-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, ELNwBkjkXaxfGBYUw8G66EVxH5SxCQIwZ2WkmohjuJ09ceQz6/7T1pjO+Q4gCnSQ GasOUR0zypovsoT5YvebSQ== 0000950135-03-002055.txt : 20030328 0000950135-03-002055.hdr.sgml : 20030328 20030328160654 ACCESSION NUMBER: 0000950135-03-002055 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 18 CONFORMED PERIOD OF REPORT: 20021231 FILED AS OF DATE: 20030328 FILER: COMPANY DATA: COMPANY CONFORMED NAME: SIERRA PACIFIC POWER CO CENTRAL INDEX KEY: 0000090144 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC & OTHER SERVICES COMBINED [4931] IRS NUMBER: 880044418 STATE OF INCORPORATION: NV FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 000-00508 FILM NUMBER: 03625422 BUSINESS ADDRESS: STREET 1: 6100 NEIL RD STREET 2: P O BOX 10100 CITY: RENO STATE: NV ZIP: 89520-0400 BUSINESS PHONE: 7026895408 MAIL ADDRESS: STREET 1: 6100 NEIL ROAD STREET 2: P.O. BOX 10100 CITY: RENO STATE: NV ZIP: 89520 FILER: COMPANY DATA: COMPANY CONFORMED NAME: SIERRA PACIFIC RESOURCES /NV/ CENTRAL INDEX KEY: 0000741508 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC & OTHER SERVICES COMBINED [4931] IRS NUMBER: 880198358 STATE OF INCORPORATION: NV FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-08788 FILM NUMBER: 03625423 BUSINESS ADDRESS: STREET 1: PO BOX 30150 STREET 2: 6100 NEIL RD CITY: RENO STATE: NV ZIP: 89511 BUSINESS PHONE: 7758344011 MAIL ADDRESS: STREET 1: P O BOX 30150 STREET 2: 6100 NEIL ROAD CITY: RENO STATE: NV ZIP: 89511 FILER: COMPANY DATA: COMPANY CONFORMED NAME: NEVADA POWER CO CENTRAL INDEX KEY: 0000071180 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 880045330 STATE OF INCORPORATION: NV FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 002-28348 FILM NUMBER: 03625424 BUSINESS ADDRESS: STREET 1: 6226 W SAHARA AVE CITY: LAS VEGAS STATE: NV ZIP: 89146 BUSINESS PHONE: 7023675000 MAIL ADDRESS: STREET 1: P O BOX 230 CITY: LAS VEGAS STATE: NV ZIP: 89151 FORMER COMPANY: FORMER CONFORMED NAME: SOUTHERN NEVADA POWER CO DATE OF NAME CHANGE: 19701113 10-K 1 b45693spe10vk.txt FORM 10-K FOR SIERRA PACIFIC AND NEVADA POWER ================================================================================ 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, 2002 Registrant, State of Incorporation, Address of Commission File Principal Executive Offices and Telephone I.R.S. employer State of Number Number Identification Number Incorporation 1-08788 SIERRA PACIFIC RESOURCES 88-0198358 Nevada P.O. Box 10100 (6100 Neil Road) Reno, Nevada 89520-0400 (89511) (775) 834-4011 2-28348 NEVADA POWER COMPANY 88-0420104 Nevada 6226 West Sahara Avenue Las Vegas, Nevada 89146 (702) 367-5000 0-00508 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 PREMIUM INCOME EQUITY SECURITIES (PIES) 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 NEW YORK STOCK EXCHANGE
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] Indicate by check mark whether any registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Sierra Pacific Resources Yes [X] No [ ]; Nevada Power Company Yes [ ] No [X] Sierra Pacific Power Company Yes [ ] No [X]; State the aggregate market value of the voting and non-voting stock held by non-affiliates. As of June 28, 2002: $707,467,699 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 21, 2003: 117,135,012 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 12, 2003, 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 NEVADA POWER COMPANY SIERRA PACIFIC POWER COMPANY ANNUAL REPORT ON FORM 10-K CONTENTS PART I.....................................................................................................3 ITEM 1. BUSINESS....................................................................................3 Sierra Pacific Resources.............................................................................3 Nevada Power Company.................................................................................4 Sierra Pacific Power Company........................................................................15 Other Subsidiaries Of Sierra Pacific Resources......................................................32 ITEM 2. PROPERTIES....................................................................................36 ITEM 3. LEGAL PROCEEDINGS..........................................................................36 ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS........................................39 PART II...................................................................................................40 ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS (SPR).............40 ITEM 6. SELECTED FINANCIAL DATA....................................................................42 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS......44 Sierra Pacific Resources............................................................................60 Nevada Power Company................................................................................71 Sierra Pacific Power Company........................................................................84 ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.............................114 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA...............................................117 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE...200 PART III.................................................................................................201 ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT..........................................201 ITEM 11. EXECUTIVE COMPENSATION.................................................................207 ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.........................214 ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.........................................215 ITEM 14. CONTROLS AND PROCEDURES................................................................218 PART IV..................................................................................................219 ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K........................219 SIGNATURES AND CERTIFICATIONS.........................................................................222
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 seven 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), and Lands of Sierra (LOS). NPC and SPPC are referred to together in this report as the "Utilities." Periodic reports on Form 10-K and Form 10-Q and current reports on Form 8-K are made available to the public, free of charge, on the Sierra Pacific Resources, Nevada Power Company and Sierra Pacific Power Company websites, www.sierrapacificresources.com, www.nevadapower.com, and www.sierrapacific.com and through links on these websites to the SEC's website at www.sec.gov as soon as reasonably practicable after they have been filed with the SEC. The contents of the above referenced website addresses are not part of this Form 10-K. 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 INDUSTRY TRENDS In the wake of volatile and unprecedented energy prices in the Western United States in 2000 and a portion of 2001, the credit quality of a number of utilities and power merchants deteriorated in 2002. Like other utilities in the West, NPC and SPPC were adversely affected by increased wholesale prices and by regulatory decisions that denied the utilities the ability to recover in full their higher fuel and purchased power costs. Major disallowances of power costs by the Public Utilities Commission of Nevada (PUCN) in March and May of 2002 led to severe liquidity problems, depressed earnings, and debt ratings downgrades for SPR and the Utilities. Although energy price volatility has subsided, many policy, regulatory, business, and financial issues remain, a number of which are being addressed or litigated at state and federal levels. See Liquidity and Capital Resources, and Regulation and Rate Proceedings, in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, for additional information regarding these issues. Adding to liquidity concerns in the industry, a number of power merchants had increased borrowings to purchase or build assets based on the prospect of higher overall wholesale prices. Wholesale prices remained 3 relatively steady in the latter part of 2002, causing demand projections to be revised downward, with the result that planned investment in generation suddenly declined and a number of highly leveraged companies were at risk of defaulting on their obligations. The year 2002 was also marked by a general economic downturn that left few industries untouched. Several companies admitted to fraudulent energy trading activities. Companies inside and outside the electric utility industry admitted to fraudulent accounting practices. As a result, federal investigations of corporations and energy markets were conducted and are ongoing. Investor, consumer, and employee protection issues led to increased oversight of the accounting profession, audit quality and independence, and to new accounting principles and legislation. Passed in July, the Sarbanes-Oxley Act of 2002 enhances criminal penalties for certain corporate wrongdoings. Rating agencies have also increased their scrutiny of the industry. According to a recent release by Standard & Poors', credit rating activity in 2002 for the investor-owned power industry involved 182 downgrades compared with only 15 upgrades during the year. The credit ratings of a number of companies, including SPR, NPC, and SPPC, were downgraded more than once. Transmission capacity continued to be constrained in many regions of the country, according to the North American Electric Reliability Council. In the second quarter of 2002, transmission congestion was almost three times the level experienced during the same period in 1999. Investment in transmission has been declining over the last decade. REGULATION AND ELECTRIC RESTRUCTURING The transition to retail competition continues to be highly uncertain, driven by a changing wholesale market, the different approaches to retail competition taken by state regulators and legislators, and the varying results from those approaches. Electric industry restructuring has been achieved in some states, including Texas and a number of states in the Northeast. In the majority of states, however, restructuring activities are either not active or they have been suspended or eliminated. While retail competition has been halted for most customers in Nevada, Assembly Bill 661 (AB 661), passed in 2001, allows commercial and governmental customers with an average demand greater than one megawatt (MW) annually to choose a new energy supplier beginning mid-2002 with permission from the PUCN upon meeting public interest tests. To date, none have left the system. However, 12 large customers have such applications pending with the PUCN. The Federal Energy Regulatory Commission (FERC) has remained committed to regional transmission organization development and wholesale power competition, and issued an initial standard market design (SMD) during 2002. The SMD rule proposed to establish a single, standardized transmission service and a single, standardized wholesale market design. In response to concerns expressed by utility regulators in a number of states, the FERC announced it would issue a white paper on its proposed SMD rule in April 2003. 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. NPC provides electricity to approximately 669,000 customers in the communities of Las Vegas, North Las Vegas, Henderson, Searchlight, Laughlin, and adjoining 4 areas, including Nellis Air Force Base. Service is also provided to the Department of Energy's Nevada Test Site in Nye County. During 2002, Nevada Electric Investment Company (NEICO) became a wholly owned subsidiary of NPC. 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 a facility for the production and distribution of chilled water, hot water and emergency power for Las Vegas' Aladdin Hotel and Casino, which filed for Chapter 11 bankruptcy protection in September 2001. 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 Other Subsidiaries of Sierra Pacific Resources, e-three for a more complete discussion of these activities. BUSINESS AND COMPETITIVE ENVIRONMENT NPC's electric business contributed 100% of its 2002 operating revenues of $1.9 billion. The system has an annual load factor of approximately 49%, which is slightly lower than the industry norm of 50% to 55%. Summer retail peak loads are driven by air conditioning demand. NPC's peak load increased an average of 5.7% annually over the past three years, reaching 4,617 MW on July 12, 2002. NPC's total electric megawatt-hour (MWh) sales have increased an average of 3.9% annually over the past three 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, with residential customer growth averaging 5.3% per year over the past 5 years. A significant part of the growth in NPC's electric sales has resulted from new residential, industrial, and gaming customers. 5 NPC's electric customers by class contributed the following toward 2002 and 2001 MWh sales:
MWH SALES (BILLED AND UNBILLED) ---------------------------------------------------------- 2002 2001 --------------------------- --------------------------- Residential 7,240,325 32.7% 7,208,540 25.5% Commercial and Industrial: Office 1,583,186 7.2% 1,986,752 7.0% Gaming/Recreation/Restaurants 4,042,837 18.2% 3,903,478 13.8% Other Retail 903,853 4.1% 825,882 3.0% All Other & Unclassified 3,426,551 15.4% 2,874,169 10.2% ------------ ------------ ------------ ------------ Total Retail 17,196,752 77.6% 16,798,821 59.5% Wholesale 4,567,880 20.6% 11,051,000 39.1% Public Authorities 403,068 1.8% 402,555 1.4% ------------ ------------ ------------ ------------ TOTAL 22,167,700 100.0% 28,252,376 100.0% ============ ============ ============ ============
Tourism and gaming remain southern Nevada's premier industries. Over 35 million tourists visited Las Vegas in 2002, infusing approximately $19.6 billion into the local economy during the year. Currently, Las Vegas is the home of 17 of the world's 20 largest hotels. Las Vegas' newest casino, the 201 room Cannery, opened on January 2, 2003 and carries a 1940s industrial theme throughout the property. The Ritz-Carlton opened the upscale 349-room, Mediterranean-themed MonteLago Village at Lake Las Vegas on February 11, 2003. The Venetian Hotel plans to open its 1,013-suite second tower in June 2003. Mandalay Resort Group has started construction on a 1,125-suite hotel tower slated to open in November 2003. Steve Wynn's Le Reve Resort is under construction and is scheduled for completion March 2005. The Mandalay Resort Group opened a new 1.5 million square foot Mandalay Bay Convention Center on January 6, 2003, becoming the nation's fifth largest convention center. 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 2002 more than 5.1 million convention and trade show delegates traveled to Las Vegas, generating more than $5.9 billion in non-gaming revenue. Despite the expansion of tourism and gaming properties in southern Nevada, a number of gaming properties filed for bankruptcy during 2002 and the industry is subject to a number of risks described later in Item 7, Management's Discussion and Analysis. During 2002, firm and non-firm sales to wholesale customers comprised 20.6% of total energy sales, a decrease of 58.7% from 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 2002 2001 --------------------------- --------------------------- Firm Sales 34,518 0.76% 159,707 1.45% Non-Firm Sales 4,533,362 99.24% 10,891,293 98.55% ------------ ------------ ------------ ------------ Total 4,567,880 100.00% 11,051,000 100.00% ============ ============ ============ ============
NPC's decrease in wholesale MWh sales from last year was a result of market conditions and a change in NPC's power procurement activities. See Energy Supply 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. 6 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 costs, availability of fuel types, the number and status of proposed independent generation projects, the need for additional transmission capacity in southern Nevada, adequacy of rate relief, NPC's ability to raise necessary capital, and changes in environmental regulations. Under NPC's franchise agreements, it is obligated to provide a safe and reliable source of energy to its customers. NPC's service territory is one of the fastest growing areas in the nation. Capital construction expenditures and estimates are reflective of this obligation to serve. Gross construction expenditures for 2002, including allowance for funds used during construction (AFUDC) and contributions in aid of construction, were $294.5 million, and for the period 1998 through 2002, were $1.24 billion. Estimated construction expenditures for 2003 and the period from 2004 to 2007 are as follows (dollars in thousands):
2003 2004-2007 Total 5-Year ----------- ----------- ------------ Total construction expenditures $ 246,902 $ 925,132 $ 1,172,034 AFUDC (14,916) (44,471) (59,387) Net salvage, including cost of removal (795) (3,178) (3,973) Net customer advances and contributions in aid of construction (8,221) (32,883) (41,104) ----------- ----------- ----------- Total cash requirements $ 222,970 $ 844,600 $ 1,067,570 =========== =========== ===========
Total construction expenditures estimated for 2003 and the 2004-2007 period consist of the following (dollars in thousands):
Total 2003 2004-2007 5-Year -------- --------- ---------- Electric Facilities: Distribution $132,628 $504,298 $636,926 Generation 14,340 100,880 115,220 Transmission 83,030 250,177 333,207 Other 16,904 69,777 86,681 -------- -------- ---------- Total $246,902 $925,132 $1,172,034 ======== ======== ==========
The Centennial Plan involves construction of 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 Centennial project is $307.7 million. Total project costs incurred through December 31, 2002, were $112.9 million. Estimated costs for 2003 are $58.0 million, which are expected to be financed utilizing internally generated cash. The Centennial Plan was approved in NPC's 2001 Refiled Resource Plan. An amendment to NPC's Refiled Resource Plan was approved by the PUCN in August 2002, which amended the in-service date for the 7 Harry Allen to Mead 500 kV project from June 2003 to April 2005. Meetings have been held with the PUCN to review the revision to the scheduled in-service date from April 2005 to April 2006 for the Harry Allen to Mead project. See Transmission, later, for additional information about the Centennial Plan. FACILITIES AND OPERATIONS TOTAL SYSTEM NPC maintains a wide variety of resources in its generation system. During 2002, NPC generated 44.0% of its total electric energy requirements, purchasing the remaining 56.0% as shown below:
Percent MWh of Total ------------ ------------ NPC COMPANY GENERATION Gas/Oil 4,073,490 17.7% Coal 6,073,563 26.3% ------------ ------------ Total Generated 10,147,053 44.0% ------------ ------------ PURCHASED POWER Hydro 537,064 2.3% Non-Firm Purchases 621,555 2.7% Short Term Firm and Spot Purchases 9,326,798 40.5% Non-Utility Purchases 2,422,418 10.5% ------------ ------------ Total Purchased 12,907,835 56.0% ------------ ------------ Total 23,054,888 100.0% ============ ============
NPC's decision to purchase short-term and spot energy is based on the economics of purchasing "as-available" energy when it is less expensive than its own generation. NPC's 2002 company generation of 10,147,053 MWh is up 2.5% from NPC's 2001 company generation of 9,899,195 MWh. NPC's 2002 purchased power of 12,907,835 MWh is down 33.0% from NPC's 2001 purchased power of 19,268,305 MWh due to changes in NPC's purchased power procurement strategies. See Energy Supply in Management's Discussion and Analysis for additional information regarding NPC's purchasing strategies. RISK MANAGEMENT See Item 7A, Quantitative and Qualitative Disclosures About Market Risk. LOAD AND RESOURCES FORECAST NPC's electric customer growth rate was 4.8% in 2002, 4.5% in 2001, and 5.1% in 2000. Annual retail electricity sales were 17.6 million MWh in 2002, which represents an increase of 2.3% over 2001 retail electricity sales of 17.2 million MWh. Annual wholesale electricity sales reached 4.6 million MWh in 2002, which represents a decrease of 58.6% from 2001 wholesale electricity sales of 11.1 million MWh. Overall, annual system electricity sales reached 22.2 million MWh in 2002, which represents a decrease of 21.5% from 2001 system electricity sales of 28.3 million MWh. The bulk of the 21.5% decrease is attributed to wholesale sales. The peak electric demand rose from 4,412 MW in 2001 to 4,617 MW in 2002. 8 The projections shown below are forecasts of the load to be provided to all of NPC's current and forecasted customers. No adjustments have been made at this time to incorporate possible changes to NPC loads due to the passage of AB 661 and Senate Bill 211 (SB 211). SB 211 allows the Colorado River Commission to sell electricity to its purveyors of water. AB661 allows commercial and governmental customers with an average demand greater than 1 MW to select other energy suppliers. See Regulation and Rate Proceedings, Nevada Matters, Customers File Under AB661 in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations. The forecast takes into account many sources of information. The peak load forecast uses the economic forecast produced by the University of Nevada Las Vegas' Center for Business and Economic Research. The population forecast is used to develop a customer forecast for NPC. Other major assumptions are normal weather (based on 20-year averages), and the addition of hotel rooms will continue as expected. Other uncertainties include abnormal temperatures, the price levels NPC will be allowed to charge, and the timing of rules allowing customers to leave NPC under AB 661 and SB 211. Also, bundled retail price levels, as well as availability of power in the West, could have great effects on consumption by customers of NPC. NPC's total system capability and peak loads for 2002, and the forecast for summer peak demand for 2003 and 2004 (assuming no curtailment of supply or load, and normal weather conditions), are indicated below:
Capacity at 2002 Peak Forecast Summer Peak (MW) --------------------------- -------------------------- MW % 2003 2004 ----------- ----------- ----------- ----------- NPC Company Generation: Existing (1) (2) 1,595 31% 1,949 1,949 ----------- ----------- ----------- ----------- Purchases Long/Short-Term Firm (3) 2,389 46% 1,800 850 Non-Utility Generators (4) 529 10% 515 515 Wholesale (5) (105) -2% (110) (113) ----------- ----------- ----------- ----------- Subtotal 2,813 54% 2,205 1,252 ----------- ----------- ----------- ----------- Additional Required (6) 763 15% 1,297 2,435 Total System Capacity 5,171 100% 5,451 5,636 =========== =========== =========== =========== 4,617 89% 4,867 5,032 Net System Peak (7) Planning Reserves 554 11% 584 604 ----------- ----------- ----------- ----------- Total 5,171 100% 5,451 5,636 =========== =========== =========== ===========
(1) Existing Generation Capacity includes Clark, Reid Gardner, Sunrise, Harry Allen Generating Stations, and NPC's share of Mohave and Navajo Generating Stations. (2) NPC and its partners in the Mohave Generating Station have not been able to install extensive pollution control equipment necessary to have Mohave's operations extended past 2005 due to coal supply and water issues. The Mohave plant represents 196 MW of capacity. See Note 17 of Notes to Financial Statements, Commitments and Contingencies, Environment for further discussion. (3) Long-Term Purchases include NPC's allotment of hydroelectric power from Hoover Dam. Values are net of line losses. (4) Non-Utility Generation Capacity includes SunPeak units and the Qualifying Facilities. (5) Amount represents on peak wholesale to Silver State Power Pool. Silver State Power Pool, a wholesale customer, is not included in the system peak value of 4,617 MW for 2002. Therefore, NPC resources (generation and purchases) are reduced by the amount of load serving Silver State to show NPC's resources left available to meet the system peak. (6) Additional Required represents the additional, uncommitted capacity needed in order to maintain an adequate reserve margin consistent with the Western Electricity Coordinating Council planning reserve criteria. These additional reserves will be met, if needed, with short-term purchases. (7) The system peak shown for 2002 of 4,617 MW occurred on July 12, 2002 at 4:00 p.m. NPC plans its system capacity needs in accordance with the Western Electricity Coordinating Council (WECC) reliability criteria, which recommends planning reserves in excess of required operating reserves. 9 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 for generation, and the year(s) that the unit(s) was (were) installed.
NPC Number MW Name Type Fuel of Units Capacity Year(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, 1980, 1982, 1993, 1994 ------- ------ Total Clark Station 10 687 Reid Gardner (2) Steam Coal 4 354 1965, 1968, 1976, 1983 Navajo (3) Steam Coal 3 255 1974 Mohave(4)(5) Steam Coal 2 196 1971 Sunrise Steam Gas/Oil 1 80 1964 Combustion Turbine Gas/Oil 1 69 ------- ------ Total Sunrise 2 149 Harry Allen Combustion Turbine Gas/Oil 1 72 1995 ------- ------ Grand Total NPC 22 1,713 ======= ======
(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 Units 1 through 3 are owned by NPC. 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 from Reid Gardner Unit No. 4 and 226 MW of peaking capacity from Reid Gardner Unit No. 4 for a total base load capacity of 354 MW and peaking capacity of 605 MW for all Reid Gardner Units. 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. (5) Due to coal supply and water issues, the Mohave plant will not be able to operate after December 31, 2005. See Note 17 of Notes to Financial Statements, Commitments and Contingencies, Environment for further discussion. 10 PURCHASED POWER NPC 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 2002, NPC experienced favorable market energy prices when compared with the previous four years. The decrease in market energy prices is reflective of FERC price cap regulation, plus the price of gas and power volatility in general, which decreased electricity costs throughout the western United States. During 2002, NPC experienced difficulty maintaining liquidity in western energy markets due to counterparties' credit concerns with NPC when its credit rating dropped below investment grade. With only a handful of counterparties willing to transact, NPC found it necessary to 1) contract with energy marketers to transact on NPC's behalf, and 2) negotiate special payment arrangements to satisfy credit concerns. These two actions remedied the liquidity limitation. If NPC continues to experience financial difficulty or if its credit ratings are further downgraded, NPC may experience considerable difficulty entering into new power supply contracts, particularly under traditional payment terms. If suppliers will not sell power to NPC under traditional payment terms, NPC may have to pre-pay its power requirements. If it does not have sufficient funds or access to liquidity to pre-pay its power requirements, particularly at the onset of the summer months, and is unable to obtain power through other means, NPC's business, operations and financial condition would be materially adversely affected and could make it difficult to provide reliable service to its customers and/or to continue to operate outside of bankruptcy. 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. 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 hydroelectric capacity is 235 MW annually. NPC has a contract to purchase 222 MW annually from Nevada Sunpeak Limited Partnership, an independent power producer. The contract became effective June 8, 1991 and will continue through May 31, 2016. 11 According to regulations issued pursuant to the Public Utility Regulatory Policies Act (PURPA), NPC is obligated, under certain conditions, to purchase the output 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 (QFs). As of December 31, 2002, 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:
CONTRACT CONTRACT NET CAPACITY QUALIFYING FACILITY START END (MW) - ------------------- -------- -------- ------------ Saguaro Power Company 10/17/1991 4/30/2022 90 Nevada Co-generation Associates #1 6/18/1992 4/30/2023 85 Nevada Co-generation Associates #2 2/1/1993 4/30/2023 85 Las Vegas Co-generation Limited Partnership 5/10/1994 5/31/2024 45 --------- 305 =========
Energy purchased by NPC from the QFs constituted 25.7% of the net purchased power requirements (excluding wholesale purchases) and 12.4% of the net system requirements during 2002. All of the QFs are co-generators providing steam for various products and businesses. In November 2002, NPC executed and filed with the PUCN four long term power purchase agreements (PPAs) with geothermal developers in northern Nevada for a total of 97 MW or an estimated 841,000 MWh per year, and two PPAs with wind developers, one in each of northern and southern Nevada for a total of 130 MW or an estimated 405,000 MWh per year. The combined total estimated non-solar supply is 1,246,000 MWh annually. The contract term for all but one geothermal PPA is for twenty years. The term for the remaining geothermal PPA is ten years, with an option for either party to extend the PPA by an additional ten years. NPC also executed five power purchase agreements related to the purchase of renewable energy under the terms of which NPC sells the power associated with the renewable energy contracts located in northern Nevada to SPPC ("Related PPAs"). For these five non-solar PPAs involving suppliers in SPPC's service territory, NPC will receive "Product" (Product is a defined term in the PPA that includes all Renewable Energy Credits "RECs" and energy supplied by the developer) from the renewable supplier at a delivery point on SPPC's transmission system and then NPC will immediately resell the energy to SPPC under the terms and conditions of a "Related PPA" (defined term in the original PPA). NPC will retain the RECs to comply with the requirements of SB 372, Nevada's renewable portfolio law. NPC has also executed a solar renewable energy PPA with Duke Solar for a 50 MW facility located near Boulder City in Clark County, Nevada in NPC's service territory. NPC expects to purchase approximately 70 GWh of energy that includes Renewable Energy Credits "RECs" annually. SPPC entered into a solar PPA with Duke Solar from the same facility located in NPC's service territory. NPC executed an additional Related PPA for this facility. For SPPC's solar PPA, SPPC will receive Product from the renewable supplier at a delivery point on NPC's transmission system and then SPPC will immediately resell the energy to NPC under the terms and conditions of the Related PPA. SPPC will retain the RECs to comply with SB 372. NPC expects to purchase 32 GWh of energy under the terms of the Related PPA. The terms for both SPPC and NPC's solar PPAs are 20 years. 12 NPC also executed a long term PPA with MNS Wind on the Nevada Test Site for an 85 MW wind project in February 2002. TRANSMISSION NPC's existing transmission lines are primarily located within Clark County, Nevada. Six 230 kV transmission lines and two 230/69 kV transformers 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. Two 500/69 kV transformers connect NPC to the Southern California Edison system at the Mohave Generating station. 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 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 the NPC control area. If the Mohave Generating station is shut down in 2005, NPC intends to continue to utilize the Eldorado Transmission System that is connected to the Mohave Generating station to supply NPC load and to meet other transmission service obligations currently in place. The transmission and generation are governed under separate contracts. NPC received approval from the PUCN to construct two transmission line projects and four switchyards proposed in NPC's 2001 Refiled Resource Plan. The Arden-Tolson 230 kV line upgrade, was completed in June 2002 to meet Independent Power Producers (IPP's) transmission service requests at a cost of $475,000. The Faulkner-Tolson 230 kV transmission line will be completed in 2003 at a cost of $9.65 million and will increase NPC's import capability by 300 MW. The Equestrian switchyard was placed in service in 2001. The McDonald switchyard is planned to be completed in 2006. The Avera 230/138 kV switching station and the Beltway 230/138 switching station upgrade projects are all internal NPC reinforcements with 2003 and 2004 in-service dates, respectively. The Avera and Beltway projects are needed for system reliability, increased import capability, and to provide a path for Centennial IPP energy to be delivered into or through NPC's transmission system. The Avera project costs are estimated at $5.3 million and the Beltway project costs are approximately $8.25 million. As a result of the supply shortage in the western United States experienced during 2000 and 2001, several IPPs proposed the construction of new generating plants in southern Nevada and requested transmission service from NPC. NPC proposed the Centennial Plan to address transmission service requests from these IPPs. The Centennial Plan was approved in NPC's 2001 Refiled Resource Plan. This plan, consistent with its tariff and the 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 to Arden 230 kV lines. Additional facilities include a new 500 kV substation at Harry Allen, 500/230 kV transformers at Mead, McCullough and Northwest substations, two phase shifting transformers at Crystal substation, and several other sub-transmission upgrades and additions. The Harry Allen - -Crystal 500 kV line and the Harry Allen 500 kV substation were energized in June 2002. The Arden- Bighorn 230 kV #1 and #2 lines were completed in July 2002. The Harry Allen - Northwest 500 kV line, the Northwest 500/230 kV transformer and the Northwest 500 kV substation were completed in mid-March 2003. The Crystal 500 kV phase shifting transformers will be installed in February 2004. The scheduled in-service date for the Harry Allen-Mead 500 kV line, the Mead 500/230 kV transformer and the McCullough 500/230 kV transformer is April 2006. 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. 13 FUEL AVAILABILITY NPC's 2002 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 1998 - 2002, 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 2002 3.65 48.30% 1.34 51.50% 5.77 0.20% 2001 5.34 42.60% 1.26 57.30% 7.14 0.10% 2000 4.93 42.60% 1.22 57.30% 7.33 0.10% 1999 2.27 40.60% 1.15 59.30% 4.01 0.10% 1998 2.35 33.00% 1.39 67.00% 3.96 *
* Oil was less than .1% of consumption For a discussion of the change in fuel costs, see Results of Operations in 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 2002'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. No deliveries under this agreement were scheduled for 2002 and NPC replaced these volumes with spot market purchases. The mine remains sealed and NPC does not anticipate that deliveries will resume before the contract terminates. The contract remains in a force majeure status. The contract was due to expire in 2007 and has been replaced by short-term purchases. The Union Pacific Rail Transportation contract provides for deliveries from the Provo, Utah interchange as well as various mines in the Price, Utah area, to the Reid Gardner Station in Moapa, Nevada. This contract was effective January 1, 1996 and has been extended through December 31, 2004. The Utah Railway contract provides for the remainder of NPC's Price, Utah area supplies. This contract has been extended through December 31, 2003 and will be renegotiated year to year as needed. 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 Tribes reservations. The supply contracts with Peabody extend to December 31, 2005, for Mohave and to June 1, 2011, for Navajo, with each contract having an option to extend for an additional 15 years. The Mohave coal is delivered from the mine to Mohave by means of a coal slurry pipeline, which requires water that is obtained from groundwater wells located on lands of the Tribes in the mine vicinity. Due to the lack of progress in negotiations with the Tribes and other parties to resolve several coal and water supply issues, Southern California Edison's (SCE's) application with the California Public Utility Commission (CPUC) to determine whether it is in the public interest to continue operation of the Mohave facility states that it probably will not be possible for SCE, the operating partner, to extend Mohave's operations beyond 2005. Due to the uncertainty over a post-2005 coal supply, SCE and the other Mohave co-owners have been prevented from commencing the installation of extensive pollution control equipment that must be put in place if Mohave's operations are extended past 2005. 14 NPC purchases natural gas on a firm, fixed and indexed price basis from the Rocky Mountain Basin. Natural gas is transported to the Clark, Sunrise and Harry Allen stations via 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 Kern River California 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. OTHER On July 7, 2002, the Board of County Commissioners of Clark County, Nevada, added an Electric Utility Advisory Question to its November 5, 2002, general election ballot which asked voters in a non-binding initiative whether "the Nevada Legislature should take appropriate action to enable the electrical energy provider for southern Nevada to be a locally controlled, not for profit public utility." The Company and various private entities and public interest groups strongly opposed the measure. Although passing by a 57% majority, this was substantially below the level of support indicated in early polls. No bills related to this issue were introduced in the 2003 Nevada legislative session. On August 22, 2002, SPR received a letter from the Southern Nevada Water Authority ("SNWA") stating that it was prepared to enter into good faith negotiations of definitive agreements to acquire NPC in some undetermined way (stock purchase or all or some of its assets) and to assume some unspecified amount of indebtedness, at a purchase price subject to adjustment at SNWA's discretion at the conclusion of negotiations and due diligence. On September 12, 2002, SPR responded with a letter stating that it did not view the SNWA's letter as an offer and expressing concerns with the SNWA's financing plans, certain significant legal issues with the proposal, SNWA's lack of utility management experience, and ambiguity in the proposal. SPR was served with a complaint by a shareholder seeking class action status to require SPR to enter into negotiations. See Legal Proceedings for further details. 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. 15 SPPC is a public utility primarily engaged in the distribution, transmission, generation, purchase, and sale of electric energy. It provides electricity to more than 318,000 customers in an approximately 50,000 square mile service area in western, central and northeastern Nevada, including the cities of Reno, Sparks, Carson City, and Elko, and a portion of eastern California, including the Lake Tahoe area. In 2002, electric revenues were 86.1% of SPPC's revenue. SPPC also provides natural gas service in Nevada to approximately 123,500 customers in an area of about 600 square miles in Reno/Sparks and environs. In 2002, natural gas revenues were 13.9% of SPPC's revenues. In June 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. The sale agreement contemplates a second closing for the transfer of hydroelectric facilities included in the contract of sale for an additional $8 million to accommodate review of the transaction by the CPUC. 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 Section 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 21 of Notes to Financial Statements, Pinon Pine. BUSINESS AND COMPETITIVE ENVIRONMENT In 2002, SPPC's electric business contributed $931 million (86.1%) in revenues from continuing operations. The electric system peak typically occurs in the summer, while the winter peak is nearly as high. The system has an annual load factor of approximately 74.98%, which is higher than the industry norm of 50% to 55%. Winter retail 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 retail peak loads are primarily driven by cooling equipment demand (including air conditioning demand) and irrigation pumping. SPPC's peak load increased an average of 2.7% annually over the past three years, reaching 1,590 MW on July 10, 2002. SPPC's total retail electric MWh sales have increased an average of 1.1% annually over the past three years. 16 SPPC's electric customers by class contributed the following toward 2002 and 2001 MWh sales:
MWH SALES (BILLED AND UNBILLED) 2002 2001 --------------------------- --------------------------- Residential 2,107,673 18.6% 2,069,140 16.1% Commercial and Industrial: Mining 2,544,393 22.5% 2,662,763 20.7% Offices/Schools/Government 1,086,445 9.6% 1,141,861 8.9% Resorts & Recreation 633,293 5.6% 689,861 5.4% Manufacturing/Warehouse 718,951 6.4% 769,053 6.0% All Other 1,600,540 14.2% 1,396,493 10.8% ------------ ------------ ------------ ------------ Total Retail 8,691,295 76.9% 8,729,171 67.9% Wholesale 2,606,480 23.0% 4,123,513 32.0% Streetlights 12,606 0.1% 11,963 0.1% ------------ ------------ ------------ ------------ TOTAL 11,310,381 100.0% 12,864,647 100.0% ============ ============ ============ ============
According to the Nevada Division of Minerals, gold is Nevada's most important mineral commodity in terms of economic impact on the state and on communities located near mining operations. The state's gold production has remained near 8 million ounces per year over the past 5 years, enabling Nevada to maintain its position as the leading gold producing state in the U.S. While gold mining in past years has been challenged by a relatively low commodity price, individual mines have focused on improving efficiency at their operations, reducing overhead costs, and closing down less efficient and uneconomic properties. While these actions led to a small decrease in total MWh sales by SPPC to the mining industry during 2002, they also enabled mines to lower production costs so they could operate economically during the period of low gold prices and improve their competitive position. With projections that recent increases in gold prices will be sustained at or above current levels for a number of years, individual companies are expected to maintain their production activities and resulting energy use at current levels for the foreseeable future. SPPC has long-term electric service agreements with eight of its major mining customers. The terms range from 5 to 15 years from the effective dates of these agreements with the longest term contract expiring in 2011. SPPC had sales in 2002 of approximately $148 million in annual revenues, which is 16.0% of 2002 electric operating revenues under these agreements. 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 and secures approximately $6 million in annual revenues through electric facilities charges. The offices/schools/government and healthcare customer segment continues to grow with the addition of new schools, government facilities and healthcare facilities. At the same time that growth is occurring, customers' implementation of energy conservation and efficiency programs has led to a 4.85% decrease in energy sales to the overall sector. In healthcare, increasing demands for new long term and acute care facilities is expected to double the number of facilities by 2006. In the education sector, one new high school will open in 2003, a middle school in 2004, and on average, two new schools will be added each year between 2005 and 2007. The resorts and recreation customer segment, consisting of hotels, casinos and ski resorts, account for 7.3% of the total electric system retail MWh sales. MWh sales were down 8% in 2002 compared to 2001 primarily as a result of customers' continued efforts to implement energy conservation measures. In the ski 17 resort segment, energy consumption was reduced in response to heavy natural precipitation and snow early in the 2002-2003 ski season that enabled resorts to decrease their use of artificial snowmaking equipment. In 2002, tourism and gaming were negatively impacted by a reduction in flight schedules to northern Nevada and a continuing increase in competition from gaming on Indian reservations in California. In response, the industry and the community continued to work together to strengthen the region's competitive position in the tourism, gaming and leisure markets. These efforts included the opening of a major new hotel casino in Reno, the completion of a $105 million, 500,000 square foot renovation and expansion of the Reno-Sparks Convention Center, and the repositioning of the state's tourism advertising to promote its natural resources and its diversified entertainment and recreation opportunities. The manufacturing and warehousing customer segment overall continued to decline for a second straight year. Many manufacturing customers have suffered large order reductions and production losses due to the economic slowdown. However, manufacturing orders are beginning to recover from their all time low point in 2002. At the same time, there has been an increase in the number of customers in the sector as the result of small manufacturers relocating out of the California market. Northern Nevada continues to develop as a destination for relocating high-technology companies, which could result in an increase in sales to the manufacturing and warehousing customer segment. In 2002 SPPC continued to solidify working relationships within the business community by assisting in the recruitment of industries in targeted sectors such as plastic manufacturers and high-technology companies. The 2001 session of the Nevada State Legislature enacted AB 661. One provision of this bill allows commercial customers with an average annual load of 1 MW or more to file a letter of intent and application with the PUCN to acquire electric energy, capacity, and ancillary services 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, protect consumers from unexpected rate hikes, and attract new energy suppliers to Nevada. During 2002, one qualifying customer filed a notice of intent with the PUCN indicating their desire to procure energy services from a new provider. This customer has not yet filed a formal application with the PUCN but could do so at any time. Under the law, the earliest departure date would be 180 days after the application is filed. SPPC's MWh sales to wholesale customers have decreased 36.8% over the past year. During 2002 firm and non-firm sales to wholesale customers comprised 23.0% 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.
WHOLESALE MWH SALES 2002 2001 ------------------------- ------------------------- Firm Sales 2,507,775 96.20% 4,085,097 99.10% Non-Firm Sales 98,705 3.80% 38,416 0.90% ----------- ----------- ----------- ----------- Total 2,606,480 100.00% 4,123,513 100.00% =========== =========== =========== ===========
SPPC's decrease in wholesale MWh sales from last year was a result of market conditions and SPPC's power procurement activities. See Energy Supply 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 18 costs, availability of fuel types, the number and status of proposed independent generation projects, the need for additional transmission capacity in northern Nevada, adequacy of rate relief, SPPC's ability to raise necessary capital and changes in environmental regulation. Under SPPC's franchise agreements, it is obligated to provide a safe and reliable source of energy to its customers. SPPC's service territory continues to experience steady growth. Capital construction expenditures and estimates are reflective of this obligation to serve. Gross construction expenditures for 2002, including AFUDC and contributions in aid of construction, were $105.3 million, and for the period 1998 through 2002, were $719.4 million. Estimated construction expenditures for 2003 and the period 2004-2007 are as follows (dollars in thousands):
Total 2003 2004-2007 5-Year ------------ ------------ ------------ Electric facilities $ 118,905 $ 333,527 $ 452,432 Gas facilities 11,791 56,463 68,254 Common facilities 2,928 12,320 15,248 ------------ ------------ ------------ Total construction expenditures 133,624 402,310 535,934 ------------ ------------ ------------ AFUDC (7,032) (20,062) (27,094) Net salvage, including cost of removal (312) (1,248) (1,560) Net customer advances and contributions in aid of construction (4,800) (19,200) (24,000) ------------ ------------ ------------ Total cash requirements $ 121,480 $ 361,800 $ 483,280 ============ ============ ============
19 Total construction expenditures estimated for 2003 and the 2004-2007 period, for each segment of SPPC's business, consist of the following (dollars in thousands):
Total 2003 2004-2007 5-Year -------------- -------------- -------------- Electric Facilities: Distribution $ 47,345 $ 181,654 $ 228,999 Generation 4,931 25,066 29,997 Transmission 60,511 98,317 158,828 Other 6,118 28,490 34,608 -------------- -------------- -------------- 118,905 333,527 452,432 -------------- -------------- -------------- Gas Facilities: Distribution 11,359 54,004 65,363 Other 432 2,459 2,891 -------------- -------------- -------------- 11,791 56,463 68,254 -------------- -------------- -------------- Common Facilities 2,928 12,320 15,248 -------------- -------------- -------------- TOTAL $ 133,624 $ 402,310 $ 535,934 ============== ============== ==============
The Falcon to Gonder Transmission Project is a 345kV transmission line within northern Nevada with a planned in-service date of May 2004. Total project costs incurred through December 31, 2002, were $32.8 million. Actual costs incurred in 2002 were $21.0 million. Estimated costs for 2003 are $46.5 million. 20 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 2002, SPPC generated 39.5% of its total electric energy requirements in its own plants, purchasing the remaining 60.5% as shown below:
Percent MWh of Total ----------- ----------- SPPC COMPANY GENERATION Gas/Oil 2,527,858 21.3% Coal 2,136,677 17.9% Hydro 34,945 0.3% ----------- ----------- Total Generated 4,699,480 39.5% ----------- ----------- PURCHASED POWER Utility Purchases: Long-Term Firm 460,221 3.9% Short-Term Firm 5,944,703 49.9% Spot Market 11,674 0.1% Non-Utility Purchases: Geothermal 693,286 5.8% Other 96,421 0.8% Transmission & Balancing (851) 0.0% ----------- ----------- Total Purchased 7,205,454 60.5% ----------- ----------- Total 11,904,934 100.0% =========== ===========
As a supplement to its own generation, SPPC purchases both firm and non-firm energy to meet its customer demand requirements. Total energy supply includes purchases from outside the electric system due to limited control area generation and also the need to access market energy supplies. SPPC's decision to purchase this energy is based on economics, mitigation of availability risk, and system import limits. Firm block purchases are transacted as both a price hedging strategy and to ensure that needed firm capacity is available over peak load periods. Spot market energy is purchased based on the economics of purchasing "as-available" energy when it is less expensive than SPPC's own generation, again, subject to net system import limits. In 2002, most of SPPC's non-utility generation came from QFs. See Energy Supply in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, for additional information. RISK MANAGEMENT See Item 7A, Quantitative and Qualitative Disclosures About Market Risk. 21 LOAD AND RESOURCES FORECAST SPPC's electric customer growth rate was 2.3% in 2002, 1.9% in 2001, and 2.6% in 2000. Annual retail electricity sales were 8.7 million MWh in 2002 and 2001. Annual wholesale electricity sales reached 2.6 million MWh in 2002, which represents a decrease of 36.8% from 2001 wholesale electricity sales of 4.1 million MWh. Overall, annual system electricity sales reached 11.3 million MWh in 2002, which represents a decrease of 12.0% from 2001 system electricity sales of 12.8 million MWh. The 2002 peak electric demand was 1,590 MW. The 2001 peak demand was 1,529 MW. The projections shown below are forecasts of the load to be provided to all of SPPC's current and forecasted customers. No adjustments have been made at this time to incorporate possible changes to SPPC loads due to the passage of AB 661 by the 2001 Nevada Legislature which allows commercial and governmental customers with an average demand greater than one MW to select other energy supplies. See Regulation and Rate Proceedings, Nevada Matters, Customers File Under AB 661 in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operation. The forecast includes an assumption that normal weather (based on 20-year averages) will occur. Other uncertainties to the forecast include abnormal weather, failure of the local economy to recover, and customer losses due to AB 661. SPPC continues to provide energy through generation and purchased power to meet both summer and winter peak loads. SPPC's total system capability and peak loads for 2002, and the forecast for summer peak demand through 2004 (assuming no curtailment of supply or load and normal weather conditions), are indicated below:
Capacity at 2002 Forecast Summer Peak Peak (MW) ---------------------------- --------------------------- MW % 2003 2004 ------------ ------------ ------------ ------------ SPPC Company Generation: Existing 989 57% 1,062 1,056 ------------ ------------ ------------ ------------ Purchases: Long/Short-Term Firm (1) 508 29% 500 125 Interruptible/Wheeling/Losses (18) (1)% -- -- Non-Utility Generators 263 15% 85 85 ------------ ------------ ------------ ------------ Subtotal 753 43% 585 210 ------------ ------------ ------------ ------------ Additional Required -- 0% 74 527 Total System Capacity 1,742 100% 1,721 1,793 ============ ============ ============ ============ Net System Peak Demand (2) 1,590 91% 1,535 1,586 Planning Reserve 152 9% 186 207 ------------ ------------ ------------ ------------ Total Requirement 1,742 100% 1,721 1,793 ============ ============ ============ ============
(1) 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 occurred during the 2002 peak, only firm power purchases. (2) The system peak shown for 2002 occurred on July 10, 2002, at 5:00 p.m. SPPC plans its system capacity needs in accordance with the WECC reliability criteria, which recommends planning reserves in excess of required operating reserves. The "Additional Required" represents the additional, uncommitted capacity needed in order to maintain adequate reserve margin consistent with the WECC planning reserve criteria. These additional reserves will be met, if needed, with short-term purchases through 2004 to the extent available. 22 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.
