ML041400379
| ML041400379 | |
| Person / Time | |
|---|---|
| Site: | Cooper  |
| Issue date: | 12/31/2003 |
| From: | Nebraska Public Power District (NPPD) |
| To: | Office of Nuclear Reactor Regulation |
| References | |
| Download: ML041400379 (44) | |
Text
ITS BEEN A UNIQUE YEAR NEBRASKA PUBLIC POWER DISTRICT l 2003 ANNUAL REPORT
Message from President & CEO and Board Chairman 1 Customer Service 2 Energy Delivery 6 Generation 10 Board of Directors and Executive Team 14-15 Financial Statements Back Pocket ALLOW US TO SHED A LITTLE LIGHT
MESSAGE FROM PRESIDENT & CEO BILL FEHRMAN AND BOARD CHAIRMAN WAYNE BOYD The Nebraska Public Power District entered 2003 on a whirlwind of change: a new chief executive officer, an internal focus of improving performance, and expectations of a positive and productive year. While some things, like reliability, remained a standard, several business developments at NPPD in 2003 can be described as unique.
Distinctive is also appropriate in illustrating the June groundbreaking for construction of NPPDs first natural-gas, combined-cycle generation facility located outside of Beatrice; the proficient return-to-service of Sheldon Station after a boiler explosion at the coal-fired plant; and the 10-year agreement signed with Entergy Nuclear, Inc. for support services at Cooper Nuclear Station.
Unusual depicts the spring storms that carried some of the largest hail on record.
In addition to replacing tornado-struck power lines near ONeill, NPPD also assisted its wholesale customers in restoring power to the tornado-damaged communities of Coleridge and Deshler. The results of a first-ever deliberative polling survey on alternative generation sources, and the Boards approval to construct the states largest wind farm, were also noteworthy.
Exceptional would portray the performance of Gerald Gentleman Station which ranks among the lowest in production costs for coal-fired plants nationwide; the completed construction of a 40-mile transmission line through the states rugged sandhills; and improved communications among employees, the Board, our customers and the public.
There are also a few extraordinary issues that will carry into 2004, including economic development activities for several ethanol production facilities in the state; the potential impact of an extended drought on the operation of generation facilities along the Platte River Basin; and NPPDs purchase agreement for 142 megawatts from Omaha Public Power Districts planned, second coal-fired unit near Nebraska City.
As we close the books on a unique year, we will strive to keep safety and excellence paramount, our production costs below regional pricing, and public power a mainstay for Nebraska. Because, no matter how distinctive, unusual or exceptional we consider the events of 2003-some things are just routine.
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CUSTOMER SERVICE Whats good for the customer is good for NPPD. This message came through clearly in 2003. Using a back-to-the-basics approach to business, President and CEO Bill Fehrman refocused employees attentions on the core functions of generation and energy delivery, while bringing communications with employees, the Board and customers to an entirely new level. Setting an unprecedented agenda of face-to-face meetings with these stakeholders, Fehrmans non-stop approach to communication fostered a work style that puts customers first.
Organizational changes throughout the year, particularly among those responsible for customer contact, also provided a clear focus on the customer. By imparting more local decision-making authority and reducing layers of management, the restructuring efforts conducted during 2003 positioned NPPD to fulfill its mission statement-to safely generate and deliver low-cost, reliable energy and provide outstanding customer service.
NPPD placed even more emphasis on its role in the recruitment and expansion of business in the state. This fall, NPPD increased its economic development services by placing economic development consultants in the communities of South Sioux City (on the northeastern side of the state) and Ogallala (in western Nebraska).
These individuals join three other consultants located in Kearney, Norfolk, and Lincoln, and expand NPPDs economic development assistance throughout the state.
NPPDs economic development team played an instrumental role in approximately 20 development projects resulting in the location or expansion of business facilities in the service areas of NPPD and its wholesale customers. These efforts brought 1,210 new jobs plus an estimated 1,130 indirect or secondary jobs to Nebraska.
Examples of these business developments include, among others, the location of the Nor-Am Logistics cold storage facility in Schuyler; the Great West Casualty insurance processing center in South Sioux City; the Technologent Inc. call center in Ainsworth; the Advantage, Inc. call center in Valentine; and the retention of the Protient, Inc. whey processing facility in Norfolk.
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The ethanol industry also continued to play an important role in economic development. By the end of 2003, 12 ethanol plants were in production or under construction. NPPD expects to see the ethanol industry grow in 2004 and will continue its cooperation with other Nebraska organizations to expand this industry throughout the state.
In other agricultural-related venues, NPPD modified its summer peak load control program to allow irrigators more flexibility in their irrigation operations and to even out some of the significant load swings that NPPD experiences during certain hours in the summer months when loads are at or near peak levels. NPPD will review these changes and make additional adjustments to its load control program in 2004, if necessary.
Irrigators make up 83 percent of the end-use customers that control their load during the summer months. Together, NPPD and its wholesale customers managed to successfully curtail 449 megawatts of firm load on July 25, the day NPPD recorded its highest billable peak of the year with 2,152 megawatts.
This is a 17.3 percent reduction in peak load without load control.
At the commercial and industrial level, NPPD revamped its Energy Information Program to include a variety of options tailored to meet the customers needs.
For example, residential energy manuals were created for wholesale customers to raise their knowledge level regarding various homeowner conservation opportunities.
NPPDs account managers began contacting the 74 municipals that take power and energy from NPPD under the Professional Retail Operations Agreements and offered them new 20- or 25-year contracts. Though not scheduled to expire until 2015, the original agreements included language that would reduce the amount of the lease payment received from NPPD after 15 years from 12 to 10 percent of adjusted gross revenues. The new agreements provide for the municipals to continue to receive the 12 percent lease payment amount for the entire term of the contract.
The Village of Hampton and Northeast Nebraska Public Power District signed contracts with NPPD during 2003 to receive call answering/dispatching service, bringing the total number of entities utilizing this service to 13. Customer care representatives at NPPDs Centralized Customer Call Center in Norfolk answered nearly 200,000 customer calls last year. The Village of Hampton also signed a second agreement with NPPD for the operations and maintenance of its electric distribution system, joining two other entities that have this customized arrangement with NPPD.
During the summer, NPPD conducted, with its customers, a first-of-its-kind survey known as deliberative polling, a trademarked process never before used in the Midwest. Residents in the service areas of NPPD and its participating wholesale customers provided their thoughts on future energy resources in the state.
From approximately 500 people surveyed via telephone in June, more than 100 individuals from 80 Nebraska communities volunteered to attend a one-day session in August to learn more about the topic and provide a second, more informed opinion. Results of this study are being used as one of several factors considered in developing NPPDs long-term energy supply strategy.
NPPD supported its mission of being low-cost by ending the year with a surplus, which enabled NPPD to maintain existing electric rates for its wholesale and retail customers in 2004. Diligence will continue into next year to keep rates down by controlling costs and working with customer rate committees to improve the understanding of the methods used to set rates for both wholesale and retail customers.
As the only totally public-power state in the nation, Nebraska is conscientious in its quest for total customer focus. From responding to customers wants and needs to measuring success through feedback, NPPDs customer service strategy will be engrained across organizational lines-from CEO to front-line employees.
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ENERGY DELIVERY One opportunity for proving exceptional customer service was the response of NPPDs system to the massive power outage that struck the northeastern United States and part of Canada on August 14.
NPPDs Energy Management System, a computerized network that monitors the flow of electric power throughout NPPDs electric grid, sensed the outage occurring. Automatic controls-along with system and plant operators at NPPD, Loup Power District and Central Nebraska Public Power & Irrigation District generation and control facilities-coordinated efforts to decrease or back off generation. NPPDs generation and loads were back in balance within 10 minutes of the event.
Another reason why the blackout did not affect Nebraska is the states reliable transmission system. NPPD has built additional transmission lines over the past few years to serve customers growing loads. In 2003, a new 40-mile, 115-kilovolt transmission line was energized and connected to the statewide grid at a cost of $6.2 million. Located south of Broken Bow, the new line increased the reliability of the electric power delivery system in this area of the state, where demand has grown significantly, and strengthened NPPDs electric grid.
This doesnt mean a Northeast-style blackout could not possibly strike NPPDs system. Nebraskas grid, for the most part, has been expanded over the years to provide efficient capacity that allows the system to handle disturbances more effectively.
Approximately $3 million per year is spent on maintenance and capital improvements to poles and structures, while approximately $8 million per year pays for upgrades to substations and related electrical protection and relay devices. In 2003, NPPD invested approximately $2 million in the Control Centers Energy Management System. By its 10th birthday on July 12, the control center had monitored and dispatched more than 279 billion kilowatt-hours.
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NPPDs transmission system carried a total of 25,562 gigawatt-hours in 2003-down about 4.2 percent from the average over the past five years of 26,682 gigawatt-hours. However, NPPD has also seen a decrease in the number of outages over the past 10 years. In 2003, NPPDs transmission system recorded 98.61 percent availability for lines rated at 115-kilovolt through 345-kilovolt.
This represents a potentially higher availability than is typically gauged for transmission voltages 230-kilovolt and above, such as the Mid-Continent Area Power Pool 10-year average benchmark (1991-2000) of 98.08 percent.
Part of NPPDs overall success in 2003 can be attributed to seeking efficient processes. In 2003, NPPDs Transmission and Distribution system operations were brought together under a single umbrella: Energy Delivery. The organizational change included consolidating NPPDs subtransmission dispatch operations and implementing a statewide outage management system called PowerOn.
PowerOn is part of NPPDs newest high-tech tool-a geospatial information, outage management, and graphic-work-design system-that digitizes much of NPPDs distribution system and places the information on a Web-enabled platform. Still in its infancy, the $6.9 million tool will let NPPD personnel view the distribution system in real-time at a computer terminal. It also standardizes many processes, including line switching and dispatching, work management, asset inventory and procurement, and system design.
NPPD was challenged somewhat in 2003 by the suspension of development activities of TRANSLink, an independent transmission company with a coverage area from Minnesota to Texas. Uncertainties surrounding regulatory mandates and jurisdictions, as well as diverging interests, called for a self-imposed moratorium by TRANSLink, and NPPD withdrew from its activities.
In its stead, the Mid-Continent Area Power Pool, the North American Electric Reliability Council and the Midwest Independent Transmission System Operator stepped up to fulfill the need for assured reliability of the nations electric delivery system. NPPD is exploring various avenues along these lines until definitive signals come from the federal government, or until an appropriate transmission solution becomes clear.
09 GENERATION What was evident in 2003 was the excellent performance of Gerald Gentleman Station (GGS), NPPDs largest electric power generating plant. GGS set a new annual generation record by producing 9,782,517 megawatt-hours. This output exceeded the previous record of 9,549,816 megawatt-hours set in 2002 and contributed to GGSs repeated ranking among the lowest tier in production costs per kilowatt-hour for U.S. coal-fired plants of more than 300 megawatts.
At its December 2003 meeting, the NPPD Board of Directors recognized GGS and its personnel for excellence in serving NPPD and its customers in an exemplary manner. The board also cited continuous plant improvement, the successful installation of a multimillion-dollar emission filtration system and consistent, sustained excellence in operational performance.
Sheldon Station rebounded this year from a boiler explosion in April. The explosion caused no injuries and the plant returned to service in July. Sheldon Station ended the year with a net generation of 1,332,522 megawatt-hours.
The year consisted of achievements and significant challenges for Cooper Nuclear Station. Coming off an excellent year of energy production in 2002 where plant output (capacity factor) ranked in the top 25 in the nation, Cooper was faced with several challenges in 2003, not the least of which was determining the stations future.
