10-K405 1 0001.txt FORM 10-K ================================================================================ UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2000
Registrant, State of Incorporation, Address of Commission File Principal Executive Offices and Telephone I.R.S. employer State of Number Number Identification Number Incorporation 1-8788 SIERRA PACIFIC RESOURCES 88-0198358 Nevada P.O. Box 10100 (6100 Neil Road) Reno, Nevada 89520-0400 (89511) (775) 834-4011 1-4698 NEVADA POWER COMPANY 88-0045330 Nevada 6226 West Sahara Avenue Las Vegas, Nevada 89146 (702) 367-5000 0-508 SIERRA PACIFIC POWER COMPANY 88-0044418 Nevada P.O. Box 10100 (6100 Neil Road) Reno, Nevada 89520-0400 (89511) (775) 834-4011 (Title of each class) (Name of exchange on which registered) Securities registered pursuant to Section 12(b) of the Act: Securities of Sierra Pacific Resources: -------------------------------------- Common Stock, $1.00 par value New York Stock Exchange Common Stock Purchase Rights New York Stock Exchange Securities of Nevada Power Company and subsidiaries: ---------------------------------------------------- 8.2% Cumulative Quarterly Income New York Stock Exchange Preferred Securities, Series A, issued by NVP Capital I 7 3/4% Cumulative Quarterly Trust Issued New York Stock Exchange Preferred Securities, issued by NVP Capital III Securities registered pursuant to Section 12(g) of the Act: Securities of Sierra Pacific Power Company and subsidiaries ----------------------------------------------------------- $2.15 Dividend Trust Originated Preferred Securities, New York Stock Exchange issued by Sierra Pacific Power Capital Trust I Securities of Sierra Pacific Power Company: ------------------------------------------- Class A Preferred Stock, Series 1, $25 stated value
Indicate by check mark whether registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No_____ --- Indicate by check mark if disclosure of delinquent filers pursuant to item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. X --- State the aggregate market value of the voting stock held by non-affiliates. As of March 13, 2001: $ 1,058,630,677 Indicate the number of shares outstanding of each of the issuer's classes of Common Stock, as of the latest practicable date. Common Stock, $1.00 par value, of Sierra Pacific Resources Outstanding at March 13, 2001: 78,475,217 Shares Sierra Pacific Resources is the sole holder of the 1,000 shares of outstanding Common Stock, $1.00 stated value, of Nevada Power Company. Sierra Pacific Resources is the sole holder of the 1,000 shares of outstanding Common Stock, $3.75 par value, of Sierra Pacific Power Company. DOCUMENTS INCORPORATED BY REFERENCE: Portions of the registrant's definitive proxy statement to be filed in connection with the annual meeting of shareholders, to be held May 21, 2001, are incorporated by reference into Part III hereof. This combined Annual Report on Form 10-K is separately filed by Sierra Pacific Resources, Nevada Power Company and Sierra Pacific Power Company. Information contained in this document relating to Nevada Power Company is filed by Sierra Pacific Resources and separately by Nevada Power Company on its own behalf. Nevada Power Company makes no representation as to information relating to Sierra Pacific Resources or its subsidiaries, except as it may relate to Nevada Power Company. Information contained in this document relating to Sierra Pacific Power Company is filed by Sierra Pacific Resources and separately by Sierra Pacific Power Company on its own behalf. Sierra Pacific Power Company makes no representation as to information relating to Sierra Pacific Resources or its subsidiaries, except as it may relate to Sierra Pacific Power Company. =============================================================================== SIERRA PACIFIC RESOURCES ANNUAL REPORT FORM 10-K CONTENTS PART I................................................................................................. 5 Item 1. Business..................................................................................... 5 Sierra Pacific Resources............................................................................ 5 Nevada Power Company................................................................................ 8 Sierra Pacific Power Company........................................................................ 16 Item 2. Properties................................................................................... 43 Item 3. Legal Proceedings............................................................................ 43 Item 4. Submission Of Matters To A Vote Of Security Holders.......................................... 43 PART II................................................................................................ 44 Item 5. Market For The Registrant's Common Stock And Related Stockholder Matters..................... 44 Item 6. Selected Financial Data...................................................................... 45 Item 7. Management's Discussion And Analysis Of Financial Condition And Results Of Operations........ 45 Sierra Pacific Resources............................................................................ 47 Nevada Power Company................................................................................ 50 Sierra Pacific Power Company........................................................................ 55 Item 7A. Quantitative and Qualitative Disclosures About Market Risk................................... 72 Item 8. Financial Statements and Supplementary Data.................................................. 75 Notes to Financial Statements....................................................................... 93 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure......... 139 PART III............................................................................................... 140 Item 10. Directors and Executive Officers of the Registrant........................................... 140 Item 11. Executive Compensation....................................................................... 146 Item 12. Security Ownership of Certain Beneficial Owners and Management............................... 152 Item 13. Certain Relationships and Related Transactions............................................... 153 PART IV................................................................................................ 158 Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K.............................. 158 SIGNATURES............................................................................................. 160
2 FORWARD LOOKING STATEMENTS The information in this Form 10-K includes forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These forward-looking statements relate to anticipated financial performance, management's plans and objectives for future operations, business prospects, outcome of regulatory proceedings, pending legislation in California and Nevada, market conditions and other matters. Words such as "anticipate," "believe," "estimate," "expect," "intend," "plan" and "objective" and other similar expressions identify those statements that are forward-looking. These statements are based on management's beliefs and assumptions and on information currently available to management. Actual results could differ materially from those contemplated by the forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with such statements, factors that could cause the actual results of Sierra Pacific Resources (SPR), Nevada Power Company (NVP), or Sierra Pacific Power Company (SPPC) to differ materially from those contemplated in any forward-looking statement include, among others, the following: (1) the outcome and timing of regulatory proceedings before the Public Utilities Commission of Nevada (PUCN) relating to the Comprehensive Energy Plan (CEP) filed by NVP and SPPC (collectively, the "Utilities") in January 2001, especially whether the significant rate increases granted by the PUCN to the Utilities on February 23, 2001, are successfully challenged in court or are reduced or delayed, and whether the other relief requested by the Utilities in the CEP is granted in a timely fashion; (2) a continuation of the current shortage of supply of electricity in the western United States and the adverse effect that such shortage is having on the price and availability of purchased power throughout the region; (3) whether the rate relief granted in the settlement agreement approved by the PUCN in July 2000, as augmented by its approval of the rate rider in the CEP, will be sufficient to stop the serious under-recovery of fuel and purchased power costs which has led to significant periodic losses by the Utilities, and whether that settlement will be challenged in court and or refunds demanded; (4) a continuation of the extremely high prices for natural gas in the western United States, as those affect both the cost of generated and purchased electricity and the cost of acquiring gas for SPPC's retail gas customers (in either case, to the extent that the Utilities are not permitted to pass these higher costs on to their respective customers); (5) whether recent California legislation barring the sale of power plants by public utilities until 2006 is amended to exempt SPPC and whether that legislation, pending legislation in Nevada, or future legislative or regulatory action in California or Nevada may bar or render impracticable the sale of the Utilities' electric generation plants; (6) if the sale of the Utilities' generation plants is prohibited or materially delayed, how such a development may affect SPR's ability to obtain the necessary regulatory approvals to complete the acquisition of Portland General Electric Co. (PGE) as well as the Utilities' ability to produce at reasonable cost power that would no longer be available under the transition power purchase agreements entered into with the purchasers of the generation plants; 3 (7) regulatory delays or conditions imposed by regulatory bodies in approving the acquisition of PGE; (8) whether the PUCN will issue favorable orders in a timely manner to permit the Utilities to borrow money and issue additional securities to finance the Utilities' operations and to purchase power and fuel necessary to serve their respective customers; (9) the extent to which the financial difficulties of California's electric utilities spread to utilities located in other western states and adversely affect SPR, NVP and SPPC's ability to access the capital markets to finance their capital requirements for construction costs and the repayment of maturing debt which are estimated for 2001 to total approximately $405 million for NVP and approximately $453 million for SPPC; (10) whether and in what form electric industry restructuring may continue in Nevada and what impact any changes may have on the Utilities, including the amount the Utilities would be allowed to recover from customers for certain costs that prove to be uneconomic after restructuring; (11) management's ability to integrate the operations of SPR, NVP and SPPC, and of PGE upon its acquisition, and to implement and realize anticipated cost savings from the merger of SPR and NVP and the acquisition of PGE; (12) regulatory or other delays in the sale of SPPC's water business to Truckee Meadows Water Authority ("TMWA"); (13) unseasonable weather and other natural phenomena, which can have potentially serious impacts on the Utilities' costs and earnings; (14) industrial, commercial and residential growth in the service territories of the Utilities; (15) the loss of any significant customers; (16) changes in the business of major customers, including those engaged in gold mining or gaming, which may result in changes in the demand for services of NVP or SPPC; and (17) the extent to which high energy prices and the financial difficulties of electric utilities and power exchanges in the western United States cause any counterparties to NVP's or SPPC's power purchase contacts to default on their obligations, which defaults could have a material adverse effect on the financial performance of NVP and/or SPPC. Other factors and assumptions not identified above may also have been involved in deriving these forward-looking statements, and the failure of those other assumptions to be realized, as well as other factors, may also cause actual results to differ materially from those projected. SPR, NVP and SPPC assume no obligation to update forward-looking statements to reflect actual results, changes in assumptions or changes in other factors affecting forward- looking statements. 4 PART I ITEM 1. BUSINESS SIERRA PACIFIC RESOURCES ------------------------ Sierra Pacific Resources, hereafter known as SPR, was incorporated under Nevada Law on December 12, 1983. SPR's mailing address is P.O. Box 30150 (6100 Neil Road), Reno, Nevada 89520-3150 (89511). SPR has eight primary, wholly owned subsidiaries: Nevada Power Company (NVP), Sierra Pacific Power Company (SPPC), Tuscarora Gas Pipeline Company (TGPC), Sierra Pacific Communications (SPC), Sierra Energy Company dba e.three (e.three), Sierra Pacific Energy Company (SPE), Lands of Sierra (LOS) and Nevada Electric Investment Company (NEICO). NVP and SPPC are referred to together in this report as the "Utilities". INTRODUCTION ------------ AN EXPLANATION OF THE REPORTING FORMAT The merger between SPR and NVP on July 28, 1999, was treated for accounting purposes as a reverse acquisition and deemed to have occurred on August 1, 1999. As a result, for financial reporting and accounting purposes, NVP was considered the acquiring entity under Accounting Principles Board Opinion No. 16, Business Combinations, even though SPR became the legal parent of NVP. Because of this accounting treatment, historic financial information presented in the financial statements for SPR for 1998 is that of NVP and includes no information for SPR. In addition, the financial information for the year ended December 31, 1999, reflects the acquisition of SPR by NVP on August 1, 1999. Therefore, the results of operations for that year reflect twelve months of information for NVP and five months of information for SPR and its pre-merger subsidiaries. This presentation is carried forward to the notes to the financial statements. The discussion in this report has been divided wherever possible to highlight the activities of the major subsidiaries of SPR. Parenthetical references are included after each major section title to identify the specific entity addressed in the section. References to SPR refer to the consolidated entity, except for the section related to debt financing in which SPR debt is discussed separately from that of its subsidiaries. INDUSTRY AND REGIONAL PROBLEMS AFFECTING THE UTILITIES (NVP AND SPPC) --------------------------------------------------------------------- Electric Utility Trends In 2000, wholesale electricity prices soared more than 300% over 1999 rates and continue at high levels. Wholesale regional electricity costs are not expected to stabilize for several years until more generation supplies are brought online. Although a number of factors have contributed to this situation, California's electric restructuring model, which deregulated wholesale prices but capped retail rates, together with inadequate supplies to meet demand, have been among the principal causes. As the largest state in the region, California market trends substantially influence the entire western U.S. The Utilities, which operate principally in Nevada, have been significantly impacted by rising wholesale prices. These conditions have depressed earnings to unprecedented low levels, including operating losses for NVP and SPR, and very low returns on investment for SPPC. If these conditions continue and there is 5 not prompt, decisive and comprehensive relief from legislators and regulators in the state, future earnings and the ability to pay dividends could be in jeopardy. During the hot 2000 summer, an inadequate supply of electricity was available to serve the western U.S. Natural gas prices also increased unexpectedly. While all western utilities are struggling with the rapid rise in prices, the problem has been most acute in California. The two largest California utilities have not been allowed to pass wholesale price increases through to consumers and as a result are experiencing severe liquidity constraints and have each stated publicly that they may file for bankruptcy. As the California utilities can no longer pay for energy, the state of California has stepped into this role. Power producers throughout the west were ordered by the U.S. Department of Energy to provide excess power to California, although that order has now expired. The California State Legislature is pursuing various legislation to resolve this issue. One of the bills signed by California's governor places a moratorium until 2006 on divestiture of any utility owned generation plants serving the California market. This moratorium applies to the sale of SPPC's power plants. While the California crisis impacts the entire west, including SPPC and NVP, Nevada differs in certain respects from California. SPPC and NVP are allowed to enter into bilateral contracts with suppliers and have secured virtually all of their normalized resource needs for 2001. Both NVP and SPPC currently own their own generation plants. Although the Utilities have been in the process of divesting their generation assets, they have negotiated transition power purchase agreements with each purchaser lasting until March 2003, which give the Utilities the ability to purchase the output at 1998 fuel prices. In July 2000, SPPC and NVP entered into a Global Settlement to resolve certain deferred energy and restructuring issues. The Global Settlement allowed both utilities to begin to raise their rates to pay for rising fuel costs. See Nevada Matters in Regulation and Rate Proceedings, later, for further discussion on the Global Settlement. However, the Global Settlement allows rates to increase based on trailing 12-month average costs and is subject to rate caps. As a result, the increases in rates are not keeping pace with the rapid rise in wholesale costs, and the companies are substantially under recovering their fuel and operating costs. As a result, the Utilities filed a Comprehensive Energy Plan (CEP) with the PUCN on January 29, 2001, seeking a further increase in rates, as well as permission to restructure certain contracts and secure long-term energy supplies for consumers. On February 23, 2001, the PUCN authorized the CEP rate increase to begin March 1, 2001, subject to subsequent review and evaluation of the filing. See Nevada Matters in Regulation and Rate Proceedings, later, for further discussion on the CEP. Generation Divestiture SPPC serves customers in the California market and is impacted by legislation passed in California. A recently enacted moratorium on the divestiture of generation by California utilities until 2006 applies to SPPC and may halt or delay SPPC's divestiture efforts as well as the sale of NVP's interest in the Mohave Generating Station in Laughlin, Nevada. In Nevada the state Consumer Advocate has filed a motion seeking a moratorium on divestiture. The Governor of Nevada had directed the PUCN to reevaluate whether divestiture continues to be in the public's interest. In addition, a bill has been introduced in the Nevada legislature that would halt divestiture until at least July 1, 2003. A delay in divestiture may have negative financial implications for the Utilities due to rising fuel costs and foregoing the benefits of the post divestiture generation buyback contracts, unless the PUCN permits recovery of these higher costs. See Generation Divestiture, later, for further discussion. In addition, SPPC's request for an exemption from the requirements of California law requiring approval of the 6 CPUC before divestiture of its plants and our request for approval of the sale was denied, subject to refiling. Regulation and Electric Restructuring The electric industry, which has been in transition toward increased competition over the past several years, is currently the subject of reevaluation nationally as a result of the problems in California and the west. In Nevada during 2000, electric restructuring and the opening of a competitive energy market were twice delayed by the Governor of Nevada. The status of restructuring efforts, including the California issues, influenced the Governor of Nevada in his decision to delay the opening of competition and to establish a committee, the Nevada Electric Energy Policy Committee (NEEPC), to advise him on energy issues. The NEEPC issued its report on January 15, 2001. The Governor included many of its recommendations in his energy protection plan and recommendations to the Nevada legislature. In the 2001 legislative session, restructuring is expected to be a prevalent topic. In addition, the Governor has halted the implementation of restructuring indefinitely until the market stabilizes. See Regulation and Rate Proceedings, later, and Regulatory Events in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, for further discussion regarding restructuring activities and regulatory changes affecting the Utilities. PORTLAND GENERAL ELECTRIC ACQUISITION ------------------------------------- In November 1999 SPR and Enron Corporation (Enron) announced they had entered into a purchase and sale agreement for Enron's wholly owned electric utility subsidiary, PGE. PGE is an electric utility serving more than 700,000 retail customers in northwest Oregon. Upon completion of the transaction, PGE would become a wholly owned subsidiary of SPR. Under terms of the agreement, Enron has agreed to sell PGE to SPR for $2.02 billion to $2.1 billion in cash, depending upon the level of liabilities assumed at the time of close. In addition, $1.0 billion in PGE debt and preferred stock would remain outstanding and be reflected in SPR's consolidated financial statements. In addition to other regulatory approvals discussed below, the PGE acquisition is subject to the approval of the Securities and Exchange Commission (the "SEC") under the Public Utility Holding Company Act ("PUHCA"), and SPR has applied to the SEC to become a registered public utility holding company under PUHCA. In connection with that application, SPR has made certain representations to the SEC regarding the methods of financing the PGE acquisition and regarding the capital structure of SPR following the acquisition. According to those representations, SPR expects to initially finance the transaction primarily through a bank loan or other form of debt. In its application to the SEC, SPR had proposed to increase its consolidated common equity following the acquisition by paying down debt at the utility level with some of the proceeds from the sale of the electric generation assets of the Utilities, the sale of non-strategic assets, the sale of additional common stock, and increased retained earnings from the combined operations of the three utility subsidiaries. In light of the uncertainty related to the sale of the Utilities' generation assets (see Generation Divestiture, later), SPR is evaluating alternative financing plans and capital structures to be presented to the SEC in connection with the financing application which must be approved as a condition for closing. The proposed transaction is subject to other closing conditions, including, without limitation, the receipt of all necessary governmental approvals, including the Federal Energy Regulatory Commission (FERC), the Federal Trade Commission/Department of Justice (FTC/DOJ), the Oregon Public Utility Commission (OPUC), and the Nuclear Regulatory Commission (NRC). SPR's filings have been made, and all state regulatory approvals have been received and only the SEC approval remains at the federal level. As of May 3, 2000, the FTC/DOJ investigation concluded and the waiting period under Hart- 7 Scott-Rodino expired with no action taken. On July 27, 2000, the NRC approved PGE's transfer application filed in January. On October 30, 2000, the OPUC approved SPR's application to acquire PGE. The OPUC approved a September 1 settlement agreement that calls for a six-year price freeze on non-fuel operations and maintenance for PGE customers and a $95 million credit for Oregon consumers. The "acquisition credit" will be shown on monthly power bills as soon as the transaction is complete and will continue through September 30, 2007. PGE will retain its ability to adjust rates to reflect changes in the prices for wholesale electricity and fuel purchased to operate its power plants. On November 21, 2000, the FERC approved the transaction based on a plan that included the sale of the power plants. The purchase and sale agreement between SPR and Enron provides that the agreement may be terminated by either party without liability (unless a pre-existing breach has occurred) if the closing of the transaction has not occurred on or before May 5, 2001. NEVADA POWER COMPANY -------------------- NVP is a Nevada corporation organized in 1921. NVP became a wholly owned subsidiary of Sierra Pacific Resources (SPR) on July 28, 1999. Its mailing address is 6226 West Sahara Avenue, Las Vegas, Nevada 89146. NVP is a public utility engaged in the distribution, transmission, generation, purchase and sale of electric energy in Clark County in southern Nevada. It provides electricity to approximately 611,000 customers in the communities of Las Vegas, North Las Vegas, Henderson, Searchlight, Laughlin and adjoining areas. Service is also provided to Nellis Air Force Base and the Department of Energy at Mercury and Jackass Flats at the Nevada Test Site. See Generation Divestiture, later. NVP has two primary, wholly owned subsidiaries, NVP Capital I and NVP Capital III, both of which are business trusts. NVP Capital I and NVP Capital III were created to issue trust securities in order to purchase junior subordinated debentures of NVP. Business and Competitive Environment NVP's electric business contributed $1.325 billion (100%) of 2000 operating revenues. The system has an annual load factor of approximately 49.3%, which is lower than the industry norm of 50% to 55%. Summer peak loads are driven by air conditioning demand. NVP's peak load increased an average of 7.1% annually over the past five years, reaching 4,325 MW on August 1, 2000. NVP's total electric megawatt-hour (MWh) sales have increased an average of 7.4% annually over the past five years. Winter peak loads are low relative to the summer peak. Winter load above the base amount is driven by air handling in forced air furnaces. NVP's service territory continues to be one of the fastest growing areas in the nation. A significant part of the growth in NVP's electric sales has resulted from new residential, industrial, and gaming customers. 8 NVP's electric customers by class contributed the following toward 2000 and 1999 MWh sales:
MWh Sales (Billed and Unbilled) 2000 1999 --------------------------------- -------------------------------- Residential 7,015,103 36.1% 6,138,436 37.9% Office 1,896,111 9.7% 875,716 5.4% Gaming/Recreation/Restaurants 3,963,286 20.4% 3,009,526 18.6% Wholesale 2,695,922 13.9% 829,551 5.1% Retail 783,467 4.0% 462,918 2.9% All Other & Unclassified 3,098,259 15.9% 4,873,063 30.1% ----------- ------ ----------- ------ TOTAL 19,452,148 100.0% 16,189,210 100.0% =========== ====== =========== ======
Tourism and gaming remain southern Nevada's premier industries. Nearly 38 million tourists visited Las Vegas in 2000, infusing approximately $30 billion into the local economy during the year. During the past two years, several major resorts opened on the Las Vegas Strip, including Bellagio, Mandalay Bay, Paris Las Vegas, The Venetian and Aladdin/Desert Passage. The number of area hotel/motel rooms grew from 119,986 in 1999 to a total of 124,205 at the end of 2000. Currently, Las Vegas is the home of 18 of the world's 20 largest hotels. No mega-resort properties are scheduled to open during 2001. Hotel room growth is expected to be 2.4% during 2001. Upon completion of a 1.3 million square foot expansion of the Las Vegas Convention Center, the Center will have more than 3.2 million square feet of meeting and exhibit space, making it one of the largest facilities of its kind in the world. When the expansion is complete, Las Vegas will have approximately 7.5 million square feet of convention and meeting space citywide. In 2000, more than 3.8 million convention and trade show delegates traveled to Las Vegas, generating more than $4 billion in non-gaming revenue. During 2000, firm and non-firm sales to wholesale customers comprised 13.7% of total energy sales, an increase of 220.1% over the prior year.
MWh Sales 2000 1999 ----------------------------------- ---------------------------------- Firm Sales 283,480 10.52% 363,133 43.80% Non-Firm Sales 2,412,442 89.48% 466,418 56.20% ------------ -------- ------------ ------- Total 2,695,922 100.00% 829,551 100.00% ============ ======== ============ =======
NVP's increase in MWh sales from last year was a result of market conditions and NVP's hedging program. NVP regularly seeks to optimize its daily and hourly portfolio by buying and selling short excess power in the wholesale markets. NVP purchases fixed cost energy at a delivery point where the energy can either be delivered to its control area or traded, should NVP not require the energy. The energy is also traded if replacement energy can be obtained less expensively than transporting the energy to the control area. NVP neither purchases nor sells energy on a speculative basis. Construction Program NVP's construction program and estimated expenditures are subject to continuing review, and are revised from time to time due to various factors, including the rate of load growth, escalation of 9 construction costs, availability of fuel types, changes in environmental regulations, adequacy of rate relief, and NVP's ability to raise necessary capital. Gross construction expenditures for 2000, including allowance for funds used during construction (AFUDC) and contributions in aid of construction were $204.5 million and for the period 1996 through 2000 were $1,167.5 million. Estimated construction expenditures for 2001 and the period from 2002 to 2005 are as follows (dollars in thousands):
2001 2002-2005 Total 5-Year ---------- ------------- -------------- Total construction expenditures $ 214,002 $ 860,796 $ 1,074,798 AFUDC (11,837) (52,135) (63,972) Net salvage, including cost of removal (1,053) (4,214) (5,267) Net customer advances and contributions in aid of construction (26,112) (104,447) (130,559) ---------- ------------- -------------- Total cash requirements $ 175,000 $ 700,000 $ 875,000 ========== ============= ==============
Total construction expenditures estimated for 2001 and the 2002-2005 period consist of the following (dollars in thousands):
Total 2001 2002-2005 5-Year ---- --------- ------ Electric Facilities: Distribution $ 136,756 $ 630,842 $ 767,598 Generation (1) 14,683 0 14,683 Transmission 30,894 181,133 212,027 Other 31,669 48,821 80,490 --------------------------------------------- $ 214,002 $ 860,796 $1,074,798 =============================================
(1) Assumes divestiture of generation assets in 2001. See Generation Divestiture, later. The River Mountain Project has been approved in previous resource plans and may be financed utilizing internally generated cash and/or the proceeds from various forms of debt and preferred securities. River Mountain is a 230kV (kilovolt) joint transmission project with the Colorado River Commission. Total project costs incurred through December 31, 2000, were $26.3 million. Actual costs for 2000 were $21.5 million. Estimated costs for 2001 are $7.9 million, which may be financed utilizing internally generated cash and/or the proceeds from various forms of debt and preferred securities. Also, see Transmission, later, for additional future construction, subject to resource plan approval, that NVP may build to provide transmission service to new generating plants planned for Southern Nevada. Expenditures for these facilities are not reflected in the tables above. 10 Facilities and Operations Total System Part of the restructuring efforts required a change to NVP's demarcation between transmission and distribution facilities. The values shown in this report reflect this change. As of December 31, 2000, NVP's electric transmission facilities consisted of approximately 1,518 overhead pole line miles and 26 substations. Its distribution facilities consisted of approximately 3,416 overhead pole line miles, 10,394 underground cable miles and 129 substations. NVP maintains a wide variety of resources in its generation system. During 2000, NVP generated 53.8% of its total electric energy requirements in its own plants, purchasing the remaining 46.2% as shown below:
Megawatt- Percent Hours of Total ------------- ------------ Company Generation ------------------ Gas/Oil 4,661,326 23.1% Coal 6,187,370 30.7% ------------- ------------ Total Generated 10,848,696 53.8% ------------- ------------ Purchased Power --------------- Long-Term Firm: Hydro 1,188,189 5.9% Utility Purchases 236,700 1.2% Short Term Firm and Spot Purchases 5,378,942 26.7% Non-Utility Purchases 2,511,120 12.5% ------------- ------------ Total Purchased 9,314,951 46.2% ------------- ------------ Total 20,163,647 100.0% ============= ============
NVP's decision to purchase short-term and spot energy is based on the economics of purchasing "as-available" energy when it is less expensive than its own generation. At the time of the 2000 system peak, NVP had purchased firm capacity under long-term contracts with qualifying facilities (QFs) equal to 11% of total peak hour capacity. Risk Management During the year 2000, NVP engaged the services of a risk management consulting company to review its existing programs and practices, to manage energy commodity (electricity, natural gas, coal and oil) price risk, and to assist in the implementation of a revised program. That project led to the development of a new Board of Directors approved Energy Risk Management Policy Manual and implementation of a new risk management system. The Energy Risk Policy Manual sets forth business objectives, organizational structure, performance metrics, reporting requirements, and establishes the Exposure Management Committee (EMC), which is responsible for providing management advice and recommendations on energy risk management-related issues. The EMC met throughout 2000. Load and Resources Forecast NVP's electric customer growth rate was 5.1%, 5.9%, and 5.9% in 2000, 1999, and 1998, respectively. Annual electricity sales reached 19.5 million megawatt- hours in 2000, which represents an 11 increase of 16.6% over 1999. The peak electric demand rose from 3,993 megawatts in 1999 to 4,325 megawatts in 2000. The projections shown below are forecasts of the load to be provided to all of NVP's current customers, and therefore include demand that may actually be met by other electric suppliers if and when open access to alternative suppliers is implemented in Nevada. See Regulation and Rate Proceedings, later. As part of its order approving the merger of SPR and NVP, the PUCN ordered NVP to divest its generation facilities to enhance competition in a deregulated environment. See Generation Divestiture, later. Until such time as those sales are completed, NVP will continue to provide energy through generation and purchased power to meet peak loads. NVP's actual total system capability and peak loads for 2000, and as estimated for summer peak demand through 2002 (assuming no curtailment of supply or load and normal weather conditions), are indicated below:
Capacity at 2000 Peak Forecast Summer Peak ------------------------------------------------------------------- MW % 2001 2002 ------------------------------------------------------------------- NVP Generation: Existing (1) 1,728 36% 0 0 ------------------------------------------------------------------- Purchases Long/Short-Term Firm (2) 2,344 48% 4,359 (7) 3,209 (7) Non-Utility Generators (4) 538 11% 515 515 Wholesale Sales (6) 44 1% 30 31 ------------------------------------------------------------------- Subtotal 2,926 60% 4,844 3,693 ------------------------------------------------------------------- Additional Required (3) 190 4% 305 1,689 Total System Capacity 4,844 100% 5,149 5,382 =================================================================== 4,325 89% 4,597 4,805 Net System Peak (5) Planning Reserves 519 11% 552 577 ------------------------------------------------------------------- Total 4,844 100% 5,149 5,382 =================================================================== Growth over previous year 6.3% 4.5%
(1) Assumes divestiture is complete by peak season 2001. See Generation Divestiture, later. (2) Long-term purchases include NVP's allotment of Hoover Dam energy. Values are net of losses. (3) Includes potential short-term firm purchases that are not under contract. Values shown represent purchases within existing transmission system limits. (4) Includes Sunpeak units, which will be divested with NVP's generating units. (5) The system peak shown for 2000 is the actual system peak of 4,325 MW, which occurred on August 1, 2000. (6) On peak wholesale to Silver State and Needles. (7) Includes agreements to purchase output of plants to be divested and other contracted firm purchases. NVP plans its system capacity needs in accordance with the Western Systems Coordinating Council (WSCC) reliability criteria, which recommends planning reserves in excess of required operating reserves. "Additional Required" represents the additional, uncommitted capacity needed in order to maintain an adequate reserve margin consistent with the WSCC planning reserve criteria. These additional reserves will be met, if needed, with short-term purchases to the extent available through 2002. 12 Generation The following is a list of NVP's share of generation plants (except Reid Gardner No. 4, see note (4) below) including the megawatt (MW) summer net capacity, the type and fuel used to generate, and the year(s) that the unit(s) was (were) installed.
Number of MW Name Type Fuel Units Capacity Years(s) Installed ---------------------------------------------------------------------------------------------------- Clark Station (1) Steam Gas/Oil 3 175 1955, 1957, 1961 Combustion Turbine Gas/Oil 1 50 1973 Combined Cycles (2) Gas/Oil 6 462 1979, 1979, 1980, 1982, 1993, 1994 --------------------- Total Clark Station 10 687 Reid Gardner (3) (4) Steam Coal 4 605 1965, 1968, 1976, 1983 Navajo (5) Steam Coal 3 255 1974 Mohave (6) Steam Coal 2 196 1971 Sunrise Steam Gas/Oil 1 80 1964 Combustion Turbine Gas/Oil 1 69 1974 --------------------- Total Sunrise 2 149 --------------------- Harry Allen Combustion Turbine Gas/Oil 1 72 1995 --------------------- Grand Total NVP 22 1964 =====================
(1) Clark Station Units Nos. 7 & 8 were on forced outages due to generator damage between May 8 through July 15 (for Unit No. 7) or through August 24 (for Unit No. 8). The damage to the unit and the resulting lost production were covered by insurance; however, the amount of coverage available is currently in dispute. (2) The combined cycles at Clark Station each consist of one steam turbine and two combustion turbines for a total of six generating units. (3) Reid Gardner Unit No. 2 was on a forced outage due to generator damage between July 16 through July 31. The damage to the unit and the resulting additional cost of purchased power, above the deductibles, are covered by insurance. (4) Reid Gardner Unit No. 4 is owned by the California Department of Water Resources ("CDWR") (67.8%) and NVP (32.2%). NVP is the operating agent. Contractually, NVP is entitled to receive 24 MW of base load capacity and 226 MW of peaking capacity. NVP is entitled to use 100% of the unit's peaking capacity for 1,500 hours each year and is entitled to 9.6% of the first 250 MW of capacity and associated energy. (5) This represents NVP's 11.3% undivided interest in the Navajo Generating Station as tenant in common without right of partition with five other non- affiliated utilities. (6) This represents NVP's 14% undivided interest in the Mohave Generating Station as tenant in common without right of partition with three other non-affiliated utilities, less operating restrictions. See Generation Divestiture, later. Purchased Power NVP maintains and utilizes a diverse portfolio of resources with the objective of minimizing its net average system operating costs. These resources consist of contracted and spot market supplies, as well as its own generation. During the last several years, NVP has experienced a dramatic increase in 13 the price of market energy, compared to previous years. Some of this increase is reflective of the overall increase in electricity costs throughout the country, the changing of regulatory environments and the opening of new and/or deregulated markets. See Industry and Regional Problems Affecting the Utilities, earlier. NVP is a member of the Western Systems Power Pool and the Southwest Reserve Sharing Group (SWRSG). NVP's membership in the SWRSG has allowed it to network with other utilities in an effort to more efficiently use its resources in the sharing of responsibilities for reserves. NVP purchases both forward firm energy (typically in blocks) and spot market energy based on economics, operating reserve margins and unit availability. NVP has been able to efficiently manage its growing loads by utilizing its generation resources in conjunction with buying and selling opportunities in the market. NVP purchases Hoover Dam power pursuant to a contract with the State of Nevada, which became effective June 1, 1987, and will continue through September 30, 2017. NVP's allocation of hydro-electric capacity is 235 MWs. NVP has a contract to purchase 222 MWs from Nevada Sunpeak Limited Partnership, an independent power producer. The contract became effective June 8, 1991 and will continue through May 31, 2016. According to the regulations of the Public Utility Regulatory Policies Act, NVP is obligated, under certain conditions, to purchase the generation produced by small power producers and cogeneration facilities at costs determined by the appropriate state utility commission. Generation facilities that meet the specifications of the regulations are known as qualifying facilities (QFs). As of December 31, 2000, NVP had a total of 305 MWs of contractual firm capacity under contract with four QFs. All QF contracts currently delivering power to NVP at long-term rates have been approved by the PUCN and have QF status as approved by the FERC. The QFs are as follows:
Contract Contract Net Capacity Qualifying Facility Start End (MW) ----------------------------------------------------------- Saguaro Power Company 10/17/91 04/30/22 90 Nevada Cogeneration Associates #1 06/18/92 04/30/23 85 Nevada Cogeneration Associates #2 02/01/93 04/30/23 85 Las Vegas Cogeneration Limited Partnership 05/10/94 05/31/24 45 ----- Total 305 =====
Energy purchased by NVP from the QFs constituted 27% of the purchase power requirements and 12.5% of the net system requirements during 2000. All of the QFs are cogenerators providing steam for various products and businesses. Transmission NVP's existing transmission lines are primarily confined within Clark County, Nevada. Four 230 kilovolt (kV) transmission lines connect NVP to the Western Area Power Administration's transmission facilities at Henderson and Mead Substations. Three 230 kV lines connect NVP to the Los Angeles Department of Water and Power's transmission facilities at McCullough Substation. A 345 kV 14 line connects NVP to PacifiCorp at the Utah-Nevada state line. Also, NVP has two, 500/230 kV transformers that connect NVP to the Navajo Transmission System at the Crystal Substation. Finally, NVP also has ownership of two, 500 kV transmission lines that transmit power from the Mohave and Navajo Generating Station, respectively, to the NVP system. The River Mountains Project is a transmission project developed in partnership with the Colorado River Commission of Nevada. NVP's portion of the project consists of two, 230 kV transmission lines built along separate transmission corridors between the Mead Substation and NVP's new Equestrian Substation. In addition, NVP is building a 230 kV transmission line between the Equestrian Substation and the Faulkner Substation. The project has a spring 2001 in-service date and increases import capability by 350 MWs. The estimated project cost is $40.4 million. NVP received approval from the PUCN to construct two transmission projects proposed in NVP's 2000 Resource Plan. The Faulkner Substation to Tolson Substation 230 kV project and the Tolson Substation to Arden Substation 230 kV upgrade project are both internal, NVP reinforcements with 2003 and 2004 in- service dates, respectively. Together, the two projects increase NVP's import capability by 380 MWs. The total estimated project costs are $10 million. Due to the supply shortage in the western U.S., several independent power producers have proposed the construction of new generating plants in southern Nevada, and have requested transmission service from NVP. NVP has committed to construct this transmission infrastructure in furtherance on its on-going business plan. The key project in this regard is the construction of a 500 kV transmission system consistent with its tariff and FERC pricing policies. See FERC Matters in Regulation and Rate Proceedings, later, for a discussion of regional transmission issues. Fuel Availability NVP's 2000 fuel requirements for electric generation were provided by natural gas, coal and oil. The average costs of coal, gas and oil for energy generation per million British thermal units (MMBtu) for the years 1996 - 2000, along with the percentage contribution to total fuel requirements were as follows:
--------------------------------------------------------------------- Average Consumption Cost & Percentage Contribution to Total Fuel Requirements Gas Coal Oil --- ---- --- $/MMBtu Percent $/MMBtu Percent $/MMBtu Percent ------- ------- -------- -------- ------- ------- 2000 4.93 42.6% 1.22 57.2% 7.33 0.1% 1999 2.27 40.6% 1.15 59.3% 4.01 0.1% 1998 2.35 33.0% 1.39 67.0% 3.96 * 1997 2.25 33.0% 1.39 67.0% 3.35 * 1996 1.95 24.0% 1.44 76.0% 3.48 * * Oil was less than .1% of consumption ---------------------------------------------------------------------
For a discussion of the change in fuel costs, see Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations. 15 Coal delivered to the Reid Gardner Station originates from various mines in the Utah coalfields and is delivered to the station via the Union Pacific Railroad. Partial requirements for coal supplies are under contract for various terms up to 2007, with the remainder of 2001's requirements purchased from the spot market under four one-year contracts. NVP's long-term coal supply agreement with RAG Coal Sales of America, Inc. is supplied from its Willow Creek Mine in Carbon County, Utah which experienced an explosion and fire on July 31, 2000, and is currently under an ongoing force majeure. No deliveries under this agreement will be scheduled for 2001 and NVP has replaced these volumes with spot market purchases. The Union Pacific Rail Transportation contract provides for deliveries from the Provo, Utah interchange as well as various mines in the Price, Utah area to the Reid Gardner Station in Moapa, Nevada. This contract was effective January 1, 1996, and has been extended through December 31, 2001. The Utah Railway contract originates the remainder of NVP's Price, Utah area supplies. This contract has been extended through December 31, 2001. All of NVP's rail transportation contracts contain certain tonnage requirements and railroad service criteria. Coal for both the Mohave and Navajo Stations is obtained from surface mining operations conducted by Peabody Coal Company on portions of the Black Mesa in Arizona within the Navajo and Hopi Indian reservations. The supply contracts with Peabody extend to December 31, 2005, for Mohave and to June 1, 2011, for Navajo, each contract having an option to extend for an additional 15 years. NVP purchases natural gas on a firm, fixed and indexed price basis from the Rocky Mountain, San Juan or Permian Supply Basins. Natural gas is transported to the Clark and Sunrise stations via El Paso Natural Gas Company from the San Juan and Permian Basins and by Kern River Gas Transmission Company from the Rocky Mountain Basin. NVP has not entered into any long-term interstate transportation contracts in anticipation of the sale of its generation assets. Local natural gas transportation service to Clark and Sunrise Stations is provided under a 32-year transportation services contract with Southwest Gas Company signed in 1995. This contact provides firm service and contains certain operating and nominating provisions. The Harry Allen Station is directly connected to Kern River Pipeline. Oil provides a secondary fuel for Clark, Sunrise and Harry Allen Stations and is used in the igniters at Reid Gardner. Regulation and Rate Proceedings See Regulation and Rate Proceedings, later, for a discussion of regulatory matters affecting NVP. SIERRA PACIFIC POWER COMPANY ---------------------------- SPPC is a Nevada corporation organized in 1965 as a successor to a Maine corporation organized in 1912. SPPC became a wholly owned subsidiary of Sierra Pacific Resources on May 31, 1984. Its mailing address is Post Office Box 10100 (6100 Neil Road), Reno, Nevada 89520-0024. SPPC is a public utility primarily engaged in the distribution, transmission, generation, purchase and sale of electric energy. It provides electricity to approximately 309,500 customers in a 50,000 square mile service area in western, central and northeastern Nevada, including the cities of Reno, 16 Sparks, Carson City, Elko, and a portion of eastern California, including the Lake Tahoe area. In 2000, electric revenues were 85.0% of SPPC's total revenue. See Generation Divestiture, later. SPPC also provides natural gas service in Nevada to approximately 115,000 customers in an area of about 600 square miles in Reno/Sparks and environs. SPPC also supplies water service in Nevada to about 73,000 customers in the Reno/Sparks metropolitan area. SPPC has entered into an agreement to sell its water business. In 2000, natural gas revenues were 9.6% and water revenues were 5.4% of SPPC's total revenues. On January 15, 2001, SPR's Board of Directors approved a definitive agreement to sell SPPC's water business to the Truckee Meadows Water Authority ("TMWA") for $350 million. Of the total purchase price, $342 million is for the water business assets and $8 million is for associated hydroelectric generation assets. The transactions are expected to close in the second quarter of 2001. See "Sale of Water Business" section that follows. SPPC has four primary, wholly owned subsidiaries: GPSF-B, Pinon Pine Corp. (PPC), Pinon Pine Investment Co. (PPIC), and Sierra Pacific Power Capital Trust I. GPSF-B, PPC and PPIC, collectively, own Pinon Pine Company, L.L.C., which was formed to take advantage of federal income tax credits available under (S) 29 of the Internal Revenue Code associated with the alternative fuel (syngas) produced by the coal gasifier located at the Pinon Pine facility. Sierra Pacific Power Capital Trust I was created to issue trust securities in order to purchase SPPC's junior subordinated debentures. Business and Competitive Environment SPPC's electric business contributed $893.8 million (89.9%) of SPPC's 2000 revenues from continuing operations. Electric system peaks typically occur in the summer, while winter peaks run nearly as high. The system has an annual load factor of approximately 68%, which is higher than the industry norm of 50% to 55%. Winter peak loads are primarily driven by increased demand for space heating, demand for air movement (with forced air gas and oil furnaces), and ski resort demands (hotels, lifts, etc.). Summer peak loads are primarily driven by cooling equipment demand (including air conditioning demand) and irrigation pumping. SPPC's peak load increased an average of 6.5% annually over the past five years, reaching 1,577 MW on July 31, 2000. SPPC's total electric megawatt- hour sales have increased an average of 11.7% annually over the past five years. The mining and wholesale sectors comprise the majority of this growth. SPPC's electric customers by class contributed the following toward 2000 and 1999 MWh sales:
MWh Sales 2000 1999 ------------------------ ------------------------- Residential 2,042,704 16.4% 1,998,174 19.6% Commercial and Industrial: Mining 2,720,018 21.9% 2,716,579 26.6% Offices/Schools/Government 1,108,988 8.9% 1,128,189 11.1% Resorts & Recreation 780,526 6.3% 768,750 7.5% Manufacturing/Warehouse 795,728 6.4% 771,733 7.6% Wholesale 3,590,648 28.9% 1,695,420 16.6% All Other 1,396,049 11.2% 1,124,091 11.0% ----------- ----- ----------- ----- Total 12,434,661 100.0% 10,202,936 100.0% =========== ===== =========== =====
17 According to the Nevada Division of Minerals statistics, Nevada leads the nation in gold production, accounting for approximately 74% of all U.S. production and 10% of world production, ranking it the third largest gold producer in the world behind South Africa and Australia. It is estimated that Nevada gold production for 2000 was approximately 8.5 million ounces. A majority of Nevada's gold mines are customers of SPPC. Currently, known gold reserves at existing mines in Nevada total approximately 80 million ounces, the majority of the nation's known gold reserves. These reserves are sufficient to continue production at current rates for the next decade. During 2000, world gold prices ranged from approximately $264 per ounce to $316 per ounce. Production costs continue to vary greatly at Nevada mines, along with profitability. Industry reports indicate many Nevada gold mines have a production cost of less than $250 per ounce, with some of the larger mines producing within the $150 to $200 per ounce range. In addition, low gold prices may shorten the expected mine lives of certain Nevada properties as lower grade ore becomes uneconomic to mine. SPPC's territory also has a variety of other mineral producing mines. Approximately 23 million ounces of silver were produced in 2000, worth about $114 million, with approximately 100 million ounces of silver resources identified in the State. Silver demand exceeded new supply for most of the 1990s, drawing down inventories built up in the 1980s. Other minerals produced in Nevada include copper, lithium, mercury, barite, diatomite, gypsum, and lime, valued at over $134 million. SPPC has seven long-term power sales agreements with major mining customers for terms of at least five years. The final contract expires in 2005. One of these customers has provided SPPC with two years' notice of termination. Five of these agreements have been reviewed and approved by the PUCN as part of SPPC's new tariff structure designed for major customers. These mining agreements secure over 236 megawatts of present and future mining load, or approximately $78 million in annual revenues, which is 8.7% of 2000 electric operating revenues. The agreements require that customers maintain minimum demand and load factor levels, and include termination charge provisions to recover all of SPPC's customer-specific facilities investment. On February 9, 2001, Newmont Mining Corporation announced that it signed a Letter of Intent with El Paso Merchant Energy Company, a subsidiary of El Paso Corporation, to negotiate a 15-year power purchase agreement for 150 megawatts of a proposed 480-megawatt power plant near Carlin, NV. The power project, to be owned by El Paso, is expected to be a major customer for the proposed 291- mile Ruby Pipeline project sponsored by another El Paso Corporation subsidiary, Colorado Interstate Gas Company. SPPC and Newmont have also executed a Memorandum of Understanding that will facilitate the ability of this proposed new plant to market electricity directly to anchor retail customers within SPPC's service territory based upon subsequent regulatory approval. Currently, Newmont gets 110 of the 175 megawatts of power it uses annually from SPPC. The resorts and recreation group consists of hotels, casinos, and ski resorts. This major customer segment comprises 6.3% of the total electric system retail MWh sales. Although tourism and gaming continue to be key contributors to the local economy, northern Nevada has seen the closure of some of the smaller family owned casinos. Larger gaming properties in downtown Reno are working together to create a destination that appeals to customers with a full menu of entertainment. A large older casino has been completely renovated with an upscale interior that is expected to open during the second quarter of 2001. Outside of the downtown area, gaming properties have completed large expansions. 18 Proposition 5 in California, which liberalized Indian reservation gaming operations, had been predicted to cause a decline in Reno's gaming revenues once implemented. Northern Nevada casinos have not seen this impact, but continue to evaluate and implement competitive strategies to expand their entertainment portfolio. These strategies include packaging entertainment value, customer comfort, and reasonable pricing, with the natural attraction of the Sierra Nevada geographic location. The manufacturing and warehousing customer segment group continues at a high growth rate slightly exceeding the resorts and recreation customer segment for 2000. A major factor for business relocations is the lack of personal income taxes and inventory taxes in Nevada coupled with easy access to air, rail and road transportation essential to manufacturing and warehousing businesses. Northern Nevada has most recently been a destination of choice for the high- technology industry, which will result in a continued increase in sales to the manufacturing and warehousing customer segment. In 2000, SPPC solidified working relationships within the business community recruiting industries in targeted sectors such as plastic manufacturers and hi-technology companies. SPPC's MWh sales to wholesale customers have increased 111.8% over the past year. During 2000, firm and non-firm sales to wholesale customers comprised 28.9% of total energy sales. MWh Sales 2000 1999 -------------------- --------------------- Firm Sales 3,342,435 93.1% 1,571,853 92.7% Non-Firm Sales 248,213 6.9% 123,567 7.3% ---------- ----- ---------- ----- Total 3,590,648 100.0% 1,695,420 100.0% ========== ===== ========== ===== SPPC's increase in MWH sales from last year was a result of market conditions and SPPC's hedging program. SPPC regularly seeks to optimize its daily and hourly portfolio by buying and selling short excess power in the wholesale markets. SPPC purchases fixed cost energy at a delivery point where the energy can either be delivered to its control area or traded, should SPPC not require the energy. The energy is also traded if replacement energy can be obtained less expensively than transporting the energy to the control area. SPPC neither purchases nor sells energy on a speculative basis. 19 Construction Program Gross construction expenditures for 2000, including allowance for funds used during construction and contributions in aid of construction, were $155.3 million and for the period 1996 through 2000 were $831.9 million. Estimated construction expenditures for 2001 and the period 2002-2005 are as follows (dollars in thousands):
Total 2001 2002-2005 5-Year ----------------------------------------- Electric facilities $ 90,963 $ 468,530 $559,493 Water facilities 24,911 0 24,911 Gas facilities 12,266 45,452 57,718 Common facilities 9,562 28,310 37,872 ----------------------------------------- Total construction expenditures $137,702 $ 542,292 $679,994 ========================================= AFUDC (2,340) (11,635) (13,975) Net salvage, including cost of removal (120) (400) (520) Net customer advances and contributions in aid of construction (10,242) (15,320) (25,562) ----------------------------------------- Total cash requirements $125,000 $ 514,937 $639,937 =========================================
Total construction expenditures estimated for 2001 and the 2002-2005 period, for each segment of SPPC's business, consist of the following (dollars in thousands):
Total 2001 2002-2005 5-Year --------------------------------------------- Electric Facilities: Distribution $ 57,376 $ 253,705 $311,081 Generation (1) 8,425 0 8,425 Transmission 11,321 189,707 201,028 Other 13,841 25,118 38,959 ---------------------------------------------- $ 90,963 $ 468,530 $559,493 ---------------------------------------------- Water Facilities (2): Treatment and Supply $ 5,654 $ 0 $ 5,654 Distribution 19,077 0 19,077 Other 180 0 180 ---------------------------------------------- $ 24,911 $ 0 $ 24,911 ---------------------------------------------- Gas Facilities: Distribution $ 11,649 $ 43,252 $ 54,901 Other 617 2,200 2,817 ---------------------------------------------- $ 12,266 $ 45,452 $ 57,718 ---------------------------------------------- Common Facilities $ 9,562 $ 28,310 $ 37,872 ---------------------------------------------- TOTAL $137,702 $ 542,292 $679,994 ==============================================
(1) Assumes divestiture of generation assets in 2001. See Generation Divestiture, later. (2) Assumes sale of water business in 2001. See Sale of Water Business, later. The Alturas Intertie Project, which went into service in December 1998, is a 345 kV transmission line from northern California to Reno. Total project costs incurred through December 31, 2000, were $156.2 million. Actual costs incurred in 2000 were $3.0 million. Estimated costs for 2001 are $1.0 million. The Falcon Transmission Project is a 345kV transmission line within 20 Northern Nevada. Total project costs incurred through December 31, 2000, were $5.2 million. Actual costs incurred in 2000 were $2.8 million. Estimated costs for 2001 are $6.4 million. SPPC's construction program and estimated expenditures are subject to continuing review, and are revised from time to time due to various factors, including the rate of load growth, escalation of construction costs, availability of fuel types, changes in environmental regulations, adequacy of rate relief, and SPPC's ability to raise necessary capital. Facilities and Operations Total System As of December 31, 2000, SPPC's electric transmission and distribution facilities consisted of approximately 13,000 overhead pole line miles, 4,500 underground cable miles and 270 substations. SPPC maintains a wide variety of resources in its generation system. During 2000, SPPC generated 43.9% of its total electric energy requirements in its own plants, purchasing the remaining 56.1% as shown below: Megawatt- Percent Hours of Total ---------- -------- Company Generation ------------------ Gas/Oil 3,754,065 28.6% Coal 1,954,691 14.9% Hydro 46,613 0.4% ---------- -------- Total Generated 5,755,369 43.9% ---------- -------- Purchased Power --------------- Utility Purchases: Long-Term Firm 718,361 5.5% Short-Term Firm 5,759,656 43.9% Spot Market 29,620 0.2% Non-Utility Purchases: Geothermal 704,182 5.4% Other 113,404 0.9% Transmission & Balancing 20,482 0.2% ---------- -------- Total Purchased 7,345,705 56.1% ---------- -------- Total 13,101,074 100.0% ========== ======== SPPC's decision to purchase spot market energy is based on the economics of purchasing "as-available" energy when it is less expensive than its own generation. At the time of the 2000 system peak, SPPC had purchased firm capacity under long-term contracts with other utilities and qualifying facilities equal to 10% of total peak hour capacity. In 2000, most of SPPC's non-utility generation came from QFs, except for 17,797 megawatt hours, which came from two small power producers. Risk Management During the year 2000, SPPC engaged the services of a risk management consulting company to review its existing programs and practices, to manage energy commodity (electricity, natural gas, coal and oil) price risk, and to assist in the implementation of a revised program. That project led to the development of a new Board of Directors approved Energy Risk Management Policy Manual and implementation of a new risk management system. The Energy Risk Policy Manual sets forth business 21 objectives, organizational structure, performance metrics, reporting requirements, and establishes the Exposure Management Committee (EMC), which is responsible for providing management advice and recommendations on energy risk management related issues. The EMC met throughout 2000. Load and Resources Forecast SPPC's electric customer growth rate was 2.5%, 2.8%, and 2.8% in 2000, 1999 and 1998, respectively. Annual electricity retail sales reached 8.8 million megawatt-hours in 2000. Peak electric demand rose from 1,470 megawatts in 1999 to 1,577 megawatts in 2000. The projections shown below are forecasts of the load to be provided to all of SPPC's current customers, and therefore, include demand that may actually be met by other electric suppliers if and when open access to alternative suppliers is implemented in Nevada. See Regulation and Rate Proceedings, later. As part of its order approving the merger of SPR and NVP, the PUCN ordered SPPC to divest its generation facilities to enhance competition in a deregulated environment. See Generation Divestiture, later. Until such time as those sales are completed, SPPC will continue to provide energy through generation and purchase power to meet both summer and winter peak loads. SPPC's actual total system capability and peak loads for 2000, and as estimated for summer peak demand through 2002 (assuming no curtailment of supply or load and normal weather conditions), are indicated below:
Capacity at 2000 Peak Forecast Summer Peak -------------------------------------------------------------- MW % 2001 2002 -------------------------------------------------------------- Company Generation: Existing (1) 1,062 61% 28 30 -------------------------------------------------------------- Purchases: Long/Short-Term Firm (2) 575 33% 1,439 1,164 Interruptible/Wheeling/Losses 5 0% 2 1 Non-Utility Generators 98 6% 99 99 -------------------------------------------------------------- Subtotal 678 39% 1,540 1,264 -------------------------------------------------------------- Additional Required 0 0% 187 545 Total System Capacity 1,740 100% 1,755 1,839 -------------------------------------------------------------- -------------------------------------------------------------- Net System Peak Demand (3) 1,577 90% 1,564 1,620 Planning Reserve 181 10% 191 219 -------------------------------------------------------------- Total Requirement 1,758 100% 1,755 1,839 ============================================================== Growth over previous year (0.2%) 4.8%
(1) Assumes divestiture is complete by peak season 2001. See Generation Divestiture, later. Kings Beach and Portola diesels and hydro plants remain under SPPC's control after power plant divestiture. 22 (2) Value is net of losses and includes committed short-term firm block purchases. Values shown represent purchases within existing transmission system limits. Includes actual economy energy purchases during the 2000 peak and is net of sales. (3) The system peak shown for 2000 is the actual system peak of 1,577 MW, which occurred on July 31, 2000. SPPC plans its system capacity needs in accordance with the WSCC reliability criteria, which recommends planning reserves in excess of required operating reserves. The "Additional Required" represents the additional, uncommitted capacity needed in order to maintain adequate reserve margin consistent with the WSCC planning reserve criteria. These additional reserves will be met, if needed, with short-term purchases through 2002 to the extent available. Generation The following is a list of SPPC's share of generation plants including the megawatt (MW) summer net capacity, the type and fuel used to generate, and the year(s) that the unit(s) was (were) installed.