SPPC Number of Name Type Fuel Units MW Capacity Year(s) Installed - ---- ---- ---- --------- ----------- ----------------- Valmy (1) Steam Coal 2 266 1981, 1985 Tracy Steam Gas/Oil 3 244 1963, 1965, 1974 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 1899-1971 ----- ----------- Grand Total SPPC 43 1,045 ===== ===========
(1) SPPC is the operator and owns an undivided 50% interest in the Valmy plant. Idaho Power Company owns the remainder. SPPC owns 100% 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 inactive, the combined cycle units have been operating on natural gas since 1996. See Note 21, Pinon Pine, to the Notes to Financial Statements. (3) The combined cycle at Pinon consists of one combustion turbine and one steam turbine. Pinon is located at the Tracy Generating Station. (4) The four hydroelectric generating units, with a total capacity of 8.7 MW, were to be included in the sale of SPPC's water business in June 2001. The California Legislature has passed a law exempting the hydro plants from the prohibition against generation divestiture. On November 9, 2002, SPPC filed an application with the CPUC for authority to sell the four hydroelectric plants. On January 13, 2003, the CPUC issued a ruling that the California Environmental Quality Act applies and SPPC must supplement the application with a certified environmental document. 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 2002, SPPC experienced favorable market energy prices when compared with the previous four years. The decrease is reflective of FERC price cap regulation, which decreased electricity costs throughout the western United States. During 2002, SPPC experienced difficulty purchasing power in western energy markets due to counterparties' credit concerns with SPPC when its credit rating dropped below investment grade. With only a handful of counterparties willing to enter into agreements, SPPC found it necessary to 1) contract with energy marketers to transact on SPPC's behalf, and 2) negotiate special payment arrangements to satisfy credit concerns. If SPPC continues to experience financial difficulty or if its credit ratings are further downgraded, SPPC may experience considerable difficulty entering into new power supply contracts, particularly under traditional payment terms. If suppliers will not sell power to SPPC under traditional payment terms, SPPC may have to pre-pay its power requirements. If it does not have sufficient funds or access to liquidity to pre-pay its power requirements and is unable to obtain power through other means, SPPC's business, operations and financial condition would be materially adversely affected and could make it difficult for SPPC to continue to provide reliable service to its customers or to operate outside of bankruptcy. 23 SPPC is a member of the Northwest Power Pool and Western Systems Power Pool. These pools have provided SPPC further access to reserves and spot market power, respectively, in the Pacific Northwest and 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 supplies a higher percentage of its native load utilizing its fossil fuel generation. Currently, SPPC has contracted for a total of 75 MW of long-term firm purchased power from PacifiCorp. SPPC's firm purchase power contract is from June 1989 to February 28, 2009 and contains a 70% minimum purchase obligation. According to PURPA, SPPC is obligated under certain conditions to purchase the output produced by small power producers and co-generation facilities at costs determined by the appropriate state utility commission. As of December 31, 2002, SPPC had a total of 109 MW of maximum contractual firm capacity under 15 contracts with QFs. SPPC had contracts with three of the 15 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 CPUC, and have QF status as approved by the FERC. One long-term QF contract terminates in 2006, one terminates in 2039, and the remaining terminate between 2014 and 2022. Energy purchased by SPPC from QF contracts continues to provide useful diversity for SPPC in meeting its peak load. All the QFs from which SPPC makes firm purchases are either geothermal, hydroelectric or biomass.
NET CAPACITY QUALIFYING FACILITY CONTRACT START CONTRACT END (MW) ------------------- -------------- ------------ ------------ Empire 12/1/1987 12/1/2017 3 Soda Lake I/Soda Lake II 2/1/1987/8/1/1991 12/1/2017/6/1/2021 11 Amor IX Stillwater 5/1/1989 5/1/2019 13 Brady Power 7/1/1992 8/1/2022 20 Caithness Power 2/1/1988 2/1/2018 12 Steamboat I 12/5/1986 12/5/2006 5 Steamboat IA 12/14/1998 12/14/2018 2 Sierra Pacific Ind 11/1/1989 11/1/2019 10 Steamboat II 12/1/1992 12/1/2022 13 Steamboat III 12/1/1992 12/1/2022 13 Homestretch I 9/1/1984 9/1/2014 1 Homestretch II 6/1/1987 9/1/2017 1 Hooper 6/1/1983 6/1/2016 1 TCID (Lahontan) 6/1/1989 6/1/2039 4 ------- 109 =======
The actual QF firm capacity output under contract was 62 MW during the summer of 2002. The actual QF output for all non-utility generator deliveries during the summer 2002 peak was 263 MW. NPC also executed five power purchase agreements related to the purchase of renewable energy under the terms of which NPC sells the power associated with the renewable energy contracts located in northern Nevada to SPPC ("Related PPAs"). For these five non-solar PPAs involving suppliers in SPPC's service 24 territory, NPC will receive "Product" (Product is a defined term in the PPA that includes all Renewable Energy Credits "RECs" and energy supplied by the developer) from the renewable supplier at a delivery point on SPPC's transmission system and then NPC will immediately resell the energy to SPPC under the terms and conditions of a "Related PPA" (defined term in the original PPA). NPC will retain the RECs to comply with the requirements of SB 372, Nevada's renewable portfolio law. SPPC entered into a solar PPA with Duke Solar from the same facility located in NPC's service territory. NPC executed an additional Related PPA for this facility. For SPPC's solar PPA, SPPC will receive Product from the renewable supplier at a delivery point on NPC's transmission system and then SPPC will immediately resell the energy to NPC under the terms and conditions of the Related PPA. SPPC will retain the RECs to comply with SB 372. NPC expects to purchase 32 GWh of energy under the terms of the Related PPA. The terms for both SPPC and NPC's solar PPAs are 20 years. 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 180-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 was completed in July 2002. Construction started March 3, 2003 with an expected in-service date of May 2004. Total project costs incurred through December 31, 2002, were $32.8 million. Actual costs incurred in 2002 were $21.0 million. Estimated costs for 2003 are $46.5 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. 25 FUEL AVAILABILITY SPPC's 2002 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 1998-2002, 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 2002 4.42 41.10% 1.68 58.70% 5.69 0.20% 2001 5.63 45.30% 1.55 32.40% 6.49 22.30% 2000 4.99 66.60% 1.51 32.20% 7.62 1.20% 1999 2.71 62.30% 1.46 37.30% 3.41 0.40% 1998 2.12 60.70% 1.56 39.00% 3.96 0.30%
For a discussion of the change in fuel costs, see Results of Operations in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations. SPPC fully satisfied all volume requirements under a long-term contract with Black Butte Coal Company for coal shipments to Valmy, which terminated 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. The coal supply agreement for Valmy has been replaced with a new contract from Arch Coal for deliveries through December 31, 2006. 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 2002, 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, 2002, Valmy's coal inventory level was 257,740 tons, or approximately 45 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 2002, transportation of coal to Valmy was provided by the Union Pacific Railroad (UP) under a contract that will expire December 31, 2004. During 2002, SPPC operated the Pinon Pine facility exclusively on natural gas. No coal was purchased in 2002 for synthetic gas production in the plant's coal gasification facility. SPPC meets its needs for residual oil for generation through purchases on the spot market. The actual residual oil inventory level was 325,334 barrels as of December 31, 2002, 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 26 plants. The LDC accounted for $149.8 million in 2002 operating revenues or 13.9% of SPPC's revenues from continuing operations. Growth in SPPC's LDC service territory continues to be strong. Customer meter count growth during 2002 was approximately 3.7%. SPPC's total customer gas meter count increased by 4,520 to 126,382 meters by the end of 2002. Growth in all sectors is expected to continue due to the fact that new real estate developments in SPPC's distribution service area are under construction and planned for the near future. SPPC's forecast for growth in the number of LDC customers in 2003 is 4,800 meters. 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. As of March 13, 2003, there are 11 large customers securing their own supplies. These customers have a combined firm distribution load of 3,665 Dth per day. Three additional customers have announced intentions to begin securing their own supplies in mid 2003. Transportation customers continue to pay firm and interruptible distribution charges. These customers are responsible for procuring and paying for their own supply. To secure gas supplies for power generation and the LDC, SPPC contracted for firm winter, summer, and annual gas supplies with over a dozen Canadian and domestic suppliers to meet the firm requirements of its LDC and electric operations. Annual contracts totaled approximately 65,000 Dth per day. The winter period contracts totaled approximately 50,000 Dth per day, and the summer period contracts totaled approximately 9,000 Dth per day. 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 contract for LNG facility operated by Paiute Pipeline Company terminated on February 28, 2003. The Jackson Prairie facility contributed a total of 12,687 Dth per day of peaking supplies. A peaking transaction to Southwest Gas terminated on the same date. In November 1996 SPPC entered an agreement to sell winter seasonal peaking capacity supplies to another company over a seven-year period. The contract provides for the payment to SPPC of a monthly reservation charge, reimbursement of pipeline capacity charges during the winter, and a volumetric commodity charge based on the market price for natural gas. SPPC was able to enter into this agreement due to the ability of its power plants to utilize alternative fuels and its power importation option. The obligation to provide peaking supply terminated on February 28, 2003 coincident with the termination of the LNG contract and therefore no additional resources are required to meet Sierra load obligations. Following is a summary of SPPC's transportation and storage portfolio (as of December 31, 2002). Firm transportation capacity on the Northwest/Paiute system exists to serve primarily the LDC. Firm transportation capacity on the Pacific Gas & Electric Gas Transmission Northwest (PGT)/Tuscarora system exists primarily to serve SPPC's electric generating plants. Storage capacity is generally used for the peaking requirements of the LDC. 27 Transportation Capacity Northwest: 68,696 decatherms per day firm (annual) Paiute: 103,774 decatherms per day firm (November through March) 61,044 decatherms per day firm (April through October NOVA: 124,777 decatherms per day firm ANG: 128,105 decatherms per day firm PGT: 69,099 decatherms per day firm (annual) 60,270 decatherms per day firm (November through April) 24,500 decatherms per day firm (KG to Stanfield) Tuscarora: 127,601 decatherms per day firm (annual) Storage Capacity Williams: 281,242 decatherms inventory capability at Jackson Prairie 12,687 decatherms withdrawal capability per day from Jackson Prairie Paiute: 463,034 decatherms Inventory capability from LNG 35,078 decatherms withdrawal capability per day from LNG
Total LDC Dth supply requirements in 2001 and 2002 were 14.26 million Dth and 14.57 million Dth, respectively. Electric generating fuel requirements for 2001 and 2002 were 28.9 million Dth and 23.7 million Dth, respectively. In December 2002, the PUCN released its order regarding SPPC's Purchase Gas Adjustment filing made on July 1, 2002 and the new rates became effective January 1, 2003. An average residential customer received a decrease in their rates of approximately 3%. As of December 31, 2002, SPPC owned and operated 1,693 miles of three-inch equivalent natural gas distribution piping, 91 miles of which were added in 2002. Two significant projects were completed to improve distribution system's capacity in two high growth areas in south Reno where 5,600 feet of 18 inch main was installed and in northern Sparks where 4,531 feet of 8 inch main was installed. SALE OF WATER BUSINESS In June 2001, SPPC closed the sale of its water business to the 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 was required to refund to customers $21.5 million of the proceeds from the sale. The refund was credited on the electric bills of SPPC's former water customers over a fifteen-month period ended November 2002. Under a service contract with TMWA, SPPC provided customer service and billing services to TMWA until August 2002. SPPC continues to provide meter-reading services under a one-year service contract renewable in one-year increments by TMWA through 2008. On September 24, 2002, California Assembly Bill 1235 was approved which amended previous California legislation that prevented until 2006 private utilities from selling any power plants that provide energy to California customers. Transfer of the four hydroelectric facilities included in the contract of sale for an additional $8 million will require action by the CPUC. On November 9, 2002, SPPC filed an application with the CPUC for authority to sell the four hydroelectric plants. Not included in the sale were certain properties along the Truckee River related to the hydroelectric facilities and in California at Independence Lake. SPPC continues to own these properties with the intent of possible future sale. For further discussion of this item, see Generation Divestiture below. 28 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. In September 2002, the California Legislature approved an amendment, AB 1235, to AB 6 that would allow SPPC to complete the sale of the four hydroelectric units to TMWA. Section 851 of the Public Utilities Code requires review and approval of the sale by the CPUC. The sale of the Farad Hydroelectric Unit is conditioned on the completion of the reconstruction of the Farad dam and flume or assignment of SPPC insurance claim for reconstruction of the dam. The Farad Reconstruction Project is currently in the permitting phase with permits expected by mid-2003. The sales agreements for the six bundles provided that they terminate eighteen months after their execution unless the parties agreed to an earlier termination. The parties could have extended the termination another six months to obtain additional regulatory approvals. As a result of the legislative and regulatory developments which rendered the contracts impossible to perform, the Utilities 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. Those discussions ended without agreement to mutually terminate; however, all the contracts have now terminated in accordance with the contract provisions. As of December 31, 2002, the Utilities had incurred costs of approximately $20.1 million at NPC and $12.2 million at SPPC in order to prepare for the sale of generation assets. The Utilities requested recovery of these costs in each Utility's respective general rate case filings with the PUCN. The PUCN delayed recovery of the divestiture costs to a future rate case request but did grant a carrying charge on the costs until such time as recovery is allowed. A further discussion of the Regulation and Rate Proceedings is included in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operation. 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 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, and hazardous and toxic waste. SPR's Board of Directors has a 29 comprehensive environmental policy and a separate board committee that oversees NPC's, SPPC's, 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. The estimated cost of new controls is $1.1 billion. As a 14% owner in Mohave, NPC's cost could be $154 million. NPC's ownership interest in Mohave comprises approximately 10% of NPC's peak generation capacity. Southern California Edison (SCE) is the operating partner of Mohave. On May 17, 2002, SCE filed with the CPUC an application to address the future disposition of SCE's share of Mohave. Mohave obtains all of its coal supply from a mine in northeast Arizona on lands of the Navajo Nation and the Hopi Tribe (the Tribes). This coal is delivered from the mine to Mohave by means of a coal slurry pipeline which requires water that is obtained from groundwater wells located on lands of the Tribes in the mine vicinity. Due to the lack of progress in negotiations with the Tribes and other parties to resolve several coal and water supply issues, SCE's application states that it appears that it probably will not be possible for SCE to extend Mohave's operations beyond 2005. Due to the uncertainty over a post-2005 coal supply, SCE and the other Mohave co-owners have been prevented from commencing the installation of extensive pollution control equipment that must be put in place if Mohave's operations are extended past 2005. NPC is currently evaluating and analyzing all of its options with regard to the Mohave project. In May 1997, the Nevada Division of Environmental Protection (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 has been approved by NDEP. NDEP is expected to identify remediation requirements of contaminated groundwater resulting from these evaporation ponds by July 2003. New pond construction and lining costs are estimated at $15 million. 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 NPC to submit a corrective action plan. The extent of contamination has been determined and remediation is occurring at a modest rate. A hydro-geologic evaluation of the current remediation was completed, and a dual phase extraction remediation system, which has been approved by NDEP, will be constructed beginning in April 2003 at an estimated cost of $150,000. 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 approved in 30 June 2002. Remediation costs are expected to be approximately $100,000. In addition to remediation, NPC will spend $789,000 to line existing ponds. This project was started in 2002 and is expected to be completed in the first quarter 2003. 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. To date, EPA has not issued additional requests for further information. NEICO, a wholly owned subsidiary of NPC, 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 $4.8 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. The property is currently leased with the intention to reclaim coal fines with subsequent revenues and reduction to the reclamation bond. SIERRA PACIFIC POWER COMPANY In September 1994 Region VII of the EPA notified SPPC that it was being named as a potentially responsible party (PRP) regarding the past improper handling of Polychlorinated Biphenyls (PCB's) by PCB Treatment, Inc., in two buildings, one located in Kansas City, Kansas and the other in Kansas City, Missouri (the Sites). Prior to 1994, SPPC sent PCB contaminated material to PCB Treatment, Inc. for disposal. Certificates of disposal were issued to SPPC by PCB Treatment, Inc. however; the contaminated material was not disposed of, but remained on-site. A number of the largest PRP's formed a steering committee, which is chaired by SPPC. The steering committee has completed its site investigations and the EPA has determined that the Sites should be remediated by removing the buildings to the appropriate landfills. The EPA has issued an administrative order on consent requiring the steering committee to oversee the performance of the work. SPPC has recorded a preliminary liability for the Sites of $650,000 of which approximately $136,000 has been spent through December 31, 2002. The steering committee is obtaining cost estimates for removal of the buildings. Once these costs have been determined, SPPC will be in a better position to estimate and record the ultimate liabilities for the Sites. LANDS OF SIERRA 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 contamination resulting from an underground fuel tank that has been removed from the property. Additional contamination from a third party fuel tank on the property has also been identified and is undergoing remediation. The Lahontan Regional Water Quality Control Board has approved closure without additional remediation pending a one-year monitoring period. Final closure is anticipated in December 2003. 31 OTHER SUBSIDIARIES OF SIERRA PACIFIC RESOURCES TUSCARORA GAS PIPELINE COMPANY TGPC was formed as a wholly owned subsidiary of SPR in 1993 for the purpose of entering into a partnership with a wholly owned subsidiary of TransCanada PipeLines, Ltd., headquartered in Calgary, Alberta, Canada. The partnership, Tuscarora Gas Transmission Company (Tuscarora) was formed for the purpose of constructing and operating an interstate natural gas pipeline from Malin, Oregon to Reno, Nevada to serve an expanding gas market in Reno, northern Nevada, and northeastern California. In late 1995, Tuscarora completed the construction of its 229-mile pipeline system and began commercial operations on December 1, 1995. Tuscarora takes custody of its customers' gas near Malin, Oregon at a pipeline interconnect with PG&E Gas Transmission Northwest (PGT), the upstream pipeline. Upon custody transfer, Tuscarora transports its shippers' gas to various delivery points along the Tuscarora system as prescribed by its customers. PGT 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 PGT system provides Tuscarora customers access to Canadian natural gas reserves in the Western Canadian Sedimentary basin, one of the largest natural gas reserve basins in North America. As an interstate natural gas pipeline, Tuscarora provides only transportation service to its customers. SPPC was the largest customer at the start of commercial operations and continues to be Tuscarora's largest customer contributing 92% of gross revenues in 2002. In 2000, Tuscarora constructed a 14.2-mile pipeline lateral, establishing a new city gate for 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 per day in November 2001. Also in 2000, Tuscarora surveyed shipper interest in an expanded Tuscarora system and determined that there was a significant need for additional transportation capacity. By late year 2000, Tuscarora executed Precedent Agreements for new expansion capacity were obtained from four customers including SPPC (11,412 Dth/day), Morgan Stanley (20,000 Dth/day), Southwest Gas Corporation (24,500 Dth/day) and Duke Energy North America (Duke) (40,000 Dth/day). In January 2001, Tuscarora launched its 2002 Expansion Project on the strength of those binding agreements. On January 30, 2002, Tuscarora received its Certificate of Public Convenience and Necessity from the FERC authorizing Tuscarora to construct and operate the 2002 Expansion Project. At that time, Tuscarora requested that all expansion shippers execute Transportation Service Agreements (TSA) in accordance with the provisions of the Precedent Agreements. It became apparent to Tuscarora at that time that Duke would not be in a position to execute a TSA because their proposed generation plant, for which their portion of the expansion capacity would be used, was being delayed by at least one year due to conditions in the energy market. On February 25, 2002, Tuscarora filed to amend its FERC certificate authorization to allow phasing the construction of facilities to accommodate the Duke delay. The FERC subsequently approved the amendment whereby Tuscarora could construct sufficient facilities to serve the non-Duke related (Phase 1) expansion facilities in year 2002 and construct the Duke related (Phase 2) expansion facilities in year 2003. On May 8, 2002, Duke notified Tuscarora that it was canceling its proposed generation plant indefinitely and therefore it was terminating its Precedent Agreement with Tuscarora to avoid further exposure to expansion related costs. This action by Duke effectively reduced the expansion subscription from an original capacity requirement of 95,912 Dth/day to 55,912 Dth/day, reflecting the loss of the Duke capacity amount of 40,000 Dth/day. Tuscarora and Duke subsequently arrived at a termination fee and payment of that fee was made on January 8, 2003. Construction of the Phase 1 non-Duke related facilities was completed in late November 2002 and the facilities were placed into service on December 1, 2002. Those Phase 1 facilities included construction of two 6,000 horsepower (site rated) compressor stations located near the towns of Canby and Susanville, California 32 and 10.5 miles of 20-inch pipeline located in Washoe County, Nevada. Phase 1 facilities also established a new Tuscarora interconnect with the Paiute Pipeline Company located near Wadsworth, Nevada and included the installation of a 600 horsepower booster station at the Paiute interconnect site. Tuscarora has been seeking, without success, shipper interest in the Duke portion of the expansion capacity and has not yet filed for a certificate amendment to remove Phase 2 facilities from the expansion project. That amendment is scheduled to be filed with the FERC by the end of March 2003. Had Phase 2 facilities been constructed, they would have consisted of one 6,000 horsepower compression station located near Likely, California and 3.5 miles of 20-inch pipeline that would have extended service from the Paiute Pipeline interconnect to the location of the proposed Duke generation plant located near Wadsworth, Nevada. The expansion project increased Tuscarora's system capacity by approximately 51% and improved the overall reliability of the natural gas transportation system in the region. In May 2001, Tuscarora completed construction of approximately 3,520-feet of pipeline lateral to serve an existing 360 MW plant located east of Reno, Nevada near SPPC's Tracy Power Plant, and in September 2001 Tuscarora completed construction of a 10.8-mile pipeline lateral to serve two new customers located in California; the City of Susanville and the California Department of Corrections High Desert facility. 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, which it is currently marketing. Sierra Touch America LLC (STA), a partnership between SPC and Touch America, formerly Montana Power Company, was formed to construct a fiber optic line between Salt Lake City, Utah and Sacramento, CA. On September 9, 2002, SPC entered into an agreement to purchase and lease certain telecommunications and fiber optic assets from Touch America, subject to successful completion of the construction, in exchange for SPC's partnership units in Sierra Touch America and the execution of a $35 million promissory note for a total purchase price of $48.5 million. The assets are currently under construction and are scheduled for completion in June 2003. On September 11, 2002, SPC entered into an agreement to sell to a telecommunications carrier for $20 million the Sacramento to Salt Lake City conduit acquired from Touch America, and will convey all rights to the conduit when construction is completed in June 2003. For a discussion of the legal proceedings affecting SPC refer to Item 3, Legal Proceedings. 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 33 and power quality systems; energy performance contracting; end-use services; and ongoing energy monitoring and verification services. In September 1998, e-three and NEICO, a wholly owned subsidiary of NPC, formed e-three Customer 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. SEGMENT FINANCIAL INFORMATION For certain financial information concerning SPR and the Utilities business segments, see Note 18, Segment Information, in Notes to Financial Statements. 34 GENERAL - EMPLOYEES (ALL) SPR and its subsidiaries had 3,194 employees as of December 31, 2002, of which 1,745 were employed by NPC and 1,336 were employed by SPPC. NPC's current contract with the International Brotherhood of Electrical Workers (IBEW) Local No. 396, which covers approximately 57% of NPC's workforce, was renegotiated in February 2002 and is in effect until February 1, 2005. The three-year contract provides for a 3% general wage increase for bargaining unit employees effective February 2, 2002, with 3% increases in 2003 and 2004. In addition, the contract provides for participation by bargaining unit employees in the incentive compensation program. SPPC's current contract with the IBEW Local No. 1245, which represents approximately 63% of SPPC's workforce, was renegotiated in December 2002 and is in effect until December 31, 2005. The three-year contract provides for a 3% general wage increase for bargaining unit employees beginning January 13, 2003, with 3.25% and 3.75% increases in 2004 and 2005, respectively. 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 of Nevada 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 2002, the Utilities collected $70.8 million in franchise or other fees based on gross revenues. They collected $8.7 million in universal energy charges based on consumption. They also paid and recorded as an expense $0.5 million of fees based on net profits. The Utilities' non-exclusive local franchises or revocable permits are as follows:
LOCATION SERVICE EXPIRATION DATE -------- ------- --------------- NPC: Las Vegas Electric November 2029 Clark County Electric May 2004 Nye County Electric May 2006 City of Henderson (1) Electric November 1999 SPPC: Reno Electric, Gas and Water (2) January 2006 Sparks Electric May 2006 Sparks Gas May 2007 Sparks Water (2) April 2004 Carson City Electric (3) October 2032 City of Elko Electric April 2017 City of South Lake Tahoe Electric April 2018 Washoe County Gas and Water (2) May 2015 Washoe County Electric September 2015 Eureka County Electric July 2018
(1) Currently attempting to renegotiate. 35 (2) Water rights and obligations under the franchise agreements were assumed by TMWA in June 2001 upon the sale of SPPC's water business. (3) As part of the thirty-year Carson City franchise agreement signed in 1982, either side could request that the agreement be renegotiated on the tenth or twentieth anniversaries. Carson City exercised this option in 2002 and a new thirty-year franchise agreement was signed. As part of the agreement, SPPC agreed to be subject to Carson City's Business License Code for utilities, which has a fee of 2.5% of gross electric revenues received from customers within the consolidated municipality of Carson City, which increased by .5%. 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 Deutsche Bank Trust Company Americas, 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. 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 In 2000, Sierra Pacific Communications (SPC), a wholly owned subsidiary of SPR, and Touch America (formerly Montana Power), formed Sierra Touch America LLC (STA), a limited liability company whose primary purpose was to engage in communications and fiber optics business projects, including construction of a fiber optic line between Salt Lake City, Utah, and Sacramento, California. The conduits included in the line are to be sold to AT&T, PF Net Corporation, and STA. Construction is expected to be completed in the second quarter of 2003. The project sustained significant cost overruns and several complaints and mechanics liens have been filed by several contractors and subcontractors, including Williams Communications LLC, Bayport Pipeline Company, and Mastec North America. In September 2002, SPC conveyed its membership interest in STA to Touch America and obtained an indemnity for any liabilities associated with STA, all in exchange for 36 title to several fibers in the line and a $35 million promissory note. Several of the mechanics lienors have named SPC as the owner of the project and Bayport Pipeline has suggested it may amend its complaint to name SPC. See Note 9, Long-Term Debt, in Notes to Financial Statements, for additional information. 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 is 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. The dismissal was affirmed by the Ninth Circuit Court of Appeals, and TANC has now filed a writ of certiorari with the United States Supreme Court. Management believes the final outcome of the appeal is not likely to have a material adverse effect on SPPC's financial position or results of operation. Enron filed a complaint with the United States Bankruptcy Court for the Southern District of New York seeking to recover approximately $216 million and $93 million against NPC and SPPC, respectively, for liquidated damages for power supply contracts terminated by Enron in May 2002 and for power previously delivered to the Utilities. The Utilities have denied liability on numerous grounds, including deceit and misrepresentation in the inducement (including, but not limited to, misrepresentation as to Enron's ability to perform), and fraud, unfair trade practices and market manipulation. The Utilities filed motions to dismiss for lack of jurisdiction and/or for a stay of all proceedings pending the actions of the Utilities' proceedings under Section 206 of the Federal Power Act at the FERC (see Regulation and Rate Proceedings in Item 7). The Utilities have also filed proofs of claims and counterclaims against Enron, for the full amount of the approximately $300 million claimed to be owed and additional damages, as well as for unspecified damages to be determined during the case as a result of acts and omissions of Enron in manipulating the power markets. On December 19, 2002, the bankruptcy judge granted Enron's motion for partial summary judgment on Enron's claim for $17.7 million and $6.7 million, respectively, for energy delivered by Enron in April 2002, for which NPC and SPPC did not pay. The court ordered this money to be deposited into an escrow account not subject to claims of Enron's creditors and subject to refund depending on the outcome of the Utilities' FERC cases on the merits. The Utilities made the deposits as ordered. The bankruptcy court denied the Utilities' motion to stay the proceeding pending the outcome of the Utilities' Section 206 case at the FERC and denied the Utilities' motion to dismiss for lack of jurisdiction as to Enron's claims for power previously delivered to the Utilities. The court stated that it would rule in due course on Enron's motion for partial summary judgment to require NPC and SPPC to post $200 million and $87 million, respectively, pending the outcome of the case on the merits, and for judgment on the merits on Enron's liquidated damage claim (contract price less market price on the date of termination) relating to power it did not deliver under contracts terminated by Enron in May 2002. The court took under advisement the Utilities' motion to stay or dismiss Enron's claim for liquidated damages relating to the undelivered power and set a hearing on Enron's motion to dismiss the Utilities' counterclaims for April 3, 2003. The United States District Court for the Southern District of New York also denied the Utilities' motion to withdraw reference of the matter to the bankruptcy court without prejudice. The bankruptcy court currently has under submission (1) Enron's motion to dismiss the Utilities' counterclaims, (2) Enron's motion for partial summary judgment regarding the amounts alleged to be due for undelivered power and the posting of collateral for undelivered power, and (3) the Utilities' motion to dismiss or stay proceeding on Enron's claims relating to delivered power. Enron's motion to dismiss the Utilities' counterclaims is set for hearing on April 3, 2003. The Utilities are unable to predict the outcome of these 37 motions. A decision adverse to the Utilities on Enron's motion for partial summary judgment, or an adverse decision in the lawsuit with respect to liability as to Enron's claims on the merits for undelivered power, would have a material adverse effect on SPR's and the Utilities' financial condition and liquidity and could make it difficult for one or more of SPR, NPC or SPPC to continue to operate outside of bankruptcy. On September 5, 2002, Morgan Stanley Capital Group (MSCG) initiated an arbitration pursuant to the arbitration provisions in various power supply contracts terminated by MSCG in April 2002. In the arbitration, MSCG is requesting that the arbitrator compel NPC to pay MSCG $25 million pending the outcome of any dispute regarding the amount owed under the contracts. NPC claims that nothing is owed under the contracts on various grounds, including breach by MSCG in terminating the contracts, and further, that the arbitrator does not have jurisdiction over NPC's contract claims and defenses. In March 2003, the arbitrator ruled in NPC's favor and dismissed the arbitration in its entirety for lack of jurisdiction. Subsequently, NPC filed a complaint against MSCG on March 26, 2003, in the United States District Court, District of Nevada, alleging that (1) MSCG's demand was wrongful and constituted a breach of the Agreement, (2) MSCG failed to exercise reasonable discretion with respect to its demand, (3) the notice of termination was improperly served and in violation of the Agreement, and (4) MSCG failed to deliver the power as required under the Agreement. NPC is asking for declaratory relief, attorneys' fees and costs of suit and other relief as the Court deems appropriate. On September 30, 2002, plaintiffs Stephen A. Gordon and Gail M. Gordon filed a lawsuit in the District Court for Clark County, Nevada, seeking class action status for themselves and all shareholders of SPR against SPR and all of its directors for an alleged breach of fiduciary duty in failing to meaningfully evaluate and consider an alleged offer from the Southern Nevada Water Authority (SNWA) to purchase Nevada Power Company. The suit seeks extraordinary relief in the form of an injunction requiring the directors to carefully evaluate and consider such offer, formation of a special stockholders committee to ensure fair and adequate evaluation procedures, and for unspecified damages and/or punitive damages in the event the SNWA withdraws its alleged offer before it can be carefully evaluated. SPR intends to vigorously defend the suit. No answer or responsive pleading has yet been required nor have plaintiffs moved for class certification. On September 30, 2002, plaintiff John Anderson filed a virtually identical lawsuit seeking the same relief. On March 21, 2003, plaintiffs' counsel moved to consolidate the Gordon and Anderson cases with another virtually identical lawsuit filed by John Dedolph. The Company believes that the cases are without merit and plans to file motions to dismiss in the second quarter 2003. On October 21, 2002, Bonneville Square and Union Plaza filed a complaint seeking class certification in the Eighth District Court for Clark County, Nevada, against NPC for fraud and misrepresentation for allegedly overcharging a certain class of customers for energy delivered over the past several years. Plaintiffs allege that NPC fraudulently placed its meters and measured energy delivered at a point prior to passing through transformers during which process a certain amount of energy is dissipated as heat, instead of placing the meters after they pass through the transformer. NPC's motion to dismiss on jurisdictional grounds was denied and NPC is filing a writ before the Nevada Supreme Court, which is being joined in by the PUCN, which agrees with NPC that it has exclusive jurisdiction over the suit. NPC denies that the placement of the meters was fraudulent and alleges that placement of the meters was mandated by either or both customer request or applicable tariff. On April 22, 2002, Reliant Energy Services, Inc. (Reliant), filed and served a cross-complaint against NPC and SPPC in the wholesale electricity antitrust cases, which was consolidated in the Superior Court of the State of California. Plaintiffs in that case seek damages and restitution from the named defendants for alleged fraud, misrepresentation, and anticompetitive conduct in manipulating the energy markets in California resulting in prices far in excess of what would otherwise have been a fair price to the plaintiff class in a competitive market. Reliant filed cross-complaints against all energy suppliers selling energy in California who were not named as original defendants in the complaint, denying liability but alleging that if there is liability, it should spread among all energy suppliers. The trial court has held all answers to cross-claims in abeyance until such time as it decides demurrers filed by all the defendants. On May 3, 2002 and July 3, 2002, respectively, Reliant Resources and IDACORP Energy, L.P. (Idaho) terminated their power deliveries to NPC. On May 20, 2002 and July 30, 2002, Reliant Resources and Idaho asserted claims for $25.6 million and $8.9 million, respectively, under the Western System Power Pool Agreement 38 (WSPP) for liquidated damages under energy contracts that each company terminated before the delivery dates of the power. Such claims are subject to mandatory mediation and, in some cases, arbitration under the contracts. To date only Idaho has requested mediation of the contracts, which should be completed by the end of second quarter. NPC alleges that Idaho and Reliant Resources were participants in market manipulation in the West and therefore are not entitled to termination payments under the contract. In August 2002, El Paso Merchant Energy (EPME) terminated contracts for energy it had delivered to NPC under a program that called for delayed payment of the full contract price. In October 2002, EPME asserted a claim against NPC for $19 million in damages representing the approximate amount unpaid under the contracts. NPC alleges that EPME's termination resulted in net payments due to NPC under the WSPP liquidated damages provision as and for liquidated damages measured by the difference between the contract price and market price of energy EPME was to deliver from 2004 to 2012. Both claims are subject to mandatory mediation under the WSPP, but neither party has requested mediation at the present time. Refer to Regulation and Rate Proceedings in Item 7. 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. 39 PART II ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS (SPR) 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 2002 and 2001 are as follows:
Dividends Paid Per Share High Low --------------- ---------- ------------- 2002 First Quarter $ .200 $ 16.850 $ 14.710 Second Quarter .000 10.500 5.590 Third Quarter .000 8.500 5.270 Fourth Quarter .000 7.020 4.650 2001 First Quarter .250 16.500 10.560 Second Quarter .000 17.000 12.700 Third Quarter .200 17.180 14.150 Fourth Quarter .200 15.900 13.700
Number of Security Holders:
Title of Class Number of Holders -------------- ----------------- Common Stock: $1.00 Par Value As of December 31, 2002: 23,206
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 conditions and other matters within the discretion of the Board. The Board declared the most recent dividend on SPR's Common Stock on February 6, 2002. Since that time, the Board has determined not to pay a dividend on SPR's Common Stock. The Board will continue to review the factors described above 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 or assurance 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. See Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations for SPR and Note 13, Notes to Financial Statements, Dividend Restrictions, for a description of the restrictions on NPC's and SPPC's ability to pay dividends to SPR. 40 EQUITY COMPENSATION PLAN INFORMATION
Number of securities remaining available for Number of securities to be Weighted-average future issuance under issued upon exercise of exercise price of equity compensation plans outstanding options, outstanding options, (excluding securities Plan category warrants and rights warrants and rights reflected in column (a)) (a) (b) (c) - ---------------------------- ------------------------------ ------------------------- ----------------------------- Equity compensation plans approved by security holders: (1) Employee Stock Purchase Plan 614,335 shares (2) Long-Term Incentive Plan 1,287,216 shares $19.52 360,248 shares Total 974,583 shares
(1) SPPC established an Employee Stock Purchase Plan effective June 1, 1963 for the purpose of providing eligible employees with the opportunity to become stockholders of that corporation. In conjunction with SPR becoming the owner of all of SPPC's outstanding common stock, the Plan was amended to reflect that the sponsor of the Plan and the issuer of the stock to be purchased under the Plan would henceforth be SPR. Under SPR's Employee Stock Purchase Plan, eligible employees of SPR and any of its subsidiaries may save regularly by payroll deductions and twice each year use their savings to purchase SPR's Common Stock. (2) The Executive Long-Term Incentive Plan (the "LTIP") provides for the granting of stock options (both "nonqualified" and "qualified"), stock appreciation rights ("SAR's"), 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. 41 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 July 28, 1999 merger between SPR and NPC 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, for the year ended December 31, 1999, the table below reflects twelve months of information for NPC and five months of information for SPR and its pre-merger subsidiaries, and for the year ended December 31, 1998, reflects information for NPC only.
Year ended December 31, (dollars in thousands, except per share amounts) ------------------------------------------------------------------- 2002 2001 2000 1999 1998 ----------- ----------- ----------- ----------- ----------- Operating Revenues $ 2,991,703 $ 4,591,374 $ 2,336,113 $ 1,284,792 $ 873,682 =========== =========== =========== =========== =========== Operating Income (Loss) $ (33,056) $ 222,869 $ 126,385 $ 162,861 $ 147,277 =========== =========== =========== =========== =========== Net Income (Loss) from Continuing Operations $ (302,055) $ 33,566 $ (45,915) $ 50,410 $ 83,673 =========== =========== =========== =========== =========== Earnings (Deficit) from Continuing Operations Per Average Common Share - Basic $ (3.00) $ 0.34 $ (0.63) $ 0.77 $ 1.64 =========== =========== =========== =========== =========== Earnings (Deficit) from Continuing Operations Per Average Common Share - Diluted $ (3.00) $ 0.34 $ (0.63) $ 0.77 $ 1.64 =========== =========== =========== =========== =========== Total Assets $ 6,896,244 $ 7,992,076 $ 5,677,908 $ 5,235,917 $ 2,541,840 =========== =========== =========== =========== =========== Long-Term Debt and NPC Obligated Mandatorily Redeemable Preferred Trust Securities $ 3,251,755 $ 3,564,977 $ 2,371,051 $ 1,793,999 $ 1,089,099 =========== =========== =========== =========== =========== Dividends Declared Per Common Share $ 0.20 $ 0.40 $ 1.00 $ 1.17 $ 1.45 =========== =========== =========== =========== ===========
42 NEVADA POWER COMPANY
Year ended December 31, (dollars in thousands) ------------------------------------------------------------------- 2002 2001 2000 1999 1998 ----------- ----------- ----------- ----------- ----------- Operating Revenues $ 1,901,034 $ 3,025,103 $ 1,326,192 $ 977,262 $ 873,682 =========== =========== =========== =========== =========== Operating Income (Loss) $ (104,003) $ 144,364 $ 74,182 $ 116,983 $ 147,277 =========== =========== =========== =========== =========== Net Income (Loss) $ (235,070) $ 63,405 $ (7,928) $ 38,787 $ 83,673 =========== =========== =========== =========== =========== Total Assets $ 4,068,522 $ 4,704,606 $ 2,903,983 $ 2,724,329 $ 2,541,840 =========== =========== =========== =========== =========== Long-Term Debt and Obligated Mandatorily Redeemable Preferred Trust Securities $ 1,677,469 $ 1,796,839 $ 1,116,656 $ 1,119,876 $ 1,089,099 =========== =========== =========== =========== =========== Dividends Declared - Common Stock $ 10,000 $ 33,000 $ 64,267 $ 72,000 $ 73,715 =========== =========== =========== =========== ===========
SIERRA PACIFIC POWER COMPANY The table below, for the year ended December 31, 1998, includes information for SPPC's water business disposed of in 2001.