Early in 2003, NPPD formed a team to determine the available options for operating Cooper. Board members and customers alike were briefed on the findings of the teams analysis, and after much discussion and considerable public input, the Board approved a resolution directing NPPD management to negotiate a long-term contract with Entergy Nuclear Nebraska, a subsidiary of Entergy Nuclear, Inc. of Jackson, Miss. Under terms of the agreement, Entergy Nuclear Nebraska will provide support services at Cooper while NPPD continues to own and operate the plant, as well as retain the operating license.
Somewhat atypical for the nuclear industry, the arrangement gives NPPD access to Entergys nuclear programs, processes, procedures and personnel available only to plants inside the Entergy fleet. NPPD anticipates benefits from Entergys expertise and business practices that are critical for the success of nuclear power plant operations today.
Concurrent with the decision to engage Entergy, the board decided to evaluate a license extension for the operation of Cooper beyond its current 2014 license and investigate the feasibility of increasing the power output at the plant. The Board also instructed management to evaluate plant refueling in 24-month intervals in lieu of the current 18-month cycles.
Operational improvements remained the primary focus at Cooper throughout the year under the scrutiny of the stations own Improvement Plan and a Confirmatory Action Letter from the Nuclear Regulatory Commission. Quarterly inspection reports from the Commission noted that Cooper has made improvements in each category under evaluation, with notable progress made in the Emergency Preparedness program.
Forced outages, a refueling outage that stretched to 50 days (scheduled for 35) and uncertainty about the plants future made for a trying year. The low-pressure turbine rotors failed during May 2003, resulting in a 36-day unplanned outage.
In response, the board approved the purchase of two new, low-pressure turbine rotors at Cooper at a cost of $35 million. Delivery is anticipated in early 2005.
Net generation for Cooper in 2003 was 4,492,333 megawatt-hours, and the plant tallied a total of 259.82 days on line. With Entergy Nuclear Nebraska onboard and the decision to evaluate the possibility of keeping the plant operating beyond its current license, a more positive future is foreseen.
Groundbreaking was held in June at the site of the future Beatrice Power Station, NPPDs first major new plant construction since Unit 2 at GGS was completed in 1982. The facility will be a natural-gas-fired, combined-cycle power plant, which means two turbines at the plant will run off natural gas, and then exhaust heat from the two turbines will be used to produce steam to power a third turbine. The efficiency of the combined-cycle plant is approximately 50 percent greater than for a simple-cycle, natural-gas-fired plant.
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By the end of the year, construction on the new station was proceeding as planned. Major equipment had been purchased, and the combustion turbines were set on their foundations. Other completed work included erecting the cooling tower, installing most underground piping, constructing the switchyard and installing the plant wells. Budgeted at $209 million and rated at 229 megawatts, the new plant is scheduled to come on line in the last quarter of 2004 to ensure it is fully operable and available before the summer of 2005.
The Beatrice facility will be especially important to NPPD as a source of replacement energy, should the drought in western Nebraska adversely affect operations at GGS. While NPPDs apprehension about the drought lies primarily with GGS, NPPDs North Platte Hydro, Canaday Station and the hydropower plants operated by Central Nebraska Public Power and Irrigation District are also of concern.
As a proactive measure, NPPD established a team to develop strategies and alternatives for the possibility of decreased water in the Platte River Basin in future years. The teams alternatives and scenarios included conservation measures, demand reductions and replacement costs for energy from GGS.
In early 2004, NPPDs Board of Directors approved funding for a well field that will be used to reduce the impact of the drought on the cooling-water availability at GGS.
In an effort to increase public awareness for balancing the multiple uses of the Platte River, NPPD coordinated a public dedication of the Water Interpretive Center outside of Ogallala. Working in concert with the Nebraska Game and Parks Commission, along with other entities that depend upon the Platte River for their livelihood, NPPD helped develop a fiber-optic map and multimedia video presentation that the Centers tourists can view to gain a better appreciation for water as a shared and renewable resource.
NPPD also raised public awareness regarding the impact that reduced Missouri River water flows can have on Cooper Nuclear Station. By participating in a study by the Nebraska Power Association, NPPD confirmed that lower Missouri River flows could potentially result in significant costs for Cooper. In August 2003, NPPD saw an increase of silt and debris along the plants intake structure, as well as a slight increase in operational costs, during four days of a federal court order for reduced river flows.
NPPD will continue to stay abreast of the ongoing dialogue between the U.S.
Fish and Wildlife Service, the U.S. Army Corps of Engineers and any other actions which could affect Coopers future power production.
Finally, the NPPD Board of Directors adhered to NPPDs strategic plan goal for greener power production. After much study, the board approved a wind farm, potentially the states largest, near Ainsworth in north central Nebraska.
The new wind farm is planned to be 30 megawatts for NPPD, with the potential to construct an additional 45 megawatts for participation by other public power entities, such as the Omaha Public Power District and Jacksonville Electric Authority of Jacksonville, Fla.
The cost is predicted to have little effect on NPPDs future rates, regardless of whether government-sponsored or other financial incentives factor into the business case.
In 2003, as NPPD welcomed future resources such as the combined-cycle facility and the wind farm, it said farewell to Kramer Power Station in eastern Nebraska near Bellevue. Dismantlement of the plant (retired from service in 1987 for economical and efficiency reasons) began in the last quarter of the year and will be complete in 2004. The demolition is part of a unique partnership between NPPD and the city of Bellevue.
Through the agreement, the city will reimburse NPPD for the total cost to dismantle the plant, as well as NPPDs costs for providing project management services for the demolition. At the completion of the project, NPPD will deed the land to the city to be used for park and recreational purposes.
The venture is one of many examples of NPPDs commitment to enhancing the quality of life in Nebraska. It also portrays NPPDs unique approach to obtaining the maximum value from our business endeavors, customer services, and power generation assets-not just in 2003, but every day of every year.
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Board of Directors Front row, left to right:
Bruce Gustafson Warren Cook Mary Harding Gary Thompson Back row, left to right:
Ralph Holzfaster Dennis Rasmussen Larry Kuncl, First Vice-Chairman Doralene Weed, Second Vice-Chairman Wayne Boyd, Chairman Darrel Nelson, Secretary Ken Schmieding
Executive Planning Council Front row, left to right:
Pat Pope, VP Energy Delivery Rick Gardner, VP Energy Supply Karla Tremel, VP Support Services Joe Moore, VP Customer Services Clay Warren, VP Stategic Programs John McClure, VP Government / Public Affairs Back row, left to right:
Dan Schaecher, VP Safety / Employee Programs Ron Asche, VP & Chief Financial Officer Bill Fehrman, President and CEO John McPhail, General Counsel Randy Edington, VP & Chief Nuclear Officer 15
ALWAYS THERE WHEN YOU NEED US STATISTICAL REVIEW 2 MANAGEMENTS DISCUSSION AND ANALYSIS 3 REPORT OF INDEPENDENT AUDITORS 10 FINANCIAL STATEMENTS 11 NOTES TO FINANCIAL STATEMENTS 15 2003 YEAR AT A GLANCE KILOWATT-HOUR SALES 17.6 BILLION OPERATING REVENUES 659.7 MILLION COST OF POWER PURCHASED AND PRODUCTION 383.1 MILLION OTHER OPERATING EXPENSES 221.5 MILLION INCREASE IN FUND EQUITY 17.9 MILLION DEBT SERVICE COVERAGE 1.47 01
2 0 0 3 STAT I ST I C A L R E V I E W Revenues from Average Electric Energy Electric Sales Number of MWH Sales (000s) Revenue Per SALES Customers Amount % Amount % KWH Retail:
Residential 67,614 745,918 4.2 $ 68,963 10.5 9.25¢ Rural & Farm 2,853 64,912 0.4 5,082 0.8 7.83¢ Commercial 14,537 836,105 4.8 55,785 8.5 6.67¢ Industrial 54 1,168,250 6.6 39,590 6.0 3.39¢ Public Lighting 190 18,268 0.1 2,022 0.3 11.07¢ Municipal Power 180 30,554 0.2 2,037 0.3 6.67¢ Miscellaneous Municipal 1,866 114,996 0.7 5,543 0.8 4.82¢ Total Retail Sales 87,294 2,979,003 17.0 179,022 27.2 6.01¢ Wholesale:
52 Municipalities (Total Requirements) 1,792,917 10.2 70,213 10.6 3.92¢ 2 Municipalities (Partial Requirements) 42,698 0.2 1,623 0.3 3.80¢ 24 Public Power Districts & Cooperatives (Total Requirements) 5,983,970 34.1 214,684 32.5 3.59¢ Total Wholesale Sales (Excluding Sales to LES, MEC and Other Utilities) 7,819,585 44.5 286,520 43.4 3.66¢ Total Retail and Wholesale Sales (Excluding Sales to LES, MEC and Other Utilities) 10,798,588 61.5 465,542 70.6 4.31¢ Sales to LES and MEC (1) 4,445,025 25.3 116,275 17.6 2.62¢ Other Utilities (Nonfirm and Other Sales) 2,327,458 13.2 59,599 9.0 2.56¢ Total Electric Energy Sales 17,571,071 100.0 641,416 97.2 3.65¢ Other Operating Revenues (Net of Deferred) 18,279 2.8 Total Operating Revenues $ 659,695 100.0 Production Costs MWH (000s)
G E N E R AT I O N Amount % Amount %
Production (Including Interchange) 15,821,784 87.2 $ 304,385 79.4 Power Purchased 2,324,443 12.8 78,742 20.6 Total Power Produced and Purchased 18,146,227 100.0 $ 383,127 100.0 (1) Sales to Lincoln Electric System (LES) include power and energy produced at NPPDs Gerald Gentleman Station, Sheldon Station, and Cooper Nuclear Station. Sales to MidAmerican Energy Company (MEC) are for power and energy produced at Cooper Nuclear Station. The sale to LES from Cooper Nuclear Station terminated on September 30, 2003.
Miles of Transmission Line in Service 5,042 Number of Employees 2,215 2003 Accrued Contractual and Tax Payments (000s):
Payments to Retail Communities $ 16,743 Payments in Lieu of Taxes $ 6,236 S O U R C E S O F E N E R GY 2003 Hydro & Renewable (11.9%)
For service to retail and total Gas & Oil Coal requirements wholesale customers (1.0%) (74.5%)
(excludes sales to Other Utilities and Sales to LES and MEC). Nuclear (12.6%)
M A N AG E M E N T S D I S C U S S I O N A N D A N A LY S I S The following Managements Discussion and Analysis should be read in conjunction with the audited Financial Statements and Notes to Financial Statements beginning on page 10.
OVERVIEW OF BUSINESS Nebraska Public Power District (the District) operates an integrated electric utility system including facilities for generation, transmission and distribution of electric power and energy for sales at wholesale and retail. The District is a summer peaking utility. An all-time summer peak of 2,370 MW was established in July 2002 for the Districts firm requirements customers. In contrast, the Districts all-time winter peak is 1,828 MW, which was established in January 2004. The District owns or has operating control over 35 generating plants, which had a combined accredited capacity during the summer of 2003 of 2,881.4 MW.
