10-K405 1 d10k405.txt FORM 10-K405 ================================================================================ 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, 2001 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: ------------------------------------------ Class A Preferred Stock, Series I, $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 15, 2002: $ 1,665,622,642 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 15, 2002: 102,110,536 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 Sierra Pacific Resources' definitive proxy statement to be filed in connection with the annual meeting of shareholders, to be held May 6, 2002, 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 ON FORM 10-K CONTENTS PART I ...................................................................................................... 3 Item 1. Business .......................................................................................... 3 Sierra Pacific Resources .... ............................................................................ 3 Nevada Power Company ........ ............................................................................ 5 Sierra Pacific Power Company ............................................................................. 14 Item 2. Properties ........................................................................................ 32 Item 3. Legal Proceedings ................................................................................. 33 Item 4. Submission Of Matters To A Vote Of Security Holders ............................................... 33 PART II ..................................................................................................... 34 Item 5. Market For The Registrant's Common Stock And Related Stockholder Matters .......................... 34 Item 6. Selected Financial Data ........................................................................... 36 Item 7. Management's Discussion And Analysis Of Financial Condition And Results Of Operations ............. 38 Sierra Pacific Resources ................................................................................. 43 Nevada Power Company ..................................................................................... 50 Sierra Pacific Power Company ............................................................................. 57 Item 7A. Quantitative and Qualitative Disclosures About Market Risk ...................................... 79 Item 8. Financial Statements and Supplementary Data ....................................................... 82 Notes to Financial Statements ............................................................................ 100 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure .............. 148 PART III .................................................................................................... 149 Item 10. Directors and Executive Officers of the Registrant .............................................. 149 Item 11. Executive compensation .......................................................................... 155 Item 12. Security Ownership of Certain Beneficial Owners and Management .................................. 161 Item 13. Certain Relationships and Related Transactions .................................................. 162 PART IV ..................................................................................................... 166 Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K ................................. 166 Signatures .................................................................................................. 168
2 FORWARD LOOKING STATEMENTS The discussion of forward looking statements in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operation, is incorporated herein by reference. 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 (NPC), 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). NPC and SPPC are referred to together in this report as the "Utilities". AN EXPLANATION OF THE REPORTING FORMAT The merger between SPR and NPC 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, NPC was considered the acquiring entity under Accounting Principles Board Opinion No. 16, Business Combinations, even though SPR became the legal parent of NPC. Because of this accounting treatment, the financial information for the year ended December 31, 1999 reflects the acquisition of SPR by NPC on August 1, 1999. Therefore, the results of operations for that year reflect twelve months of information for NPC 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 (NPC and SPPC) --------------------------------------------------------------------- Electric Utility Trends The year 2001 was challenging and unpredictable for the electric utility industry, marked by volatile and uncharacteristic power prices, deterioration in the credit quality of a number of utilities and power merchants, bankruptcy of a major California utility and a major Houston based energy trading company, and increased involvement and oversight by government and regulators. Dramatic increases in wholesale power prices that began in 2000 continued into the first half of 2001, particularly in the West. Rolling blackouts occurred in California. Wholesale energy prices in the West peaked in the spring at levels up to four times what they were in the prior year. While continuing blackouts and high power prices were predicted in the second half of the year, they did not materialize. Instead, power prices moderated largely because of mild weather across the United States, lower natural gas prices, conservation in California, and the imposition by the FERC of federal price caps in California and eleven western states, 3 including Nevada (see Regulation and Rate Proceedings, FERC Matters in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations). Remaining as a result of this energy price volatility is a long list of policy, regulatory, business and financial issues, many of which are being addressed at both state and federal levels. California continues to influence the region. In California, continued high prices during the first half of the year and the lack of adequate rate relief led to an inability to purchase energy, and credit problems and defaults for the state's three largest utilities. In April 2001, Pacific Gas & Electric Company filed for bankruptcy. The State of California took on the role of energy buyer through its Department of Water Resources and funded billions of dollars for short and long-term energy purchases which it plans to fund through the issuance of bonds. While California's regulatory and policy issues are specific to California, the state's problems exacerbated western energy problems and left a mark throughout the region as western states continue to struggle with the question of who should pay large fuel and purchased power balances. Like other utilities in the West, the Utilities, which operate principally in Nevada, have been significantly impacted by increased wholesale prices. High fuel and power costs have led to large financing requirements, liquidity constraints and depressed earnings. In Nevada, emergency legislation, Assembly Bill (AB) 369, was enacted in April 2001 to control volatility in the price of retail electricity in Nevada and to ensure the Utilities the financial resources to provide adequate and reliable electric service. To achieve these purposes, AB 369 allows the Utilities to recover in future periods their costs for wholesale power and fuel, subject to regulatory review for prudency. NPC filed for recovery of deferred energy balances on December 1, 2001 and SPPC filed for recovery of deferred energy balances on February 1, 2002. The businesses of SPR, NPC, and SPPC are substantially dependent upon the outcomes of these proceedings. See Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations for further legislative and regulatory discussions. Also in December, the Utilities filed an action under Section 206 of the Federal Power Act seeking a rollback of wholesale power prices and refunds. High energy prices, power shortages, and a push at state and federal levels for increased supply resulted in an unprecedented number of new power plant project announcements nationally and in Nevada - mostly unregulated and mostly natural gas-fired. Some power plants have been built or are under construction. NPC is constructing transmission facilities to interconnect new merchant plants being built in southern Nevada (see Nevada Power Company, Transmission, for a discussion of the Centennial Plan). Towards year-end, a weakening economy, lower demand, and a decline in energy prices have caused power plant builders to reconsider planned projects. Some have announced downsizings or cancellations. In addition, falling energy prices and pressure from the major credit rating agencies have caused the announcement of a number of asset sales. In Nevada, the Utilities' divestiture of generation assets, which the PUCN had previously ordered, was halted by the provisions of AB 369 that prohibit the sale of generation assets until July 2003. Additionally, in April 2001, SPR and Enron Corporation (Enron) mutually agreed to the termination of their agreement for SPR's purchase of Enron's wholly owned subsidiary, Portland General Electric (PGE), headquartered in Portland, Oregon. National energy policy is also undergoing change due to the events of 2000 and 2001. The President's National Energy Policy Report was issued in May 2001. Recently, Senate Bill (SB) 517 addressed the Public Utility Holding Company Act (PUHCA) repeal and the Public Utility Regulatory Policies Act (PURPA) reform, some FERC provisions, reliability, utility mergers, open access transmission, net metering and interconnection. Senate action on the bill is pending. 4 Regulation and Electric Restructuring The transition to retail competition continues to be highly uncertain, driven by the development of a relatively young wholesale market and the different approaches to retail competition taken by state regulators and legislators. Rising wholesale prices, the western energy crisis, and the recent bankruptcy filings of Pacific Gas & Electric Company and Enron have led many states to review or revise restructuring plans. While deregulation has been suspended in some states, in other states, the process has slowed. In Nevada, AB 369, which became law in April 2001, repealed all statutes authorizing retail competition in Nevada's electric utility industry and voided any license issued to alternative sellers in connection with retail competition. AB 661, passed in July 2001, enables large customers with demand of one megawatt (MW) or more to choose a new energy supplier beginning mid-2002 with permission from the PUCN upon meeting public interest tests. Remaining committed to regional transmission organization development and power competition, FERC plans to propose electric market design rules and issue a final ruling by year-end 2002. Also, FERC recently approved the nation's first regional transmission organization in the Midwest. NEVADA POWER COMPANY -------------------- NPC is a Nevada corporation organized in 1921. NPC became a wholly owned subsidiary of SPR on July 28, 1999. Its mailing address is 6226 West Sahara Avenue, Las Vegas, Nevada 89146. NPC 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 639,000 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. Business and Competitive Environment NPC's electric business contributed 100% of its 2001 operating revenues of $3.025 billion. The system has an annual load factor of approximately 49.0%, which is slightly lower than the industry norm of 50% to 55%. Summer peak loads are driven by air conditioning demand. NPC's peak load increased an average of 5.8% annually over the past five years, reaching 4,412 MW on July 2, 2001. NPC's total electric megawatt-hour (MWh) sales have increased an average of 5.8% 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. NPC's service territory continues to be one of the fastest growing areas in the nation. A significant part of the growth in NPC's electric sales has resulted from new residential, industrial, and gaming customers. NPC's electric customers by class contributed the following toward 2001 and 2000 MWh sales: 5
MWh Sales (Billed and Unbilled) 2001 2000 ------------------------ ------------------------- Residential 7,208,540 25.5% 7,035,488 36.2% Office 1,986,752 7.1% 1,896,111 9.7% Gaming/Recreation/Restaurants 3,903,478 13.8% 3,963,286 20.4% Wholesale 11,051,000 39.1% 2,675,484 13.8% Other Retail 825,882 2.9% 783,467 4.0% All Other & Unclassified 3,276,724 11.6% 3,101,564 15.9% ----------- ------ ------------ ------ TOTAL 28,252,376 100.0% 19,455,400 100.0% =========== ====== ============ ======
Tourism and gaming remain southern Nevada's premier industries. Over 35 million tourists visited Las Vegas in 2001, infusing approximately $19.8 billion into the local economy during the year. Currently, Las Vegas is the home of 18 of the world's 20 largest hotels. No mega-resort properties are scheduled to open during 2002. Hotel room growth is expected to be just 0.8% during 2002. The Las Vegas Convention Center has recently completed a $150 million expansion project, adding 918,000 square feet of exhibit space and 90,000 square feet of meeting space. The Las Vegas Convention Center now has more than 3.2 million square feet of total space, and features approximately 2 million square feet of net exhibit space, and 380,000 square feet of net meeting room space, accommodating 170 meeting rooms with seating capacities from 20 to 7,500. In 2001, more than 4.0 million convention and trade show delegates traveled to Las Vegas, generating more than $4.8 billion in non-gaming revenue. Shortly after the terrorist attacks of September 11, 2001, an estimated 12,000-15,000 gaming industry employees were laid off due to an expected decrease in tourism revenue. In October 2001, many of these employees were recalled, although some of them only on a part-time or on-call basis. Although tourist traffic is not back to its previous levels, an upward trend has been realized since early October 2001. During 2001, firm and non-firm sales to wholesale customers comprised 39.1% of total energy sales, an increase of 310.0% over the prior year. Wholesale customers consist of other utilities or municipalities that sell power to end users, marketing entities and others that exchange power with NPC.
Wholesale MWh Sales 2001 2000 ----------------------- --------------------- Firm Sales 159,707 1.45% 283,480 10.52% Non-Firm Sales 10,891,293 98.55% 2,412,442 89.48% ---------- ------ --------- ------ Total 11,051,000 100.00% 2,695,922 100.00% ========== ====== ========= ======
NPC's increase in wholesale MWh sales from last year was a result of market conditions and NPC's power procurement activities. See Purchased Power Procurement in Item 7, Management's Discussion And Analysis Of Financial Condition And Results Of Operations, for a discussion of the Utilities' purchased power procurement strategies. Construction Program NPC'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 6 costs, availability of fuel types, the number and status of proposed independent generation projects, the need for additional transmission capacity in southern Nevada, changes in environmental regulations, adequacy of rate relief, and NPC's ability to raise necessary capital. Gross construction expenditures for 2001, including allowance for funds used during construction (AFUDC) and contributions in aid of construction, were 200.9 million, and for the period 1997 through 2001, were $1,155.6 million. Estimated construction expenditures for 2002 and the period from 2003 to 2006 are as follows (dollars in thousands):
2002 2003-2006 Total 5-Year ------------- ---------------- ----------------- Total construction expenditures $ 328,435 $ 862,661 1,191,096 AFUDC (8,699) (20,813) (29,512) Net salvage, including cost of removal (1,034) (4,140) (5,174) Net customer advances and contributions in aid of construction (7,602) (30,408) (38,010) ------------- -------------- ------------- Total cash requirements $ 311,100 $ 807,300 1,118,400 ============= ============== =============
Total construction expenditures estimated for 2002 and the 2003-2006 period consist of the following (dollars in thousands):
Total 2002 2003-2006 5-Year ----------------------------------------------- Electric Facilities: Distribution $128,436 $543,543 $ 671,979 Generation 26,027 53,392 79,419 Transmission 156,220 225,575 381,795 Other 17,752 40,151 57,903 --------------------------------------------- $328,435 $862,661 $1,191,096 =============================================
The River Mountain Project is a 230kV (kilovolt) joint transmission project with the Colorado River Commission. Total project costs incurred through December 31, 2001, were approximately $34.0 million. Actual costs for 2001 were $7.7 million. This project was completed in 2001 and was in service in June of 2001. The Centennial Plan was approved in NPC's 2001 Refiled Resource Plan. This plan, consistent with its tariff and FERC pricing policies, involves the following 500 kV lines (1) the Harry Allen substation to Crystal substation 500 kV lines, (2) the Harry Allen substation to Northwest substation 500 kV line, and (3) the Harry Allen substation to Mead substation 500 kV line. Additional facilities include a new 500 kV substation at Harry Allen, 500/230 kV transformer at Mead and Northwest substation, phase shifting transformer at Crystal substation, and several other sub-transmission upgrades and additions. Total estimated cost of the project is $296.2 million. Total project actual costs incurred through December 31, 2001, were $20.1 million. Estimated costs for 2002 are $131.1 million, which may be financed utilizing internally generated cash and/or the proceeds from various forms of debt. See Transmission, later, for additional information about the Centennial Plan. 7 Facilities and Operations Total System NPC maintains a wide variety of resources in its generation system. The availability of alternate resources allows NPC to dispatch its electric generation system in a more cost-effective manner under varying operating and fuel market conditions, while maintaining system integrity. NPC also supplies its customers' electric power needs using a combination of firm and interruptible resources to maximize operating flexibility, while minimizing cost. During 2001, NPC generated 33.9% of its total electric energy requirements in its own plants, purchasing the remaining 66.1% as shown below: Megawatt- Percent Hours of Total ----------------- --------------- NPC Company Generation ---------------------- Gas/Oil 4,206,728 14.4% Coal 5,692,467 19.5% ----------------- --------------- Total Generated 9,899,195 33.9% ----------------- --------------- Purchased Power --------------- Hydro 544,772 1.9% Non-Firm Purchases 274,278 0.9% Short Term Firm and Spot Purchases 16,058,378 55.1% Non-Utility Purchases 2,390,877 8.2% ----------------- --------------- Total Purchased 19,268,305 66.1% ----------------- --------------- Total 29,167,500 100.0% ================= =============== NPC's decision to purchase short-term and spot energy in lieu of its own generation is based on the economics of purchasing "as-available" energy when it is less expensive than its own generation. NPC's 2001 company generation of 9,899,195 MWh is down 7.9% from NPC's 2000 company generation of 10,744,466 MWh due to decreased generation late in 2001 when the cost of purchased power was more economical than generation. NPC's 2001 purchased power of 19,268,305 MWh is up 99.5% from NPC's 2000 purchased power of 9,659,118 MWh. Risk Management See Item 7A, Quantitative and Qualitative Disclosures About Market Risk. Load and Resources Forecast NPC's electric customer growth rate was 4.5% in 2001, 5.1% in 2000, and 5.9% in 1999. Retail electricity sales were 17.2 million MWh in 2001, which represents an increase of 2.4% over 2000 retail electricity sales of 16.8 million MWh. Wholesale electricity sales reached 11.1 million MWh in 2001, which represents an increase of 313% over 2000 wholesale electricity sales of 2.7 million MWh. Overall, annual system electricity sales reached 28.3 million MWh in 2001, which represents an increase of 45% over 2000 system electricity sales of 19.5 million MWh. The bulk of the 45% increase is attributed to wholesale sales. Changes in the wholesale market have dramatically increased the amount of purchases and sales of wholesale 8 power. See Purchased Power Procurement in Item 7, Management's Discussion And Analysis Of Financial Condition And Results Of Operations, for a discussion of the Utilities' purchased power procurement strategies. NPC's peak electric demand rose to 4,412 MW in 2001 from 4,325 MW in 2000. The forecasted peak energy demand for 2002 and 2003 below reflects, among others, five key assumptions: . Southern Nevada experiences normal weather conditions, based on historical 20-year averages. . No adjustments have been made to incorporate the potential loss of customers leaving for alternative providers under the provisions of AB 661 or Senate Bill 211, which allows the Colorado River Commission to sell electricity to its purveyors of water for water pumping electric-related loads only. However, four large commercial customers of NPC have filed an application under the provisions of AB 661 to procure energy from an alternative source other than the Utility and one large commercial customer has filed a letter of intent to file an application to procure energy from an alternative source. The combined peak load of AB 661 notice of intent customers and SB 211 eligible customers is less than 10% of NPC's retail load. . Retail electric rates are set at the levels requested in NPC's most recent general and deferred energy rate case filings. . The southern Nevada economy recovers from the effects of the September 11, 2001, terrorist attacks by the fourth quarter of 2002. . Concerns over power outages in California subside by summer 2002 resulting in reduced conservation efforts by NPC's customers. Sales and peak energy demand will vary from forecasted levels to the extent that actual experience varies from the above assumptions and to the extent that other factors affect sales and demand. NPC's actual total system capability and peak loads for 2001, and as estimated for summer peak demand for 2002 and 2003 are shown below: 9
Capacity at 2001 Peak Forecast Summer Peak (2) ------------------------------------------------------------------ MW % 2002 2003 ------------------------------------------------------------------ NPC Company Generation: Existing 1,559 32% 1,937 1,937 ------------------------------------------------------------------ Purchases Long/Short-Term Firm (1) 2,492 51% 2,022 1,572 Non-Utility Generators (2) 504 10% 515 515 Wholesale (3) (107) (2%) (114) (119) ------------------------------------------------------------------ Subtotal 2,889 59% 2,423 1,968 ------------------------------------------------------------------ Additional Required (4) 449 9% 889 1,557 Total System Capacity 4,897 100% 5,249 5,462 ================================================================== Net System Peak (5) 4,412 90% 4,687 4,877 Planning Reserves 485 10% 562 585 ------------------------------------------------------------------ Total Requirement 4,897 100% 5,249 5,462 ================================================================== Growth over previous year 7.2% 4.1%
(1) Long-term purchases include NPC's allotment of Hoover Dam energy. Values are net of losses. (2) Includes Sunpeak units. (3) On peak wholesale commitment to Silver State Power Pool (SSPP). Generation and purchases are reduced by the amount of load serving SSPP to show remaining resources to meet the system peak. (4) Includes potential short-term firm purchases that are not under contract. Values shown represent purchases within existing transmission system limits. (5) The system peak shown for 2001 is the actual system peak of 4,412 MW, which occurred on July 2, 2001. NPC 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 adequate reserve margin consistent with the WSCC planning reserve criteria. These additional reserves will be met, if needed, with short-term purchases through 2003 to the extent available. Generation The following is a list of NPC's share of generation plants (except Reid Gardner No. 4, see note (2) below), including the MW summer net capacity, the type and fuel used to generate, and the year(s) that the unit(s) was (were) installed. 10
Number of MW Name Type Fuel Units Capacity Years(s) Installed ----------------------------------------------------------------------------------------------------------- Clark Station Steam Gas/Oil 3 175 1955, 1957, 1961 Combustion Turbine Gas/Oil 1 50 1973 Combined Cycles (1) Gas/Oil 6 462 1979, 1979, 1980, 1982, 1993, 1994 ----------------------- Total Clark Station 10 687 Reid Gardner (2) Steam Coal 4 605 1965, 1968, 1976, 1983 Navajo (3) Steam Coal 3 255 1974 Mohave (4) 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 NPC 22 1964 =======================
(1) The combined cycles at Clark Station each consist of one steam turbine and two combustion turbines for a total of six generating units. (2) Reid Gardner Unit No. 4 is jointly owned by the California Department of Water Resources ("CDWR") (67.8%) and NPC (32.2%). NPC is the operating agent. Contractually, NPC is entitled to receive 24 MW of base load capacity and 226 MW of peaking capacity. NPC 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. (3) This represents NPC's 11.3% undivided interest in the Navajo Generating Station as tenant in common without right of partition with five other non-affiliated utilities. (4) This represents NPC'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. Purchased Power NPC utilizes and maintains a diverse portfolio of resources with the objective of minimizing its net average system operating costs while providing reliable service. This portfolio consists of contracted and spot market supplies, as well as its own generation. During the past several years, including the first half of 2001, NPC experienced a dramatic increase in the market price of energy. Some of this increase reflects an overall increase in electricity costs throughout the country, the changing of regulatory environments, and the opening of new and/or deregulated markets. However, costs for contracted and spot market energy supplies fell dramatically in the second half of 2001 and limited NPC's ability to mitigate previous purchase power costs by selling any short-term excess energy because it limited the price at which NPC could sell surplus energy during market shortages. Some of NPC's purchased power contracts are also at price levels above which NPC is permitted to recover in current rates. See Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, for a discussion of deferred energy accounting and legislation. NPC is a member of the Western Systems Power Pool and the Southwest Reserve Sharing Group (SRSG). NPC's membership in the SRSG has allowed it to network with other utilities in an effort to use its resources more efficiently in the sharing of responsibilities for reserves. NPC purchases both forward firm energy (typically in blocks) and spot market energy based on economics, operating reserve margins and unit availability. NPC seeks to manage its growing loads efficiently by utilizing its generation resources in conjunction with buying and selling opportunities in the market. 11 NPC 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. NPC's allocation of hydro-electric capacity is 235 MW. NPC has a contract to purchase 222 MW 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 PURPA, NPC 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, 2001, NPC had a total of 305 MW of contractual firm capacity under contract with four QFs. All QF contracts currently delivering power to NPC at long-term rates have been approved by the PUCN and have QF status as approved by the FERC. The QFs are as follows: Net Qualifying Facility Contract Contract Capacity 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 NPC from the QFs constituted 29.1% of the net purchased power requirements (excluding wholesale purchases), and 13.2% of the net system requirements during 2001. All of the QFs are cogenerators providing steam for various products and businesses. Transmission NPC's existing transmission lines are primarily confined within Clark County, Nevada. Four 230kV transmission lines connect NPC to the Western Area Power Administration's transmission facilities at Henderson and Mead Substations. Three 230 kV lines connect NPC to the Los Angeles Department of Water and Power's transmission facilities at McCullough Substation. A 345 kV line connects NPC to PacifiCorp at the Utah-Nevada state line. Also, NPC has two 500/230 kV transformers that connect NPC to the Navajo Transmission System at the Crystal Substation. Finally, NPC also has ownership rights in two 500 kV transmission lines that allow for the transmittal of NPC's share of power from its interests in the Mohave and Navajo Generating Stations to NPC's systems. The River Mountain Project is a transmission project developed in partnership with the Colorado River Commission of Nevada that was placed in service in June 2001. NPC's portion of the project consists of two 230 kV transmission lines built along separate transmission corridors between the Mead Substation and NPC's new Equestrian Substation. In addition, to facilitate the ability to deliver power scheduled between Mead Substation and Equestrian Substation, NPC built a 230 kV transmission line between the Equestrian Substation and the Faulkner Substation. The project increased import capability by 350 MW. The completed project costs were approximately $34.0 million. 12 NPC received approval from the PUCN to construct two transmission projects proposed in NPC's 2001 Refiled 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, NPC reinforcements with 2003 and 2004 in-service dates, respectively. Due to independent power producer (IPP) transmission service requests, the Arden-Tolson 230 kV upgrade project will be advanced one year for an in-service date of June 2003. The Faulkner-Tolson 230 kV project will increase NPC's import capability by 300 MW. The total estimated project costs are $8.29 million. Due to the supply shortage in the western United States, several IPP's have proposed the construction of new generating plants in southern Nevada, and have requested transmission service from NPC. NPC has committed to construct this transmission infrastructure in furtherance of its on-going business plan. NPC has proposed the Centennial Plan to address transmission service requests from these IPP's. The Centennial Plan was approved in NPC's 2001 Refiled Resource Plan. This plan, consistent with its tariff and FERC pricing policies, involves the following lines (1) the Harry Allen substation to Crystal substation 500 kV line, (2) the Harry Allen substation to Northwest substation 500 kV line, (3) the Harry Allen substation to Mead substation 500 kV line and (4) Two Bighorn-Arden 230 kV lines. Additional facilities include a new 500 kV substation at Harry Allen, 500/230 kV transformers at Mead and Northwest substation, a phase shifting transformer at Crystal substation, and several other sub-transmission upgrades and additions. See Regulation and Rate Proceedings, FERC Matters in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations for a discussion of regional transmission issues. Fuel Availability NPC's 2001 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 1997 - 2001, 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 ------- ------- ------- ------- ------- ------- 2001 5.34 42.6% 1.26 57.3% 7.14 0.1% 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 * * 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. 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. NPC'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 were scheduled for 2001 and NPC replaced these volumes with spot market purchases. 13 The mine remains sealed and NPC does not anticipate that deliveries will resume before the contract terminates. 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, 2004. The Utah Railway contract originates the remainder of NPC's Price, Utah area supplies. This contract has been extended through December 31, 2002. All of NPC'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. NPC 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. NPC has entered into a summer seasonal transportation contract for 50,000 decatherms (Dth)/day and an annual contract for 75,000 Dth/day of Kern River Pipeline capacity. This service is scheduled for delivery in May 2003 and will run for a period of 15 years. NPC also responded to an open season for shorter term service in the Kern River California Emergency Expansion and was awarded 29,600 Dth/day for the period July 2001 to April 2002 and 5,600 Dth/day for the period May 2002 to April 2003. The Emergency Expansion service does not carry any renewal rights. 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 in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations. 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 315,000 customers in a 50,000 square mile service area in 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. In 2001, electric revenues were 90.6% of SPPC's revenue. 14 SPPC also provides natural gas service in Nevada to approximately 119,500 customers in an area of about 600 square miles in Reno/Sparks and environs. In 2001, natural gas revenues were 9.4% of SPPC's revenues. On June 11, 2001, SPPC completed the sale of its water business to the Truckee Meadows Water Authority (TMWA) for $341 million. SPPC recorded a $25.8 million gain on the sale, net of income taxes of $18.2 million. Transfer of the hydroelectric facilities included in the contract of sale for an additional $8 million will require action by the California Public Utility Commission (CPUC). The sale agreement contemplates a second closing for the hydroelectric facilities to accommodate the CPUC's review of the transaction. See "Sale of Water Business," later, for further discussion. SPPC has three primary, wholly owned subsidiaries: GPSF-B, Pinon Pine Corp. (PPC) and Pinon Pine Investment Co. (PPIC). 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. (See Note 5 to the Financial Statements.) Business and Competitive Environment In 2001, SPPC's electric business contributed $1,399 million (90.6%) in revenues from continuing operations. The electric system peak typically occurs in the summer, while the winter peak runs nearly as high. The system has an annual load factor of approximately 71%, 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 4.6% annually over the past five years, reaching 1,529 MW on August 7, 2001. SPPC's total electric MWh sales have increased an average of 10.3% 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 2001 and 2000 MWh sales:
MWh Sales 2001 2000 -------------------------- ---------------------------- Residential 2,069,140 16.1% 2,042,704 16.4% Commercial and Industrial: Mining 2,662,763 20.7% 2,720,018 21.9% Offices/Schools/Government 1,141,861 8.9% 1,108,988 8.9% Resorts & Recreation 689,861 5.4% 780,526 6.3% Manufacturing/Warehouse 769,053 5.9% 795,728 6.4% Wholesale 4,123,513 32.1% 3,613,996 29.1% All Other 1,408,456 10.9% 1,372,701 11.0% ----------- ------ ------------ ------ Total 12,864,647 100.0% 12,434,661 100.0% =========== ====== ============ ======
According to the Nevada Division of Minerals, the State led the nation in the production of gold in 2001, as it has for many years. Nevada's gold production in 2001 reached 8.1 million ounces. However, in 2001 the industry continued to be challenged by low gold prices and numerous financial, environmental, and regulatory hurdles. It responded to these pressures by continuing to pursue mergers and consolidations, streamlining 15 operations, cutting overhead costs, and closing down less efficient and uneconomic properties. These actions led to SPPC seeing a small decrease in total MWh sales to the mining industry during 2001. SPPC has long-term power sales agreements with seven of its major mining customers for terms ranging from 5 to 15 years. The final contract expires in 2011. These agreements secure over 265 MW of present and future mining load, or approximately $96 million in annual revenues, which is 6.9% of 2001 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. The resorts and recreation customer segment consists of hotels, casinos and ski resorts which comprise 5.4% of the total electric system retail MWh sales. Overall MWh sales are slightly down from 2000 due to implementation of energy conservation efforts at most of the large casino hotels and a winter that has provided an increase in precipitation. The snowfall has decreased the need for the ski resorts to use their snowmaking equipment which is a large component of their energy consumption. Tourism and gaming were affected by the decrease in flight schedules and the economy downturn last September. Northern Nevada casinos have also seen some impact from Indian gaming in northern California. Though the tourism and gaming segment faced challenges in 2001, northern Nevada continues to be a strong player in the entertainment industry. Northern Nevada casino hotels are continuously focusing on competitive strategies by packaging entertainment value, customer comfort and reasonable pricing with the natural attraction of the Sierra Nevada geographical location which has proven to be a successful model. Many of the larger casinos have also remodeled their facilities to provide for an increased demand for conventions. The manufacturing and warehousing customer segment overall continues to grow at a steady pace. Several manufacturing customers have suffered large order reductions and production losses due to the economic slowdown, which has had an impact on the rapid growth projections. At the same time, there has been growth in the sector as the result of manufacturers relocating out of the California market and expanding their Nevada presence. Northern Nevada continues to show promise as a destination of choice for the high-technology industry, which should result in a continued increase in sales to the manufacturing and warehousing customer segment. In 2001, SPPC solidified working relationships within the business community recruiting industries in targeted sectors such as plastic manufacturers and hi-technology companies. The 2001 session of the Nevada State legislature saw the passage of AB 661. One provision of this bill allows commercial customers with an average annual load of one megawatt or more to file a letter of intent and application with the PUCN to buy electricity from another provider beginning in mid-2002. This provision was part of a package of legislation passed by the 2001 Legislature to ensure the continued creditworthiness of the Utilities and protect consumers from unexpected rate hikes. During 2001, a number of SPPC's large commercial customers indicated they would be filing applications to pursue alternative supplier options. See Regulation and Rate Proceedings in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations for further discussion. SPPC's MWh sales to wholesale customers have increased 14.1% over the past year. During 2001, firm and non-firm sales to wholesale customers comprised 32.1% of total energy sales. Wholesale customers consist of other utilities or municipalities that sell power to end users, marketing entities and others that exchange power with SPPC. 16
Wholesale MWh Sales 2001 2000 --------------------------- --------------------------- Firm Sales 4,085,097 99.1% 3,365,783 93.1% Non-Firm Sales 38,416 0.9% 248,213 6.9% ---------- ------ ---------- ------ Total 4,123,513 100.0% 3,613,996 100.0% ========== ====== ========== ======
SPPC's increase in wholesale MWh sales from last year was a result of market conditions and SPPC's power procurement activities. See Purchased Power Procurement in Item 7, Management's Discussion And Analysis Of Financial Condition And Results Of Operations, for a discussion of the Utilities' purchased power procurement strategies. Construction Program 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, the number and status of proposed independent generation projects, the need for additional transmission capacity in northern Nevada, changes in environmental regulations, adequacy of rate relief, and SPPC's ability to raise necessary capital. Gross construction expenditures for 2001, including AFUDC and contributions in aid of construction, were $133.6 million, and for the period 1997 through 2001, were $762.4 million. Estimated construction expenditures for 2002 and the period 2003-2006 are as follows (dollars in thousands):
Total 2002 2003-2006 5-Year --------------------------------------------- Electric facilities $ 132,875 $ 382,096 $ 514,971 Gas facilities 9,751 48,420 58,171 Common facilities 6,669 26,660 33,329 --------------------------------------------- Total construction expenditures 149,295 457,176 606,471 --------------------------------------------- AFUDC (5,682) (15,056) (20,738) Net salvage, including cost of removal (120) (400) (520) Net customer advances and contributions in aid of construction (3,942) (15,320) (19,262) --------------------------------------------- Total cash requirements $ 139,551 $ 426,400 $ 565,951 =============================================
Total construction expenditures estimated for 2002 and the 2003-2006 period, for each segment of SPPC's business, consist of the following (dollars in thousands): 17 Total 2002 2003-2006 5-Year ---- --------- ------ Electric Facilities: Distribution $ 48,386 $ 256,387 $ 304,773 Generation 5,335 21,100 26,435 Transmission 69,709 83,599 153,308 Other 9,445 21,010 30,455 ------------------------------------------ 132,875 382,096 514,971 ------------------------------------------ Gas Facilities: Distribution 8,819 44,680 53,499 Other 932 3,740 4,672 ------------------------------------------ 9,751 48,420 58,171 ------------------------------------------ Common Facilities 6,669 26,660 33,329 ------------------------------------------ TOTAL $ 149,295 $ 457,176 $ 606,471 ========================================== The Falcon to Gonder Transmission Project is a 345kV transmission line within northern Nevada with a planned in-service date of June 2003. Total project costs incurred through December 31, 2001, were $11.5 million. Actual costs incurred in 2001 were $5.9 million. Estimated costs for 2002 are $54.5 million. Facilities and Operations Total System SPPC maintains a wide variety of resources in its generation system. The availability of alternate resources allows SPPC to dispatch its electric generation system in a more cost-effective manner under varying operating and fuel market conditions, while maintaining system integrity. SPPC also supplies its customers' electric power needs using a combination of firm and interruptible resources to maximize operating flexibility and reliability, while minimizing cost. During 2001, SPPC generated 44.6% of its total electric energy requirements in its own plants, purchasing the remaining 55.4% as shown below: 18 Megawatt- Percent Hours of Total ----------- ---------- SPPC Company Generation ----------------------- Gas/Oil 4,090,757 30.3% Coal 1,870,909 13.9% Hydro 50,993 0.4% ----------- -------- Total Generated 6,012,659 44.6% ----------- -------- Purchased Power --------------- Utility Purchases: Long-Term Firm 454,589 3.4% Short-Term Firm 6,164,555 45.7% Spot Market 30,910 .2% Non-Utility Purchases: Geothermal 702,616 5.2% Other 125,988 .9% Transmission & Balancing 5,071 0.0% ----------- -------- Total Purchased 7,483,729 55.4% ----------- -------- Total 13,496,388 100.0% =========== ======== As a supplement to its own internal generation, SPPC purchases both firm and non-firm energy to meet its customer demand requirements. See Purchased Power Procurement in Item 7, Management's Discussion And Analysis Of Financial Condition And Results Of Operations, for a discussion of the Utilities' purchased power procurement strategies. In 2001, most of SPPC's non-utility generation came from QFs, except for 21,730 MWh, which came from two small power producers. Risk Management See Item 7A, Quantitative and Qualitative Disclosures About Market Risk. Load and Resources Forecast SPPC's electric customer growth rate was 1.9% in 2001, 2.6% in 2000, and 2.6% in 1999. Annual retail electricity sales were 8.7 million MWh in 2001, which represents a decrease of 1% compared to 2000 retail electricity sales of 8.8 million MWh. Annual wholesale electricity sales reached 4.1 million MWh in 2001, which represents an increase of 14% over 2000 wholesale electricity sales of 3.6 million MWh. Overall, annual system electricity sales reached 12.9 million MWh in 2001, which represents an increase of 3.5% over 2000 system electricity sales of 12.4 million MWh. The 2001 peak electric demand was 1,529 MW compared to a weather-adjusted peak of 1,531 MW for 2000. The lack of growth in the peak is mainly attributable to demand-reduction efforts by customers due to the power issues in the West. The forecasted peak energy demand for 2002 and 2003 below reflects, among others, five key assumptions: . Northern Nevada experiences normal weather conditions, based on historical 20-year averages. . No adjustments have been made to incorporate the potential loss of customers leaving for alternative providers under the provisions of AB661. However, one large commercial customer of SPPC has filed an application under the provisions of AB 661 to procure energy from an alternative source other than the Utility. The customer, SPPC, and PUCN staff are negotiating a stipulation regarding settlement of the terms and conditions under which this customer will be permitted to procure energy from an alternative source other than SPPC. The terms and conditions of the stipulation are expected to comply with the provisions of AB 661 in that SPPC and 19 its remaining customers will not be negatively impacted by the customer's departure. A hearing on the stipulation has been set for March 20, 2002. . Retail electric rates are set at the levels requested in SPPC's most recent general and deferred energy rate case filings. . SPPC continues to be a summer peaking utility. . Concerns over power outages in California subside by summer 2002 resulting in reduced conservation efforts by SPPC's customers. Sales and peak energy demand will vary from forecasted levels to the extent that actual experience varies from the above assumptions and to the extent that other factors affect sales and demand. SPPC's actual total system capability and peak loads for 2001, and as estimated for summer peak demand for 2002 and 2003 are shown below:
Capacity at 2001 Peak Forecast Summer Peak ----------------------------------------------------- MW % 2002 2003 ----------------------------------------------------- SPPC Company Generation: Existing (1) 1,026 58% 1,045 1,062 ----------------------------------------------------- Purchases: Long/Short-Term Firm (2) 475 27% 500 525 Interruptible/Wheeling/Losses (3) 176 10% 5 7 Non-Utility Generators 93 5% 85 85 ----------------------------------------------------- Subtotal 744 42% 590 617 ----------------------------------------------------- Additional Required 0 0% 176 165 Total System Capacity 1,770 100% 1,811 1,844 ===================================================== Net System Peak Demand (4) 1,529 90% 1,621 1,654 Planning Reserve 177 10% 190 190 ----------------------------------------------------- Total Requirement 1,706 100% 1,811 1,844 ===================================================== Growth over previous year 6.2% 1.8%
(1) The Clark Mountain Gas Turbine (G.T.) and Winnemucca G.T. were both unavailable during the time of the 2001 system peak. Assumes Pinon Pine duct burner modification occurs in the fall 2002, adding 17 MW of net capacity. (2) Value is net of losses and includes committed short-term firm block purchases. Values shown represent purchases within existing transmission system limits. No economy (non-firm) energy purchases (only firm power purchases) occurred during the 2001 peak. (3) Includes net wheeling from the Naniwa power station during the 2001 peak of 132 MW, which was retained in SPPC's system. (4) The system peak shown for 2001 occurred on August 7, 2001, at 5:00 p.m. SPPC plans its system capacity needs in accordance with the 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 adequate reserve margin consistent with the WSCC planning reserve criteria. These additional reserves will be met, if needed, with short-term purchases through 2003 to the extent available. At the time of the 2001 system peak, SPPC had purchased firm capacity 20 under long-term contracts with other utilities and qualifying facilities equal to 10% of total peak hour capacity. Short-term firm block purchases comprised 26% of the peak, with no economy (non-firm) purchases transacted (only firm power purchases). Generation The following is a list of SPPC's share of generation plants including the 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 ----------------------------------------------------------------------------------------------------------------------- Valmy (1) Steam Coal 2 266 1981, 1985 Tracy Steam Gas/Oil 3 244 1963, 1965, 1975 Pinon (2) Combined Cycle (3) 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 (4) 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) 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. (3) The combined cycle at Pinon consists of one combustion turbine and one steam turbine. (4) The 4 hydro generating units were to be included in the sale of SPPC's water business in June 2001. However, the California Legislature has mandated that the sale of these units (as well as any other units serving California markets) be postponed until 2006 due to uncertainty in the California power markets. See sale of Water Business, 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 2001, 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 western United States. See Industry and Regional Problems Affecting the Utilities, earlier. Some of SPPC's purchased power contracts are at price levels above which SPPC is permitted to recover in current rates. See Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, for a discussion of deferred energy accounting and legislation. 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 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 21 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 PURPA, 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, 2001, 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 8.8% of the net system requirements (excluding wholesale purchases) during 2001. 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 2001. The actual QF output for all non-utility generator deliveries during the summer 2001 peak was 93 MW Transmission 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 kV 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 to Gonder Project is a 185-mile 345 kV line connecting SPPC's Falcon Substation to Mt. Wheeler Power's Gonder Substation. The Falcon to Gonder Project improves system import and export capabilities and enables SPPC to provide transmission service between Idaho, Utah, and the northwest. The Final Environmental Impact Statement was released in December 2001. Federal permitting is expected to be completed by the end of March 2002, with construction starting in May 2002. SPPC has ordered long lead material like towers and transformers, and is preparing to start the construction bid process. The project in- 22 service date is June 2003. Total project costs incurred through December 31, 2001, were $11.5 million. Actual costs incurred in 2001 were $5.9 million. Estimated costs for 2002 are $54.5 million. See Regulation and Rate Proceedings, FERC Matters in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations for a discussion of regional transmission issues. Fuel Availability SPPC's 2001 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 MMBtu for the years 1997-2001, along with the percentage contribution to total fuel requirements, are as follows:
------------------------------------------------------------------------------------------ Average Consumption Cost & Percentage Contribution to Total Fuel Requirements Gas Coal Oil --- ---- --- $/MMBtu Percent $/MMBtu Percent $/MMBtu Percent ------- ------- ------- ------- ------- ------- 2001 5.63 45.3% 1.55 32.4% 6.49 22.3% 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% ------------------------------------------------------------------------------------------