Number MW Name Type Fuel of Units Capacity Years(s) Installed --------------------------------------------------------------------------------------------------------------- Valmy (1) (2) Steam Coal 2 266 1981, 1985 Tracy Steam Gas/Oil 3 244 1963, 1965, 1975 Pinon (3) Combined Cycle (4) Gas 1 89 1996 Clark Mtn. CT's Combustion Turbine Gas/Oil 2 138 1994 Ft. Churchill Steam Gas/Oil 2 226 1968, 1971 Other (5) Gas Turbine, Hydro Gas/Oil, Propane 33 82 1899-1970 ------ ------ Grand Total SPPC 43 1045 ====== ======
(1) SPPC is the operator and owns an undivided 50 percent interest in the Valmy plant. Idaho Power Company owns the remainder. The capacities shown above for the Valmy plant represent SPPC's share only. SPPC owns 100 percent of all of its remaining electric generation plants. (2) Valmy Unit No. 2 was on forced outage due to boiler problems from August 29 through September 14. The damage to the unit and the resulting additional cost of purchased power, above the deductibles, are covered by insurance; however, the amount of coverage available is currently in dispute. (3) Pinon is part of the Pinon Pine Integrated Coal Gasification Combined Cycle power plant. This project was part of the Department of Energy's Clean Coal Demonstration Program. Although the coal gasification portion of the facility is in the start-up phase, the unit has been operating on natural gas since 1996. (4) The combined cycle at Pinon consists of one combustion turbine and one steam turbine. (5) The 4 hydro generating units are included in the sale of SPPC's water business announced in January 2001. See Sale of Water Business, later. See Generation Divestiture, later. Purchased Power SPPC continues to manage a diverse portfolio of contracted and spot market supplies, as well as its own generation, with the objective of minimizing its net average system operating costs. During 23 2000, SPPC experienced a dramatic increase in the price of market energy, compared to previous years. Some of this increase is reflective of the overall increase in electricity costs throughout the country, the changing of regulatory environments and the opening of new and/or deregulated markets. See Industry and Regional Problems Affecting the Utilities, earlier. SPPC's system peak shown for 2000 is the actual system peak of 1,577 MW, which occurred on July 31, 2000. SPPC is a member of the Northwest Power Pool and Western Systems Power Pool. These pools have provided SPPC further access to spot market power in the Pacific Northwest and the Southwest. In turn, SPPC's generation facilities provide a backup source for other pool members who rely heavily on hydroelectric systems. SPPC has an agreement with PacifiCorp's Utah division for delivery of firm power, which also provides added access to spot market power. SPPC purchases hydroelectric and thermal generation spot market energy, by the hour, based upon economics and system import limits. Also purchased during peak load periods is firm energy as required to supply load and maintain adequate operating reserve margins. As off-system energy costs increase, SPPC supplies a higher percentage of its native load utilizing its fossil fuel generation but is still required to buy peaking energy from the market. Currently, SPPC has contracted for a total of 75 MW of long-term firm purchased power from the utility supplier listed below. SPPC's firm purchase power contract contains minimum purchase obligations. Meeting these minimums has not been a problem for SPPC in the past, and is not expected to be a problem in the future. Contract Operation Termination Minimum Contract Party Capacity Date Date Capacity --------------------------------------------------------------------------- PacifiCorp 75 MW June 1989 Feb 28, 2009 70% According to the Public Utility Regulatory Policies Act, SPPC is obligated, under certain conditions, to purchase the generation produced by small power producers and co-generation facilities at costs determined by the appropriate state utility commission. Generation facilities that meet the specifications of the regulations are known as qualifying facilities. As of December 31, 2000, SPPC had a total of 109 MW of maximum contractual firm capacity under 15 contracts with QFs. SPPC also had contracts with three projects at variable short-term avoided cost rates. All QF contracts currently delivering power to SPPC at long-term rates have been approved by either the PUCN or the California Public Utility Commission (CPUC), and have QF status as approved by the FERC. One long-term QF contract terminates in 2006, one terminates in 2039, and the rest terminate between 2014 and 2022. Energy purchased by SPPC from QFs constituted 10% of the net system requirements during 2000. These contracts continue to provide useful diversity for SPPC in meeting its peak load. All the QFs from which SPPC makes firm purchases are either geothermal (87%), hydroelectric or biomass. The actual QF firm capacity output under contract was 64 MW during the summer of 2000. The actual QF output for all non-utility generator deliveries during the summer 2000 peak was 80 MW. Transmission In planning its transmission capacity, SPPC considers generation and purchased power options, as well as the requirements for providing retail and wholesale transmission services. 24 SPPC's existing transmission lines extend some 300 miles from the crest of the Sierra Nevada in eastern California, northeast to the Nevada-Idaho border at Jackpot, Nevada, about 160 miles from Reno northwest to Alturas, California, and 250 miles from the Reno area south to Tonopah, Nevada. A 230 kilovolt transmission line connects SPPC to facilities near the Utah-Nevada state line, which in turn interconnects SPPC to Utah Power facilities. A 345 kV transmission line connects SPPC to Idaho Power facilities at the Idaho - Nevada state line. A 345 kV line connects SPPC to the Bonneville Power Administration's facilities near Alturas, California. SPPC also has two 120 kV lines and one 60 kV line that interconnect with Pacific Gas & Electric on the west side of SPPC's system at Donner Summit, California. Two 60 kV transmission ties allow wheeling of up to 14 MW of power from the Beowawe Geothermal Project, which is located within SPPC's service area, to Southern California Edison. These two minor interties are available for use during emergency conditions affecting either party. The transmission intertie system provides access to regional energy sources. The Falcon Project is a 185-mile 345kV line connecting SPPC's Falcon Substation to SPPC'S Gonder Substation. The Falcon Project improves system import and export capabilities and enables SPPC to provide transmission service between Idaho, Utah, and the northwest. A Right-of-Way application was submitted to the Bureau of Land Management (BLM) in December 1998, and Electric Resource Plan approval was received from the PUCN in April 1999. In October 1999 SPPC received a letter from the BLM requiring the preparation of an Environmental Impact Statement (EIS). Current activities include completion of environmental field surveys, hiring a consultant to prepare the EIS, and WSCC rating studies. The EIS process should continue until July 2001, which should translate to a project in-service date in June 2003. Annual costs for 2000 were $2.83 million, total costs as of December 31, 2000, were $5.25 million and the estimated net cash total cost is $99.9 million. See FERC Matters in Regulation and Rate Proceedings, later, for a discussion of regional transmission issues. Fuel Availability SPPC's 2000 fuel requirements for electric generation were provided by natural gas, coal, and oil. The average costs of coal, gas and oil for energy generation per million British thermal units (MMBtu) for the years 1996-2000, along with the percentage contribution to total fuel requirements were as follows:
------------------------------------------------------------------------------------------------------------- Average Consumption Cost & Percentage Contribution to Total Fuel Requirements Gas Coal Oil --- ---- --- $/MMBtu Percent $/MMBtu Percent $/MMBtu Percent ------- ------- ------- ------- ------- ------- 2000 4.99 66.6% 1.51 32.2% 7.62 1.2% 1999 2.71 62.3% 1.46 37.3% 3.41 0.4% 1998 2.12 60.7% 1.56 39.0% 3.96 0.3% 1997 2.03 62.0% 1.80 37.0% 3.35 1.0% 1996 2.10 61.0% 1.88 37.0% 3.48 2.0% -------------------------------------------------------------------------------------------------------------
For a discussion of the change in fuel costs, see Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations. 25 SPPC's long-term contract with Black Butte Coal Company for coal shipments to Valmy from the mine near Rock Springs, Wyoming, remains in effect until June 30, 2007, or until all volume requirements under the contract are delivered and/or canceled. Due to previous accelerated purchases and cancellations and continuing cancellations of minimum monthly volume obligations, SPPC projects it will fully satisfy all volume requirements and that termination of the contract will occur sometime in early to mid-2002. SPPC's long-term coal contract with Canyon Fuel Company, LLC (Canyon), which provides coal for Valmy from Canyon's SUFCO mine in Central Utah, expires on June 30, 2003. This contract also contains minimum volume requirements that SPPC expects to meet each year until termination. The current owner of the SUFCO mine is Arch Coal, Inc., which acquired ARCO Coal (the previous owner of the Canyon properties, including SUFCO) on June 1, 1998. During 2000, several short-term agreements for the purchase of spot market coal were in place, with two of these agreements extending into 2001. The source of this coal is the Uinta Basin of Utah. These spot market purchases supplement base volume requirements under SPPC's long-term coal contracts at a cost approximately one-half that of contract coal. As of December 31, 2000, Valmy's coal inventory level was 154,796 tons, or approximately 27 days of consumption at 100% capacity. SPPC normally targets an average annual coal stockpile sufficient to provide a 30 day supply at full load. During 2000, transportation of coal to Valmy was provided by the Union Pacific Railroad (UP) under a 3-year agreement effective June 1, 1998. This agreement was negotiated as a resolution to SPPC's previously filed complaint with the Surface Transportation Board alleging unreasonable rate levels being charged by the UP. During 2000, SPPC operated the Pinon Pine facility exclusively on natural gas. No coal was purchased in 2000 for synthetic gas production in the plant's coal gasification facility. SPPC meets its needs for residual oil for generation through purchases on the spot market. With no other mitigating factors, SPPC's residual oil inventory policy is to maintain 50,000 to 75,000 barrels at each of its Tracy and Ft. Churchill generating plants. Oil prices were significantly lower than natural gas prices in December 2000. Additional oil supply was ordered for consumption and to ensure the ability of the electric division to make gas available to SPPC's natural gas business on peak days. The actual residual oil inventory level at these two sites was 203,000 barrels as of December 31, 2000, which is equal to a 9.2 day supply at full load operation. Natural Gas Business SPPC's natural gas business is a local distribution company (LDC) in the Reno/Sparks area that accounted for $100.8 million in 2000 operating revenues or 10.1% of SPPC's revenues from continuing operations. Growth in SPPC's service territory continues to be strong. Customer meter count growth during 2000 was 4.0%. SPPC's total customer meter count increased 4,529 to 116,416 meters by the end of 2000. Growth in all sectors is expected to continue as new developments in SPPC's distribution service area are planned. 26 SPPC's natural gas LDC business is subject to competition from other suppliers and other forms of energy available to its customers. Large customers with fuel switching capability compare natural gas prices on an interruptible basis to alternative energy source prices. During the last year, SPPC has had as many as eight customers secure their own gas supplies, with SPPC providing transportation service on its distribution system. Recently, however, many customers on the gas transportation tariff, as well as other tariffs utilizing current market pricing have chosen to return to SPPC's firm retail tariffs. Those customers have been required to sign agreements to remain on these firm tariffs for a two-year period. SPPC has contracted for firm winter-only and annual gas supplies with 11 Canadian and domestic suppliers to meet the firm requirements of its LDC and electric operations. The contracts total 160,000 decatherms per day through March 2001 and 115,000 decatherms per day for April through October 2001. SPPC's firm natural gas supply is supplemented with natural gas storage services and supplies from a Northwest Pipeline Co. facility located at Jackson Prairie in southern Washington and a liquefied natural gas (LNG) storage from a facility located near Lovelock, Nevada. The LNG facility is operated by Paiute Pipeline Company and is used for meeting peak demand. The Jackson Prairie and LNG facilities can contribute a total of approximately 48,000 decatherms per day of peaking supplies. In November 1996, SPPC entered an agreement to sell winter seasonal peaking capacity supplies to another company over a seven-year period. The contract provides for the payment to SPPC of a monthly reservation charge, reimbursement of pipeline capacity charges during the winter, and a volumetric commodity charge based on the market price for natural gas. SPPC was able to enter into this agreement due to the ability of its power plants to utilize alternative fuels and its power importation option. The obligation to serve this peaking obligation will be transferred to the purchasers of the generation facilities. Following is a summary of the transportation and approximate storage capacity of SPPC's current gas supply program. Firm transportation capacity on the Northwest/Paiute system exists to serve primarily the LDC. Firm transportation capacity on the PGT/Tuscarora system exists primarily to serve SPPC's electric generating plants. Storage capacity is generally used for the peaking requirements of the LDC. Transportation Capacity Northwest: 68,696 decatherms per day firm 90,000 decatherms per day interruptible Paiute: 103,774 decatherms per day firm from November through March 61,044 decatherms per day firm from April through October 90,000 decatherms per day interruptible NOVA: 47,500 decatherms per day firm ANG: 53,000 decatherms per day firm PGT: 30,000 decatherms per day firm 60,270 decatherms per day firm (winter only) 90,000 decatherms per day interruptible Tuscarora: 106,250 decatherms per day firm 50,000 decatherms per day interruptible 27 Storage Capacity Williams: 281,242 decatherms from Jackson Prairie 12,687 decatherms per day from Jackson Prairie Paiute: 463,034 decatherms from Lovelock LNG 35,078 decatherms per day from Lovelock LNG facility As discussed in Generation Divestiture, later, SPPC is pursuing its obligations to sell its gas-fired generation. As part of these sales, SPPC will be transferring portions of its firm pipeline and the winter peaking supply agreement, described above, to the buyers of the Ft. Churchill and Tracy generation bundles. The final allocation of capacity to the buyers is still being determined but will meet the divestiture stipulation requirement that SPPC maintain the availability and reliability of natural gas to its local gas distribution company. Total LDC decatherm supply requirements in 2000 and 1999 were 13.2 million decatherms and 13.4 million decatherms, respectively. Electric generating fuel requirements for 2000 and 1999 were 38.6 million decatherms and 32.6 million decatherms, respectively. In November 2000, SPPC filed a Purchase Gas Adjustment requesting an increase in gas rates of $26,843,000. In January 2001, the PUCN approved a stipulation to make these rates effective February 1, 2001. An average residential customer's monthly bill increased by $11.52 (or 35%). The PUCN also reserved the right to adjust these rates after an evidentiary hearing. As of December 31, 2000, SPPC owned and operated 1,493 miles of three-inch equivalent natural gas distribution piping, 54 miles of which were added in 2000. In addition, SPPC completed in 2000, the construction of a new high- pressure regulator station equipped to receive gas from a second tap on the Tuscarora gas transmission line. This will give the LDC the ability to receive more supply and exercise more operating flexibility. In 2000, SPPC completed several technology projects for the LDC. These projects included a state of the art Supervisory Control and Data Acquisition System and completion of an electronic mapping system for all gas facilities. Sale of Water Business On January 15, 2001, SPR's Board of Directors approved a definitive agreement to sell SPPC's water business to the TMWA for $350 million. Of the total purchase price, $342 million is for the water business assets and $8 million is for associated hydroelectric generation assets. The transactions are subject to various closing conditions, including the release of the water business assets from the lien of SPPC's first mortgage indenture and the receipt of satisfactory regulatory treatment of the gain to SPPC, and are expected to close in the second quarter of 2001. SPPC expects to exit the water business entirely. The sale includes treatment facilities, distribution infrastructure, surface and ground water rights, and storage rights. The total net plant of the water business, including the hydroelectric assets, is approximately $266 million. The water business has approximately 85 employees and serves more than 73,000 customers in the Reno/Sparks metropolitan area. The employees of the water business will become employees of TMWA. TMWA is a joint power authority created by the cities of Reno and Sparks, and Washoe County. TMWA is governed by a Board of Directors consisting of seven representatives (three from the City of Reno, two from the City of Sparks, one from Washoe County, and one at-large director). TMWA intends to finance the transaction through the issuance of tax-exempt bonds. 28 Termination of SPPC's certificate of public convenience and necessity to serve water will require the approval of the PUCN. This filing for termination is set to be heard by the PUCN on March 14, 2001. Transfer of the hydroelectric facilities will require action by the California Public Utilities Commission (CPUC). The sale agreement contemplates a second closing for the hydroelectric facilities to accommodate the CPUC's review of the transaction. Not included in the sale are SPPC-owned properties at Independence Lake (approximately 2,200 acres) and along the Truckee River corridor (approximately 3,500 acres). These properties may be sold in a separate auction in the future. Water Business The water distribution business contributed $57 million (5.4%) to SPPC's 2000 total revenues. Water production in 2000 totaled 26.7 billion gallons. 4 billion gallons were produced from SPPC's groundwater wells. The remaining 22.7 billion gallons were treated through SPPC's two water treatment facilities, the Chalk Bluff Water Treatment Plant and the Glendale Water Treatment Plant. During 2000, 0.56 billion gallons of treated surface water were recharged into the groundwater wells for storage and removal in future years. SPPC's peak day send- out of water to customers during 2000 was 139.3 million gallons, a 4.1% increase over the previous 133.8 million gallon peak set in 1998. The increase in peak day demand was due to high summer temperatures, increases in customer numbers, and decreasing customer concern with conservation. Overall weather conditions during the year produced a below average snow pack with a normal to warm summer season; annual production was up 6.9 %. SPPC's water supplies are from both surface and groundwater sources, with the addition of drought storage and refill provisions sufficient to withstand prolonged drought conditions. The surface water source is the Truckee River, which originates in Lake Tahoe and flows north and east through the cities of Reno and Sparks to Pyramid Lake, located northeast of Reno. SPPC's groundwater comes from 29 supply wells located around the Reno/Sparks area. Regulation and Rate Proceedings See Regulation and Rate Proceedings, later, for a discussion of regulatory matters affecting SPPC. GENERATION DIVESTITURE (NVP AND SPPC) ------------------------------------- In June 1998, SPR announced a plan to divest its generation assets. This business strategy was described in the SPR/NVP merger applications filed with the PUCN and the FERC in July 1998. The FERC, Department of Justice, and SEC approved the merger. The PUCN conditionally approved the merger in December 1998, and one of the conditions was the filing of the divestiture plan with the PUCN. The plan was filed with the PUCN in April 1999, and included details about the auction process, market power mitigation, sale of the assets in described bundles, description of the proposed generation tariffs, description of the proposed power purchase contracts, and a description of the proposed independent system administrator. In June 1999, the PUCN approved a stipulation in the Merger docket case with several conditions. Some of those conditions were: re-file the divestiture plan with the PUCN; file the generation aggregation tariffs (GAT); file the proposal for the Independent System Administrator (ISA) 29 at the FERC; file the proposal for the buyback of purchase power contracts; and file proposals for mitigation of QF and other purchase power contracts. A revised divestiture plan was filed with the PUCN in October 1999. PUCN approval and an Order for Divestiture Plan Stipulation were received in February 2000. The approved plan includes seven bundles: SPPC's bundles are North Valmy (286 MW), Fort Churchill (226 MW), Tracy/Pinon (545 MW); NVP's bundles are Clark (690 MW), Sunrise/Sunpeak (390 MW), Reid Gardner (590 MW), and Harry Allen (76 MW). Not included in the plan's seven bundles were NVP's 14% (222 MW) interest in the Mohave Generating Station ("Mohave") and 11% (255 MW) interest in the Navajo Generating Station ("Navajo") although NVP committed to sell its share of these plants. In March 2000, the Utilities prepared the required offering materials and solicited bids for the seven bundles described in the approved divestiture plan. At the same time, separate negotiations began for the sale of NVP's interests in Mohave and Navajo. Asset sale agreements, described below, have been signed for NVP's 14% share of Mohave and for six of the seven bundles described in the approved divestiture plan (Valmy, Tracy/Pinon, Clark, Reid Gardner, Sunrise/Sunpeak & Harry Allen). Marketing for the sale of SPPC's Fort Churchill bundle and NVP's 11% interest in the jointly owned Navajo power plant is continuing. On May 10, 2000, AES Corporation (AES) announced that it was the successful bidder for the purchase of a controlling interest in the 1,580 MW Mohave Generating Station in Laughlin, Nevada for approximately $667 million. NVP owns a 14% undivided interest in the facility. Mohave Generating Station is a 2-unit, coal-fired power plant located on 2,500 acres along the Colorado River, approximately 80 miles south of Las Vegas. AES executed Asset Sale Agreements with the sellers, NVP (14%) and Southern California Edison Company (56%), for a 70% undivided interest in the facility. Under the agreement, NVP will have the right to buy energy and ancillary services from AES for agreed upon prices, subject to a collar, through early 2003. The total sale price of NVP's interest is $142 million, subject to taxes and other adjustments. The actual sales proceeds will be net of a payment from NVP to AES for the power purchase agreement. The sale is subject to approval and review by various regulatory agencies. On October 19, 2000, SPR and SPPC announced an agreement to sell SPPC's 50% interest in the Valmy Power Station to NRG Energy, Inc. ("NRG") of Minneapolis, Minnesota. Under the agreement, SPPC will have the right to buy energy and ancillary services from the Valmy Power Station for agreed upon prices, subject to a collar, through early 2003. The total sale price of the asset bundle, which includes the Battle Mountain Diesel Plant and the Winnemucca Gas Plant, is $332 million, subject to taxes and other adjustments. The actual sales proceeds will be net of a payment from SPPC to NRG for the power purchase agreement. The Valmy Power Station sells electricity in northern Nevada and surrounding markets. SPPC's net capacity interest in the Valmy Power Station totals 286 MW. Located forty miles from Winnemucca, Nevada, the Valmy Power Station consists of two similar coal-fired units and is owned jointly by SPPC and Idaho Power Company. SPPC owns 50% of the station and operates the plant. The sale is subject to approval and review by various regulatory agencies. On October 27, 2000, SPR and SPPC announced an agreement to sell SPPC's Tracy/Pinon Power Station to WPS Power Development, Inc., a wholly owned subsidiary of WPS Resources Corporation of Green Bay, Wisconsin. Under the agreement, SPPC will have the right to buy energy and ancillary services from WPS Power Development for agreed upon prices, subject to a collar, from 30 closing of the agreement through February 2003. The total sale price of the asset bundle, which includes the Tracy Plant, Pinon Pine, and the Brunswick, Gabbs and Valley Road diesel generators, is $260 million, subject to taxes and other adjustments. The actual sales proceeds will be net of a payment from SPPC to WPS Power Development for the power purchase agreement. The Tracy/Pinon Power Station sells electricity in northern Nevada and surrounding markets. Tracy is also the site of the Pinon Pine Integrated Coal Gasification Combined Cycle project co-funded by the U.S. Department of Energy as part of the Clean Coal Technology Program. SPPC's average capacity in the Tracy/Pinon Power Station totals 525 megawatts. Located approximately 20 miles from Reno, Nevada, the Tracy/Pinon Power Station consists of three similar gas- and oil-fired units, four gas turbines, and the Pinon Pine facility (a combined cycle unit). The sale is subject to approval and review by various regulatory agencies. On November 20, 2000, SPR and NVP announced an agreement to sell NVP's Clark and Reid Gardner Generating Stations to a holding company formed by NRG and Dynegy Inc. (Dynegy) of Houston, Texas. Under the agreement, NVP will have the right to buy energy and ancillary services for agreed upon prices, subject to a collar, from closing of the agreement through February 2003. The total sale price of the asset bundles is $955 million, subject to taxes and other adjustments. The actual sales proceeds will be net of a payment from NVP to NRG and Dynegy for the power purchase agreement. The Clark Generating Station, located in southeastern Las Vegas, consists of 10 gas- and oil-fired generating units, totaling 740 megawatts. The Reid Gardner Generating Station consists of four baseload coal-fired units and is located 52 miles northeast of Las Vegas. Three of the units, 110 megawatts each, are wholly owned by NVP. NVP and the CDWR jointly own the fourth unit, a 275 megawatts coal-fired unit. NRG and Dynegy will jointly acquire NVP's combined ownership and use interest in the fourth unit as part of the transaction. The CDWR will maintain its 15 megawatts ownership interest in the unit. The sale is subject to approval and review by various regulatory agencies. On December 4, 2000, SPR and NVP announced an agreement to sell NVP's Harry Allen Power Station to Pinnacle West Energy (Pinnacle), a subsidiary of Pinnacle West Corporation of Phoenix, Arizona. Under the agreement, NVP will have the right to buy energy and ancillary services from Pinnacle for agreed upon prices, subject to a collar, from closing of the agreement through February 2003. The total sale price of the asset bundle is $71 million, subject to taxes and other adjustments. The actual sales proceeds will be net of a payment from NVP to Pinnacle for the power purchase agreement. The Harry Allen Power Station, located approximately 30 miles north of the city of North Las Vegas, is a 72 megawatt combustion turbine unit. The sale is subject to approval and review by various regulatory agencies. On December 11, 2000, SPR and NVP announced an agreement to sell NVP's Sunrise Station electric generating plant to Reliant Energy Power Generation, Inc. (Reliant), a subsidiary of Reliant Energy of Houston, Texas. The sale includes two generating units owned by NVP and rights to electricity produced by three additional units on the Sunrise site owned by an independent power producer. Under the agreement, NVP will have the right to buy energy and ancillary services from Reliant for agreed upon prices, subject to a collar, from closing of the agreement through February 2003. The total sale price of the asset bundle is $109 million, subject to taxes and other adjustments at closing. The actual sales proceeds will be net of a payment from NVP to Reliant for the power purchase agreement. The Sunrise Station, located near the eastern edge of Las Vegas, consists of two generating units that can be fueled by natural gas or oil and are capable of producing up to 149 megawatts of electricity. The facility also includes three additional gas turbine generating units rated at 222 megawatts. These three units are owned by an independent power producer, Nevada Sun-Peak Limited Partnership, under contract to NVP. The sale is subject to approval and review by various regulatory agencies. 31 As noted above, each of the sales requires the buyer to execute an Asset Sale Agreement, an energy buyback contract called a Transitional Power Purchase Agreement (TPPA), and an Interconnection Agreement. The TPPA's allow SPPC and NVP to obtain energy from these plants at 1998 productions costs from the time of closing to March 2003. The Utilities have obtained FERC approval of the TPPA's and Generation Aggregation Tariffs (GAT), as well as PUCN approval of the Mohave ownership sale. On January 18, 2001, California enacted a law prohibiting any further divestiture of generation properties by California utilities, including SPPC, until 2006. SPR is actively seeking legislation to exempt SPPC from this moratorium on generation sales. However, unless modified by future legislative action or by a court, California law has halted divestiture of SPPC's Valmy, Tracy and Ft. Churchill plants. As Edison is the operating partner in the Mohave Station, the pending sale of that unit is also implicated. Without divestiture, the TPPAs negotiated with the buyers of these units as part of the sale agreements are terminated. On January 24, 2001, the Nevada Utility Consumer Advocate ("UCA") filed a Petition with the PUCN seeking to halt regulatory review of all pending sales agreements for all Nevada generation until the PUCN can make a determination that generation divestiture is still in the public interest. If adopted by the PUCN, the UCA's proposal would at a minimum delay the effective date for TPPAs for all SPPC and NVP units and require that the Utilities immediately secure a fuel supply to run these generators beyond 2001. On March 8, 2001, the PUCN ordered that there be a hearing to address the UCA proposal. The PUCN also consolidated NVP's application for the sale of the Harry Allen plant with the hearing on the UCA proposal. The PUCN requested that the Utilities suspend all generation sale applications until the hearing and order is issued on the UCA request. No divestiture sale filings will be submitted until the PUCN has ruled on the UCA motion. On February 22, 2001, the Governor of Nevada presented his Nevada Energy Protection Plan. One of the points of the plan is re-examination of utility divestiture. The Governor has written to the PUCN, expressing his concern that divestiture in its current form could adversely impact Nevada. He has asked the PUCN to reconsider the issue. Senate Bill 253 has been introduced in the Nevada legislature which, if passed, would halt divestiture of generation until 2003. Although the closing of these sales is scheduled for the second and third quarters of 2001, whether and when such closings will occur depends upon the resolution of the legislative and regulatory issues discussed above. As of December 31, 2000, NVP and SPPC had spent $8.7 million and $11.4 million, respectively, in order to prepare for the generation asset sales. REGULATION AND RATE PROCEEDINGS ------------------------------- Also see Regulatory Events in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations for additional regulatory and rate matters. Nevada Matters (NVP and SPPC) SPPC and NVP are subject to the jurisdiction of the PUCN and, in the case of SPPC, the CPUC with respect to rates, standards of service, siting of, and necessity for, generation and certain transmission facilities, accounting, issuance of securities and other matters with respect to electric distribution and transmission operations. SPPC submits integrated resource plans regarding its electric, 32 gas, and water business operations to the PUCN for approval. NVP submits an integrated resource plan regarding its electric business operations to the PUCN for approval. Under federal law, the Utilities are subject to certain jurisdictional regulation, primarily by the FERC. The FERC has jurisdiction under the Federal Power Act with respect to rates, service, interconnection, accounting, and other matters in connection with the Utilities' sale of electricity for resale and the transmission of energy for others. The FERC also has jurisdiction over the natural gas pipeline companies from which SPPC and NVP take service. As a result of regulation, many of the fundamental business decisions of the Utilities, as well as the rate of return they are permitted to earn on their utility assets, is subject to the approval of governmental agencies. The Utilities are also subject to regulation by environmental authorities. See Environment, later. Comprehensive Energy Plan (NVP and SPPC) On January 29, 2001, the Utilities jointly filed a Comprehensive Energy Plan (the "CEP") with the PUCN. The CEP includes proposals for the Utilities' energy supply portfolio, for emergency rate relief, and for low income and conservation programs. Under the CEP, SPPC and NVP map out a strategy to meet Nevada's short- and long-term energy needs, focusing on new mechanisms to recover the enormous increases in the cost of wholesale power. The CEP also calls for accelerated approval of new long-term power contracts and encourages new power plant development. It also provides for automatic price reductions as wholesale prices eventually fall. The CEP includes tiered rate increases, based on energy usage, that range from zero for certain low usage customers to as much as 29 percent for the state's largest energy users. The average increase is expected to be approximately 17 percent. Under the CEP, up to $5 million in revenue would be provided to the State of Nevada to be used at the State's discretion to fund conservation and low- income protection programs. The Utilities have proposed that the new mechanism take effect on March 1, 2001, and be adjusted on March 1, 2002, or sooner, if wholesale prices fall and if divesture of the Utilities' Nevada power plants is completed and contracts are in place that guarantee the Utilities can purchase power from those plants for two years at 1998 prices. On February 23, 2001, the PUCN voted 3 to 0 to allow the CEP Rider to become effective March 1, 2001, reserving the right to review the reasonableness and to adjust these rates after an evidentiary hearing which will be scheduled at a pre-hearing conference on March 23, 2001. The Utilities will also continue to make monthly fuel and purchased power filings, which are scheduled to expire on March 1, 2003 (See Fuel and Purchased Power Rider below.) Fuel and Purchased Power Rider (NVP and SPPC) On July 20, 2000, the PUCN approved stipulated agreements (the "Global Settlement") that resolved pending state and federal lawsuits and major restructuring issues. On August 3, 2000, the PUCN approved certain revisions to the stipulated agreements. One stipulation allowed NVP to increase its rates effective August 1, 2000, by approximately $48 million annually to recover increased 33 costs of fuel and purchased power, and to update its costs of fuel and purchased power thereafter with monthly fuel and purchased power filings through March 2003. Increases and/or decreases are capped at incrementally increased or decreased rates over successive six-month periods at .95 mils for the first six months, 1.15 mils for the second six months, 1.35 mils for the third six months, 1.55 mils for the next six months, and 1.75 mils for the remaining period. The Global Settlement also permitted SPPC to commence filing monthly fuel and purchased power adjustment cases on the same basis to commence not later than November 1, 2000. SPPC's fuel and purchased power increases and/or decreases are also capped at incrementally increased or decreased rates over successive six- month periods starting October 1, 2000, at 4.5 mils for the first six-month period followed by .95, 1.15, 1.35, 1.55, and1.75 mils for each successive six- month period. Under the terms of the Settlement, the PUCN will review the prudency of the increases after submission of semi-annual audits with any refunds due, if any, to be included in future adjustments. See Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, for further discussion regarding the Global Settlement. Under the terms of the Settlement, the PUCN will review the prudency of the increases after submission of semi-annual audits with any refunds due, if any, to be included in future adjustments. SPR and NVP Merger (NVP and SPPC) As previously mentioned, the merger between SPR and NVP was finalized on July 28, 1999. As part of a stipulation among the merging companies, the PUCN staff and the UCA regarding the merger, the Utilities were required to re-file the plan to divest their generating assets, and file a final ISA proposal with the PUCN and the FERC. In January 2000, the FERC approved the ISA proposal. As part of the conditions for the merger, the Utilities were each required to file a general rate case and unbundle costs. In May 1999, the Nevada Legislature passed Senate Bill 438 (SB 438), which modified the electric restructuring statutes, and, among other things, revised the scope of this proceeding to only unbundling of costs and establishing distribution rates. In May 2000, the PUCN issued final orders related to the proceeding. Several parties, including NVP and SPP, filed Petitions for Reconsideration of the PUCN's orders. In November 2000, the PUCN issued a final Order on Reconsideration in each case. Both NVP and SPP have filed distribution tariffs with the PUCN incorporating the final distribution rates from these proceedings. The effective date of the distribution tariffs is pending the opening of the retail market to competition. The Utilities were also required to file a general rate case three years after the start of retail competition in the state of Nevada. That requirement was subsequently changed in the Global Settlement to no later than October 1, 2002, with rates to be effective March 1, 2003. For more information on the Global Settlement, see Regulatory Events in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations. The filing will give the Utilities the opportunity to recover certain costs of the merger, including goodwill, provided they can demonstrate that merger savings exceed certain merger costs. Merger costs are to be split among the non-competitive, potentially competitive and unregulated services or businesses. An opportunity to recover the non-competitive portion of the merger costs will be addressed in the rate case. The burden is on the Utilities to prove that merger savings exceed merger costs. For more information regarding the Merger, see Note 2 of SPR's consolidated financial statements. Electric Industry Restructuring (NVP and SPPC) During the 1997 session, the Nevada Legislature passed Assembly Bill 366 (AB 366). AB 366 was a comprehensive bill that introduced competition for electric and gas retail services. Since the fall of 1997, the PUCN has been developing regulations to implement AB 366. In the 1999 session, the 34 legislature passed SB 438 that significantly modified many provisions of AB 366. These two pieces of legislation substantially alter the way the Utilities are regulated and how they will serve their customers. However, in 2000, electric restructuring and the opening of a competitive energy market were twice delayed by the Governor of Nevada. The status of restructuring efforts, including the California issues, influenced the Governor of Nevada in his decision to delay the opening of competition and to establish a committee, the NEEPC, to advise him on energy issues. The NEEPC issued its report on January 15, 2001. The Governor included many of the NEEPC's recommendations in his energy protection plan and recommendations to the Nevada legislature. Deregulation has been halted indefinitely. In addition, the Governor will not consider deregulation until the market stabilizes, adequate consumer protections are in force, and supplies are at an acceptable level. In the 2001 legislative session, restructuring is expected to be a prevalent topic. Gas Rate Increase (SPPC) On November 1, 2000, SPPC filed to increase gas rates in two filings: The Purchase Gas Adjustment filing was made requesting an increase in natural gas rates of $26.8 million. An average residential customer's monthly bill will increase by $11.52 (or 35%). The Purchase Liquid Propane (LP) Gas Adjustment filing requests an increase in LP gas rates of $24.5 thousand. An average LP gas customer's monthly bill will increase by $4.77 (or 11%). On January 2, 2001, the PUCN approved a stipulation to make these rates effective February 1, 2001. FERC Matters (NVP and SPPC) --------------------------- Regional Transmission Organization ("RTO") On May 1, 2000, the Utilities, together with Avista Corporation, Bonneville Power Administration (BPA), Idaho Power Company, The Montana Power Company, PacifiCorp, Portland General Electric, and Puget Sound Energy, Inc. formed RTO West and filed articles of incorporation in the State of Washington. RTO West will be a non-profit independent system operator governed by an independent board of directors with a stakeholder advisory board. RTO West would be the single provider and controller of transmission operations in an eight-state region. In October 2000, RTO West submitted with FERC a compliance filing and supplemental material, which provided details of the formation of RTO West. This filing was made in compliance with FERC Order 2000, which required all investor-owned utilities in the United States who own interstate transmission to file a proposal to participate in an RTO or an explanation of efforts and plans to participate in an RTO. FERC Order 2000 requires RTOs to be operated by independent entities that are not participants in the energy market. In addition, RTOs should eliminate regional transmission rate pancaking (multiple rates on a transmission path), manage congestion, internalize parallel path flows, deal effectively and fairly with transmission owning utilities that are not under the FERC jurisdiction, and provide incentives for transmission owning utilities to efficiently operate and invest in their grids. The RTO West utilities intend to submit another filing to the FERC in spring 2001 which will include documents necessary to complete the RTO West proposal. The creation of RTO West is subject to regulatory approvals from FERC and the states served by the investor-owned utilities. The organization will begin operations after all approvals are obtained. FERC's goal is for all RTO's to be operational by December 15, 2001. The proposed operational date in the RTO West filing is approximately one year later. 35 Independent Transmission Company On October 16, 2000, the Utilities, together with Portland General Electric Company, Avista Corporation, The Montana Power Company, and Puget Sound Energy filed jointly with FERC to form TransConnect, a for-profit Independent Transmission Company. The six utilities forming TransConnect will be able to maintain passive ownership in TransConnect, which will be operated by a corporate manager with no affiliated energy market participant. TransConnect's members will aggregate their bulk transmission assets into one large independent transmission company in order to achieve economies of scale and focus purely on the transmission business. TransConnect would own or lease the transmission facilities of the six utilities in Oregon, Washington, Nevada and Montana and parts of Idaho and California. Those facilities are within the proposed territory for RTO West. TransConnect would become a member of RTO West, which will be the single provider of transmission services and controller of transmission operations in the region. The formation of TransConnect is expected to speed coordination efforts for RTO West by reducing the number of transmission owning companies it deals with to one company instead of six vertically integrated utilities. TransConnect's size should allow it to better attract capital for construction of new transmission facilities and system improvements helping ease transmission congestion - a major problem during peak demand periods in the West. TransConnect's members believe TransConnect's "independent" status should allow it to obtain innovative rates for helping achieve the goals of the RTO, such as efficient use of, and investment in, transmission systems and reliability benefits to consumers. The creation of TransConnect is subject to regulatory approvals from FERC, state regulators, and the board of directors of each company. The TransConnect utilities intend to submit a transmission proposal to the FERC by Spring 2001. The initial operations date will be coordinated with the RTO West process. Alturas Intertie Certain Northern California public power groups have challenged the Company's filing with the FERC of the interconnection and operating agreements related to the Alturas Intertie in December 1998 and January 1999. The California groups alleged that the potential reduction in imports into California constitutes an impairment of reliability and therefore seek to force reductions in use of the Alturas Intertie during peak periods. The Company (supported by Bonneville Power Administration and PacifiCorp) has filed testimony before the FERC that the Alturas Intertie does not adversely affect reliability and that, under the FERC's Order No. 888, customers in Nevada are entitled to compete with customers in California for transmission capacity in the Pacific Northwest on a first-come, first-served basis. The FERC staff has agreed with the Company's position on this matter. The matter was tried to an Administrative Law Judge in April and May, 2000, and a decision is expected to be issued imminently. One of the California groups, the Transmission Agency of Northern California ("TANC"), also initiated proceedings in the United States District Court for the Eastern District of California and the United States Court of Appeals for the Ninth Circuit, in each case alleging that Bonneville's construction of a small portion of the Alturas Intertie violated the Northwest Power Preference Act and requesting an injunction prohibiting operation of the Alturas Intertie. The case before the Eastern District was dismissed for lack of jurisdiction. The case before the Ninth Circuit was dismissed for TANC's failure to prosecute. In December 1999, TANC filed suit in the Superior Court of the State of 36 California, Sacramento County, seeking an injunction against operation of the Alturas Intertie based on numerous allegations under state law, including inverse condemnation, trespass, private nuisance, and conversion. That case was removed to Federal Court and dismissed by the trial court, and is now on appeal in the Ninth Circuit. ENVIRONMENT (SPR, NVP AND SPPC) ------------------------------- As with other utilities, NVP and SPPC are subject to federal, state and local regulations governing air, water quality, hazardous and solid waste, land use and other environmental considerations. Nevada's Utility Environmental Protection Act requires approval of the PUCN prior to construction of major utility, generation and transmission facilities. The United States Environmental Protection Agency (EPA), Nevada Division of Environmental Protection (NDEP), and Clark County Health District (CCHD) administer regulations involving air quality, water pollution, solid, hazardous and toxic waste. SPR's Board of Directors has a comprehensive environmental policy and separate board committee which oversees NVP, SPPC, and SPR's corporate performance and achievements related to the environment. Nevada Power Company The Grand Canyon Trust and Sierra Club filed a lawsuit in the U.S. District Court, District of Nevada, in February 1998 against the owners (including NVP) of the Mohave Generation Station ("Mohave"), alleging violations of the Clean Air Act regarding emissions of sulfur dioxide and particulates. An additional plaintiff, National Parks and Conservation Association, later joined the suit. The plant owners and plaintiffs have had numerous settlement discussions and filed a proposed settlement with the court in October 1999. The consent decree, approved by the court in November 1999, established emission limits for sulfur dioxide and opacity and required installation of air pollution controls for sulfur dioxide, nitrogen oxides and particulate matter. The new emission limits must be met by January 1, 2006, and April 1, 2006, for the first and second units respectively. However, if the owners sell their entire ownership interest with a closing date prior to December 30, 2002, the new emission limits become effective 36 months and 39 months from the date of last closing for the two respective units. The estimated cost of new controls is $300 million. As a 14% owner in the Mohave Station, NVP's cost could be $42 million. Also, the United States Congress authorized the EPA to study the potential impact Mohave may have on visibility in the Grand Canyon area. A final report of the study results was released in March 1999. The study acknowledges that sulfur dioxide emissions from Mohave are transported to the Grand Canyon. EPA has solicited information to determine whether visibility impairment in the Grand Canyon can be reasonably attributed to Mohave. If EPA determines that significant visibility impairment is reasonably attributable to the station, EPA could initiate a review for Best Available Retrofit Technology. Mohave's owners believe that settlement of the suit discussed above is acceptable to the EPA. Provisions that are agreed to in a settlement are expected to be reflected in a State Implementation Plan for Nevada and resolve any concerns of EPA regarding visibility impairment In May 1997, NDEP ordered NVP to submit a plan to eliminate the discharge of Reid Gardner Station wastewater to groundwater. The NDEP order also required a hydrological assessment of groundwater impacts in the area. In June 1999, NDEP determined that wastewater ponds had degraded groundwater quality. In August 1999, NDEP issued a discharge permit to Reid Gardner Station and an order that requires all wastewater ponds to be closed or lined with impermeable liners over the next 10 years. This order also required NVP to submit a Site Characterization Plan to NDEP to ascertain 37 impacts. This plan is under review by NDEP. After approval, an estimate of remediation costs will be determined by NVP. New pond construction and lining costs are estimated at $20 million. Also, at the Reid Gardner Station, the NDEP has determined that there is additional groundwater contamination that resulted from oil spills at the facility. NDEP has required submitting a corrective action. The extent of contamination has been determined and remediation is occurring. This remediation is not expected to materially affect the financial position of SPR or NVP. In May 1999, NDEP issued an order to eliminate the discharge of NVP's Clark Station wastewater to groundwater. The order also required a hydrological assessment of groundwater impacts in the area. This assessment was submitted to NDEP in February 2001 and is under review. NVP will spend $565,000 to line existing ponds. After review by NDEP, NVP will implement remediation. Management does not expect this matter to materially affect the financial position of SPR or NVP. In December 2000, an above ground storage tank failed at NVP's Clark Station necessitating remediation of approximately 30,000 gallons of Bunker Fuel. Remediation costs are not expected to be significant. NVP determined that, while constructing the McCullough-Arden transmission line, access roads were created within a wilderness study area in violation of the Bureau of Land Management (BLM) Right of Way Grant. NVP's preliminary estimate for restoration costs is $200,000, which was reserved as of December 31, 1999. No resulting BLM action is pending. As part of the generation divestiture process Phase I and/or Phase II Environmental Assessments were conducted at all of the Utilities' facilities. These assessments noted additional remediation requirements for all the generation assets. All remediation has been completed except for the Reid Gardner facility. The assessment is under review by NDEP. Management does not expect this item to materially affect the financial position of SPR, NVP or SPPC. Sierra Pacific Power Company In September 1994, Region VII of EPA notified SPPC that it was being named as a potentially responsible party (PRP) regarding the past improper handling of Polychlorinated Biphenyls (PCBs) by PCB Treatment, Inc., located in Kansas City, Kansas, and Kansas City, Missouri (the Sites). The EPA is requesting that SPPC voluntarily pay an undefined, pro rata, share of the ultimate clean-up costs at the Sites. A number of the largest PRP's formed a steering committee, which is chaired by SPPC. The responsibility of the Committee is to direct clean-up activities, determine appropriate cost allocation, and pursue actions against recalcitrant parties, if necessary. The EPA issued an administrative order on consent requiring signatories to perform certain investigative work at the Sites. The steering committee retained a consultant to prepare an analysis regarding the Sites. The Site evaluations have been completed. EPA is developing an allocation formula to allocate the remediation costs. SPPC has recorded a preliminary liability for the Sites of $650,000 of which approximately $135,000 has been spent through December 31, 2000. In October 2000, NDEP issued Notices of Alleged Violation (NOAV's) to SPPC for operating the Winnemucca Gas Turbine and the Tracy Peaking Combustion Turbine No. 1 over their annual operating hours. SPPC has applied for additional operating hours on these units per the NOAV's. In December 2000, SPPC notified NDEP that the annual operating hours for the Battle Mountain, Gabbs, and Brunswick Gas Turbines were exceeded in 2000. SPPC has applied for a Class II 38 Air Operating Permit for these units. Enforcement action is pending per NDEP review of permit applications. In January 2001, Placer County Air Pollution Control District issued a Notice of Violation and a subsequent $160,000 penalty to SPPC for operating the Kings Beach Diesel Generation Facility in excess of its permitted annual operating hours. A settlement conference was held in February 2001 to present additional facts or circumstances to be considered in settling this matter. Settlement negotiations are continuing. Other Subsidiaries of SPR Lands of Sierra, a wholly owned subsidiary of SPR, owns property in North Lake Tahoe, California, which is leased to independent condominium owners. The property has both soil and groundwater petroleum contaminate resulting from an historic underground fuel tank. Additional contaminate from a third party fuel tank on the property has also been identified and is undergoing remediation. Estimated future remediation costs are not expected to be significant. Nevada Electric Investment Company (NEICO), a wholly owned subsidiary of SPR, owns property in Wellington, Utah, which was the site of a coal washing and load out facility. The site now has a reclamation estimate supported by a bond of $4 million with the Utah Division of Oil and Gas Mining. The property was under contract for sale and the contract required the purchaser to provide $1.3 million in escrow towards reclamation. However, the sales contract was terminated and NEICO took title to the escrow funds. In September 2000, NEICO leased the property together with an option to purchase it. It is NEICO's intention to sell the property. OTHER SUBSIDIARIES OF SIERRA PACIFIC RESOURCES ---------------------------------------------- Tuscarora Gas Pipeline Company TGPC was formed as a wholly owned subsidiary in 1993 for the purpose of entering into a partnership (Tuscarora Gas Transmission Company or TGTC) with a subsidiary of TransCanada to develop, construct and operate a natural gas pipeline to serve an expanding gas market in Reno, northern Nevada, and northeastern California. In December 1995, TGTC completed construction and began service on its 229-mile pipeline extending from Malin, Oregon, to Reno, Nevada. TGTC interconnects with PG&E Gas Transmission-Northwest (PG&E GT-NW) at Malin, Oregon. PG&E GT-NW is a major interstate natural gas pipeline extending from the U.S./Canadian border, at a point near Bonners Ferry, Idaho to the Oregon/California border. The PG&E GT-NW system provides TGTC customers access to natural gas reserves in the Western Canadian Sedimentary basin, one of the largest natural gas reserve basins in North America. As of December 31, 2000, SPR had an investment of approximately $17.2 million in this subsidiary. As an interstate pipeline, TGTC provides only transportation service. SPPC was the largest customer of TGTC during 2000, contributing 95% of revenues. Malin, Oregon began taking service from TGTC during October 1996. The Sierra Army Depot at Herlong, California began taking service from TGTC October 1997. In 1998, TGTC began serving two new customers, the United States Gypsum Company located north of Empire, Nevada and HL Power Company located northwest of Wendel, California. 39 In 2000, TGTC began construction on a 16.1-mile lateral creating a new citygate connection into the SPPC distribution system. The lateral was completed and placed in service January 29, 2001, providing SPPC with an additional 10,000 decatherms per day of transportation capacity. Also in 2000, TGTC surveyed shipper interest in the feasibility of a proposed expansion project. Sufficient interest was obtained and further investigation into the possibility of expanding TGTC's facilities to serve increased market demand in Nevada and northeastern California is continuing. For a discussion of TGPC's results of operations refer to Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations. Sierra Pacific Communications SPC, formerly Sierra Pacific Media Group, was created to examine and pursue telecommunications opportunities that leveraged existing skill sets of installing and deploying pipe and wire infrastructure. SPC presently has fiber optic assets deployed in the cities of Reno and Las Vegas. The expanding telecommunications market in these areas should provide continuing future opportunities to expand this fiber base and other profitable opportunities. SPC is making final preparations to begin selling bandwidth services in the Reno/Sparks and Las Vegas metropolitan areas. Sales are scheduled to commence in the second quarter of 2001. SPC will continue to construct fiber networks for businesses and governmental agencies in the Reno/Sparks and Las Vegas areas. Sierra Touch America LLC, a partnership between SPC and Touch America, a subsidiary of Montana Power Company, is constructing and will operate a fiber optic line between Salt Lake City, Utah and Sacramento, CA. The route is being constructed for AT&T, PF Net corporations, and Sierra Touch America. SPC's share of construction cost is approximately $25 million of a total estimated construction cost of $120 million. Right-of-way and permitting efforts are in their final phases. Construction activity between Sacramento and Reno commenced in July 2000 and final acceptance of this portion of the build is expected during the second quarter of 2001. Construction within Salt Lake City is complete and construction is in progress through the Reno, NV metropolitan area. The entire project is scheduled for completion in the third quarter of 2001. For a discussion of SPC's results of operations refer to Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations. e.three e.three was organized in October 1996 as an unregulated wholly owned subsidiary of SPR. It provides comprehensive energy and other business solutions in commercial and industrial markets. This is accomplished by offering a variety of energy-related products and services to increase customers' productivity and profits and improve the quality of the indoor environment. These products and services include: technology and efficiency improvements to lighting, heating, ventilation and air-conditioning equipment; installation or retrofit of controls and power quality systems; energy performance contracting; end-use services; and ongoing energy monitoring and verification services. In September 1998, e.three and NEICO, then a wholly owned subsidiary of NVP, formed e.three Custom Energy Solutions, LLC, a Nevada limited liability company, for the purpose of selling and implementing energy-related performance contracts and similar energy services in southern Nevada. e.three Custom Energy Solutions, LLC's primary focus for its sales activities is in the commercial and industrial markets. During the latter half of 1999, e.three Custom Energy Solutions, LLC began developing a chilled water cooling plant in the downtown area of Las Vegas. The plant is owned by 40 e.three Custom Energy Solutions, LLC and will supply the indoor air-cooling requirements for a number of businesses in its immediate vicinity. The plant was operational in August of 2000. In October 1998, e.three acquired Independent Energy Consulting, Inc. (IEC), a California based company, in an exchange of SPR stock for all of IEC's stock. IEC provides energy procurement management, third party auditing, performance contract consulting and strategic energy planning in the industrial and commercial markets. For a discussion of e.three's results of operations refer to Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations. Sierra Pacific Energy Company SPE was formed to market a package of technology and energy-related products and services in Nevada. SPE filed an application with the PUCN to be licensed as an Alternative Seller of Electricity in the state of Nevada. SPE has withdrawn its application with the PUCN and dissolved its retail energy marketing efforts. For a discussion of SPE's results of operations refer to Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations. Lands of Sierra LOS was organized in 1964 to develop and manage SPPC's non-utility property in Nevada and California. These properties previously included retail, industrial, office and residential sites, timberland, and other properties. Remaining properties include land in Nevada and California. SPR has decided to focus on its core energy business. In keeping with this strategy, LOS continues to sell its remaining properties. For a discussion of LOS' results of operations refer to Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations. Nevada Electric Investment Company NEICO is a wholly owned subsidiary of SPR. In October of 1997, NEICO and UTT Nevada, Inc., an affiliate of Exelon Thermal Technologies, formed Northwind Las Vegas, LLC, a Nevada limited liability company, for the purpose of evaluating district energy projects in southern Nevada. Also, in October of 1997, NEICO and UTT Nevada, Inc. formed Northwind Aladdin, LLC, a Nevada limited liability company, for the purpose of owning, constructing, operating and maintaining the facility for the production and distribution of chilled water, hot water and emergency power for the Aladdin Hotel and Casino project in Las Vegas, Nevada. The project was completed in the first quarter of 2000 and is operational. In September 1998, NEICO and e.three formed e.three Custom Energy Solutions, LLC, a Nevada limited liability company, for the purpose of selling and implementing energy-related performance contracts and similar energy services in southern Nevada. Refer to e.three for a more complete discussion of these activities. For a discussion of NEICO's results of operations refer to Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations. 41 GENERAL - EMPLOYEES (ALL) ------------------------- SPR and its subsidiaries had 3,232 employees as of December 31, 2000, of which 1,686 were employed by NVP and 1,451 were employed by SPPC. NVP's current contract with the International Brotherhood of Electrical Workers (IBEW) Local No. 396, which covers 55.2% of NVP's workforce, was renegotiated in 1997 and 1998, and is in effect until February 1, 2002. The contract provides for a 4% general wage increase for bargaining unit employees beginning February 2, 1998, with 3% increases in 1999, 2000, and 2001. SPPC's current contract with the IBEW Local No. 1245, which represents 62% of SPPC's workforce, was renegotiated in March 2000 and is in effect until December 31, 2002. The two-year contract provides for 3% general wage increases for bargaining unit employees beginning January 1, 2001, and January 1, 2002. In addition, the contract provides for participation by bargaining unit employees in the incentive compensation program. GENERAL - FRANCHISES (NVP AND SPPC) ----------------------------------- The Utilities have nonexclusive local franchises or revocable permits to carry on their business in the localities in which their respective operations are conducted in Nevada and California. The franchise and other governmental requirements of some of the cities and counties in which the Utilities operate provide for payments based on gross revenues. During 2000, the Utilities collected $47.2 million in franchise or other fees based on gross revenues. They also paid and recorded as expense $0.7 million of fees based on net profits.
