 million/year (with an expected value of about $43 million/year) for 2005-2007 if no corrmaitments 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 range.s 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 cbst 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 ~ 35 = 30 _~ 25 ~ 2o Without Block Purchases 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 ¯the long-term resource already available and the fixed-price renewable resource commitments. cons~,~,.ratl,~l the c,:÷.,,oStaff......wi!! undertake analyses of alternatives taking an to ;’~’~ o ""~ ,..~ ~ resource balance, retail rate targets, and reserve positions before making resource procurements in the short- to. medium-tern~ 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, tt~ee fixed-price block purchases are being contemplated for execution in year 2003: ,,Jan Feb Mar Apr May Jun,, Jul Aug Sep Oct Nov Dec Block 1 on-pk X X X X X X X (2005-2007)off-pk X X X X X X X Block 2 on-pk X X X X (2005-2006)off-pk Block 3 on-pk ~X X ..............X X X X X X X X X (2005)off-pk ........{ ............................ o Seek Council approval of a set of master agreements with suppliers by summer 2003 witla the authority to transact for terms ofup 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 longer based on higher likelihood of supplier default, vMue 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 interlimked 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 tile Risk Oversight Committee and to the uAc and Council. 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; ¯Whenever possible, utilizing simple tools to manage risks and utilizing NCPA resources and expertise; and ¯Managing the electric portfolio to achieve the portfolio objectives with streamlined operations to minimize overhead costs and to act expeditiously, while maintaining tile appropriate level of o’~ersight 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 Swaminathan and Jane Ratchye 14 Senior Resource Planners, Resource Management REVIEWED BY: Girish Balachandran Assistant Director, Resource Management APPROVED BY: John Ulrich Director of Utilities 15 Attachment A Attachment A: LEAP Guidelines approved by the City Council (Octobe,r 21, 2002 - CM-R:398: 02) Guideline 1: Electric Portfolio Dependence on Western - While maintairdng the flexibility to adopt favorable ’custom products’ offered by Western, manage a supply portfo]io 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 2.Procuring resources at fixed price for at most 75% of expected toad for 5 or more years out, assuming average hydro conditions; and D.Avoiding contract-based fixed price energy put.chases (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 upgrading 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 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 loca! reliability, minimize congestion and wheeling charges, and stabilize/reduce costs. 16 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 program, the City shall invest in new renewable resources to meet the City’s susthinability goals while ensuring that the 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 programs, utilizing funds collected tba-ough the 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: 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. 17 Attachment B Attachment B: Description of Existing Supply Resources The table below shows CPAU’s inventory of existing generation and transmission resources that will be available in year 2005. Inventory of CPAU’s Existing Asset or ~Resource Term/ Expiry Western Base Resource 2024 Calaveras Hydroelectric 2032 plant SCL receipt (June-Oct) ....2014 SCL return (Nov-April)2014 25 MW, Q1 & Q4 contract 2009 COTP Transmission TOTAL Generation Nominal Capacit y (M~V) -175 54 and Transmission Portfolio, Year 2005 Expected Dry Year Wet Year Unit Cost (after Energy Energy Energy -removing (GWh/yr)(GWh/yr)(GWh/yr)stranded cost) 383 222 568 $19/MWh* 130 48 235 $32/MWh* 16 (21) !1o NA 618 16 (21) " 110 NA 375 (21) 110 NA 908 10.¸ (9) NA 50 NA $36.60/MWh $1.7million/yr $25/MWh (energy only) * The-average unit cost is shown for average hydrologic conditions and can vary widely depending on the hydro conditions. Description of the Western Base Resource Western’s Base Resource is a very different product than the current Western Commercial Firna product. Cunently, 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 Resohrce is essentially a slice of the available hydroelectric resource. As such, it is a non-finn? product and is subject to uncertain water supply conditions and uncertain water pumping load obligations. Western’s Base Resource is defined as the resource "available 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 New Melones dams are located] and any adjustments for maintenance, rese~wea, transformation losses mad certain ancillary smMces’. The generation designated as the Base Resource consists of: !) CVP generation, which provides the majority of the energy produced; 2) a power purchase coat{act 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 terminate that contract in exchange for a lump sum payment. Therefore, staff expects that this power will not be part of the Western Base Resource. ~ Firm supplies are those whose delivery can be counted on. Non-firm supplies can be interrupted for any reason (e.g. unit outage, hydrologic conditions, or economics). 18 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 GWhJyear to help meet Project Use obligations. If implemented, Palo Alto wilt be allocated its share (11.62%) of this purchase. The estimated average am-real energy available from Western’s Base Resource (CVP generation less Project Use obligations) is expected to be -3,300 GWh. CVP generation is highly dependent on water supply c~nditions. During a dry year, the corresponding energy available is 1,900 GWh/year. A wet year is expected to produce 4,900 GWh/year. CVP generation is also dependent on environmental regulations and constraints and water delivery obligations to CVP water customers and can change periodically. The potential impact of Trinity River restoration issues co\rid 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 fiom the Western Base Resource will gradually degrade 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 Alto’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. Westem’s Base Resource (without the 50 MW power purchase) is expected to cost about $62 million/year. This means that Palo Alto’s 11.6 percent obligation will be about $7.25 million/year regardless of how much of the Base Resource is available and utilized by Palo Alto. Thus, in an average hydr.ologic year, the cost of Base Resource energy in 2005 is expected to be about $19 per megawatt-hour (MWh). In a dry year (10~h 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 (90~h percentile), at an estimated cos{ of only $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 ow.nership; however, this capacity reverts back to the City in January 2005 so that the City will again have access to its perrnanent share of 54 MW of the plant output. 19 Attachment B As with the Western Base Resource product, output from the Calaveras project is subject to hydro conditions. Palo Alto’s share of the expected output in an average hydro year is 130 GWh/year with dry and w.et hydro years yielding 48 GWh!year and 235 GWl-dyear, respectively. The Calaveras project, coupled with tlae Western Ease Resource, makes the bulk of the existing supply portfolio hiNaly subject to variable hydro conditions. The bulk of the cost of the Calaveras project consists of debt payments. 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 proj ect that were deemed ’°stranded costs" associated with this plant via increased retail rates during the 1997-1999 period. Thus, the remaiNng 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, m~d 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 greater 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 medium-term 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-collected part of the investinent cost associated with COT.P 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-Altowill, in tuna, be provided first preference for the use of the line. Aaaother option being considered is to utilize the transmission to facilitate a new transmission control area for municipal utilities in conjunction with Western. 2O 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 80,000 60,000 40,000 20,000 Resource Deficit in 2008 AVERAGE Hydro Year Deficit 1 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 21 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 160,000 140,000 120,000 100,000 8o,ooo 60,000 SCL Adjusted 40,000 20,000 0 Jan Feb Mar Apr May Jun Jul 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 rneet the City’s annual energy needs of-l,100 GWh in the 2005. The projected shortfall in an average hydro year is -500 GWh, or-45% of the total mmual needs. b.The energy deficit is highly variable by month with greater 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 nonna! hydro year the total energy available (given 10% renewables in place) is -730 GWh/year, while wet and dry 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. ~ 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 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. The existing non-new renewabl~ resources are low dost 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 greatest hydro variability is in the winter and spring months (December-May). 