Year ended December 31, (dollars in thousands) ------------------------------------------------------------------- 2002 2001 2000 1999 1998 ----------- ----------- ----------- ----------- ----------- Operating Revenues $ 1,081,034 $ 1,547,430 $ 995,722 $ 709,374 $ 685,189 =========== =========== =========== =========== =========== Operating Income $ 55,292 $ 78,968 $ 45,409 $ 112,703 $ 114,263 =========== =========== =========== =========== =========== Net Income (Loss) from Continuing Operations $ (13,968) $ 22,743 $ (4,077) $ 64,615 $ 84,475 =========== =========== =========== =========== =========== Total Assets $ 2,398,490 $ 2,706,976 $ 2,208,389 $ 2,084,707 $ 2,011,820 =========== =========== =========== =========== =========== Long-Term Debt $ 914,788 $ 923,070 $ 654,316 $ 673,930 $ 654,950 =========== =========== =========== =========== =========== Dividends Declared - Common Stock $ 44,900 $ 63,000 $ 85,000 $ 76,000 $ 76,000 =========== =========== =========== =========== ===========
43 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, CURRENTLY PENDING AND TO BE FILED BY NPC AND SPPC (THE UTILITIES) WITH THE PUBLIC UTILITIES COMMISSION OF NEVADA (PUCN), INCLUDING THE PERIODIC APPLICATIONS 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 ADDITIONAL UNFAVORABLE RULINGS BY THE PUCN, A FURTHER DOWNGRADE OF THE CURRENT DEBT RATINGS OF SPR, NPC, OR SPPC, AND/OR ADVERSE DEVELOPMENTS WITH RESPECT TO NPC'S OR SPPC'S POWER AND FUEL SUPPLIERS; (3) WHETHER NPC'S ABILITY TO PAY SPR DIVIDENDS WILL BE RESTORED IN THE NEAR FUTURE, AND WHETHER SPPC WILL BE ABLE TO CONTINUE TO PAY SPR DIVIDENDS UNDER THE TERMS OF SPPC'S FINANCING AGREEMENTS AND/OR RESTATED ARTICLES OF INCORPORATION; (4) 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; (5) WHETHER SUPPLIERS, SUCH AS ENRON, WHICH HAVE TERMINATED THEIR POWER SUPPLY CONTRACTS WITH NPC AND/OR SPPC WILL BE SUCCESSFUL IN PURSUING THEIR CLAIMS AGAINST THE UTILITIES FOR LIQUIDATED DAMAGES UNDER THEIR POWER SUPPLY CONTRACTS, AND WHETHER ENRON WILL BE SUCCESSFUL IN ITS LAWSUIT AGAINST NPC AND SPPC; (6) WHETHER SPR, NPC, AND SPPC WILL BE ABLE TO MAINTAIN SUFFICIENT STABILITY WITH RESPECT TO THEIR LIQUIDITY AND RELATIONSHIPS WITH SUPPLIERS; (7) WHETHER CURRENT SUPPLIERS OF PURCHASED POWER, NATURAL GAS, OR FUEL TO NPC OR SPPC WILL CONTINUE TO DO BUSINESS WITH NPC OR SPPC OR WILL TERMINATE THEIR CONTRACTS AND SEEK LIQUIDATED DAMAGES FROM THE RESPECTIVE UTILITY; (8) WHETHER THE UTILITIES WILL NEED TO PURCHASE ADDITIONAL POWER ON THE SPOT MARKET TO MEET UNANTICIPATED POWER DEMANDS (FOR EXAMPLE, DUE TO UNSEASONABLY HOT WEATHER) AND WHETHER 44 SUPPLIERS WILL BE WILLING TO SELL SUCH POWER TO THE UTILITIES IN LIGHT OF THEIR WEAKENED FINANCIAL CONDITION; (9) WHETHER SPPC WILL BE ABLE TO MAKE THE GASIFIER FACILITY AT THE PINON PINE POWER PROJECT OPERATIONAL AND, IN ANY EVENT, WHETHER SPPC WILL BE SUCCESSFUL IN OBTAINING PUCN APPROVAL TO RECOVER THE COSTS OF THE GASIFIER IN A FUTURE GENERAL RATE CASE; (10) WHETHER NPC AND SPPC WILL BE SUCCESSFUL IN OBTAINING PUCN APPROVAL TO RECOVER GOODWILL AND OTHER MERGER COSTS RECORDED IN CONNECTION WITH THE 1999 MERGER BETWEEN SPR AND NPC IN A FUTURE GENERAL RATE CASE; (11) WHOLESALE MARKET CONDITIONS, INCLUDING AVAILABILITY OF POWER ON THE SPOT MARKET, WHICH AFFECT THE PRICES THE UTILITIES HAVE TO PAY FOR POWER AS WELL AS THE PRICES AT WHICH THE UTILITIES CAN SELL ANY EXCESS POWER; (12) THE OUTCOME OF THE UTILITIES' PENDING LAWSUITS IN NEVADA STATE COURT SEEKING TO REVERSE PORTIONS OF THE PUCN'S ORDERS DENYING THE RECOVERY OF DEFERRED ENERGY COSTS, INCLUDING THE OUTCOME OF PETITIONS FILED BY THE BUREAU OF CONSUMER PROTECTION OF THE NEVADA ATTORNEY GENERAL'S OFFICE SEEKING ADDITIONAL DISALLOWANCES; (13) WHETHER THE UTILITIES WILL BE ABLE, EITHER THROUGH FEDERAL ENERGY REGULATORY COMMISSION (FERC) PROCEEDINGS OR NEGOTIATION, TO OBTAIN LOWER PRICES ON THEIR LONGER-TERM PURCHASED POWER CONTRACTS ENTERED INTO DURING 2000 AND 2001 THAT ARE PRICED ABOVE CURRENT MARKET PRICES FOR ELECTRICITY; (14) THE EFFECT THAT ANY FUTURE TERRORIST ATTACKS, WARS OR THREATS OF WAR MAY HAVE ON THE TOURISM AND GAMING INDUSTRIES IN NEVADA, PARTICULARLY IN LAS VEGAS, AS WELL AS ON THE ECONOMY IN GENERAL; (15) 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; (16) INDUSTRIAL, COMMERCIAL, AND RESIDENTIAL GROWTH IN THE SERVICE TERRITORIES OF THE UTILITIES; (17) THE LOSS OF ANY SIGNIFICANT CUSTOMERS; (18) THE EFFECT OF EXISTING OR FUTURE NEVADA, CALIFORNIA, OR FEDERAL LEGISLATION OR REGULATIONS AFFECTING ELECTRIC INDUSTRY RESTRUCTURING, INCLUDING LAWS OR REGULATIONS WHICH COULD ALLOW ADDITIONAL CUSTOMERS TO CHOOSE NEW ELECTRICITY SUPPLIERS OR CHANGE THE CONDITIONS UNDER WHICH THEY MAY DO SO; (19) 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, INCLUDING THE EFFECT ON THE NEVADA GAMING INDUSTRY OF THE OPENING OF ADDITIONAL INDIAN GAMING ESTABLISHMENTS IN CALIFORNIA AND OTHER STATES; (20) CHANGES IN ENVIRONMENTAL REGULATIONS, TAX, OR ACCOUNTING MATTERS OR OTHER LAWS AND REGULATIONS TO WHICH THE UTILITIES ARE SUBJECT; (21) FUTURE ECONOMIC CONDITIONS, INCLUDING INFLATION OR DEFLATION RATES AND MONETARY POLICY; 45 (22) FINANCIAL MARKET CONDITIONS, INCLUDING CHANGES IN AVAILABILITY OF CAPITAL OR INTEREST RATE FLUCTUATIONS; (23) UNUSUAL OR UNANTICIPATED CHANGES IN NORMAL BUSINESS OPERATIONS, INCLUDING UNUSUAL MAINTENANCE OR REPAIRS; AND (24) 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, in the case of SPPC, they are also subject to the California Public Utility Commission (CPUC) 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. Regulatory assets represent incurred costs that have been deferred because it is probable they will be recovered through future rates collected from customers. Regulatory liabilities generally represent obligations to make refunds to customers for previous collections for costs that are not likely to be incurred. Management regularly assesses whether the regulatory assets are probable of future recovery by considering factors such as applicable regulatory environment changes and the status of any pending or potential deregulation legislation. Although current rates do not include the recovery of all existing regulatory assets as discussed further below and in Note 1 in Notes to Financial Statements, management believes the existing regulatory assets are probable of recovery. This determination reflects the current political and regulatory climate in the state, and is subject to change in the future. If future recovery of costs ceases to be probable, the write-off of regulatory assets would be required to be recognized as a charge or expensed in current period earnings. Regulatory Accounting affects other Critical Accounting Policies, including Deferred Energy Accounting, Accounting for Goodwill and Merger Costs, Accounting for Generation Divestiture Costs, Impairment of Long-Lived Assets, and Accounting for Derivatives and Hedging Activities, all of which are discussed immediately below. 46 DEFERRED ENERGY ACCOUNTING On April 18, 2001, the Governor of Nevada signed into law Assembly Bill 369 (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 implemented 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 statement of operations 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 under the statute to recover, a carrying charge on such deferred balances. The Utilities are 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 Energy Supply, later, for a discussion of the Utilities' purchased power procurement strategies, and Commodity Price Risk in Item 7A, Quantitative and Qualitative Disclosures About Market Risk, for a discussion of the Utilities' commodity risk management program. As discussed above, deferred energy accounting facilitates the recovery of costs incurred to procure fuel and purchased power for SPPC and NPC. As described in more detail under Regulation and Rate Proceedings, Nevada Matters, Nevada Power Company 2001 Deferred Energy Case, on November 30, 2001, NPC filed an application with the PUCN seeking to establish a Deferred Energy Accounting Adjustment (DEAA) rate to clear deferred balances for purchased fuel and power costs accumulated between March 1, 2001 and September 30, 2001. The application sought to establish a rate to clear accumulated purchased fuel and power costs of $922 million and spread the cost recovery over a period of not more than three years. On March 29, 2002, the PUCN issued its decision on the deferred energy application, disallowing $434 million of deferred purchased fuel and power costs, and allowing NPC to collect the remaining $478 million over three years beginning April 1, 2002. As a result of this disallowance, NPC wrote off $465 million of deferred energy costs and related carrying charges, the two major national rating agencies immediately downgraded the credit rating on SPR's, NPC's and SPPC's debt securities (followed by further downgrades late in April), and the market price of SPR's common stock fell substantially. As described in more detail under Regulation and Rate Proceedings, Nevada Matters, Sierra Pacific Power Company 2002 Deferred Energy Case, SPPC filed an application with the PUCN seeking to establish a DEAA rate to clear its deferred balances for purchased fuel and power costs accumulated between March 1, 2001 and November 30, 2001. The application sought to establish a rate to clear accumulated purchased fuel and power costs of $205 million and spread the cost recovery over a period of not more than three years. On May 28, 2002, the PUCN issued its decision on SPPC's deferred energy application, disallowing $53 million of deferred purchased fuel and power costs, and allowing SPPC to collect the remaining $150 million over three years beginning June 1, 2002. As a result of this decision, SPPC wrote off $58 million of disallowed deferred energy costs and related carrying charges. 47 Both Utilities have continued to be entitled under AB 369 to utilize deferred energy accounting for their electric operations. Because of contracts entered into during the Western energy crisis in 2001 to assure adequate supplies of electricity for their customers, the Utilities incurred fuel and purchased power costs in excess of amounts they were permitted to recover in current rates. As a result, during 2002 both Utilities continued to record additional amounts in their deferral of energy costs accounts. On November 14, 2002, NPC filed an application with the PUCN seeking to clear deferred balances of $195.7 million for purchased fuel and power costs accumulated between October 1, 2001, and September 30, 2002, and to spread the recovery of the deferred costs, together with a carrying charge, over a period of not more than three years. Intervenors filed their direct testimony on March 7, 2003 calling for disallowances between approximately $83 and $300 million of the total fuel and purchased power costs. The largest of the proposed disallowances are based on the same alleged imprudence as found in the PUCN order for NPC's 2001 Deferred Energy Case relating to NPC's failure to enter into power contracts in 1999. Some Intervenors' testimony, in the current case, argue in favor of this disallowance based on the last Deferred order but did not quantify their proposals and in some cases would be additive to the ranges stated above. The PUCN Staff does not support this disallowance but calculated a range of $116 to $347 million in the event that the PUCN disallows deferred energy costs based upon the same alleged imprudence cited by the PUCN in its 2001 decision relative to this issue. While all Intervenors call for the PUCN to reduce NPC's requested energy rates for recovery of past energy costs, some also propose to increase customers' energy rates for purchases that will occur during the upcoming deferred accounting period. On January 14, 2003, SPPC filed an application with the PUCN seeking to clear deferred balances of $15.4 million for purchased fuel and power costs accumulated between December 1, 2001, and November 30, 2002, and to spread the recovery of the deferred costs, together with a carrying charge, over a period of not more than three years. A significant disallowance in either or both of these deferred energy rate cases or in future cases to be filed by either Utility would have a material adverse affect on the future financial position, results of operations, and liquidity of SPR, NPC, and SPPC and could make it difficult for one or more of SPR, NPC or SPPC to continue to operate outside of bankruptcy. See Regulation and Rate Proceedings, later, for additional discussion of the regulatory process underway to recover these deferred costs. If not for deferred energy accounting during 2001 and 2002, 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 current deferrals permitted by the deferred energy accounting provisions of AB 369, the reported net losses of SPR, NPC, and SPPC for 2002 of ($307.5) million, ($235.1) million, and ($17.9) million would have been (net of income tax) reported as net losses (including the write-offs resulting from the disallowances discussed above) of ($495.9) million, ($379.7) million and ($61.6) million, respectively. Similarly, 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 and $45.9 million would have been (net of income tax) reported as net losses of ($715.4) million, ($573.6) million and ($89.1) million, respectively. ACCOUNTING FOR GOODWILL AND MERGER COSTS The order issued by the PUCN in December 1998 approving the merger of SPR and NPC directed both NPC and SPPC to defer three categories of merger costs to be reviewed for recovery through future rates. That order specifically directed both Utilities to defer merger transaction costs, transition costs and goodwill costs for 48 a three-year period. The deferral of these costs was intended to allow adequate time for the anticipated savings from the merger to develop. At the end of the three-year period, the order instructs the Utilities to propose an amortization period for the merger costs and allows the Utilities to recover the costs to the extent they are offset by merger savings. Costs deferred as a result of the PUCN order were $331.2 million of goodwill and $62.2 million in other merger costs as of December 31, 2002. The deferred other merger costs consist of $40.5 million of transaction and transition costs and $21.7 million of employee separation costs. Employee separation costs were comprised of $17.2 million of employee severance, relocation and related costs, and $4.5 million of pension and post-retirement benefits net of plan curtailment gains. 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, requests to recover deferred merger costs, including goodwill. In its decisions dated March 27, 2002, and May 28, 2002, for NPC and SPPC, respectively the PUCN decided not to make any determination on the recovery of merger costs until general rate cases are filed with test years ending on or after December 31, 2002. However, the PUCN did instruct the Utilities to continue to recognize these costs as deferred assets without carrying charges. The extent to which goodwill and merger costs will be recovered in future revenues and the timing of those recoveries is expected to be determined in general rate cases that are required to be filed in 2003. To the extent that the Utilities are not permitted to recover any portion of goodwill in future rates, the amount not recoverable will be reviewed for impairment and accounted for under the provisions of SFAS No. 142. A significant disallowance of goodwill or merger costs by the PUCN could have a material adverse affect on the future financial condition, results of operations and liquidity of SPR, NPC, and SPPC and could make it difficult for one or more of SPR, NPC, or SPPC to continue to operate outside of bankruptcy. ACCOUNTING FOR GENERATION DIVESTITURE COSTS As a condition to its approval of the merger between SPR and NPC, the Utilities filed, and in February 2000 the PUCN approved, a revised Divestiture Plan stipulation for the sale of the Utilities' generation assets. 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. 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. In September 2002, the California Legislature approved an exemption to AB 6 that would allow SPPC to complete the sale of the hydroelectric units to TMWA subject to review and approval of the sale by the CPUC. The sales agreements for the six bundles provided that they terminate eighteen months after their execution, and all of the agreements have now terminated in accordance with their respective provisions. As of December 31, 2002, NPC and SPPC had incurred costs of approximately $20.1 million and $12.2 million, respectively, in order to prepare for the sale of generation assets. In the fourth quarter of 2001 each Utility requested recovery of its respective costs in its application for a general rate increase filed with the PUCN. In 2002 the PUCN delayed recovery of divestiture costs to future rate case requests but did grant a carrying charge 49 on the costs until such time as recovery is allowed. To the extent that the Utilities are not permitted to recover any portion of these costs in future rates, the disallowed costs and related carrying charges would be required to be written off in current period earnings. IMPAIRMENT OF LONG-LIVED ASSETS SPR and the Utilities evaluate their Utility Plant and definite-lived tangible assets for impairment whenever indicators of impairment exist. As discussed in more detail in Note 21 of Notes to Financial Statements, Pinon Pine, SPPC owns a combined cycle generation facility, a post-gasification facility, and, through its wholly owned subsidiaries, owns a gasifier that are collectively referred to as the Pinon Pine Power Project ("Pinon Pine"). Construction of Pinon Pine was completed in June 1998. Included in the Consolidated Balance Sheets of SPR and SPPC is the net book value of the gasifier and related assets, which is approximately $100 million as of December 31, 2002. To date, SPPC has not been successful in obtaining sustained operation of the gasifier. In 2001 SPPC retained an independent engineering consulting firm to complete a comprehensive study of the Pinon Pine gasification plant. SPPC received a final report of the study in November 2002. SPPC is reviewing the various options outlined in the study. If after evaluating the options presented in the draft report, SPPC decides not to pursue modifications intended to make the facility operational, SPPC intends to seek recovery, net of salvage, through regulated rates in its next general rate case based, in part, on the PUCN's approval of Pinon Pine as a demonstration project in an earlier resource plan. However, 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. ACCOUNTING FOR 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 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. 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. Fuel and purchased power costs are subject to deferred energy accounting. 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 operations and comprehensive income. Upon settlement of a derivative instrument, actual fuel and purchased power costs are recognized if they are currently recoverable or deferred if they are recoverable or payable through future rates. 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. 50 At December 31, 2002, the fair value of the derivatives resulted in the recording of $30 million, $29 million, and $1 million in risk management assets and $74 million, $30 million, and $44 million in risk management liabilities in the Consolidated Balance Sheets of SPR, NPC, and SPPC, respectively. Net risk management regulatory assets of $45 million, $2 million, and $44 million were recorded in the Consolidated Balance Sheets of SPR, NPC, and SPPC, respectively at December 31, 2002. SPR and the Utilities have other non-energy related derivative instruments such as interest rate swaps. The transition adjustment related to these types of derivative instruments resulting from the adoption of SFAS No. 133 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 Other comprehensive income until the related transactions are settled or terminate, at which time the amounts are reclassified into earnings. On April 1, 2002, SPR paid $9.5 million to terminate an interest rate swap related to $200 million of SPR floating rate notes maturing April 20, 2003, of which $7.3 million was reclassified into earnings during the twelve-month period ended December 31, 2002. ENVIRONMENTAL CONTINGENCIES SPR and its subsidiaries are subject to federal, state and local regulations governing air and 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 and water quality, solid, and hazardous and toxic waste. SPR and its subsidiaries are subject to rising costs that result from a steady increase in the number of federal, state and local laws and regulations designed to protect the environment. These laws and regulations can result in increased capital, operating, and other costs as a result of compliance, remediation, containment and monitoring obligations, particularly with laws relating to power plant emissions. In addition, SPR or its subsidiaries may be a responsible party for environmental clean up at a site identified by a regulatory body. The management of SPR and its subsidiaries cannot predict with certainty the amount and timing of all future expenditures related to environmental matters because of the difficulty of estimating clean up costs and compliance and the possibility that changes will be made to the current environmental laws and regulations. There is also uncertainty in quantifying liabilities under environmental laws that impose joint and several liability on all potentially responsible parties. SPR and its subsidiaries accrue for environmental costs only when they can conclude that it is probable that they have an obligation for such costs and can reasonably determine the amount of such costs. Note 17 of Notes to Financial Statements, Commitments and Contingencies, discusses the environmental matters of SPR and its subsidiaries that have been identified, and the estimated financial effect of those matters. To the extent that (1) actual results differ from the estimated financial effects, (2) there are environmental matters not yet identified for which SPR or its subsidiaries are determined to be responsible, or (3) the Utilities are unable to recover through future rates the costs to remediate such environmental matters, there could be a material adverse effect on the financial condition and future liquidity and results of operations of SPR and its subsidiaries. 51 LITIGATION CONTINGENCIES Note 17 of Notes to Financial Statements, Commitments and Contingencies, discusses the significant legal matters of SPR and its subsidiaries. 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. DEFINED BENEFIT PLANS AND OTHER POSTRETIREMENT PLANS As further explained in Note 14 of Notes to Financial Statements, Retirement Plan and Post-Retirement Benefits, SPR maintains a pension plan as well as other postretirement benefit plans that provide health and life insurance for retired employees. All employees are eligible for these benefits if they reach retirement age while still working for SPR or its subsidiaries. These costs are determined in accordance with the provisions of SFAS No. 87, "Employers' Accounting for Pensions," and SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," and ultimately collected in rates billed to customers. The amounts funded are then used to meet benefit payments to plan participants. SPR contributed $41.1 million and $13.8 million to its pension plan, and $0.2 million and $0.7 million to the other postretirement benefits plan in 2002 and 2001, respectively. Due to the sharp decline in United States equity markets since the third quarter of 2000, the value of a significant portion of the assets held in the plans' trusts to satisfy the obligations of the plans has decreased significantly. As a result, additional contributions may be required in the future to meet the requirements of the plan to pay benefits to plan participants. PENSION PLANS SPR's reported costs of providing non-contributory defined pension benefits (described in Note 14 of Notes to Financial Statements, Retirement Plan and Post-Retirement Benefits) are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience. For example, pension costs are impacted by actual employee demographics (including age and employment periods), the level of contributions SPR makes to the plan, and earnings on plan assets. Changes made to the provisions of the plan may also impact current and future pension costs. Pension costs may also be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets and the discount rates used in determining the projected benefit obligation and pension costs. In accordance with SFAS No. 87, changes in pension obligations associated with these factors may not be immediately recognized as pension costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. As such, significant portions of pension costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants. For the twelve months ended December 31, 2002, 2001, and 2000, SPR recorded pension benefit expense of approximately $22.5 million, $14.2 million, and $12.5 million, respectively, in accordance with the provisions of SFAS No. 87. Actual payments of benefits made to retirees for the twelve months ended September 30, 2002 and 2001, were $30.0 million and $36.4 million, respectively. SPR has made no changes to pension plan provisions in 2002, 2001, and 2000 that have had any significant impact on recorded pension amounts. As further described in Note 14 of Notes to Financial Statements, Retirement Plan and Post-Retirement Benefits, SPR has revised the discount rate in 2002 as compared to 2001 and 2000. This change did not have a significant impact on reported pension costs in 2002. SPR's pension plan assets are primarily made up of equity and fixed income investments. Fluctuations in actual equity market returns as well as changes in general interest rates may result in increased or decreased 52 pension costs in future periods. Likewise, changes in assumptions regarding current discount rates and expected rates of return on plan assets could also increase or decrease recorded pension costs. The following chart reflects the sensitivities associated with a change in certain actuarial assumptions by the indicated percentage. While the chart below reflects an increase in the percentage for each assumption, SPR and its actuaries expect that the inverse of this change would impact the projected benefit obligation (PrBO) and the reported annual pension cost on the income statement (PeC) by a similar amount in the opposite direction. Each sensitivity below reflects an evaluation of the change based solely on a change in that assumption only.
Actuarial Assumption Change in Assumption Impact on PrBO Impact on PeC ($ millions) Incr/(Decr) Incr/(Decr) Incr/(Decr) -------------------- -------------------- -------------- ------------- Discount Rate 1% $ (45.0) $ (4.9) Rate of Return on Plan Assets 1% $ -- $ (2.7)
In selecting an assumed discount rate, SPR considered the yield on high quality bonds as measured by the Moody's Investors Service, Inc. (Moody's) Aa composite bond index. In selecting an assumed rate of return on plan assets, SPR considers past performance and economic forecasts for the types of investments held by the plan. The market value of SPR's plan assets has been affected by sharp declines in equity markets since the third quarter of 2000. Plan assets earned $51.1 million in 2000 and lost $39.3 million and $23.1 million in 2001 and 2002, respectively. As a result of SPR's plan asset returns at September 30, 2002, SPR was required to recognize an additional minimum liability in the amount of $89.6 million, as prescribed by SFAS No. 87. The liability was recorded as a reduction to common equity through a charge to Accumulated Other Comprehensive Income, and did not affect net income for 2002. The charge to Accumulated Other Comprehensive Income will be restored through common equity in future periods to the extent fair value of trust assets exceeds the accumulated benefit obligation. Pension cost and cash funding requirements could increase in future years without a substantial recovery in the equity markets. OTHER POSTRETIREMENT BENEFITS SPR's reported costs of providing other postretirement benefits (described in Note 14 of Notes to Financial Statements, Retirement Plan and Post-Retirement Benefits) are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience. For example, other postretirement benefit costs are impacted by actual employee demographics (including age and employment periods), the level of contributions made to the plan, earnings on plan assets, and health care cost trends. Changes made to the provisions of the plan may also impact current and future other postretirement benefit costs. Other postretirement benefit costs may also be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets and the discount rates used in determining the postretirement benefit obligation and postretirement costs. For the twelve months ended December 31, 2002, 2001, and 2000, SPR recorded other postretirement benefit expense of approximately $3.1 million, $2.5 million, and $2.6 million, respectively, in accordance with 53 the provisions of SFAS No. 106. Actual payments of benefits made to retirees for the twelve months ended September 30, 2002, and 2001, were $6.9 million and $4.6 million, respectively. SPR has made no changes to other postretirement benefit plan provisions in 2002, 2001, and 2000 that have had any significant impact on recorded benefit plan amounts. As further described in Note 14 of Notes to Financial Statements, Retirement Plan and Post-Retirement Benefits, SPR has revised the discount rate in 2002 as compared to 2001 and 2000. This change did not have a significant impact on reported other postretirement benefit costs in 2002. However, in determining the other postretirement benefit obligation and related cost, these assumptions can change from period to period, and such changes could result in material changes to such amounts. SPR's other postretirement benefit plan assets are primarily made up of equity and fixed income investments. Fluctuations in actual equity market returns as well as changes in general interest rates may result in increased or decreased other postretirement benefit costs in future periods. Likewise, changes in assumptions regarding current discount rates and expected rates of return on plan assets could also increase or decrease recorded other postretirement benefit costs. The following chart reflects the sensitivities associated with a change in certain actuarial assumptions by the indicated percentage. While the chart below reflects an increase in the percentage for each assumption, SPR and its actuaries expect that the inverse of this change would impact the projected accumulated other postretirement benefit obligation (APBO) and the reported annual other postretirement benefit cost on the income statement (PBC) by a similar amount in the opposite direction. Each sensitivity below reflects an evaluation of the change based solely on a change in that assumption only.
Actuarial Assumption Change in Assumption Impact on APBO Impact on PBC ($ millions) Incr/(Decr) Incr/(Decr) Incr/(Decr) -------------------- -------------------- -------------- ------------- Discount Rate 1% $ (15.7) $ (1.5) Health Care Cost Trend Rate 1% $ 14.9 $ 1.5 Rate of Return on Plan Assets 1% N/A $ (0.5)
In selecting an assumed discount rate, SPR considered the yield on high quality bonds as measured by Moody's Aa composite bond index. In selecting an assumed rate of return on plan assets, SPR considers past performance and economic forecasts for the types of investments held by the plan. The market value of the SPR's plan assets has been affected by sharp declines in equity markets since the third quarter of 2000. Plan assets increased in value $17.3 million in 2000 and lost $15.8 million and $6.8 million in 2001 and 2002, respectively. Also, other postretirement benefit cost and cash funding requirements could increase in future years without a substantial recovery in the equity markets. COST CAPITALIZATION POLICIES The Utilities continue to devote substantial resources in 2003 on the Centennial Transmission project at NPC and the Falcon to Gonder Transmission project at SPPC. In addition, certain operating units of the Utilities are charged with maintaining, repairing and replacing components of generation, transmission and distribution systems both on a scheduled basis and on an as-needed basis. As described in Note 1 of Notes to 54 Financial Statements, Summary of Significant Accounting Policies, the cost of additions, including betterments and replacements of units of property, is charged to utility plant. When units of property are replaced, renewed or retired, their cost, plus removal or disposal costs less salvage, is charged to accumulated depreciation. Certain direct and indirect costs are capitalized, including the cost of debt and equity capital associated with construction and retirement activity as prescribed by Generally Accepted Accounting Principles (GAAP) and the FERC's Uniform System of Accounts. The indirect construction overhead costs capitalized are based upon the following cost components: the cost of time spent by administrative employees in planning and directing construction; property taxes; employee benefits including such costs as pensions, postretirement and post employment benefits, vacations and payroll taxes; and an allowance for funds used during construction (AFUDC). The level of indirect construction overhead costs capitalized by the Utilities is based upon real-time construction activity. Accordingly, payroll and other costs capitalized will fluctuate based upon seasonal construction activities and the deployment of resources to those efforts. During periods of higher maintenance levels, these payroll and other costs will not be capitalized. As such, operating income could be impacted by the manner in which payroll and related costs are deployed. However, the total cash flow of the Utilities is not impacted by the allocation of these costs to various construction or maintenance activities. In 2002, the Utilities capitalized approximately $5.2 million of AFUDC as a result of construction activity financed primarily by their debt. This amount is a non-cash component reflected in the Consolidated Statements of Operations and has no impact on the operating cash flow. Recognition of AFUDC 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, all capital costs charged for Utility services. DEPRECIATION EXPENSE The Utilities have a significant investment in electric plant. SPPC also has an investment in gas distribution plant. Depreciable assets of generation, transmission and distribution operations represent approximately 92% of the Utilities' investment in utility plant. As described in Note 1 to Notes to Financial Statements, Summary of Significant Accounting Policies, the Utilities depreciate these assets utilizing a composite rate, which currently includes a component for net negative salvage. These assets are depreciated on a straight-line basis over the remaining useful life of the related assets, which approximates the anticipated physical lives of these assets in most cases. The Nevada Administrative Code requires the Utilities to provide a depreciation study every four years in order to substantiate the remaining physical lives of their investment in utility plant. Adjustments to the estimated depreciable lives of the Utilities' plant are recorded on a prospective basis, as prescribed by GAAP and the FERC's Uniform System of Accounts. Substantially all of the Utilities' plant is subject to the ratemaking jurisdiction of the PUCN or the FERC and, in the case of SPPC, the CPUC, which also approves any changes the Utilities may make to depreciation rates utilized for this property. Because the Utilities' periodic depreciation expense is included as a component of the revenue requirement utilized in the development of the Utilities' tariff rates, revenue reflects collection of the recognized depreciation expense. Accordingly, the impact of depreciation on net income is not significant. However, operating cash flows are positively affected by the amount of depreciation collected in rates, since depreciation expense is not a current cash outlay for the Utilities. ASSET RETIREMENT OBLIGATIONS In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 provides accounting requirements for the recognition and measurement of liabilities associated with the retirement of tangible long-lived assets. Under the standard, these liabilities will be recognized at fair value as incurred and capitalized as part of the cost of the related tangible long-lived assets. Accretion of the liabilities 55 due to the passage of time will be an operating expense. Retirement obligations associated with long-lived assets included within the scope of SFAS No. 143 are those for which a legal obligation exists under enacted laws, statutes written or oral contracts, including obligations arising under the doctrine of promissory estoppel. The Utilities adopted SFAS No. 143 on January 1, 2003. Prior to adopting SFAS 143, costs for removal of most utility assets were accrued as an additional component of depreciation expense. Under SFAS 143, only the costs to remove an asset with legally binding retirement obligations will be accrued over time through accretion of the asset retirement obligation and depreciation of the capitalized asset retirement cost. Management's methodology to assess its legal obligation included an inventory of assets by system and components, and a review of right of ways and easements, regulatory orders, leases and federal, state, and local environmental laws. Management assumed in determining its Asset Retirement Obligations that transmission, distribution and communications systems will be operated in perpetuity and would continue to be used or sold without land remediation; and, mass asset properties that are replaced or retired frequently would be considered normal maintenance. Management has identified a legal obligation to retire generation plant assets specified in land leases for NPC's jointly-owned Navajo generating station. The land on which the Navajo generating station resides is leased from the Navajo Nation. The provisions of the leases require the lessees to remove the facilities upon request of the Navajo Nation at the expiration of the leases. Management has determined that the present value of NPC's Navajo Asset Retirement Obligation will not have a material effect on the financial position or results of operations of SPR or NPC. SPPC has no significant asset retirement obligations. The Utilities have various transmission and distribution lines as well as substations that operate under various rights of way that contain end dates and restorative clauses. Management operates the transmission and distribution system as though they will be operated in perpetuity and will continue to be used or sold without land remediation. As a result, the Utilities have not recorded any costs associated with the removal of the transmission and distribution systems. STOCK COMPENSATION PLANS In December 2002, the FASB released SFAS No. 148, "Accounting for Stock-Based Compensation-Transition and Disclosure," as an amendment to SFAS No. 123, "Accounting for Stock-Based Compensation." SPR has previously adopted the disclosure-only provisions of SFAS No. 123, and as of December 31, 2002 has adopted the updated disclosure requirements set forth in SFAS No. 148. Pursuant to those updated disclosure requirements, SPR has included the following discussion on the stock compensation plans. For additional information on SPR's stock compensation plans, see Note 1 of Notes to Financial Statements, Summary of Significant Accounting Policies, and Note 15, Stock Compensation Plans. 56 At December 31, 2002, SPR had several stock-based compensation plans. 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. SPR has adopted the disclosure-only provisions of SFAS No. 123, Accounting for Stock Based Compensation, and its related amendment(s). 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 (dollars in thousands, except per share amounts):
2002 2001 2000 --------- -------- --------- Stock Compensation Cost included in Net Income as Reported, net of related tax effects As Reported $ (1,567) $ 346 $ (152) ========= ======== ========= Net Income (Loss) As Reported $(307,521) $ 56,733 $ (39,780) Less: Stock Compensation Cost, net of related tax effects Pro Forma 2,047 1,209 695 --------- -------- --------- Net Income (Loss) Pro Forma $(309,568) $ 55,524 $ (40,475) ========= ======== ========= Basic Earnings Per Share As Reported $ (3.01) $ 0.65 $ (0.51) Pro Forma $ (3.03) $ 0.63 $ (0.52) Diluted Earnings Per Share As Reported $ (3.01) $ 0.65 $ (0.51) Pro Forma $ (3.03) $ 0.63 $ (0.52)
UNBILLED RECEIVABLES Revenues related to the sale of energy are recorded based on meter reads, which occur on a systematic basis throughout a month, rather than when the service is rendered or energy is delivered. At the end of each month, the energy delivered to the customers from the date of their last meter read to the end of the month is estimated and the corresponding unbilled revenues are calculated. These estimates of unbilled sales and revenues are based on the ratio of billable days versus unbilled days, amount of energy procured and generated during that month, historical customer class usage patterns and the Utilities' current tariffs. Customer accounts receivable as of December 31, 2002, include unbilled receivables of $60 million and $63 million for NPC and SPPC, respectively. Customer accounts receivable as of December 31, 2001, include unbilled receivables of $49 million and $63 million for NPC and SPPC, respectively. PROVISION FOR UNCOLLECTIBLE ACCOUNTS The Utilities reserve for doubtful accounts based on past experience writing off uncollectible customer accounts. The adequacy of these reserves will vary to the extent that future collections differ from past experience. MAJOR FACTORS AFFECTING RESULTS OF OPERATIONS As discussed in the results of operations sections that follow, operating results for the year ended December 31, 2002, were severely affected by the PUCN's March 29, 2002, decision in NPC's deferred energy 57 rate case to disallow $434 million of deferred purchased fuel and power costs. The PUCN concluded that NPC was imprudent in entering into certain transactions and also imprudent in not entering into other transactions: in particular, that NPC should have purchased 25% of its projected 2001 load in 1999 when prices were lower, and that it purchased 3% too much supply for summer 2001 and should have sold the excess at an earlier date. NPC has appealed this decision to the First Judicial District Court of Nevada. Arguments were heard on March 14, 2003 and a decision is expected in the second quarter. As a result of this disallowance, NPC wrote off approximately $465 million of deferred energy costs and related carrying charges. In addition, the decision of the PUCN on May 28, 2002, in SPPC's deferred energy rate case to disallow $53 million of deferred purchased fuel and power costs accumulated between March 1, 2001, and November 30, 2001, had a significant negative impact on the results of operations of SPR and SPPC for the year ended December 31, 2002. The PUCN concluded that SPPC was imprudent for buying too much power for summer 2001, and for failing to buy 33% of its total summer 2001 supplies on an index price instead of a firm price. SPPC has appealed this decision to the First Judicial District Court of Nevada and arguments are scheduled to be heard in October 2003. As a result of this disallowance, SPPC wrote off approximately $58 million of deferred energy costs and related carrying charges. The discussion below provides the context in which these decisions were made. In an effort to mitigate the effects of higher fuel and purchased power costs that developed in the western United States in 2000, the Utilities entered into the Global Settlement with the PUCN in July 2000 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 for NPC and SPPC, respectively. 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. 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 Assembly Bill 369 (AB 369). The provisions of AB 369 include a moratorium on the sale of generation assets by electric utilities until July 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 had the necessary financial resources to provide adequate and reliable electric service under the then 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 recovered 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. On November 30, 2001, NPC filed a deferred energy application seeking to establish a Deferred Energy Accounting Adjustment (DEAA) rate to clear purchased fuel and power costs of $922 million accumulated between March 1, 2001, and September 30, 2001, and to spread the cost recovery 58 over a period of not more than three years. On February 1, 2002, SPPC filed a deferred energy application seeking to establish a DEAA rate to clear purchased fuel and power costs of $205 million accumulated between March 1, 2001, and November 30, 2001, and to spread the cost recovery over a period of not more than three years. See Regulation and Rate Proceedings, later, for a discussion of the Utilities' general rate case filings and decisions. The March 29, 2002, decision of the PUCN on NPC's deferred energy rate case to disallow $434 million of deferred purchased fuel and power costs accumulated between March 1, 2001, and September 30, 2001, had a significant negative impact on the results of operations of SPR and NPC for the year ended December 31, 2002. The PUCN's decision also caused the two major national rating agencies to issue immediate downgrades of the credit ratings on SPR's, NPC's and SPPC's debt securities (followed by further downgrades late in April). Following those events, the market price of SPR's common stock fell substantially; NPC and SPPC were obliged within five business days of the downgrades to issue general and refunding mortgage bonds to secure their bank lines of credit; NPC was obliged to obtain a waiver and amendment from its credit facility banks before it was permitted to draw down on the facility; NPC and SPPC were no longer able to issue commercial paper; a number of NPC's power suppliers contacted NPC regarding its ability to pay the purchase price of outstanding contracts; and several power suppliers, including a subsidiary of Enron Corp., terminated their power supply agreements with one or both of the Utilities. As discussed later under Regulation and Rate Proceedings, the PUCN's March 29, 2002, decision on NPC's deferred energy application is being challenged by NPC in a lawsuit filed in the First District Court of Nevada. Arguments were heard on March 14, 2003 and a decision is expected in the second quarter. The Bureau of Consumer Protection (BCP) of the Nevada Attorney General's Office has since filed a petition in NPC's pending state court case seeking additional disallowances. The May 28, 2002, decision of the PUCN on SPPC's deferred energy rate case to disallow $53 million of deferred purchased fuel and power costs accumulated between March 1, 2001, and November 30, 2001, also had a significant negative impact on the results of operations of SPR and SPPC for the year ended December 31, 2002. The PUCN's decision on SPPC's deferred energy application is being challenged by SPPC in a lawsuit filed August 22, 2002, in Nevada state court, which is discussed later under Regulation and Rate Proceedings, and arguments are scheduled to be heard in October 2003. The BCP of the Nevada Attorney General's Office has since filed a petition in SPPC's state action seeking additional disallowances. On November 14, 2002, NPC filed an application with the PUCN seeking to clear deferred balances of $195.7 million for purchased fuel and power costs accumulated between October 1, 2001, and September 30, 2002, and to spread the recovery of the deferred costs, together with a carrying charge, over a period of not more than three years. On January 14, 2003, SPPC filed an application with the PUCN seeking to clear deferred balances of $15.4 million for purchased fuel and power costs accumulated between December 1, 2001, and November 30, 2002, and to spread the recovery of the deferred costs, together with a carrying charge, over a period of not more than three years. See "Critical Accounting Policies--Deferred Energy Accounting" above for more detail. A significant disallowance in either or both of these deferred energy rate cases or in future cases to be filed by either Utility could further weaken the financial condition, liquidity, and capital resources of SPR, NPC, and SPPC. In particular, such a decision or decisions could cause further downgrades of debt securities by the rating agencies, could make it impracticable to access the capital markets, and could cause additional power suppliers to terminate purchased power contracts and seek liquidated damages. Under such circumstances, it could be difficult for one or more of SPR, NPC, or SPPC to continue to operate outside of bankruptcy. 59 SIERRA PACIFIC RESOURCES RESULTS OF OPERATIONS SPR incurred a net loss of ($307.5) million for the year ended December 31, 2002, compared to net income of $56.7 million in 2001, and a net loss of ($39.8) million in 2000. SPR's operating results for 2002 reflect the write-off of $527 million (before taxes) of deferred energy costs and related carrying charges as a result of the PUCN's decisions in NPC's and SPPC's deferred energy rate cases to disallow $434 million and $57 million, respectively, of deferred purchased power, fuel, and gas costs. On March 15, 2002, SPR paid $20.6 million in common stock dividends. NPC declared and paid a common stock dividend of $10 million to its parent, SPR, in the first quarter of 2002. During 2002 SPPC paid common stock dividends of $44.9 million to its parent, SPR, and $3.9 million in dividends to holders of its preferred stock. NPC and SPPC each received a capital contribution of $10 million from SPR in March 2002. ANALYSIS OF CASH FLOWS SPR's consolidated net cash flows improved in 2002 compared to 2001, resulting from an increase in cash flows from operating activities offset in part by decreases in cash flows from investing and financing activities. Although SPR recorded a net loss during 2002, compared to net income in 2001, the current year's loss resulted largely from the write-off of disallowed deferred energy costs at the utilities for which the cash outflow had occurred in 2001. Other factors contributing to 2002's improved cash flows from operating activities include the collection of deferred energy costs from customers and lower energy prices. Also, cash flows from operating activities in the current year reflect the receipt of an income tax refund. Cash flows from investing activities decreased in 2002 because 2001 investing activities included cash provided from the sale of the assets of SPPC's water business. Also, cash flows from investing activities decreased because of additional cash utilized for construction activities during 2002 compared to 2001. Cash flows from financing activities were lower in 2002 because of decreases in net long-term debt issued, decreases in short-term borrowings and reduced proceeds from the sale of common stock. SPR's consolidated 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 Note 7, Common Stock and Other Paid-in Capital and Note 12 Short-Term Borrowings, of Notes to Financial Statements for detailed financing information. LIQUIDITY AND CAPITAL RESOURCES (SPR CONSOLIDATED) SPR, on a stand-alone basis, had cash and cash equivalents of approximately $1.5 million at December 31, 2002, and approximately $179.3 million at February 28, 2003. SPR's future liquidity and its ability to pay the principal of and interest on its indebtedness depend on SPPC's ability to continue to pay dividends to SPR, on NPC's financial stability and the restoration of its ability to pay dividends to SPR, and on SPR's ability to access the capital markets or otherwise refinance maturing debt. Further adverse developments at NPC or SPPC, including a material disallowance of deferred energy costs in current and future rate cases or an adverse decision in the pending lawsuit by Enron, could make it difficult for SPR to operate outside of bankruptcy. 