GENERATION PLANTS Number of Accredited Percent of Type: Plants (1) Capability (MW) Total Coal - Gerald Gentleman Station 1 1,365.0 47.3 Coal - Sheldon Station 1 225.0 7.8 Gas/Oil - Canaday Station 1 118.0 4.1 Nuclear - Cooper Nuclear Station 1 758.0 26.3 Hydro 9 157.3 5.5 Diesel 19 103.1 3.6 Combustion Turbine 3 155.0 5.4 35 2,881.4 100.0 (1) Includes six hydro plants and 17 diesel plants under contract to the District In addition to the above generating plants, the District purchases 451.4 MW of firm power from the Western Area Power Administration and other capacity and energy on both a short-term and non-firm basis in the wholesale energy market.
The District also owns and operates 5,042 miles of transmission and subtransmission lines, encompassing the entire State of Nebraska.
The Districts customer base for firm energy sales consists of approximately 87,300 retail customers plus 76 municipalities, public power districts, and cooperatives that are total requirements wholesale customers of the District. In addition, the District has several participation sale contracts in place with other utilities for the sale of power and energy at wholesale from specific generating plants. The District also sells energy on a non-firm basis in the wholesale energy market.
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ENERGY SALES Gigawatt Hours 20,000 15,000 8,229 6,165 7,191 8,000 6,772 10,000 5,000 9,166 10,041 10,088 10,755 10,799 0
1999 2000 2001 2002 2003 Firm Energy Sales Additional Energy Sales (1) All years include the sale of energy to MEC from Cooper Nuclear Station Prior to 2002, the District had two accounting divisions as required by separate Bond Resolutions, the Nuclear Facility Revenue Bond Resolution and the General System Revenue Bond Resolution. The costs of the Districts nuclear generating facility, Cooper Nuclear Station (CNS), were accounted for separately from the remainder of the Districts operations.
On August 1, 2002, the District defeased all outstanding nuclear facility debt and legally discharged its obligations under the Nuclear Facility Revenue Bond Resolution. This allowed for the financial consolidation of the two divisions. The financial statements reflect this transaction for all years presented.
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CONDENSED BALANCE SHEETS 2003 2002 2001 Condensed Balance Sheets (000s):
Utility Plant, net $ 1,538,213 $ 1,475,440 $ 1,525,990 Special Purpose Funds 561,906 508,910 414,686 Current Assets 379,604 351,747 321,452 Deferred Charges and Other Assets 307,053 123,187 89,732 Total Assets $ 2,786,776 $ 2,459,284 $ 2,351,860 Fund Equity $ 720,554 $ 702,691 $ 669,761 Long-Term Debt 1,289,331 1,148,457 1,201,032 Current Liabilities 162,898 208,923 162,219 Deferred Credits and Other Liabilities 613,993 399,213 318,848 Total Fund Equity and Liabilities $ 2,786,776 $ 2,459,284 $ 2,351,860 RESULTS OF OPERATIONS 2003 2002 2001 Condensed Statements of Revenues, Expenses, and Changes in Fund Equity (000s):
Operating Revenues $ 659,695 $ 634,630 $ 625,348 Operating Expenses (604,587) (590,521) (598,644)
Operating Income 55,108 44,109 26,704 Investment and Other Income 21,416 48,621 48,620 Debt and Other Expenses (58,661) (59,800) (63,085)
Increase in Fund Equity $ 17,863 $ 32,930 $ 12,239 Total operating revenues were $659.7 million in 2003, $634.6 million in 2002, and $625.3 million in 2001. The sources of operating revenues were as follows:
($ Millions) 2003 2002 2001 Firm Sales - Wholesale & Retail $ 465.5 $ 445.9 $ 403.1 Participation Sales to LES & MEC 116.3 153.2 162.3 Sales to Other Utilities 59.6 62.2 60.9 Other Operating Revenue 21.5 18.6 18.9 Deferred Revenue (3.2) (45.3) (19.9)
Total Operating Revenue $ 659.7 $ 634.6 $ 625.3
Revenues From Firm Sales Revenue from firm sales increased $19.6 million, or 4.4%, in 2003 compared to 2002. This increase is due primarily to increases in both the Districts wholesale and retail rates in 2003 of 4.0% and 3.6%, respectively. Firm sales increased
$42.8 million, or 10.6%, in 2002 compared to 2001. This increase reflects increased energy sales of 6.6% and increases in both wholesale and retail electric rates of 4.0% and 8.4% respectively.
AVERAGE REVENUE PER KWh SOLD - RETAIL (Retail - All Classes)
Cents per KWh 6.20 6.00 6.01 5.87 5.80 5.60 5.43 5.40 5.27 5.29 5.20 5.00 1999 2000 2001 2002 2003 AVERAGE REVENUE PER KWh SOLD - WHOLESALE (Firm Wholesale Customers Only)
Cents per KWh 4.00 3.80 3.66 3.60 3.50 3.42 3.40 3.20 3.13 3.13 3.00 1999 2000 2001 2002 2003 Revenues From Participation Sales and Sales to Other Utilities The District currently makes participation sales to Lincoln Electric System (LES) from the capacity and energy produced at Gerald Gentleman Station (GGS) and Sheldon Station; to MidAmerican Energy Company (MEC) from Cooper Nuclear Station (CNS); to Aquila Inc. (Aquila) from GGS; and to the Municipal Energy Agency of Nebraska (MEAN) from GGS and CNS. The District also engages in sales of energy with other utilities on a non-firm basis.
The decrease in participation sales revenue from LES and MEC of $36.9 million in 2003 compared to 2002 and the decrease of $9.1 million in 2002 compared to 2001 is primarily related to participation sales from the Districts nuclear facility. The decrease in revenue reflects new pricing arrangements for capacity and energy from CNS that was sold to LES and MEC pursuant to settlement agreements reached on July 31, 2002, between the respective parties concerning litigation related to CNS. In addition, the sale to LES for capacity and energy from CNS terminated on September 30, 2003.
Sales to other utilities consist of the participation sales to Aquila and MEAN and non-firm off-system sales. The Energy Authority (TEA), of which the District is a member, has energy marketing responsibilities for the Districts non-firm off-system sales and the related management of credit risks.
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Deferred Revenues The Districts wholesale and retail electric rates are established on a prospective basis. The estimated revenue requirements used to establish rates include operating expenses, excluding depreciation and amortization; debt service requirements on revenue bonds; payments of principal and interest on subordinated debt; amounts for capital projects to be paid from current revenues; and amounts for reserves to pay future costs, such as future nuclear facility decommissioning costs.
Under the provisions of the Districts wholesale power contracts, if the rates for wholesale power service in any year result in a surplus or deficiency in revenues necessary to meet revenue requirements, such surplus or deficiency, within certain limits set forth in the wholesale power contracts, may be retained in a rate stabilization account. Any amounts in excess of the limits will be included as an adjustment to revenue requirements in future rate periods. A similar process is followed in accounting for any surplus or deficiency in revenues necessary to meet revenue requirements for retail electric service.
Under generally accepted accounting principles for regulated electric utilities, such surpluses or deficiencies are accounted for as regulatory assets or liabilities. The District follows this accounting treatment.
The District recognizes all revenues in excess of revenue requirements in any year as a deferral or reduction of revenues.
Such surplus revenues are excluded from the net revenues available under the General Resolution to meet debt service requirements for such year. Surplus revenues are included in the determination of net revenues available under the General Resolution to meet debt service requirements in the year that such surplus revenues are taken into account in setting rates. The District recognized any deficiency in revenues needed to meet revenue requirements in any year as an accrual or increase in revenues, even though the revenue accrual will not be realized as cash until some future rate period. Such revenue deficiency is included, in the year accrued, in the net revenues available under the General Resolution to meet debt service requirements for such year. Revenue deficiencies are excluded in the determination of net revenues available under the General Resolution to meet debt service requirements in the year that such revenue deficit is taken into account in setting rates.
The District deferred or reduced revenues a net amount of $3.2 million in 2003. The Districts revenues in 2003 from firm wholesale and retail electric sales resulted in a surplus, or over collection of costs, of $20.9 million, which surplus amount was deferred (decrease in revenues). In addition, the wholesale and retail rates that were adopted for 2003 included consideration to refund $17.7 million of surplus net revenues from past years. Such surplus had previously been accounted for as a reduction in revenue in the year(s) the surplus occurred. Accordingly, the 2003 revenues from electric rates, which reflect the surplus being refunded, are offset by the revenue adjustment (increase) for such amount. In comparison, for 2002, the District deferred or reduced revenues a net amount of $45.3 million. The Districts revenues in 2002 from firm wholesale and retail electric sales resulted in surplus, or over collection of costs, of $43.3 million, which surplus amount was deferred (decrease in revenues). In addition, the wholesale and retail rates that were adopted for 2002 included consideration to collect $2.0 million of deficit net revenues from years prior to 2002. Such deficits had previously been accounted for as accrued revenue in the year(s) the deficit occurred. Accordingly, the 2002 revenues from firm electric sales are offset by the revenue adjustment (decrease) for this deficit collected in the 2002 rates. For 2001, the District deferred or reduced revenues a net amount of $19.9 million. The Districts revenues in 2001 from firm wholesale and retail electric sales resulted in a surplus of $2.3 million, which surplus was deferred (decrease in revenues). In addition, there was a $17.6 million revenue adjustment (decrease) for deficits from prior years that were collected in revenues from electric sales in 2001.
As of December 31, 2003, the District had $40.5 million of surplus deferred revenues yet to be applied as credits against revenue requirements in future rate periods, of which $17.6 million was utilized for such purposes in setting wholesale and retail electric rates for 2004. As of December 31, 2002, the District had surplus net revenues of $37.3 million yet to be applied against revenue requirements in future rate periods. As of December 31, 2001, the District had a deficiency in net revenues of $8.0 milion yet to be recovered in future rate periods.
Operating Expenses As reflected in the audited financial statements, total operating expenses in 2003 were $604.6 million, an increase of
$14.1 million from 2002. Total operating expenses in 2002 were $590.5 million, a decrease of $8.1 million from 2001 operating expenses of $598.6 million. The changes were due to the following:
Purchased power and production fuel expenses were $179.9 million, $159.7 million, and $146.8 million in 2003, 2002, and 2001, respectively. These expenses increased $20.2 million in 2003 compared to 2002 because of (i) a planned refueling and maintenance outage at CNS in the spring of 2003 which lasted 50 days, while there was no such outage in 2002, (ii) a 36 day forced outage at CNS in late spring/early summer of 2003 due to a failed blade on one of two low pressure turbine rotors, and (iii) a 75 day forced outage at one of the units at Sheldon Station resulting from a boiler explosion when the plant was in start-up following a scheduled spring maintenance outage. These outages required the purchase of replacement energy and generation of energy from other District plants, all at a cost incrementally higher than
the fuel costs for generating energy at either CNS or Sheldon Station. Purchased power and production fuel expenses increased $12.9 million in 2002 compared to 2001 because of higher energy sales to the Districts firm wholesale and retail customers that resulted from the hot-dry summer weather conditions.
Production operation and maintenance expenses were $203.2 million, $149.7 million, and $173.2 million in 2003, 2002, and 2001, respectively. These costs increased $53.5 million in 2003 compared to 2002. This was due primarily to the planned refueling and maintenance outage at CNS in 2003, while there was no such outage in 2002, and the forced outages at CNS and Sheldon Station during 2003. In addition, the District also accrued $16.0 million in 2003 for certain stay benefits payable in late 2004 to employees at CNS. There was no such expense accrual for stay benefits in 2002.
Such costs, totalling $5.6 million, were deferred in 2002. Production operation and maintenance costs decreased $23.5 million in 2002 compared to 2001 since there was not a planned refueling and maintenance outage at the Districts nuclear facility in 2002, while there was such an outage in 2001.