23 Attachment C Attachment C: Portfolio lYIodeling Assumptions Evaluation of the LEAP portfolios requires making many assumptions about the future. This attachment is a brief documentation of the key variables used in the spreadsheet model. Portfolios A set of portfolios consisting of a group of resources was developed. Th~ portfolios included: 10. Do Nothing 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 them~al 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 ofthem~al generation is assumed to float with market prices. Maximum Fixed-Price Market Purchases - commit to fixed-price contracts with different tenns (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 Thermal Portfolio - commit to 50 MW of thermal generation ownershipt The gas purchased for the generation is assumed to float with market prices. Maximum Tolling Portfolio - commit to 25 MW of short-tenn (maximum 10-year) of round-the-clocl( thermal tolling contracts. The gas purchased for the generation is assumed to float with market prices. Maximum Local Resources Portfolio - commit to a total orS0 MW ownership of gas- fired g~neration 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 cormnitments made are for green resources. Maximize demand-side efficiency programs and customer site co-generation. Minimum Exposure to Congestion Portfolio - Commit to ownership of 2~ MW of large generation plant in Bay Area. Commit to ownership of 2~ 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 mmual 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 2fi MW of thermal generation is assumed to float with market prices. For purposes of modeling these portfolio options, the following thermal resources were assumed" 24 Attachment C Description Outside Bay Area Generation Inside Bay Area Generation ........ Local Generation Tolling Contract (take-or-pay) Heat Rate (Btu/kWh) 7400 7200 19000 17000 Fixed cost (capital and fixed O&M-) - ($/MW. -yr) $46,000 $67,000 $81,~00 .... $66,900 Variable O&M ($~VrWh), $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 Renewables 2 Additi0~aI DSM programs 3 Forward Purchase Outside Bay Area Generation Inside Bay Area Generation X X X X X X X X X X X X X X X X X X X X 100 100 100 100 100 %%%%% X X X X Xl X layof X .....x x f x x x x X x x ..........x x 100 100 .......200 100 %%%% Yes Yes ......... 25M 25M w W 25M 25M 50M 25M W W W W w Local Generation ~olling Contract (take-orTpay) Gas Exposure 4 Notes: 1 2 3 50M W 25M W float float fix float float float float N/A float Output = average year output every year (no hydrologic uncertainty from Western) x lOO % 25M W float 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 C Resources Western The output from the WesternBase Resource is assumed to be as estimated by Western and be dependent upon the hydrologic year type. Tkis resource is a part of all portfolios. For the "Hydro Hedge Portfolio", the output is assumed to be as for an average hydrologic year for every year. Calaveras 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-tl~e-clock fox 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 Program The LEAP Guidelines require increased investment in nev¢ 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 LEAP 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. Forward 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. ThelTnal 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-m0nth, or $46,000/MW-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 C "Maximum Fixed-Price", "Minimum Hydro", and "Hydro Hedge". 50MW of this resource is par~ of the "Maximum Thermal Portfolio"..Gas costs are assumed to float with market prices for all portfolios except the "M-aximum Fixed-Price Portfolio", which is assumed to fixed.the gas prices for greater cost certainty. These cost estimates are supported from ongoing conmmnication with marketers, suppliers, NCPA, a recent Wall Street Jmm-~al 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 be 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 Aaea~ 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 con-esponds 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 Port.folio". 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 technology for a 50 MW unit. Th~ 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 of 4%/year. Variable O&M costs are assumed to be $5/MWh escalating at 3%/year. Gas costs are assumed to floa[ with market prices. The "Maximum Local Portfolio" has 50 MW of this resource. Gas Tollin~ A~reement 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 $5.50/kW-montb, or fixed costs of $66,000/MW-year. Variable costs are assumed to be $2/MWh, escalating at 3%/year. The heat rate is 7000 Btu/kWh and the gas costs are assumed to float with market pricesi Th~ "Maximum Toll Portfolio" has 25 MW of this resource. Expanded DSM Program. The load forecast in the model assumes ongoing Demand-Side Management programs are in place. The "Super Green Portfolio" and the "Minimum Congestion Portfolio" are assumed to have an additional 5% of load reductions due to aggressive DSM programs. The costs for these progrmns are estimated to cost $50/MWh above the costs of.market priced electricity. 27 ~ttacnment ~ to Aprn z, zoo~ t3~t~ Keport: Lv,A_t" lmplementanon t’lan Attachment C ~vdrolo.aic H e d g_e_e In the "Hydrologic 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 hycho year output. For this certainty, the City pays $5/MWh. This cost is assumed to escalate at 3%/year. Ranges for Key Uncertain Variables ~¥drologic Year Hydrolo~c condition is a key variable for Palo Alt0’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% 0fthe 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 160,000 140,000 120,000 I00,000 80,000 60,000 40,000 20,000 ,0 I I I I I 1 I I 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 through 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 C E!ectricity Market Price Forecast at NPI 5 (round-the-cl0ck) $120 $11o $1oo $90 $80 $7O $6O $5O $4O $30 $2O t n Forward Price -*- Low Spot Market ---:÷-High Spot Market -*-- Base Spot Market Due to the predorninance ofnaturaI 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 some.what 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 tirne 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 C Gas Market Price Forecasts $11 $10 $9 rn $8 ---- $7 v o $6 co $5 $4 High Forecast ~_..~_~....---~ Base Forecast ~’~’--" ..................... Low Forecast $3 In the m~certainty analysis, it was assumed that gas and electric p~ices are somewhat con-elated. If electric prices m’e 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 Annual Cost The fixed al~nual cost of the Western resource is uncertain due to increasing O&M costs, different costallocation 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 Ertron 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 l%/year to 5%/year was tested for this uncertain variable. Western Availability De,aradation There is some -uncertainty with regm-d 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 productidn 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 l%/year. A range from 0%/year to 3%/year was tested -for this uncertain variable. 3O 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 bringing 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 value for congestion costs was set at $3FMWh, escalating at 3%/year. A range of fiom $1fMWh to $fi/MWh was used to test the sensitivity of the variable. Congestion Cost for Ja~gide 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 $1.00/MWH, with an expected cost of $0.50iMWH. 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 programs that have been implemented would continue to hold down load growth as well 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. Cha~ging this variable will not change the outcome of the analysis. Transmission costs Transmission costs to the citygate are assumed to be $5.50£VlWh, 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 prognams. 31 Attachment D Attachment D: Portfolio Modeling Results Analysis Approach The ten portfolios were developed so as {o test a wide range of potential ~trategies. The evaluation plan was to look at results fiom 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. Assnmptions were made for every uncertain variable and ranges were developed for the most significant variables. Attachment 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 sigmificant for the purposes of the analysis. Those critical variables include: Hydrologic 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 thm~ 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 forward curve for electric prices was developed from on-peak market quotes tlgough 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 unknown future electric prices. Gas market prices - the long-term forward curve for gas prices was developed f:rom market quotes. Ranges were developed to capture the uncertainty in those estimates. Western mmual 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 productior~ degradation - due to regulatory, environmental and other pressurds, 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. Congestion Cost for Inside Bag Area- the costs of congestion that must be paid to bring resources located inside the Bay Area into Palo Alto. Rm~,~es for U~icertain Vari ables "Base" projections", or "50%" values, were developed for the key uncertain variables. In addition, "low" (10%) and "high" (90%) values were developed. Attacl~ment C provides additional detail for each uncertain variables. 