60 DIVIDENDS FROM SUBSIDIARIES 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 NPC and SPPC 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 that the Utilities may declare and pay, and to federal statutory limitation on the payment of dividends. In addition, certain agreements entered into by the Utilities set restrictions on the amount of dividends they may declare and pay and restrict the circumstances under which such dividends may be declared and paid. The specific restrictions on dividends contained in agreements to which NPC and SPPC are party, as well as specific regulatory limitations on dividends, are summarized below. o NPC's first mortgage indenture limits the cumulative amount of dividends and other distributions that NPC may pay on its capital stock to the cumulative net earnings of NPC since 1953, subject to adjustments for the net proceeds of sales of capital stock since 1953. At the present time, this restriction precludes NPC from making further payments of dividends on NPC's common stock and will continue to bar dividends until NPC, over time, generates sufficient earnings to eliminate the deficit under this provision (which was approximately $237 million as of December 31, 2002), unless the restriction is earlier waived, amended, or removed by the consent of the first mortgage bondholders, or the first mortgage bonds are redeemed or defeased. There can be no assurance that any such consent could be obtained or that any first mortgage bonds could be redeemed prior to their stated maturity. Under this provision, NPC continues to have capacity to repurchase or redeem shares of its capital stock, although other restrictions set forth below would limit the amount of any such repurchases or redemptions. o NPC's 10 7/8% General and Refunding Mortgage Notes, Series E, due 2009, which were issued on October 29, 2002, limit the amount of payments in respect of common stock that NPC may pay to SPR. However, that limitation does not apply to payments by NPC to enable SPR to pay its reasonable fees and expenses (including, but not limited to, interest on SPR's indebtedness and payment obligations on account of SPR's Premium Income Equity Securities (PIES)) provided that: o those payments do not exceed $60 million for any one calendar year, o those payments comply with any regulatory restrictions then applicable to NPC, and o the ratio of consolidated cash flow to fixed charges for NPC's most recently ended four full fiscal quarters immediately preceding the date of payment is at least 1.75 to 1. The terms of the Series E Notes also permit NPC to make payments to SPR in an aggregate amount not to exceed $15 million from the date of the issuance of the Series E Notes. In addition, NPC may make payments to SPR in excess of the amounts described above so long as, at the time of payment and after giving effect to the payment: o there are no defaults or events of default with respect to the Series E Notes, o NPC has a ratio of consolidated cash flow to fixed charges for NPC's most recently ended four full fiscal quarters immediately preceding the payment date of at least 2.0 to 1, and o the total amount of such dividends is less than: o the sum of 50% of NPC's consolidated net income measured on a quarterly basis cumulative of all quarters from the date of issuance of the Series E Notes, plus o 100% of NPC's aggregate net cash proceeds from contributions to its common equity capital or the issuance or sale of certain equity or convertible debt securities of NPC, plus o the lesser of cash return of capital or the initial amount of certain restricted investments, plus o the fair market value of NPC's investment in certain subsidiaries. 61 If NPC's Series E Notes are upgraded to investment grade by both Moody's Investors Service, Inc. (Moody's) and Standard & Poor's Rating Group, Inc. (S&P), these restrictions will be suspended and will no longer be in effect so long as the Series E Notes remain investment grade. o On October 29, 2002, NPC established an accounts receivables purchase facility. The agreements relating to the receivables purchase facility contain various conditions, including a limitation on payments in respect of common stock by NPC to SPR that is identical to the limitation contained in NPC's General and Refunding Mortgage Notes, Series E, described above. o The PUCN issued a Compliance Order, Docket No. 02-4037, on June 19, 2002, relating to NPC's request for authority to issue long-term debt. The PUCN order requires that, until such time as the order's authorization expires (December 31, 2003), NPC must either receive the prior approval of the PUCN or reach an equity ratio of 42% before paying any dividends to SPR. If NPC achieves a 42% equity ratio prior to December 31, 2003, the dividend restriction ceases to have effect. As of December 31, 2002, NPC's equity ratio was 36.1%. o The terms of NPC's preferred trust securities provide that no dividends may be paid on NPC's common stock if NPC has elected to defer payments on the junior subordinated debentures issued in conjunction with the preferred trust securities. At this time, NPC has not elected to defer payments on the junior subordinated debentures. o SPPC's Term Loan Agreement dated October 30, 2002, which expires October 31, 2005, limits the amount of payments that SPPC may pay to SPR. However, that limitation does not apply to payments by SPPC to enable SPR to pay its reasonable fees and expenses (including, but not limited to, interest on SPR's indebtedness and payment obligations on account of SPR's PIES) provided that those payments do not exceed $90 million, $80 million and $60 million in the aggregate for the twelve month periods ending on October 30, 2003, 2004 and 2005, respectively. The Term Loan Agreement also permits SPPC to make payments to SPR in an aggregate amount not to exceed $10 million during the term of the Term Loan Agreement. In addition, SPPC may make payments to SPR in excess of the amounts described above so long as, at the time of the payment and after giving effect to the payment, there are no defaults or events of default under the Term Loan Agreement, and such amounts, when aggregated with the amount of payments to SPR by SPPC since the date of execution of the Term Loan Agreement, do not exceed the sum of: o 50% of SPPC's Consolidated Net Income for the period commencing January 1, 2003 and ending with last day of fiscal quarter most recently completed prior to the date of the contemplated dividend payment, plus o the aggregate amount of cash received by SPPC from SPR as equity contributions on its common stock during such period. o On October 29, 2002, SPPC established an accounts receivables purchase facility. The agreements relating to the receivables purchase facility contain various conditions, including a limitation on the payment of dividends by SPPC to SPR that is identical to the limitation contained in SPPC's Term Loan Agreement, described above. o SPPC's Articles of Incorporation 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. SPPC's Articles also prohibit SPPC from declaring or paying any dividends on any shares of 62 common stock (other than dividends payable in shares of common stock), or making any other distribution on any shares of common stock or any expenditures for the purchase, redemption or other retirement for a consideration of shares of common stock (other than in exchange for or from the proceeds of the sale of common stock) except from the net income of SPPC, and its predecessor, available for dividends on common stock accumulated subsequent to December 31, 1955, less preferred stock dividends, plus the sum of $500,000. At the present time, SPPC believes that these restrictions do not materially limit its ability to pay dividends and/or to purchase or redeem shares of its common stock. o The Utilities are subject to the provision of the Federal Power Act that states that dividends cannot be paid out of funds that are properly included in capital account. Although the meaning of this provision is not clear, it could be interpreted to impose an additional material limitation on a utility's ability, in the absence of retained earnings, to pay dividends. Management intends to seek a modification of the financial covenant, contained in NPC's first mortgage indenture, in the near future. The regulatory limitation contained in the PUCN's Compliance Order, Docket No. 02-4037, dated June 19, 2002, expires on December 31, 2003. Prior to the expiration date of the Compliance Order, management may seek PUCN approval for a payment of dividends by NPC or may seek a waiver from the PUCN of the dividend restriction. EFFECTS OF RATE CASE DECISIONS On March 29 and April 1, 2002, S&P and Moody's lowered the unsecured debt ratings of SPR, NPC and SPPC to below investment grade in response to the decision of the PUCN with respect to NPC's rate cases. On April 23 and 24, 2002, the unsecured debt ratings of SPR and the Utilities were further downgraded by both rating agencies, and the Utilities' secured debt ratings were downgraded to below investment grade. The downgrades affected SPR's, NPC's and SPPC's 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. Credit Facility. As a result of the ratings downgrades, SPR's ability to access the capital markets to raise funds was severely limited. On April 3, 2002, SPR terminated its $75 million unsecured revolving credit facility as a condition to the banks agreeing to an amendment of NPC's former $200 million unsecured revolving credit facility that permitted NPC to draw down funds under that facility. See NPC, Liquidity and Capital Resources, for more information. Power Supplier Issues. With respect to NPC's and SPPC's contracts for purchased power, NPC and SPPC purchase and sell electricity with counterparties under the Western Systems Power Pool (WSPP) agreement, an industry standard contract that NPC and SPPC are required to use as members of the WSPP. The WSPP contract is posted on the WSPP website. These contracts provide that a material adverse change may give rise to a right to request collateral, which, if not provided within 3 business days, could cause a default. A default must be declared within 30 days of the event, giving rise to the default becoming known. A default will result in a termination payment equal to the present value of the net gains and losses for the entire remaining term of all contracts between the parties 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, which is substantially based on quoted market prices, can be used to roughly approximate the termination payment and benefit at any point in time. The net mark-to-market value as of February 28, 2003, for all suppliers continuing to provide power under a WSPP agreement was an approximate $17.0 million benefit for NPC and an approximate $7.8 million payment for SPPC. Following the PUCN decisions, a number of power suppliers requested collateral from the Utilities. On April 4, 2002, the Utilities sent a letter to their suppliers advising them that, assuming the Utilities could access the capital markets for secured debt and no other significant negative developments occurred, the Utilities 63 expected to be able to honor their obligations under the power supply contracts. However, the Utilities noted that a simultaneous call for 100% mark-to-market collateral in the short-term would likely not be met. On April 24, 2002, the Utilities met with representatives of various suppliers to discuss SPR's and the Utilities' financial situation and plans, and indicated that they intended to propose extended payment terms for the above-market portions of NPC's existing power contracts. Such extended payment terms were proposed to NPC's suppliers in a letter dated May 2, 2002, in which NPC proposed paying less than contract prices, but more than market prices plus interest, for the period May 1 to September 15, 2002, and paying any balances remaining prior to December 2003. NPC also agreed to extend the suppliers' rights under the WSPP agreement. As of October 29, 2002, NPC paid all remaining outstanding balances owed to its continuing suppliers. In early May of 2002, Enron Power Marketing Inc. (Enron), Morgan Stanley Capital Group Inc. (MSCG), Reliant Energy Services, Inc. and several smaller suppliers terminated their power deliveries to NPC and SPPC. These terminating suppliers asserted their contractual right under the WSPP agreement to terminate deliveries based upon the Utilities' alleged failure to provide adequate assurance of their performance under the WSPP agreement to any of their suppliers. Each of these terminating suppliers has asserted, or has indicated that it will assert, claims for liquidated damages against the Utilities under the terminated power supply contracts. Enron filed a complaint with the United States Bankruptcy Court for the Southern District of New York seeking to recover approximately $216 million and $93 million against NPC and SPPC, respectively, for liquidated damages for power supply contracts terminated by Enron in May 2002 and for power previously delivered to the Utilities. The Utilities have denied liability on numerous grounds, including deceit and misrepresentation in the inducement (including, but not limited to, misrepresentation as to Enron's ability to perform), and fraud, unfair trade practices and market manipulation. The Utilities filed motions to dismiss for lack of jurisdiction and/or for a stay of all proceedings pending the actions of the Utilities' proceedings under Section 206 of the Federal Power Act at the FERC (see Regulation and Rate Proceedings). The Utilities have also filed proofs of claims and counterclaims against Enron, for the full amount of the approximately $300 million claimed to be owed and additional damages, as well as for unspecified damages to be determined during the case as a result of acts and omissions of Enron in manipulating the power markets. On December 19, 2002, the bankruptcy judge granted Enron's motion for partial summary judgment on Enron's claim for $17.7 million and $6.7 million, respectively, for energy delivered by Enron in April 2002, for which NPC and SPPC did not pay. The court ordered this money to be deposited into an escrow account not subject to claims of Enron's creditors and subject to refund depending on the outcome of the Utilities' FERC cases on the merits. The Utilities made the deposits as ordered. The bankruptcy court denied the Utilities' motion to stay the proceeding pending the outcome of the Utilities' Section 206 case at the FERC and denied the Utilities' motion to dismiss for lack of jurisdiction as to Enron's claims for power previously delivered to the Utilities. The court stated that it would rule in due course on Enron's motion for partial summary judgment to require NPC and SPPC to post $200 million and $87 million, respectively, pending the outcome of the case on the merits, and for judgment on the merits on Enron's liquidated damage claim (contract price less market price on the date of termination) relating to power it did not deliver under contracts terminated by Enron in May 2002. The court took under advisement the Utilities' motion to stay or dismiss Enron's claim for liquidated damages relating to the undelivered power and set a hearing on Enron's motion to dismiss the Utilities' counterclaims for April 3, 2003. The United States District Court for the Southern District of New York also denied the Utilities' motion to withdraw reference of the matter to the bankruptcy court without prejudice. The bankruptcy court currently has under submission (1) Enron's motion to dismiss the Utilities' counterclaims, (2) Enron's motion for partial summary judgment regarding the amounts alleged to be due for undelivered power and the posting of collateral for undelivered power, and (3) the Utilities' motion to dismiss or stay proceeding on Enron's claims relating to delivered power. Enron's motion to dismiss the Utilities' counterclaims is set for hearing on April 3, 2003. The Utilities are unable to predict the outcome of the motions. A decision adverse to the Utilities on Enron's motion for 64 partial summary judgment, or an adverse decision in the lawsuit with respect to liability as to Enron's claims on the merits for undelivered power, would have a material adverse effect on SPR's and the Utilities' financial condition and liquidity and could make it difficult to continue to operate outside of bankruptcy. On June 10, 2002, Duke Energy Trading and Marketing (Duke) entered into an agreement with SPR and the Utilities to supply up to 1,000 megawatts of electricity per hour, as well as natural gas, to fulfill the Utilities' power requirements during the peak summer period. The effect of the Duke agreement was to replace the amount of contracted power and natural gas that would have been supplied by the various terminating suppliers, including Enron. Duke also agreed to accept deferred payment for a portion of the amount due under its existing power contracts with NPC for purchases made through September 15, 2002. On October 25, 2002, Duke was paid the full amount of the deferred payments. On September 5, 2002, MSCG initiated an arbitration pursuant to the arbitration provisions in various power supply contract terminated by MSCG in April 2002. In the arbitration, MSCG is requesting that the arbitrator compel NPC to pay MSCG $25 million pending the outcome of any dispute regarding the amount owed under the contracts. NPC claims that nothing is owed under the contracts on various grounds, including breach by MSCG in terminating the contracts, and further, that the arbitrator does not have jurisdiction over NPC's contract claims and defenses. In March 2003, the arbitrator ruled in NPC's favor and dismissed the arbitration in its entirety for lack of jurisdiction. On September 30, 2002, El Paso Merchant Energy Group (EPME) notified NPC that it was terminating all transactions entered into with NPC under the WSPP agreement. On October 8, 2002, NPC received a letter from EPME seeking a termination payment of approximately $36 million with respect to the terminated WSPP agreement transactions. At the present time, NPC disagrees with EPME's calculation, and expects that net gains and losses relating to the terminated transactions, including a delayed payment amount of approximately $19 million that was owed to EPME for power deliveries through September 15, 2002, will result in a net payment due to NPC. Gas Supplier Issues. With respect to the purchase and sale of natural gas, NPC and SPPC use several types of contracts. Standard industry sponsored agreements include: o the Gas Industry Standards Board (GISB) agreement which is used for physical gas transactions, o the North American Energy Standards Board (NAESB) agreement which is used for physical gas transactions, o the Gas EDI Base Contract for Short Term Sale and Purchase of Natural Gas which is also used for physical gas transactions, o 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 contain language similar to that found in the WSPP agreement and other agreements have unique provisions dealing with material adverse changes. 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. These contracts are 65 subject to FERC approved tariffs, which, under certain circumstances, require the Utilities to provide collateral to continue receiving service. To date, a letter of credit has been provided to one of SPPC's gas suppliers. Construction Projects. In response to the decisions by the PUCN in NPC's rate cases, SPR implemented certain measures that positively impacted cash flow by $101.4 million in 2002. Two major transmission construction projects, the Centennial Plan and the Falcon to Gonder Project, were delayed for a total 2002 capital preservation impact of $71.9 million. The delay in NPC's Centennial Plan had an impact of $38.4 million and the delay of SPPC's Falcon to Gonder Project had an impact of $33.5 million. An additional $29.5 million was reduced from the Utilities' 2002 capital budgets by curtailing or delaying other projects. FEDERAL TAX REFUND In March 2002, NPC received a federal income tax refund of $79.3 million. Additionally, SPR and the Utilities received $105.7 million of refunds in the second quarter of 2002. These refunds were the result of income tax losses generated in 2001. Federal legislation passed in March 2002 changed the allowed carry-back of these losses from two years to five years. This change permitted SPR and the Utilities to accelerate the receipt of a portion of their income tax receivables sooner than expected. The remaining income tax losses of $281.9 million as of December 31, 2002 may be utilized in future periods to reduce taxes payable to the extent that SPR and the Utilities recognize taxable income. The carryforward period for net operating losses incurred is 20 years, and as such the losses incurred in the years ended December 31, 2000, 2001, and 2002 will expire in 2020, 2021, and 2022, respectively. ACCOUNTS RECEIVABLE FACILITY On October 29, 2002, NPC and SPPC established accounts receivable purchase facilities of up to $125 million and $75 million, respectively, which expire on August 28, 2003 unless either NPC or SPPC has activated its respective facility before that date, in which case such facility will be automatically extended to, and will expire on, October 28, 2003. If NPC or SPPC elect to activate their receivables purchase facilities, they will sell all of their accounts receivable generated from the sale of electricity and natural gas to customers to their newly created bankruptcy remote special purpose subsidiaries. The receivables sales will be without recourse except for breaches of customary representations and warranties made at the time of sale. The subsidiaries will, in turn, sell these receivables to a bankruptcy-remote subsidiary of SPR. SPR's subsidiary will issue variable rate revolving notes backed by the purchased receivables. Lehman Brothers Holdings, Inc. has committed to be the sole initial committed purchaser of all of the variable rate revolving notes. The agreements relating to the receivables purchase facilities contain various conditions to purchase, covenants and trigger events, and other provisions customary in receivables transactions. In addition to customary termination and mandatory repurchase events, each Utilities' receivables purchase facility may terminate in the event that the Utility or SPR defaults (i) on the payment of indebtedness, or (ii) on the payment of amounts due under a swap agreement, and such defaults aggregate to greater than $10 million and $5 million for the Utility and SPR, respectively. Under the terms of the agreements relating to the receivables purchase facility, each Utility's facility may not be activated or, if activated, will be terminated in the event of a material adverse change in the condition, operations or business prospects of the Utility. SPR has agreed to guaranty the performance by NPC and SPPC of certain obligations as sellers and servicers under the receivables purchase facilities. NPC and SPPC intend to use their accounts receivables purchase facilities as back-up liquidity facilities and do not plan to activate these facilities in the foreseeable future. CROSS DEFAULT PROVISIONS Certain financing agreements of SPR and the Utilities contain cross-default provisions that would result in an event of default under such financing agreements if there is a failure under other financing agreements of 66 SPR and the Utilities to meet payment terms or to observe other covenants that would result in an acceleration of payments due. Most of these default provisions (other than ones relating to a failure to pay other indebtedness) provide for a cure period of 30-60 days from the occurrence of a specified event during which time, SPR or the Utilities may rectify or correct the situation before it becomes an event of default. The primary cross-default provisions in SPR's and the Utilities' various financing agreements are briefly summarized below: o The indenture pursuant to which SPR issued its 7.25% Convertible Notes due 2010 provides for an event of default if SPR or any of its significant subsidiaries (NPC and SPPC) fails to pay indebtedness in excess of $10 million or has any indebtedness of $10 million or more accelerated and declared due and payable; o NPC's General and Refunding Mortgage Indenture provides for an event of default if a matured event of default under NPC's First Mortgage Indenture occurs; o The terms of NPC's Series E Notes provide that a default with respect to the payment of principal, interest or premium beyond the applicable grace period under any mortgage, indenture or other security instrument, by NPC or any of its restricted subsidiaries, relating to debt in excess of $15 million, triggers a right of the holders of the Series E Notes to require NPC to redeem the Series E Notes at a price equal to 100% of the aggregate principal amount plus accrued and unpaid interest and liquidated damages, if any, upon notice given by at least 25% of the outstanding Series E Notes holders; o NPC's receivables purchase facility may terminate in the event that either NPC or SPR defaults (i) in the payment of indebtedness, or (ii) in the payment of amounts due under hedge agreements, and such defaults aggregate to greater than $10 million and $5 million for NPC and SPR, respectively; o SPPC's General and Refunding Mortgage Indenture provides for an event of default if a matured event of default under SPPC's First Mortgage Indenture occurs; o SPPC's Term Loan Agreement provides for an event of default if (a) SPPC or any of its subsidiaries default (i) in the payment of indebtedness, or (ii) in the payment of amounts due under hedge agreements, and such defaults aggregate to greater than $10 million, or (b) SPPC's General and Refunding Mortgage Indenture ceases to be enforceable; and o SPPC's receivables purchase facility may terminate in the event that either SPPC or SPR defaults (i) in the payment of indebtedness, or (ii) in the payment of amounts due under hedge agreements, and such defaults aggregate to greater than $10 million and $5 million for SPPC and SPR, respectively. PENSION PLAN MATTERS SPR has a qualified pension plan that covers substantially all employees of SPR, NPC and SPPC. The annual net benefit cost for the plan will increase for 2003 by approximately $16.1 million over the 2002 cost of $18.4 million. As of September 30, 2002, the plan had assets with a fair value that was less than the present value of the accumulated benefit obligation under the plan. On December 6, 2002, SPR and the Utilities contributed a total of $24 million to meet their funding obligations under the plan. At the present time, SPR and the Utilities do not expect that any near term funding obligation will have a material adverse effect on their liquidity. FINANCING TRANSACTIONS In January 2003, SPR acquired $8.75 million aggregate principal amount of its Floating Rate Notes due April 20, 2003 in exchange for 1.30 million shares of its common stock, in two privately-negotiated transactions exempt from the registration requirements of the Securities Act of 1933. 67 On February 5, 2003, SPR issued 13.66 million shares of common stock in exchange for a total of 2,095,650 of its PIES in five privately-negotiated transactions exempt from the registration requirements of the Securities Act of 1933. On February 14, 2003, SPR issued and sold $300 million of its 7.25% Convertible Notes due 2010. Approximately $53.4 million of the net proceeds from the sale of the notes were used to purchase U.S. government securities that were pledged to the trustee for the first five interest payments on the notes payable during the first two and one-half years. A portion of the remaining net proceeds of the notes have been used to repurchase approximately $58.5 million of SPR's Floating Rate Notes due April 20, 2003. The remaining portion of the net proceeds will be used to repay the remainder of SPR's Floating Rate Notes due April 20, 2003 at maturity and for general corporate purposes. The Convertible Notes were issued with registration rights. The Convertible Notes will not be convertible prior to August 14, 2003. At any time on or after August 14, 2003 through the close of business February 14, 2010, holders of the Convertible Notes may convert each $1,000 principal amount of their notes into 219.1637 shares of SPR's common stock, subject to adjustment upon the occurrence of certain dilution events. Until SPR has obtained shareholder approval to fully convert the Convertible Notes into shares of common stock, holders of the Convertible Notes will be entitled to receive 76.7073 shares of common stock and a remaining portion in cash based on the average closing price of SPR's common stock over five consecutive trading days for each $1,000 principal amount of notes surrendered for conversion. At an assumed five-day average closing price of $3.20 (the last reported sale price of SPR's common stock on March 17, 2003), the total amount of the cash payable on conversion of the Convertible Notes would be approximately $137 million. If SPR does obtain shareholder approval, it may elect to satisfy the cash payment component of the conversion price of the Convertible Notes solely with shares of common stock. SPR has agreed to use reasonable efforts to obtain shareholder approval, not later than 180 days after the date of issuance of the Convertible Notes, for approval to issue and deliver shares of SPR's common stock in lieu of the cash payment component of the conversion price of the Convertible Notes. If SPR does not obtain shareholder approval, SPR will be required to pay the cash portion of any Convertible Notes as to which the holders request conversion on or after August 14, 2003. Although management does not believe it is likely that a significant amount of the Convertible Notes will be converted in the foreseeable future, in the event that SPR does not have available funds to pay the cash portion of the Convertible Notes upon the requested conversion, SPR may have to issue additional debt to raise the necessary funds. There can be no assurance that SPR will be able to access the capital markets to issue such additional debt. The indenture under which the Convertible Notes were issued does not contain any financial covenants or any restrictions on the payment of dividends, the repurchase of SPR's securities or the incurrence of indebtedness. The indenture does allow the holders of the Convertible Notes to require SPR to repurchase all or a portion of the holders' Convertible Notes upon a change of control. Currently, SPR (on a stand-alone basis) has a substantial amount of debt and other obligations including, but not limited to: $133 million of its unsecured Floating Rate Notes due April 20, 2003; $300 million of its unsecured 8 3/4% Senior Notes due 2005; and $240 million of its unsecured 7.93% Senior Notes due 2007; and $300 million of its 7.25% Convertible Notes due 2010. SPR intends to pay off the remaining principal balance of its Floating Rate Notes due April 20, 2003 with cash currently on hand. EFFECT OF HOLDING COMPANY STRUCTURE Due to the holding company structure, SPR's right as a common shareholder to receive assets of any of its direct or indirect subsidiaries upon a subsidiary's liquidation or reorganization is junior to the claims against the assets of such subsidiary by its creditors and preferred stockholders. Therefore, SPR's debt obligations are effectively subordinated to all existing and future claims of its subsidiaries' creditors, particularly those of NPC 68 and SPPC, including trade creditors, debt holders, secured creditors, taxing authorities, guarantee holders, NPC's preferred trust security holders and SPPC's preferred stockholders. As of December 31, 2002, NPC, SPPC and their subsidiaries had approximately $2.86 billion of debt and other obligations outstanding and approximately $238.9 million of outstanding preferred securities. Although the Utilities are parties to agreements that limit the amount of additional indebtedness they may incur, the Utilities retain the ability to incur substantial additional indebtedness and other liabilities. CONSTRUCTION EXPENDITURES AND FINANCING (SPR CONSOLIDATED) The table below provides SPR's consolidated cash construction expenditures and internally generated cash, net for 2000 through 2002 (dollars in thousands):
2002 2001 2000 Total -------------- -------------- -------------- -------------- Cash construction expenditures $ 343,474 $ 302,025 $ 329,346 $ 974,845 ============== ============== ============== ============== Net cash flow from operating activities $ 458,826 $ (1,043,341) $ 188,246 $ (396,269) Less common & preferred cash dividends 24,485 64,917 83,057 172,459 -------------- -------------- -------------- -------------- Internally generated cash $ 434,341 $ (1,108,258) 105,189 (568,728) ============== ============== ============== ============== Internally generated cash as a percentage of 126% Not Applicable 32% Not Applicable cash construction expenditures
SPR's consolidated cash construction expenditures for 2003 through 2007 are estimated to be $1.6 billion. Construction expenditures for 2003 are projected to be $344 million and are expected to be financed by internally generated funds, including the recovery of deferred energy at the Utilities. It is anticipated that no capital contributions from SPR will be used to fund construction expenditures at the Utilities. Cash provided by internally generated funds during 2003 assumes, among other things, no disallowances on the Utilities' currently filed deferred energy rate cases and the full recovery of such deferred energy amounts over three years, no additional disallowances related to the Utilities' appeals of their prior deferred energy cases and no adverse decision in the lawsuit filed by Enron against the Utilities seeking $200 million and $87 million in termination payments from NPC and SPPC, respectively. Material disallowances of currently-filed or previously-filed deferred energy costs or a decision adverse to the Utilities with respect to the Enron lawsuit would have a material adverse effect on SPR's and the Utilities' financial condition and future results of operations, and could cause additional downgrades of their securities by the rating agencies and make it significantly more difficult to finance operations and to buy fuel and purchased power from third parties. See Regulation and Rate Proceedings, Nevada Matters for additional information regarding the Utilities' recently filed deferred energy rate cases and prior deferred energy rate cases and Liquidity and Capital Resources for additional information regarding the Enron lawsuit and the potential impact of a negative outcome with respect to any of these uncertainties. In the event that SPR's and/or the Utilities' financial conditions worsen, they may be unable to finance their construction expenditures with internally generated funds and instead may need to raise all or a portion of the necessary funds through the capital markets or from activating the Utilities' accounts receivable purchase facilities to provide additional liquidity. For additional information regarding the accounts receivable purchase facilities, see Liquidity and Capital Resources. Each of the Utilities may activate its receivables purchase facility within five days upon the delivery of certain customary funding documentation and the delivery of General and Refunding Mortgage Bonds to secure the facility. If a material adverse event were to occur for either of the Utilities, it could potentially trigger a termination event with respect to the receivables facility and would also make it more difficult for the Utilities or SPR to access the capital markets for any such financing needs. 69 CONTRACTUAL OBLIGATIONS (SPR CONSOLIDATED) The table below provides SPR's contractual obligations on a consolidated basis (except as otherwise indicated), not including estimated construction expenditures described above, as of December 31, 2002, 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):
PAYMENT DUE BY PERIOD 2003 2004 2005 2006 2007 Thereafter Total ------------ ------------ ------------ ------------ ------------ ------------ ------------ NPC/SPPC Other Long-Term Debt $ 472,963 $ 153,468 $ 106,491 $ 58,909 $ 8,349 $ 2,108,634 $ 2,908,814 SPR Long-Term Debt 200,000 -- 300,000 -- 345,000 -- 845,000 NPC Preferred Trust Securities -- -- -- -- -- 188,872 188,872 Purchased Power 547,459 284,925 249,217 234,072 220,391 3,494,648 5,030,712 Coal and Natural Gas 167,856 145,341 110,382 101,251 80,223 659,834 1,264,887 Operating Leases 11,100 8,726 7,674 6,505 6,439 57,698 98,142 Other Long-Term Obligations 75 100 -- -- -- -- 175 ------------ ------------ ------------ ------------ ------------ ------------ ------------ Total Contractual Cash Obligations $ 1,399,453 $ 592,560 $ 773,764 $ 400,737 $ 660,402 $ 6,509,686 $ 10,336,602 ============ ============ ============ ============ ============ ============ ============
CAPITAL STRUCTURE (SPR CONSOLIDATED) On April 3, 2002, SPR terminated its $75 million unsecured revolving credit facility in connection with the amendment of NPC's $200 million unsecured revolving credit facility, discussed in Nevada Power Company, Liquidity and Capital Resources. SPR's actual capital structure on a consolidated basis (except as otherwise indicated) at December 31, 2002, and 2001 was as follows (dollars in thousands):
2002 2001 --------------------------- --------------------------- Short-Term Debt (1) $ 672,963 13% $ 299,010 5% Long-Term Debt 3,062,883 58% 3,376,105 60% Preferred Stock 50,000 1% 50,000 1% Preferred Trust Securities 188,872 3% 188,872 4% Common Equity 1,327,166 25% 1,695,336 30% ------------ ------------ ------------ ------------ TOTAL $ 5,301,884 100% $ 5,609,323 100% ============ ============ ============ ============
(1) Including current maturities of long-term debt and $200 million of SPR holding company debt. 70 NEVADA POWER COMPANY RESULTS OF OPERATIONS NPC incurred a net loss of ($235.1) million in 2002 compared to net income of $63.4 million in 2001 and a net loss of ($7.9) million in 2000. NPC's operating results for 2002 reflect the write-off of approximately $465 million (before taxes) of deferred energy costs and related carrying charges as a result of the PUCN's March 29, 2002, decision in NPC's deferred energy rate case to disallow $434 million of deferred purchased fuel and power costs. The PUCN's decision is being challenged by NPC in a lawsuit filed in Nevada state court. In the first quarter of 2002 NPC paid $10 million in dividends on its common stock to its parent, SPR, all of which was reinvested in NPC as a contribution to capital. No other dividend payments or capital contributions occurred in 2002. Currently, NPC is restricted from paying dividends to SPR under the terms of certain financing agreements and a recent order of the PUCN. See Liquidity and Capital Resources for a discussion of these restrictions. 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
2002 2001 2000 ---------------------------------- ------------------------------------ --------------- Change from Change from Amount Prior year Amount Prior year Amount --------------- ----------------- --------------- ------------------ --------------- ELECTRIC OPERATING REVENUES: Residential $ 675,837 4.8% $ 644,875 31.0% $ 492,365 Commercial 345,342 14.1% 302,682 32.9% 227,790 Industrial 520,116 16.2% 447,766 37.0% 326,916 -------------- -------------- -------------- Retail revenues 1,541,295 10.5% 1,395,323 33.3% 1,047,071 Other (1) 359,739 -77.9% 1,629,780 483.9% 279,121 -------------- -------------- -------------- TOTAL REVENUES $ 1,901,034 -37.2% $ 3,025,103 128.1% $ 1,326,192 ============== ============== ============== Retail sales in thousands of megawatt-hours (MWh) 17,197 2.4% 16,799 2.7% 16,363 Average retail revenue per MWh $ 89.63 7.9% $ 83.06 29.8% $ 63.99
(1) Primarily wholesale, as discussed below NPC's retail revenues increased in 2002 primarily due to a combination of customer growth and a net rate increase resulting from NPC's General Rate and Deferred Energy Cases (see Regulation and Rates Proceedings, later). The number of residential, commercial, and industrial customers increased over 2001 by 4.9%, 5.7 % and 2.1%, respectively. Commercial and industrial growth is attributable to the opening of several new schools, shopping centers, and casinos in the Las Vegas area. Effective April 1, 2002, the PUCN authorized an increase in energy related rates that are used to recover current and previously incurred fuel and purchased power costs. In addition to that rate increase, the PUCN also granted NPC the authority to increase its energy recovery rate by one cent per kilowatt-hour for the month of June 2002 only. This one-time increase in rates generated approximately $16 million which was used to accelerate the recovery of previously incurred fuel and purchased power costs. The decrease in the 2002 Other revenues was primarily due to the lower sales resulting from a reduction in transactions entered into for hedging purposes and the optimization of purchased power costs. See Energy Supply, later, for a discussion of the Utilities' purchased power procurement strategies. 71 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 (see Regulation and Rates Proceedings, later). The number of residential, commercial, and industrial customers increased over the prior year by 4.8%, 4.4% and 6.5%, respectively. Substantially all of the increase in the 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 Energy Supply, later, for a discussion of the Utilities' purchased power procurement strategies. PURCHASED POWER
2002 2001 2000 --------------------------------- ---------------------------------- ------------- Change from Change from Amount Prior year Amount Prior year Amount --------------- --------------- --------------- ----------------- ------------- PURCHASED POWER $ 1,241,783 -59.0% $ 3,026,336 350.8% $ 671,396 Purchased power in thousands of MWh 12,908 -33.0% 19,268 99.5% 9,659 Average cost per MWh of Purchased Power (1) $ 78.46 -50.0% $ 157.07 126.0% $ 69.51
(1) Not including contract termination costs, discussed below NPC's purchased power costs were significantly lower in 2002 compared to 2001 due to substantial decreases in prices and volumes. Per unit costs of power decreased 50.0% primarily due to lower Short-Term Firm energy prices. These price decreases were the result of a less volatile energy market. The overall decrease in the cost of purchased power was offset, in part, by a $228 million reserve provision recorded for terminated contracts. See Liquidity and Capital Resources, later, for a discussion of these terminated power contracts. Volumes purchased decreased by 33.0% as a result of a reduction in hedging activities due to a change in risk management activities and energy supply strategies described later in Energy Supply. Purchases associated with risk management activities, which are included in Short-Term Firm energy, decreased significantly in both volume and price in 2002. Wholesale sales associated with risk management activities decreased in volume by approximately 58%. Risk management activities include transactions entered into for hedging purposes and to optimize purchased power costs. See Energy Supply, later, for a discussion of the Utilities' purchased power procurement strategies. Purchased power costs were higher in 2001 as compared to 2000 due to a 99.5% increase in the volume purchased and an increase in the per unit cost of power of 126%. Purchased power costs were higher 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. FUEL FOR POWER GENERATION
2002 2001 2000 ------------------------------ -------------------------------- ------------- Change from Change from Amount Prior year Amount Prior year Amount ------------- --------------- ------------- ---------------- ------------- FUEL FOR POWER GENERATION $ 309,293 -30.0% $ 441,900 50.9% $ 292,787 Thousands of MWhs generated 10,147 2.5% 9,899 -7.9% 10,744 Average fuel cost per MWh of Generated Power $ 30.48 -31.7% $ 44.64 63.8% $ 27.25
72 NPC's 2002 fuel expense decreased 30% compared to 2001 primarily due to a substantial decrease in natural gas prices. This was slightly offset by an increase in coal prices and an overall increase in MWhs generated. In 2001, NPC's fuel expense increased over 50.9% 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. DEFERRAL OF ENERGY COSTS - NET
2002 2001 2000 ------------------------ ---------------------------- ----------- Change from Change from Amount Prior year Amount Prior year Amount --------- ----------- ---------- ------------- ----------- DEFERRAL OF ENERGY COSTS-ELECTRIC-NET $(179,182) -80.9% $ (937,322) N/A $ 16,719 DEFERRED ENERGY COSTS DISALLOWED 434,123 N/A -- N/A -- --------- ---------- -------- $ 254,941 N/A $ (937,322) N/A $ 16,719 ========= ========== ========
The change in Deferral of energy costs-electric-net for the twelve months ended December 31, 2002, compared to the same period in the prior year, reflects the amortization in 2002 of prior deferred costs pursuant to the PUCN's decision on NPC's deferred energy rate case, which resulted in increased rates beginning April 1, 2002, and the one-time rate increase of $0.01 per kilowatt-hour for the month of June 2002. The amortization was offset, in part, by the recording of current year deferrals of electric energy costs, reflecting 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-electric-net also reflects the deferral in the second and fourth quarter of 2002 of approximately $228 million for contract termination costs as described in more detail in Note 17 of Notes to Financial Statements, Commitments and Contingencies. Deferred energy costs disallowed reflects the second quarter write-off of $434 million of electric deferred energy costs incurred in the seven months ended September 30, 2001, that were disallowed by the PUCN in its March 29, 2002 decision on NPC's deferred energy rate case. NPC recorded Deferral of energy costs-electric-net in 2001 due to the implementation of deferred energy accounting beginning March 1, 2001. The 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-electric-net for 2000 represent 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. See Critical Accounting Policies, earlier, and Note 1 of Notes to Financial Statements, Summary of Significant Accounting Policies for more information regarding deferred energy accounting. ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFUDC)
2002 2001 2000 --------------------------- -------------------------- ----------- Change from Change from Amount Prior year Amount Prior year Amount ----------- ----------- ----------- ----------- ----------- ALLOWANCE FOR OTHER FUNDS USED DURING CONSTRUCTION $ (153) -59.9% $ (382) -115.6% $ 2,456 ALLOWANCE FOR BORROWED FUNDS USED DURING CONSTRUCTION 3,412 59.4% 2,141 -72.7% 7,855 ----------- ----------- ----------- $ 3,259 85.3% $ 1,759 -82.9% $ 10,311 =========== =========== ===========
AFUDC for NPC is higher in 2002 compared to 2001 because of an increase in construction work-in-progress (CWIP) and the adjustments in 2001 to amounts assigned to specific components of facilities that were 73 completed in different periods. This increase was offset by a small decrease in the AFUDC rate compared to 2001 due to an increase in short-term debt. In 2001, AFUDC is lower compared to 2000 because of adjustments to amounts assigned to specific components of facilities that were completed in different periods. OTHER (INCOME) AND EXPENSES
2002 2001 2000 -------------------------- -------------------------- ----------- Change from Change from Amount Prior year Amount Prior year Amount ----------- ----------- ----------- ----------- ----------- OTHER OPERATING EXPENSE $ 167,768 -1.0% $ 169,442 21.3% $ 139,723 MAINTENANCE EXPENSE 41,200 -8.7% 45,136 32.5% 34,057 DEPRECIATION AND AMORTIZATION 98,198 5.5% 93,101 8.3% 85,989 INCOME TAXES (133,411) -850.6% 17,775 N/A (12,162) INTEREST CHARGES ON LONG-TERM DEBT 98,886 21.2% 81,599 26.5% 64,513 INTEREST CHARGES- OTHER 21,395 61.9% 13,219 -3.7% 13,732 INTEREST ACCRUED ON DEFERRED ENERGY (12,414) -71.0% (42,743) N/A -- OTHER INCOME (273) -93.5% (4,200) -4.8% (4,413) OTHER EXPENSE 9,933 110.9% 4,709 112.5% 2,216 INCOME TAXES - OTHER INCOME AND EXPENSE 1,627 -89.1% 14,962 1145.8% 1,201