Franchise Type of Service Expiration Date ----------------------------------------------------------------------------------------- NVP: Las Vegas Electric November 2029 Clark County Electric May 2004 Nye County Electric May 2006 City of Henderson * Electric November 1999 SPPC: Reno Electric, Gas and Water January 2006 Sparks Electric May 2006 Sparks Gas May 2007 Sparks Water April 2004 Carson City Electric February 2012 City of Elko Electric April 2017 City of South Lake Tahoe Electric April 2018 Washoe County Gas and Water May 2015 Washoe County Electric September 2015 Eureka County Electric July 2018
*Being renegotiated. The Utilities will apply for renewal of franchises in a timely manner prior to their respective expiration dates. 42 GENERAL - RESEARCH AND DEVELOPMENT (ALL) ---------------------------------------- SPR, through its NVP and SPPC subsidiaries, participates in several utility associations, including the Electric Power Research Institute. SPR has invested in Nth Power Technologies (Nth), a venture capital fund that invests in developing technology companies. Nth has made several investments that may result in SPR strengthening its market position and developing new products and services. ITEM 2. PROPERTIES The general character of SPR's, NVP's, and SPPC's principal facilities is discussed in Item 1 - Business. Substantially all of NVP's utility plant is subject to the lien of the Indenture of Mortgage, dated October 1, 1953, and supplemental indentures thereto between NVP and Bankers Trust Company, as trustee, securing NVP's outstanding first mortgage bonds. Substantially all of SPPC's utility plant is subject to the lien of the Indenture of Mortgage, dated December 1, 1940, and supplemental indentures thereto between SPPC and State Street Bank and Trust, as trustee, securing SPPC's outstanding first mortgage bonds. ITEM 3. LEGAL PROCEEDINGS SPR, through the course of its normal business operations, is currently involved in a number of legal actions, none of which has had or, in the opinion of management, is expected to have a significant impact on its financial position or results of operations. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS None. 43 PART II ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS SIERRA PACIFIC RESOURCES ------------------------ SPR's Common Stock is traded on the New York Stock Exchange (symbol SRP). The dividends paid per share and high and low sale prices of the Common Stock in the consolidated transaction reporting system in "The Dow Jones News Retrieval Service" for 2000 and 1999 are as follows: Dividends Paid Per Share High Low --------- ------- -------- 2000 First Quarter $.250 $18.437 $ 12.125 Second Quarter .250 15.687 12.500 Third Quarter .250 19.437 12.562 Fourth Quarter .250 18.062 14.875 1999 First Quarter .325 39.875 33.375 Second Quarter .340 37.000 34.500 Third Quarter* .250 39.125 21.125 Fourth Quarter .250 23.312 16.875 *The merger of SPR and NVP was consummated on July 28, 1999. After that time, SPR owned all of the outstanding common stock of NVP. Prior to that time, SPR owned no securities of NVP. Number of Security Holders: Title of Class Number of Holders -------------- ----------------- Common Stock: $1.00 Par Value As of December 31, 2000: 28,126 Dividends are considered periodically by the Board of Directors and are subject to factors that ordinarily affect dividend policy, such as earnings, business conditions, regulatory factors, the financial condition of SPR and other matters within the discretion of the Board. On December 12, 2000, the SPR Board of Directors voted for a quarterly common dividend of $.25 per share. This dividend of approximately $19.9 million was paid on February 1, 2001, to holders of record as of January 12, 2001. SPR's primary source of funds for the payment of dividends to its stockholders is dividends paid by SPPC and NVP on their common stock, all of which is owned by SPR. Certain contractual and regulatory restrictions may affect the ability of the Utilities to pay dividends to SPR. See Note 13 to the consolidated financial statements. As described herein, the unprecedented conditions in the wholesale energy markets have negatively affected the earnings of SPR, NVP and SPPC. If these conditions continue, without prompt relief, future earnings and the ability to pay dividends are also in question. 44 NVP and SPPC are wholly owned subsidiaries of SPR and, as such, each of their common stock is not publicly traded and no market exists for it. ITEM 6. SELECTED FINANCIAL DATA SIERRA PACIFIC RESOURCES ------------------------ The table below, for periods prior to July 28, 1999, reflects historical information for NVP.
Year Ended December 31, (dollars in thousands, except per share amounts) ---------------------------------------------------------------------------- 2000 1999 1998 1997 1996 --------- --------- --------- --------- --------- Operating Revenues $ 2,334,254 $ 1,284,792 $ 873,682 $ 799,148 $ 805,374 =========== =========== =========== =========== =========== Operating Income $ 127,389 $ 162,861 $ 147,277 $ 137,196 $ 132,230 =========== =========== =========== =========== =========== Net (Loss) Income $ (39,780) $ 51,750 $ 83,499 $ 82,091 $ 74,912 =========== =========== =========== =========== =========== (Losses) Earnings per Average Common Share $ (0.51) $ 0.83 $ 1.64 $ 1.65 $ 1.56 =========== =========== =========== =========== =========== Total Assets $ 5,639,484 $ 5,235,917 $ 2,541,840 $ 2,339,422 $ 2,163,224 =========== =========== =========== =========== =========== Long-Term Debt and Redeemable Preferred Securities $ 2,371,051 $ 1,793,999 $ 1,089,099 $ 1,014,311 $ 841,364 =========== =========== =========== =========== =========== Cash Dividends Paid Per Common Share $ 1.00 $ 1.17 $ 1.45 $ 1.60 $ 1.60 =========== =========== =========== =========== ===========
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS As discussed in the results of operations sections that follow, operating results for 2000 were negatively affected by significantly higher fuel and purchased power costs. These costs were reflective of higher and extremely volatile prices for purchased power and fuel that developed in May 2000 in the western United States and have continued since. Sierra Pacific Resources (SPR), Nevada Power Company (NVP), and Sierra Pacific Power Company (SPPC) cannot predict how long these unprecedented market conditions will persist. If such market conditions persist, they could have a material adverse effect on the future earnings of SPR, NVP and SPPC. In an effort to mitigate the effects of higher fuel and purchased power costs, NVP and SPPC (collectively the "Utilities") entered into the Global Settlement during 2000, permitting the Utilities to increase electric rates. The Global Settlement established a Fuel and Purchase Power (F&PP) Rider mechanism for each Utility that has resulted in incremental rate increases that are described in more detail later. However, because the mechanism for adjusting rates lags changes in actual energy costs and is subject to certain caps, increases have been insufficient to cover fuel and purchased power costs that continued to rise during the fourth quarter of 2000. In response to continued increases in fuel and purchased power costs and the imbalance between these costs and retail prices, SPR and the Utilities filed on January 29, 2001, an emergency 45 Comprehensive Energy Plan (CEP) with the Public Utilities Commission of Nevada (PUCN). In the CEP, SPR and the Utilities propose short-term emergency price increases ranging from zero for certain low-usage customers to as much as 29 percent for the state's largest energy users. The average increase is 17 percent. The CEP also addresses other issues including long-term contracts, low income assistance and conservation programs, all intended to help stabilize energy markets in the state. Also in the CEP, the Utilities propose to continue making the F&PP filings, which are scheduled to expire on March 1, 2003. Both the F&PP Rider and the CEP Rider proposed in the plan represent dollar-for- dollar pass through of wholesale costs. On February 23, 2001, the PUCN voted 3 to 0 to allow the CEP Rider to become effective March 1, 2001, reserving the right to review the reasonableness and to adjust these rates after an evidentiary hearing which will be scheduled at a pre-hearing conference on March 23, 2001. With respect to NVP, the F&PP Rider began September 1, 2000. This rider is based on the incremental increase in F&PP costs between two historic 12-month periods, subject to certain caps. The stipulation requires that filings be made by NVP each month, with the last filing to be made December 15, 2002, for rates effective February 1, 2003. As a result of the Global Settlement, in addition to a net annualized rate increase of $48 million that became effective as of August 1, 2000, the following monthly filings have been made to date for NVP:
Increase Increase Annualized Date Effective Incurred Allowed Increase Filing Filed Date Mills/kWh Mills/kWh (in millions) ------ ----- ----- --------- --------- ------------- 1 Aug-1, 2000 Sep-1, 2000 1.1 0.95 $15.1 2 Aug-15, 2000 Oct-1, 2000 2.56 0.95 15.3 3 Sep-15, 2000 Nov-1, 2000 2.97 0.95 15.6 4 Oct-15, 2000 Dec-1, 2000 2.91 0.95 15.8 5 Nov-15, 2000 Jan-1, 2001 1.41 0.95 15.8 6 Dec-15, 2000 Feb-1, 2001 0.42 0.42 8.2 7 Jan-15, 2001 Mar-1, 2001 0.17 1.15 16.6 8 Feb-15, 2001 April-1, 2001 0.36 1.15 16.8
As of March 14, 2001, the PUCN has approved and NVP has implemented the first seven of the above rate increases. In each monthly filing, NVP must include a calculation of its Fixed Charge Coverage Ratio for the 12-month period (May 2000 for the first filing). If the Fixed Charge Coverage Ratio is at or above 2.5, then no increase in the rider is allowed for that filing. In addition, every six months an audit of fuel and purchase power practices will be conducted. Any findings of imprudence by the PUCN are to be reflected in future F&PP rider filings. SPPC also entered into the Global Settlement, permitting it to file monthly fuel and purchased power adjustment cases. Beginning November 1, 2000, an F&PP Rider was established for SPPC. As with NVP, the rider is based on the incremental increase in F&PP costs between two 12-month periods, subject to certain caps. The first such filing for SPPC was based on comparing SPPC's F&PP costs for the 12 months ended July 2000 with SPPC's Base Tariff Energy Rate (BTER). The stipulation requires SPPC to make a filing each month, with the last filing to be made December 15, 2002, for rates effective February 1, 2003. 46 As a result of the stipulation, SPPC has filed with the PUCN for approval of the following electric rate increases:
Increase Increase Annualized Date Effective Incurred Allowed Increase Filing Filed Date Mills/kWh Mills/kWh $Millions ------ ----- ---- --------- --------- --------- 1 Sep-15, 2000 Nov-1, 2000 3.2 3.2 $25.7 2 Oct-15, 2000 Dec-1, 2000 1.5 0.95 7.7 3 Nov-15, 2000 Jan-1, 2001 1.6 0.95 7.7 4 Dec-15, 2000 Feb-1, 2001 0.82 0.82 6.7 5 Jan-15, 2001 Mar-1, 2001 1.29 0.95 7.7 6 Feb-15, 2001 April-1, 2001 4.01 0.95 7.9
As of March 14, 2001, the PUCN has approved and SPPC has implemented the first five of the above rate increases. The Fixed Charge Coverage Ratio and audit provisions are the same for SPPC as for NVP. In addition to the above rate filings, on November 1, 2000, SPPC filed with the PUCN to recover $26.8 million in additional costs to its natural gas distribution segment, to account for the higher cost of natural gas that SPPC pays to its suppliers. The increase went into effect February 1, 2001. Comparative fuel and purchased power cost information is included in each Utility's Results of Operations discussion that follows. Also see "Regulatory Events" that follows. RESULTS OF OPERATIONS SIERRA PACIFIC RESOURCES ------------------------ SPR incurred a net loss of $39.8 million for the year end December 31, 2000, compared to net income of $51.8 million in 1999. NVP and SPPC, SPR's principal subsidiaries, declared common stock dividends to their parent, SPR, of $64.3 million and $85 million, respectively. SPPC also declared $3.9 million in dividends to holders of its preferred stock. Operating results for 2000 were adversely affected by fuel and purchased power costs at the Utilities as previously mentioned and as discussed in the results of operations that follow. The merger between SPR and NVP was accounted for as a reverse purchase under generally accepted accounting principles, with NVP considered the acquiring entity, even though SPR became the legal parent of NVP. For accounting purposes, the merger was deemed to have occurred on August 1, 1999. As a result of this reverse purchase accounting treatment: (i) the historical financial statements of SPR for periods prior to the date of the merger are no longer the financial statements of SPR, and therefore, are no longer presented; (ii) the historical financial statements of SPR for periods prior to the date of the merger are those of NVP; (iii) based on a merger date of August 1, 1999, the Consolidating Statements of Income for the twelve months ended December 31, 1999, include five months (August through December 1999) of operating activity for SPR and its subsidiaries other than NVP and include the operating results of NVP for the entire periods presented; and (iv) the Consolidating Statements of Income for the twelve months ended December 31, 2000, include twelve months of operating activity for SPR and its subsidiaries. 47 SIERRA PACIFIC RESOURCES CONSOLIDATING STATEMENTS OF INCOME (Dollars in Thousands)
Year Ended December 31, 2000 -------------------------------------------------------- 12 months 12 months 12 months NVP SPPC Other Total --------------------------- ------------------------- OPERATING REVENUES: Electric $ 1,325,470 $ 893,782 $ - $ 2,219,252 Gas 100,803 - 100,803 Other - - 14,199 14,199 ----------- --------- ---------- ------------ 1,325,470 994,585 14,199 2,334,254 ----------- --------- ---------- ------------ OPERATING EXPENSES: Operation: Purchased power 671,396 444,979 - 1,116,375 Fuel for power generation 292,787 233,748 - 526,535 Gas purchased for resale - 83,199 - 83,199 Deferral of energy costs-net 16,719 (16,164) - 555 Other 139,723 96,438 24,335 260,496 Maintenance 34,057 18,420 - 52,477 Depreciation and amortization 85,989 69,350 696 156,035 Taxes: Income taxes (12,162) (672) (18,188) (31,022) Other than income 23,501 18,152 562 42,215 ----------- --------- ---------- ------------ 1,252,010 947,450 7,405 2,206,865 ----------- --------- ---------- ------------ OPERATING INCOME 73,460 47,135 6,794 127,389 ----------- --------- ---------- ------------ OTHER INCOME: Allowance for other funds used during construction 2,456 357 - 2,813 Other income (expense) - net 1,718 (2,429) 3,357 2,646 ----------- --------- ---------- ------------ 4,174 (2,072) 3,357 5,459 ----------- --------- ---------- ------------ Total Income Before Interest Charges 77,634 45,063 10,151 132,848 ----------- --------- ---------- ------------ INTEREST CHARGES: Long-term debt 64,513 36,865 33,218 134,596 Other 13,732 11,312 10,843 35,887 Allowance for borrowed funds used during construction and capitalized interest (7,855) (2,779) - (10,634) ----------- --------- ---------- ------------ 70,390 45,398 44,061 159,849 ----------- --------- ---------- ------------ (LOSS) INCOME BEFORE SPPC/NVP OBLIGATED MANDATORILY REDEEMABLE PREFERRED TRUST SECURITIES 7,244 (335) (33,910) (27,001) Preferred dividend requirements of obligated mandatorily redeemable preferred trust securities (15,172) (3,742) - (18,914) ----------- --------- ---------- ------------ (LOSS) INCOME BEFORE PREFERRED STOCK DIVIDENDS (7,928) (4,077) (33,910) (45,915) Preferred stock dividend requirements and redemption premium - (3,499) (3,499) ----------- --------- ---------- ------------ (LOSS) INCOME FROM CONTINUING OPERATIONS (7,928) (7,576) (33,910) (49,414) ----------- --------- ---------- ------------ INCOME FROM DISCONTINUED OPERATIONS - 9,634 - 9,634 ----------- --------- ---------- ------------ NET (LOSS) INCOME $ (7,928) $ 2,058 $ (33,910) $ (39,780) =========== ========= ========== ============
48 SIERRA PACIFIC RESOURCES CONSOLIDATING STATEMENTS OF INCOME (Dollars in Thousands)
Year ended Year Ended December 31, 1999 Dec. 31, 1998 ----------------------------------------------------------------- 12 months 5 months 5 months NVP SPPC Other Total NVP ------------------------- ------------------------------------ OPERATING REVENUES: Electric $977,262 $ 259,440 $ - $ 1,236,702 $ 873,682 Gas - 38,958 - 38,958 - Other - - 9,132 9,132 - ---------- --------- --------- ----------- ----------- 977,262 298,398 9,132 1,284,792 873,682 ---------- --------- --------- ----------- ----------- OPERATING EXPENSES: Operation: Purchased power 293,600 79,856 - 373,456 283,838 Fuel for power generation 154,546 51,584 - 206,130 149,804 Gas purchased for resale - 27,262 - 27,262 - Deferral of energy costs-net 97,238 - - 97,238 (29,680) Other 141,041 40,961 11,389 193,391 134,652 Maintenance 50,805 8,492 - 59,297 49,082 Depreciation and amortization 80,644 29,188 243 110,075 73,562 Taxes: Income taxes 19,943 10,602 (5,247) 25,298 42,949 Other than income 22,462 7,232 90 29,784 22,198 ---------- --------- --------- ----------- ----------- 860,279 255,177 6,475 1,121,931 726,405 ---------- --------- --------- ----------- ----------- OPERATING INCOME 116,983 43,221 2,657 162,861 147,277 ---------- --------- --------- ----------- ----------- OTHER INCOME: Allowance for other funds used during construction 3,713 (1,374) - 2,339 8,944 Other income (expense) - net (1,824) (853) 352 (2,325) (4,602) ---------- --------- --------- ----------- ----------- 1,889 (2,227) 352 14 4,342 ---------- --------- --------- ----------- ----------- Total Income Before Interest Charges 118,872 40,994 3,009 162,875 151,619 ---------- --------- --------- ----------- ----------- INTEREST CHARGES: Long-term debt 64,454 12,741 299 77,494 56,995 Other 8,815 5,885 11,529 26,229 6,018 Allowance for borrowed funds used during construction and capitalized interest (8,356) 356 - (8,000) (6,080) ---------- --------- --------- ----------- ----------- 64,913 18,982 11,828 95,723 56,933 ---------- --------- --------- ----------- ----------- (LOSS) INCOME BEFORE SPPC/NVP OBLIGATED MANDATORILY REDEEMABLE PREFERRED TRUST SECURITIES 53,959 22,012 (8,819) 67,152 94,686 Preferred dividend requirements of obligated mandatorily redeemable preferred trust securities (15,172) (1,570) - (16,742) (11,013) ---------- --------- --------- ----------- ----------- (LOSS) INCOME BEFORE PREFERRED STOCK DIVIDENDS 38,787 20,442 (8,819) 50,410 83,673 Preferred stock dividend requirements and redemption premium (95) (2,105) - (2,200) (174) ---------- --------- --------- ----------- ----------- (LOSS) INCOME FROM CONTINUING OPERATIONS 38,692 18,337 (8,819) 48,210 83,499 ---------- --------- --------- ----------- ----------- INCOME FROM DISCONTINUED OPERATIONS - 3,540 - 3,540 - ---------- --------- --------- ----------- ----------- NET (LOSS) INCOME $ 38,692 $ 21,877 $ (8,819) $ 51,750 $ 83,499 ========== ========= ========= =========== ===========
49 NEVADA POWER COMPANY -------------------- Results of Operations NVP's net loss in 2000 was $7.9 million, down from 1999 net income before dividend requirements on preferred stock of $38.8 million. The causes for significant changes in specific lines comprising the results of operations for NVP for the years ended are provided below (dollars in thousands except for amounts per unit): Electric Operating Revenue
2000 1999 1998 -------------------------------- ------------------------------- ------------- Change from Change from Amount Prior year Amount Prior year Amount -------------- --------------- ------------- -------------- ------------- Electric Operating Revenues: Residential $ 492,365 18.3% $ 416,345 9.5% $ 380,299 Commercial 227,790 13.8% 200,186 13.9% 175,760 Industrial 326,916 12.6% 290,409 16.4% 249,390 -------------- ------------- ------------- -------------- ------------- Retail revenues 1,047,071 15.5% 906,940 12.6% 805,449 Other 278,399 295.9% 70,322 3.1% 68,233 -------------- ------------- ------------- -------------- ------------- Total Revenues $ 1,325,470 35.6% $ 977,262 11.9% $ 873,682 ============== ============= ============= ============== ============= Total retail sales (MWH) 16,363,000 12.0% 14,615,000 8.3% 13,491,000 -------------- ------------- ------------- -------------- ------------- Average retail revenue per MWH $ 63.99 3.1% $ 62.06 3.9% $ 59.70
NVP's retail revenues increased in 2000 due to a combination of customer growth, warmer than normal weather, and rate increases resulting from the Global Settlement (see Regulatory Events, later). The number of residential, commercial, and industrial customers increased over the prior year by 5.6%, 4.6% and 7.4%, respectively. As a result of the Global Settlement, NVP implemented monthly rate increases starting August 1, 2000. Other electric revenues increased in 2000 due to large increases in wholesale power sales at much higher prices. NVP's increase in MWH sales from last year was a result of market conditions and NVP's hedging program. NVP regularly seeks to optimize its daily and hourly portfolio by buying and selling short excess power in the wholesale markets. NVP purchases fixed cost energy at a delivery point where the energy can either be delivered to its control area or traded, should NVP not require the energy. The energy is also traded if replacement energy can be obtained less expensively than transporting the energy to the control area. NVP neither purchases nor sells energy on a speculative basis. NVP's residential and commercial electric revenue increased in 1999 primarily due to 6% customer growth for both categories and an energy price increase of 4% effective March 1999. Industrial electric revenues increased in 1999 primarily due to 7% customer growth and an energy price increase of 4% effective March 1999. Other electric revenues increased in 1999 due to greater wholesale electric revenue that was partially offset by lower emission credit sales and water rights revenue in 1999. 50 Purchased Power
2000 1999 1998 --------------------------------- ------------------------------- ------------ Change from Change from Amount Prior year Amount Prior year Amount ----------- ------------- ------------- ------------- ------------ Total Purchased Power $ 671,396 98.1% $ 338,972 19.4% $ 283,838 Less Imputed Capacity Deferral - - (45,372) - - ----------- ------------ ------------ ------------- ------------ Purchased Power $ 671,396 128.7% $ 293,600 3.4% $ 283,838 =========== ============ ============ Purchased Power MWH 9,659,118 22.9% 7,861,985 14.2% 6,886,920 Average cost per MWH of Purchased Power $ 69.51 61.2% $ 43.12 4.6% $ 41.21
NVP's Purchased power costs were significantly higher in 2000 due to substantial increases in prices and higher volumes. A 61% increase in per unit cost of power was caused primarily by higher Short-Term Firm and "Economy" energy prices. These price increases were the result of much higher fuel costs to energy producers combined with increased demand and limited power supplies. Volumes purchased rose 23% to accommodate increases in system load and wholesale sales. Purchased power costs have been reduced by expected insurance recoveries for generation plant outages in 2000. The recoveries are estimated to total $18 million. Purchased power costs were higher in 1999 as compared to 1998 due to a 14% increase in the volume purchased and an increase in the per unit cost of power. This increase in cost was partially offset by a $45 million adjustment (shown separately above) in 1999 related to the deferral of the portion of one-part firm power contracts deemed by regulators to be related to capacity costs rather than energy costs. Fuel for Power Generation
2000 1999 1998 ------------------------------ ---------------------------------- -------------- Change from Change from Amount Prior year Amount Prior year Amount ------------- ------------- -------------- ---------------- ------------- Fuel for Power Generation $ 292,787 89.4% $ 154,546 3.2% $ 149,804 MWHs generated 10,744,466 17.2% 9,167,963 3.7% 8,843,057 Average fuel cost per MWH of Generated Power $ 27.25 61.7% $ 16.86 -0.5% $ 16.94
NVP's 2000 fuel expense increased over 89% compared to 1999 primarily due to a substantial increase in natural gas prices and, to a lesser degree, as a result of increased generation to accommodate system load. In 1999, NVP's fuel expense increased slightly due to an increase in volumes generated to accommodate customer growth. 51 Deferral of Energy Cost - Net
2000 1999 1998 -------------------------- ------------------------------- ----------- Change from Change from Amount Prior year Amount Prior year Amount ---------- ------------ ----------- -------------- ----------- Deferral of energy costs-net $ 16,719 -82.8% $ 97,238 N/A $ (29,680)
Deferral of energy costs-net decreased in 2000 because NVP discontinued deferred energy cost recognition effective August 1, 2000, pursuant to the July 2000 Global Settlement with the PUCN, and because of decisions, described below, by the PUCN affecting 1999's Deferral of energy costs-net. For more information on the Global Settlement, see Regulatory Events, later. In February and March 2000, the PUCN issued orders that rejected NVP's requested rate relief in its 1999 deferred energy filings. As a result of these decisions, a pre-tax charge of $80 million to Deferral of energy costs-net was made in 1999 to provide a reserve for previously deferred energy and imputed capacity costs. Also, deferral of energy costs-net were higher in 1999 because NVP was granted a price increase to cover current fuel expense, which allowed NVP to currently recognize previously deferred costs. In 1998, NVP deferred $27.0 million of increased energy costs for collection in a later period and recognized $2.7 million of energy cost deferrals that had been deferred prior to 1998. Prior to August 2000, recovery of fuel expenses was administered under Nevada's deferred energy cost accounting procedures. Under a deferred energy procedure, changes in the costs of fuel and purchased power are usually reflected in customer rates through annual rate adjustments and should not affect income. See Note 1 of "Notes to Financial Statements" for more information regarding deferred energy accounting. Allowance For Funds Used During Construction (AFUDC)
2000 1999 1998 ---------------------------------- --------------------------------- ------------ Change from Change from Amount Prior year Amount Prior year Amount ------------- ---------------- -------------- --------------- ------------ Allowance for other funds used during construction $ 2,456 -33.9% $ 3,713 -58.5% $ 8,944 Allowance for borrowed funds used during construction 7,855 -6.0% 8,356 37.4% 6,080 ------------- ---------------- ------------- -------------- ------------ $ 10,311 -14.6% $ 12,069 -19.7% $ 15,024 ------------- ---------------- ------------- -------------- ------------
NVP's AFUDC was lower in 2000 primarily due to an overall rate decrease resulting from an increase in short-term debt at a lower interest rate. AFUDC was lower in 1999 than 1998 because construction of the Crystal Transmission Project was completed in May 1999. 52
2000 1999 1998 ------------------------- ------------------------- ----------- Change from Change from Amount Prior year Amount Prior year Amount ---------- ------------- ---------- ------------- ---------- Other operating expense $139,723 -0.9% $141,041 4.7% $134,652 Maintenance expense 34,057 -33.0% 50,805 3.5% 49,082 Depreciation and amortization 85,989 6.6% 80,644 9.6% 73,562 Income taxes (12,162) -161.0% 19,943 -53.6% 42,949 Interest charges on long-term debt 64,513 0.1% 64,454 13.1% 56,995 Interest charges- other 13,732 55.8% 8,815 46.5% 6,018 Other income (expense)-net 1,718 -194.2% (1,824) -60.4% (4,602)
NVP's other operating expense for 2000 decreased due to reduced labor and benefit costs as a result of merger efficiencies and unfilled vacancies. These savings were offset, in part, by an increase in the provision for uncollectible accounts that included a provision of $7.3 million related to receivables from the California Power Exchange and California's Independent System Operator. NVP's other operating expense increased $6.4 million in 1999 over 1998 primarily due to growth related costs for distribution expenses and administrative and general costs that included group insurance and short-term incentive costs. The level of NVP's maintenance and repair expenses depends primarily upon the scheduling, magnitude and number of generation unit overhauls at NVP's generating stations. In 2000 maintenance expense decreased from the prior year primarily as a result of fewer planned plant maintenance activities at NVP's coal generation facilities. In addition, crews performed more required activities of a capital nature, thereby reducing the amount of maintenance expense. In 1999, maintenance expense increased by $1.7 million over 1998 primarily due to boiler maintenance at the Reid Gardner Generating Station. NVP's 2000 depreciation and amortization expense was higher due to an increase in electric plant-in-service over the prior year. Depreciation expense was higher in 1999 compared to 1998 because of the addition of approximately $280 million in depreciable assets including the completion of the Crystal Transmission Project in May 1999. Due to a net loss, NVP recorded an income tax benefit for 2000. NVP's income taxes were lower in 1999 as compared to 1998 due to lower operating income before taxes. NVP's interest charges on long-term debt for 2000 were comparable to 1999's. Interest charges on NVP's long-term debt were higher in 1999 than 1998 due to interest costs associated with $130.0 million of unsecured notes issued in March 1999. See Note 9 of "Notes to Financial Statements" for additional information regarding long-term debt. NVP's interest charges-other increased in 2000 compared to 1999 due to increased debt through the use of commercial paper in 2000 and due to interest costs associated with the issuance of floating rate notes in October 1999 and June, August, and December 2000. Interest charges-other were higher in 1999 than 1998 because of interest costs associated with higher short-term borrowings in 1999. NVP's other income (expense)-net improved in 2000 as a result of greater increases in life insurance cash surrender values and reductions in contributions and membership dues. Other income (expense)-net improved in 1999 compared to 1998 because corporate and short-term incentive costs were charged to operating expenses during 1999 rather than other expense. 53 Liquidity and Capital Resources NVP's net cash flows increased in 2000 compared to 1999. The net increase in cash resulted from less cash used in investing activities and more cash provided by financing activities. A reduction in the net cash used for utility plant was the main cause for the decrease in cash used for investing activities. The increase in cash flows from financing activities was due to an increase in funding received from SPR (less dividends paid) offset, in part, by less cash provided by the net issuance of long and short-term debt. The overall net increase in cash was also partially offset by a reduction in cash flows from operating activities that was mainly due to a decrease in operating income. NVP's overall net cash flows for 1999 were comparable to 1998. Increases in cash flows from operating activities and less cash used for investing activities were both substantially offset by less cash provided by financing activities. As discussed in "Construction Expenditures and Financing" and "Capital Structure" below, it is anticipated that NVP will have external capital requirements for construction costs and for the repayment of maturing short-term and long-term debt during 2001 totaling approximately $405 million, which NVP will need to fund through a combination of (i) the issuance of long-term and short-term debt and (ii) capital contributions from SPR. The remaining cash requirements for these categories in 2001 are anticipated to be provided by internally-generated funds. Construction Expenditures and Financing The table below provides NVP's consolidated cash construction expenditures and internally generated cash, net for 1998 through 2000 (Dollars in thousands):
2000 1999 1998 Total --------- --------- --------- --------- Cash construction expenditures $ 196,636 $ 220,919 $ 302,041 $ 719,596 ========= ========= ========= ========= Net cash flow from operating activities $ 113,711 $ 178,178 $ 148,281 $ 440,170 Less common & preferred cash dividends 88,308 121,646 73,962 283,916 --------- --------- --------- --------- Internally generated cash 25,403 56,532 74,319 156,254 Add equity contribution from parent 137,000 18,000 0 155,000 --------- --------- --------- --------- Total cash available $ 162,403 $ 74,532 $ 74,319 $ 311,254 ========= ========= ========= ========= Internally generated cash as a percentage of cash construction expenditures 13% 26% 25% 22% Total cash available as a percentage of cash construction expenditures 83% 34% 25% 43%
NVP's estimated cash construction expenditures for 2001 through 2005 are $875 million. NVP estimates that 70% (approximately $123 million) of its 2001 cash expenditures will be provided by internally generated funds, with the remainder (approximately $52 million) being provided by the issuance of long- term debt, short-term debt, and parent contributions. This estimate anticipates that NVP will pay all of its net income in dividends to SPR. NVP anticipates receiving $40 million of capital contribution from SPR in 2001. Capital Structure As of December 31, 2000, NVP had short-term debt outstanding of $100 million comprised entirely of floating rate notes. 54 On July 24, 2000, NVP received a 30-day extension of its $150 million Credit Facility to August 28, 2000, in accordance with the terms of the credit agreement. On August 28, 2000, NVP received a 364-day extension of this facility to August 27, 2001. NVP's actual consolidated capital structure at December 31, 2000, and 1999 was as follows (Dollars in thousands):
2000 1999 --------------------- ------------------- Short-Term Debt (1) $ 352,910 15% $ 271,842 12% Long-Term Debt 927,784 39% 931,004 42% Preferred Securities 188,872 8% 188,872 9% Common Equity (2) 887,737 38% 822,973 37% --------------------- ------------------- TOTAL $2,357,303 100% $2,214,691 100% ===================== ===================
(1) Including current maturities of long-term debt and preferred stock. (2) Does not include equity in Sierra Pacific Resources: 2000 = $471,975; 1999 = $654,156. SIERRA PACIFIC POWER COMPANY ---------------------------- Results of Operations As described in Note 17, Discontinued Operations, SPPC has adopted a plan to sell the water utility business. Accordingly, the water business is reported as a discontinued operation and the operating results have been reclassified to report separately the net results of operations from the water business. SPPC's net loss from continuing operations before dividend requirements on preferred stock in 2000 was $4.1 million, down from net income of $64.6 million in 1999. SPPC's operating results that follow are based upon the Sierra Pacific Power Company Consolidated Statements of Income included in Item 8 of this report. The components of gross margin are (dollars in thousands):
2000 1999 1998 -------- -------- -------- Operating Revenues: Electric $893,782 $609,197 $585,657 Gas 100,803 100,177 99,532 -------- -------- -------- Total Revenues 994,585 709,374 685,189 -------- -------- -------- Energy Costs: Electric 678,727 294,846 271,773 Gas 83,199 68,125 65,430 -------- -------- -------- Total Energy Costs 761,926 362,971 337,203 -------- -------- -------- Gross Margin $232,659 $346,403 $347,986 ======== ======== ======== Gross Margin by Segment: Electric $215,055 $314,351 $313,884 Gas 17,604 32,052 34,102 -------- -------- -------- Total $232,659 $346,403 $347,986 ======== ======== ========
55 The causes for significant changes in specific lines comprising the results of operations for the years ended are provided below (dollars in thousands except for amounts per unit): Electric Operating Revenues
2000 1999 1998 --------------------------- -------------------------- ---------- Change from Change from Amount Prior year Amount Prior year Amount ---------- ------------- ---------- ------------- ---------- Electric Operating Revenues: Residential $ 178,701 4.2% $ 171,533 1.4% $ 169,109 Commercial 196,846 4.5% 188,348 5.4% 178,752 Industrial 196,143 5.6% 185,771 0.5% 184,820 ---------- ------------- ---------- ------------- ---------- Retail revenues 571,690 4.8% 545,652 2.4% 532,681 Other 322,092 406.9% 63,545 20.0% 52,976 ---------- ------------- ---------- ------------- ---------- Total Revenues $ 893,782 46.7% $ 609,197 4.0% $ 585,657 ========== ============= ========== ============= ========== Retail sales in megawatt-hours (MWH) 8,807,332 4.7% 8,412,853 4.5% 8,047,650 ---------- ------------- ---------- ------------- ---------- Average retail revenue per MWH $ 64.91 0.1% $ 64.86 -2.0% $ 66.19
As a result of the Global Settlement (see Regulatory Events, later), beginning in November 2000, the PUCN allowed SPPC to begin recovery of increases in fuel and purchased power costs. For the months of November and December, this recovery added revenues of approximately $2.9 million. The increases in residential and commercial electric revenues in 2000 were also due to warmer weather during the cooling-season than in 1999 as evidenced by a 15% increase in cooling degree days, and, to a lesser extent, by increases in customers. The increase in industrial electric revenues was also due to significant increases in usage per customer, primarily by mining customers, more than offsetting the migration of some customers to the commercial class. Other electric revenues increased in 2000 due to large increases in wholesale power sales at much higher prices. SPPC's increase in MWH sales from last year was a result of market conditions and SPPC's hedging program. SPPC regularly seeks to optimize its daily and hourly portfolio by buying and selling short excess power in the wholesale markets. SPPC purchases fixed cost energy at a delivery point where the energy can either be delivered to its control area or traded, should SPPC not require the energy. The energy is also traded if replacement energy can be obtained less expensively than transporting the energy to the control area. SPPC neither purchases nor sells energy on a speculative basis. In 1999, residential, commercial and industrial electric revenues were higher due to 3% increases in both residential and commercial customers and a 7.8% increase in industrial customers. The increases in residential and industrial revenues were partially offset by lower use per residential customer due to milder weather and lower use per industrial customer because of reduced production by several of SPPC's gold mining customers. The average retail revenue per MWh was lower for 1999 because of increased revenues from customers that are charged lower rates per MWh. Other electric revenues were higher due to a $19.4 million increase in wholesale electric sales. 56 Gas Operating Revenues
2000 1999 1998 --------------------------------- --------------------------------- ----------- Change from Change from Amount Prior year Amount Prior year Amount ----------- ---------------- ------------- --------------- ----------- Gas Operating Revenues: Residential $ 43,541 1.5% $ 42,888 -2.2% $ 43,833 Commercial 21,368 0.5% 21,259 -3.5% 22,022 Industrial 11,307 0.5% 11,252 -9.0% 12,368 Miscellaneous 1,782 36.6% 1,305 281.3% (720) ----------- -------------- ------------- -------------- ----------- Total retail revenue 77,998 1.7% 76,704 -1.0% 77,503 Wholesale revenue 22,805 -2.8% 23,473 6.6% 22,029 ----------- -------------- ------------- -------------- ----------- Total Revenues $ 100,803 0.6% $ 100,177 0.6% $ 99,532 =========== ============== ============= ============== =========== Sales (Decatherms): Retail 13,239,534 -1.1% 13,387,819 -5.3% 14,142,782 Wholesale 5,521,317 -47.0% 10,424,212 -11.2% 11,738,372 ----------- -------------- ------------- -------------- ----------- Total 18,760,851 -21.2% 23,812,031 -8.0% 25,881,154 ----------- -------------- ------------- -------------- ----------- Average revenues per decatherm Retail $ 5.89 2.8% $ 5.73 4.6% $ 5.48 Wholesale $ 4.13 83.6% $ 2.25 19.7% $ 1.88
Residential, commercial and industrial gas revenues in 2000 were comparable to 1999. Increases from customer growth were largely offset by lower usage as a result of milder temperatures during the heating seasons. Overall, wholesale gas sales declined slightly in 2000. A 47% decline in unit (decatherm) sales was the result of less gas available for wholesale sales because of significant increases in the usage of gas supplies for electricity generation. This decline was nearly balanced by an 83% increase in wholesale unit prices. Residential, commercial and industrial gas revenues were lower in 1999 because of lower per customer use resulting from milder weather in 1999. Lower gas revenues in 1999 were partially offset by additional customers in all categories. Wholesale gas revenues were higher due to several large gas sales contracts in the first quarter of 1999. Purchased Power
2000 1999 1998 ------------------------------- ---------------------------- ------------ Change from Change from Amount Prior Year Amount Prior Year Amount ------------- --------------- ------------ ------------- ------------ Purchased Power $ 444,979 147.5% $ 179,781 14.5% $ 156,970 Purchased Power MWH 7,349,000 26.8% 5,797,903 25.4% 4,623,959 Average cost per MWH of Purchased Power $ 60.55 95.3% $ 31.01 -8.7% $ 33.95
Purchased power costs increased dramatically in 2000 due to economy and wholesale energy prices nearly doubling. These price increases were the result of much higher fuel costs to energy producers combined with increased demand and limited power supplies. Volumes purchased were also higher to accommodate increased system load. 57 Purchased power costs were higher in 1999 than 1998 primarily because SPPC fulfilled more of its total energy requirements with less expensive purchased power and reduced its own generation. Purchased power costs were also higher during 1999 due to increased wholesale sales. The higher costs were partially offset by lower average unit prices for purchased power. Fuel For Power Generation
2000 1999 1998 ------------------------------ -------------------------------- -------------- Change from Change from Amount Prior year Amount Prior year Amount ------------ ------------- ------------- ------------- -------------- Fuel for Power Generation $ 233,748 103.1% $ 115,065 0.2% $ 114,803 MWHs generated 5,756,000 15.2% 4,998,140 -9.5% 5,524,262 Average fuel cost per MWH of Generated Power $ 40.61 76.4% $ 23.02 10.8% $ 20.78
Fuel for power generation costs more than doubled in 2000 due mainly to significant increases in natural gas prices, and, to a lesser extent, because volumes purchased were higher to accommodate greater system load. Fuel for generation costs in 1999 were comparable with 1998 because higher gas prices were nearly offset by a 9.5% reduction in the volume of electric generation as SPPC was able to replace electricity from generation with less expensive purchased power. Gas Purchased for Resale
2000 1999 1998 ------------------------------ ------------------------------------- -------------- Change from Change from Amount Prior year Amount Prior year Amount -------------- ------------ -------------- -------------- -------------- Gas Purchased for Resale Retail $ 65,744 37.8% $ 47,696 7.2% $ 44,473 Wholesale 17,455 -14.6% 20,429 -2.5% 20,957 -------------- ----------- -------------- ------------- -------------- Total $ 83,199 22.1% $ 68,125 4.1% $ 65,430 =============- =========== ============== ============= ============== Gas Purchased for Resale (decatherms) Retail 12,964,605 -4.0% 13,501,728 -6.6% 14,462,505 Wholesale 5,492,507 -47.3% 10,424,212 -11.2% 11,738,372 -------------- ----------- -------------- ------------- -------------- Total 18,457,112 -22.9% 23,925,940 -8.7% 26,200,877 ============== =========== ============== ============= ============== Average cost per decatherm Retail $ 5.07 43.6% $ 3.53 14.6% $ 3.08 Wholesale $ 3.18 62.2% $ 1.96 9.5% $ 1.79
The cost of gas purchased for resale increased in 2000 because a decrease in the quantities of gas purchased was more than offset by large increases in unit prices. The decline in retail gas purchases corresponds to decreases in demand by SPPC's retail customers. The decrease in wholesale purchases 58 was the result of increased power plant consumption of gas, thereby decreasing the availability of gas for wholesale activities. The significant gas price increases are consistent with the regional growth in demand for limited supplies of natural gas. The cost of gas purchased for retail sales increased slightly in 1999 because of higher unit prices attributable to increased demand for gas in the Pacific Northwest and additional transportation fees. Deferral of Energy Cost - Net
2000 1999 1998 ----------------------------- ------------------------- ------------ Change from Change from Amount Prior year Amount Prior year Amount --------- ------------- -------- ------------ ------------ Deferral of energy costs-net $(16,164) N/A $ - N/A $ -
In January 2000, SPPC began deferring natural gas costs in excess of that allowed in the tariff for its gas LDC, after the expiration of a rate freeze that was in effect from 1997 through 1999. Recovery of fuel expenses is administered under Nevada's deferred energy cost accounting procedures. Under the deferred energy procedure, changes in the costs of fuel and purchased power are reflected in customer rates through annual rate adjustments and do not affect income. See Note 1 of "Notes to Financial Statements" for more information regarding deferred energy accounting. Allowance For Funds Used During Construction (AFUDC)
2000 1999 1998 --------------------------- ------------------------------ -------- Change from Change from Amount Prior year Amount Prior year Amount -------- ------------ -------- ------------- -------- Allowance for other funds used during construction $ 357 N/A $(1,370) -138.2% $3,589 Allowance for borrowed funds used during construction 2,779 1870.9% 141 -97.7% 6,000 ------ ------- ------- ------- ------ $3,136 N/A $(1,229) -112.8% $9,589 ------ ------- ------- ------- ------
SPPC's total allowance for funds used during construction was higher in 2000 compared to 1999 due to higher construction work-in-progress balances in 2000, an AFUDC rate increase, and an adjustment to AFUDC in 1999 discussed below. AFUDC was lower in 1999 than 1998 because of construction completed in June and December 1998 for the Pinon and Alturas projects, respectively. Also, the 1999 amounts reflect a $2.3 million adjustment to reverse amounts previously charged to AFUDC. 59 2000 1999 1998 ------------------------- -------------------------- -------------- Change from Change from Amount Prior year Amount Prior year Amount -------- ------------ -------- -------------- -------------- Other operating expense $96,438 4.0% $92,745 -2.0% $94,669 Maintenance expense 18,420 -9.3% 20,309 -0.3% 20,374 Depreciation and amortization 69,350 -0.6% 69,762 12.5% 61,990 Income taxes (672) -102.0% 33,870 -14.8% 39,753 Interest charges on long-term debt 36,865 18.3% 31,151 11.3% 27,979 Interest charges- other 11,312 0.2% 11,286 55.0% 7,283 Other income (expense)-net (2,429) 260.9% (673) -1301.8% 56
SPPC's other operating expense for 2000 was higher due to an increase in the provision for uncollectible accounts offset, in part, by reduced labor and benefit costs as a result of merger efficiencies and unfilled vacancies. Other operating expense for 1999 includes a $4.5 million adjustment, which increased expense and reduced revenue related to a rate reserve established in 1998. This was offset by other reductions. Maintenance expense for 2000 decreased from 1999 as a result of fewer outages and lower plant maintenance expenses. Maintenance expense for 1999 was comparable to the prior year. Depreciation and amortization expense decreased in 2000 because an increase due to growth was more than offset by a reduction as a result of the full amortization of computer software. Depreciation and amortization expense increased for 1999 compared to 1998 due to the completion of the Alturas Intertie in December 1998 and the Pinon Pine Post-Gasification facilities in June 1998. Due to a net loss from continuing operations, SPPC recorded an income tax benefit for 2000. Operating income taxes were less in 1999 than 1998 due to lower operating income before taxes. Interest charges on long-term debt were higher in 2000 as a result of increased average long-term debt balances compared to 1999, including the June 2000 issuance of $200 million of variable rate notes. Interest on long-term debt was higher in 1999 than in 1998 due to higher average long-term debt balances than the prior year. SPPC's interest charges-other in 2000 were comparable to 1999. Interest charges-other were higher for 1999 than in 1998 because of a PUCN decision to assess partial interest on amounts payable in a prior year's earnings sharing case and higher average short-term borrowing in 1999. SPPC's other income (expense)-net declined in 2000 mainly due to the reclassification of lease expenses for SPPC's main offices. Other income (expense)-net declined in 1999 compared to 1998 primarily because of a reduction in miscellaneous interest income. 60
2000 1999 1998 --------------------------- --------------------------- --------- Change from Change from Amount Prior year Amount Prior year Amount -------- ------------- --------- ------------ --------- Discontinued Operations: Income from operations of water business $9,634 46.3% $6,583 645.5% $ 883 ====== ==== ====== ===== =====
Income from operations of the water business increased in 2000 due primarily to higher revenues. The increase in revenues resulted from both customer growth and to a lesser extent higher usage per customer. Income from operations of the water business increased in 1999 over 1998 due primarily to higher revenues. The increase in revenues resulted from both customer growth and an April 1998 price increase. Liquidity and Capital Resources SPPC's net cash flows increased in 2000 compared to 1999. The net increase in cash resulted from less cash used in investing activities and more cash provided by financing activities. The decrease in cash used for investing activities was primarily due to SPPC's 1999 acquisition of General Electric Capital Corporation's interest in Pinon Pine Company L.L.C. Cash flows from financing activities increased slightly compared to the prior year due to the retirement of preferred stock in 1999. See Note 8 (Preferred Stock and Preferred Securities) for information concerning the preferred stock retirement. The overall net increase in cash was partially offset by a reduction in cash flows from operating activities that was mainly due to a decrease in operating income. Overall net cash flows decreased during 1999, as compared to 1998, due to lower net cash flows from operating activities and to a lesser extent greater cash used in investing activities. The decrease in cash flows from operating and investing activities was partially offset by cash provided from financing activities. The decrease in cash provided from operating activities was primarily due to cash utilized for customer refunds and merger related cash requirements. The increase in cash used for investing activities was due to SPPC's acquisition of General Electric Capital Corporation's interest in Pinon Pine Company L.L.C., GPSF-B. Net cash provided by financing activities resulted from the issuance of $24 million of California rate reduction bonds in April 1999, and $100 million floating rate notes issued on September 17, 1999. See Note 9 of "Notes to Financial Statement" for more details regarding the California bonds. As discussed in "Construction Expenditures and Financing" and "Capital Structure" below, it is anticipated that SPPC will have capital requirements for construction costs and for the repayment of maturing short-term and long-term debt during 2001 totaling approximately $453 million, which SPPC will need to fund through a combination of (i) the issuance of long-term and short-term debt and (ii) the proceeds from the sale of the water business. 61 Construction Expenditures and Financing
2000 1999 1998 Total --------- --------- --------- --------- Cash construction expenditures $ 132,354 $ 116,131 $ 139,098 $ 387,583 ========= ========= ========= ========= Net cash flow from operating activities $ 112,010 $ 122,329 $ 153,191 $ 387,529 Less common & preferred cash dividends 84,899 81,746 80,459 247,104 --------- --------- --------- --------- Internally generated cash 27,111 40,583 72,732 140,425 Add equity contribution from parent 14,000 22,000 17,250 53,250 --------- --------- --------- --------- Total cash available $ 41,111 $ 62,583 $ 89,982 $ 193,675 ========= ========= ========= ========= Internally generated cash as a percentage of cash construction expenditures 20% 35% 52% 36% Total cash available as a percentage of cash construction expenditures 31% 54% 64% 50%
SPPC's estimated cash construction expenditures for 2001 through 2005 are $640 million. SPPC estimates that all of its 2001 cash expenditures (approximately $125 million) will be provided by the issuance of long-term debt, short-term debt, and proceeds from the sale of the water business. This estimate anticipates that SPPC will pay all of its net income in dividends to SPR. Capital Structure As of December 31, 2000, SPPC had short-term debt outstanding of $108.9 million comprised entirely of commercial paper. On July 24, 2000, SPPC received a 30-day extension of its $150 million Credit Facility to August 28, 2000, in accordance with the terms of the credit agreement. On August 28, 2000, SPPC received a 364-day extension of this facility to August 27, 2001. SPPC's actual capital structure at December 31, 2000, and 1999 was as follows (dollars in thousands):
2000 1999 ---------------- ---------------- Short-Term Debt (1) $ 328,578 20% $ 212,339 13% Long-Term Debt 605,816 37% 625,430 39% Preferred Stock 50,000 3% 50,000 3% Preferred Securities 48,500 3% 48,500 3% Common Equity 604,795 37% 673,738 42% ---------------- ---------------- TOTAL $1,637,689 100% $1,610,007 100% ================ ================
(1) Including current maturities of long-term debt and preferred stock. RESULTS OF OPERATIONS - OTHER SUBSIDIARIES ------------------------------------------ Tuscarora Gas Pipeline Company TGPC, a wholly owned subsidiary of SPR, contributed $2.1 million in net income for the twelve months ended December 31, 2000. The Consolidated Statements of Income of Sierra Pacific Resources for the year ended December 31, 1999, include the operating results of TGPC for the five month period ended December 31, 1999, based on a merger date of August 1, 1999, for accounting purposes. TGPC contributed $711 thousand in net income for the five months ended December 31, 1999. TGPC contributed $1.8 million in net income for the twelve months ended December 31, 1999. 62 Sierra Pacific Communications SPC, a wholly owned subsidiary of SPR, incurred a net loss of $989 thousand for the twelve months ended December 31, 2000. The Consolidated Statements of Income of Sierra Pacific Resources for the year ended December 31, 1999, include the operating results of SPC, for the five month period ended December 31, 1999, based on a merger date of August 1, 1999, for accounting purposes. SPC incurred a net loss of $62 thousand for the five months ended December 31, 1999. SPC incurred a net loss of $75 thousand for the twelve months ended December 31, 1999. e-three e.three, a wholly owned subsidiary of SPR, contributed $338 thousand of net income for the twelve months ended December 31, 2000. The Consolidated Statements of Income of Sierra Pacific Resources for the year ended December 31, 1999, include the operating results of e.three, for the five month period ended December 31, 1999, based on a merger date of August 1, 1999, for accounting purposes. e.three incurred a net loss of $381 thousand for the five months ended December 31, 1999. e.three incurred a net loss of $788 thousand for the twelve months ended December 31, 1999. Sierra Pacific Energy Company SPE, a wholly owned subsidiary of SPR, incurred a net loss of $4.5 million for the twelve months ended December 31, 2000. The Consolidated Statements of Income of Sierra Pacific Resources for the year ended December 31, 1999, include the operating results of SPE for the five month period ended December 31, 1999, based on a merger date of August 1, 1999, for accounting purposes. SPE incurred a net loss of $2.2 million for the five months ended December 31, 1999. SPE incurred a net loss of $3.6 million for the twelve months ended December 31, 1999. Lands of Sierra LOS, a wholly owned subsidiary of SPR, incurred a net loss of $191 thousand for the twelve months ended December 31, 2000. The Consolidated Statements of Income of Sierra Pacific Resources for the year ended December 31, 1999, include the operating results of LOS for the five month period ended December 31, 1999, based on a merger date of August 1, 1999, for accounting purposes. LOS contributed net income of $816 thousand for the five months ended December 31, 1999. LOS contributed net income of $810 thousand for the twelve months ended December 31, 1999. Nevada Electric Investment Company Nevada Electric Investment Company (NEICO), a wholly owned subsidiary of SPR, contributed net income of $384 thousand for the twelve months ended December 31, 2000. NEICO was, prior to 2000, a wholly owned subsidiary of NVP. Accordingly, NEICO's operating results for the twelve months ended December 31, 1999 (a net loss of $594,000), are included in NVP's operating results for that period. Sierra Pacific Resources (Holding Company) The holding company operating results included approximately $44.5 million and $11.5 million of interest costs for 2000 and 1999 that resulted primarily from the merger financing. For additional merger information, see Note 2 of the consolidated financial statements included in this report. 63 Liquidity and Capital Resources (SPR Consolidated) SPR's net cash flows increased in 2000 compared to 1999. The net increase in cash resulted from less cash used in investing activities offset substantially by decreases in cash from operating and financing activities. The decrease in cash flows used in investing activities is due to the merger cash requirements included in the 1999 amounts. Cash flows from operating activities were less in 2000 due primarily to a decrease in operating income and an increase in accounts receivable, offset, in part, by increases in accounts payable and depreciation and amortization. Cash flows from financing activities decreased in 2000 compared to 1999 because most of the cash provided by long- term debt issued in 2000 was utilized to retire short-term borrowings and other long-term debt. See Notes 9 (Long Term Debt) and 12 (Short-Term Borrowings) for detailed financing information. Overall net cash flows increased slightly during 1999, as compared to 1998. Net cash flows were greater in 1999 due to more cash provided from operating and financing activities. The increase in cash provided from operating and financing activities was partially offset by more cash used in investing activities. The increase in cash flows from operating activities was primarily due to the collection of revenues related to previously deferred energy costs. Increased cash from financing activities resulted from the issuance of $456.2 million of commercial paper by SPR to provide funding of the cash portion of the merger consideration. Also, NVP issued long-term debt of $130 million senior unsecured notes, and SPPC and NVP each issued $100 million floating rate notes in September and October 1999, respectively. Cash utilized for investing activities increased primarily as a result of the merger cash requirements. See Note 2 to the consolidated financial statements included in this report for more information about the merger cash requirements. Construction Expenditures and Financing (SPR Consolidated) The table below provides SPR's consolidated cash construction expenditures and internally generated cash, net for 2000 and 1999. The historical information for 1998 is NVP information (Dollars in thousands):
2000 1999 1998 Total ---------- ---------- ---------- ----------- Cash construction expenditures* $ 328,990 $ 729,794 $ 302,041 $ 1,360,825 ========== ========== ========== =========== Net cash flow from operating activities 185,896 211,089 148,281 545,266 Less common & preferred cash dividends 83,057 115,833 73,962 272,852 ---------- ---------- ---------- ----------- International generated cash 102,839 95,256 74,319 272,414 ========== ========== ========== =========== Internally generated cash as a percentage of cash construction expenditures 31% 13% 25% 20%
* 1999 cash construction expenditures include $448.3 million of merger related costs. SPR's estimated cash construction expenditures for 2001 through 2005 are $1.5 billion. SPR estimates that 14% (approximately $47 million) of its 2001 cash expenditures will be provided by internally generated funds, with the remainder being provided by the issuance of long-term debt, short-term debt, and proceeds from the sale of the water business. It is anticipated that the Utilities will pay all of their net income in dividends to SPR. SPR anticipates capital contributions of $40 million to NVP in 2001, which NVP will use, together with proceeds from the issuance of long- term and short-term debt, to fund construction. SPPC will utilize proceeds from the issuance of long-term and short-term debt, and proceeds from the sale of the water business to fund construction. 64 Capital Structure (SPR Consolidated) SPR's actual consolidated capital structure at December 31, 2000, and 1999 was as follows (Dollars in thousands):
2000 1999 ---------------- ---------------- Short-Term Debt (1) $ 685,601 15% $ 957,688 22% Long-Term Debt 2,133,679 48% 1,556,627 36% Preferred Stock 50,000 1% 50,000 1% Preferred Securities 237,372 5% 237,372 6% Common Equity 1,359,712 31% 1,477,129 35% ---------------- ---------------- TOTAL $4,466,364 100% $4,278,816 100% ================ ================