The transmission and distribution operation and maintenance expenses did not vary significantly from year to year. These expenses were $33.9 million, $33.0 million, and $32.0 million in 2003, 2002, and 2001, respectively.
Customer service and information expenses were $15.2 million, $27.8 million, and $18.0 million in 2003, 2002, and 2001, respectively. These expenses decreased $12.6 million in 2003 compared to 2002 primarily because of the write-off in 2002 of $11.4 million of unpaid billings by LES and MEC from December 2000 through May 2002 for CNS decommissioning related costs. This is also the reason for the increase in such expenses in 2002 compared to 2001.
Administrative and general expenses were $46.1 million, $47.5 million, and $51.0 million in 2003, 2002, and 2001, respectively. These expenses decreased in 2003 and 2002 as a result of cost reduction efforts achieved by the District.
Decommissioning expenses represent the amount accrued each year for the future decommissioning of CNS. In 2003, the District adopted the provisions of SFAS No. 143, Accounting for Asset Retirement Obligations (SFAS No. 143), see ACCOUNTING CHANGE. Accretion expense for 2003 was $26.3 million. The District deferred, as a regulatory asset, the difference between the 2003 accretion expense and the amount of annual decommissioning costs included in the determination of the Districts wholesale and retail rates for 2003 of $17.9 million. The annual expense includes amounts being collected in the Districts wholesale and retail rates and an amount equivalent to the accrued annual investment earnings on monies accumulated in the decommissioning funds established for such purpose. Decommissioning expenses were $17.9 million, $40.1 million, and $33.3 million in 2003, 2002, and 2001, respectively. These expenses decreased
$22.2 million in 2003 compared to 2002 due to a reduction from $11.0 million to $3.9 million in the expense provision included in the Districts wholesale and retail rates and a reduction in accrued investment earnings that resulted from market fluctuations in the value of investments and lower interest rates. The expenses increased in 2002 compared to 2001 because of additional accruals equivalent to the higher investment earnings in 2002.
Depreciation and amortization expenses decreased $25.1 million in 2003 compared to 2002 and decreased $13.7 million in 2002 compared to 2001 due to 2002 being the last year of depreciation expense related to the original construction cost of CNS.
Increase in Fund Equity Fund equity (net revenues) were $17.9 million in 2003, $32.9 million in 2002, and $12.2 million in 2001. The decrease in 2003 compared to 2002 reflects the reduction in revenue requirements used to establish the Districts electric rates in 2003, as compared to 2002, for payments of revenue bond principal amounts, which amounts decreased as a result of the defeasance of all outstanding nuclear facility debt on August 1, 2002, and reduced amounts planned for commercial paper principal retirements in 2003. These amounts were partially offset by the decrease in depreciation and amortization expenses in 2003, which results in an increase in fund equity as compared to 2002. The increase in 2002 compared to 2001 reflects an increase in revenue requirements used to establish rates in 2002 for commercial paper principal retirements, increased amounts included in rates for capital investments to be funded from current earnings, and a decrease in depreciation and amortization expenses. These amounts were partially offset by a reduction in revenue requirements used to establish the Districts electric rates in 2002 for payments of revenue bond principal amounts.
07
CAPITAL REQUIREMENTS The Districts Board of Directors authorized capital projects totaling approximately $96.0 million in 2003, $312.8 million in 2002, and $79.8 million in 2001. The amount for 2003 included $35.0 million for the purchase of replacement low pressure turbine rotors at CNS to replace the turbine rotor that failed during the year. The amount authorized for 2002 included $240.8 million for a new 229 MW combined-cycle natural gas fired generation plant and related facilities, which are scheduled to be operational by December 2004. The remaining capital projects authorized in 2003 and 2002, which totaled $61.0 million and $72.0 million, respectively, and the amounts authorized in 2001 were primarily for renewals and replacements to existing facilities and other minor additions and improvements. The Districts Board approved budget for capital projects in 2004 is $161.2 million, which includes $68.9 million for the installation of 50 MW of wind generation.
The Districts capital requirements are funded by a combination of monies generated from operations, issuance of revenue bonds, issuance of short-term debt, and other available reserve funds.
FINANCING ACTIVITIES The District had $1.258 billion (par amount) of outstanding revenue bonds at December 31, 2003, as compared to $1.120 billion (par amount) at December 31, 2002, and $1.118 billion (par amount) at December 31, 2001. The revenue bonds outstanding are at fixed interest rates and were issued at premiums or discounts. In addition, the District had outstanding
$81.9 million of tax-exempt commercial paper (TECP) notes at December 31, 2003, $77.9 million at December 31, 2002, and $108.0 million at December 31, 2001. Taxable commercial paper (TCP) notes totalling $60.5 million were also outstanding on December 31, 2001. A bank credit agreement is maintained to support the sale of the commercial paper notes. The District had $75.0 million of construction notes outstanding at December 31, 2002.
In September 2003, the District issued $205.0 million of revenue bonds at a premium to refund the $75.0 million of construction notes outstanding and to provide completion financing for the construction of the combined cycle generation plant. In March 2002, the District issued $48.4 million of revenue bonds at a premium to fund $29.9 million of authorized capital projects and to refund $19.0 million of TECP notes. Such TECP notes had previously been issued to pay the completion cost of environmental facilities constructed at the Districts Gerald Gentleman Station coal-fired generating plant. In October 2002, the District issued $95.2 million of revenue bonds at a premium to refund the $60.5 million of outstanding TCP notes and to reimburse itself for a $39.1 million payment made to MEC in connection with the settlement of litigation related to the Districts nuclear facility.
In 2003, the District retired $70.8 million of General System Revenue Bonds. In 2002, the District retired $69.0 million of General System Revenue bonds and $17.0 million of Nuclear Facility Revenue Bonds. In addition, on August 1, 2002, the District legally defeased the remaining outstanding Nuclear Facility Revenue Bonds totaling $56.9 million. Such defeasance was funded with monies held in the Nuclear Facility debt service fund, debt service reserve fund, and other available funds on deposit under the Nuclear Facility Revenue Bond Resolution. In 2001, the District retired $66.6 million of General System Revenue bonds and $29.8 million of Nuclear Facility Revenue Bonds.
The Districts credit ratings on its long-term debt remained unchanged in 2003 and as of December 31, 2003 were as follows:
Moodys Investors Service A1 (stable outlook)
Fitch Ratings A+ (negative outlook)
Standard & Poors Ratings Services A (negative outlook)
DEBT SERVICE COVERAGE The Districts debt service coverage was 1.47 in 2003, 1.57 in 2002, and 1.47 in 2001. The coverage is provided primarily by the amounts collected in operating revenues to fund the cost of utility plant additions, the amounts collected in operating revenues for principal and interest payments on the outstanding commercial paper notes, and the amounts collected in operating revenues to fund the cost of payments made to those municipalities by the District under long-term Professional Retail Operating Agreements. The District has established a goal in its planning process to target a minimum debt service coverage of approximately 1.5 times annual debt service.
CNS FUTURE OPERATION Cooper Nuclear Station, which has an accredited capacity of 758 MWs, is currently licensed to operate to January 2014.
The District is currently performing additional studies on CNS relating to (i) uprating station capacity by 15 to 17 percent, (ii) implementing 24-month fuel cycles instead of the current 18-month fuel cycles, and (iii) extending the operating license an additional 20 years (until 2034). A recommendation to the Board regarding the issues associated these additional studies is expected late in 2004.
The District entered into an agreement for support services at CNS with Entergy Nuclear Nebraska, LLC, a wholly owned indirect subsidiary of Entergy Corporation, in September 2003. The Entergy Agreement is for an initial term ending January 18, 2014. The agreement requires the District to reimburse Entergys costs of providing services and to pay Entergy annual management fees. Beginning in 2007, Entergy could also earn additional annual incentive fees if CNS achieves identified safety and regulatory performance targets.
The power sales contract with LES for the sale of 95 MW of capacity and energy from CNS ended in September 2003.
The current power sales contract with MEC for the sale of 380 MW of capacity and energy from CNS will end in December 2004. The District entered into a power sales contract with MEC to provide 250 MW of capacity and energy from January 1, 2005 until December 31, 2009. The District also entered into agreements for the sale of capacity and energy from CNS to Heartland Consumer Power District (Heartland) and the Municipal Energy Agency of Nebraska (MEAN). The Heartland agreement provides for delivery of capacity and energy beginning on January 1, 2004 and terminating on December 31, 2013 in amounts ranging from 5 MW up to 45 MW. The MEAN agreement provides for delivery of capacity and energy beginning May 1, 2004 and terminating on April 30, 2014 in amounts ranging from 30 MW up to 60 MW, of which 60% will be provided from CNS and 40% from GGS. The District continues to work with additional interested parties to secure contracts to sell up to 75 MW of additional capacity and energy from CNS.
ACCOUNTING CHANGE In 2003, the District adopted the provisions of SFAS No. 143, which provides accounting requirements for the recognition and measurement of liabilities for legal obligations associated with the retirement of tangible long-lived assets. Amounts recorded under SFAS No. 143 are subject to various assumptions and determinations, such as determining whether a legal obligation exists to remove assets, estimating the fair value of the costs of removal, estimating when final removal will occur, and the credit-adjusted risk-free interest rates to be utilized to discount the estimated cost of the future liabilities.
The District identified CNS as an asset for which a legal retirement obligation exists. As of December 31, 2003, the District has recorded an estimated liability of $552.1 million for an asset retirement obligation (ARO). The District has accumulated, as of December 31, 2003, a total of $355.1 million to meet such estimated liability. The difference of $197.0 million between the estimated ARO and the funds accumulated for such purpose has been recorded as a regulatory asset and represents amounts which will be collected through electric rates and future investment earnings on the monies held for this purpose.
In addition, the District has identified an ARO for the future closure of ash landfills at the sites of the Districts GGS and Sheldon Station coal-fired plants. The District has recorded an estimated liability, and a related regulatory asset, of $1.1 million as of December 31, 2003 for such ARO.
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REPORT OF INDEPENDENT AUDITORS To the Board of Directors of Nebraska Public Power District:
In our opinion, the accompanying balance sheets and the related statements of revenues, expenses and changes in fund equity and cash flows present fairly, in all material respects, the financial position of Nebraska Public Power District (the District), a public corporation and political subdivision of the State of Nebraska, at December 31, 2003 and 2002, and the results of its operations and its cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Districts management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America and the standards applicable to financial audits contained in Government Auditing Standards, issued by the Comptroller General of the United States, which 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed in Note 1 to the financial statements, concurrent with the defeasance of the outstanding bonds of the Nuclear Facility, the District merged the operations of the Nuclear Facility into the General System. The financial statements referred to above reflect this transaction for all years presented.
As discussed in Notes 2 and 12 to the financial statements, the District changed the manner in which it accounts for asset retirement obligations as of January 1, 2003.
Managements discussion and analysis included on pages 3 through 9 is not a required part of the basic financial statements but is supplementary information required by the Governmental Accounting Standards Board. We have applied certain limited procedures, which consisted primarily of inquiries of management, regarding the methods of measurement and presentation of the required supplementary information. However, we did not audit the information and express no opinion on it.
Our audits were conducted for the purpose of forming an opinion on the basic financial statements taken as a whole.
The supplemental schedule, Calculation of Debt Service Ratios in accordance with the General Revenue Bond Resolution for the years ended December 31, 2003 and 2002, is presented for purposes of additional analysis and is not a required part of the basic financial statements. Such information has been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, is fairly stated in all material respects in relation to the basic financial statements taken as a whole.
