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HomeMy WebLinkAboutElectric Board - Minutes - 08/18/1999Minutes to be approved by the Board at the September 15,1999 meeting FORT COLLINS ELECTRIC BOARDMINUTEs: lie 1Vleetut Au t 38,.19995 Council Liaison: Scott Mason I Staff Liaison: Shannon Turner - 416-2254 (W) Chairperson: Jim Welch Phone: 498-8947 (W/H) Vice Chair: Richard Smart Phone: 221-4474 (H) A regular meeting of the Fort Collins Electric Board was held at 5 p.m. on Wednesday, August 18, 1999, in the Utilities Training Room at 700 Wood Street, Fort Collins, Colorado. BOARD PRESENT: Bill Brayden, Joseph Di Rocco, Jeff Eighmy, Barbara Rutstein, Richard Smart and Jim Welch BOARD ABSENT: Virginia Purvis STAFF PRESENT: Dave Agee, Ellen Alward, Lori Clements -Grote, Eric Dahlgren, Bob Kost, Mike Smith, Dennis Sumner and Wendy Williams GUESTS: Mike Dahl, Platte River Power Authority Bob Abiecunas, Platter River Power Authority John Allum, Platter River Power Authority Brian Moeck, General Manager - Platte River Power Authority OBSERVER: Lu Fisk, League of Women Voters INTRODUCTION OF NEW BOARD MEMBERS: Vice Chairperson Welch introduced new Board Member Joe Di Rocco. Joe has a background in financing independent power projects and is currently employed with the State of Wyoming as their chief financial investment counselor. New Board Member, Virginia Purvis was unable to attend the meeting. In Virginia's absence, Mike Smith provided a brief background. She is a program manager with Hewlett Packard Company and was previously employed by Fort Collins Utilities. APPROVAL OF MINUTES: Board Member Rutstein made a motion to approve the minutes of the June 16, 1999 meeting. Board Member Smart seconded the motion. The motion passed unanimously, and the minutes from the June 16, 1999 meeting were approved. UPDATE COLORADO ELECTRIC ADVISORY PANEL DRAFr REPORT John Allum of Platte River Power Authority provided Board Members with an update on the Colorado Electric Advisory Panel created in 1998 by Study Bill 152, to investigate electric restructuring in Colorado. The Advisory Panel has been working on two topics: 1. Determining whether restructuring of the retail industry in Colorado is in the best interest of all electric consumers of Colorado. 2. Recommending the manner in which restructuring should be implemented, should the General Assembly decide to proceed. The 30-member panel began meeting in July 1998, and is made up of representatives from municipals, IOU's, co-op's, utilities, agriculture, residential and industrial. Several consultants assisted the panel. The panel's draft report was presented in July 1999, followed by five public hearings throughout Colorado. The final report will be completed in November 1999. The consultants who worked with the Panel included Coulton, CH2M Hill, and Stone & Webster. Coulton investigated low-income issues, while CH2M Hill investigated taxes and rates. Stone & Webster created a model of the power system in Colorado for the period of 2003- 2017, and then estimated potential impacts on a restructured envirorunent. Their results indicate 5,000 megawatts (MW) would need to be added to Colorado's electrical system, about 250 MW per year through 2017. Their model preferred gas fired combined cycle and combustion turbine units. John noted that the model assumes Colorado is operated as a one load control area, but in reality Colorado is divided into two load control areas. Public Service operates several plants, as does Western Area Power Administration. There was a question regarding whether John agreed with the Stone & Webster study results. John explained that when the panel hired Stone and Webster, they also created a task force of eight individuals to guide the consultants. The task force initiated sensitivity runs, fuel costs and environmental costs to assure the model was responding properly. He noted the assumptions made by the consultant were reasonable. The study found that Public Service, with over two-thirds of the generation along the Front Range, has market power in Colorado. The Front Range is a constrained area, and there are no transmission ties to Kansas, New Mexico or Oklahoma. Ninety percent of the electric load in Colorado lies between Fort Collins and Pueblo. The poolco model predicts rates will increase. If rates were to go up, the model predicts 29,000 fewer jobs, 26,000 fewer residents and $1.5 billion in personal income debt over the 15-year period. On July 1, 1999, the panel issued a draft study report. The preliminary results show residential and industrial rates are average when compared to Colorado's border states, and are lower than average when compared to the states that have restructured. Colorado