For a discussion of the change in fuel costs, see Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations. 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 cancelled. Due to previous accelerated purchases and cancellations, and continuing cancellations of minimum monthly volume obligations, SPPC fully satisfied all volume requirements and termination of the contract occurred in February 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 2001, two short-term agreements for the purchase of spot market coal were in place. 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, 2001, Valmy's coal inventory level was 378,011 tons, or approximately 65 days of consumption at 100% capacity. Inventory levels were increased to allow for economically priced supplies under contract to be delivered prior to the expiration of those supply arrangements. During 2001, transportation of coal to Valmy was provided by the Union Pacific Railroad (UP) under a 3-year agreement effective June 1, 1998. The agreement was extended an additional 3.5 years and will now expire December 31, 2004. During 2001, SPPC operated the Pinon Pine facility exclusively on natural gas. No coal was purchased in 2001 for synthetic gas production in the plant's coal gasification facility. 23 SPPC meets its needs for residual oil for generation through purchases on the spot market. During portions of 2001, oil prices were significantly lower than natural gas prices. 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 318,000 barrels as of December 31, 2001, which is equal to a 14-day supply at full load operation. Natural Gas Business SPPC's natural gas business consists of operating the local distribution company (LDC) for the Reno/Sparks metropolitan area and procuring gas for electrical power generation at the Tracy and Ft. Churchill plants. The LDC accounted for $145.7 million in 2001 operating revenues or 9.4% of SPPC's revenues from continuing operations. Growth in SPPC's LDC service territory continues to be strong. Customer meter count growth during 2001 was 4.7%. SPPC's total customer meter count increased by 5,446 to 121,862 meters by the end of 2001. Growth in all sectors is expected to continue as new developments in SPPC's distribution service area are planned. SPPC's forecast for growth in the number of LDC customers in 2002 is: residential 4.8%, small commercial 2.5%, and large commercial 5.5%. 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. Additionally, large customers have the ability to secure their own gas supplies; however, through 2000 and 2001, large customers that were securing their own supplies generally found that receiving gas from SPPC's LDC was more reliable and more economical than securing their own supplies. At the end of 2001, only two large customers were still securing their own supplies. To secure gas supplies for power generation and the LDC, SPPC contracted for firm winter-only and annual gas supplies with 10 Canadian and domestic suppliers to meet the firm requirements of its LDC and electric operations. The winter period contracts totaled 160,000 Dth per day through March 2001, and the summer period contracts totaled 115,000 Dth 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 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 Dth 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. Following is a summary of the transportation and approximate storage capacity of SPPC's current gas supply program for 2001 (for the twelve months period ending October 31, 2002). 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. 24 Transportation Capacity ----------------------- Northwest: 68,696 decatherms per day firm (annual) 90,000 decatherms per day interruptible Paiute: 103,774 decatherms per day firm (November through March) 61,044 decatherms per day firm (April through October) 90,000 decatherms per day interruptible NOVA: 103,774 decatherms per day firm ANG: 93,301 decatherms per day firm PGT: 83,500 decatherms per day firm (annual) 60,270 decatherms per day firm (November through April) 90,000 decatherms per day interruptible Tuscarora: 121,911 decatherms per day firm (annual) 50,000 decatherms per day interruptible 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 Total LDC Dth supply requirements in 2000 and 2001 were 13.2 million Dth and 14.26 million Dth, respectively. Electric generating fuel requirements for 2001 and 2000 were 28.96 million Dth and 38.6 million Dth, respectively. In January 2001, the PUCN approved a Purchase Gas Adjustment filing from the previous year and the new rates became effective February 1, 2001. An average residential customer had an increase in their rates of approximately 35%. In November 2001, the PUCN approved another Purchase Gas Adjustment filing. An average residential customer had an increase in their rate of approximately 25%. Each of these approvals reflects complete recovery of the LDC's gas purchases. As of December 31, 2001, SPPC owned and operated 1,601 miles of three-inch equivalent natural gas distribution piping, 108 miles of which were added in 2001. Also during 2001, Tuscarora Gas completed construction of a lateral gas transmission line to a new SPPC high-pressure regulator station (completed in 2000). The lateral transmission line connected Tuscarora's primary transmission line to SPPC's LDC north of Reno in the Stead, Nevada area. The line provided the LDC the ability to receive more supply and exercise more operating flexibility. In 2001, SPPC completed several smaller system improvement projects. A small propane system that SPPC owns and operates was connected to the new Tuscarora Gas lateral line and converted to a natural gas system. Over 4 miles of 12" diameter main was added to the system, which improved the capacity and reliability in the southwest Reno area. Sale of Water Business On June 11, 2001, SPPC closed the sale of its water business to the Truckee Meadows Water Authority (TMWA) for $341 million. SPPC recorded a $25.8 million gain on the sale, net of income taxes of $18.2 million. Pursuant to a stipulation entered into in connection with the sale and approved by the PUCN, SPPC is required to refund to customers $21.5 million of the proceeds from the sale. The refund is being credited on the electric bills of SPPC's former water customers over a period not to exceed fifteen months from June 11, 2001. Under a service contract with TMWA, SPPC will provide, on an interim basis, customer service, billing, and meter reading services to TMWA. Transfer of the hydroelectric facilities included in the contract of sale for an additional $8 million will require action by the CPUC. The sale agreement contemplates a second 25 closing for the hydroelectric facilities to accommodate the CPUC's review of the transaction. Not included in the sale were certain properties along the Truckee River related to the hydroelectric facilities and in California at Independence Lake. SPPC will continue to own this property with the intent of a possible future sale. Regulation and Rate Proceedings See Regulation and Rate Proceedings in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations. GENERATION DIVESTITURE (NPC AND SPPC) ------------------------------------- As a condition to its approval of the merger between SPR and NPC, the PUCN required the Utilities to file a Divestiture Plan for the sale of their electric generation assets. The PUCN approved a revised Divestiture Plan stipulation in February 2000. In May 2000 an agreement was announced for the sale of NPC's 14% undivided interest in the Mohave Generating Station ("Mohave"). In the fourth quarter of 2000 the Utilities announced agreements to sell six additional bundles of generation assets described in the approved Divestiture Plan. The sales were subject to approval and review by various regulatory agencies. AB 369, which was signed into law on April 18, 2001, prohibits until July 2003 the sale of generation assets and directs the PUCN to vacate any of its orders that had previously approved generation divestiture transactions. In January 2001, California enacted a law that prohibits until 2006 any further divestiture of generation properties by California utilities, including SPPC, and could also affect any sale of NPC's interest in Mohave after July 2003 since the majority owner of that project is Southern California Edison. In addition, SPPC's request for an exemption from the requirements of a separate California law requiring approval of the CPUC to divest its plants was denied, subject to future refiling. The sales agreements for the six bundles provide that they terminate eighteen months after their execution unless the parties agree to an earlier termination. The parties may extend the termination another six months to obtain additional regulatory approvals. As a result of the legislative and regulatory developments which have rendered the contracts impossible to perform, the Utilities are engaged in discussions with the buyers of the generation assets regarding the formal termination of the sales agreements and the related energy buyback contracts and interconnection agreements. As of December 31, 2001, the Utilities had incurred costs of approximately $12.3 million and $15.5 million, respectively, in order to prepare for the sale of generation assets. The Utilities have requested recovery of these costs in each Utility's respective general rate case filing with the PUCN, discussed in Regulation and Rate Proceedings, in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operation. PORTLAND GENERAL ELECTRIC ACQUISITION ------------------------------------- On April 26, 2001, SPR and Enron Corp. announced that they had mutually agreed to terminate their agreement for SPR's purchase of Enron's wholly owned subsidiary, Portland General Electric (PGE). In negotiating the mutual termination, SPR agreed to share certain expenses that Enron Corp and PGE had incurred for the proposed transaction. The Consolidated Statement of Income of SPR for the year ended December 31, 2001, reflects a charge in connection with the planned purchase of PGE of $22 million, including approximately $7.5 million representing a termination payment for shared expenses. ENVIRONMENT (SPR, NPC AND SPPC) ------------------------------- As with other utilities, NPC 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 26 or 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 that oversees NPC, 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 NPC) 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 $395 million. As a 14% owner in the Mohave Station, NPC's cost could be $55 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. The EPA has solicited information to determine whether visibility impairment in the Grand Canyon can be reasonably attributed to Mohave. The EPA determined that significant visibility impairment to the Grand Canyon cannot be reasonably attributable to the station provided controls are installed as agreed to in the consent order. Therefore, the EPA will not require a Best Available Retrofit Technology Review. Provisions that were agreed to in the settlement will be reflected in the state Implementation Plan for Nevada. In May 1997, NDEP ordered NPC 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 NPC 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 NPC. New pond construction and lining costs are estimated at $15 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 plan. The extent of contamination has been determined and remediation is occurring at a modest rate. An engineering evaluation of the current remediation technology will occur in 2002 to verify efficiency and to expedite remediation. Remediation modifications are not expected to materially affect the financial position of SPR or NPC. In May 1999, NDEP issued an order to eliminate the discharge of NPC's Clark Station wastewater to groundwater. The order also required a hydrological assessment of groundwater impacts in the area. This assessment, submitted to NDEP in February 2001, warranted a Corrective Action Plan which was submitted to NDEP in November and is pending review. Remediation costs are expected to be in the $500,000 - $750,000 27 range. In addition to remediation, NPC will spend $789,000 to line existing ponds. After review and approval of the Corrective Action Plan by NDEP, NPC will implement remediation. In July 2000, NPC received a request from the EPA for information to determine the compliance of certain generation facilities at the Clark Station with the applicable State Implementation Plan. In November 2000, NPC and the Clark County Health District entered into a Corrective Action Order requiring, among other steps, capital expenditures at the Clark Station totaling approximately $3 million. In March 2001, the EPA issued an additional request for information that could result in remediation beyond that specified in the November 2000 Corrective Action Order. If the EPA prevails, capital expenditures and temporary outages of four of Clark Station's generation units could be required. Additionally, depending on the time of year that the compliance activity and corresponding generation outage would occur, the incremental cost to purchase replacement energy could be substantial. 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 $136,000 has been spent through December 31, 2001. Once evaluations are completed, SPPC will be in a better position to estimate and record the ultimate liabilities for the Sites. Other Subsidiaries of SPR LOS, 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 underground fuel tank that has been removed from the property. 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. 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 is NEICO's intention to either lease or 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 28 extending from Malin, Oregon to Reno, Nevada. TGTC interconnects with PG&E Gas Transmission - Northwest (GT-NW) at Malin, Oregon. 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 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, 2001, SPR had an investment of approximately $14.6 million in this subsidiary. As an interstate pipeline, TGTC provides only transportation service. SPPC was the largest customer of TGTC during 2001, contributing 80% of revenues. Malin, Oregon began taking service from TGTC during October 1996. The Sierra Army Depot at Herlong, California began taking service from TGTC in 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. In 2000, TGTC began construction on a 14.2-mile lateral, creating a new city gate connection into the SPPC distribution system. The lateral was completed and placed in service January 29, 2001, providing SPPC with an additional 10,000 Dth per day of firm transportation capacity in January 2001 and 5,661 Dth in November 2001. Also in 2000, TGTC surveyed shipper interest in the feasibility of an expansion of transportation capacity. This survey established that 95,912 Dth per day of new capacity would be required to meet the needs of existing and new shippers for the 2002-2003 winter heating season. Facilities required in Nevada would be approximately 14.2 miles of 20" diameter pipe and one 600 HP booster unit, and in California, three compressor stations each with a 6,000 HP turbine and related facilities. On January 30, 2002, the FERC approved the plans to expand the interstate gas pipeline owned by the Tuscarora Gas Transmission Company. The project will increase the pipeline's capacity by 74% and will improve reliability of the natural gas transmission systems that serve northern Nevada. Final permitting for the project is pending before the U.S. Bureau of Land Management and other state and local agencies. In May 2001, TGTC completed construction of approximately 3,520-feet of pipeline with meter and flow control to serve a 360 MW plant, a new interruptible transportation customer east of Reno, Nevada near SPPC's Tracy Power Plant, and in September, 2001, TGTC completed construction of a 10.8-mile pipeline to serve two new customers: the City of Susanville and the Department of Correction both in California. 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 was created to examine and pursue telecommunications opportunities that leverage SPPC's existing skills of installing and deploying pipe and wire infrastructure. SPC presently has fiber optic assets deployed in the cities of Reno and Las Vegas. SPC is currently marketing bandwidth services in the Reno/Sparks and Las Vegas metropolitan areas. Sierra Touch America LLC (STA), a partnership between SPC and Touch America, a subsidiary of Montana Power Company, is constructing a fiber optic line between Salt Lake City, Utah and Sacramento, CA. The conduits included in the line are under contract to be sold to AT&T, PF Net corporations, and STA. SPC is responsible for 50% of the partnership's operating expenses and shares in the construction cost of the fiber network. Construction activity between Sacramento and Reno commenced in July 2000. Construction within Salt Lake City is complete and construction is in progress through the Reno, NV metropolitan area. The entire project is expected to be completed by mid 2003. For a discussion of the legal proceedings affecting SPC refer to Item 3, Legal Proceedings. 29 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 NPC, 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. 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. In mid 2000, e.three Custom Energy Solutions, LLC completed the construction of a chilled water cooling plant in the downtown area of Las Vegas. The plant is owned by e.three Custom Energy Solutions, LLC and supplies the indoor air-cooling requirements for a number of businesses in its immediate vicinity. 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. SPE continues to manage several long term commitments entered into prior to its withdrawal from the retail energy marketing effort. 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. 30 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. GENERAL - EMPLOYEES (ALL) ------------------------- SPR and its subsidiaries had 3,333 employees as of December 31, 2001, of which 1,787 were employed by NPC and 1,415 were employed by SPPC. NPC's current contract with the International Brotherhood of Electrical Workers (IBEW) Local No. 396, which covers 55% of NPC's workforce, was renegotiated in February 2002 and is in effect until February 1, 2005. The contract provides for a 3% general wage increase for bargaining unit employees effective February 2, 2002, with 3% increases in 2003 and 2004. 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 provided 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 (NPC 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 2001, the state also passed a law requiring public utilities to collect from their customers a fee based on consumption. This universal energy charge is to help those customers who need assistance in paying their utility bills or need help in paying for ways to reduce energy consumption. During 2001, the Utilities collected $58.3 million in franchise or other fees based on gross revenues. They collected $3.9 million in universal energy charges based on consumption. They also paid and recorded as expense $0.5 million of fees based on net profits. 31
Franchise Type of Service Expiration Date -------------------------------------------------------------------------------- NPC: 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
*currently being renegotiated. ** Water rights and obligations under the franchise agreements were assumed by Truckee Meadows Water Authority in June 2001 upon the sale of SPPC's water business. The Utilities will apply for renewal of franchises in a timely manner prior to their respective expiration dates. GENERAL - RESEARCH AND DEVELOPMENT (ALL) ---------------------------------------- SPR, through its NPC 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, NPC's, and SPPC's principal facilities is discussed in Item 1 - Business. Substantially all of NPC's utility plant is subject to the lien of the Indenture of Mortgage, dated October 1, 1953, and supplemental indentures thereto among NPC and Bankers Trust Company, securing NPC's outstanding first mortgage bonds. Additionally, all of NPC's property in Nevada is subject to the lien of the General and Refunding Mortgage Indenture dated as of May 1, 2001 between NPC and the Bank of New York, as trustee, which lien is junior, subject and subordinate to the prior lien of the Indenture of Mortgage mentioned above. 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, and Gerald R. Wheeler, as trustees, securing SPPC's outstanding first mortgage bonds. 32 Additionally, all of SPPC's property in Nevada is subject to the lien of the General and Refunding Mortgage Indenture dated as of May 1, 2001 between SPPC and the Bank of New York, as trustee, which lien is junior, subject and subordinate to the prior lien of the Indenture of Mortgage mentioned above. Item 3. Legal Proceedings Sierra Touch America LLC (STA), a partnership between SPC and Touch America, a subsidiary of Montana Power Company, is constructing a fiber optic line between Salt Lake City, Utah and Sacramento, CA. The conduits included in the line are under contract to be sold to AT&T, PF Net corporations, and STA. SPC is responsible for 50% of the partnership's operating expenses and shares in the construction cost of the fiber network. Construction activity between Sacramento and Reno commenced in July 2000, and the estimated completion date has been moved to early 2003. Williams Communications, LLC ("Williams") has filed a complaint in United States District Court alleging that STA has failed to make timely payment on invoices in connection with a construction agreement between Williams and STA. TI Energy Services ("TI") has filed a complaint in the District Court of Harris County, Texas, alleging that STA has failed to make timely payment on invoices in connection with a services agreement between TI and STA, whereby TI is to provide services for certain segments of the fiber optic line. Although SPC's ultimate liability, if any, cannot be estimated, Management believes the final outcome of the litigation is not likely to have a material adverse effect on SPR's financial position or results of operations. SPPC owns a 345 kV transmission line that connects SPPC to the facilities of the Bonneville Power Administration ("BPA") near Alturas, California. The Transmission Agency of Northern California ("TANC") 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 BPA'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 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. Although SPPC's ultimate liability, if any, cannot be estimated at this time, Management believes the final outcome of the appeal and any subsequent litigation is not likely to have a material adverse effect on SPR's financial position or results of operation. See Environment in Item 1, Business, for information on environmental proceedings. 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 their financial positions or results of operations. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS None. 33 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 2001 and 2000 are as follows:
Dividends Paid Per Share High Low --------------- ---------- ------------ 2001 First Quarter $.250 $ 16.000 $ 10.800 Second Quarter .000 17.000 13.290 Third Quarter * .200 17.020 14.670 Fourth Quarter * .200 15.560 13.850 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
* For federal income tax purposes, these payments were determined to be return of capital and therefore not taxable as ordinary income. Number of Security Holders: Title of Class Number of Holders -------------- ----------------- Common Stock: $1.00 Par Value As of March 15, 2002: 25,019 Dividends are considered periodically by SPR's Board of Directors and are subject to factors that ordinarily affect dividend policy, such as current and prospective earnings, current and prospective business conditions, regulatory factors, SPR's financial condition and other matters within the discretion of the Board. As a result of the unprecedented conditions in the wholesale energy markets that negatively affected SPR's earnings prior to the restoration of deferred energy accounting in Nevada, the Board of Directors decided on April 13, 2001 not to pay the Common Stock dividend that, if it had followed historical practices, would have been paid in May 2001. Following the passage of legislation in Nevada which reinstated deferred energy accounting for electric utilities, the Board re-examined the factors described previously and on July 20, 2001 declared a dividend of $.20 per share on SPR's Common Stock, payable September 15, 2001. The Board of Directors also established the following schedule for when future dividends would normally be paid, if declared: December 15, March 15, June 15 and September 15. The Board subsequently voted on November 6, 2001 to declare a dividend of $.20 per share, payable December 15, 2001. The Board will continue to review these factors on a periodic basis to determine if and when it would be prudent to declare a dividend on SPR's Common Stock. There is no guarantee that dividends will be paid in the future, or that, if paid, the dividends will be paid at the same amount or with the same frequency as in the past. 34 On February 6, 2002, the SPR Board of Directors declared a quarterly common dividend of $.20 per share. This dividend of approximately $20.4 million will be paid on March 15, 2002, to holders of record as of February 22, 2002. The primary source of funds for the payment of dividends to SPR's stockholders is dividends paid to SPR by NPC and SPPC on their common stock, all of which is owned by SPR. These two subsidiaries are public utilities and are subject to regulation by state utility commissions which may impose limits on investment returns or otherwise impact the amount of dividends which may be paid by those companies. Moreover, the Articles of Incorporation of SPPC contain restrictions on the payment of dividends on SPPC's common stock in the event of a default in the payment of dividends on SPPC's preferred stock. Similarly, the bank credit facilities of NPC and SPPC prohibit the payment of dividends on each company's common stock if that company is in default under the terms of the relevant credit facility. Finally, the terms of certain outstanding series of first mortgage bonds of both NPC and SPPC contain certain quantitative limits on the amount of dividends that may be paid on each company's common stock. 35 ITEM 6. SELECTED FINANCIAL DATA See Item 7, Management's Discussion And Analysis Of Financial Condition And Results Of Operations, for a discussion of factors that may affect the future financial condition and results of operations of SPR, NPC, and SPPC. SIERRA PACIFIC RESOURCES ------------------------ The table below, for periods prior to July 28, 1999, reflects historical information for NPC.
Year ended December 31, (dollars in thousands, except per share amounts) ------------------------------------------------------------------------------ 2001 2000 1999 1998 1997 ---- ---- ---- ---- ---- Operating Revenues $ 4,588,730 $ 2,334,254 $ 1,284,792 $ 873,682 $ 799,148 ============ ============== ============= =============== ============= Operating Income $ 222,869 $ 127,389 $ 162,861 $ 147,277 $ 137,196 ============ ============== ============= =============== ============= Net Income (Loss) from Continuing Operations $ 29,866 $ (49,414) $ 48,210 $ 83,499 $ 82,091 ============= ============== ============= =============== ============= Income (Loss) from Continuing Operations Per Average Common Share - Basic $ 0.34 $ (0.63) $ 0.77 $ 1.64 $ 1.65 ============= ============== ============= =============== ============= Income (Loss) from Continuing Operations Per Average Common Share - Diluted $ 0.34 $ (0.63) $ 0.77 $ 1.64 $ 1.65 ============= ============== ============= =============== ============= Total Assets $ 8,181,314 $ 5,677,908 $ 5,235,917 $ 2,541,840 $ 2,339,422 ============= ============== ============= =============== ============= Long-Term Debt and SPPC/NPC Obligated Mandatorily Redeemable Preferred Trust Securities $ 3,564,977 $ 2,371,051 $ 1,793,999 $ 1,089,099 $ 1,014,311 ============= ============== ============= =============== ============= Dividends Declared Per Common Share $ 0.40 $ 1.00 $ 1.17 $ 1.45 $ 1.60 ============= ============== ============= =============== =============
36 NEVADA POWER COMPANY --------------------
Year ended December 31, (dollars in thousands) ---------------------------------------------------------------------------------------- 2001 2000 1999 1998 1997 ---- ---- ---- ---- ---- Operating Revenues $ 3,025,103 $ 1,325,470 $ 977,262 $ 873,682 $ 799,148 =============== =============== ================ ================ ================== Operating Income $ 144,364 $ 73,460 $ 116,983 $ 147,277 $ 137,196 =============== =============== ================ ================ =================== Net Income (Loss) $ 56,733 $ (39,780) $ 51,750 $ 83,499 $ 82,091 =============== =============== ================ ================ ================== Total Assets $ 5,225,369 $ 3,407,751 $ 3,378,485 $ 2,541,840 $ 2,339,422 =============== =============== ================ ================ ================== Long-Term Debt and Obligated Mandatorily Redeemable Preferred Trust Securities $ 1,796,839 $ 1,116,656 $ 1,119,876 $ 1,089,099 $ 1,014,311 =============== =============== ================ ================ ================== Dividends Declared - Common Stock $ 33,000 $ 64,000 $ 72,000 $ 73,715 $ 79,177 =============== =============== ================ ================ ==================
SIERRA PACIFIC POWER COMPANY ---------------------------- The table below, for the years ended December 31, 1998 and 1997, includes information for SPPC's water business disposed of in 2001.
Year ended December 31, (dollars in thousands) ---------------------------------------------------------------------------------------- 2001 2000 1999 1998 1997 ---- ---- ---- ---- ---- Operating Revenues $ 1,544,786 $ 994,585 $ 709,374 $ 685,189 $ 657,540 =============== =============== ================ ================ ================== Operating Income $ 78,968 $ 47,135 $ 112,703 $ 114,263 $ 120,172 =============== =============== ================ ================ ================== Net Income (Loss) from Continuing Operations $ 19,043 $ (7,576) $ 59,658 $ 79,678 $ 77,668 =============== =============== ================ ================ ================== Total Assets $ 2,685,907 $ 2,208,389 $ 2,084,707 $ 2,011,820 $ 1,912,242 =============== =============== ================ ================ ================== Long-Term Debt and Obligated Mandatorily Redeemable Preferred Trust Securities $ 923,070 $ 654,316 $ 673,930 $ 654,950 $ 655,389 =============== =============== ================ ================ ================== Dividends Declared - Common Stock $ 63,000 $ 85,000 $ 76,000 $ 76,000 $ 72,000 =============== =============== ================ ================ ==================
37 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 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, 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 (NPC), or Sierra Pacific Power Company (SPPC) to differ materially from those contemplated in any forward-looking statement include, among others, the following: (1) unfavorable rulings in rate cases previously filed and to be filed by NPC and SPPC (the "Utilities") with the Public Utilities Commission of Nevada (PUCN), including the periodic applications authorized by recent Nevada legislation to permit the Utilities to recover costs for fuel and purchased power that have been recorded by the Utilities in their deferred energy accounts and deferred natural gas recorded by SPPC for its gas distribution business; (2) the ability of SPR, NPC and SPPC to access the capital markets to support their requirements for working capital, including amounts necessary to finance deferred energy costs, construction costs and the repayment of maturing debt, particularly in the event of unfavorable rulings by the PUCN and/or a downgrade of the existing debt ratings of SPR, NPC or SPPC; (3) 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; (4) the extent to which volatile energy prices and the financial difficulties of electric utilities and power exchanges in the western United States cause any counterparties to the Utilities' purchased power contracts to default on their obligations, thus requiring the Utilities to seek to replace the power on the spot market; (5) the effect of price controls promulgated in June 2001 by the Federal Energy Regulatory Commission ("FERC") on the price at which the Utilities can sell excess power in the wholesale markets; (6) the effect that any future terrorist attacks may have on the tourism and gaming industries in Nevada, particularly in Las Vegas, as well as on the economy in general; (7) the effect of existing or future Nevada, California or federal legislation or regulations affecting electric industry restructuring, including laws or regulations which could allow certain customers to choose new electricity suppliers; (8) unseasonable weather and other natural phenomena, which can have potentially serious impacts on the Utilities' ability to procure adequate supplies of fuel or purchased power to serve their respective customers and on the cost of procuring such supplies; 38 (9) industrial, commercial and residential growth in the service territories of the Utilities; (10) the loss of any significant customers; (11) 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 the Utilities; (12) changes in environmental regulations, tax or accounting matters or other laws and regulations to which the Utilities are subject; (13) future economic conditions, including inflation rates and monetary policy; (14) financial market conditions, including changes in availability of capital or interest rate fluctuations; (15) unusual or unanticipated changes in normal business operations, including unusual maintenance or repairs; and (16) employee workforce factors, including changes in collective bargaining unit agreements, strikes or work stoppages. 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, NPC 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. CRITICAL ACCOUNTING POLICIES The following items represent critical accounting policies that under different conditions or using different assumptions could have a material effect on the financial condition, liquidity and capital resources of SPR and the Utilities. Regulatory Accounting 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. 39 Deferred Energy Accounting On April 18, 2001, the Governor of Nevada signed into law Assembly Bill (AB) 369. The provisions of AB 369, which are described in greater detail in "Regulation and Rate Proceedings," later, include, among others, a reinstatement of deferred energy accounting for fuel and purchased power costs incurred by electric utilities. In accordance with the provisions of SFAS No. 71, the Utilities began utilizing deferred energy accounting on March 1, 2001, for their respective electric operations. Under deferred energy accounting, to the extent actual fuel and purchased power costs exceed fuel and purchased power costs recoverable through current rates, that excess is not recorded as a current expense on the income statement but rather is deferred and recorded as an asset on the balance sheet. Conversely, a liability is recorded to the extent fuel and purchased power costs recoverable through current rates exceed actual fuel and purchased power costs. These excess amounts are reflected in adjustments to rates and recorded as revenue or expense in future time periods, subject to PUCN review. AB 369 provides that the PUCN may not allow the recovery of any costs for purchased fuel or purchased power "that were the result of any practice or transaction that was undertaken, managed or performed imprudently by the electric utility." In reference to deferred energy accounting, AB 369 specifies that fuel and purchased power costs include all costs incurred to purchase fuel, to purchase capacity, and to purchase energy. The Utilities also record, and are eligible to recover, a carrying charge on such deferred balances. If not for deferred energy accounting during 2001, SPR's, NPC's and SPPC's results of operations, financial condition, liquidity and capital resources would have been materially adversely affected. For example, without the deferred energy accounting provisions of AB 369, the 2001 reported net income of SPR, NPC and SPPC of $56.7 million, $63.4 million/1/ and $45.9 million would have been (net of income tax) reported as net losses of ($715.4) million, ($573.6) million/1/ and ($89.1) million, respectively. In addition, a significant disallowance by the PUCN of costs currently deferred would have a material adverse affect on the future results of operations of SPR, NPC and SPPC. See "Regulation and Rate Proceedings," later, for a more detailed discussion of deferred energy accounting, including the regulatory process underway to recover these deferred costs. Derivatives and Hedging Activities Effective January 1, 2001, SPR, SPPC, and NPC adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS No. 138. As amended, SFAS No. 133 requires that an entity recognize all derivative instruments as either assets or liabilities in the statement of financial position and measure the instruments at fair value. In order to manage loads, resources and energy price risk, the Utilities buy fuel and power under forward contracts. In addition to forward fuel and power purchase contracts, the Utilities also use options and swaps to manage price risk. All of these instruments are considered to be derivatives under SFAS No. 133. The risk management assets and liabilities recorded in the balance sheets of the Utilities and SPR are primarily comprised of the fair value of these forward fuel and power purchase contracts and other energy related derivative instruments. With the reinstatement of deferred energy accounting pursuant to AB 369, prudently incurred fuel and purchased power costs are expected to be recoverable through future rates. Accordingly, the energy related risk management assets and liabilities and the corresponding unrealized gains and losses (changes in fair value) are offset with a regulatory asset or liability rather than recognized in the statements of income and comprehensive income. Upon settlement of the derivative instrument, actual fuel and purchased power costs are recognized or deferred to the extent they are recoverable or payable through future rates. ------------------------- /1/ Excludes equity in losses of SPR. 40 The fair values of the forward contracts and swaps are determined based on quotes obtained from independent brokers and exchanges. The fair values of options are determined using a pricing model which incorporates assumptions such as the underlying commodity's forward price curve, time to expiration, strike price, interest rates, and volatility. The use of different assumptions and variables in the model could have a significant impact on the valuation of the instruments. SPR and the Utilities have other non-energy related derivative instruments such as interest rate swaps. The transition adjustment resulting from the adoption of SFAS No. 133 related to these types of derivative instruments was reported as the cumulative effect of a change in accounting principle in Other Comprehensive Income. Additionally, the changes in fair values of these non-energy related derivatives are also reported in the statements of comprehensive income until the related transactions are settled or terminate, at which time the amounts will be reclassified into earnings. No amounts were reclassified into earnings during 2001. See Note 22 of "Notes to Financial Statements" for additional information regarding derivatives and hedging activities. Provision for Uncollectible Accounts The Utilities reserve for doubtful accounts based on past experience writing off uncollectible customer accounts. The collapse of the energy markets in California, and the subsequent bankruptcy of the California Power Exchange and the financial difficulties of the Independent System Operator, resulted in the Utilities reserving for outstanding receivables for power purchases by these two entities of $19.9 million and $1.5 million (before taxes) for NPC and SPPC, respectively. The weakening economy and the disruption to the leisure travel industry after September 11th also impacted the Utilities' customer delinquencies in 2001. Additional amounts of $14.8 million and $6.1 million were reserved for delinquent retail customer accounts of NPC and SPPC, respectively. The adequacy of these reserves will vary to the extent that future collections differ from past experience. Uncollectible retail customer accounts amounting to $5.6 million and $2.5 million respectively, for NPC and SPPC, were written off against this provision in 2001. Significant collection efforts are underway to recover portions of the rest of the delinquent accounts. MAJOR FACTORS AFFECTING RESULTS OF OPERATIONS As discussed in the results of operations sections that follow, operating results for 2001 were affected by the high and extremely volatile fuel and purchased power costs that developed in the western United States in 2000 and continued into 2001, and by several responsive legislative and regulatory actions. In an effort to mitigate the effects of higher fuel and purchased power costs, in July 2000, the Utilities entered into the Global Settlement with the PUCN, which established a mechanism that initiated incremental rate increases for each Utility. Cumulative electric rate increases under the Global Settlement were $127 million and $65 million per year, respectively, for the Utilities. However, because the rate adjustment mechanism of the Global Settlement was subject to certain caps and could not keep pace with the continued escalation of fuel and purchased power prices, on January 29, 2001, the Utilities filed a Comprehensive Energy Plan (CEP) with the PUCN. The CEP included a request for emergency rate increases (CEP Riders). On March 1, 2001, the PUCN permitted the requested CEP Riders to go into effect subject to later review. The CEP Riders provided further rate increases of $210 million and $104 million per year, respectively, for NPC and SPPC. 41 Notwithstanding the increases under the Global Settlement and the CEP Riders, the Utilities' revenues for fuel and purchased power recovery continued to be less than the related expenses. Accordingly, the Utilities sought additional relief pursuant to legislation. On April 18, 2001, the Governor of Nevada signed into law AB 369. The provisions of AB 369, which are described later in greater detail in "Regulation and Rate Proceedings," include a moratorium on the sale of generation assets by electric utilities until 2003, the repeal of electric industry restructuring, and, beginning March 1, 2001, a reinstatement of deferred energy accounting for fuel and purchased power costs incurred by electric utilities. The stated purposes of this emergency legislation included, among others, to control volatility in the price of electricity in the retail market in Nevada and to ensure that the Utilities have the necessary financial resources to provide adequate and reliable electric service under present market conditions. As discussed above in "Critical Accounting Policies," deferred energy accounting allows the Utilities an opportunity to recover in future periods that portion of their costs for fuel and purchased power not covered by current rates and defers to future periods the expense associated with the amounts by which fuel and purchased power costs exceed the costs to be recovered in current rates. Recovery is subject to PUCN review as to prudency and other matters. AB 369 requires each Utility to file general rate applications and deferred energy applications with the PUCN by specific dates. NPC's deferred energy application, filed on November 30, 2001, seeks to establish a Deferred Energy Accounting Adjustment ("DEAA") rate to clear accumulated purchased fuel and power costs of $922 million and spread the cost recovery over a not more than three-year period resulting in a net increase of 21%. The decision of the PUCN on NPC's deferred energy application is to take effect on April 1, 2002. SPPC's deferred energy application, filed on February 1, 2002, seeks to establish a DEAA rate to clear accumulated purchased fuel and power costs of $205 million and spread the cost recovery over a not more than three-year period resulting in a net increase of 9.8%. The PUCN decision on SPPC's deferred energy application is to take effect on June 1, 2002. See "Regulation and Rate Proceedings," later, for a discussion of the Utilities' general rate case filings. The decisions of the PUCN on the Utilities' deferred energy applications are expected to have a significant effect on the results of operations of SPR, NPC, and SPPC in 2002 and subsequent periods, and may have a material effect on the financial condition, liquidity, and capital resources of SPR, NPC, and SPPC. In particular, to the extent that the PUCN finds that any amount included in either Utility's deferred account was imprudently incurred, the PUCN will not permit that amount to be recovered through higher rates, and an equivalent amount of the Utility's deferred energy costs asset will be required to be written off. Such a write-off could cause a substantial loss to be incurred by the Utility, could cause its securities to be downgraded by the rating agencies and could make it significantly more difficult to finance the operations of the Utility and to buy fuel and purchased power from third parties. In the event that a significant amount of the Utilities' deferred energy costs are disallowed by the PUCN, there can be no assurance that SPR, NPC, or SPPC will be able to remain solvent. As discussed in greater detail in "Regulation and Rate Proceedings," on June 19, 2001, the FERC adopted a price mitigation plan applicable to spot market wholesale power sales in California and throughout the western United States during the period June 20, 2001 through September 30, 2002. The price mitigation plan established a mechanism with which to determine the maximum amount that may be charged for power sold during this period. Although the Utilities are not able to predict at this time the long-term effect that the FERC price mitigation plan and other market developments may have on their results of operations, management believes that, under certain market conditions, the FERC plan adversely affects the availability of spot market power to the Utilities and reduces the price at which the Utilities can sell power on the wholesale market. Another potential result from these price mitigation measures could be the delay and/or cancellation of proposed power plants throughout the western United States. If these results occur, the long-term supply of energy could be reduced. Numerous parties, including NPC and several northwest utilities, appealed the FERC order to the District of Columbia Court of Appeals on the basis that the price caps are unfair to electric customers who reside outside of California. The parties to the appeal await action by the Court. 42 SIERRA PACIFIC RESOURCES ------------------------ Results of Operations SPR earned $56.7 million for the year ended December 31, 2001, compared to a net loss of ($39.8) million in 2000, and net income of $51.8 million in 1999. NPC and SPPC, SPR's principal subsidiaries, declared common stock dividends to their parent, SPR, of $33 million and $63 million, respectively. SPPC also declared $3.9 million in dividends to holders of its preferred stock. Liquidity and Capital Resources (SPR Consolidated) SPR's net cash flows during 2001 were comparable to 2000. An increase in net cash flows used for operating activities was offset by a decrease in cash used for investing activities and an increase in cash provided from financing activities. The increase in cash used in operating activities resulted substantially from the payment of higher energy and natural gas costs. The decrease in cash used for investing activities resulted from the sale of SPPC's water business. The increase in cash provided from financing activities resulted from a reduction in net retirements of short-term debt and proceeds from the sale of common stock. Cash provided by financing activities was substantially utilized for the payment of higher energy costs in 2001. See Notes 7 (Common Stock and Other Paid-in Capital) and 12 (Short-Term Borrowings) for detailed financing information. 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. Since SPR is a holding company, substantially all of its cash flow is provided by dividends paid to SPR by NPC and SPPC on their common stock, all of which is owned by SPR. Since these two subsidiaries are public utilities, they are subject to regulation by state utility commissions which may impose limits on investment returns or otherwise impact the amount of dividends which may be paid by those companies. Moreover, the Articles of Incorporation of SPPC contain restrictions on the payment of dividends on SPPC's common stock in the event of a default in the payment of dividends on SPPC's preferred stock. Similarly, the Credit Agreements of NPC and SPPC prohibit the payment of dividends on each company's common stock if that company is in default under the terms of the relevant credit facility. Finally, the terms of certain outstanding series of first mortgage bonds of both NPC and SPPC limit the cumulative amount of dividends that may be paid on each company's common stock to the cumulative net earnings of that company over an extended period of time. Any of these provisions which potentially restrict dividends payable by NPC or SPPC could adversely affect liquidity at the SPR level. In addition to the liquidity provided by dividends from its subsidiaries, SPR maintains $75 million of short-term liquidity capacity at the holding company level in the form of a Credit Agreement with the same bank group that has entered into Credit Agreements with NPC and SPPC. This facility matures on November 28, 2002 and may be used to provide liquidity for general corporate purposes including to back up a commercial paper program, although SPR does not currently maintain a commercial paper program. The Credit Agreement contains a number of restrictive covenants including restrictions on liens, sales of assets and mergers or sale and leaseback transactions by SPR or its subsidiaries. The Credit Agreement also contains financial covenants requiring that SPR maintain: 43 . a ratio of (i) Total Indebtedness to (ii) the sum of Total Indebtedness and Shareholders Equity that does not exceed 0.65:1 as of the last day of each fiscal quarter. . a Consolidated Interest Coverage Ratio of not less than 1.5 to 1 calculated as of the last day of each fiscal quarter for the preceding four consecutive fiscal quarters. As of December 31, 2001, SPR was in compliance with these financial covenants. The borrowing costs under the Credit Agreement are at a variable interest rate consisting of a spread over LIBOR or an alternate base rate that is based upon a pricing grid tied to the credit rating on SPR's senior unsecured long-term debt. SPR had no borrowings outstanding under the Credit Agreement as of December 31, 2001. On or before the maturity date of the Credit Agreement, SPPC currently intends to either renew or replace the Credit Agreement. Like the Credit Agreements for NPC and SPPC, SPR's Credit Agreement is unsecured. However, SPR's Credit Agreement does not require the issuance of collateral to the banks in the event that the credit rating on SPR's long-term unsecured debt is downgraded. Construction Expenditures and Financing (SPR Consolidated) The table below provides SPR's consolidated cash construction expenditures and internally generated cash, net for 1999 through 2001 (dollars in thousands):
2001 2000 1999 Total -------------- ----------- ---------- ------------- Cash construction expenditures $ 302,875 $328,990 $729,794 $1,361,659 ============== =========== ========== ============= Net cash flow from operating activities $ (1,045,221) $185,896 $211,089 $ (648,236) Less common & preferred cash dividends 64,917 83,057 115,833 263,807 -------------- ----------- ---------- ------------- Internally generated cash $ (1,110,138) 102,839 95,256 (912,043) ============== =========== ========== ============= Internally generated cash as a percentage of cash construction expenditures Not Applicable 31% 13% Not Applicable
* 1999 cash construction expenditures include $448.3 million of merger related costs. SPR's estimated cash construction expenditures for 2002 through 2006 are $1.7 billion. Construction expenditures for 2002 (approximately $470 million) will be financed through debt issuance and internally generated funds, including recovery of deferred energy. It is anticipated that the Utilities will pay all of their net income in dividends to SPR. SPR anticipates capital contributions of $16 million to NPC and $60 million to SPPC in 2002. SPPC will utilize proceeds from the issuance of short-term debt and parent contributions to fund construction. Cash provided by internally generated funds during 2002 assumes full recovery of deferred energy costs over three years for NPC and SPPC. SPR also assumes general rate increases approved as filed effective at the beginning of the second quarter and mid-year for NPC and SPPC, respectively. To the extent that the PUCN finds that any of the Utilities' deferred energy costs resulted from imprudent purchases, the PUCN will not permit that amount to be recovered through higher rates, and an equivalent amount of the Utilities' deferred energy cost asset will be required to be written off. A material write-off of deferred energy costs would have a material adverse affect on the future results of operations of SPR and the Utilities and could cause their securities to be downgraded by the rating agencies and make it significantly more difficult to finance operations, and buy fuel and purchased power from third parties. 44 If SPR does not receive substantial recovery of deferred energy costs for the Utilities, depending upon the extent of the disallowance, the rating agencies might downgrade SPR and its subsidiaries. A downgrade by one or more of the national rating agencies of the credit rating for the debt of SPR, NPC or SPPC would affect the companies' liquidity primarily in two principal areas: (1) their respective financing arrangements and (2) NPC's and SPPC's contracts for fuel, for purchase and sale of electricity and for transportation of natural gas. With respect to the financing arrangements, in the event that either NPC's or SPPC's commercial paper programs are downgraded, the downgraded issuer would no longer be able to issue commercial paper, thereby requiring the issuer to draw upon its back-up credit facility to pay off outstanding commercial paper balances. With respect to other financing arrangements, a downgrade in and of itself would not trigger an event of default or otherwise accelerate the payment obligations under any of SPR's, NPC's or SPPC's financing agreements. However, the bank Credit Agreements of NPC and SPPC include a "springing lien" feature, pursuant to which NPC or SPPC would be required, in the event that the company's senior unsecured debt is downgraded, to issue General and Refunding Mortgage bonds to the banks in an amount equal to the aggregate principal amount of the commitments under the facilities. If the springing lien were triggered for NPC, NPC would likely be obligated, under a negative pledge clause applicable to its senior unsecured notes, to issue an additional $130 million of General and Refunding Bonds as collateral for those securities. With respect to NPC's and SPPC's contracts for purchased power, NPC and SPPC purchase and sell electricity with their counterparties under the Western Systems Power Pool ("WSPP") agreement, which is an industry standard contract. The WSPP contract is posted on the WSPP website. These contracts provide that a material adverse change may trigger a request for collateral, which, if not provided within 3 business days, may trigger a default. A request for collateral must be exercised within 30 days of the event becoming known. A default will result in a termination payment equal to the present value of the net gains and losses aggregated to a single liquidated amount due within 3 business days following the date the notice of termination is received. The mark to market value can be used to roughly approximate the termination payment at any point in time. With respect to the purchase and sale of natural gas, NPC and SPPC use several types of contracts. Standard industry sponsored agreements include: (1) the Gas Industry Standards Board ("GSIB") agreement which is used for physical gas transactions, (2) the GasEDI Base Contract for Short Term Sale and Purchase of Natural Gas which is also used for physical gas transactions, or (3) the International Swap Dealers Association (ISDA) agreement which is used for financial gas transactions. Alternatively, the gas transactions might be governed by a non-standard bilateral master agreement negotiated between the parties, or by the confirmation associated with the transaction. The natural gas contract terms and conditions are more varied than the electric contracts. Consequently, some of the contracts do not contain rating downgrade triggers and some contain language similar to that found in the WSPP agreement. Gas transmission services are provided under the FERC Gas Tariff or a custom agreement. These contracts require the entities to establish and maintain creditworthiness to obtain service. Contractual Obligations (SPR Consolidated) The table below provides SPR's consolidated contractual obligations, not including estimated construction expenditures described above, as of December 31, 2001, that SPR expects to satisfy through a combination of internally generated cash and, as necessary, through the issuance of short-term and long-term debt (dollars in thousands): 45
