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HomeMy WebLinkAboutAgenda Report - January 31, 2001 B-01 SMElectric Utility Department Personnel: 47 positions Cost: $6,719,695 Source: 2000-01 Budget Document Lodi Electric Utility Revenue & Expenses Source: 2000-01 Budget Document Lodi Electric Utility Purchasing Power in Today's Market Conclusion: City of Lodi Electric Utility Customers Will Not Be Sub ect To Lar e Rate Increases Source: Shirtsleeve Session 1-30-01 Lodi Electric Utility Benefits to the Citizens of Lodi Lodi Pays Less For Power Residential & Business (15-25% Less) General Fund Transfer $4,000,000 + Greater Reliability Of Higher Level of Service Service For Police, Fire & Parks & Recreation Public Benefits Program Assembly Bill 1890 Assembly Bi111890 passed by the State Legislature directed electric utilities to set aside 2.85% of their revenue for the following kinds of programs: Research, Development & Demonstration 5% Renewable Energy Resources 10/n ■ Today - 2,000 Public Power Organizations in the USA - Public Power generates 25% of power History of NCPA ■ 1948 - Lodi receives PG&E notice of 36% rate increase — Affects all customers — Lodi wholesale rate going higher than PG&E Industrial Rates ■ Early 1950's — Same problem affecting other publics — Coordinated rate intervention needed History of NCPA • Northern California Municipal Electric Association Formed circa 1950 — Forum for solving similar problems & training • NCMEA was an informal organization - City Managers - Electric Utility Superintendents ■ Publics concerned about continued reliance only on IOUs ■ Western refused to help transmit power or sell additional power Citing recent contract with PG&E Lack of legal standing of NCMEA Legitimacy at Last ■ 1968 - NCPA formed under California Joint Powers Act ■ NCMEA members could now collectively enter into contracts ■ 1968 PG&E promise to wheel Pool Members ■ Alameda ■ Biggs ■ Gridley ■ Healdsburg ■ Lodi ■ Lompoc ■ Palo Alto ■ Plumas-Sierra ■ Roseville ■ Ukiah Non -Pool Members ■ Port of Oakland ■ Redding ■ Santa Clara ■ Turlock Irrig Dist ■ Truckee Donner Associate Members ■ ABAG ■ BART ■ Davis ■ Lassen MUD ■ PCWA ■ Santa Barbara Sources Of Generation ■ Hydro ■ Geothermal ■ Combustion Turbine No. 1 ■ Combustion Turbine No. 2 ■ Additional generation through the market Hydro Generation ■ Collierville 244 megawatts (MWs) ■ Used for capacity & peaking ■ Storage reservoirs provide reserve ■ Spicer Reservoir 5 MWs ■ 189,000 acre feet of storage © Spicer ■ Weather considerations affecting O&M ville ColUer oNsTev VA otise Spicer Power House Geothermal Generation ■ Two plants ■ Each plant has two units ■ Project output is currently 160 MW's ■ 68 production wells & 6 injection wells ■ 102 miles of underground well pipe ■ 8 miles of steam gathering pipe ■ 5 miles of injection pipe ■ Effluent Pipeline Project Geothermal Plants No. 1 and No. 2 Geothermal Facilities Drill Rig Turbine Combustion Turbine Generation ■ CT #1 Project ■ Located at Roseville (2), Alameda (2), & Lodi (1) ■ CT #2 Project ■ CT #2 is located in Lodi next to Interstate 5 Combustion Turbine Project No. 1 (Roseville) Combustion Turbine Project No. 2 (Lodi) '1 L J i the Northern California Power Agency was established in 1968 as a non-profit California Joint Action Agency. NCPA membership is open to municipalities, rural electric cooperatives, irrigation districts, and other publicly owned entities interested in the purchase, aggregation, sched- uling, and management of electrical energy. For three successful decades, NCPA has provided scale and skill economies devoted to the purchase, generation, transmission, pooling, and conservatior of electric energy and capacity for its members. With the onset of electric utility restructuring, the Agency has become a primary supplier of power scheduling and interchange management services to power marketers and public agencies. NCPA operates through four Business Units: Administrative Services, Genera tion Services, Legislative and Regulatory, and Power Management. NCPA members and associate members individually elect participation in Agency activities according to their particular needs. i highlights 2 report from management 3 progress review administrative services 4 power management 5 generation services 6 legislative & regulatory 7 highlight: gridley 8-9 highlight: lodi highlight: redding members' total energy usage coincident and non -coincident peak usage members ncpa management financial report 10-11 12-13 14 15 16-19 20 back pocket insert 2 The Generation Services Business Unit responded to member and market needs in an exceptional manner during the last fiscal year. Highlights for the year include: • No Y2K problems as a result of testing and preparation • Reliability Must Run (RMR) status achieved on our Geothermal Plant 2 units and the Alameda & Lodi Com- bustion Turbines ■ RMR contract, providing members a new income to offset budget requirements and allowing units to participate in California's ancillary services market a Consolidation of the Geothermal steam field control room into Plant 1 control room ■ DOE funding of $250,000 obtained for Geothermal's new Reliability Centered Maintenance Program • DOE funding of $180,000 obtained for work in the steam field area of "Enhanced Geothermal Systems Technology" • Renegotiation and reduction of royalty payments based upon the Increasing Percentage Method, which enables NCPA to be more competitive with other geothermal operators ■ Installation of new screens in the Beaver Creek Diversion Spillway. ■ Expansion of the New Spicer Reservoir boat ramp parking lot, more than doubling available space a Record production levels at the CT No.1 & No. 2 Projects. ■ New ISO approved Quad4 revenue meters installed at the interconnected member city substations • MCI communication circuits installed in conjunction with meter installation at both member city substa- tions and generating units. Wow! And we thought last year was "tumultuous and exciting." This year has seen even more changes in the electric industry. With wholesale energy prices higher than ever, NCPA's members found their jointly owned NCPA generation plants enabled them to keep their rates low. And having generation resources provides assurance that retail rates will be competitive long into the future. e rt fro 1 na e e'i'` The ongoing electric industry restructuring has presented NCPA and its members with many challenges. Members are working cooperatively dealing with the changes. NCPA generation plants were operated more than ever. The California ISO is paying NCPA for the reliability value of its plants bringing added value to the members. NCPA staff is focused on results and introduced many cost saving and efficiency improving programs. The Agency's staff performed very well and the members are working together successfully dealing with industry changes. We wish to thank everyone who contributed to NCPA's successful year. inally, NCPA members are beginning to reap benefits few would have imagined when industry restructuring was first contemplated several years ago. During this fiscal year, Administrative Services staff began billing and receiving revenues from the California ISO for NCPA services. It didn't happen without a large cooperative effort by management ana the entire membership. With Power Management staff finalizing contract commitments, the Administrative Services staff was working hard to understand the new playing field under California Independent System 4 Operator rules and procedures. At the same time, the new business environment needed new software to provide proper scheduling of gener- ating resources, communication of the schedules back to the ISO, anc the transmittal back to the ISO of "real time" operating data from meters at NCPA generation plants. Just when we thought we had everything ready to go, the rules changed with the ISO implementation of "Auto- mated Dispatch" instructions and "10 minute settlements." All required appropriate software, staff, procedures, training, and quality control. New industry hurdles? Of course, but not formi- dable obstacles to success when we work together. Throughout our transition, all efforts in every area have emphasized accountability and managing the risks inherent in the new marketplace. NCPA has established clear authorities and limits for implement- ing all energy transactions. Our newly established Internal Risk Oversight Committee provides immediate attention to resolv- ing potential business transaction problems, e.g. modifications to credit or authority limits as energy prices fluctuate widely (as they did soaring to new highs this summer). Building on the success of our 1998-1999 debt restructuring program, NCPA continued its efforts to further reduce members' debt service net billings. Our new interest rate exchange agreement should provide in excess of $1 million in annual debt payment savings to the Hydroelectric project participants. We also accomplished a forward purchase agreement on the Geothermal project which assures that participants receive the highest possible interest earnings on their debt payments temporarily held by our bond trustee prior to paying bond holders. It is a rare and memorable year when all NCPA business units can share significant cost reduc- tions and revenue enhancements all within the same time frame. Indeed, NCPA members find themselves well positioned to move forward with renewed confidence in our changing and increasingly competitive environment. t is the third year of California's electric industry restructuring, which unofficially commenced on March 31, 1998. The new marketplace continues to challenge all participants with its transactional com- plexity, price volatility, and political and economic uncertainty. Few market participants can predict the future course of California's deregulation; however, most expect a continued atmosphere of wide price swings, retail customer dissatisfac tion, and attempts at political solutions to regain price stabil- ity, predictability, and system reliability. Public power agen- `ka; cies, which continue to provide fully integrated electric servii From left to right: Al Parsons -Coordinated