(1) Including current maturities of long-term debt and preferred stock. Included in amounts above for Short-Term and Long-Term Debt is $4 million and $600 million, respectively, of SPR holding company debt. REGULATORY EVENTS (NVP AND SPPC) -------------------------------- Substantially all of the utility operations of both NVP and SPPC are conducted in Nevada. As a result both companies are subject to utility regulation within Nevada and therefore deal with many of the same regulatory issues. Also see Note 20, Subsequent Events, in the Notes to Financial Statements. Nevada Electric Restructuring Competition in the Nevada electricity market was originally scheduled to start on March 1, 2000. However, in February 2000 the Governor of Nevada delayed the date of competition indefinitely. Generally, restructuring regulations and PUCN decisions during 2000 proceeded slowly. Numerous hearings and workshops have been held by the PUCN regarding three important regulations, "provider of last resort", "past costs", and "renewable portfolio requirements" regulations. In accordance with Financial Accounting Standard Board (FASB) Statement No. 71, "Accounting for the Effects of Certain Types of Regulation," SPPC's and NVP's financial statements reflect the effects of rate regulation and decisions by regulatory commissions. For example, expenses may be deferred as regulatory assets on the balance sheet and subsequently be amortized to the income statement when they are recovered from customers in future periods. Similarly, certain items may be deferred as regulatory liabilities, which are also eventually amortized to the income statement. Management periodically assesses whether the requirements for application of SFAS 71 are satisfied. In 1997, the Emerging Issues Task Force of the FASB concluded that once sufficiently detailed deregulation guidance is issued, an entity should discontinue applying SFAS 71 to the separable portion of their business whose pricing is being deregulated. However, an entity may continue to recognize regulatory assets previously associated with that separable portion of their business provided that the transition plan provides for their recovery through the regulatory process. Given the uncertainty related to the current restructuring legislation and PUCN restructuring rules that would ultimately enable retail competition in Nevada, SPPC and NVP continue to apply regulatory accounting to the generation, transmission and distribution portions of their businesses. On March 28, 2000, SPR, NVP and SPPC filed a federal lawsuit challenging Nevada's laws providing for competition in the electric utility industry and the PUCN's implementation of competition. 65 On July 20, 2000, the PUCN approved the Global Settlement that resolved pending state and federal lawsuits and major restructuring issues, including past costs. On August 3, 2000, the PUCN approved 19 revisions to the stipulated agreements. The stipulations provided for open access to occur in a phased manner beginning in November 2000 for large commercial customers and continuing until September 2001 for residential customers. On October 4, 2000, the Governor announced that he had decided to delay the opening of the electricity market in order to allow the state to develop a comprehensive energy policy. The Governor also appointed a bipartisan panel, NEEPC to develop a long-term strategy and report its findings by January 15, 2001, prior to the start of the 2001 legislative session. Management believes it is probable that changes will be made to restructuring legislation and/or PUCN restructuring rules, although it is not possible at this time to predict the nature of those changes or to assess their possible impact on the Utilities. On January 15, 2001, the NEEPC issued its report providing recommendations on electric restructuring issues to the Governor. The report addressed several areas including low income assistance, conservation, renewables, and incentives for encouraging supply. The committee recommended that the market not open until conditions beneficial to Nevada exist. In addition recommendations were provided for market stabilization. The NEEPC report includes a position paper provided by the Southern Nevada Water Authority (SNWA). The SNWA proposes that a non-profit governmental entity be considered as the provider of energy. In February 2001, the Governor of Nevada issued the Nevada Energy Protection Plan. This Plan calls for implementation of conservation measures, measures to facilitate construction of new power plants, new transmission capability, and a focus on alternative energy sources. In addition, the Plan calls for a re-examination of divestiture and places an indefinite halt on the implementation of restructuring. Highlights of the July 20, 2000 Stipulations (The Global Settlement): -------------------------------------------------------------------- Fuel and Purchased Power Rider The Global Settlement established a Fuel and Purchase Power (F&PP) Rider which allowed NVP to increase its rates effective August 1, 2000, by approximately $48 million annually to recover increased costs of fuel and purchased power, and to update its going-forward costs of fuel and purchased power thereafter with monthly fuel and purchased power filings up to March 2003. Increases and/or decreases are capped at incrementally increased or decreased rates over successive six-month periods at .95 mils for the first six months, 1.15 mils for the second six months, 1.25 mils for the third six months, 1.55 mils for the next six months, and 1.75 mils for the remaining period. The Settlement also permits SPPC to commence filing monthly fuel and purchased power adjustment cases on the same basis to commence not later than November 1, 2000. SPPC fuel and purchased power increases and/or decreases are also capped at incrementally increased or decreased rates over successive six-month periods starting October 1, 2000, at 4.5 mils for the first six-month period followed by .95, 1.15, 1.35, 1.55, and 1.75 mils for each successive six-month period. See the tables at beginning of Management's Discussion and Analysis for actual rate increases implemented to date. 66 Incentives for Utilities to Meet Open Access Dates Provided that open access procedures including billing and settlement are in place by the open access dates, NVP and SPPC will be allowed to retain up to $16 million and $9 million, respectively, from any gain on the divestiture of generation assets. Past Costs Major past cost issues are resolved by the stipulations. The Utilities have waived their rights to the collection of any past costs other than those provided for in the stipulations. The parties have agreed that the stipulations eliminate the need for a past cost regulation. Generation Divestiture The gain on the sale of generation facilities for regulatory purposes will be calculated based upon recorded book values as of the date of sale and includes costs of sale, less applicable taxes and amounts related to the Transitional Purchase Power Agreements ("TPPAs"). Common and general plant allocable to generation will be recoverable from the gain. NVP is to receive the first $15 million dollars in settlement for certain deferred energy costs. Additional gain, if any, from the sale of NVP's generation facilities will be applied to the allowed incentive to NVP for meeting retail open access dates, as described above. Additional gain, if any, up to $9 million, from the sale of SPPC's generation facilities will be applied to the allowed incentives to SPPC for meeting retail open access dates, as described above. Any remaining gains will be set aside in escrow accounts to be utilized to pay down costs associated with above-market purchased power contracts. Long-Term Purchased Power Contracts The Utilities will auction their purchased power contracts on an annual basis in the wholesale markets. If the auction does not yield sufficient proceeds to pay for the purchased power contracts, the Utilities will collect the difference from all customers through a non-bypassable wires charge. This Purchased Power Agreement Adjustment Mechanism (PPAAM) charge will be in place when the market opens. The Utilities filed their first PPAAM with the PUCN on October 2, 2000. To the extent that there are tax or market advantages, the Utilities will pursue a competitive permanent auction of purchased power contracts. Such an auction would be funded by an amount not to exceed the principal and interest in the escrow accounts that were funded by the gain on the sale of generation assets. If the permanent auction does not proceed or if such auction does not exhaust the generation escrow accounts, the PPAAM charge will be reduced by an annuity calculated on any remaining amount in the generation escrow account. Transition Costs The ability of the Utilities to recover costs they expect to spend to open the market, referred to as transition costs, was not resolved by the stipulations. The Utilities expect to petition the PUCN in the near future to request recovery of their transition costs. In other matters related to restructuring, the PUCN has continued rulemaking and discussion related to a number of topics including: 67 Provider Of Last Resort ----------------------- The PLR will provide electric service to customers who do not select an electricity provider and to customers who are not able to obtain service from an alternative seller after the date competition begins. The PUCN adopted this regulation in December 2000. The final regulation did not include language that restricted the PLR's ability to finance costs. However the final regulation contains a strict standard of conduct to govern the relationship between electric distribution utility (EDU) and PLR functions. Implementation of these provisions could have negative financial ramifications. Transmission Access for Retail Competition ------------------------------------------ On July 19, 2000, the Utilities filed with the FERC a modified Open Access Tariff that would govern transmission access for retail competition in Nevada until a RTO becomes operational. The modified Open Access Tariff was approved by FERC on October 25, 2000, to become effective when retail competition begins in Nevada. The Utilities also continue to pursue compliance with FERC Order 2000, which calls for utilities to form RTO's. Also see FERC Matters, below. Pricing of Distribution Service and Unbundling of Utility Services ------------------------------------------------------------------ In May, 2000, the Utilities filed final versions of the approved non-price terms and conditions and rates reflecting the PUCN's filed Opinion and Order in Dockets 99-4001 and 99-4005 (known as the Compliance Filings). These tariffs govern the rates, terms and conditions for Distribution Service for customers who choose and alternate energy supplier. OTHER NEVADA MATTERS Earnings Sharing (SPPC) On May 1, 2000, SPPC filed its third and last compliance filings related to the 1997 rate stipulation. The filings provide a calculation of Sierra's electric and gas earnings in excess of a 12% return on equity (ROE). Any earnings in excess of 12% ROE are shared 50/50 between shareholders and customers. On August 4, 2000, the PUCN approved a stipulation between SPPC, PUCN Staff, and the Nevada Utility Consumer Advocate that rebated $8.63 million and $670,000 to electric and gas customers, respectively, in 2000. In addition SPPC refunded an additional $390,000 to electric customers resulting from the 1999 compliance filing. The August 4, 2000, approved stipulation also resolved all outstanding issues associated with previous shared earning filings. Deferred Energy Filing On July 20, 2000, NVP signed the "Global Settlement" stipulation which eliminated the deferred energy accounting adjustment rates, effective August 1, 2000. In consideration of such termination, NVP may be allowed to recover up to $15 million in the aggregate out of the first-available after-tax proceeds from the sale of NVP's generation assets above book value and costs of sale. Until such recovery is completed NVP may accrue carrying charges at an annual rate of 9.5% on the unrecovered balance. 68 CALIFORNIA MATTERS (SPPC, NVP) Generation Divestiture On March 2, 2000, SPPC filed an application requesting exemption from CPUC approval of the Nevada-based generation divestiture transaction. SPPC cited several reasons for the exemption including that the PUCN and FERC oversight of the generation divestiture will assure reliability and market power mitigation as required by California's electric restructuring legislation. On September 18, 2000, a proposed settlement agreement was filed with the CPUC. However, on January 18, 2001, California enacted a law prohibiting any further divestiture of generation properties by California utilities, including SPPC, until 2006. Unless modified by future legislative action or by a court, divestiture of SPPC's Valmy, Tracy and Ft. Churchill plants is halted. As Edison is the operating partner in the Mohave Station, the pending sale of that unit is also implicated. Without divestiture, the TPPAs negotiated with the buyers of these units as part of the sale agreements are terminated. Distribution Performance-based Rate-making (PBR) On May 4, 2000, the CPUC dismissed without prejudice SPPC's January 3, 2000, distribution PBR proposal. The order accepted the application as meeting the compliance requirement but directed SPPC to re-file it when the cost of capital and cost of service studies are available. On July 3, 2000, SPPC re- submitted the PBR proposal along with the Cost of Service Study. On September 20, 2000, a pre-hearing conference was held which established a procedural schedule and hearings are scheduled to begin April 2, 2001. On May 8, 2000, SPPC filed its 2001 Cost of Capital application. In September 2000, hearings were held. On December 21, 2000, the CPUC approved a 2001 Return on Equity of 10.8% resulting in a Rate of Return of 9.01% for SPPC's California operations. The CPUC also approved an automatic trigger mechanism that will replace SPPC's annual cost of capital filings. Litigation Regarding California Power Market In response to complaints and requests for relief filed by California utilities and their customers, the FERC issued an order on August 23, 2000, initiating hearing proceedings under section 206 of the Federal Power Act to address matters affecting bulk power markets and wholesale energy prices (including price volatility) in California. On November 1, 2000, the FERC proposed specific remedies to address problems that it found in California's wholesale bulk power markets and to ensure just and reasonable wholesale power rates by public utility sellers in California. This ongoing proceeding, together with proceedings currently pending before the CPUC, may result in significant changes to the California power markets. Some parties to these proceedings have requested refunds from sellers of electrical power for past market transactions. The FERC denied this request for sales prior to October 2, 2000. However, the FERC held that sales made after October 2, 2000, are subject to refund, with the level and extent of any refund to be determined in future orders. Although a relatively small portion of SPPC's electricity customers are in the California, SPR, SPPC and NVP are monitoring the developments in California and at the FERC to determine what effect, if any, those developments may have on SPPC's California operations, on bulk sales of power by either utility and on general market prices for wholesale energy in the western United States. 69 FERC MATTERS (SPPC, NVP) Regional Transmission Organization (RTO) On May 1, 2000, NVP, SPPC, and Avista Corporation, BPA, Idaho Power Company, The Montana Power Company, PacifiCorp, Portland General Electric, and Puget Sound Energy, Inc. formed RTO West and filed articles of incorporation in the State of Washington. RTO West will be a non-profit independent system operator governed by an independent board of directors with a stakeholder advisory board. RTO West would be the single provider of transmission services, and controller of transmission operations in an eight-state region. RTO West submitted a compliance filing on October 16, 2000, with FERC. Supplemental material, which provided details of the formation of RTO West, was submitted on October 23. The creation of RTO West is subject to regulatory approvals from FERC and the states served by the investor-owned utilities. The organization will begin operations after all approvals are obtained. FERC's goal is for all RTO's to be operational by December 15, 2001. The proposed operational date in the RTO West filing is approximately one year later. Independent Transmission Company On October 16, 2000, NVP, SPPC, and Portland General Electric Company, Avista Corporation, The Montana Power Company, and Puget Sound Energy filed jointly with FERC to form TransConnect, a for-profit Independent Transmission Company. The creation of TransConnect is subject to regulatory approvals from FERC, state regulators, and the board of directors of each company. TransConnect would own or lease the transmission facilities of the six utilities in Oregon, Washington, Nevada and Montana and parts of Idaho and California. Those facilities are within the proposed territory for RTO West. RTO West would deal with TransConnect, instead of the six utilities. The TransConnect utilities are currently preparing a rate filing to the FERC in the second quarter of 2001. The initial operations date will be coordinated with the RTO West process. Open Access Transmission Rates In May 1999, NVP filed an application with the FERC to increase its Open Access Transmission rates. On March 30, 2000, the FERC approved the settlement filed on February 8, 2000 with rates becoming effective on March 1, 2000. Also on March 30, 2000, NVP filed a Loss Study that NVP agreed to provide in the settlement. On May 23, 2000, the FERC accepted NVP's Loss Study and the docket was completed. In March 1999, SPPC filed an application with the FERC to increase its Open Access Transmission rates. On March 30, 2000, SPPC filed a Loss Study that SPPC agreed to provide in the partial settlement that was approved in January 2000. On April 26, 2000, a settlement was filed by SPPC on issues raised by the City of Fallon and on August 1, 2000, the FERC approved the settlement. On July 18, 2000 a settlement was filed by SPPC on issues raised by the Mines which provides that the issues not be resolved in this case, but at a later date. On September 18, 2000, the FERC approved the settlement. On July 7, 2000, a settlement was filed by SPPC resolving all Loss Study issues in the case and on September 18, 2000, the FERC approved the settlement. 70 Revised Generation Tariffs And Transitional Purchase Power Agreements On March 31, 2000, the Utilities filed for approval of Generation Tariffs that contain the rates, terms and conditions under which the new owners of divested generation facilities could sell energy and ancillary services. The filing also included pro-forma Transitional Purchase Power Agreements (TPPAs) between the Utilities and the new owners of the divested generation facilities. Final signed versions of the TPPAs will be submitted to the FERC as part of the Asset Sale Agreements between the Utilities and the new owners of the divested generation facilities. On May 31, 2000, the FERC accepted for filing the Generation Tariff and the pro forma TPPAs. The FERC required one modification to the TPPAs in that the Utilities were required to notify the new owners one day ahead of their intended use of the generation or release the capacity to the new owners. The FERC also set for hearing the rates in the generation tariff and in the TPPAs. The Utilities have reached a settlement with the FERC Staff, PUCN and the Nevada Bureau of Consumer Protection regarding the rates in the Generation Tariff and TPPAs. The settlement has not yet been submitted to the FERC for approval. Merger Savings On April 8, 1998, SPR and NVP filed a joint application with the PUCN for approval of their proposed merger. On December 31, 1998, the PUCN voted 3-0 to approve the merger, with conditions. The conditions include, among others, requirements to divest generation, file the divestiture plan with the Commission for approval, file an Independent Systems Administrator (ISA) proposal with the FERC, file a generation tariff with the FERC, file a rate case and unbundle costs in 1999, file a subsequent rate case three years after retail competition, and submit application to recover stranded costs. The merger savings should approximate $30 million per year. The Utilities have experienced a reduction in the workforce, primarily in the administrative and general areas, of approximately 300 employees since the merger announcement date of April 30, 1998. The merger savings are tracking with and exceeding the targeted $30 million per year. Final numbers and analysis will be part of the aforementioned subsequent rate case to be filed three years after retail competition. 71 ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK SPR has evaluated its risk related to financial instruments whose values are subject to market sensitivity. The only such instruments are fixed and variable rate debt, and preferred securities obligations, which were as follows on December 31, 2000, and 1999. Fair market value was determined using quoted market price for the same or similar issues or on the current rates offered for debt of the same remaining maturities. Long-term debt (dollars in thousands):
Expected Maturity Date December 31, 2000 Fixed Rate --------------------------------------------------------------------------------------------------- Expected Maturities Amounts Weighted Avg Int Rate Fair Market Value ------------------------------------------------------------------------------------------------- NVP SPPC SPR Consolidated Consolidated Consolidated ---------------- ----------------- 2001 $ 100 $ 19,620 $ - $ 19,720 $ 5.57% 2002 15,000 2,626 17,626 7.40% 2003 20,632 20,632 5.63% 2004 130,000 2,621 132,621 6.20% 2005 2,622 300,000 302,622 8.73% Thereafter 588,942 497,311 1,086,253 6.55% ================================================== ================ ================== Total Fixed Rate $ 734,042 $ 545,432 $ 300,000 $ 1,579,474 $ 1,579,221 ------------------------------------------------------------------------- ------------------ Variable Rate Due 2001 $ 250,000 $ 200,000 $ - $ 450,000 7.48% Due 2002 100,000 100,000 7.29% Due 2003 200,000 200,000 7.24% Due 2009 15,000 15,000 4.45% Due 2020 100,000 80,000 180,000 4.36% ================================================== ================ ================== $ 365,000 $ 280,000 $ 300,000 $ 945,000 $ 941,920 ------------------------------------------------------------------------- ------------------ Preferred securities (fixed rate) Due 2036 $ - $ 48,500 $ 48,500 8.60% Due 2037 118,872 118,872 8.20% Due 2038 70,000 70,000 7.75% ================================================== ================ ================== $ 188,872 48,500 $ 237,372 $ 234,792 Total $1,287,914 $ 873,932 $ 600,000 $ 2,761,846 $ 2,755,933 ---------------------==================================================------------------------------==================
72
Expected Maturity Date December 31, 1999 Fixed Rate -------------------------------------------------------------------------------------------------------------- Expected Maturities Amounts Weighted Ave Int Rate Fair Market Value -------------------------------------------------------------------------------------------------------------- NVP SPPC SPR Consolidated Consolidated -------------------------------------------------------------------------------------------------------------- 2000 $ 89,954 $ 2,755 $ 10 ,000 $ 102,709 7.00% 2001 19,620 112 19,732 5.58% 2002 15,000 2,626 17,626 7.05% 2003 20,631 80 20,711 5.53% 2004 130,000 2,621 132,621 6.20% 2005 - - Thereafter 786,004 499,932 1,285,936 6.68% ========================================================= ====================== ============== Total Fixed Rate $1,020,958 $ 548,185 $ 10,192 $ 1,579,335 $ 1,540,990 --------------------------------------------------------- ---------------------- -------------- Variable Rate Due 2000 $ 100,000 $ 100,000 6.92% Due 2001 - Due 2002 - Due 2003 - Due 2005 - Due 2020 80,000 80,000 3.81% ========================================================= --------------- -------------- $ - $ 180,000 $ - $ 180,000 $ 180,000 --------------------------------------------------------- --------------- -------------- Preferred securities (fixed rate) Due 2036 $ 188,872 $ 48,500 $ 237,372 18.18% $ 208,618 ========================================================= =============== ============== Total $1,209,830 $ 776,685 $ 10,192 $ 1,996,707 $ 1,929,608 =============================================================================== --------------- ==============
* Weighted daily average rate for month ended December 31, 2000, and 1999. COMMODITY PRICE RISK SPR is exposed to commodity price risk primarily related to changes in the market price of electricity as well as changes in fuel costs incurred to generate electricity. As a result of the merger of SPR and NVP, the Board of Directors of the combined company requested that management review and consolidate the Risk Management Programs of the two utilities. SPPC and NVP engaged the services of an energy risk management consulting company to review existing policies and procedures, make any recommendations to the existing Program, and implement the revised Program. That project led SPPC and NVP to adopt revised policies and procedures, and implement new IT systems to track any commodity price exposure. The primary objective of the revised risk management policy is to decrease the Utilities' exposure to commodity prices which are primarily western electric and natural gas prices. SPPC's gas local distribution company is protected by deferred energy accounting procedures (See Note 1 to the Financial Statements). SPR also monitors and manages credit risk with its trading counterparties. Currently, SPR has outstanding transactions with over 30 energy and financial services companies. The aggregate credit risk associated with these transactions is $1.6 billion. The top 10 companies ranked by credit exposure are all rated investment grade corporations with assets exceeding $10 billion with head offices in various 73 locations throughout the United States and Europe. These counterparties make up approximately 85% of the total credit exposure. 74 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Page ---- Independent Auditors' Reports............................................. 76-77 Financial Statements: Consolidated Balance Sheets as of December 31, 2000 and 1999......... 78 Consolidated Statements of Income for the Years Ended December 31, 2000, 1999 and 1998................................................ 79 Consolidated Statements of Common Shareholders' Equity for the Years Ended December 31, 2000, 1999 and 1998....................... 80 Consolidated Statements of Cash Flows for the Years Ended December 31, 2000, 1999 and 1998................................... 81 Consolidated Statements of Capitalization as of December 31, 2000 and 1999..................................................... 82-83 Balance Sheets for Nevada Power Company as of December 31, 2000 and 1999..................................................... 84 Statements of Income for Nevada Power Company for the Years Ended December 31, 2000, 1999 and 1998.................................. 85 Statements of Cash Flows for Nevada Power Company for the Years Ended December 31, 2000, 1999 and 1998.............. 86 Statements of Capitalization for Nevada Power Company as of December 31, 2000 and 1999........................... 87 Balance Sheets for Sierra Pacific Power Company as of December 31, 2000 and 1999........................................ 88 Statements of Income for Sierra Pacific Power Company for the Years Ended December 31, 2000, 1999 and 1998............... 89 Consolidated Statements of Common Shareholders' Equity for Sierra Pacific Power Company for the Years Ended December 31, 2000, 1999 and 1998..................................................... 90 Statements of Cash Flows for Sierra Pacific Power Company for the Years Ended December 31, 2000, 1999 and 1998.............. 91 Statements of Capitalization for Sierra Pacific Power Company as of December 31, 2000 and 1999........................... 92 Notes to Financial Statements ........................................... 93
75 INDEPENDENT AUDITORS' REPORT To the Board of Directors and Stockholders of Sierra Pacific Resources Reno, Nevada We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Sierra Pacific Resources and subsidiaries (the Company) and the separate unconsolidated balance sheets and statements of capitalization of Nevada Power Company (NVP) as of December 31, 2000 and 1999, and the related statements of income, common shareholders' equity, and cash flows for each of the three years in the period ended December 31, 2000. Our audits also included the consolidated financial statement schedules listed in the Index at Item 14. These financial statements and financial statement schedules are the responsibility of the Company's and NVP's management. Our responsibility is to express an opinion on these financial statements and financial statement schedules based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such financial statements present fairly, in all material respects, the consolidated financial position of the Company and the financial position of NVP as of December 31, 2000 and 1999, and the respective results of their operations and their cash flows for each of the three years in the period ended December 31, 2000 in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly in all material respects the information set forth therein. Deloitte & Touche LLP Reno, Nevada February 23, 2001 (March 9, 2001 as to Note 20) 76 INDEPENDENT AUDITORS' REPORT To the Board of Directors and Shareholder of Sierra Pacific Power Company Reno, Nevada We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Sierra Pacific Power Company and subsidiaries as of December 31, 2000 and 1999, and the related consolidated statements of income, common shareholder's equity, and cash flows for each of the three years in the period ended December 31, 2000. Our audits also included the financial statement schedule listed in the Index at Item 14. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2000 and 1999, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2000, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly in all material respects the information set forth therein. Deloitte & Touche LLP Reno, Nevada February 23, 2001 (March 9, 2001 as to Note 20) 77 SIERRA PACIFIC RESOURCES CONSOLIDATED BALANCE SHEETS (Dollars in Thousands)
December 31, 2000 1999 ------------------ ------------------ ASSETS Utility Plant at Original Cost: Plant in service $ 5,269,724 $ 5,028,204 Less: accumulated provision for depreciation 1,636,657 1,490,600 ------------------ ------------------ 3,633,067 3,537,604 Construction work-in-progress 348,067 278,530 ------------------ ------------------ 3,981,134 3,816,134 ------------------ ------------------ Investments in subsidiaries and other property, net 135,062 105,880 ------------------ ------------------ Current Assets: Cash and cash equivalents 51,503 4,789 Accounts receivable less provision for uncollectible accounts: 2000-$13,194; 1999-$6,475 336,361 213,452 Materials, supplies and fuel, at average cost 75,132 73,193 Deferred energy costs 16,370 14,884 Other 59,128 7,003 ------------------ ------------------ 538,494 313,321 ------------------ ------------------ Deferred Charges: Goodwill, net of amortization 320,256 327,725 Regulatory tax asset 175,509 192,588 Other regulatory assets 105,588 101,227 Other 116,965 122,677 ------------------ ------------------ 718,318 744,217 ------------------ ------------------ Net assets of discontinued operations (Note 17) 266,476 256,365 ------------------ ------------------ $ 5,639,484 $ 5,235,917 ================== ================== CAPITALIZATION AND LIABILITIES Capitalization: Common shareholders' equity $ 1,359,712 $ 1,477,129 Preferred stock 50,000 50,000 SPPC/ NVP obligated mandatorily redeemable preferred trust securities 237,372 237,372 Long-term debt 2,133,679 1,556,627 ------------------ ------------------ 3,780,763 3,321,128 ------------------ ------------------ Current Liabilities: Short-term borrowings 213,074 754,979 Current maturities of long-term debt 472,527 202,709 Accounts payable 312,039 138,448 Accrued interest 30,184 15,394 Dividends declared 20,890 20,850 Accrued salaries and benefits 28,957 15,410 Deferred taxes on deferred energy costs - 5,683 Other current liabilities 17,795 29,773 ------------------ ------------------ 1,095,466 1,183,246 ------------------ ------------------ Commitments & Contingencies (Note 18) Deferred Credits: Deferred federal income taxes 407,370 405,594 Deferred investment tax credit 59,189 62,604 Regulatory tax liability 50,994 49,440 Customer advances for construction 109,962 109,422 Accrued retirement benefits 80,027 67,314 Other 55,713 37,169 ------------------ ------------------ 763,255 731,543 ------------------ ------------------ $ 5,639,484 $ 5,235,917 ================== ==================
The accompanying notes are an integral part of the financial statements. 78 SIERRA PACIFIC RESOURCES CONSOLIDATED STATEMENTS OF INCOME (Dollars in Thousands, Except Per Share Amounts)
Year ended December 31, 2000 1999 1998 ---------------- ---------------- ---------------- OPERATING REVENUES: Electric $ 2,219,252 $ 1,236,702 $ 873,682 Gas 100,803 38,958 - Other 14,199 9,132 - ---------------- ---------------- ---------------- 2,334,254 1,284,792 873,682 ---------------- ---------------- ---------------- OPERATING EXPENSES: Operation: Purchased Power 1,116,375 373,456 283,838 Fuel for power generation 526,535 206,130 149,804 Gas purchased for resale 83,199 27,262 - Deferral of energy costs-net 555 97,238 (29,680) Other 260,496 193,391 134,652 Maintenance 52,477 59,297 49,082 Depreciation and amortization 156,035 110,075 73,562 Taxes: Income taxes (31,022) 25,298 42,949 Other than income 42,215 29,784 22,198 ---------------- ---------------- ---------------- 2,206,865 1,121,931 726,405 ---------------- ---------------- ---------------- OPERATING INCOME 127,389 162,861 147,277 ---------------- ---------------- ---------------- OTHER INCOME: Allowance for other funds used during construction 2,813 2,339 8,944 Other income (expense) - net 2,646 (2,325) (4,602) ---------------- ---------------- ---------------- 5,459 14 4,342 ---------------- ---------------- ---------------- Total Income Before Interest Charges 132,848 162,875 151,619 ---------------- ---------------- ---------------- INTEREST CHARGES: Long-term debt 134,596 77,494 56,995 Other 35,887 26,229 6,018 Allowance for borrowed funds used during construction and capitalized interest (10,634) (8,000) (6,080) ---------------- ---------------- ---------------- 159,849 95,723 56,933 ---------------- ---------------- ---------------- (LOSS) INCOME BEFORE SPPC/NVP OBLIGATED MANDATORILY REDEEMABLE PREFERRED TRUST SECURITIES (27,001) 67,152 94,686 Preferred dividend requirements of SPPC/NVP obligated mandatorily redeemable preferred trust securities (18,914) (16,742) (11,013) ---------------- ---------------- ---------------- (LOSS) INCOME BEFORE PREFERRED STOCK DIVIDENDS (45,915) 50,410 83,673 Preferred stock dividend requirements of subsidiary (3,499) (2,200) (174) ---------------- ---------------- ---------------- (LOSS) INCOME FROM CONTINUING OPERATIONS (49,414) 48,210 83,499 ---------------- ---------------- ---------------- DISCONTINUED OPERATIONS: Income from operations of water business to be disposed of (net of income taxes of $3,426 and $788 in 2000 and 1999, respectively) 9,634 3,540 - ---------------- ---------------- ---------------- NET (LOSS) INCOME $ (39,780) $ 51,750 $ 83,499 ================ ================ ================ (Loss) Income per share - Basic (Loss) Income from continuing operations $ (0.63) $ 0.77 $ 1.64 Income from discontinued operations 0.12 0.06 - ---------------- ---------------- ---------------- Net income (loss) $ (0.51) $ 0.83 $ 1.64 ================ ================ ================ (Loss) Income per share - Diluted (Loss) Income from continuing operations $ (0.63) $ 0.77 $ 1.64 Income from discontinued operations 0.12 0.06 - ---------------- ---------------- ---------------- Net (loss) income $ (0.51) $ 0.83 $ 1.64 ================ ================ ================ Weighted Average Shares of Common Stock Outstanding 78,435,405 62,577,385 50,993,000 ================ ================ ================ Annual Dividends Paid Per Share of Common Stock $ 1.000 $ 1.165 $ 1.450 ================ ================ ================
The accompanying notes are an integral part of the financial statements. 79 SIERRA PACIFIC RESOURCES CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY (Dollars in Thousands)
Year ended December 31, ------------------------------------------------------- 2000 1999 1998 ----------------- ---------------- ---------------- Common Stock: Balance at Beginning of Year $ 78,414 $ $ 54,066 $ 53,604 401(k) Savings Plan - - 65 Stock purchase and dividend reimbursement 61 - 397 Merger conversion - 36,064 - Merger cash consideration - (11,716 - ----------------- ---------------- ---------------- Balance at End of Year 78,475 78,414 54,066 ----------------- ---------------- ---------------- Other Paid-In Capital: Balance at Beginning of Year 1,293,990 683,156 662,987 Premium on sale of common stock - - 20,169 CSIP, DRP, ESPP and other 1,231 1,409 - Merger transactions - 212,148 - Revaluation of pension asset - 66,103 - Goodwill - 331,174 - ----------------- ---------------- ---------------- Balance at End of Year 1,295,221 1,293,990 683,156 ----------------- ---------------- ---------------- Retained Earnings (Deficit): Balance at Beginning of Year 104,725 126,814 117,032 Income (loss) before preferred dividends of continuing operations (45,915) 50,410 83,673 Income from discontinued operations (before preferred dividend allocation of $401 and $196 in 2000 and 1999, respectively ) 10,035 3,736 - Dividends declared: Preferred stock of subsidiaries (3,900) (2,721) (174) Common stock (78,929) (73,514) (73,717) ----------------- ---------------- ---------------- Balance at End of Year (13,984) 104,725 126,814 ----------------- ---------------- ---------------- Total Common Shareholders' Equity at End of Year $ 1,359,712 $ 1,477,129 $ 864,036 ================= ================ ================
The accompanying notes are an integral part of the financial statements 80 SIERRA PACIFIC RESOURCES CONSOLIDATED STATEMENTS OF CASH FLOWS (Dollars in Thousands)
Year ended December 31, 2000 1999 1998 --------------- ------------- ----------- CASH FLOWS FROM OPERATING ACTIVITIES: (Loss) Income before preferred dividends from continuing operations $ (45,915) $ 50,410 $ 83,673 Income before preferred dividends from discontinued operations 10,035 3,736 - Non-cash items included in income: Depreciation and amortization 163,370 113,236 73,562 Deferred taxes and deferred investment tax credit (18,564) (16,543) 23,640 AFUDC and capitalized interest (13,858) (10,501) (15,025) Deferred energy costs 14,884 48,313 (33,819) Early retirement and severance amortization 4,196 1,748 - Other non-cash 30,972 24,122 13,896 Changes in certain assets and liabilities, net of acquisition: Accounts receivable (122,909) (7,393) (9,034) Materials, supplies and fuel (1,864) (3,846) 2,764 Other current assets (52,125) 155 1,359 Accounts payable 173,591 49,655 22,788 Other current liabilities 16,359 (6,342) (7,918) Other - net 27,724 (35,661) (7,605) --------------- ------------- ----------- Net Cash Flows From Operating Activities 185,896 211,089 148,281 --------------- ------------- ----------- CASH FLOWS USED IN INVESTING ACTIVITIES: Acquisition of business, net of cash acquired - (448,311) - Additions to utility plant (359,774) (299,064) (314,933) AFUDC and other charges to utility plant 15,227 (3,645) 3,996 Customer refunds for construction (889) 8,173 - Contributions in aid of construction 16,446 13,053 8,896 --------------- ------------- ----------- Net cash used for utility plant (328,990) (729,794) (302,041) --------------- ------------- ----------- (Investments in) disposal of subsidiaries and other property - net (28,056) 1,366 (2,277) --------------- ------------- ----------- Net Cash Used In Investing Activities (357,046) (728,428) (304,318) --------------- ------------- ----------- CASH FLOWS FROM FINANCING ACTIVITIES: (Decrease) Increase in short-term borrowings (547,310) 495,165 105,000 Proceeds from issuance of long-term debt 1,165,000 230,699 - Retirement of long-term debt (318,061) (63,293) (17,436) Change in funds held in trust - - 52,939 Proceeds from NVP obligated mandatorily redeemable preferred trust securities - - 70,000 Retirement of preferred stock - (26,380) (200) Sale of common stock 1,292 - 20,746 Dividends paid (83,057) (115,833) (73,962) --------------- ------------- ----------- Net Cash Provided By Financing Activities 217,864 520,358 157,087 --------------- ------------- ----------- Net Increase in Cash and Cash Equivalents 46,714 3,019 1,050 Beginning balance in Cash and Cash Equivalents 4,789 1,770 720 --------------- ------------- ----------- Ending balance in Cash and Cash Equivalents $ 51,503 $ 4,789 $ 1,770 =============== ============= =========== Supplemental Disclosures of Cash Flow Information: Cash Paid During Period For: Interest $ 167,158 $ 127,063 $ 75,487 Income Taxes $ 12,730 $ 43,719 $ 27,110
The accompanying notes are an integral part of the financial statements 81 SIERRA PACIFIC RESOURCES CONSOLIDATED STATEMENTS OF CAPITALIZATION (Dollars in Thousands)
December 31, 2000 1999 --------------- -------------- Common Shareholders' Equity: Common stock $1.00 par value, authorized 250 million; issued and outstanding 2000: 78,475,217 shares; 1999, 78,428,480 shares $ 78,475 $ 78,414 Additional paid-in capital 1,295,221 1,293,990 Retained earnings (deficit) (13,984) 104,725 --------------- -------------- Total Common Shareholders' Equity 1,359,712 1,477,129 --------------- -------------- Preferred Stock of Subsidiaries: Not subject to mandatory redemption Outstanding at December 31 Class A Series 1; $1.95 dividend 50,000 50,000 --------------- -------------- Preferred Securities of Subsidiaries: NVP obligated Mandatorily Redeemable Preferred Securities of NVP's Subsidiary Trust, NVP Capital I, holding solely $122.6 million principal amount of 8.2% Junior Subordinated Debentures of NVP, due 2037 118,872 118,872 NVP obligated Mandatorily Redeemable Preferred Securities of NVP's Subsidiary Trust, NVP Capital III, holding solely $72.2 million principal amount of 7 3/4% Junior Subordinated Debentures of NVP, due 2038 70,000 70,000 SPPC obligated Mandatorily Redeemable Preferred Securities of SPPC's Subsidiary Trust, SPPC Capital I, holding solely $50 million principal amount of 8.60% Junior Subordinated Debentures of SPPC, due 2036 48,500 48,500 --------------- -------------- Total Preferred Securities 237,372 237,372 --------------- -------------- Long-Term Debt: First Mortgage Bonds: Unamortized bond premium and discount, net (913) (583) Debt Secured by First Mortgage Bonds: 7 5/8% Series L due 2002 15,000 15,000 7.80% Series T due 2009 - 15,000 6.70% Series V due 2022 105,000 105,000 6.60%Series W due 2019 39,500 39,500 7.20% Series X due 2022 78,000 78,000 8.50% Series Z due 2023 35,000 35,000 7.06% Series AA due 2000 - 85,000 2.00% Series Z due 2004 72 93 2.00% Series O due 2011 1,374 1,497 6.35% Series FF due 2012 1,000 1,000 6.55% Series AA due 2013 39,500 39,500 6.30% Series DD due 2014 45,000 45,000 6.65% Series HH due 2017 75,000 75,000 6.65% Series BB due 2017 17,500 17,500 6.55% Series GG due 2020 20,000 20,000 6.30% Series EE due 2022 10,250 10,250 6.95% to 8.61% Series A MTN due 2022 110,000 110,000 7.10% and 7.14% Series B MTNdue 2023 58,000 58,000 6.62% to 6.83% Series C MTN due 2006 50,000 50,000 5.90% Series JJ due 2023 9,800 9,800 5.90% Series KK due 2023 30,000 30,000
The accompanying notes are an integral part of the financial statements. 82 SIERRA PACIFIC RESOURCES CONSOLIDATED STATEMENTS OF CAPITALIZATION (Dollars in Thousands) Continued from previous page
December 31, 2000 1999 ----------------- ---------------- 5.00% Series Y due 2024 3,138 3,207 6.70% Series II due 2032 21,200 21,200 5.47% Series D MTN due 2001 17,000 17,000 5.50% Series D MTN due 2003 5,000 5,000 5.59% Series D MTN due 2003 13,000 13,000 ----------------- ---------------- Subtotal, excluding current portion 798,421 898,964 ----------------- ---------------- Industrial development revenue bonds 7.80% due 2020 - 100,000 5.90% Series 1997A due 2032 52,285 52,285 5.90% Series 1995B due 2030 85,000 85,000 5.60% Series 1995A due 2030 76,750 76,750 5.50% Series 1995C 44,000 44,000 Pollution control revenue bonds 6 3/8% due 2036 20,000 20,000 5.80% Series 1997B due 2032 20,000 20,000 5.30% Series 1995D due 2011 14,000 14,000 5.45% Series 1995D due 2023 6,300 6,300 5.35% Series 1995E due 2022 13,000 13,000 ----------------- ---------------- Total excluding current portion 331,335 431,335 ----------------- ---------------- Variable Rate Notes Floating rate note due 2000 - 100,000 Floating rate note due 2001 200,000 - Floating rate note due 2001 150,000 - Floating rate note due 2001 100,000 - IDRB Series 2000A due 2020 100,000 - PCRB Series 2000B due 2009 15,000 - Water facilities note maturing 2020 80,000 80,000 Floating Rate Note due 2002 100,000 - Floating Rate Note due 2003 200,000 - ----------------- ---------------- 945,000 180,000 8.75% Senior unsecured note Series 2000 due 2005 300,000 - 6.20% Senior unsecured note Series A 130,000 130,000 ----------------- ---------------- 430,000 130,000 ----------------- ---------------- 8.75% Senior unsecured note Series 2000 due 2005 81,815 87,007 Current maturities and sinking fund requirements (472,531) (189,842) Other 19,639 19,163 ----------------- ---------------- Total Long-Term Debt 2,133,679 1,556,627 TOTAL CAPITALIZATION $ 3,780,763 $ 3,321,128 ================= ================
The accompanying notes are an integral part of the financial statements. 83 NEVADA POWER COMPANY BALANCE SHEETS (Dollars in Thousands)
December 31, 2000 1999 ---------------- -------------- ASSETS Utility Plant at Original Cost: Plant in service $ 3,089,705 $ 2,928,973 Less: accumulated provision for depreciation 855,599 772,003 ---------------- -------------- 2,234,106 2,156,970 Construction work-in-progress 228,856 195,671 ---------------- -------------- 2,462,962 2,352,641 ---------------- -------------- Investments in Sierra Pacific Resources (Note 1A) 471,975 654,156 Investments in subsidiaries and other property, net 13,418 15,644 ---------------- -------------- 485,393 669,800 ---------------- -------------- Current Assets: Cash and cash equivalents 43,858 243 Accounts receivable less provision for uncollectible accounts: 2000-$11,605; 1999-$2,826 137,097 110,955 Materials, supplies and fuel, at average cost 45,573 43,108 Deferred energy costs - 14,884 Other 28,933 3,573 ---------------- -------------- 255,461 172,763 ---------------- -------------- Deferred Charges: Regulatory tax asset 113,647 130,833 Other regulatory assets 32,583 28,190 Other 25,912 24,258 ---------------- -------------- 172,142 183,281 ---------------- -------------- $ 3,375,958 $ 3,378,485 ================ ============== CAPITALIZATION AND LIABILITIES Capitalization: Common shareholders' equity including $471,975 and $654,156 of equity in Sierra Pacific Resources in 2000 and 1999 (Note 1A) $ 1,359,712 $ 1,477,129 NVP obligated mandatorily redeemable preferred trust securities 188,872 188,872 Long-term debt 927,784 931,004 ---------------- -------------- 2,476,368 2,597,005 ---------------- -------------- Current Liabilities: Short-term borrowings 100,000 182,000 Current maturities of long-term debt 252,910 89,842 Accounts payable 126,015 75,088 Accrued interest 16,913 10,098 Dividends declared 86 24,126 Accrued salaries and benefits 12,297 7,025 Deferred taxes on deferred energy costs - 5,683 Other current liabilities 16,450 18,536 ---------------- -------------- 524,671 412,398 ---------------- -------------- Commitments & Contingencies (Note 18) Deferred Credits: Deferred federal income taxes 216,753 236,139 Deferred investment tax credit 25,163 26,624 Regulatory tax liability 19,908 14,993 Customer advances for construction 65,588 69,341 Accrued retirement benefits 27,985 18,262 Other 19,522 3,723 ---------------- -------------- 374,919 369,082 ---------------- -------------- $ 3,375,958 $ 3,378,485 ================ ==============
The accompanying notes are an integral part of the financial statements. 84 NEVADA POWER COMPANY STATEMENTS OF INCOME (Dollars in Thousands, Except Per Share Amounts)
Year ended December 31, ---------------------------------------------- 2000 1999 1998 -------------- ------------- -------------- OPERATING REVENUES: Electric $ 1,325,470 $ 977,262 $ 873,682 OPERATING EXPENSES: Operation: Purchased power 671,396 293,600 283,838 Fuel for power generation 292,787 154,546 149,804 Deferral of energy costs-net 16,719 97,238 (29,680) Other 139,723 141,041 134,652 Maintenance 34,057 50,805 49,082 Depreciation and amortization 85,989 80,644 73,562 Taxes: Income taxes (12,162) 19,943 42,949 Other than income 23,501 22,462 22,198 -------------- ------------- -------------- 1,252,010 860,279 726,405 -------------- ------------- -------------- OPERATING INCOME 73,460 116,983 147,277 -------------- ------------- -------------- OTHER INCOME: Equity in earnings (losses) of Sierra Pacific Resources (Note 1A) (31,852) 13,058 - Allowance for other funds used during construction 2,456 3,713 8,944 Other income (expense) - net 1,718 (1,824) (4,602) -------------- ------------- -------------- (27,678) 14,947 4,342 -------------- ------------- -------------- Total Income Before Interest Charges 45,782 131,930 151,619 -------------- ------------- -------------- INTEREST CHARGES: Long-term debt 64,513 64,454 56,995 Other 13,732 8,815 6,018 Allowance for borrowed funds used during construction and capitalized interest (7,855) (8,356) (6,080) -------------- ------------- -------------- 70,390 64,913 56,933 -------------- ------------- -------------- (LOSS) INCOME BEFORE NVP OBLIGATED MANDATORILY REDEEMABLE PREFERRED TRUST SECURITIES (24,608) 67,017 94,686 Preferred dividend requirements of NVP obligated mandatorily redeemable preferred trust securities (15,172) (15,172) (11,013) -------------- ------------- -------------- INCOME (LOSS) BEFORE PREFERRED STOCK DIVIDENDS (39,780) 51,845 83,673 Preferred stock dividend requirements - (95) (174) -------------- ------------- -------------- NET (LOSS) INCOME $ (39,780) $ 51,750 $ 83,499 ============== ============= ============== Net (Loss) Income Per Share- Basic $ (0.51) $ 0.83 $ 1.64 ============== ============= ============== - Diluted $ (0.51) $ 0.83 $ 1.64 ============== ============= ============== Weighted Average Shares of Common Stock Outstanding (000's) 78,435 62,577 50,993 ============== ============= ============== Dividends Paid Per Share of Common Stock $ 1.000 $ 1.165 $ 1.450 ============== ============= ==============
The accompanying notes are an integral part of the financial statements. 85 NEVADA POWER COMPANY STATEMENTS OF CASH FLOWS (Dollars in Thousands)
Year ended December 31, ---------------------------------------------- 2000 1999 1998 ------------ ------------ ------------ CASH FLOWS FROM OPERATING ACTIVITIES: (Loss) Income before preferred dividends $ (39,780) $ 51,845 $ 83,673 Non-cash items included in income: Depreciation and amortization 85,989 80,643 73,562 Deferred taxes and deferred investment tax credit (26,528) (18,913) 23,640 AFUDC and capitalized interest (10,311) (12,069) (15,025) Deferred energy costs 14,884 48,313 (33,819) Other non-cash 20,101 16,908 13,896 Equity in earnings of SPR (Note 2) 31,852 (13,058) - Changes in certain assets and liabilities, net of acquisition: Accounts receivable (26,142) (11,795) (9,034) Materials, supplies and fuel (2,465) (3,502) 2,764 Other current assets (25,360) 1,778 1,359 Accounts payable 50,927 34,964 22,788 Other current liabilities 10,001 17,066 (7,918) Other - net 30,543 (14,002) (7,605) ------------ ------------ ------------ Net Cash Flows From Operating Activities 113,711 178,178 148,281 ------------ ------------ ------------ CASH FLOWS USED IN INVESTING ACTIVITIES: Additions to utility plant (204,505) (223,963) (314,933) AFUDC and other charges to utility plant 11,622 (2,184) 3,996 Customer refunds for construction (3,753) 5,228 - Contributions in aid of construction - - 8,896 ------------ ------------ ------------ Net cash used for utility plant (196,636) (220,919) (302,041) Investments in subsidiaries and other property - net - 1,499 (2,277) ------------ ------------ ------------ Net Cash Used In Investing Activities (196,636) (219,420) (304,318) CASH FLOWS FROM FINANCING ACTIVITIES: (Decrease) increase in short-term borrowings (82,000) 77,000 105,000 Proceeds from issuance of long-term debt 365,000 129,900 - Retirement of long-term debt (205,152) (60,283) (17,436) Change in funds held in trust - 9 52,939 Proceeds from NVP-obligated mandatorily redeemable preferred trust securities - - 70,000 Retirement of preferred stock - (3,265) (200) Sale of common stock - - 20,746 Additional investment of Parent 137,000 18,000 Dividends paid (88,308) (121,646) (73,962) ------------ ------------ ------------ Net Cash Provided By Financing Activities 126,540 39,715 157,087 ------------ ------------ ------------ Net Increase/Decrease in Cash and Cash Equivalents 43,615 (1,527) 1,050 Beginning balance in Cash and Cash Equivalents 243 1,770 720 ------------ ------------ ------------ Ending balance in Cash and Cash Equivalents $ 43,858 $ 243 $ 1,770 ============ ============ ============= Supplemental Disclosures of Cash Flow Information: Cash Paid During Period For: Interest $ 71,430 $ 91,196 $ 75,487 Income Taxes $ 6,500 $ 38,219 $ 27,110
The accompanying notes are an integral part of the financial statements. 86 NEVADA POWER COMPANY STATEMENTS OF CAPITALIZATION (Dollars in Thousands)
December 31, 2000 1999 -------------- ------------ Common Shareholders' Equity: Common stock issued $ 1 $ 1 Other paid-in capital 892,185 755,226 Retained earnings (deficit) (4,449) 67,746 Equity in Sierra Pacific Resources (Note 1A) 471,975 654,156 -------------- ------------ Total Common Shareholder's Equity 1,359,712 1,477,129 -------------- ------------ Preferred Securities: NVP obligated Mandatorily Redeemable Preferred Securities of NVP's Subsidiary Trust, NVP Capital I, holding solely $122.6 million principal amount of 8.2% Junior Subordinated Debentures of NVP, due 2037 118,872 118,872 NVP obligated Mandatorily Redeemable Preferred Securities of NVP's Trust, NVP Capital III, holding solely $72.2 million principal amount of 7 3/4% Junior Subordinated Debentures of NVP, due 2038 70,000 70,000 -------------- ------------ Total Preferred Securities 188,872 188,872 -------------- ------------ Long-Term Debt: First Mortgage Bonds: Unamortized bond premium and discount, net (163) 212 Debt Secured by First Mortgage Bonds: 7 5/8% Series L due 2002 15,000 15,000 7.80% Series T due 2009 - 15,000 6.70% Series V due 2022 105,000 105,000 6.60% Series W due 2019 39,500 39,500 7.20% Series X due 2022 78,000 78,000 8.50% Series Z due 2023 35,000 35,000 7.06% Series AA due 2000 - 85,000 -------------- ------------ Subtotal, excluding current portion 272,337 372,712 Industrial development revenue bonds 7.80% due 2020 - 100,000 5.90% Series 1997A due 2032 52,285 52,285 5.90% Series 1995B due 2030 85,000 85,000 5.60% Series 1995A due 2030 76,750 76,750 5.50% Series 1995C due 2030 44,000 44,000 Pollution Control Revenue Bonds 6 3/8% due 2036 20,000 20,000 5.80% Series 1997B due 2032 20,000 20,000 5.30% Series 1995D due 2011 14,000 14,000 5.45% Series 1995D due 2023 6,300 6,300 5.35% Series 1995E due 2022 13,000 13,000 -------------- ------------ Total excluding current portion 331,335 431,335 -------------- ------------ Variable Rate Notes Floating rate note due 2001 150,000 - Floating rate note due 2001 100,000 - IDRB Series 2000A due 2020 100,000 - PCRB Series 2000B due 2009 15,000 - -------------- ------------ 365,000 - -------------- ------------ 6.20% Senior unsecured note Series A 130,000 130,000 Obligation under capital leases 81,815 87,007 Current maturities and sinking fund requirements (252,911) (89,842) Other, excluding current portion 208 (208) -------------- ------------ Total Long-Term Debt 927,784 931,004 -------------- ------------ TOTAL CAPITALIZATION $ 2,476,368 $ 2,597,005 ============== ============
The accompanying notes are an integral part of the financial statements. 87 SIERRA PACIFIC POWER COMPANY CONSOLIDATED BALANCE SHEETS (Dollars in Thousands)
December 31, 2000 1999 --------------- --------------- ASSETS Utility Plant at Original Cost: Plant in service $ 2,180,019 $ 2,097,533 Less: accumulated provision for depreciation 781,058 718,597 --------------- --------------- 1,398,961 1,378,936 Construction work-in-progress 119,210 82,859 --------------- --------------- 1,518,171 1,461,795 --------------- --------------- - Investments in subsidiaries and other property, net 60,047 62,704 --------------- --------------- Current Assets: Cash and cash equivalents 5,348 3,011 Accounts receivable less provision for uncollectible accounts: 2000 - $1,589; 1999 - $3,649 133,369 111,175 Materials, supplies and fuel, at average cost 29,209 29,642 Deferred energy costs 16,370 - Other 29,852 3,103 --------------- --------------- 214,148 146,931 --------------- --------------- Deferred Charges: Regulatory tax asset 61,862 61,755 Other regulatory assets 61,236 69,645 Other 12,036 25,512 --------------- --------------- 135,134 156,912 --------------- --------------- - - Net assets of discontinued operations (Note 9) 266,476 256,365 --------------- --------------- $ 2,193,976 $ 2,084,707 =============== =============== CAPITALIZATION AND LIABILITIES Capitalization: Common shareholder's equity $ 604,795 $ 673,738 Preferred stock 50,000 50,000 SPPC obligated mandatorily redeemable preferred trust securities 48,500 48,500 Long-term debt 605,816 625,430 --------------- --------------- 1,309,111 1,397,668 --------------- --------------- Current Liabilities: Short-term borrowings 108,962 109,584 Current maturities of long-term debt 219,616 102,755 Accounts payable 146,724 78,491 Accrued interest 6,992 5,110 Dividends declared 23,975 19,974 Accrued salaries and benefits 15,475 8,385 Other current liabilities 2,932 10,673 --------------- --------------- 524,676 334,972 --------------- --------------- Commitments & Contingencies (Note 18) Deferred Credits: Deferred federal income taxes 180,166 161,891 Deferred investment tax credit 34,025 35,980 Regulatory tax liability 31,087 34,447 Accrued retirement benefits 44,374 49,052 Customer advances for construction 41,776 40,081 Other 28,761 30,616 --------------- --------------- 360,189 352,067 --------------- --------------- $ 2,193,976 $ 2,084,707 =============== ===============
The accompanying notes are an integral part of the financial statements. 88 SIERRA PACIFIC POWER COMPANY CONSOLIDATED STATEMENTS OF INCOME (Dollars in Thousands)
December 31, 2000 1999 1998 --------------- --------------- --------------- OPERATING REVENUES: Electric $ 893,782 $ 609,197 $ 585,657 Gas 100,803 100,177 99,532 --------------- --------------- --------------- 994,585 709,374 685,189 --------------- --------------- --------------- OPERATING EXPENSES: Operation: Purchased power 444,979 179,781 156,970 Fuel for power generation 233,748 115,065 114,803 Gas purchased for resale 83,199 68,125 65,430 Deferral of energy costs - net (16,164) - - Other 96,438 92,745 94,669 Maintenance 18,420 20,309 20,374 Depreciation and amortization 69,350 69,762 61,990 Taxes: Income taxes (672) 33,870 39,753 Other than income 18,152 17,014 16,937 --------------- --------------- --------------- 947,450 596,671 570,926 --------------- --------------- --------------- OPERATING INCOME 47,135 112,703 114,263 --------------- --------------- --------------- OTHER INCOME: Allowance for other funds used during construction 357 (1,370) 3,589 Other (expense) income - net (2,429) (673) 56 --------------- --------------- --------------- (2,072) (2,043) 3,645 --------------- --------------- --------------- Total Income 45,063 110,660 117,908 --------------- --------------- --------------- INTEREST CHARGES: Long-term debt 36,865 31,151 27,979 Other 11,312 11,286 7,283 Allowance for borrowed funds used during construction and capitalized interest (2,779) (141) (6,000) --------------- --------------- --------------- 45,398 42,296 29,262 --------------- --------------- --------------- INCOME BEFORE SPPC OBLIGATED MANDATORILY REDEEMABLE PREFERRED TRUST SECURITIES (335) 68,364 88,646 Preferred dividend requirements of SPPC obligated mandatorily redeemable preferred trust securities (3,742) (3,749) (4,171) --------------- --------------- --------------- (LOSS) INCOME BEFORE PREFERRED DIVIDENDS (4,077) 64,615 84,475 Preferred dividend requirements and premium paid on redemption (3,499) (4,957) (4,797) --------------- --------------- --------------- NET (LOSS) INCOME FROM CONTINUING OPERATIONS (7,576) 59,658 79,678 --------------- --------------- --------------- DISCONTINUED OPERATIONS: Income from operations of water business to be disposed of (net of income taxes of $3,426, $2,172 and $3,797 in 2000, 1999 and 1998, respectively) 9,634 6,583 883 --------------- --------------- --------------- NET INCOME $ 2,058 $ 66,241 $ 80,561 =============== =============== ===============
The accompanying notes are an integral part of the financial statements. 89 SIERRA PACFIC POWER COMPANY CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER'S EQUITY (Dollars in Thousands)
Year ended December 31, 2000 1999 1998 -------------- -------------- ------------- Common Stock Balance at Beginning of Year and End of Year $ 4 $ 4 $ 4 -------------- -------------- ------------- Other Paid-In Capital Balance at Beginning Year 584,684 562,684 545,434 Additional investment by parent company 14,000 22,000 17,250 -------------- -------------- ------------- Balance at End of Year 598,684 584,684 562,684 -------------- -------------- ------------- Retained Earnings Balance at Beginning of Year 89,049 98,679 94,118 (Loss) Income before preferred dividends of continuing operations (4,077) 64,615 84,475 Income from discontinued operations (before preferred dividend allocation of $401 and $528 and $662 in 2000, 1999 and 1998 respectively) 10,035 7,111 1,545 Preferred stock dividends declared & premium on redemption (3,900) (5,355) (5,459) Common stock dividends declared (85,000) (76,000) (76,000) -------------- -------------- ------------- Balance at End of Year 6,107 89,050 98,679 -------------- -------------- ------------- Total Common Shareholder's Equity at End of Year $ 604,795 $ 673,738 $ 661,367 ============== ============== =============
The accompanying notes are an integral part of the financial statements 90 SIERRA PACIFIC POWER COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (Dollars in Thousands)
Year Ended December 31, 2000 1999 1998 -------------- -------------- -------------- Cash Flows From Operating Activities: (Loss) Income before preferred dividends from continuing operations $ (4,077) $ 64,615 $ 84,475 Income before preferred dividends from discontinued operations 10,035 7,111 1,545 Non-Cash items included in income: Depreciation and amortization 76,685 77,373 69,435 Deferred taxes and investment tax credits 7,935 5,595 (3,743) AFUDC and capitalized interest (3,547) 1,033 (10,211) Early retirement and severance amortization 4,196 4,194 4,177 Other non-cash 10,871 8,644 2,400 Changes in certain assets and liabilities: Accounts receivable (22,194) 685 (13,836) Materials, supplies and fuel 508 (4,294) (521) Other current assets (26,749) (411) (120) Accounts payable 68,233 12,459 2,944 Other current liabilities 1,231 (23,257) 6,844 Other-net (11,117) (31,418) 9,802 -------------- -------------- -------------- Net Cash Flows From Operating Activities 112,010 122,329 153,191 -------------- -------------- -------------- Cash Flows From Investing Activities: Additions to utility plant (155,269) (142,306) (183,384) Non-cash charges to utility plant 3,605 (768) 10,587 Customer refunds for construction 2,864 5,120 (3,517) Contributions in aid of construction 16,446 21,823 37,216 -------------- -------------- -------------- Net cash used for utility plant (132,354) (116,131) (139,098) Investment in subsidiaries and other non-utility property - net 2,292 (28,720) (2,788) -------------- -------------- -------------- Net Cash Used in Investing Activities (130,062) (144,851) (141,886) -------------- -------------- -------------- Cash Flows From Financing Activities Increase in short-term borrowings (5,915) 1,972 30,637 Proceeds from issuance of long-term debt 200,000 124,495 35,000 Retirement of long-term debt (102,797) (33,270) (5,456) Retirement of preferred stock - (23,115) - Additional investment by parent company 14,000 22,000 17,250 Dividends paid and premiums on preferred redemption (84,899) (81,746) (80,459) -------------- -------------- -------------- Net Cash Provided by (Used in) Financing Activities 20,389 10,336 (3,028) -------------- -------------- -------------- Net Increase (Decrease) in Cash and Cash Equivalents 2,337 (12,186) 8,277 Beginning Balance in Cash and Cash Equivalents 3,011 15,197 6,920 -------------- -------------- -------------- Ending Balance in Cash and Cash Equivalents $ 5,348 $ 3,011 $ 15,197 ============== ============== ============== Supplemental Disclosures of Cash Flow Information: Cash Paid During Year For: Interest $ 57,331 $ 54,303 $ 48,250 Income taxes 9,644 28,604 45,963