32 Attachment D The ranges used in the analysis for each nncertain variable are shown in the chart below: Uncertain Variable Hydrolo~c Year Electric Market Prices Gas Market Prices Western A~mual Cost Western Cost Escalation Rate Western Availability Degradation Congestion Cost - Outside Bay Area * Congestion Cost - 5aside Bay Area * Low (10%) Value Base (50%) Value High (90%) Value Dry Low Low $6 million 1%/year 0%/year $1/MWh $OFMWh Average Bgse Base $7.25 million 3%/year 1%/year ¯ $3/MWh $0.50/MWh Wet High High $10 million 5%/year 3%lyear $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 $20fMWh. 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 m~d 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 assigned to the low, base, and high values. 33 Attachment D Cost to Serve Load The cost to serve load includes al! 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 Therma~ Portfolio", the portfolio with 50 MW of gas-fired generation located outside the Bay A~’ea. The expected value of the cost for an average year was about $64 milli6rgyear. The range of cost, given the uncertainties, was-from a low (t 0%) of $49 million to a lkigh (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) o_3 o o (D o > 95 90 85 8O 75 7O 65 High (90%) Cost Medium (50%) Cost L-6W-(-1-0 o~)-C-0-gt- Mark-to-Market Value Mafl(-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 of $10 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 into 10ng-terrn 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 D with 50 MW of gas-fired generation located outside the Ba~ Area. The expected value of the MTM for an average year was about $64 milli0n!year. The MTM ranged from a low (10%) of $49 million to a high (90%) of $81 million. The results of the analysis comparing the MTM of the portfolios is shown in the following ~aph: 4O LEAP Portfolio Results Mark-to-Market Value (sorted by Expected Value) 35 30 25 20 15 10 5 0 -5 9.0%) MTM E-xp eet-ed-V-al-u e Medium (50%) MTM 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 10ad 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 toserve load perspective would have low cost to serve load and low risk of cost to serve load. The chart of cost and the risk in 35 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 $2.25 million higher than the "Maximum Thermal Portfolio’s". 35 -c- 34 c 33 o E 32 -o 31 o ® 30 u? 29 o co 28oo o 27 ~ 26 25 LEAP Portfolio Analysis Results ¯ Base +Max Toll Max. Local Max Thermal []Min. Congestion Max. Fixed Price ¯ Max. Thei-rnal []Min. Congestion Max. Fixed Price :::<Min. Hydro NMax. Local ¯Base +Max. Toll __-_HYdro Hedge ..... Min. Hydro 64 65 66 67 68 69 Cost to Serve Load ($ 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 lie somewhere between the high (90% vakle) 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 ($36.1 36 Attachment D million). The portfolio with the lowest risk (528.2 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 $31.2 million. LEAP Portfolio Analysis Results 4O 26 Max. Fixed Price : ........... __Min. Congestion [] Max. Local Max Thermal Min. Hydro Max Toll + Baseo Hydro Hedge ¯ Max. Thermal []Min. Congestion Max. Fixed Price ;<Min. Hydro ;K Max. Local ¯Base +Max. Toll -Hydro Hedge 10 11 12 13 14 15 Mark-to-Market Value ($ 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 greatest source of risk, followed by electric market price. ~ydr0logic Year Type Not sm-prisingly, hydro risk is the greatest 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 E~ectric ~arket P~ces The cost of the "Maximum Thermal Portfolio" varies from $57.5 to$70 million/year if all other variables are held at their base values while the lectric 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 vmiables 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 significant. 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 m~d 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 am~ual 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 anal $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 greater cost, but less risk than the Maximum Thermal Portfolio, but is superior to the Base Portfolio on both cost and risk. tt 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 Maximuin Thermal 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 Utilities Advisory Commission April 2, 2003 Approved Minutes ROLL CALL 2 ORAL COMMUNICATIONS 2 AGENDA R_EVIEW 2 REPORT FROM COMMISSIONERS 2 DIRECTOR’S REPORT 3 BUDGET/CIP OVERVIEW 4 FIBER TO THE HOME, PHASE I 11 Break 3 8 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 REC OMMENDATI ONS 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 t’11 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. E.~rgusQn, Bechtel, Rosenbaum, Beecham: Aye Carlson: I’ll say aye too. Dawes is Nay. Motion passes. Thank you very much Haft. 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-TERM 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 making a recommendation to purchase the Western 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 glad 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 before? 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 anything it’s very minor. Changing in the wording, the way in which it is presented. We’ve gone tl~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 c~fhow 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 refon-natted it in a way that we can look at that map as we go down the path. Fer~uson: 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 dea!. So that recommendationwill 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 acta_~ally. You’re gonna get much more information from Karl Kmapp when he mak.es 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 actua! 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 show.n onthat docm’nent. 4/2/03 UAC MINUTES APPROVED Page 45 of 53 Dawes: I couldn’t make some of the numbers come out. When you talked about, I guess, I don’t want to go into at this point. Balachandran: Commission Dawes, Karl Knapp will be here for the next item. He’ll give you infolTnation 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. When 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 ! 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. Fer~uson: I move the staff recommendation. Carlson: Is there a second? Bechtel: I’1t 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 Finance Committee July 15, 2003 Long-term Electric Acquisition Plan Morton: The next item on the agenda is the Long-term Electric Acquisition Plan. John, would you like to introduce this item? Ulrich: Yes, we’re setting up a short presentation that will summarize the two items that we have this evening. First off, this is our long-term electric acquisition plan that we’ll be referring to as LEAP. And you’ve had an opportunity to look at this a short time ago and we took the information you gave us when we reviewed our plan with the Utilities Advisory Commission. They approved this plan unanimously. Attached to the CMR is a copy of an ordinance authorizing the City Manager to purchase a portion of the City’s energy requirements for what we’re calling Block 1, Block 2, and Block 3, and also a copy of the implementation recommendations that were reported to the UAC in April and the minutes of that meeting. So all this may look a bit complex. We wanted to show you the thorough investigation that we did because I don’t think I would be understating that this is probably one of the most important decisions that we’re going to be asking you to participate in and recommend to the City Council their approval because our current four- year contract that provided virtually all our electric supply is ending at the end of 2004 and this is the replacement plan, both the short-term plan for the transition and then a longer-term plan for acquisition of assets that we hope will be in place for many years to come. This also incorporates the interest I think all of us have in having renewables as a replacement for some of the electric supply that we currently have. So this is a blend of all of those in a strong attempt to have a firm and reliable supply going into the future. So we’ll review those in details and feel free to ask any questions. Freeman: I have one. This actually states that the UAC saw the information for Block 1 and Block 2 but did not see or have input on B!ock 3. Ulrich: Yes. Freeman: So that’s clarified? I want to make sure all my colleagues understand that that the UAC did not look at the Block 3, only Block 1 and Block 2. Balachandran: Could I clarify that? The UAC actually did look at it. All the blocks were presented to them. We didn’t ask them for a specific recommendation on Block 3, but Block 3 is part of the implementation plan that they approved. It may get a little clearer as we go along as to the context of the blocks as part of the long-term plan. Freeman: Okay. (Inaudible) said they did not review specific recolrm~endations. Balachandran: Because we did ask them for it. Morton: ...recommendation for it but they did see the overall... Balachandran: Correct. Ulrich: Girish Balachandran will go through the overview and