System Operations; to their customers, are uniquely placed to assure customers Kevin McMahan -Resource Scheduler/Marketer; Les Pereira- stable, predictable power supply at affordable rates. NCPA Transmission Planning & Design. and its members pursue strategies designed to assure reliab energy levels to meet member loads and, at the same time, provide real time flexibility to sell resource sur- pluses in this volatile environment. The Power Management Business Unit works closely with the Administrative, Legislative and Regulatory, ar Generation Services Business Units to attain business and operational objectives that maintain high values for existing generation while simultaneously meeting member loads at target cost levels. Capturing value from the new marketplace involves personnel from all business units and member staffs working cooperatively to: • Schedule and dispatch power • Implement member defined risk profiles ■ Analyze and assess market information a Enhance member communications ■ Evaluate and implement new power supplies Highlights of Power Management Business Unit activities over the last year include: • Promoting Fred Young to Supervisor of Real Time Operations ■ Designating Al Parsons as Manager of Coordinated System Operations a Placing the day ahead scheduling function under the direction of Tom Lee, NCPA's Portfolio Manager NCPA's Les Pereira also participated in WSCC's generator evaluation and testing program and achieved WSCC compliance for all NCPA generation units. Our focus for the coming year includes reviewing Tong -term resource needs to assure generation sufficient and rate stability. and the ongoing development and implementation of business processes to meet memb needs, all driven by the constantly changing marketplace. he high availability of all units provided much needed system support for our members and the state during the spring and summer periods. All units were on-line during the many Stage 2 alerts that occurred. The STIG unit at Lodi experienced the highest hours of operation in the history of the plant, as did all of our simple cycle Combustion Turbine project #1 units. Generation Services' employees performed at a high level of professionalism to assure our units' availability during the most critical times of potential power shortages in the state. The year also marked the change of leadership at our Geothermal project with the retirement of Larry Jones, Plant Manager. Murray Grande replaced Larry and has continued and enhanced the team effort that was begun the previous fiscal year. The geothermal team developed new operating strategies for the steam field, which resulted in higher unit generation output during peak load conditions. The Hydro project produced 521,456 MW hours, which was consistent with our projections for the year. NCPA staff com- pleted the challenging installation of the new screens at Beaver Creek. This new design provides substantial increase in water diverted to McKay's reservoir, resulting in additional generation at the Collierville plant for our members and the state grid. The FERC five-year independent consultant safety inspection of all facilities was completed with no significant findings. The Combustion Turbine project #1 high level of operation necessitated increased staffing and maintenance. Personnel responded to the increased operation in an exceptional mariner. After years of very little operation, this year's operation demon- strates the value of this investment. The Combustion Turbine #2 project (STIG) plant has been in operation 24 -hours per day, seven days a week during June and into the summer months. The professionalism of the plant staff has kept the STIG running at record production. The Generation Services Business Unit has had an exceptional year. Innovation, creativity, and teamwork are a way of life at all of the NCPA Generating Sites. The many accomplishments were made with the budget finishing the year with a deviation of less than 1/2 percent from a total budget of $136,604,000. 6 .n z...:�' -: -:..F• 4 f nCPA's Legislative and Regulatory Committee focused this year on several major Agency issues. Strong commitment and a sense of teamwork throughout the year brought several important successes, including: ▪ The largest contingent yet of NCPA members, officials and staff for the Washington, DC legislativ trip, where nearly all NCPA Congressional members co-sponsored our legislative efforts concernin the Trinity River and private -use restrictions. n NCPA's aggressive advocacy helped convince the California State Legislature to kill PG&E's proposal to spin-off its hydroelectric system. a The Department of Energy and Western Area Power Administration began executing 20 -year Central Valley Project power supply allocation contracts (to begin in 2004). 2 An expanded monthly "Leg/Rey Newsletter" communicated vital issues and provided an improvE medium for others to report important items to NCPA members. NCPA continued working with state and national coalition partners to influence matters affecting our members. General Manager George Fraser testified before the U.S. Senate on behalf of The Consumers fc Fair Competition. Business Unit Manager Roger Fontes testified before the State Senate, opposing PG&E' hydro divestiture proposal, with others including DRIP (Defending Ratepayers Interests against PG&E). NCPA conducted very successful Congressional and State Legislative Staff Tours at NCPA's Hydroelectric and Geothermal projects. The response was so positive that we have been asked to consider providing tour for elected officials and senior administration appointees. NCPA sponsored legislation (AB 1657) would establish a 120 -day statute of limitations on lawsuits to set aside or void approved electric service rate decisions made by NCPA member councils or rate setting bodies. Late opposition from the State Department of General Services, however, means considerable work remains before we can hope to receive the Governor's approval. Legislative and Regulatory Business Unit staff functions changed significantly this year. Duties for the Legisla- tive Committee expanded to include Regulatory Programs. The new structure better positions NCPA to advoc. on behalf of its members and have significant influence on issues affecting public power. n CPA's Legislative and Regulatory Committee focused this year on several major Agency issues. Strong commitment and a sense of teamwork throughout the year brought several important successes, including: a The largest contingent yet of NCPA members, officials and staff for the Washington, DC legislativ trip, where nearly all NCPA Congressional members co-sponsored our legislative efforts concernir the Trinity River and private -use restrictions. 9 NCPA's aggressive advocacy helped convince the California State Legislature to kill PG&E's proposal to spin-off its hydroelectric system. a The Department of Energy and Western Area Power Administration began executing 20 -year Central Valley Project power supply allocation contracts (to begin in 2004). a An expanded monthly "Leg/Reg Newsletter" communicated vital issues and provided an improv( medium for others to report important items to NCPA members. NCPA continued working with state and national coalition partners to influence matters affecting our members. General Manager George Fraser testified before the U.S. Senate on behalf of The Consumers fc Fair Competition. Business Unit Manager Roger Fontes testified before the State Senate, opposing PG&E hydro divestiture proposal, with others including DRIP (Defending Ratepayers Interests against PG&E). NCPA conducted very successful Congressional and State Legislative Staff Tours at NCPA's Hydroelectric and Geothermal projects. The response was so positive that we have been asked to consider providing tour for elected officials and senior administration appointees. NCPA sponsored legislation (AB 1657) would establish a 120 -day statute of limitations on lawsuits to set aside or void approved electric service rate decisions macle by NCPA member councils or rate setting bodies. Late opposition from the State Department of General Services, however, means considerable work remains before we can hope to receive the Governor's approval. Legislative and Regulatory Business Unit staff functions changed significantly this year. Duties for the Legisla- tive Committee expanded to include Regulatory Programs. The new structure better positions NCPA to advoc on behalf of its members and have significant influence on issues affecting public power. . r lk 8 Situated between the Sacramento and Feather Rivers in Butte County (55 miles north of Sacramento on Highway 99), the Gridley area was settled in the 1950s. The area soon developed into a rich agricultural region. The town was subdivided in the 1970s when a railroad was constructed through the area. electric service The privately owned Gridley Light and Power Company provided electric power to the business district as early as 1897. Power was generated at night by a steam plant with a dynamo capable of serving 350 lights. Following incorporation in 1906, the City constructed a street light system and contracted with the local power company for electricity. In 1910, following the accidental electrocution of the owner, City residents voted to acquire the system from his estate. At that time the service area of this utility extended well beyond the City's boundaries. In 1915 service territory outside the City was sold to PG&E. The City then contracted with PG&E for power delivery. In 1963, the City was an early power purchaser from the Bureau of Reclamation long before such power was competi- tive. Electrical power was wheeled by PG&E. In 1968, Gridley became a charter member of NCPA. In 1995, the Cities of Biggs and Gridley (which are three miles apart) agreed to share an electric staff that operates the electric systems of both communities. While a member of NCPA, Gridley has been able to provide quality service at rates less than PG&E while making contributions to the General Fund that enhance the quality of life for residents. the community Agriculture has continued to be a dominant force in the economy of the