The accompanying notes are an integral part of the financial statements. 91 SIERRA PACIFIC POWER COMPANY CONSOLIDATED STATEMENTS OF CAPITALIZATION (Dollars in Thousands)
December 31, 2000 1999 ---------------- ---------------- Common Shareholder's Equity: Common stock, $3.75 par value, 1,000 shares authorized, issued and outstanding $ 4 $ 4 Other paid-in capital 598,684 584,684 Retained earnings 6,107 89,050 ---------------- ---------------- Total Common Shareholder's Equity 604,795 673,738 Cumulative Preferred Stock: Not subject to mandatory redemption: $25 stated value Class A Series 1; $1.95 dividend 50,000 50,000 ---------------- ---------------- Company-obligated mandatorily redeemable preferred securites of the Company's subsidiary trust, Sierra Pacific Power Capital I, holding solely $50 million principal amount of 8.60% junior subordinated debentures of the Company, due 2036 48,500 48,500 ---------------- ---------------- Long Term Debt: First Mortgage Bonds: Unamortized bond premium and discount, net (750) (795) Debt Secured by First Mortgage Bonds: 2.00% Series Z due 2004 72 93 2.00% Series O due 2011 1,374 1,497 6.35% Series FF due 2012 1,000 1,000 6.55% Series AA due 2013 39,500 39,500 6.30% Series DD due 2014 45,000 45,000 6.65% Series HH due 2017 75,000 75,000 6.65% Series BB due 2017 17,500 17,500 6.55% Series GG due 2020 20,000 20,000 6.30% Series EE due 2022 10,250 10,250 6.95% to 8.61% Series A MTN due 2022 110,000 110,000 7.10% and 7.14% Series B MTN due 2023 58,000 58,000 6.62% to 6.83% Series C MTN due 2006 50,000 50,000 5.90% Series JJ due 2023 9,800 9,800 5.90% Series KK due 2023 30,000 30,000 5.00% Series Y due 2024 3,138 3,207 6.70% Series II due 2032 21,200 21,200 5.47% Series D MTN due 2001 17,000 17,000 5.50% Series D MTN due 2003 5,000 5,000 5.59% Series D MTN due 2003 13,000 13,000 ---------------- ---------------- Subtotal, excluding current portion 526,084 526,252 Variable Rate Note: Water Facilities Note: maturing 2020 80,000 80,000 Floating rate note due 2000 - 100,000 Floating rate note due 2001 200,000 - ---------------- ---------------- Subtotal 280,000 180,000 Other 19,348 21,932 Current Maturities (219,616) (102,754) ---------------- ---------------- Total Long-Term Debt 605,816 625,430 ---------------- ---------------- TOTAL CAPITALIZATION $ 1,309,111 $ 1,397,668 ================ ================
The accompanying notes are an integral part of the financial statements. 92 NOTES TO FINANCIAL STATEMENTS ----------------------------- NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES The significant accounting policies for both utility and non-utility operations are as follows: General The consolidated financial statements include the accounts of Sierra Pacific Resources (SPR) and its wholly-owned subsidiaries, Nevada Power Company (NVP), Sierra Pacific Power Company (SPPC), Tuscarora Gas Pipeline Company (TGPC), Lands of Sierra, Inc. (LOS), Sierra Gas Holding Company (SGHC), Sierra Energy Company dba eo three (eo three), Nevada Electric Investment Company (NEICO), Sierra Pacific Energy Company (SPE), Sierra Water Development Company (SWDC) and Sierra Pacific Communications (SPC). All significant intercompany balances and intercompany transactions have been eliminated in consolidation. See Note 2 for additional information regarding the presentation of consolidated financial results pursuant to the 1999 merger of SPR and NVP. NVP is an operating public utility that provides electric service in Clark County in southern Nevada. The assets of NVP represent 51% of the consolidated assets of SPR at December 31, 2000. NVP provides electricity to approximately 611,000 customers in the communities of Las Vegas, North Las Vegas, Henderson, Searchlight, Laughlin and adjoining areas. Service is also provided to Nellis Air Force Base and the Department of Energy at Mercury and Jackass Flats at the Nevada Test Site. The consolidated financial statements of SPR include the accounts of NVP's wholly owned subsidiaries, NVP Capital I and NVP Capital III. SPPC is an operating public utility that provides electric service in northern Nevada and northeastern California. SPPC also provides natural gas and water services in the Reno/Sparks area of Nevada. The assets of SPPC represent 39% of the consolidated assets of SPR at December 31, 2000. SPPC provides electricity to approximately 309,500 customers in a 50,000 square mile service area including western, central and northeastern Nevada, including the cities of Reno, Sparks, Carson City, Elko, and a portion of eastern California, including the Lake Tahoe area. The consolidated financial statements of SPR include the accounts of SPPC's wholly owned subsidiaries, Pinon Pine Corporation, Pinon Pine Investment Company, GPSF-B, SPPC Funding LLC, and Sierra Pacific Power Capital I. The Utilities' accounts for electric operations and SPPC's accounts for gas operations are maintained in accordance with the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission ("FERC"). SPPC maintains its accounts for water operations in accordance with the Uniform System of Accounts prescribed by the National Association of Regulatory Utility Commissioners. TGPC is a partner in a joint venture that developed, constructed, and operates a natural gas pipeline serving the expanding gas market in the Reno area and certain northeastern California markets. TGPC accounts for its joint venture interest under the equity method. eo three provides comprehensive energy services in commercial and industrial markets on a regional basis. SPE markets a package of telecommunication products and services. SPC was formed in 1999 to provide telecommunications services using fiber optic cable technology in both northern and southern Nevada. SPR is a limited partner in an energy technology venture capital partnership formed to gain access to new technologies that could affect SPR and its subsidiaries. This partnership invests in energy 93 companies offering technologies of strategic advantage to its partners. The initial term of this partnership expires in 2006, with two extensions of up to two years each. SPR's investment in the partnership was $4.4 million as of December 31, 2000, of which $875,000 was made in 2000. The remaining $600,000 balance of SPR's commitment is expected to be drawn as funds are needed by the partnership during 2001. Gains and losses will be allocated 80% to the limited partners based on their contributions, and 20% to the general partner. SPR, as a limited partner, is entitled to 7.89% and accounts for this investment on the cost basis. The preparation of consolidated financial statements in conformity with generally accepted accounting principles in the United States of America requires management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities. These estimates and assumptions also affect the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of certain revenues and expenses during the reporting period. Actual results could differ from these estimates. Certain reclassifications of prior year information have been made for comparative purposes but have not affected previously reported net income or common shareholders' equity. Utility Plant In addition to direct labor and material costs, the Utilities also charge the following to the cost of constructing utility plant: the cost of time spent by administrative employees in planning and directing construction work; property taxes; employee benefits (including such costs as pensions, postretirement and postemployment benefits, vacations and payroll taxes); and an allowance for funds used during construction (AFUDC). The original cost of plant retired or otherwise disposed of and the cost of removal less salvage is generally charged to the accumulated provision for depreciation. The cost of current repairs and minor replacements is charged to operating expenses when incurred. The cost of renewals and betterments is capitalized. Allowance For Funds Used During Construction and Capitalized Interest As part of the cost of constructing utility plant, the Utilities capitalize AFUDC. AFUDC represents the cost of borrowed funds and, where appropriate, the cost of equity funds used for construction purposes in accordance with rules prescribed by the FERC and the Public Utility Commission for Nevada ("PUCN"). AFUDC is capitalized in the same manner as construction labor and material costs, with an offsetting credit to "other income" for the portion representing the cost of equity funds and as a reduction of interest charges for the portion representing borrowed funds. Recognition of this item as a cost of utility plant is in accordance with established regulatory ratemaking practices. Such practices permit the utility to earn a fair return on, and recover in rates charged for utility services, all capital costs. This is accomplished by including such costs in the rate base and in the provision for depreciation. NVP's AFUDC rates used during 2000, 1999, and 1998 were 8.34%, 8.55%, and 9.66%, respectively. SPPC's AFUDC rates used during 2000, 1999, and 1998 were 7.17%, 6.09%, and 7.69%, respectively. As specified by the PUCN, certain projects were assigned a lower AFUDC rate due to specific low-interest-rate financings directly associated with those projects. 94 Depreciation Depreciation is calculated using the straight-line composite method over the estimated remaining service lives of the related properties. NVP's depreciation provision for 2000, 1999, and 1998, as authorized by the PUCN and stated as a percentage of the original cost of depreciable property, was approximately 2.9%. SPPC's depreciation provision for 2000, 1999, and 1998, as authorized by the PUCN and stated as a percentage of the original cost of depreciable property, was approximately 3.21%, 3.14%, and 3.31%, respectively. Cash and Cash Equivalents Cash is comprised of cash on hand and working funds. Cash equivalents consist of high quality investments in money market funds. Current Assets - Other Included in the December 31, 2000, balance of Current Assets - Other presented in the SPR, NVP and SPPC Balance Sheets is $35.2 million, $13.2 million and $22.0 million, respectively, of federal income taxes receivable due to the tax benefit resulting from losses. Regulatory Accounting and Other Regulatory Assets The Utilities' rates are currently subject to the approval of the PUCN and are designed to recover the cost of providing generation, transmission and distribution services. As a result, the Utilities qualify for the application of Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation", issued by the Financial Accounting Standards Board (FASB). This statement recognizes that the rate actions of a regulator can provide reasonable assurance of the existence of an asset and requires the capitalization of incurred costs that would otherwise be charged to expense where it is probable that future revenue will be provided to recover these costs. SFAS No. 71 prescribes the method to be used to record the financial transactions of a regulated entity. The criteria for applying SFAS No. 71 include the following: (i) rates are set by an independent third party regulator, (ii) approved rates are intended to recover the specific costs of the regulated products or services, and (iii) rates that are set at levels that will recover costs can be charged to and collected from customers. SFAS No. 101, "Regulated Enterprises-Accounting for the Discontinuation of Application of FASB Statement No. 71", requires that an enterprise whose operations cease to meet the qualifying criteria of SFAS No. 71 discontinue the application of that statement by eliminating the effects of any actions of regulators that had been previously recognized. In 1997, the Emerging Issues Task Force (EITF) released Issue 97-4. In doing so, it reached a consensus that a utility subject to a deregulation plan for its generation business should stop applying SFAS No. 71 to the generating portion of its business no later than the date when a deregulation plan with sufficient detail of the effect of the plan is known. EITF 97-4 also reached a consensus that regulatory assets and liabilities that originated in a portion of the business that is discontinuing its application of SFAS No. 71 should be evaluated on the basis of where (that is, the portion of the business in which) the regulated cash flows to realize and settle them will be derived. The result of the consensus is that there is no elimination of regulatory assets which the deregulatory legislation or rate order specifies collection of, if the regulatory assets are recoverable through a portion of the business which remains subject to SFAS No. 71. 95 In conformity with SFAS No. 71, the accounting for the Utilities conforms to generally accepted accounting principles as applied to regulated public utilities and as prescribed by the agencies and commissions of the jurisdictions in which they operate. In accordance with these principles, certain costs that would otherwise be charged to expense or capitalized as plant costs are deferred as regulatory assets based on expected recovery from customers in future rates. Management's expected recovery of deferred costs is based upon specific ratemaking decisions or precedent for each item. The following other regulatory assets were included in the consolidated balance sheets of SPR as of December 31 (dollars in thousands):
DESCRIPTION 2000 1999 AMORTIZATION PERIODS ------------------------------------------- --------- --------- -------------------- Early retirement and severance offers $ 12,567 $ 17,001 Various through 2004 Loss on reacquired debt 32,548 31,279 Various through 2030 Plant assets 3,964 7,104 Various through 2031 Merger transition costs 8,275 6,638 To be determined Merger severance/relocation 22,434 19,398 To be determined Merger goodwill 11,533 3,392 To be determined Other costs 14,267 16,415 Various --------- --------- Total $ 105,588 $ 101,227 ========= =========
Currently, the electric utility industry is predominantly regulated on a basis designed to recover the cost of providing electric power to its retail and wholesale customers. If cost-based regulation were to be discontinued in the industry for any reason, including competitive pressure on the cost-based prices of electricity, profits could be reduced, and utilities might be required to reduce their asset balances to reflect a market basis less than cost. Discontinuance of cost-based regulation would also require affected utilities to write off their associated regulatory assets. Management cannot predict the potential impact, if any, of these competitive forces on the Utilities' future financial position and results of operations. Management periodically assesses whether the requirements for application of SFAS 71 are satisfied. Given the uncertainty related to the current restructuring legislation and PUCN restructuring rules that would ultimately enable retail competition in Nevada, the Utilities continue to apply regulatory accounting to the generation, transmission and distribution portions of their businesses. Deferral of Energy Costs Nevada and California statutes permit regulated utilities to, from time-to- time, adopt deferred energy accounting procedures, which record as deferred energy costs the difference between actual energy expense and energy revenues. Under regulations adopted by the PUCN, deferred energy rates are revised at least every 12 months to recapture the accumulated deferred balance over a future period. The intent of these procedures is to ease the effect of fluctuations in the cost of purchased gas, fuel and purchased power. NVP utilized deferred energy accounting procedures in 1998, 1999, and part of 2000. Pursuant to stipulated agreements with the PUCN in July 2000, NVP ceased utilizing deferred energy accounting effective August 1, 2000. During 1999, SPPC did not employ deferred energy accounting procedures, but resumed those procedures for natural gas operations as of January 1, 2000. 96 Federal Income Taxes and Investment Tax Credits SPR and its subsidiaries file a consolidated federal income tax return. Current income taxes are allocated based on SPR's and each subsidiary's respective taxable income or loss and investment tax credits as if each subsidiary filed a separate return. Deferred taxes are provided on temporary differences at the statutory income tax rate in effect as of the most recent balance sheet date. SPR accounts for income taxes in accordance with SFAS No. 109, "Accounting for Income Taxes." SFAS No. 109 requires recognition of deferred tax liabilities and assets for the future tax consequences of events that have been included in the consolidated financial statements or tax returns. Under this method, deferred tax liabilities and assets are determined based on the difference between the financial statement and tax bases of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. For regulatory purposes, the Utilities are authorized to provide for deferred taxes on the difference between straight-line and accelerated tax depreciation on post-1969 utility plant expansion property, deferred energy, and certain other differences between financial reporting and taxable income, including those added by the Tax Reform Act of 1986 (TRA). In 1981, the Utilities began providing for deferred taxes on the benefits of using the Accelerated Cost Recovery System for all post-1980 property. In 1987, the TRA required the Utilities to begin providing deferred taxes on the benefits derived from using the Modified Accelerated Cost Recovery System. Investment tax credits are no longer available to the Utilities. The deferred investment tax credits are being amortized over the estimated service lives of the related properties. Revenues Operating revenues include unbilled utility revenues earned (service has been delivered, but not yet billed by the end of the accounting period). These amounts are also included in accounts receivable. Recent Pronouncements Financial Accounting Standards Board Effective January 1, 2001, SPR, SPPC and NVP adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS No. 138. SFAS No. 133, as amended, establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. SFAS No. 133 requires that an entity recognize all derivatives as assets or liabilities in the consolidated balance sheets and measure those instruments at fair value. On January 1, 2001, SPR recorded a transition adjustment to implement this new standard that resulted in an increase in other comprehensive income of approximately $158 million, before tax. SPPC and NVP recorded a transition adjustment to implement this new standard that resulted in an increase in other comprehensive income of approximately $205 million, before tax, and a decrease in other comprehensive income of approximately $43 million, before tax, respectively. The adjustments were recognized as of January 1, 2001, as the cumulative effect of a change in accounting principle. There was no significant transition adjustment affecting the consolidated statements of income. The ongoing effects of SFAS No. 133 will depend on future market conditions and the positions in derivative instruments and hedging activities at the measurement dates. 97 NOTE 1A. FINANCIAL STATEMENTS OF NEVADA POWER COMPANY As described in Note 2 that follows, NVP was deemed to be the acquirer of SPR for accounting purposes as reflected in the SPR Consolidated Financial Statements. However, after the merger with SPR and as a result of the structure of the transactions, NVP is a separate legal entity, which is a wholly owned subsidiary of SPR. As a legal matter, NVP does not own any equity interest in SPR. The audited NVP Financial Statements accommodate the presentation of financial information of NVP on a stand-alone basis by summarizing all non-NVP financial information into a few items on each of the Financial Statements. These summarized items are repeated below (in 000's): Non-NVP Financial Items on the NVP Financial Statements
NVP Balance Sheet: December 31, 2000 December 31, 1999 ------------------ ----------------- ----------------- Investment in Sierra Pacific Resources $471,975 $654,156 Equity in Sierra Pacific Resources $471,975 $654,156
The Investment in Sierra Pacific Resources reflects the net assets, after deducting for all liabilities and preferred stock of Sierra Pacific Resources not related to NVP. The Equity in Sierra Pacific Resources reflects the sum of paid-in-capital and retained earnings of SPR, without the benefit of NVP. These line items are required by the rules of purchase accounting and do not represent any asset to which holders of NVP's securities may look for recovery of their investment. These items must be disregarded for determining the ability of NVP to satisfy its obligations or to pay dividends (preferred or common), for calculating NVP's ratios of earnings to fixed charges and preferred stock dividends, and for all of NVP's financial covenants and earnings tests including those under its charter and mortgage.
NVP Income Statement: Twelve Months Ended Twelve Months Ended Twelve Months Ended --------------------- ------------------- ------------------- ------------------- December 31, 2000 December 31, 1999 December 31, 1998 ----------------- ----------------- ----------------- Equity in Earnings (Losses) of Sierra Pacific Resources $(31,852) $13,058 $ --
The Equity in Earnings (Losses) of Sierra Pacific Resources represents the net income (loss) of SPR after SPPC preferred stock dividends. This line item is required by the rules of purchase accounting and does not represent any item of revenue or income to which holders of NVP's securities may look for recovery of their investment. This item must be disregarded for determining the ability of NVP to satisfy its obligations or its ability to pay dividends (preferred or common), for calculating NVP's ratios of earnings to fixed charges and preferred dividends, and for all of NVP's financial covenants and earnings tests including those under its charter and mortgage.
NVP Statement of Cash Flow: Year Ended Year Ended Year Ended --------------------------- ---------- ---------- ---------- December 31, 2000 December 31, 1999 December 31, 1998 ----------------- ----------------- ----------------- Equity in Earnings (Losses) of Sierra Pacific Resources $(31,852) $13,058 $ --
As in the Income Statement, the Equity in Earnings (Losses) of Sierra Pacific Resources represents the net income (loss) of SPR, after SPPC preferred stock dividends. This line item is required by the rules of purchase accounting and does not represent any item of cash flow to which holders of NVP's securities may look for recovery of their investment. This item must be disregarded for determining the ability of NVP to satisfy its obligations or its ability to pay 98 dividends (preferred or common), for calculating NVP's ratios of earnings to fixed charges and preferred dividends, and for all of NVP's financial covenants and earnings tests including those under its charter and mortgage.
NVP Statement of Capitalization: December 31, 2000 December 31, 1999 -------------------------------- ----------------- ----------------- Equity in Sierra Pacific Resources $471,975 $654,156
The Equity in Sierra Pacific Resources reflects the sum of paid-in-capital and retained earnings of SPR on NVP's books. This line item is required by the rules of purchase accounting and does not represent any item of cash flow to which holders of NVP's securities may look for recovery of their investment. This item must be disregarded for determining the ability of NVP to satisfy its obligations or its ability to pay dividends (preferred or common), for calculating NVP's ratios of earnings to fixed charges and preferred dividends, and for all of NVP's financial covenants and earnings tests including those under its charter and mortgage. NOTE 2. SIERRA PACIFIC RESOURCES AND NEVADA POWER MERGER On July 28, 1999, the merger between SPR and NVP was consummated. The merger was accounted for as a reverse purchase under generally accepted accounting principles, with NVP considered the acquiring entity even though SPR is the surviving legal entity. In addition, for accounting purposes the merger was deemed to have occurred on August 1, 1999. As a result of this reverse purchase accounting treatment: (i) the historical financial statements of SPR for periods prior to the date of the merger are no longer the financial statements of SPR, and therefore, are no longer presented; (ii) the historical financial statements of SPR for periods prior to the date of the merger are those of NVP; and (iii) based on a merger date of August 1, 1999, the Consolidated Statements of Income for the twelve months ended December 31, 1999, include five months (August through December 1999) of operating activity for SPR and its subsidiaries other than NVP. The same statements include the operating results of NVP for the entire periods presented Through December 31, 2000, SPR incurred a total of $57.9 million in capitalized costs since merger work began. The capitalized merger amounts consist of $35.5 million of transaction and transition costs and $22.4 million of employee separation costs. Employee severance, relocation, and related costs for SPR were $22.4 million, of which $.9 million remains unpaid as of December 31, 2000. Other costs incurred in connection with employee separations included pension and postretirement benefits net of plan gains of $4.5 million. In accordance with the terms of the merger, each outstanding share of SPR's common stock was converted into the right to receive either $37.55 in cash or 1.44 shares of newly issued SPR common stock. Each outstanding share of NVP common stock was converted to the right to receive either $26.00 in cash or 1.00 share of newly issued SPR common stock. 4,037,000 shares of SPR and 11,716,611 shares of NVP common stock were exchanged for $151.6 million and $304.6 million, respectively. The remaining shares of each company were converted to newly issued shares of SPR common stock. SPR stockholders and NVP stockholders received 38,866,054 and 39,548,506 shares, respectively, of newly issued SPR common stock, resulting in 78,414,560 outstanding shares of SPR on August 1, 1999. The total consideration paid to SPR common stockholders was equal to cash of $151.6 million and 38,866,054 shares of newly issued SPR common stock at a price of $24.18 per share based on the average closing price of NVP common stock between April 22, 1998 and May 6, 1998. The eleven-day 99 average price of NVP common stock used in determining the total stock consideration represents the market price over a reasonable period of time before and after the transaction was announced on April 29, 1998. Goodwill of $331.2 million was recorded in connection with the merger and is being amortized over 40 years. However, the order of the Public Utilities Commission of Nevada (PUCN) approving the merger allowed SPR to defer merger costs (including goodwill) allocable to the regulated Utilities for a three-year period. At the end of the deferral period SPR will propose an amortization period for goodwill and other merger costs. Accordingly, goodwill amortization associated with the regulated Utilities is being reclassified to a regulatory asset during the three-year period. NOTE 3. REGULATORY ACTIONS Nevada Matters -------------- Earnings Sharing (SPPC) On May 1, 2000, SPPC filed its third and last compliance filings related to the 1997 rate stipulation. The filings provide a calculation of Sierra's electric and gas earnings in excess of a 12% return on equity (ROE). Any earnings in excess of 12% ROE are shared 50/50 between shareholders and customers. On August 4, 2000, the PUCN approved a stipulation between SPPC, Staff, and the UCA that rebated $8.63 million and $670,000 to electric and gas customers, respectively, in 2000. In addition SPPC refunded an additional $390,000 to electric customers resulting from the 1999 compliance filing. The August 4, 2000, approved stipulation also resolved all outstanding issues associated with previous shared earning filings. Stipulations (The Global Settlement) On July 20, 2000, SPR, NVP and SPPC signed the "Global Settlement" stipulation which eliminated NVP's deferred energy accounting adjustment ("DEAA") rates, effective August 1, 2000. In consideration of such termination, NVP will be allowed to recover out of the first-available after-tax proceeds from the sale of NVP's generation assets above book value and costs of sale, up to $15 million in the aggregate. Until such recovery is completed NVP may accrue carrying charges at an annual rate of 9.5% on the unrecovered balance. Also part of the Global Settlement, a Fuel and Purchased Power Rider ("F&PP") allowed NVP to increase its rates effective August 1, 2000, by approximately $48 million annually to recover increased costs of fuel and purchased power, and to update its going-forward costs of fuel and purchased power thereafter with monthly fuel and purchased power filings up to March 2003. Increases and/or decreases are capped at incrementally increased or decreased rates over successive six-month periods at .95 mils for the first six months, 1.15 mils for the second six months, 1.25 mils for the third six months, 1.55 mils for the next six months, and 1.75 mils for the remaining period. The Settlement also permitted SPPC to commence filing monthly fuel and purchased power adjustment cases on the same basis to commence not later than November 1, 2000. SPPC fuel and purchased power increases and/or decreases are also capped at incrementally increased or decreased rates over successive six-month periods starting October 1, 2000 at 4.5 mils for the first six-month period followed by .95, 1.15, 1.35, 1.55, and1.75 mils for each successive six-month period. Under the terms of the Settlement, the PUCN will review the prudency of the increases after submission of semi-annual audits with refunds, if any, to be included in future adjustments. 100 Comprehensive Energy Plan See Note 20, Subsequent Events. California Matters On February 18, 1999, the California Public Utility Commission (CPUC) approved SPPC's proposed Revenue Cycle Services Credits (RCSC) application filed February 2, 1998. The RCSC addresses meter ownership, meter services, meter reading, and billing and applies to customers who select their provider of a revenue cycle service. On April 9, 1999, SPPC made a compliance tariff filing which reflects the approved credits. On April 5, 1999, the CPUC approved SPPC's proposed unbundled rates effective back to June 1, 1998. FERC Matters (SPPC) In March 1999, SPPC filed an application with the FERC to increase its Open Access Transmission rates. In October 1999, SPPC filed an Offer of Partial Settlement which resolved all issues with the exception of pricing to the Mines and to the City of Fallon. On January 31, 2000, the FERC approved the Partial Settlement. On March 30, 2000, SPPC filed a Loss Study that SPPC agreed to provide in the Partial Settlement. On April 26, 2000, a settlement was filed by SPPC on issues raised by the City of Fallon and on August 1, 2000, the FERC approved the settlement. On July 18, 2000, a settlement was filed by SPPC on issues raised by the Mines which provides that the issues not be resolved in this case, but at a later date. On September 18, 2000, the FERC approved the settlement. On July 7, 2000, a settlement was filed by SPPC resolving all Loss Study issues in the case and on September 18, 2000, the FERC approved the settlement. On March 31, 2000, the Utilities filed for approval of Generation Tariffs that contain the rates, terms and conditions under which the new owners of divested generation facilities could sell energy and ancillary services. The filing also included pro-forma Transitional Purchase Power Agreements (TPPAs) between the Utilities and the new owners of the divested generation facilities. Final signed versions of the TPPAs will be submitted to the FERC as part of the Asset Sale Agreements between the Utilities and the new owners of the divested generation. On May 31, 2000, the FERC accepted for filing the Generation Tariff and the TPPAs. The FERC required one modification to the TPPAs in that the Utilities were required to notify the new owners day-ahead of real-time of their intended use of the generation or release the capacity to the new owners. The FERC also set for hearing the rates in the generation tariff and in the TPPAs. The Utilities have reached a settlement with the FERC Staff, PUCN and the Bureau of Consumer Protection regarding the rates in the Generation Tariff and TPPAs. The settlement has not yet been submitted to the FERC for approval. FERC Matters (NVP) On May 29, 1999, SPPC and NVP filed an application with the FERC to increase its Open Access Transmission rates. On November 24, 1999, an unopposed motion to suspend the procedural schedule to allow consummation of a settlement was filed with the FERC. The Settlement was filed February 8, 2000 and the proposed rates became effective on March 1, 2000. 101 On March 31, 1999, NVP filed with the FERC for approval of generation tariffs, which contain the rates, terms and conditions under which the new owners of SPR's generation would operate after divestiture. The FERC approved the tariffs on November 1, 1999. In compliance with the FERC's November 1 order, NVP filed pro forma service agreements for the approved tariffs on November 16, which were subsequently approved on December 16. NOTE 4. EARNINGS PER SHARE SPR follows SFAS No. 128, "Earnings Per Share". The following provides the calculation for Diluted EPS. The difference between Basic EPS and Diluted EPS is due to common stock equivalent shares resulting from stock options, the employee stock purchase plan, performance shares and a non-employee director stock plan. Common stock equivalents were determined using the treasury stock method. 102
December 31, ------------------------------------------------- 2000 1999 1998 ------------ ------------ ------------ Basic EPS Numerator (Loss) Income from continuing operations ($000) $ (49,414) $ 48,210 $ 83,499 Income from discontinued operations ($000) 9,634 3,540 -- ------------ ------------ ------------ (Loss) Net income ($000) $ (39,780) $ 51,750 $ 83,499 ============ ============ ============ Denominator Weighted average number of shares outstanding 78,435,405 62,577,385 50,993,000 Per-Share Amounts: ------------ ------------ ------------ (Loss) Income from continuing operations $ (0.63) $ 0.77 $ 1.64 Income from discontinued operations 0.12 0.06 -- ------------ ------------ ------------ (Loss) Net income $ (0.51) $ 0.83 $ 1.64 ============ ============ ============ Diluted EPS Numerator (Loss) Income from continuing operations ($000) $ (49,414) $ 48,210 $ 83,499 Income from discontinued operations ($000) 9,634 3,540 -- ------------ ------------ ------------ (Loss) Net income ($000) $ (39,780) $ 51,750 $ 83,499 ============ ============ ============ Denominator Weighted average number of shares outstanding before dilution 78,435,405 62,577,385 50,993,000 Stock options 5,645 20,447 -- Executive long term incentive plan- performance shares 35,393 26,118 -- Non-Employee Director stock plan 5,885 5,736 -- Employee stock purchase plan 2,807 1,790 -- ------------ ------------ ------------ 78,485,135 62,631,476 50,993,000 ------------ ------------ ------------ Per-Share Amounts: (Loss) Income from continuing operations $ (0.63) $ 0.77 $ 1.64 Income from discontinued operations 0.12 0.06 -- ------------ ------------ ------------ (Loss) Net income $ (0.51) $ 0.83 $ 1.64 ============ ============ ============
103 NOTE 5. INVESTMENTS IN SUBSIDIARIES AND OTHER PROPERTY Investments in subsidiaries and other property consisted of (dollars in thousands): Sierra Pacific Resources ------------------------ December 31, 2000 1999 -------- -------- Investment in Pinon Pine, LLC $ 58,049 $ 60,043 Investment in TGTC 17,164 16,408 Cash Value-Life Insurance 13,393 11,492 Acquisition Costs 12,451 1,698 Other Investments 34,005 16,239 -------- -------- $135,062 $105,880 ======== ======== Nevada Power Company -------------------- December 31, 2000 1999 -------- -------- Cash Value-Life Insurance $ 13,393 $ 11,492 Other 25 4,152 -------- -------- $ 13,418 $ 15,644 ======== ======== Sierra Pacific Power Company ---------------------------- December 31, 2000 1999 -------- -------- Investment in Pinon Pine, LLC $ 58,049 $ 60,043 Other 1,998 2,661 -------- -------- $ 60,047 $ 62,704 ======== ======== NOTE 6. JOINTLY OWNED FACILITIES At December 31, 2000, SPR (through its utility subsidiaries NVP and SPPC) owned the following undivided interests in jointly owned electric utility facilities:
Construction % Owned Accumulated Net Plant in Work in Generating Facility by Company Plant in Service Depreciation Service Progress Subsidiary ----------------------------------------------------------------------------------------------------------------------------- Navajo Station 11.3 $201,614 $ 90,881 $110,733 $ 4,386 NVP Mohave Facility 14.0 78,679 34,733 43,946 6,160 NVP Reid Gardner No. 4 32.2 125,945 50,906 75,039 797 NVP Valmy Station 50.0 280,009 118,521 161,488 102 SPPC -------- -------- -------- ------- TOTAL $686,247 $295,041 $391,206 $11,445 ======== ======== ======== =======
The amounts above for Navajo and Mohave include NVP's share of transmission systems and general plant equipment and, in the case of Navajo, NVP's share of the jointly owned railroad which delivers coal to the plant. Each participant provides its own financing for all of these jointly owned 104 facilities. NVP's share of operating expenses for these facilities is included in the corresponding operating expenses in the Consolidated Statements of Income. Valmy SPPC and Idaho Power Company each own an undivided 50% interest in the Valmy generating station, with each company being responsible for financing its share of capital and operating costs. SPPC is the operator of the plant for both parties. SPPC's share of direct operation and maintenance expenses for Valmy is included in the accompanying Consolidated Statements Of Income. Pinon Pine Pinon Pine Corp. and Pinon Pine Investment Co., wholly owned subsidiaries of SPPC, collectively own a 38% interest in Pinon Pine Company, L.L.C. GPSF-B, a Delaware corporation formerly owned by General Electric Capital Corporation (GECC) and now owned by SPPC, owns the remaining 62% as of February 1999. The LLC was formed to take advantage of federal income tax credits associated with the alternative fuel (syngas) produced by the coal gasifier available under ss. 29 of the Internal Revenue Code. The entire project, which includes an LLC-owned gasifier and an SPPC-owned power island and post-gasification facility to partially cool and clean the syngas, is referred to collectively as the Pinon Pine Power Project. Pinon Pine is a project co-funded by the Department of Energy (DOE) under an agreement between SPPC and DOE that runs through December 31, 2000. Through December 31, 2000, the DOE has funded $166.5 million for both construction and operation and maintenance of the project. To date, SPPC has not been successful in obtaining sustained operation of the gasifier but work continues to identify problem areas and redesign solutions which will likely require additional capital expenditures. Due to the problems noted above, SPPC and Foster Wheeler settled on a portion of the cost overrun and have entered into an alternative dispute resolution. NOTE 7. COMMON STOCK AND ADDITIONAL PAID-IN CAPITAL As of December 31, 2000, 3,568,358 shares of common stock were reserved for issuance under the Common Stock Investment Plan (CSIP), Employees' Stock Purchase Plan (ESPP), Non-Employee Director Stock Plan and Executive Long-Term Incentive Plan (ELTIP). The ELTIP for key management employees allows for the issuance of SPR's common shares to key employees through December 31, 2003. This Plan permits the following types of grants, separately or in combination: nonqualified and qualified stock options; stock appreciation rights; restricted stock; performance units; performance shares and bonus stock. SPR also provides an ESPP to all of its employees meeting minimum service requirements. Employees can choose twice each year to have up to 15% of their base earnings withheld to purchase company common stock. The purchase price of the stock is 90% of the market value on the offering date or 100% of the market price on the execution date, if less. The Non-employee Director Stock Plan provides that a portion of SPR's outside directors' annual retainer be paid in SPR common stock. SPR records the costs of these plans in accordance with Accounting Principles Board Opinion Number 25. As a part of the August 1, 1999, merger, the NVP ELTIP was terminated and existing SPR plans were adopted by the surviving company. 105 On September 21, 1999, the Board of Directors of SPR (the "SPR Board") declared a dividend distribution of one right (an "SPR Right") for each outstanding share of SPR common stock to shareholders of record at the close of business on October 31, 1999. By issuing the new SPR Rights, the SPR Board extended the benefits and protections afforded to shareholders under the Rights Agreement, dated as of October 31, 1989, which expired on October 31, 1999. Each SPR Right, initially evidenced by and traded with the shares of SPR Common Stock, entitles the registered holder (other than an "Acquiring Person" as defined in the Rights Agreement) to purchase at an exercise price of $75.00, $150.00 worth of common stock at its then-market value, subject to certain conditions and approvals set forth in the Rights Agreement. If, at any time while there is an Acquiring Person, SPR engages in a merger or other business combination transaction or series of related transactions in which the Common Stock is changed or exchanged or 50% or more of its assets or earning power is transferred, each SPR Right (not previously voided by the occurrence of a Flip-in Event, as described in the Rights Agreement) will entitle its holder to purchase, at the SPR Right's then-current Exercise Price, common stock of such Acquiring Person having a calculated value of twice the SPR Right's then-current Exercise Price. The SPR Rights are not exercisable until the Distribution Date and expire on October 31, 2009, unless previously redeemed by SPR. Following an SPR Distribution Date, the SPR Rights will trade separately from the SPR Common Stock and will be evidenced by separate certificates. Until an SPR Right is exercised, the holder thereof will have no rights as a shareholder of SPR, including, without limitation, the right to receive dividends. The purpose of the plan is to help ensure that SPR's shareholders receive fair and equal treatment in the event of any proposed hostile takeover of SPR. The changes in common stock and additional paid-in capital for 2000, 1999, and 1998, are as follows (dollars in thousands):
Shares Issued Amount 2000 1999 1998 2000 1999 1998 ---------- ------------ ---------- --------- -------- --------- Merger exchange - 78,414,560 - $ - $ 66,540 $ - CSIP/DRP 5,389 - 799,762 237 - 19,067 ESPP, and other 55,268 - 65,609 1,055 - 1,564 ---------- ------------ ---------- --------- -------- -------- 60,657 78,414,560 865,371 $ 1,292 $ 66,540 $ 20,631 ========== ============ ========== ========= ======== ========
NOTE 8. PREFERRED STOCK AND PREFERRED SECURITIES All issues of preferred stock are superior to SPR common stock with respect to dividend payments (which are cumulative) and liquidation rights. 106 The following table indicates the dollar amount and number of shares outstanding at December 31 of each year:
Amount Shares Outstanding -------------------------- ------------------------ (Dollars in thousands) 2000 1999 2000 1999 -------------------------- ------------------------ Preferred Stock --------------- Not subject to mandatory redemption SPPC Class A Series I $ 50,000 $ 50,000 2,000,000 2,000,000 -------------------------- ------------------------ Total Preferred stock 50,000 50,000 2,000,000 2,000,000 ========================== ======================== Preferred Securities -------------------- Subject to mandatory redemption: Preferred Securities of Nevada Power Co Capital I $ 118,872 $ 118,872 147,058 147,058 Preferred Securities of Nevada Power Co Capital III 70,000 70,000 86,598 86,598 -------------------------- ------------------------- Subtotal 188,872 188,872 233,656 233,656 Preferred securities of Sierra Pacific Power Company Capital I 48,500 48,500 1,940,000 1,940,000 -------------------------- ------------------------ Total Preferred Securities 237,372 237,372 2,173,656 2,173,656 ========================== ========================
NVP NVP's obligations provide a full and unconditional guarantee of the Trust's obligations under the QUIPS. Financial statements of the Trust are consolidated with NVP's. Separate financial statements are not filed because the Trust is wholly owned by NVP and essentially has no independent operations, and NVP's guarantee of the Trust's obligations is full and unconditional. The $118.9 million in net proceeds was used for general corporate utility purposes and the repayment of short-term debt. In October 1998, NVP Capital III (Trust), a wholly-owned subsidiary of Nevada Power Company, issued 2,800,000, 7 3/4% Cumulative Quarterly Trust Issued Preferred Securities at $25 per security. NVP owns the entire common securities, 86,598 shares issued by the Trust for $2.2 million. The Trust Issued Preferred Securities and the common securities represent undivided beneficial ownership interests in the assets of the Trust, a statutory business trust formed under the laws of the state of Delaware. The existence of the Trust is for the sole purpose of issuing the Trust Issued Preferred Securities and the common securities and using the proceeds thereof to purchase from NVP its 7 3/4% Junior Subordinated Deferrable Interest Debentures due September 30, 2038, extendible to September 30, 2047, under certain conditions, in a principal amount of $72.2 million. The sole asset of the Trust is the deferrable interest debentures. Holders of the Trust Issued Preferred Securities are entitled to receive preferential cumulative cash distributions accruing from the date of original issuance and payable quarterly on the last day of March, June, September and December of each year. The Trust Issued Preferred Securities are subject to mandatory redemption, in whole or in part, upon repayment of the deferrable interest debentures at maturity or their earlier redemption in an amount equal to the amount of related deferrable interest debentures maturing or being redeemed. The Trust Issued Preferred Securities are redeemable at $25 per preferred security plus accumulated and unpaid distributions thereon to the 107 date of redemption. NVP's obligations provide a full and unconditional guarantee of the Trust's obligations under the Trust Issued Preferred Securities. Financial statements of the Trust are consolidated with NVP's. Separate financial statements are not filed because the Trust is wholly owned by NVP and essentially has no independent operations, and NVP's guarantee of the Trust's obligations is full and unconditional. The $70 million in net proceeds was used for general corporate utility purposes including the repayment of short-term debt. On July 23, 1999, NVP redeemed the 4.7%, 5.2% and 5.4% Series Redeemable Cumulative Preferred Stock. The total par value and premium was $3.5 million and was paid in accordance with the merger agreement with Sierra Pacific Resources. SPPC SPPC's Restated Articles of Incorporation, as amended on August 19, 1992, authorize an aggregate total of 11,780,500 shares of preferred stock at any given time. On July 29, 1996, Sierra Power Capital I (the Trust), a wholly owned subsidiary of SPPC, issued $48.5 million (1,940,000 shares) of 8.60% Trust Originated Preferred Securities (the Preferred Securities). SPPC owns all the common securities of the Trust; 60,000 shares totaling $1.5 million (Common Securities). The Preferred Securities and the Common Securities (the Trust Securities) represent undivided beneficial ownership interests in the assets of the Trust. The existence of the Trust is for the sole purpose of issuing the Trust Securities and using the proceeds thereof to purchase from SPPC its 8.60% Junior Subordinated Debentures due July 30, 2036, in a principal amount of $50 million. The sole asset of the Trust is SPPC's junior subordinated debentures. SPPC's obligations provide a full and unconditional guarantee of the Trust's obligations under the Preferred Securities. The Preferred Securities of Sierra Pacific Power Capital I are redeemable only in conjunction with the redemption of the related 8.60% junior subordinated debentures. The junior subordinated debentures will mature on July 30, 2036, and may be redeemed, in whole or in part, at any time on or after July 30, 2001, or at any time in certain circumstances upon the occurrence of a tax event. A tax event occurs if an opinion has been received from tax counsel that there is more than an insubstantial risk that: the Trust is, or will be subject to federal income tax with respect to interest accrued or received on the junior subordinated debentures; the Trust is, or will be subject to more than a de minimis amount of other taxes, duties or other governmental charges; interest payable by SPPC to the Trust on the junior subordinated debentures is not, or will not be, deductible, in whole or in part for federal income tax purposes. Upon the redemption of the junior subordinated debentures, payment will simultaneously be applied to redeem preferred securities having an aggregate liquidation amount equal to the aggregate principal amount of the Junior Subordinated Debentures. The preferred securities are redeemable at $25 per preferred security plus accrued dividends. Financial statements of the Trust are consolidated with SPPC's. Separate financial statements are not filed because the Trust is wholly owned by SPPC and essentially has no independent operation, and SPPC's guarantee of the Trust's obligations is full and unconditional. On November 1, 1999, SPPC paid $23.5 million, par value and premium, to redeem Series A, $2.44 Dividend (4.88%), Series B, $2.36 Dividend (4.72%) and Series C, $3.90 Dividend (7.8%). On February 15, 2001, SPPC received consents from the holders of a majority of its preferred stock to increase the amount of unsecured indebtedness that SPPC may issue. Under SPPC's Restated Articles of Incorporation, SPPC cannot, without the consent of a majority of the total number of votes 108 which may be cast by the holders of SPPC's preferred stock, issue unsecured debt securities with maturities of greater than 12 months for any purpose (other than refunding outstanding unsecured debt or retiring outstanding shares of preferred stock) if such unsecured indebtedness would exceed 20% of the aggregate of (1) the total principal amount of all bonds and other securities representing secured indebtedness then outstanding and (2) the total capital and surplus of SPPC then stated on its books. As of September 30, 2000, SPPC could issue approximately $14 million in additional unsecured debt under this limitation. Pursuant to the consent solicitation, SPPC received the consent of the holders of a majority of preferred stock to issue up to $400 million in long-term unsecured indebtedness in excess of the present limitation. Upon receipt of the required number of consents, SPPC paid a participation premium in the amount of $.50 per share consented to each holder of shares of preferred stock whose valid, unrevoked consent was received prior to the specified return date. The aggregate amount of the participation premium paid was $.9 million. The only series of preferred stock of SPPC currently outstanding is its Class A, Series 1 Preferred Stock, of which 2 million shares are outstanding. NOTE 9. LONG TERM DEBT Substantially all utility plant is subject to the lien of NVP and SPPC indentures under which the first mortgage bonds are issued. Nevada Power Company On March 30, 1999, NVP issued $130 million, 6.2%, Series A senior unsecured notes, due 2004. The notes were issued under rule 144A with registration rights. Net proceeds were used to repay NVP's line of credit. On October 1, 1999, NVP redeemed $45,000,000, Series Y, 6.93%, in first mortgage bonds. On April 20, 2000, NVP utilized a $100 million capital contribution from SPR to retire $85 million of NVP's First Mortgage Bonds maturing on May 1, 2000, and the remaining proceeds were used to pay off its commercial paper outstanding under the program established in July 1999. On June 9, 2000, NVP issued $150 million of floating rate notes that will mature on June 12, 2001. Interest on the notes is payable quarterly. The interest rate on the notes for each interest period is a floating rate, subject to adjustment every three months, equal to the London InterBank Offered Rate (LIBOR) for three-month U.S. dollar deposits plus a spread of 0.55%. These notes are not entitled to any sinking fund and are non-callable. The net proceeds of the $150 million issue were used to redeem $100 million of floating rate notes on July 14, 2000, and the remaining proceeds were used to reduce NVP's commercial paper outstanding under the program established in July 1999. On June 22, 2000, Clark County, Nevada issued for NVP's benefit $100 million Industrial Development Refunding Revenue Bonds, Series 2000A, due June 1, 2020. The interest rate is currently being determined by a Dutch Auction based on an auction period of seven days. The Series A bonds were issued to refund $100 million of Clark County's 7.80% Industrial Development Revenue Bonds Series 1990 on June 30, 2000. On July 28, 2000, Clark County, Nevada issued for NVP's benefit $15 million Pollution Control Refunding Revenue Bonds, Series 2000B, due October 1, 2009. The interest rate is currently being determined by a Dutch Auction based on an auction period of seven days. The Series B bonds were issued to refund a like principal amount of Clark County's 7.80% Pollution Control Revenue Bonds Series 1989 on October 2, 2000. 109 The method of determining the interest rate on the Series A and Series B Bonds may be converted from time to time in accordance with the related Indenture so that such bonds would, thereafter, bear interest at a daily, weekly, flexible, term or auction rate. Both Series A and Series B Bonds are insured by AMBAC Assurance Corporation. On July 24, 2000, NVP received a 30-day extension on its $150 million Credit Facility to August 28, 2000, in accordance with the terms of the credit agreement. On August 28, 2000, NVP received a 364-day extension of this facility to August 27, 2001. The credit program was established in July 1999 to provide credit for general corporate purposes including commercial paper backup. On August 18, 2000, NVP issued $100 million of floating rate notes that will mature on August 20, 2001. Interest on the notes is payable quarterly, commencing on November 18, 2000. The interest rate on the notes for each period is a floating rate, subject to adjustment every three months, equal to the London InterBank Offered Rate (LIBOR) for three-month U.S. dollar deposits plus a spread of 0.58%. These notes are not entitled to any sinking fund. The notes are redeemable at the option of NVP, in whole or in part from time to time, without premium, beginning February 18, 2001. The net proceeds of the $100 million issue were used to reduce NVP's commercial paper outstanding under the program established in July 1999. On March 1, 2001, NVP entered into an Amendment and Waiver Agreement related to its Credit Agreement modifying the fixed charge coverage ratio required by the Agreement's financial covenants. Sierra Pacific Power Company On April 9, 1999, SPPC sold the right to receive payments made in respect of Transition Property as defined by the Offering Circular dated March 30, 1999, to SPPC Funding LLC, a Delaware special purpose limited liability company whose sole member is SPPC, in exchange for the proceeds of the SPPC Funding LLC Notes, Series 1999-1 (the Underlying Notes). SPPC Funding LLC then issued and sold the Underlying Notes to the California Infrastructure and Economic Development Bank Special Purpose Trust SPPC-1 (the Trust) in exchange for the proceeds of the sale of the Trust's $24 million 6.4% Rate Reduction Certificates, Series 1999-1 (the Certificates). The Trust, which had been established by the California Infrastructure and Economic Development Bank, issued and sold the Certificates in a private placement pursuant to Rule 144A under the Securities Act of 1933, as amended. The Certificates are one of a series of rate reduction certificates that may be issued from time to time by the Trust and sold to investors upon terms determined at the time of sale. On July 12 and July 16, 1999, respectively, $10 million of the 6.86% and $20 million of the 6.83% of the Series C, collateralized medium-term SPPC notes matured. On September 17, 1999, SPPC issued $100 million floating rate notes, due October 13, 2000. Interest on the notes is payable quarterly, commencing on December 15, 1999. The interest rate on the notes for each interest period to maturity is a floating rate, subject to adjustment every three months. The quarterly rate is equal to the London InterBank Offered Rate (LIBOR) for three- month U.S. dollar deposits plus a spread of 0.75%. These notes are not entitled to any sinking fund and are redeemable in whole, without premium at the option of SPPC, beginning March 15, 2000 and on the 15th day of each month thereafter. The proceeds of this financing were used to pay down commercial paper issued under the program established in July 1999. 110 On June 9, 2000, SPPC issued $200 million of floating rate notes that will mature on June 12, 2001. Interest on the notes is payable quarterly. The interest rate on the notes for each interest period is a floating rate, subject to adjustment every three months, equal to the London InterBank Offered Rate (LIBOR) for three month U.S. dollar deposits plus a spread of 0.50%. These notes are not entitled to any sinking fund and are non-callable. The net proceeds of the $200 million issue were used to redeem $100 million of floating rate notes on July 14, 2000, and the remaining proceeds were used to reduce the amount of SPPC's commercial paper outstanding under the program established in July 1999. On July 24, 2000, SPPC received a 30-day extension of its $150 million Credit Facility to August 28, 2000, in accordance with the terms of the credit agreement. On August 28, 2000, SPPC received a 364-day extension of this facility to August 27, 2001. The credit facility was established in July 1999 to provide credit for general corporate purposes including commercial paper backup. On March 1, 2001, SPPC entered into an Amendment and Waiver Agreement related to its Credit Agreement modifying the fixed charge coverage ratio required by the Agreement's financial covenant. Sierra Pacific Resources On April 1, 1999, $10 million of SPR's Series D senior notes matured. On March 31, 2000, $10 million of SPR's Series E senior notes matured. On April 20, 2000, SPR issued an aggregate of $300 million floating rate notes, $200 million of which matures on April 20, 2003 and the remaining $100 million of which matures on April 20, 2002. Interest on the notes is payable quarterly. The interest rate on the notes for each interest period is a floating rate, subject to adjustment every three months, equal to the London InterBank Offered Rate (LIBOR) for three-month U.S. dollar deposits plus a spread of 0.60% for the notes maturing in 2003, and a spread of 0.65% for the notes maturing in 2002.These notes are not entitled to any sinking fund. The notes due 2002 will be redeemable in whole, without premium, at the option of SPR beginning April 20, 2001, and on each interest payment date thereafter. The net proceeds of the $200 million issue were used to retire an equal amount of commercial paper of SPR issued under the line of credit established in July 1999 that was used as temporary funding for the cash portion of the NVP merger consideration. The net proceeds of the $100 million issue were used to make a capital contribution to NVP. On September 26, 2000, SPR entered into a forward swap relating to its $200 million floating rate notes that will mature on April 20, 2003, effectively locking in a LIBOR rate of 6.655%, which will result in an interest rate of 7.255% on the notes until their maturity. This transaction became effective on October 20, 2000. On April 20, 2000, upon issuance of these floating rate notes, SPR reduced its bank credit facility to $300 million from the previous amount of $500 million in accordance with the terms of credit agreement. The credit facility was established in July 1999 to provide credit for general corporate purposes including commercial paper backup. On June 21, 2000, SPR further reduced its credit facility to $150 million. The remaining $150 million credit facility was a 3-year credit facility, which has since been terminated by SPR effective August 11, 2000. On May 9, 2000, SPR issued $300 million of notes under its universal shelf registration. These notes bear interest at an annual rate of 8.75% and will mature on May 15, 2005. Interest on the notes is payable semi-annually. The notes are not subject to any sinking fund and are redeemable in whole or in part at any time upon payment of the principal amount of the notes being redeemed, plus accrued 111 interest and a make-whole premium. The net proceeds from the issuance of these notes were used to retire an equal amount of commercial paper issued by SPR under the program established in July 1999. NVP's, SPPC's and SPR's aggregate annual amount of maturities for long-term debt for the next five years is shown below (in thousands of dollars):
NVP SPPC SPR ----------- ----------- ----------- 2001 $ 252,910 $ 219,616 $ 472,527 2002 15,000 2,626 117,626 2003 - 20,632 220,632 2004 130,000 2,621 132,621 2005 - 2,622 302,622 ----------- ----------- ----------- Subtotal 397,910 248,117 1,246,028 Thereafter 782,784 577,315 1,360,178 ----------- ----------- ----------- Total $ 1,180,694 $ 825,432 $ 2,606,206 =========== =========== ===========
NOTE 10. TAXES Nevada Power Company The following reflects the composition of taxes on income (in thousands of dollars):
2000 1999 1998 --------- -------- -------- Federal: Taxes estimated to be currently payable (refundable) $ (10,141) $ 38,444 $ 17,163 Deferred taxes related to: Excess of tax depreciations over book depreciation 6,625 12,302 24,111 Contributions in aid of construction and customer advances (6,076) (9,678) (13,211) Avoided interest capitalized (4,557) (3,933) 6,463 Repairs & maintenance 1,750 -- -- Research and experimentation 1,750 -- -- Severance programs -- 2,788 -- Other - net, deferral of energy cost 2,723 (17,250) 12,405 Net amortization of investment tax credit (1,460) (1,460) (1,460) --------- -------- -------- Total $ (9,386) $ 21,213 $ 45,471 ========= ======== ======== As Reflected in Statement of Income: Federal income taxes (12,162) 19,943 42,949 State income taxes -- -- -- --------- -------- -------- Operating Income (12,162) 19,943 42,949 Other income - net 2,776 1,270 2,522 --------- -------- -------- Total $ (9,386) $ 21,213 $ 45,471 ========= ======== ========