the report and our attempt is to summarize this and feel free if there’s anything that isn’t clear, just ask away. Balachandran: Thank you. Feel free to stop me at anytime for questions. First off, I would like to say this is a joint effort, a number of people behind actually who did most of the work from different divisions and the Utilities Department. Beecham: So you brought half your staff here? Balaehandran: Pretty much. We also have the Marketing Manager, we have folks from ASD, the Risk Manager is also here. Kishimoto: Would you mind introducing them? Balachandran: Sure. That’s Karl Van Orsdol. He’s the Risk Manager and he reports to Carl Yeats. This is Tom Auzenne, Utility Marketing Manager. There’s a piece our plan which is demand-side oriented. Tom Kabat, Jane Ratchye, Karla Dailey, Shiva, and Karl Knapp from Utilities, all of whom played a role in developing this plan. I’m going to divide my presentation. The first few slides are background and setup for why we are here. This is essentially two views of our portfolio. The pie chart on the left tells you what we have today. The pie chart on the right tells you what our future portfolio is going to look like. This includes, you can see the deficit is about 26% of our needs. There’s also 20% renewable portfolio in there which you approved several months ago, and you’ve also approved 25 MW purchase. This slide basically tells you how the deficit in our portfolio after the year 2004 changed based on hydro conditions. So this is basically our portfolio in two different hydro conditions. The point of this is there’s a large variability due to hydro. There are outside forces in addition to what’s happening to us through our contracts (inaudible). This chart basically talks about different outside forces, from State regulators, Federal regulators, the Legislature, State and Federal level, the California ISO. And these are different uncertainties that affect our planning process. Beecham: There’s been some talk in the community about why it takes more effort now to manage (inaudible). This is one reason why it gets more and more complex and more (inaudible) driven, than just flipping switches. Balachandran: This management structure essentially describes the energy risk management structure. This spans different departments. It talks about directing the City Council to the different offices we have, the front, back, and middle offices and this was something that you approved back last year which then ted to hiring of the Risk Manager. You approved the Risk Management Policies. So there’s a controlled structure in place that allows you to have adequate oversight of utilities operations. We also have the City Auditor and City Attorney having an advisory role in the Risk Oversight Committee. Yes? Kishimoto: (Inaudible). You’re going pretty fast. Just to give you some numbers on this, like on this first column. So this is 25 MW? What (inaudible). Balaehandran: This is an energy-based chart and so the rule of thumb for Palo Alto is 1,000 Gwh is what we use a year. Kishimoto: Currently? Balaehandran: It’s actually a little more than that. Actually we peaked out at about 1,150, and now I think we’re at about 1,080, 1,050. Kishimoto: Okay. Balaehandran: It’s easy to divide and multiply with that. Kishimoto: And the future, what kind of, assuming not too much... Balachandran: Exactly, our growth is not really significant... Ulrich: (Inaudible). You’re seeing a significant difference between the Western contract and the deficit that ensues because of variabilities in that hydro conditions after the new contract comes into place. Kishimoto: Right. Let’s see, on your chart about the deregulation, can you just quickly walk us through this and see if there’s anything, what we should know about this. Balaehandran: Let’s go clockwise from the top at State Regulators. Today we have the California PuNic Utilities Commission which regulates the IOUs. They also influence our cost on the gas side which we’ll come to later. On the electric side, they deal with the IOU’s. They also deal with transmission expansion planning. Kishimoto: What is that? Balaehandran: Investor-owned utilities, which is PG&E essentially. So PG&E and we’ve come down to that on the bankruptcy again. We have the California Energy Commission which has siting approval. They’re in charge of that. They also do energy plans for the state. They’re also involved in a number of renewable resource initiatives. They do develop the standards for what is a renewable resource and what’s not. You have the California Power Authority which was created during the energy crisis and right now, their aim in life is to build peaker plants and that’s plants that can deal with the summer peaks. They also have authority to invest in renewable resources. You also have an Electricity Oversight Board that was supposed to coordinate some of the actions of the energy industry in California. The California Power Authority and Electricity Oversight Board are kind of in flux right now. Their roles are not really clearly defined. Kishimoto: So do they actually create peakers or they encourage peakers, I mean they create more (inaudible)? Balaehandran: They put out RFPs to get peakers installed. The state regulation right now looks at different ways of consolidating these different agencies so that we can have a coherent energy policy and you know what happened in the State Legislature. So that kind of has its own... Freeman: ...business of the 1800’s. Balaehandran: Well, it seemed simpler 10 years ago. Freeman: Well, if you look back at the history of the whole Central Valley Project and all that, every time something came up they couldn’t deal with, they create a new government agency and it would either be state or federal or somebody else. I mean then they go away and then they come back and they morph, but this is more than ever. Balaehandran: As Counci! Member Beecham was saying~ we didn’t have to interact with many of them in the past whereas today we have to because many of them influence decisions which could have a large impact on Palo Alto. That really is a major change that we’ve seen day to day in our work, and it doesn’t seem to be getting better. The federal regulators, you have the Federal Energy Regulatory CommisSion. One of the big things they’ve been trying to do is standard market design. Actually, I think Council Member Kishimoto went back to DC to try to slow that down; it was very effective. But today, for example, the California ISO, which is on the top left, has come up with what they call Market Design 2002, which is their way of implementing standard market design. The FERC in one forum says, "Yea_h, we’re going to slow this down, we’re going to issue a white paper, we’re going to look at all different regions in the country and what their concerns are. On the other hand, they’re going full speed ahead in implementing California’s structure. So, to a certain extent, they’re speaking from both sides of their mouth. So the Market Design 2002 on the top left has the potential to impact us a lot for what’s known as the new market structure (inaudible) transmission congestion pricing. And Palo Alto being in the what’s known as the transmission congestive zone, there’s potential for our costs to go up. Kishimoto: So they could affect our transmission rates as soon as next year or .... Balaehandran: Yes, as soon as next year. Even before, our costs have been going up because administration costs ofrurming the ISO gets passed through to us. Beecham: Nothing changes, we get no more service, just more charges. Freeman: They need an audit. 4 Balachandran: As a matter of fact, the ISO was audited, and it was a scathing audit. They said, "Okay, here it is" and put it aside. It’s like many of the recommendations of the audit have not been implemented. The bankruptcy case, I actually created a slide prior to PG&E and the PUC coming out with their settlement plan. So the new market structure was (inaudible) .... know what they were thinking at that time. But there’s uncertainty about how far that plan’s going to advance, and we could be impacted in both the electric and gas sides. Talk about the federal legislature, the State Legislature’s SB888 doesn’t seem to be going very far this year. I think the authors introduced a line in there saying it’s for display purposes only. So, it’s really not going to go very far. The renewable portfolio standard introduced by Senator Sher, that’s a law and we’re following that. Actually, we’re doing more than what he required. There’s some risk to how the investor-owned utilities would actually implement it in the sense that what you have approved for us is very much more clear than what the investor-owned utilities have to do. So, maybe five years from now, 10 years from now, who knows, there’s a risk that maybe their plans will change whereas our plans, you know we may have invested in some renewables already, and our relatively competitive position can be affected. Just something to keep a lookout for and we do track it. What are our main thoughts about deregulation? One is we propose standard market design, Market Design 2002. We encourage bay area transmission investment and we work with PG&E and the ISO and FERC on that. We’ve told FERC in a number of our filings saying, if you want to impose the standard market design on us, make sure you have enough transmission investment and