In accordance with Government Auditing Standards, we have also issued our report dated April 9, 2004 on our consideration of the Districts internal control over financial reporting and on our tests of its compliance with certain provisions of laws, regulations, contracts and grants for the years ended December 31, 2003. That report is an integral part of an audit performed in accordance with Government Auditing Standards and should be read in conjunction with this report in considering the results of our audits.
Chicago, Illinois April 9, 2004
F I N A N C I A L STAT E M E N T S Balance Sheets December 31, 2003 and 2002 (000s) 2003 2002 ASSETS Utility Plant, at Cost:
Utility plant in service $ 3,110,760 $ 2,958,976 Less reserve for depreciation 1,794,064 1,639,634 1,316,696 1,319,342 Construction work in progress 152,115 75,480 Nuclear fuel, at amortized cost 69,402 80,618 1,538,213 1,475,440 Special Purpose Funds:
Cash and cash equivalents:
Construction funds 2 71,614 Debt reserve fund 80 3,968 Employee benefit funds 982 Investments:
Construction funds 114,802 29,549 Debt reserve fund 84,911 78,214 Employee benefit funds 5,975 Decommissioning funds 355,154 325,565 561,906 508,910 Current Assets:
Cash and cash equivalents 40,925 50,538 Investments 186,107 155,994 Receivables, less allowance for doubtful accounts of $520 and $557 58,163 57,167 Fossil fuels, at average cost 19,977 20,277 Materials and supplies, at average cost 69,129 65,793 Accrued stay benefit costs 3,000 Prepayments and other current assets 2,303 1,978 379,604 351,747 Deferred Charges and Other Assets:
Deferred Asset Retirement Obligation 197,635 Prepaid capacity costs 46,798 48,864 Deferred settlement charges 39,100 39,100 Accrued stay benefit costs 5,578 Unamortized financing costs 11,354 8,965 Investment in The Energy Authority 4,975 3,696 Receivables from sale of property 1,124 2,108 Other 6,067 14,876 307,053 123,187 TOTAL ASSETS $ 2,786,776 $ 2,459,284 FUND EQUITY AND LIABILITIES Fund Equity $ 720,554 $ 702,691 Long-Term Debt:
Revenue bonds, net 1,207,431 1,070,557 Commercial paper notes 81,900 77,900 1,289,331 1,148,457 Current Liabilities:
Current maturities of long-term debt 69,945 70,750 Construction notes 75,738 Accounts payable and accrued liabilities 46,507 38,579 Accrued in lieu of tax payments 6,254 6,145 Accrued payments to retail communities 3,667 3,568 Accrued stay benefits 18,611 Other 17,914 14,143 162,898 208,923 Deferred Credits and Other Liabilities:
Asset Retirement Obligation 553,227 External decommissioning fund 325,565 Internal decommissioning fund 11,694 Deferred revenues 40,464 37,264 Other 20,302 24,690 613,993 399,213 TOTAL FUND EQUITY AND LIABILITIES $ 2,786,776 $ 2,459,284 The accompanying notes to financial statements are an integral part of these statements. 11
Statements of Revenues, Expenses, and Changes in Fund Equity for the years ended December 31, (000s) 2003 2002 Operating Revenues $ 659,695 $ 634,630 Operating Expenses:
Power purchased 78,742 51,897 Production -
Fuel 101,167 107,828 Operation and maintenance 203,218 149,744 Transmission and distribution operation and maintenance 33,893 32,974 Customer service and information 15,174 27,769 Administrative and general 46,148 47,504 Payments to retail communities 16,743 16,269 Decommissioning 17,895 40,057 Depreciation and amortization 85,371 110,430 Payments in lieu of taxes 6,236 6,049 604,587 590,521 Operating Income 55,108 44,109 Investment and Other Income:
Investment income 18,826 46,297 Other income 2,590 2,324 21,416 48,621 Increase in Fund Equity Before Debt and Other Expenses 76,524 92,730 Debt and Other (Income) Expenses:
Interest on long-term debt 61,851 60,686 Allowance for funds used during construction (2,541) (1,120)
Other (income) expenses (649) 234 58,661 59,800 Increase in Fund Equity 17,863 32,930 Fund Equity:
Beginning balance 702,691 669,761 Ending balance $ 720,554 $ 702,691 The accompanying notes to financial statements are an integral part of these statements.
Statements of Cash Flows for the years ended December 31, (000s) 2003 2002 Cash Flows from Operating Activities:
Receipts from customers $ 713,688 $ 734,431 Payments to suppliers and employees (513,311) (524,134)
Net cash provided by operating activities 200,377 210,297 Cash Flows from Investing Activities:
Proceeds from sales and maturities of investments 827,354 589,185 Purchase of investments (891,901) (643,345)
Income received on investments 9,043 12,924 Net cash provided by (used in) investing activities (55,504) (41,236)
Cash Flows from Capital and Related Financing Activities:
Proceeds from issuance of bonds 202,904 150,489 Proceeds from issuance of notes 4,000 75,899 Proceeds from repayment of notes receivable 1,425 2,447 Capital expenditures for utility plant (159,959) (84,566)
Principal payments on bonds (70,750) (144,385)
Interest payments on bonds (58,678) (57,658)
Principal payments on notes (75,000) (90,540)
Interest payments on notes (870) (2,384)
Other non-operating revenues 2,442 2,108 Net cash used in capital and related financing activities (154,486) (148,590)
Net increase (decrease) in cash and cash equivalents (9,613) 20,471 Cash and cash equivalents, beginning of year 50,538 30,067 Cash and cash equivalents, end of year $ 40,925 $ 50,538 Reconciliation of Operating Income To Cash Provided By Operating Activities:
Operating income $ 55,108 $ 44,109 Adjustments to reconcile operating income to net cash provided by operating activities:
Depreciation and amortization 85,371 110,430 Undistributed net revenue - The Energy Authority (1,279) 790 Decommissioning 17,895 29,049 Amortization of nuclear fuel 16,551 26,384 Changes in assets and liabilities which provided (used) cash:
Receivables, net (1,925) 2,864 Materials and supplies (3,336) (5,079)
Fossil fuels 300 (3,249)
Prepayments and other current assets (325) (121)
Deferred settlement charges (39,100)
Accrued stay benefit costs and other assets 11,387 (4,618)
Accounts payable and accrued payments to retail communities 8,027 1,143 Deferred revenues 3,200 45,293 Other 9,403 2,402 Net cash provided by operating activities $ 200,377 $ 210,297 The accompanying notes to financial statements are an integral part of these statements.
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Supplemental Schedule Calculation of Debt Service Ratios in accordance with the General Revenue Bond Resolution for the years ended December 31, (000s) 2003 2002 Operating revenues $ 659,695 $ 634,630 Operating expenses (604,587) (590,521)
Operating income 55,108 44,109 Investment and other income 21,416 48,621 Debt and other expenses (58,661) (59,800)
Increase (Decrease) in fund equity 17,863 32,930 Add:
Debt and other expenses 58,661 59,800 Depreciation and amortization 85,371 110,430 Payments to retail communities
- 16,743 16,269 160,775 186,499 Deduct:
Gain on sale of property 78 183 Investment income (disbursed) retained in construction funds (641) 2,036 Unrealized (loss) gain on investment securities (3,004) 2,221 Nuclear facility debt service 21,943 (3,567) 26,383 Fund equity available for debt service under the General Revenue Bond Resolution $ 182,205 $ 193,046 Amounts deposited in the General System Debt Service Account:
Principal $ 70,750 $ 70,495 Interest 53,567 52,577
$ 124,317 $ 123,072 Ratio of fund equity available for debt service to debt service deposits 1.47 1.57
- Under the provisions of the General Revenue Bond Resolution, the payments required to be made by the District with respect to the Professional Retail Operating Agreements are to be made on the same basis as subordinated debt.
The accompanying notes to financial statements are an integral part of these statements.
N OT E S TO F I N A N C I A L STAT E M E N T S
- 1.
SUMMARY
OF SIGNIFICANT ACCOUNTING POLICIES:
A. Organization Nebraska Public Power District (the District), a public corporation and a political subdivision of the State of Nebraska, operates an integrated electric utility system which includes facilities for the generation, transmission and distribution of electric power and energy to its wholesale and retail customers. The control of the District and its operations is vested in a Board of Directors consisting of 11 members popularly elected from districts comprising subdivisions of the Districts chartered territory. The Board of Directors is authorized to establish rates.
B. Basis of Accounting Prior to 2002, the District had two separate divisions for accounting purposes consisting of the General System and the Nuclear Facility as was required by the respective Revenue Bond Resolutions. On August 1, 2002, the District defeased all remaining outstanding bonds of the Nuclear Facility allowing for the consolidation of the two divisions. This consolidation is reflected for all periods presented.
The financial statements are prepared in accordance with generally accepted accounting principles and follow accounting guidance provided by the Governmental Accounting Standards Board (GASB). The District elected the option permitted by GASB Statement No. 20, Accounting and Financial Reporting for Proprietary Funds and Other Governmental Entities That Use Proprietary Fund Accounting to implement all Financial Accounting Standards Board (FASB) pronouncements that do not conflict or contradict GASB pronouncements.
The District follows the provisions of SFAS No. 71, Accounting for the Effects of Certain Types of Regulation (SFAS No. 71). In general, SFAS No. 71 permits an entity with cost-based rates to defer certain costs or income that would otherwise be recognized when incurred to the extent that the rate-regulated entity is recovering or expects to recover such amounts in rates charged to its customers.
C. Use of Estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
D. Revenue Wholesale revenues are recorded in the period in which service is rendered, and retail revenues are recorded in the month retail customers are billed. Consequently, revenues applicable to service rendered to retail customers from the period covered by the last billing in a year to the end of the year are not recorded as revenues until the following year.
The District is required under the General Revenue Bond Resolution (the Resolution) to charge rates for electric power and energy so that revenues will be at least sufficient to pay operating expenses, aggregate debt service on the General Revenue bonds, amounts to be paid into the Debt Reserve Fund, and all other charges or liens payable out of revenues. In the event the Districts rates for wholesale service result in a surplus or deficit in revenues during a rate period, such surplus or deficit within certain limits may be retained in a rate stabilization account. Any amounts in excess of the limits will be taken into account in projecting revenue requirements and establishing rates in future rate periods. Such treatment of wholesale revenues is stipulated by the Districts long-term wholesale power supply contracts. The District accounts for any surplus or deficit in revenues for retail service in a similar manner.
The surpluses and deficits from prior years have been accounted for in these financial statements by either a deferral of revenue or costs. The cumulative surplus at December 31, 2003, to be reflected in future revenue requirements is approximately $40.5 million.
E. Depreciation, Amortization and Maintenance The District records depreciation over the estimated useful life of the property primarily on a straight line basis. The Districts electric rates are established based upon debt service and operating fund requirements. Straight-line depreciation is not considered in the design of rates. As such, the District has provided for depreciation of utility plant funded from debt in its rate setting process by using the debt service principal requirements as the basis for depreciation as opposed to the straight line basis of depreciation included in the financial statements of the District. Under the methodology employed in establishing rates, the cumulative excess of depreciation expense calculated using the debt service principal approach over the amount calculated using the straight-line method is $18.8 million and $49.1 million for the years ended December 31, 2003 and 2002, respectively. Depreciation expense calculated under the debt service principal approach exceeded straight-line depreciation by $5.8 million and $67.2 million for the years ended December 31, 2003 and 2002, respectively. Actual depreciation expense on utility plant was $76.2 million and $101.1 million for the years ended December 31, 2003 and 2002, respectively. Depreciation on utility plant was approximately 3% in each of the years ended December 31, 2003 and 2002. The District has fully depreciated utility plant that is still in-service of $622.7 million and $611.8 million at December 31, 2003 and 2002, respectively.