112 The total income tax provisions differ from amounts computed by applying the federal statutory tax rate to income before income taxes for the following reasons (in thousands of dollars):
2000 1999 1998 ---------- ---------- --------- Income before preferred dividend requirements $ (7,928) $ 38,793 $ 83,673 Total income tax expense (benefit) (9,386) 21,213 45,471 ---------- ---------- --------- (17,314) 60,006 129,144 Statutory tax rate 35% 35% 35% ---------- ---------- --------- Expected income tax expense (benefit) (6,060) 21,001 45,200 Depreciation related to difference in costs basis for tax purposes 1,431 1,431 1,431 Allowance for funds used during construction - equity 300 300 300 ITC amortization (1,460) (1,460) (1,460) Other - net (3,597) (59) -- ---------- ---------- --------- $ (9,386) $ 21,213 $ 45,471 ========== ========== ========= Effective tax rate 54.2% 35.3% 35.2% ========== ========== =========
The net deferred federal income tax liability consists of deferred federal income tax liabilities less related deferred federal income tax assets, as shown (in thousands of dollars):
2000 1999 ---------- ---------- Deferred Federal Income Tax Liabilities: AFUDC $ 6,067 $ 2,204 Bond redemptions 5,683 1,944 Excess of tax depreciation over book depreciation 188,213 174,642 Severance programs 1,982 2,788 Repairs and maintenance 4,050 - Research and experimentation 3,666 - Tax benefits flowed through to customer 114,097 130,834 Other - net (12,537) 3,306 ---------- ----------- Total $ 311,221 $ 315,718 Deferred Federal Income Tax Assets: Avoided interest capitalized 9,584 4,819 Employee benefit plans 906 2,881 Contributions in aid of construction and customer advances 63,953 56,826 Gross-ups received on contributions in aid of construction and customer advances 4,108 - Unamortized investment tax credit 13,550 14,060 Other - net 2,367 993 ---------- ----------- 94,468 79,579 Total $ 216,753 $ 236,139 ========== ===========
NVP's balance sheets contain also a net regulatory tax asset of $100.6 million at year-end 2000 and $116.8 million at year-end 1999. The net regulatory asset consists of future revenue to be received from customers of $114.1 million at year-end 2000 and $130.8 million at year-end 1999, due to flow-through of the tax benefits of temporary differences. Offset against this amount are future revenues to be refunded to customers (a regulatory liability), consisting of $13.5 million at year-end 2000 and $14 million at year-end 1999 due to unamortized investment tax credits. 113 The regulatory tax liability for temporary differences related to liberalized depreciation will continue to be amortized over the life of the plant. The regulatory tax liability for temporary differences caused by the investment tax credit will be amortized ratably in the same fashion as the accumulated deferred investment credit. Sierra Pacific Power Company The following reflects the composition of taxes on income (in thousands of dollars):
2000 1999 1998 ---------- ---------- ---------- Federal: Taxes estimated to be currently payable $ 866 $ 29,101 $ 46,176 Deferred taxes related to: Excess of tax depreciations over book depreciation 1,830 3,574 4,100 Contributions in aid of construction and customer advances (1,963) (2,701) (2,963) Avoided interest capitalized (548) 69 (875) Repairs & maintenance 2,162 1,504 - Research and experimentation 1,980 1,031 - Severance programs 508 3,774 - Other - net (1,262) 402 (2,075) Net amortization of investment tax credit (1,955) (1,981) (1,930) State (California) 446 888 925 ----------- ---------- ---------- Total $ 2,064 $ 35,661 $ 43,358 =========== ========== ========== As Reflected in Statement of Income (includes tax amounts related 0 discontinued operations): Federal income taxes 2,308 35,154 42,625 State income taxes 446 888 925 ----------- ---------- ---------- Operating Income 2,754 36,042 43,550 Other income - net (690) (381) (192) ----------- ---------- ---------- Total $ 2,064 $ 35,661 $ 43,358 ----------- ---------- ----------
114 The total income tax provisions differ from amounts computed by applying the federal statutory tax rate to income before income taxes for the following reasons (in thousands of dollars):
2000 1999 1998 ------------ ------------ ------------ Income before preferred dividend requirements $ 5,958 $ 71,726 $ 86,020 Total income tax expense 2,064 35,661 43,358 ------------ ------------ ------------ 8,022 107,387 129,378 Statutory tax rate 35% 35% 35% ------------ ------------ ------------ Expected income tax expense 2,808 37,585 45,282 Depreciation related to difference in costs basis for tax purposes 1,424 1,408 1,383 Allowance for funds used during construction - equity (167) 386 (1,334) Tax benefit from the disposition of assets (210) (442) 63 ITC amortization (1,955) (1,981) (1,930) California franchise taxes (net of federal benefit) 290 577 601 Other - net (126) (1,872) (707) ------------ ------------ ------------ $ 2,064 $ 35,661 $ 43,358 ============ ============ ============ Effective tax rate 25.7% 33.2% 33.5% ============ ============ ============
The net deferred federal income tax liability consists of deferred federal income tax liabilities less related deferred federal income tax assets, as shown (in thousands of dollars):
2000 1999 ------------ ------------ Deferred Federal Income Tax Liabilities: AFUDC $ 8,834 $ 8,894 Bond redemptions 5,732 6,099 Excess of tax depreciation over book depreciation 169,403 161,903 Severance programs 3,949 6,380 Repairs and maintenance 9,148 7,684 Research and experimentation 5,513 1,031 Tax benefits flowed through to customer 65,471 65,531 Other - net 2,642 (1,541) ------------ ------------ Total $ 270,692 $ 255,981 ============ ============ Deferred Federal Income Tax Assets: Avoided interest capitalized 15,187 14,624 Employee benefit plans 4,282 3,944 Contributions in aid of construction and customer advances 39,024 36,626 Gross-ups received on contributions in aid of construction and customer advances 5,407 5,163 Unamortized investment tax credit 18,322 19,991 Other - net 5,089 5,372 ------------ ------------ 87,311 85,720 Total $ 183,381 $ 170,261 ============ ============
SPPC's balance sheets contain a net regulatory tax asset of $31.3 million at year-end 2000 and $27.7 million at year-end 1999. The net regulatory asset consists of future revenue to be received from customers of $65.5 million at year-end 2000 and $65.5 million at year-end 1999, due to flow-through of the tax benefits of temporary differences. Offset against this amount are future revenues to be refunded to customers (a regulatory liability), consisting of $15.9 million at year-end 2000 and $17.9 million at year-end 1999, due to temporary differences for liberalized depreciation at rates in excess of current tax rates, and $18.3 million at year-end 2000 and $20.0 million at year-end 1999 due to unamortized investment tax credits. 115 The regulatory tax liability for temporary differences related to liberalized depreciation will continue to be amortized using the average rate assumption method required by the Tax Reform Act of 1986. The regulatory tax liability for temporary differences caused by the investment tax credit will be amortized ratably in the same fashion as the accumulated deferred investment credit. Sierra Pacific Resources The following reflects the composition of taxes on income (in thousands of dollars):
2000 1999 1998 ------------------- -------------------- -------------------- Federal: Taxes estimated to be currently payable (refundable) $ (28,042) $ 42,379 $ 17,163 Deferred taxes related to: Excess of tax depreciations over book depreciation 8,455 11,569 24,111 Contributions in aid of construction and customer advances (8,038) (11,508) (13,211) Avoided interest capitalized (5,106) (3,594) 6,463 Repairs & maintenance 3,912 1,469 - Research and experimentation 3,730 - - Severance programs 508 6,072 - Other - net, deferral fo energy cost 2,040 (17,114) 12,405 Net amortization of investment tax credit (3,415) (2,285) (1,460) State (California) 446 370 - ------------------- -------------------- -------------------- Total $ (25,510) $ 27,358 $ 45,471 =================== ==================== ==================== As Reflected in Statement of Income (includes tax amounts related to discontinued operations) Federal income taxes (28,042) 25,716 42,949 State income taxes 446 370 - ------------------- -------------------- -------------------- Operating Income (27,596) 26,086 42,949 Other income - net 2,086 1,272 2,522 ------------------- -------------------- -------------------- Total $ (25,510) $ 27,358 $ 45,471 =================== ==================== ====================
116 The total income tax provisions differ from amounts computed by applying the federal statutory tax rate to income before income taxes for the following reasons (in thousands of dollars):
2000 1999 1998 ----------- --------- --------- Income before preferred dividend requirements $ (35,880) $ 54,146 $ 83,673 Total income tax expense (benefit) (25,510) 27,358 45,471 --------- --------- --------- (61,390) 81,504 129,144 Statutory tax rate 35% 35% 35% --------- --------- --------- Expected income tax expense (benefit) (21,487) 28,526 45,200 Depreciation related to difference in costs basis for tax purposes 2,855 1,879 1,431 Allowance for funds used during construction - equity 133 805 300 Tax benefit from the disposition of assets (210) (184) -- ITC amortization (3,415) (2,441) (1,460) California franchise taxes (net of federal benefit) 290 241 -- Other - net (3,676) (1,468) -- --------- --------- --------- $ (25,510) $ 27,358 $ 45,471 ========= ========= ========= Effective tax rate 41.6% 33.6% 35.2% ========= ========= =========
The net deferred federal income tax liability consists of deferred federal income tax liabilities less related deferred federal income tax assets, as shown (in thousands of dollars):
2000 1999 ------------------ ------------------ Deferred Federal Income Tax Liabilities: AFUDC $ 14,901 $ 11,098 Bond redemptions 11,415 8,043 Excess of tax depreciation over book depreciation 357,616 336,545 Severance programs 13,198 7,684 Repairs and maintenance 9,179 - Research and experimentation 5,931 9,168 Tax benefits flowed through to customer 179,568 196,365 Other - net 647 10,481 ------------------ ------------------ Total $ 592,455 $ 579,384 Deferred Federal Income Tax Assets: Avoided interest capitalized 24,771 19,443 Employee benefit plans 5,188 6,825 Demand side program costs - 1,473 Contributions in aid of construction and customer advances including gross-ups 112,492 98,615 Unamortized investment tax credit 31,872 34,051 Other - net 7,547 5,013 ------------------ ------------------ 181,870 165,420 Total $ 410,585 $ 413,964 ================== ==================
For a discussion of SPR's regulatory tax assets and liabilities, which consist primarily of amounts at each of the Utilities, see the preceding discussions for each utility. 117 NOTE 11. FAIR VALUE OF FINANCIAL INSTRUMENTS The December 31, 2000, carrying amount for cash and cash equivalents, current assets, accounts receivable, accounts payable and current liabilities approximates fair value due to the short-term nature of these instruments. The total fair value of NVP's consolidated long-term debt at December 31, 2000, is estimated to be $851.2 million, (excluding current portion) based on quoted market prices for the same or similar issues or on the current rates offered to NVP for debt of the same remaining maturities. The total fair value (excluding current portion) was estimated to be $910.9 million at December 31, 1999. The estimated fair value of NVP's preferred securities is $186.3 million at December 31, 2000. The fair value of NVP's preferred securities was estimated to be $160.1 million at December 31, 1999. The total fair value of SPPC's consolidated long-term debt at December 31, 2000, is estimated to be $587.4 million (excluding current portion) based on quoted market prices for the same or similar issues or on the current rates offered to SPPC for debt of the same remaining maturities. The total fair value (excluding current portion) was estimated to be $607.1 million as of December 31, 1999. The estimated fair value of SPPC's preferred securities is $48.5 million at December 31, 2000. The fair value of SPPC's preferred securities was estimated to be $48.5 million at December 31, 1999. The total fair value of SPR's consolidated long-term debt at December 31, 2000, is estimated to be $2,051.7 million (excluding current portion) based on quoted market prices for the same or similar issues or on the current rates offered to SPR for debt of the same remaining maturities. The total fair value (excluding current portion) was estimated to be $1,518 million as of December 31, 1999. The estimated fair value of SPR's consolidated preferred securities is $234.8 million at December 31, 2000. The fair value of SPR's consolidated preferred securities was estimated to be $208.6 million at December 31, 1999. NOTE 12. SHORT-TERM BORROWINGS On December 27, 2000, SPR put into place a $50 million unsecured revolving credit facility with Wells Fargo Bank. This facility may be used for working capital and general corporate purposes, including commercial paper backup. This facility will expire on June 30, 2001. On January 23, 2001, SPR drew down the bank facility and currently has $50 million outstanding. On August 28, 2000, the Utilities each renewed their $150 million unsecured revolving credit facility. These facilities may be used for working capital and general corporate purposes, including commercial paper backup. These facilities will expire on August 27, 2001. SPR, SPPC and NVP have sustained their A2/P2 rating by Standard and Poor's and Moody's, respectively. On December 18, 2000, NVP issued $100 million of floating rate notes that will mature on December 17, 2001. Interest on the notes is payable quarterly, commencing on March 17, 2001. The interest on the notes will be a floating rate for each interest period, subject to adjustment every three months. The interest is equal to the London Interbank Offered Rate (LIBOR) for three months of U.S. dollar deposits plus a spread of 0.79%. The Notes are not subject to any sinking fund. 118 At December 31, 2000, SPR had $4 million of outstanding short-term debt comprised entirely of commercial paper with a weighted average interest rate of 6.60%. NVP had short-term debt outstanding of $100 million comprised entirely of floating rate notes. SPPC had $108.9 million outstanding at year-end, comprised entirely of commercial paper, with a weighted average interest rate of 6.67%. The other subsidiaries of SPR had no outstanding short-term borrowings as of year-end. NOTE 13. DIVIDEND RESTRICTIONS SPR's primary source of funds for the payment of dividends to its stockholders is dividends paid by the Utilities on their common stock, all of which is owned by SPR. Accordingly, SPR's ability to pay dividends is dependent upon the ability of the Utilities to pay dividends on their common stock. The Restated Articles of Incorporation of the Utilities, the indentures relating to the various series of their First Mortgage Bonds, and the bank credit agreements of the Utilities contain restrictions as to the payment of dividends on their common stock and as to the purchase or retirement of their capital stock. Under the most restrictive of these provisions, approximately $8.5 million in dividends had been paid to SPR through December 31, 2000, by the Utilities in excess of available unrestricted retained earnings. 119 NOTE 14. RETIREMENT PLAN AND POST-RETIREMENT BENEFITS Pension and other postretirement benefit plans: SPR has pension plans covering substantially all employees. Benefits are based on years of service and the employee's highest compensation for a period prior to retirement. SPR also has other postretirement plans which provide medical and life insurance benefits for certain retired employees. The following table provides a reconciliation of benefit obligations, plan assets and the funded status of the plans. This reconciliation is based on a September 30 measurement date and reflects the acquisition of SPPC by NVP during 1999 under purchase accounting:
Other Postretirement Pension Benefits Benefits ------------------------------- ----------------------------- 2000 1999 2000 1999 ------------------------------- ----------------------------- Change in benefit obligations Benefit obligation, beginning of year $ 348,470 $ 149,031 $ 77,987 $ 16,381 Service cost 11,907 8,481 1,775 996 Interest cost 26,469 12,823 5,829 1,982 Participant contributions 0 0 300 255 Plan amendment & special termination 498 5,865 0 1,312 Actuarial loss (gain) (8,922) 4,663 (4,101) (1,694) Merger of SPPC Plans 0 192,140 0 60,386 Curtailment loss (gain) 0 (5,373) 0 386 Benefits paid (30,287) (19,160) (4,000) (2,017) ------------- ------------ ------------ ------------ Benefit obligation, end of year $ 348,135 $ 348,470 $ 77,790 $ 77,987 ============= ============ ============ ============ Change in plan assets Fair value of plan assets, beginning of year $ 326,708 $ 111,160 $ 66,688 $ 11,138 Actual return on plan assets 51,136 15,510 17,377 4,649 Company contributions 1,596 10,432 $ 1,535 $ 2,069 Participant contributions 0 0 $ 300 $ 255 Merger of SPPC Plans 0 208,766 0 $ 50,593 Benefits paid (30,287) (19,160) (4,000) (2,016) ------------- ------------ ------------ ------------ Fair value of plan assets, end of year $ 349,153 $ 326,708 $ 81,900 $ 66,688 ============= ============ ============ ============ Funded Status, end of year $ 1,018 $ (21,762) $ 4,110 $ (11,299) Unrecognized net actuarial (gains) losses (13,526) 19,765 (22,696) (11,418) Unrecognized prior service cost 11,561 12,264 0 0 Unrecognized net transition obligation 0 0 11,248 12,217 Contributions made in 4th quarter 270 769 0 1,096 ------------- ------------ ------------ ------------ Accrued pension and postretirement benefit obligations $ (677) $ 11,036 $ (7,338) $ (9,404) ============= ============ ============ ============
120 Amounts for pension and postretirement benefits recognized in the consolidated balance sheets consist of the following:
Other Postretirement Pension Benefits Benefits ------------------------------ --------------------------- 2000 1999 2000 1999 ------------------------------ --------------------------- Prepaid pension asset $ 13,939 $ 24,536 N/A N/A Accrued benefit liability (14,616) (13,500) $ (7,338) $ (9,404) Intangible asset 725 346 N/A N/A Accumulated other comprehensive income 2,446 1,822 N/A N/A Additional minimum liability (3,171) (2,168) N/A N/A ---------- -------- -------- --------- Net amount recognized (677) 11,036 (7,338) (9,404) ========== ======== ======== =========
The weighted-average actuarial assumptions as of the measurement date were as follows:
Other Postretirement Pension Benefits Benefits ------------------------- ------------------------- 2000 1999 1998 2000 1999 1998 ------------------------- ------------------------- Discount rate 8.00% 7.50% 6.75% 8.00% 7.50% 6.75% Expected return on plan assets 8.50% 8.50% 8.50% 8.50% 8.50% 8.50% Rate of compensation increase 4.50% 4.50% 4.50% N/A N/A N/A
SPR has assumed a health care cost trend rate of 6% for 2000 and all future years. 121 Net periodic pension and other postretirement benefit costs include the following components:
Pension Benefits ------------------------------------------------ 2000 1999 1998 ------------------------------------------------ Service cost $ 11,907 $ 8,481 $ 5,386 Interest cost 26,469 12,823 9,285 Expected return on assets (27,186) (11,712) (7,697) Amortization of: Transition asset 0 0 0 Prior service costs 1,201 841 780 Actuarial (gains) losses 159 976 187 ------------ ---------- ---------- Net periodic benefit cost 12,550 11,409 7,941 Additional charges (credits): Special termination charges 0 5,865 0 Curtailment credits 0 (3,920) 0 ------------ ---------- ---------- Total net benefit cost $ 12,550 $ 13,354 $ 7,941 ============ ========== ========== Other Postretirement Benefits ------------------------------------------------ 2000 1999 1998 ------------------------------------------------ Service cost $ 1,775 $ 996 $ 433 Interest cost 5,829 1,982 1,155 Expected return on assets (5,327) (1,741) (770) Amortization of: Prior service costs 0 0 0 Transition obligation 968 1,344 967 Actuarial (gains) losses (598) (596) (505) ------------ ---------- ---------- Net periodic benefit cost 2,647 1,985 1,280 Additional charges (credits): Special termination charges 0 1,312 0 Curtailment loss 0 1,283 0 ------------ ---------- ---------- Total net benefit cost $ 2,647 $ 4,580 $ 1,280 ============ ========== ==========
In 1999, a regulatory asset was booked to offset the net effect of special termination benefits and curtailment costs incurred in connection with the merger of SPR and NVP. The assumed health care cost trend rate has a significant effect on the amounts reported. A one percentage point change in the assumed health care cost trend rate would have had the following effects on 2000 service and interest costs and the accumulated postretirement benefit obligation at year end: One percentage point change Increase Decrease --------------------------- -------- -------- Effect on service and interest components of net periodic cost $ 985 $ (787) Effect on accumulated postretirement benefit obligation $ 8,184 $(6,707) 122 NOTE 15. STOCK COMPENSATION PLANS At December 31, 2000, Sierra Pacific Resources had several stock-based compensation plans which are described below. SPR applies Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees, in accounting for its stock option plans. Accordingly, no compensation cost has been recognized for nonqualified stock options and the employee stock purchase plan. The total compensation cost that has been charged against income for the performance shares, dividend equivalents and the non-employee director stock plans was ($0.2) million for 2000, and $0.2 million for 1999. SPR has adopted the disclosure-only provisions of SFAS No. 123, Accounting for Stock Based Compensation. Had compensation cost for SPR's nonqualified stock options and the employee stock purchase plan been determined based on the fair value at the grant dates for awards under those plans consistent with the provisions of SFAS No. 123, SPR's income applicable to common stock would have been decreased to the pro forma amounts indicated below: 2000 1999 ------------------------ Net Income (Loss) As Reported (39,780) 51,750 Pro Forma (40,75) 50,908 Basic Earnings Per Share As Reported (0.51) 0.83 Pro Forma (0.52) 0.81 Diluted Earnings Per Share As Reported (0.51) 0.83 Pro Forma (0.52) 0.81 1. Prior to the August 1, 1999, merger, NVP did not have a nonqualified stock option plan or an employee stock purchase plan; therefore, presentation of the historical data for the above item is limited to two years. SPR's executive long-term incentive plan for key management employees, which was approved by shareholders on May 16, 1994, provides for the issuance of up to 750,000 of SPR's common shares to key employees through December 31, 2003. June 19, 2000, shareholders approved an increase of 1,000,000 shares for the executive long-term incentive plan. The plan permits the following types of grants, separately or in combination: nonqualified and qualified stock options, stock appreciation rights, restricted stock, performance units, performance shares, and bonus stock. During 2000, SPR issued nonqualified stock options, performance shares, and restricted stock under the long-term incentive plan. 123 Non-Qualified Stock Options Nonqualified stock options granted during 2000 were issued at an option price not less than market value at the date of the grant, August 4, 2000. This grant vests to the participant 25% per year over a four year period from the grant date, and may be exercised for a period not to exceed either the 65th birthday of the participant, February 18, 2009, or one year after retirement, whichever occurs first. The options may be exercised using either cash or previously acquired shares, valued at the current market price, or a combination of both. The Fair value of each nonqualified option has been estimated on the date of grant using the Black-Scholes option pricing model with the following assumptions used for grants issued in 2000 and 1999: ------------------------------------------------------------------------- Option Grant Date Dividend Expected Risk-Free Rate Expected Life Yield Volatility of Return ------------------------------------------------------------------------- August 4, 2000 4.81% 30.49% 6.14% 9.6 years August 1, 1999 4.25% 17.41% 6.31% 10 years January 1, 1999 4.40% 18.60% 5.08% 10 years ------------------------------------------------------------------------- A summary of the status of SPR's nonqualified stock option plan as of December 31, 2000, and 1999, and changes during the year is presented below:
---------------------------------------------------------------------------------------------------- 2000 1999 --------------------------------------------------------- Weighted- Weighted- Average Exercise Average Nonqualified Stock Options Shares Price Shares Exercise Price ---------------------------------------------------------------------------------------------------- Outstanding at beginning of year (1) 841,355 $24.33 289,119 $21.98 Granted (2) 400,000 $16.00 588,200 $25.36 Exercised 14,107 $14.28 1,286 $14.39 Forfeited 407,687 $25.06 34,678 $22.48 Outstanding at end of year 819,561 $20.07 841,355 $24.33 Options exercisable at year-end 209,099 $22.74 128,969 $20.53 Weighted-average grant date fair value of options granted (3): August 4 $ 4.10 January 1 $ 4.05 August 1 $ 5.11 ----------------------------------------------------------------------------------------------------
1. The historical information is presented for only two years because Nevada Power did not have a nonqualified stock option plan prior to the August 1, 1999, merger. After the merger, the SPR plan, approved in 1994 by the SPR Board of Directors, was adopted by the surviving company. 2. The number of nonqualified stock options granted during the year was 400,000 shares. 3. The fair value of each nonqualified option has been estimated on the date of grant using the Black-Scholes option-pricing model, with the following assumptions used for grants on August 4, 2000: dividend yield of 4.81%, expected volatility of 30.49%, risk-free rate of return of 6.14%, and an expected life of 9.5 years. 124 The following table summarizes information about nonqualified stock options outstanding at December 31, 2000:
-------------------------------------------------------------------------------------- Options Outstanding Options Exercisable ------------------------------------------------------- Number Remaining Number Exercise Outstanding Contractual Exercise Exercisable Grant Date Price at 12/31/00 Life Price at 12/31/00 -------------------------------------------------------------------------------------- 1/1/94 $14.24 8,000 3 years $14.24 8,000 1/1/95 $13.02 9,748 4 years $13.02 9,748 1/1/96 $16.23 8,673 5 years $16.23 6,938 1/1/97 $19.97 45,500 6 years $19.97 45,500 1/1/98 $24.93 69,120 7 years $24.93 46,082 1/1/99 $24.22 115,920 8 years $24.22 38,636 8/1/99 $26.00 162,600 8.6 years $26.00 54,195 8/4/00 $16.00 400,000 9 years $16.00 - Weighted Average Remaining 8.3 years Contractual Life --------------------------------------------------------------------------------------
Each participant was granted dividend equivalents for all 1996 and prior nonqualified option grants. Each dividend equivalent entitles the participant to receive a contingent right to be paid an amount equal to dividends declared on shares originally granted from the date of grant through the exercise date. Dividend equivalents will be forfeited if options expire unexercised. Performance Shares On August 4, 2000, January 1, 2000, and January 1, 1999, SPR granted performance shares in the following numbers and initial values, respectively: 10,164 valued at $16.00 per share, 40,600 valued at $26.00 per share, and 28,944 valued at $24.22 per share. The actual number of shares earned by each participant is dependent upon SPR achieving certain financial goals over three- year performance periods. The value of performance shares, if earned, will be equal to the market value of SPR's common shares as of the end of the performance periods. Sierra Pacific Resources, at its sole discretion, may pay earned performance shares in the form of cash or in shares, or a combination thereof. Simultaneous with the grant of the performance shares above, each participant was granted dividend equivalents. Each dividend equivalent entitles the participant to receive a contingent right to be paid an amount equal to dividends declared on shares originally granted throughout the performance period. Additionally, in order for dividend equivalents to be paid on the performance shares, certain financial targets must be met. Dividend equivalents will be forfeited if options expire unexercised. Restricted Stock Shares In 2000, SPR granted 16,000 restricted stock shares at a grant price of $16.00 per share. The grant vests over 4 years with 4,000 shares becoming available in 2002, 4,000 shares in 2003, and 8,000 shares in 2004. There are no performance criteria or dividend equivalents associated with the grant. 125 Employee Stock Purchase Plan Upon the inception of SPR's employee stock purchase plan, SPR was authorized to issue up to 400,162 shares of common stock to all of its employees with minimum service requirements. June 19, 2000, shareholders approved an additional 700,000 shares for distribution under the plan. According to the terms of the plan, employees can choose twice each year to have up to 15% of their base earnings withheld to purchase SPR's common stock. The purchase price of the stock is 90% of the market value on the offering commencement date. Employees can withdraw from the plan at any time prior to the exercise date. Under the plan SPR sold 46,773 and 21,888 shares to employees in 2000 and 1999, respectively. Compensation cost has been estimated for the employees' purchase rights on the date of grant using the Black-Scholes option-pricing model with the following assumptions used for 2000 and 1999, respectively: average dividend yield of 4.72% and 4.31%, average expected volatility of 30.97% and 18.85%, and average risk-free interest rates of 5.86 and 5.08%. The weighted average fair value of those purchase rights in 2000 was $3.03 and $2.85 in 1999. Non-Employee Director Stock Plan SPR's non-employee director stock plan provides that a portion of the outside directors' annual retainer be paid in SPR stock. Under the current plan, the annual retainer for non-employee directors is $30,000, and the minimum amount to be paid in SPR stock is $20,000 per director. During 2000 and 1999, SPR granted the following total shares and related compensation to directors in SPR stock, respectively: 16,915 and 4,741 shares, and $250,000 and $150,000. SPR did not pay out any phantom stock shares in 2000. NOTE 16. POSTEMPLOYMENT BENEFITS During 1999, SPR offered a severance program to non-bargaining-unit employees, which provides for severance pay and medical benefits continuation totaling $13.7 million and $0.8 million respectively. As approved by the PUCN in 1999, this cost is being deferred as a regulatory asset as of December 31, 2000. The order approving the merger by the PUCN, directed the Utilities to defer merger costs (including severance and related benefits) for a three-year period. The deferral of these costs is intended to allow adequate time for the anticipated savings from the merger to develop. At the end of the three-year period, the order instructs SPPC and NVP to propose an amortization period for these costs, and allows SPPC and NVP to recover the costs to the extent that they are offset by merger savings. At December 31, 2000, the remaining liability for unpaid severance was $0.9 million. NOTE 17. DISCONTINUED OPERATIONS (SALE OF WATER BUSINESS) On September 7, 2000, SPR and SPPC adopted a plan to sell SPPC's water utility business. Accordingly, the water business is reported as a discontinued operation as of September 30, 2000, and the consolidated financial statements have been reclassified to report separately the net assets and operating results of the water business. SPR's and SPPC's prior year operating results have been restated to reflect continuing operations. On January 15, 2001, the SPR Board of Directors approved a definitive agreement to sell SPPC's water business to the Truckee Meadows Water Authority (TMWA) for $350 million. The transaction is subject to various closing conditions, including the release of the water business assets from the lien of SPPC's first mortgage indenture and the receipt of satisfactory regulatory treatment of the gain to SPPC, and is expected to close in the second quarter 2001. The transaction must be approved by the PUCN. 126 SPPC reserved the right to terminate the agreement in the event the PUCN imposes any conditions to the sale unacceptable to SPPC. Included in the sale will be water storage and supply, transmission, treatment and distribution facilities. Also, included in the sale will be four hydroelectric generation plants on the Truckee River. Accounts receivable consists of amounts due from developers for distribution facilities. Regulatory assets included for sale consist primarily of costs incurred in connection with the Truckee River negotiated water settlement. Other unallocated assets that may be in part included in the sale are not reflected in the table of net assets that follows. Assets and liabilities of the water utility business consist of the following:
Amounts in thousands December 31, 2000 December 31, 1999 ----------------- ----------------- Plant in service $338,199 $323,195 Less: Accumulated provision for depreciation 88,056 80,502 Construction work-in-progress 11,861 14,702 Accounts receivable 2,520 2,520 Materials 353 428 Regulatory tax asset 3,609 3,776 Other regulatory assets 4,674 4,015 Total Assets $273,160 $268,134 -------- -------- Deferred federal income taxes 3,215 8,370 Regulatory tax liability 3,469 3,399 ----- ----- Net assets of discontinued operations $266,476 $256,365 -------- --------
Water revenues for the years ended December 31, 2000, 1999, and 1998 were $57 million, $54 million, and $49 million, respectively. Net income from operations of the water business during the period September 7 through December 31, 2000, was approximately $700 million. These amounts are not included in the revenues and income (loss) from continuing operations shown in the accompanying income statements. The income from operations of the water business to be disposed of, as shown in the Consolidated Statements of Income of SPR, includes (in thousands) preferred dividends of $401, $195, and $0 for the years ended December 31, 2000, 1999, and 1998, respectively. The income from operations of the water business to be disposed of, as shown in the Consolidated Statements of Income of SPPC, includes (in thousands) preferred dividends of $401, $528, and $662 the years ended December 31, 2000, 1999, and 1998, respectively. NOTE 18. COMMITMENTS AND CONTINGENCIES Construction ------------ The Utilities' combined estimated cash construction expenditures for the year 2001 and the five-year period 2001-2005 are $300 million and $1.515 billion, respectively. 127 Due to the supply shortage in the western U.S., several independent power producers have proposed the construction of new generating plants in Southern Nevada, and have requested transmission service from Nevada Power. Nevada Power has committed to construct this transmission infrastructure in furtherance on its on-going business plan. The key project in this regard is the construction of a 500 kV transmission system consistent with its tariff and Federal Energy Regulatory Commission pricing policies. Energy Contracts ---------------- NVP and SPPC each have one long-term contract for the purchase of electric energy and/or capacity. These contracts expire in 2016 and 2009, respectively. Estimated future commitments under non-cancelable agreements with initial terms of one year or more at December 31, 2000, were as follows (dollars in thousands): Accounted for as a Accounted for as Long-Term Long-Term Capital Executory Contract Lease ------------------------------------------ 2001 $ 24,486 $ 10,823 2002 21,248 10,319 2003 21,225 9,790 2004 21,650 9,286 2005 21,817 8,756 2006 to 2016 70,357 74,069 The above long-term capital lease minimum payments have not been reduced by an estimated $75.9 million of executory costs and $20.8 million in interest. According to the regulations of the Public Utility Regulator Policies Act, the Utilities are obligated, under certain conditions, to purchase the generation produced by small power producers and cogeneration facilities at costs determined by the appropriate state utility commission. Generation facilities that meet the specifications of the regulations are known as qualifying facilities (QFs). As of December 31, 2000, NVP had a total of 305 MWs of contractual firm capacity under contract with four QFs. The contracts terminate between 2022 and 2024. As of December 31, 2000, SPPC had a total of 109 MWs of maximum contractual firm capacity under 15 contracts with QFs. SPPC also had contracts with three projects at variable short-term avoided cost rates. One of SPPC's long-term QF contracts terminates in 2006, one terminates in 2039, and the rest terminate between 2014 and 2022. 128 Commodity Contracts ------------------- The Utilities have several long-term contracts for the purchase and transportation of coal and natural gas. These contracts expire in years ranging from 2001 to 2023. Estimated future commitments under non-cancelable agreements with initial terms of one year or more at December 31, 2000 were as follows (dollars in thousands): Coal and Gas Transportation 2001 $ 51,835 $ 67,689 2002 33,854 52,970 2003 19,548 44,706 2004 11,440 39,140 2005 9,813 39,141 2006 to 2023 19,084 366,467 Leases ------ In 1984, NVP sold its administrative headquarters facility, less furniture and fixtures, for $27 million and entered into a 30-year capital lease of that facility with five-year renewal options beginning in year 31. The fixed rental obligation for the first 30 years is $5.1 million per year. Future cash rental payments as of December 31, 2000, were as follows (dollars in thousands): 2001 $ 6,156 2002 6,156 2003 6,156 2004 6,946 2005 7,735 2006 to 2014 65,752 The amount of imputed interest necessary to reduce the future cash rental payments to present value is $49.4 million as of December 31, 2000. Total interest expense on the lease obligation was $5.8 million and total amortization of the leased facility was $(352,000) for the year ended December 31, 2000. The total accumulated amortization of the leased facility on December 31, 2000, was $8.9 million. SPPC has an operating lease for its corporate headquarters building. The primary term of the lease is 25 years, ending in 2010. The current annual rental is $5.4 million, which amount remains constant until the end of the primary term. The lease has renewal options for an additional 50 years. SPR's estimated future minimum cash payments, including SPPC's headquarters building, under non-cancelable operating leases with initial terms of one year or more at December 31, 2000, were as follows (dollars in thousands): 2001 $ 14,380 2002 10,621 2003 8,754 2004 8,279 2005 7,822 2006 to 2045 71,489 129 Portland General Electric Acquisition ------------------------------------- In November 1999 SPR and Enron Corporation (Enron) announced they had entered into a purchase and sale agreement for Enron's wholly owned electric utility subsidiary, PGE. PGE is an electric utility serving more than 700,000 retail customers in northwest Oregon. Upon completion of the transaction, PGE would become a wholly owned subsidiary of SPR. Under terms of the agreement, Enron has agreed to sell PGE to SPR for $2.02 billion to $2.1 billion in cash, depending upon the level of liabilities assumed at the time of close. In addition, $1.0 billion in PGE debt and preferred stock would remain outstanding and be reflected in SPR's consolidated financial statements. In addition to other regulatory approvals discussed below, the PGE acquisition is subject to the approval of the Securities and Exchange Commission (the "SEC") under the Public Utility Holding Company Act ("PUHCA"), and SPR has applied to the SEC to become a registered public utility holding company under PUHCA. In connection with that application, SPR has made certain representations to the SEC regarding the methods of financing the PGE acquisition and regarding the capital structure of SPR following the acquisition. According to those representations, SPR expects to initially finance the transaction primarily through a bank loan or other form of debt. In its application to the SEC, SPR had proposed to increase its consolidated common equity following the acquisition by paying down debt at the utility level with some of the proceeds from the sale of the electric generation assets of the Utilities, the sale of non-strategic assets, the sale of additional common stock, and increased retained earnings from the combined operations of the three utility subsidiaries. In light of the uncertainty related to the sale of the Utilities' generation assets (see Sale of Generation Assets later), SPR is evaluating alternative financing plans and capital structures to be presented to the SEC in connection with the financing application which must be approved as a condition for closing. The proposed transaction is subject to other closing conditions, including, without limitation, the receipt of all necessary governmental approvals, including the Federal Energy Regulatory Commission (FERC), the Federal Trade Commission/Department of Justice (FTC/DOJ), the Oregon Public Utility Commission (OPUC), and the Nuclear Regulatory Commission (NRC). SPR's filings have been made, and all state regulatory approvals have been received and only the SEC approval remains at the federal level. As of May 3, 2000, the FTC/DOJ investigation concluded and the waiting period under Hart-Scott-Rodino expired with no action taken. On July 27, 2000, the NRC approved PGE's transfer application filed in January. On October 30, 2000, the OPUC approved SPR's application to acquire PGE. The OPUC approved a September 1 settlement agreement that calls for a six-year price freeze on non-fuel operations and maintenance for PGE customers and a $95 million credit for Oregon consumers. The "acquisition credit" will be shown on monthly power bills as soon as the transaction is complete and will continue through September 30, 2007. PGE will retain its ability to adjust rates to reflect changes in the prices for wholesale electricity and fuel purchased to operate its power plants. On November 21, 2000, the FERC approved the transaction based on a plan that included the sale of the power plants. The purchase and sale agreement between SPR and Enron provides that the agreement may be terminated by either party without liability (unless a pre-existing breach has occurred) if the closing of the transaction has not occurred on or before May 5, 2001. As of December 31, 2000, SPR had incurred approximately $12.4 million of transaction costs in preparation for the PGE acquisition. Sale of Generation Assets ------------------------- In June 1998, SPR announced a plan to divest its generation assets. This business strategy was described in the SPR/NVP merger applications filed with the PUCN and the FERC. 130 The approved plan includes seven bundles: SPPC's bundles are North Valmy (286 MW), Fort Churchill (226 MW), Tracy/Pinon (545 MW); NVP's bundles are Clark (690 MW), Sunrise/Sunpeak (390 MW), Reid Gardner (590 MW), and Harry Allen (76 MW). Not included in the plan's seven bundles were NVP's 14% (222 MW) interest in the Mohave Generating Station ("Mohave") and 11% (255 MW) interest in the Navajo Generating Station ("Navajo") although NVP committed to sell its share of these plants. Asset sale agreements, described below, have been signed for NVP's 14% share of Mohave and for six of the seven bundles described in the approved divestiture plan (Valmy, Tracy/Pinon, Clark, Reid Gardner, Sunrise/Sunpeak and Harry Allen). Marketing for the sale of SPPC's Fort Churchill bundle and NVP's 11% interest in the jointly owned Navajo power plant is continuing. On May 10, 2000, AES Corporation (AES) announced that it was the successful bidder for the purchase of a controlling interest in the 1,580 MW Mohave Generating Station in Laughlin, Nevada for approximately $667 million. NVP owns a 14% undivided interest in the facility. Mohave Generating Station is a 2-unit, coal-fired power plant located on 2,500 acres along the Colorado River, approximately 80 miles south of Las Vegas. AES executed Asset Sale Agreements with the sellers, NVP (14%) and Southern California Edison Company (56%), for a 70% undivided interest in the facility. Under the agreement, NVP will have the right to buy energy and ancillary services from AES for agreed upon prices, subject to a collar, through early 2003. The total sale price of NVP's interest is $142 million, subject to taxes and other adjustments. The actual sales proceeds will be net of a payment from NVP to AES for the power purchase agreement. The sale is subject to approval and review by various regulatory agencies. On October 19, 2000, SPR and SPPC announced an agreement to sell SPPC's 50% interest in the Valmy Power Station to NRG Energy, Inc. ("NRG") of Minneapolis, Minnesota. Under the agreement, SPPC will have the right to buy energy and ancillary services from the Valmy Power Station for agreed upon prices, subject to a collar, through early 2003. The total sale price of the asset bundle, which includes the Battle Mountain Diesel Plant and the Winnemucca Gas Plant, is $332 million, subject to taxes and other adjustments. The actual sales proceeds will be net of a payment from SPPC to NRG for the power purchase agreement. The Valmy Power Station sells electricity in northern Nevada and surrounding markets. SPPC's net capacity interest in the Valmy Power Station totals 286 MW. Located forty miles from Winnemucca, Nevada, the Valmy Power Station consists of two similar coal-fired units and is owned jointly by SPPC and Idaho Power Company. SPPC owns 50% of the station and operates the plant. The sale is subject to approval and review by various regulatory agencies. On October 27, 2000, SPR and SPPC announced an agreement to sell SPPC's Tracy/Pinon Power Station to WPS Power Development, Inc., a wholly owned subsidiary of WPS Resources Corporation of Green Bay, Wisconsin. Under the agreement, SPPC will have the right to buy energy and ancillary services from WPS Power Development for agreed upon prices, subject to a collar, from closing of the agreement through February 2003. The total sale price of the asset bundle, which includes the Tracy Plant, Pinon Pine, and the Brunswick, Gabbs and Valley Road diesel generators, is $260 million, subject to taxes and other adjustments. The actual sales proceeds will be net of a payment from SPPC to WPS Power Development for the power purchase agreement. The Tracy/Pinon Power Station sells electricity in northern Nevada and surrounding markets. Tracy is also the site of the Pinon Pine Integrated Coal Gasification Combined Cycle project co-funded by the U.S. Department of Energy as part of the Clean Coal Technology Program. SPPC's average capacity in the Tracy/Pinon Power Station totals 525 megawatts. Located approximately 20 miles from Reno, Nevada, the Tracy/Pinon Power Station consists of three similar gas- and oil-fired units, four gas turbines, and the Pinon Pine 131 facility (a combined cycle unit). The sale is subject to approval and review by various regulatory agencies. On November 20, 2000, SPR and NVP announced an agreement to sell NVP's Clark and Reid Gardner Generating Stations to a holding company formed by NRG and Dynegy Inc. (Dynegy) of Houston, Texas. Under the agreement, NVP will have the right to buy energy and ancillary services for agreed upon prices, subject to a collar, from closing of the agreement through February 2003. The total sale price of the asset bundles is $955 million, subject to taxes and other adjustments. The actual sales proceeds will be net of a payment from NVP to NRG and Dynegy for the power purchase agreement. The Clark Generating Station, located in southeastern Las Vegas, consists of 10 gas- and oil-fired generating units, totaling 740 megawatts. The Reid Gardner Generating Station consists of four baseload coal-fired units and is located 52 miles northeast of Las Vegas. Three of the units, 110 megawatts each, are wholly owned by NVP. NVP and the California Department of Water Resources (CDWR) jointly own the fourth unit, a 275 megawatts coal-fired unit. NRG and Dynegy will jointly acquire NVP's combined ownership and use interest in the fourth unit as part of the transaction. The CDWR will maintain its 15 megawatts ownership interest in the unit. The sale is subject to approval and review by various regulatory agencies. On December 4, 2000, SPR and NVP announced an agreement to sell NVP's Harry Allen Power Station to Pinnacle West Energy (Pinnacle), a subsidiary of Pinnacle West Corporation of Phoenix, Arizona. Under the agreement, NVP will have the right to buy energy and ancillary services from Pinnacle for agreed upon prices, subject to a collar, from closing of the agreement through February 2003. The total sale price of the asset bundle is $71 million, subject to taxes and other adjustments. The actual sales proceeds will be net of a payment from NVP to Pinnacle for the power purchase agreement. The Harry Allen Power Station, located approximately 30 miles north of the city of North Las Vegas, is a 72 megawatt combustion turbine unit. The sale is subject to approval and review by various regulatory agencies. On December 11, 2000, SPR and NVP announced an agreement to sell NVP's Sunrise Station electric generating plant to Reliant Energy Power Generation, Inc. (Reliant), a subsidiary of Reliant Energy of Houston, Texas. The sale includes two generating units owned by NVP and rights to electricity produced by three additional units on the Sunrise site owned by an independent power producer. Under the agreement, NVP will have the right to buy energy and ancillary services from Reliant for agreed upon prices, subject to a collar, from closing of the agreement through February 2003. The total sale price of the asset bundle is $109 million, subject to taxes and other adjustments at closing. The actual sales proceeds will be net of a payment from NVP to Reliant for the power purchase agreement. The Sunrise Station, located near the eastern edge of Las Vegas, consists of two generating units that can be fueled by natural gas or oil and are capable of producing up to 149 megawatts of electricity. The facility also includes three additional gas turbine generating units rated at 222 megawatts. These three units are owned by an independent power producer, Nevada Sun-Peak Limited Partnership, under contract to NVP. The sale is subject to approval and review by various regulatory agencies. On January 18, 2001, California enacted a law prohibiting any further divestiture of generation properties by California utilities, including SPPC, until 2006. SPR is actively seeking legislation to exempt SPPC from this moratorium on generation sales. However, unless modified by future legislative action or by a court, California law has halted divestiture of SPPC's Valmy, Tracy and Ft. Churchill plants. As Edison is the operating partner in the Mohave Station, the pending sale of that unit is also implicated. Without divestiture, the TPPAs negotiated with the buyers of these units as part of the sale agreements are terminated. 132 On January 24, 2001, the Nevada Utility Consumer Advocate ("UCA") filed a Petition with the PUCN seeking to halt regulatory review of all pending sales agreements for all Nevada generation until the PUCN can make a determination that generation divestiture is still in the public interest. If adopted by the PUCN, the UCA's proposal would at a minimum delay the effective date for TPPAs for all SPPC and NVP units and require that the Utilities immediately secure a fuel supply to run these generators through the 2001 Summer peak and perhaps beyond. On February 22, 2001, the Governor of Nevada presented his Nevada Energy Protection Plan. One of the points of the plan is re-examination of utility divestiture. The Governor has written to the PUCN, expressing his concern that divestiture in its current form could adversely impact Nevada. He has asked the PUCN to revisit the issue. Senate Bill 253 has been introduced in the Nevada legislature. If passed, this Bill would halt divestiture of generation until 2003. Although the closing of these sales is scheduled for the second and third quarters of 2001, whether and when such closings will occur depends upon the resolution of the legislative and regulatory issues discussed above. As of December 31, 2000, NVP and SPPC had spent $8.7 million and $11.4 million, respectively, in order to prepare for the generation asset sales. Environmental ------------- Nevada Power Company The Grand Canyon Trust and Sierra Club filed a lawsuit in the U.S. District Court, District of Nevada, in February 1998, against the owners (including NVP) of the Mohave Generation Station ("Mohave"), alleging violations of the Clean Air Act regarding emissions of sulfur dioxide and particulates. An additional plaintiff, National Parks and Conservation Association later joined the suit. The plant owners and plaintiffs have had numerous settlement discussions and filed a proposed settlement with the court in October 1999. The consent decree, approved by the court in November 1999, established emission limits for sulfur dioxide and opacity and required installation of air pollution controls for sulfur dioxide, nitrogen oxides and particulate matter. The new emission limits must be met by January 1, 2006 and April 1, 2006, for the first and second units respectively. However, if the owners sell their entire ownership interest with a closing date prior to December 30, 2002, the new emission limits become effective 36 months and 39 months from the date of last closing for the two respective units. The estimated cost of new controls is $300 million. As a 14% owner in the Mohave Station, NVP's cost could be $42 million. Also, the United States Congress authorized the EPA to study the potential impact Mohave may have on visibility in the Grand Canyon area. A final report of the study results was released in March 1999. The study acknowledges that sulfur dioxide emissions from Mohave are transported to the Grand Canyon. EPA has solicited information to determine whether visibility impairment in the Grand Canyon can be reasonably attributed to Mohave. If EPA determines that significant visibility impairment is reasonably attributable to the station, EPA could initiate a review for Best Available Retrofit Technology. Mohave's owners believe that settlement of the suit discussed above is acceptable to the EPA. Provisions that are agreed to in a settlement are expected to be reflected in a State Implementation Plan for Nevada and resolve any concerns of EPA regarding visibility impairment In May 1997, NDEP ordered NVP to submit a plan to eliminate the discharge of Reid Gardner Station wastewater to groundwater. The NDEP order also required a hydrological assessment of groundwater impacts in the area. In June 1999, NDEP determined that wastewater ponds had degraded 133 groundwater quality. In August 1999, NDEP issued a discharge permit to Reid Gardner Station and an order that requires all wastewater ponds to be closed or lined with impermeable liners over the next 10 years. This order also required NVP to submit a Site Characterization Plan to NDEP to ascertain impacts. This plan is under review by NDEP. After approval, an estimate of remediation costs will be determined by NVP. New pond construction and lining costs are estimated at $20 million. Also, at the Reid Gardner Station, the NDEP has determined that there is additional groundwater contamination that resulted from oil spills at the facility. NDEP has required submitting a corrective action. The extent of contamination has been determined and remediation is occurring. This remediation is not expected to materially affect the financial position of SPR or NVP. In May 1999, NDEP issued an order to eliminate the discharge of NVP's Clark Station wastewater to groundwater. The order also required a hydrological assessment of groundwater impacts in the area. This assessment was submitted to NDEP in February 2001 and is under review. NVP will spend $565,000 to line existing ponds. After review by NDEP, NVP will implement remediation. Management does not expect this matter to materially affect the financial position of SPR or NVP. In December 2000, an above ground storage tank failed at NVP's Clark Station necessitating remediation of approximately 30,000 gallons of Bunker Fuel. Remediation costs are not expected to be significant. NVP determined that, while constructing the McCullough-Arden transmission line, access roads were created within a wilderness study area in violation of the Bureau of Land Management (BLM) Right of Way Grant. NVP's preliminary estimate for restoration costs is $200,000, which was reserved as of December 31, 1999. No resulting BLM action is pending. As part of the generation divestiture process Phase I and/or Phase II Environmental Assessments were conducted at all of the Utilities' facilities. These assessments noted additional remediation requirements for all the generation assets. All remediation has been completed except for the Reid Gardner facility. The assessment is under review by NDEP. Management does not expect this item to materially affect the financial position of SPR, NVP or SPPC. Sierra Pacific Power Company In September 1994, Region VII of EPA notified SPPC that it was being named as a potentially responsible party (PRP) regarding the past improper handling of Polychlorinated Biphenyls (PCBs) by PCB Treatment, Inc., located in Kansas City, Kansas, and Kansas City, Missouri (the Sites). The EPA is requesting that SPPC voluntarily pay an undefined, pro rata share of the ultimate clean-up costs at the Sites. A number of the largest PRP's formed a steering committee, which is chaired by SPPC. The responsibility of the Committee is to direct clean-up activities, determine appropriate cost allocation, and pursue actions against recalcitrant parties, if necessary. The EPA issued an administrative order on consent requiring signatories to perform certain investigative work at the Sites. The steering committee retained a consultant to prepare an analysis regarding the Sites. The Site evaluations have been completed. EPA is developing an allocation formula to allocate the remediation costs. SPPC has recorded a preliminary liability for the Sites of $650,000 of which approximately $135,000 has been spent through December 31, 2000. Once evaluations are completed, SPPC will be in a better position to estimate and record the ultimate liabilities for the Sites. 134 In October 2000, NDEP issued Notices of Alleged Violation (NOAV's) to SPPC for operating the Winnemucca Gas Turbine and the Tracy Peaking Combustion Turbine No. 1 over their annual operating hours. SPPC has applied for additional operating hours on these units per the NOAV's. In December 2000, SPPC notified NDEP that the annual operating hours for the Battle Mountain, Gabbs, and Brunswick Gas Turbines were exceeded in 2000. SPPC has applied for a Class II Air Operating Permit for these units. Enforcement action is pending per NDEP review of permit applications. In January 2001, Placer County Air Pollution Control District issued a Notice of Violation and a subsequent $160,000 penalty to SPPC for operating the Kings Beach Diesel Generation Facility in excess of its permitted annual operating hours. A settlement conference was held in February 2001 to present additional facts or circumstances to be considered in settling this matter. Other Subsidiaries of SPR Lands of Sierra, a wholly owned subsidiary of SPR, owns property in North Lake Tahoe, California, which is leased to independent condominium owners. The property has both soil and groundwater petroleum contaminate resulting from an historic underground fuel tank. Additional contaminate from a third party fuel tank on the property has also been identified and is undergoing remediation. Estimated future remediation costs are not expected to be significant. Nevada Electric Investment Company (NEICO), a wholly owned subsidiary of SPR, owns property in Wellington, Utah, which was the site of a coal washing and load out facility. The site now has a reclamation estimate supported by a bond of $4 million with the Utah Division of Oil and Gas Mining. The property was under contract for sale and the contract required the purchaser to provide $1.3 million in escrow towards reclamation. However, the sales contract was terminated and NEICO took title to the escrow funds. In September 2000, NEICO leased the property together with an option to purchase it. It is NEICO's intention to sell the property. See Notes 1, 3, 6, 8, 9, 12, 14, 16, and 17 of SPR's consolidated financial statements for additional commitments and contingencies. SPR and its subsidiaries, through the course of their normal business operations, are currently involved in a number of other legal actions, none of which has had or, in the opinion of management, is expected to have a significant impact on its financial position or results of operations. NOTE 19. SEGMENT INFORMATION SPR operates three business segments (as defined by FASB statement No. 131, Disclosure about Segments of an Enterprise and Related Information) providing regulated electric, natural gas and water service. Electric service is provided to Las Vegas and surrounding Clark County, northern Nevada and the Lake Tahoe area of California. Natural gas and water services are provided in the Reno- Sparks area of Nevada. Other segment information includes segments below the quantitative threshold for separate disclosure. On September 7, 2000, SPR and SPPC adopted a plan to sell SPPC's water utility business. Accordingly, the water business is reported as a discontinued operation as of September 30, 2000 and the consolidated financial statements have been reclassified to report separately the net assets and 135 operating results of the water business. Accordingly the water business is not reflected in the segment information below. Information as to the operations of the different business segments is set forth below based on the nature of products and services offered. SPR evaluates performance based on several factors, of which the primary financial measure is business segment operating income. The accounting policies of the business segments are the same as those described in the summary of significant accounting policies (Note 1). Intersegment revenues are not material. In accordance with the requirements of purchase accounting and based on a merger date of August 1, 1999, the segmented financial information for the period ended December 31, 1999, includes five months of operating activity for SPR's subsidiaries other than NVP. Segmented information for 1998 includes only the operations of NVP.