The decrease in Other operating expense for 2002 reflects $10.0 million of reserve provisions which were established in 2001 for retail uncollectible accounts in NPC's service territory and $12.6 million for uncollectible amounts associated with the California Power Exchange, which NPC continues to pursue for collection. Additional factors that resulted in lower Other operating expenses during 2002 include the reversal of a $6 million reserve originally established in 2001 pursuant to the PUCN order for costs associated with the conclusion of electric industry restructuring. NPC had no 2002 short-term incentive plan expense compared to $5.5 million in 2001. Increases in Other operating expense during 2002 include $14.7 million in legal and advisory fees associated with liquidity issues and the consequences of the PUCN's deferred energy rate case decision. Additional increases in Other operating expense in 2002 included $12.1 million related to collection for and write-off of uncollectible accounts. 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). The level of NPC's maintenance and repair expenses fluctuates primarily upon the scheduling, magnitude, and number of generation unit overhauls at NPC's generating stations. As a result of an outage delay at Reid-Gardner and deferred outage at Clark Station, maintenance costs were decreased by $6.1 million in 2002. These decreases were partially offset by miscellaneous increases at Mohave and Navajo totaling $1.4 million. 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. An increase in the computer depreciation rate pursuant to a PUCN order and additions to plant-in-service were the primary cause of NPC's increase in depreciation and amortization expense in 2002 compared to 2001. Depreciation and amortization were also higher in 2001 than 2000 due to an increase in plant-in-service. As a result of net losses recognized during 2002 and 2000, NPC recorded an income tax benefit for those years. As a result of net income for 2001, NPC incurred income tax expense. See Note 10 of Notes to Financial Statements, Taxes, for additional information regarding the computation of income taxes. 74 NPC's interest charges on long-term debt increased in 2002 compared to 2001 due to additional issuances of long-term debt at higher interest rates during 2002 and to the payment of a full year of interest on $100 million of long-term debt issued throughout 2001. In 2002, NPC redeemed $15 million in debt and issued additional debt of $250 million. For 2001 compared to 2000, NPC's increased interest charges were attributable to the issuance of $700 million of long-term debt mentioned above. See Note 9 of Notes to Financial Statements, Long-Term Debt for additional information regarding long-term debt. NPC's interest charges-other increased in 2002 compared to 2001 due primarily to interest on extended payments to fuel and power suppliers resulting from renegotiated purchased power and fuel contracts. Increased credit facility fees also contributed to the increase in 2002 over the prior year (Refer to Liquidity and Capital Resources for further discussion of power and fuel contracts and the credit facilities). Interest charges-other for the year 2001 were comparable to 2000. NPC's interest accrued on deferred energy decreased during 2002, compared to 2001 due to a significant decline in the related deferred fuel and purchased power balances. For the period 2001 compared to 2000, the increase in these carrying charges was attributable to the related increases in deferred fuel and purchased power balances. (Refer to Regulation and Rate Proceedings for further discussion of deferred energy accounting issues). NPC's other income for the year 2002 decreased from 2001 due, primarily, to an expense adjustment related to sale of SO2 emission allowances ordered by the PUCN. Other income for the year 2001 was comparable to 2000. For the year 2001 compared to 2000, the decrease was primarily attributable to the classification, in 2001, of lease revenues as operating income, while in 2000 these revenues were classified as non-operating. NPC's other expense increased in 2002 compared to 2001 due primarily to costs associated with NPC's contribution to a group opposed to the inclusion of an Electric Utility Advisory Question to the November 2002 general election ballot. NPC also incurred increased costs for assistance programs, corporate advertising, and miscellaneous customer information activities. For the year 2001, compared to 2000, NPC's other expense increased, as a result of increased expenditures to its low-income energy assistance programs. Income Taxes - Other Income and Expense decreased in 2002 as a result of lower other income and expense than 2001 primarily due to lower accrued interest on deferred energy costs. The increase from 2000 to 2001 was also caused by the corresponding increase in other income and expense from 2000 to 2001. ANALYSIS OF CASH FLOWS NPC's net cash flows improved in 2002 compared to 2001, resulting from an increase in cash flows from operating activities offset in part by decreases in cash flows from investing and financing activities. Although NPC recorded a substantial loss for 2002, compared to net income in 2001, the current year's loss resulted largely from the write-off of disallowed deferred energy costs for which the cash outflow had occurred in 2001. Other factors contributing to 2002's improved cash flows from operating activities include the collection of deferred energy costs from customers and lower energy prices. Cash flows from operating activities in the current year also reflect the receipt of an income tax refund. Cash flows from investing activities decreased because of additional cash utilized for construction activities during 2002 compared to 2001. Cash flows from financing activities were lower because of decreases in net long-term debt issued, decreases in short-term borrowings and less cash invested by NPC's parent, SPR, during 2002. 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 75 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 Note 9 Long-Term Debt and Note 12 Short-Term Borrowings of the Notes to 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. LIQUIDITY AND CAPITAL RESOURCES NPC had cash and cash equivalents of approximately $95 million at December 31, 2002, and approximately $96 million at February 28, 2003. 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 long-term debt during 2003 totaling approximately $578 million, which NPC expects to finance with internally generated funds, including the recovery of deferred energy, and the issuance of debt. NPC's liquidity would be significantly affected by an adverse decision in the lawsuit by Enron, or by unfavorable rulings by the PUCN in pending or future NPC or SPPC rate cases. S&P and Moody's have NPC's credit ratings on "negative outlook" and "stable", respectively. Future downgrades by either S&P or Moody's could preclude NPC's access to the capital markets, and could adversely affect NPC's ability to continue to purchase power and fuel. Adverse developments with respect to any one or a combination of the foregoing could have a material adverse effect on NPC's financial condition and liquidity, and could make it difficult for NPC to continue to operate outside of bankruptcy. EFFECT OF RATE CASE DECISIONS On March 29 and April 1, 2002, following the decision by the PUCN in NPC's deferred energy rate case, S&P and Moody's lowered NPC's unsecured debt ratings to below investment grade. On April 23 and 24, 2002, NPC's unsecured debt ratings were further downgraded and its secured debt ratings were downgraded to below investment grade. As a result of these downgrades, NPC's ability to access the capital markets to raise funds were severely limited. Since SPR's credit ratings were similarly downgraded, SPR's ability to make capital contributions to NPC also became severely limited. Commercial Paper and Credit Facilities. In connection with the credit downgrades by S&P and Moody's, NPC lost its A2/P2 commercial paper ratings and can no longer issue commercial paper. At the time, NPC had a commercial paper balance outstanding of $198.9 million, with a weighted average interest rate of 2.52%. Since NPC was no longer able to issue its commercial paper, it paid off its maturing commercial paper with the proceeds of borrowings under its credit facility and terminated its commercial paper program on May 28, 2002. NPC does not expect to have direct access to the commercial paper market for the foreseeable future. NPC's $200 million unsecured revolving credit facility was also affected by the decision in the deferred energy rate case. Following the announcement of that decision, the banks participating in NPC's credit facility determined that a material adverse event had occurred with respect to NPC, thereby precluding NPC from borrowing funds under its credit facility. The banks agreed to waive the consequences of the material adverse event in a waiver letter and amendment that was executed on April 3, 2002. As required under the waiver letter and amendment, NPC issued and delivered its General and Refunding Mortgage Bond, Series C, due November 28, 2002, in the principal amount of $200 million, to the Administrative Agent as security for the credit facility. 76 This facility was paid in full and terminated on October 30, 2002 with proceeds from the issuance of NPC's $250 million 10 7/8% General and Refunding Mortgage Notes, Series E, due 2009. Power Supplier Issues. Historically, NPC has purchased a significant portion of the power that it sells to its customers from power suppliers. As discussed under Sierra Pacific Resources, Liquidity and Capital Resources, following the PUCN's decision on March 29, 2002 in NPC's deferred energy rate case, a number of power suppliers requested collateral from NPC under the WSPP standard contract. NPC informed such suppliers that a simultaneous call for 100% mark-to-market collateral in the short term would likely not be met and proposed extended payment terms for the above-market portions of NPC's existing power contracts. Although several power suppliers terminated their contacts with NPC (as discussed below), the remaining suppliers accepted the deferred payments, which were paid in full by October 29, 2002. In early May of 2002, Enron, MSCG, Reliant Energy Services, Inc. and several smaller suppliers terminated their power deliveries to NPC. These terminating suppliers asserted their contractual right under the WSPP agreement to terminate deliveries based upon NPC's alleged failure to provide adequate assurance of its performance under the WSPP agreement to any of its suppliers. Each of these terminating suppliers has asserted a claim for liquidated damages under the terminated power supply contracts. Enron filed a complaint with the United States Bankruptcy Court for the Southern District of New York seeking to recover approximately $216 million against NPC for liquidated damages for power supply contracts terminated by Enron in May 2002 and for power previously delivered to NPC. NPC has denied liability on numerous grounds, including deceit and misrepresentation in the inducement (including, but not limited to, misrepresentation as to Enron's ability to perform), and fraud, unfair trade practices and market manipulation. NPC filed motions to dismiss for lack of jurisdiction and/or for a stay of all proceedings pending the actions of the Utilities' proceedings under Section 206 of the Federal Power Act at the FERC (see Regulation and Rate Proceedings). The Utilities have also filed proofs of claims and counterclaims against Enron, for the full amount of the approximately $300 million claimed to be owed and additional damages, as well as for unspecified damages to be determined during the case as a result of acts and omissions of Enron in manipulating the power markets. On December 19, 2002, the bankruptcy judge granted Enron's motion for partial summary judgment on Enron's claim for $17.7 million for energy delivered by Enron in April 2002, for which NPC did not pay. The court ordered this money to be deposited into an escrow account not subject to claims of Enron's creditors and subject to refund depending on the outcome of the Utilities' FERC cases on the merits. NPC made the deposit as ordered. The bankruptcy court denied NPC's motion to stay the proceeding pending the outcome of the Utilities' Section 206 case at the FERC and denied NPC's motion to dismiss for lack of jurisdiction as to Enron's claims for power previously delivered to the Utilities. The court stated that it would rule in due course on Enron's motion for partial summary judgment to require NPC to post $200 million pending the outcome of the case on the merits, and for judgment on the merits on Enron's liquidated damage claim (contract price less market price on the date of termination) relating to power it did not deliver under contracts terminated by Enron in May 2002. The court took under advisement the Utilities' motion to stay or dismiss Enron's claim for liquidated damages relating to the undelivered power and set a hearing on Enron's motion to dismiss the Utilities' counterclaims for April 3, 2003. The United States District Court for the Southern District of New York also denied the Utilities' motion to withdraw reference of the matter to the bankruptcy court without prejudice. The bankruptcy court currently has under submission (1) Enron's motion to dismiss NPC's counterclaims, (2) Enron's motion for partial summary judgment regarding the amounts alleged to be due for undelivered power and the posting of collateral for undelivered power, and (3) NPC's motion to dismiss or stay proceeding on Enron's claims relating to delivered power. Enron's motion to dismiss NPC's counterclaims is set for hearing on April 3, 2003. NPC is unable to predict the outcome of the motions. A decision adverse to NPC on Enron's motion for partial summary judgment, 77 or an adverse decision in the lawsuit with respect to liability as to Enron's claims on the merits for undelivered power, would have a material adverse effect on NPC's financial condition and liquidity and could make it difficult for NPC to continue to operate outside of bankruptcy. On June 10, 2002, Duke entered into an agreement with NPC, SPR and SPPC to supply up to 1,000 megawatts of electricity per hour, as well as natural gas, to fulfill NPC's customers' power requirements during the peak summer period. The effect of the Duke agreement was to replace the amount of contracted power and natural gas that would have been supplied by the various terminating suppliers, including Enron. Duke also agreed to accept deferred payment for a portion of the amount due under its existing power contracts with NPC for purchases made through September 15, 2002. On October 25, 2002, Duke was paid the full amount of the deferred payments. On September 5, 2002, MSCG initiated an arbitration pursuant to the arbitration provisions in various power supply contracts terminated by MSCG in April 2002. In the arbitration, MSCG is requesting that the arbitrator compel NPC to pay MSCG $25 million pending the outcome of any dispute regarding the amount owed under the contracts. NPC claims that nothing is owed under the contracts on various grounds, including breach by MSCG in terminating the contracts, and further, that the arbitrator does not have jurisdiction over NPC's contracts claims and defenses. In March 2003, the arbitrator ruled in NPC's favor and dismissed the arbitration in its entirety for lack of jurisdiction. On September 30, 2002, EPME notified NPC that it was terminating all transactions entered into with NPC under the WSPP agreement. On October 8, 2002, NPC received a letter from EPME seeking a termination payment of approximately $36 million with respect to the terminated WSPP agreement transactions. At the present time, NPC disagrees with EPME's calculation, and expects that net gains and losses relating to the terminated transactions, including a delayed payment amount of approximately $19 million owed to EPME for power deliveries through September 15, 2002, will result in a net payment due to NPC. If NPC continues to experience financial difficulty or if its credit ratings are further downgraded, NPC may experience considerable difficulty entering into new power supply contracts, particularly under traditional payment terms. If suppliers will not sell power to NPC under traditional payment terms, NPC may have to pre-pay its power requirements. If it does not have sufficient funds or access to liquidity to pre-pay its power requirements, particularly at the onset of the summer months, and is unable to obtain power through other means, NPC's business, operations and financial condition would be materially adversely affected and could make it difficult to provide reliable service to its customers or to continue to operate outside of bankruptcy. ACCOUNTS RECEIVABLE FACILITY On October 29, 2002, NPC established an accounts receivable purchase facility of up to $125 million, which was arranged by Lehman Brothers. The receivables purchase facility expires on August 28, 2003 unless NPC has activated the facility prior to that date, in which case the facility will be automatically extended to, and will expire on, October 28, 2003. If NPC elects to activate the receivables purchase facility, NPC will sell all of its accounts receivable generated from the sale of electricity to customers to its newly created bankruptcy remote special purpose subsidiary. The receivables sales will be without recourse except for breaches of customary representations and warranties made at the time of sale. The subsidiary will, in turn, sell these receivables to a bankruptcy-remote subsidiary of SPR. SPR's subsidiary will issue variable rate revolving notes backed by the purchased receivables. Lehman Brothers Holdings, Inc. has committed to be the sole initial committed purchaser of all of the variable rate revolving notes. The agreements relating to the receivables purchase facility contain various conditions to purchase, covenants and trigger events, and other provisions customary in receivables transactions. In addition to customary termination and mandatory repurchase events, the receivables purchase facility may terminate in the 78 event that either NPC or SPR defaults (i) in the payment of indebtedness, or (ii) in the payment of amounts due under a swap agreement, and such defaults aggregate to greater than $10 million and $5 million for NPC and SPR, respectively. Under the terms of the agreements relating to the receivables purchase facility, NPC's facility may not be activated or, if activated, will be terminated in the event of a material adverse change in the condition, operations or business prospects of NPC. In addition, the agreements contain a limitation on the payment of dividends by NPC to SPR that is identical to the limitation contained in NPC's General and Refunding Mortgage Notes, Series E, described below. SPR has agreed to guaranty NPC's performance of certain obligations as a seller and servicer under the receivables purchase facility. NPC has agreed to issue $125 million principal amount of its General and Refunding Mortgage Bonds upon activation of the receivables purchase facility. The full principal amount of the bond would secure certain of NPC's obligations as seller and servicer, plus certain interest, fees and expenses thereon to the extent not paid when due, regardless of the actual amounts owing with respect to the secured obligations. As a result, in the event of an NPC bankruptcy or liquidation, the holder of the bond securing the receivables purchase facility may recover more on a pro rata basis than the holders of other General and Refunding Mortgage securities, who could recover less on a pro rata basis, than they otherwise would recover. However, in no event will the holder of the bond recover more than the amount of obligations secured by the bond. NPC intends to use the accounts receivable purchase facility as a back-up liquidity facility and does not plan to activate this facility in the foreseeable future. NPC may activate the facility within five days upon the delivery of certain customary funding documentation and the delivery of the $125 million General and Refunding Mortgage Bond. MORTGAGE INDENTURES NPC's first mortgage indenture creates a first priority lien on substantially all of NPC's properties. As of December 31, 2002, $372.5 million of NPC's first mortgage bonds were outstanding. NPC agreed in connection with its Series E Notes that it would not issue any more first mortgage bonds. 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, 2002, $870 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 (1) 70% of net utility property additions, (2) the principal amount of retired General and Refunding Mortgage Bonds, and/or (3) 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. As of December 31, 2002, NPC had the capacity to issue approximately $1.04 billion of additional General and Refunding Mortgage securities. However, the financial covenants contained in the Series E Notes limits NPC ability to issue additional General and Refunding Mortgage Bonds or other debt. NPC has reserved $125 million of General and Refunding Mortgage bonds for issuance upon the initial funding of NPC's receivables facility. 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. PUCN ORDER On June 19, 2002, the PUCN issued a Compliance Order, Docket No. 02-4037 which requires that until such time as the order's authorization expires (December 31, 2003), NPC must either receive the prior approval of the PUCN or reach an equity ratio of 42% before paying any dividends to SPR. If NPC achieves a 42% 79 equity ratio prior to December 31, 2003, the dividend restriction ceases to have effect. As of December 31, 2002, NPC's equity ratio was 36.1%. On July 3, 2002, the BCP of the Nevada Attorney General's Office filed a petition with the PUCN requesting that the hearing in Docket No. 02-4037 be reopened to allow for the introduction of additional evidence or for the PUCN to reconsider its decision granting NPC the authority to issue long-term debt. On September 11, 2002, the PUCN denied the petition to reopen the proceeding and rescinded the portion of its Compliance Order that had previously required NPC to immediately issue $50 million to $100 million of debt. FINANCING TRANSACTIONS AND COVENANTS On October 25, 2002, NPC redeemed its 7 5/8% Series L, First Mortgage Bonds due November 1, 2002, in the aggregate principal amount of $15 million. On October 29, 2002, NPC issued and sold $250 million of its 10 7/8% General and Refunding Mortgage Notes, Series E, due 2009 for a purchase price of $235.6 million. The Series E Notes were issued with registration rights. The proceeds of the issuance were used to pay off NPC's $200 million credit facility and for general corporate purposes. The Series E Notes limit the amount of payments in respect of common stock that NPC may pay to SPR. However, that limitation does not apply to payments by NPC to enable SPR to pay its reasonable fees and expenses (including, but not limited to, interest on SPR's indebtedness and payment obligations on account of SPR's PIES) provided that those payments do not exceed $60 million for any one calendar year, those payments comply with any regulatory restrictions then applicable to NPC, and the ratio of consolidated cash flow to fixed charges for NPC's most recently ended four full fiscal quarters immediately preceding the date of payment is at least 1.75 to 1. The terms of the Series E Notes also permit NPC to make payments to SPR in an aggregate amount not to exceed $15 million from the date of the issuance of the Series E Notes. In addition, NPC may make dividend payments to SPR in excess of the amounts described above so long as, at the time of payment and after giving effect to the payment: there are no defaults or events of default with respect to the Series E Notes, NPC can meet a fixed charge coverage ratio test, and the total amount of such dividends is less than (i) the sum of 50% of NPC's consolidated net income measured on a quarterly basis cumulative of all quarters from the date of issuance of the Series E Notes, plus (ii) 100% of NPC's aggregate net cash proceeds from the issuance or sale of certain equity or convertible debt securities of NPC, plus (iii) the lesser of cash return of capital or the initial amount of certain restricted investments, plus (iv) the fair market value of NPC's investment in certain subsidiaries. The terms of the Series E Notes also restrict NPC from incurring any additional indebtedness unless (i) at the time the debt is incurred, the ratio of consolidated cash flow to fixed charges for NPC's most recently ended four quarter period on a pro forma basis is at least 2 to 1, or (ii) the debt incurred is specifically permitted, which includes certain credit facility or letter of credit indebtedness, obligations incurred to finance property construction or improvement, indebtedness incurred to refinance existing indebtedness, certain intercompany indebtedness, hedging obligations, indebtedness incurred to support bid, performance or surety bonds, and certain letters of credit issued to support NPC's obligations with respect to energy suppliers. If NPC's Series E Notes are upgraded to investment grade by both Moody's and S&P, the dividend restrictions and the restrictions on indebtedness applicable to the Series E Notes will be suspended and will no longer be in effect so long as the Series E Notes remain investment grade. Among other things, the Series E Notes also contain restrictions on liens (other than permitted liens, which include liens to secure certain permitted debt) and certain sale and leaseback transactions. In the event of a change of control of NPC, the holders of Series 80 E Notes are entitled to require that NPC repurchase the Series E Notes for a cash payment equal to 101% of the aggregate principal amount plus accrued and unpaid interest. The Series E Notes will mature October 15, 2009. CROSS DEFAULT PROVISIONS Certain financing agreements of NPC contain cross-default provisions that would result in an event of default under such financing agreements if there is a failure under other financing agreements of NPC and SPR to meet payment terms or to observe other covenants that would result in an acceleration of payments due. Most of these default provisions (other than ones relating to a failure to pay other indebtedness) provide for a cure period of 30-60 days from the occurrence of a specified event during which time, NPC or SPR may rectify or correct the situation before it becomes an event of default. The primary cross-default provisions in NPC's various financing agreements are briefly summarized below: o NPC's General and Refunding Mortgage Indenture provides for an event of default if a matured event of default under NPC's First Mortgage Indenture occurs; o The terms of NPC's Series E Notes provide that a default with respect to the payment of principal, interest or premium beyond the applicable grace period under any mortgage, indenture or other security instrument, by NPC or any of its restricted subsidiaries, relating to debt in excess of $15 million, triggers a right of the holders of the Series E Notes to require NPC to redeem the Series E Notes at a price equal to 100% of the aggregate principal amount plus accrued and unpaid interest and liquidated damages, if any, upon notice given by at least 25% of the outstanding Series E Notes holders; and o NPC's receivables purchase facility may terminate in the event that either NPC or SPR defaults (i) in the payment of indebtedness, or (ii) in the payment of amounts due under hedge agreements, and such defaults aggregate to greater than $10 million and $5 million for NPC and SPR, respectively. PENSION PLAN MATTERS SPR has a qualified pension plan that covers substantially all employees of SPR, NPC and SPPC. The annual net benefit cost for the plan will increase for 2003 by approximately $16.1 million over the 2002 cost of $18.4 million. As of September 30, 2002, the measurement date, the plan had assets with a fair value that was less than the present value of the accumulated benefit obligation under the plan. On December 6, 2002, NPC contributed a total of $13.05 million to meet its funding obligations under the plan. At the present time, NPC does not expect that any near term funding obligation will have a material adverse effect on its liquidity. 81 CONSTRUCTION EXPENDITURES AND FINANCING The table below provides NPC's consolidated cash construction expenditures and internally generated cash, net for 2000 through 2002 (dollars in thousands):
2002 2001 2000 Total ----------- ----------- ----------- ----------- Cash construction expenditures $ 250,441 $ 196,896 $ 196,636 $ 643,973 =========== =========== =========== =========== Net cash flow from operating activities $ 253,757 $ (757,402) $ 113,711 $ (389,934) Common and preferred cash dividends paid 10,000 33,014 88,308 131,322 ----------- ----------- ----------- ----------- Internally generated cash 243,757 (790,416) 25,403 (521,256) Investment by parent company 10,000 474,921 137,000 621,921 ----------- ----------- ----------- ----------- Total cash available $ 253,757 $ (315,495) $ 162,403 $ 100,665 =========== =========== =========== =========== Internally generated cash as a percentage of 97% N/A 13% N/A cash construction expenditures Total cash generated (used) as a percentage of 101% N/A 83% 16% cash construction expenditures
NPC's estimated cash construction expenditures for 2003 through 2007 are $1.068 billion. Construction expenditures for 2003 are projected to be $223 million and are expected to be financed by internally generated funds, including the recovery of deferred energy. Cash provided by internally generated funds during 2003 assumes, among other things, no disallowances on NPC's currently filed deferred energy rate case and the full recovery of such deferred energy amounts over three years, no additional disallowances related to NPC's appeal of its prior deferred energy case and no adverse decision in the lawsuit filed by Enron against NPC seeking $200 million in termination payments. Material disallowances of currently-filed or previously-filed deferred energy costs or an adverse decision with respect to the Enron lawsuit would have a material adverse effect on NPC's financial condition and future results of operations and could cause additional downgrades of its securities by the rating agencies and make it significantly more difficult to finance operations and to buy fuel and purchased power from third parties. See Regulation and Rate Proceedings, Nevada Matters for additional information regarding NPC's recently filed deferred energy rate case and prior deferred energy rate case and Liquidity and Capital Resources for additional information regarding the Enron lawsuit and the potential impact of a negative outcome with respect to any of these uncertainties. In the event that NPC's financial condition worsens, it may be unable to finance its construction expenditures with internally generated funds and instead may need to raise all or a portion of the necessary funds through the capital markets or from activating its accounts receivables purchase facility to provide additional liquidity. For additional information regarding the accounts receivables purchase facility, see Liquidity and Capital Resources. NPC may activate its receivables purchase facility within five days upon the delivery of certain customary funding documentation and the delivery of $125 million of its General and Refunding Mortgage Bonds to secure the facility. If a material adverse event were to occur, it could potentially trigger a termination event with respect to the receivables facility and would also make it more difficult for NPC to access the capital markets for any such financing needs. CONTRACTUAL OBLIGATIONS The table below provides NPC's consolidated contractual obligations, not including estimated construction expenditures described above, as of December 31, 2002, that NPC expects to satisfy through a 82 combination of internally generated cash and, as necessary, through the issuance of short-term and long-term debt (dollars in thousands):
PAYMENT DUE BY PERIOD 2003 2004 2005 2006 2007 Thereafter Total ----------- ----------- ----------- ----------- ----------- ----------- ----------- Long-Term Debt $ 354,677 $ 135,570 $ 6,091 $ 6,509 $ 5,949 $ 1,348,384 $ 1,857,180 Preferred Trust Securities -- -- -- -- -- 188,872 188,872 Purchased Power 408,656 241,957 220,343 204,666 189,434 3,456,297 4,721,353 Coal and Natural Gas 74,424 69,326 38,552 31,775 29,953 341,341 585,371 Operating Leases 2,263 1,170 869 181 119 459 5,061 Other Long-Term Obligations 75 100 -- -- -- -- 175 ----------- ----------- ----------- ----------- ----------- ----------- ----------- Total Contractual Cash Obligations $ 840,095 $ 448,123 $ 265,855 $ 243,131 $ 225,455 $ 5,335,353 $ 7,358,012 =========== =========== =========== =========== =========== =========== ===========
CAPITAL STRUCTURE As of December 31, 2002, NPC had no short-term debt outstanding. On October 29, 2002, NPC established an accounts receivable purchase facility of up to $125 million, which was arranged by Lehman Brothers. If NPC elects to activate the receivables purchase facility, NPC will sell all of its accounts receivable generated from the sale of electricity to customers to its newly created bankruptcy remote special purpose subsidiary. The receivables sales will be without recourse except for breaches of customary representations and warranties made at the time of sale. The subsidiary will, in turn, sell these receivables to a bankruptcy-remote subsidiary of SPR. SPR's subsidiary will issue variable rate revolving notes backed by the purchased receivables. Lehman Brothers Holdings, Inc. has committed to be the sole initial purchaser of all of the variable rate revolving notes. NPC intends to use the accounts receivable purchase facility as a back-up liquidity facility and does not plan to activate this facility in the foreseeable future. NPC may activate the facility within five days upon the delivery of certain customary funding documentation and the delivery of a $125 million General and Refunding Mortgage Bond. See Liquidity and Capital Resources for additional information regarding the terms and conditions of the accounts receivable purchase facility. NPC's actual consolidated capital structure at December 31, 2002, and 2001 was as follows (dollars in thousands):
2002 2001 ---------------- ---------------- Short-Term Debt (1) $ 354,677 11% $ 149,880 4% Long-Term Debt 1,488,597 47% 1,607,967 48% Preferred Trust Securities 188,872 6% 188,872 6% Common Equity 1,149,131 36% 1,393,583 42% ---------- --- ---------- --- TOTAL $3,181,277 100% $3,340,302 100% ========== === ========== ===
(1) Including current maturities of long-term debt. OTHER MATTERS On July 7, 2002, the Board of County Commissioners of Clark County, Nevada, added an Electric Utility Advisory Question to its November 5, 2002, general election ballot which asked voters in a non-binding initiative whether "the Nevada Legislature should take appropriate action to enable the electrical energy provider for southern Nevada to be a locally controlled, not for profit public utility." The Company and various private entities and public interest groups strongly opposed the measure. Although passing by a 57% majority, this was substantially below the level of support indicated in early polls. No bills related to this issue were introduced in the 2003 Nevada legislative session. 83 On August 22, 2002, SPR received a letter from the Southern Nevada Water Authority ("SNWA") stating that it was prepared to enter into good faith negotiations of definitive agreements to acquire NPC in some undetermined way (stock purchase or all or some of its assets) and to assume some unspecified amount of indebtedness, at a purchase price subject to adjustment at SNWA's discretion at the conclusion of negotiations and due diligence. On September 12, 2002, SPR responded with a letter stating that it did not view the SNWA's letter as an offer and expressing concerns with the SNWA's financing plans, certain significant legal issues with the proposal, SNWA's lack of utility management experience, and ambiguity in the proposal. SPR was served a complaint by a shareholder seeking class action status to require SPR to enter into negotiations. See Legal Proceedings for further details. SIERRA PACIFIC POWER COMPANY RESULTS OF OPERATIONS SPPC incurred a net loss from continuing operations of ($14.0) million in 2002, compared to net income of $22.7 million in 2001, and a net loss of ($4.1) million in 2000. SPPC's operating results for 2002 reflect the write-off of approximately $58 million (before taxes) of deferred energy costs and related carrying charges as a result of the PUCN's May 28, 2002, decision in SPPC's deferred energy rate case to disallow $53 million of deferred purchased fuel and power costs. The PUCN's decision is being challenged by SPPC in a lawsuit filed in Nevada state court. During 2002, SPPC paid $44.9 million in common stock dividends to its parent, SPR, $10 million of which was reinvested in SPPC as a contribution to capital. SPPC also paid $3.9 million in dividends to holders of its preferred stock. SPPC closed the sale of its water utility business in June 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. 84 The components of gross margin are (dollars in thousands):
2002 2001 2000 ----------- ----------- ----------- Operating Revenues: Electric $ 931,251 $ 1,401,778 $ 894,919 Gas 149,783 145,652 100,803 ----------- ----------- ----------- Total Revenues 1,081,034 1,547,430 995,722 ----------- ----------- ----------- Energy Costs: Electric 687,652 1,113,634 678,727 Gas 120,603 113,364 67,035 ----------- ----------- ----------- Total Energy Costs 808,255 1,226,998 745,762 ----------- ----------- ----------- Gross Margin $ 272,779 $ 320,432 $ 249,960 =========== =========== =========== Gross Margin by Segment: Electric $ 243,599 $ 288,144 $ 216,192 Gas 29,180 32,288 33,768 ----------- ----------- ----------- Total $ 272,779 $ 320,432 $ 249,960 =========== =========== ===========
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
2002 2001 2000 ------------------------ ------------------------ ---------- Change from Change from Amount Prior year Amount Prior year Amount ---------- ----------- ---------- ----------- ---------- ELECTRIC OPERATING REVENUES: Residential $ 218,663 4.0% $ 210,350 17.7% $ 178,701 Commercial 268,631 10.1% 243,883 23.9% 196,846 Industrial 269,610 6.2% 253,936 29.5% 196,143 ---------- ---------- ---------- Retail revenues 756,904 6.9% 708,169 23.9% 571,690 Other (1) 174,347 -74.9% 693,609 114.6% 323,229 ---------- ---------- ---------- TOTAL REVENUES $ 931,251 -33.6% $1,401,778 56.6% $ 894,919 ========== ========== ========== Retail sales in thousands of megawatt-hours (MWh) 8,692 -0.4% 8,729 -0.9% 8,807 Average retail revenue per MWh $ 87.08 7.3% $ 81.13 25.0% $ 64.91
(1) Primarily wholesale, as discussed below SPPC's retail revenues were higher in 2002 primarily as a result of a net rate increase resulting from SPPC's general rate and deferred energy cases (refer to Regulation and Rates Proceedings, later). Effective June 1, 2002, the PUCN authorized an increase in SPPC's energy related rates that are used to recover current and previously incurred fuel and purchased power costs. The decrease in 2002 Other revenues was primarily due to the lower sales resulting from a reduction in transactions entered into for hedging purposes and the optimization of purchased power costs. See Energy Supply, later, for a discussion of the Utilities' purchased power procurement strategies. The increase in SPPC's 2001 retail revenues was primarily due to rate increases resulting from the Global Settlement and Comprehensive Energy Plan (refer to Regulation and Rate Proceedings, later). These increases in rates were used to recover fuel and purchased power costs. 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 85 wholesale sales compared to 2000 was a result of market conditions and SPPC's power procurement activities. See Energy Supply, later, for a discussion of the Utilities' purchased power procurement strategies. GAS OPERATING REVENUES
2002 2001 2000 ---------------------------- --------------------------- ----------- Change from Change from Amount Prior year Amount Prior year Amount ----------- ------------ ----------- ------------- ----------- GAS OPERATING REVENUES: Residential $ 76,400 19.7% $ 63,815 46.6% $ 43,541 Commercial 37,018 20.7% 30,680 43.6% 21,368 Industrial 20,252 12.9% 17,941 58.7% 11,307 ----------- ----------- ----------- Retail revenues 133,670 112,436 76,216 Wholesale 16,113 -51.6% 33,298 46.0% 22,805 Miscellaneous -- -100.0% (82) -104.6% 1,782 ----------- ----------- ----------- TOTAL REVENUES $ 149,783 2.8% $ 145,652 44.5% $ 100,803 =========== =========== =========== Retail sales in thousands of decatherms 14,030 -1.7% 14,276 7.8% 13,240 Average retail revenues per decatherm $ 9.53 20.9% $ 7.88 36.8% $ 5.76
2002 retail gas revenues were significantly higher than the prior year primarily due to a rate increase resulting from SPPC's purchased gas adjustment filing. Effective November 5, 2001, the PUCN authorized this increase in energy related rates that are used to recover current and previously incurred purchased gas. Other gas revenues were significantly lower in 2002, due to lower wholesale prices and sales. Gas revenues rose in 2001, as compared to 2000 primarily due to the fact that the PUCN allowed SPPC to implement two gas rate increases. 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. Other revenues were higher due to an increase in wholesale gas sales. PURCHASED POWER
2002 2001 2000 ------------------------------------- ------------------------------------- --------------- Change from Change from Amount Prior Year Amount Prior Year Amount ---------------- ----------------- ---------------- ----------------- --------------- PURCHASED POWER $ 545,040 -46.9% $ 1,025,741 130.5% $ 444,979 Purchased power in thousands of MWh 7,206 -5.1% 7,591 3.3% 7,349 Average cost per MWh of Purchased power (1) $ 63.59 -52.9% $ 135.13 123.2% $ 60.55
(1) Not including contract termination costs, discussed below Purchased power costs decreased dramatically in 2002 due to overall purchase power prices decreasing by 52.9%. These price decreases were the result of a less volatile energy market. The overall decrease in the cost of purchased power was offset in part by an $86.8 million reserve provision recorded in the second quarter for terminated contracts. Purchased power costs also reflect a 40% decrease in wholesale sales activity. Purchases associated with risk management activities, which include transactions entered into for hedging purposes 86 and to optimize purchased power costs, are included in the purchased power amounts. See Energy Supply, later, for a discussion of the Utilities' purchased power procurement strategies. Purchased power costs were higher in 2001 than 2000 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 2001 due to hedging activities in response to higher purchased power prices. FUEL FOR POWER GENERATION
2002 2001 2000 ------------------------------------- ------------------------------------- --------------- Change from Change from Amount Prior Year Amount Prior Year Amount ---------------- ----------------- ---------------- ----------------- --------------- FUEL FOR POWER GENERATION $ 144,143 -49.7% $ 286,719 22.7% $ 233,748 Thousands of MWh generated 4,699 -21.5% 5,986 4.0% 5,756 Average fuel cost per MWh of Generated Power $ 30.67 -36.0% $ 47.90 18.0% $ 40.61
Fuel for power generation costs decreased 49.7% in 2002 as compared to 2001 due primarily to decreased natural gas prices and, to a lesser extent, to lower system load requirements. Fuel for generation costs in 2001 were higher than 2000 due to higher gas prices and an increase in volumes purchased to accommodate greater system load. GAS PURCHASED FOR RESALE
2002 2001 2000 ------------------------------------- ------------------------------------- --------------- Change from Change from Amount Prior Year Amount Prior Year Amount ---------------- ----------------- ---------------- ----------------- --------------- GAS PURCHASED FOR RESALE $ 91,961 -32.6% $ 136,534 64.1% $ 83,199 Gas Purchased for Resale (in thousands of decatherms) 17,930 7.0% 16,756 -9.2% 18,457 Average cost per decatherm $ 5.13 -37.1% $ 8.15 80.7% $ 4.51
The cost of gas purchased for resale decreased in 2002 as compared to 2001 primarily as a result of lower unit prices more than offsetting an increase in quantities. The significant gas price decreases are consistent with the increase in availability. Although there was a lower demand by retail customers as a result of warmer weather, SPPC sold more volume to wholesale customers causing the increase in quantities. As compared to 2000, the cost of gas purchased for resale increased in 2001 because a decrease in 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 higher unit prices were attributable to increased demand for gas in the Pacific Northwest and additional transportation fees. 87 DEFERRAL OF ENERGY COSTS - NET
2002 2001 2000 ------------------------------------- ------------------------------------- --------------- Change from Change from Amount Prior Year Amount Prior Year Amount ---------------- ----------------- ---------------- ----------------- --------------- Deferred energy costs - electric - net $(54,632) -72.5% $ (198,826) N/A $ -- Deferred energy costs disallowed 56,958 N/A -- N/A -- Deferred energy costs - gas - net 24,785 N/A (23,170) 43.3% (16,164) -------- ---------- -------- Total $ 27,111 N/A $ (221,996) N/A $(16,164) ======== ========== ========
The change in Deferred energy costs-electric-net for the twelve months ended December 31, 2002, compared to the same period the prior year, reflects the amortization in 2002 of prior deferred costs pursuant to the PUCN's decision on SPPC's deferred energy rate case, which resulted in increased rates beginning June 1, 2002. The amortization was offset in part by the recording of current year deferrals of electric energy costs, reflecting 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 also reflects the deferral in the second quarter of 2002 of approximately $82 million for contract termination costs and the second quarter 2002 write-off of $53 million of electric deferred energy costs incurred in the nine months ended November 30, 2001, that were disallowed by the PUCN in their May 28, 2002, decision on SPPC's deferred energy rate case. See more detail in Note 17 of Notes to Financial Statements, Commitments and Contingencies. 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 local distribution company (LDC). In 2001, the deferral increased in 2001 due to higher gas costs incurred by SPPC. The significant change from 2001 is attributed to lower gas costs in 2002 combined with the recovery of fuel and purchased power costs through current rates, which exceeded the actual fuel and purchase power costs. Deferred energy costs disallowed reflects a write-off of $4 million in gas costs, incurred in the twelve months ended April 2002, that were disallowed by the PUCN in their December 23, 2002 decision on SPPC's Purchase Gas Adjustment rate case. See Critical Accounting Policies, earlier, and Note 1 of Notes to Financial Statements, Summary of Significant Accounting Policies for more information regarding deferred energy accounting. ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFUDC)
2002 2001 2000 ------------------------------------- ------------------------------------- --------------- Change from Change from Amount Prior Year Amount Prior Year Amount ---------------- ----------------- ---------------- ----------------- --------------- ALLOWANCE FOR OTHER FUNDS USED DURING CONSTRUCTION $ 117 -86.3% $ 856 139.8% $ 357 ALLOWANCE FOR BORROWED FUNDS USED DURING CONSTRUCTION 1,858 181.5% 660 -76.3% 2,779 ------------ ------------ ------------ $ 1,975 30.3% $ 1,516 -51.7% $ 3,136 ============ ============ ============
AFUDC for SPPC is higher in 2002 compared to 2001 due to an increase in construction work-in-progress (CWIP) and because AFUDC in 2001 reflected an adjustment to refine amounts assigned to specific components of facilities that were completed in different periods. This increase was offset in part by a decrease in the AFUDC rate. AFUDC is lower in 2001 compared to 2000 because of adjustments to amounts assigned to 88 specific components of facilities that were completed in different periods offset by an increase in the AFUDC rate. OTHER (INCOME) AND EXPENSES
2002 2001 2000 ----------------------------------- ------------------------------------- ------------- Change from Change from Amount Prior Year Amount Prior Year Amount -------------- ----------------- ---------------- ----------------- ------------- OTHER OPERATING EXPENSE $ 106,122 -10.5% $ 118,526 22.2% $ 97,021 MAINTENANCE EXPENSE 23,240 -4.6% 24,363 32.3% 18,420 DEPRECIATION AND AMORTIZATION 76,373 5.9% 72,103 0.7% 71,630 INCOME TAXES (6,922) -181.4% 8,507 N/A (672) INTEREST CHARGES ON LONG-TERM DEBT 66,474 20.4% 55,199 49.7% 36,865 INTEREST CHARGES-OTHER 10,663 43.5% 7,433 -34.3% 11,312 INTEREST ACCRUED ON DEFERRED ENERGY (10,644) -14.6% (12,461) 5978.5% (205) OTHER INCOME (4,266) 101.9% (2,113) -37.9% (3,405) OTHER EXPENSE 6,577 6.5% 6,176 23.4% 5,003 INCOME TAXES-OTHER INCOME AND EXPENSE 2,431 N/A (91) -86.8% (690)
The decrease in Other operating expense for 2002 reflects $8.6 million of reserve provisions which were established in 2001 for retail uncollectible accounts in SPPC's service territory and uncollectible amounts associated with the California Power Exchange. Additional factors that resulted in lower Other operating expenses during 2002 include the reversal of a $7.0 million reserve originally established in 2001 pursuant to the PUCN order for costs associated with the conclusion of electric industry restructuring. SPPC had no 2002 short-term incentive plan expense compared to $4.2 million in 2001. Increases in Other operating expense during 2002 include $9.0 million in legal and advisory fees associated with liquidity issues and the consequences of the PUCN's deferred energy rate case decision. 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. 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. Depreciation and amortization were higher in 2002 than 2001 due to an increase in plant-in-service and an increase to depreciation of $1.8 million to reflect an adjustment to depreciation rates related to combustion turbines. These increases were offset in part by a PUCN-ordered reduction in depreciation rates that was implemented June 1, 2002. Depreciation and amortization were also higher in 2001 than 2000 due to an increase in plant-in-service. As a result of net losses from continuing operations recognized during 2002 and 2000, SPPC recorded an income tax benefit for those years. Due to net income from continuing operations, SPPC recorded income tax expense for 2001. SPPC's Interest charges on long-term debt increased in 2002 compared to 2001 due to additional issuances of long-term debt at higher interest rates and to the payment of a full year of interest on $320 million of long-term debt issued in May 2001. In 2002, SPPC redeemed approximately $4 million in debt and issued additional debt of $100 million. For 2001 compared to 2000, SPPC's increased interest charges were attributable to the issuance of $320 million of long-term debt. 89 SPPC's Interest charges-other increased in 2002 compared to 2001 due to interest on extended payments to fuel and power suppliers resulting from renegotiated purchased power and fuel contracts, interest on short term notes, and credit facility fees (refer to Liquidity and Capital Resources for further discussion of power and fuel contracts and the credit facilities). SPPC's interest charges-other decreased in 2001 compared to 2000 due to a decrease in commercial paper balances in 2001. SPPC's interest accrued on deferred energy decreased in 2002, compared to 2001 due to a decline in carrying charges on deferral of fuel and purchased power balances in 2002 as compared to 2001. For 2001, the increase over 2000 was due to the increases in deferred fuel and purchased power balances pursuant to AB 369. (Refer to Regulation and Rate Proceedings for discussion of deferred energy issues). SPPC's Other income for 2002 compared to 2001 increased due to increased interest and dividend income and gains on disposition of property. For 2001 as compared to 2000 the decrease was attributable to reductions in lease revenues, interest and dividend income, and miscellaneous gains on dispositions of property. SPPC's Other expense increased in 2002 compared to 2001 due primarily to increased expenditures to its low-income energy assistance programs. For 2001 as compared to 2000 Other expense increased due to increased expenses attributable to SPPC's subsidiaries, and by costs relating to SPPC's divestiture of its water business. Net tax expense on other income and expense increased in 2002 over 2001 because in 2001 certain benefits related to sale of the water utility business were recorded in other income and expense. These benefits were the result of the true-up of the 2000 tax return recorded in 2001. In 2001, a net tax benefit was recorded due to the net excess of other expenses over other income for the year. DISCONTINUED OPERATIONS
2002 2001 2000 ----------------------------------- ------------------------------------- ------------- Change from Change from Amount Prior Year Amount Prior Year Amount -------------- ----------------- ---------------- ----------------- ------------- Income from operations of water business $ -- -100.0% $ 1,022 -89.4% $ 9,634