Payments Due By Period 2002 2003 2004 2005 2006 Thereafter Total ------------- ------------------------------------------------------------------------------- Long- Term Debt (1) $ 299,010 $ 570,632 $ 132,621 $ 302,622 $ 52,629 $ 2,317,601 $ 3,675,115 Purchased Power 1,348,451 152,852 151,627 136,680 137,446 777,064 2,704,120 Coal and Natural Gas 367,373 126,027 129,482 96,671 94,299 725,651 1,539,503 Capital Lease Obligations 6,156 6,156 6,946 7,736 7,736 58,016 92,746 Operating Leases 12,127 9,284 8,194 7,289 6,863 63,463 107,220 Other Long-Term Obligations 300 300 ------------- ------------ ------------ ----------- ----------- -------------- ------------ Total Contractual Cash Obligations $ 2,033,417 $ 864,951 $ 428,870 $ 550,998 $ 298,973 $ 3,941,795 $ 8,119,004 ============= ============ ============ =========== =========== ============== ============
(1) Includes short-term debt of $177,000. Capital Structure (SPR Consolidated) SPR's actual consolidated capital structure at December 31, 2001, and 2000 was as follows (dollars in thousands):
2001 2000 ------------------------- ----------------------- Short-Term Debt (1) $ 299,010 6% $ 685,601 15% Long-Term Debt 3,376,105 57% 2,133,679 48% Preferred Stock 50,000 1% 50,000 1% Preferred Trust Securities 188,872 4% 237,372 5% Common Equity 1,702,322 32% 1,359,712 31% ------------------------- -------------------------- TOTAL $5,616,309 100% $ 4,466,364 100% ========================= ==========================
(1) Including current maturities of long-term debt. Included in amounts above for Long-Term Debt is $600 million of SPR holding company debt. The merger between SPR and NPC was accounted for as a reverse purchase under generally accepted accounting principles, with NPC considered the acquiring entity, even though SPR became the legal parent of NPC. 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 NPC; (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 NPC and include the operating results of NPC for the entire periods presented; and (iv) each of the Consolidating Statements of Income for the twelve months periods ended December 31, 2001 and 2000, include twelve months of operating activity for SPR and its subsidiaries. 46 SIERRA PACIFIC RESOURCES CONSOLIDATING STATEMENTS OF INCOME (Dollars in Thousands)
Year Ended December 31, 2001 ---------------------------------------------------------- 12 months 12 months 12 months NPC SPPC Other Total ---------------------------- --------------------------- OPERATING REVENUES: Electric $ 3,025,103 $ 1,399,134 $ - $ 4,424,237 Gas 145,652 - 145,652 Other - - 18,841 18,841 ------------- -------------- ------------ -------------- 3,025,103 1,544,786 18,841 4,588,730 ------------- -------------- ------------ -------------- OPERATING EXPENSES: Operation: Purchased power 3,026,336 1,025,741 - 4,052,077 Fuel for power generation 441,900 286,719 - 728,619 Gas purchased for resale - 136,534 - 136,534 Deferral of energy costs-electric-net (937,322) (198,826) - (1,136,148) Deferral of energy costs-gas-net - (23,170) - (23,170) Other 169,442 117,627 44,892 331,961 Maintenance 45,136 24,363 - 69,499 Depreciation and amortization 93,101 70,358 1,181 164,640 Taxes: - Income taxes 17,775 8,507 (27,512) (1,230) Other than income 24,371 17,965 743 43,079 ------------- -------------- ------------ -------------- 2,880,739 1,465,818 19,304 4,365,861 ------------- -------------- ------------ -------------- OPERATING INCOME 144,364 78,968 (463) 222,869 ------------- -------------- ------------ -------------- OTHER INCOME: Allowance for other funds used during construction (382) 856 - 474 Other income - net 27,272 8,489 2,962 38,723 ------------- -------------- ------------ -------------- 26,890 9,345 2,962 39,197 ------------- -------------- ------------ -------------- Total Income Before Interest Charges 171,254 88,313 2,499 262,066 ------------- -------------- ------------ -------------- INTEREST CHARGES: Long-term debt 81,599 55,199 51,572 188,370 Other 13,219 7,433 3,509 24,161 Allowance for borrowed funds used during construction and capitalized interest (2,141) (660) - (2,801) ------------- -------------- ------------ -------------- 92,677 61,972 55,081 209,730 ------------- -------------- ------------ -------------- INCOME (LOSS) BEFORE SPPC/NPC OBLIGATED MANDATORILY REDEEMABLE PREFERRED TRUST SECURITIES 78,577 26,341 (52,582) 52,336 Preferred dividend requirements of obligated mandatorily redeemable preferred trust securities (15,172) (3,598) - (18,770) ------------- -------------- ------------ -------------- INCOME (LOSS) BEFORE PREFERRED STOCK DIVIDENDS 63,405 22,743 (52,582) 33,566 Preferred stock dividend requirements - (3,700) - (3,700) ------------- -------------- ------------ -------------- INCOME (LOSS) FROM CONTINUING OPERATIONS 63,405 19,043 (52,582) 29,866 INCOME FROM DISCONTINUED OPERATIONS - 1,022 - 1,022 GAIN ON DISPOSAL OF WATER BUSINESS - 25,845 - 25,845 ------------- -------------- ------------ -------------- NET INCOME (LOSS) $ 63,405 $ 45,910 $ (52,582) $ 56,733 ============= ============== ============ ==============
47 SIERRA PACIFIC RESOURCES CONSOLIDATING STATEMENTS OF INCOME (Dollars in Thousands)
Year Ended December 31, 2000 ---------------------------------------------------------- 12 months 12 months 12 months NPC 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-electric-net 16,719 - - 16,719 Deferral of energy costs-gas-net - (16,164) - (16,164) 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 ------------- -------------- -------------- -------------- INCOME (LOSS) BEFORE SPPC/NPC 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) BEFORE PREFERRED STOCK DIVIDENDS (7,928) (4,077) (33,910) (45,915) Preferred stock dividend requirements - (3,499) - (3,499) ------------- -------------- -------------- -------------- (LOSS) 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 December 31, 1999 --------------------------------------------------------- 12 months 5 months 5 months NPC SPPC Other Total --------------------------- ----------------------------- OPERATING REVENUES: Electric $ 977,262 $ 259,440 $ - $ 1,236,702 Gas - 38,958 - 38,958 Other - - 9,132 9,132 ------------- ------------- ------------- --------------- 977,262 298,398 9,132 1,284,792 ------------- ------------- ------------- --------------- OPERATING EXPENSES: Operation: Purchased power 293,600 79,856 - 373,456 Fuel for power generation 154,546 51,584 - 206,130 Gas purchased for resale - 27,262 - 27,262 Deferral of energy costs-electric-net 97,238 - - 97,238 Other 141,041 40,961 11,389 193,391 Maintenance 50,805 8,492 - 59,297 Depreciation and amortization 80,644 29,188 243 110,075 Taxes: Income taxes 19,943 10,602 (5,247) 25,298 Other than income 22,462 7,232 90 29,784 ------------- ------------- ------------- --------------- 860,279 255,177 6,475 1,121,931 ------------- ------------- ------------- --------------- OPERATING INCOME 116,983 43,221 2,657 162,861 ------------- ------------- ------------- --------------- OTHER INCOME: Allowance for other funds used during construction 3,713 (1,374) - 2,339 Other (expense) income - net (1,824) (853) 352 (2,325) ------------- ------------- ------------- --------------- 1,889 (2,227) 352 14 ------------- ------------- ------------- --------------- Total Income Before Interest Charges 118,872 40,994 3,009 162,875 ------------- ------------- ------------- --------------- INTEREST CHARGES: Long-term debt 64,454 12,741 299 77,494 Other 8,815 5,885 11,529 26,229 Allowance for borrowed funds used during construction and capitalized interest (8,356) 356 - (8,000) ------------- ------------- ------------- --------------- 64,913 18,982 11,828 95,723 ------------- ------------- ------------- --------------- INCOME (LOSS) BEFORE SPPC/NPC OBLIGATED MANDATORILY REDEEMABLE PREFERRED TRUST SECURITIES 53,959 22,012 (8,819) 67,152 Preferred dividend requirements of obligated mandatorily redeemable preferred trust securities (15,172) (1,570) - (16,742) ------------- ------------- ------------- --------------- INCOME (LOSS) BEFORE PREFERRED STOCK DIVIDENDS 38,787 20,442 (8,819) 50,410 Preferred stock dividend requirements (95) (2,105) - (2,200) ------------- ------------- ------------- --------------- INCOME (LOSS) FROM CONTINUING OPERATIONS 38,692 18,337 (8,819) 48,210 INCOME FROM DISCONTINUED OPERATIONS - 3,540 - 3,540 ------------- ------------- ------------- --------------- NET INCOME (LOSS) $ 38,692 $ 21,877 $ (8,819) $ 51,750 ============= ============= ============= ===============
49 NEVADA POWER COMPANY -------------------- Results of Operations NPC earned net income of $63.4 million in 2001, compared to a net loss of ($7.9) million in 2000, and 1999 net income before dividend requirements on preferred stock of $38.8 million. These amounts do not include NPC's equity in the earnings (losses) of SPR. The causes for significant changes in specific lines comprising the results of operations for NPC for the respective years ended are provided below (dollars in thousands except for amounts per unit): Electric Operating Revenue
2001 2000 1999 ---------------------------- ----------------------------- ------------- Change from Change from Amount Prior year Amount Prior year Amount ------------- ------------- ------------- ------------- ------------- Electric Operating Revenues: Residential $ 644,875 31.0% $ 492,365 18.3% $ 416,345 Commercial 302,682 32.9% 227,790 13.8% 200,186 Industrial 447,766 37.0% 326,916 12.6% 290,409 ------------- ------------- ------------- Retail revenues 1,395,323 33.3% 1,047,071 15.5% 906,940 Other 1,629,780 485.4% 278,399 295.9% 70,322 ------------- ------------- ------------- Total Revenues $ 3,025,103 128.2% $ 1,325,470 35.6% $ 977,262 ============= ============= ============= Total retail sales (MWh) 16,799,000 2.7% 16,363,000 12.0% 14,615,000 Average retail revenue per MWh $ 83.06 29.8% $ 63.99 3.1% $ 62.06
NPC's retail revenues increased in 2001 due to a combination of customer growth, and rate increases resulting from the Global Settlement and Comprehensive Energy Plan (CEP) (see Major Factors Affecting Results Of Operations, earlier). The number of residential, commercial, and industrial customers increased over the prior year by 4.8%, 4.4% and 6.5%, respectively. As a result of the CEP, a rate increase of 17% for retail customers became effective March 1, 2001. Substantially all of the increase in Other electric revenues was due to the sale of wholesale electric power to other utilities. NPC's increase in wholesale sales compared to 2000 was a result of market conditions and NPC's power procurement activities. See Purchased Power Procurement, later, for a discussion of the Utilities' purchased power procurement strategies. NPC'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. 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, NPC implemented monthly rate increases starting August 1, 2000. Other electric revenues were higher in 2000 compared to 1999 due to increased sales of wholesale electric power to other utilities. See Purchased Power Procurement, later, for a discussion of the Utilities' purchased power procurement strategies. 50 Purchased Power
2001 2000 1999 ----------------------------- ---------------------------- ------------- Change from Change from Amount Prior year Amount Prior year Amount -------------- ------------- ------------ ------------- ------------- Total purchased power $ 3,026,336 350.8% $ 671,396 98.1% $ 338,972 Less imputed capacity deferral - - - - (45,372) -------------- ------------- ------------- Purchased Power $ 3,026,336 350.8% $ 671,396 128.7% $ 293,600 ============== ============= ============= Purchased power MWh 19,268,305 99.5% 9,659,118 22.9% 7,861,985 Average cost per MWh of purchased power $ 157.06 126.0% $ 69.51 61.2% $ 43.12
NPC's purchased power costs were significantly higher in 2001 due to substantial increases in prices and volumes. Per unit costs of power increased 126% primarily due to higher Short-Term Firm energy prices. These price increases were the result of much higher fuel costs, combined with increased demand and limited power supplies. Volumes purchased rose 100% to accommodate increases in system load of approximately 2.7% and increases in wholesale sales of approximately 310%. Purchases associated with risk management activities, which include transactions entered into for hedging purposes and to optimize purchased power costs, are included in the purchased power amounts. See Purchased Power Procurement, later, for a discussion of the Utilities' purchased power procurement strategies. Purchased power costs were higher in 2000 as compared to 1999 due to a 23% increase in the volume purchased and an increase in the per unit cost of power of 61%. Fuel for Power Generation
2001 2000 1999 ---------------------------- ----------------------------- ------------- Change from Change from Amount Prior year Amount Prior year Amount ------------- ------------- ------------- ------------- ------------- Fuel for Power Generation $ 441,900 50.9% $ 292,787 89.4% $ 154,546 MWhs generated 9,899,195 -7.9% 10,744,466 17.2% 9,167,963 Average fuel cost per MWh of generated power $ 44.64 63.8% $ 27.25 61.6% $ 16.86
NPC's 2001 fuel expense increased over 50% compared to 2000 primarily due to a substantial increase in natural gas prices, offset in part, by decreased generation late in 2001 when the cost of purchased power was more economical than generation. In 2000, NPC's fuel expense increased 89% compared to 1999 primarily due to a substantial increase in natural gas prices. 51 Deferral of Energy Costs - Net
2001 2000 1999 --------------------------- -------------------------- --------- Change from Change from Amount Prior year Amount Prior year Amount ----------- -------------- ---------- -------------- ---------- Deferral of energy costs-electric-net $ (937,322) N/A $ 16,719 -82.8% $ 97,238
NPC recorded a significant Deferral of energy costs-net in 2001 due to the implementation of deferred energy accounting beginning March 1, 2001. The current year amounts reflect the extent to which actual fuel and purchased power costs exceeded the fuel and purchased power costs recovered through current rates. Deferral of energy costs-net for 2000 represents energy costs that had been deferred in prior periods and were then recovered in 2000, as a result of deferred energy rate increases granted in 1999. Deferral of energy costs-net decreased in 2000 compared to 1999 because NPC discontinued deferred energy cost accounting 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 Major Factors Affecting Results Of Operations, earlier. In February and March 2000, the PUCN issued orders that rejected NPC'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 write-off deferred energy and imputed capacity costs. See "Critical Accounting Policies," earlier, and Note 1 of "Notes to Financial Statements" for more information regarding deferred energy accounting. Allowance For Funds Used During Construction (AFUDC)
2001 2000 1999 -------------------------- --------------------------- ---------- Change from Change from Amount Prior year Amount Prior year Amount ---------- -------------- ---------- --------------- ---------- Allowance for other funds used during construction $ (382) -115.6% $ 2,456 -33.9% $ 3,713 Allowance for borrowed funds used during construction 2,141 -72.7% 7,855 -6.0% 8,356 ------- -------- -------- $ 1,759 -82.9% $ 10,311 -14.6% $ 12,069 ------- -------- --------
NPC AFUDC is lower in 2001 because of adjustments to amounts assigned to specific components of facilities that were completed in different periods. In 2000, there was a small decrease in the AFUDC rate compared to 1999 because of an increase in short-term debt. 52 Other Expenses
2001 2000 1999 ------------------------------ --------------------------- ------------ Change from Change from Amount Prior year Amount Prior year Amount ------------ -------------- ------------ ------------- ------------ Other operating expense $ 169,442 21.3% $ 139,723 -0.9% $ 141,041 Maintenance expense 45,136 32.5% 34,057 -33.0% 50,805 Depreciation and amortization 93,101 8.3% 85,989 6.6% 80,644 Income taxes 17,775 N/A (12,162) -161.0% 19,943 Interest charges on long-term debt 81,599 26.5% 64,513 0.1% 64,454 Interest charges- other 13,219 -3.7% 13,732 55.8% 8,815 Other income (expense)-net 27,272 1487.4% 1,718 -194.2% (1,824)
Other operating expense increased in 2001 compared to 2000 due to a $16.6 million larger addition to the provision for uncollectible customer accounts than in 2000, reflecting the impact of the weakening economy and disruption to the leisure travel industry after September 11, 2001. Other operating expense also increased due to the addition of $12.6 million to the uncollectible provision related to receivables from the California Power Exchange (PX) and California's Independent System Operator (ISO). NPC's other operating expense for 2000 was $8.8 million lower than 1999 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 the PX and ISO. The level of NPC's maintenance and repair expenses depends primarily upon the scheduling, magnitude and number of generation unit overhauls at NPC's generating stations. Maintenance expense for 2001 increased from the prior year as a result of increased outage work at Reid-Gardner, additional expenditures for repairs and outages at Clark Station and increased work at Mohave. In 2000 maintenance expense decreased from the prior year primarily as a result of fewer planned plant maintenance activities at NPC's coal generation facilities. In addition, in 2000 crews performed required activities of a capital nature, thereby reducing the amount of maintenance expense. An increase in plant-in-service was the cause of NPC's increase in depreciation and amortization expense in 2001 compared to 2000. Depreciation and amortization was also higher in 2000 than 1999 due to an increase in plant-in-service. As a result of net income for 2001, NPC incurred income tax expense. Due to a net loss in 2000, NPC recorded an income tax benefit for the year. See Note 10 of "Notes to Financial Statements" for additional information regarding the computation of income taxes. NPC's interest charges on long-term debt increased in 2001 compared to 2000, following a net increase in associated debt of $450 million (new issuances of $700 million and redemptions of $250 million during 2001). Interest charges on long-term debt for 2000 were comparable to 1999s. See Note 9 of "Notes to Financial Statements" for additional information regarding long-term debt. NPC's interest charges-other in 2001 were comparable to 2000. Interest charges-other increased in 2000 compared to 1999 due to increased debt through the issuance 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. NPC's other income (expense) - net improved in 2001 due primarily to the recognition in the current year of carrying charges on deferred fuel and purchased power balances pursuant to AB 369. Other income 53 (expense)-net improved in 2000 over the prior year as a result of greater increases in life insurance cash surrender values and reductions in contributions and membership dues. Liquidity and Capital Resources NPC's net cash flows decreased in 2001 compared to 2000. The net decrease in cash resulted from a significant increase in cash flows used in operating activities combined with cash used in investing activities both partially offset by an increase in cash provided by external financing sources. The increase in cash flows used in operating activities resulted substantially from the payment of significantly higher energy costs during 2001. Net cash used in investing activities was comparable between 2001 and 2000. Net cash provided by financing activities was higher in 2001 as a result of cash provided by the issuance of short-term and long-term debt, as described in Notes 12 and 9 to the Financial Statements, and additional capital contributions from SPR. Cash provided by financing activities was substantially utilized for the payment of higher energy costs in 2001. NPC'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 received from operating activities that was mainly due to a decrease in operating income. As discussed in "Construction Expenditures and Financing" and "Capital Structure" that follow, NPC anticipates external capital requirements for construction costs and for the repayment of maturing short-term and long-term debt during 2002 totaling approximately $403 million, which NPC will fund through a combination of (i) internally generated funds, (ii) the issuance of short-term debt and preferred stock, and (iii) capital contributions from SPR. NPC's primary source of short-term liquidity has been its commercial paper program, pursuant to which it sells commercial paper of varying maturities through dealers to institutional purchasers of commercial paper. NPC's current program permits the sale of up to $200 million of commercial paper on a revolving basis. As of December 31, 2001, NPC had $130.5 million of commercial paper outstanding, representing all of NPC's short-term debt as of that date. As is customary for an A2/P2 commercial paper issuer, NPC's commercial paper program requires that NPC maintain a back-up credit facility in the event that NPC is unable to sell additional commercial paper to pay off outstanding commercial paper due to conditions within the commercial paper market or due to a downgrade in the credit rating of NPC's commercial paper. Accordingly, if there ever were an event of default under or cancellation or termination of the back-up credit facility, NPC would not be able to issue commercial paper until NPC obtained another back-up credit facility or until the default were waived or cured. As discussed in "Capital Structure" below, NPC has a Credit Agreement with a number of banks which matures on November 28, 2002. Although this facility may be used to provide liquidity for general corporate purposes, it has been used primarily by NPC to back up its commercial paper program. The Credit Agreement contains a number of restrictive covenants including restrictions on liens, sales of assets, mergers, and sale and leaseback transactions. The Credit Agreement also contains financial covenants requiring that NPC maintain: . a ratio of (i) Total Indebtedness to (ii) the sum of Total Indebtedness and Shareholders Equity that does not exceed 0.60:1 as of the last day of each fiscal quarter. . a Consolidated Interest Coverage Ratio of not less than 2.0:1 calculated as of the last day of each fiscal quarter for the preceding four consecutive fiscal quarters. 54 As of December 31, 2001, NPC was in compliance with these financial covenants. The borrowing costs under the Credit Agreement are at a variable interest rate consisting of a spread over LIBOR or an alternate base rate that is based upon a pricing grid tied to the credit rating on NPC's senior unsecured long-term debt. NPC had no borrowings outstanding under the Credit Agreement as of December 31, 2001. On or before the maturity date of the Credit Agreement, NPC currently intends to either renew or replace the Credit Agreement. The Credit Agreement is currently unsecured. However, NPC will be required to secure the Credit Agreement through the issuance of General and Refunding Mortgage bonds to the lenders in the event that the credit rating on NPC's senior unsecured long-term debt is downgraded (i) by Moody's Investors Service, Inc. to Baa3 or lower or (ii) by Standard & Poor's Ratings Group to BB+ or lower. The Credit Agreement requires NPC to maintain sufficient capacity under its General and Refunding Mortgage Indenture to satisfy this collateral requirement. NPC and SPPC are currently negotiating receivables purchase facilities, in an aggregate principal amount not to exceed $200 million, that are expected to be finalized by the end of first quarter 2002. Under the proposed facilities, NPC and SPPC would each sell receivables in a true sale to special purpose entities that would in-turn sell those assets to a commercial paper conduit that would pay for the purchase of the assets by issuing commercial paper. These facilities will be used to provide additional liquidity for working capital and general corporate purposes in addition to NPC's existing commercial paper program. NPC expects the facility to be accounted for in compliance with SFAS No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities." The special purpose entities will be wholly owned subsidiaries and their financial positions and results of operations will be reflected in the consolidated financial statements of SPR, NPC, and SPPC. NPC's first mortgage indenture creates a first priority lien on substantially all of NPC's properties. As of December 31, 2001, $387.5 million of NPC's first mortgage bonds were outstanding. Although the first mortgage indenture allows NPC to issue additional mortgage bonds on the basis of (i) 60 percent of net utility property additions and/or (ii) the principal amount of retired mortgage bonds, NPC agreed in its General and Refunding Mortgage Indenture that it would limit the issuance of additional first mortgage bonds to not more than $80 million. NPC's General and Refunding Mortgage Indenture creates a lien on substantially all of NPC's properties in Nevada that is junior to the lien of the first mortgage indenture. As of December 31, 2001, $490 million of NPC's General and Refunding Mortgage securities were outstanding. Additional securities may be issued under the General and Refunding Mortgage Indenture on the basis of (i) 70 percent of net utility property additions, (ii) the principal amount of retired General and Refunding Mortgage bonds and/or (iii) the principal amount of first mortgage bonds retired after delivery to the indenture trustee of the initial expert's certificate under the General and Refunding Mortgage Indenture. At December 31, 2001, NPC had the capacity to issue approximately $1.2 billion of additional General and Refunding Mortgage bonds. However, the financial covenants contained in the Credit Agreement described above may limit NPC's ability to issue additional general and refunding bonds or other debt. NPC also has the ability to release property from the liens of the two mortgage indentures on the basis of net property additions, cash and/or retired bonds. To the extent NPC releases property from the lien of its General and Refunding Mortgage Indenture, it will reduce the amount of bonds issuable under that indenture. Under the terms of NPC's $130 million of 6.20% Senior Unsecured Notes due 2004, NPC may be required, upon the issuance of additional General and Refunding Mortgage bonds, to secure the Senior Unsecured Notes through the issuance of an equal principal amount of General and Refunding Mortgage bonds. 55 Construction Expenditures and Financing The table below provides NPC's consolidated cash construction expenditures and internally generated cash, net for 1999 through 2001 (dollars in thousands):
2001 2000 1999 Total ---------- --------- --------- ---------- Cash construction expenditures $ 196,896 $ 196,636 $ 220,919 $ 614,451 ========== ========= ========= ========== Net cash flow from operating activities $ (757,402) $ 113,711 $ 178,178 $ (465,513) Less common & preferred cash dividends 33,014 88,308 121,646 242,968 ---------- --------- --------- ---------- Internally generated cash (790,416) 25,403 56,532 (708,481) Add equity contribution from parent 474,921 137,000 18,000 629,921 ---------- --------- --------- ---------- Total cash available $ (315,495) $ 162,403 $ 74,532 $ (78,560) ========== ========= ========= ========== Internally generated cash as a percentage of cash construction expenditures Not Applicable 13% 26% Not Applicable Total cash generated (used) as a percentage of cash construction expenditures Not Applicable 83% 34% Not Applicable ----------------------------------------------------------------------------------------------------------------------
NPC's estimated cash construction expenditures for 2002 through 2006 are $1.118 billion. Construction expenditures for 2002 (approximately $311 million) will be financed through debt issuance and internally generated funds, including recovery of deferred energy. In 2002, NPC expects to pay all of its net income in dividends to SPR and to receive $16 million of capital contribution from SPR. Cash provided by internally generated funds during 2002 assumes full recovery of deferred energy over three years and general rate increases approved as filed effective at the beginning of the second quarter. To the extent that the PUCN finds that any of NPC's deferred energy costs resulted from imprudent purchases, the PUCN will not permit that amount to be recovered through higher rates, and an equivalent amount of NPC's deferred energy cost asset will be required to be written off. A material write-off of deferred energy costs would have a material adverse affect on the future results of operations of NPC and could cause NPC's securities to be downgraded by the rating agencies and make it significantly more difficult to finance operations, and buy fuel and purchased power from third parties. Also see Construction Expenditures and Financing (SPR Consolidated) earlier. Contractual Obligations The table below provides NPC's contractual obligations, not including estimated construction expenditures described above, as of December 31, 2001, that NPC expects to satisfy through a combination of internally generated cash and, as necessary, through the issuance of short-term and long-term debt and preferred stock (dollars in thousands): 56
Payments Due By Period 2002 2003 2004 2005 2006 Thereafter Total ---------- -------------------------------------------------------------------------------- Long- Term Debt (1) $ 149,880 $ 350,000 $ 130,000 $ - $ - $1,127,967 $1,757,847 Purchased Power 1,046,893 17,061 109,904 109,374 108,996 713,711 2,105,939 Coal and Natural Gas 187,663 55,493 63,780 31,043 31,064 373,228 742,271 Capital Lease Obligations 6,156 6,156 6,946 7,736 7,736 58,016 92,746 Operating Leases 2,941 1,470 1,090 926 504 - 6,931 ---------- ---------- ---------- ---------- ---------- ---------- ---------- Total Contractual Cash Obligations $1,393,533 $ 430,180 $ 311,720 $ 149,079 $ 148,300 $2,272,922 $4,705,734 ========== ========== ========== ========== ========== ========== ==========
(1) Includes short-term debt of $130,500. Capital Structure As of December 31, 2001, NPC had short-term debt outstanding of $130.5 miion comprised entirely of commercial paper. On November 29, 2001, NPC put into place a $200 million unsecured revolving credit facility replacing an existing $250 million credit facility, which may be used for working capital and general corporate purposes, including commercial paper backup. This new credit facility requires NPC to issue general and refunding mortgage bonds to secure this credit facility in the event of a decline in NPC's senior unsecured debt rating. This facility will expire on November 28, 2002. NPC's actual consolidated capital structure at December 31, 2001, and 2000 was as follows (dollars in thousands):
2001 2000 ------------------------- ----------------------- Short-Term Debt (1) $ 149,880 4% $ 352,910 15% Long-Term Debt 1,607,967 48% 927,784 39% Preferred Trust Securities 188,872 6% 188,872 8% Common Equity (2) 1,393,063 42% 887,737 38% ------------------------- ----------------------- TOTAL $3,339,782 100% $2,357,303 100% ========================= =======================
(1) Including current maturities of long-term debt. (2) Does not include equity in Sierra Pacific Resources: 2001 = $309,259; 2000 = $471,975. SIERRA PACIFIC POWER COMPANY ---------------------------- Results of Operations 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. SPPC's 2001 net income from continuing operations before dividend requirements on preferred stock was $22.7 million, compared to a net loss in 2000 of ($4.1) million and net income of $64.6 million in 1999. As described in Note 17, Discontinued Operations, SPPC closed the sale of its water utility business on June 11, 2001. Accordingly, the water business is reported as a discontinued operation and the continuing operating results have been reclassified to report separately the net results of operations from the water business. 57 The components of gross margin are (dollars in thousands):
2001 2000 1999 --------------- --------------- --------------- Operating Revenues: Electric $ 1,399,134 $ 893,782 $ 609,197 Gas 145,652 100,803 100,177 --------------- --------------- --------------- Total Revenues 1,544,786 994,585 709,374 --------------- --------------- --------------- Energy Costs: Electric 1,113,634 678,727 294,846 Gas 113,364 67,035 68,125 --------------- --------------- --------------- Total Energy Costs 1,226,998 745,762 362,971 --------------- --------------- --------------- Gross Margin $ 317,788 $ 248,823 $ 346,403 =============== =============== =============== Gross Margin by Segment: Electric $ 285,500 $ 215,055 $ 314,351 Gas 32,288 33,768 32,052 --------------- --------------- --------------- Total $ 317,788 $ 248,823 $ 346,403 =============== =============== ===============
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
2001 2000 1999 --------------------------- --------------------------- ------------ Change from Change from Amount Prior year Amount Prior year Amount ------------ ------------ ------------ ------------ ------------ Electric Operating Revenues: Residential $ 210,350 17.7% $ 178,701 4.2% $ 171,533 Commercial 243,883 23.9% 196,846 4.5% 188,348 Industrial 253,936 29.5% 196,143 5.6% 185,771 ------------ ------------ ------------ Retail revenues 708,169 23.9% 571,690 4.8% 545,652 Other 690,965 114.5% 322,092 406.9% 63,545 ------------ ------------ ------------ Total Revenues $ 1,399,134 56.5% $ 893,782 46.7% $ 609,197 ============ ============ ============ Total retail sales (MWh) 8,729,173 -0.9% 8,807,332 4.7% 8,412,853 ------------ ------------ ------------ Average retail revenue per MWh $ 81.13 25.0% $ 64.91 0.1% $ 64.86
The increase in SPPC's 2001 retail revenues was primarily due to rate increases resulting from the Global Settlement and CEP - see Major Factors Affecting Results Of Operations, earlier. These rate increases partially offset the increases in fuel and purchased power costs that SPPC had incurred. Also contributing to the higher revenues was an increase in the number of residential, commercial and industrial customers of 2.8%, 3.3% and 9.3%, respectively. Substantially all of the increase in Other electric revenues was due to the sale of wholesale electric power to other utilities. SPPC's increase in wholesale sales compared to 2000 was a result of market conditions and SPPC's power procurement activities. See Purchased Power Procurement, later, for a discussion of the Utilities' purchased power procurement strategies. 58 In 2000, as a result of the Global Settlement, retail revenues were $2.9 million higher than 1999 because the PUCN allowed SPPC to begin recovering its increases in fuel and purchased power costs. The increases in residential and commercial electric revenues in 2000 were also due to warmer weather during the cooling-season than in 1999 and, to a lesser extent, by increases in the number of customers. Industrial revenues increased because of significant increases in usage per customer, primarily by mining customers. Other electric revenues were higher due to an increase in wholesale electric sales. See Purchased Power Procurement, later, for a discussion of the Utilities' purchased power procurement strategies. Gas Operating Revenues
2001 2000 1999 --------------------------- --------------------------- ------------ Change from Change from Amount Prior year Amount Prior year Amount ------------ ------------ ------------ ------------ ------------ Gas Operating Revenues: Residential $ 63,815 46.6% $ 43,541 1.5% $ 42,888 Commercial 30,680 43.6% 21,368 0.5% 21,259 Industrial 17,941 58.7% 11,307 0.5% 11,252 Wholesale 33,298 46.0% 22,805 -2.8% 23,473 Miscellaneous (82) -104.6% 1,782 36.6% 1,305 ------------ ------------ ------------ Total Revenues $ 145,652 44.5% $ 100,803 0.6% $ 100,177 ============ ============ ============ Sales (Decatherms) 17,099,787 -8.9% 18,760,851 -21.2% 23,812,031 Average revenues per decatherm $ 8.52 58.7% $ 5.37 27.6% $ 4.21
Gas revenues rose in 2001, primarily due to the fact that the PUCN allowed SPPC to implement two gas rate increases (see Regulation and Rate Proceedings). These increases were the result of higher gas costs that SPPC incurred. Revenues were also higher due to increases of 5.0%, 3.1% and 10.6%, respectively, in residential, commercial and industrial customers, and an increase in wholesale revenues. 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 compared to 1999. A decline in wholesale volume 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 offset by an increase in wholesale unit prices. Purchase Power
2001 2000 1999 --------------------------- --------------------------- ------------ Change from Change from Amount Prior year Amount Prior year Amount ------------ ------------ ------------ ------------ ------------ Purchased Power $ 1,025,741 130.5% $ 444,979 147.5% $ 179,781 Purchased Power MWH 7,591,000 3.3% 7,349,000 26.8% 5,797,903 Average cost per MWH of Purchased Power $ 135.13 123.2% $ 60.55 95.3% $ 31.01
Purchased power costs increased dramatically in 2001 due to Short-Term Firm purchase power prices doubling. Purchased power costs also reflect a 14% increase in wholesale sales. Purchases associated with risk management activities, which include transactions entered into for hedging purposes and to optimize purchased power costs, are included in the purchased power amounts. See Purchased Power Procurement, later, for a discussion of the Utilities' purchased power procurement strategies. 59 Purchased power costs were higher in 2000 than 1999 primarily because prices per MWh were double that of the prior year and purchased power was relied on to accommodate increased system load. Purchased power costs were also higher during 2000 due to hedging activities in response to higher purchased power prices. Fuel For Power Generation
2001 2000 1999 ---------------------------- ----------------------------- -------------- Change from Change from Amount Prior year Amount Prior year Amount -------------- ------------- -------------- ------------- -------------- Fuel for Power Generation $ 286,719 22.7% $ 233,748 103.1% $ 115,065 MWHs generated 5,985,779 4.0% 5,756,000 15.2% $ 4,998,140 Average fuel cost per MWH of Generated Power $ 47.90 18.0% $ 40.61 76.4% $ 23.02
Fuel for power generation costs increased 22.7% in 2001 due mainly to increased natural gas prices, and, to a lesser extent, because volumes purchased were higher to accommodate greater system load. Fuel for generation costs in 2000 were higher than 1999 due to higher gas prices and an increase in volumes purchased. Gas Purchased for Resale
2001 2000 1999 ---------------------------- ----------------------------- -------------- Change from Change from Amount Prior year Amount Prior year Amount -------------- ------------- ----------- ------------- ------------ Gas Purchased for Resale $ 136,534 64.1% $ 83,199 22.1% $ 68,125 Gas Purchased for Resale (decatherms) 16,756,970 -9.2% 18,457,112 -22.9% 23,925,940 Average cost per decatherm $ 8.15 80.7% $ 4.51 58.2% $ 2.85
The cost of gas purchased for resale increased in 2001 because a decrease in the quantities of gas purchased was more than offset by large increases in unit prices. The decrease in quantities purchased was the result of increased 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 resale increased in 2000 because the decrease in quantities of gas purchased was again more than offset by large increases in unit prices. The decrease in quantities purchased corresponded to reduced demand by SPPC's retail customers and reduced availability of gas for wholesale sales as a result of increased power plant consumption of gas. The higher unit prices were attributable to increased demand for gas in the Pacific Northwest and additional transportation fees. 60 Deferral of Energy Cost - Net
2001 2000 1999 ---------------------------- ---------------------------- -------------- Change from Change from Amount Prior year Amount Prior year Amount --------------- ------------ --------------- ----------- -------------- Deferred energy costs - electric $ (198,826) N/A $ - N/A - Deferred energy costs - gas (23,170) 43.3% (16,164) N/A - --------------- --------------- -------------- Total $ (221,996) N/A $ (16,164) N/A $ - =============== =============== ==============
For 2001, SPPC recorded significant Deferral of energy costs electric-net (for purchased power and fuel for generation) due to the implementation of deferred energy accounting beginning March 1, 2001. The current year amounts reflect the extent to which actual fuel and purchased power costs exceeded the fuel and purchased power costs recovered through current rates. SPPC did not utilize deferred energy accounting for its electric operations in 2000 or 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 "Critical Accounting Policies," earlier, and Note 1 of "Notes to Financial Statements" for more information regarding deferred energy accounting. In January 2000, after the expiration of a rate freeze that was in effect from 1997 through 1999, SPPC began deferring natural gas costs in excess of that allowed in the tariff for its gas LDC. The deferral increased significantly in 2001 due to higher gas costs incurred by SPPC, as discussed in "Gas Purchased for Resale," above. Allowance For Funds Used During Construction (AFUDC)
2001 2000 1999 ---------------------------- --------------------------- -------------- Change from Change from Amount Prior year Amount Prior year Amount --------------- ----------- -------------- ----------- -------------- Allowance for other funds used during construction $ 856 139.8% $ 357 N/A $ (1,370) Allowance for borrowed funds used during construction 660 -76.3% 2,779 1870.9% 141 --------------- --------------- -------------- $ 1,516 -51.7% $ 3,136 N/A $ (1,229) --------------- --------------- --------------
SPPC's AFUDC is lower in 2001 because of adjustments to amounts assigned to specific components of facilities that were completed in different periods offset by an increase in the AFUDC rate. AFUDC for 2000 is higher than 1999 because of an AFUDC rate increase in 2000 and a $2.3 million adjustment in 1999 to reverse amounts previously charged to AFUDC. 61 Other Expenses
2001 2000 1999 ---------------------------- ------------------------- ----------- Change from Change from Amount Prior year Amount Prior year Amount ----------- --------------- ----------- ------------ ----------- Other operating expense $ 117,627 22.0% $ 96,438 4.0% $92,745 Maintenance expense 24,363 32.3% 18,420 -9.3% 20,309 Depreciation and amortization 70,358 1.5% 69,350 -0.6% 69,762 Income taxes 8,507 N/A (672) -102.0% 33,870 Interest charges on long-term debt 55,199 49.7% 36,865 18.3% 31,151 Interest charges- other 7,433 -34.3% 11,312 0.2% 11,286 Other income (expense)-net 8,489 N/A (2,429) 260.9% (673)
Other operating expense increased in 2001 compared to 2000 due to a $7 million larger addition to the provision for uncollectible customer accounts than in 2000, and a $3.5 million reserve provision established as a result of AB 369. Additionally, there were increased expenses related to the start-up of the Pinon Gasifier in 2001. 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. Maintenance costs in 2001 were higher due to additional turbine repairs and no major overhauls in 2000 at Valmy. There was also a shift from divestiture in 2000 to maintenance activities in 2001 at Tracy as well as unplanned maintenance on the diesel generators. Maintenance expense for 2000 decreased from 1999 as a result of fewer outages and lower plant maintenance expenses. Depreciation and amortization was higher in 2001 than 2000 due to an increase in plant-in-service. Depreciation and amortization decreased in 2000 from 1999 because of computer software that was fully amortized in 1999. As a result of recorded income for continuing operations for 2001, SPPC incurred income tax expense. Due to a net loss from continuing operations, SPPC recorded an income tax benefit for 2000. See Note 10 of "Notes to Financial Statements" for additional information regarding the computation of income taxes. SPPC'S interest charges on long-term debt were higher in 2001 than 2000, primarily due to the issuance of $320 million of its General and Refunding Mortgage bonds in May 2001. 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. SPPC'S interest charges-other decreased in 2001 compared to 2000 due to a decrease in commercial paper balances in 2001. For the year 2000, these interest charges-other were comparable to 1999. SPPC's other income (expense) - net improved in 2001 due primarily to the recognition in the current year of carrying charges on deferred fuel and purchased power balances pursuant to AB 369. SPPC's other income (expense)-net declined in 2000 mainly due to the reclassification of lease expenses for SPPC's main offices. 62 Discontinued Operations
2001 2000 1999 ---------------------------- --------------------------- ------------ Change from Change from Amount Prior year Amount Prior year Amount ------------ -------------- ------------ ------------ ------------ Income from operations of water business $ 1,022 -89.4% $ 9,634 46.3% $ 6,583
Income from operations of the water business decreased in 2001 as a result of the sale of the water business on June 11, 2001, prior to the seasonal increase in revenues resulting from higher water send-out. Income from operations of the water business increased in 2000 due primarily to higher revenues, which resulted from both customer growth and to a lesser extent higher usage per customer. Liquidity and Capital Resources SPPC's net cash flows during 2001 were comparable to 2000. For 2001, an increase in net cash flows from investing activities was substantially offset by a decrease in net cash flows from operating activities. The increase in net cash flows from investing activities resulted from the sale of the assets of SPPC's water business. The decrease in cash flows from operating activities resulted substantially from the payment of significantly higher energy and resale natural gas costs. These uses of cash flows were partially offset by a decrease in accounts payable in 2001. The decrease in cash flows from financing activities was due to reduced reliance on commercial paper in 2001 and the retirement of preferred stock as described in Note 8 to the Financial Statements offset, in part, by capital contributions from SPR. 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 Trust Securities) for information concerning the preferred stock retirement. As discussed in "Construction Expenditures and Financing" and "Capital Structure" below, SPPC will have capital requirements for construction costs and for the repayment of maturing short-term and long-term debt during 2002 totaling approximately $189 million, which SPPC will need to fund through a combination of (i) internally generated funds, (ii) the issuance of short-term debt, and (iii) capital contributions from SPR. SPPC's primary source of short-term liquidity has been its commercial paper program, pursuant to which it sells commercial paper of varying maturities through dealers to institutional purchasers of commercial paper. SPPC's current program permits the sale of up to $150 million of commercial paper on a revolving basis. As of December 31, 2001, SPPC had $46.5 million of commercial paper outstanding, representing all of SPPC's short-term debt as of that date. As is customary for an A2/P2 commercial paper issuer, SPPC's commercial paper program requires that SPPC maintain a back-up credit facility in the event that SPPC is unable to sell additional commercial paper to pay off outstanding commercial paper due to conditions within the commercial paper market or due to a downgrade in the credit rating of SPPC's commercial paper. Accordingly, if there ever were an event of default under or cancellation or termination of the back-up credit facility, SPPC would not be able to issue commercial paper until SPPC obtained another back-up credit facility or until the default were waived or cured. As discussed in "Capital Structure" below, SPPC has a Credit Agreement with a number of banks which matures on November 28, 2002. Although this facility may be used to provide liquidity for general corporate purposes, it has been used primarily by SPPC to back up its commercial paper program. The Credit Agreement 63 contains a number of restrictive covenants including restrictions on liens, sales of assets, mergers, and sale and leaseback transactions. The Credit Agreement also contains financial covenants requiring that SPPC maintain: . a ratio of (i) Total Indebtedness to (ii) the sum of Total Indebtedness and Shareholders Equity that does not exceed 0.60:1 as of the last day of each fiscal quarter. . a Consolidated Interest Coverage Ratio of not less than 2.0:1 calculated as of the last day of each fiscal quarter for the preceding four consecutive fiscal quarters. As of December 31, 2001, SPPC was in compliance with these financial covenants. The borrowing costs under the Credit Agreement are at a variable interest rate consisting of a spread over LIBOR or an alternate base rate that is based upon a pricing grid tied to the credit rating on SPPC's senior unsecured long-term debt. SPPC had no borrowings outstanding under the Credit Agreement as of December 31, 2001. On or before the maturity date of the Credit Agreement, SPPC currently intends to either renew or replace the Credit Agreement. The Credit Agreement is currently unsecured. However, SPPC will be required to secure the Credit Agreement through the issuance of General and Refunding Mortgage bonds to the lenders in the event that the credit rating on SPPC's senior unsecured long-term debt is downgraded (i) by Moody's Investors Service, Inc. to Baa3 or lower or (ii) by Standard & Poor's Ratings Group to BB+ or lower. The Credit Agreement requires SPPC to maintain sufficient capacity under its General and Refunding Mortgage Indenture to satisfy this collateral requirement. SPPC and NPC are currently negotiating receivables purchase facilities, in an aggregate principal amount not to exceed $200 million, that are expected to be finalized by the end of first quarter 2002. Under the proposed facilities, SPPC and NPC would each sell receivables in a true sale to special purpose entities that would in-turn sell those assets to a commercial paper conduit that would pay for the purchase of the assets by issuing commercial paper. These facilities will be used to provide additional liquidity for working capital and general corporate purposes in addition to SPPC's existing commercial paper program. SPPC expects the facility to be accounted for in compliance with SFAS No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities." The special purpose entities will be wholly owned subsidiaries and their financial positions and results of operations will be reflected in the consolidated financial statements of SPR, NPC, and SPPC. SPPC's first mortgage indenture creates a first priority lien on substantially all of SPPC's properties in Nevada and California. As of December 31, 2001, $509.7 million of SPPC's first mortgage bonds were outstanding. Although the first mortgage indenture allows SPPC to issue additional mortgage bonds on the basis of (i) 60 percent of net utility property additions and/or (ii) the principal amount of retired mortgage bonds, SPPC agreed in its General and Refunding Mortgage Indenture that it would not issue any additional first mortgage bonds. SPPC's General and Refunding Mortgage Indenture creates a lien on substantially all of SPPC's properties in Nevada that is junior to the lien of the first mortgage indenture. As of December 31, 2001, $320 million of SPPC's General and Refunding Mortgage bonds were outstanding. Additional securities may be issued under the General and Refunding Mortgage Indenture on the basis of (i) 70 percent of net utility property additions, (ii) the principal amount of retired General and Refunding Mortgage bonds and/or (iii) the principal amount of first mortgage bonds retired after delivery to the indenture trustee of the initial expert's certificate under the General and Refunding Mortgage Indenture. At December 31, 2001, SPPC had the capacity to issue approximately $416 million of additional General and Refunding Mortgage bonds. However, the financial covenants contained in the Credit Agreement described above may limit SPPC's ability to issue additional General and Refunding bonds or other debt. 64 SPPC also has the ability to release property from the liens of the two mortgage indentures on the basis of net property additions, cash and/or retired bonds. To the extent SPPC releases property from the lien of its General and Refunding Mortgage Indenture, it will reduce the amount of bonds issuable under that indenture. Construction Expenditures and Financing The table below provides SPPC's consolidated cash construction expenditures and internally generated cash, net for 1999 through 2001 (dollars in thousands):