region, which is known for the early development of a regional gravity irrigation system. Rice, peaches, walnuts, prunes and kiwi are grown and pro- cessed locally. The City has focused significant attention on renovation of the historic downtown, senior housing, economic development and youth services. The historic Hazel Hotel was recently renovated into a senior housing/ commercial project. Hundreds of volunteers participated in a project to build and operate the 12,500 square Guardian community center. Sportsmen are attracted to this area due to the abundant popula- tions of duck, geese, and pheasant. The annual salmon runs attract anglers from a wide area. Gridley is also home to the Gray Lodge Wildlife Sanctuary. DISCOVER GRIDLEY ethanol project During the last 5 to 6 years, the City of Gridley has been involved in a unique effort to generate a new industry in the Sacramento Valley. During the 1990s, the rice industry faced legislative mandates to radically alter historic farming prac- tices. Traditionally rice fields were burned after the fall harves The smoke that lingered over the North Sacramento Valley caused a public outcry. The California Legislature responded by phasing out open field burning. Gridley secured grant funding from the Department of Energy to develop methods c converting agricultural waste products into ethanol. Project partners include U.C. Davis, the National Renewable Energy Laboratory, the California Energy Commission, the Butte County Air Quality Management District, and representatives of the rice industry. A Rice Straw Co-op has been formed that now harvests rice straw and serves as a supplier. BC Interna- tional, a firm located in Dedham, MA is working with the City of Gridley to build a Butte County ethanol facility that will produce 25,000,000 gallons of ethanol annually for use as motor vehicle fuel. Ethanol can be used to replace MTBE that has polluted ground water supplies throughout the State. I 10 how todi became the valley's shining star Nestled in California's San Joaquin Valley, Lodi is home to nearly 60,000 people. Originally known as Mokelumne Station, Lodi was established in 1869. Lodi's 12.2 square miles are encircled by acres and acres of healthy vineyards, and is considered one of the premiere places to call home. The tree -lined streets, lush city parks, low crime rate, easygoing lifestyle, and serene surroundings are a testimony to this distinction. However, Lodi was not always that way. Some historians claim Lodi was named after a popular racehorse from that bygone era; and in those early days, Lodi was considered the sporting center of the Central Valley! Horse racing along downtown's Sacramento Street and fourteen up-tempo saloons is what set Lodi apart from neighbor- ing towns and cities. Then, towards the turn of the century, there was a dramatic influx of new residents from the Dakotas to Lodi, settling on the rich farmland that encompasses the community. Churches were built at an aston- ishing rate, the saloons essentially dried-up, and a new quality of life began in Lodi. A hundred years ago and today, the quality of life and the robust Lodi economy stem primarily from the prosperous agricultural and viticulture industry. The prime crop is wine grapes, followed by strawberries, - '-.. _ -_.__. __ _..._ _ .�.. • .-.yrs.-I.�, . •- nwn. �. ..�� ..i :Yi orchard fruits and vegetables. But it is :,.•" _L�a <_- .: ,.: - the wine grapes that have given Lodi a rather unique identity: the nation's number one wine grape producing region of five varietals. As a result of the tremendous success of the local wine industry, the new, state-of-the-art Lodi Wine & Visitors Convention Bureau office pictured above opened in the summer of 2000. the city of Jodi electric utility In 1910, the City of Lodi Electric Utility began providing safe and reliable electric service, maintaining five miles of electric distribution lines, with over 500 utility poles consisting of mostly downtown Lodi streetlights. Considered to be a luxury, electricity was afforded by only a handful of the estimated 2,000 citizens. In 2000, the City of Lodi Electric Utility is serving over 23,000 residential, commer- cial and industrial customers, and main- taining some 205 miles of overhead and underground electric distribution lines, and roughly 5,400 utility poles. With four strategically placed substations, and an aggressive maintenance and tree trimming program, the City of Locli Electric Utility now boasts one of the country's best service reliability ratings for electric utility providers of similar size. The department, with Director Alan Vallow at the helm, has 41 full-time employees, the majority of whom are dedicated to the service and maintenance division. This commit- ment to excellent customer service and reliable electric service has not gone unnoticed by the citizens of Lodi. In a recent customer survey, the City of Lodi Electric Utility received an overall "A" grade, based upon service, safety and its competitive price for electricity. The City of Lodi Electric Utility provides other benefits to the community as well. Each year, the utility contributes 12 cents from every dollar received from the sale of electricity to the City of Lodi General Operating Fund. These monies, over $4 million annually, are used for important city services, such as police and fire protection, road maintenance, and parks and recreation activities. In addition, the City of Lodi Electric Utility spends countless hours on community functions and events, through sponsorships, safety and customer program presentations, and employee volunteerism. One of Director Vallow's first contributions to the City of Lodi Electric Utility, was his team's new motto: Large Enough to Meet Your Needs...Small Enough to Care. It is both Vallow's and his team of dedicated employees' intent to continue providing safe, reliable and competitively priced electric service well into this 2151 century. Redding, where "working together to improve our community" is far more than a catchy new City motto. City offi- cials and residents alike are proud of our growing community, and are committed to achieving continued growth without sacrificing our superb quality of life. Our longer range planning efforts emphasize participation and growth through continued improvement insuring support and ongoing cooperation from all segments of our community, including the corporate sector, non-profit organizations, government agencies, volunteer groups, and a broad and diverse base of business and residential interests. The City has always emphasized coordinated efforts to maximize efficiency and maintain high quality standards. These efforts were enhanced this year with completion of the new three-story, 109,000 square -foot Civic Center. Centralizing all City departments under one roof has facilitated closer working relationships among City agencies, making City officials and processes much more accessible to the community. 12 redding electric utility: smart seniice...bright ideas! Serving the City of Redding since 1921, Redding Electric Utility (REU) moves into the new millennium well positioned to achieve our goal of providing our customers with safe, reliable, and competitively priced energy. As we assess our future, we are confident that our programs and strategies have established sound delivery capabilities for both near and longer term needs in all key areas. _4 RFU REDDING ELECTRIC UTILITY (I FY OF =:euoihe customer programs Customers represent REU's primary focus, and we have continued to develop and refine programs that are beneficial to the community. New this year are the "Kool Vantage" High Efficiency Air -Conditioning and ENERGY STAR rebate programs. "Kool Vantage" provides financial incentives of up to $800 for residential custom- ers and up to $1,500 for commercial and industrial customers who purchase high efficiency HVAC systems. ENERGY STAR provides rebates of up to $300 for the purchase of ENERGY STAR rated appliances and windows. service reliability We all take pride in our performance reliability. Although faced with continually increasing demands, REU customers experience fewer outages than surrounding areas thanks to the hard work of REU line employees and the success of the department's planning, resource management efforts, and delivery agreements. Many projects are underway to maintain REU's exceptional historical service record, both in maintenance of distribution wires that deliver the energy and in having sufficient generation resources to serve our customer's energy needs. eliminating long-term debt for deregulation REU continues its aggressive response to State deregulation laws. In 1997 REU instituted a 23 percent interim rate surcharge in order to eliminate $200 million of long- term debt over the next seven years. Through surcharge collection, internal cost reductions, and power sales from its generating facility, REU has reached the halfway point toward its goal. Debt removal is projected as early as 2002, over two years ahead of schedule. community events and activities REU has always been an active participant in community events and activi- ties. For the sixth year in a row, REU served as a regional host for the U.S. Department of Energy National Science Bowl. meeting future development needs The City of Redding looks forward to a future of strong and well managed economic growth and development. REU will be an integral part of that development by assessing and planning for growing resource requirements. Continuing its long standing tradition of providing businesses and residents with the best possible service at the lowest possible price, and by participating as active, involved citizens of this wonderful community, REU finds itself well positioned for the future. Alameda Biggs Gridley Healdsburg Lodi Lompoc 1/1 Palo Alto Plumas-Sierra Port of Oakland Redding Roseville Santa Clara Truckee Donner Turlock Irrigation Ukiah i 1 1 1 1 1 1 300 600 900 1200 1500 1800 2100 2400 2700 Gwh 396.9 7.4 31.0 72.3 431.7 139.5 1,189.6 131.5 58.8 728.6 927.2 2,614.1 128.3 1,519.3 115.8 Coincident Peak 1999 July 12, 1999 4:00 p.m. Total 1,746 MW Alameda Biggs Gridley Healdsburg Lodi Lompoc