Current rates for electric service provide for a portion of plant additions to be funded from revenues. These plant additions are capitalized and depreciated over their estimated useful life. At December 31, 2003 and 2002, $432.5 million and $423.3 million, respectively, of net utility plant was funded from revenues. Provision for depreciation of utility plant funded from revenues is computed using the straight-line method.
The District has long-term Professional Retail Operating (PRO) Agreements with 74 municipalities for certain retail electric distribution systems. These PRO Agreements obligate the District to make payments based on gross revenues from the municipalities and pay for normal property additions during the term of the agreements. The District has recorded provisions, net of retirements, for amortization of these plant additions of $6.6 million in 2003 and $6.8 million in 2002. These plant additions, which are fully reserved, totaled $99.4 million at December 31, 2003 and $94.9 million at December 31, 2002.
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The District charges maintenance and repairs, including the cost of renewals and replacements of minor items of property, to maintenance expense accounts. Renewals and replacements of property (exclusive of minor items of property, as set forth above) are charged to utility plant accounts. Upon retirement of property subject to depreciation, the cost of property is removed from the plant accounts and charged to the reserve for depreciation, net of salvage.
F. Cash and Investments The District follows GASB Statement No. 31, Accounting and Financial Reporting for Certain Investments and for External Investment Pools. GASB 31 requires the Districts investments to be recorded at market value with the changes in the market value of investments reported as Investment income in the Statement of Revenues, Expenses, and Changes in Fund Equity. Investments are recorded at market value as determined by quoted market prices.
Cash deposits, primarily interest bearing, are covered by federal depository insurance or pledged collateral of unregistered U.S.
Government securities held by various depositories. Investments at December 31, 2003 and 2002, were in unregistered U.S. Government securities and Federal Agency obligations held in the Districts name by the custodial banks.
The District considers highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.
G. Materials and Supplies The District maintains an inventory for materials and supplies which are valued at average cost. Due provision is made for slow moving or obsolete items.
H. Nuclear Fuel The District has entered into several long-term contracts for the various nuclear fuel components of uranium concentrates, conversion, enrichment, and fabrication. These contracts do not obligate the District to purchase fuel components in excess of the requirements of operations. Nuclear fuel in the reactor is being amortized on the basis of energy produced as a percentage of total energy expected to be produced. Fees for disposal of fuel in the reactor are being provided as part of the fuel cost.
I. Deferred Costs The District has deferred the cost of a $39.1 million payment to MidAmerican Energy Company (MEC) in conjunction with the settlement of litigation with respect to the operation of the Districts Cooper Nuclear Station (CNS). The District has also deferred
$3.0 million and $5.6 million as of December 31, 2003 and 2002, respectively, representing accrued stay benefits to CNS employees that remain employed at CNS through September 21, 2004. The deferred costs will be recognized as expense in future rate periods when such costs are included in the revenue requirements used to establish electric rates.
J. Unamortized Financing Costs These costs represent issuance expenses on all bonds and are being amortized over the life of the respective bonds using the bonds outstanding method.
K. Allowance for Funds Used During Construction (AFUDC)
This allowance, which represents the cost of funds used to finance construction, is capitalized as a component of the cost of the utility plant and is credited to Debt and Other Expenses. The capitalization rate depends on the source of financing. The rate for construction financed with revenue bonds is based upon the interest cost of each bond issue less interest income. Construction financed on a short-term basis with tax-exempt commercial paper (TECP) is charged a rate based upon the projected average interest cost of TECP outstanding. For the periods presented herein, the AFUDC rates for construction funded by revenue bonds vary from 3.8%
to 5.6%. For construction financed on a short-term basis with TECP, the rate charged was 3.0% in 2003 and 4.5% in 2002.
L. Fund Equity Fund equity consists primarily of cumulative operating revenues collected for utility plant additions, net of related accumulated depreciation, and debt service principal payments. The remaining fund equity will be fully offset by future depreciation expense. In addition, fund equity includes cumulative interest income received on construction funds.
M. Recent Accounting Pronouncements In April 2003, the FASB issued SFAS No. 149, Amendment of SFAS No. 133 on Derivative Instruments and Hedging Activities (SFAS No. 149) which clarifies and amends various issues related to derivatives and financial instruments addressed in SFAS No. 133 and interpretations issued by the Derivatives Implementation Group. In particular, SFAS No. 149 (1) clarifies when a contract with an initial net investment meets the characteristics of a derivative; (2) clarifies when a derivative contains a financing component that should be recorded as a financing transaction on the balance sheet and the statement of cash flows; (3) amends the definition of an underlying in SFAS No. 133 to conform to the language used in FIN No. 45; and (4) clarifies other derivative concepts. SFAS No.
149 is applicable to all contracts entered into or modified after June 30, 2003 and to all hedging relationships designated after June 30, 2003. The adoption of SFAS No. 149 did not have any effect on the Districts financial statements.
In November 2003, the FASB issued FIN No. 45, Guarantors Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others (FIN No. 45). As required by FIN No. 45, the District adopted the disclosure requirements on December 31, 2002. On January 1, 2003, the District adopted the initial recognition and measurement provisions for guarantees issued or modified after December 31, 2002. The adoption of the recognition and measurement provisions did not have any impact on the Districts financial statements.
In May 2003, the FASB issued EITF No. 01-08, Determining Whether an Arrangement Contains a Lease (EITF No. 01-08). In this abstract the Task Force reached a consensus on determining an arrangement contains a lease within the scope of SFAS No. 13, Accounting for Leases (SFAS No. 13). EITF No. 01-08 applied to arrangements agreed or committed to, modified, or acquired in business combinations initiated after the next reporting period beginning after May 28, 2003. On December 31, 2003, the District adopted EITF No. 01-08 for purposes of determining if an arrangement contains a lease within the scope of SFAS No. 13. The adoption of EITF No. 01-08 did not have any impact on the financial statements. The District will continue to review its agreements and any modifications under the provisions of EITF No. 01-08.
In March 2003, the GASB issued GASB Statement No. 40, Deposit and Investment Risk Disclosures (GASB 40), to provide the public with better information about the risks that could potentially impact a governments ability to provide services and pay its debt.
GASB 40 (1) amends GASB Statement No. 3, Deposits with Financial Institutions, Investments (including Repurchase Agreements),
and Reverse Repurchase Agreements, (2) addresses additional risks to which governments are exposed, and (3) requires that state and local governments communicate key information about deposit and investment risks. GASB 40 is effective for fiscal years beginning after June 15, 2004.
In November, 2003, the GASB issued GASB Statement No. 42, Accounting and Financial Reporting for Impairment of Capital Assets and for Insurance Recoveries (GASB No. 42). The new standard requires governments to record the impairment of capital assets upon occurrence or upon impairment identification rather than over the remaining useful life of the capital asset. Disclosure is required when an impairment of capital assets is recorded. GASB No. 42 also requires the use of a consistent method to record insurance recoveries. GASB No. 42 is effective for fiscal years beginning after December 15, 2004.
In June 2003, the GASB issued Technical Bulletin 2003-1, Disclosure Requirements for Derivatives Not Reported at Fair Value on the Statement of Net Assets (TB 2003-1). This TB replaces TB 94-1, Disclosure about Derivatives and Similar Debt and Investment Transactions. The guidance provided by TB 2003-1 defines a derivative, specifies the information that must be disclosed in the financial statements, including the derivatives objective, terms, fair value, and risks (risks include credit risk, interest rate risk, basis risk, termination risk, rollover risk, and market-access risk), and describes the acceptable methods for determining a derivatives fair value. TB 2003-1 is effective for financial statement periods ending after June 15, 2003. The adoption of TB 2003-1 did not have any impact on the Districts financial statements.
- 2. ACCOUNTING CHANGES:
In June 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations (SFAS No. 143). SFAS No. 143 provides accounting requirements for retirement obligations associated with tangible long-lived assets. As discussed in Note 11, the District adopted SFAS No. 143 as of January 1, 2003.
- 3. UTILITY PLANT:
Utility plant activity for the year ended December 31, 2003 was as follows (000s):
December 31, December 31, 2002 Increases Decreases 2003 Nondepreciable utility plant:
Land and improvements $ 37,805 $ 583 $ (75) $ 38,313 Construction in progress 75,480 152,315 (75,680) 152,115 Nuclear fuel* 80,618 5,336 (16,552) 69,402 Total nondepreciable utility plant 193,903 158,234 (92,307) 259,830 Depreciable utility plant:
Generation - Fossil 1,099,463 13,345 (21,896) 1,090,912 Generation - Nuclear 835,639 154,869 (13,982) 976,526 Transmission 589,483 20,101 (2,342) 607,242 Distribution 123,640 5,725 (16) 129,349 General 272,946 15,019 (19,547) 268,418 Total depreciable utility plant 2,921,171 209,059 (57,783) 3,072,447 Less reserve for depreciation (1,639,634) (212,213) 57,783 (1,794,064)
Depreciable utility plant, net 1,281,537 (3,154) 1,278,383 Utility plant activity, net $ 1,475,440 $ 155,080 $ (92,307) $1,538,213
- Nuclear fuel decreases represent amortization.
The 2004 construction plan includes authorization for future expenditures of $161.2 million. These expenditures will be funded from existing bond proceeds, revenues, other available funds and additional financings as deemed appropriate.
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- 4. CAPITAL LEASE:
The District entered into a capital lease in June 2000 with the City of Norfolk, Nebraska for a new centralized retail customer call center. At the expiration of the capital lease in 2010, the District assumes ownership of the call center.
Future capital lease payments as of December 31, 2003 are as follows (000s):
Year Payments 2004 $ 134 2005 134 2006 134 2007 134 2008 134 2009 134 2010 67 Total payments 871 Less amounts representing interest (165)
Net principal payments $ 706
- 5. SPECIAL PURPOSE FUNDS:
Special purpose funds of the District are as follows:
The Construction funds are used for capital improvements, additions and betterments to and extensions of the Districts system.
The sources of monies for deposits to the construction funds are from revenue bond proceeds and issuance of short term debt.
The Debt reserve fund, as established under the Resolution, consists of a Primary account and a Secondary account. The District is required by the Resolution to maintain an amount equal to fifty percent of the maximum amount of interest accrued in the current or any future year in the Primary account. Such amount totaled $33.6 million and $29.7 million as of December 31, 2003 and 2002, respectively. The Secondary account can be established at such amounts and can be utilized for any lawful purpose as determined by the Districts Board of Directors. Such account totaled $51.4 million and $52.5 million as of December 31, 2003 and 2002, respectively.
The Employee benefit funds consist of a self funded hospital-medical benefit plan and a retired employee life insurance benefit plan. The District pays 80% of the hospital-medical premiums with the employees paying the remaining 20% of the cost of such coverage. The plan had contributed funds of $5.5 million at December 31, 2003. The District pays the total cost of the employee life insurance benefit once the employee retires. The plan had contributed funds of $1.4 million at December 31, 2003. Both funds are held by outside trustees in compliance with the funding plans approved by the Districts Board of Directors.
The Decommissioning funds are utilized to account for the investments held to fund the estimated cost of decommissioning CNS when its operating license expires. The decommissioning funds are held by outside trustees or custodians in compliance with the decommissioning funding plans approved by the Districts Board of Directors.