make sure that no market power exists, and market power is basically the ability of suppliers to raise their prices because they have captive demand. In the Bay Area, you have about 70% of generation owned by two companies, not a very good situation. This slide tells you (interrupted). Go ahead, Bern. Beecham: I was going to go back to a comment on the previous slide. As far as I can tell, we in Palo Alto have probably, I think, one of the best risk oversight system setup considering what I have seen at NCPA and, I suspect, generally within munis. I think we have been in the forefront of analysis, the audits, external and internal, and I think it’s top-notch. Balaehandran: Over here, all the boxes in yellow are what have been approved already, and all those initiatives that you have approved support what we are bringing to you today. What we are bringing to you today is No. 8, the LEAP Implementation Plan and block purchases. This is not very clear, maybe it’s clearer in your handout. Essentially what we are trying to do here is give you an overview of LEAP. On the right-hand side in red are different uncertainties and issues that are driving the need for a plan. On the left- hand side, the three branches talk about the first one are the objectives, the portfolio objectives that you approved. The portfolio objectives were stable rates, energy efficiency, reliability, supply rate advantage. The specific language is in your report. We built on those objectives in creating seven guidelines which were more detailed on those four objectives. You approved that in October, 2002. So today we come to you with our Implementation Plan which builds on those objectives and guidelines and basically deals with these drivers and uncertainties. The Inaplementation Plan has two components to it. There’s a long-term portfolio component which has 11 different segments to it and we’ll go into those. We have a short-term portfolio component which has four segments to it. We have two recommendations. One is to approve the whole Implementation Plan in concept. And, specifically, we would like you to approve one of those 15 recommendations which is the block purchase recommendation. Each of the other parts of the plan will come to you as appropriate for approval. For example, we are looking at a thermal investment if there’s a demand response program. As an efficiency program, those would be brought back to you in the context of here’s the plan you approved and here are the specific details of that particular aspect of the plan. Freeman: Palo Alto agreed, it has already been brought? Balacllandran: Correct, there are aspects which have been done already. On to the next slide. These are 11 different parts of the long-term portfolio part of the LEAP plan and as Council Member Freeman said, the Palo Alto Green Program has been implemented and, I believe, to great success. It’s actually been tremendous. Acquiring renewal resources to meet LEAP Guidelines, that process has started already. Council Member Beecham is chairing a committee of the NCPA Commission that is looking into a renewable RFP and we’ve completed Phase 1 of that. Phase 2 will be done sometime in September. Going down, No. 4, investments in efficiency, Utility Marketing Services and ourselves look at opportunities. Just like during the energy crisis, you approved up to $5 million to spend on energy efficiency. When those opportunities come up, we look at them. So, the first four could be classified in the green category. The next three could be in the, basically, traditional generation resources, especially No. 5. We are working with NCPA to issue an RFP for generation resources. The Cities of Alameda, Santa Clara, Palo Alto are specifically interested in getting generation. A number of the other smaller members are also interested in investing in some thermal generation. Freeman: Which thermal generation? Balachandran: Basically gas-fired generation. Freeman: Do you have an example of something? Ulrich: Well, they’re building a plant near Santa Clara, Los Esteros. It’s a plant that takes natural gas out of the pipeline and burns it and turns a turbine (inaudible). Beecham: And more locally, Stanford has a 49 MW cogen plant. Freeman: That’s the one that’s ..... Ulrich: Thermal, in our terms, is some way of making electricity from burning a fossil fuel. Freeman: Coal, for example. 6 Balachandran: Yes. Ulrich: Well, we’re thinking about that, but we haven’t put that in the (inaudible). But that would be an example. And some utilities are using .... Freeman: Isn’t Stanford’s coal? Beecham: And what you see coming up is steam (inaudible). In fact, Santa Clara does have coal facilities and we talked about it. (Interruption) ....more facilities that are coal- burning facilities (inaudible). Ulrich: If you look at the mix in California, we’re a share of that energy that is used in Palo Alto. Some of it comes from the burning of coal some place in the Southwest. Freeman: So prepare an RFP for more energy from sources like coal burning. Ulri(h: Typically, they’re going to be natural gas. Balachandran: We basically are going to focus on natural gas. So, when you look at 5 and 7, there could be some tradeoffs between them. A gas tolling option is basically a financial product where you mimic a thermal plant, You can buy a heat rate from a supplier. Basically you can buy heat rate of, say, 8,000 BTUs/Kwh and you pay a capacity price for that and whenever you want to get electricity, you can actually fix the price of gas on your own and basically run it throu~h that virtual (inaudible) Kishimoto: You have to pay up front, like you’re building a plant? Balachandran: No, just like a power plant, you pay every month. It’s not a prepay. Ulrich: There’s a number of alternatives that you have to look at and some have more risks and costs than rewards. Freeman: And No. 6 is of interest. What would that be? Balachandran: That could be cogen in Palo Alto, distributed generation which is real small generation in Palo Alto to support the distribution system. So sometimes you can actually site a small generator at a customer site and avoid adding new distribution lines. Knapp: There’s an overlap between No. 6 and No. 1. There are some locally-sited resources which aren’t really big enough to meet the big 20% (inaudible), but just about anything you find in Palo Alto is going to be renewable or fuel cell or something ultra clean anyway. Ulrich: One of the reasons why we have these alternatives is that as Girish pointed out these risks that are articulated about transmission and congestion into Palo Alto. Some of the tradeoffwill be to have generation that is close to locally produced as possible. 7 Freeman: I guess my concern, though, is cleanliness of generation. I would hate to see a coal generator in the middle of a Palo Alto street. Ulrich: As much I may want to pursue that, the reality of that is about the same as a nuclear power plant. But I think we should be looking at other options like natural gas. Why don’t you go to a coal plant sometime? Freeman: I grew up in Pennsylvania - I know about them. Kishimoto: Do you have a breakdown in percentage or what you’re expecting from this one? Balachandran: Yes, actually the guidelines that you approved already do that. It does that. For example - let me switch to the next slide - the guidelines say 25-50 MW of thermal generation. Some of the analysis we have done say investing in 50 MW of thermal generatio~ is the best option at the present time. So, when you look at that, and since it’s lumpy and opportunities don’t come up very often, we don’t really have contro! of how much. We can’t really size it as 26 or 29 or 32 MW. Sometimes, to a certain extent, you take what you can get. We know we want some thermal investment somewhere between 25-50. Freeman: Out of how many total? Balachandran: About 200 MW total. Morton: How do we know some of our partners also want that? It means that in effect, the chance for partnerships (inaudible) production basically. Balachandran: The larger the plant, the cheaper the heat rate. No. 8 is basically a catch-all because from time to time we do get access to some high value opportunities. Beecham: What’s an example of that? Balachandran: Well, I’ll just toss one out. It’s kind out in left field. The Poe Hydroelectric Project, for example. It’s a long shot. For example, Western is considering forming a control area and as part of that they have fights to certain transmission assets that they’ve owned for close to 40 years and there are ways of perfecting those fights to get access to transmission to the Northwest and offer to Western customers at relatively cheap rates. So that, for example, would be something .... Morton: So, again, these are all partnerships where there’s a large economic investment that we would want somehow to be a part of so we can guarantee our supply or transmission, whichever... Balachandran: Yes, I see two pieces. We take responsibility for developing the portfolio. To actually implement the purchase, we’re going to do it with a bunch of other people for most of these alternatives. There may be some of the green alternatives that we do on our own, but even on those, Tom works with other agencies. But sometimes it’s very specific to Palo Alto, like the Palo Alto Green Program is completely developed, you know, for Palo Alto. But most of the high dollar supply items, we don’t have the