commercial rates are below average in all cases. Municipals had the lowest rates, while independently owned utilities (IOU's) had average rates, and the co-op's had the highest rates. About one third of Colorado's power is sold to households. The panel concluded safeguards and educational programs would be needed for residential customers, if restructuring were to occur. Utilities may have to provide a standard offer contract for consumers who do not want to participate. As approximately 20 percent of the state is considered low income, there was support on the panel for assistance benefits and low-income programs. Alternate views included capping the gap between residential customers and industrial customer rates, and that customers should be able to aggregate. The consensus of the panel was that restructuring was not critical to encourage renewables. Most of the panel favored a market -based or green pricing concept. A strong majority of the panel rejected renewable energy mandates. Alternate views involved requiring a fixed amount of renewables in the resource mix and some financial support to encourage renewables. Taxes and fees are a big issue for municipals as restructuring could impact taxes and fees significantly. This issue would need to be resolved, if restructuring were to move forward. The Stone and Webster study forecast a $2.7 billion stranded benefit. No other state has had this level of stranded benefits. Most panel members agreed the benefits should be reimbursed to the rate payers versus the shareholders. As John explained, most states that are restructuring have either nuclear power plants or high cost co -generation contracts that drive the prices up. If the market price is lower than the sales price, then you have stranded costs. If the market price is higher, you have stranded benefits. In Colorado, all of the utilities except West Plains Energy had stranded benefits. The panel concluded that restructuring would have a negative impact on rural Colorado. The benefits would arrive in rural areas last, if at all. They felt REAs and small municipals should have a choice of opting in rather than being part of deregulation and then having to opt out. Competitive advantage deals with such items as tax-exempt financing and preference power from WAPA. As the panel did not have enough information to look at this issue, it will probably be investigated this fall. The Stone & Webster study showed that PSCo has strong market power though 2010. The consultant with the Office of Consumer Council believes PSCo would have strong market power throughout the 15-year study. The alternate view is the ISO role and the standard offer may mitigate some of the market power issues. There was a question regarding whether electric rates could be lowered if the City opted to deregulate. If the City "opted in," Platte River might be able to increase revenues from outside sales, possibly resulting in lower rates for the four owner cities. There were differing opinions among panel members on each of the issues. Overall, the panel voted against restructuring in Colorado. The results of the six public meetings found participants where also opposed to restructuring. The Panel will have a fall discussion on several issues, including a comparison of the DOE report and the Stone & Webster report. The final report will be issued by November 1. PLATTE RIVER POWER AUTHORITY FUTURE LOADS AND RESOURCES Mike Dahl and Bob Abiecunas gave a presentation on the peaking resource project. PRPA's load growth, as well as regional load growth, is exceeding available resources. Market prices are volatile and increasing, and constraints on the transmission system limit import capacity. Bob cited an example of the problem in Colorado. In July 1998, PSCo customers experienced rolling blackouts and localized power outages. Due to high temperatures PSCo's demand exceeded their generation capacity. PRPA set record peaks last summer but avoided blackouts. PRPA's load forecast shows that from 1992 to 1998 there has been a 131 MW or 47 percent demand increase. Peak demand increases have been seen in both winter and summer seasons. PRPA estimates resource deficits of 25 MW. PRPA is looking at a peaker, which is capable of 63 MW in the summer and 80 MW in the winter. Mike Dahl discussed the options PRPA analyzed when looking for a solution to the peaking shortfall. These options included short and long term market purchases, partnering options and peaking ownership. The analysis of short-term purchases found it is very difficult during peak periods to get capacity into this area from outside Colorado. There were both reliability and price concerns with this option. Long-term power purchasing was