SPPC closed the sale of its water utility business in 2001. Accordingly, the water business is reported as a discontinued operation. Income from operations of the water business decreased in 2001 compared to 2000 as a result of the sale of the water business in June 2001, prior to the seasonal increase in revenues resulting from higher water send-out. ANALYSIS OF CASH FLOWS SPPC's net cash flows improved in 2002 compared to 2001, resulting primarily from an increase in cash flows from operating activities offset in part by a decrease in cash flows from investing activities. Although SPPC recorded a net loss during 2002 compared to net income in 2001 the current year's loss resulted largely from the write-off of disallowed deferred energy costs for which the cash outflow had occurred in 2001. Other factors contributing to 2002's improved cash flows from operating activities include the collection of deferred energy costs from customers and lower energy prices. Also, cash flows from operating activities in the current year reflect the receipt of an income tax refund. Cash flows from investing activities decreased in 2002 because 2001 investing activities included cash provided from the sale of the assets of SPPC's water business. Cash flows from financing activities during 2002 were comparable to 2001. 90 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 of Notes to the Financial Statements, Preferred Stock and Preferred Trust Securities, offset in part by capital contributions from SPR. LIQUIDITY AND CAPITAL RESOURCES SPPC had cash and cash equivalents of approximately $88.9 million at December 31, 2002, and approximately $104.2 million at February 28, 2003. As discussed in Construction Expenditures and Financing and Capital Structure, SPPC anticipates having capital requirements for construction costs and for the repayment of maturing long-term debt during 2003 totaling approximately $222 million, which SPPC expects to finance with internally generated funds, including the recovery of deferred energy and the issuance of debt. SPPC's future liquidity could be significantly affected by unfavorable rulings by the PUCN in pending or future SPPC or NPC rate cases. S&P and Moody's have SPPC's credit ratings on "negative outlook" and "stable", respectively. Future downgrades by either S&P or Moody's could preclude SPPC's access to the capital markets and could adversely affect SPPC's ability to continue purchasing power and fuel. Adverse developments with respect to any one or a combination of the factors and contingencies set forth above could have a material adverse effect on SPPC's financial condition and liquidity, and could make it difficult to continue to operate outside of bankruptcy. EFFECT OF RATE CASE DECISIONS On March 29 and April 1, 2002, following the decision by the PUCN in NPC's deferred energy rate case, S&P and Moody's lowered SPPC's unsecured debt ratings to below investment grade. On April 23 and 24, 2002, SPPC's unsecured debt ratings were further downgraded and its secured debt ratings were downgraded to below investment grade. The decision of the PUCN on May 29, 2002, on SPPC's deferred energy application to disallow $53 million of deferred purchased fuel and power costs accumulated between March 1, 2001 and November 30, 2001, did not result in any further downgrades of SPPC's securities. As a result of the downgrades, SPPC's ability to access the capital markets to raise funds is severely limited. Since SPR's credit ratings were similarly downgraded, SPR's ability to make capital contributions to SPPC also became severely limited. Commercial Paper and Credit Facilities. In connection with the credit ratings downgrades referenced above, SPPC lost its A2/P2 commercial paper ratings and can no longer issue commercial paper. At the time, SPPC had a commercial paper balance outstanding of $47.7 million with a weighted average interest rate of 2.49%. SPPC paid off its maturing commercial paper with the proceeds of borrowings under its credit facility and terminated its commercial paper program on May 28, 2002. SPPC does not expect to have direct access to the commercial paper market for the foreseeable future. SPPC's $150 million unsecured revolving credit facility was also affected by the downgrade in SPPC's credit rating. Under this facility, SPPC was required, in the event of a ratings downgrade of its senior unsecured debt, to secure the facility with General and Refunding Mortgage Bonds. In satisfaction of its obligation to 91 secure the credit facility, on April 8, 2002, SPPC issued and delivered its General and Refunding Mortgage Bond, Series B, due November 28, 2002, in the principal amount of $150 million, to the Administrative Agent for the credit facility. As of May 10, 2002, SPPC had borrowed the entire $150 million of funds available under its credit facility to, in part, pay off maturing commercial paper, maintaining a cash balance at SPPC. This facility was paid in full and terminated on October 31, 2002 with available cash and proceeds from SPPC's $100 million Term Loan Facility. Power Supplier Issues. Historically, SPPC has purchased a significant portion of the power that it sells to its customers from power suppliers. As discussed under Sierra Pacific Resources, Liquidity and Capital Resources, following the PUCN's decision on March 29, 2002 in NPC's deferred energy rate case, a number of power suppliers requested collateral from SPPC and NPC under the WSPP standard contract. Both SPPC and NPC informed such suppliers that a simultaneous call for 100% mark-to-market collateral in the short term would likely not be met. Several power suppliers terminated their contacts with SPPC (as discussed above). In early May of 2002, Enron, MSCG, Reliant Energy Services, Inc. and several smaller suppliers terminated their power deliveries to SPPC. These terminating suppliers asserted their contractual right under the WSPP agreement to terminate deliveries based upon SPPC's alleged failure to provide adequate assurance of its performance under the WSPP agreement to any of its suppliers. Each of these terminating suppliers has asserted, or has indicated that it will assert, a claim for liquidated damages under the terminated power supply contracts. Enron filed a complaint with the United States Bankruptcy Court for the Southern District of New York seeking to recover approximately $93 million against SPPC for liquidated damages for power supply contracts terminated by Enron in May 2002 and for power previously delivered to SPPC. SPPC has denied liability on numerous grounds, including deceit and misrepresentation in the inducement, (including, but not limited to, misrepresentation as to Enron's ability to perform) and for fraud, unfair trade practices, and market manipulation. SPPC filed motions to dismiss for lack of jurisdiction and/or for a stay of all proceedings pending the actions of the Utilities' 206 actions at the FERC (see Regulation and Rate Proceedings). The Utilities have also filed proofs of claims and counterclaims against Enron, for the full amount of the approximately $300 million claimed to be owed and additional damages, for unspecified damages to be determined during the case as a result of acts and omissions of Enron in manipulating the power markets. On December 19, 2002, the bankruptcy judge granted Enron's motion for partial summary judgment on Enron's claim for $6.7 million for energy delivered by Enron in April 2002, for which SPPC did not pay. The court ordered this money to be deposited into an escrow account not subject to claims of Enron's creditors and subject to refund depending on the outcome of the Utilities' FERC cases on the merits. The bankruptcy court denied SPPC's motion to stay the proceeding pending the outcome of the Utilities' Section 206 case at the FERC and denied SPPC's motion to dismiss for lack of jurisdiction as to Enron's claims for power previously delivered to the Utilities. The court stated that it would rule in due course on Enron's motion for partial summary judgment to require SPPC to post $87 million pending the outcome of the case on the merits, and for judgment on the merits on Enron's liquidated damage claim (contract price less market price on the date of termination) relating to power it did not deliver under contracts terminated by Enron in May 2002. The court took under advisement the Utilities' motion to stay or dismiss Enron's claim for liquidated damages relating to the undelivered power and set a hearing on Enron's motion to dismiss the Utilities' counterclaims for April 3, 2003. The United States District Court for the Southern District of New York also denied the Utilities' motion to withdraw reference of the matter to the bankruptcy court without prejudice. The bankruptcy court currently has under submission (1) Enron's motion to dismiss SPPC's counterclaims, (2) Enron's motion for partial summary judgment regarding the amounts alleged to be due for undelivered power and the posting of collateral for undelivered power, and (3) SPPC's motion to dismiss or stay proceeding on Enron's claims relating to delivered power. Enron's motion to dismiss SPPC's counterclaims is 92 set for hearing on April 3, 2003. SPPC is unable to predict the outcome of the motions. A decision adverse to SPPC on Enron's motion for partial summary judgment, or an adverse decision in the lawsuit with respect to liability as to Enron's claims on the merits for undelivered power, would have a material adverse effect on SPPC's financial condition and liquidity and would make it difficult to continue to operate outside of bankruptcy. If SPPC continues to experience financial difficulty or if its credit ratings are further downgraded, SPPC may experience considerable difficulty entering into new power supply contracts, particularly under traditional payment terms. If suppliers will not sell power to SPPC under traditional payment terms, SPPC may have to pre-pay its power requirements. If it does not have sufficient funds or access to liquidity to pre-pay its power requirements, SPPC's business, operations and financial condition will be materially adversely affected and could make it difficult for SPPC to provide reliable service to its customers or to continue to operate outside of bankruptcy. ACCOUNTS RECEIVABLE FACILITY On October 29, 2002, SPPC established an accounts receivable purchase facility of up to $75 million, which was arranged by Lehman Brothers. The receivables purchase facility expires on August 28, 2003 unless SPPC has activated the facility prior to that date, in which case the facility will be automatically extended to, and will expire on, October 28, 2003. If SPPC elects to activate the receivables purchase facility, SPPC will sell all of its accounts receivable generated from the sale of electricity and natural gas to customers to its newly created bankruptcy remote special purpose subsidiary. The receivables sales will be without recourse except for breaches of customary representations and warranties made at the time of sale. The subsidiary will, in turn, sell these receivables to a bankruptcy-remote subsidiary of SPR. SPR's subsidiary will issue variable rate revolving notes backed by the purchased receivables. Lehman Brothers Holdings, Inc. has committed to be the sole initial committed purchaser of all of the variable rate revolving notes. The agreements relating to the receivables purchase facility contain various conditions to purchase, covenants and trigger events, and other provisions customary in receivables transactions. In additional to customary termination and mandatory repurchase events, the receivables purchase facility may terminate in the event that either SPPC or SPR defaults (i) on the payment of indebtedness, or (ii) on the payment of amounts due under a swap agreement, and such defaults aggregate to greater than $10 million and $5 million for SPPC and SPR, respectively. Under the terms of the agreements relating to the receivables purchase facility, SPPC's facility may not be activated or, if activated, will be terminated in the event of a material adverse change in the condition, operations or business prospects of SPPC. In addition, the agreements contain a limitation on the payment of dividends by SPPC to SPR that is identical to the limitation contained in SPPC's Term Loan Agreement, described below. SPR has agreed to guaranty SPPC's performance of certain obligations as a seller and servicer under the receivables purchase facility. 93 SPPC has agreed to issue $75 million principal amount of its General and Refunding Mortgage Bonds upon activation of the receivables purchase facility. The full principal amount of the bond would secure certain of SPPC's obligations as seller and servicer, plus certain interest, fees and expenses thereon to the extent not paid when due, regardless of the actual amounts owing with respect to the secured obligations. As a result, in the event of an SPPC bankruptcy or liquidation, the holder of the bond securing the receivables purchase facility may recover more on a pro rata basis than the holders of other General and Refunding Mortgage securities, who could recover less on a pro rata basis, than they otherwise would recover. However, in no event will the holder of the bond recover more than the amount of obligations secured by the bond. SPPC intends to use the accounts receivable purchase facility as a back-up liquidity facility and does not plan to activate this facility in the foreseeable future. SPPC may activate the facility within five days upon the delivery of certain customary funding documentation and the delivery of the $75 million General and Refunding Mortgage Bond. MORTGAGE INDENTURES 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, 2002, $505.3 million of SPPC's first mortgage bonds were outstanding. 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, 2002, $420 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% 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, 2002, SPPC had the capacity to issue approximately $427 million of additional General and Refunding Mortgage securities. However, the financial covenants contained in SPPC's Term Loan Agreement and Receivable Purchase Facility Agreements limit SPPC's ability to issue additional General and Refunding Mortgage Securities or other debt. SPPC has reserved $75 million of General and Refunding Mortgage Bonds for issuance upon the initial funding of its receivables purchase facility. 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. FINANCING TRANSACTIONS AND COVENANTS On May 23, 2002, SPPC satisfied its obligations with respect to its 2% First Mortgage Bonds due 2011, 5% Series Y First Mortgage Bonds due 2024, and 2% Series Z First Mortgage Bonds due 2004 by depositing $1.2 million, $3.1 million, and $45,000, respectively, with its First Mortgage Trustee. These First Mortgage Bonds were issued to secure loans made to SPPC by the United States under the Rural Electrification Act of 1936, as amended. On October 30, 2002, SPPC entered into a $100 million Term Loan Agreement with several lenders and Lehman Commercial Paper Inc., as Administrative Agent. The net proceeds of $97 million from the Term Loan Facility, along with available cash, were used to pay off SPPC's $150 million credit facility, which was secured by a Series B General and Refunding Mortgage Bond. SPPC's Term Loan Agreement limits the amount of 94 dividends that SPPC may pay to SPR. However, that limitation does not apply to payments by SPPC to enable SPR to pay its reasonable fees and expenses (including, but not limited to, interest on SPR's indebtedness and payment obligations on account of SPR's premium income equity securities) provided that those payments do not exceed $90 million, $80 million and $60 million in the aggregate for the twelve month periods ending on October 30, 2003, 2004 and 2005, respectively. The Term Loan Agreement also permits SPPC to make dividend payments to SPR in an aggregate amount not to exceed $10 million during the term of the Term Loan Agreement. In addition, SPPC may make dividend payments to SPR in excess of the amounts described above so long as, at the time of the payment and after giving effect to the payment, there are no defaults or events of default under the Term Loan Agreement, and such amounts, when aggregated with the amount of dividends paid to SPR by SPPC since the date of execution of the Term Loan Agreement, does not exceed the sum of (i) 50% of SPPC's Consolidated Net Income for the period commencing January 1, 2003 and ending with last day of fiscal quarter most recently completed prior to the date of the contemplated dividend payment plus (ii) the aggregate amount of cash received by SPPC from SPR as equity contributions on its common stock during such period. SPPC's Term Loan Agreement requires that SPPC maintain a ratio of consolidated total debt to consolidated total capitalization at all times during each of the following quarters in an amount not to exceed (i) .650 to 1.0 for the fiscal quarters ended December 31, 2002 through December 31, 2003, (ii) .625 to 1.0 for the fiscal quarters ended March 31, 2004 through December 31, 2004, and (iii) .600 to 1.0 for the fiscal quarter ended March 31, 2005 and for each fiscal quarter thereafter. SPPC's Term Loan Agreement also requires that SPPC maintain a consolidated interest coverage ratio for any four consecutive fiscal quarters ending with the fiscal quarter set forth below of not less than (i) 1.75 to 1.00 for the fiscal quarters ended December 31, 2002 and March 31, 2003, (ii) 2.50 to 1.0 for the fiscal quarters ended June 30, 2003 through December 31, 2003, (iii) 2.75 to 1.0 for the fiscal quarters ended March 31, 2004 through September 30, 2004, and (iv) 3.00 to 1.0 for the fiscal quarter ended December 31, 2004 and for each fiscal quarter thereafter. As of December 31, 2002, SPPC was in compliance with these financial covenants. The Term Loan Facility, which is secured by a $100 million Series C General and Refunding Mortgage Bond, will expire October 31, 2005. SPPC's Washoe County, Nevada, Water Facilities Refunding Revenue Bonds, Series 2001 in the aggregate principal amount of $80 million, will be subject to remarketing on May 1, 2003. In the event that these bonds cannot be successfully remarketed on that date, SPPC will be required to purchase the outstanding bonds at a price of 100% of the principal amount, plus accrued interest. CROSS DEFAULT PROVISIONS Certain financing agreements of SPPC contain cross-default provisions that would result in an event of default under such financing agreements if there is a failure under other financing agreements of SPPC and SPR to meet payment terms or to observe other covenants that would result in an acceleration of payments due. Most of these default provisions (other than ones relating to a failure to pay other indebtedness) provide for a cure period of 30-60 days from the occurrence of a specified event during which time, SPPC or SPR may rectify or correct the situation before it becomes an event of default. The primary cross-default provisions in SPPC's various financing agreements are briefly summarized below: o SPPC's General and Refunding Mortgage Indenture provides for an event of default if a matured event of default under SPPC's First Mortgage Indenture occurs; o SPPC's Term Loan Agreement provides for an event of default if (a) SPPC or any of its subsidiaries default (i) in the payment of indebtedness, or (ii) in the payment of amounts due under hedge agreements, and such defaults aggregate to greater than $10 million, or (b) SPPC's General and Refunding Mortgage Indenture ceases to be enforceable; and 95 o SPPC's receivables purchase facility may terminate in the event that either SPPC or SPR defaults (i) in the payment of indebtedness, or (ii) in the payment of amounts due under hedge agreements, and such defaults aggregate to greater than $10 million and $5 million for SPPC and SPR, respectively. PENSION PLAN MATTERS SPR has a qualified pension plan that covers substantially all employees of SPR, NPC and SPPC. The annual net benefit cost for the plan will increase for 2003 by approximately $16.1 million over the 2002 cost of $18.4 million. As of September 30, 2002, the plan had assets with a fair value that was less than the present value of the accumulated benefit obligation under the plan. On December 6, 2002, SPPC contributed a total of $10.53 million to meet its funding obligations under the plan. At the present time, SPPC does not expect that any near term funding obligation will have a material adverse effect on its liquidity. CONSTRUCTION EXPENDITURES AND FINANCING The table below provides SPPC's consolidated cash construction expenditures and internally generated cash, net for 2000 through 2002 (dollars in thousands):
2002 2001 2000 Total ---------- -------------- ---------- -------------- Cash construction expenditures $ 93,033 $ 105,129 $ 132,710 $ 330,872 ========== ============== ========== ============== Net cash flow from operating activities $ 163,995 $ (211,699) $ 114,360 $ 66,656 Common and preferred cash dividends paid 48,805 89,901 84,899 223,605 ---------- -------------- ---------- -------------- Internally generated cash 115,190 (301,600) 29,461 (156,949) Investment by parent company 10,000 104,948 14,000 128,948 ---------- -------------- ---------- -------------- Total cash available $ 125,190 $ (196,652) $ 43,461 $ (28,001) ========== ============== ========== ============== Internally generated cash as a percentage of cash construction expenditures 124% Not Applicable 22% Not Applicable Total cash generated (used) as a percentage of cash construction expenditures 135% Not Applicable 33% Not Applicable
SPPC's estimated cash construction expenditures for 2003 through 2007 are $483 million. Construction expenditures for 2003 are projected to be $121 million and are expected to be financed by internally generated funds, including the recovery of deferred energy at the Utilities. Cash provided by internally generated funds during 2003 assumes, among other things, no disallowances on SPPC's currently filed deferred energy rate case and the full recovery of such deferred energy amounts over three years, no additional disallowances related to SPPC's appeal of its prior deferred energy case and no adverse decision in the lawsuit filed by Enron against SPPC seeking $87 million in termination payments. Material disallowances of currently-filed or previously-filed deferred energy costs or an adverse decision with respect to the Enron lawsuit would have a material adverse effect on SPPC's financial condition and future results of operations and could cause additional downgrades of its securities by the rating agencies and make it significantly more difficult to finance operations and to buy fuel and purchased power from third parties. See Regulation and Rate Proceedings, Nevada Matters for additional information regarding SPPC's recently filed deferred energy rate case and prior deferred energy rate case and Liquidity and Capital Resources for additional information regarding the Enron lawsuit and the potential impact of a negative outcome with respect to any of these uncertainties. 96 In the event that SPPC's financial condition worsens, it may be unable to finance its construction expenditures with internally generated funds and instead may need to raise all or a portion of the necessary funds through the capital markets or from activating its accounts receivables purchase facility to provide additional liquidity. For additional information regarding the accounts receivables purchase facility, see Liquidity and Capital Resources. SPPC may activate its receivables purchase facility within five days upon the delivery of certain customary funding documentation and the delivery of $75 million of its General and Refunding Mortgage Bonds to secure the facility. If a material adverse event were to occur, it could potentially trigger a termination event with respect to the receivables facility and would also make it more difficult for SPPC to access the capital markets for any such financing needs. CONTRACTUAL OBLIGATIONS The table below provides SPPC's contractual obligations, not including estimated construction expenditures described above, as of December 31, 2002, 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):
PAYMENTS DUE BY PERIOD 2003 2004 2005 2006 2007 Thereafter Total ------------ ------------ ------------ ------------ ------------ ------------ ------------ Long- Term Debt $ 101,400 $ 3,400 $ 100,400 $ 52,400 $ 2,400 $ 760,250 $ 1,020,250 Purchased Power 138,803 42,968 28,874 29,406 30,957 38,351 309,359 Coal and Natural Gas 93,432 76,016 71,830 69,476 50,270 318,493 679,517 Operating Leases 8,357 7,080 6,425 6,177 6,173 55,153 89,365 ------------ ------------ ----------- ------------ ------------ ------------ ------------ Total Contractual Cash Obligations $ 341,992 $ 129,464 $ 207,529 $ 157,459 $ 89,800 $ 1,172,247 $ 2,098,491 ============ ============ =========== ============ ============ ============ ============
CAPITAL STRUCTURE As of December 31, 2002, SPPC had no short-term debt outstanding. On October 29, 2002, SPPC established an accounts receivable purchase facility of up to $75 million, which was arranged by Lehman Brothers. If SPPC elects to activate the receivables purchase facility, SPPC will sell all of its accounts receivable generated from the sale of electricity to customers to its newly created bankruptcy-remote special purpose subsidiary. The receivables sales will be without recourse except for breaches of customary representations and warranties made at the time of sale. The subsidiary will in turn sell these receivables to a bankruptcy-remote subsidiary of SPR. SPR's subsidiary will issue variable rate revolving notes backed by the purchased receivables. Lehman Brothers Holdings, Inc. has committed to be the sole initial purchaser of all of the variable rate revolving notes. SPPC intends to use the accounts receivable purchase facility as a back-up liquidity facility and does not plan to activate this facility in the foreseeable future. SPPC may activate the facility within five days upon the delivery of certain customary funding documentation and the delivery of the $75 million General and Refunding Mortgage Bond. See Liquidity and Capital Resources for additional information regarding the terms and conditions of the accounts receivable purchase facility. SPPC's actual capital structure at December 31, 2002, and 2001 was as follows (dollars in thousands):
2002 2001 ---------------- ---------------- Short-Term Debt (1) $ 101,400 6% $ 49,130 3% Long-Term Debt 914,788 54% 923,070 54% Preferred Stock 50,000 3% 50,000 3% Common Equity 639,295 37% 692,901 40% ---------- --- ---------- --- TOTAL $1,705,483 100% $1,715,101 100% ========== === ========== ===
(1) Including current maturities of long-term debt. 97 ENERGY SUPPLY (NPC AND SPPC) The energy supply function at the Utilities encompasses the reliable and efficient operation of the Utilities' owned generation, the procurement of all fuels and purchased power, and resource optimization (i.e., physical and economic dispatch). The Utilities have undertaken a rigorous review of the energy supply function and have implemented policy, planning and organizational changes to address the dramatic changes that have and are occurring in the energy industry. The structure of the western wholesale energy market has seen dramatic changes in recent months. Significant amongst these are the collapse of the energy trading model and the merchant energy sector, which has resulted in reduced liquidity in the traded spot and forward markets for standard products. In addition, a credit crisis in the broader energy sector has resulted in a series of cancellations of new generation projects; putting intermediate term capacity margins in the broader region and within both Utilities' sub-region in jeopardy. The Utilities also face energy supply challenges for their respective load control areas. There is the potential for continued price volatility in each Utility's service territory, particularly during peak periods. A greater dependence on gas-fired generation in the service territory subjects power prices to gas price volatilities. Both Utilities face load obligation uncertainty due to the potential for customer switching. Counterparties in these areas have significant credit difficulties, representing credit risk to the Utilities. Finally, each Utility's own credit situation can have an impact on its ability to enter into transactions. In response to these energy supply challenges, the Utilities have adopted an approach to managing the energy supply function that has three primary elements. The first element is a set of management guidelines to procuring and optimizing the supply portfolio that is consistent with the requirements of a load serving entity with a full requirements obligation. The second element is an energy risk-management and risk control approach that ensures clear separation of roles between the day-to-day management of risks and compliance monitoring and control; and ensures clear distinction between policy setting (or planning) and execution. Lastly, the Utilities will pursue a process of ongoing regulatory involvement and acknowledgement of the resource portfolio management plans. ENERGY SUPPLY PLANNING Within the energy supply planning process, there are three key components covering different time frames: (1) the PUCN-approved long-term integrated resource plan has a twenty-year year planning horizon; (2) the energy supply plan, which is an intermediate term resource procurement and risk management plan that establishes the supply portfolio parameters within which intermediate term resource requirements will be met, has a one to three year planning horizon; and (3) tactical execution activities with a one-month to twelve-month focus. The energy supply plan will operate in conjunction with the PUCN-approved twenty-year integrated resource plan. It will serve as a guide for near-term execution and fulfillment of energy needs. When the energy supply plan calls for executing contracts of duration of more than three years, the plan will require PUCN approval as part of the integrated resource planning process. 98 In developing energy supply plans and implementing on those plans, management guidelines followed by the Utilities include: o Maintaining an energy supply plan that balances costs, risks, price volatility, reliability and predictability of supply. o Investigating feasible commercial options to implement against the energy supply plan. o Applying quantitative techniques and diligence commensurate with risk to evaluate and execute each transaction. o Implementing the approved energy supply plan in a manner that manages ratepayer risk in terms of reliability, volatility and cost. o Monitoring the portfolio against evolving market conditions and managing the resource optimization options. o Ensuring simple, transparent and well-documented decisions and execution processes. ENERGY RISK MANAGEMENT AND CONTROL The Utilities' efforts to manage energy commodity (electricity, natural gas, coal and oil) price risk are governed by a Board of Directors' revised and approved Enterprise Risk Management and Control Policy. That policy created the Enterprise Risk Oversight Committee (EROC) and made that committee responsible for the overall policy direction of the Utilities' risk management and control efforts. That policy further instructed the EROC to oversee the development of appropriate risk management and control policies including the Energy Supply Risk Management and Control Policy. The Utilities' commodity risk management program establishes a control framework based on existing commercial practices. The program creates predefined risk limits 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 portfolio and credit limits. The Utilities, through the purchase and sale of financial instruments and physical products, maintain an energy risk management program that limits energy risk to levels consistent with energy supply plans approved by the Chief Executive Officer and the EROC. REGULATORY ISSUES The Utilities' long-term integrated resource plans are filed with the PUCN for approval every three years. Nevada law provides that resource additions approved by the PUCN in the resource planning process are deemed prudent for ratemaking purposes. The Utilities resource plans will be filed with the PUCN on July 1, 2003 and 2004 for NPC and SPPC, respectively. Between resource plan filings, the Utilities are required to seek PUCN approval for power purchases with terms of three years or greater by filing amendments to prior resource plan filings. The Utilities will also seek regulatory input and acknowledgement of intermediate term energy supply plans. The Utilities feel this is necessary to ensure that the appropriate levels of risks are being mitigated at reasonable costs, the appropriate levels of risks are being retained in the portfolio, and decisions to manage risks with best available information at the point in time when decisions are made are subject to reasonable mechanisms for rate recovery. 99 INTERMEDIATE TERM ENERGY SUPPLY PLANS The Utilities are in the process of developing and implementing their intermediate term energy supply plans. Those plans cover the years 2003 through 2005 and require Enterprise Risk Oversight Committee and the CEO approval prior to implementation. The energy supply plans will operate within the framework of the PUCN-approved twenty-year integrated resource plans. They serve as a guide for near-term execution and fulfillment of energy needs. When the energy supply plans call for the execution of contracts of duration of more than three years, an amended resource plan will be prepared and submitted for PUCN approval. The energy supply plans will be updated at least annually. NPC's energy supply plan has been approved internally and was filed with the PUCN on January 31, 2003 for informational purposes. SPPC's plan is in the final stages of development and also will be filed with the PUCN for informational purposes. Key features of NPC's plan are: o Weigh the intermediate-term portfolio mix heavily towards peaking and seasonal capacity, or synthetic tolling based contracts (i.e., power prices indexed to gas prices), to meet the following requirements: o Optimize the tradeoff between overall fuel and purchase power cost and market price risk. o Pursue in-region capacity to enhance long-term regional reliability. o Represent the set of transactions/products available in the market. o Reduce credit risk--in a market with weak counter-party financials. o Procure to match the difficult load profile, to the extent possible. o Hedge the gas price risk exposure in the fuel portfolio through the purchase of call options. o Manage off-peak and shoulder month energy price risk through ongoing intermediate and short-term optimization activities (e.g., optimizing the dispatch of NPC generation and/or buying directly from the market). SPPC's energy supply plan will have many of the same features of NPC's plan with respect to managing fuel and purchased power cost and risk exposure, but SPPC's plan is being specifically tailored to its load obligation and the energy supply characteristics of its sub-region. Both of the energy supply plans represent a change in procurement strategy from previous years. The strategy now focuses on executing contracts for power deliveries to the Utilities' physical points of delivery. In previous years, the Utilities used hedges to reduce price and commodity risk for future purchases by executing power contracts at so-called "liquid" trading points. A typical hedge transaction involved the purchase of power at one of the major trading hubs where prices were highly correlated with a physical delivery point to the Utility. The hedged purchase was either delivered to the Utilities' service territories to service their customers or, if the hedged purchase was not needed to fulfill power requirements, resold in the liquid market. With the significant drop in liquidity in wholesale markets, the Utilities have changed their procurement strategy to focus on power deliveries to the Utilities' physical points of delivery. RECENT PROCUREMENT ACTIVITIES As part of the implementation of NPC's energy supply plan, NPC in January 2003 entered into long-term purchase agreements with three companies - Panda Gila River LP, Calpine Energy Services and Mirant Americas Energy Marketing LP. The agreement with Panda Gila River LP provides 200 megawatts of power to be delivered from Gila River Power Station in Gila Bend, Arizona, during the summer months of 2003, 2004 and 2005. Panda Gila River LP is a joint venture between TECO Power Services Corporation and Panda Energy International, Inc. 100 Currently under construction, the 2,145-megawatt facility will come on line in four phases, starting in the spring of 2003. Calpine Energy Services, a wholly-owned subsidiary of Calpine Corporation, has agreed to deliver 100 MW of energy between the hours of 9 a.m. and midnight and 50 MW of energy from 1 a.m. to 8 a.m., seven days a week from June 1, 2003 through May 31, 2006. Energy will be delivered from Calpine's South Point Energy Center. All three contracts, Panda, Calpine, and Mirant, involve energy deliveries to NPC's control area. The arrangement with Mirant involves three separate agreements under which Mirant will provide a total of 325 MW of capacity and energy to NPC. Each agreement identifies specific delivery dates ranging from May of 2003 and continuing through April of 2008. A majority of the energy (225 MW) will be delivered from the Apex facility located in Las Vegas. Those agreements are subject to PUCN approval and were filed by NPC with the PUCN on January 24, 2003. In a separate development, NPC also signed an agreement with Reliant for a total of 400 MW to be delivered the summer of 2003 only. Because this is a short-term contract, it is not subject to advance approval by the PUCN. SHORT-TERM RESOURCE OPTIMIZATION STRATEGY The Utilities' short-term resource optimization 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 optimization 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 optimization involves minimizing system production costs each hour by either changing the generation output or buying needed power and/or 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 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 optimization 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 detrimental 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. 101 RESULTS OF OPERATIONS - SPR (HOLDING COMPANY) AND OTHER SUBSIDIARIES TUSCARORA GAS PIPELINE COMPANY TGPC, a wholly owned subsidiary of SPR, contributed $3.3 million in net income for the twelve months ended December 31, 2002, $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. SIERRA PACIFIC COMMUNICATIONS SPC, a wholly owned subsidiary of SPR, incurred a net loss of ($5.9) million for the twelve months ended December 31, 2002, 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. SPC's increased loss for the twelve months ended December 31, 2002, was due to interest charges and other costs associated with its exit from Sierra Touch America LLC, including the $2.3 million write-off of an uncollectible receivable. For additional information see Note 9 of Notes to Financial Statements, Long-Term Debt. e-THREE e-three, a wholly owned subsidiary of SPR, incurred a net loss of ($1.2) million for the twelve months ended December 31, 2002, contributed $666,000 of net income for the twelve months ended December 31, 2001, and contributed $338,000 of net income for the twelve months ended December 31, 2000. e-three's loss for the twelve months ended December 31, 2002, is due primarily to a significant reduction in revenues attributable to a general decline in e-three's primary market and a transitional goodwill impairment charge of approximately $1.5 million. SIERRA PACIFIC ENERGY COMPANY SPE, a wholly owned subsidiary of SPR, incurred a net loss of ($295,000) for the twelve months ended December 31, 2002, 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. LANDS OF SIERRA LOS, a wholly owned subsidiary of SPR, contributed net income of $128,000 for the twelve months ended December 31, 2002, net income of $281,000 for the twelve months ended December 31, 2001, and net income of $191,000 for the twelve months ended December 31, 2000. SIERRA PACIFIC RESOURCES (HOLDING COMPANY) The holding company's operating results included approximately $71.5 million, $55.8 million, and $44.5 million of interest costs for the twelve months ended December 31, 2002, 2001, and 2000, respectively, that resulted primarily from merger related financing. The holding company's operating results for the twelve months ended December 31, 2001, also reflect a charge of $22 million in connection with SPR's terminated plans to purchase Portland General Electric Company, including approximately $7.5 million representing a termination payment for shared expenses. 102 REGULATION AND RATE PROCEEDINGS 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 and Tuscarora Gas Pipeline Company (TGPC) 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. 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 has the effect of delaying additional rate increases to consumers while, at the same time, providing a method for the Utilities to recover their increased costs for fuel and purchased power. After the initial 2001 general rate applications described below under Nevada Matters, each Utility will be required to file future general rate applications at least every 24 months. 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. 103 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 of Notes to Financial Statements, Regulatory Actions, for a discussion of the deferred energy accounting provisions of AB 369. 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 5% of their energy from renewable resources. These requirements increase to 15% by 2013. Prior law capped renewable energy requirements at 1%. Currently, SPPC obtains approximately 9% 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 one MW to select new energy suppliers. A more detailed explanation appears in the section Customers File under AB 661. 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 administer the disposition of the funds. 104 NEVADA MATTERS NEVADA POWER COMPANY 2001 GENERAL RATE CASE On October 1, 2001, NPC filed an application with the PUCN, as required by law, seeking an electric general rate increase. 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, or an overall 1.7% rate increase. The application also sought a return on common equity (ROE) for NPC's total electric operations of 12.25% and an overall rate of return (ROR) of 9.30%. On March 27, 2002, the PUCN issued its decision on the general rate application, ordering a $43 million revenue decrease with an ROE of 10.1% and ROR of 8.37%. The effective date for the decision was April 1, 2002. The decision also resulted in adjustments increasing accumulated depreciation by $6.7 million, and the inclusion of approximately $5 million of revenues related to SO2 Allowances. The PUCN delayed consideration of recovery of SPR/NPC merger costs until a future rate case. NPC was not granted a carrying charge on these deferred costs. NPC plans to renew its request to recover these costs in its next general rate case, which will be filed by the fourth quarter 2003. Recovery of costs related to the generation divestiture project, which supported Nevada's now-abandoned utility restructuring policy, were delayed until the plants are sold or some other mechanism is proposed to allow recovery of the costs. A carrying charge was allowed by the PUCN for the delayed recovery of divestiture costs. On April 15, 2002, NPC filed a petition for reconsideration with the PUCN. On May 24, 2002, the PUCN issued an order on the petition for reconsideration. The PUCN modified its original order reversing the adjustment to accumulated depreciation of $6.7 million, and decreased the SO2 allowance revenue amortization to $3.2 million per year. Revised rates for these changes went into effect on June 1, 2002. NEVADA POWER COMPANY 2001 DEFERRED ENERGY CASE 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, and September 30, 2001, as required by law. The application sought to establish a Deferred Energy Accounting Adjustment (DEAA) rate to clear accumulated purchased fuel and power costs of $922 million and spread the recovery of the deferred costs, together with a carrying charge, over a period of not more than three years. On March 29, 2002, the PUCN issued its decision on the deferred energy application, allowing NPC to recover $478 million over a three-year period, but disallowing $434 million of deferred purchased fuel and power costs and $30.9 million in carrying charges consisting of $10.1 million in carrying charges accrued through September 2001 and $20.8 million in carrying charges accrued from October 2001 through February 2002. The order stated that the disallowance was based on alleged imprudence in incurring the disallowed costs. On April 11, 2002, NPC filed a lawsuit in the First District Court of Nevada seeking to reverse portions of the PUCN's decision. NPC's lawsuit requests that the District Court reverse portions of the PUCN's order and remand the matter to the PUCN with direction that the PUCN authorize NPC to immediately establish rates that would allow NPC to recover its entire deferred energy balance of $922 million, with a carrying charge, over three years. Arguments were heard on March 14, 2003 and a decision is expected in the second quarter. NPC is not able to predict the outcome of a decision in this matter. Various interveners in NPC's deferred energy case before the PUCN filed petitions with the PUCN for reconsideration of the PUCN's order, seeking additional disallowances of between $12.8 million and 105 $488 million. On May 24, 2002, the PUCN issued an order denying any further disallowances and granted NPC the authority to increase the deferred energy cost recovery charge for the month of June 2002 by one cent per kilowatt-hour. This increase accelerated the recovery of the deferred balance by approximately $16 million for the month of June 2002 only. The Bureau of Consumer Protection (BCP) of the Nevada Attorney General's Office has since filed a petition in NPC's pending state court case seeking additional disallowances. NEVADA POWER COMPANY 2002 DEFERRED ENERGY CASE On November 14, 2002, NPC filed an application with the PUCN seeking to clear deferred balances for purchased fuel and power costs accumulated between October 1, 2001, and September 30, 2002, as required by law. The application seeks to establish a rate to repay accumulated purchased fuel and power costs of $195.7 million, together with a carrying charge, over a period of not more than three years. The application also requests a reduction to the going-forward rate for energy, reflecting reduced wholesale energy costs. The combined effect of these two adjustments results in an overall rate reduction of 5.3%. A hearing is scheduled to begin on April 7, 2003 and a ruling is required by May 15, 2003. Intervenors filed their direct testimony on March 7, calling for disallowances between approximately $83 and $300 million of the total fuel and purchased power costs. The largest of the proposed disallowances are based on the same alleged imprudence as found in the PUCN order for NPC's 2001 Deferred Energy Case relating to NPC's failure to enter into power contracts in 1999. Some Intervenors' testimony, in the current case, argue in favor of this disallowance based on the last Deferred order but did not quantify their proposals and in some cases would be additive to the ranges stated above. The PUCN Staff does not support this disallowance but calculated a range of $116 to $347 million in the event that the PUCN disallows deferred energy costs based upon the same alleged imprudence cited by the PUCN in its 2001 decision relative to this issue. While all Intervenors call for the PUCN to reduce NPC's requested energy rates for recovery of past energy costs, some also propose to increase customers' energy rates for purchases that will occur during the upcoming deferred accounting period. NEVADA POWER COMPANY DEMAND REDUCTION PROGRAMS On November 14, 2002, NPC filed an application with the PUCN seeking recovery of expenses incurred in the implementation and operation of programs for energy conservation and load management. In the filing, NPC requested a one-year recovery of approximately $1.9 million. This would result in an average 0.12% increase in present rates. NPC asked for this increase to become effective simultaneously with the rate change to be ordered in its 2002 deferred energy case discussed above. NPC subsequently negotiated a settlement agreement with the intervenors (PUCN Staff and Bureau of Consumer Protection), which is expected to be approved by the PUCN coincident with its 2002 Deferred Energy ruling. With the exception of a small disallowance ($14,673), the agreement called for approval of NPC's request for cost recovery. SIERRA PACIFIC POWER COMPANY 2001 GENERAL RATE CASE On November 30, 2001, as required by law, SPPC filed an application with the PUCN seeking an electric general rate increase. 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 sought an ROE for SPPC's total electric operations of 12.25% and an overall ROR of 9.42%. 106 On May 28, 2002, the PUCN issued its decision on the general rate application, ordering a $15.3 million revenue decrease with an ROE of 10.17% and ROR of 8.61%. The effective date of the decision was June 1, 2002. The PUCN delayed consideration of recovery of SPR/NPC merger costs until a future rate case, and SPPC was not granted a carrying charge on these deferred costs. SPPC is currently planning to renew its request to recover these costs in a general rate case to be filed by the fourth quarter of 2003. Recovery of costs related to the generation divestiture project, which supported Nevada's now-abandoned utility restructuring policy, were delayed until the plants are sold or some other mechanism is proposed to allow recovery of the costs. A carrying charge was allowed by the PUCN for the delayed recovery of divestiture costs. Various parties to the case had filed petitions for reconsideration of the order. On July 18, 2002, the PUCN issued a final decision on the petitions for reconsideration, clarifying issues contained in its original order. As a result of the clarifications, SPPC was ordered to change the total annual electric revenue decrease from $15.3 million to $15.8 million. On August 19, 2002, Barrick Goldstrike Mines (Barrick) filed a lawsuit in the First District Court of Nevada seeking to reverse portions of the decision. A stipulation of the parties was subsequently approved by the PUCN. In accordance with the stipulation, SPPC has reduced the electric service rates charged to Barrick and is accruing the reductions in a deferred account as a regulatory asset. The stipulation calls for a review of the subject rates during the next general rate case and a pass through of the deferred costs to either Barrick or other customers. SIERRA PACIFIC POWER COMPANY 2002 DEFERRED ENERGY CASE On February 1, 2002, SPPC filed an application with the PUCN, as required by law, seeking to clear deferred balances for purchased fuel and power costs accumulated between March 1, 2001 and November 30, 2001. The application sought to establish a DEAA rate to clear accumulated purchased fuel and power costs of $205 million and spread the cost recovery over a period of not more than three years. It also sought to recalculate the Base Tariff Energy Rate to reflect anticipated ongoing purchased fuel and power costs. On May 28, 2002, the PUCN issued its decision on the deferred energy application, allowing SPPC three years to collect $150 million but disallowing $53 million of deferred purchased fuel and power costs and $2 million in carrying charges. On August 22, 2002, SPPC filed a lawsuit in the First District Court of Nevada seeking to reverse portions of the decision of the PUCN denying the recovery of deferred energy costs incurred by SPPC on behalf of its customers in 2001 on the grounds that such power costs were not prudently incurred. SPPC's lawsuit requests that the District Court reverse portions of the order of the PUCN and remand the matter to the PUCN with direction that the PUCN authorize SPPC to immediately establish rates that would allow SPPC to recover its entire deferred energy balance of $205 million, with a carrying charge, over three years. A hearing has been scheduled for October 2003. On August 22, 2002, the BCP from the Nevada Attorney General's Office also filed a lawsuit in the First District Court of Nevada seeking to set aside the decision of the PUCN so that SPPC is not authorized to reflect in rates any costs for fuel and purchased power which may have been imprudently incurred. A hearing date has not yet been scheduled. At this time, SPPC is not able to predict the outcome or the timing of a decision in these matters. SIERRA PACIFIC POWER COMPANY 2003 DEFERRED ENERGY CASE On January 14, 2003, SPPC filed an application with the PUCN, as required by law, seeking to clear deferred balances for purchased fuel and power costs accumulated between December 1, 2001 and 107 November 30, 2002. The application seeks to establish a DEAA rate to clear accumulated purchased fuel and power costs of $15.4 million and spread the cost recovery over a period of not more than three years. 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 requested DEAA would amount to 0.01%. A hearing is scheduled to begin on May 12, 2003, and a ruling is required before July 13, 2003. SIERRA PACIFIC POWER COMPANY DEMAND REDUCTION PROGRAMS On January 14, 2003, SPPC filed with the PUCN an application seeking recovery of expenses incurred in the implementation and operation of programs for energy conservation and load management. In the filing, SPPC requested a one-year recovery of approximately $0.9 million. This would result in an average 0.12% increase in present rates. SPPC asked for this increase to become effective simultaneously with the rate change to be ordered in its 2003 deferred energy case discussed above. CUSTOMERS FILE UNDER AB 661 (NPC, SPPC) Assembly Bill 661 (AB 661), passed by the Nevada legislature in 2001, 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, the departure must not burden the Utilities with increased costs or cause any remaining customers to pay increased costs, and the departing customers must pay their portion of any deferred energy balances. The PUCN adopted regulations prescribing the criteria that will be used to determine if there will be negative impacts to remaining customers or the Utility. These regulations place certain limits upon the departure of NPC customers until 2003; most significantly, the amount of load departing is limited to approximately 1100 MW in peak conditions. Customers wishing to choose a new supplier must provide 180-day notice to the Utilities. AB 661 permitted customers to file applications with the PUCN beginning in the fourth quarter of 2001, and customers could begin to receive service from new suppliers by mid-2002. On January 10, 2002, Barrick, an approximately 130 MW SPPC customer, filed a notice of intent with the PUCN indicating their desire to exit the system of SPPC and to purchase energy, capacity and ancillary services from a provider other than SPPC. Barrick has not yet filed a formal application with the PUCN but could do so at any time. Under the law, the earliest departure date would be 180 days after the application is filed. During May 2002, Rouse Fashion Show Management LLC, Coast Hotels and Casinos Inc., Station Casinos, Inc., Gordon Gaming Corporation, MGM Mirage, and Park Place Entertainment filed separate applications with the PUCN to exit the system of NPC and to purchase energy, capacity and ancillary services from a provider other than NPC. The loads of these customers aggregate 260 MW on peak. Hearings on the applications of all the customers except Park Place Entertainment were completed on July 19, 2002, and the PUCN issued its decision on July 31, 2002. In its decision, the PUCN approved the applications of these customers to choose an energy supplier other than NPC. The earliest any of these customers could have begun taking energy from an alternative provider was November 1, 2002. If all five customers whose applications were approved had left its system on November 1, 2002, NPC would have incurred an annual estimated loss in revenue of $48 million, which would be offset by an estimated reduction in costs, primarily for fuel and purchased power, of $46 million with the difference being paid by exit fees from the departing customers. These customers would also be responsible for their share of balances in NPC's deferred energy accounts until the time they left and would have continued to pay their share of these balances after they left. For example, if all five customers whose applications were approved had left the system on November 1, 2002, their remaining share of NPC's previously approved deferred energy balance is estimated to have been $27 million. 