- 6. PREPAID CAPACITY COSTS:
Prepaid capacity costs are associated with the purchase of the capacity of a 50 MW hydroelectric generating facility owned and operated by The Central Nebraska Public Power and Irrigation District (Central). The District is recording amortization on a straight-line basis over the 40 year estimated useful life of the facility. Accumulated amortization was $35.8 million in 2003 and $33.8 million in 2002.
The District has an agreement whereby Central makes available all the production of the facility and the District pays all costs of operating and maintaining the facility plus a charge based on the amount of energy delivered to the District. Costs of $0.9 million in 2003 and $0.8 million in 2002, respectively, are included in Power purchased.
- 7. INVESTMENT IN THE ENERGY AUTHORITY:
The District is a member of The Energy Authority (TEA), a power marketing corporation. The Energy Authority assumes the wholesale power marketing responsibilities of its members with each member having ownership in the joint venture. The Energy Authority has access to approximately 14,000 megawatts of its members generation located in Nebraska, Missouri, Florida, Georgia and South Carolina. The Energy Authority also provides its members with natural gas procurement or contract management services for gas used in the generation of electricity and for local distribution. The Energy Authority provides the District with gas contract management services.
The table below contains the condensed unaudited financial information for TEA as of December 31, (000s):
Condensed Balance Sheet 2003 2002 Current Assets $ 96,633 $ 97,209 Noncurrent and Restricted Assets 13,996 12,779 Total Assets $ 110,629 $ 109,988 Current Liabilities $ 74,811 $ 76,578 Noncurrent Liabilities 10,601 10,163 Net Assets 25,217 23,247 Total Liabilities and Net Assets $ 110,629 $ 109,988 Condensed Statement of Operations Revenues $ 631,297 $ 498,111 Energy Costs (505,186) (407,433)
Gross Profit 126,111 90,678 Operating Expenses (17,900) (14,554)
Operating Income 108,211 76,124 Non-Operating Income 528 313 Increase in Net Assets $ 108,739 $ 76,437 As of December 31, 2003 and 2002, the District had a 21.4% ownership interest in TEA. Generally, the members share of net revenue generated by TEA is not based on ownership percentage, rather each members share of net revenue is based on their purchased power and power sales with TEA. The Energy Authority revenue generated from non-member transactions is distributed to members based on ownership percentage. The District accounts for its investment in TEA under the equity method and had an equity investment in TEA of $5.0 million and $3.7 million at December 31, 2003 and 2002, respectively. The Districts power purchases and sales are reflected in Power purchased and Operating Revenues, respectively, on the Statements of Revenues, Expenses, and Changes in Fund Equity. The District recorded power purchases and sales with TEA of $39.4 million and $27.0 million, respectively, during 2003, and $16.4 million and $31.2 million, respectively, during 2002. Included in Receivables is $4.4 million and $3.9 million due from TEA as of December 31, 2003 and 2002, respectively, related to December sales to TEA. Additionally, included in Accounts payable is $.5 million and $1.2 million due to TEA as of December 31, 2003 and 2002, respectively, related to December purchases from TEA. Investment in The Energy Authority includes $3.2 million of contributed capital and TEA net revenue attributable to the District that has been retained by TEA for working capital purposes. Such amounts retained by TEA totaled $1.8 million and $0.5 million at December 31, 2003 and 2002, respectively. The net change in undistributed net revenue reported in the Statements of Cash Flows of $1.3 million and $0.8 million for the years ended December 31, 2003 and 2002, respectively, have been recognized in Operating Revenues.
As of December 31, 2003, the District is obligated to guaranty, directly or indirectly, TEAs electric trading activities in an amount up to $28.9 million plus attorneys fees which any party claiming and prevailing under the guaranty might incur and be entitled to recover under its contract with TEA. Generally, the Districts guaranty obligations for electric trading would arise if TEA did not make the contractually required payment for energy, capacity or transmission which was delivered or made available or if TEA failed to deliver or provide energy, capacity or transmission as required under a contract.
Upon the District making any payments under its electric guaranty, it has certain contribution rights with the other members of TEA in order that payments made under the TEA member guaranties would be equalized ratably, based upon each members equity ownership interest in TEA. After such contributions have been effected, the District would only have recourse against TEA to recover amounts paid under the guaranty.
The term of this guaranty is generally indefinite, but the District has the ability to terminate its guaranty obligations by causing to be provided advance notice to the beneficiaries thereof. Such termination of its guaranty obligations only applies to TEA transactions not yet entered into at the time the termination takes effect.
The District also paid a membership fee of $2.6 million in 1999 which is being amortized over a five-year period.
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- 8. REVENUE BONDS:
In March 2002, the District issued General Revenue Bonds, 2002 Series A, in the amount of $48,390,000 to refund a portion of the outstanding tax-exempt commercial paper notes and to pay for the costs of acquisition and construction of various improvements and additions to the Districts infrastructure.
On August 1, 2002, the District defeased all outstanding nuclear facility debt and legally discharged its obligations under the Nuclear Facility Revenue Bond Resolution.
In October 2002, the District issued General Revenue Bonds, 2002 Series B, in the amount of $95,205,000 for the principal purpose of refunding all the outstanding taxable commercial paper notes and to reimburse itself for a payment made to MEC in settlement of litigation.
In September 2003, the District issued General Revenue Bonds, 2003 Series A, in the amount of $205,000,000 to complete the cost of construction of a combined cycle natural gas-fired electric generating plant and related facilities and to pay at maturity on December 1, 2003, the Districts Construction Notes, 2002 Series.
Revenue bonds consist of the following (000s):
December 31, Interest Rate 2003 2002 General Revenue Bonds:
1998 Series A:
Serial Bonds 2003 - 2016 4.30% - 5.25% $ 460,845 $ 505,135 Term Bonds 2017 - 2027 5.00% 13,485 13,485 Capital Appreciation Bonds 2005 4.65%
- 22,457 21,448 2006 4.70%
- 23,161 22,110 2007 4.75%
- 24,259 23,146 1998 Series B:
Serial Bonds 2003 - 2017 4.30% - 5.25% 115,950 132,635 Term Bonds 2018 - 2027 5.00% 83,570 83,570 1999 Series A Serial Bonds 2002 -2018 4.00% - 5.125% 168,870 176,545 2002 Series A Serial Bonds 2002 - 2006 3.00% - 5.00% 44,760 46,860 2002 Series B:
Serial Bonds 2005 - 2025 4.00% - 5.00% 72,320 72,320 Term Bonds 2026 - 2032 5.00% 22,885 22,885 2003 Series A:
Serial Bonds 2005 - 2026 2.50% - 5.00% 118,905 Term Bonds 2027 - 2034 5.00% 86,095 Total par amount of revenue bonds 1,257,562 1,120,139 Unamortized premium net of discount 19,814 21,168 1,277,376 1,141,307 Less - current maturities of revenue bonds (69,945) (70,750)
Total revenue bonds $1,207,431 $1,070,557
- Approximates yield to maturity.
Debt service payments and principal payments of the General Revenue Bonds as of December 31, 2003 are as follows (000s):
Debt Service Principal Year Payments Payments
- Includes $39,170,000 of the 2004 $ 129,805 $ 69,945 2002 Series A Bonds maturing in 2005 132,085 75,787 2006 which the District expects to 2006 162,812** 109,091**
refinance with General Revenue 2007 116,835 67,274 Bonds. 2008 121,870 74,405 2009-2013 562,153 384,865 2014-2018 302,560 207,310 2019-2023 151,668 94,400 The fair value of outstanding revenue bonds is determined 2024-2028 126,676 92,845 using rates currently available to the District. The fair value is 2029-2033 82,429 68,955 estimated to be $1,356.0 million and $1,208.7 million at 2034 13,319 12,685 December 31, 2003 and 2002, respectively. Total Payments $1,902,212 $1,257,562
- 9. COMMERCIAL PAPER NOTES:
The District is authorized to issue up to $150.0 million of tax-exempt commercial paper (TECP) notes and had authorization to issue up to $80.0 million of taxable commercial paper (TCP) notes until November 1, 2002. A $150.0 million credit agreement, which expires November 1, 2005, is maintained with a bank to support the sale of the TECP commercial paper notes. The credit agreement to support the sale of the TCP notes was terminated effective November 1, 2002. The District has outstanding as of December 31, 2003, $81.9 million of TECP. The proceeds of the TECP notes have been used to provide short-term financing for certain capital additions and for other lawful purposes of the District. The effective interest rates on outstanding TECP notes for 2003 and 2002 were 1.0% and 1.5%, respectively.
The District refunded the TCP notes with tax-exempt revenue bonds in October 2002. The effective interest rates on outstanding TCP notes for 2002 was 2.0%.
The $81.9 million of TECP commercial paper notes outstanding at December 31, 2003, are anticipated to be retired by future collections through electric rates and issuance of revenue bonds. The carrying value of commercial paper notes approximates market due to the short-term nature of the notes.
- 10. LINE-OF-CREDIT ARRANGEMENTS:
The District has a $150.0 million bank line-of-credit agreement that supports the payment of the principal outstanding of the tax-exempt commercial paper notes. See Note 9 for additional information. The District also has a $10.0 million bank line-of-credit to satisfy the payment guarantee requirements established by the Federal Price-Anderson Act.
- 11. LONG-TERM DEBT:
Long-term debt activity net of current activity for the year ended December 31, 2003 was as follows (000s):
Principal Amounts December 31, December 31, Due Within 2002 Increases Decreases 2003 One Year Revenue bonds $1,070,557 $211,406 $(74,532) $1,207,431 $ 69,945 Commercial paper notes 77,900 4,000 81,900 Total long-term debt activity $1,148,457 $215,406 $(74,532) $1,289,331 $ 69,945
- 12. ASSET RETIREMENT OBLIGATION:
Effective January 1, 2003, the District recorded an obligation for the fair value of its legal liability for asset retirement obligations associated with CNS and various ash landfills at its two coal fired power stations. During 2003, the District opened an additional ash landfill and recorded a corresponding asset retirement obligation of $.3 million. At December 31, 2003, this liability is estimated at
$553.2 million and is included in Deferred Credits and Other Liabilities.
The following table shows costs as of January 1, 2003 and changes to the ARO that are included in Deferred Credits and Other Liabilities on the balance sheet as of December 31, 2003 (millions of dollars):
For the Year Ended December 31, 2003 Balance, beginning of year $ 526.6 Accretion expense 26.3 Asset retirement obligation .3 Balance, end of year $ 553.2 At the point the liability for asset retirement is incurred, SFAS No. 143 requires capitalization of the costs to the related asset.
For asset retirement obligations existing at the time of adoption, the statement requires capitalization of costs at the level that existed at the point of incurring the liability. These capitalized costs are depreciated over the same period as the related asset. At the date of adoption, the depreciation expense for past periods was recorded as a regulatory asset in accordance with SFAS No. 71 because the District will be able to recover these costs in future rates.
The initial liability is accreted to its present value each period. The District defers this accretion as a regulatory asset based on its determination that these costs can be collected from customers. The District has no asset retirement obligations relating to its other various assets such as coal, gas and hydro generating facilities, aboveground and underground storage tanks, and certain electric transmission and distribution facilities. These facilities are generally located on property owned by the District. Under current state statutes, the District has no legal obligation to retire those facilities.
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The following table presents the AROs that would have been included in Deferred Credits and Other Liabilities on the balance sheets if SFAS No. 143 had been applied during all periods presented (millions of dollars):
For the Year Ended December 31, 2002 Balance, beginning of year $ 501.5 Accretion expense 25.1 Balance, end of year $ 526.6 The pro forma asset retirement obligation the District would have recognized as of January 1, 2002 had the District implemented SFAS No. 143 as of that date, was approximately $501.5 million based on the information, assumptions, and interest rates as of January 1, 2003, used to determine the $526.6 million liability recognized upon initial adoption of SFAS No. 143. Because the Districts Board of Directors are allowing these costs to be recovered in future rates, adoption of SFAS No. 143 in 2002 would have had no impact on fund equity. Accordingly, pro forma impacts are not presented.