December 31, 2000 Electric Gas All Other Reconciling Consolidated Eliminations Operating Revenues $2,219,252 $100,803 $ 14,199 $ 2,334,254 ========== ======== ======== ============== Operating income $ 107,175 $ 13,422 $ 6,792 $ 127,389 ========== ======== ======== ============== Operating income taxes $ (16,106) $ 3,271 $(18,187) $ (31,022) ========== ======== ======== ============== Depreciation $ 150,364 $ 4,974 $ 697 $ 156,035 ========== ======== ======== ============== Interest expense on long term debt $ 97,060 $ 4,318 $ 33,218 $ 134,596 ========== ======== ======== ============== Assets $4,586,682 $172,522 $541,524 $338,756 $ 5,639,484 ========== ======== ======== ======== ============== Capital expenditures $ 321,934 $ 14,490 $ 23,350 $ 359,774 ========== ======== ======== ============== December 31, 1999 Electric Gas All Other Reconciling Consolidated Eliminations Operating Revenues $1,236,702 $ 38,958 $ 9,132 $ 1,284,792 ========== ======== ======== ============== Operating income $ 157,030 $ 3,175 $ 2,656 $ 162,861 ========== ======== ======== ============== Operating income taxes $ 30,120 $ 425 $ (5,247) $ 25,298 ========== ======== ======== ============== Depreciation $ 107,704 $ 2,128 $ 243 $ 110,075 ========== ======== ======== ============== Interest expense on long term debt $ 75,869 $ 1,326 $ 299 $ 77,494 ========== ======== ======== ============== Assets $4,355,641 $153,347 $426,881 $300,048 $ 5,235,917 ========== ======== ======== ======== ============== Capital expenditures $ 275,761 $ 7,051 $ 16,252 $ 299,064 ========== ======== ======== ============== December 31, 1998 Electric Gas All Other Reconciling Consolidated Eliminations Operating Revenues $ 873,682 $ 873,682 ========== ============== Operating income $ 147,277 $ 147,277 ========== ============== Operating income taxes $ 42,949 $ 42,949 ========== ============== Depreciation $ 73,562 $ 73,562 ========== ============== Interest expense on long term debt $ 56,995 $ 56,995 ========== ============== Assets $2,541,840 $ 2,541,840 ========== ============== Capital expenditures $ 314,933 $ 314,933 ========== ==============
136 The reconciliation of Capital expenditures for 2000 and 1999 represents capital expenditures of the discontinued water business. The reconciliation of segment assets at December 31, 2000, and 1999 to the consolidated total includes the following unallocated amounts: 2000 1999 Other property $ 1,998 $ 2,661 Cash 5,348 3,011 Current assets- other 29,852 3,103 Other regulatory assets 33,315 34,571 Net Assets-Discontinued Operations 262,476 256,365 Deferred charges- other 1,767 337 -------- -------- $338,756 $300,048 ======== ======== NOTE 20. SUBSEQUENT EVENTS Comprehensive Energy Plan (NVP and SPPC) On January 29, 2001, the Utilities jointly filed a Comprehensive Energy Plan (the "CEP") with the PUCN. The CEP includes proposals for emergency rate relief, for the Utilities' energy supply portfolio, and for low income and conservation programs. Under the CEP, the Utilities map out a strategy to meet Nevada's short- and long-term energy needs, focusing on new mechanisms to recover the cost of wholesale power. The CEP also calls for accelerated approval of new long-term power contracts and encourages new power plant development. It also provides for automatic price reductions when wholesale prices fall. The CEP also includes a proposal that up to $5 million in revenue, generated from rate increases, will be provided to the State of Nevada to be used at the State's discretion to fund conservation and low-income protection programs. The CEP provides that the Utilities continue making monthly fuel and purchased power filings, which are scheduled to expire on March 1, 2003. See Note 3 "Regulatory Actions" for information about the monthly fuel and purchased power filings as provided for by the Global Settlement At a special agenda meeting On February 23, 2001, the PUCN issued an order approving the CEP rate increases to be effective March 1, 2001. The PUCN also set this matter for further proceedings to address the other proposals in the CEP and to analyze the need for the rate increases. A pre-hearing conference is scheduled for March 23, 2001. The CEP includes tiered rate increases, based on energy usage, that range from zero for certain low usage customers to as much as 29 percent for the state's largest energy users. The average increase is expected to be approximately 17 percent. The Utilities have proposed that the rate increases be adjusted on March 1, 2002, or sooner, if wholesale prices fall and if divesture of the Utilities' Nevada power plants is completed and contracts are in place that guarantee the Utilities can purchase power from the new owners of those plants for two years at 1998 prices. Business Matters - California (NVP, SPPC) The California Power Exchange, a non-profit public benefit corporation established to operate the California electricity marketplace where electricity was bought and sold, filed for Chapter 11 bankruptcy protection on March 9, 2001. The California Power Exchange was created by the California legislature in conjunction with its efforts to restructure the electricity industry within the state of California. From March 31, 1998, until January 30, 2001, the Exchange was responsible for establishing 137 a competitive spot market for electric power through day and hour ahead auction of generation and demand bids. At December 31, 2000 the California Power Exchange was indebted to NVP in the amount of $14.8 million for energy sales. An uncollectible reserve of $5.3 million is reflected in NVP's results of operations for the year 2000. SPPC had no outstanding transactions with the California Power Exchange at December 31, 2000. NOTE 21. QUARTERLY FINANCIAL DATA (UNAUDITED) The following figures are unaudited and include all adjustments necessary in the opinion of management for a fair presentation of the results of interim periods. In accordance with the requirements of purchase accounting and based on a merger date of August 1, 1999, the quarterly financial information for the first two quarters of 1999 reflects the operations of NVP. The information for the quarter ended September 30, 1999, includes two months of operating activity for SPR's subsidiaries other than NVP as well as the quarterly data for NVP. Dollars are presented in thousands except per share amounts. 138
Quarter Ended March 31, 2000 June 30, 2000 September 30, 2000 December 31, 2000 Operating Revenues $ 392,649 $ 475,408 $ 867,978 $ 598,219 =========== =========== =========== =========== Operating Income $ 57,968 $ 15,950 $ 20,162 $ 36,962 =========== =========== =========== =========== Income (loss) from continuing operations $ 17,250 $ (24,021) $ (23,741) $ (18,903) Income from discontinued operations 928 3,830 4,193 684 ----------- ----------- ----------- ----------- Net income (loss) $ 18,178 $ (20,191) $ (19,548) $ (18,219) =========== =========== =========== =========== Income (loss) per share-Basic: Income (loss) from continuing operations $ 0.22 $ (0.31) $ (0.30) $ (0.24) Income from discontinued operations $ 0.01 $ 0.05 $ 0.05 $ 0.01 ----------- ----------- ----------- ----------- Net income (loss) $ 0.23 $ (0.26) $ (0.25) $ (0.23) =========== =========== =========== =========== Income (loss) per share-Diluted: Income (loss) from continuing operations $ 0.22 $ (0.31) $ (0.30) $ (0.24) Income from discontinued operations $ 0.01 $ 0.05 $ 0.05 $ 0.01 ----------- ----------- ----------- ----------- Net income (loss) $ 0.23 $ (0.26) $ (0.25) $ (0.23) =========== =========== =========== =========== Quarter Ended March 31, 2000 June 30, 2000 September 30, 2000 December 31, 2000 Operating Revenues $ 182,433 $ 237,937 $ 467,046 $ 397,377 =========== =========== =========== =========== Operating Income $ 20,961 $ 30,913 $ 97,911 $ 13,076 =========== =========== =========== =========== Income (loss) from continuing operations $ 4,483 $ 11,754 $ 62,146 $ (30,173) Income from discontinued operations - - 2,554 986 ----------- ----------- ----------- ----------- Net income (loss) $ 4,483 $ 11,754 $ 64,700 $ (29,187) =========== =========== =========== =========== Income (loss) per share-Basic: Income (loss) from continuing operations $ 0.09 $ 0.23 $ 0.89 $ (0.44) Income from discontinued operations $ - $ - $ 0.04 $ 0.02 ----------- ----------- ----------- ----------- Net income (loss) $ 0.09 $ 0.23 $ 0.93 $ (0.42) =========== =========== =========== =========== Income (loss) per share-Diluted: Income (loss) from continuing operations $ 0.09 $ 0.23 $ 0.89 $ (0.44) Income from discontinued operations $ - $ - $ 0.04 $ 0.02 ----------- ----------- ----------- ----------- Net income (loss) $ 0.09 $ 0.23 $ 0.93 $ (0.42) =========== =========== =========== ===========
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. 139 PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT (a) Directors The following is a listing of all the current directors of SPR, NVP and SPPC, and their ages as of December 31, 2000. There are no family relationships among them. Directors serve three-year terms with three (or four) terms of office expiring at each Annual Meeting, or until their successors have been elected and qualified. Directors whose terms expire in 2003: Edward P. Bliss, 68 Consultant to Zurich Scudder Investments Co; retired partner, Loomis, Sayles & Company, Inc., an investment counsel firm in Boston, Massachusetts. He is also a Director of Seaboard Petroleum, Midland, Texas. Mr. Bliss has served as a Director of SPR since 1991, of SPPC since 1991, and was elected a Director of NVP in July 1999. Mary Lee Coleman, 63 President of Coleman Enterprises, a developer of shopping centers and industrial parks. She is also a director of First Dental Health. Ms. Coleman has served as a Director of NVP since 1980, and was elected a Director of SPR and SPPC in July 1999. Theodore J. Day, 51 Senior Partner, Hale, Day, Gallagher Company, a real estate brokerage and investment firm. Mr. Day has served as a Director of SPPC since 1986, of SPR since 1987, and was elected a Director of NVP in July 1999. He is also a Director of the W.M. Keck Foundation. Jerry E. Herbst, 62 Chief Executive Officer of Terrible Herbst, Inc., a gas station, car wash, convenience store chain; and Herbst Supply Co., Inc., a wholesale fuel distributor; family-owned businesses for which he has worked since 1959. He is also a partner of the Coast Resorts (hotel and casino industry). Mr. Herbst has served as a Director of NVP since 1990, and was elected a Director of SPR and SPPC in July 1999. 140 Directors whose terms expire in 2002: Krestine M. Corbin, 63 President and Chief Executive Officer of Sierra Machinery, Incorporated since 1984 and a director of that company since 1980. She also serves on the Federal Reserve Board of San Francisco Board of Directors. Ms. Corbin has served as a Director of SPR since 1991, of SPR since 1989, and was elected a Director of NVP in July 1999. Fred D. Gibson, Jr., 73 Retired Chairman, President and Chief Executive Officer, but remains as a director, of American Pacific Corporation, a manufacturer of chemicals and pollution abatement equipment and a real estate developer. Mr. Gibson has been affiliated with American Pacific Corporation and its predecessor, Pacific Engineering & Production Co., since 1956. He is also a director of Cashman Equipment Company. Mr. Gibson has served as a Director of NVP since 1978, and was elected a Director of SPR and SPPC in July 1999. James L. Murphy, 71 Certified Public Accountant and retired partner of and consultant to Grant Thornton L.L.P., an international accounting and management consulting firm. Mr. Murphy is the owner, independent trustee and general partner of several real estate development projects and numerous rental properties. He is also a retired Colonel in the United States Air Force Reserve. Mr. Murphy has served as a Director of SPPC since 1990, of SPR since 1992, and was elected a Director of NVP in July 1999. Dennis E. Wheeler, 58 Chairman, President and Chief Executive Officer of Coeur d'Alene Mines Corporation since 1986. Mr. Wheeler has served as a Director of SPR since 1990, of SPPC since 1992, and was elected a Director of NVP in July 1999. Directors whose terms expire in 2001: James R. Donnelley, 65 Partner, Stet & Query, Ltd., since June 2000. Retired, R.R. Donnelly & Sons Company since June 2000, Vice Chairman of the Board, R.R. Donnelley & Sons Company from July 1990 to June 2000, and a Director of that company since 1976. Mr. Donnelley was R.R. Donnelley and Sons' Group President, Corporate Development from June 1987 to July 1990, and Group President, Financial Printing Services Group from January 1985 to January 1988. He is also a Director of Pacific Magazines & Printing Limited, and Chairman of National Merit Scholarship Corporation. Mr. Donnelley has served as a Director of SPR since 1987, of SPPC since 1992, and was elected a Director of NVP in July 1999. Walter M. Higgins, 56 Chairman, President and Chief Executive Officer of SPR since August 8, 2000. Chairman, President and Chief Executive Officer of AGL Resources, Inc., from February 1998 to August 141 2000. Chairman, President and Chief Executive Officer of SPR from January 4, 1994 to January 14, 1998. President and Chief Operating Officer of Louisville Gas and Electric Company from 1991 to November 1993. He is also a director of Aegis Insurance Services, Inc. NEETF, American Gas Association, and Infrastrux. John F. O'Reilly, 55 Chairman and Chief Executive Officer of the law firm of Keefer, O'Reilly, and Ferrario. Mr. O'Reilly is also Chairman and Chief Executive Officer of the O'Reilly Gaming Group and is Chairman of the Nevada Test Site Development Corporation. Mr. O'Reilly has served as a Director of NVP since 1995, and was elected a Director of SPR and SPPC in July 1999. Messrs. Higgins and Murphy are Directors of Lands of Sierra, Inc.; Messrs. Day and Higgins are Directors of Tuscarora Gas Pipeline Company; Mr. Higgins is a Director of Sierra Pacific Communications, Sierra Water Development Company, Sierra Gas Holdings Company, Pinon Pine Corporation, Pinon Pine Investment Company, and GPSF-B. The Directors of ethree are Michael J. Carano and Richard J. Coyle. All of the above listed companies are subsidiaries of Sierra Pacific Resources, with the exception of Pinon Pine Corporation, Pinon Pine Investment Company, and GPSF-B, which are subsidiaries of Sierra Pacific Power Company. (b) Executive Officers The following are current executive officers of the companies indicated and their ages as of December 31, 2000. There are no family relationships among them. Officers serve a term which extends to and expires at the annual meeting of the Board of Directors or until a successor has been elected and qualified: Walter M. Higgins, 56, Chairman, President and Chief Executive Officer, Sierra Pacific Resources See above description under Item 10(a), "Directors." Steven W. Rigazio, 46, President, Nevada Power Company Mr. Rigazio was elected President of Nevada Power Company in June 2000. Previously, he was Senior Vice President, Energy Delivery for SPPC and NVP in July 1999. Previously he was Vice President, Finance and Planning, Treasurer, and Chief Financial Officer for NVP effective October 1993. Other NVP management positions include Vice President and Treasurer, Chief Financial Officer; Vice President, Planning; Director of System Planning; Manager of Rates and Regulatory Affairs; and Supervisor of Rates and Regulations. Mr. Rigazio has been with NVP since 1984. William E. Peterson, 53, Senior Vice President, General Counsel and Corporate Secretary, Sierra Pacific Resources Mr. Peterson was elected to his present position in January 1994, and holds the same positions with SPPC and NVP. He was previously Senior Vice President, Corporate Counsel for SPPC from July 1993 to January 1994. Prior to joining SPR in 1993, he served as General Counsel and Resident Agent for SPR since 1992, while a partner in the Woodburn and Wedge law firm. He was a partner in the Woodburn and Wedge law firm since 1982. 142 Mark A. Ruelle, 39, Senior Vice President & Chief Financial Officer, Sierra Pacific Resources, Sierra Pacific Power Company and Nevada Power Company Mr. Ruelle was elected to his present position in December 2000, and holds the same positions with SPPC and NVP. Prior to joining SPR, Mr. Ruelle was President of Westar Energy, a subsidiary of Western Resources in 1996, and before that, served as Vice President, Corporate Development for Western Resources in 1995. Mr. Ruelle was with Western Resources since 1987 and served in numerous positions in regulatory affairs, treasury, finance, corporate development, and strategy planning. David G. Barneby, 55, Vice President, Generation, Sierra Pacific Power Company & Nevada Power Company Mr. Barneby was elected Vice President, Generation, in July 1999. Previously he was elected Vice President, Power Delivery for NVP effective October 1993. Mr. Barneby has been with NVP since 1965, and other management positions include Vice President, Generation; Manager, Generation Engineering and Construction; and Superintendent and Project Manager, Reid Gardner Unit 4. Jeffrey L. Ceccarelli, 46, President, Sierra Pacific Power Company Mr. Ceccarelli was elected to his present position in June 2000. He previously held the position of Vice President, Distribution Services, New Business, in July 1999 for SPPC and NVP. He was elected Vice President, Distribution Services for SPPC in February 1998. Prior to this, he served as Executive Director, Distribution Services. From January 1996 through January 1998, Mr. Ceccarelli was Director, Customer Operations. A civil engineer, Mr. Ceccarelli has been with SPPC since 1972. Gloria T. Banks Weddle, 51, Vice President, Corporate Services, Sierra Pacific Power Company and Nevada Power Company Ms. Weddle was elected Vice President, Corporate Services of Sierra Pacific Power Company and Nevada Power Company in July 1999, she had held the same position with NVP since January 1996. Previously she was Vice President, Human Resources and Corporate Services for NVP effective October 1993. Other NVP management positions include Vice President, Human Resources; Director of Human Resources; and Manager of Compensation and Benefits. Ms. Weddle has been with NVP since 1973. Matt H. Davis, 45, Vice President, Distribution Services, Nevada Power Company Mr. Davis was elected Vice President, Distribution Services for NVP. In the spring of 2000, he held a similar position forth both NVP and SPPC since July 1999. Previously he was Director, System Planning, and Division Director, System Planning and Operations for NVP. Mr. Davis has been with NVP since 1978. Steven C. Oldham, 50, Vice President, Corporate Development & Strategic Planning, Sierra Pacific Resources Mr. Oldham was elected to his current position in June 2000. Previously, he was Vice President, Transmission Business Group and Strategic Development; Vice President, Information 143 Resources, Corporate Redesign and Merger Transaction; Vice President, Regulation and Treasurer; and Treasurer and Director of Finance. Mr. Oldham has been with SPPC since 1976. Mary O. Simmons, 45, Controller, Sierra Pacific Resources Ms. Simmons was elected to her current position in June 1997, and holds the same position with SPPC and NVP. Her previous positions include: Director, Water Policy and Planning; Director, Budgets and Financial Services; and Assistant Treasurer, Shareholder Relations for SPR. Ms. Simmons is a certified public accountant and has been with SPR since 1985. Douglas R. Ponn, 53, Vice President, Governmental and Regulatory Affairs, Sierra Pacific Power Company and Nevada Power Company Mr. Ponn was elected Vice President, Governmental and Regulatory Affairs, in July 1999 for both SPPC and NVP. Previously he was Executive Director, Governmental and Regulatory Affairs. Mr. Ponn has been with SPR since 1986. Mary Jane Reed, 54, Vice President, Human Resources, Sierra Pacific Power Company and Nevada Power Company Ms. Reed was elected Vice President, Human Resources of SPPC in January 1997, and was named to the same position with NVP in July 1999. She was previously Vice President, Human Resources, Network Group for Bell Atlantic Corporation. Ms. Reed was with Bell Atlantic from 1968 - 1996 and, in addition to the Vice President's position, served as Director of Human Resources, Assistant to the President for Consumer Affairs, and several other managerial positions. Richard K. Atkinson, 49, Treasurer, Sierra Pacific Resources Mr. Atkinson was elected Treasurer of SPR, SPPC, and NVP in December 2000. Previously he held the positions of Assistant Treasurer, Executive Director, Finance, and other positions in the Finance Department. Mr. Atkinson has been with SPPC since 1980. Michael R. Smart, 44, Acting Vice President, Resource Management, Sierra Pacific Power Company and Nevada Power Company Mr. Smart was appointed to his present position in October 2000. Previously he was Executive Director, Resource Management for SPPC and NVP effective August 1999. Prior to this, from February 1998, he served as Director, Electric Operations for SPPC. From August 1996 to February 1998, he was Director of Energy Sales. A registered electrical engineer in Nevada and California, Mr. Smart has been with SPPC since 1979 and has held numerous management positions in operations, engineering, and planning. Although all outstanding shares of SPPC's common stock are held by SPR and it is SPR's common stock which is traded on the New York Stock Exchange, SPPC has one series of non-voting preferred stock still outstanding and registered under the Securities Exchange Act of 1934 ("the Act"). As a technical matter, SPPC is thus deemed an "issuer" for purposes of the Act whose officers are required to make filings with respect to beneficial ownership, if any, of those non-voting preferred securities. SPPC's officers, all of whom are currently reporting pursuant to Section 16(a) of the Act 144 with respect to SPR's common stock, have now filed reports with respect to SPPC's preferred stock, which reports show no past or current beneficial ownership of such preferred stock. 145 ITEM 11. EXECUTIVE COMPENSATION Summary Compensation Table The following table sets forth information about the compensation of each Chief Executive Officer that served in that position during 2000, and each of the four most highly compensated officers for services in all capacities to SPR and its subsidiaries. Also included is an individual who, although not an officer at the end of 2000, warranted inclusion due to compensation levels.
--------------------------------------------------------------------------------------------------- Annual Compensation ------------------------------------------------------- Other Annual Name and Principal Position Year Salary ($) Bonus ($) Compensation ($) (a) (b) (c) (d)(2) (e)(3) --------------------------------------------------------------------------------------------------- Walter M. Higgins (1) 2000 $ 215,151 $ - $ 33,690 Chairman of the Board, President, and Chief Executive Officer Michael R. Niggli (1) 2000 $ 350,654 $ - $ - Chairman and Chief 1999 $ 400,000 $ 255,130 $ 1,183 Executive Officer 1998 $ 353,846 $ 216,000 $ 11,161 Steven W. Rigazio 2000 $ 255,003 $ - $ 15,477 President, Nevada Power 1999 $ 262,075 $ 81,700 $ 60,654 Company 1998 $ 219,462 $ 30,750 $ 13,712 Mark A. Ruelle 2000 $ 250,255 $ - $ 15,967 Senior Vice President, Chief 1999 $ 196,654 $ 86,658 $ 7,389 Financial Officer and Treasurer 1998 $ 192,116 $ 72,843 $ 12,342 Malyn K. Malquist 2000 $ 177,306 $ - $ 52,415 President and Chief 1999 $ 352,692 $ 199,875 $ 14,337 Operating Officer 1998 $ 292,960 $ 180,900 $ 16,486 William E. Peterson 2000 $ 216,203 $ - $ 25,943 Senior Vice President, 1999 $ 200,000 $ 83,053 $ 20,727 General Counsel and Corporate Secretary 1998 $ 199,385 $ 71,503 $ 18,918 Gloria T. Banks-Weddle 2000 $ 209,426 $ - $ 16,154 Vice President, Corporate 1999 $ 185,769 $ 57,564 $ 41,358 Services 1998 $ 177,222 $ 54,000 - --------------------------------------------------------------------------------------------------- -------------------------------------------------------------------------------------------------------- Long-Term Compensation Awards Payout --------------------------------------------------------------------- Securities Underlying Restricted Stock Options/ SARs All Other Name and Principal Position Awards ($) (#) LTIP Payouts ($) Compensation ($) (a) (f)(4) (g)(5) (h)(6) (i)(7) -------------------------------------------------------------------------------------------------------- Walter M. Higgins (1) $ 256,000 400,000 $ - $ 411,758 Chairman of the Board, President, and Chief Executive Officer Michael R. Niggli (1) $ - - $ 66,781 $3,543,295 Chairman and Chief $ - 123,000 $ 410,306 $ 8,934 Executive Officer $ - - $ 115,399 $ 79,743 Steven W. Rigazio $ - - $ 26,713 $ 201,227 President, Nevada Power $ - 36,260 $ 127,712 $ 6,811 Company $ - - $ 29,304 $ 4,800 Mark A. Ruelle $ - - $ 59,357 $ 19,160 Senior Vice President, Chief $ - 61,292 $ - $ 8,565 Financial Officer and Treasurer $ - 9,000 $ 50,108 $ 8,974 Malyn K. Malquist $ - - $ 110,977 $2,855,202 President and Chief $ - 298,792 $ - $ 22,021 Operating Officer $ - 61,000 $ 85,184 $ 15,805 William E. Peterson $ - - $ 59,357 $ 20,926 Senior Vice President, $ - 80,168 $ - $ 11,974 General Counsel and Corporate Secretary $ - 9,000 $ 85,184 $ 29,939 Gloria T. Banks-Weddle $ - - $ 16,410 $ 15,934 Vice President, Corporate $ - 18,220 $ 101,582 $ 7,371 Services $ - - $ 29,960 $ 4,514 --------------------------------------------------------------------------------------------------------
146 (1) Mr. Niggli resigned from his position of Chairman, President and Chief Executive Officer of Sierra Pacific Resources on July 22, 2000, and Mr. Higgins was named Chairman, President and Chief Executive Officer. (2) The amounts presented for 2000 and 1999, and those for the SPR executives in 1998, represent incentive pay received pursuant to SPR's "pay for performance" team incentive plan approved by stockholders in May, 1994. The 1998 amounts for the NVP executives represent pay received according to the NVP Short-Term Incentive Plan. All of the amounts are reported in the year they were earned, although payment may have occurred in a subsequent reporting period. The Board of Directors has elected not to grant payment of the 2000 incentive pay to the executives. (3) For all of the executives listed, except Mr. Malquist, these amounts represent Personal Time Off payouts. Of the amount reported for Mr. Malquist, $17,687.17 represents the difference between the price paid by the executive, upon the exercise of non-qualified stock options, and the fair market value on the date of purchase; the remainder, $34,727.49, represents the payment of dividend equivalents. (4) Upon rehire, Mr. Higgins was awarded a restricted stock grant of 16,000 shares, with the payment of dividend equivalents. On the date of grant the value of this award was $256,000 at $16.00 per share; at December 31, 2000, the value of the grant was $257,000 at $16.0625 per share. The grant will vest over a four year period in the following manner: a. September 2002 4,000 shares b. September 2003 4,000 shares c. September 2004 8,000 shares (5) As a result of the August 1, 1999 merger with Nevada Power Company, all SPR nonqualifying stock options outstanding as of that date were converted at a ratio of 1.44:1. For the pre-merger SPR executives, the 1999 option amounts include the number of new shares issued during the year, as well as the total number of shares that were converted for that employee. For 1998 the amounts are the same as those presented in prior years and do not reflect the conversion. Also, the 2000 Non-Qualified Stock Options were granted in August of 1999, therefore they are included in the 1999 amounts. (6) The Long-term incentive payouts for the SPR executives, for the three-year period January 1, 1997 to December 31, 1999, were not approved for payment by the SPR Board of Directors; therefore, zero amounts are shown in 1999 for the pre-merger SPR executives. In 1999, Nevada Power executives received a lump sum payout of all their performance shares as a result of the August 1, 1999, merger. (7) Amounts for All Other Compensation include the following for 2000: 147
------------------------------------------------------------------------------------------------------------------------------------ Walter M. Michael R. Steven W. Mark A. Malyn K. William E. Gloria T. Description Higgins Niggli Rigazio Ruelle Malquist Peterson Banks-Weddle ------------------------------------------------------------------------------------------------------------------------------------ Company contributions to the 401k deferred compensation plan $ 10,200 $ 10,200 $ 10,200 $ 10,200 $ 10,200 $ 10,200 $ 10,200 Company paid portion of Medical/Dental/Vision Benefits $ 2,444 $ 1,844 $ 5,499 $ 5,499 $ 917 $ 5,499 $ 4,149 Company contributions to the nonqualified deferred compensation plan $ 2,785 $ 4,497 $ 3,391 Imputed income on group term life insurance $ 1,233 $ 955 $ 653 $ 328 $ 253 $ 728 $ 715 premiums paid by SPR Insurance premiums paid for executive term life policies $ 1,116 $ 348 $ 558 $ 1,107 $ 870 Moving Expense Reimbursement $ 32,323 Additional Compensation upon Rehire $ 397,881 Non-Qualified Pension Payments $ 249,666 Severance/Stay Agreement payments $ 3,496,856 $ 184,875 $ 2,589,111 Total $ 411,758 $ 3,543,295 $ 201,227 $ 19,160 $ 2,855,202 $ 20,926 $ 15,934 ------------------------------------------------------------------------------------------------------------------------------------
Options/SAR Grants in Last Fiscal Year The following table shows all grants of options to the named executive officers of SPR in 2000. Pursuant to SEC rules, the table also shows the present value of the grant at the date of grant.
------------------------------------------------------------------------------------------------------------------ Percent of Number of Total Securities Options/SAR's Underlying Granted to Options/SAR's Employees in Exercise of Base Grant Date Name Granted Fiscal Year Price ($/share) Expiration Date Present Value (a)(1) (b) (c)(2) (d) (e)(3) (f)(4) ------------------------------------------------------------------------------------------------------------------ Walter M. Higgins 08/04/2000 Grant date 400,000 100.00% $ 16.00 2/18/09 $ 1,520,635 Michael R. Niggli - - - - - Steven W. Rigazio - - - - - Mark A. Ruelle - - - - - Malyn K. Malquist - - - - - William E. Peterson - - - - - Gloria T. Banks-Weddle - - - - - ------------------------------------------------------------------------------------------------------------------
(1) Under the SPR executive long-term incentive plan, a grant of 400,000 shares of nonqualifying stock options was made on August 4, 2000. One-quarter of this grant vests annually commencing one year after the date of the grant, and is dependent on certain stock performance criteria. (2) The total number of nonqualifying stock options granted to all employees in 2000 was 400,000. All of the executives, except Mr. Higgins because his employment did not begin until 2000, were 148 granted their year 2000 shares on the date of the NVP & SPR merger, August 1, 1999. As a result, these grants were reported in 1999. (3) Mr. Higgins' grant will expire on either his 65th birthday, 02/18/09, or one year from his date of retirement, whichever occurs first. (4) The hypothetical grant-date present values are calculated under the Black-Scholes Model. The Black-Scholes Model is a mathematical formula used to value options traded on stock exchanges. The assumptions used in determining the option grant date present value listed above include the stock's average expected volatility (30.49%), average risk free rate of return (6.14%), average projected dividend yield (4.81%), the stock option term (9.5 years), and an adjustment for risk of forfeiture during the vesting period (4 years at 3%). No adjustment was made for non-transferability. Aggregated Option/SAR Exercises in Last Fiscal Year and FY-End Option/SAR Values The following table provides information as to the value of the options held by the named executive officers at year end measured in terms of the closing price of Sierra Pacific Resources common stock on December 31, 2000.
--------------------------------------------------------------------------------------------------------------------- Shares Number of Securities Underlying Value of Unexercised in-the- Acquired on Value Unexercised Options/SARs at money Options/SARs at Fiscal Name Exercise Realized Fiscal Year-End Year-End (a) (b) (c) (d) (e) -------------------------------------------------------------- Exercisable Unexercisable Exercisable Unexercisable --------------------------------------------------------------------------------------------------------------------- Walter M. Higgins - - - - $ - $ - Michael R. Niggli - - - - $ - $ - Steven W. Rigazio - - 4,320 31,940 $ - $ - Mark A. Ruelle - - 25,032 36,260 $ - $ - Malyn K. Malquist 14,107 17,687 - - $ - $ - William E. Peterson - - 42,899 37,269 $ 28,412 $ - Gloria T. Banks-Weddle - - 2,640 15,580 $ - $ - ---------------------------------------------------------------------------------------------------------------------
(c) Related to the exercise of the options reported in (b), Mr. Malquist received dividend equivalents totaling $34,727. (e) Pre-tax gain. Value of in-the-money options based on December 31, 2000, closing trading price of $16.0625 less the option exercise price. Long-Term Incentive Plans-Awards in Last Five Years The executive long-term incentive plan (LTIP) provides for the granting of stock options (both nonqualified and qualified), stock appreciation rights (SARs), restricted stock performance units, performance shares and bonus stock to participating employees as an incentive for outstanding performance. Incentive compensation is based on the achievement of pre-established financial goals for SPR. Goals are established for total shareholder return (TSR) compared against the Dow Jones Utility Index and annual growth in earnings per share (EPS). The following table provides information as to the performance shares granted to the named executive officers of Sierra Pacific Resources in 2000. Nonqualifying stock options granted to the named executives as part of the LTIP are shown in the table "Option/SAR Grants in Last Fiscal Year." 149
-------------------------------------------------------------------------------------------- Performance Estimated Future Payouts Under Number of or Other Non-Stock Price-Based Plans --------------------------------------- Shares, Units Period Until or Other Maturation Name Rights or Payout Threshold($) Target ($) Maximum ($) (a) (b) (c) (d)(1) (e)(2) (f)(3) -------------------------------------------------------------------------------------------- Walter M. Higgins 10,164 3 years $ 132,132 $ 264,264 $ 462,462 Michael R. Niggli - - $ - $ - $ - Steven W. Rigazio 2,900 3 years $ 37,700 $ 75,400 $ 131,950 Mark A. Ruelle 2,900 3 years $ 37,700 $ 75,400 $ 131,950 Malyn K. Malquist - - $ - $ - $ - William E. Peterson 2,900 3 years $ 37,700 $ 75,400 $ 131,950 Gloria T. Banks-Weddle 1,300 3 years $ 16,900 $ 33,800 $ 59,150 --------------------------------------------------------------------------------------------
(1) The threshold represents the level of TSR and EPS achieved during the cycle which represents minimum acceptable performance and which, if attained, results in payment of 50% of the target award. Performance below the minimum acceptable level results in no award earned. (2) The target represents the level of TSR and EPS achieved during the cycle which indicates outstanding performance and which, if attained, results in payment of 100% of the target award. (3) The maximum represents the maximum payout possible under the plan and a level of TSR and EPS indicative of exceptional performance which, if attained, results in a payment of 175% of the target award. All levels of awards are made with reference to the price of each performance share at the time of the grant. Pension Plans The following table shows annual benefits payable on retirement at normal retirement age 65 to elected officers under SPR's defined benefit plans based on various levels of remuneration and years of service which may exist at the time of retirement.
---------------------------------------------------------------------------------------- Annual Benefits for Years of Service Indicated --------------------------------------------------------------------- Highest Average Five-Years 15 Years 20 Years 25 Years 30 Years 35 Years Remuneration ---------------------------------------------------------------------------------------- $ 60,000 $ 27,000 $ 31,500 $ 36,000 $ 36,000 $ 36,000 $120,000 $ 54,000 $ 63,000 $ 72,000 $ 72,000 $ 72,000 $180,000 $ 81,000 $ 94,500 $108,000 $108,000 $108,000 $240,000 $108,000 $126,000 $144,000 $144,000 $144,000 $300,000 $135,000 $157,500 $180,000 $180,000 $180,000 $360,000 $162,000 $189,000 $216,000 $216,000 $216,000 $420,000 $189,000 $220,500 $252,000 $252,000 $252,000 $480,000 $216,000 $252,000 $288,000 $288,000 $288,000 $540,000 $243,000 $283,500 $324,000 $324,000 $324,000 $600,000 $270,000 $315,000 $360,000 $360,000 $360,000 $660,000 $297,000 $346,500 $396,000 $396,000 $396,000 $720,000 $324,000 $378,000 $432,000 $432,000 $432,000 ----------------------------------------------------------------------------------------
150 SPR's noncontributory retirement plan provides retirement benefits to eligible employees upon retirement at a specified age. Annual benefits payable are determined by a formula based on years of service and final average earnings consisting of base salary and incentive compensation. Remuneration for the named executives is the amount shown under "Salary" and "Incentive Pay" in the "Summary Compensation Table. Pension costs of the retirement plan to which SPR contributes 100% of the funding are not and cannot be readily allocated to individual employees and are not subject to Social Security or other offsets. During 2000, a change was made to the policy for calculating credited years of service; now, the first year of service is recognized as credited. Reflecting this change, the years of credited service for the named executives are as follows: Mr. Higgins, 7.1; Mr. Niggli, 0; Mr. Malquist, 0; Mr. Rigazio, 16.5; Mr. Ruelle, 3.8; Mr. Peterson, 14.5; and Ms. Banks-Weddle, 26.5. A supplemental executive retirement plan (SERP) and an excess plan are also offered to the named executive officers. The SERP is intended to ensure the payment of a competitive level of retirement income to attract, retain and motivate selected executives. The excess plan is intended to provide benefits to executive officers whose pension benefits under SPR's retirement plan are limited by law to certain maximum amounts. Severance Arrangements Individual severance allowance plans exist for the named executive officers which provide for severance pay, payable in a lump sum or by purchase of an annuity, if within three years after a change in control of SPR, there is a termination of employment by SPR related to such change in control, or a termination of employment by the employee for good reason, in each case as described in the plans. In these circumstances, officers are entitled to a severance allowance not to exceed an amount equal to 36 months of the officer's base salary and any bonus and the continuation for up to 36 months of participation in SPR's group medical and life insurance plans. Change in control is defined in the plans as, among other things, a dissolution or liquidation, a reorganization, merger or consolidation in which SPR is not the surviving corporation, the sale of all or substantially all the assets of SPR (not the sale of a work unit) or the acquisition by any person or entity of 30% or more of the voting power of SPR. In addition, several merger-related and merger-conditioned severance arrangements have been entered into between SPR and several executives, which are described in Item 13 - Certain Relationships and Related Transactions. 151 ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT Voting Stock The table below sets forth the shares of Sierra Pacific Resources Common Stock beneficially owned by each director, nominee for director, the Chief Executive Officer, and the four other most highly compensated executive officers. No director, nominee for director or executive officer owns, nor do the directors and executive officers as a group own, in excess of one percent of the outstanding Common Stock of SPR. Unless otherwise indicated, all persons named in the table have sole voting and investment power with respect to the shares shown.