2001 2000 1999 Total ----------- --------- --------- ----------- Cash construction expenditures $ 105,979 $ 132,354 $ 116,131 $ 354,464 =========== ========= ========= =========== Net cash flow from operating activities $ (213,579) $ 112,010 $ 122,329 $ 20,760 Less common & preferred cash dividends 89,901 84,899 81,746 256,546 ----------- --------- --------- ----------- Internally generated cash (303,480) 27,111 40,583 (235,786) Add equity contribution from parent 104,948 14,000 22,000 140,948 ----------- --------- --------- ----------- Total cash available $ (198,532) $ 41,111 $ 62,583 $ (94,838) =========== ========= ========= =========== Internally generated cash as a percentage of cash construction expenditures Not Applicable 20% 35% Not Applicable Total cash generated (used) as a percentage of cash construction expenditures Not Applicable 31% 54% Not Applicable ---------------------------------------------------------------------------------------------------------------------------------
SPPC's estimated cash construction expenditures for 2002 through 2006 are $556 million. SPPC estimates that 29% of its 2002 cash expenditures (approximately $40 million) will be provided by the issuance of short-term debt and parent contributions. In 2002, SPPC expects to pay all of its net income in dividends to SPR and to receive $60 million of capital contribution from SPR. Cash provided by internally generated funds during 2002 assumes full recovery of deferred energy over three years; and assumes general rate increases approved as filed and effective mid-year. To the extent that the PUCN finds that any of SPPC's deferred energy costs resulted from imprudent purchases, the PUCN will not permit that amount to be recovered through higher rates, and an equivalent amount of SPPC's deferred energy cost asset will be required to be written off. A material write-off of deferred energy costs would have a material adverse affect on the future results of operations of SPPC and could cause SPPC's securities to be downgraded by the rating agencies and make it significantly more difficult to finance operations, and buy fuel and purchased power from third parties. Also see Construction Expenditures and Financing (SPR Consolidated) earlier. Contractual Obligations The table below provides SPPC's contractual obligations, not including estimated construction expenditures described above, as of December 31, 2001, that SPPC expects to satisfy through a combination of internally generated cash and, as necessary, through the issuance of short-term and long-term debt (dollars in thousands): 65
Payments Due By Period 2002 2003 2004 2005 2006 Thereafter Total --------------------------------------------------------------------------------------------------------- Long-Term Debt (1) $ 49,130 $ 20,632 $ 2,621 $ 2,622 $ 52,629 $ 844,566 $ 972,200 Purchased Power 301,558 135,791 41,723 27,306 28,450 63,353 598,181 Coal and Natural Gas 179,710 70,534 65,702 65,628 63,235 352,423 797,232 Operating Leases 8,612 7,337 6,724 6,217 6,212 61,376 96,478 ------------- ----------- ------------ -------------- ------------- -------------- ------------ Total Contractual Cash Obligations $539,010 $ 234,294 $ 116,770 $ 101,773 $ 150,526 $ 1,321,718 $ 2,464,091 ============= =========== ============ ============== ============= ============== ============
(1) Includes short-term debt of $46,500. Capital Structure As of December 31, 2001, SPPC had short-term debt outstanding of $46.5 million comprised entirely of commercial paper. On November 29, 2001, SPPC put into place a $150 million unsecured revolving credit facility replacing an existing $250 million credit facility, which may be used for working capital and general corporate purposes, including commercial paper backup. This new credit facility requires SPPC to issue general and refunding mortgage bonds to secure this credit facility in the event of a decline in SPPC's senior unsecured debt rating. This facility will expire on November 28, 2002. SPPC's actual capital structure at December 31, 2001, and 2000 was as follows (dollars in thousands):
2001 2000 ---------------------- ------------------------- Short-Term Debt (1) $ 49,130 3% $ 328,578 20% Long-Term Debt 923,070 54% 605,816 37% Preferred Stock 50,000 3% 50,000 3% Preferred Trust Securities - - 48,500 3% Common Equity 692,654 40% 604,795 37% ------------- -------- --------------- --------- TOTAL $1,714,854 100% $ 1,637,689 100% ============= ======== =============== =========
(1) Including current maturities of long-term debt. PURCHASED POWER PROCUREMENT (NPC and SPPC) Traditionally, the Utilities obtained purchased power through annual and monthly Requests for Proposals ("RFPs") to electric suppliers. Over the past few years, structural and competitive changes in the energy markets have decreased the responsiveness of potential suppliers to the Utilities' RFPs. As a result of the market conditions in late 1999, the Utilities modified their procurement practices to rely less on the formal RFP process and more on the broker market. Brokers connect buyers and sellers in order to obtain optimal pricing for both sides. In October 1999, the Utilities established and utilized a timed procurement strategy in order to obtain a targeted percentage of their calculated purchased power requirement for procurement in the forward markets each month, following an overall trend of procuring power closer to the time of delivery. The timed procurement strategy was implemented at a time when the PUCN had ordered the Utilities to sell their generation plants in anticipation of retail competition and when it was still unclear what role the Utilities would play as a provider of last resort. As the price of purchased power escalated in the late Spring of 2000 and serious concerns developed regarding the availability of purchased power in California and throughout the western United States, the 66 Utilities began accelerating and extending their timed procurement strategies to fill summer peak requirements for 2001 and 2002. In an effort to mitigate the higher costs for 2001 energy procurement at the height of the crisis and to insure availability of electricity to the Utilities' customers, the Utilities entered into forward agreements covering 2001 and 2002 in order to take advantage of the then lower pricing for 2002 purchases. The Utilities are currently working with major regional suppliers seeking bids to blend some of their existing forward contract prices (for deliveries in 2002 through 2005) to smooth out recent spikes in forward contract prices and to reduce overall purchased power costs for deliveries in 2002. At this time the Utilities cannot predict the likelihood of success of these efforts. The Utilities continued to use the monthly RFP process in 2001, with the exception of the months of March through September for NPC. During the months of March through September, NPC had already secured purchased power resources such that it could rely on the spot market for its remaining power requirements. In NPC's Refiled 2000 Resource Plan (PUCN Docket No. 01-7016) and SPPC's 2001 Resource Plan (PUCN Docket No. 01-7004), the Utilities set forth their base long-term procurement strategy which has since been modified to include obtaining up to 300 MW for NPC and 250 MW for SPPC of firm, baseload energy (seven days a week, twenty four hours a day) beginning January 1, 2004, with up to 500 MW of intermediate and peaking power purchases for delivery in the second and third quarter of each year. The Utilities' purchased power procurement strategy involves an analysis of the Utilities' energy requirements to meet the needs of their retail and FERC jurisdictional loads. Net energy requirements are determined by subtracting already secured resources, including power plant generation, cogeneration facilities and previously purchased power contracts, from the Utilities' forecasted energy requirements. Once the net energy requirements are established, future energy prices are analyzed, using the forward market as the best predictor of future prices. The net energy requirements and applicable pricing data are presented to the Utilities' Risk Management Committee ("RMC") which analyzes these requirements, reviews alternative purchasing strategies and provides guidance on the timing and quantity of purchases. See Item 7A, Quantitative and Qualitative Disclosures About Market Risk for additional discussion regarding the RMC's role and the application of risk management policies. The RMC regularly reviews updated transaction information, available secured energy resources and power requirements in order to determine secured resources requirements as well as total power requirements. Short Term Power Procurement Strategy The Utilities' short term power procurement strategy involves both day-ahead (next day through the end of the current month) and real-time (next hour through the end of the current day) activities that require buying, selling and scheduling power resources to determine the most economical way to produce or procure the power resources needed to meet the retail customer load. After connecting generation units to the system, the Utilities dispatch the generation output based on the comparative economics of generation versus spot-market purchase opportunities and determine the amount of excess capacity, which is then sold on the wholesale market, or the amount of deficiency capacity, which must be procured on an hourly basis. The day-ahead resource coordination begins with an analysis of projected loads and existing resources. Firm forward take-or-pay contracts are scheduled and counted towards meeting the capacity needs of the day being pre-scheduled. Any deficiency in the projected operating reserve for the next day, after consideration of available internal generation resources is met by additional firm purchased power resources. The day-of resource coordination involves minimizing system production costs each hour by either changing the generation output or buying needed power/selling excess power in the wholesale market. Any sale of excess power priced above the incremental cost of producing such power reduces the net production cost of operating the electrical 67 system and thereby benefits the end use customer. The Utilities endeavor to reduce the electrical systems' net production cost by selling the available excess power resources. Real-time resource coordination requires an hourly determination of whether to run generation or purchase power in order to achieve the lowest production costs by calculating the projected incremental or decremental cost of generation required to meet the forecast load in comparison to obtaining power in the wholesale power market. In the event that committed generators suffer a forced outage that is expected to last through the remaining monthly period, the operating cost of the next available generation resource is compared to purchase power options to determine the lowest cost option. Term Power Procurement Strategy The majority of the Utilities' purchased power resources are secured through term transactions (transactions of greater than one month). To coordinate fuel and purchase power resources, the Utilities analyze their existing portfolios of fuel and purchased power and the projected electrical system loads for the period under consideration. Existing contracts for natural gas and purchased power are compared to the projected load profile to determine if there are adequate resources to cover the peak loads plus reasonable reserves. If monthly resources are insufficient to cover the average daily peak plus 7%, the cost of generating additional electrical energy is compared to the available purchase power cost to determine the lowest cost option for securing additional power resources. If the monthly resources exceed the requirements of the average daily peak plus 7%, the Utilities analyze whether it is more cost-efficient to sell off power and power resources or to keep the excess power to cover generation contingencies and deal with the excesses on a daily or hourly basis. Hedging Transactions Over the last two years the Utilities have used hedges to reduce price and commodity risk for future purchases by executing contracts at so-called "liquid" trading points. A liquid trading point is a hub where significant volumes of energy are freely purchased and sold amongst many parties at a heavy volume so that one particular transaction has no discernable effect on the market price of energy at that trading point. The hedged purchases are either delivered to the Utilities' service territories to service their customers or, if the hedged purchase is not needed to fulfill power requirements, resold in the liquid market depending upon the size of the load, the status of internal generation, and the market price at time of delivery. A typical hedge transaction involves the purchase or sale of power at one of the major trading hubs where prices are highly correlated to the ultimate point of delivery. The following is an illustration of a typical hedging transaction for NPC. NPC's main point of interconnection with the Western System Coordinating Council grid is at Mead Substation, Nevada. If NPC seeks to purchase 25 MW of power for delivery on a specified future date, NPC can purchase energy from other major trading hubs that are highly correlated to Mead, such as Palo Verde, Arizona, thereby assuring the availability of 25 MW electricity on that date to meet anticipated loads. By purchasing power at Palo Verde, NPC is also protected from the risk of market participants knowing that NPC must make a purchase and the resultant increase in prices at NPC's primary point of delivery. Once it makes the purchase at Palo Verde, NPC will continually monitor whether other power might be available at a lower total cost, including the cost of transmitting the electricity to NPC's system. If NPC finds an opportunity to purchase the same amount of power at delivery hubs closer to Mead, such as Pinnacle Peak Substation in Arizona, for a lower total cost than taking delivery of the original purchase at Palo Verde, NPC will sell its 25 MW position at Palo Verde and purchase the 25 MW position for delivery at Pinnacle Peak. Shortly before the date of delivery, NPC may have an opportunity to procure yet another source of power that will deliver 25 MW more cheaply, on a total cost basis, directly to Mead Substation. NPC would 68 therefore sell the 25 MW position at Pinnacle Peak and purchase the 25 MW position for delivery at Mead Substation. In the above example, NPC will record a total of 75 MW of purchased power expense, 50 MW of wholesale power sales and 25 MW of retail sales, all of which are related to meeting the same 25 MW load requirement. This series of transactions is designed to acquire power at the lowest feasible total cost while at the same time ensuring that the basic commodity will be available on the date needed. At no time are the Utilities trading power on a speculative basis. Any savings in costs achieved by such a series of transactions will lower the Utility's overall costs for purchased power and therefore reduce the Utility's deferred energy account balance. RESULTS OF OPERATIONS - OTHER SUBSIDIARIES ------------------------------------------ Tuscarora Gas Pipeline Company TGPC, a wholly owned subsidiary of SPR, contributed $2.6 million in net income for the twelve months ended December 31, 2001, and $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 $711,000 in net income for the five months ended December 31, 1999, and $1.8 million in net income for the twelve months ended December 31, 1999. Sierra Pacific Communications SPC, a wholly owned subsidiary of SPR, incurred a net loss of ($2.9) million for the twelve months ended December 31, 2001, and a net loss of ($989,000) 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 ($62,000) for the five months ended December 31, 1999, and a net loss of ($75,000) for the twelve months ended December 31, 1999. e.three e.three, a wholly owned subsidiary of SPR, contributed $666,000 of net income for the twelve months ended December 31, 2001, and $338,000 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 ($381,000) for the five months ended December 31, 1999, and a net loss of ($788,000) for the twelve months ended December 31, 1999. Sierra Pacific Energy Company SPE, a wholly owned subsidiary of SPR, incurred a net loss of ($335,000) for the twelve months ended December 31, 2001, and 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, and a net loss of ($3.6) million for the twelve months ended December 31, 1999. 69 Lands of Sierra LOS, a wholly owned subsidiary of SPR, incurred a net loss of ($281,000) for the twelve months ended December 31, 2001, and a net loss of ($191,000) 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 $816,000 for the five months ended December 31, 1999, and net income of $810,000 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 $101,000 for the twelve months ended December 31, 2001, and net income of $384,000 for the twelve months ended December 31, 2000. Prior to 2000, NEICO was a wholly owned subsidiary of NPC. Accordingly, NEICO's operating results for the twelve months ended December 31, 1999 (a net loss of $594,000), are included in NPC's operating results for that period. Sierra Pacific Resources (Holding Company) The holding company operating results included approximately $55.8 million, $44.5 million, and $11.5 million of interest costs for 2001, 2000, and 1999, respectively, that resulted primarily from the merger financing. For additional merger information, see Note 2 to the Consolidated Financial Statements included in this report. REGULATION AND RATE PROCEEDINGS ------------------------------- Nevada Matters (NPC and SPPC) ----------------------------- The Utilities are subject to the jurisdiction of the PUCN and, in the case of SPPC, the California Public Utility Commission (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. NPC and SPPC submit integrated resource plans 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 interstate transmission. The FERC also has jurisdiction over the natural gas pipeline companies from which the Utilities 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, are subject to the approval of governmental agencies. As with other utilities, NPC 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 or 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 that oversees NPC, SPPC, and SPR's corporate performance and achievements related to the environment. 70 Nevada Legislation ------------------ On April 18, 2001, the Governor of Nevada signed into law AB 369. The provisions of AB 369 include a moratorium on the sale of generation assets by electric utilities, the repeal of electric industry restructuring, and a reinstatement of deferred energy accounting for fuel and purchased power costs incurred by electric utilities. The stated purposes of this emergency legislation were, among others, to control volatility in the price of electricity in the retail market in Nevada, and to ensure that the Utilities have the necessary financial resources to provide adequate and reliable electric service under present market conditions. To achieve these purposes, AB 369 allows the Utilities to recover in future periods their current costs for wholesale power and fuel, which have risen dramatically over the past year. Deferred energy accounting will have the effect of delaying additional rate increases to consumers until the second quarter of 2002 while, at the same time, providing a method for the Utilities to recover their increased costs for fuel and purchased power. Set forth below is a summary of key provisions of AB 369. Generation Divestiture Moratorium AB 369 prohibits all divestiture of generation assets by electric utilities until July 2003. After January 1, 2003, NPC or SPPC may seek PUCN permission to sell one or more generation assets with the sale to be effective on or after July 1, 2003. The PUCN may approve the request to divest only if it finds the transaction to be in the public interest. The PUCN may base its approval of the request upon such terms, conditions, or modifications as it deems appropriate. AB 369 directs the PUCN to take all steps necessary to obtain federal approval for the prohibition on divestiture and to vacate any of its own orders that had previously approved generation divestiture transactions. Deferred Energy Accounting AB 369 required the Utilities to use deferred energy accounting for their respective electric operations beginning on March 1, 2001. The intent of deferred energy accounting is to ease the effect of fluctuations in the cost of purchased power and fuel. See Note 3 to the Financial Statements for a discussion of the deferred energy accounting provisions of AB 369. Transition of Rates to Deferred Energy Accounting All rates in effect on April 1, 2001, including the cumulative increases under the Global Settlement and the CEP Riders, remain in effect until the PUCN issues final orders on future general and initial deferred energy rate applications. (See "Required Filings," below). No further applications can be made for the Fuel and Purchased Power (F&PP) riders that were part of the July 2000 Global Settlement described in SPR's Annual Report on Form 10-K for the year ended December 31, 2000. The Utilities are not permitted to recover any shortfall incurred before March 1, 2001, resulting from the difference between actual fuel and purchased power costs and the rates permitted by the Global Settlement. Although the F&PP riders were in effect during this period, the riders were based on trailing 12-month average costs and were subject to caps and, therefore, did not allow the Utilities full recovery for fuel and purchased power costs due to the rapid rise in energy prices. AB 369 prohibits the PUCN from taking any further action on the CEP, and provides that, except for the CEP Rider rate increases put in effect on April 1, 2001, the CEP will be deemed to have been withdrawn by the Utilities. Additionally, approximately $20 million of revenue collected by the Utilities based on the CEP before 71 April 1, 2001 was credited to the deferred energy accounts, which caused the accounts to start in an over-collected position. Required Filings The Utilities have both filed a general rate application and a deferred energy application on the dates listed below:
General Rate Case Deferred Energy Filing ----------------- ---------------------- File Date Effective Date File Date Effective Date Nevada Power Company Oct. 1, 2001 April 1, 2002 Dec. 1, 2001 April 1, 2002 Sierra Pacific Power Company Dec. 1, 2001 June 1, 2002 Feb. 1, 2002 June 1, 2002
In connection with clearing the Utilities' deferred energy accounts, the PUCN must investigate and determine whether the Utilities' rates that went into effect on March 1, 2001, pursuant to the CEP, are just and reasonable and reflect prudent business practices. The rates in effect on April 1, 2001, remain in effect until the PUCN issues final orders on the general and initial deferred energy rate applications referred to above. The PUCN is prohibited from adjusting rates during this time period unless an adjustment is absolutely necessary to avoid a finding that the rates are confiscatory and, therefore, in violation of the United States or Nevada Constitutions. If adjustments are necessary, they may only be made to the extent necessary to avoid an unconstitutional result. After the initial general rate applications described above, each Utility will be required to file future general rate applications at least every 24 months. See "Nevada Power Company General Rate Case," later, for a discussion of NPC's general rate application filed on October 1, 2001 and "Nevada Power Company Deferred Energy Case," later, for a discussion of NPC's deferred rate application filed on November 30, 2001. See "Sierra Pacific Power Company General Rate Case," later, for a discussion of SPPC's general rate application filed on November 30, 2001 and "Sierra Pacific Power Company Deferred Energy Case," later, for a discussion of SPPC's deferred rate application filed on February 1, 2002. Restrictions on Mergers and Acquisitions AB 369 imposes certain restrictions on mergers and acquisitions involving Nevada electric utilities. In particular, the PUCN may not approve a merger or acquisition involving an electric utility unless the utility complies with the generation divestiture provisions of AB 369. In addition, AB 369 includes provisions that would have significantly affected the required regulatory approvals for the proposed acquisition of PGE from Enron. On April 26, 2001, Enron and SPR terminated, by mutual agreement, the proposed purchase and sale of PGE. AB 369 also provides that if an electric utility holding company acquires an interest in an out-of-state public utility prior to July 1, 2003, each electric utility in which the holding company holds a controlling interest shall not be entitled to the benefit of deferred energy accounting. Thus, in the event that SPR acquires an out-of-state public utility, NPC and SPPC would lose the ability to utilize deferred energy accounting. 72 Repeal of Electric Industry Restructuring AB 369 repeals all statutes authorizing retail competition in Nevada's electric utility industry and voids any license issued to an alternative seller in connection with retail electric competition. Other Legislation SB 372, which increased renewable energy portfolio requirements, was enacted in the 2001 Nevada legislative session. Renewable resources include biomass, wind, solar, and geothermal projects. In 2003, the Utilities will be required to purchase five percent of their energy from renewable resources. These requirements increase to 15% by 2013. Prior law capped renewable energy requirements at one percent. Currently, SPPC obtains approximately nine percent of its energy from renewable resources, while NPC obtains less than one percent from renewables. SB 372 requires the PUCN to establish standards for renewable energy contracts, including prices and other terms and conditions. If sufficient renewable energy contracts that meet PUCN standards are not available, the Utilities will not be required to meet the portfolio requirements. All renewable energy contracts meeting PUCN standards will be recoverable in the deferred energy accounts. The 2001 Nevada legislature passed another key piece of legislation for the Nevada energy industry, AB 661. AB 661 allows commercial and governmental customers with an average demand greater than 1 MW to select new energy suppliers. The Utilities would continue to provide transmission, distribution, metering and billing services to such customers. AB 661 requires customers wishing to choose a new supplier to receive the approval of the PUCN and meet public interest standards. In particular, departing customers must secure new energy resources that are not under contract to the Utilities, remaining customers or the utility cannot be negatively impacted by the departure, and the departing customers must pay any deferred energy balances. The PUCN has adopted regulations prescribing the criteria that will be used to determine if there will be negative impacts to remaining customers or the utility. Certain limits are placed upon the departure of NPC customers until 2003; most significantly, the amount of load departing is limited to approximately 1100 MW in peak conditions. AB 661 permits customers to file applications with the PUCN beginning in the fourth quarter of 2001. Customers must provide 180-day notice to the Utilities and could begin to receive service from new suppliers by mid-2002. On January 10, 2002, an approximately 130 MW SPPC customer submitted an application to the PUCN under AB 661. The customer, SPPC, and PUCN staff are negotiating a stipulation regarding settlement of the terms and conditions under which this customer will be permitted to procure energy from an alternative source other than SPPC. The terms and conditions of the stipulation are expected to comply with the provisions of AB 661 in that SPPC and its remaining customers will not be negatively impacted by the customer's departure. A hearing on the stipulation has been set for March 20, 2002. AB 661 also contains new electric and gas energy surcharges for low-income assistance and weatherization programs. These surcharges are recoverable directly from customers as separate line items on their bills with the Utilities remitting collected surcharges to the PUCN. Various state agencies will administer the disposition of the funds. Nevada Power Company General Rate Case (NPC) On October 1, 2001, NPC filed an application with the PUCN seeking an electric general rate increase. This application was mandated by AB 369, which was enacted by the Nevada legislature in April 2001. On December 21, 2001, NPC filed a Certification to its general rate filing updating costs and revenues pursuant to Nevada regulations. In the certification filing, NPC requested an increase in its general rates charged to all classes of electric customers designed to produce an increase in annual electric revenues of $22.7 million, which is an overall 1.7% rate increase. The application also seeks a return on common equity ("ROE") for Nevada Power's total electric operations of 12.25% (a reduction from NPC's last-authorized ROE for bundled electric 73 operations of 12.50%) and an overall rate of return ("ROR") of 9.30% (a reduction from NPC's last-authorized ROR for bundled electric operations of 10.02%). Public hearings on NPC's general rate case began on February 4, 2002. Various parties have intervened in NPC's general rate case including the Staff of the PUCN, the Bureau of Consumer Protection from the Nevada Attorney General's office, MGM/Mirage, and the Nevada Coalition Of Commercial Energy Consumers. The reduction of NPC's revenue requirements proposed by the intervenors ranges from $50 million to $107 million. Nevada Power Company Deferred Energy Case (NPC) On November 30, 2001, NPC filed an application with the PUCN seeking to clear deferred balances for purchased fuel and power costs accumulated between March 1, 2001 through September 30, 2001. This application was mandated by AB 369, which was enacted by the Nevada Legislature in April 2001. The application seeks to establish a Deferred Energy Accounting Adjustment ("DEAA") rate to clear accumulated purchased fuel and power costs of $922 million and spread the cost recovery over a not more than three-year period. It also seeks to recalculate the Base Tariff Energy Rate to reflect anticipated ongoing purchased fuel and power costs. The total rate increase resulting from the DEAA would amount to 21%. NPC has proposed an alternate plan in which full recovery of the deferred balance would be amortized over a period greater than three years, but not to exceed six years. Public hearings began March 4, 2002. Various parties have intervened in NPC's deferred energy rate case including the Staff of the PUCN, the Bureau of Consumer Protection from the Nevada Attorney General's office, MGM/Mirage, the Southern Nevada Water Authority, the Nevada Energy Buyers Group, and the Nevada Coalition Of Commercial Energy Consumers. The disallowance of NPC's deferred energy balance that is proposed by the intervenors ranges from $85 million to $980 million. The disallowance of a significant amount of NPC's deferred energy costs could result in NPC becoming insolvent. Some intervenors have argued that disallowance of NPC's deferred energy costs would be in the best interests of ratepayers based on speculation that some of the deferred energy costs could be avoided under bankruptcy laws if NPC were to become subject to bankruptcy proceedings. Sierra Pacific Power Company General Rate Case (SPPC) On November 30, 2001, SPPC filed an application with the PUCN seeking an electric general rate increase. This application was mandated by AB 369, which was enacted by the Nevada Legislature in April 2001. On February 28, 2002, SPPC filed a certification to its general rate filing, updating costs and revenues pursuant to Nevada regulations. In the certification filing, SPPC requested an increase in its general rates charged to all classes of electric customers, which were designed to produce an increase in annual electric revenues of $15.9 million representing an overall 2.4% rate increase. The application also seeks an ROE for SPPC's total electric operations of 12.25% (an increase from SPPC's last authorized ROE for bundled electric operations of 12.0%) and an overall ROR of 9.42% (a reduction from SPPC's last authorized ROR for bundled electric operations of 10%). Public hearings for SPPC's general rate case are scheduled to begin on April 8, 2002. Various parties have intervened in SPPC's general rate case including the Staff of the PUCN, the Bureau of Consumer Protection from the Nevada Attorney General's office, and Barrick Goldstrike Mines, among others. Intervenor testimony will not be filed until March 22, 2002. Sierra Pacific Power Company Deferred Energy Case (SPPC) On February 1, 2002, SPPC filed an application with the PUCN seeking to clear deferred balances for purchased fuel and power costs accumulated between March 1, 2001 and November 30, 2001. This application was mandated by AB 369. The application seeks to establish a DEAA rate to clear accumulated purchased fuel and power costs of $205 million and spread the cost recovery over a not more than three-year period. It also seeks to recalculate the Base Tariff Energy Rate to reflect anticipated ongoing purchased fuel and power costs. The total rate increase resulting from the DEAA would amount to 9.8%. SPPC has proposed an alternate plan in which full recovery of the deferred balance would be amortized over a period greater than three years, but not to exceed six years. Public hearings are scheduled to begin in April 2002. Various parties have intervened in SPPC's deferred energy rate case including the Staff of the PUCN, the Bureau of Consumer Protection from the Nevada Attorney General's office, and Barrick Goldstrike Mines, among others. Intervenor testimony will not be filed until April 22, 2002. The disallowance of a significant amount of SPPC's deferred energy costs could result in SPPC becoming insolvent. 74 Resource Plans (SPPC, NPC) On July 2, 2001, SPPC filed its electric resource plan for the period of 2001-2020. On July 9, 2001, NPC filed its amended electric resource plan for the period of 2000-2019. The plans include scenarios to meet the electric needs of customers while sustaining reliable electric systems. The integrated resource plans evaluate resources to be used to meet forecasted loads. Resource options considered include new transmission lines to access energy markets, construction of generation facilities, power purchases from IPP's under short- and long-term agreements, and conservation programs. On October 18, 2001, the PUCN approved NPC's amended resource plan. On August 2, 2001, a pre-hearing conference was held on SPPC's resource plan and procedural orders were established. Public hearings on SPPC's plan were held in late October, and on November 1, 2001, the PUCN issued an order approving and adopting SPPC's plan. PUCN Rulemaking for Assembly Bill 661 (SPPC, NPC) The PUCN opened an investigatory and rulemaking docket to implement the provisions of AB 661. The PUCN has scheduled a workshop to receive comments regarding proposed regulations. These regulations concern eligible customers purchasing new electric resources from suppliers other than SPPC or NPC. A public hearing regarding the regulation was held on October 30, 2001. On November 26, 2001, the PUCN approved the regulations. Optional Conservation Service (NPC, SPPC) On April 19, 2001, the PUCN approved new NPC and SPPC electric rates for Optional Conservation Service (Schedule OC). Schedule OC allows the Utilities to request customers with demand greater than 1 MW to voluntarily curtail their load when there is an economic or system need for capacity and energy. Customers who curtail load will receive a billing credit. Parallel Generation Tariffs (NPC, SPPC) On May 11, 2001, the Utilities filed with the PUCN revisions to existing tariffs that will allow customers to interconnect standby generators in parallel with the Utilities' facilities. These changes will allow customers meeting specific requirements to utilize their standby generators in support of the Optional Conservation Service tariffs during times of power shortages or higher prices. On August 3, 2001, the PUCN approved the revisions. Finance Authority (NPC, SPPC) On September 20, 2001, the PUCN approved the June 19, 2001 applications by the Utilities for authority to issue long or short-term debt on either a secured or unsecured basis in an aggregate amount not to exceed $200 million for NPC and $100 million for SPPC through the end of 2002. NPC has issued all of its $200 million of authorized debt. SPPC has not issued any debt under this authority and has the full amount of the $100 million of authorized debt available for future issuances. On September 20, 2001, the PUCN also approved the Utilities' June 19, 2001 applications to amend an order issued by the PUCN allowing each of the Utilities to issue unsecured short-term promissory notes in an amount not to exceed $250 million through the period ending December 31, 2001. In the applications, the Utilities requested that the PUCN amend its previous order to provide the Utilities with the flexibility to issue secured promissory notes in addition to, or in lieu of, the authorized unsecured promissory notes. On October 1, 2001, NPC and SPPC each filed an application with the PUCN requesting authority to issue secured or unsecured promissory notes in aggregate amounts not to exceed $250 million through December 31, 2004. On October 9, 2001, the Utilities filed amended applications reducing the time period to 75 December 31, 2003. On November 29, 2001, the PUCN issued a compliance order approving the requests. Currently, NPC has $50 million and SPPC has $100 million of short-term debt authority remaining from these PUCN authorizations. Natural Gas Rate Increase (SPPC) On June 29, 2001, SPPC filed with the PUCN a Purchase Gas Adjustment (PGA) seeking recovery of $41.4 million in accumulated, unrecovered purchased gas expenses, and an increase in the going-forward rate to $.71 per therm. Public hearings were held on October 22 and 23, 2001. On November 5, 2001, the PUCN granted SPPC's application and approved recovery of the entire $41.4 million accumulated deferred balance over a three-year period and an increase in the going-forward rate to $.6648 per therm. Any over or under-recovery of future energy costs will be the subject of a future PGA application. SPPC will file its next PGA on July 1, 2002. SPR and NPC Merger (NPC and SPPC) The merger between SPR and NPC was finalized on July 28, 1999. As part of the conditions for the merger, the Utilities were each required to divest all generation assets and file a general rate case unbundling costs. In May 1999, the Nevada Legislature passed SB 438, which modified the electric restructuring statutes. The Utilities filed general rate cases, unbundling costs and filed distribution rates for an unregulated market. However, in April of 2001 the Nevada Legislature passed AB 369, discussed earlier, which repealed the condition that the Utilities divest their generation assets and placed a moratorium on the sale of any generation assets until July 2003. AB 369 also repealed electric restructuring (deregulation). FERC Matters (NPC and SPPC) --------------------------- Price Mitigation Plan On June 19, 2001, the FERC adopted a price mitigation plan applicable to spot market wholesale power sales in California and throughout the western United States during the period June 20, 2001 through September 30, 2002. The price mitigation plan establishes a mechanism with which to determine the maximum amount that may be charged for power sold during this period. The intent of the mitigation plan is to simulate the price that might be charged for electricity sold under competitive market conditions. Sellers that do not wish to establish rates on the basis of this price mitigation plan may propose cost-of-service rates covering all of their generating units in the WSCC for the duration of the mitigation plan. Although the Utilities are not able to predict at this time the long-term effect that the FERC price mitigation plan and other market developments may have on their results of operations, management believes that, under certain market conditions, the FERC plan adversely affects the availability of spot market power to the Utilities and reduces the price at which the Utilities can sell power on the wholesale market. Another potential result from these price mitigation measures could be the delay and/or cancellation of proposed power plants throughout the western United States. If these results occur, the long-term supply of energy could be reduced. Numerous parties, including NPC and several northwest utilities, appealed the June 19 and July 25, 2001 orders from the FERC to the District of Columbia Court of Appeals on the basis that the price caps are unfair to electric customers who reside outside of California. In a report to Congress on January 31, 2002, the FERC said the price mitigation plan had little if any influence on prices at which Western utilities were able to resell power. SPR is not persuaded by the FERC's report and continues to believe that the FERC's price caps have negatively impacted electric customers outside California. The parties to the appeal await action by the Court. 76 Regional Transmission Organization and Independent Transmission Company NPC and SPPC are members of the utility groups that are forming a proposed regional transmission organization (RTO West) and a proposed independent transmission company (TransConnect). In October 2000, RTO West submitted to the FERC a compliance filing and supplemental material, which provided details of the formation of the RTO. RTO West, as proposed, would be a non-profit independent system operator of the regional transmission grid, governed by an independent board of directors. 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. Also in October 2000, TransConnect submitted to the FERC a proposal to form a for-profit Independent Transmission Company which would become a member of RTO West. On April 25, 2001, FERC gave preliminary approval for both RTO West and TransConnect. On November 13, 2001, TransConnect submitted a filing to FERC asking for preliminary approval of its proposed transmission rate structure, modified governance proposal, and transmission planning and expansion protocol. On December 1, 2001, RTO West submitted a status report on its development efforts to FERC in compliance with FERC's April 2001 order. Both organizations remain subject to approvals from state regulators and the board of directors of each member company. The current filing utility members of RTO West are NPC, SPPC, Avista Corporation, British Columbia Hydro & Power Authority, Bonneville Power Administration (BPA), Idaho Power Company, The Montana Power Company, PacifiCorp, Portland General Electric, and Puget Sound Energy, Inc. The current filing utility members of TransConnect are NPC, SPPC, Avista Corporation, and Portland General Electric. Wholesale Sales Tariffs On March 13, 2001, the Utilities each filed an application for an order approving market-based rates. The market-based authority would apply to sales of electric energy and capacity outside of the Utilities' control areas. On May 11, 2001, SPPC and NPC received approval for market-based rates subject to a compliance order. SPPC's and NPC's compliance filing was accepted on August 10, 2001. Alturas Intertie Certain Northern California public power groups have challenged SPPC'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. SPPC (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 SPPC's position on this matter. The matter was tried to an Administrative Law Judge (ALJ) in April and May 2000. In 2001, the ALJ agreed with SPPC's position, but imposed a limitation on additional transfer capacity created by future upgrades to the system. The ALJ stated allocation of additional transfer capacity would require agreement among the parties. Both sides have appealed this decision to the full FERC. 77 California Matters (SPPC) ------------------------- Rate Stabilization Plan SPPC serves approximately 44,500 customers in California. On June 29, 2001, SPPC filed with the CPUC a Rate Stabilization Plan, which includes two phases. Phase One, which was also filed June 29, 2001, is an emergency electric rate increase of $10.2 million annually or 26%. If granted, the typical residential monthly electric bill for a customer using 650 kilowatt-hours would increase from approximately $47.12 to $60.12. On August 14, 2001, a pre-hearing conference was held, and a procedural order was established. On September 27, 2001, the Administrative Law Judge issued an order stating that no interim or emergency relief could be granted until the end of the "rate freeze" period mandated by the California restructuring law for recovery of stranded costs. In accordance with the judge's request, on October 26, 2001, SPPC filed an amendment to its application declaring the rate freeze period to be over. Phase Two, which is scheduled to be filed with the CPUC in April 2002, will be a general rate case to recover costs for expenses other than fuel and purchased power. SPPC will also ask the CPUC to reinstate the Energy Cost Adjustment Clause, which would allow SPPC to file for periodic rate adjustments to reflect its actual costs for fuel and purchased power. Phase Two will also include a proposal pertaining to the termination of the 10% rate reduction mandated by AB 1890. On December 5 and 11, 2001 hearings on Phase One were held and on January 11, 2002, opening briefs were filed. Reply briefs were filed on January 25, 2002. A proposed draft decision is expected by the end of March 2002. SPPC will file Phase Two on April 1, 2002. Distribution Performance-based Rate-making Hearings on SPPC's distribution performance -based rate-making (PBR) proposal were held on April 2, 2001. An outline of the settlement reached by SPPC, the CPUC Office of Ratepayer Advocates, and The Utility Reform Network resolving all issues was presented during the hearing. On May 11, 2001, a formal joint settlement was submitted to the Administrative Law Judge. To date there has been no formal action on the filed joint settlement. On December 11, 2001, the Commission approved an order dismissing the application because of the pending emergency rate increase request and SPPC's plans to file a GRC. This decision approved parts of the joint settlement agreement and the record of the proceeding will be available for use in future proceedings before the Commission. California Assembly Bill 6X On January 18, 2001, the California Legislature passed Assembly Bill (AB) 6X. AB 6X modified Section 377 of California law restricting the sale of generation assets. AB 6X states that no facility for the generation of electricity owned by a public utility may be disposed of prior to January 1, 2006. Since SPPC is a public utility serving California customers, the sale of SPPC's generation assets was halted. The sale of the Mohave Generating Station, in which NPC has a 14% undivided interest, was also stopped because Southern California Edison is an operating partner of that facility. 78 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. Such instruments are fixed and variable rate debt, and preferred trust securities obligations, which were as follows on December 31, 2001, and 2000. 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 December 31, 2001 Date --------------------------------------------------------------------------------------------------------- Expected Maturities Amounts Weighted Avg Int Rate * Fair Market Value --------------------------------------------------------------------------------------------------------- Fixed Rate NPC SPPC SPR Consolidated Consolidated Consolidated ------------------------------------------------------- --------------------- ------------------- 2002 $ 15,000 $ 2,630 $ - $ 17,630 7.40% 2003 210,000 20,632 - 230,632 5.97% 2004 130,000 2,621 - 132,621 6.10% 2005 - 2,622 300,000 302,622 8.73% 2006 - 52,629 - 52,629 6.71% Thereafter 938,835 845,527 345,000 2,129,362 6.87% ------------------------------------------------------- --------------------- ------------------- Total Fixed Rate $1,293,835 $ 926,661 $ 645,000 $ 2,865,496 $ 2,953,374 ------------------------------------------------------- --------------------- ------------------- Variable Rate 2002 $ - $ - $ 100,000 $ 100,000 3.04% 2003 140,000 - 200,000 340,000 3.43% 2004 - - - - 2005 - - - - 2006 - - - - Thereafter 115,000 - - 115,000 1.82% ------------------------------------------------------- --------------------- ------------------- $ 255,000 $ - $ 300,000 $ 555,000 $ 549,400 ------------------------------------------------------- --------------------- ------------------- Preferred securities (fixed rate) After 2006 $ 188,872 $ - $ - $ 188,872 8.03% ------------------------------------------------------- --------------------- ------------------- $ 188,872 $ - $ - $ 188,872 $ 181,525 ------------------------------------------------------- --------------------- ------------------- Total $1,737,707 $ 926,661 $ 945,000 $ 3,609,368 $ 3,684,299 ----------------------=======================================================-------------------------------===================
79
Expected Maturity December 31, 2000 --------------------------------------------------------------------------------------------------------- Expected Maturities Amounts Weighted Avg Int Rate * Fair Market Value --------------------------------------------------------------------------------------------------------- Fixed Rate NPC SPPC SPR 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 6.65% ======================================================= ===================== =================== Total Fixed Rate $ 734,042 $ 545,432 $ 300,000 $ 1,579,474 $ 1,579,221 ------------------------------------------------------- --------------------- ------------------- Variable Rate 2001 $ 250,000 $ 200,000 $ - $ 450,000 7.48% 2002 - - 100,000 100,000 7.29% 2003 - - 200,000 200,000 7.24% 2004 - - - - 2005 - - - - Thereafter 115,000 80,000 - 195,000 4.37% ======================================================= --------------------- =================== $ 365,000 $ 280,000 $ 300,000 $ 945,000 $ 941,920 ------------------------------------------------------- --------------------- ------------------- Peferred securities (fixed rate) After 2005 $ 188,872 $ 48,500 $ - $ 237,372 8.15% $ 234,792 ======================================================= ===================== =================== Total $1,287,914 $ 873,932 $ 600,000 $ 2,761,846 $ 2,755,933 ----------------------=======================================================-------------------------------===================