- 13. CONSTRUCTION NOTES:
In May 2002, the District issued Construction Notes, 2002 Series, in the amount of $75.0 million to finance a portion of the cost of construction of a combined cycle natural gas-fired electric generating plant and related facilities. The Construction Notes had an interest rate of 3.5% and matured on December 1, 2003. The District issued revenue bonds in September 2003 for the purpose of refunding the construction notes and funding the completion costs of this project.
- 14. PAYMENTS IN LIEU OF TAXES:
The District is required to make payments in lieu of taxes, aggregating 5% of the gross revenue derived from electric retail sales within the city limits of incorporated cities and towns served directly by the District.
- 15. LOW-LEVEL RADIOACTIVE WASTE DISPOSAL:
The District has access to the Barnwell, South Carolina low-level radioactive waste disposal facility and ships low-level radioactive waste generated as a result of operations at Cooper Nuclear Station to this facility on a routine basis. Legislation has been passed in South Carolina which would significantly reduce the amount of waste accepted from outside South Carolina and eliminate access after June 30, 2008. The District is also now utilizing the Envirocare Facility in Clive, Utah for a portion of its low-level radioactive waste disposal needs. The District cannot predict future costs for the Barnwell and Envirocare facilities or whether the Barnwell and Envirocare facilities will remain open or available to the District.
- 16. DEPARTMENT OF ENERGY FACILITIES ASSESSMENT:
Under the provisions of the National Energy Policy Act adopted in 1992, the District is subject to assessments initially estimated to be $1.67 million per year (to be adjusted for inflation) for a period up to 15 years for the purpose of paying the costs of decontaminating and decommissioning Department of Energy (DOE) operated uranium enrichment facilities. Such assessments commenced in 1993 and are to end in 2006. The District and a number of other utilities have filed legal proceedings to challenge DOEs past and future collections. The estimated aggregate amount for such annual assessments for the 3 remaining years is approximately $7.1 million, or $2.4 million per year. The District has recorded such annual assessments by reflecting a liability of approximately $7.1 million as of December 31, 2003 and $9.4 million as of December 31, 2002.
- 17. RETIREMENT PLAN:
The Districts Employees Retirement Plan (the Plan) is a defined contribution pension plan established by the District to provide benefits at retirement to regular full-time and part-time employees of the District. At December 31, 2003, there were 2,089 Plan members. Plan members are required to contribute a minimum of 2%, up to a maximum of 5%, of covered salary. The District is required to contribute two times the Plan members contribution based on covered salary up to $40,000. On covered salary greater than $40,000, the District is required to contribute one times the Plan members contribution. Plan provisions and contribution requirements are established and may be amended by the Districts Board of Directors. The Districts contribution was $9.8 million for 2003 and $9.9 million for 2002 of which $.9 million was in Accounts payable at December 31, 2003 and 2002.
- 18. POSTRETIREMENT BENEFITS:
The District, for employees hired on or prior to December 31, 1992, pays all or part of the cost (determined by retirement age) of certain hospital-medical premiums when these employees retire.
The District amended the plan effective January 1, 1993. Employees hired on or after that date must participate in the plan as an active employee the last five years of employment in order to qualify for these benefits. In addition, employees hired on or after January 1, 1993, are subject to a contribution cap that limits the Districts portion of the cost of such coverage to the full premium the year the employee or retired employee reached age 65, or the year in which the employee retires if older than age 65. Any increases in the cost of such coverage in subsequent years would be paid by the retired employee.
The District amended the plan effective January 1, 1999. Employees hired on or after January 1, 1999 are not eligible for postretirement hospital-medical benefits once they reach age 65 or Medicare eligibility. The District further amended the plan effective January 1, 2004, to provide that employees hired on or after that date will not be eligible for post retirement hospital-medical benefits once they retire.
The District also provides employees a life insurance benefit when they retire.
Substantially all of the Districts retired and active employees are eligible for such benefits. Currently, the cost of these benefits is recognized as expense as the premiums are paid. The total cost of postretirement hospital-medical and life insurance benefits was
$5.8 million for 2003 and $5.2 million for 2002.
Statement 12, Disclosure of Information on Post-employment Benefits Other Than Pension Benefits by State and Local Governmental Employees (OPEB), issued by the GASB provides that entities should provide certain minimum disclosures regarding the OPEB provided.
Additionally, Statement 12 provides for differing methods for financing OPEB. The District, as indicated above, currently funds OPEB on a pay-as-you-go basis and has not elected to fund OPEB through advance funding on an actuarially determined basis. The District does not contemplate any changes to the method for funding OPEB until results of the GASBs project on recognition and measurement of OPEB are available for analysis.
- 19. COMMITMENTS AND CONTINGENCIES:
The District has coal supply and coal transportation contracts with minimum future payments of $233.7 million. The various coal contracts expire through 2009. The various coal transportation contracts expire through 2011. These contracts are subject to price escalation adjustments.
The District has wholesale power purchase commitments with the Western Area Power Administration through 2020 with annual minimum future payments of approximately $18.4 million. This contract is subject to rate changes.
The District has two power sales contracts with MEC. The initial contract for 380 MW is for a term ending on December 31, 2004.
The second contract for 250 MW is for a term beginning January 1, 2005 and ending on December 31, 2009. Both power sales contracts are for the delivery of 380 MW and 250 MW, respectively, of the accredited capacity and associated energy from CNS at prices as set forth in the contracts.
The District has entered into long-term PRO Agreements having initial terms of 15, 20 or 25 years with 74 municipalities for the operation of certain retail electric distribution systems. These PRO agreements obligate the District to make payments based on gross revenues from the municipalities and pay for normal property additions during the term of the agreement.
The District entered into new 20-year wholesale power contracts, with a term that expires December 31, 2021, with the majority of its firm requirements wholesale customers to provide them with their total power and energy requirements through 2007, after which the wholesale customer could level-off its power and energy purchases through 2010 and thereafter could reduce its power and energy purchases up to ten percent per year with at least three years advance notice.
Effective January 2004, the District entered into a Participation Power Agreement (the NC2 Agreement) with Omaha Public Power District (OPPD) to purchase 142 megawatt (MW), which is a 23.7% share, of the power from a 600 MW coal fired power plant to be constructed by OPPD and to be known as Nebraska City Station Unit 2 (NC2). OPPD will retain 50.0% of the output for its own use and has entered into similar participation power sales agreements with other power purchasers. The Districts obligation under the NC2 Agreement to make payments is an unconditional take-or-pay obligation, obligating the District to make such payments whether or not NC2 or any part thereof is completed, delayed, terminated, available, operable, operating or retired. The NC2 Agreement contains a step up provision obligating the District to pay a share of the cost of any deficit in funds for operating expenses, debt service, other costs related to NC2 and reserves as a result of a defaulting power purchaser. The Districts obligation pursuant to such step up provision is limited to 160.0% of its original participation share (23.7%).
Under the provisions of the Federal Price-Anderson Act, the District and all other licensed nuclear power plant operators could each be assessed for claims in amounts up to $88.1 million per unit owned in the event of any nuclear incident involving any licensed facility in the nation, with a maximum assessment of $10.0 million per year per incident per unit owned. To satisfy the obligation, the District has obtained a $10.0 million line of credit.
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The Nuclear Regulatory Commission (NRC) evaluates nuclear plant performance as part of its reactor oversight process. The NRC has five performance categories. As a result of performance deficiencies identified during the period from October 2000 to April 2002 in the area of emergency preparedness, the District was placed in the second lowest of the five performance categories and was required to develop and implement a performance improvement plan at CNS with NRC oversight. The NRC also issued a Confirmatory Action Letter (CAL) in January 2003 to assure completion by the District of its improvement plan. The NRC is conducting periodic inspections to assess whether sustained performance improvements are being achieved. The NRC, in its report for the year 2003, indicated that overall, CNS operated in a manner that preserved public health and safety. While the District has made progress, the NRC noted that not all areas have yet achieved sustained performance improvement.
The District is currently working to have substantially all such performance improvement actions completed in early 2004. Following the Districts completion of the actions to implement the performance improvements, the NRC will conduct a comprehensive assessment of the effectiveness of these actions as part of the CAL closure process. The District cannot currently predict the timing or outcome of this review. Accordingly, CNS will remain in the current NRC performance category until the satisfactory completion of the actions listed in the CAL and the District has demonstrated sustained improvements in plant performance.
As part of the 1989 settlement agreement between General Electric Company (GE) and the District, GE has agreed to store at its facility at Morris, Illinois, the spent nuclear fuel assemblies from the first two CNS core loadings at no cost to the District until May 2002, which is the expiration of the current license for the Morris facility. After that date, storage will be at no cost to the District so long as GE can maintain the NRC license for the Morris Facility for a period of 20 additional years on essentially the existing design and operating configuration. GE has advised that they have submitted a request to the NRC for renewal of the license. GE is currently answering questions from the NRC which process will likely continue until midsummer 2004 at which time, the facility license renewal is expected to be approved by the NRC. If after May 2002, storage of the assemblies results in certain additional costs to GE then the District shall be responsible for such costs. Such costs would be included as part of fuel costs and collected for in the Districts rates for electric service. As of December 31, 2003, the District has not incurred any costs relating to the storage of these assemblies.
On December 4, 2002, Region VII of the Environmental Protection Agency (EPA) sent a letter to the District, and three other utilities located within Region VII, requesting documents and certain information pursuant to Section 114(a) of the federal Clean Air Act. The letter requests pertain to the Districts Gerald Gentleman Station and Sheldon Station. The EPA is interested in determining compliance with the Clean Air Act, Nebraskas implementation plan and potential application of federal new source review requirements.
In general, a finding of non-compliance can require the installation of air pollution control equipment and the assessment of penalties.
The District has provided the documents and information requested to the EPA. The District has not received any further written communications from the EPA regarding this inquiry.
- 20. LITIGATION:
Litigation between the District and MEC and between the District and Lincoln Electric System (LES) had occurred with respect to, among other things, the operation of CNS. On July 31, 2002, the District executed separate settlement agreements with MEC and LES which provided for the release and discharge by each party from any and all claims of any kind and nature whatsoever with respect to CNS and the agreement by the District to hold harmless and indemnify MEC and LES from and against any and all costs and expenses that the District has accrued, incurred or paid or will accrue, incur or pay with respect to CNS, including, without limitations, decommissioning costs, spent fuel costs, employee retention costs and post-retirement medical benefits. The settlement agreement with MEC also provided for the District to pay MEC $39.1 million. In addition, as part of the previous litigation between the District and MEC and between the District and LES, MEC and LES withheld payment of decomissioning costs billed to them by the District since December 2000. The withheld amount of $11.4 million was written off in 2002 as a customer service and information operating expense. Concurrently with such settlements, the District defeased all outstanding Nuclear Facility Revenue Bonds and satisfied and discharged the Nuclear Facility Revenue Bond Resolution as of August 1, 2002.
A number of other claims and suits are pending against the District for alleged damages to persons and property and for other alleged liabilities arising out of matters usually incidental to the operation of a utility such as the District. In the opinion of management, the exposure under these claims and suits would not materially affect the financial position, results of operation and cash flows of the District as of December 31, 2003.
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