108 Additionally, these departing customers would have been responsible for paying their share of the yet to be approved accumulated deferred energy balances from October 1, 2001, to their date of departure. They also would have remained accountable to any rulings made by the District Court on legal actions brought in NPC's past deferred energy case. They could also have benefited from any refunds that might be granted on power contracts under review with the FERC. A hearing on the application of Park Place Entertainment was held on August 2, 2002, and on August 12, 2002, the PUCN approved the application with terms and conditions similar to those described above for the aforementioned five customers. All of the customers approved for departure were to address compliance items in their PUCN orders. None of these customers submitted the compliance items required by the PUCN on the required schedule and none of these customers provided official notice of departure. As a result, on February 11, 2003, these applications were closed. All of these customers have submitted new applications requesting a departure date of July 1, 2003. Decisions on these applications are anticipated by the end of the first quarter 2003. Monte Carlo, Riviera, Imperial Palace, Stratosphere, and Potlach, have also filed applications for departure in June or July of 2003. Decisions on these applications, other than the Riviera and Imperial Palace, are also anticipated by the end of the first quarter 2003. On January 29, 2003, stipulations on the applications of the Imperial Palace and the Riviera were filed with the PUCN adopting most of the provisions that were previously decided in the PUCN's decision on July 31, 2002 with the exception of how the base tariff general rate (BTGR) and the base tariff energy rate (BTER) effects will be addressed in the computation of the exit fees and the related accounting treatment. On February 3, 2003, the PUCN held hearings on the applications and stipulations. On February 27, 2003, the PUCN issued an order approving the parties' stipulation as filed. Additionally, the PUCN ordered that the BTGR revenue impact associated with these customers leaving the system be addressed in NPC's next general rate case (GRC) following the customers departure and all BTER benefits of these customers leaving the system flow through the deferred energy process and accrue to remaining customers. The amount of BTGR revenues that would be lost as a result of these customers' departing, until NPC files its next GRC, is estimated at $500 thousand annually. The Imperial Palace and the Riviera are still required to pay their share of NPC's previously approved deferred energy balance, which is estimated at $1.7 million at June 1, 2003, their estimated departure date. Additionally, these customers will be responsible for paying their share of the yet to be approved accumulated deferred energy balances from October 1, 2001 through June 1, 2003, which is currently estimated at $541 thousand. They also will remain accountable to any rulings made by the District Court on legal actions brought in NPC's past deferred energy case. They could also benefit from any refunds that might be granted on power contracts under review with the FERC. On March 14, 2003, NPC filed for reconsideration of the February 27, 2003 PUCN order regarding the accounting for and computation of exit fees. Any customer who departs NPC's system and later decides to return to NPC as their energy provider will be charged for their energy at a rate equivalent to NPC's incremental cost of service. A stipulation regarding the incremental cost of service tariff is currently pending before the PUCN. NEVADA POWER COMPANY ADDITIONAL FINANCE AUTHORITY On April 26, 2002, Nevada Power filed with the PUCN an application seeking additional finance authority. In the application, NPC asked for authority to issue secured long-term debt in an aggregate amount not to exceed $450 million through the period ending 2003. On June 19, 2002, the PUCN issued a Compliance Order, Docket No. 02-4037, authorizing NPC to issue $300 million of long-term debt. The PUCN order requires NPC, if it is able, to issue the $50 million of remaining authorized short-term debt, before it issues any long-term debt authorized by the order. Moreover, the order provides that, if NPC is able to issue short-term 109 debt at any point prior to September 1, 2002 (whether or not the issuance of short-term debt actually occurs), the amount of long-term debt authorized by the order will be automatically reduced to $250 million. The PUCN order also provides that NPC will bear the burden of demonstrating that any financings undertaken pursuant to the order, including any determination made regarding the length of such commitment, the type of security or rate, is reasonable. Until such time as the Order's authorization expires (December 31, 2003), NPC must either receive the prior approval of the PUCN or reach an equity ratio of 42% before paying any dividends to SPR. If NPC reaches a 42% equity ratio prior to December 31, 2003, the dividend restriction ceases to have effect. On July 3, 2002, the BCP of the Nevada Attorney General's Office filed a petition with the PUCN requesting that the hearing in Docket No. 02-4037 be reopened to allow for the introduction of additional evidence or for the PUCN to reconsider its decision granting NPC the authority to issue long-term debt. On September 11, 2002, the PUCN denied the petition to reopen the proceeding and rescinded the portion of its Compliance Order that had previously required NPC to immediately issue $50 million to $100 million of debt. ANNUAL PURCHASED GAS COST ADJUSTMENT (SPPC) On July 1, 2002, SPPC filed a Purchased Gas Cost Adjustment application for its natural gas local distribution company. In the application, SPPC has asked for a reduction of $0.05421 to its Base Purchased Gas Rate (BPGR) and an increase in its Balancing Account Adjustment charge (BAA) by the same amount. This request would result in no change to revenues or customer rates. This docket was consolidated for hearing purposes with the Liquid Petroleum Gas Cost Adjustment below. On December 23, 2002, the PUCN voted to decrease rates for SPPC's natural gas customers by approximately 3% ($3.2 million plus applicable carrying charges). The PUCN noted that the decrease was due primarily to lower gas costs for SPPC and to a disallowance for imprudent hedging practices. The PUCN adjusted SPPC's costs related to fixed floating hedging contracts. The PUCN also disallowed an alleged $0.7 million customer subsidy under an SPPC optional gas tariff. The new BAA is $0.12330 (which includes a three-year amortized BAA of $0.09998 from Docket 01-6050 and the current annual amortized BAA of $0.02332). SPPC had requested a total BAA of $0.15419. A BPGR of $0.61059 per therm was approved, a reduction from the previous BPGR of $0.66480. The new rates were implemented January 1, 2003. SPPC has filed a petition for reconsideration of the decisions to disallow the $3.2 million hedging costs and the $0.7 million alleged customer subsidy. On February 6, 2003, the PUCN granted the petition for reconsideration and a decision is expected by the end of the first quarter 2003. LIQUID PETROLEUM GAS COST ADJUSTMENT (SPPC) On July 1, 2002, SPPC filed an application to adjust rates for its liquid petroleum gas (LPG) distribution company. In the application, SPPC has asked for an increase of $0.04133 to its current LPG rate and a decrease in its BAA by the same amount. This request would result in no change to revenues or customer rates. This docket was consolidated for hearing purposes with the annual Purchased Gas Cost Adjustment above. The LPG and BAA rates were approved December 23, 2002, and resulted in no change in the overall level of rates. 110 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 (ALJ) 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 ALJ's request, on October 26, 2001, SPPC filed an amendment to its application declaring the rate freeze period to be over. On December 5 and 11, 2001, hearings were held and on January 11, 2002 and January 25, 2002, opening briefs and reply briefs were filed. On July 17, 2002, the CPUC approved the requested 2-cent per kilowatt-hour surcharge, subject to refund and interest pending the outcome of Phase Two. The increase of $10 million or 26% is applicable to all customers except those eligible for low-income and medical-needs rates and went into effect July 18, 2002. Phase Two of the Rate Stabilization Plan was filed with the CPUC on April 1, 2002, and includes a general rate case and requests 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 wholesale energy supplies. Phase Two also includes a proposal to terminate the 10% rate reduction mandated by AB 1890, but does not include a performance-based, rate-making proposal. This request was for an additional overall increase in revenues of 17.1%, or $8.9 million annually. On December 19, 2002, SPPC filed an amendment to the Phase Two application reducing the requested increase by $4.1 million to $4.8 million or 9.2% annually. SPPC agreed to make certain changes to the application and file the amendment following discussions with the CPUC Office of Ratepayer Advocates. In February 2003, the Office of the Ratepayer Advocates (ORA) filed testimony proposing to reduce SPPC's request by $3.2 million resulting in a $1.6 million increase or 3.3%. On March 14, 2003, SPPC filed rebuttal testimony. Hearings are scheduled to begin on April 9, 2003, and a decision by the CPUC is expected in late 2003. CALIFORNIA ASSEMBLY BILL 1235 On September 24, 2002, the Governor of California signed into law Assembly Bill 1235 (AB 1235), which allows the transfer of hydroelectric plants along the Truckee River from SPPC to the Truckee Meadows Water Authority (TMWA). AB 1235 effectively amends previous California legislation (AB 6X) that prevented private utilities from selling any power plants that provide energy to California customers until 2006. AB 1235 was effective September 24, 2002, and provides an exemption for the four "run-of-the-river" hydroelectric plants that SPPC sold to TMWA as part of the sale of its water business in June 2001. On November 9, 2002, SPPC filed an application with the CPUC for authority to sell the four hydroelectric plants. On January 13, 2003, the CPUC issued a ruling that the California Environmental Quality Act applies to this proceeding and SPPC must supplement the application with a certified environmental document. SPPC has begun informal discussions with the CPUC on the environmental issues and cannot yet predict the outcome of this proceeding. 111 FERC MATTERS (NPC, SPPC) FERC 206 COMPLAINTS In December 2001, the Utilities filed 10 wholesale purchased power complaints with the FERC under Section 206 of the Federal Power Act seeking to reduce prices of certain forward power purchase contracts that the Utilities entered into prior to the price caps established by the FERC during the western United States utility crisis. The Utilities believe the prices under these purchased power contracts are unjust and unreasonable. The Utilities negotiated a settlement with Duke Energy Trading and Marketing, but were unable to reach agreement in bilateral settlement discussions with other respondents. The Utilities have already paid the full contact price for all power actually delivered by these suppliers, but are contesting claims made by their terminated power suppliers, including Enron. Hearings concluded on October 24, 2002, and an initial decision was issued by the Administrative Law Judge (ALJ) overseeing the proceedings on December 19, 2002. The ALJ stated that the Utilities' complaints did not meet the public interest standard of proof, which the ALJ believed applied to the reformation of the Utilities' contracts. The Utilities and others, including the PUCN, have filed Briefs on Exception to the ALJ's Initial Order with the FERC. If the initial order is not modified by the ALJ, it will be reviewed by the full FERC in the second quarter of 2003. On March 26, 2003, the Staff of the FERC (FERC staff) concluded that supply-demand imbalance, flawed market design and inconsistent rules made significant market manipulation possible in the Western states in 2000 and 2001. The FERC has not decided how or if this manipulation impacted NPC's and SPPC's claims. Additionally, the FERC staff recommended that certain market participants identified in the Cal ISO Report released January 6, 2003, including SPPC, be directed to show cause why their behavior did not constitute gaming in violation of the Cal ISO and Cal PX tariffs. In its report, the Cal ISO indicated that it was unclear as to the reason SPPC received certain revenues in the amount of $6,391. The total revenues for all companies for which the FERC staff recommended show cause orders is approximately $2.8 million. SPPC was one of the over 30 market participants included in the FERC staff's recommendation. The FERC has not yet decided whether to issue a show cause order to SPPC or to any of the other companies identified by the FERC staff. The FERC staff also recommended that the Cal ISO fully explain the screen that was used to identify the subject transactions and that the information should be made available to the public. OPEN ACCESS TRANSMISSION TARIFF On September 27, 2002, the Utilities filed with the FERC a revised Open Access Transmission Tariff (OATT) designated as Docket No ER02-2607-000. The purpose of the filing was to implement changes that are required to implement retail open access in Nevada. The Utilities requested the changes to become effective November 1, 2002, the date retail access was scheduled to commence in Nevada in accordance with provisions of AB 661, passed in the 2001 session of the Nevada Legislature. On October 11, 2002, the Utilities filed with the FERC, revised rates, terms, and conditions for ancillary services offered in the OATT designated Docket No. ER03-37-000. On November 25, 2002, the FERC suspended the rates in Docket No. ER03-37-000 for a nominal period and made them effective subject to refund on January 1, 2003, as requested by the Utilities. On November 21, 2002, the FERC suspended the revised OATT in Docket No. ER02-2607-000 for a nominal period, made it effective subject to refund, set certain issues for hearing, and directed the Utilities to 112 make a compliance filing. The compliance filing was submitted on December 23, 2002. This order additionally established hearing procedures and consolidated the two dockets for hearing. On March 11, 2003, all parties to these dockets reached a settlement in principle regarding all issues. The settlement agreement is expected to be filed with the FERC on or before May 2003. REGIONAL TRANSMISSION ORGANIZATION 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). On March 29, 2002, RTO West submitted to the FERC a Stage II 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. On November 13, 2001, TransConnect submitted to the FERC a Stage II compliance filing and supplemental material, which provided details of the formation of the ITC - a member of RTO West. On September 18, 2002, and September 23, 2002, FERC gave conditioned approval for both RTO West and TransConnect phase II filings. 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. STANDARD MARKET DESIGN NOPR On July 31, 2002, the FERC issued a Standard Market Design Notice of Proposed Rulemaking. The FERC's intent is to standardize the practices and policies followed by all jurisdictional entities in the United States. This proposal is currently being reviewed and evaluated by interested parties. The Utilities have submitted comments on this proposed rule. 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 BPA 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 by an 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. 113 ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK INTEREST RATE RISK SPR, NPC and SPPC have evaluated their 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. As reflected in the tables that follow, the fair market value of SPR's market-sensitive financial instruments declined approximately 8.5% during 2002 as a result of credit rating downgrades by Standard and Poor's and Moody's. Fair market value is determined using quoted market price for the same or similar issues or on the current rates offered for debt of the same remaining maturities. Expected Maturity Date December 31, 2002
Fair Market Value Expected Maturities Amounts (dollars in thousands) Weighted Avg Int Rate(1) (dollars in thousands) --------------------------------------------------- ------------------------ ---------------------- Fixed Rate NPC SPPC SPR Consolidated Consolidated Consolidated ---------- ---------- ---------- ------------ ------------------------ ---------------------- 2003 $ 210,013 $ 101,400 $ 16,886 $ 328,299 6.03% 2004 130,013 3,400 14,498 147,911 6.40% 2005 15 100,400 300,000 400,415 9.16% 2006 15 52,400 -- 52,415 6.71% 2007 17 2,400 345,000 347,417 7.92% Thereafter 1,188,848 760,250 -- 1,949,098 7.65% ---------- ---------- ---------- ------------ ------------------------ ---------------------- Total Fixed Rate $1,528,921 $1,020,250 $ 676,384 $ 3,225,555 $ 2,846,356 ---------- ---------- ---------- ------------ ------------------------ ---------------------- Variable Rate 2003 $ 140,000 $ -- $ 200,000 $ 340,000 2.94% 2004 -- -- -- -- 2005 -- -- -- -- 2006 -- -- -- -- 2007 -- -- -- -- Thereafter 115,000 -- -- 115,000 1.74% ---------- ---------- ---------- ------------ ------------------------ ---------------------- $ 255,000 $ -- $ 200,000 $ 455,000 $ 385,800 ---------- ---------- ---------- ------------ ------------------------ ---------------------- Preferred securities (fixed rate) After 2007 $ 188,872 $ -- $ -- $ 188,872 8.03% $ 139,834 ---------- ---------- ---------- ------------ ------------------------ ---------------------- Total $1,972,793 $1,020,250 $ 876,384 $ 3,869,427 $ 3,371,990 ---------- ---------- ---------- ------------ ------------------------ ----------------------
114 Expected Maturity Date December 31, 2001
Fair Market Value Expected Maturities Amounts (dollars in thousands) Weighted Avg Int Rate(1) (dollars in thousands) --------------------------------------------------- ------------------------ ---------------------- Fixed Rate NPC SPPC SPR 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 ---------- ---------- ---------- ------------ ------------------------ ---------------------- Peferred securities (fixed rate) After 2005 $ 188,872 $ -- $ -- $ 188,872 8.03% $ 181,525 ========== ========== ========== ============ ======================== ---------------------- Total $1,737,707 $ 926,661 $ 945,000 $ 3,609,368 $ 3,684,299 ---------- ---------- ---------- ------------ ------------------------ ----------------------
(1) Weighted average daily rate for months ended December 31, 2002, and 2001. COMMODITY PRICE RISK The Utilities are 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 Energy Supply 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' revised and approved Enterprise Risk Management and Control Policy. That policy created the EROC and made that committee responsible for the overall policy direction of the Utilities' risk management and control efforts. That policy further instructed the EROC to oversee the development of appropriate risk management and control policies including the Energy Supply Risk Management and Control Policy. The Utilities' commodity risk management program establishes a control framework based on existing commercial practices. The program creates common predefined risk limits 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 portfolio and credit limits. The Utilities, through the purchase and sale of the financial instruments and physical products, maintain an energy risk management program that limits energy risk to levels consistent with approved Energy Supply Plans. The program has provisions for the systematic identification, quantification, evaluation, and 115 management of the energy risk inherent in the Utilities' operations and for the preparation of periodic reports to document the Utilities' efforts and to comply with legal and regulatory requirements. The Energy Supply Plans include recommended courses of action to be followed during the three-year period covered by the plan and: o govern the purchase and sale of fuel and wholesale power and the associated transmission or transportation services; o include assessments of projected loads and resources, assessments of expected market prices, and, evaluations of relevant supply portfolio options available to the Utilities; o evaluate the risk attributable to those supply portfolio options; and, o address the use of financial instruments for hedging in conjunction with energy purchases and sales. Currently, commodity price increases due to changes in market conditions for purchased fuel and power and natural gas are recovered through the deferred energy accounting mechanism, with no anticipated effect on earnings. Commodity price risk is mitigated by the use of long-term fuel supply agreements, long- term purchase power agreements and derivative instruments such as forwards, options and swaps entered into to meet the anticipated fuel and power needs necessary to satisfy the jurisdictional load requirements of the Utilities. However, the Utilities are subject to regulatory risk related to commodity price changes due to the fact that the PUCN may disallow recovery for any of these costs that it considers imprudently incurred. CREDIT RISK The Utilities also monitor and manage credit risk with their trading counterparties. As of December 31, 2002, the Utilities had outstanding transactions with over 50 energy and financial services companies. The Utilities credit risk associated with these transactions was approximately $12 million as of December 31, 2002. 116 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Page ---- Independent Auditors' Reports ................................................................. 118 Financial Statements: Consolidated Balance Sheets as of December 31, 2002 and 2001 .......................... 121 Consolidated Statements of Operations for the Years Ended December 31, 2002, 2001 and 2000 ................................................................ 122 Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2002, 2001 and 2000 ................................................... 123 Consolidated Statements of Common Shareholders' Equity for the Years Ended December 31, 2002, 2001 and 2000 ....................................... 124 Consolidated Statements of Cash Flows for the Years Ended December 31, 2002, 2001 and 2000 ................................................... 125 Consolidated Statements of Capitalization as of December 31, 2002 and 2001 ............ 126 Consolidated Balance Sheets for Nevada Power Company as of December 31, 2002 and 2001 ......................................................... 128 Consolidated Statements of Operations for Nevada Power Company for the Years Ended December 31, 2002, 2001 and 2000 ............................... 129 Consolidated Statements of Comprehensive Income (Loss) for Nevada Power Company for the Years Ended December 31, 2002, 2001 and 2000 ....................... 130 Consolidated Statements of Common Shareholder's Equity for Nevada Power Company for the Years Ended December 31, 2002, 2001 and 2000 ............................... 131 Consolidated Statements of Cash Flows for Nevada Power Company for the Years Ended December 31, 2002, 2001 and 2000 ............................... 132 Consolidated Statements of Capitalization for Nevada Power Company as of December 31, 2002 and 2001 ............................................ 133 Consolidated Balance Sheets for Sierra Pacific Power Company as of December 31, 2002 and 2001 ......................................................... 134 Consolidated Statements of Operations for Sierra Pacific Power Company for the Years Ended December 31, 2002, 2001 and 2000 ............................... 135 Consolidated Statements of Comprehensive Income (Loss) for Sierra Pacific Power Company for the Years Ended December 31, 2002, 2001 and 2000 ....................... 136 Consolidated Statements of Common Shareholder's Equity for Sierra Pacific Power Company for the Years Ended December 31, 2002, 2001 and 2000 ................. 137 Consolidated Statements of Cash Flows for Sierra Pacific Power Company for the Years Ended December 31, 2002, 2001 and 2000 ............................... 138 Consolidated Statements of Capitalization for Sierra Pacific Power Company as of December 31, 2002 and 2001 ............................................ 139 Notes to Financial Statements ................................................................. 140
117 INDEPENDENT AUDITORS' REPORT To the Board of Directors and Shareholders 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 as of December 31, 2002 and 2001, and the related consolidated statements of operations, comprehensive income (loss), common shareholders' equity, and cash flows for each of the three years in the period ended December 31, 2002. Our audits also included the financial statement schedule listed in the Index at Item 15. 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 Sierra Pacific Resources and subsidiaries as of December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002, 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, presents fairly in all material respects the information set forth therein. As discussed in Note 20 to the consolidated financial statements, during 2002 the Company changed its method of accounting for goodwill to conform to Statement of Accounting Standards No. 142, Accounting for Goodwill. Deloitte & Touche LLP Reno, Nevada February 28, 2003 118 INDEPENDENT AUDITORS' REPORT To the Board of Directors and Shareholder of Nevada Power Company Reno, Nevada We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Nevada Power Company and subsidiaries as of December 31, 2002 and 2001, and the related consolidated statements of operations, comprehensive income (loss), common shareholder's equity, and cash flows for each of the three years in the period ended December 31, 2002. Our audits also included the financial statement schedule listed in the Index at Item 15. 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 Nevada Power Company and subsidiaries as of December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002, 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, presents fairly in all material respects the information set forth therein. Deloitte & Touche LLP Reno, Nevada February 28, 2003 119 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, 2002 and 2001, and the related consolidated statements of operations, comprehensive income (loss), common shareholder's equity, and cash flows for each of the three years in the period ended December 31, 2002. Our audits also included the financial statement schedule listed in the Index at Item 15. 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 Sierra Pacific Power Company and subsidiaries as of December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002, 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, presents fairly in all material respects the information set forth therein. Deloitte & Touche LLP Reno, Nevada February 28, 2003 120 SIERRA PACIFIC RESOURCES CONSOLIDATED BALANCE SHEETS (Dollars in Thousands)
DECEMBER 31, 2002 2001 ------------ ------------ ASSETS Utility Plant at Original Cost: Plant in service $ 5,989,701 $ 5,744,041 Less accumulated provision for depreciation 1,944,351 1,783,773 ------------ ------------ 4,045,350 3,960,268 Construction work-in-progress 263,346 203,456 ------------ ------------ 4,308,696 4,163,724 ------------ ------------ Investments in subsidiaries and other property, net 134,068 73,573 ------------ ------------ Current Assets: Cash and cash equivalents 193,386 99,109 Restricted cash (Note 1) 13,705 -- Accounts receivable less provision for uncollectible accounts: 2002-$44,184 ; 2001-$39,335 359,083 394,489 Deferred energy costs - electric 268,979 333,062 Deferred energy costs - gas 17,045 19,805 Income tax receivable -- 185,011 Materials, supplies and fuel, at average cost 87,840 94,484 Risk management assets (Note 19) 29,570 286,509 Other 48,960 14,071 ------------ ------------ 1,018,568 1,426,540 ------------ ------------ Deferred Charges and Other Assets: Goodwill (Note 20) 310,441 312,145 Deferred energy costs - electric 685,875 854,778 Deferred energy costs - gas -- 23,248 Regulatory tax asset 163,889 169,738 Other regulatory assets (Note 1) 136,933 96,725 Risk management assets (Note 19) 368 61,058 Risk management regulatory assets - net (Note 19) 44,970 664,383 Other 92,436 146,164 ------------ ------------ 1,434,912 2,328,239 ------------ ------------ $ 6,896,244 $ 7,992,076 ============ ============ CAPITALIZATION AND LIABILITIES Capitalization: Common shareholders' equity $ 1,327,166 $ 1,695,336 Preferred stock 50,000 50,000 NPC obligated mandatorily redeemable preferred trust securities 188,872 188,872 Long-term debt 3,062,883 3,376,105 ------------ ------------ 4,628,921 5,310,313 ------------ ------------ Current Liabilities: Short-term borrowings -- 177,000 Current maturities of long-term debt 672,963 122,010 Accounts payable 233,099 265,250 Accrued interest 50,308 37,565 Dividends declared 1,045 1,045 Accrued salaries and benefits 20,828 30,145 Deferred taxes 126,228 145,903 Risk management liabilities (Note 19) 69,953 855,301 Other current liabilities 46,719 15,678 ------------ ------------ 1,221,143 1,649,897 ------------ ------------ Commitments & Contingencies (Note 17) Deferred Credits and Other Liabilities: Deferred federal income taxes 333,423 508,329 Deferred investment tax credit 48,492 51,947 Regulatory tax liability 42,718 46,702 Customer advances for construction 116,032 108,179 Accrued retirement benefits 107,580 82,624 Risk management liabilities (Note 19) 3,917 163,636 Contract termination reserves (Note 17) 312,594 -- Other 81,424 70,449 ------------ ------------ 1,046,180 1,031,866 ------------ ------------ $ 6,896,244 $ 7,992,076 ============ ============
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS. 121 SIERRA PACIFIC RESOURCES CONSOLIDATED STATEMENTS OF OPERATIONS (DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
YEAR ENDED DECEMBER 31, 2002 2001 2000 ------------ ------------ ------------ OPERATING REVENUES: Electric $ 2,832,285 $ 4,426,881 $ 2,221,111 Gas 149,783 145,652 100,803 Other 9,635 18,841 14,199 ------------ ------------ ------------ 2,991,703 4,591,374 2,336,113 ------------ ------------ ------------ OPERATING EXPENSES: Operation: Purchased power 1,786,823 4,052,077 1,116,375 Fuel for power generation 453,436 728,619 526,535 Gas purchased for resale 91,961 136,534 83,199 Deferred energy costs disallowed 491,081 -- -- Deferral of energy costs - electric - net (233,814) (1,136,148) 16,719 Deferral of energy costs - gas - net 24,785 (23,170) (16,164) Other 294,219 332,860 261,079 Maintenance 64,440 69,499 52,477 Depreciation and amortization 175,782 166,385 158,315 Taxes: Income taxes (168,498) (1,230) (31,022) Other than income 44,544 43,079 42,215 ------------ ------------ ------------ 3,024,759 4,368,505 2,209,728 ------------ ------------ ------------ OPERATING INCOME (LOSS) (33,056) 222,869 126,385 ------------ ------------ ------------ OTHER INCOME (EXPENSE): Allowance for other funds used during construction (36) 474 2,813 Interest accrued on deferred energy 23,058 55,204 205 Other income 10,578 12,023 12,091 Other expense (18,386) (13,634) (8,135) Income taxes (4,058) (14,870) (511) ------------ ------------ ------------ 11,156 39,197 6,463 ------------ ------------ ------------ Total Income (Loss) Before Interest Charges (21,900) 262,066 132,848 ------------ ------------ ------------ INTEREST CHARGES: Long-term debt 234,542 188,370 134,596 Other 35,711 24,161 35,887 Allowance for borrowed funds used during construction and capitalized interest (5,270) (2,801) (10,634) ------------ ------------ ------------ 264,983 209,730 159,849 ------------ ------------ ------------ Dividend requirements of NPC obligated mandatorily redeemable preferred trust securities 15,172 18,770 18,914 ------------ ------------ ------------ INCOME (LOSS) FROM CONTINUING OPERATIONS (302,055) 33,566 (45,915) ------------ ------------ ------------ DISCONTINUED OPERATIONS: Income from operations of water business disposed of (net of income taxes of $888 and $3,426 in 2001 and 2000, respectively) -- 1,022 9,634 Gain on disposal of water business (net of income taxes of $18,237) -- 25,845 -- CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE, NET OF TAX (NOTE 20) (1,566) -- -- ------------ ------------ ------------ NET INCOME (LOSS) (303,621) 60,433 (36,281) ------------ ------------ ------------ Preferred stock dividend requirements of subsidiary 3,900 3,700 3,499 ------------ ------------ ------------ EARNINGS (LOSS) APPLICABLE TO COMMON STOCK $ (307,521) $ 56,733 $ (39,780) ============ ============ ============ Basic and diluted earnings (loss) per share of common stock From continuing operations $ (3.00) $ 0.34 $ (0.63) From discontinued operations -- 0.01 0.12 Gain on disposal of water business -- 0.30 -- Cumulative effect of change in accounting principle (net of tax) (0.01) -- -- ------------ ------------ ------------ Applicable to common stock $ (3.01) $ 0.65 $ (0.51) ============ ============ ============ Weighted Average Shares of Common Stock Outstanding 102,126,079 87,542,441 78,435,405 ============ ============ ============ Dividends Paid Per Share of Common Stock $ 0.20 $ 0.65 $ 1.00 ============ ============ ============
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS. 122 SIERRA PACIFIC RESOURCES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (DOLLARS IN THOUSANDS)
YEAR ENDED DECEMBER 31, -------------------------------------- 2002 2001 2000 ---------- ---------- ---------- NET INCOME (LOSS) $ (303,621) $ 60,433 $ (36,281) OTHER COMPREHENSIVE INCOME (LOSS) Adoption of SFAS No. 133- Accounting for Derivative Instruments and Hedging Activities: Cumulative effect upon adoption of change in accounting principle as of January 1 (Net of taxes of $1,035) -- (1,923) -- Change in market value of risk management assets and liabilities as of December 31 (Net of taxes of $3,083 and $2,726 in 2002 and 2001, respectively) 5,726 (5,063) -- Minimum pension liability adjustment (Net of taxes of $24,904) (46,251) -- -- ---------- ---------- ---------- OTHER COMPREHENSIVE (LOSS) (40,525) (6,986) -- ---------- ---------- ---------- COMPREHENSIVE INCOME (LOSS) $ (344,146) $ 53,447 $ (36,281) ========== ========== ==========
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS 123 SIERRA PACIFIC RESOURCES CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY (DOLLARS IN THOUSANDS)
Year ended December 31, 2002 2001 2000 ---------- ---------- ---------- COMMON STOCK: Balance at Beginning of Year $ 102,111 $ 78,475 $ 78,414 Stock purchase and dividend reinvestment 66 23,636 61 ---------- ---------- ---------- Balance at end of year 102,177 102,111 78,475 ---------- ---------- ---------- OTHER PAID-IN CAPITAL: Balance at Beginning of Year 1,598,634 1,295,221 1,293,990 Premium on sale of common stock -- 330,050 -- Common Stock issuance costs -- (13,910) -- Purchase contract adjustment payment -- (13,676) CSIP, DRP, ESPP and other 390 949 1,231 ---------- ---------- ---------- Balance at End of Year 1,599,024 1,598,634 1,295,221 ---------- ---------- ---------- RETAINED EARNINGS (ACCUMULATED DEFICIT): Balance at Beginning of Year 1,577 (13,984) 104,725 Income (loss) from continuing operations (302,055) 33,566 (45,915) Income from discontinued operations (before preferred dividend allocation of $200 and $401 in 2001 and 2000, respectively) -- 1,222 10,035 Cumulative effect of change in accounting principle, net of tax (1,566) Gain on disposal of water business -- 25,845 -- Preferred stock dividends declared (3,900) (3,900) (3,900) Common stock dividends declared (20,580) (41,172) (78,929) ---------- ---------- ---------- Balance at End of Year (326,524) 1,577 (13,984) ---------- ---------- ---------- ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS): Balance at Beginning of Year (6,986) -- -- Cumulative effect upon adoption of change in accounting principle as of January 1 (net of taxes of $1,035) -- (1,923) -- Change in market value of risk management assets and liabilities as of December 31 (net of taxes of $3,083 and $2,726 in 2002 and 2001, respectively) 5,726 (5,063) -- Minimum pension liability adjustment (net of taxes of $24,904) (46,251) -- -- ---------- ---------- ---------- Balance at End of Year (47,511) (6,986) -- ---------- ---------- ---------- TOTAL COMMON SHAREHOLDERS' EQUITY AT END OF YEAR $1,327,166 $1,695,336 $1,359,712 ========== ========== ==========
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS 124 SIERRA PACIFIC RESOURCES CONSOLIDATED STATEMENTS OF CASH FLOWS (Dollars in Thousands)
YEAR ENDED DECEMBER 31, 2002 2001 2000 ------------ ------------ ------------ CASH FLOWS FROM OPERATING ACTIVITIES: Net Income (Loss) $ (303,621) $ 60,433 $ (36,281) Preferred dividends included in discontinued operations -- 200 401 Non-cash items included in income: Depreciation and amortization 175,782 169,866 165,136 Deferred taxes and deferred investment tax credit (18,410) 85,917 (18,564) AFUDC and capitalized interest (5,234) (3,285) (13,858) Amortization of deferred energy costs - electric 176,718 -- -- Amortization of deferred energy costs - gas 13,231 3,562 -- Deferred energy costs disallowed (net of taxes) 320,484 -- -- Early retirement and severance amortization 2,706 3,121 4,196 Gain on disposal of water business -- (44,081) -- Other non-cash 6,297 2,290 31,550 Adjustment in value of Premium Income Equity Securities -- (13,677) -- Changes in certain assets and liabilities: Accounts receivable 35,406 (1,841) (174,112) Deferral of energy costs - electric (413,654) (1,187,840) 14,884 Deferral of energy costs - gas 10,270 (30,245) (16,370) Materials, supplies and fuel 6,644 (18,654) (1,858) Other current assets (48,594) 4,248 (52,125) Accounts payable (32,151) (97,992) 224,794 Income tax receivable 185,011 -- -- Other current liabilities 34,467 14,752 16,359 Other assets (3,073) (9,315) 9,971 Other liabilities 316,547 19,200 34,123 ------------ ------------ ------------ Net Cash from Operating Activities 458,826 (1,043,341) 188,246 ------------ ------------ ------------ CASH FLOWS FROM INVESTING ACTIVITIES: Additions to utility plant (399,807) (333,606) (360,130) AFUDC and other charges to utility plant 5,234 3,285 15,227 Customer advances (refunds) for construction 7,852 815 (889) Contributions in aid of construction 43,247 27,481 16,446 ------------ ------------ ------------ Net cash used for utility plant (343,474) (302,025) (329,346) Proceeds from sale of assets of water business -- 318,882 -- Investments in subsidiaries and other property - net (57,781) (9,065) (30,050) ------------ ------------ ------------ Net Cash from Investing Activities (401,255) 7,792 (359,396) ------------ ------------ ------------ CASH FLOWS FROM FINANCING ACTIVITIES: Decrease in short-term borrowings (177,000) (36,074) (547,310) Proceeds from issuance of long-term debt 350,000 1,215,000 1,165,000 Retirement of long-term debt (112,269) (323,091) (318,061) Redemption of preferred stock -- (48,500) -- Sale of common stock 460 340,737 1,292 Dividends paid (24,485) (64,917) (83,057) ------------ ------------ ------------ Net Cash from Financing Activities 36,706 1,083,155 217,864 ------------ ------------ ------------ NET INCREASE IN CASH AND CASH EQUIVALENTS 94,277 47,606 46,714 Beginning Balance in Cash and Cash Equivalents 99,109 51,503 4,789 ------------ ------------ ------------ Ending Balance in Cash and Cash Equivalents $ 193,386 $ 99,109 $ 51,503 ============ ============ ============ SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION: Cash paid (received) during period for: Interest $ 257,462 $ 208,390 $ 167,158 Income taxes $ (185,011) $ (55,022) $ 12,730
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS 125 SIERRA PACIFIC RESOURCES CONSOLIDATED STATEMENTS OF CAPITALIZATION (DOLLARS IN THOUSANDS)
DECEMBER 31, 2002 2001 ------------ ------------ COMMON SHAREHOLDERS' EQUITY: Common stock $1.00 par value, authorized 250 million shares; issued and outstanding 2002: 102,177,000 shares; 2001, 102,111,000 shares $ 102,177 $ 102,111 Other paid-in capital 1,599,024 1,598,634 Retained earnings accumulated (deficit) (326,524) 1,577 Accumulated Other Comprehensive Loss (47,511) (6,986) ------------ ------------ Total Common Shareholders' Equity 1,327,166 1,695,336 ------------ ------------ 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 TRUST SECURITIES OF SUBSIDIARIES: 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 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 ------------ ------------ Total Preferred Securities of Subsidiaries 188,872 188,872 ------------ ------------ LONG-TERM DEBT: Unamortized bond premium and discount, net (17,968) (959) Debt Secured by First Mortgage Bonds 7.63% Series L due 2002 -- 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 2.00% Series O due 2011 -- 1,281 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 5.00% Series Y due 2024 -- 3,072 6.70% Series II due 2032 21,200 21,200 5.50% Series D MTN due 2003 5,000 5,000 5.59% Series D MTN due 2003 13,000 13,000 ------------ ------------ Subtotal 744,782 781,200 ------------ ------------
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS. 126 SIERRA PACIFIC RESOURCES CONSOLIDATED STATEMENTS OF CAPITALIZATION (Dollars in Thousands)
DECEMBER 31, CONTINUED FROM PREVIOUS PAGE 2002 2001 ------------ ------------ 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 2003 140,000 140,000 IDRB Series 2000A due 2020 100,000 100,000 PCRB Series 2000B due 2009 15,000 15,000 Floating Rate Notes due 2002 100,000 Floating Rate Notes due 2003 200,000 200,000 ------------ ------------ Subtotal 455,000 555,000 ------------ ------------ Debt Secured by General and Refunding Bonds: 8.25% Series A due 2011 350,000 350,000 10.88% Series E due 2009 250,000 -- 8.00% Series A due 2008 320,000 320,000 10.50% (Variable) Series C due 2005 100,000 -- ------------ ------------ Subtotal 1,020,000 670,000 ------------ ------------ Other Notes: 5.75% Series 2001 due 2036 80,000 80,000 6.00% Series B notes due 2003 210,000 210,000 8.75% Senior unsecured note Series 2000 due 2005 300,000 300,000 7.93% Senior unsecured notes due 2007 345,000 345,000 ------------ ------------ Subtotal 935,000 935,000 ------------ ------------ Obligations under capital leases 73,259 78,313 ------------ ------------ Current maturities and sinking fund requirements (672,963) (122,010) ------------ ------------ Other 46,470 17,267 ------------ ------------ Total Long-Term Debt 3,062,883 3,376,105 ------------ ------------ TOTAL CAPITALIZATION $ 4,628,921 $ 5,310,313 ============ ============
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS. 127 NEVADA POWER COMPANY CONSOLIDATED BALANCE SHEETS (DOLLARS IN THOUSANDS)
DECEMBER 31, 2002 2001 ---------- ---------- ASSETS Utility Plant at Original Cost: Plant in service $3,542,300 $3,356,584 Less accumulated provision for depreciation 1,017,494 928,939 ---------- ---------- 2,524,806 2,427,645 Construction work-in-progress 173,189 134,706 ---------- ---------- 2,697,995 2,562,351 ---------- ---------- Investments in subsidiaries and other property, net 20,295 12,721 ---------- ---------- Current Assets: Cash and cash equivalents 95,009 8,505 Restricted cash (Note 1) 3,850 -- Accounts receivable less provision for uncollectible accounts: 2002-$33,841; 2001-$30,861 202,590 210,333 Deferred energy costs - electric 213,193 281,555 Income tax receivable -- 102,904 Materials, supplies and fuel, at average cost 44,074 48,511 Risk management assets (Note 19) 28,173 200,829 Other 31,602 6,698 ---------- ---------- 618,491 859,335 ---------- ---------- Deferred Charges and Other Assets: Deferred energy costs - electric 524,345 698,510 Regulatory tax asset 106,071 109,859 Other regulatory assets 53,109 27,694 Risk management assets (Note 19) 368 49,493 Risk management regulatory assets - net (Note 19) 1,491 351,264 Other 46,357 33,379 ---------- ---------- 731,741 1,270,199 ---------- ---------- $4,068,522 $4,704,606 ========== ========== CAPITALIZATION AND LIABILITIES Capitalization: Common shareholder's equity $1,149,131 $1,393,583 NPC obligated mandatorily redeemable preferred trust securities 188,872 188,872 Long-term debt 1,488,597 1,607,967 ---------- ---------- 2,826,600 3,190,422 ---------- ---------- Current Liabilities: Short-term borrowings -- 130,500 Current maturities of long-term debt 354,677 19,380 Accounts payable 143,002 146,114 Accounts payable, affiliated companies 4,287 56,441 Accrued interest 29,892 19,310 Dividends declared 78 71 Accrued salaries and benefits 7,781 12,450 Deferred taxes 90,616 117,244 Risk management liabilities (Note 19) 29,908 522,508 Other current liabilities 22,115 17,710 ---------- ---------- 682,356 1,041,728 ---------- ---------- Commitments & Contingencies (Note 17) Deferred Credits and Other Liabilities: Deferred federal income taxes 129,687 237,916 Deferred investment tax credit 21,902 23,533 Regulatory tax liability 17,300 18,604 Customer advances for construction 66,434 61,454 Accrued retirement benefits 54,216 28,104 Risk management liabilities (Note 19) -- 78,558 Contract termination reserves (Note 17) 225,816 -- Other 44,211 24,287 ---------- ---------- 559,566 472,456 ---------- ---------- $4,068,522 $4,704,606 ========== ==========
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS. 128 NEVADA POWER COMPANY CONSOLIDATED STATEMENTS OF OPERATIONS (Dollars in Thousands)
YEAR ENDED DECEMBER 31, 2002 2001 2000 ------------ ------------ ------------ OPERATING REVENUES: Electric $ 1,901,034 $ 3,025,103 $ 1,326,192 OPERATING EXPENSES: Operation: Purchased power 1,241,783 3,026,336 671,396 Fuel for power generation 309,293 441,900 292,787 Deferred energy costs disallowed 434,123 -- -- Deferral of energy costs-net (179,182) (937,322) 16,719 Other 167,768 169,442 139,723 Maintenance 41,200 45,136 34,057 Depreciation and amortization 98,198 93,101 85,989 Taxes: Income taxes (133,411) 17,775 (12,162) Other than income 25,265 24,371 23,501 ------------ ------------ ------------ 2,005,037 2,880,739 1,252,010 ------------ ------------ ------------ OPERATING INCOME (LOSS) (104,003) 144,364 74,182 ------------ ------------ ------------ OTHER INCOME (EXPENSE): Allowance for other funds used during construction (153) (382) 2,456 Interest accrued on deferred energy 12,414 42,743 -- Other income 273 4,200 4,413 Other expense (9,933) (4,709) (2,216) Income taxes (1,627) (14,962) (1,201) ------------ ------------ ------------ 974 26,890 3,452 ------------ ------------ ------------ Total Income (Loss) Before Interest Charges (103,029) 171,254 77,634 ------------ ------------ ------------ INTEREST CHARGES: Long-term debt 98,886 81,599 64,513 Other 21,395 13,219 13,732 Allowance for borrowed funds used during construction and capitalized interest (3,412) (2,141) (7,855) ------------ ------------ ------------ 116,869 92,677 70,390 ------------ ------------ ------------ Dividend requirements of NPC obligated mandatorily redeemable preferred trust securities 15,172 15,172 15,172 ------------ ------------ ------------ NET INCOME (LOSS) $ (235,070) $ 63,405 $ (7,928) ============ ============ ============
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS. 129 NEVADA POWER COMPANY CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (DOLLARS IN THOUSANDS)
Year ended December 31, ------------------------------------- 2002 2001 2000 ---------- ---------- ---------- NET INCOME (LOSS) $ (235,070) $ 63,405 $ (7,928) OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX: Adoption of SFAS No. 133- Accounting for Derivative Instruments and Hedging Activities: Cumulative effect upon adoption of change in accounting principle as of January 1 (Net of taxes of $239) -- 444 -- Change in market value of risk management assets and liabilities as of December 31 (Net of taxes of $213 and $41 in 2002 and 2001, respectively) (397) 76 -- Minimum pension liability adjustment (Net of taxes of $4,838) (8,985) -- -- ---------- ---------- ---------- OTHER COMPREHENSIVE INCOME (LOSS) (9,382) 520 -- ---------- ---------- ---------- COMPREHENSIVE INCOME (LOSS) $ (244,452) $ 63,925 $ (7,928) ========== ========== ==========
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS 130 NEVADA POWER COMPANY CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER'S EQUITY (DOLLARS IN THOUSANDS)
Year ended December 31, 2002 2001 2000 ---------- ---------- ---------- COMMON STOCK Balance at Beginning of Year and End of Year $ 1 $ 1 $ 1 ---------- ---------- ---------- OTHER PAID-IN CAPITAL: Balance at Beginning of Year 1,367,106 892,185 755,185 Additional investment by parent company 10,000 474,921 137,000 ---------- ---------- ---------- Balance at End of Year 1,377,106 1,367,106 892,185 ---------- ---------- ---------- RETAINED EARNINGS (ACCUMULATED DEFICIT): Balance at Beginning of Year 25,956 (4,449) 67,746 Income (loss) for the year (235,070) 63,405 (7,928) Common stock dividends declared (10,000) (33,000) (64,267) ---------- ---------- ---------- Balance at End of Year (219,114) 25,956 (4,449) ---------- ---------- ---------- ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS): Balance at Beginning of Year 520 -- -- Cumulative effect upon adoption of change in accounting principle as of January 1 (net of taxes of $239) -- 444 -- Change in market value of risk management assets and liabilities as of December 31 (net of taxes of $213 and $41 in 2002 and 2001, respectively) (397) 76 -- Minimum pension liability adjustment (net of taxes of $4,838) (8,985) -- -- ---------- ---------- ---------- Balance at End of Year (8,862) 520 -- ---------- ---------- ---------- TOTAL COMMON SHAREHOLDER'S EQUITY AT END OF YEAR $1,149,131 $1,393,583 $ 887,737 ========== ========== ==========
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS. 131 NEVADA POWER COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (Dollars in Thousands)