* Weighted daily average rate for months ended December 31, 2001, and 2000. 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. See Purchased Power Procurement in Item 7, Management's Discussion And Analysis Of Financial Condition And Results Of Operations, for a discussion of the Utilities' purchased power procurement strategies. The Utilities' efforts to manage energy commodity (electricity, natural gas, coal and oil) price risk are governed by a Board of Directors approved Energy Risk Management Policy. That policy is augmented by an IT system to track any commodity price exposure. The Energy Risk Management Policy sets forth business objectives, organizational structure, performance metrics and operating requirements. The policy also establishes guidelines for the Risk Management Committee ("RMC"), which is responsible for providing management advice and recommendations on energy risk management related issues. The RMC met periodically throughout 2001. The Utilities' commodity risk management program establishes a control framework based on existing commercial practices. The program creates common predefined risk parameters and delineates management responsibilities and organizational relationships. The program requires that transaction accounting systems and procedures be maintained for systematically identifying, measuring, evaluating and responding to the variety of risks inherent in the Utilities' commercial activities. The program's control framework consists of a disclosure and reporting mechanism designed to keep management fully informed of the operation's compliance with performance parameters. The objective of the Utilities' energy risk management program is to help management exercise informed judgments on risk assessment and management. Supporting activities are designed: 80 . To provide management with a quantification of the Utilities' cash flow requirements for fuel and purchased power; . To provide management with a quantification of the Utilities' cash flow sensitivity to movements in energy markets; . To provide management with a quantification of the expected retail rate impact attributable to expenditures for fuel and purchased power; . To provide management with estimates of the sensitivity of retail rates to movements in energy markets; . To extract market pricing information that can be used in future decisions; and . To help to optimize the output from the Utilities' generation assets. On March 1, 2001, deferred energy accounting procedures were applied to the Utilities' electric operations. Such procedures had been in place for SPPC's gas distribution company. Deferred energy accounting facilitates the recovery of costs incurred while procuring fuel and purchased power for SPPC and NPC. The Utilities also monitor and manage credit risk with their trading counterparties. As of December 31, 2001, the Utilities have outstanding transactions with over 40 energy and financial services companies. The Utilities had net credit risk with only eleven of their trading counterparties totaling approximately $2 million as of December 31, 2001. 81 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Page ---- Independent Auditors' Reports .......................................................................... 83-84 Financial Statements: Consolidated Balance Sheets as of December 31, 2001 and 2000 ................................... 85 Consolidated Statements of Income for the Years Ended December 31, 2001, 2000 and 1999 ......................................................................... 86 Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2001, 2000 and 1999 ............................................................ 87 Consolidated Statements of Common Shareholders' Equity for the Years Ended December 31, 2001, 2000 and 1999 ................................................ 87 Consolidated Statements of Cash Flows for the Years Ended December 31, 2001, 2000 and 1999 ............................................................ 88 Consolidated Statements of Capitalization as of December 31, 2001 and 2000 ..................... 89-90 Balance Sheets for Nevada Power Company as of December 31, 2001 and 2000 .................................................................. 91 Statements of Income for Nevada Power Company for the Years Ended December 31, 2001, 2000 and 1999 ........................................ 92 Statements of Cash Flows for Nevada Power Company for the Years Ended December 31, 2001, 2000 and 1999 ........................................ 93 Statements of Capitalization for Nevada Power Company as of December 31, 2001 and 2000 ..................................................... 94 Consolidated Balance Sheets for Sierra Pacific Power Company as of December 31, 2001 and 2000 .................................................................. 95 Consolidated Statements of Income for Sierra Pacific Power Company for the Years Ended December 31, 2001, 2000 and 1999 ........................................ 96 Consolidated Statements of Comprehensive Income for Sierra Pacific Power Company for the Years Ended December 31, 2001, 2000 and 1999 ................................ 97 Consolidated Statements of Common Shareholders' Equity for Sierra Pacific Power Company for the Years Ended December 31, 2001, 2000 and 1999 .......................... 97 Consolidated Statements of Cash Flows for Sierra Pacific Power Company for the Years Ended December 31, 2001, 2000 and 1999 ........................................ 98 Consolidated Statements of Capitalization for Sierra Pacific Power Company as of December 31, 2001 and 2000 ..................................................... 99 Notes to Financial Statements .......................................................................... 100
82 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 (NPC) as of December 31, 2001 and 2000, and the related statements of income, comprehensive income, common shareholders' equity, and cash flows for each of the three years in the period ended December 31, 2001. Our audit also included the consolidated and unconsolidated 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 NPC'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 NPC as of December 31, 2001 and 2000, and the respective results of their operations and their cash flows for each of the three years in the period ended December 31, 2001 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 22, 2002 83 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, 2001 and 2000, and the related consolidated statements of income, comprehensive income, common shareholder's equity, and cash flows for each of the three years in the period ended December 31, 2001. 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, 2001 and 2000, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2001, 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 22, 2002 84 SIERRA PACIFIC RESOURCES CONSOLIDATED BALANCE SHEETS (Dollars in Thousands)
December 31, 2001 2000 ----------- ----------- ASSETS Utility Plant at Original Cost: Plant in service $ 5,683,296 $ 5,269,724 Less: accumulated provision for depreciation 1,777,517 1,636,657 ----------- ----------- 3,905,779 3,633,067 Construction work-in-progress 203,456 347,299 ----------- ----------- 4,109,235 3,980,366 ----------- ----------- Investments in subsidiaries and other property, net 128,892 135,062 ----------- ----------- Current Assets: Cash and cash equivalents 99,109 51,503 Accounts receivable less provision for uncollectible accounts: 2001-$39,335; 2000-$13,194 394,489 388,332 Deferred energy costs - electric (Note 1) 333,062 - Deferred energy costs - gas (Note 1) 19,805 - Federal income tax receivable 18,590 32,904 Materials, supplies and fuel, at average cost 94,167 75,132 Risk management assets (Note 22) 286,509 - Other 14,071 18,442 ----------- ----------- 1,259,802 566,313 ----------- ----------- Deferred Charges: Goodwill, net of amortization 312,145 320,256 Deferred energy costs - electric (Note 1) 854,778 - Deferred energy costs - gas (Note 1) 23,248 16,370 Federal income tax receivable 355,659 - Regulatory tax asset 169,738 175,509 Other regulatory assets 102,959 105,588 Risk management assets (Note 22) 61,058 - Risk management regulatory assets - net (Note 22) 664,383 - Other 139,417 116,965 ----------- ----------- 2,683,385 734,688 ----------- ----------- Net assets of discontinued operations (Note 17) - 261,479 ----------- ----------- $ 8,181,314 $ 5,677,908 =========== =========== CAPITALIZATION AND LIABILITIES Capitalization: Common shareholders' equity $ 1,702,322 $ 1,359,712 Accumulated other comprehensive income (6,986) - Preferred stock 50,000 50,000 SPPC/ NPC obligated mandatorily redeemable preferred trust securities 188,872 237,372 Long-term debt 3,376,105 2,133,679 ----------- ----------- 5,310,313 3,780,763 ----------- ----------- Current Liabilities: Short-term borrowings 177,000 213,074 Current maturities of long-term debt 122,010 472,527 Accounts payable 265,250 363,242 Accrued interest 37,565 30,184 Dividends declared 1,045 20,890 Accrued salaries and benefits 30,145 28,957 Deferred taxes on deferred energy costs 123,503 - Risk management liabilities (Note 22) 855,301 - Other current liabilities 15,678 10,013 ----------- ----------- 1,627,497 1,138,887 ----------- ----------- Commitments & Contingencies (Note 18) Deferred Credits: Deferred federal income taxes 412,658 406,310 Deferred investment tax credit 51,947 55,252 Deferred taxes on deferred energy costs 307,309 Regulatory tax liability 46,702 50,994 Customer advances for construction 108,179 109,962 Accrued retirement benefits 82,624 80,027 Risk management liabilities (Note 22) 163,636 - Other 70,449 55,713 ----------- ----------- 1,243,504 758,258 ----------- ----------- $ 8,181,314 $ 5,677,908 =========== ===========
The accompanying notes are an integral part of the financial statements. 85 SIERRA PACIFIC RESOURCES CONSOLIDATED STATEMENTS OF INCOME (LOSS) (Dollars in Thousands, Except Per Share Amounts)
Year ended December 31, 2001 2000 1999 ------------ ------------ ------------ OPERATING REVENUES: Electric $ 4,424,237 $ 2,219,252 $ 1,236,702 Gas 145,652 100,803 38,958 Other 18,841 14,199 9,132 ------------ ------------ ------------ 4,588,730 2,334,254 1,284,792 ------------ ------------ ------------ OPERATING EXPENSES: Operation: Purchased power 4,052,077 1,116,375 373,456 Fuel for power generation 728,619 526,535 206,130 Gas purchased for resale 136,534 83,199 27,262 Deferral of energy costs - electric - net (1,136,148) 16,719 97,238 Deferral of energy costs - gas - net (23,170) (16,164) - Other 331,961 260,496 193,391 Maintenance 69,499 52,477 59,297 Depreciation and amortization 164,640 156,035 110,075 Taxes: Income taxes (1,230) (31,022) 25,298 Other than income 43,079 42,215 29,784 ------------ ------------ ------------ 4,365,861 2,206,865 1,121,931 ------------ ------------ ------------ OPERATING INCOME 222,869 127,389 162,861 ------------ ------------ ------------ OTHER INCOME: Allowance for other funds used during construction 474 2,813 2,339 Other income (expense) - net 38,723 2,646 (2,325) ------------ ------------ ------------ 39,197 5,459 14 ------------ ------------ ------------ Total Income Before Interest Charges 262,066 132,848 162,875 ------------ ------------ ------------ INTEREST CHARGES: Long-term debt 188,370 134,596 77,494 Other 24,161 35,887 26,229 Allowance for borrowed funds used during construction and capitalized interest (2,801) (10,634) (8,000) ------------ ------------ ------------ 209,730 159,849 95,723 ------------ ------------ ------------ INCOME (LOSS) BEFORE SPPC/NPC OBLIGATED MANDATORILY REDEEMABLE PREFERRED TRUST SECURITIES 52,336 (27,001) 67,152 Preferred dividend requirements of SPPC/NPC obligated mandatorily redeemable preferred trust securities (18,770) (18,914) (16,742) ------------ ------------ ------------ INCOME (LOSS) BEFORE PREFERRED STOCK DIVIDENDS 33,566 (45,915) 50,410 Preferred stock dividend requirements of subsidiary (3,700) (3,499) (2,200) ------------ ------------ ------------ INCOME (LOSS) FROM CONTINUING OPERATIONS 29,866 (49,414) 48,210 ------------ ------------ ------------ DISCONTINUED OPERATIONS: Income from operations of water business disposed of (net of income taxes of $888, $3,426 and $788 in 2001, 2000 and 1999, respectively) 1,022 9,634 3,540 Gain on disposal of water business (net of income taxes of $18,237) 25,845 - - ------------ ------------ ------------ NET INCOME (LOSS) $ 56,733 $ (39,780) $ 51,750 ============ ============ ============ Income (Loss) per share - Basic and Diluted Income (Loss) from continuing operations $ 0.34 $ (0.63) $ 0.77 Income from discontinued operations 0.01 0.12 0.06 Gain on disposal of water business 0.30 - - ------------ ------------ ------------ Net income (loss) $ 0.65 (0.51) $ 0.83 ============ ============ ============ Weighted Average Shares of Common Stock Outstanding 87,542,441 78,435,405 62,577,385 ============ ============ ============ Annual Dividends Paid Per Share of Common Stock $ 0.65 $ 1.000 $ 1.165 ============ ============ ============
The accompanying notes are an integral part of the financial statements. 86 SIERRA PACIFIC RESOURCES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Dollars in Thousands)
Year ended December 31, --------------------------------------------- 2001 2000 1999 ----------- ----------- ----------- NET INCOME (LOSS) $ 56,733 $ (39,780) $ 51,750 OTHER COMPREHENSIVE INCOME, NET OF TAX: Adoption of SFAS No. 133- Accounting for Derivative Instruments and Hedging Activities: Cummulative effect upon adoption of change in accounting principle as of January 1 (1,923) - - Change in market value of risk management assets and liabilities as of December 31 (5,063) - - Minimum pension liability adjustment - (513) 1,001 ----------- ----------- ----------- OTHER COMPREHENSIVE INCOME (6,986) (513) 1,001 ----------- ----------- ----------- COMPREHENSIVE INCOME $ 49,747 $ (40,293) $ 52,751 =========== =========== ===========
The accompanying notes are an integral part of the financial statements SIERRA PACIFIC RESOURCES CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY (Dollars in Thousands)
Year ended December 31, --------------------------------------------- 2001 2000 1999 ----------- ----------- ----------- Common Stock: Balance at Beginning of Year $ 78,475 $ 78,414 $ 54,066 Stock purchase and dividend reimbursement 23,636 61 - Merger conversion - - 36,064 Merger cash consideration - - (11,716) ----------- ----------- ----------- Balance at End of Year 102,111 78,475 78,414 ----------- ----------- ----------- Other Paid-In Capital: Balance at Beginning of Year 1,295,221 1,293,990 683,156 Premium on sale of common stock 330,050 - - Common stock issuance costs (13,910) - - Purchase contract adjustment payments (13,676) - - CSIP, DRP, ESPP and other 949 1,231 1,409 Merger transactions - - 212,148 Revaluation of pension asset - - 66,103 Goodwill - - 331,174 ----------- ----------- ----------- Balance at End of Year 1,598,634 1,295,221 1,293,990 ----------- ----------- ----------- Retained Earnings (Deficit): Balance at Beginning of Year (13,984) 104,725 126,814 Income (loss) from continuing operations before preferred dividends 33,566 (45,915) 50,410 Income from discontinued operations (before preferred dividend allocation of $200, $401, and $196 in 2001, 2000, and 1999, respectively) 1,222 10,035 3,736 Gain on disposal of water business 25,845 - - Dividends declared and premium on redemption: Preferred stock of subsidiaries (3,900) (3,900) (2,721) Common stock (41,172) (78,929) (73,514) ----------- ----------- ----------- Balance at End of Year 1,577 (13,984) 104,725 ----------- ----------- ----------- Total Common Shareholders' Equity at End of Year $ 1,702,322 $ 1,359,712 $ 1,477,129 =========== =========== ===========
The accompanying notes are an integral part of the financial statements 87 SIERRA PACIFIC RESOURCES CONSOLIDATED STATEMENTS OF CASH FLOWS (Dollars in Thousands)
Year ended December 31, 2001 2000 1999 -------------- ------------- ------------ CASH FLOWS FROM OPERATING ACTIVITIES: Income (loss) from continuing operations before preferred dividends $ 33,566 $ (45,915) $ 50,410 Income from discontinued operations before preferred dividends 1,222 10,035 3,736 Gain on disposal of water business 25,845 - - Non-cash items included in income: Depreciation and amortization 168,100 163,370 113,236 Deferred taxes and deferred investment tax credit 85,917 (18,564) (16,543) AFUDC and capitalized interest (3,285) (13,858) (10,501) Deferral of energy costs - electric - net (1,187,840) 14,884 48,313 Deferral of energy costs - gas - net (26,683) - - Early retirement and severance amortization 3,121 4,196 1,748 Gain on disposal of water business (44,081) - - Other non-cash (11,473) 30,972 24,122 Changes in certain assets and liabilities, net of acquisition: Accounts receivable (1,841) (174,112) (7,393) Materials, supplies and fuel (18,682) (1,864) (3,846) Other current assets 4,248 (52,125) 155 Accounts payable (97,992) 224,794 49,655 Other current liabilities 14,752 16,359 (6,342) Other - net 9,885 27,724 (35,661) -------------- ------------- ------------ Net Cash Flows from Operating Activities (1,045,221) 185,896 211,089 -------------- ------------- ------------ CASH FLOWS USED IN INVESTING ACTIVITIES: Acquisition of business, net of cash acquired - - (448,311) Additions to utility plant (334,456) (359,774) (299,064) AFUDC and other charges to utility plant 3,285 15,227 (3,645) Customer refunds for construction 815 (889) 8,173 Contributions in aid of construction 27,481 16,446 13,053 -------------- ------------- ------------ Net cash used for utility plant (302,875) (328,990) (729,794) Proceeds from sale of assets of water business 318,882 - - (Investments in) disposal of subsidiaries and other property - net (6,335) (28,056) 1,366 -------------- ------------- ------------ Net Cash Used in Investing Activities 9,672 (357,046) (728,428) -------------- ------------- ------------ CASH FLOWS FROM FINANCING ACTIVITIES: (Decrease) increase in short-term borrowings (36,074) (547,310) 495,165 Proceeds from issuance of long-term debt 1,215,000 1,165,000 230,699 Retirement of long-term debt (323,091) (318,061) (63,293) Redemption of preferred stock (48,500) - (26,380) Sale of common stock 340,737 1,292 - Dividends paid (64,917) (83,057) (115,833) -------------- ------------- ------------ Net Cash Provided by Financing Activities 1,083,155 217,864 520,358 -------------- ------------- ------------ Net Increase in Cash and Cash Equivalents 47,606 46,714 3,019 Beginning balance in Cash and Cash Equivalents 51,503 4,789 1,770 -------------- ------------- ------------ Ending balance in Cash and Cash Equivalents $ 99,109 $ 51,503 $ 4,789 ============== ============= ============ Supplemental Disclosures of Cash Flow Information: Cash paid (received) during period for: Interest $ 208,390 $ 167,158 $ 127,063 Income taxes $ (55,022) $ 12,730 $ 43,719
The accompanying notes are an integral part of the financial statements 88 SIERRA PACIFIC RESOURCES CONSOLIDATED STATEMENTS OF CAPITALIZATION (Dollars in Thousands)
December 31, 2001 2000 ----------- ----------- Common Shareholders' Equity: Common stock $1.00 par value, authorized 250 million; issued and outstanding 2001: 102,111,000 shares; 2000, 78,475,000 shares $ 102,111 $ 78,475 Other paid-in capital 1,598,634 1,295,221 Retained earnings (deficit) 1,577 (13,984) ----------- ----------- Total Common Shareholders' Equity 1,702,322 1,359,712 ----------- ----------- Accumulated Other Comprehensive Loss (6,986) - ----------- ----------- 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: NPC obligated Mandatorily Redeemable Preferred Securities of NPC's Subsidiary Trust, NVP Capital I, holding solely $122.6 million principal amount of 8.2% Junior Subordinated Debentures of NPC, due 2037 118,872 118,872 NPC obligated Mandatorily Redeemable Preferred Securities of NPC's Subsidiary Trust, NVP Capital III, holding solely $72.2 million principal amount of 7.75% Junior Subordinated Debentures of NPC, 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 ----------- ----------- Total Preferred Securities 188,872 237,372 ----------- ----------- Long-Term Debt: Unamortized bond premium and discount, net (959) (913) Debt Secured by First Mortgage Bonds 7.63% Series L due 2002 15,000 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 2.00% Series Z due 2004 56 72 2.00% Series O due 2011 1,281 1,374 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. 89 SIERRA PACIFIC RESOURCES CONSOLIDATED STATEMENTS OF CAPITALIZATION (Dollars in Thousands)
Continued from previous page December 31, 2001 2000 ----------- ----------- 5.00% Series Y due 2024 3,072 3,138 6.70% Series II due 2032 21,200 21,200 5.47% Series D MTN due 2001 - 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 781,200 798,421 ----------- ----------- Industrial development revenue bonds 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 6.20% Series 1999B due 2004 130,000 130,000 ----------- ----------- Subtotal 388,035 388,035 ----------- ----------- Pollution control revenue bonds 6.38% 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 ----------- ----------- Subtotal 73,300 73,300 ----------- ----------- Variable Rate Notes Floating rate notes due 2001 - 200,000 Floating rate notes due 2001 - 150,000 Floating rate notes due 2001 - 100,000 Floating rate notes due 2003 140,000 - IDRB Series 2000A due 2020 100,000 100,000 PCRB Series 2000B due 2009 15,000 15,000 Water facilities notes maturing 2020 - 80,000 Floating Rate Notes due 2002 100,000 100,000 Floating Rate Notes due 2003 200,000 200,000 ----------- ----------- Subtotal 555,000 945,000 ----------- ----------- Debt Secured by General and Refunding Bonds: 8.25% Series A due 2011 350,000 - 8.00% Series A due 2008 320,000 - ----------- ----------- Subtotal 670,000 - ----------- ----------- Other Notes: 5.75% Series 2001 due 2036 80,000 - 6.00% Series B notes due 2003 210,000 - 8.75% Senior unsecured note Series 2000 due 2005 300,000 300,000 7.93% Senior unsecured notes due 2007 345,000 - ----------- ----------- Subtotal 935,000 300,000 ----------- ----------- Obligations under capital leases 78,313 81,815 ----------- ----------- Current maturities and sinking fund requirements (122,010) (472,531) ----------- ----------- Other 17,267 19,639 ----------- ----------- Total Long-Term Debt 3,376,105 2,133,679 ----------- ----------- TOTAL CAPITALIZATION $ 5,310,313 $ 3,780,763 =========== ===========
The accompanying notes are an integral part of the financial statements. 90 NEVADA POWER COMPANY BALANCE SHEETS (Dollars in Thousands)
December 31, 2001 2000 ----------------- --------------- ASSETS Utility Plant at Original Cost: Plant in service $ 3,356,584 $ 3,089,705 Less: accumulated provision for depreciation 928,939 855,599 ----------------- --------------- 2,427,645 2,234,106 Construction work-in-progress 134,706 228,856 ----------------- --------------- 2,562,351 2,462,962 ----------------- --------------- Investment in Sierra Pacific Resources (Note 1A) 309,259 471,975 Investments in subsidiaries and other property, net 12,721 13,418 ----------------- --------------- 321,980 485,393 ----------------- --------------- Current Assets: Cash and cash equivalents 8,505 43,858 Accounts receivable less provision for uncollectible accounts: 2001-$30,861; 2000-$11,605 210,333 168,890 Deferred energy costs - electric (Note 1) 281,555 - Federal income tax receivable 18,590 18,728 Materials, supplies and fuel, at average cost 48,511 45,573 Risk management assets (Note 22) 200,829 - Other 6,698 10,205 ----------------- --------------- 775,021 287,254 ----------------- --------------- Deferred Charges: Deferred energy costs - electric (Note 1) 698,510 - Federal income tax receivable 295,818 - Regulatory tax asset 109,859 113,647 Other regulatory assets 31,588 32,583 Risk management assets (Note 22) 49,493 - Risk management regulatory assets - net (Note 22) 351,264 - Other 29,485 25,912 ----------------- --------------- 1,566,017 172,142 ----------------- --------------- $ 5,225,369 $ 3,407,751 ================= =============== CAPITALIZATION AND LIABILITIES Capitalization: Common shareholders' equity including $309,259 and $471,975 of equity in Sierra Pacific Resources in 2001 and 2000 (Note 1A) $ 1,702,322 $ 1,359,712 Accumulated other comprehensive income 520 - NPC obligated mandatorily redeemable preferred trust securities 188,872 188,872 Long-term debt 1,607,967 927,784 ----------------- --------------- 3,499,681 2,476,368 ----------------- --------------- Current Liabilities: Short-term borrowings 130,500 100,000 Current maturities of long-term debt 19,380 252,910 Accounts payable 202,555 157,808 Accrued interest 19,310 16,913 Dividends declared 71 86 Accrued salaries and benefits 12,450 12,297 Deferred taxes on deferred energy costs 98,544 - Risk management liabilities (Note 22) 522,508 - Other current liabilities 17,710 16,450 ----------------- --------------- 1,023,028 556,464 ----------------- --------------- Commitments & Contingencies (Note 18) Deferred Credits: Deferred federal income taxes 223,641 216,753 Deferred investment tax credit 23,533 25,163 Deferred taxes on deferred energy costs 244,479 - Regulatory tax liability 18,604 19,908 Customer advances for construction 61,454 65,588 Accrued retirement benefits 28,104 27,985 Risk management liabilities (Notes 22) 78,558 - Other 24,287 19,522 ----------------- --------------- 702,660 374,919 ----------------- --------------- $ 5,225,369 $ 3,407,751 ================= ===============
The accompanying notes are an integral part of the financial statements. 91 NEVADA POWER COMPANY STATEMENTS OF INCOME (LOSS) (Dollars in Thousands, Except Per Share Amounts)
Year ended December 31, ------------ ------------ ------------ 2001 2000 1999 ------------ ------------ ------------ OPERATING REVENUES: Electric $ 3,025,103 $ 1,325,470 $ 977,262 OPERATING EXPENSES: Operation: Purchased power 3,026,336 671,396 293,600 Fuel for power generation 441,900 292,787 154,546 Deferral of energy costs-net (937,322) 16,719 97,238 Other 169,442 139,723 141,041 Maintenance 45,136 34,057 50,805 Depreciation and amortization 93,101 85,989 80,644 Taxes: Income taxes 17,775 (12,162) 19,943 Other than income 24,371 23,501 22,462 ------------ ------------ ------------ 2,880,739 1,252,010 860,279 ------------ ------------ ------------ OPERATING INCOME 144,364 73,460 116,983 ------------ ------------ ------------ OTHER INCOME (EXPENSE): Equity in (losses) earnings of Sierra Pacific Resources (Note 1A) (6,672) (31,852) 13,058 Allowance for other funds used during construction (382) 2,456 3,713 Other income (expense) - net 27,272 1,718 (1,824) ------------ ------------ ------------ 20,218 (27,678) 14,947 ------------ ------------ ------------ Total Income Before Interest Charges 164,582 45,782 131,930 ------------ ------------ ------------ INTEREST CHARGES: Long-term debt 81,599 64,513 64,454 Other 13,219 13,732 8,815 Allowance for borrowed funds used during construction and capitalized interest (2,141) (7,855) (8,356) ------------ ------------ ------------ 92,677 70,390 64,913 ------------ ------------ ------------ INCOME (LOSS) BEFORE NPC OBLIGATED MANDATORILY REDEEMABLE PREFERRED TRUST SECURITIES 71,905 (24,608) 67,017 Preferred dividend requirements of NPC obligated mandatorily redeemable preferred trust securities (15,172) (15,172) (15,172) ------------ ------------ ------------ INCOME (LOSS) BEFORE PREFERRED STOCK DIVIDENDS 56,733 (39,780) 51,845 Preferred stock dividend requirements - - (95) ------------ ------------ ------------ NET INCOME (LOSS) $ 56,733 $ (39,780) $ 51,750 ============ ============ ============ Net Income (Loss) Per Share - Basic $ 0.65 $ (0.51) $ 0.83 ============ ============ ============ - Diluted $ 0.65 $ (0.51) $ 0.83 ============ ============ ============ Weighted Average Shares of Common Stock Outstanding (000's) 87,542 78,435 62,577 ============ ============ ============ Dividends Paid Per Share of Common Stock $ 0.65 $ 1.000 $ 1.165 ============ ============ ============
The accompanying notes are an integral part of the financial statements. 92 NEVADA POWER COMPANY STATEMENTS OF CASH FLOWS (Dollars in Thousands)
Year ended December 31, --------------------------------------- 2001 2000 1999 ----------- ---------- ----------- CASH FLOWS FROM OPERATING ACTIVITIES: Income (loss) before preferred dividends $ 56,733 $ (39,780) $ 51,845 Non-cash items included in income: Depreciation and amortization 93,102 85,989 80,643 Deferred taxes and deferred investment tax credit 55,085 (26,528) (18,913) AFUDC and capitalized interest (1,759) (10,311) (12,069) Deferral of energy costs - net (980,065) 14,884 48,313 Other non-cash 264 20,101 16,908 Equity in losses (earnings) of SPR (Note 1A) 6,672 31,852 (13,058) Changes in certain assets and liabilities, net of acquisition: Accounts receivable (41,444) (57,935) (11,795) Materials, supplies and fuel (2,938) (2,465) (3,502) Other current assets 3,507 (25,360) 1,778 Accounts payable 44,747 82,720 34,964 Other current liabilities 3,812 10,001 17,066 Other - net 4,882 30,543 (14,002) ----------- ---------- ----------- Net Cash Flows from Operating Activities (757,402) 113,711 178,178 ----------- ---------- ----------- CASH FLOWS USED IN INVESTING ACTIVITIES: Additions to utility plant (200,852) (204,505) (223,963) AFUDC and other charges to utility plant 1,759 11,622 (2,184) Customer refunds for construction (4,134) (3,753) 5,228 Contributions in aid of construction 6,331 - - ----------- ---------- ----------- Net cash used for utility plant (196,896) (196,636) (220,919) (Investments in) disposal of subsidiaries and other property - net (115) - 1,499 ----------- ---------- ----------- Net Cash Used in Investing Activities (197,011) (196,636) (219,420) ----------- ---------- ----------- CASH FLOWS FROM FINANCING ACTIVITIES: Increase (decrease) in short-term borrowings 30,500 (82,000) 77,000 Proceeds from issuance of long-term debt 815,000 365,000 129,900 Retirement of long-term debt (368,347) (205,152) (60,283) Change in funds held in trust - - 9 Redemption of preferred stock - - (3,265) Investment of SPR 474,921 137,000 18,000 Dividends paid (33,014) (88,308) (121,646) ----------- ---------- ----------- Net Cash Provided by Financing Activities 919,060 126,540 39,715 ----------- ---------- ----------- Net (Decrease) Increase in Cash and Cash Equivalents (35,353) 43,615 (1,527) Beginning balance in Cash and Cash Equivalents 43,858 243 1,770 ----------- ---------- ----------- Ending balance in Cash and Cash Equivalents $ 8,505 $ 43,858 $ 243 =========== ========== =========== Supplemental Disclosures of Cash Flow Information: Cash paid (received) during period for: Interest $ 90,280 $ 71,430 $ 91,196 Income taxes $ (13,702) $ 6,500 $ 38,219
The accompanying notes are an integral part of the financial statements. 93 NEVADA POWER COMPANY STATEMENTS OF CAPITALIZATION (Dollars in Thousands)
December 31, 2001 2000 -------------- ------------- Common Shareholder's Equity: Common stock issued $ 1 $ 1 Other paid-in capital 1,367,106 892,185 Retained earnings (deficit) 25,956 (4,449) Equity in Sierra Pacific Resources (Note 1A) 309,259 471,975 -------------- ------------- Total Common Shareholder's Equity 1,702,322 1,359,712 -------------- ------------- Accumulated Other Comprehensive Income 520 - -------------- ------------- Preferred Securities: NPC obligated Mandatorily Redeemable Preferred Securities of NPC's Subsidiary Trust, NVP Capital I, holding solely $122.6 million principal amount of 8.2% Junior Subordinated Debentures of NPC, due 2037 118,872 118,872 NPC obligated Mandatorily Redeemable Preferred Securities of NPC's Trust, NVP Capital III, holding solely $72.2 million principal amount of 7.75% Junior Subordinated Debentures of NPC, due 2038 70,000 70,000 -------------- ------------- Total Preferred Securities 188,872 188,872 -------------- ------------- Long-Term Debt: Unamortized bond premium and discount, net 2 (163) Debt Secured by First Mortgage Bonds: 7.63% Series L due 2002 15,000 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 -------------- ------------- Subtotal 272,502 272,337 -------------- ------------- Industrial development revenue bonds 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 6.20% Series 1999B due 2004 130,000 130,000 -------------- ------------- Subtotal 388,035 388,035 -------------- ------------- Pollution Control Revenue Bonds 6.38% 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 -------------- ------------- Subtotal 73,300 73,300 -------------- ------------- Variable Rate Notes Floating rate notes due 2001 - 150,000 Floating rate notes due 2001 - 100,000 Floating rate notes due 2003 140,000 - IDRB Series 2000A due 2020 100,000 100,000 PCRB Series 2000B due 2009 15,000 15,000 -------------- ------------- Subtotal 255,000 365,000 -------------- ------------- Debt Secured by General and Refunding Bonds: 8.25% Series A due 2011 350,000 - -------------- ------------- Other Notes: 6.0% Series B notes due 2003 210,000 - -------------- ------------- Obligation under capital leases 78,313 81,815 -------------- ------------- Current maturities and sinking fund requirements (19,380) (252,911) -------------- ------------- Other, excluding current portion 197 208 -------------- ------------- Total Long-Term Debt 1,607,967 927,784 -------------- ------------- TOTAL CAPITALIZATION $ 3,499,681 $ 2,476,368 ============== =============
The accompanying notes are an integral part of the financial statements. 94 SIERRA PACIFIC POWER COMPANY CONSOLIDATED BALANCE SHEETS (Dollars in Thousands)
December 31, 2001 2000 ---------- ---------- ASSETS Utility Plant at Original Cost: Plant in service $2,326,712 $2,180,019 Less: accumulated provision for depreciation 848,578 781,058 ---------- ---------- 1,478,134 1,398,961 Construction work-in-progress 68,750 118,442 ---------- ---------- 1,546,884 1,517,403 ---------- ---------- Investments in subsidiaries and other property, net 57,185 60,047 ---------- ---------- Current Assets: Cash and cash equivalents 11,772 5,348 Accounts receivable less provision for uncollectible accounts: 2001 - $8,474; 2000 - $1,589 194,698 153,547 Deferred energy costs - electric 51,507 -- Deferred energy costs - gas 19,805 -- Federal income tax receivable -- 21,958 Materials, supplies and fuel, at average cost 42,290 29,209 Risk management assets (Note 22) 85,680 -- Other 5,935 7,894 ---------- ---------- 411,687 217,956 ---------- ---------- Deferred Charges: Deferred energy costs - electric 156,268 -- Deferred energy costs - gas 23,248 16,370 Federal income tax receivable 41,040 -- Regulatory tax asset 59,879 61,862 Other regulatory assets 51,146 61,236 Risk management assets (Note 22) 11,565 -- Risk management regulatory assets - net (Note 22) 313,119 -- Other 13,886 12,036 ---------- ---------- 670,151 151,504 ---------- ---------- Net assets of discontinued operations (Note 17) -- 261,479 ---------- ---------- $2,685,907 $2,208,389 ========== ========== CAPITALIZATION AND LIABILITIES Capitalization: Common shareholder's equity $ 692,654 $ 604,795 Accumulated other comprehensive income 247 -- Preferred stock 50,000 50,000 SPPC obligated mandatorily redeemable preferred trust securities -- 48,500 Long-term debt 923,070 605,816 ---------- ---------- 1,665,971 1,309,111 ---------- ---------- Current Liabilities: Short-term borrowings 46,500 108,962 Current maturities of long-term debt 2,630 219,616 Accounts payable 95,555 166,134 Accrued interest 8,408 6,992 Dividends declared 974 23,975 Accrued salaries and benefits 15,466 15,475 Deferred taxes on deferred energy costs 24,959 -- Risk management liabilities (Note 22) 332,793 -- Other current liabilities 3,387 2,932 ---------- ---------- 530,672 544,086 ---------- ---------- Commitments & Contingencies (Note 18) Deferred Credits: Deferred federal income taxes 178,533 179,106 Deferred investment tax credit 28,414 30,088 Deferred taxes on deferred energy costs 62,831 -- Regulatory tax liability 28,098 31,087 Customer advances for construction 46,725 41,776 Accrued retirement benefits 43,028 44,374 Risk management liabilities (Note 22) 77,324 -- Other 24,311 28,761 ---------- ---------- 489,264 355,192 ---------- ---------- $2,685,907 $2,208,389 ========== ==========
The accompanying notes are an integral part of the financial statements. 95 SIERRA PACIFIC POWER COMPANY CONSOLIDATED STATEMENTS OF INCOME (Dollars in Thousands)
December 31, 2001 2000 1999 ----------- ----------- ----------- OPERATING REVENUES: Electric $ 1,399,134 $ 893,782 $ 609,197 Gas 145,652 100,803 100,177 ----------- ----------- ----------- 1,544,786 994,585 709,374 ----------- ----------- ----------- OPERATING EXPENSES: Operation: Purchased power 1,025,741 444,979 179,781 Fuel for power generation 286,719 233,748 115,065 Gas purchased for resale 136,534 83,199 68,125 Deferral of energy costs - electric - net (198,826) -- -- Deferral of energy costs - gas - net (23,170) (16,164) -- Other 117,627 96,438 92,745 Maintenance 24,363 18,420 20,309 Depreciation and amortization 70,358 69,350 69,762 Taxes: Income taxes 8,507 (672) 33,870 Other than income 17,965 18,152 17,014 ----------- ----------- ----------- 1,465,818 947,450 596,671 ----------- ----------- ----------- OPERATING INCOME 78,968 47,135 112,703 ----------- ----------- ----------- OTHER INCOME (EXPENSE): Allowance for other funds used during construction 856 357 (1,370) Other income (expense) - net 8,489 (2,429) (673) ----------- ----------- ----------- 9,345 (2,072) (2,043) ----------- ----------- ----------- Total Income 88,313 45,063 110,660 ----------- ----------- ----------- INTEREST CHARGES: Long-term debt 55,199 36,865 31,151 Other 7,433 11,312 11,286 Allowance for borrowed funds used during construction and capitalized interest (660) (2,779) (141) ----------- ----------- ----------- 61,972 45,398 42,296 ----------- ----------- ----------- INCOME (LOSS) BEFORE SPPC OBLIGATED MANDATORILY REDEEMABLE PREFERRED TRUST SECURITIES 26,341 (335) 68,364 Preferred dividend requirements of SPPC obligated mandatorily redeemable preferred trust securities (3,598) (3,742) (3,749) ----------- ----------- ----------- INCOME (LOSS) BEFORE PREFERRED DIVIDENDS 22,743 (4,077) 64,615 Preferred dividend requirements and premium paid on redemption (3,700) (3,499) (4,957) ----------- ----------- ----------- NET INCOME (LOSS) FROM CONTINUING OPERATIONS 19,043 (7,576) 59,658 ----------- ----------- ----------- DISCONTINUED OPERATIONS: Income from operations of water business disposed of (net of income taxes of $888, $3,426 and $2,172 in 2001, 2000 and 1999 respectively) 1,022 9,634 6,583 Gain on disposal of water business (net of income taxes of $18,237) 25,845 -- -- ----------- ----------- ----------- NET INCOME $ 45,910 $ 2,058 $ 66,241 =========== =========== ===========
The accompanying notes are an integral part of the financial statements 96 SIERRA PACIFIC POWER COMPANY CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Dollars in Thousands)
Year ended December 31, --------------------------- 2001 2000 1999 ------- ------- ------- NET INCOME $45,910 $ 2,058 $66,241 OTHER COMPREHENSIVE INCOME, NET OF TAX: Adoption of SFAS No. 133- Accounting for Derivative Instruments and Hedging Activities: Cumulative effect upon adoption of change in 211 -- -- accounting principle as of January 1 Change in market value of risk management and liabilities as of December 31 36 ------- ------- ------- OTHER COMPREHENSIVE INCOME 247 -- -- ------- ------- ------- COMPREHENSIVE INCOME $46,157 $ 2,058 $66,241 ======= ======= =======
The accompanying notes are an integral part of the financial statements SIERRA PACIFIC POWER COMPANY CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER'S EQUITY (Dollars in Thousands)
Year ended December 31, 2001 2000 1999 --------- --------- --------- Common Stock: Balance at Beginning of Year and End of Year $ 4 $ 4 $ 4 --------- --------- --------- Other Paid-In Capital: Balance at Beginning Year 598,684 584,684 562,684 Additional investment by parent company 104,949 14,000 22,000 --------- --------- --------- Balance at End of Year 703,633 598,684 584,684 --------- --------- --------- Retained (Deficit) Earnings: Balance at Beginning of Year 6,107 89,050 98,679 Income (Loss) before preferred dividends of continuing operations 22,743 (4,077) 64,615 Income from discontinued operations (before preferred dividend allocation of $200, $401, and $528 in 2001, 2000, and 1999, respectively) 1,222 10,034 7,111 Gain on disposal of water business 25,845 -- -- Preferred stock dividends declared and premium on redemption (3,900) (3,900) (5,355) Common stock dividends declared (63,000) (85,000) (76,000) --------- --------- --------- Balance at End of Year (10,983) 6,107 89,050 --------- --------- --------- Total Common Shareholder's Equity at End of Year $ 692,654 $ 604,795 $ 673,738 ========= ========= =========
The accompanying notes are an integral part of the financial statements 97 SIERRA PACIFIC POWER COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (Dollars in Thousands)
Year Ended December 31, 2001 2000 1999 --------- --------- --------- Cash Flows From Operating Activities: Income (loss) from continuing operations before preferred dividends $ 22,743 $ (4,077) $ 64,615 Income from discontinued operations before preferred dividends 1,222 10,035 7,111 Gain on disposal of water business 25,845 -- -- Non-cash items included in income: Depreciation and amortization 73,818 76,685 77,373 Deferred taxes and investment tax credits 57,382 7,935 5,595 AFUDC and capitalized interest (1,526) (3,547) 1,033 Deferral of energy costs - electric - net (207,775) -- -- Deferral of energy costs - gas - net (26,683) -- -- Early retirement and severance amortization 3,121 4,196 4,194 Gain on disposal of water business (44,081) -- -- Other non-cash (386) 10,871 8,644 Changes in certain assets and liabilities: Accounts receivable (36,835) (41,604) 685 Materials, supplies and fuel (12,728) 508 (4,294) Other current assets 1,836 (26,749) (411) Accounts payable (70,579) 87,643 12,459 Other current liabilities 2,380 1,231 (23,257) Other-net (1,333) (11,117) (31,418) --------- --------- --------- Net Cash Flows from Operating Activities (213,579) 112,010 122,329 --------- --------- --------- Cash Flows From (Used in) Investing Activities: Additions to utility plant (133,604) (155,269) (142,306) AFUDC and other charges to utility plant 1,526 3,605 (768) Customer refunds for construction 4,949 2,864 5,120 Contributions in aid of construction 21,150 16,446 21,823 --------- --------- --------- Net cash used for utility plant (105,979) (132,354) (116,131) Proceeds from sale of assets of water business 318,882 -- -- Disposal of (investments in) subsidiaries and other property - net 2,747 2,292 (28,720) --------- --------- --------- Net Cash From (Used in) Investing Activities 215,650 (130,062) (144,851) --------- --------- --------- Cash Flows From Financing Activities (Decrease) increase in short-term borrowings (62,462) (5,915) 1,972 Proceeds from issuance of long-term debt 400,000 200,000 124,495 Retirement of long-term debt (299,732) (102,797) (33,270) Redemption of preferred stock (48,500) -- (23,115) Investment by parent company 104,948 14,000 22,000 Dividends paid and premiums on preferred redemption (89,901) (84,899) (81,746) --------- --------- --------- Net Cash Provided by Financing Activities 4,353 20,389 10,336 --------- --------- --------- Net Increase (Decrease) in Cash and Cash Equivalents 6,424 2,337 (12,186) Beginning Balance in Cash and Cash Equivalents 5,348 3,011 15,197 --------- --------- --------- Ending Balance in Cash and Cash Equivalents $ 11,772 $ 5,348 $ 3,011 ========= ========= ========= Supplemental Disclosures of Cash Flow Information: Cash paid (received) during year for: Interest $ 66,597 $ 57,331 $ 54,303 Income taxes (25,632) 9,644 28,604
The accompanying notes are an integral part of the financial statements. 98 SIERRA PACIFIC POWER COMPANY CONSOLIDATED STATEMENTS OF CAPITALIZATION (Dollars in Thousands)
December 31, 2001 2000 ----------- ----------- Common Shareholder's Equity: Common stock, $3.75 par value, 1,000 shares authorized, issued and outstanding $ 4 $ 4 Other paid-in capital 703,633 598,684 Retained (deficit) earnings (10,983) 6,107 ----------- ----------- Total Common Shareholder's Equity 692,654 604,795 ----------- ----------- Accumulated Other Comprehensive Income 247 -- ----------- ----------- Cumulative Preferred Stock: Not subject to mandatory redemption $25 stated value Class A Series 1; $1.95 dividend 50,000 50,000 ----------- ----------- Preferred Securities SPPC-obligated mandatorily redeemable preferred securites of SPPC'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 ----------- ----------- Long Term Debt: Unamortized bond premium and discount, net (961) (750) Debt Secured by First Mortgage Bonds 2.00% Series Z due 2004 56 72 2.00% Series O due 2011 1,281 1,374 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 3,072 3,138 6.70% Series II due 2032 21,200 21,200 5.47% Series D MTN due 2001 -- 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 508,698 526,084 ----------- ----------- Variable Rate Notes Water facilities notes maturing 2020 -- 80,000 Floating rate notes due 2001 -- 200,000 ----------- ----------- Subtotal -- 280,000 ----------- ----------- Debt Secured by General and Refunding Bonds 8.00% Series A due 2008 320,000 -- ----------- ----------- Other Notes: 5.75% Series 2001 due 2036 80,000 -- ----------- ----------- Other 17,002 19,348 ----------- ----------- Current maturities and sinking fund requirements (2,630) (219,616) ----------- ----------- Total Long-Term Debt 923,070 605,816 ----------- ----------- TOTAL CAPITALIZATION $ 1,665,971 $ 1,309,111 =========== ===========
The accompanying notes are an integral part of the financial statements. 99 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 (NPC), Sierra Pacific Power Company (SPPC), Tuscarora Gas Pipeline Company (TGPC), Sierra Pacific Communications (SPC), Lands of Sierra, Inc. (LOS), Sierra Energy Company dba e.three (e.three), Nevada Electric Investment Company (NEICO), Sierra Pacific Energy Company (SPE), Sierra Water Development Company (SWDC) and, Sierra Gas Holding Company (SGHC). 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 NPC. NPC is an operating public utility that provides electric service in Clark County in southern Nevada. The assets of NPC represent 60% of the consolidated assets of SPR at December 31, 2001. NPC provides electricity to approximately 639,000 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 NPC'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 service in the Reno/Sparks area of Nevada. The assets of SPPC represent 33% of the consolidated assets of SPR at December 31, 2001. SPPC provides electricity to approximately 315,000 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"). 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. e.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. Also, SPC and a subsidiary of Montana Power Company are in a partnership that is constructing a fiber optic line between Salt Lake City, Utah and Sacramento, CA. 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 100 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. Deferral of Energy Costs Nevada and California statutes permit regulated utilities to, from time-to-time, adopt deferred energy accounting procedures. The intent of these procedures is to ease the effect of fluctuations in the cost of purchased gas, fuel and purchased power. Under deferred energy accounting, to the extent actual fuel and purchased power costs exceed fuel and purchased power costs recoverable through current rates, that excess is not recorded as a current expense on the income statement but rather is deferred and recorded as an asset on the balance sheet. Conversely, a liability is recorded to the extent fuel and purchased power costs recoverable through current rates exceed actual fuel and purchased power costs. These excess amounts are reflected in adjustments to rates and recorded as revenue or expense in future time periods. AB 369 requires the Utilities to use deferred energy accounting for their respective electric operations beginning on March 1, 2001, and to file applications to clear their respective deferred energy account balances at least every 12 months. See Note 3 for additional information on the deferred energy accounting provisions of AB 369. NPC utilized deferred energy accounting procedures in 1999, and part of 2000. NPC ceased utilizing deferred energy accounting effective August 1, 2000, and resumed those procedures on March 1, 2001. During 1999, SPPC did not employ deferred energy accounting procedures, but resumed those procedures for natural gas operations as of January 1, 2000, and for its electric operations on March 1, 2001. 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 of 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. NPC's AFUDC rates used during 2001, 2000, and 1999 were 8.32%, 8.34%, and 8.55%, respectively. SPPC's AFUDC rates used during 2001, 2000, and 1999 were 7.94%, 101 7.17%, and 6.09%, 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. Depreciation Depreciation is calculated using the straight-line composite method over the estimated remaining service lives of the related properties. NPC's depreciation provision for 2001, 2000, and 1999, 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 2001, 2000, and 1999, as authorized by the PUCN and stated as a percentage of the original cost of depreciable property, was approximately 3.21%, 3.21%, and 3.14%, 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. 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 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): 102
DESCRIPTION 2001 2000 AMORTIZATION PERIODS --------------------------------------- ---- ---- --------------------------- Early retirement and severance offers $ 7,701 $ 12,567 Various through 2004 Loss on reacquired debt 32,882 32,548 Various through 2030 Plant assets 3,783 3,964 Various through 2031 Merger transition costs 10,543 8,275 To be determined Merger severance/relocation 21,851 22,434 To be determined Merger goodwill 19,675 11,533 To be determined Other costs 6,524 14,267 Various ---------- --------- Total $ 102,959 $ 105,588 ========= =========
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. The provisions of AB 369, signed into law in April 2001, include the repeal of all statutes authorizing retail competition in Nevada's electric utility industry. Accordingly, the Utilities continue to apply regulatory accounting to the generation, transmission and distribution portions of their businesses. 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. 103 Revenues Operating revenues include billed and unbilled utility revenues. The accrual for unbilled revenues represents amounts owed to the Utilities for service provided to customers for which the customers have not yet been billed. These unbilled amounts are also included in accounts receivable. Recent Pronouncements Financial Accounting Standards Board In June 2001, the FASB issued three new pronouncements, SFAS No. 141, "Business Combinations," SFAS No. 142, "Goodwill and Other Intangible Assets," and SFAS No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 141 requires that the purchase method of accounting be used for all business combinations initiated after June 30, 2001. SFAS No. 142, adopted January 1, 2002, changes the accounting for goodwill from an amortization method to one requiring at least an annual review for impairment. Due to the regulatory treatment anticipated for most of SPR's goodwill, Management does not expect SFAS No. 142 to have a material effect on the financial position or results of operations of SPR, NPC, and SPPC. SFAS No. 143, effective for fiscal years beginning after June 15, 2002, requires an entity to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. Management does not expect the adoption of SFAS No. 143 to have a material effect on the financial position or results of operations of SPR, NPC, and SPPC. In August 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." This standard provides guidance on the impairment of long-lived assets and for long-lived assets to be disposed of. The standard supersedes the current authoritative literature on impairments as well as disposal of a segment of a business and was adopted January 1, 2002. Note 1A. FINANCIAL STATEMENTS OF NEVADA POWER COMPANY As described in Note 2 that follows, NPC 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, NPC is a separate legal entity, which is a wholly owned subsidiary of SPR. As a legal matter, NPC does not own any equity interest in SPR. The audited NPC Financial Statements accommodate the presentation of financial information of NPC on a stand-alone basis by summarizing all non-NPC financial information into a few items on each of the Financial Statements. These summarized items are repeated below (in 000's): Non-NPC financial items on the NPC Financial Statements
NPC Balance Sheet: December 31, 2001 December 31, 2000 ------------------ ----------------- ----------------- Investment in Sierra Pacific Resources $309,259 $471,975 Equity in Sierra Pacific Resources $309,259 $471,975
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 NPC. The Equity in Sierra Pacific Resources reflects the sum of paid-in-capital and retained earnings of SPR, without the benefit of NPC. These line items are presented under the rules of purchase accounting and do not represent any asset to which holders of NPC's securities may look for recovery of their investment. These items must be disregarded for determining the ability of NPC to satisfy its obligations or to pay dividends (preferred or common), for 104 calculating NPC's ratios of earnings to fixed charges and preferred stock dividends, and for all of NPC's financial covenants and earnings tests including those under its charter and mortgage.
NPC Income Statement: Year Ended Year Ended Year Ended --------------------- ---------- ---------- ---------- December 31, 2001 December 31, 2000 December 31, 1999 ----------------- ----------------- ----------------- Equity in (Losses) Earnings of Sierra Pacific Resources $(6,672) $(31,852) $13,058
The Equity in (Losses) Earnings of Sierra Pacific Resources represents the net income (loss) of SPR after SPPC preferred stock dividends. This line item is presented under the rules of purchase accounting and does not represent any item of revenue or income to which holders of NPC's securities may look for recovery of their investment. This item must be disregarded for determining the ability of NPC to satisfy its obligations or its ability to pay dividends (preferred or common), for calculating NPC's ratios of earnings to fixed charges and preferred dividends, and for all of NPC's financial covenants and earnings tests including those under its charter and mortgage.
NPC Statement of Cash Flow: Year Ended Year Ended Year Ended --------------------------- ---------- ---------- ---------- December 31, 2001 December 31, 2000 December 31, 1999 ----------------- ----------------- ----------------- Equity in (Losses) Earnings of Sierra Pacific Resources $(6,672) $(31,852) $13,058
As in the Income Statement, the Equity in (Losses) Earnings of Sierra Pacific Resources represents the net income (loss) of SPR, after SPPC preferred stock dividends. This line item is presented under the rules of purchase accounting and does not represent any item of cash flow to which holders of NPC's securities may look for recovery of their investment. This item must be disregarded for determining the ability of NPC to satisfy its obligations or its ability to pay dividends (preferred or common), for calculating NPC's ratios of earnings to fixed charges and preferred dividends, and for all of NPC's financial covenants and earnings tests including those under its charter and mortgage.