wherewithal to do them on our own. Kishimoto: Can you explain that gas tolling a just a little more? Balachandran: Let me ask Shiva to explain that. Swaminathan: It is essentially a contract which is not specific to any plant. The contract tries to mimic the characteristics of the plant. It is a contract essentially for physically (inaudible) electricity, but it tries to mimic all the physical characteristics. (Inaudible) buy this contract and tell the supplier to supply your gas or you pay for gas from a supplier who (inaudible). The supplier than gives electricity. In return it gives natural gas (inaudible). You also pay a fixed cost each month, so essemially it is a toll. Morton: An example might be if Calpine had a plant, we would buy the gas and they would process the gas and give us the output. Swaminathan: Correct, except we don’t have a plant specified as part of that. Morton: No, they would do that. They, in fact, become the processor of our natural resource purchase. Freeman: But it doesn’t necessarily have to be that, it can be any place? That’s why it’s not identified, but they’ll supply it. Beecham: What’s the benefit of us taking the risk on the gas? Swaminathan: Either way, we will be taking a risk whether we own the plant or not. Balachandran: Owning a plant and be subject to (inaudible). Beecham: It’s just basically a commodity purchase. We have a right to the commodity. Ulrich: I think the attempt here to having 11, it can show a broad cross section Of long- term ways of reaching our needs. I think over time, and with all the risks, regulations and costs changing, that we’re going to move around between various resources to get the best combination of renewables, cost, and reliability. We need all these options. Balachandran: Through the objectives and guidelines, you’ve actually set the broad parameters of what the portfolio would look like in terms of what resources we’re going to go after, how much green, how much thermal - you’ve already done that. So when we come to you, it’s going to be built on a series of more detailed analysis. Here are a couple of actions you have taken already. One is the 25 MW block of power for five years was already implemented. You’ve approved it, we bought the power actually much cheaper than what the market is today, so it’s in the money, we like to say. Morton: This is peak load supplement basically, right? I assume it’s during the peak period of usage. Balachandran: I believe this is all through the year. Sorry, I take that back, Q4 and Q1. Ulrich: You can see the purchase on the short-term portfolio development on page 14. Balachandran: It’s actually not the high usage but the high deficit level. Beecham: Well, we have a high deficit because of high usage... Balaehandran: No, because there’s lack of hydro. The high usage comes in summer but hydro essentially dries up. Summer is when the springs run off, everything is (inaudible) and then you have very low flows in Q4 and Q1. Coming back to this here, the two actions you have taken, you approved our renewable portfolio standard. I talked about the NCPA RFP. This is what our resource balance would look like going out about 30 years. See at the bottom, there’s a (inaudible) hydro project, renewables in two phases - you know, adds up to about 20%. Here’s the Western base resource which is actually - you know, we can extend it. We don’t know what’s going to happen after 2024. 2024 is the contract we have now. Just (inaudible) a straight line. The 25 MW purchase on the left-hand side is what we just talked about, the Q1, Q4 purchase. And then you have the 25 MW thermal baseload plan. So, this just your graphical representation of how our portfolio could look like on an annual basis. Ulrich: Can I go back for just a second? I think I’ll spend a couple of minutes so that you’re real clear on it. Unless you’re dealing with this everyday, it’s a little hard to see it, so feel free to ask some questions. Freeman: Resource deficit- does this graph, I mean, is this building on top of each other? Balachandran: Yes. Freeman: So that’s saying that in the year 2009, we’re not going to have as big a resource deficit as we do in 2006? Balachandran: Well, yes, this is the deficit in 2005, it comes down here. This is the other piece. Freeman: Oh, I see. 10 Balachandran: This is long term. This is going be saying remain exposed to market prices. Freeman: So, when those special things come along that we can buy cheap, we do? Balaehandran: Yes, and also as part of the guidelines that you approved said, don’t hedge for more than 75% five years out, not more than 90% two years out. Hence one of our recommendations here is to develop the less than two year hydro hedging plan because within two years is when you have the (inaudible) hydro (inaudible). So in actual fact, you can actually come to that year, 2009, based on what the portfolio looks like based on what the reserves are, rates are, hydro conditions, we may actually fill this up. This is working out real long term (inaudible) basic structure. Ulrich: Girish, could you walk through the short-term. It gives, I think, a better understanding more gaphically of the resources we currently have and how it changes in 2004 and the reasons for the Coral purchase. Let me just talk about the Blocks 1, 2, and 3 because we’re going to come back to that later and ask for your approval on that. I think it helps to see how that all fits in. Balaehandran: Okay. So, this top (inaudible) line is our load. You have the renewable resource down here, you have Calaveras here, and this is Western in an average year. As you can see, the amount of energy we get from Western in January through February and March is not very much. And as you have the spring melt, the amount of energy you get from Western increases and towards the end of summer, it drops again. So, if you look at this, this was a huge deficit we had in Q1 and Q4. So, we came to you and asked you - I mean, it just seemed real easy to make this decision to be able to fill it. And then, we still had a rather large deficit over here. And that’s part of our recommendation today. Let’s fill in Block 1, 2 and 3 to fill in these deficits. This is the short-term strategy so once you get (inaudible), for example, the amount of fill-in you have to make (inaudible) as we ramp up on the renewable purchases, this will also (interrupted)... Freeman: Wait, once we get the thermal plant? Balaehandran: Yes, the 25-50 MW thermal plant. Ulrich: In the long term, the (inaudible). That doesn’t mean it’s built here in town but that means that you have to have on a long-term basis that thermal baseload. Morton: That’s just a supply guarantee. You get a 25 MW supply g~aarantee from some thermal plant (inaudible). Ulrich: Instead of continuing to buy these block purchases, we invest long-term in a thermal plant or we do it through this tolling or some other arrangement where we have a tong-term commitment to 25 MW of thermal power. 11 Balachandran: The thermal plant - I’m skipping ahead a little bit - we expect a decision to be made on that. We’ve given a pretty long time horizon between spring- summer, 2004, through 2006, so there’s a two-year horizon depending on what opportunities come to Us, what the decision-making process is then. Freeman: So, the thermal baseload plant is not on the short-term portfolio because we don’t have it yet? Balachandran: That’s right. Freeman: How much would it be? What would the band thickness be on that one, for exampleWell, it would be at least as big as this one because this is 25 MW block so it’s going to be at least as big as this but not larger than twice the size of this. The largest it can get is both these blocks. Kishimoto: What’s that Coral purchase then? Balachandran: The Coral purchase is the 25 MW Q1, Q4 purchase that you approved a while ago. Beecham: And that’s the name of the company? Balachandran: Yes, sorry. Freeman: Oh, it’s not the co!or. Ulrich: I think it’s helpful to point out that Western is (inaudible) normal factor. Balachandran: Right, actually, good point. So this is Western in a normal average hydro year. Beecham: Not a dry year? Balachandran: Exactly, not a dry year or not a wet year. Freeman: Or not a year where it turned back. Balachandran: We don’t think about that. Ulrich: It does not compute. Balachandran: But in a wet year, it could be (inaudible) .... next strategy... In a dry year, there’s a huge variation. (Inaudible) ... the earlier pie charts that we showed you and the deficit varied between 7% and 45. 