investigated through six entities. PSCo and West Plains did not have the resources, Colorado Springs' offer was not economical, and Tri-State, Tenaska and KN Energy declined to bid. Partnering options were explored with North American Power group. They were interested in building a unit at Rawhide, but the price was 50 percent higher. Third party financing was eliminated due to economics. PRPA inquired about the possibility of purchasing capacity at Fort St. Vrain, but PSCo is in a shortfall position and is also trying to purchase generation. PRPA staff concluded it would be best to build the transmission at Rawhide. This solution is the most economical and would eliminate transmission issues associated with purchase options, provide a long-term solution to meeting load growth, reduce market risk, leverage existing resources. The project began in April of this year and the plan is to have the turbines running by June 2002. UTILITIES 2000-2001 BUDGET REVIEW: Dave Agee presented the Board with an overview of the Utilities 2000-2001 budget. While Light and Power has not experienced a rate increase in five years, an average of a two percent electric rate increase is budgeted in 2001. The increase is an average based on cost of service. Water rates will increase by six percent every year from 2000-2004 to cover the costs of a $51 million water plant expansion. Wastewater rates will also be increasing moderately to cover plant expansions. Extensive Stormwater improvements are resulting in significant rate increases. Dave emphasized there are no cost subsidies between funds, each is maintained separately. With inflation, these rate increases will cause the average residential utility bill to increase form $80 to $100 by 2004. A comparison of several cities along the Front Range was conducted and shows Fort Collins will remain very competitive. The 2000-2001 budget includes a new fund, the Internal Service Fund, which includes the administrative costs of the combined Utilities. Based on an internal costs of service study, the administrative costs are then apportioned to the four Utility funds. In 2000, the total operating budget for Utilities is expected to go up by 5.5 percent. Purchase power is anticipated to go down by 1.3 percent, due to the Hewlett Packard expansion being delayed. In 2001, a 5 percent increase over 2000 is expected. The Light & Power capital budget's largest expenditure in 2000 and 2001 is the electric undergrounding program, approximately $1.8 million. Subdivision construction is projected at $1.6 million. Service center additions are planned in 2000 for $1.4 million. Overall the capital budget is approximately $10 million. u Ellen Alward noted Light and Power has historically projected a two percent rate increase during the budget process, but then delayed any increase. The 2001 rate increase has been delayed for a couple of years (1999 and 2000). If conditions remain the same, Utilities may be able delay it another year. The Board concluded they would like additional information on trends in budget allocations (specifically cost detail on historic and future costs) and discretionary programs (i.e. conservation efforts, zilch loans, green power programs, etc.). Additional information will be provided in the September packet. OVERVIEW OF THE 1999 WORK PLAN: Board Members reviewed the 1999 work plan. It was concluded that the Chairperson would contact Scott Mason, Council Liaison to get year 2000 goals from Council. This feedback will serve as the basis for discussion of the 2000 work plan. REPORT FROM ATTENDEES OF APPA ANNUAL CONFERENCE: Board Member Smart and Bob Kost attended the APPA Annual Conference and shared their observations. Board Member Smart noted the message of preparing for the competitive marketplace was the main theme this year. He sited various aspects of this theme: branding, building customer relationships and positioning for competition. Bob said he saw the program as providing more focus this year. Bob noted public power is doing well in the evolving competitive market. Efforts are being made by the IOUs to eliminate some of the options public power uses to bring value to its customers. For example, in Las Cruses New Mexico an IOU has been obstructing community efforts for the last 10 years. He mentioned Memphis Tennessee's experience, where a City Council Member initiated an effort to sell the municipal utility. ELECTION OF OFFICERS: Vice Chairperson, Jim Welch was unanimously elected as Chairperson, and Board Member Smart was unanimously elected as Vice -Chairman. FUTURE AGENDA ITEMS: • Utilities 2000-2001 budget overview • 1999 Work Plan • Light and Power portion of 2000 Legislative Agenda Shannon L. Turner Board Liaison