NPC Statement of Capitalization: December 31, 2001 December 31, 2000 -------------------------------- ----------------- ----------------- Equity in Sierra Pacific Resources $309,259 $471,975
The Equity in Sierra Pacific Resources reflects the sum of paid-in-capital and retained earnings of SPR on NPC's books. This line item is presented under the rules of purchase accounting and does not represent any item of cash flow to which holders of NPC's securities may look for recovery of their investment. This item must be disregarded for determining the ability of NPC to satisfy its obligations or its ability to pay dividends (preferred or common), for calculating NPC's ratios of earnings to fixed charges and preferred dividends, and for all of NPC'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 NPC was consummated. The merger was accounted for as a reverse purchase under generally accepted accounting principles, with NPC 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 NPC; 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 105 December 1999) of operating activity for SPR and its subsidiaries other than NPC. The same statements include the operating results of NPC for the entire periods presented Through December 31, 2001, SPR incurred a total of $60.2 million in capitalized costs since merger work began. The capitalized merger amounts consist of $38.4 million of transaction and transition costs and $21.8 million of employee separation costs. Employee severance, relocation, and related costs for SPR were $17.3 million, of which $.4 million remains unpaid as of December 31, 2001. Other costs incurred in connection with employee separations included pension and postretirement benefits net of plan curtailment 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 NPC 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 NPC 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 NPC 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 NPC common stock between April 22, 1998 and May 6, 1998. The eleven-day average price of NPC 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. The order of the PUCN approving the merger allowed SPR to defer merger costs (including goodwill) allocable to the regulated Utilities for a three-year period. Accordingly, goodwill amortization through December 31, 2001, associated with the regulated Utilities has been reclassified to a regulatory asset. On October 1, 2001, and November 30, 2001, NPC and SPPC, respectively, filed applications with the PUCN for general rate increases that included, among other items, a request to recover deferred merger costs, including goodwill. The Utilities have proposed to recover merger transition and transaction costs over ten years and goodwill over forty years. Decisions on the NPC and SPPC cases are expected no later than April 1, 2002, and June 1, 2002, respectively. See Note 3 "Regulatory Actions" for additional information about these rate cases. NOTE 3. REGULATORY ACTIONS Nevada Matters (NPC and SPPC) ----------------------------- The Utilities are subject to the jurisdiction of the PUCN and, in the case of SPPC, the California Public Utility Commission (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. NPC and SPPC submit integrated resource plans 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 interstate 106 transmission. The FERC also has jurisdiction over the natural gas pipeline companies from which the Utilities 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, are subject to the approval of governmental agencies. Nevada Legislation ------------------ On April 18, 2001, the Governor of Nevada signed into law AB 369. The provisions of AB 369 include a moratorium on the sale of generation assets by electric utilities, the repeal of electric industry restructuring, and a reinstatement of deferred energy accounting for fuel and purchased power costs incurred by electric utilities. Set forth below is a summary of key provisions of AB 369. Generation Divestiture Moratorium AB 369 prohibits all divestiture of generation assets by electric utilities until July 2003. After January 1, 2003, NPC or SPPC may seek PUCN permission to sell one or more generation assets with the sale to be effective on or after July 1, 2003. The PUCN may approve the request to divest only if it finds the transaction to be in the public interest. The PUCN may base its approval of the request upon such terms, conditions, or modifications as it deems appropriate. AB 369 directs the PUCN to take all steps necessary to obtain federal approval for the prohibition on divestiture and to vacate any of its own orders that had previously approved generation divestiture transactions. Deferred Energy Accounting AB 369 required the Utilities to use deferred energy accounting for their respective electric operations beginning on March 1, 2001. The intent of deferred energy accounting is to ease the effect of fluctuations in the cost of purchased power and fuel. Under deferred energy accounting, to the extent actual fuel and purchased power costs exceed fuel and purchased power costs recoverable through current rates, that excess is not recorded as a current expense on the income statement but rather is deferred and recorded as an asset on the balance sheet. Conversely, a liability is recorded to the extent fuel and purchased power costs recoverable through current rates exceed actual fuel and purchased power costs. These excess amounts are reflected in adjustments to rates and recorded as revenue or expense in future time periods, subject to PUCN review. AB 369 provides that the PUCN may not allow the recovery of any costs for purchased fuel or purchased power "that were the result of any practice or transaction that was undertaken, managed or performed imprudently by the electric utility." In reference to deferred energy accounting, AB 369 specifies that fuel and purchased power costs include all costs incurred to purchase fuel, to purchase capacity, and to purchase energy. The Utilities also record, and are eligible to recover, a carrying charge on such deferred balances. AB 369 requires that each Utility file an application to clear its deferred energy account balances after the end of each 12-month period, but allows the balances from each 12-month period to be recovered over an adjustment period of up to three years in order to reduce the volatility of rate changes. In addition, after the initial deferred energy case, each utility is allowed to file an application to clear its deferred energy account balances after the end of a six-month period if the proposed net increase or decrease in fuel and purchased power revenues for the six-month period is more than 5%. If a utility using deferred energy accounting realizes a rate of return greater than the rate authorized by the PUCN, the portion that exceeds the authorized rate of return will be transferred to the next deferred energy adjustment period. Before an electric utility may clear its deferred accounts, AB 369 requires the PUCN to determine whether the costs for purchased fuel and purchased power that the electric utility recorded in its deferred 107 accounts are recoverable and whether the revenues that the electric utility collected from customers in Nevada for purchased fuel and purchased power are properly recorded and credited in its deferred accounts. AB 369 prohibits the PUCN from allowing an electric utility to recover any costs for purchased fuel and purchased power that were the result of any practice or transaction that was undertaken, managed or performed imprudently by the electric utility. To the extent that the PUCN finds that any amount included in either Utility's deferred account was imprudently incurred, the PUCN will not permit that amount to be recovered through higher rates, and an equivalent amount of the Utility's deferred energy costs asset will be required to be written off. Such a write-off could cause a substantial loss to be incurred by the Utility, could cause its securities to be downgraded by the rating agencies, and could make it significantly more difficult to finance the operations of the Utility and to buy fuel and purchased power from third parties. In addition, as discussed under "Required Filings" below, the PUCN must determine whether the rates that went into effect on March 1, 2001, pursuant to the CEP as filed by the Utilities with the PUCN on January 29, 2001, are just and reasonable and reflect prudent business practices. Transition of Rates to Deferred Energy Accounting All rates in effect on April 1, 2001, including the cumulative increases under the Global Settlement and the CEP Riders, remain in effect until the PUCN issues final orders on future general and initial deferred energy rate applications. (See "Required Filings," below). No further applications can be made for the Fuel and Purchased Power (F&PP) riders that were part of the July 2000 Global Settlement described in SPR's Annual Report on Form 10-K for the year ended December 31, 2000. The Utilities are not permitted to recover any shortfall incurred before March 1, 2001, resulting from the difference between actual fuel and purchased power costs and the rates permitted by the Global Settlement. Although the F&PP riders were in effect during this period, the riders were based on trailing 12-month average costs and were subject to caps and, therefore, did not allow the Utilities full recovery for fuel and purchased power costs due to the rapid rise in energy prices. AB 369 prohibits the PUCN from taking any further action on the CEP, and provides that, except for the CEP Rider rate increases put in effect on April 1, 2001, the CEP will be deemed to have been withdrawn by the Utilities. Additionally, approximately $20 million of revenue collected by the Utilities based on the CEP before April 1, 2001 was credited to the deferred energy accounts, which caused the accounts to start in an over-collected position. Required Filings The Utilities have both filed a general rate application and a deferred energy application on the dates listed below:
General Rate Case Deferred Energy Filing ----------------- ---------------------- File Date Effective Date File Date Effective Date Nevada Power Company Oct. 1, 2001 April 1, 2002 Dec. 1, 2001 April 1, 2002 Sierra Pacific Power Company Dec. 1, 2001 June 1, 2002 Feb. 1, 2002 June 1, 2002
In connection with clearing the Utilities' deferred energy accounts, the PUCN must investigate and determine whether the Utilities' rates that went into effect on March 1, 2001, pursuant to the CEP, are just and reasonable and reflect prudent business practices. The rates in effect on April 1, 2001, remain in effect until the PUCN issues final orders on the general and initial deferred energy rate applications referred to above. The PUCN is prohibited from adjusting rates during this time period unless an adjustment is absolutely necessary to avoid a finding that the rates are confiscatory and, therefore, in violation of the United States or Nevada 108 Constitutions. If adjustments are necessary, they may only be made to the extent necessary to avoid an unconstitutional result. After the initial general rate applications described above, each Utility will be required to file future general rate applications at least every 24 months. Restrictions on Mergers and Acquisitions AB 369 imposes certain restrictions on mergers and acquisitions involving Nevada electric utilities. In particular, the PUCN may not approve a merger or acquisition involving an electric utility unless the utility complies with the generation divestiture provisions of AB 369. In addition, AB 369 includes provisions that would have significantly affected the required regulatory approvals for the proposed acquisition of PGE from Enron. On April 26, 2001, Enron and SPR terminated, by mutual agreement, the proposed purchase and sale of PGE. AB 369 also provides that if an electric utility holding company acquires an interest in an out-of-state public utility prior to July 1, 2003, each electric utility in which the holding company holds a controlling interest shall not be entitled to the benefit of deferred energy accounting. Thus, in the event that SPR acquires an out-of-state public utility, NPC and SPPC would lose the ability to utilize deferred energy accounting. Repeal of Electric Industry Restructuring AB 369 repeals all statutes authorizing retail competition in Nevada's electric utility industry and voids any license issued to an alternative seller in connection with retail electric competition. Other Legislation SB 372, which increased renewable energy portfolio requirements, was enacted in the 2001 Nevada legislative session. Renewable resources include biomass, wind, solar, and geothermal projects. In 2003, the Utilities will be required to purchase five percent of their energy from renewable resources. These requirements increase to 15% by 2013. Prior law capped renewable energy requirements at one percent. Currently, SPPC obtains approximately nine percent of its energy from renewable resources, while NPC obtains less than one percent from renewables. SB 372 requires the PUCN to establish standards for renewable energy contracts, including prices and other terms and conditions. If sufficient renewable energy contracts that meet PUCN standards are not available, the Utilities will not be required to meet the portfolio requirements. All renewable energy contracts meeting PUCN standards will be recoverable in the deferred energy accounts. The 2001 Nevada legislature passed another key piece of legislation for the Nevada energy industry, AB 661. AB 661 allows commercial and governmental customers with an average demand greater than 1 MW to select new energy suppliers. The Utilities would continue to provide transmission, distribution, metering and billing services to such customers. AB 661 requires customers wishing to choose a new supplier to receive the approval of the PUCN and meet public interest standards. In particular, departing customers must secure new energy resources that are not under contract to the Utilities, remaining customers or the utility cannot be negatively impacted by the departure, and the departing customers must pay any deferred energy balances. The PUCN has adopted regulations prescribing the criteria that will be used to determine if there will be negative impacts to remaining customers or the utility. Certain limits are placed upon the departure of NPC customers until 2003; most significantly, the amount of load departing is limited to approximately 1100 MW in peak conditions. AB 661 permits customers to file applications with the PUCN beginning in the fourth quarter of 2001. Customers must provide 180-day notice to the Utilities and could begin to receive service from new 109 suppliers by mid-2002. On January 10, 2002, an approximately 130 MW SPPC customer submitted an application to the PUCN under AB 661. The customer, SPPC, and PUCN staff are negotiating a stipulation regarding settlement of the terms and conditions under which this customer will be permitted to procure energy from an alternative source other than SPPC. The terms and conditions of the stipulation are expected to comply with the provisions of AB 661 in that SPPC and its remaining customers will not be negatively impacted by the customer's departure. A hearing on the stipulation has been set for March 20, 2002. AB 661 also contains new electric and gas energy surcharges for low-income assistance and weatherization programs. These surcharges are recoverable directly from customers as separate line items on their bills with the Utilities remitting collected surcharges to the PUCN. Various state agencies will administer the disposition of the funds. Nevada Power Company General Rate Case (NPC) On October 1, 2001, NPC filed an application with the PUCN seeking an electric general rate increase. This application was mandated by AB 369, which was enacted by the Nevada legislature in April 2001. On December 21, 2001, NPC filed a Certification to its general rate filing updating costs and revenues pursuant to Nevada regulations. In the certification filing, NPC requested an increase in its general rates charged to all classes of electric customers designed to produce an increase in annual electric revenues of $22.7 million, which is an overall 1.7% rate increase. The application also seeks a return on common equity ("ROE") for Nevada Power's total electric operations of 12.25% (a reduction from NPC's last-authorized ROE for bundled electric operations of 12.50%) and an overall rate of return ("ROR") of 9.30% (a reduction from NPC's last-authorized ROR for bundled electric operations of 10.02%). Public hearings on NPC's general rate case began on February 4, 2002. Various parties have intervened in NPC's general rate case including the Staff of the PUCN, the Bureau of Consumer Protection from the Nevada Attorney General's office, MGM/Mirage, and the Nevada Coalition Of Commercial Energy Consumers. The reduction of NPC's revenue requirements proposed by the intervenors ranges from $50 million to $107 million. Nevada Power Company Deferred Energy Case (NPC) On November 30, 2001, NPC filed an application with the PUCN seeking to clear deferred balances for purchased fuel and power costs accumulated between March 1, 2001 through September 30, 2001. This application was mandated by AB 369, which was enacted by the Nevada Legislature in April 2001. The application seeks to establish a Deferred Energy Accounting Adjustment ("DEAA") rate to clear accumulated purchased fuel and power costs of $922 million and spread the cost recovery over a not more than three-year period. It also seeks to recalculate the Base Tariff Energy Rate to reflect anticipated ongoing purchased fuel and power costs. The total rate increase resulting from the DEAA would amount to 21%. NPC has proposed an alternate plan in which full recovery of the deferred balance would be amortized over a period greater than three years, but not to exceed six years. Public hearings began March 4, 2002. Various parties have intervened in NPC's deferred energy rate case including the Staff of the PUCN, the Bureau of Consumer Protection from the Nevada Attorney General's office, MGM/Mirage, the Southern Nevada Water Authority, the Nevada Energy Buyers Group, and the Nevada Coalition Of Commercial Energy Consumers. The disallowance of NPC's deferred energy balance that is proposed by the intervenors ranges from $85 million to $980 million. Sierra Pacific Power Company General Rate Case (SPPC) On November 30, 2001, SPPC filed an application with the PUCN seeking an electric general rate increase. This application was mandated by AB 369, which was enacted by the Nevada Legislature in April 2001. On February 28, 2002, SPPC filed a certification to its general rate filing, updating costs and revenues pursuant to Nevada regulations. In the certification filing, SPPC requested an increase in its general rates charged to all classes of electric customers, which were designed to produce an increase in annual electric 110 revenues of $15.9 million representing an overall 2.4% rate increase. The application also seeks an ROE for SPPC's total electric operations of 12.25% (an increase from SPPC's last authorized ROE for bundled electric operations of 12.0%) and an overall ROR of 9.42% (a reduction from SPPC's last authorized ROR for bundled electric operations of 10%). Public hearings for SPPC's general rate case are scheduled to begin on April 8, 2002. Various parties have intervened in SPPC's general rate case including the Staff of the PUCN, the Bureau of Consumer Protection from the Nevada Attorney General's office, and Barrick Goldstrike Mines, among others. Intervenor testimony will not be filed until March 22, 2002. Sierra Pacific Power Company Deferred Energy Case (SPPC) On February 1, 2002, SPPC filed an application with the PUCN seeking to clear deferred balances for purchased fuel and power costs accumulated between March 1, 2001 and November 30, 2001. This application was mandated by AB 369. The application seeks to establish a DEAA rate to clear accumulated purchased fuel and power costs of $205 million and spread the cost recovery over a not more than three-year period. It also seeks to recalculate the Base Tariff Energy Rate to reflect anticipated ongoing purchased fuel and power costs. The total rate increase resulting from the DEAA would amount to 9.8%. SPPC has proposed an alternate plan in which full recovery of the deferred balance would be amortized over a period greater than three years, but not to exceed six years. Public hearings are scheduled to begin in April 2002. Various parties have intervened in SPPC's deferred energy rate case including the Staff of the PUCN, the Bureau of Consumer Protection from the Nevada Attorney General's office, and Barrick Goldstrike Mines, among others. Intervenor testimony will not be filed until April 22, 2002. Finance Authority (NPC, SPPC) On September 20, 2001, the PUCN approved the June 19, 2001 applications by the Utilities for authority to issue long or short-term debt on either a secured or unsecured basis in an aggregate amount not to exceed $200 million for NPC and $100 million for SPPC through the end of 2002. NPC has issued all of its $200 million of authorized debt. SPPC has not issued any debt under this authority and has the full amount of the $100 million of authorized debt available for future issuances. On September 20, 2001, the PUCN also approved the Utilities' June 19, 2001 applications to amend an order issued by the PUCN allowing each of the Utilities to issue unsecured short-term promissory notes in an amount not to exceed $250 million through the period ending December 31, 2001. In the applications, the Utilities requested that the PUCN amend its previous order to provide the Utilities with the flexibility to issue secured promissory notes in addition to, or in lieu of, the authorized unsecured promissory notes. On October 1, 2001, NPC and SPPC each filed an application with the PUCN requesting authority to issue secured or unsecured promissory notes in aggregate amounts not to exceed $250 million through December 31, 2004. On October 9, 2001, the Utilities filed amended applications reducing the time period to December 31, 2003. On November 29, 2001, the PUCN issued a compliance order approving the requests. Currently, NPC has $50 million and SPPC has $100 million of short-term debt authority remaining from these PUCN authorizations. Natural Gas Rate Increase (SPPC) On June 29, 2001, SPPC filed with the PUCN a Purchase Gas Adjustment (PGA) seeking recovery of $41.4 million in accumulated, unrecovered purchased gas expenses, and an increase in the going-forward rate to $.71 per therm. Public hearings were held on October 22 and 23, 2001. On November 5, 2001, the PUCN granted SPPC's application and approved recovery of the entire $41.4 million accumulated deferred balance over a three-year period and an increase in the going-forward rate to $.6648 per therm. Any over or under-recovery of future energy costs will be the subject of a future PGA application. SPPC will file its next PGA on July 1, 2002. 111 FERC Matters (NPC and SPPC) --------------------------- Price Mitigation Plan On June 19, 2001, the FERC adopted a price mitigation plan applicable to spot market wholesale power sales in California and throughout the western United States during the period June 20, 2001 through September 30, 2002. The price mitigation plan establishes a mechanism with which to determine the maximum amount that may be charged for power sold during this period. The intent of the mitigation plan is to simulate the price that might be charged for electricity sold under competitive market conditions. Sellers that do not wish to establish rates on the basis of this price mitigation plan may propose cost-of-service rates covering all of their generating units in the WSCC for the duration of the mitigation plan. Although the Utilities are not able to predict at this time the long-term effect that the FERC price mitigation and other market developments plan may have on their results of operations, management believes that, under certain market conditions, the FERC plan adversely affects the availability of spot market power to the Utilities and reduces the price at which the Utilities can sell power on the wholesale market. Another potential result from these price mitigation measures could be the delay and/or cancellation of proposed power plants throughout the western United States. If these results occur, the long-term supply of energy could be reduced. Numerous parties, including NPC and several northwest utilities, appealed the June 19 and July 25, 2001 orders from the FERC to the District of Columbia Court of Appeals on the basis that the price caps are unfair to electric customers who reside outside of California. In a report to Congress on January 31, 2002, the FERC said the price mitigation plan had little if any influence on prices at which Western utilities were able to resell power. SPR is not persuaded by the FERC's report and continues to believe that the FERC's price caps have negatively impacted electric customers outside California. The parties to the appeal await action by the Court. Wholesale Sales Tariffs On March 13, 2001, the Utilities each filed an application for an order approving market-based rates. The market-based authority would apply to sales of electric energy and capacity outside of the Utilities' control areas. On May 11, 2001, SPPC and NPC received approval for market-based rates subject to a compliance order. SPPC's and NPC's compliance filing was accepted on August 10, 2001. California Matters (SPPC) ------------------------- Rate Stabilization Plan SPPC serves approximately 44,500 customers in California. On June 29, 2001, SPPC filed with the CPUC a Rate Stabilization Plan, which includes two phases. Phase One, which was also filed June 29, 2001, is an emergency electric rate increase of $10.2 million annually or 26%. If granted, the typical residential monthly electric bill for a customer using 650 kilowatt-hours would increase from approximately $47.12 to $60.12. On August 14, 2001, a pre-hearing conference was held, and a procedural order was established. On September 27,2001, the Administrative Law Judge issued an order stating that no interim or emergency relief could be granted until the end of the "rate freeze" period mandated by the California restructuring law for recovery of stranded costs. In accordance with the judge's request, on October 26, 2001, SPPC filed an amendment to its application declaring the rate freeze period to be over. Phase Two, which is scheduled to be filed with the CPUC in April 2002, will be a general rate case to recover costs for expenses other than fuel and purchased power. SPPC will also ask the CPUC to reinstate the Energy Cost Adjustment Clause, which would allow SPPC to file for periodic rate adjustments to reflect its actual costs for fuel and purchased power. Phase Two will also include a proposal pertaining to the termination of the 10% rate reduction mandated by AB 1890. On December 5 and 11, 2001 hearings on Phase One were held and on January 11, 2002, opening briefs were filed. Reply briefs were filed on January 25, 2002. A proposed draft decision is expected by the end of March 2002. SPPC will file Phase Two on April 1, 2002. 112 NOTE 4. EARNINGS PER SHARE The following table outlines 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. Also see Note 7, Common Stock and Other Paid-in Capital.
Year ended December 31, -------------------------------------------- 2001 2000 1999 ------------ ------------ ------------ Basic EPS Numerator ($000) Income (loss) from continuing operations $ 29,866 $ (49,414) $ 48,210 Income from discontinued operations 1,022 9,634 3,540 Gain on disposal of water business 25,845 -- -- ------------ ------------ ------------ Net income (loss) $ 56,733 $ (39,780) $ 51,750 ============ ============ ============ Denominator Weighted average number of shares outstanding 87,542,441 78,435,405 62,577,385 ============ ============ ============ Per-Share Amounts: Income (loss) from continuing operations $ 0.34 $ (0.63) $ 0.77 Income from discontinued operations 0.01 0.12 0.06 Gain on disposal of water business 0.30 -- -- ------------ ------------ ------------ Net income (loss) $ 0.65 $ (0.51) $ 0.83 ============ ============ ============ Diluted EPS Numerator ($000) Income (loss) from continuing operations $ 29,866 $ (49,414) $ 48,210 Income from discontinued operations 1,022 9,634 3,540 Gain on disposal of water business 25,845 -- -- ------------ ------------ ------------ Net income (loss) $ 56,733 $ (39,780) $ 51,750 ============ ============ ============ Denominator Weighted average number of shares outstanding before dilution 87,542,441 78,435,405 62,577,385 Stock options/1/ 14,021 5,645 20,447 Executive long term incentive plan- performance shares/1/ 43,693 35,393 26,118 Non-Employee Director stock plan/1/ 9,355 5,885 5,736 Employee stock purchase plan/1/ 2,862 2,807 1,790 ------------ ------------ ------------ 87,612,372 78,485,135 62,631,476 ------------ ------------ ------------ Per-Share Amounts/1/: Income (loss) from continuing operations $ 0.34 $ (0.63) $ 0.77 Income from discontinued operations 0.01 0.12 0.06 Gain on disposal of water business 0.30 -- -- ------------ ------------ ------------ Net income (loss) $ 0.65 $ (0.51) $ 0.83 ============ ============ ============
/1/ Because of a net loss for the year ended December 31, 2000, stock equivalents would be anti-dilutive. Accordingly, Diluted EPS for that period is computed using the weighted average number of shares outstanding before dilution. 113 NOTE 5. INVESTMENTS IN SUBSIDIARIES AND OTHER PROPERTY Investments in subsidiaries and other property consisted of (dollars in thousands): Sierra Pacific Resources ------------------------ December 31, 2001 2000 -------- -------- Investment in Pinon Pine, LLC $ 55,319 $ 58,049 Investment in TGTC 18,799 17,164 Investment in Sierra Touch America 9,917 2,675 Cash Value-Life Insurance 12,580 13,393 Acquisition Costs 220 12,451 Other Investments 32,057 31,330 -------- -------- $128,892 $135,062 ======== ======== Nevada Power ------------ December 31, 2001 2000 -------- -------- Cash Value-Life Insurance $ 12,580 $ 13,393 Other 141 25 -------- -------- $ 12,721 $ 13,418 ======== ======== Sierra Pacific Power -------------------- December 31, 2001 2000 -------- -------- Investment in Pinon Pine, LLC $ 55,319 $ 58,049 Other 1,866 1,998 -------- -------- $ 57,185 $ 60,047 ======== ======== SPPC, through its wholly owned subsidiaries, Pinon Pine Corp., Pinon Pine Investment Co., and GPSF-B, owns Pinon Pine Company, L.L.C. (the "LLC"). 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"). Construction of Pinon Pine was completed in June 1998. Pinon Pine is a project co-funded by the Department of Energy (DOE) under an agreement between SPPC and DOE that expired December 31, 2000. Through December 31, 2001, the DOE funded $167 million for construction, operation, and maintenance of the project. Included in the Consolidated Balance Sheets of SPR and SPPC is the net book value of the gasifier and related assets, which is approximately $105 million as of December 31, 2001, of which $50 million is included in Utility Plant, and $55 million is included in Investments in subsidiaries and other property. 114 To date, SPPC has not been successful in obtaining sustained operation of the gasifier. SPPC has retained an independent engineering consulting firm, to complete a comprehensive study of the Pinon Pine gasification plant by mid-2002. The study will evaluate the potential modifications required to make the facility operational and reliable using several technology scenarios. The evaluation of each scenario will include an estimate of the additional capital expenditures necessary for reliable operation of the facility, and the risks associated with that technology. Although not anticipated, if analysis of the study by SPPC's management indicates there is no economically feasible use of the Pinon Pine assets, SPPC intends to pursue recovery of Pinon Pine, net of salvage, as a regulatory asset. The request for recovery would be based, in part, on the PUCN's approval of Pinon Pine in an earlier resource plan. In that event, if SPPC is unsuccessful in obtaining recovery, there could be a material adverse effect on SPPC's and SPR's financial condition and results of operations. NOTE 6. JOINTLY OWNED FACILITIES At December 31, 2001, SPR (through its utility subsidiaries NPC and SPPC) owned the following undivided interests in jointly owned electric utility facilities:
% Owned Construction by Accumulated Net Plant in Work in Generating Facility Subsidiary Plant in Service Depreciation Service Progress Subsidiary ---------------------------------------------------------------------------------------------------------------------- Navajo Station 11.3 $225,748 $ 97,933 $127,815 $ 3,804 NPC Mohave Facility 14.0 84,570 37,133 47,437 1,655 NPC Reid Gardner No. 4 32.2 126,107 54,580 71,527 278 NPC Valmy Station 50.0 281,768 126,370 155,398 21 SPPC -------- -------- -------- ------- TOTAL $718,193 $316,016 $402,177 $ 5,758 ======== ======== ======== =======
The above amounts for Navajo and Mohave include NPC's share of transmission systems and general plant equipment and, in the case of Navajo, NPC'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 facilities. NPC's share of operating expenses for these facilities is included in the corresponding operating expenses in the Consolidated Statements of Income. The Mohave Generating Station is jointly owned by Southern California Edison (56%), Los Angeles Department of Water and Power (20%), NPC (14%) and Salt River Project (10%). According to the terms of the operating agreement, if any of the participants default on their contractual obligations for a period of six (6) months, thereafter the output of the station is reduced by the defaulting participant's percentage of ownership. The non-defaulting participants would then assume the station's reduced variable costs and ongoing fixed operating costs in accordance with their respective ownership percentages. The non-defaulting participants would submit the dispute or default to a board of arbitrators, which would determine what remedies are necessary to resolve the dispute or remedy the default. At December 31, 2001, none of the participants had defaulted on their contractual obligations. 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. 115 NOTE 7. COMMON STOCK AND OTHER PAID-IN CAPITAL As of December 31, 2001, 3,508,039 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 SPR 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 NPC ELTIP was terminated and existing SPR plans were adopted by the surviving company. 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. On August 15, 2001, SPR completed a public offering of 23,575,000 shares of its common stock, yielding net proceeds of approximately $340 million, all of which were contributed to NPC as an additional equity investment. On November 16 and 21, 2001, SPR completed a public offering of 6,900,000 of its Corporate PIES, yielding net proceeds of approximately $345 million. Each Corporate PIES unit consists of a forward stock purchase contract and a senior unsecured note issued by SPR with a face amount of $50. The senior notes are pledged as collateral to secure each holder's obligation to purchase shares of SPR common stock under the stock purchase contract. The senior note may be released from the pledge arrangement if a holder opts to create Treasury PIES by delivering a like principal amount of U.S. Treasury securities to the Securities Intermediary in substitution for the senior notes. 116 Each stock purchase contract obligates the holder to purchase SPR common stock on or before November 15, 2005, the Purchase Contract Settlement Date. The number of shares each investor is entitled to receive will depend on the average closing price of SPR common stock over a 20-day trading period prior to the settlement. Prior to the Purchase Contract Settlement Date, holders of Corporate PIES have the option to pay $50 per Corporate PIES to settle their purchase contract obligations. If the holders do not elect to make a cash payment, the proceeds from the remarketing of the senior notes will be used to satisfy their purchase contract obligations. The purchase contracts are forward transactions in SPR common stock. Upon issuance, a liability for the present value of the purchase contract adjustment payments, approximately $13.7 million, was recorded in Other deferred credits, with a corresponding reduction to Other paid-in capital. See further discussion regarding these senior notes and the purchase contract adjustment payments at Note 9 - Long-Term Debt. Upon settlement of a purchase contract, SPR will receive the stated amount of $50 on the purchase contract and will issue the required number of shares of common stock. The stated amount received will be credited to stockholders' equity and allocated between the Common stock and Other paid-in capital accounts. Prior to the issuance of common stock upon settlement of the purchase contracts, SPR expects that the PIES will be reflected in SPR `s earnings per share calculations using the treasury stock method. Under this method, the number of shares of common stock used in calculating earnings per share is deemed to be increased by the excess, if any, of the number of shares of common stock issuable upon settlement of the purchase contracts over the number of shares that could be purchased by SPR in the market at the average closing price during the relevant period using the proceeds receivable upon settlement. As a result, SPR expects there will be no dilutive effect on its earnings per share except during periods when the average closing price per share of common stock is above the threshold appreciation price. The changes in common stock and additional paid-in capital for 2001, 2000, and 1999, are as follows (dollars in thousands):
Shares Issued Amount ------------------------------------ ------------------------------------ 2001 2000 1999 2001 2000 1999 ---------- ------ ---------- --------- ---------- ---------- Public Offering 23,575,000 - - $340,364 $ - $ - Merger Exchange - - 78,414,560 - - 66,540 CSIP/DRP - 5,389 - - 237 - ESPP and other 60,319 55,268 - 830 1,055 - ---------- ------ ---------- --------- ---------- ---------- 23,635,319 60,657 78,414,560 $341,194 $ 1,292 $ 66,540 ========== ====== ========== ========= ========== ==========
NOTE 8. PREFERRED STOCK AND PREFERRED TRUST SECURITIES SPPC's preferred stock is superior to SPPC's common stock with respect to dividend payments (which are cumulative) and liquidation rights. The following table indicates the dollar amount and number of shares of SPPC preferred stock outstanding at December 31 of each year: 117
Amount Shares Outstanding ------------------------ -------------------------- (Dollars in thousands) 2001 2000 2001 2000 ------------------------ -------------------------- 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 ======================== ==========================
The following table indicates the principal amount and number of shares of NPC and SPPC preferred trust securities outstanding at December 31 of each year:
Amount Shares Outstanding ------------------------ -------------------------- (Dollars in thousands) 2001 2000 2001 2000 ------------------------ -------------------------- Preferred Trust 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 - 1,940,000 ------------------------ -------------------------- Total Preferred Trust Securities $ 188,872 $ 237,372 233,656 2,173,656 ======================== ==========================
SPR has issued neither preferred stock nor preferred trust securities. Nevada Power Company -------------------- Preferred Trust Securities On April 2, 1997, NVP Capital I (Trust), a wholly owned subsidiary of NPC, issued 4,754,860 8.2% QUIPS at $25 per security. NPC owns all of the Series A common securities, 147,058 shares issued by the Trust for $3.7 million. The QUIPS 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 QUIPS and the common securities and using the proceeds thereof to purchase from NPC its 8.2% Junior Subordinated Deferrable Interest Debentures (QUIDS) due March 31, 2037, extendible to March 31, 2046, under certain conditions, in a principal amount of $122.6 million. The sole asset of the Trust is the QUIDS. Holders of the Series A QUIPS 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 Series A QUIPS are subject to mandatory redemption, in whole or in part, upon repayment of the Series A QUIDS at maturity or their earlier redemption in an amount equal to the amount of related Series A QUIDS maturing or being redeemed. The QUIPS are redeemable at $25 per preferred security plus accumulated and unpaid distributions thereon to the date of redemption. NPC's obligations provide a full and unconditional guarantee of the Trust's obligations under the QUIPS. Financial statements of the Trust are consolidated with NPC's. Separate financial statements are not filed because the Trust is wholly owned by NPC and essentially has no independent operations, and NPC'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. 118 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. NPC 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 NPC 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 date of redemption. NPC'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 NPC's. Separate financial statements are not filed because the Trust is wholly owned by NPC and essentially has no independent operations, and NPC'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. Preferred Stock On July 23, 1999, NPC 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. Sierra Pacific Power Company ---------------------------- Preferred Trust Securities 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. On November 29, 2001 SPPC redeemed all of the outstanding 8.60% Trust Originated Preferred Securities of its wholly owned subsidiary, Sierra Pacific Power Capital Trust 1, at a price of $25.00 per preferred security. 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. 119 Preferred Stock 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 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 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, prior to the consent solicitation, 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 its preferred stock to issue up to $400 million in long-term unsecured indebtedness in excess of the present limitation. As of December 31, 2001, SPPC would have been able to issue approximately $634 million of additional unsecured indebtedness. 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 liens of NPC's and SPPC's indentures under which their first mortgage bonds and General and Refunding Mortgage bonds are issued. Nevada Power Company On April 20, 2000, NPC utilized a $100 million capital contribution from SPR to retire $85 million of NPC's First Mortgage Bonds that matured on May 1, 2000, and to reduce outstanding commercial paper balances under NPC's commercial paper program that was established in July 1999. On June 22, 2000, Clark County, Nevada issued for NPC'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 NPC'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. 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 ("AMBAC"). On August 3, 2001, NPC issued $115 million of its Series BB and Series 120 CC First Mortgage Bonds to AMBAC to secure NPC's reimbursement obligations under the Series 2000A and 2000B Clark County Bonds insurance agreements. On May 24, 2001, NPC issued $350 million of its 8.25% General and Refunding Mortgage Bonds, Series A, due June 1, 2011. The bonds were issued with registration rights under and secured by a General and Refunding Mortgage Indenture dated as of May 1, 2001 that is subject to the prior lien of NPC's Indenture of Mortgage dated as of October 1, 1953. The proceeds of the issuance were used to refinance or discharge outstanding indebtedness including commercial paper, short-term debt, and current maturities of long-term debt. On January 29, 2002, NPC successfully completed the exchange of these bonds for identical bonds, registered under the Securities Act of 1933. On June 12, 2001, $150 million of NPC's floating rate notes matured and were paid in full. The floating rate notes were issued on June 9, 2000, and the net proceeds of the $150 million issue were used to redeem $100 million of floating rate notes on July 14, 2000, and to reduce NPC's commercial paper outstanding under its commercial paper program. On August 20, 2001, $100 million of NPC's floating rate notes matured and were paid in full. The floating rate notes were issued August 18, 2000, and the net proceeds of the $100 million issue were used to reduce NPC's commercial paper outstanding under its commercial paper program. On September 20, 2001 and October 15, 2001, NPC issued an aggregate total of $210 million of 6% unsecured notes due September 15, 2003. Interest on the notes is payable on March 15 and September 15 of each year. These notes are not entitled to any sinking fund and are non-callable. The proceeds of the issuance were used to refinance or discharge outstanding indebtedness including commercial paper, short-term debt, and current maturities of long-term debt. On October 18, 2001, NPC issued $140 million of its General and Refunding Mortgage Notes, Floating Rate, Series B, due October 15, 2003. The proceeds of the issuance were used to refinance or discharge outstanding indebtedness including commercial paper, short-term debt, and current maturities of long-term debt. Sierra Pacific Power Company On April 27, 2001, Washoe County, Nevada issued for SPPC's benefit $80 million of Water Facilities Refunding Revenue Bonds, Series 2001, due March 1, 2036. The bonds bear interest at a term rate of 5.75% per annum from their date of issuance to April 30, 2003. Beginning May 1, 2003, the method of determining the interest rate on the 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. The bonds were issued to refund $80 million of Washoe County variable rate Water Facilities Revenue Bonds (Sierra Pacific Power Company Project) Series 1990 on April 30, 2001. SPPC's obligations in respect of the Series 1990 bonds had been supported by a letter of credit that was terminated in connection with the redemption of those bonds. On June 11, 2001, SPPC completed the sale of its water business assets including the Project financed by the sale of the bonds. Although SPPC no longer owns the Project, SPPC will continue to bear the obligations and payments for the bonds under the terms of the Financing Agreement dated as of March 1, 2001, between SPPC and Washoe County, Nevada. On May 24, 2001, SPPC issued $320 million of its 8.00% General and Refunding Mortgage Bonds, Series A, due June 1, 2008. The bonds were issued with registration rights under and secured by a General and Refunding Mortgage Indenture dated as of May 1, 2001 that is subject to the prior lien of SPPC's Indenture of Mortgage dated as of December 1, 1940. The proceeds of the issuance were used to refinance or discharge outstanding indebtedness including commercial paper, short-term debt, and current maturities of long-term debt. On January 29, 2002, SPPC successfully completed the exchange of these bonds for identical bonds, registered under the Securities Act of 1933. 121 On June 12, 2001, $200 million of SPPC's floating rate notes matured and were paid in full. The floating rate notes were issued on June 9, 2000, and the net proceeds of the $200 million issue were used to redeem $100 million of floating rate notes on July 14, and the remaining proceeds were used to reduce the amount of SPPC's commercial paper outstanding under the program established in July 1999. On December 17, 2001, $17 million of SPPC's MTN Series D matured and were paid in full. Sierra Pacific Resources On March 31, 2000, $10 million of SPR's Series E senior notes matured and were paid in full. 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 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 NPC merger consideration. The net proceeds of the $100 million issue were used to make a capital contribution to NPC. 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 May 9, 2000, SPR issued $300 million of its 8.75% Notes due 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 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 its commercial paper program that was established in July 1999 and was cancelled in June 2001. On November 16 and 21, 2001, SPR issued an aggregate of $345 million senior unsecured notes in connection with the public offering of 6,900,000 of its Corporate PIES. Each Corporate PIES unit consists of a forward stock purchase contract and a senior unsecured note issued by SPR with a face amount of $50. The senior notes are pledged as collateral to secure each holder's obligation to purchase shares of SPR common stock under the stock purchase contract. The senior note may be released from the pledge arrangement if a holder opts to create Treasury PIES by delivering a like principal amount of U.S. Treasury securities to the Securities Intermediary in substitution for the senior notes. Each stock purchase contract obligates the holder to purchase SPR common stock on or before November 15, 2005, the Purchase Contract Settlement Date. The number of shares each investor is entitled to receive will depend on the average closing price of SPR common stock over a 20-day trading period prior to the settlement. See further discussion regarding the forward stock purchase contract at Note 7 Common Stock And Other Paid-In-Capital. Each holder of Corporate PIES is entitled to receive quarterly payments consisting of purchase contract adjustment payments and interest on the senior unsecured notes. The Corporate PIES have a combined rate of 9.0%, which is comprised of the coupon on the senior note of 7.93% and the stated rate of the purchase contract adjustment payments of 1.07%. Interest on the senior unsecured notes began to accrue on November 16, 2001, and quarterly interest payments will be made each quarter beginning with the first payment, which was made on 122 February 15, 2002. All senior unsecured notes will be remarketed beginning on August 10, 2005, up to and including November 1, 2005, and, if necessary, on November 9, 2005, unless holders of senior notes that are not part of a Corporate PIES elect not to have their senior notes remarketed. Upon remarketing, the interest rate will be reset and the senior notes will accrue interest at the reset rate after the remarketing settlement date. Prior to the Purchase Contract Settlement Date, holders of Corporate PIES have the option to pay $50 per Corporate PIES to settle their purchase contract obligations. If the holders do not elect to make a cash payment, the proceeds from the remarketing of the senior notes will be used to satisfy their purchase contract obligations. If any senior notes remain outstanding after the Purchase Contract Settlement Date, SPR will pay interest payments on those senior notes until their maturity on November 15, 2007. Purchase contract adjustment payments will accrue from November 16, 2001. Holders received the first quarterly purchase contract adjustment payments of $0.1323 per unit ($913,000 in aggregate) on February 15, 2002, and will receive payments of $0.1338 per unit ($923,000 in aggregate) for each subsequent quarter. Upon issuance, a liability for the present value of the purchase contract adjustment payments, approximately $13.7 million, was recorded in Other Deferred Credits, with a corresponding reduction to Other Paid-in-Capital. NPC'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):
SPR Holding Co. SPR NPC SPPC and Other Subs. Consolidated ------------ ------------- --------------- ------------ 2002 $ 19,380 $ 2,630 $ 100,000 $ 122,010 2003 350,000 20,632 200,000 570,632 2004 130,000 2,621 - 132,621 2005 - 2,622 300,000 302,622 2006 - 52,629 - 52,629 ------------ ------------- -------------- ------------- Subtotal 499,380 81,134 600,000 1,180,514 Thereafter 1,127,967 844,566 345,068 2,317,601 ------------ ------------- -------------- ------------- Total $ 1,627,347 $ 925,700 $ 945,068 $ 3,498,115 ============ ============= ============== =============
123 NOTE 10. TAXES Nevada Power Company The following reflects the composition of taxes on income (in thousands of dollars):
2001 2000 1999 ---------- ----------- ---------- As Reflected in Statement of Income: Federal income taxes $ 18,715 $ (12,162) $ 19,943 State income taxes (940) - - ----------- ----------- ---------- Operating Income 17,775 (12,162) 19,943 Other income - net 15,008 2,776 1,270 ----------- ----------- ---------- Total $ 32,783 $ (9,386) $ 21,213 =========== =========== ==========
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):
2001 2000 1999 ------------ ----------- ----------- Income before preferred dividend requirements $ 63,405 $ (7,928) $ 38,787 Total income tax expense 32,783 (9,386) 21,213 ------------ ----------- ----------- 96,188 (17,314) 60,000 Statutory tax rate 35% 35% 35% ------------ ----------- ----------- Expected income tax expense 33,666 (6,060) 21,000 Depreciation related to difference in costs basis for tax purposes 1,431 1,431 1,431 Allowance for funds used during construction - equity 383 300 300 Tax benefit from the disposition of assets - - - State taxes (net of federal benefit) (611) - - ITC amortization (1,630) (1,460) (1,460) Other - net (456) (3,597) (58) ------------ ----------- ----------- $ 32,783 $ (9,386) $ 21,213 ============ =========== =========== Effective tax rate 34.1% 54.2% 35.5% ============ =========== ===========
124 The net accumulated deferred federal income tax liability consists of accumulated deferred federal income tax liabilities less related accumulated deferred federal income tax assets, as shown (in thousands of dollars):
2001 2000 ----------- ----------- Deferred Federal Income Tax Liabilities: Allowance for funds used during construction - debt $ 7,659 $ 6,067 Bond redemptions 5,460 5,683 Excess of tax depreciation over book depreciation 212,969 197,248 Severance programs 1,982 1,982 Tax benefits flowed through to customer 113,647 114,097 Deferred energy 343,023 - Other - net 1,943 (1,016) ----------- ----------- 686,683 324,061 ----------- ----------- Deferred Federal Income Tax Assets: Avoided interest capitalized 11,217 9,584 Employee benefit plans 8,555 3,536 Reserve for bad debt 10,801 4,062 Contributions in aid of construction and customer advances 69,232 63,953 Gross-ups received on contributions in aid of construction and customer advances 6,514 4,108 Excess deferred income taxes 5,859 6,358 Unamortized investment tax credit 13,255 13,550 Other - net (5,414) 2,157 ----------- ----------- 120,019 107,308 ----------- ----------- Total $ 566,664 $ 216,753 =========== ===========
NPC's balance sheets contain a net regulatory asset of $94.4 million at year-end 2001 and $94 million at year-end 2000. The net regulatory asset consists of future revenue to be received from customers (a regulatory asset) of $113.6 million at year-end 2001 and $114 million at year-end 2000, 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 $5.9 million at year-end 2001 and $6.4 million at year-end 2000 due to temporary differences for liberalized depreciation at rates in excess of current tax rates, and $13.3 million at year-end 2001 and $13.6 million at year-end 2000 due to unamortized investment tax credits. The regulatory 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 liability for temporary differences caused by the investment tax credit will be amortized ratably in the same fashion as the accumulated deferred investment credit. In addition, certain items of deferred taxes represent positive cash flows to NPC. These items reduce rate base and, therefore, are benefits passed through to customers. However, because NPC had a net operating loss for tax purposes in 2001, some of this benefit could not be utilized (i.e., deferred energy). 125 Sierra Pacific Power Company The following reflects the composition of taxes on income (in thousands of dollars):
2001 2000 1999 ----------- ----------- ----------- As Reflected in Statement of Income Federal income taxes $ 10,731 $ (1,118) $ 32,982 State income taxes (2,224) 446 888 ----------- ----------- ----------- Operating Income 8,507 (672) 33,870 Other income - net 1,753 (586) (324) ----------- ----------- ---------- Total $ 10,260 $ (1,258) $ 33,546 =========== =========== ==========
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):