12 Kishimoto: So, what about (inaudible) the thermal assuming that we will be capital investors in this plant? Balachandran: Yes. Kishimoto: We would co-own it? And not just go out for a tong contract? Balachandran: We’re putting out the thermal plant, putting out the gas tolling option also and we’re going to see what we get from the market. There are some opportunities already. We’ve talked to some folks but we need to make it a formal solicitation process. We hope within the next six weeks or so we at least put out an RFP to, maybe a Phase 1 RFP, to get information. Kishimoto: This is the long-term commitment to thermal alternative (inaudible). So, that’s obviously the congestion pricing? Balachandran: Exactly. Kishimoto: Can you give me an idea of the scale, I mean what are we talking about? Balachandran: On congestion cost? Kishimoto: Yes. Balachandran: Be careful about my answer here. The market design which involves congestion pricing is untested in this market. So, it could go through the roof. It depends on so many different variables. For our study purposes, just for this purpose, we assumed a low case of $1 million a year and a high case of $5 million a year. Translating that into a bill impact, say somewhere in the middle, say a $3-$3-1/2 million impact, translates into a 5% bill increase. Now, the estimates for congestion pricing are as high as $8-$13 million a year. There are estimates which go as high as that. So, we’re(inaudible) and coming back to the point we’re making over here, those thermal alternatives when we present it to you - you know, whatever comes out of the RFP we present it to you, one of the tradeoffs is going to be location of the plant. The closer it is to where we consume it, the less congestion risk we have. But there are other ways of dealing with mitigating congestion risk including having an active regulatory and legislative program to talk to folks who actually design this to ensure that inequitable market structures are not imposed on us. But that’s the point on the third bullet which is looking at location. Freeman: I am going to go back to a question about thermal generation. I know the objective is to leave the door wide open to figure out what’s the best cost but are we juxtaposed here to having this green renewable at the bottom and then this thermal generation which could be something that’s not quite ecologically sound? Are there any constraints on what that thermal should be? Balachandran: Yes, not more than 50 MW. 13 Freeman: I’m not talking about volume. What type? Kishimoto: She’s talking about does Palo Alto want to put a, say no investment on coal? Ulrich: You can do that. You can set restrictions or parameters if that’s what you wanted. Freeman: I’m just asking if there are any at this point. Balachandran: No... Freeman: So it can be any thermal? What are thermal options, gas, coal, oil, nuclear. Well, it can’t be nuclear, right? Beecham: Diablo has 25 MW to sell to us for 15 years. Ulrich: You asked the depth and breadth of what could be thermal and that could be .... Freeman: And that could be thermal. Balachandran: Biomass... Knapp: (Inaudible) it could be constrained as approved by Council. Freeman: Well, thermal is approved by Council. Thermal, I don’t know whether we get to types of thermal. See what I mean? Knapp: When the actual purchase recommendation comes, it has to be approved by City Council. I think that is the mechanism by which these kinds of issues get filtered out. Beecham: I think on a practical basis (inaudible) if you’ve got coal going out of California and because of transmission, it’s probably not very economic. Part of the reason for owning our own thermal also, I think, is to (inaudible) the generation as much as possible to Palo Alto and minimize transmission issues (inaudible) natural gas. It’s just typically called thermal. Ulrich: The question is more of what’s practical for thermal (inaudible) in Palo Alto. I gave you a range of (inaudible). Freeman: Right, and that’s what I asked. Ulrich: Councilman Beecham is correct that we’re not you’re going to have a coal plant here and you’re not going to have a nuclear plant here. They make very efficient gas- fired thermal plants now and so you can specify how efficient they are and build them accordingly. I do have to continue to say with all of the risks that continue to be out here 14 in the regulatory and legislative area, the most risk (inaudible) area would be to have a plant that’s as close to Palo Alto as possible. Balachandran: So, here’s the short-term portfolio. There are four parts to it. One is the 3 blocks of power that we are asking for approval today. Council approval of the enabling agreements - this is going to come to you at a later date. Right now it’s scheduled for the Finance Committee the middle of September. We’re going to come back to you with the enabling agreements. The hedging strategies, I think the internal structure we have in place is going to oversee that but the implementation of it you’re going to look at. Demand response program is also one part of this plan. You’ve seen this chart. It’s the same thing we talked about. I talked about this. This is basically driving our short-term plan. You have hydro risk and we are trying to maintain our reserve levels at a certain target. Now here’s the timeline. Before getting into the timeline, I just want to re-emphasize maybe what we’re asking for so you have (inaudible) in the timeline too. Each part of this LEAP Implementation Plan that you’re being asked to approve is going to come back to you at some point. So, some of the more specific tradeoffs, for example thermal generation, etc., you’re going to see that. We are also committing to two updates to Council per year on where we are on this plan, just updating you as to progress. And, of course, each time there’s an approval required, after we’ve done a lot of the research and going out and getting information, and maybe even evaluating contracts, we’ll bring it to you for approval. So, here’s the timeline, the enabling agreements are going to come to you in November, 2003. The short-term block purchases, there’s a typo there. Council approval is the first step, the Finance Committee, and then scheduled for Council August 4. Execution is November this year through May, 2004. Acquiring renewable resources, Phase 1 ofNCPA RFP, is underway. We will probably come to you, we expect to come to you in January, 2004 with specific renewable projects, then execution in a six months after that. Local generation resources, we’re going to investigate. Transmission investment opportunities, we continue to investigate. RFP for thermal generation is going to go out this fall. We’ll bring you back a recommendation in the spring. This is expectation. Implementation of (inaudible) investment, we’ve given it a 20-month period, 22 months. DSM programs, you’ve already approved one. We continue to implement this very successful Palo Alto green progran~. As needed, we’ll develop a demand response program. And skipping the next one and going to the last, this twice yearly updates to Council (inaudible) implementation progress. Going to the last slide, as we stated, what we’re asking for today is approval of the Implementation Plan, and again, we want to emphasize we bring back each of the different elements to you for approval. But the one piece of that that we’re asking for approval on today is the 3 blocks. Morton: Thank you, Girish. Before we go into discussions, I think we’ll take a 5- minute break. Morton: Colleagues, if we could come back, we will begin the discussions. Vice Mayor Beecham, as the Council’s liaison to the Utilities Advisory Commission, I’m going to turn the floor to you, and if you’d like to make any brief comments or point out any 15 issues in your mind that you want the Finance Committee to focus on, I’ll give you the floor first if you’d like. Beecham: I appreciate that. This has been reviewed by the UAC, you got their minutes (inaudible) are quite because the UAC has seen it a number of times before and has worked in great detail with staff going over many of the options, many of the analyzes, thorough assessments, probabilities and so on. I think this is quite consistent with what the Council has directed in the past, what the Council has accepted from staff recommendations in the past. It’s a very competent implementation of going forward with and addressing the change in the situation with the WAPA contract chanNng at the end of 2004. There are risks in here, but I think based on the analysis staff has done, those risks are managed as well as probably anybody knows how. As time goes forward, we’ll find months or years where we’re short because of hydro or gas prices go up. That’ll happen (inaudible) months or years where we come out advantageous. The analysis here and the recommendations are based so that in the long run (a) we’re not exposed to extreme risk such as happened with PG&E and others, also as happened with PG&E gas customers who are exposed on a month-to-month basis to market gas prices. That is not the City policy, so (a) we are working to limit the extreme exposures and (b) though we are accepting some risk because on a long-term analysis, your long-term costs are lower if you (inaudible) the risk as opposed to basically buying insurance from somebody else for them to (inaudible). So, it’s an assessment of what is the optimum. I think we had reports in the past that have shown us some of the charts the staff has looked at, summary charts of comparing the different risks based on the best case, worst case and costs. I think this is probably as good as we’re going to find in terms of optimizing how we achieve our objectives in a (inaudible). Morton: Thank you. I’ll follow along on that and just make the comment that when we finally get down to the word "laddered" and all this terminology, I begin to recognize a financial concept to hang on to. I mean, basically, what we’re hoping to do is manage our risk and so, in effect, you have a floating average with your cost structure so you’re never at maximum market risk. But, of course on the other hand, then you have commitments which is the downside. So, we have known costs for some portion of our energy and those costs may or may not be favorable. Ideally, we’ll be below market but we can’t guarantee what the market’s going to be. Colleagues, we’ll be asked to make a recommendation to Council, so I would entertain a motion and then we can discuss the motion by asking questions and then coming up to a final decision. Beecham: I (inaudible) staff recommendation. Morton: I have a motion from Vice Mayor Beecham to approve the staff recommendation. Kishimoto: I’m happy to second. I do want to discuss it. Morton: Then we will discuss the motion. I have a second from Council Member Kishimoto. Council Member Kishimoto, would you like to .... 