Palo Alto Plumas- Sierra Port of Oakland Redding Roseville Santa Clara Truckee Donner Turlock Irrigation Ukiah 100 200 300 400 MW 58 2 8 17 122 19 209 20 0 206 234 425 14 382 30 Non -Coincident Peak 1999 1999 Total 1,839 MW 100 200 300 400 MW 68 2 8 17 124 26 212 26 8 211 240 456 29 382 30 alameda v population 73,713 Tom Evans Load Mix: Industrial 8.7% Commercial 51.9% Residential 39.4% Total Energy 1999: 396,922 MWh Peak Load: 68,230 Kw port of oakland . John Aidoo Total Energy 1999: 58,814 MWh Peak Load: 8,400 Kw ukiah e population 14,961 Phillip Ashiku Load Mix: Industrial 0.00/0 Commercial 63.90/0 Residential 36.1% Total Energy 1999: 115,798 MWh Peak Load: 30,450 Kw population 57,935 Keith Land Load Mix: Industrial 22.7% Commercial 39.4% Residential 3 7.8% Total Energy 1999: 431,684 MWh Peak Load: 123,985 Kw pato atto population 61,505 Bern Beecham Load Mix: Industrial 45.7% Commercial 38.2% Residential 16.1% Total Energy 1999: 1,189,568 MWh Peak Load: 212,700 Kw redding population 79,593 Pat Kight Load Mix: Industrial 4.0% Commercial 47.5% Residential 48.4% Total Energy 1999: 728,585 MWh Peak Load: 210,900 Kw turiock irrigation district population 167,000 (estimated service area) Michael Crowell Load Mix: Industrial 48.4°/o Commercial 9.40/0 Residential 42.2% Total Energy 1999: 1,519,296 MWh Peak Load: 382,480 Kw santa clara ► population 102,895 Judy Nadler Load Mix: Industrial 87.6% Commercial 3.5% Residential 8.9% Total Energy 1999: 2,614,106 MWh Peak Load: 455,650 Kw rosevi lle population 74,234 Dan Goodhall (not pictured) Load Mix: Industrial 38.8°!0 Commercial 31.5% Residential 29.7% Total Energy 1999: 927,183 MWh Peak Load: 240,150 Kw plumas-sierra population 15,400 (estimated service area) Robert McDonald Load Mix: Industrial 43.5% Commercial 8.4% Residential 48.1% Total Energy 1999: 131,475 MWh Peak Load: 21,965 Kw gridley v population 5,040 Tom Sanford Load Mix: Industrial 0.0% Commercial 57.2% Residential 42.8% Total Energy 1999: 31,013 MWh Peak Load: 8,550 Kw ELECTR SER BIGGS el[ population 43,284 Mike Siminski Load Mix: Industrial 29.1% Commercial 23.4% Residential 47.5% Total Energy 1999: 139,462 MWh Peak Load: 25,765 Kw biggs 4 population 1,752 Tim Bradford Load Mix: Industrial 27.6% Commercial 18.3% Residential 54.1% Total Energy 1999: 7,445 MWh Peak Load: 2,200 Kw truckee donner pud v population 12,903 Jim Maass Load Mix: Industrial 0.0% Commercial 40.5°/ Residential 59.506 Total Energy 1999: 128,258 MWh Peak Load: 28,550 Kw healdsburg 41 population 10,430 Jason Liles Load Mix: Industrial 4-.1°/° Commercial 60.8% Residential 35.1°/° Total Energy 1999: 72,252 MWh Peak Load: 17,420 Kw 19 20 ncpa executive committee Jason Liles Healdsburg Michael Siminski Lompoc Tom Sanford Gridley Judy Nadler Santa Clara James Maass Truckee plant superintendents Larry Jones Geothermal Project alameda Torn Evans, Commissioner Don Rushton, Alternate Juelle-Ann Boyer, Alternate biggs Tim Bradford, Commissioner grid[ey Tom Sanford, Commissioner Jack Slota, Alternate healdsburg Jason Liles, Commissioner Chet Wystepek, Alternate Bill Duarte, Alternate Mark Gleason, Alternate Lodi Keith Land, Commissioner Alan Vallow, Alternate Jack Stone, Alternate Susan Hitchcock, Alternate Lompoc Mike Siminski, Commissioner Gary Keefe, Alternate Tom Taylor Hydroelectric Project Mike Argentine Combustion Turbine Projects ncpa management George Fraser General Manager Donald Dame Assistant General Manager, Power Management Roger Fontes Assistant General Manager, Legislative & Regulatory Jack Sovern Assistant General Manager, Generation Services pato alto Bern Beecham, Commissioner John Ulrich, Alternate Girish Balachandran, Alternate plumas-sierra Robert McDonald, Commissioner Bob Marshall, Alternate Tony Martinez, Alternate port of oakland John Aidoo, Commissioner redding Pat Kight, Commissioner Jim Feider, Alternate rosevi l[e Dan Goodhall, Commissioner Bryan Gross, Alternate Dave Dockham, Alternate Tom Habashi, Alternate Jerry Roemmelt, Alternate James Whalen Assistant General Manager, Administrative Services Thomas Breckon Information Systems Manager Linda Cox General Services Manager Dale Lain Treasurer -Controller Hari Modi Manager of Federal Affairs W. Kent Palmerton Industry Restructuring Manager Desiree Rioux Executive Assistant to the General Manager, Assistant Commission Secretary santa tiara Judy Nadler, Commissioner Jennifer Sparacino, Alternate Jim Pope, Alternate Aldyth Parle, Alternate John McGuire, Alternate truckee donner pud Jim Maass, Commissioner Peter Holzmeister, Alternate Joseph Aguera, Alternate Ron Hemig, Alternate Robert Jones, Alternate Patricia Sutton, Alternate turlock irrigation district Michael Crowell, Commissioner Chris Kiriakou, Alternate Ken Weisel, Alternate u kia h Phillip Ashiku, Commissioner Darryl Barnes, Alternate kaltey age15 Kaiiey is cutting a cow on. her horse `Spot'. She is currently., leadin g'the rookie ofthe :year in district 2. These age 20 three spirited At sisters have ~'� age 18 always been Shannon active in athletics. They age 16 all attended +Hotton High.: kendyt age 7 Kendyl plays awesome defense for the '`Lincoln youth soccer.; team. age 4 *Marvelous, di ;finished third in the state of Califomiathis.yaar. age $ Y'tvrisdn° Tyler is en.;exilertBMXbike:rac er . who has been riding since :1999. jutia age 13 Julia:belongs,t United States. .Association, an level 6;She floor routine.: Most valuable shortstop+and sta iorthe Visalia Utile League. o �s with our chi rid out relief --pitch Q Mellrbers Geothermalprolect oldroeeetrr�Urolect °�eectNQ12 Comb ostio ihrblhe aie Pr Gtihb�yire Members Ci Ssoc,3te b a combined balance sheets _ northern california power agency and associated power corporations assets, (000's omitted) June 30, 2000 June 30,1999 current assets Cash and cash equivalents S 7,163 $ 19,814 Investments 15,010 16,971 Accounts receivable Participants 1,016 (213) Other 13,644 1,109 Interest receivable 2,875 270 Inventory and supplies—at average cost 4,668 4,705 Prepaid expenses 481 521 TOTAL CURRENT ASSETS 44,857 43,177 restricted assets Cash and cash equivalents 57,918 56,896 Investments 242,444 228,284 Interest receivable 2,003 575 TOTAL RESTRICTED ASSETS 302,365 285,755 electric plant Electric plant in service Less: accumulated depreciation other assets and deferred charges 1,016,313 1,015,343 (429,9881 (395,902) 586,325 619,441 Unamortized excess cost on refunding of debt, net 193,808 216,159 Deferred expenses to be recovered in future years 89,847 121,476 Unamortized debt issuance expenses 19,001 20,096 302,656 357,731 S 1,236,203 S 1,306,104 1 combined balance thefts, continued northern california power agency and associated power corporations 2 liabilities and capitalization (000's omitted) June 30, 2000 June 30,1999 liabilities payable from current assets Accounts payable S 16,258 $ 14,909 Member advances 792 830 Operating reserves 814 778 TOTAL LIABILITIES PAYABLE FROM CURRENT ASSETS 17,864 16,517 liabilities payable from restricted assets General operating reserves 21,648 36,364 Current portion of long-term debt 60,375 57,595 Accrued interest payable 27,491 29,173 Deferred compensation 9,491 7,912 Member advances 710 264 Accounts payable 206 205 TOTAL LIABILITIES PAYABLE FROM RESTRICTED ASSETS 119,921 131,513 capitalization Long-term debt, net Accumulated net revenues other liabilities and deferred credits Deferred revenues 1,042, 893 23,818 1,066,711 31,707 S 1,236,203 1,104, 589 20,530 1,125,119 32,955 S 1,306,104 combined sfatemPnts of revenues, expenses and changes in accumulated net revenues northern catifornia power agency and associated power corporations (000's omitted) June 30, 2000 June 30,1999 sales for resale Participants S 169,493 $ 159,399 Other 35,851 16,668 205,344 176,067 operating expenses Depreciation 34,140 34,036 Purchased power 42,661 31,054 Operations 23,646 22,174 Administrative and general 9,328 8,101 Maintenance Expenses 8,735 7,986 118,510 103,351 net operating revenues 86,834 72,716 other revenues (expenses) Agency members' dues, assessments and contributions 24,630 77,615 Interest expense (59,0691 (62,131) Interest income 15,930 9,257 Amortization of deferred charges (24,069) (45,332) Property tax refund 17,500 Other 235 4,255 (42,3431 1,164 future recoverable costs (31,616) (54,014) net revenues before refunds 12,875 19,866 refunds to participants (9,587) (25,681) net revenues (expenses) 3,288 (5,815) accumulated net revenues Beginning of year 20,530 26,345 End of year S 23,818 $ 20,530 combined statements of cash flow northern catifornia power agency and associated power corporations (000's omitted) June 30, 2000 June 30,1999 cash flows from operating activities Net operating revenues S 86,834 S 72,716 Adjustments to reconcile net operating revenues to cash provided by operating activities: Depreciation 34,140 34,036 120,974 106,752 Cash flows impacted by changes in Accounts receivable (13,764) 5,018 Inventory and prepaids 78 (149) Operating reserves (26,908) 17,765 Deferred revenues (1,248) (1,266) Accounts payable 1,348 6,346 Deferred compensation 1,579 1,496 NET CASH PROVIDED BY OPERATING ACTIVITIES 82,059 135,962 cash flows from investing activities Proceeds from maturities and sales of investments 161,280 318,038 Interest received on cash and investments 8,900 8,310 Purchase of investments (170,138) (302,026) NET CASH (USED IN) PROVIDED BY INVESTING ACTIVITIES 42 24,322 cash flows from capital and related financing activities Proceeds from bond issues 548,752 Expenditures for debt issuance costs (11,547) Acquisition and construction of electric plant (965) (955) Principal repayment on long-term debt (57,595) (57,115) Interest paid on Tong -term debt (60,877) (69,702) Payments to refund/defease debt (636,024) NET CASH USED IN CAPITAL AND RELATED FINANCING ACTIVITIES (119,437) (226,591) d combines! statements of cash flow, continued northern catifornia power agency and associated power corporations (000's omitted) June 30, 2000 June 30,1999 cash flows from non -capital financing activities Assessments and advances from members 25,037 (410) Other proceeds 670 4,255 NET CASH PROVIDED BY (USED IN) NON -CAPITAL FINANCING ACTIVITIES 25,707 3,845 DECREASE IN CASH AND CASH EQUIVALENTS (11,629) (62,462) Cash and cash equivalents, beginning of year 76,710 139,172 CASH AND CASH EQUIVALENTS, END OF YEAR S 65,081 S 76,710 c notes to combined financial statements northern california power agency and associated power corporations June 30, 2000 and 1999 note a—organization the agency Northern California Power Agency (Agency) was formed in 1968 as a joint powers agency of the State of Califor- nia. The membership consists of eleven cities with publicly owned electric utility distribution systems, one irrigation district, one public utility district, one port authority, and seven other associate member entities. The Agency is generally empowered to purchase, generate, transmit, distribute, and sell electrical energy. Members participate in the projects of the Agency on an elective basis. Various legal and tax considerations caused the Agency to provide that separate not-for-profit corporations should be delegated by the Agency to own the geothermal electrical generating projects undertaken by the Agency. These Associated Power Corporations, Northern California Municipal Power Corporations No. Two and No. Three have delegated to the Agency the authority to construct, operate and manage their respective geothermal plants and related assets. The Agency, in return for financing the costs of acquisition and construction, acquires all the capacity and energy generated by the plants. The Agency is governed by a Com pission comprised of one representative for each member. The Commission is responsible for the general management of the affairs, property, and business of the Agency. Under the direction of the General Manager, the staff of the Agency is responsible for providing various administrative, operating and planning services for the Agency and Associated Power Corporations. note b—significant accenting policies basis of accounting and principles of combination The records of the Agency and its Associated Power Corporations are maintained substantially in accordance with the Federal Energy Regulatory Commission Uniform System of Accounts. Generally accepted accounting prin- ciples are applied by the Agency in conformance with pronouncements of the Government Accounting Standards Board (GASB) and, where not in conflict with GASB pronouncements, the Financial Accounting Standards Board (FASB) pronouncements issued on or before November 30, 1989. The combined financial statements encompass the Agency and Associated Power Corporations on an accrual accounting basis. All material intercompany balances and transactions have been eliminated from the combined amounts reported. Electric Plant: Electric plant in service is recorded at cost. Depreciation expense is computed using the straight-line method over the estimated useful lives of the related assets. The provision for depreciation was approximately 3% of the average electric plant in service for the Agency during 2000 and 1999. Unamortized Excess Cost on Refunding of Debt: Gains and losses on refunding of debt are deferred as unamor- tized excess cost on refunding of debt and are amortized using the interest method over the shorter of the term of the debt refunded or the term of the refunding debt obligation. deferred expenses to be recovered in future years In accordance with the Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation", the Agency has deferred the net of certain items of expense and revenue that otherwise would have been charged to operations because it is probable that such items will be recovered in the future years' operations. The Agency expects to recover these items in rates over the term of the related debt obligations it has issued. On an ongoing basis, the Agency reviews its operations to determine the continued applicability of these deferrals under SFAS No. 71. The items of expense that have been deferred are those originally paid from bond proceeds, including deprecia- tion, amortization of excess cost on refunding of debt, debt issuance expense, and interest paid from bond proceeds. Revenues used to acquire electric plant have also been deferred to future years. As of June 30, 2000 and 1999, the Agency had accumulated deferred expenses (net of revenues) to be recovered in future years of approxi- mately $58,140,000 and 588,522,000, respectively. 6 unamortized debt issue expenses Unamortized debt issuance expenses are amortized to income over the term of the related issue. Amortization is computed using the interest method. long-term debt Long-term debt is stated net of unamortized discount and premium. Discount and premium are amortized over the term of the related obligation using the interest method. Amortization of debt discount and premium is included in total interest cost for the period. operating reserves The Agency has established various funded operating reserves for anticipated periodic operating costs and related liabilities including, but not limited to, scheduled maintenance other than ordinary repairs and replacements. Certain amounts funded each year are charged to operating expense because the rates established by the Agency for power sales to its members include these costs on a prospective basis. Increases in specific operating reserves are authorized by the Agency's Commission. A non -project specific, individual participant controlled, General Operating Reserve is also maintained for participating Agency members. rates Power sales to participants for their resale include both power generated by operating plants and power pur- chased from outside sources. Rates for power sales are designed to recover costs that include budgeted annual operating costs and debt service. Additional amounts for operating reserves or rate stabilization may be included in rates under the terms ofrbond indentures. During fiscal years 2000 and 1999, no amounts were specifically collected for rate stabilizatCn. The Agency's rates for electric service are not subject to the regulatory jurisdiction of the California Public Utilities Commission (CPUC) or the Federal Energy Regulatory Commission (FERC). Rather, the Agency's rates are estab- lished annually in connection with its budget, which is approved by its governing Commission. fair values of financial instruments The following methods and assumptions were used by the Agency in estimating its fair value disclosures for financial instruments: Cash and Cash Equivalents: The carrying amount reported in the balance sheet for cash and cash equiva- lents approximates its fair value, see Note C. Investments: The fair values for investments are based on quoted market prices, see Note C. Long-term Debt: The fair value of the Agency's long-term debt (including current maturities) is estimated to be approximately 51,110,857,000. This estimate was developed using discounted cash flow analyses, based on current borrowing rates for tax-exempt securities with similar ratings and maturities. accumulated net revenues The Agency and the Associated Power Corporations are intended to operate on a not-for-profit basis. Therefore, any balance in Accumulated Net Revenues primarily represents differences between total revenues collected using rates based on estimated operating expenses and debt service, and the total actual expenses incurred. In subsequent periods of operation, excess collections may be refunded to participants or appropriated for other uses at the discretion of the Agency's Commission. In the event the Agency incurs an Accumulated Net Expense balance, the balance would be subject to recovery in participant rates under the terms of the related take -or -pay Member Agreements (see Note D). retirement plans The Agency has established a noncontributory, simplified employee retirement plan (SEP) utilizing Individual Retirement Accounts for substantially all employees. Retirement age under the plan is 59 'h. The Agency also sponsors a deferred compensation plan in accordance with Internal Revenue Code Section 457. The plan is adminis- tered and managed by the International City Management Association. Participation in the plan is voluntary and open to all employees. Until withdrawn by individual participants, assets of the plan are held in a retirement trust account that belongs to the Agency. Annually, the Agency determines its retirement contribution as a percent of covered compensation. The cost is accrued and funded concurrently with the related payroll expense. The Agency's cost for the years ended June 30, 2000 and 1999 was approximately 51,925,000 and 51,736,000, respectively. The Agency is a member of the State of California PERS medical insurance plan. Under this plan medical insur- ance is provided to all active employees and their families as well as all retirees (and their spouses) with at least 10 years of service. The Agency previously established a separate reserve account to fund retiree medical insur- ance premiums under this plan. Based on the current cost trends of health plans, in which the employees and retirees are participating, the actuarially determined aggregate expected post-retirement benefit obligation is fully funded. Current significant actuarial assumptions used in making this determination were: a) annual discount rate of 7.75%; b) annual probability of retirement based on actual history; and, c) mortality rates based on the 1983 Group Annuity Mortality Table. As of June 30, 2000 and 1999, the carrying value of the retirement medical insur- ance reserve approximated $6,302,000 and $5,925,000, respectively. At fiscal year end June 30, 2000, the Agency had 160 eligible employees and eleven retirees drawing benefits under this program. note c—cash and investments cash Operating cash is maintained in interest-bearing depository accounts that are collateralized, in accordance with state law. The Agency commingles operating cash for investment purposes only. Separate detailed accounting records are maintained for each account's related investments. cash equivalents Cash equivalents are short-term investments purchased with original maturities of 90 days or less. Cash equiva- lents consist primarily of guaranteed investment contracts, U.S. Treasury and Agency Securities. restricted cash and investments Long-term debt and other agreements