2001 2000 1999 ----------- ---------- ----------- Income before preferred dividend requirements $ 22,743 $ (4,077) $ 64,615 Total income tax expense 10,260 (1,258) 33,546 ----------- ---------- ---------- 33,003 (5,335) 98,161 Statutory tax rate 35% 35% 35% ----------- ---------- ---------- Expected income tax expense 11,551 (1,867) 34,356 Depreciation related to difference in costs basis for tax purposes 1,513 1,531 1,408 Allowance for funds used during construction - equity (298) (149) 386 Tax benefit from the disposition of assets (111) (175) (442) ITC amortization (1,824) (1,824) (1,981) State taxes (net of federal benefit) (1,446) 290 577 Other - net 875 936 (758) ----------- ---------- ----------- $ 10,260 $ (1,258) $ 33,546 =========== ========== =========== Effective tax rate 31.1% 23.6% 34.2% =========== =========== ===========
The net accumulated deferred federal income tax liability consists of accumulated deferred federal income tax liabilities less related accumulated deferred federal income tax assets, as shown (in thousands of dollars): 126
2001 2000 ----------- ----------- Deferred Federal Income Tax Liabilities: Allowance for funds used during construction - debt $ 4,837 $ 7,399 Bond redemptions 6,048 5,732 Excess of tax depreciation over book depreciation 188,389 176,125 Severance programs 3,317 3,465 Tax benefits flowed through to customer 63,410 65,471 Deferred energy 87,790 5,729 Other 4,132 6,366 ----------- ----------- 357,923 270,287 ----------- ----------- Deferred Federal Income Tax Assets: Avoided interest capitalized 12,444 11,313 Employee benefit plans 3,451 3,789 Reserve for bad debt 2,960 388 Contributions in aid of construction and customer advances 35,163 33,979 Gross-ups received on contributions in aid of construction and customer advances 5,462 5,059 Excess deferred income taxes 12,797 14,494 Unamortized investment tax credit 17,452 18,434 Other 1,871 3,725 ----------- ----------- 91,600 91,181 ----------- ----------- Accumulated Deferred Federal Income Taxes $ 266,323 $ 179,106 =========== ===========
SPPC's balance sheets contain a net regulatory asset of $33.1 million at year-end 2001 and $32.6 million at year-end 2000. The net regulatory asset consists of future revenue to be received from customers (a regulatory asset) of $63.4 million at year-end 2001 and $65.5 million at year-end 2000, 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 $12.8 million at year-end 2001 and $14.5 million at year-end 2000, due to temporary differences for liberalized depreciation at rates in excess of current tax rates, and $17.5 million at year-end 2001 and $18.4 million at year-end 2000 due to unamortized investment tax credits. The regulatory 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 liability for temporary differences caused by the investment tax credit will be amortized ratably in the same fashion as the accumulated deferred investment credit. In addition, certain items of deferred taxes represent positive cash flows to SPPC. These items reduce rate base and, therefore, are benefits passed through to customers. However, because SPPC had a net operating loss for tax purposes in 2001, some of this benefit could not be utilized (i.e., deferred energy). Sierra Pacific Resources The following reflects the composition of taxes on income (in thousands of dollars):
2001 2000 1999 ------------ ------------ ----------- As Reflected in Statement of Income: Federal income taxes $ 1,934 $ (31,468) $ 24,410 State income taxes (3,164) 446 888 ------------ ------------ ----------- Operating Income (1,230) (31,022) 25,298 Other income - net 16,761 2,190 946 ------------ ------------ ----------- Total $ 15,531 $ (28,832) $ 26,244 ============ ============ ===========
127 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):
2001 2000 1999 ------------ ---------- ---------- Income before preferred dividend requirements $ 33,566 $ (45,915) $ 50,410 Total income tax expense (benefit) 15,531 (28,832) 26,244 ------------ ---------- --------- 49,097 (74,747) 76,654 Statutory tax rate 35% 35% 35% ------------ ---------- --------- Expected income tax expense (benefit) 17,184 (26,161) 26,829 Depreciation related to difference in costs basis for tax purposes 2,944 2,962 2,839 Allowance for funds used during construction - equity 85 151 686 Tax benefit from the disposition of assets (111) (175) (442) ITC amortization (3,454) (1,824) (1,981) State taxes (net of federal benefit) (2,057) (1,170) (883) Other - net 940 (2,615) (804) ------------ ---------- --------- $ 15,531 $ (28,832) $ 26,244 ============ ========== ========= Effective tax rate 31.6% 38.6% 34.2% =========== ========= =========
The net accumulated deferred federal income tax liability consists of accumulated deferred federal income tax liabilities less related accumulated deferred federal income tax assets, as shown (in thousands of dollars):
2001 2000 ------------ ---------- Deferred Federal Income Tax Liabilities: Allowance for funds used during construction - debt $ 12,496 $ 13,466 Bond redemptions 11,508 11,415 Excess of tax depreciation over book depreciation 401,358 373,373 Severance programs 5,299 5,447 Tax benefits flowed through to customer 177,057 179,568 Deferred energy 430,813 5,729 Other 16,558 5,350 ------------ ----------- 1,055,089 594,348 ------------ ----------- Deferred Federal Income Tax Assets: Avoided interest capitalized 23,661 20,897 Employee benefit plans 12,006 7,325 Reserve for bad debt 13,761 4,450 Contributions in aid of construction and customer advances 104,395 97,932 Gross-ups received on contribution in aid of construction and customer advances 11,976 9,167 Excess deferred income taxes 18,656 20,852 Unamortized investment tax credit 30,707 31,984 Other (3,543) (4,569) ------------ ----------- 211,619 188,038 ------------ ----------- Total $ 843,470 $ 406,310 ============ ===========
SPR's balance sheets contain a net regulatory asset of $127.7 million at year-end 2001 and $126.7 million at year-end 2000. The net regulatory asset consists of future revenue to be received from customers (a regulatory asset) of $177.1 million at year-end 2001 and $179.6 million at year-end 2000, due to flow-through of the tax benefits of temporary differences. Offset against these amounts are future revenues to be refunded to customers (a regulatory liability), consisting of $18.7 million at year-end 2001 and $20.9 million at 128 year-end 2000, due to temporary differences for liberalized depreciation at rates in excess of current tax rates, and $30.7 million at year-end 2001 and $32 million at year-end 2000 due to unamortized investment tax credits. The regulatory 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 liability for temporary differences caused by the investment tax credit will be amortized ratably in the same fashion as the accumulated deferred investment credit. In addition, certain items of deferred taxes represent positive cash flows to SPR. These items reduce rate base and, therefore, are benefits passed through to customers. However, because SPR had a net operating loss for tax purposes in 2001, some of this benefit could not be utilized (i.e., deferred energy). NOTE 11. FAIR VALUE OF FINANCIAL INSTRUMENTS The December 31, 2001, 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 NPC's consolidated long-term debt at December 31, 2001, is estimated to be 1.56 billion (excluding current portion) based on quoted market prices for the same or similar issues or on the current rates offered to NPC for debt of the same remaining maturities. The total fair value (excluding current portion) was estimated to be $851.2 million at December 31, 2000. The estimated fair value of NPC's preferred trust securities is $181.5 million at December 31, 2001. The fair value of NPC's preferred securities was estimated to be $186.3 million at December 31, 2000. The total fair value of SPPC's consolidated long-term debt at December 31, 2001, is estimated to be $946.5 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 $587.4 million as of December 31, 2000. SPPC's preferred trust securities were redeemed on November 29, 2001. The fair value of SPPC's preferred trust securities was estimated to be $48.5 million at December 31, 2000. The total fair value of SPR's consolidated long-term debt at December 31, 2001, is estimated to be $3.386 billion (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 $2.052 billion as of December 31, 2000. The estimated fair value of SPR's consolidated preferred trust securities is $181.5 million at December 31, 2001. The fair value of SPR's consolidated preferred trust securities was estimated to be $234.8 million at December 31, 2000. NOTE 12. SHORT-TERM BORROWINGS SPR On January 16, 2001, SPR paid off its commercial paper balance of $4 million. SPR cancelled its commercial paper program as of June 12, 2001. On November 29, 2001, SPR put into place a $75 million unsecured revolving credit facility that may be used for working capital and general corporate purposes. This facility will expire on November 28, 2002. As of December 31, 2001 SPR had not drawn on this facility and had no outstanding balance. 129 NPC On November 29, 2001, NPC put into place a $200 million unsecured revolving credit facility that may be used for working capital and general corporate purposes, including commercial paper backup. This new credit facility requires NPC to issue General and Refunding Mortgage Bonds to secure this credit facility in the event of a decline in NPC's senior unsecured debt rating. This facility will expire on November 28, 2002. On December 17, 2001, $100 million of NPC's floating rate notes matured and were paid in full. On December 31, 2001, NPC had a commercial paper balance outstanding of $130.5 million with a weighted average interest rate of 2.85%, and remaining capacity to issue an additional $69.5 million under its commercial paper program. NPC sustained its A2/P2 ratings by Standard and Poor's and Moody's, respectively. SPPC On November 29, 2001, SPPC put into place a $150 million unsecured revolving credit facility that may be used for working capital and general corporate purposes, including commercial paper backup. This new credit facility requires SPPC to issue General and Refunding Mortgage Bonds to secure this credit facility in the event of a decline in SPPC's senior unsecured debt rating. This facility will expire on November 28, 2002. On December 31, 2001, SPPC had a commercial paper balance outstanding of $46.5 million with a weighted average interest rate of 2.77%, and remaining capacity to issue an additional $103.5 million under its commercial paper program. SPPC sustained its A2/P2 ratings by Standard and Poor's and Moody's, respectively. 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 SPR and the Utilities contain restrictions as to the payment of dividends on their common stock and as to the purchase, redemption or retirement of their capital stock. 130 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 NPC during 1999 under purchase accounting:
Other Postretirement Pension Benefits Benefits ------------------------------- ---------------------------- 2001 2000 2001 2000 ------------------------------ ---------------------------- Change in benefit obligations Benefit obligation, beginning of year $ 348,135 $ 348,470 $ 77,790 $ 77,987 Service cost 13,494 11,907 1,922 1,775 Interest cost 27,742 26,469 6,358 5,829 Participant contributions - - 466 300 Plan amendment and special termination 476 498 - - Actuarial loss (gain) 6,864 (8,922) (5,201) (4,101) Special Termination Benefits 394 - - - Acquisitions and divestiture - - (1,231) - Benefits paid (36,428) (30,287) (4,661) (4,000) ------------- ------------- ------------ ------------ Benefit obligation, end of year $ 360,677 $ 348,135 $ 75,443 $ 77,790 ============= ============= ============ ============ Change in plan assets Fair value of plan assets, beginning of year $ 349,153 $ 326,708 $ 81,900 $ 66,688 Actual return on plan assets (39,320) 51,136 (15,797) 17,377 Company contributions 1,900 1,596 730 1,535 Participant contributions - - 466 300 Acquistion and divestiture - - (1,231) - Benefits paid (36,428) (30,287) (4,661) (4,000) ------------- ------------- ------------ ------------ Fair value of plan assets, end of year $ 275,305 $ 349,153 $ 61,407 $ 81,900 ============= ============= ============ ============ Funded Status, end of year $ (85,373) $ 1,018 $ (14,036) $ 4,110 Unrecognized net actuarial (gains) losses 61,750 (13,526) (5,365) (22,696) Unrecognized prior service cost 10,366 11,561 - - Unrecognized net transition obligation - - 10,280 11,248 Contributions made in 4th quarter 11,917 270 - - ------------- ------------- ------------ ------------ Accrued pension and postretirement benefit obligations $ (1,340) $ (677) $ (9,121) $ (7,338) ============= ============= ============ ============
131 Amounts for pension and postretirement benefits recognized in the consolidated balance sheets consist of the following:
Pension Benefits Benefits ------------------------- ------------------------- 2001 2000 2001 2000 ------------------------- ------------------------- Prepaid pension asset $ 14,051 $ 13,939 N/A N/A Accrued benefit liability (15,391) (14,616) $ (9,121) $ (7,338) Intangible asset - - N/A N/A Accumulated other comprehensive income 1,395 1,395 N/A N/A Additional minimum liability (1,395) (1,395) N/A N/A ----------- ----------- ----------- ----------- Net amount recognized $ (1,340) $ (677) $ (9,121) $ (7,338) =========== =========== =========== ===========
The weighted-average actuarial assumptions as of the measurement date were as follows:
Other Postretirement Pension Benefits Benefits ---------------------------- ------------------------------ 2001 2000 1999 2001 2000 1999 ---------------------------- ------------------------------ Discount rate 7.50% 8.00% 7.50% 7.50% 8.00% 7.50% 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 2001 and all future years. 132 Net periodic pension and other postretirement benefit costs include the following components: Pension Benefits -------------------------------------- 2001 2000 1999 -------------------------------------- Service cost $ 13,494 $ 11,907 $ 8,481 Interest cost 27,742 26,469 12,823 Expected return on assets (28,806) (27,186) (11,712) Amortization of: Transition asset - - - Prior service costs 1,195 1,201 841 Actuarial losses 200 159 976 ----------- ----------- ------------ Net periodic benefit cost 13,825 12,550 11,409 Additional charges (credits): Special termination charges 394 - 5,865 Curtailment credits - - (3,920) ----------- ----------- ------------ Total net benefit cost $ 14,219 $ 12,550 $ 13,354 =========== =========== ============ Other Postretirement Benefits -------------------------------------- 2001 2000 1999 -------------------------------------- Service cost $ 1,922 $ 1,775 $ 996 Interest cost 6,358 5,829 1,982 Expected return on assets (6,774) (5,327) (1,741) Amortization of: Prior service costs - - - Transition obligation 969 968 1,344 Actuarial gains - (598) (596) ----------- ----------- ------------ Net periodic benefit cost 2,475 2,647 1,985 Additional charges (credits): Special termination charges - - 1,312 Curtailment loss - - 1,283 ----------- ----------- ------------ Total net benefit cost $ 2,475 $ 2,647 $ 4,580 =========== =========== ============ 133 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 2001 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 $ 708 $ (583) Effect on accumulated postretirement benefit obligation $ 6,961 $(5,839) NOTE 15. STOCK COMPENSATION PLANS At December 31, 2001, 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 (benefit) that has been charged against income for the performance shares, dividend equivalents, restricted stock grants, and the non-employee director stock plans was $0.5 million for 2001, ($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:
2001 2000 1999 -------------------------------- Net Income (Loss) As Reported $ 56,733 $ (39,780) $ 51,750 Pro Forma $ 55,524 $ (40,475) $ 50,908 Basic Earnings (Loss) Per Share As Reported $ 0.65 $ (0.51) $ 0.83 Pro Forma $ 0.63 $ (0.52) $ 0.81 Diluted Earnings (Loss) Per Share As Reported $ 0.65 $ (0.51) $ 0.83 Pro Forma $ 0.63 $ (0.52) $ 0.81
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. On 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 2001, SPR issued nonqualified stock options, performance shares, and restricted stock under the long-term incentive plan. Non-Qualified Stock Options Nonqualified stock options granted during 2001 were issued at an option price not less than market value at the date of the grants: January 1, May 15, May 22, July 19, and November 15. The January 1 grant vests to the participants 33% per year over a 3 year period from the grant date, and the remaining grants vest to the participants 25% per year over a four year period from the grant date. All grants may be exercised for a 134 period not exceeding ten years from the grant date. The options may be exercised using either cash or previously acquired shares, valued at the current market price, or a combination of both. A summary of the status of SPR's nonqualified stock option plan as of December 31, 2001, 2000, and 1999, and changes during the year is presented below:
----------------------------------------------------------------------------------------------------------------------------- 2001 2000 1999 ------------------------------------------------------------------------------------- Weighted- Weighted- Weighted- Average Exercise Average Exercise Average Nonqualified Stock Options Shares Price Shares Price Shares Exercise Price ----------------------------------------------------------------------------------------------------------------------------- Outstanding at beginning of year 799,428 $ 19.94 839,442 $ 24.33 289,126 $ 21.98 Granted/1/ 414,530 $ 15.08 400,000 $ 16.00 586,280 $ 25.35 Exercised - - 14,107 $ 14.28 1,286 $ 14.39 Forfeited - - 425,907 $ 25.07 34,678 $ 22.48 Outstanding at end of year 1,213,958 $ 18.28 799,428 $ 19.94 839,442 $ 24.33 Options exercisable at year-end 262,533 $ 23.03 202,394 $ 22.66 128,975 $ 20.53 Weighted-average grant date fair value of options granted/2/: November 15, 2001 $ 3.28 July 19, 2001 $ 4.62 May 22, 2001 $ 3.90 May 15, 2001 $ 4.05 January 1, 2001 $ 3.32 August 4, 2000 $ 4.10 August 1, 1999 $ 5.11 January 1, 1999 $ 4.05 -----------------------------------------------------------------------------------------------------------------------------
1. The number of nonqualified stock options granted during the year was 414,530 shares. 2. 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 2001, 2000 and 1999:
------------------------------------------------------------------------------- Dividend Expected Risk-Free Rate of Option Grant Date Yield Volatility Return Expected Life ------------------------------------------------------------------------------- November 15, 2001 5.04% 32.37% 4.63% 10 years July 19, 2001 4.47% 32.02% 5.66% 10 years May 22, 2001 4.98% 32.48% 5.55% 10 years May 15, 2001 4.98% 32.48% 5.55% 10 years January 1, 2001 5.48% 32.22% 5.22% 10 years 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 -------------------------------------------------------------------------------
135 The following table summarizes information about nonqualified stock options outstanding at December 31, 2001:
------------------------------------------------------------------------------------- Options Outstanding Options Exercisable ------------------------------------------------------- Number Remaining Number Exercise Outstanding Contractual Exercise Exercisable Grant Date Price at 12/31/01 Life Price at 12/31/01 ------------------------------------------------------------------------------------- 1/1/1994 $14.24 8,003 2 years $14.24 8,003 1/1/1995 $13.02 9,750 3 years $13.02 9,750 1/1/1996 $16.23 8,674 4 years $16.23 8,674 1/1/1997 $19.97 45,501 5 years $19.97 45,501 1/1/1998 $24.93 69,120 6 years $24.93 69,120 1/1/1999 $24.22 106,080 7 years $24.22 70,724 8/1/1999 $26.00 152,300 7.6 years $26.00 50,762 8/4/2000 $16.00 400,000 8 years $16.00 - 1/1/2001 $14.80 310,530 9 years $14.80 - 5/15/2001 $16.09 27,000 9.5 years $16.09 - 5/22/2001 $15.52 40,000 9.5 years $15.52 - 7/19/2001 $16.95 27,000 9.6 years $16.95 - 11/15/2001 $14.12 10,000 9.9 years $14.12 - Weighted Average Remaining 7.9 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 In 2001, 2000 and 1999, SPR granted performance shares in the following numbers and initial values: 1/1/2001 8/4/2000 1/1/2000 1/1/1999 ----------------------------------------------- Shares Granted 135,906 4,798 31,707 28,944 Value per Share $ 14.80 $16.00 $ 26.00 $ 24.22 The actual number of shares earned by each participant is dependent upon SPR achieving certain financial goals over three-year performance periods. However, 66,100 shares included in the number granted on 1/1/2001 have a one-year performance period, from January 1 through December 31, 2001. The value of all performance share grants, 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. The grant of 66,100 shares on 1/1/2001 will be paid in SPR stock only. 136 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 2001, SPR granted 13,200 restricted stock shares, detailed as follows: Grant Date 11/15/2001 7/19/2001 5/22/2001 5/15/2001 -------------------------------------------------- Shares Granted 2,400 2,500 4,000 4,300 Grant Price per Share $14.12 $16.95 $15.52 $16.09 Vesting Schedule for all: 4 years, 25% per year 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. No restricted stock grants were issued in 1999. There are no performance criteria associated with the restricted stock grants, and all grants were issued with an entitlement to dividend equivalents. 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. On 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 33,830, 46,773 and 21,888 shares to employees in 2001, 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 2001, 2000 and 1999: ---------------------------------------------------------------- Average Average Average Weighted Dividend Expected Risk-Free Average Fair Year Yield Volatility Rate of Return Value ---------------------------------------------------------------- 2001 5.01% 32.43% 2.82% $2.72 2000 4.72% 30.97% 5.86% $3.03 1999 4.31% 18.85% 5.08% $2.85 ---------------------------------------------------------------- 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 2001, 2000 and 1999, SPR granted the following total shares and related compensation to directors in SPR stock, respectively: 14,573, 16,915 and 4,741 shares, and $210,000, $250,000 and $150,000. SPR did not pay out any phantom stock shares in 2001. 137 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 $14.3 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, 2001. 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 instructed the Utilities to propose an amortization period for these costs, and allows SPPC and NPC to recover the costs to the extent that they are offset by merger savings. The Utilities have filed a case with the PUCN for recovery of these amounts and other merger costs. NPC and SPPC have proposed recovery over a 10-year period, and expect a decision on their filings by April 1, 2002 and June 1, 2002, respectively. At December 31, 2001, the remaining liability for unpaid severance was $0.4 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, and on June 11, 2001, SPPC closed the sale of its water business to the Truckee Meadows Water Authority (TMWA) for $341 million. SPPC recorded a $25.8 million gain on the sale, net of the refund described below and net of income taxes of $18.2 million. Included in the sale were facilities for water storage, supply, transmission, treatment and distribution, as well as accounts receivable and regulatory assets. Accounts receivable consisted of amounts due from developers for distribution facilities. Regulatory assets consisted primarily of costs incurred in connection with the Truckee River negotiated water settlement. Transfer of hydroelectric facilities included in the contract of sale for an additional $8 million 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. Pursuant to a stipulation entered into in connection with the sale and approved by the Public Utilities Commission of Nevada ("PUCN"), SPPC is required to hold in trust for refund to customers $21.5 million of the proceeds from the sale. The refund is being credited on the electric bills of SPPC's former water customers over a period not to exceed fifteen months from June 11, 2001. Under a service contract with TMWA, SPPC will provide, on an interim basis, customer service, billing, and meter reading services to TMWA. Revenues from operations of the water business for the years ended December 31, 2001, 2000, and 1999 were $23 million, $57 million, and $54 million, respectively. The net income from operations of the water business, as shown in the Consolidated Statements of Income of SPR, includes (in thousands) preferred dividends of $200, $401, and $196 for the years ended December 31, 2001, 2000, and 1999, respectively. The income from operations of the water business, as shown in the Consolidated Statements of Income of SPPC, includes (in thousands) preferred dividends of $200, $401, and $528 for the years ended December 31, 2001, 2000, and 1999, respectively. These amounts are not included in the revenues and income (loss) from continuing operations shown in the accompanying income statements. NOTE 18. COMMITMENTS AND CONTINGENCIES Construction ------------ The Utilities' combined estimated cash construction expenditures for the year 2002 and the five-year period 2002-2006 are $470 million and $1.7 billion, respectively. 138 Purchased Power --------------- NPC has three long-term contracts for the purchase of electric energy. One of these contracts commences in 2004 and expires in 2012. NPC's other contracts expire in 2016 and 2017. SPPC has one such contract that expires in 2009. Estimated future commitments under non-cancelable agreements with initial terms of one year or more at December 31, 2001, were as follows (dollars in thousands): 2002 $ 46,440 2003 152,852 2004 151,627 2005 136,680 2006 137,446 2007 to 2017 777,064 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, 2001, NPC 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, 2001, 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. Coal and Natural Gas -------------------- The Utilities have several long-term contracts for the purchase and transportation of coal and natural gas. These contracts expire in years ranging from 2006 to 2027. Estimated future commitments under non-cancelable agreements with initial terms of one year or more at December 31, 2001 were as follows (dollars in thousands): Coal and Gas Transportation 2002 $ 42,870 $ 78,255 2003 39,528 86,499 2004 36,451 93,031 2005 17,534 79,137 2006 18,045 76,254 2007 to 2023 0 725,651 Leases ------ In 1984, NPC 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, 2001, were as follows (dollars in thousands): 139 2002 $ 6,156 2003 6,156 2004 6,946 2005 7,736 2006 7,736 2007 to 2014 58,016 The amount of imputed interest necessary to reduce the future cash rental payments to present value is $44 million as of December 31, 2001. Total interest expense on the lease obligation was $5.7 million and total amortization of the leased facility was $(278,000) for the year ended December 31, 2001. The total accumulated amortization of the leased facility on December 31, 2001, was $8.6 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, 2001, were as follows (dollars in thousands): 2002 $ 12,127 2003 9,284 2004 8,194 2005 7,289 2006 6,863 2007 to 2045 63,463 Sale of Generation Assets ------------------------- As a condition to its approval of the merger between SPR and NPC, the PUCN required the Utilities to file a Divestiture Plan for the sale of their electric generation assets. The PUCN approved a revised Divestiture Plan stipulation in February 2000. In May 2000 an agreement was announced for the sale of NPC's 14% undivided interest in the Mohave Generating Station ("Mohave"). In the fourth quarter of 2000 the Utilities announced agreements to sell six additional bundles of generation assets described in the approved Divestiture Plan. The sales were subject to approval and review by various regulatory agencies. AB 369, which was signed into law on April 18, 2001, prohibits until July 2003 the sale of generation assets and directs the PUCN to vacate any of its orders that had previously approved generation divestiture transactions. In January 2001, California enacted a law that prohibits until 2006 any further divestiture of generation properties by California utilities, including SPPC, and could also affect any sale of NPC's interest in Mohave after July 2003 since the majority owner of that project is Southern California Edison. In addition, SPPC's request for an exemption from the requirements of a separate California law requiring approval of the CPUC to divest its plants was denied, subject to future refiling. The sales agreements for the six bundles provide that they terminate eighteen months after their execution unless the parties agree to an earlier termination. The parties may extend the termination another six months to obtain additional regulatory approvals. As a result of the legislative and regulatory developments which have rendered the contracts impossible to perform, the Utilities are engaged in discussions with the buyers of the generation assets regarding the formal termination of the sales agreements and the related energy buyback contracts and interconnection agreements. As of December 31, 2001, NPC and SPPC had incurred costs of approximately $12.3 million and $15.5 million, respectively, in order to prepare for the sale of generation assets. The Utilities have requested recovery of these costs in each Utility's respective general rate case filing with the PUCN, discussed in Note 3, Regulatory Actions. 140 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 NPC) 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 $395 million. As a 14% owner in the Mohave Station, NPC's cost could be $55 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. The EPA has solicited information to determine whether visibility impairment in the Grand Canyon can be reasonably attributed to Mohave. The EPA determined that significant visibility impairment to the Grand Canyon cannot be reasonably attributable to the station provided controls are installed as agreed to in the consent order. Therefore, the EPA will not require a Best Available Retrofit Technology Review. Provisions that were agreed to in the settlement will be reflected in the state Implementation Plan for Nevada. In May 1997, NDEP ordered NPC 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 NPC 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 NPC. New pond construction and lining costs are estimated at $15 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 plan. The extent of contamination has been determined and remediation is occurring at a modest rate. An engineering evaluation of the current remediation technology will occur in 2002 to verify efficiency and to expedite remediation. Remediation modifications are not expected to materially affect the financial position of SPR or NPC. In May 1999, NDEP issued an order to eliminate the discharge of NPC's Clark Station wastewater to groundwater. The order also required a hydrological assessment of groundwater impacts in the area. This assessment, submitted to NDEP in February 2001, warranted a Corrective Action Plan which was submitted to NDEP in November and is pending review. Remediation costs are expected to be in the $500,000 - $750,000 range. In addition to remediation, NPC will spend $789,000 to line existing ponds. After review and approval of the Corrective Action Plan by NDEP, NPC will implement remediation. 141 In July 2000, NPC received a request from the EPA for information to determine the compliance of certain generation facilities at the Clark Station with the applicable State Implementation Plan. In November 2000, NPC and the Clark County Health District entered into a Corrective Action Order requiring, among other steps, capital expenditures at the Clark Station totaling approximately $3 million. In March 2001, the EPA issued an additional request for information that could result in remediation beyond that specified in the November 2000 Corrective Action Order. If the EPA prevails, capital expenditures and temporary outages of four of Clark Station's generation units could be required. Additionally, depending on the time of year that the compliance activity and corresponding generation outage would occur, the incremental cost to purchase replacement energy could be substantial. 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 $136,000 has been spent through December 31, 2001. Once evaluations are completed, SPPC will be in a better position to estimate and record the ultimate liabilities for the Sites. Other Subsidiaries of SPR LOS, 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 underground fuel tank that has been removed from the property. 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. 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 is NEICO's intention to either lease or sell the property. Other Commitments and Contingencies ----------------------------------- 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 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 $4.7 million as of December 31, 2001, of which $325,000 was made in 2001. The remaining $300,000 balance of SPR's commitment is expected to be drawn, as funds are needed by the partnership during 2002. 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%. 142 Certain of the Utilities' substations and portions of its generating stations, transmission, distribution, and communication systems are located on lands owned by units or agencies of federal, state and local governments under licenses, permits, easements (collectively, "rights"). Except for those granted in perpetuity, these rights may be canceled, with notice, at the will of the grantor. Certain rights may impose restrictions and obligations on the Utilities, including, but not limited to, care of property, limits on use, and the right of inspection. Certain of the rights obligate the Utilities to make periodic payments and may also allow the grantor to periodically reappraise the lands on which the Utilities' property is located. Such reappraisals, which may result in a change to the required periodic payments, may occur from annually to every five years. In connection with these rights, the Utilities incurred expenses of $1.41 million, $1.11 million and $1.38 million in 2001, 2000, and 1999, respectively. Sierra Touch America LLC (STA), a partnership between SPC and Touch America, a subsidiary of Montana Power Company, is constructing a fiber optic line between Salt Lake City, Utah and Sacramento, CA. The conduits included in the line are under contract to be sold to AT&T, PF Net corporations, and STA. SPC is responsible for 50% of the partnership's operating expenses and shares in the construction cost of the fiber network. Construction activity between Sacramento and Reno commenced in July 2000, and the estimated completion date has been moved to early 2003. Williams Communications, LLC ("Williams") has filed a complaint in United States District Court alleging that STA has failed to make timely payment on invoices in connection with a construction agreement between Williams and STA. TI Energy Services ("TI") has filed a complaint in the District Court of Harris County, Texas, alleging that STA has failed to make timely payment on invoices in connection with a services agreement between TI and STA, whereby TI is to provide services for certain segments of the fiber optic line. Although SPC's ultimate liability, if any, cannot be estimated, Management believes the final outcome of the litigation is not likely to have a material adverse effect on SPR's financial position or results of operations. SPPC owns a 345 kV transmission line that connects SPPC to the facilities of the Bonneville Power Administration ("BPA") near Alturas, California. The Transmission Agency of Northern California ("TANC") 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 BPA'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 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. Although SPPC's ultimate liability, if any, cannot be estimated at this time, Management believes the final outcome of the appeal and any subsequent litigation is not likely to have a material adverse effect on SPR's financial position or results of operation. 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. See Notes 3, 5, 6, 7, 8, 9, 12, 14, and, 16 of SPR's consolidated financial statements for additional commitments and contingencies. 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 143 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 and the consolidated financial statements have been reclassified to report separately the net assets and operating results of the water business. Therefore the water business is not reflected in the segment information below. Operational information 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 Note 1, Summary of Significant Accounting Policies. 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 NPC.
Reconciling December 31, 2001 NPC Electric SPPC Electric Total Electric Gas All Other Eliminations Consolidated ----------------- ------------------------------------------- --------- --------- ------------ ------------ Operating revenues $ 3,025,103 $ 1,399,134 $ 4,424,237 $ 145,652 $ 18,841 $ 4,588,730 Operating income 144,364 71,219 215,583 7,749 (463) - 222,869 Operating income taxes 17,775 5,534 23,309 2,973 (27,512) (1,230) Depreciation 93,101 64,648 157,749 5,710 1,181 164,640 Interest expense on long term debt 81,599 50,071 131,670 5,128 51,572 188,370 Assets 5,225,369 2,336,479 7,561,848 264,108 270,038 85,320 8,181,314 Capital expenditures 200,852 117,563 318,415 16,041 - 334,456 Reconciling December 31, 2000 NPC Electric SPPC Electric Total Electric Gas All Other Eliminations Consolidated ----------------- ------------------------------------------- --------- --------- ------------ ------------ Operating revenues $ 1,325,470 $ 893,782 $ 2,219,252 $ 100,803 $ 14,199 $ 2,334,254 Operating income 73,460 33,715 107,175 13,420 6,794 127,389 Operating income taxes (12,162) (3,944) (16,106) 3,272 (18,188) (31,022) Depreciation 85,989 64,375 150,364 4,975 696 156,035 Interest expense on long term debt 64,513 32,547 97,060 4,318 33,218 134,596 Assets 3,407,751 1,722,725 5,130,476 151,905 61,768 333,759 5,677,908 Capital expenditures 204,505 117,429 321,934 14,490 23,350 359,774 Reconciling December 31, 1999 NPC Electric SPPC Electric Total Electric Gas All Other Eliminations Consolidated ----------------- ------------------------------------------- --------- --------- ------------ ------------ Operating revenues $ 977,262 $ 259,440 $ 1,236,702 $ 38,958 $ 9,132 $ 1,284,792 Operating income 116,983 40,047 157,030 3,175 2,656 162,861 Operating income taxes 19,943 10,177 30,120 425 (5,247) 25,298 Depreciation 80,644 27,060 107,704 2,128 243 110,075 Interest expense on long term debt 64,454 11,415 75,869 1,326 299 77,494 Assets 2,748,329 1,607,312 4,355,641 153,347 426,881 300,048 5,235,917 Capital expenditures 223,963 51,798 275,761 7,051 16,252 299,064
144 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, 2001, 2000, and 1999 to the consolidated total includes the following unallocated amounts: 2001 2000 1999 -------- ---------- ---------- Other property $ - $ 1,998 $ 2,661 Cash 11,772 5,348 3,011 Current assets- other 50,862 29,852 3,103 Other regulatory assets 22,626 33,315 34,571 Net assets - discontinued operations - 261,479 256,365 Deferred charges- other 60 1,767 337 -------- ---------- ---------- $ 85,320 $ 333,759 $ 300,048 ======== ========== ========== Note 20. Subsequent Events On February 6, 2002, a dividend of $975,000 ($0.4875 per share) was declared on SPPC's preferred stock. The dividend is payable on March 1, 2002, to holders of record as of February 8, 2002. On February 6, 2002, SPR's Board of Directors declared a dividend on common stock of 20 cents per share, payable March 15, 2002, to shareholders of record at the close of business on February 22, 2002. On February 6, 2002, NPC's Board of Directors declared a $10 million dividend on NPC's common stock, all of which is held by SPR. On February 6, 2002, SPPC's Board of Directors declared a $10 million dividend on SPPC's common stock, all of which is held by SPR. Both dividends were paid on March 15, 2002. 145 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. Dollars are presented in thousands except per share amounts.
Quarter Ended March 31, 2001 June 30, 2001 September 30, 2001 December 31, 2001 Operating Revenues $ 737,926 $ 1,155,462 $ 1,971,900 $ 723,442 ============== ============= ================== ================= Operating Income $ (30,487) $ 78,294 $ 122,190 $ 52,872 ============== ============= ================== ================= Income (loss) from continuing operations $ (83,860) $ 27,549 $ 80,409 $ 5,768 Income from discontinued operations 381 641 - - Gain on disposal of water business - 25,845 - - -------------- ------------- ------------------ ----------------- Net income (loss) $ (83,479) $ 54,035 $ 80,409 $ 5,768 ============== ============= ================== ================= Income (loss) per share-Basic: Income (loss) from continuing perations $ (1.07) $ 0.35 $ 0.89 $ 0.06 Income from discontinued operations 0.01 0.01 - - Gain on disposal of water business - 0.33 - - -------------- ------------- ------------------ ----------------- Net income (loss) $ (1.06) $ 0.69 $ 0.89 $ 0.06 ============== ============= ================== ================= Income (loss) per share-Diluted: Income (loss) from continuing operations $ (1.07) $ 0.35 $ 0.89 $ 0.06 Income from discontinued operations 0.01 0.01 - - Gain on disposal of water business - 0.33 - - -------------- ------------- ------------------ ----------------- Net income (loss) $ (1.06) $ 0.69 $ 0.89 $ 0.06 ============== ============= ================== ================= Quarter Ended March 31, 2000 June 30, 2000 September 30, 2000 December 31, 2000 Operating Revenues $ 392,649 $ 474,312 $ 868,174 $ 599,119 ============== ============= ================== ================= Operating Income $ 57,193 $ 15,144 $ 19,074 $ 35,978 ============== ============= ================== ================= Income (loss) from continuing operations $ 17,251 $ (24,021) $ (23,742) $ (18,902) Income from discontinued operations 927 3,830 4,194 683 -------------- ------------- ------------------ ----------------- 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) ============== ============= ================== =================
146 NOTE 22. DERIVATIVES AND HEDGING ACTIVITIES (SPR, NPC, SPPC) Effective January 1, 2001, SPR, SPPC, and NPC adopted Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS No. 138, both issued by the Financial Accounting Standards Board. As amended, SFAS No. 133 requires that an entity recognize all derivatives as either assets or liabilities in the statement of financial position, measure those instruments at fair value, and recognize changes in the fair value of the derivative instruments in earnings in the period of change unless the derivative qualifies as an effective hedge. The adoption of this standard did not have a material impact on the earnings of SPR or the Utilities. SPR and the Utilities did, however, recognize all derivatives as assets or liabilities in the condensed consolidated balance sheets upon adoption and measured those instruments at fair value. This resulted in SPR, NPC, and SPPC recording $981 million, $678 million, and $303 million of risk management assets, respectively, and $822 million, $722 million, and $97 million of risk management liabilities, respectively, at January 1, 2001. On April 18, 2001, AB 369 was signed into law in Nevada. AB 369 reinstated deferred energy accounting by the Utilities effective March 1, 2001. (See Note 3 - Regulatory Actions, above.) As a result, fuel and purchased power expenses, including gains and losses on derivative instruments, are recoverable or payable through future rates. In accordance with SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation," regulatory assets and liabilities are established to the extent that such derivative gains and losses are recoverable or payable through future rates. Because of this accounting treatment, the Utilities will not apply hedge accounting to their electricity and natural gas derivatives. However, SPR and the Utilities have adopted cash flow hedge accounting for other derivative instruments not subject to regulatory treatment. The transition adjustments resulting from adoption of SFAS No. 133 related to the other derivative instruments not subject to regulatory treatment was reported as the cumulative effect of a change in accounting principle in Other Comprehensive Income of SPR and the Utilities. SPR's and the Utilities' objective in using derivatives is to reduce exposure to energy price risk and interest rate risk. Energy price risks result from activities that include the generation, procurement and marketing of power and the procurement and marketing of natural gas. Derivative instruments used to manage energy price risk include forwards, options, and swaps. These contracts allow the Utilities to reduce the risks associated with volatile electricity and natural gas markets. Derivatives used to manage interest rate risk include interest rate swaps designed to moderate exposure to interest-rate changes and lower the overall cost of borrowing. At December 31, 2001, SPR had one interest rate swap related to $200 million of SPR floating rate notes maturing April 20, 2003. This interest rate swap is considered a completely effective cash flow hedge. At December 31, 2001, the fair value of the derivatives resulted in the recording of $347 million, $250 million and $97 million in risk management assets and $1.019 billion, $601 million and $410 million in risk management liabilities in the Consolidated Balance Sheets of SPR, NPC and SPPC, respectively. The fair values of the forward contracts and swaps are determined based on quotes obtained from independent brokers and exchanges. The fair values of options are determined using a pricing model which incorporates assumptions such as the underlying commodity's forward price curve, time to expiration, strike price, interest rates, and volatility. The use of different assumptions and variables in the model could have a significant impact on the valuation of the instruments. Due to the regulatory environment in which the Utilities operate, regulatory assets and liabilities are established to the extent that electricity and natural gas derivative gains and losses are recoverable or payable through future rates. Accordingly, at December 31, 2001, $664 million, $351 million and $313 million in net 147 risk management regulatory assets were recorded in the Consolidated Balance Sheets of SPR, NPC, and SPPC, respectively. In addition, for the twelve months ended December 31, 2001, the unrealized gains and losses resulting from the change in the fair value of derivatives designated and qualifying as cash flow hedges for SPR, NPC, and SPPC were recorded in Other Comprehensive Income. Such amounts will be reclassified into earnings when the related transactions are settled or terminate. No amounts were reclassified into earnings during the twelve months ended December 31, 2001. Management has evaluated the impact of Derivatives Implementation Group Issues C10 and C15 with respect to option contracts and optionality features. In Management's opinion, the implementation of these interpretations will not result in any changes to the initial application of SFAS No. 133 nor have a significant impact on the financial position or results of operations of SPR or the Utilities. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. 148 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, NPC and SPPC, and their ages as of December 31, 2001. 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 2002: Krestine M. Corbin, 64 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 1989, of SPPC since 1992, and was elected a Director of NPC 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 NPC 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 NPC in July 1999. Clyde T. Turner, 64 Chairman and CEO of Turner Investments, Ltd., a general-purpose investment company, and several special-purpose real estate development companies known as Spectrum Companies in Las Vegas, Nevada. He is also a director of St. Rose Dominican Hospital and CapCure, and a member of the Environmental Advisory Committee to the Board of County Commissions, Clark County, Nevada. Mr. Turner is the retired Chairman and Chief Executive Officer of Mandalay Bay. He was elected a Director of SPR in November 2001. 149 Dennis E. Wheeler, 59 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 NPC in July 1999. Directors whose terms expire in 2003: Edward P. Bliss, 69 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 1992, and was elected a Director of NPC in July 1999. Mary Lee Coleman, 64 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 NPC since 1980, and was elected a Director of SPR and SPPC in July 1999. Theodore J. Day, 52 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 NPC in July 1999. He is also a Director of the W.M. Keck Foundation. Jerry E. Herbst, 63 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 NPC since 1990, and was elected a Director of SPR and SPPC in July 1999. Directors whose terms expire in 2004: James R. Donnelley, 66 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 NPC in July 1999. Walter M. Higgins, 57 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 2000. Chairman, President and Chief Executive Officer of SPR from January 4, 1994 to January 14, 1998. President and 150 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, 56 Chairman and Chief Executive Officer of the law firm of Mangels, Butler, Marmaro & O'Reilly. He was formerly with 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 on the Board of Trustees of Loyola Marymount University. Mr. O'Reilly has served as a Director of NPC 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 e.three are Walter M. Higgins 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, 2001. 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, 57, Chairman, President and Chief Executive Officer, Sierra Pacific Resources See above description under Item 10(a), "Directors." William E. Peterson, 54, 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 NPC. 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. Mark A. Ruelle, 40, President, Nevada Power Company Mr. Ruelle was elected to his present position in May 2001. He was formerly Senior Vice President and Chief Financial Officer for SPR since December 2000, and held the same positions with SPPC and NPC. 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. 151 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 NPC. 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. Dennis D. Schiffel, 58, Senior Vice President and Chief Financial Officer, Sierra Pacific Resources Mr. Schiffel was elected to his current position in July 2001. Previously, he was vice President, Corporate Planning, for ARCO. He held various positions there, including investor relations, finance, planning and treasury at ARCO's parent company or operating units overseas. Matt H. Davis, 45, Vice President, Transmission Services, Nevada Power Company Mr. Davis was elected to his present position in November 2001. He was formerly Vice President, Distribution Services for NPC. In the spring of 2000, he held a similar position forth both NPC and SPPC since July 1999. Previously he was Director, System Planning, and Division Director, System Planning and Operations for NPC. Mr. Davis has been with NPC since 1978. Steven C. Oldham, 51, Senior Vice President, Energy Supply, Sierra Pacific Power Company and Nevada Power Company Mr. Oldham was elected to his current position in August 2001. Previously, he was Senior Vice President, Corporate Development and Strategic Planning. Previous to that, he was Vice President, Transmission Business Group and Strategic Development; Vice President, Information 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. Victor H. Pena, 53, Senior Vice President and Chief Administrative Officer, Sierra Pacific Power Company and Nevada Power Company Mr. Pena was elected to his current position in May 2001. From 1998 to his appointment at SPPC and NPC, he held various executive positions at AGL Resources, Inc., in Atlanta, Georgia, including Vice President, Business Development, and Vice President, Financial Systems and Controller. Mary O. Simmons, 46, Vice President, Rates and Regulatory Affairs, Sierra Pacific Power Company and Nevada Power Company Ms. Simmons was elected to her current position in May 2001. Previously she held the position of Controller for SPR since July 1999, and held the same position with SPPC and NPC. 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, 54, Vice President, Public Policy, Sierra Pacific Power Company and Nevada Power Company Mr. Ponn was elected to his present position in May 2001. Formerly he held the position of Vice President, Governmental and Regulatory Affairs, since July 1999 for both SPPC and NPC. Previously 152 he was Executive Director, Governmental and Regulatory Affairs. Mr. Ponn has been with SPR since 1986. Mary Jane Reed, 55, 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 NPC 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, 50, Treasurer and Investor Relations Officer, Sierra Pacific Resources Mr. Atkinson was elected to his current position in May 2001 and holds the same position with SPPC and NPC. He was formerly Treasurer of SPR, SPPC, and NPC 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, 45, Vice President, Resource Management, Sierra Pacific Power Company and Nevada Power Company Mr. Smart was appointed to his present position in May 2001. He was formerly Acting Vice President, Resource Management, since October 2000. Previously he was Executive Director, Resource Management for SPPC and NPC 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. Paul Heagen, 49, Vice President, Marketing and Corporate Communications, Sierra Pacific Power Company and Nevada Power Company Mr. Heagen was appointed to his present position in 2001. He has held various positions at GTE Corporation in all areas of utility communications, marketing, public policy, crisis management, corporate branding, and communications strategy. Carol Marin, 50, Vice President, Customer Service, Sierra Pacific Power Company and Nevada Power Company Ms. Marin was elected to her present position in May 2001. Previously she held the position of Director, Customer Information Systems Project for both companies from August 1999-May 2001. From 1977 until 1999, Ms. Marin served in a variety of management positions for SPPC in customer service, major accounts, and operations analysis. Ms. Marin has been with SPPC for 25 years. Susan Brennan, 42, Vice President, Information Services, Sierra Pacific Power Company and Nevada Power Company. Ms. Brennan was elected to her present position in May 2001. Previously she held the position of Executive Director, Customer Service, from august 1999 to May 2001. From 1992 to 1999, Ms. Brennan served in various financial and industry restructuring positions. Ms. Brennan has been with NPC 10 years. 153 John Brown, 51, Controller, Sierra Pacific Resources Mr. Brown was elected to his present position in May 2001 and holds the same position at SPPC and NPC. Previously he held the position of Director, Corporate and Tax Accounting. Mr. Brown has held a variety of positions in SPR, including Compliance Officer, Director, Shareholder Relations, and Director, Internal Audit. Mr. Brown has been with SPR 21 years. 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 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 with respect to SPR's common stock, have filed reports with respect to SPPC's preferred stock, which reports show no past or current beneficial ownership of such preferred stock. 154 ITEM 11. EXECUTIVE COMPENSATION SUMMARY COMPENSATION TABLE The following table sets forth information about the compensation of the Chief Executive Officer that served in that position during 2001, 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 2001, warranted inclusion due to compensation levels.