16 Kishimoto: First of all, I do thank the staff and the UAC for working very systematically and (inaudible) over the years because I know what a huge transition that this represents. I guess I just have a couple of notes. One was we started to have little bit of an interesting discussion during the UAC Commissioner interviews which just happened right before this and actually you raised the topic when Walter (inaudible) came to talk to us. You said, "Well, what’s the outlook for nuclear?" And you said, "Well, basically utilities are in a dilemma of, since they have to choose between natural gas and, of course, the prices are skyrocketing and renewables will still take a long time to come up and they have their pros and cons and what’s going to be that core that’s going to kind of fill that gap in between?" I’m definitely not going to recommend that we look at nuclear. I just want to put on the table a question about well, what were the major dilemmas that you had to face or what are the other utilities doing in terms of this kind of long term... Ulrich: Just a brief overview. There’s very few others, actually I don’t know of any other utility quite like us, in size and in resource mix. Frankly, we have a fairly constant load. We don’t forecast growth as other utilities are, such as Santa Clara. So, we don’t have to be looking at more and more greater power plants. What we need is a steady supply, so to speak. And we have this significant benefit from Western in having been able to renew a contract for 20 years. So that’s a known contract, but it has the problem of being hydro and it goes anywhere from a dry to a wet year. So that’s a real challenge. We also own Calaveras which is also a hydro resource. And then we have the commitments we are making to renewables. Those are three that I think we can say that’s what we want to do to the best of our ability. The problem is we can’t rely on what’s going to happen next year in the water area. So we have to have to have these strategies that can layer and change depending on those kinds of conditions. I would suspect there are very few other places that have this, and I think that’s what’s the innovative and the real thoughtful plan here is being able to do that layering and change it depending on what those conditions are. Then having this long-term view, no matter how much we think we’ve got this figured out, we need that laddering so we don’t get stuck with a price that may be improved on in a subsequent year and then at the same time be able to look at a long-term steady supply based on purchasing. Kishimoto: Like, for example, is PG&E looking more seriously at cogeneration and nuclear, other things we’re not looking at? Ulrich: I can’t say what they’re looking for in that I’m not sure PG&E is really looking for resources. They’re (inaudible) and that’s the way the market is supposed to work. What we’re trying to do is be versatile, survive in this market, and be able to provide a reliable resource for our customers and this is why we have this plan. Balachandran: IfI could add one more piece to it. I don’t know of any California utility that’s looking at nuclear, and pretty much all the utilities are out buying stuff, are looking at gas. 17 Kishimoto: The danger is we’re going to be over-dependent (inaudible). Ulrich: Well, I don’t think any of us can see there will be a nuclear power plant being built in the foreseeable future, but I think you should have an option open that if somebody has some nuclear power plant someplace and we can work out the congestion or the transmission cost to bring it here, we ought to at least consider it. That’s an option, but don’t rely on that. I think the idea of having those 11 different ideas and then having the long term, when we get down to something we think is the right mix, we’ll bring it to you and request your approval. Freeman: I used to sell software. I was selling software to Chevron in Santa Barbara where they have the offshore drilling and the oil comes in through these pipes and goes to this plant. I think my recollection is depending on the pressure that is placed on that oil, you create different types of fuels. So, there’s oil, there’s petro, there’s all sorts of things. And then there’s natural gas. Where does natural gas come from7 Ulrich: It’s usually a product of a well that also has oil in it. (Inaudible) same when they extract the natural gas off the top of it Freeman: So they can do that also, I guess, with the pipeline? Ulrich: (Inaudible) natural gas .... Freeman: So, again, when we’re talking about natural gas, we’re talking about a resource that maybe (a) we’re not getting from foreign sources, so U.S. or California... Ulrich: Well, some of it comes from Canada. There’s a pipeline that goes there and the remainder comes from the southwest Permian Basin and a little bit from California. Freeman: How about the relative - well, we’re very oil dependent now and we’ve had to go outside to find more oil and of course it’ s going to run out - what’ s the situation with naturaI gas relative to oil? I don’t know, I really don’t know. Balachandran: In gas, we’re not as dependent and also when you look - it’s funny you ask - Alan Greenspan was just talking about this and raising the issue that we have a serious gas infrastructure problem. One of the things that he’s recommending, along with a number of other people, liquefied natural gas - you actually liquefy the natural gas - you can get that from other parts of the world and bring it to the United States and then convert it back to its gaseous form. So that’s one place where we may expand, the country may expand to get a new source of supply. Freeman: New oil. Balachandran: I’m sorry? Freeman: New oil, it’ll be the same as oil then? 18 Balachandran: Well, no, it’s not the same in the sense of where the oil is versus where the gas is. When you look at oil supplies in the world and you look at the major concentration, gas is more diverse in where it is. So in terms of dependence to one area of the world, we are not as dependent on gas as we are on oil. So, that’s one of the reasons why Greenspan in his testimony said that that risk, of say like right now in the Middle East and OPEC and stuff like that, they can control prices to a certain extent, that we don’t have that kind of concentration of sources of supply for gas. Freeman: So, what about hydrogen as a source? Ulrich: Well, we looked at that as one of our - it is a ... I think for our planning purposes, it’s not one that we would consider as something we’re going to be able to use in the foreseeable future. But all of those things are on the drawing board. Knapp: Hydrogen is a very clean carrier and way to store energy, but there are no natural sources of hydrogen in the ground. So it has to be either made from natural gas which is actually .... Freeman: Is there hydrogen in the air? Knapp: Not very much. Most hydrogen is actually .... Freeman: Water? Knapp: There is water, there is pienty of water. Most people who are designing hydrogen closed loop systems are generating electricity from some other source, renewable or it can be any other source, but then you can split the atom or split the molecule into hydrogen and oxygen and that has a round trip efficiency of, say, 60-75%. Hydrogen is very hard to store and to ship. So it goes right through O -ings, glass. It is very explosive, has an explosive range of 4%, like 95% so it’s... Freeman: I guess what I was just really asking was there any... Knapp: I guess we don’t’ need a treatise on hydrogen. Hydrogen is more of a storage medium than a fuel source. That’s the short. But it’s very clean. It’s a great way to go in the (inaudible). Morton: (Inaudible) ...discussion back to the items on the .... Freeman: Well, that’s why I was bringing it back to - I was wondering out of the 11 items which I think - by the way, this is one of the best presentations I’ve seen, so very, very good presentation, very clear. I understand the 11 points, so my question was just building off of different sources of energy. I’m sure you scoured the planet and earth for types of energy to get to those 11, but if there was just anything else that was coming down the pike that we could fi!! in those deficits. 19 Ulrich: Not in the foreseeable future, but you can see, again, the benefit here is you can add and subtract from this plan depending on what comes along later on. Freeman: Okay. Ulrich: We wouldn’t be looking at buying a thermal plant, for example, that would take care of all our load. We would take a portion... Freeman: You mean a diverse portfolio? Morton: Colleagues, in view of the fact we still have three more items on the agenda. If there are no more questions, I would like to call (inaudible). Freeman: We already voted. Morton: What’s your pleasure. (Ayes) That passes unanimously. 2O