require the maintenance of certain restricted asset accounts. Cash and investments held in these accounts are restricted for specific uses, including project construction, operations, debt service, and special reserve requirements. Investments are stated at cost adjusted for amortization of premiums and accretion of discounts, which approximates market. investments The Agency is authorized to invest in obligations of the U.S. Government and its agencies and instrumentalities, in certificates of deposit, commercial paper, bankers acceptances, repurchase and reverse repurchase agreements, passbook savings account demand deposits, municipal bonds, and the State Treasurer's Local Agency Investment Fund (LAIF) pool. The Agency's investments as of June 30, 2000 are categorized, as follows, by increasing levels of risk, which indicate the level of risk assumed by the Agency at year-end: Category 1: Insured or registered investments for which securities are held by the Agency's Agent in the Agency's name. Category 2: Uninsured and unregistered investments for which the securities are held by the broker's or dealer's trust department or agent in the Agency's name. Category 3: Uninsured and unregistered investments for which the securities are held by the broker or dealer, or by its trust department or agent but not in the Agency's name. The Agency had no investments in this category. (000's omitted) Description Category 1 Category 2 Carrying Value Market Value Guaranteed Investment Contracts $ — $ 95,447 $ 95,447 $ 95,447 U.S. Agencies 66,453 11,416 77,869 76,357 State & Local Obligations 32,458 — 32,458 32,458 LAIF — 22,900 22,900 22,900 U.S. Treasury 9,425 8,554 17,979 18,473 Deferred Compensation Plan 9,491 9,491 9,491 Municipal Bonds 1,300 — 1,300 1,300 Time Deposits 10 — 10 10 TOTAL INVESTMENTS $ 109,646 $ 147,808 $ 257,454 $ 256,436 8 note d—project financing and construction financing programs The Agency's project construction and development programs have been individually financed by project revenue bonds collateralized by the Agency's assignment of all payments, revenues, and proceeds associated with its interest in each project. Each project participant has agreed to pay its proportionate share of debt service and other costs of the related project, notwithstanding the suspension, interruption, interference, reduction or curtail- ment of output from the project for any reason (that is, the take or pay member agreements). Certain of the revenue bonds are additionally supported by municipal bond insurance credit enhancements. (000's omitted) Long-term debt at June 30: 2000 Geothermal Project 1987 Refunding Series A Term, 5.00% due 2009 (effective rate 6.35%) 1993 Refunding Series A-1, A-2 and A-3 and Series B (relating to a like amount of Special Revenue Bonds) Serial, 5.00-5.85% due 2000-2010 (effective rate 5.00 to 5.85%1 1996 Refunding Series A Serial, 4.125-5.0% due 2002-2005 (effective rate 4.125 to 4.30%) 1996 Refunding Series B Serial, 4.75-5.50% due 2000-2002; (effective rate 4.28 to 4.45%) 1999 $ 25,000 $ 25,000 151,080 121,590 80,630 378,300 154,827 121,590 113,190 414,607 Hydroelectric Project 1992 Refunding Series A Serial, 5.60-10.00% due 2000-2009; 55,845 59,930 Term, 5.50-6.30% due 2012-2023 131,900 131,900 (effective rate 5.65 to 10.00%) 1993 Refunding Series A Serial, 4.70-5.40% due 2000-2009; 2,210 2,380 Term, 5.50% due 2013-2024 50,945 50,945 (effective rate 4.70 to 5.78%) 1998 Refunding Series A Serial, 4.50-5.25% due 2000-2018; 71,490 78,180 Term, 5.00-5.20% due 2023-2032 223,310 223,310 (effective rate 4.00 to 5.472%) 535,700 546,645 Combustion Turbine Project 1998 Refunding Series A Serial, 4.00-5.00% due 2000-2010; (effective rate 2.85 to 4.35%) 38,855 43,165 Transmission Project 1998 Refunding Series a Serial, 4.00-4.25% due 2000-2010; 8,820 9,920 (effective rate 2.85 to 4.35%) 9 (000's omitted) Long-term debt at June 30, continued: 2000 1999 Multiple Capital Facilities Project 1992 Series A Serial, 5.40-6.50% due 2000-2008; 14,035 14,980 Term, 6.50% due 2012; 9,605 9,605 Term, 6.625% auctioned variable & residual rates due 2017-2025 55,000 55,000 (effective rate 5.20 to 6.68%) 1999 Refunding Series A Serial, 4.00-5.25% due 2003-2016; 26,410 26,410 Term, 5.50% due 2025: 41,465 41,465 (effective rate 3.65 to 4.94%) 146,515 147,460 Northwest Resource 1997 Series A Serial, 4.20% due 2001; 6,025 10,010 (effective rate 4.35%) Less: Unamortized net discount and premium 1,114,215 1,171,807 Current portion (10,947) (9,623) (60,375) (57,595) $ 1,042,893 $ 1,104,589 Debt service requirements for each of the next five years ending June 30'" and cumulative thereafter as of June 30, 2000 (in thousands): Principal Interest Total 2001 $ 60,375 $ 60,020 $ 120,395 2002 55,880 57,287 113,167 2003 50,000 53,958 103,958 2004 52,935 51,682 104,617 2005 55,890 49,214 105,104 2006 and after 839,132 585,265 1,424,397 $ 1,114,212 $ 857,426 $ 1,971,638 redemption provisions As set forth in the bond indentures, the term bonds are subject to redemption prior to maturity in varying amounts at specific dates. At the option of the Agency, term bonds are also subject to early redemption at specific redemp- tion prices and dates. Defeased Debt: Various bond refundings were undertaken to defease debt and realize future debt service savings. Debt was defeased by using the proceeds of the refunding issues and other available moneys to irrevocably place in trust cash and U.S. Government securities, which together with interest earned thereon, will be sufficient to pay both the interest and the appropriate maturity or redemption value of the refunded bonds as required. Accordingly, these defeased debt issues have been considered extinguished for financial reporting purposes. At year-end the following defeased debt remained outstanding: Geothermal Project No. Three, 1987 Series A Project No. Three, 1993 Series A -10 (000's omitted) 2000 1999 $ 52,080 90,620 142,700 $ 52,080 90,620 142,700 (000's omitted) 2000 1999 Hydroelectric Project No. Three, 1985 Series A 12,150 12,150 Project No. Three, 1986 Series A 36,960 36,960 49,110 49,110 Combustion Turbine Project No. One, 1989 Series A 17,180 51,925 Transmission Project No. One, 1989 Series A 3,860 12,360 $ 212,850 $ 256,095 debt restructuring During fiscal year 1998-99 the Agency completed a partial restructuring of its outstanding debt to achieve a more optimal overall debt service structure. The debt restructuring is expected to assist participants in Agency projects in achieving respective cost structures more compatible with their expectations of future energy pricing and demand levels. The restructuring is further explained in the following project descriptions. geothermal project In addition to the geothermal leasehold, wells, gathering system and related facilities, the project consists of two electric generating stations (Plant 1 and Plant 2). Each plant has two 55 MW (nameplate rating) turbine generator units utilizing low temperature geothermal steam; associated electrical, mechanical and control facilities; a heat dissipation system; a steam gathering system; a transmission tapline; and, other related facilities. Geothermal steam for the project is derived from the geothermal property, which includes wellpads, access roads, steam wells and reinjection wells. As part of its debt restructuring, in August 1998 the Agency converted $121,590,000 of Geothermal Project Number 3 Revenue Bonds, 1996 Refunding Series A from a weekly variable to a long-term fixed interest rate as provided in the indenture. In addition, the Debt Service Reserve Account was funded with a surety bond issued by MBIA Insurance Corporation and the released moneys, along with contributions from project participants of $76,160,411, were applied to the defeasance of approximately $142.7 million of outstanding project debt maturing on and after July 1, 2006. The effect of this portion of the restructuring was to reduce debt service on the Project by $108,578,086 over the next 12 years, resulting in an economic loss to the Agency (difference between the present values of the old and new debt service payments) of $1,736,885 In December 1999, the Agency established an escrow deposit account and entered into a guaranteed investment contract to economically defease $25 million of Geothermal Project Number 3 Revenue Bonds, 1987 Refunding Series A, which mature in 2009. As a result, the Agency reduced its aggregate Geothermal Project debt service payments by approximately $13,469,805 over the next nine years and obtained an economic gain (difference between the present values of the old and new debt service payments) of approximately $2,809,676. hydroelectric project The Agency contracted to finance, manage, construct, and operate Hydroelectric Project Number One for the licensed owner, Calaveras County Water District. In exchange, the Agency has the right to the electric output of the project for 50 years from February 1982. The Agency also has an option to purchase power from the project in excess of the District's requirements for the subsequent 50 years, subject to regulatory approval. In July 1998 the Agency issued $301,490,000 of Hydroelectric Project Number One Revenue Bonds, 1998 Refunding Series A in connection with its debt restructuring. The bond proceeds, together with certain surplus construction funds, were used to redeem $301,840,000 of Hydroelectric Project Number One Revenue Bonds, Refunding Series E, F & G on August 27, 1998. Concurrently, on that date the Debt Service Reserve Account was funded with a surety bond issued by MBIA Insurance Corporation. Released Debt Service Reserve Account moneys were applied to the payment of a portion of the debt service on outstanding Hydroelectric Project Revenue Bonds, 1992 Refunding Series A and 1993 Series A. The effect of this restructuring was to spread debt service on the project over the entire project license period, an additional eight years, providing the Agency with an economic gain (difference between the present values of the old and new debt service payments) of $44,687,273. 