------------------------------------------------------------------------------------------------------------------------------------ Annual Compensation Long-Term Compensations --------------------------------------------------------------------------------------------------- Awards Payout ---------------------------------------------------------- Securities Underlying All Other Name and Principal Other Annual Restricted Stock Options/SARs LTIP Payouts Compensations Position Year Salary ($) Bonus ($) Compensation ($) Awards ($) (#) ($) ($) (a) (b) (c) (d)(2) (e)(3) (f)(4) (g)(5) (h)(6) (i)(7) ------------------------------------------------------------------------------------------------------- ---------------------------- Walter M Higgings 2001 $ 590,000 $ - $ 70,970 $ - 110,130 $ - $ 614,129 Chairman of the Board, 2000 $ 215,151 $ - $ 33,690 $ 256,000 400,000 $ - $ 411,758 President, and Chief Executive Officer Mark A. Ruelle 2001 $ 280,962 $ - $ 28,108 $ 62,080 66,520 $ - $ 109,437 President Nevada Power 2000 $ 250,255 $ - $ 15,967 $ - - $ 59,357 $ 19,160 Company 1999 $ 196,654 $ 86,658 $ 7,389 $ - 61,292 $ - $ 8,565 Steven W. Rigazio/1/ 2001 $ 255,000 $ - $ 843 $ - 26,520 $ - $ 573,177 President, Nevada Power 2000 $ 255,003 $ - $ 15,477 $ - - $ 26,713 $ 201,227 Company 1999 $ 262,075 $ 81,700 $ 60,654 $ - 36,260 $ 27,712 $ 6,811 William E. Peterson 2001 $ 231,538 $ - $ 31,606 $ - 22,880 $ - $ 20,456 Senior Vice President 2000 $ 216,203 $ - $ 25,943 $ - - $ 59,357 $ 20,926 General Counsel and 1999 $ 200,000 $ 83,053 $ 20,727 $ - 80,168 $ - $ 11,974 Corporate Secretary Jeffrey L. Cecarelli 2001 $ 221,539 $ - $ 13,712 $ - 22,510 $ - $ 19,429 President, Sierra Pacific 2000 $ 191,539 $ - $ 19,320 $ - - $ 36,527 $ 16,781 Power Company 1999 $ 148,077 $ 26,840 $ 8,321 $ - 26,140 $ - $ 1,484 Steven C. Oldham 2001 $ 219,039 $ - $ - $ - 20,800 $ - $ 19,775 Senior Vice President, 2000 $ 186,584 $ - $ 13,750 $ - - $ 36,527 $ 19,678 Energy Supply 1999 $ 151,058 $ 26,840 $ 8,859 $ - 41,286 $ - $ 7,970 ------------------------------------------------------------------------------------------------------------------------------------
1. Mr. Rigazio was President of Nevada Power Company until the appointment of Mr. Ruelle to that position in May 2001. 2. The amounts presented for 1999 represent incentive pay received pursuant to SPR's "pay for performance" team incentive plan approved by stockholders in May, 1994. 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 elected not to grant payment of the 2000 and 2001 incentive pay to the executives. 3. For all of the executives listed these amounts represent Personal Time Off payouts. 4. As the result of a promotion, Mr. Ruelle was awarded a restricted stock grant of 4,000 shares with dividend equivalents. At December 31, 2001, the value of the grant was $60,200 at $15.05 per share. The grant will vest over a four year period at 25% per year. In 2000, Mr. Higgins was awarded a restricted stock grant of 16,000 shares with dividend equivalents. At December 31, 2001, the value of the grant was $240,800 at $15.05 per share. The grant will vest over a four year period in the following manner: 155 September 2002 4,000 shares September 2003 4,000 shares 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. The 2000 Non-Qualified Stock Options were granted in August of 1999 and are therefore included in the 1999 amounts. 6. The Long-term incentive payouts for the SPR executives, for the three-year periods ended December 31, 1999 and December 31, 2001, were not approved for payment by the SPR Board of Directors; therefore, for these payouts, zero amounts are shown in 1999 for the pre-merger SPR executives, and in 2001 for all 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 2001:
------------------------------------------------------------------------------------------------------------------- Walter M. Mark A. Steven W. William E. Jeffrey L. Steven C. Description Higgins Ruelle Rigazio Peterson Ceccarelli Oldham ------------------------------------------------------------------------------------------------------------------- Company contributions to the 401k $ 10,200 $ 9,600 $ 10,200 $ 8,400 $ 10,200 $ 10,200 deferred compensation plan Company paid portion of $ 7,752 $ 7,180 $ 7,752 $ 7,752 $ 7,752 $ 7,752 Medical/Dental/Vision Benefits Company contributions to the $ 646 $ 1,935 nonqualified deferred compensation plan Imputed income on group term life $ 3,612 $ 400 $ 600 $ 773 $ 477 $ 690 insurance premiums paid by SPR Insurance premiums paid for executive $ 7,746 $ 563 $ 1,596 $ 1,000 $ 1,133 term life policies Moving Expense Reimbursement (includes $ 418,211 $ 91,048 closing costs on sale of home) Additional Compensation upon Rehire $ 72,865 Taxable Interest on Refund of $ 24,935 Non-Qualified Pension Contribution Housing Allowance $ 64,122 Spouse Travel Expense Reimbursement $ 4,686 Severance/Stay Agreement payments $ 554,625 Total $ 614,129 $ 109,437 $ 573,177 $ 20,456 $ 19,429 $ 19,775 -------------------------------------------------------------------------------------------------------------------
Options/SAR Grants in Last Fiscal Year The following table shows all grants of options to the named executive officers of SPR in 2001. Pursuant to Securities and Exchange Commission (SEC) rules, the table also shows the present value of the grant at the date of grant. 156
-------------------------------------------------------------------------------------------------------------- Number of Percent of Total Securities Options/SAR's Underlying Granted to Exercise of Options/SAR's Employees in Base Price Grant Date Name Granted Fiscal Year ($/share) Expiration Date Present Value (a) (b) (1) (c) (2) (d) (e) (f)(3) -------------------------------------------------------------------------------------------------------------- Walter M. Higgins 01/01/2001 Grant date 110,130 26.57% $14.80 01/01/2011 $365,632 Mark A. Ruelle 01/01/2001 Grant date 26,520 6.40% $14.80 01/01/2011 $ 88,046 05/22/2001 Grant date 40,000 9.65% $15.52 05/22/2011 $156,000 Steven W. Rigazio 01/01/2001 Grant date 26,520 6.40% $14.80 01/01/2011 $ 88,046 William E. Peterson 01/01/2001 Grant date 22,880 5.52% $14.80 01/01/2011 $ 75,962 Jeffrey L. Ceccarelli 01/01/2001 Grant date 22,510 5.43% $14.80 01/01/2011 $ 74,733 Steven C. Oldham 01/01/2001 Grant date 20,800 5.02% $14.80 01/01/2011 $ 69,056 --------------------------------------------------------------------------------------------------------------
1. Under the SPR executive long-term incentive plan, the 2001 grants of nonqualifying stock options were made on January 1, 2001. One-third of these grants vest annually commencing one year after the date of the grant. An additional grant of 40,000 shares of nonqualifying stock options was made to Mr. Ruelle as the result of a promotion. This grant vests at a rate of one-quarter per year for four years beginning one year after the grant date of May 22, 2001. 2. The total number of nonqualifying stock options granted to all employees in 2001 was 414,530. 3. 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 values listed above include the stock's average expected volatility (32.31%), average risk free rate of return (5.32%), average projected dividend yield (4.99%), the stock option term (10 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 Fiscal Year-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, 2001.
------------------------------------------------------------------------------------------------------------------- Shares Number of Securities Underlying Value of Unexercised in-the- Acquired on Value Unexercised Options/SARs at money Options/SARs at Name Exercise Realized Fiscal Year-End Fiscal Year-End (a) (b) (c) (d) (e) --------------------------------------------------------------- Exercisable Unexercisable Exercisable Unexercisable ------------------------------------------------------------------------------------------------------------------- Walter M. Higgins - - - 510,130 $ - $ 27,533 Mark A. Ruelle - - 41,439 86,374 $ - $ 6,630 Steven W. Rigazio - - 16,406 46,374 $ - $ 6,630 William E. Peterson - - 60,317 42,734 $ 16,768 $ 5,720 Jeffrey L. Ceccarelli - - 16,633 32,017 $ - $ 5,628 Steven C. Oldham - - 31,780 30,307 $ 8,028 $ 5,200 -------------------------------------------------------------------------------------------------------------------
(e) Pre-tax gain. Value of in-the-money options based on December 31, 2001 closing trading price of $15.05 less the option exercise price. 157 Long-Term Incentive Plans-Awards in Last Five Years The executive long-term incentive plan (LTIP) provides for the granting of stock options (both nonqualified and qualified), stock appreciation rights (SARs), restricted stock performance units, performance shares and bonus stock to participating employees as an incentive for outstanding performance. Incentive compensation is based on the achievement of pre-established financial goals for SPR. Goals are established for total shareholder return (TSR) compared against the Dow Jones Utility Index and annual growth in earnings per share (EPS). The following table provides information as to the performance shares granted to the named executive officers of Sierra Pacific Resources in 2001. Nonqualifying stock options granted to the named executives as part of the LTIP are shown in the table "Option/SAR Grants in Last Fiscal Year."
--------------------------------------------------------------------------------------------------------- Performance or Estimated Future Payouts Under Non-Stock Number of Other Period Price-Based Plans ------------------------------------------------ Shares, Units Until or Other Maturation or Name Rights Payout Threshold ($) Target ($) Maximum ($) (a) (b) (c) (d)(1) (e)(2) (f)(3) --------------------------------------------------------------------------------------------------------- Walter M. Higgins 20,650 3 years $ 152,810 $ 305,620 $ 534,835 Mark A. Ruelle 4,970 3 years $ 36,778 $ 73,556 $ 128,723 Steven W. Rigazio 4,970 3 years $ 36,778 $ 73,556 $ 128,723 William E. Peterson 4,290 3 years $ 31,746 $ 63,492 $ 111,111 Jeffrey L. Ceccarelli 4,220 3 years $ 31,228 $ 62,456 $ 109,298 Steven C. Oldham 3,900 3 years $ 28,860 $ 57,720 $ 101,010 ---------------------------------------------------------------------------------------------------------
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 qualified and non-qualified defined benefit plans based on various levels of remuneration and years of service which may exist at the time of retirement. The amounts below are based upon a maximum benefit of 60% of final average earnings used under the Supplemental Executive Retirement Plan. This maximum is reduced to 50% for any Officer who became a participant after November 1, 1999. 158
--------------------------------------------------------------------------------------- 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 ---------------------------------------------------------------------------------------
SPR's noncontributory qualified 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 in columns (c) and (d) of 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. The years of credited service under the qualified retirement plan for the named executives are as follows: Mr. Higgins 5.5, Mr. Ruelle 4.7, Mr. Rigazio 17.4, Mr. Peterson 8.4, Mr. Ceccarelli 27.3, and Mr. Oldham 25.2. A supplemental executive retirement plan (SERP) and a restoration 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 Restoration Plan is intended to provide benefits to executive officers whose benefits cannot be paid under the qualified plan because of salary deferrals to the Non-Qualified Deferred Compensation Plan, IRS limitations on compensation that can be recognized by a qualified plan, and IRS limitations on benefits payable from a qualified plan. The years of credited service under the non-qualified SERP are as follows: Mr. Higgins 8.1, Mr. Ruelle 4.7, Mr. Rigazio 17.4, Mr. Peterson 16.4, Mr. Ceccarelli 27.3, and Mr. Oldham 25.2. 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. 159 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. 160 ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT Voting Stock of SPR The following table indicates the shares owned by Franklin Advisors, and Putnam Investments, the only investors known to Sierra Pacific Resources to be owners of more than 5 percent of any class of its voting stock as of March 11, 2002.
Name and Address of Shares Beneficially Title of Class Beneficial Owner Owned Percent of Class -------------- ---------------- ----- ---------------- Common Stock Franklin Advisors 9,978,000 10.8% 777 Mariners Island Blvd. San Mateo, Ca. 94404 Common Stock Putnam Investors 5,400,000 5.3% One Post Office Square Boston, Ma. 02109
The table below sets forth the shares of SPR 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 Name of Director Owned as of Shares Outstanding as of or Nominee March 11, 2002 March 11, 2002 ------------------------ ---------------- ------------------------------ Edward P. Bliss 29,450 Mary L. Coleman 150,634 Krestine M. Corbin 22,271 Theodore J. Day 36,130 No director or nominee James R. Donnelley 37,429 for director owns in excess Fred D. Gibson Jr. 24,095 of one percent. Jerry E. Herbst 15,479 Walter M. Higgins 49,868 James L. Murphy 34,268 John F. O'Reilly 14,985 Clyde T. Turner 0 Dennis E. Wheeler 19,994 -------------- 434,603 ==============
161
Common Shares Beneficially Percent of Total Common Owned as of Shares Outstanding as of Executive Officers March 11, 2002 March 11, 2002 -------------------------------- ------------------ ---------------------------- Walter M. Higgins 49,868 Steven W. Rigazio (1) 16,406 No executive officer owns Mark A. Ruelle 47,244 In excess of one percent William E. Peterson 88,294 Jeffrey L. Ceccarelli 44,422 Steven C. Oldham 55,891 ------ 302,125 ======= All directors and executive officers as a group (a)(b)(c) 862,753 =======
(1) Mr. Rigazio was President of Nevada Power Company until the appointment of Mr. Ruelle to that position in May 2001. (a) Includes shares/units acquired through participation in the Employee Stock Purchase Plan and/or the 401(k) plan. (b) The number of shares beneficially owned includes: shares 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. Shares beneficially owned pursuant to stock options granted to Messrs. Higgins, Rigazio, Peterson, Ruelle, Ceccarelli, Oldham, and directors and executive officers as a group are 0, 16,406, 80,029, 62,366, 30,210, 44,787, and 338,409 shares, respectively. (c) Included in the shares beneficially owned by the Directors are 100,172 shares of "phantom stock" representing 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 SPPC since 1920 and for Sierra Pacific Resources and all of its subsidiaries from their inception, continues to perform legal work for SPR. Mr. Peterson's spouse, an equity partner in the firm since 1982, has performed work for SPR since 1976 and continues to do so from time to time. Susan Oldham, a former employee of SPPC specializing in water resources law, planning and policy, accepted SPPC's voluntary severance offering in December 1995. Ms. Oldham is the spouse of Steven C. Oldham, Senior Vice President, Energy Supply, for NPC and SPPC. Ms. Oldham, a licensed attorney in Nevada and California, performed specialized legal services in the water resources area for SPR on a contract basis through June 2001. Change in Control Agreements ---------------------------- SPR has entered into change in control severance agreements with Walter M. Higgins, Jeffrey L. Ceccarelli, Steven C. Oldham, William E. Peterson, Mark A. Ruelle, Victor H. Pena, Dennis D. Schiffel, Mary 162 O. Simmons, Susan Brennan, Carol Marin, Paul Heagen, Richard K. Atkinson, John Brown, Douglas R. Ponn, Michael R. Smart, Matt H. Davis, and Mary Jane Reed. These agreements provide that, upon termination of the executive's employment within 24 or 36 months following a change in control of SPR (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 SPR and the acquirer)), the executive will receive certain payments and benefits. These severance payments and benefits include (i) a lump sum payment equal to two or 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 SPR's retirement plans for an additional two or three years (or, in the case of SPR'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 24 or 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 SPR. 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 new contracts expire on December 31, 2003, unless renewed or replaced before that time. Employment Agreements --------------------- Walter M. Higgins On August 4, 2000, SPR 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 SPR. SPR engaged Towers Perrin to evaluate Mr. Higgins' offer prior to consummating it in order to assure that it was consistent with SPR 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 SPR's short-term incentive program, at 65% of base pay, and participation in SPR's long-term incentive program approved by shareholders at 140% of base salary. Payments are 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 163 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 SPR, which will vest 25% per year or sooner if certain price threshold levels are met. Mr. Higgins is also eligible to participate in SPR's Supplemental Executive Retirement Plan and was provided credit for all previous years of service with SPR, 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 SPR 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 SPR 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 SPR (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 SPR 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 SPR's retirement plans for an additional three years (or, in the case of SPR'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, SPR 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 SPR 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 SPR immediately prior to such merger or sale; (ii) any person acquires 20% or more of SPR's voting stock; (iii) SPR enters into an agreement or SPR 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 SPR 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 SPR at the beginning of such period cease to be directors; or (v) the stockholders of SPR approve a complete liquidation or dissolution of SPR. Steven W. Rigazio On August 31, 2000, SPR 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 SPR's long-term disability 164 plan and will continue to be covered by SPR'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, SPR will continue to provide the Employee's spouse and eligible dependents all medical coverage so long as they are not covered by other plans. Mr. Rigazio died on December 27, 2001, and the payments described above were made. David G. Barneby On June 19, 1999, Nevada Power, a wholly owned subsidiary of SPR, 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 SPR. 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. Mr. Barneby retired on January 1, 2002. In the event any payments or benefits or distributions thereof under the contract or any other agreements, policies, or plans of SPR 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. 165 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' Reports.............................................. 83-84 Consolidated Balance Sheets as of December 31, 2001 and 2000 .............. 85 Consolidated Statements of Income for the Years Ended December 31, 2001, 2000 and 1999 ..................................................... 86 Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2001, 2000 and 1999 ........................................ 87 Consolidated Statements of Common Shareholders' Equity for the Years Ended December 31, 2001, 2000 and 1999 .................................. 87 Consolidated Statements of Cash Flows for the Years Ended December 31, 2001, 2000 and 1999 ................................................. 88 Consolidated Statements of Capitalization as of December 31, 2001 and 2000 ................................................................ 89-90 Balance Sheets for Nevada Power Company as of December 31, 2001 and 2000 .................................................................... 91 Statements of Income for Nevada Power Company for the Years Ended December 31, 2001, 2000 and 1999 ........................................ 92 Statements of Cash Flows for Nevada Power Company for the Years Ended December 31, 2001, 2000 and 1999 ........................................ 93 Statements of Capitalization for Nevada Power Company as of December 31, 2001 and 2000 ....................................................... 94 Consolidated Balance Sheets for Sierra Pacific Power Company as of December 31, 2001 and 2000 .............................................. 95 Consolidated Statements of Income for Sierra Pacific Power Company for the Years Ended December 31, 2001, 2000 and 1999 .................... 96 Consolidated Statements of Comprehensive Income for Sierra Pacific Power Company for the Years Ended December 31, 2001, 2000 and 1999 ............ 97 Consolidated Statements of Common Shareholders' Equity for Sierra Pacific Power Company for the Years Ended December 31, 2001, 2000 and 1999 ........................................................... 97 Consolidated Statements of Cash Flows for Sierra Pacific Power Company for the Years Ended December 31, 2001, 2000 and 1999 ............ 98 Consolidated Statements of Capitalization for Sierra Pacific Power Company as of December 31, 2001 and 2000 .......................... 99 Notes to Financial Statements ............................................. 100 2. Financial Statement Schedules: Schedule II - Consolidated Valuation and Qualifying Accounts ....... 169-170
166 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. 3. Exhibits: Exhibits are listed in the Exhibit Index on pages 171-189. (b) Reports on Form 8-K Form 8-K dated November 16, 2001, filed by SPR - Item 5, Other Events Disclosed that on November 16, 2001, SPR completed a public offering of $300,000,000 principal amount of its Premium Income Equity Securities at a price of $50 per unit with quarterly payments of an initial annual combined rate of 9%. 167 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, 2002 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, 2002. /S/ Dennis Schiffel /S/ John Brown ------------------------------------------ ------------------------------------------ Dennis Schiffel John Brown Senior Vice President, Controller Chief Financial Officer (Principal Accounting Officer) (Principal Financial Officer) /S/ Edward P. Bliss /S/ Jerry E. Herbst ------------------------------------------ ------------------------------------------ Edward P. Bliss Jerry E. Herbst Director Director /S/ Mary Lee Coleman /S/ James L. Murphy ------------------------------------------ ------------------------------------------ Mary Lee Coleman James L. Murphy Director Director /S/ Krestine M. Corbin /S/ John F. O'Reilly ------------------------------------------ ------------------------------------------ Krestine M. Corbin John F. O'Reilly Director Director /S/ Theodore J. Day /S/ Clyde T. Turner ------------------------------------------ ------------------------------------------ Theodore J. Day Clyde T. Turner Director Director /S/ James R. Donnelley /S/ Dennis E. Wheeler ------------------------------------------ ------------------------------------------ James R. Donnelley Dennis E. Wheeler Director Director /S/ Fred D. Gibson, Jr. ------------------------------------------ Fred D. Gibson, Jr. Director
168 Sierra Pacific Resources Schedule II - Consolidated Valuation and Qualifying Accounts For The Years Ended December 31, 2001, 2000 and 1999 (Dollars in Thousands)
Provision for Uncollectible Accounts --------------- 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 (1) 14,879 Amounts written off, less recoveries (8,160) -------------- Balance at December 31, 2000 13,194 ============== Balance at January 1, 2001 13,194 Provision charged to income (2) 42,767 Amounts written off, less recoveries (16,626) -------------- Balance at December 31, 2001 $ 39,335 ==============
Nevada Power Company Schedule II - Consolidated Valuation and Qualifying Accounts For The Years Ended December 31, 2001, 2000 and 1999 (Dollars in Thousands)
Provision for Uncollectible Accounts --------------- 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 (1) 13,090 Amounts written off, less recoveries (4,311) -------------- Balance at December 31, 2000 11,605 Balance at January 1, 2001 11,605 Provision charged to income (2) 32,137 Amounts written off, less recoveries (12,881) -------------- Balance at December 31, 2001 $ 30,861 ==============
169 Sierra Pacific Power Company Schedule II - Consolidated Valuation and Qualifying Accounts For The Years Ended December 31, 2001, 2000 and 1999 (Dollars in Thousands) Provision for Uncollectible Accounts ----------------- 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) 1,789 Amounts written off, less recoveries (3,849) ---------- Balance at December 31, 2000 1,589 Balance at January 1, 2001 1,589 Provision charged to income (2) 10,630 Amounts written off, less recoveries (3,745) ---------- Balance at December 31, 2001 $ 8,474 ========== (1) Included in the provision charged to income in 2000 was $7.3 million and $0.3 million, respectively, for NPC and SPPC as reserves against receivables from California's Power Exchange and Independent System Operator. (2) In 2001, the provision charge to income included $12.6 million and $1.2 million respectively, for NPC and SPPC as reserves against receivables from California's Power Exchange and Independent System Operator. The provision charge also included $.1 million and $.4 million respectively, for NPC and SPPC as reserves against receivables from Enron. 170 2001 FORM 10-K EXHIBIT INDEX (a) 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. (* filed herewith) (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). . By-laws of Sierra Pacific Resources as amended through February 25, 2000 (filed as Exhibit 3(A) to Form 10-K for year ended December 31, 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). . 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). 171 . 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 . Amended and Restated Rights Agreement dated as of February 28, 2001 between Sierra Pacific Resources and Wells Fargo Bank Minnesota, N.A. as successor Rights Agent (filed as Exhibit 4.1 to Registration Statement on Form S-3 filed July 2, 2001, File No. 333-64438). . Purchase and Contract Agreement dated November 16, 2001, between Sierra Pacific Resources and The Bank of New York, relating to the Company's Premium Income Equity Securities (PIES) (filed as Exhibit 4.3 to Form 8-K dated November 16, 2001). . Corporate PIES Certificate (filed as Exhibit 4.4 to Form 8-K dated November 16, 2001). . Treasury PIES Certificate (filed as Exhibit 4.5 to Form 8-K dated November 16, 2001). . Pledge Agreement dated November 16, 2001, among Sierra Pacific Resources, Wells Fargo Bank Minnesota, N.A. and The Bank of New York (filed as Exhibit 4.6 to Form 8-K dated November 16, 2001). . Remarketing Agreement dated November 16, 2001, between Sierra Pacific Resources and Lehman Brothers, Inc. (filed as Exhibit 4.7 to Form 8-K dated November 16, 2001). . 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). . 7.93% Senior Note due 2007 issued in connection with Sierra Pacific Resources PIES (filed as Exhibit 4.2 to Form 8-K dated November 16, 2001). . Officers' Certificate establishing the terms of the 7.93% Senior Notes due 2007 (filed as Exhibit 4.3 to Form 8-K dated November 16, 2001). . 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 (filed as Exhibit 4(A) to Form 10-K for the year ended December 31, 2000). . Form of Global Floating Rate Note due April 20, 2002 in connection with the Company's money market note program (filed as Exhibit 4(B) to Form 10-K for year ended December 31, 2000). 172 . Form of Global Floating Rate Note due April 20, 2003 in connection with the Company's money market note program (filed as Exhibit 4(C) to Form 10-K for year ended December 31, 2000). Nevada Power Company . General and Refunding Mortgage Indenture, dated as of May 1, 2001, between Nevada Power Company and The Bank of New York, as Trustee (filed as Exhibit 4.1(a) to Form 10-Q for the quarter ended June 30, 2001). . First Supplemental Indenture, dated as of May 1, 2001, establishing Nevada Power Company's 8.25% General and Refunding Mortgage Bonds, Series A, due June 1, 2011 (filed as Exhibit 4.1(b) to Form 10-Q for the quarter ended June 30, 2001). . Officer's Certificate establishing the terms of Nevada Power Company's 8.25% General and Refunding Mortgage Bonds, Series A, due June 1, 2011 (filed as Exhibit 4.1(c) to Form 10-Q for the quarter ended June 30, 2001). . Form of Nevada Power Company's 8.25% General and Refunding Mortgage Bonds, Series A, due June 1, 2011 (filed as Exhibit 4.1(d) to Form 10-Q for the quarter ended June 30, 2001). . *(A) Second Supplemental Indenture, dated as of October 1, 2001, establishing Nevada Power Company's General and Refunding Mortgage Notes, Floating Rate, Series B, due October 15, 2003. . *(B) Officer's Certificate establishing the terms of Nevada Power Company's General and Refunding Mortgage Notes, Floating Rate, Series B, due October 15, 2003. . *(C) Form of Nevada Power Company's General and Refunding Mortgage Notes, Floating Rate, Series B, due October 15, 2003. . Fiscal and Paying Agency Agreement, dated as of September 19, 2001, between Nevada Power Company and Bankers Trust Company, relating to the issuance and sale of Nevada Power Company's 6% Notes due 2003 (filed as Exhibit 4.1 to Form 10-Q for the quarter ended September 30, 2001). . Form of Global Note due September 15, 2003, in connection with the issuance and sale of Nevada Power Company's 6% Notes due 2003 (filed as Exhibit 4.2 to Form 10-Q for the quarter ended September 30, 2001). . 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). 173 . 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, FileNo. 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). . 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). . Form of Senior Unsecured Note Indenture between Nevada Power Company and IBJ Whitehall Bank & Trust Company dated as of March 1, 1999 (filed as Exhibit 4.1 to Form S-4, File No. 333-77325). 174 . Supplemental Indenture No. 1 between Nevada Power Company and IBJ Whitehall Bank & Trust Company dated as of March 1, 1999 (including form of 6.20% Senior Unsecured Note, Series A due April 15, 2004) (filed as Exhibit 4.2 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). . 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). . Indenture of Mortgage and Deed of Trust providing for Nevada Power Company's First Mortgage Bonds, dated as of October 1, 1953 and Twenty-Eight Supplemental Indentures as follows: . First Supplemental Indenture, dated as of August 1, 1954 (filed as Exhibit 4.2 to Form S-1, File No. 2-11440). . 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). . Second Supplemental Indenture, dated as of September 1, 1956 (filed as Exhibit 4.9 to Form S-1, File No. 2-12566). . Third Supplemental Indenture, dated as of May 1, 1959 (filed as Exhibit 4.13 to Form S-1, File No. 2-14949). . Fourth Supplemental Indenture, dated as of October 1, 1960 (filed as Exhibit 4.5 to S-1, File No. 2-16968). . Fifth Supplemental Indenture, dated as of December 1, 1961 (filed as Exhibit 4.6 to Form S-16, File No. 2-74929). . Sixth Supplemental Indenture, dated as of October 1, 1963 (filed as Exhibit 4.6A to Form S-1, File No. 2-21689). . Seventh Supplemental Indenture, dated as of August 1, 1964 (filed as Exhibit 4.6B to Form S-1, File No. 2-22560). . Eighth Supplemental Indenture, dated as of April 1, 1968 (filed as Exhibit 4.6C to Form S-9, File No. 2-28348. . Ninth Supplemental Indenture, dated as of October 1, 1969 (filed as Exhibit 4.6D to Form S-1, File No. 2-34588). . Tenth Supplemental Indenture, dated as of October 1, 1970 (filed as Exhibit 4.6E to Form S-7, File No. 2-38314). 175 . Eleventh Supplemental Indenture, dated as of November 1, 1972 (filed as Exhibit 2.12 to Form S-7, File No. 2-45728). . Twelfth Supplemental Indenture, dated as of December 1, 1974 (filed as Exhibit 2.13 to Form S-7, File No. 2-52350). . Thirteenth Supplemental Indenture, dated as of October 1, 1976 (filed as Exhibit 4.14 to Form S-16, File No. 2-74929). . Fourteenth Supplemental Indenture, dated as of May 1, 1977 (filed as Exhibit 4.15 to Form S-16, File No. 2-74929). . Fifteenth Supplemental Indenture, dated as of September 1, 1978 (filed as Exhibit 4.16 to Form S-16, File No. 2-74929). . Sixteenth Supplemental Indenture, dated as of December 1, 1981 (filed as Exhibit 4.17 to Form S-16, File No. 2-74929). . Seventeenth Supplemental Indenture, dated as of August 1, 1982 (filed as Exhibit 4.2 to Form 10-K, File No. 1-4698, Year 1982). . Eighteenth Supplemental Indenture, dated as of November 1, 1986 (filed as Exhibit 4.6 to Form S-3, File No. 33-9537). . Nineteenth Supplemental Indenture, dated as of October 1, 1989 (filed as Exhibit 4.2 to Form 10-K, File No. 1-4698, Year 1989). . Twentieth Supplemental Indenture, dated as of May 1, 1992 (filed as Exhibit 4.21 to Form S-3, File No. 33-53034). . Twenty-First Supplemental Indenture, dated as of June 1, 1992 (filed as Exhibit 4.22 to Form S-3, File No. 33-53034). . Twenty-Second Supplemental Indenture, dated as of June 1, 1992 (filed as Exhibit 4.23 to Form S-3, Filed No. 33-53034). . Twenty-Third Supplemental Indenture, dated as of October 1, 1992 (filed as Exhibit 4.23 to Form S-3, File No. 33-53034). . Twenty-Fourth Supplemental Indenture, dated as of October 1, 1992 (filed as Exhibit 4.23 to Form S-3, File No. 33-53034). . Twenty-Fifth Supplemental Indenture, dated as of January 1, 1993 (filed as Exhibit 4.23 to Form S-3, File No. 33-53034). . Twenty-Sixth Supplemental Indenture, dated as of 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 as of July 1, 1999 (filed as Exhibit 4(C) to Form 10-K for year ended December 31, 1999). 176 . *(D) Twenty-Eighth Supplemental Indenture dated as of July 1, 2001. Sierra Pacific Power Company . Indenture of Mortgage providing for Sierra Pacific Power Company's First Mortgage Bonds, dated as of December 1, 1940 (filed as Exhibit 7-A to Registration No. 2-7475). . Ninth Supplemental Indenture, dated as of June 1, 1964 (filed as Exhibit 2-M to Registration No. 2-59509). . Tenth Supplemental Indenture, dated as of March 31, 1965 (filed as Exhibit 4-K to Registration No. 2-23932). . Eleventh Supplemental Indenture, dated as of October 1, 1965 (filed as Exhibit 4-L to Registration No. 2-26552). . Twelfth Supplemental Indenture, dated as of July 1, 1967 (filed as Exhibit 4-L to Registration No. 2-36982). . Sixteenth Supplemental Indenture, dated as of October 1, 1975 (filed as Exhibit 2-Y to Registration No. 2-53404). . Nineteenth Supplemental Indenture, dated as of April 1, 1978 (filed as Exhibit (4)(A) to the 1991 Form 10-K). . Twentieth Supplemental Indenture, dated as of October 1, 1978 (filed as Exhibit (4)(B) to the 1991 Form 10-K). . Twenty-Seventh Supplemental Indenture, dated as of August 1, 1989 (filed as Exhibit (4)(A) to the 1989 Form 10-K). . Twenty-Eighth Supplemental Indenture, dated as of May 1, 1992 (filed as Exhibit (4)(A) to the 1992 Form 10-K). . Twenty-Ninth Supplemental Indenture, dated as of June 1, 1992 (filed as Exhibit D to Form 8-K dated July 15, 1992). . Thirtieth Supplemental Indenture, dated as of July 1, 1992 (filed as Exhibit (4)(B) to the 1992 Form 10-K). . Thirty-First Supplemental Indenture, dated as of November 1, 1992 (filed as Exhibit (4)(C) to the 1992 Form 10-K). . Thirty-Second Supplemental Indenture, dated as of June 1, 1993 (filed as Exhibit 4.6 to Registration No. 33-69550). . Thirty-Third Supplemental Indenture, dated as of October 1, 1993 (filed as Exhibit C to Form 8-K dated October 20, 1993). . Thirty-Fourth Supplemental Indenture, dated as of February 1, 1996 (filed as Exhibit C to Form 8-K dated March 11, 1996). 177 . Thirty-Fifth Supplemental Indenture, dated as of February 1, 1997 (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). . 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). 178 (10) Sierra Pacific Resources, Nevada Power Company, and Sierra Pacific Power Company Sierra Pacific Resources . *(A) Credit Agreement dated as of November 30, 2001, among Sierra Pacific Resources, Union Bank of California, N.A., as Sole Bookrunner and Administrative Agent, Wells Fargo Bank, N4.A., as Syndication Agent, Bank One, NA, BNP Paribas and Mellon Bank, N.A., as Co-Documentation Agents, the Lenders party hereto from time to time, and Union Bank of California, N.A. and Wells Fargo Bank, N.A., as Co-Lead Arrangers relating to $75,000,000 credit facility. . *(B) Change in Control Agreement dated May 21, 2001, by and between Sierra Pacific Resources and Walter M. Higgins. . Walter M. Higgins Employment Letter dated August 4, 2000 (filed as Exhibit 10(B) to Form 10-K for the year ended December 31, 2000). . *(C) Change in Control Agreement dated May 21, 2001, by and among Sierra Pacific Resources and the following officers (individually): Jeffrey L. Ceccarelli, Steven C. Oldham, Victor H. Pena, William E. Peterson and Mark A. Ruelle in substantially the same form as the Change in Control Agreement dated May 21, 2001 by and between Sierra Pacific Resources and Dennis D. Schiffel. . *(D) Change in Control Agreement dated May 21, 2001, by and among Sierra Pacific Resources and the following officers (individually): Richard K. Atkinson, Susan Brennan, Matt H. Davis, Carol Elmore, Paul Heagen, Douglas R. Ponn, Mary O. Simmons and Mike Smart, in substantially the same form as the Change in Control Agreement dated May 21, 2001 by and between Sierra Pacific Resources and John E. Brown. . 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). Nevada Power Company . Asset Sale Agreement between Nevada Power Company and The AES Corporation dated as of May 10, 2000 for the Mohave Asset Bundle (filed as Exhibit (10)(C) to Form 10-K for the year ended December 31, 2000). . Transitional Power Purchase Agreement by and between Nevada Power Company and AES Mohave, LLC dated as of May 10, 2000 (filed as Exhibit (10)(D) to Form 10-K for the year ended December 31, 2000). . 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 (filed as Exhibit (10)(E) to Form 10-K for the year ended December 31, 2000). 179 . Transitional Power Purchase Agreement by and between Nevada Power Company and Clark Power LLC dated as of November 16, 2000 (filed as Exhibit (10)(F) to Form 10-K for the year ended December 31, 2000). . 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 (filed as Exhibit (10)(G) to Form 10-K for the year ended December 31, 2000). . Transitional Power Purchase Agreement by and between Nevada Power Company and Reid Gardner Power LLC dated as of November 16, 2000 (filed as Exhibit (10)(H) to Form 10-K for the year ended December 31, 2000). . Asset Sale Agreement between Nevada Power Company and Pinnacle West Energy Corporation for the Harry Allen Asset Bundle, dated as of December 1, 2000 (filed as Exhibit (10)(I) to Form 10-K for the year ended December 31, 2000). . Transitional Power Purchase Agreement by and between Nevada Power Company and Pinnacle West Energy Corporation dated as of December 1, 2000 (filed as Exhibit (10)(J) to Form 10-K for the year ended December 31, 2000). . 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 (filed as Exhibit (10)(K) to Form 10-K for the year ended December 31, 2000). . Transitional Power Purchase Agreement by and between Nevada Power Company and Reliant Energy Sunrise, LLC dated as of December 9, 2000 (filed as Exhibit (10)(L) to Form 10-K for the year ended December 31, 2000). . *(E) Credit Agreement, dated as of November 1, 2001, among Nevada Power Company, Union Bank of California, N.A., as Sole Bookrunner and Administrative Agent, Wells Fargo Bank, N.A., as Syndication Agent, Bank One, NA, BNP Paribas and Mellon Bank, N.A., as Co-Documentation Agents, the Lenders party hereto from time to time, and Union Bank of California, N.A. and Wells Fargo Bank, N.A., as Co-Lead Arrangers relating to $200,000,000 credit facility. . Letter of Credit and Reimbursement Agreement dated as of October 1, 1995 among Nevada Power Company, The Banks named therein, and Societe Generale, Los Angeles Branch (relating to the Clark County, Nevada $85,000,000 Industrial Development Refunding Revenue Bonds, Series 1995B; Clark County, Nevada $20,300,000 Pollution Control Refunding Revenue Bonds Series, 1995D; and Coconino County, Arizona Pollution Control Corporation $13,000,000 Pollution Control Refunding Revenue Bonds, Series 1995E) (filed as Exhibit 10.80 to Form 10-K, File No. 1-4698, Year 1995). . Letter of Credit and Reimbursement Agreement dated as of October 1, 1995 among Nevada Power Company, The Banks named therein, and Barclays Bank PLC, New York Branch (relating to Clark County, Nevada $44,000,000 Industrial Development Refunding Revenue Bonds, Series 1995C) (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 (relating to $60,000,000 Clark County, Nevada Floating Rate Weekly 180 Demand Industrial Development Revenue Bonds, Series 1989A) (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 (relating to $25,000,000 Clark County, Nevada Floating Rate Weekly Demand Industrial Development Revenue Bonds, Series 1998) (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 (relating to Clark County, Nevada $44,000,000 Floating Rate Weekly Demand Industrial Development Revenue Bonds, Series 1985) (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). . Financing Agreement No. 1 between Clark County, Nevada and Nevada Power Company dated as of June 1, 2000 (Series 2000A) (filed as Exhibit 10(O) to Form 10-K for the year ended December 31, 2000). . Financing Agreement No. 2 between Clark County, Nevada and Nevada Power Company dated as of June 1, 2000 (Series 2000B) (filed as Exhibit 10(P) to Form 10-K for the year ended December 31, 2000). . Financing Agreement between Clark County, Nevada and Nevada Power Company dated November 1, 1997 (relating to Clark County, Nevada $52,285,000 Industrial Development Revenue Bonds, Series 1997A) (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 (relating to Coconino County, Arizona $20,000,000 Pollution Control Corporation Pollution Control Revenue Bonds, Series 1997B) (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 (relating to Coconino County, Arizona Pollution Control Corporation $20,000,000 Pollution Control Revenue Bonds, Series 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 (relating to Clark County, Nevada $76,750,000 Industrial Development Revenue Bonds, 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 (relating to Clark County, Nevada $85,000,000 Industrial Development Refunding Revenue Bonds, Series 1995B) (filed as Exhibit 10.76 to Form 10-K, File No. 1-4698, Year 1995). 181 . Financing Agreement between Clark County, Nevada and Nevada Power Company dated October 1, 1995 (relating to Clark County, Nevada $76,750,000 Industrial Development Revenue Bonds, Series 1995A and $44,000,000 Industrial Development Refunding Revenue Bonds, Series x 1995C) (filed as Exhibit 10.77 to Form 10-K, File No. 1-4698, Year 1995). . Financing Agreement between Clark County, Nevada and Nevada Power Company dated October 1, 1995 (relating to Clark County, Nevada $20,300,000 Pollution Control Refunding Revenue Bonds, 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 (relating to Coconino County, Arizona Pollution Control Corporation $13,000,000 Pollution Control Refunding Revenue Bonds, 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 (Relating to Industrial Development Refunding Revenue Bonds, Series 1992C) (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 (Relating to Clark County, Nevada $105,000,000 Industrial Development Revenue Bonds, 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 (Relating to Pollution Control Refunding Revenue Bonds, 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 (relating to Clark County, Nevada $25,000,000 Floating Rate Weekly Demand Industrial Development Revenue Bonds, Series 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 (relating to Clark County, Nevada $44,000,000 Floating Rate Weekly Demand Industrial Development Revenue Bonds, Series 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 (relating to Clark ounty, Nevada $78,000,000 Industrial Development Revenue Bonds, Series 1983) (filed as Exhibit 10.36 to Form 10-K, File No. 1-4698, Year 1985). . 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 (filed as Exhibit 10(Q) to Form 10-K for the year ended December 31, 2000). . 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 (filed as Exhibit 10(R) to Form 10-K for the year ended December 31, 2000). 182 . Generation Agreement dated as of June 25, 1999 between Nevada Power Company and the International Brotherhood of Electrical Workers Local No. 396 (filed as Exhibit 10(S) to Form 10-K for the year ended December 31, 2000). . 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). . *(F) Western Systems Power Pool ("WSPP") Agreement effective March 1, 2002 between Nevada Power Company as a member of WSPP and the other members of the WSPP. . 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). . 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 183 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). . Reliability Management System Agreement dated June 18, 1999 by and between Western Systems Coordinating Council and Nevada Power Company (filed as Exhibit 10(U) to Form 10-K for the year ended December 31, 2000). . *(G) Service Agreement No. 90 for Long-Term Firm Point-To-Point Transmission Service filed with the Federal Energy Regulatory Commission July 20, 2001 between Nevada Power Company and Reliant Energy Services, Inc. . *(H) Service Agreement Nos. 95 and 96 for Long-Term Firm Point-To-Point Transmission Service filed with the Federal Energy Regulatory Commission August 1, 2001 between Nevada Power Company and Calpine Corporation. . *(I) Service Agreement No. 97 for Long-Term Firm Point-To-Point Transmission Service filed with the Federal Energy Regulatory Commission August 1, 2001 between Nevada Power Company and Duke Energy Trading and Marketing. . *(J) Service Agreement Nos. 98 and 99 for Long-Term Firm Point-To-Point Transmission Service filed with the Federal Energy Regulatory Commission August 1, 2001 between Nevada Power Company and Mirant Americas Development, Inc. 184 . *(K) Service Agreement No. 100 for Long-Term Firm Point-To-Point Transmission Service filed with the Federal Energy Regulatory Commission August 1, 2001 between Nevada Power Company and Pinnacle West Energy Company. . *(L) Service Agreement No. 101 for Long-Term Firm Point-To-Point Transmission Service filed with the Federal Energy Regulatory Commission August 1, 2001 between Nevada Power Company and Reliant Energy Services, Inc. . *(M) Service Agreement No. 102 for Long-Term Firm Point-To-Point Transmission Service filed with the Federal Energy Regulatory Commission August 3, 2001 between Nevada Power Company and Las Vegas Cogeneration II, LLC. . Sublease Agreement between Powveg Leasing Corp., as Lessor and Nevada Power Company as Lessee, dated January 1, 1984 for lease of administrative headquarters (the primary term of the sublease ends in 2014 and the lessee has the option to extend the term up to 25 additional years) (filed as Exhibit 10.31 to Form 10-K, File No. 1-4698, Year 1983). Sierra Pacific Power Company . Asset Sale Agreement between Sierra Pacific Power Company and NRG Energy, Inc. dated as of October 16, 2000 for the North Valmy Asset Bundle (filed as Exhibit (10)(V) to Form 10-K for the year ended December 31, 2000). . Transitional Power Purchase Agreement by and between Sierra Pacific Power Company and Valmy Power LLC dated as of October 16, 2000 (filed as Exhibit (10)(W) to Form 10-K for the year ended December 31, 2000). . 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 (filed as Exhibit (10)(X) to Form 10-K for the year ended December 31, 2000). . Transitional Power Purchase Agreement by and between Sierra Pacific Power Company and WPS Northern Nevada, LLC dated as of October 25, 2000 (filed as Exhibit (10)(Y) to Form 10-K for the year ended December 31, 2000). . Asset Purchase Agreement between Sierra Pacific Power Company and Truckee Meadows Water Authority dated as of January 15, 2001 (filed as Exhibit (10)(Z) to Form 10-K for the year ended December 31, 2000). . *(N) Credit Agreement dated as of November 30, 2001, among Sierra Pacific Power Company, Union Bank of California, N.A., as Sole Bookrunner and Administrative Agent, Wells Fargo Bank, N.A., as Syndication Agent, Bank One, NA, BNP Paribas and Mellon Bank, N.A., as Co-Documentation Agents, the Lenders party hereto from time to time, and Union Bank of California, N.A. and Wells Fargo Bank, N.A., as Co-Lead Arrangers relating to $150,000,000 credit facility. . 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). 185 . 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). . *(O) Financing Agreement dated as of March 1, 2001 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 2001. . 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 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). . 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). 186 . 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). . Western Systems Power Pool ("WSPP") Agreement effective March 1, 2002 between Sierra Pacific Power Company as a member of WSPP and the other members of the WSPP (filed as Exhibit (10)(F) above). . 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). . *(P) Amendatory Agreement No. 1 dated April 11, 1995 to 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. . *(Q) Amendatory Agreement No. 2 dated July 5, 2000 to 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. . *(R) Coal Sales Agreement dated January 1, 2002 between Sierra Pacific Power Company and Arch Coal Sales Company, Inc. (5 year term ending on December 31, 2006). . 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). . 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). . 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). 187 . 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). . 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). . 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). (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. Great Basin Energy Company, a Nevada Corporation. Lands of Sierra, Inc., a Nevada Corporation. Nevada Electric Investment Company, a Nevada Corporation. Sierra Energy Company dba e.three, a Nevada Corporation. Sierra Gas Holdings Company, a Nevada Corporation. Sierra Pacific Energy Company, a Nevada Corporation. Sierra Pacific Resources Capital Trust I, a Delaware Business Trust. Sierra Pacific Resources Capital Trust II, a Delaware Business Trust. Sierra Water Development Company, a Nevada Corporation. Tuscarora Gas Pipeline Company, a Nevada Corporation. Tuscarora Gas Operating Company, a Nevada Corporation. 188 Nevada Power Company . Commonsite, Inc., 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. Pinon Pine Investment Co. LLC, a Nevada Limited Liability Company. 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. 333-72160 (Post-Effective Amendment to Registration No. 333-80149 on Form S-3. 189