Common Shares Beneficially Percent of Total Common Owned as of Shares Outstanding as of Name of Director or Nominee March 15, 2001 March 15, 2001 ---------------------------------------- --------------------- ----------------------------------- Edward P. Bliss 26,637 Mary L. Coleman 165,895 Krestine M. Corbin 19,636 Theodore J. Day 34,172 No director or nominee James R. Donnelley 34,459 for director owns in excess Fred D. Gibson Jr. 21,580 of one percent. Jerry E. Herbst 13,902 Walter M. Higgins 30,010 James L. Murphy 18,513 John F. O'Reilly 12,733 Dennis E. Wheeler 17,552 --------------------- 395,089 ===================== Common Shares Beneficially Percent of Total Common Owned as of Shares Outstanding as of Executive Officers March 15, 2001 March 15, 2001 ---------------------------------------- --------------------- ----------------------------------- Walter M. Higgins 30,010 Michael R. Niggli (1) - Steven W. Rigazio 31,660 No executive officer owns Mark A. Ruelle 50,286 In excess of one percent William E. Peterson 69,275 Gloria T. Banks-Weddle 14,825 --------------------- 196,056 ===================== All directors and executive officers as a group (a) (b) (c) 739,782 =====================
(1) Mr. Niggli resigned from his position of Chairman, President and Chief Executive Officer of Sierra Pacific Resources on July 22, 2000, and Mr. Higgins was named Chairman, President and Chief Executive Officer. (a) Includes shares acquired through participation in the Employee Stock Purchase Plan and/or the 401(k) plan. (b) The number of shares beneficially owned includes shares which the Executive Officers currently have the right to acquire pursuant to stock options granted and performance shares earned under the Executive Long-Term Incentive Plan. Share beneficially owned pursuant to stock options and restricted stock granted to Messrs. Higgins, Rigazio, Peterson, Ruelle, Banks-Weddle and directors and executive officers as a group are -0-, 16,407, 60,316, 47,244, 13,891 and 261,881 shares, respectively. Shares beneficially owned as a result of performance shares earned by Messrs. Higgins, Rigazio, Peterson, Ruelle, Banks-Weddle and directors and executive officers as a group are -0-, 1,521, 3,042, 3,042, 934, and 14,506 shares, respectively. Additionally, 16,000 shares are beneficially owned by Mr. Higgins pursuant to restricted stock grants. (c) Included in the shares beneficially owned by the Directors are 97,683 shares of "phantom stock" representing 152 the actuarial value of the Director's vested benefits in the terminated Retirement Plan for Outside Directors. The "phantom stock" is held in an account to be paid at the time of the Director's departure from the Board. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS Transactions with Management ---------------------------- Mr. Peterson, formerly a partner with the law firm of Woodburn and Wedge, became Senior Vice President and General Counsel for Sierra Pacific Resources in 1993. Woodburn and Wedge, which has performed legal services for Sierra Pacific Power Company since 1920 and for Sierra Pacific Resources and all of its subsidiaries from their inception, continues to perform legal work for the company. Mr. Peterson's spouse, an equity partner in the firm since 1982, has performed work for the company since 1976 and continues to do so from time to time. Susan Oldham, a former employee of Sierra Pacific Power Company specializing in water resources law, planning and policy, accepted the Company's voluntary severance offering in December 1995. Ms. Oldham is the spouse of Steven C. Oldham, Senior Vice President, Corporate Development and Strategic Planning, for the Company. Ms. Oldham, a licensed attorney in Nevada and California, has continued to perform specialized legal services in the water resources area for the Company on a contract basis. Change in Control Agreements ---------------------------- The Company has entered into change in control severance agreements with Gloria Banks Weddle, Jeffrey L. Ceccarelli, Matt H. Davis, Steven C. Oldham, William E. Peterson, Douglas R. Ponn, Mark A. Ruelle, Mary O. Simmons, and Mary Jane Reed. These agreements provide that, upon termination of the executive's employment within 24 months following a change in control of the Company (as defined in the agreement either (a) by SPR for reasons other than cause (as defined in the agreements), (b) death or disability, or (c) by the executive for good reason as defined in the agreement, including a diminution of responsibilities, compensation, or benefits (unless, with respect to reduction in salary or benefits, such reduction is applicable to all senior executives of the Company and the acquirer)), the executive will receive certain payments and benefits. These severance payments and benefits include (i) a lump sum payment equal to three times the sum of the executive's base salary and target bonus, (ii) a lump sum payment equal to the present value of the benefits the executive would have received had he continued to participate in the Company's retirement plans for an additional three years (or, in the case of the Company's Supplemental Executive Retirement Plan only, the greater of three years or the period from the date of termination until the executive's early retirement date, as defined in such plan), and (iii) continuation of life, disability, accident and health insurance benefits for a period of 36 months immediately following termination of employment. The agreements also provide that if any compensation paid, or benefit provided, to the executive, whether or pursuant to the change in control agreements, would be subject to the federal excise tax on "excess parachute payments," payments and benefits provided pursuant to the agreement will be cut back to the largest amount that would not be subject to such excise tax, if such cutback results in a higher after-tax payment to the executive. The Board of Directors entered into these agreements in order to attract and retain excellent management and to encourage and reinforce continued attention to the executives' assigned duties without distraction under circumstances arising from the possibility of a change in control of the Company. In entering into these agreements, the Board was advised by Towers Perrin, the national compensation and benefits consulting firm described above, and Skadden, Arps, Slate, Meagher & Flom, an independent outside law firm, to insure that the agreements entered into were in line with existing industry standards, and provided benefits to management consistent with those standards. The 153 Company declined to renew these contracts in 2000, and they will expire on December 31, 2001, unless renewed or replaced before that time. Employment Agreements --------------------- Walter M. Higgins On August 4, 2000, the Company elected Walter M. Higgins as President, Chief Executive Officer and Chairman of the Board under terms and conditions of an employment offer. The terms and conditions of that agreement essentially replicate Mr. Higgins' compensation and benefits package provided by his previous employer, AGL Resources, and make him whole for benefits and compensation lost, forgone, or otherwise forfeited as a result of his accepting employment with the Company. The Company engaged Towers Perrin to evaluate Mr. Higgins' offer prior to consummating it in order to assure that it was consistent with Company policy to compensate its senior executives, including the Chief Executive Officer, at or near the midpoint of the competitive market for base salary and incentive compensation opportunities for executives of comparably sized companies in general industry. The employment agreement with Mr. Higgins provides for an annual base salary of $590,000, participation in the Company's short-term incentive program, at 65% of base pay, and participation in the Company's long-term incentive program approved by shareholders at 140% of base salary. These programs are described in the Human Resources Committee Report on Executive Compensation provided above. Under the agreement, Mr. Higgins was also paid $387,881, representing 83% of the incentive payment he would have earned as of September 30, 2000, and would have been paid had he remained at AGL Resources, Inc., until November 1, 2000. The agreement also provides that Mr. Higgins would receive one-half of 38% of the year 2000 SPR annual incentive opportunity provided he satisfied expectations of the Board during the remainder of the year, and one-half of 38% of the year 2000 award opportunity based on the same goals and under the same terms and conditions as exist for the officer group as a whole. The Committee determined that Mr. Higgins achieved his performance goals and therefore earned one-half of the 38%, but consistent with its decision not to pay any incentive award to the officer group as a whole, elected not to award Mr. Higgins any annual incentive compensation for FY 2000. Future payments will be based on corporate and personal performance targets established under terms and conditions of the plan. The agreement also provides that Mr. Higgins will be paid long-term incentives in accordance with the terms of the plan approved by shareholders in 1994, which contemplates a performance share grant of 13,200 shares effective January 2001, to be earned over a three-year period under performance measurements relating to financial performance and total shareholder return. Effective January 1, 2001, he also received 104,000 non-qualified stock options, which will vest at one-third per year. As with the officer group as a whole, the strike price will be fixed at the average daily closing price of the stock on the New York Stock Exchange for the 30-day period January 1-31. In addition, Mr. Higgins will be eligible to receive on a pro-rata basis (28 of 36 months) the 2000-2002 performance share grants, which are also earned based on targets relating to financial performance and total shareholder return. Mr. Higgins also received a one-time restricted stock grant of 16,000 shares with dividend equivalents, grossed-up for taxes, which will vest over a four-year period. Mr. Higgins is required to accumulate and maintain, over five years, two times annual compensation in SPR stock, and was also granted 400,000 non-qualified stock options at a strike price based on the closing stock price on the day he accepted employment with the Company, which will vest 25% per year or sooner if certain price threshold levels are met. Mr. Higgins is also eligible to participate in the Company's Supplemental Executive Retirement Plan and was provided 154 credit for all previous years of service with the Company, plus all years served at AGL Resources or Louisville Gas & Electric, with benefits reduced by any qualified benefits received from that prior employment. Mr. Higgins was also provided $2,000,000 of life insurance coverage at Company expense and is otherwise eligible to participate in all employer-sponsored health, pension, benefit, and welfare plans. In the event Mr. Higgins is terminated by the Company for any reason other than cause (as defined in the agreement), he will receive one year's base salary and annual incentive payment, subject to execution of an appropriate release and non-compete covenants. In the event of a termination resulting from a change in control, within 24 months following a change in control of the Company (as defined in the agreement either (a) by SPR for reasons other than cause (as defined in the agreement), (b) death or disability, or (c) by Mr. Higgins for good reason as defined in the agreement, including a diminution of responsibilities, compensation, or benefits (unless, with respect to reduction in salary or benefits, such reduction is applicable to all senior executives of the Company and the acquirer)), he will receive certain payments and benefits. This severance payment and benefit include (i) a lump sum payment equal to three times the sum of his base salary and target bonus, (ii) a lump sum payment equal to the present value of the benefits he would have received had he continued to participate in the Company's retirement plans for an additional three years (or, in the case of the Company's Supplemental Executive Retirement Plan only, the greater of three years or the period from the date of termination until the executive's early retirement date, as defined in such plan), and (iii) continuation of life, disability, accident and health insurance benefits for a period of 36 months immediately following termination of employment. Under the employment agreement, Sierra Pacific will pay any additional amounts sufficient to hold Mr. Higgins harmless for any excise tax that might be imposed as a result of being subject to the federal excise tax on "excess parachute payments" or similar taxes imposed by state or local law in connection with receiving any compensation or benefits that are considered contingent on a change in control. A change in control for purposes of the Employment Agreement occurs (i) if Sierra Pacific merges or consolidates, or sells all or substantially all of its assets, and less than 65% of the voting power of the surviving corporation is owned by those stockholders who were stockholders of Sierra Pacific immediately prior to such merger or sale; (ii) any person acquires 20% or more of Sierra Pacific's voting stock; (iii) Sierra Pacific enters into an agreement or Sierra Pacific or any person announces an intent to take action, the consummation of which would otherwise result in a change in control, or the Board of Directors of Sierra Pacific adopts a resolution to the effect that a change in control has occurred; (iv) within a two-year period, a majority of the directors of Sierra Pacific at the beginning of such period cease to be directors; or (v) the stockholders of Sierra Pacific approve a complete liquidation or dissolution of Sierra Pacific. Mr. Niggli and Mr. Malquist In connection with the 1999 merger of Sierra Pacific Resources and Nevada Power Company, Sierra Pacific Resources entered into Employment Agreements with Messrs. Niggli and Malquist. Messrs. Niggli and Malquist are sometimes hereinafter individually referred to as the "Executive." The Employment Agreements became effective on July 28, 1999, and had a term of three years. Pursuant to the Employment Agreements, Mr. Niggli served as Chairman and Chief Executive Officer of Sierra Pacific Resources, and Mr. Malquist served as President and Chief Operating Officer of Sierra Pacific Resources and Chief Executive Officer of Nevada Power Company and Sierra Pacific Power Company. 155 Each Executive's Employment Agreement provided that he would receive annual base salary commensurate with his position and level of responsibility, as determined by the Sierra Pacific Board (or compensation committee thereof), but not less than the Executive's annual base salary as in effect immediately prior to the Merger. Each Employment Agreement also provided that the Executive would be eligible to participate in any annual incentive and long-term cash incentive plans applicable to executive and management employees that are authorized by the Board. The Executives were also entitled to participate in all employee benefit plans in which senior executives of Sierra Pacific are entitled to participate, in certain fringe benefits, and in the supplemental retirement plans in which they participated immediately prior to the Merger. If during the term of the employee agreement Sierra Pacific terminated the employment of the Executive for reasons other than cause (as defined in the agreement), death or disability, or the Executive terminated his employment for good reason (as defined in the employment agreement), the Executive would receive, in addition to all compensation earned through the date of termination and coverage and benefits under all benefit and incentive plans to which he is entitled pursuant to the terms thereof, a severance payment equal to three times the sum of his annual base salary and target annual bonus. In addition, the Executive would continue to receive health benefits (i.e., medical insurance, etc.) and life benefits on the same terms and conditions as existed prior to his termination for 36 months following his termination (the "Continuation Period"). Sierra Pacific also agreed to pay any additional amounts sufficient to hold the Executive harmless for any excise tax that might be imposed as a result of being subject to the federal excise tax on "excess parachute payments" or similar taxes imposed by state or local law in connection with receiving any compensation or benefits that is considered contingent on a change in control. Mr. Malquist's employment was terminated on April 18, 2000, and Mr. Niggli's employment was terminated on July 21, 2000, in each case under circumstances which entitled the Executive to the termination benefits described above and as set forth in the summary compensation table. As a result of these terminations, Mr. Malquist received a total payment (including a gross-up for excise taxes) of $2,589,111, and Mr. Niggli received a total payment (including a gross-up for excise taxes) of $3,496,856. Steven W. Rigazio On August 31, 2000, the Company entered into an employment agreement with Steven W. Rigazio, President of Nevada Power. Under the terms of the agreement, Mr. Rigazio will be paid $255,000 in annual base salary, subject to adjustment if the Board determines that an adjustment is appropriate. In addition, Mr. Rigazio is entitled to receive annual incentive and long-term compensation in accordance with the terms and conditions of existing plans as apply to the officer group as a whole. If Mr. Rigazio becomes disabled during the course of his employment, he will be entitled to receive 100% of base salary for six months, and any annual incentive pay for which he would otherwise be eligible during the year he first went on disability. At the expiration of any short-term disability, Mr. Rigazio would be eligible for long-term disability under the Company's long-term disability plan and will continue to be covered by the Company's medical, vision and dental plans during all of such time and will continue to earn years of service under the Retirement Plan until age 65 at which time he will be required to retire. During such time, he will also receive life insurance benefits substantially similar to those he was entitled to receive before going on short-term disability or long-term disability. If Mr. Rigazio dies before age 55 (the Retirement Plan's earliest retirement date), his surviving spouse will be eligible to receive the Retirement Plan's pre-retirement death benefit at the time Mr. Rigazio would have become 55. If Mr. Rigazio dies while on short-term disability or long-term disability, his surviving spouse will be eligible for SERP benefits as if Mr. Rigazio were 62 and will be paid an annuity on the date of death, or when Mr. Rigazio would have reached age 55, whichever occurs later. In addition, the 156 Company will continue to provide the Employee's spouse and eligible dependents all medical coverage so long as they are not covered by other plans. In addition to salary, the Company will also pay Mr. Rigazio $1,109,250 in six $184,875 installments beginning on October 1, 2000, and ending July 2002. If Mr. Rigazio is terminated or dies, any remaining balance will be paid to his estate or surviving spouse. David G. Barneby On June 19, 1999, Nevada Power, a wholly owned subsidiary of the Company, entered into a retention agreement effective on the date of the merger with David G. Barneby, Vice President, Generation, which provides him with benefits which he would have been entitled to receive had he voluntarily terminated his original May 13, 1998, employment agreement with the Company. The agreement provides, in addition to base pay and any incentive pay or long-term pay accrued during the period of his employment, an additional $600,890 in cash, payable in substantially equal quarterly installments commencing on October 1, 1999, and ending on July 31, 2002. If employment is terminated during the term or if the employee dies during the term, any remaining and unpaid installments shall be paid to the employee or to his heirs. If the employee is terminated or retires, then the employee shall, in addition, receive the economic equivalent to an enhancement of his retirement allowing for payment in cash of the present value of the average early retirement benefit calculated on the basis of the greater of actual age or age 55, and an additional five years of age or years of service or a combination thereof to maximize retiree medical benefits. The employee is also entitled to 24 months of employee health and life benefits in amounts substantially equivalent to those in effect immediately prior to termination. In the event any payments or benefits or distributions thereof under the contract or any other agreements, policies, or plans of the Company would be subject to the excise tax imposed by Section 4999 of the Internal Revenue Code by reason of being considered contingent on a change of control, then the employee is entitled to receive an additional payment equal to such excise tax. 157 PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K (a) Financial Statements, Financial Statement Schedules and Exhibits
Page ---- 1. Financial Statements: Independent Auditors' Report.................................................. 76-77 Consolidated Balance Sheets as of December 31, 2000 and 1999.................. 78 Consolidated Statements of Income for the Years Ended December 31, 2000, 1999 and 1998...................................................... 79 Consolidated Statements of Common Shareholders' Equity for the Years Ended December 31, 2000, 1999 and 1998............................. 80 Consolidated Statements of Cash Flows for the Years Ended December 31, 2000, 1999 and 1998......................................... 81 Consolidated Statements of Capitalization as of December 31, 2000 and 1999................................................................. 82-83 Balance Sheets for Nevada Power Company as of December 31, 2000 and 1999............................................... 84 Statements of Income for Nevada Power Company for the Years Ended December 31, 2000, 1999 and 1998..................... 85 Statements of Cash Flows for Nevada Power Company for the Years Ended December 31, 2000, 1999 and 1998............. 86 Statements of Capitalization for Nevada Power Company as of December 31, 2000 and 1999................................. 87 Consolidated Balance Sheets for Sierra Pacific Power Company as of December 31, 2000 and 1999........................................ 88 Consolidated Statements of Income for Sierra Pacific Power Company for the Years Ended December 31, 2000, 1999 and 1998................... 89 Consolidated Statements of Common Shareholders' Equity for Sierra Pacific Power Company for the Years Ended December 31, 2000, 1999 and 1998.......................................................... 90 Consolidated Statements of Cash Flows for Sierra Pacific Power Company for the Years Ended December 31, 2000, 1999 and 1998............ 91 Consolidated Statements of Capitalization for Sierra Pacific Power Company as of December 31, 2000 and 1999......................... 92 Notes to Financial Statements............................................... 93-139 2. Financial Statement Schedules: Schedule II - Consolidated Valuation and Qualifying Accounts........... 161-162
All other schedules have been omitted because they are not required or are not applicable, or the required information is shown in the financial statements or notes thereto. Columns omitted from schedules have been omitted because the information is not applicable. 158 3. Exhibits: Exhibits are listed in the Exhibit Index on pages 163-181. (b) Reports on Form 8-K None. 159 SIGNATURES Pursuant to the requirements of Section 13 and 15(d) of the Securities Exchange Act of 1934, Sierra Pacific Resources, Nevada Power Company and Sierra Pacific Power Company have each duly caused this report to be signed on their behalf by the undersigned, thereunto duly authorized. The signatures for each undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof. SIERRA PACIFIC RESOURCES NEVADA POWER COMPANY SIERRA PACIFIC POWER COMPANY By /s/ Walter M. Higgins -------------------------------- Walter M. Higgins Chairman, Chief Executive Officer and Director March 20, 2001 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of Sierra Pacific Resources, Nevada Power Company and Sierra Pacific Power Company and in the capacities indicated on the 20th day of March, 2001. /s/ Mark A. Ruelle /s/ Mary O. Simmons --------------------------------------- --------------------------------- Mark A. Ruelle Mary O. Simmons Senior Vice President, Controller Chief Financial Officer (Principal Accounting Officer) (Principal Financial Officer) /s/ Edward P. Bliss /s/ Fred D. Gibson, Jr. --------------------------------------- --------------------------------- Edward P. Bliss Fred D. Gibson, Jr. Director Director /s/ Mary Lee Coleman /s/ Jerry E. Herbst --------------------------------------- --------------------------------- Mary Lee Coleman Jerry E. Herbst Director Director /s/ Krestine M. Corbin /s/ James L. Murphy --------------------------------------- --------------------------------- Krestine M. Corbin James L. Murphy Director Director /s/ Theodore J. Day /s/ John F. O'Reilly --------------------------------------- --------------------------------- Theodore J. Day John F. O'Reilly Director Director /s/ James R. Donnelley /s/ Dennis E. Wheeler --------------------------------------- --------------------------------- James R. Donnelley Dennis E. Wheeler Director Director 160 Sierra Pacific Resources Schedule II - Consolidated Valuation and Qualifying Accounts For The Years Ended December 31, 2000, 1999 and 1998 (Dollars in Thousands) Provision for Uncollectible Accounts -------------- Balance at January 1, 1998 $ 3,995 Provision charged to income 8,899 Amounts written off, less recoveries (7,004) -------------- Balance at December 31, 1998 5,890 Balance at January 1, 1999 5,890 Provision charged to income 7,882 Amounts written off, less recoveries (7,297) -------------- Balance at December 31, 1999 6,475 Balance at January 1, 2000 6,475 Provision charged to income 14,879 Amounts written off, less recoveries (8,160) -------------- Balance at December 31, 2000 (1) $ 13,194 ============== Nevada Pacific Resources Schedule II - Consolidated Valuation and Qualifying Accounts For The Years Ended December 31, 2000, 1999 and 1998 (Dollars in Thousands) Provision for Uncollectible Accounts -------------- Balance at January 1, 1998 $ 2,291 Provision charged to income 5,213 Amounts written off, less recoveries (5,075) -------------- Balance at December 31, 1998 2,429 Balance at January 1, 1999 2,429 Provision charged to income 5,877 Amounts written off, less recoveries (5,480) -------------- Balance at December 31, 1999 2,826 Balance at January 1, 2000 2,826 Provision charged to income 13,090 Amounts written off, less recoveries (4,311) -------------- Balance at December 31, 2000 (1) $ 11,605 ============== 161 Sierra Pacific Power Company Schedule II - Consolidated Valuation and Qualifying Accounts For The Years Ended December 31, 2000, 1999 and 1998 (Dollars in Thousands)
Provision for Uncollectible Accounts ------------------- Balance at January 1, 1998 $ 1,704 Provision charged to income 3,686 Amounts written off, less recoveries (1,929) ------------------- Balance at December 31, 1998 3,461 Balance at January 1, 1999 3,461 Provision charged to income 2,005 Amounts written off, less recoveries (1,817) ------------------- Balance at December 31, 1999 3,649 Balance at January 1, 2000 3,649 Provision charged to income 1,789 Amounts written off, less recoveries (3,849) ------------------- Balance at December 31, 2000 (1) $ 1,589 ===================
(1) Included in the provision charged to income in 2000 was $7.3 million and $0.3 million, respectively, for NVP and SPPC as reserves against receivables from California's Power Exchange and Independent System Operator. 162 2000 FORM 10-K EXHIBIT INDEX Exhibits Index Certain of the following exhibits with respect to SPR and its subsidiaries, Nevada Power Company, Sierra Pacific Power Company, Lands of Sierra, Inc., Sierra Energy Company, Tuscarora Gas Pipeline Company and Sierra Water Development Company, are filed herewith. Certain other of such exhibits have heretofore been filed with the Commission and are incorporated herein by reference. (2) Sierra Pacific Resources . Stock Purchase Agreement between Enron Corp. and Sierra Pacific Resources dated November 5, 1999, relating to the proposed acquisition of Portland General Electric Company (filed as Exhibit 10.1 to Form 8-K dated November 5, 1999). (3) Sierra Pacific Resources . Restated Articles of Incorporation of Sierra Pacific Resources dated July 28, 1999 (filed as Exhibit 3(A) to Form 10-K for year ended December 31, 1999). . *(A) By-laws of Sierra Pacific Resources as amended through February 25, 2000. Nevada Power Company . Restated Articles of Incorporation of Nevada Power Company, dated July 28, 1999 (filed as Exhibit 3(B) to Form 10-K for year ended December 31, 1999). . Amended and Restated By-Laws of Nevada Power Company dated July 28, 1999 (filed as Exhibit 3(C) to Form 10-K for year ended December 31, 1999). Sierra Pacific Power Company . Restated Articles of Incorporation of Sierra Pacific Power Company dated May 19, 1987 (filed as Exhibit (3)(A) to Form 10-K for the year ended December 31, 1993). . Certificate of Amendments dated August 26, 1992 to Restated Articles of Incorporation of Sierra Pacific Power Company dated May 19, 1987, in connection with Sierra Pacific Power Company's preferred stock (filed as Exhibit 3.1 to Form 8-K dated August 26, 1992). . Certificate of Designation, Preferences and Rights dated August 31, 1992 to Restated Articles of Incorporation of Sierra Pacific Power Company dated May 19, 1987, in connection with Sierra Pacific Power Company's Class A Series 1 Preferred Stock (filed as Exhibit 4.3 to Form 8-K dated August 26, 1992). . By-laws of Sierra Pacific Power Company, as amended through November 13, 1996 (filed as Exhibit (3)(A) to Form 10-K for the year ended December 31, 1996). . Articles of Incorporation of Pinon Pine Corp., dated December 11, 1995 (filed as Exhibit (3)(A) to Form 10-K for the year ended December 31, 1995). 163 . Articles of Incorporation of Pinon Pine Investment Co., dated December 11, 1995 (filed as Exhibit (3)(B) to Form 10-K for the year ended December 31, 1995). . Agreement of Limited Liability Company of Pinon Pine Company, L.L.C., dated December 15, 1995, between Pinon Pine Corp., Pinon Pine Investment Co. and GPSF-B INC 1995 (filed as Exhibit (3)(C) to Form 10-K for the year ended December 31, 1995). . Amended and Restated Limited Liability Company Agreement of SPPC Funding LLC dated as of April 9, 1999, in connection with the issuance of California rate reduction bonds (filed as Exhibit (3)(A) to Form 10-K for the year ended December 31, 1999). (4) Sierra Pacific Resources . Indenture between Sierra Pacific Resources and The Bank of New York, dated as of May 1, 2000 for the issuance of debt securities (filed as Exhibit 4.1 to Form 8-K dated May 22, 2000). . Global 8-3/4% Note due 2005 (filed as Exhibit 4.2 to Form 8-K dated May 22, 2000). . Officers' Certificate establishing the terms of the 8-3/4% Notes due 2005 (filed as Exhibit 4.3 to Form 8-K dated May 22, 2000). . *(A) Fiscal and Paying Agency Agreement dated as of April 17, 2000 between Sierra Pacific Resources and Bankers Trust Company, relating to the Company's money market note program. . *(B) Form of Global Floating Rate Note due April 20, 2002 in connection with the Company's money market note program. . *(C) Form of Global Floating Rate Note due April 20, 2003 in connection with the Company's money market note program. . Rights Agreement between Sierra Pacific Resources and Harris Trust and Savings Bank dated as of September 21, 1999 (filed as Exhibit 99.1 to the Form 8-K dated December 7, 1999). Nevada Power Company . Fiscal and Paying Agency Agreement dated as of October 12, 1999 between Nevada Power Company and Bankers Trust Company, relating to Nevada Power Company's money market note program (filed as Exhibit 4(A) to Form 10-K for year ended December 31, 1999). Substantially identical agreements were used for the June 9, August 18, and December 18, 2000 issuances of money market notes. . Form of Global Floating Rate Note due October 6, 2000 in connection with the Company's money market note program (filed as Exhibit 4(B) to Form 10-K for year ended December 31, 1999). . *(D) Form of Global Floating Rate Note due June 12, 2001 in connection with the Company's money market note program. 164 . *(E) Form of Global Floating Rate Note due August 20, 2001 in connection with the Company's money market note program. . *(F) Form of Global Floating Rate Note due December 17, 2001 in connection with the Company's money market note program. . Junior Subordinated Indenture between Nevada Power and IBJ Schroder Bank & Trust Company, as Debenture Trustee dated March 1, 1997 (filed as Exhibit 4.01 to Form S-3, File No. 333-21091). . Trust Agreement of NVP Capital I dated March 1, 1997 (filed as Exhibit 4.03 to Form S-3, File No. 333-21091). . Form of Amended and Restated Trust Agreement dated March 1, 1997 (filed as Exhibit 4.10 to Form S-3, File No. 333-21091). . Form of Agreement as to Expenses and Liabilities between Nevada Power and NVP Capital I dated March 1, 1997 (filed as Exhibit 4.14 to Form S-3, File No. 333-21091). . Form of Preferred Security Certificate for NVP Capital I and NVP Capital II dated March 1, 1997 (filed as Exhibit 4.11 to Form S-3, File No. 333-21091). . Form of Guarantee Agreement dated March 1, 1997 (filed as Exhibit 4.12 to Form S-3, File No. 333-21091). . Form of Supplemental Indenture between Nevada Power and IBJ Schroder Bank & Trust Company, as Debenture Trustee dated March 1, 1997 (filed as Exhibit 4.13 to Form S-3, File No. 333- 21091). . Supplemental Indenture No. 2 and Assumption Agreement, dated as of June 1, 1999, between Nevada Power Company and IBJ Whitehall Bank & Trust Company, supplementing and assuming the Junior Subordinated Indenture dated as of March 1, 1997 between Nevada Power Company and IBJ Whitehall Bank & Trust Company (filed as Exhibit 4(D) to Form 10-K for year ended December 31, 1999). . Form of Indenture between Nevada Power and IBJ Schroder Bank & Trust Company, as Trustee dated October 1, 1998 (filed as Exhibit 4.1 to Form S-3, File Nos. 333-63613 and 333-63613-01). . Certificate of Trust of NVP Capital III dated October 1, 1998 (filed as Exhibit 4.2 to Form S-3, File Nos. 333-63613 and 333- 63613-01). . Trust Agreement for NVP Capital III dated October 1, 1998 (filed as Exhibit 4.3 to Form S-3, File Nos. 333-63613 and 333- 63613-01). . Form of Amended and Restated Declaration of Trust dated October 1, 1998 (filed as Exhibit 4.4 to Form S-3, File Nos. 333-63613 and 333-63613-01). 165 . Form of Preferred Security Certificate for NVP Capital III dated October 1, 1998 (filed as Exhibit 4.5 to Form S-3, File Nos. 333- 63613 and 333-63613-01). . Form of Preferred Securities Guarantee Agreement dated October 1, 1998 (filed as Exhibit 4.7 to Form S-3, File Nos. 333-63613 and 333-63613-01). . Form of Junior Subordinated Deferrable Interest Debenture dated October 1, 1998 (filed as Exhibit 4.9 to Form S-3, File Nos. 333- 63613 and 333-63613-01). . Supplemental Indenture No. 1 and Assumption Agreement, dated as of June 1, 1999, between Nevada Power Company and IBJ Whitehall Bank & Trust Company, supplementing and assuming the Indenture dated as of October 1, 1998 between Nevada Power Company and IBJ Whitehall Bank & Trust Company (filed as Exhibit 4(E) to Form 10-K for year ended December 31, 1999). . Supplemental Indenture No. 1 between Nevada Power Company and IBJ Whitehall Bank & Trust Company dated as of March 1, 1999 (filed as Exhibit 4.2 to Form S-4, File No. 333-77325). . Supplemental Indenture No. 3 and Assumption Agreement, dated as of July 1, 1999, between Nevada Power Company and IBJ Whitehall Bank & Trust Company, supplementing and assuming the Senior Unsecured Note Indenture dated as of March 1, 1999 between Nevada Power Company and IBJ Whitehall Bank & Trust Company (filed as Exhibit 4(F) to Form 10-K for year ended December 31, 1999). . Form of Senior Unsecured Note Indenture between Nevada Power Company and IBJ Whitehall Bank & Trust Company dated as of April 1, 1999 (filed as Exhibit 4.1 to Form S-4, File No. 333-77325). . Supplemental Indenture No. 2 between Nevada Power Company and IBJ Whitehall Bank & Trust Company dated as of April 1, 1999 (including form of 6.20% Senior Unsecured Note, Series B due April 15, 2004) (filed as Exhibit 4.3 to Form S-4, File No. 333-77325). . Instrument of Further Assurance dated April 1, 1956 to Indenture of Mortgage and Deed of Trust dated October 1, 1953 (filed as Exhibit 4.8 to Form S-1, File No. 2-12666). . Indenture of Mortgage and Deed of Trust Providing for First Mortgage Bonds, dated October 1, 1953 and Twenty-Seven Supplemental Indentures as follows: . First Supplemental Indenture, dated August 1, 1954 (filed as Exhibit 4.2 to Form S-1, File No. 2-11440). . Second Supplemental Indenture, dated September 1, 1956 (filed as Exhibit 4.9 to Form S-1, File No. 2-12566). . Third Supplemental Indenture, dated May 1, 1959 (filed as Exhibit 4.13 to Form S-1, File No. 2-14949). . Fourth Supplemental Indenture, dated October 1, 1960 (filed as Exhibit 4.5 to S-1, File No. 2-16968). 166 . Fifth Supplemental Indenture, dated December 1, 1961 (filed as Exhibit 4.6 to Form S-16, File No. 2-74929). . Sixth Supplemental Indenture, dated October 1, 1963 (filed as Exhibit 4.6A to Form S-1, File No. 2-21689). . Seventh Supplemental Indenture, dated August 1, 1964 (filed as Exhibit 4.6B to Form S-1, File No. 2-22560). . Eighth Supplemental Indenture, dated April 1, 1968 (filed as Exhibit 4.6C to Form S-9, File No. 2-28348. . Ninth Supplemental Indenture, dated October 1, 1969 (filed as Exhibit 4.6D to Form S-1, File No. 2-34588). . Tenth Supplemental Indenture, dated October 1, 1970 (filed as Exhibit 4.6E to Form S-7, File No. 2-38314). . Eleventh Supplemental Indenture, dated November 1, 1972 (filed as Exhibit 2.12 to Form S-7, File No. 2-45728). . Twelfth Supplemental Indenture, dated December 1, 1974 (filed as Exhibit 2.13 to Form S-7, File No. 2-52350). . Thirteenth Supplemental Indenture, dated October 1, 1976 (filed as Exhibit 4.14 to Form S-16, File No. 2-74929). . Fourteenth Supplemental Indenture, dated May 1, 1977 (filed as Exhibit 4.15 to Form S-16, File No. 2-74929). . Fifteenth Supplemental Indenture, dated September 1, 1978 (filed as Exhibit 4.16 to Form S-16, File No. 2-74929). . Sixteenth Supplemental Indenture, December 1, 1981 (filed as Exhibit 4.17 to Form S-16, File No. 2-74929). . Seventeenth Supplemental Indenture, dated August 1, 1982 (filed as Exhibit 4.2 to Form 10-K, File No. 1-4698, Year 1982). . Eighteenth Supplemental Indenture, dated November 1, 1986 (filed as Exhibit 4.6 to Form S-3, File No. 33-9537). . Nineteenth Supplemental Indenture, dated October 1, 1989 (filed as Exhibit 4.2 to Form 10-K, File No. 1-4698, Year 1989). . Twentieth Supplemental Indenture, dated May 1, 1992 (filed as Exhibit 4.21 to Form S-3, File No. 33-53034). . Twenty-First Supplemental Indenture, dated June 1, 1992 (filed as Exhibit 4.22 to Form S-3, File No. 33-53034). 167 . Twenty-Second Supplemental Indenture, dated June 1, 1992 (filed as Exhibit 4.23 to Form S-3, Filed No. 33-53034). . Twenty-Third Supplemental Indenture, dated October 1, 1992 (filed as Exhibit 4.23 to Form S-3, File No. 33-53034). . Twenty-Fourth Supplemental Indenture, dated October 1, 1992 (filed as Exhibit 4.23 to Form S-3, File No. 33-53034). . Twenty-Fifth Supplemental Indenture, dated January 1, 1993 (filed as Exhibit 4.23 to Form S-3, File No. 33-53034). . Twenty-Sixth Supplemental Indenture, dated May 1, 1995 (filed as Exhibit 4.2 to Form 10-K, File No. 1-4698, Year 1995). . Twenty-Seventh Supplemental Indenture dated as of July 1, 1999 (filed as Exhibit 4(C) to Form 10-K for year ended December 31, 1999). Sierra Pacific Power Company . Fiscal and Paying Agency Agreement dated as of September 14, 1999 between Sierra Pacific Power Company and Bankers Trust Company, relating to the Company's money market note program (filed as Exhibit 4(A) to Form 10-K for year ended December 31, 1999). . Form of Global Floating Rate Note due October 13, 2000 in connection with Sierra Pacific Power Company's money market note program (filed as Exhibit 4(B) to Form 10-K for year ended December 31, 1999). . *(G) Form of Global Floating Rate Note due June 12, 2001 in connection with Sierra Pacific Power Company's money market note program. . Mortgage Indentures of Sierra Pacific Power Company defining the rights of the holders of the Company's First Mortgage Bonds: . Original Indenture (filed as Exhibit 7-A to Registration No. 2-7475). . Ninth Supplemental Indenture (filed as Exhibit 2-M to Registration No. 2-59509). . Tenth Supplemental Indenture (filed as Exhibit 4-K to Registration No. 2-23932). . Eleventh Supplemental Indenture (filed as Exhibit 4-L to Registration No. 2-26552). . Twelfth Supplemental Indenture (filed as Exhibit 4-L to Registration No. 2-36982). . Sixteenth Supplemental Indenture (filed as Exhibit 2-Y to Registration No. 2-53404). . Nineteenth Supplemental Indenture (filed as Exhibit (4)(A) to the 1991 Form 10-K). 168 . Twentieth Supplemental Indenture (filed as Exhibit (4)(B) to the 1991 Form 10-K). . Twenty-Seventh Supplemental Indenture (filed as Exhibit (4)(A) to the 1989 Form 10-K). . Twenty-Eighth Supplemental Indenture (filed as Exhibit (4)(A) to the 1992 Form 10-K). . Twenty-Ninth Supplemental Indenture (filed as Exhibit D to Form 8-K dated July 15, 1992). . Thirtieth Supplemental Indenture (filed as Exhibit (4)(B) to the 1992 Form 10-K). . Thirty-First Supplemental Indenture (filed as Exhibit (4)(C) to the 1992 Form 10-K). . Thirty-Second Supplemental Indenture (filed as Exhibit 4.6 to Registration No. 33-69550). . Thirty-Third Supplemental Indenture (filed as Exhibit C to Form 8-K dated October 20, 1993). . Thirty-Fourth Supplemental Indenture (filed as Exhibit C to Form 8-K dated March 11, 1996). . Thirty-Fifth Supplemental Indenture (filed as Exhibit C to Form 8-K dated March 10, 1997). . Indenture dated as of April 9, 1999 between SPPC Funding LLC and Bankers Trust Company of California, N.A. in connection with the issuance of California rate reduction bonds (filed as Exhibit 4(C) to Form 10-K for year ended December 31, 1999). . First Series Supplement dated as of April 9, 1999 to Indenture between SPPC Funding LLC and Bankers Trust Company of California, N.A. in connection with the issuance of California rate reduction bonds (filed as Exhibit 4(D) to Form 10-K for year ended December 31, 1999). . Form of SPPC Funding LLC Notes, Series 1999-1, in connection with the issuance of California rate reduction bonds (filed as Exhibit 4(E) to Form 10-K for year ended December 31, 1999). . Indenture between Sierra Pacific Power Company and IBJ Schroder Bank and Trust Company as Trustee dated July 1, 1996 in connection with the offering of the Preferred Securities of the Trust (filed as Exhibit 4.2 to Form 8-K dated August 2, 1996). . First Supplemental Indenture to the Indenture used in connection with the issuance of Junior Subordinated Debentures dated July 24, 1996 in connection with the offering of the Preferred Securities of the Trust (filed as Exhibit 4.3 to Form 8-K dated August 2, 1996). 169 . Amended and Restated Declaration of Trust of Sierra Pacific Power Capital I (the Trust) dated July 24, 1996 in connection with the offering of the Preferred Securities of the Trust (filed as Exhibit 4.1 to Form 8-K dated August 2, 1996). . Guarantee with respect to Preferred Securities dated July 29, 1996 in connection with the offering of the Preferred Securities of the Trust (filed as Exhibit 4.4 to Form 8-K dated August 2, 1996). . Guarantee with respect to Common Securities dated July 29, 1996 in connection with the offering of the Preferred Securities of the Trust (filed as Exhibit 4.5 to Form 8-K dated August 2, 1996). . Collateral Trust Indenture dated June 1, 1992 between Sierra Pacific Power Company and Bankers Trust Company, as Trustee, relating to Sierra Pacific Power Company's medium-term note program (filed as Exhibit B to Form 8-K dated July 15, 1992). . First Supplemental Indenture dated June 1, 1992 (filed as Exhibit C to Form 8-K dated July 15, 1992). . Second Supplemental Indenture dated October 1, 1993 (filed as Exhibit B to Form 8-K dated October 20, 1993). . Third Supplemental Indenture dated as of February 1, 1996 (filed as Exhibit B to Form 8-K dated March 11, 1996). . Fourth Supplemental Indenture dated as of February 1, 1997 (filed as Exhibit B to Form 8-K dated March 10, 1997). . Form of Medium-Term Global Fixed Rate Note, Series A in connection with Sierra Pacific Power Company's medium-term note program (filed as Exhibit E to Form 8-K dated July 15, 1992 ). . Form of Medium-Term Global Fixed Rate Note, Series B in connection with Sierra Pacific Power Company's medium-term note program (filed as Exhibit D to Form 8-K dated October 25, 1993). . Form of Medium-Term Global Fixed-Rate Note, Series C in connection with Sierra Pacific Power Company's medium-term note program (filed as Exhibit D to Form 8-K dated March 11, 1996). . Form of Medium-Term Global Fixed-Rate Note, Series D in connection with Sierra Pacific Power Company's medium-term note program (filed as Exhibit D to Form 8-K dated March 10, 1997). (10) Sierra Pacific Resources, Nevada Power Company, and Sierra Pacific Power Company . Stipulation and Agreement to Compromise and Settle - Federal (filed as Exhibit (10.A) to Form 10-Q for quarter ended September 30, 2000). 170 . Stipulation and Agreement to Compromise and Settle - State (filed as Exhibit (10.B) to Form 10-Q for quarter ended September 30, 2000). Sierra Pacific Resources . *(A) Credit Agreement dated as of December 26, 2000 among Sierra Pacific Resources and Wells Fargo Bank, N.A. relating to $50,000,000 credit facility. . Change in Control Agreement dated April 20, 2000, by and between Sierra Pacific Resources and with Gloria Banks Weddle in substantially the same form as the Change in Control Agreements filed as Exhibit (10)(A) to Sierra Pacific Power Company's Annual Report on Form 10-K for the year ended December 31, 1997, and incorporated herein by reference thereto (filed as Exhibit 10 to Form 10-Q for the quarter ended June 30, 2000). . Change in Control Agreement dated February 18, 1997 by and among Sierra Pacific Resources and the following officers (individually): Gerald W. Canning, Jeffrey L. Ceccarelli, Randy G. Harris, Malyn K. Malquist, Steven C. Oldham, Victor H. Pena, William E. Peterson, Mark A. Ruelle, Mary O. Simmons, Doug Ponn, and Mary Jane Willier (filed as Exhibit 10(A) to Form 10-K for the year ended December 31, 1997). . *(B) Walter M. Higgins Employment Letter dated August 4, 2000. . Employment Agreement dated as of April 29, 1998 between Sierra Pacific Resources and Michael R. Niggli (Exhibit 7.15.1 to Agreement and Plan of Merger, dated as of April 29, 1998, among Sierra Pacific Resources, Nevada Power Company, LAKE Merger Sub, and DESERT Merger Sub, filed as Exhibit 2.1 to Form 8-K dated April 30, 1998). . Employment Agreement dated as of April 29, 1998 between Sierra Pacific Resources and Malyn K. Malquist (Exhibit 7.15.2 to Agreement and Plan of Merger, dated as of April 29, 1998, among Sierra Pacific Resources, Nevada Power Company, LAKE Merger Sub, and DESERT Merger Sub, filed as Exhibit 2.1 to Form 8-K dated April 30, 1998). . Change in Control Agreements dated February 18, 1997 by and among Sierra Pacific Resources and the following officers (individually): Gerald W. Canning, Jeffrey L. Ceccarelli, Randy G. Harris, Malyn K. Malquist, Steven C. Oldham, William E. Peterson, Mark A. Ruelle, Mary O. Simmons, and Mary Jane Willier (filed as Exhibit (10)(A) to Sierra Pacific Power Company's Form 10-K for the year ended December 31, 1997). . Sierra Pacific Resources Executive Long-Term Incentive Plan (filed as Exhibit 99.1 to Form S-8 dated December 13, 1999). . Sierra Pacific Resources' Non-Employee Director Stock Plan (filed as Exhibit 99.2 to Form S-8 dated December 13, 1999). . Sierra Pacific Resources' Employee Stock Purchase Plan (filed as Exhibit 99.3 to Form S-8 dated December 13, 1999). 171 Nevada Power Company . *(C) Asset Sale Agreement between Nevada Power Company and The AES Corporation dated as of May 10, 2000 for the Mohave Asset Bundle. . *(D) Transitional Power Purchase Agreement by and between Nevada Power Company and AES Mohave, LLC dated as of May 10, 2000. . *(E) Asset Sale Agreement between Nevada Power Company, NRG Energy, Inc. and Dynegy Holdings Inc. for the Clark Asset Bundle dated as of November 16, 2000. . *(F) Transitional Power Purchase Agreement by and between Nevada Power Company and Clark Power LLC dated as of November 16, 2000. . *(G) Asset Sale Agreement between Nevada Power Company, NRG Energy, Inc. and Dynegy Holdings Inc. for the Reid Gardner Asset Bundle dated as of November 16, 2000. . *(H) Transitional Power Purchase Agreement by and between Nevada Power Company and Reid Gardner Power LLC dated as of November 16, 2000. . *(I) Asset Sale Agreement between Nevada Power Company and Pinnacle West Energy Corporation for the Harry Allen Asset Bundle, dated as of December 1, 2000. . *(J) Transitional Power Purchase Agreement by and between Nevada Power Company and Pinnacle West Energy Corporation dated as of December 1, 2000. . *(K) Asset Sale Agreement between Nevada Power Company and Reliant Energy Sunrise, LLC for the Sunrise/Sun-Peak Asset Bundle dated as of December 9, 2000. . *(L) Transitional Power Purchase Agreement by and between Nevada Power Company and Reliant Energy Sunrise, LLC dated as of December 9, 2000. . Credit Agreement dated as of June 24, 1999 among Nevada Power Company, Mellon Bank, N.A., First Union Bank and Wells Fargo Bank, N.A. relating to $150,000,000 credit facility (filed as Exhibit (10)(B) to Form 10-K for year ended December 31, 1999). . *(M) Amended and Restated Credit Agreement dated as of August 28, 2000 among Nevada Power Company, Mellon Bank, N.A., First Union Bank and Wells Fargo Bank, N.A. relating to $150,000,000 credit facility. . *(N) Amendment and Waiver Agreement dated as of March 1, 2001 among Nevada Power Company, Mellon Bank, N.A., First Union Bank and Wells Fargo Bank, N.A. relating to $150,000,000 credit facility. . Letter of Credit and Reimbursement Agreement dated as of October 1, 1995 among Nevada Power Company, The Banks Named Herein, and Societe Generale, Los Angeles Branch (filed as Exhibit 10.80 to Form 10-K, File No. 1-4698, Year 1995). 172 . Letter of Credit and Reimbursement Agreement dated as of October 1, 1995 among Nevada Power Company, The Banks Named Herein, and Barclays Bank PLC, New York Branch (filed as Exhibit 10.81 to Form 10-K, File No. 1-4698, Year 1995). . Letter of Credit and Reimbursement Agreement dated as of April 12, 1994 between Nevada Power Company and Societe Generale, Los Angeles Branch and Amendment No. 1 thereto dated as of May 3, 1994 (filed as Exhibit 10.72 to Form 10-K, File No. 1-4698, Year 1994). . Reimbursement Agreement dated as of November 1, 1988 between the Fuji Bank, Limited and Nevada Power Company (filed as Exhibit 10.43 to Form 10-K, File No. 1-4698, Year 1988). . Reimbursement Agreement dated as of December 1, 1985 between The Fuji Bank, Limited and Nevada Power Company (filed as Exhibit 10.38 to Form 10-K, File No. 1-4698, Year 1986). . Guaranty Agreement dated as of March 1, 1974 between Nevada Power Company and Commerce Union Bank as Trustee (filed as Exhibit 5.39 to Form 8-K, File No. 1-4698, April 1974). . *(O) Financing Agreement No. 1 between Clark County, Nevada and Nevada Power Company dated as of June 1, 2000 (Series 2000A). . *(P) Financing Agreement No. 2 between Clark County, Nevada and Nevada Power Company dated as of June 1, 2000 (Series 2000B). . Financing Agreement between Clark County, Nevada and Nevada Power Company dated November 1, 1997 (filed as Exhibit 10.83 to Form 10-K, File No. 1-4698, Year 1997). . Financing Agreement between Coconino County, Arizona Pollution Control Corporation and Nevada Power Company dated November 1, 1997 (filed as Exhibit 10.84 to Form 10-K, File No. 1-4698, Year 1997). . Financing Agreement between Coconino County, Arizona Pollution Control Corporation and Nevada Power Company dated October 1, 1996 (filed as Exhibit 10.82 to Form 10-K, File 1-4698, Year 1996). . Financing Agreement between Clark County, Nevada and Nevada Power Company dated October 1, 1995 (Series 1995A) (filed as Exhibit 10.75 to Form 10-K, File No. 1-4698, Year 1995). . Financing Agreement between Clark County, Nevada and Nevada Power Company dated October 1, 1995 (Series 1995B) (filed as Exhibit 10.76 to Form 10-K, File No. 1-4698, Year 1995). . Financing Agreement between Clark County, Nevada and Nevada Power Company dated October 1, 1995 (Series 1995C) (filed as Exhibit 10.77 to Form 10-K, File No. 1-4698, Year 1995). 173 . Financing Agreement between Clark County, Nevada and Nevada Power Company dated October 1, 1995 (Series 1995D) (filed as Exhibit 10.78 to Form 10-K, File No. 1-4698, Year 1995). . Financing Agreement between Coconino County, Arizona Pollution Control Corporation and Nevada Power Company dated October 1, 1995 (Series 1995E) (filed as Exhibit 10.79 to Form 10-K, File No. 1-4698, Year 1995). . Financing Agreement between Clark County, Nevada and Nevada Power Company dated October 1, 1992 (filed as Exhibit 10.67 to Form 10-K, File No. 1- 4698, Year 1992). . Financing Agreement between Clark County, Nevada and Nevada Power Company dated June 1, 1992 (Series 1992A) (filed as Exhibit 10.65 to Form 10-K, File No. 1-4698 (Year 1992). . Financing Agreement between Clark County, Nevada and Nevada Power Company dated June 1, 1992 (Series 1992B) (filed as Exhibit 10.66 to Form 10-K, File No. 1-4698, Year 1992). . Financing Agreement between Clark County, Nevada and Nevada Power Company dated as of November 1, 1988 (filed as Exhibit 10.42 to Form 10-K, File No. 1-4698, Year 1988). . Financing Agreement between Clark County, Nevada and Nevada Power Company dated as of December 1, 1985 (filed as Exhibit 10.37 to Form 10-K, File No. 1-4698, Year 1985). . Financing Agreement dated as of February 1, 1983 between Clark County, Nevada and Nevada Power Company (filed as Exhibit 10.36 to Form 10-K, File No. 1-4698, Year 1985). . Retention Agreement dated as of July 28, 1999 between Nevada Power Company and David G. Barneby (filed as Exhibit (10)(E) to Form 10-K for year ended December 31, 1999). . Employment Agreement dated as of March 13, 1998 between Nevada Power Company and Gloria Banks Weddle (filed as Exhibit (10)(C) to Form 10-K for year ended December 31, 1999). . Employment Agreement dated as of March 13, 1998 between Nevada Power Company and Steven W. Rigazio (filed as Exhibit (10)(D) to Form 10-K for year ended December 31, 1999). . *(Q) Plant Collective Bargaining Agreement dated February 1, 1998, effective through February 1, 2002 between Nevada Power Company and the International Brotherhood of Electrical Workers Local No. 396. . *(R) Clerical Collective Bargaining Agreement dated February 1, 1998, effective through February 1, 2002 between Nevada Power Company and the International Brotherhood of Electrical Workers Local No. 396. 174 . *(S) Generation Agreement dated as of June 25, 1999 between Nevada Power Company and the International Brotherhood of Electrical Workers Local No. 396. . Settlement Agreement and Promissory Note between Mountain Coal Company and Atlantic Richfield Company and Nevada Power Company dated March 9, 1994 (filed as Exhibit 10.71 to Form 10-K, File No. 1-4698, Year 1993). . Contract for Long-Term Power Purchases from Qualifying Facilities dated May 27, 1992 between Las Vegas Co-generation, Inc. and Nevada Power Company. (filed as Exhibit 10.70 to Form 10-K, File No. 1-4698, Year 1993). . Western Systems Power Pool Agreement ("Agreement") dated January 2, 1991 between thirty-nine other Western Systems Power Pool members as listed on pages 1 and 2 of the Agreement and Nevada Power Company (filed as Exhibit 10.61 to Form 10-K, File No. 1-4698, Year 1990). . Contract A for Long-Term Power Purchases from Qualifying Facilities dated May 2, 1989 between Nevada Cogenerational Associates #1 (assigned from Bonneville Nevada Corporation) and Nevada Power Company (filed as Exhibit 10.47 to Form 10-K, File No. 1-4698, Year 1989) . Contract B for Long-Term Power Purchases from a Qualifying Facility dated May 24, 1990 between Nevada Cogenerational Associates (assigned from Bonneville Nevada Corporation) and Nevada Power Company (filed as Exhibit 10.56 to Form 10-K, File No. 1-4698, Year 1990). . Contract for Long-Term Power Purchases from Qualifying Facilities dated April 10, 1989 between Saguaro Power Company (assigned from Magna Energy Systems and Eastern Sierra Energy Company) and Nevada Power Company (filed as Exhibit 10.48 to Form 10-K, File No. 1-4698, Year 1989). . Agreement for Transmission Service dated March 29, 1989 between Overton Power District No. 5, Lincoln County Power District No. 1 and Nevada Power Company (filed as Exhibit 10.51 to Form 10-K, File No. 1-4698, Year 1989). . Contract for Operation, Maintenance, Replacement, Ownership, and Interconnection of Facilities dated June 30, 1988 between United States Department of Energy Western Area Power Administration and Nevada Power Company (filed as Exhibit 10.52 to Form 10-K, File No. 1-4698, Year 1989). . Transmission Facilities Agreement between Utah Power & Light Company and Nevada Power Company, dated August 17, 1987 (filed as Exhibit 10.41 to Form 10-K, File No. 1-4698, Year 1987). . Contract for Sale of Electrical Energy between the State of Nevada and Nevada Power Company, dated July 8, 1987 (filed as Exhibit 10.39 to Form 10-K, File No. 1-4698, Year 1987). 175 . Sublease Agreement between Powveg Leasing Corp., as Lessor and Nevada Power Company as Lessee, dated January 11, 1984 for lease of administrative headquarters (filed as Exhibit 10.31 to Form 10-K, File No. 1-4698, Year 1983). . Participation Agreement Reid Gardner Unit No. 4 dated July 11, 1979 between Nevada Power Company and California Department of Water Resources (filed as Exhibit 5.34 to Form S-7, File No. 2-65097). . Amended Mohave Project Coal Slurry Pipeline Agreement dated May 26, 1976 between Peabody Coal Company and Black Mesa Pipeline, Inc. (Exhibit B to Exhibit 10.18) (filed as Exhibit 5.36 to Form S-7, File No. 2-56356). . Amended Mohave Project Coal Supply Agreement dated May 26, 1976 between Nevada Power Company and Southern California Edison Company, Department of Water and Power of the City of Los Angeles, Salt River Project Agricultural Improvement and Power District and the Peabody Coal Company (filed as Exhibit 5.35 to Form S-7, File No. 2-56356). . Navajo Project Co-Tenancy Agreement dated March 23, 1976 between Nevada Power Company, Arizona Public Service Company, Department of Water and Power of the City of Los Angeles, Salt River Project Agricultural Improvement and Power District, Tucson Gas & Electric Company and the United States of America (filed as Exhibit 5.31 to Form 8-K, File No. 1-4696, April 1974). . Mohave Operating Agreement dated July 6, 1970 between Nevada Power Company, Salt River Project Agricultural Improvement and Power District, Southern California Edison Company and Department of Water and Power of the City of Los Angeles (filed as Exhibit 13.26F to Form S-1, File No. 2-38314). . Navajo Project Coal Supply Agreement dated June 1, 1970 between Nevada Power Company, the United States of America, Arizona Public Service Company, Department of Water and Power of the City of Los Angeles, Salt River Project Agricultural District, Tucson Gas & Electric Company and the Peabody Coal Company (filed as Exhibit 13.27B to Form S-1, File No. 2-38314). . Eldorado System Conveyance and Co-Tenancy Agreement dated December 20, 1967 between Nevada Power Company and Salt River Project Agricultural Improvement and Power District and Southern California Edison Company (filed as Exhibit 13.30 to Form S-9, File No. 2-28348). . Mohave Project Plant Site Conveyance and Co-Tenancy Agreement dated May 29, 1967 between Nevada Power Company and Salt River Project Agricultural Improvement and Power District and Southern California Edison Company (filed as Exhibit 13.27 to Form S-9, File No. 2-28348). . *(T) Los Angeles-Nevada Power NOB to MCC500 50 MW Firm Transmission Service Agreement dated October 17, 2000 between Nevada Power Company and Department of Water and Power of the City of Los Angeles. 176 . *(U) Reliability Management System Agreement dated June 18, 1999 by and between Western Systems Coordinating Council and Nevada Power Company. Sierra Pacific Power Company . *(V) Asset Sale Agreement between Sierra Pacific Power Company and NRG Energy, Inc. dated as of October 16, 2000 for the North Valmy Asset Bundle. . *(W) Transitional Power Purchase Agreement by and between Sierra Pacific Power Company and Valmy Power LLC dated as of October 16, 2000. . *(X) Asset Sale Agreement between Sierra Pacific Power Company and WPS Northern Nevada, LLC for the Tracy/Pinon Asset Bundle dated as of October 25, 2000. . *(Y) Transitional Power Purchase Agreement by and between Sierra Pacific Power Company and WPS Northern Nevada, LLC dated as of October 25, 2000. . *(Z) Asset Purchase Agreement between Sierra Pacific Power Company and Truckee Meadows Water Authority dated as of January 15, 2001. . Credit Agreement dated as of June 24, 1999 among Sierra Pacific Power Company, Mellon Bank, N.A., First Union Bank and Wells Fargo Bank, N.A. relating to $150,000,000 credit facility (filed as Exhibit (10)(B) to Form 10-K for year ended December 31, 1999). . *(AA) Amended and Restated Credit Agreement dated as of August 28, 2000 among Sierra Pacific Power Company, Mellon Bank, N.A., First Union Bank and Wells Fargo Bank, N.A. relating to $150,000,000 credit facility. . *(BB) Amendment and Waiver Agreement dated as of March 1, 2001 among Sierra Pacific Power Company, Mellon Bank, N.A., First Union Bank and Wells Fargo Bank, N.A. relating to $150,000,000 credit facility. . Letter of Credit, Reimbursement and Security Agreement dated December 12, 1990 between Sierra Pacific Power Company and Union Bank of Switzerland relating to the Washoe County, Nevada Water Facilities Revenue Bonds (Sierra Pacific Power Company Project) Series 1990 (filed as Exhibit (10)(F) to Form 10-K for the year ended December 31, 1990). . Financing Agreement dated June 1, 1993 between Sierra Pacific Power Company and Washoe County, Nevada relating to the Washoe County, Nevada Water Facilities Refunding Revenue Bonds (Sierra Pacific Power Company Project) Series 1993A (filed as Exhibit (10) (I) to Form 10-K for the year ended December 31, 1993). . Financing Agreement dated June 1, 1993 between Sierra Pacific Power Company and Washoe County, Nevada relating to the Washoe County, Nevada Gas and Water Facilities Refunding Revenue Bonds (Sierra Pacific Power Company Project) Series 1993B (filed as Exhibit (10) (J) to Form 10-K for the year ended December 31, 1993). . First Amendment dated August 12, 1991 to Financing Agreement dated December 1, 1990 between Sierra Pacific Power Company and Washoe County, Nevada relating to the 177 Washoe County, Nevada Water Facilities Revenue Bonds (Sierra Pacific Power Company Project) Series 1990 (filed as Exhibit (10)(J) to Form 10-K for the year ended December 31, 1991). . Financing Agreement dated September 1, 1990 between Sierra Pacific Power Company and Washoe County, Nevada relating to the Washoe County, Nevada Gas Facilities Revenue Bonds (Sierra Pacific Power Company Project) Series 1990 (filed as Exhibit (10)(C) to Form 10-K for the year ended December 31, 1990). . Financing Agreement dated September 1, 1990 between Sierra Pacific Power Company and Washoe County, Nevada relating to the Washoe County, Nevada Water Facilities Revenue Bonds (Sierra Pacific Power Company Project) Series 1990 (filed as Exhibit (10)(E) to Form 10-K for the year ended December 31, 1990). . Financing Agreement dated December 1, 1987 between Sierra Pacific Power Company and Washoe County, Nevada relating to the Washoe County, Nevada Variable Rate Demand Gas Facilities Revenue Bonds (Sierra Pacific Power Company Project) Series 1987 (filed as Exhibit (10)(H) to Form 10-K for the year ended December 31, 1993). . Financing Agreement dated June 1, 1987 between Sierra Pacific Power Company and Washoe County, Nevada relating to the Washoe County, Nevada Variable Rate Demand Water Facilities Revenue Bonds (Sierra Pacific Power Company Project) Series 1987 (filed as Exhibit (10)(G) to Form 10-K for the year ended December 31, 1993). . Financing Agreement dated March 1, 1987 between Sierra Pacific Power Company and Humboldt County, Nevada relating to the Humboldt County, Nevada Variable Rate Demand Pollution Control Refunding Revenue Bonds (Sierra Pacific Power Company Project) Series 1987 (filed as Exhibit (10)(E) to Form 10-K for the year ended December 31, 1993). . Financing Agreement dated March 1, 1987 between Sierra Pacific Power Company and Washoe County, Nevada relating to the Washoe County, Nevada Variable Rate Demand Gas and Water Facilities Refunding Revenue Bonds (Sierra Pacific Power Company Project) Series 1987 (filed as Exhibit (10)(F) to Form 10-K for the year ended December 31, 1993). . Agreement dated January 1, 1998 (extended through December 31, 2002) between Sierra Pacific Power Company and the International Brotherhood of Electrical Workers Local No. 1245 (filed as Exhibit 10(B) to Form 10-K for the year ended December 31, 1997). . Transition Property Purchase and Sale Agreement dated as of April 9, 1999 between Sierra Pacific Power Company and SPPC Funding LLC in connection with the issuance of California rate reduction bonds (filed as Exhibit 10(B) to Form 10-K for the year ended December 31, 1999). . Transition Property Servicing Agreement dated as of April 9, 1999 between Sierra Pacific Power Company and SPPC Funding LLC in connection with the issuance of California rate reduction bonds (filed as Exhibit 10(C) to Form 10-K for the year ended December 31, 1999). 178 . Administrative Services Agreement dated as of April 9, 1999 between Sierra Pacific Power Company and SPPC Funding LLC in connection with the issuance of California rate reduction bonds (filed as Exhibit 10(D) to Form 10-K for the year ended December 31, 1999). . Addendum dated October 9, 1993 to Rail Transportation Contract dated June 30, 1986 between Sierra Pacific Power Company and Idaho Power Company as shippers and Union Pacific Railroad Companies as carriers (filed as Exhibit (10)(D) to Form 10-K for the year ended December 31, 1993). . Cooperative Agreement dated July 31, 1992 between Sierra Pacific Power Company and the United States Department of Energy in connection with the Pinon Pine Integrated Coal Gasification Combined Cycle Project (filed as Exhibit (10)(H) to Form 10-K for the year ended December 31, 1992). . Settlement Agreement and Mutual Release dated May 8, 1992 between Sierra Pacific Power Company and Coastal States Energy Company (filed as Exhibit (10)(D) to Form 10-K for the year ended December 31, 1992; confidential portions omitted and filed separately with the Securities and Exchange Commission). . Letter of Amendment dated May 18, 1987 to Lease dated January 30, 1986 between Sierra Pacific Power Company and Silliman Associates Limited Partnership relating to the Company's corporate headquarters building (filed as Exhibit (10) (K) to Form 10-K for the year ended December 31, 1993). . General Transfer Agreement dated February 25, 1988 between Sierra Pacific Power Company and the United States of America Department of Energy acting by and through the Bonneville Power Administration (filed as Exhibit (10)(E) to Form 10-K for the year ended December 31, 1988). . Rail Transportation Contract dated June 30, 1986 between Sierra Pacific Power Company and Idaho Power Company as shippers and Union Pacific and Western Pacific Railroad Companies as carriers (filed as Exhibit (10)(C) to Form 10-K for the year ended December 31, 1993). . Coal Purchase Contract dated June 19, 1986 between Sierra Pacific Power Company, Black Butte Coal Company and Idaho Power Company (filed as Exhibit (10)(C) to the Form 10-K for the year ended December 31, 1992). . Lease dated January 30, 1986 between Sierra Pacific Power Company and Silliman Associates Limited Partnership relating to the Company's corporate headquarters building (filed as Exhibit (10)(I) to Form 10-K for the year ended December 31, 1992). . Interconnection Agreement dated May 29, 1981 between Sierra Pacific Power Company and Idaho Power Company (filed as Exhibit (10)(C) to Form 10-K for the year ended December 31, 1991). . Amendatory Agreement dated February 14, 1992 to Interconnection Agreement dated May 29, 1981 between Sierra Pacific Power Company and Idaho Power Company (filed as Exhibit (10)(D) to Form 10-K for the year ended December 31, 1991). 179 . Coal Sales Agreement dated May 16, 1978 between Sierra Pacific Power Company and Coastal States Energy Company (confidential portions omitted and filed separately with the Securities and Exchange Commission) (filed as Exhibit 5-GG to Registration No. 2-62476). . Amendment No. 1 dated November 8, 1983 to Coal Sales Agreement dated May 16, 1978 between Sierra Pacific Power Company and Coastal States Energy Company (filed as Exhibit (10)(B) to Form 10-K for the year ended December 31, 1991). . Amendment No. 2 dated February 25, 1987 to Coal Sales Agreement dated May 16, 1978 between Sierra Pacific Power Company and Coastal States Energy Company (filed as Exhibit (10)(A) to Form 10-K for the year ended December 31, 1993). . Amendment No. 3 dated May 8, 1992 to Coal Sales Agreement dated May 16, 1978 between Sierra Pacific Power Company and Coastal States Energy Company (filed as Exhibit (10)(B) to Form 10-K for the year ended December 31, 1992; confidential portions omitted and filed separately with the Securities and Exchange Commission). (11) Nevada Power Company and Sierra Pacific Power Company . Nevada Power Company and Sierra Pacific Power Company are wholly owned subsidiaries and, in accordance with Paragraph 6 of SFAS No. 128 (Earnings Per Share), earnings per share data have been omitted. (12) Sierra Pacific Resources . *(A) Statement regarding computation of Ratios of Earnings to Fixed Charges. Nevada Power Company . *(B) Statement regarding computation of Ratios of Earnings to Fixed Charges. Sierra Pacific Power Company . *(C) Statement regarding computation of Ratios of Earnings to Fixed Charges. (21) Sierra Pacific Resources . Nevada Power Company, a Nevada Corporation. Sierra Pacific Power Company, a Nevada Corporation. Lands of Sierra, Inc., a Nevada Corporation. Sierra Energy Corporation, a Nevada Corporation. Tuscarora Gas Pipeline Company, a Nevada Corporation. Sierra Water Development Company, a Nevada Corporation. Sierra Pacific Resources Capital Trust I, a Delaware business trust. Sierra Pacific Resources Capital Trust II, a Delaware business trust. 180 Nevada Power Company . Nevada Electric Investment Company, a Nevada Corporation. NVP Capital I, a Delaware Business Trust. NVP Capital II, a Delaware Business Trust. Sierra Pacific Power Company . Pinon Pine Company, a Nevada Corporation. Pinon Pine Investment Company, a Nevada Corporation. GPSF-B, a Delaware Corporation. SPPC Funding LLC, a Delaware Limited Liability Company. Sierra Pacific Power Capital Trust I, a Delaware Business Trust. (23) Sierra Pacific Resources . *(A) Consent of Independent Accountants in connection with the Sierra Pacific Resources' Registration Statements No. 333-77523 (Common Stock Investment Plan) on Form S-3, No. 333-92651 (Employees' Stock Ownership Plan, Executive Long-Term Incentive Plan, and Non-Employee Director Stock Plan) on Forms S-8, and No. 333-80149 (8-3/4% Notes Due 2005) on Form S-3. (99) Sierra Pacific Resources, Nevada Power Company, Sierra Pacific Power Company . Comprehensive Energy Plan dated January 29, 2001 (filed as Exhibit 99.2 to Form 8-K dated February 1, 2001). 181