11 combustion turbine project The project consists of five combustion turbine units, each nominally rated at 25 megawatts. Two such units are located in Roseville, two in Alameda and one in Lodi. The project provides capacity during peak load periods and emergency capacity reserves. Capacity and energy from the project are also sold to others from time to time. The Agency continued its debt restructuring in December 1998 with the issuance of $43,165,000 of Combustion Turbine Project Number One Revenue Bonds, 1998 Refunding Series A. Proceeds from the bonds, together with other available moneys, were used to refund approximately $46,514,971 (including accreted values of capital appreciation bonds) of outstanding Combustion Turbine Project Number One Revenue Bonds, 1989 Refunding Series A. The effect of the refunding was to reduce debt service on the project by more than $11.2 million over the next 12 years providing the Agency with an economic gain (difference between the present values of the old and new debt service payments) of $3,153,799. transmission project The project was undertaken to meet certain obligations of the Agency under the Agency/PG&E Interconnection Agreement. The project includes an ownership interest in PG&E's 230kV Castle Rock to Lakeville Substation Transmission Line in Sonoma County, additional firrn transmission rights in that Transmission Line, and a central scheduling and dispatch facility in service at the Agency's headquarters in Roseville, California. In December 1998, as part of its debt restructuring, the Agency issued $9,920,000 of Transmission Project Number One Revenue Bonds, 1998 Refunding Series A. Together with other available moneys, proceeds from the bonds were used to refund approximately $11,441,088 (including accreted value of capital appreciation bonds) of outstanding Transmission Project Number One Revenue Bonds, 1989 Refunding Series A. The refunding reduced debt service on the project by more than $4.1 million over the next 12 years providing the Agency with an economic gain (difference between the present values of the old and new debt service payments) of $774,037. multiple capital facilities project The project originally included three components; (1) One 49.9 megawatt combustion turbine, Unit One, located in Lodi, California, owned and operated by the Agency; (2) One 49.9 megawatt combustion turbine, Unit Two, located in Ceres, California, owned and operated by Turlock Irrigation District; and, (3) Certain improvements to the electric system owned and operated by the City of Lodi. Each of these three components were supported by separate and unrelated member participation agreements. In March of 1998 the Turlock Irrigation District refinanced the costs of Unit Two and Unit Two is, therefore, no longer included in the project. The acquisition and construction of improvements to the electric system of the City of Lodi (Lodi Facilities) were not undertaken and the plan to do so was abandoned in 1998. Debt on this component of the project is being redeemed as noted below. In January 1999 the Agency issued $67,875,000 of Capital Facilities Revenue Bonds, 1999 Refunding Series A. The refunded 1992 Bonds have not been legally defeased, but rather will remain outstanding until their applicable maturity or redemption dates. The 1999 Bonds are special, limited obligations of the Agency. Until September 3, 2002 (the Crossover Date), the 1999 Bonds are payable solely from, and secured by, certain investment receipts received from the investment of amounts in the Escrow Fund pursuant to an Escrow Deposit Agreement. After the Crossover Date, the 1999 Bonds will be payable solely from and secured solely by, Project Revenues primarily received from project participants for the combustion turbine unit located in Lodi. No 1992 Bonds are expected to be outstanding after the Crossover Date; however, if there were such outstanding 1992 Bonds, the aforementioned pledge of Project Revenues would be junior and subordinate to that securing the 1992 Bonds. A portion of the 1992 Bonds allocable to the Lodi Facilities maturing after September 3, 2002 will be irrevocably called for redemption on August 1, 2002 and a portion of such 1992 Bonds will be irrevocably called for redemp- tion on September 3, 2002. Investment receipts on amounts in the Construction Fund and the Debt Service Reserve Account with respect to the Lodi Facilities are expected to be sufficient to pay debt service on those bonds prior to September 3, 2002, and to redeem those bonds as noted above. 12 This cross-over refunding reduced debt service on the Project by more than $14.5 million over the next 28 years providing the Agency with an economic gain (difference between the present values of the old and new debt service payments) of $4,663,699. Northwest Resource: In 1996, the Agency notified Washington Water Power Company (WWP) of its intent to terminate their long-term agreement for the purchase of 50 MW of firm annual capacity effective June 30, 2001. In consideration of an even earlier termination date, December 31, 1996, the Agency made a capacity payment to WWP representing the present value of the unpaid fixed charges for such firm capacity to June 30, 2001, on behalf of eight participating members. In February 1997 the Agency issued $18,310,000 of Northwest Resource Revenue Bonds, 1997 Series A, to finance certain of the project participants' respective shares of such electric capacity payment. The bonds, special limited obligation revenue bonds, are payable solely from, and secured solely by, amounts to be received from such project participants pursuant to separate Financing Agreements. note e --commitments and contingencies power exchange agreement The Agency has a seasonal exchange agreement with Seattle City Light for 60 megawatts of summer capacity and 90,580 megawatt hours of energy in exchange for a return of 46 megawatts of capacity and 108,696 megawatt hours of energy in the winter. The agreement terminates in May 2014. power purchase contracts The Agency has various other long-term power purchase contracts with various suppliers on behalf of certain of its members. Minimum estimated commitments under these contracts are approximately $3,646,000 annually. combustion turbine fuel supply agreements The Agency has entered into the following contracts to provide natural gas fuel supply for use in its combustion turbines: ■ A 30 -year agreement terminating in November 2023 with the Pacific Gas Transmission Company and its partners in a gas pipeline between Alberta, Canada, and northern California. • A 15 -year agreement terminating in November 2008 with PanCanadian Energy for firm natural gas supply. • A 10 -year agreement terminating in March 2005 with PanCanadian Energy for not ifirm natural gas supply. The estimated minimum commitments under these contracts is approximately $4,731,000 annually. geothermal project production The Agency's Geothermal Plants experienced greater -than -anticipated declines in steam production from existing geothermal wells. Steam for the Agency's Geothermal plants comes from lands in the Geysers Area, which, are leased by the Agency from the federal government. The Agency operates these steam -supply areas. Initially, both Geothermal Plant 1 and Geothermal Plant 2 were operated as baseload generating projects at full capability comparable to the manner in which other Geysers projects were being operated. However, operation of both plants at high generation levels, together with high steam usage by others in the same area, resulted in a decline in the steam production from the steam wells at a rate greater than expected. As a result, by April 1988, for the purpose of slowing the decline in the steam field capability, the Agency changed its steam field production from baseload to load -following and reduced average annual generation to 150 MW gross. These changes were effective in reducing the decline in steam production. Beginning in 1991, along with other steam field operators in the area, the Agency implemented operating strate- gies to further reduce the rate of decline in steam production. The Agency's strategy included continuing average annual production at the 150 MW gross level, lowering steam turbine operating pressures to improve mass flow, and augmenting mass flow by managing the injection of plant condensate and supplemental water. These additional strategies were successful in accomplishing a further reduction in the rate of decline. To provide supplemental water, the Agency built two catch basins to collect plant site runoff. The catch basins have increased the amount of fluid injected by 3.8%. In April 1996, the Agency completed modifications of the Unit 2 steam turbine at Plant 1 and associated steam collection system to generate power with lower pressure steam at higher mass -flow rates than previously possible to optimize the utilization of the available steam resource. 13 In addition, the Agency entered into agreements with other producers in the Geysers Area to finance and con- struct the Southeast Geysers Effluent Pipeline Project. Construction was completed in September 1997 and operation began soon thereafter. The 26 -mile Effluent Project collects 7.8 million gallons per day from Lake County Sanitation District wastewater treatment plants at Clearlake and Middletown and delivers the wastewater to the Agency and the two other Geysers steam field operators for injection, The Agency is entitled to receive one third of the wastewater. Based on current operating protocols and forecasted operations, the Agency expects average annual generation of approximately 150 MW through 2000. After 2000 both the average and peak capacity are expected to de- crease, reaching approximately 90 MW by the year 2010 and remaining in excess of 60 MW through 2025, the end of the study period. claims and litigation The California Attorney General's Office, representing the California Regional Water Quality Control Board, has notified the Agency that the state will require cleanup and closure of the Butts Canyon Road waste facility near Middletown, California. The Agency disposed geothermal sulfur waste at this facility from 1981 through 1985. If the Agency were found liable, its share of the total study, cleanup and closure cost of this facility is currently estimated to be in the range of $300,000 to $500,000. Staff and legal counsel are working cooperatively with other involved parties to resolve this matter in an effective and cost efficient manner. Two environmental consulting firms have been retained by the potentially responsible parties to conduct the necessary site investigation and prepare a remedial action plan. In connection with the operation of the California Independent System Operator (ISO), PG&E has filed with the Federal Energy Regulatory Commission (FERC) a rate seeking to recover an additional $7 to $10 million from the Agency for services PG&E claims it acquired from the ISO to meet its contractual obligations to the Agency, but which the Agency's Interconnection Agreement did not provide for full compensation to PG&E. Given the Federal Energy Regulatory Commission doctrine against retroactive ratemaking and certain contractual protections, the Agency and its legal counsel believe it is unlikely that PG&E could recover any sums for past acts. However, PG&E may be able to collect some of these types of charges in the future. An adverse ruling by the FERC in this regard could cost the Agency several million dollars. The Agency expects to contest these charges vigorously if necessary. The Agency is participating in a FERC matter where the California ISO filed a new Transmission Access Charge for ISO participation by transmission owners. The filing is currently in multiparty settlement negotiations. If success- ful, a settlement could well establish the terms and conditions under which the Agency could join the ISO. However, it is too early to assess the probable cost or rate consequences of any settlement that may be reached. If no settlement occurs, the case will be litigated. Recently, the Pacific Gas & Electric Company (PG&E) filed a Reliability Services Tariff, under which it purports to charge existing contract transmission customers such as the Agency for so-called "reliability benefits" certain resources confer on the grid. The Agency and others challenged those charges and the FERC set the case for hearing. PG&E is being permitted to collect the rates in the interim, but a favorable hearing order would result in the refund of those amounts. The proposed rate has a three year phase-in period. If fully phased in, the rate increase would be in excess of 100% of the Agency's annual transmission costs under its interconnection agree- ment alone (about $5 million). The Agency is vigorously contesting these charges at hearing. The Agency and its Power Corporations are also engaged in various legal proceedings before federal and state courts and various administrative tribunals incidental to the Agency's operations. Based on its review of the aforementioned proceedings with outside legal counsel, the Agency believes that the ultimate aggregate liability, if any, resulting from these proceedings will not have a substantially adverse effect on the combined financial position or results of operations of the Agency and the associated Power Corporations. interconnection agreement advance termination notice The Pacific Gas & Electric Company (PG&E) previously gave the Agency notice that it would terminate the Agency/ PG&E interconnection Agreement on July 31, 2000. The termination date has been extended to March 31, 2002 by mutual agreement, as part of a settlement in connection with a California restructuring docket currently awaiting action by the Federal Energy Regulatory Commission (FERC). 14 PG&E has acknowledged its continuing obligations to serve the Agency under a November 20, 1991, settlement agreement in a Notice of Violation (NOV) proceeding before the Nuclear Regulatory Commission. Given these uncertainties, the Agency cannot presently determine the future effects, if any, the termination of the Agency/PG&E Interconnection Agreement may have on the Agency. electric industry restructuring In September 1996, Assembly Bill 1890 (AB1890) became law, which together with decisions of the California Public Utilities Commission (CPUC) have provided the framework for restructuring the electric industry in Califor- nia. Among other things, AB1890 provided for customers of investor-owned utilities purchasing electricity from other vendors, the establishment of an Independent System Operator (ISO) to control transmission assets and the establishment of a Power Exchange (PX) to pool generation asset output in a wholesale short-term spot market for electricity. Although the provisions of AB1890 apply in large part to investor-owned electric utilities under jurisdiction of the CPUC, some provisions apply to publicly owned utilities such as the Agency and its members. Under AB1890, if a publicly owned utility authorizes direct transactions within its service area between electricity suppliers and end use customers and makes its transmission assets available to the ISO, it is also authorized to impose a severance fee or transition charge on such transactions to recover above -market generation costs. These and other provisions of AB1890 contain a number of ambiguities and uncertainties as to their application. Al- though the California Legislature may address some of these in future legislation, other issues may ultimately be determined by regulatory or judicial actions. Federal legislation has also been proposed in connection with deregulation of the electric industry and the ability of publicly owned utilities to issue tax-exempt bonds in a deregulated electric industry. No prediction can be made as to whether any of the proposed legislation will become law, or what would be its final form or effect. Electric industry market participants, such as the Agency and its members, are facing numerous potential risks and uncertainties including, but not limited to, significant volatility in energy prices, loss of customers, particularly large commercial and industrial customers, and inability to recover stranded costs of electric generation -related assets. The Agency and its members are continuing to study and to take various actions that may be implemented in an effort to recover or mitigate potential stranded costs or to otherwise enhance their ability to compete in the increasingly competitive electric marketplace. However, the Agency cannot predict either the ultimate outcome of the ongoing changes in the electric industry or whether such outcome will have a material adverse effect on its financial position or results of operations. note f—subsequent events In August 2000 on behalf of its Hydroelectric Project, the Agency and two counter -parties entered into a $107 million notional amount, 12 year, fixed -to -floating interest rate exchange agreement, which is cancelable at specific dates after the first year. In connection with the exchange agreement, the Agency received an upfront fee of $1,000,000. In addition, during the term of the agreement, the net difference between the variable rate the Agency has agreed to pay and the 5.05% fixed rate the counter -parties have agreed to pay will be calculated on the notional amount and exchanged. The Bond Market Association (BMA) index will be used to determine the variable rate. The Agency expects to realize a reduction in the project's net debt service as a result of this agree- ment. In the event of a default or an early termination, the responsible party is required to make a termination payment to the other party. Also in August 2000, on behalf of its Geothermal Project Number 3, the Agency entered into an Investment Sale Agreement (Forward Purchase Contract) in connection with debt service payments on Geothermal Project Number 3 Revenue Bonds: $147,150,000 1993 Refunding Series A-1, A-2, A-3, and Series B; $121,590,000 1996 Refunding Series A; and $46,455,000 1996 Refunding Series B. The Agency entered into this agreement to lock in a 6.775% fixed rate of interest on future deposits into the Geothermal Project's Debt Service Fund. The Agency will continue to make debt service payments to the bond trustee: however, under terms of the agreement the bond trustee is required to purchase eligible securities, as defined in the bond indenture, from the supplying financial institution at the fixed rate of return. These securities mature on or prior to the time the required debt service payments have to be made from the debt service fund. The Investment Sale Agreement continues until July 1, 2010. In the event of a default or an early termination, the responsible party is required to make a termination payment to the other party. 15 ERNST & YOUNG • Ernst & Young r ('lata lowers 555 Capitol Mall Suite 650 Sacramento, California 0814 REPORT OF INDEPENDENT AUDITORS Commissioners Northern California Power Agency and Associated Power Corporations ■ Phone: M 16) 4-10-1401) fax: 1016) 411-0774 \\WWI `\.l lllll We have audited the accompanying combined balance sheets of Northern California Power Agency and Associated Power Corporations as of June -30, 2000 and 1999, and the related combined statements of revenues, expenses and changes in accumulated net revenues, and cash flows for the years then ended. These financial statements are the responsibility of the Agency's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the combined financial position of Northern California Power Agency and Associated Power Corporations as of June 30, 2000 and 1999, and the combined results of their operations and their cash flows for the years then ended in conformity with accounting principles generally accepted in the United States. �o4/wut f hP �.Li-L September 27, 2000 Ernst & Young 11P is a member of Ernst & Young International, Ltd, CAUSES 1. Demand Exceeds Capacity 2. Limited California Generating Capacity 3. Dysfunctional Market Structure 4. Possible Market Power Abuses 5. Power Plants Down for Servicing 6. Regional Energy Demand and High Natural Gas Prices 7. Inadequate Regulatory Authority ELECTRIC DEREGULATION Background • High Cost of Electricity • High Prices/Inadequate Supply • How Restructuring Works -Power Exchange (PX) -Independent System Operator (ISO) • Stranded Costs and Retail Freeze -10% Temporary Rate Reduction Freeze Ends • Increased Wholesale Prices and Supply Shortage