YEAR ENDED DECEMBER 31, 2002 2001 2000 ---------- ---------- ---------- CASH FLOWS FROM OPERATING ACTIVITIES: Net Income (Loss) $ (235,070) $ 63,405 $ (7,928) Non-cash items included in income: Depreciation and amortization 98,198 93,102 85,989 Deferred taxes and deferred investment tax credit 20,868 55,085 (26,528) AFUDC and capitalized interest (3,259) (1,759) (10,311) Amortization of deferred energy costs 146,554 -- -- Deferred energy costs disallowed (net of taxes) 282,181 -- -- Other non-cash 563 264 20,101 Changes in certain assets and liabilities: Accounts receivable 8,487 (41,444) (57,935) Deferral of energy costs (338,152) (980,065) 14,884 Materials, supplies and fuel 4,437 (2,938) (2,465) Other current assets (28,691) 3,507 (25,360) Accounts payable (55,316) 44,747 82,720 Income tax receivable 102,904 -- -- Other current liabilities 10,317 3,812 10,001 Other assets -- -- 3,521 Other liabilities 239,736 4,882 27,022 ---------- ---------- ---------- Net Cash from Operating Activities 253,757 (757,402) 113,711 ---------- ---------- ---------- CASH FLOWS FROM INVESTING ACTIVITIES: Additions to utility plant (294,480) (200,852) (204,505) AFUDC and other charges to utility plant 3,259 1,759 11,622 Customer advances (refunds) for construction 4,980 (4,134) (3,753) Contributions in aid of construction 35,800 6,331 -- ---------- ---------- ---------- Net cash used for utility plant (250,441) (196,896) (196,636) Investments in subsidiaries and other property - net (2,239) (115) -- ---------- ---------- ---------- Net Cash from Investing Activities (252,680) (197,011) (196,636) ---------- ---------- ---------- CASH FLOWS FROM FINANCING ACTIVITIES: Increase (decrease) in short-term borrowings (130,500) 30,500 (82,000) Proceeds from issuance of long-term debt 250,000 815,000 365,000 Retirement of long-term debt (34,073) (368,347) (205,152) Investment by parent company 10,000 474,921 137,000 Dividends paid (10,000) (33,014) (88,308) ---------- ---------- ---------- Net Cash from Financing Activities 85,427 919,060 126,540 ---------- ---------- ---------- NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 86,504 (35,353) 43,615 Beginning Balance in Cash and Cash Equivalents 8,505 43,858 243 ---------- ---------- ---------- Ending Balance in Cash and Cash Equivalents $ 95,009 $ 8,505 $ 43,858 ========== ========== ========== SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION: Cash paid (received) during period for: Interest $ 109,679 $ 90,280 $ 71,430 Income taxes $ (102,904) $ (13,702) $ 6,500
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS 132 NEVADA POWER COMPANY CONSOLIDATED STATEMENTS OF CAPITALIZATION (Dollars in Thousands)
DECEMBER 31, 2002 2001 ------------ ------------ COMMON SHAREHOLDER'S EQUITY: Common stock issued, stated value $1 1,000 shares authorized, issued and outstanding $ 1 $ 1 Other paid-in capital 1,377,106 1,367,106 Retained earnings accumulated (deficit) (219,114) 25,956 Accumulated other shareholder's equity (8,862) 520 ------------ ------------ Total Common Shareholders' Equity 1,149,131 1,393,583 ------------ ------------ PREFERRED TRUST SECURITIES: 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 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 (13,906) 2 Debt Secured by First Mortgage Bonds: 7.63% Series L due 2002 -- 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 243,594 272,502 ------------ ------------ 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 2003 140,000 140,000 IDRB Series 2000A due 2020 100,000 100,000 PCRB Series 2000B due 2009 15,000 15,000 ------------ ------------ Subtotal 255,000 255,000 ------------ ------------ Debt Secured by General and Refunding Bonds: 8.25% Series A due 2011 350,000 350,000 10.88% Series E due 2009 250,000 -- ------------ ------------ 600,000 350,000 ------------ ------------ Other Notes: 6.0% Series B notes due 2003 210,000 210,000 ------------ ------------ Obligation under capital leases 73,259 78,313 ------------ ------------ Current maturities and sinking fund requirements (354,677) (19,380) ------------ ------------ Other, excluding current portion 86 197 ------------ ------------ Total Long-Term Debt 1,488,597 1,607,967 ------------ ------------ TOTAL CAPITALIZATION $ 2,826,600 $ 3,190,422 ============ ============
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS. 133 SIERRA PACIFIC POWER COMPANY CONSOLIDATED BALANCE SHEETS (DOLLARS IN THOUSANDS)
DECEMBER 31, 2002 2001 ---------- ---------- ASSETS Utility Plant at Original Cost: Plant in service $2,447,401 $2,387,457 Less accumulated provision for depreciation 926,857 854,834 ---------- ---------- 1,520,544 1,532,623 Construction work-in-progress 90,157 68,750 ---------- ---------- 1,610,701 1,601,373 ---------- ---------- Investments in subsidiaries and other property, net 874 1,866 ---------- ---------- Current Assets: Cash and cash equivalents 88,910 11,772 Restricted cash (Note 1) 9,605 -- Accounts receivable less provision for uncollectible accounts: 2002 - $10,343; 2001 - $8,474 154,821 175,771 Accounts receivable, affiliated companies 58,680 18,927 Deferred energy costs - electric 55,786 51,507 Deferred energy costs - gas 17,045 19,805 Materials, supplies and fuel, at average cost 41,727 42,607 Income tax receivable -- 62,109 Risk management assets (Note 19) 1,397 85,680 Other 12,955 5,935 ---------- ---------- 440,926 474,113 ---------- ---------- Deferred Charges and Other Assets: Deferred energy costs - electric 161,530 156,268 Deferred energy costs - gas -- 23,248 Regulatory tax asset 57,818 59,879 Other regulatory assets 64,149 49,356 Risk management assets (Note 19) -- 11,565 Risk management regulatory assets - net (Note 19) 43,479 313,119 Other 19,013 16,189 ---------- ---------- 345,989 629,624 ---------- ---------- $2,398,490 $2,706,976 ========== ========== CAPITALIZATION AND LIABILITIES Capitalization: Common shareholder's equity $ 639,295 $ 692,901 Preferred stock 50,000 50,000 Long-term debt 914,788 923,070 ---------- ---------- 1,604,083 1,665,971 ---------- ---------- Current Liabilities: Short-term borrowings -- 46,500 Current maturities of long-term debt 101,400 2,630 Accounts payable 71,247 95,555 Accrued interest 12,136 8,408 Dividends declared 968 974 Accrued salaries and benefits 10,812 15,466 Deferred taxes 35,612 28,659 Risk management liabilities (Note 19) 40,045 332,793 Other current liabilities 10,864 3,387 ---------- ---------- 283,084 534,372 ---------- ---------- Commitments & Contingencies (Note 17) Deferred Credits and Other Liabilities: Deferred federal income taxes 248,766 258,733 Deferred investment tax credit 26,590 28,414 Regulatory tax liability 25,418 28,098 Customer advances for construction 49,598 46,725 Accrued retirement benefits 44,856 43,028 Risk management liabilities (Note 19) 3,917 77,324 Contract termination reserves (Note 17) 86,778 -- Other 25,400 24,311 ---------- ---------- 511,323 506,633 ---------- ---------- $2,398,490 $2,706,976 ========== ==========
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS. 134 SIERRA PACIFIC POWER COMPANY CONSOLIDATED STATEMENTS OF OPERATIONS (Dollars in Thousands)
YEAR ENDED DECEMBER 31, 2002 2001 2000 ------------ ------------ ------------ OPERATING REVENUES: Electric $ 931,251 $ 1,401,778 $ 894,919 Gas 149,783 145,652 100,803 ------------ ------------ ------------ 1,081,034 1,547,430 995,722 ------------ ------------ ------------ OPERATING EXPENSES: Operation: Purchased power 545,040 1,025,741 444,979 Fuel for power generation 144,143 286,719 233,748 Gas purchased for resale 91,961 136,534 83,199 Deferred energy costs disallowed 56,958 -- -- Deferral of energy costs - electric - net (54,632) (198,826) -- Deferral of energy costs - gas - net 24,785 (23,170) (16,164) Other 106,122 118,526 97,021 Maintenance 23,240 24,363 18,420 Depreciation and amortization 76,373 72,103 71,630 Taxes: Income taxes (6,922) 8,507 (672) Other than income 18,674 17,965 18,152 ------------ ------------ ------------ 1,025,742 1,468,462 950,313 ------------ ------------ ------------ OPERATING INCOME 55,292 78,968 45,409 ------------ ------------ ------------ OTHER INCOME (EXPENSE): Allowance for other funds used during construction 117 856 357 Interest accrued on deferred energy 10,644 12,461 205 Other income 4,266 2,113 3,405 Other expense (6,577) (6,176) (5,003) Income taxes (2,431) 91 690 ------------ ------------ ------------ 6,019 9,345 (346) ------------ ------------ ------------ Total Income Before Interest Charges 61,311 88,313 45,063 ------------ ------------ ------------ INTEREST CHARGES: Long-term debt 66,474 55,199 36,865 Other 10,663 7,433 11,312 Allowance for borrowed funds used during construction and capitalized interest (1,858) (660) (2,779) ------------ ------------ ------------ 75,279 61,972 45,398 ------------ ------------ ------------ Dividend requirements of obligated mandatorily redeemable preferred trust securities -- 3,598 3,742 INCOME (LOSS) FROM CONTINUING OPERATIONS (13,968) 22,743 (4,077) ------------ ------------ ------------ DISCONTINUED OPERATIONS: Income from operations of water business disposed of (net of income taxes of $888 and $3,426 in 2001 and 2000, respectively) -- 1,022 9,634 Gain on disposal of water business (net of income taxes of $18,237) -- 25,845 -- ------------ ------------ ------------ NET INCOME (LOSS) (13,968) 49,610 5,557 ------------ ------------ ------------ Preferred Dividend Requirements 3,900 3,700 3,499 ------------ ------------ ------------ Earnings (loss) applicable to common stock $ (17,868) $ 45,910 $ 2,058 ============ ============ ============
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS. 135 SIERRA PACIFIC POWER COMPANY CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (DOLLARS IN THOUSANDS)
YEAR ENDED DECEMBER 31, ------------------------------------- 2002 2001 2000 ---------- ---------- ---------- NET INCOME (LOSS) $ (13,968) $ 49,610 $ 5,557 OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX: Cumulative effect upon adoption of change in accounting principle as of January 1 (net of taxes of $114) -- 211 -- Change in market value of risk management assets and liabilities as of December 31 (net of taxes of $102 and $19 in 2002 and 2001, respectively) (189) 36 -- Minimum pension liability adjustment (net of taxes of $350) (649) ---------- ---------- ---------- OTHER COMPREHENSIVE INCOME (LOSS) (838) 247 -- ---------- ---------- ---------- COMPREHENSIVE INCOME (LOSS) $ (14,806) $ 49,857 $ 5,557 ========== ========== ==========
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS 136 SIERRA PACIFIC POWER COMPANY CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER'S EQUITY (DOLLARS IN THOUSANDS)
Year ended December 31, 2002 2001 2000 ---------- ---------- ---------- COMMON STOCK Balance at Beginning of Year and End of Year $ 4 $ 4 $ 4 OTHER PAID-IN CAPITAL: Balance at Beginning of Year 703,633 598,684 584,684 Additional investment by parent company 10,000 104,949 14,000 ---------- ---------- ---------- Balance at End of Year 713,633 703,633 598,684 ---------- ---------- ---------- RETAINED EARNINGS (ACCUMULATED DEFICIT): Balance at Beginning of Year (10,983) 6,107 89,049 Income (Loss) from continuing operations before preferred dividends (13,968) 22,743 (4,077) Income from discontinued operations (before preferred dividend allocation of $200 and $401 in 2001 and 2000 respectively) -- 1,222 10,035 Gain on disposal of water business -- 25,845 -- Preferred stock dividends declared (3,900) (3,900) (3,900) Common stock dividends declared (44,900) (63,000) (85,000) ---------- ---------- ---------- Balance at End of Year (73,751) (10,983) 6,107 ---------- ---------- ---------- ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS): Balance at Beginning of Year 247 -- -- Adoption of SFAS No. 133 - Accounting for Derivative Instruments and Hedging Activities Cumulative effect upon adoption of change in accounting principle as of January 1 (net of taxes of $114) -- 211 -- Change in market value of risk management assets and liabilities as of December 31 (net of taxes of $102 and $19 in 2002 and 2001, respectively) (189) 36 -- Minimum pension liability adjustment (net of taxes of $350) (649) -- -- ---------- ---------- ---------- Balance at End of Year (591) 247 -- ---------- ---------- ---------- TOTAL COMMON SHAREHOLDER'S EQUITY AT END OF YEAR $ 639,295 $ 692,901 $ 604,795 ========== ========== ==========
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS. 137 SIERRA PACIFIC POWER COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (Dollars in Thousands)
YEAR ENDED DECEMBER 31, 2002 2001 2000 ---------- ---------- ---------- CASH FLOWS FROM OPERATING ACTIVITIES: Net income (loss) $ (13,968) $ 49,610 $ 5,557 Preferred dividends included in discontinued operations -- 200 401 Non-cash items included in income: Depreciation and amortization 76,373 75,584 78,451 Deferred taxes and deferred investment tax credit (5,107) 57,382 7,935 AFUDC and capitalized interest (1,975) (1,526) (3,547) Amortization of deferred energy costs - electric 30,164 -- -- Amortization of deferred energy costs - gas 13,231 3,562 -- Deferred energy costs disallowed (net of taxes) 38,303 -- -- Early retirement and severance amortization 2,706 3,121 4,196 Gain on disposal of water business -- (44,081) -- Other non-cash (5,291) (300) 11,449 Changes in certain assets and liabilities: Accounts receivable (18,803) (36,835) (41,604) Deferral of energy costs - electric (75,502) (207,775) -- Deferral of energy costs - gas 10,270 (30,245) (16,370) Materials, supplies and fuel 880 (12,700) 514 Other current assets (16,625) 1,836 (26,749) Accounts payable (24,308) (70,579) 87,643 Income tax receivable 62,109 -- -- Other current liabilities 6,551 2,380 1,231 Other assets (856) -- 8,467 Other liabilities 85,843 (1,333) (3,214) ---------- ---------- ---------- Net Cash from Operating Activities 163,995 (211,699) 114,360 ---------- ---------- ---------- CASH FLOWS FROM INVESTING ACTIVITIES: Additions to utility plant (105,327) (132,754) (155,625) AFUDC and other charges to utility plant 1,975 1,526 3,605 Customer advances (refunds) for construction 2,872 4,949 2,864 Contributions in aid of construction 7,447 21,150 16,446 ---------- ---------- ---------- Net cash used for utility plant (93,033) (105,129) (132,710) Proceeds from sale of assets of water business -- 318,882 -- Disposal of subsidiaries and other property - net 993 17 298 ---------- ---------- ---------- Net Cash from Investing Activities (92,040) 213,770 (132,412) ---------- ---------- ---------- CASH FLOWS FROM FINANCING ACTIVITIES: Decrease in short-term borrowings (46,500) (62,462) (5,915) Proceeds from issuance of long-term debt 100,000 400,000 200,000 Retirement of long-term debt (9,512) (299,732) (102,797) Redemption of preferred stock -- (48,500) -- Investment by parent company 10,000 104,948 14,000 Dividends paid (48,805) (89,901) (84,899) ---------- ---------- ---------- Net Cash from Financing Activities 5,183 4,353 20,389 ---------- ---------- ---------- NET INCREASE IN CASH AND CASH EQUIVALENTS 77,138 6,424 2,337 Beginning Balance in Cash and Cash Equivalents 11,772 5,348 3,011 ---------- ---------- ---------- Ending Balance in Cash and Cash Equivalents $ 88,910 $ 11,772 $ 5,348 ========== ========== ========== SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION: Cash paid (received) during period for: Interest $ 73,409 $ 66,597 $ 57,331 Income taxes $ (62,109) $ (25,632) $ 9,644
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS 138 SIERRA PACIFIC POWER COMPANY CONSOLIDATED STATEMENTS OF CAPITALIZATION (DOLLARS IN THOUSANDS)
DECEMBER 31, 2002 2001 ------------ ------------ COMMON SHAREHOLDER'S EQUITY: Common stock, $3.75 par value, 1,000 shares authorized, issued and outstanding $ 4 $ 4 Other paid-in capital 713,633 703,633 Retained deficit (73,751) (10,983) Accumulated Other Comprehensive Income (591) 247 ------------ ------------ Total Common Shareholder's Equity 639,295 692,901 ------------ ------------ CUMULATIVE PREFERRED STOCK: Not subject to mandatory redemption $25 stated value Class A Series 1; $1.95 dividend 50,000 50,000 ------------ ------------ LONG TERM DEBT: Unamortized bond premium and discount, net (4,062) (961) Debt Secured by First Mortgage Bonds 2.00% Series Z due 2004 -- 56 2.00% Series O due 2011 -- 1,281 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 6.70% Series II due 2032 21,200 21,200 5.50% Series D MTN due 2003 5,000 5,000 5.59% Series D MTN due 2003 13,000 13,000 ------------ ------------ Subtotal 501,188 508,698 ------------ ------------ Debt Secured by General and Refunding Bonds 8.00% Series A due 2008 320,000 320,000 10.50% (Variable) Series C due 2005 100,000 -- ------------ ------------ 420,000 320,000 ------------ ------------ Other Notes: 5.75% Series 2001 due 2036 80,000 80,000 ------------ ------------ Other 15,000 17,002 ------------ ------------ Current Maturities and sinking fund requirements (101,400) (2,630) ------------ ------------ Total Long-Term Debt 914,788 923,070 ------------ ------------ TOTAL CAPITALIZATION $ 1,604,083 $ 1,665,971 ============ ============
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS. 139 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), Sierra Pacific Energy Company (SPE), Sierra Water Development Company (SWDC) and, Sierra Gas Holding Company (SGHC). NPC and SPPC are referred to together in this report as the Utilities. All significant intercompany balances and intercompany transactions have been eliminated in consolidation. NPC is an operating public utility that provides electric service in Clark County in southern Nevada. The assets of NPC represent approximately 59% of the consolidated assets of SPR at December 31, 2002. NPC provides electricity to approximately 669,000 customers in the communities of Las Vegas, North Las Vegas, Henderson, Searchlight, Laughlin and adjoining areas, including Nellis Air Force Base. Service is also provided to the Department of Energy's Nevada Test Site in Nye County. The consolidated financial statements of SPR include the accounts of NPC's wholly owned subsidiaries, Nevada Electric Investment Company (NEICO), 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 approximately 35% of the consolidated assets of SPR at December 31, 2002. SPPC provides electricity to approximately 318,000 customers in a 50,000 square mile service area including western, central, and northeastern Nevada, including the cities of Reno, Sparks, Carson City, and 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. Certain reclassifications of prior year information have been made for comparative purposes but have not affected previously reported net income or common shareholders' equity. The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities. These estimates and assumptions also affect the disclosure 140 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. MANAGEMENT'S STATEMENT SIERRA PACIFIC RESOURCES SPR, on a stand-alone basis, had cash and cash equivalents of approximately $7.4 million at December 31, 2002, and approximately $179.3 million at February 28, 2003. Currently, SPR has a substantial amount of debt and other obligations including, but not limited to: $133 million of its unsecured Floating Rate Notes due April 20, 2003; $300 million of its unsecured 8 3/4% Senior Notes due 2005; and $240 million of its unsecured 7.93% Senior Notes due 2007; and $300 million of its 7.25% Convertible Notes due 2010. SPR intends to pay off the remaining principal balance of its Floating Rate Notes due April 20, 2003 with cash currently on hand. SPR's future liquidity and its ability to pay the principal of and interest on its indebtedness depend on SPPC's ability to continue to pay dividends to SPR, on NPC's financial stability and a restoration of its ability to pay dividends to SPR, and on SPR's ability to access the capital markets or otherwise refinance maturing debt. On October 29, 2002, SPPC paid a common stock dividend of $25 million to its parent, SPR. Further adverse developments at NPC or SPPC, including a material disallowance of deferred energy costs in current and future rate cases or an adverse decision in the pending lawsuit by Enron, could make it difficult to continue to operate outside of bankruptcy. See Note 13, Dividend Restrictions for information regarding the dividend restrictions applicable to NPC and SPPC and Note 17, Commitments and Contingencies for additional information regarding uncertainties that could impact the SPR's liquidity and financial condition. The provisions that currently restrict dividends payable by NPC or SPPC have adversely affected SPR's liquidity and will continue to negatively impact SPR's liquidity until those provisions are no longer in effect. Management intends to seek a modification of the financial covenant contained in NPC's first mortgage indenture in the near future. The regulatory limitation contained in the PUCN's Compliance Order, Docket No. 02-4037, dated June 19, 2002, expires on December 31, 2003. Prior to the expiration date of the Compliance Order, management may seek PUCN approval for a payment of dividends by NPC or may seek a waiver from the PUCN of the dividend restriction. Financing Transactions. On February 14, 2003, SPR issued and sold $300 million of its 7.25% Convertible Notes due 2010. Approximately $53.4 million of the net proceeds from the sale of the notes were used to purchase U.S. government securities that were pledged to the trustee for the first five interest payments on the notes payable during the first two and one-half years. A portion of the remaining net proceeds of the notes have been used to repurchase approximately $58.5 million of SPR's Floating Rate Notes due April 20, 2003. Of the remaining net proceeds, approximately $133 million will be used to repay the remainder of SPR's Floating Rate Notes due April 20, 2003 at maturity, and the remaining approximately $65 million will be available for general corporate purposes, including the payment of interest on SPR's other outstanding indebtedness. The Convertible Notes will not be convertible prior to August 14, 2003. At any time on or after August 14, 2003 through the close of business February 14, 2010, holders of the Convertible Notes may convert each $1,000 principal amount of their notes into 219.1637 shares of SPR's common stock, subject to adjustment upon the occurrence of certain dilution events. Until SPR has obtained shareholder approval to fully convert the Convertible Notes into shares of common stock, holders of the Convertible Notes will be entitled to receive 76.7073 shares of common stock and a remaining portion in cash based on the average closing price of SPR's 141 common stock over five consecutive trading days for each $1,000 principal amount of notes surrendered for conversion. At an assumed five-day average closing price of $3.20 (the last reported sale price of SPR's common stock on March 17, 2003), the total amount of the cash payable on conversion of the Convertible Notes would be approximately $137 million. If SPR does not obtain shareholder approval, SPR will be required to pay the cash portion of any Convertible Notes as to which the holders request conversion on or after August 14, 2003. Although management does not believe it is likely that a significant amount of the Convertible Notes will be converted in the foreseeable future, in the event that SPR does not have available funds to pay the cash portion of the Convertible Notes upon the requested conversion, SPR may have to issue additional debt to raise the necessary funds. There can be no assurance that SPR will be able to access the capital markets to issue such additional debt. If SPR does obtain shareholder approval, it may elect to satisfy the cash payment component of the conversion price of the Convertible Notes solely with shares of common stock. SPR has agreed to use reasonable efforts to obtain shareholder approval, not later than 180 days after the date of issuance of the Convertible Notes, for approval to issue and deliver shares of SPR's common stock in lieu of the cash payment component of the conversion price of the Convertible Notes. For further information regarding the terms of the Convertible Notes, see Note 9, Long-Term Debt. Effect of Holding Company Structure. Due to the holding company structure, SPR's right as a common shareholder to receive assets of any of its direct or indirect subsidiaries upon a subsidiary's liquidation or reorganization is junior to the claims against the assets of such subsidiary by its creditors. Therefore, SPR's debt obligations are effectively subordinated to all existing and future claims of its subsidiaries' creditors, particularly those of NPC and SPPC, including trade creditors, debt holders, secured creditors, taxing authorities, guarantee holders and NPC's and SPPC's preferred security holders. As of December 31, 2002, NPC, SPPC and their subsidiaries had approximately $2.86 billion of debt and other obligations outstanding and approximately $238.9 million of outstanding preferred securities. Although the Utilities are parties to agreements that limit the amount of additional indebtedness they may incur, the Utilities retain the ability to incur substantial additional indebtedness and other liabilities. The accompanying financial statements do not include any adjustments that might result from the outcome of the uncertainties discussed above. NEVADA POWER COMPANY NPC had cash and cash equivalents of approximately $95 million at December 31, 2002, and approximately $96 million at February 28, 2003. In addition to anticipated capital requirements for construction, NPC has approximately $355 million of debt maturing in 2003. NPC expects to finance these requirements with internally generated funds, including the recovery of deferred energy, and the issuance of debt. NPC's liquidity would be significantly affected by an adverse decision in the lawsuit by Enron, or by unfavorable rulings by the PUCN in pending or future NPC or SPPC rate cases. S&P and Moody's have NPC's credit ratings on "negative" and "stable", respectively. Future downgrades by either S&P or Moody's could preclude NPC's access to the capital markets. Furthermore, if NPC continues to experience financial difficulty or if its credit ratings are further downgraded, NPC may experience considerable difficulty entering into new power supply contracts, particularly under traditional payment terms. If suppliers will not sell power to NPC under traditional payment terms, NPC may have to pre-pay its power requirements. If it does not have sufficient funds or access to liquidity to pre-pay its power requirements, particularly at the onset of the summer months, and is unable to obtain power through other means, NPC's business, operations and financial condition 142 will be adversely affected. Adverse developments with respect to any one or a combination of the foregoing could make it difficult to continue to operate outside of bankruptcy. 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, 2002, $870 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 (1) 70% of net utility property additions, (2) the principal amount of retired General and Refunding Mortgage Bonds, and/or (3) 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. As of December 31, 2002, NPC had the capacity to issue approximately $1.04 billion of additional General and Refunding Mortgage securities. However, the financial covenants contained in NPC's Series E Notes limit NPC's ability to issue additional General and Refunding Mortgage Bonds or other debt. See Note 9, Long-Term Debt for information regarding NPC's Series E Notes. NPC has reserved $125 million of General and Refunding Mortgage bonds for issuance upon the initial funding of NPC's receivables facility. See Note 12, Short-Term Borrowings for information regarding NPC's accounts receivable facility. NPC intends to use its accounts receivable purchase facility as a back-up liquidity facility and does not plan to activate this facility in the foreseeable future. NPC may activate the facility within five days upon the delivery of certain customary funding documentation and the delivery of the $125 million General and Refunding Mortgage Bond. The accompanying financial statements do not include any adjustments that might result from the outcome of the uncertainties discussed above. SIERRA PACIFIC POWER COMPANY SPPC had cash and cash equivalents of approximately $88.9 million at December 31, 2002, and approximately $104.2 million at February 28, 2003. In addition to anticipated capital requirements for construction, SPPC has approximately $101 million of debt maturing in 2003. SPPC expects to finance these requirements with internally generated funds, including the recovery of deferred energy, and the issuance of debt. SPPC's future liquidity could be significantly affected by unfavorable rulings by the PUCN in pending or future SPPC or NPC rate cases. S&P and Moody's have SPPC's credit ratings on "negative outlook" and "stable", respectively. Future downgrades by either S&P or Moody's could preclude SPPC's access to the capital markets. Furthermore, if SPPC continues to experience financial difficulty or if its credit ratings are further downgraded, SPPC may experience considerable difficulty entering into new power supply contracts, particularly under traditional payment terms. If suppliers will not sell power to SPPC under traditional payment terms, SPPC may have to pre-pay its power requirements. If it does not have sufficient funds or access to liquidity to pre-pay its power requirements, and is unable to obtain power through other means, SPPC's business, operations and financial condition will be adversely affected. Adverse developments with respect to 143 any one or a combination of the factors and contingencies set forth above could make it difficult to continue to operate outside of bankruptcy. 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, 2002, $420 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% 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, 2002, SPPC had the capacity to issue approximately $427 million of additional General and Refunding Mortgage securities. However, the financial covenants contained in SPPC's Term Loan Agreement and Receivable Purchase Facility Agreements limit SPPC's ability to issue additional General and Refunding Mortgage Securities or other debt. SPPC has reserved $75 million of General and Refunding Mortgage Bonds for issuance upon the initial funding of its receivables purchase facility. See Note 9, Long-Term Debt for information regarding SPPC's Term Loan Agreement and Note 12, Short-Term Borrowings for information regarding SPPC's accounts receivable facility. SPPC intends to use its accounts receivable purchase facility as a back-up liquidity facility and does not plan to activate this facility in the foreseeable future. SPPC may activate the facility within five days upon the delivery of certain customary funding documentation and the delivery of the $75 million General and Refunding Mortgage Bond. The accompanying financial statements do not include any adjustments that might result from the outcome of the uncertainties discussed above. REGULATORY ACCOUNTING AND OTHER REGULATORY ASSETS The Utilities' rates are currently subject to the approval of the PUCN and, in the case of SPPC, rates are also subject to the approval of the California Public Utility Commission (CPUC) 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. In addition to the deferral of energy costs discussed below, significant items to which SPR and the Utilities apply regulatory accounting include goodwill and other merger costs resulting from the 1999 merger of SPR and NPC, generation divestiture costs, and the loss on reacquired debt. 144 Regulatory assets represent incurred costs that have been deferred because it is probable they will be recovered through future rates collected from customers. Regulatory liabilities generally represent obligations to make refunds to customers for previous collections for costs that are not likely to be incurred. Management regularly assesses whether the regulatory assets are probable of future recovery by considering factors such as applicable regulatory environment changes and the status of any pending or potential deregulation legislation. 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 the 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 No. 71 are satisfied. The provisions of Assembly Bill 369 (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. 145 The following Other regulatory assets were included in the consolidated balance sheets of SPR as of December 31 (dollars in thousands):
Receiving Regulatory Treatment Remaining ------------------------------ Waiting for Amortization Earning a Not Earning Regulatory 2002 2001 DESCRIPTION Period Return a Return Treatment Total Total -------------------- --------- ----------- ----------- --------- --------- Early retirement and severance offers Various thru 2004 $ -- $ 4,995 $ -- $ 4,995 $ 7,701 Loss on reacquired debt Term of Related Debt 31,812 -- -- 31,812 32,882 Plant assets Various thru 2031 3,558 -- -- 3,558 3,783 Nevada divestiture costs -- -- 32,313 32,313 -- Merger transition costs (a) -- -- 12,601 12,601 10,543 Merger severance/relocation (a) -- -- 21,747 21,747 21,851 Merger goodwill (a) -- -- 19,675 19,675 19,675 California restructure costs -- -- 4,318 4,318 3,631 Conservation programs -- -- 3,374 3,374 1,798 Variable rate mechanism deferral -- -- 721 721 454 Other costs -- -- 1,819 1,819 (5,593) --------- ----------- ----------- --------- --------- Total regulatory assets $ 35,370 $ 4,995 $ 96,568 $ 136,933 $ 96,725 ========= =========== =========== ========= =========
(a) See Note 2, Sierra Pacific Resources and Nevada Power Merger, for additional information about the accounting treatment and regulatory recovery of merger costs. Merger goodwill above represents the portion of total goodwill that has been reclassified to a regulatory asset. 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. On April 18, 2001, the Governor of Nevada signed into law AB 369. The provisions of AB 369, which are described in greater detail in Note 3, Regulatory Actions, 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 implemented 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 statement of operations 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 requires the Utilities to file applications to clear their respective deferred energy account balances at least every 12 months and 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 under the statute to recover a carrying charge on such deferred balances. NPC utilized deferred energy accounting procedures until August 1, 2000, and resumed those procedures on March 1, 2001. SPPC resumed deferred energy accounting procedures for its natural gas operations as of January 1, 2000, and for its electric operations on March 1, 2001. 146 The following deferred energy costs were included in the consolidated balance sheets as of the dates shown (dollars in thousands):
December 31, 2002 ---------------------------------------------------- NPC SPPC SPPC SPR Description Electric Electric Gas Total ----------- ---------- ---------- ---------- ---------- Unamortized balances approved for collection in current rates $ 331,159 $ 120,183 $ 18,957 $ 470,299 Balances pending PUCN approval 195,670 15,380 -- 211,050 Balances accrued since end of periods submitted for PUCN approval (1) (17,750) (148) (1,912) (19,810) Terminated suppliers (2) 228,459 81,901 -- 310,360 ---------- ---------- ---------- ---------- Total $ 737,538 $ 217,316 $ 17,045 $ 971,899 ========== ========== ========== ========== Current Assets Deferred energy costs - electric $ 213,193 $ 55,786 $ -- $ 268,979 Deferred energy costs - gas -- -- 17,045 17,045 Deferred Assets -- Deferred energy costs - electric 524,345 161,530 -- 685,875 ---------- ---------- ---------- ---------- Total $ 737,538 $ 217,316 $ 17,045 $ 971,899 ========== ========== ========== ==========
December 31, 2001 ------------------------------------------------- NPC SPPC SPPC SPR Description Electric Electric Gas Total ----------- ---------- ---------- ---------- ---------- Unamortized balances approved for collection in current rates $ -- $ -- $ 37,956 $ 37,956 Balances pending PUCN approval 921,917 205,418 -- 1,127,335 Balances accrued since end of periods submitted for PUCN approval 58,148 2,357 5,097 65,602 ---------- ---------- ---------- ---------- Total $ 980,065 $ 207,775 $ 43,053 $1,230,893 ========== ========== ========== ========== Current Assets Deferred energy costs - electric $ 281,555 $ 51,507 $ -- $ 333,062 Deferred energy costs - gas -- -- 19,805 19,805 Deferred Assets -- Deferred energy costs - electric 698,510 156,268 -- 854,778 Deferred energy costs - gas -- -- 23,248 23,248 ---------- ---------- ---------- ---------- Total $ 980,065 $ 207,775 $ 43,053 $1,230,893 ========== ========== ========== ==========
(1) Credits represent over-collections, that is, the extent to which gas or fuel and purchased power costs recovered through rates exceed actual gas or fuel and purchased power costs. (2) Amounts related to terminated suppliers are discussed in Note 17, Commitments and Contingencies. 147 UTILITY PLANT The cost of additions, including betterments and replacements of units of property, is charged to utility plant. When units of property are replaced, renewed or retired, their cost plus removal or disposal costs, less salvage, is charged to accumulated depreciation. The cost of current repairs and minor replacements is charged to operating expenses when incurred. In addition to direct labor and material costs, certain direct and indirect costs are capitalized, including the cost of debt and equity capital associated with construction and retirement activity. The indirect construction overhead costs capitalized are based upon the following cost components: the cost of time spent by administrative employees in planning and directing construction; property taxes; employee benefits including such costs as pensions, postretirement and post employment benefits, vacations and payroll taxes; and an allowance for funds used during construction (AFUDC). 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 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 are intended to 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 2002, 2001 and 2000 were 4.72%, 8.32%, and 8.34%, respectively. SPPC's AFUDC rates used during 2002, 2001 and 2000 were 5.54%, 7.97%, and 7.17%, 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 Substantially all of the Utilities' plant is subject to the ratemaking jurisdiction of the PUCN or the FERC, and, in the case of SPPC, the CPUC, which also approves any changes the Utilities may make to depreciation rates utilized for this property. Depreciation is calculated using the straight-line composite method over the estimated remaining service lives of the related properties, which approximates the anticipated physical lives of these assets in most cases. NPC's depreciation provision for 2002, 2001 and 2000, as authorized by the PUCN and stated as a percentage of the original cost of depreciable property, was approximately 3.0%, 2.94%, and 2.76%. SPPC's depreciation provision for 2002, 2001 and 2000, as authorized by the PUCN and stated as a percentage of the original cost of depreciable property, was approximately 3.33%, 3.29%, and 3.25%, respectively. IMPAIRMENT OF LONG-LIVED ASSETS SPR and the Utilities evaluate their Utility Plant and definite-lived tangible assets for impairment whenever indicators of impairment exist. 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. 148 FEDERAL INCOME TAXES AND INVESTMENT TAX CREDITS SPR and its subsidiaries file a consolidated federal income tax return. Current income taxes are allocated based on SPR's and each subsidiary's respective taxable income or loss and investment tax credits as if each subsidiary filed a separate return. Deferred taxes are provided on temporary differences at the statutory income tax rate in effect as of the most recent balance sheet date. SPR accounts for income taxes in accordance with SFAS No. 109, "Accounting for Income Taxes." SFAS No. 109 requires recognition of deferred tax liabilities and assets for the future tax consequences of events that have been included in the consolidated financial statements or tax returns. Under this method, deferred tax liabilities and assets are determined based on the difference between the financial statement and tax bases of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. For regulatory purposes, the Utilities are authorized to provide for deferred taxes on the difference between straight-line and accelerated tax depreciation on post-1969 utility plant expansion property, deferred energy, and certain other differences between financial reporting and taxable income, including those added by the Tax Reform Act of 1986 (TRA). In 1981, the Utilities began providing for deferred taxes on the benefits of using the Accelerated Cost Recovery System for all post-1980 property. In 1987, the TRA required the Utilities to begin providing deferred taxes on the benefits derived from using the Modified Accelerated Cost Recovery System. Investment tax credits are no longer available to the Utilities. The deferred investment tax credits are being amortized over the estimated service lives of the related properties. REVENUES Operating revenues include 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. Revenues related to the sale of energy are recorded based on meter reads, which occur on a systematic basis throughout a month, rather than when the service is rendered or energy is delivered. At the end of each month, the energy delivered to the customers from the date of their last meter read to the end of the month is estimated and the corresponding unbilled revenues are calculated. These estimates of unbilled sales and revenues are based on the ratio of billable days versus unbilled days, amount of energy procured and generated during that month, historical customer class usage patterns and the Utilities' current tariffs. STOCK COMPENSATION PLANS In December 2002, the FASB released SFAS No. 148, "Accounting for Stock-Based Compensation-Transition and Disclosure," as an amendment to SFAS No. 123, "Accounting for Stock-Based Compensation." SPR has previously adopted the disclosure-only provisions of SFAS No. 123, and as of December 31, 2002 has adopted the updated disclosure requirements set forth in SFAS No. 148. At December 31, 2002, SPR had several stock-based compensation plans which are described more fully in Note 15 "Stock Compensation Plans." 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. 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 149 applicable to common stock would have been decreased to the pro forma amounts indicated below (dollars in thousands, except per share amounts):
2002 2001 2000 ------------ ------------ ------------ Stock Compensation Cost included in Net Income as Reported, net of related tax effects As Reported $ (1,567) $ 346 $ (152) ============ ============ ============ Earnings (Deficit) applicable to Common Stock As Reported $ (307,521) $ 56,733 $ (39,780) Less: Stock Compensation Cost, net of related tax effects Pro Forma 2,047 1,209 695 ------------ ------------ ------------ Earnings (Deficit) applicable to Common Stock Pro Forma $ (309,568) $ 55,524 $ (40,475) ============ ============ ============ Basic Earnings Per Share As Reported $ (3.01) $ 0.65 $ (0.51) Pro Forma $ (3.03) $ 0.63 $ (0.52) Diluted Earnings Per Share As Reported $ (3.01) $ 0.65 $ (0.51) Pro Forma $ (3.03) $ 0.63 $ (0.52)
RECENT PRONOUNCEMENTS See Note 20, Change in Accounting for Goodwill, for a discussion of SPR's implementation of SFAS No. 142. SFAS No. 143 provides accounting requirements for the recognition and measurement of liabilities associated with the retirement of tangible long-lived assets. Under the standard, these liabilities will be recognized at fair value as incurred and capitalized as part of the cost of the related tangible long-lived assets. Accretion of the liabilities due to the passage of time will be an operating expense. Retirement obligations associated with long-lived assets included within the scope of SFAS No. 143 are those for which a legal obligation exists under enacted laws, statutes written or oral contracts, including obligations arising under the doctrine of promissory estoppel. The Utilities adopted SFAS No. 143 on January 1, 2003. Prior to adopting SFAS 143, costs for removal of most utility assets were accrued as an additional component of depreciation expense. Under SFAS 143, only the costs to remove an asset with legally binding retirement obligations will be accrued over time through accretion of the asset retirement obligation and depreciation of the capitalized asset retirement cost. Management's methodology to assess its legal obligation included an inventory of assets by system and components, and a review of right of ways and easements, regulatory orders, leases and federal, state, and local environmental laws. Management assumed in determining its Asset Retirement Obligations that transmission, distribution and communications systems will be operated in perpetuity and would continue to be used or sold without land remediation; and, mass asset properties that are replaced or retired frequently would be considered normal maintenance. Management has identified a legal obligation to retire generation plant assets specified in land leases for NPC's jointly-owned Navajo generating station. The land on which the Navajo generating station resides is leased from the Navajo Nation. The provisions of the leases require the lessees to remove the facilities upon request of the Navajo Nation at the expiration of the leases. Management has determined that the present value of NPC's Navajo Asset Retirement Obligation will not have a material effect on the financial position or results of operations of SPR or NPC. SPPC has no significant asset retirement obligations. The Utilities have various transmission and distribution lines as well as substations that operate under various rights of way that contain end dates and restorative clauses. Management operates the transmission and distribution system as though they will be operated in perpetuity and will continue to be used or sold without 150 land remediation. As a result, the Utilities have not recorded any costs associated with the removal of the transmission and distribution systems. 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. In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections." Among other things, this statement rescinds SFAS No. 4, "Reporting Gains and Losses from Extinguishment of Debt" which required all gains and losses from extinguishment of debt to be aggregated and, if material, classified as an extraordinary item, net of related income tax effect. As a result, the criteria in Accounting Principles Board Opinion No. 30, "Reporting the Results of Operations - Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions," will now be used to classify those gains and losses. Adoption of this statement did not have an impact on the financial position or results of operations of SPR, NPC or SPPC. In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities." SFAS No. 146 addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies Emerging Issues Task Force Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)." SFAS No. 146 requires that a liability for a cost associated with an exit or disposal activity be recognized when the liability is incurred. A fundamental conclusion reached by the FASB in this statement is that an entity's commitment to a plan, by itself, does not create a present obligation to others that meets the definition of a liability. Adoption of this statement did not have an impact on the financial position or results of operations of SPR, NPC or SPPC. On January 22, 2003, the FASB directed its staff to prepare a draft of SFAS No. 149, "Accounting for Certain Financial Instruments with Characteristics of Liabilities and Equity." The final draft is expected to be issued in March 2003. The statement will establish standards for accounting for financial instruments with characteristics of liabilities, equity, or both. As such, the NPC obligated mandatorily redeemable preferred trust securities may be classified as a liability once SFAS No. 149 goes into effect. The proposed effective date of SFAS No. 149 is July 1, 2003. In November 2002, the FASB issued Interpretation 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees," which elaborates on the disclosures to be made in interim and annual financial statements of a guarantor about its obligations under certain guarantees that it has issued. It also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing a guarantee. Initial recognition and measurement provisions of the Interpretation are applicable on a prospective basis to guarantees issued or modified after December 31, 2002. The disclosure requirements are effective for financial statements of interim or annual periods ending after December 15, 2002. As of December 31, 2002, any guarantees of SPR and its subsidiaries were intercompany, whereby the parent issues the guarantees on behalf of its consolidated subsidiaries to a third party. NEVADA POWER COMPANY FINANCIAL STATEMENTS The accompanying NPC consolidated financial statements for the years ended December 31, 2001 and 2000, have been revised to more clearly present stand-alone financial statements that solely reflect the financial position and results of operations of the legal entity, NPC. 151 The SPR-NPC merger was treated as a reverse acquisition for accounting purposes, as described in Note 2. As a result, for accounting purposes only, NPC was treated as the acquirer and accordingly, as the parent of SPR. Therefore, post-merger 2001 and 2000 financial statements for NPC have been previously presented as if NPC had a deemed equity investment in SPR. In fact, however, the legal relationship between NPC and SPR is the reverse, with SPR being the legal parent and NPC its wholly owned subsidiary. Management understands that in light of this legal structure, it would be appropriate to present NPC financial statements as NPC-only, without showing any equity investment in SPR. In the reverse acquisition accounting, NPC appropriately recorded the assets and liabilities of SPR and subsidiaries at fair value, following the guidance in Accounting Principles Board Opinion No.16. The assets and liabilities of NPC, as the accounting acquirer, were appropriately not revalued in the combination. As noted above, the presentation of the consolidated financial statements of NPC for the years ended December 31, 2001 have been revised. The resulting presentation includes only the assets of NPC to which holders of NPC's securities may look for recovery of their investment and only the financial information used in determining NPC's ability to pay dividends, in calculating NPC's ratio of earnings to fixed charges and in determining compliance with NPC's various financing agreements. 152 Specifically, the effects of the revision were to eliminate the following items in the NPC financial statements (dollars in thousands):
December 31, 2001 ----------------- NPC Consolidated Balance Sheets: Investment in Sierra Pacific Resources $309,259 Equity in Sierra Pacific Resources $309,259 NPC Consolidated Statements of Capitalization: Equity in Sierra Pacific Resources $309,259
Year Ended Year Ended December 31, 2001 December 31, 2000 ----------------- ----------------- NPC Consolidated Income Statements: Equity in Losses of Sierra Pacific Resources $(6,672) $(31,852) NPC Consolidated Statements of Cash Flows: Equity in (Losses) Earnings of Sierra Pacific Resources $(6,672) $(31,852)
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. As a result of the acquisition, goodwill of $331.2 million was recognized which represented the total consideration paid to SPR common shareholders less the fair value of SPR's net assets. The order issued by the PUCN in Docket No. 98-7023 on December 31, 1998 approving the merger of SPR and NPC directed both SPPC and NPC to defer three categories of merger costs to be reviewed for recovery through future rates. That order instructed both utilities to defer merger transaction costs, transition costs and goodwill costs for a three-year period. The deferral of these costs was intended to allow adequate time for the anticipated savings from the merger to develop. At the end of the three-year period, the order instructs the Utilities to propose an amortization period for the merger costs and allows the Utilities to recover the costs to the extent they are offset by merger savings. Accordingly, goodwill amortization associated with the regulated Utilities has been reclassified to a regulatory asset. Also deferred as a result of the PUCN order is $62.2 million in other merger costs as of December 31, 2002. These deferred costs consist of $40.5 million of transaction and transition costs and $21.7 million of employee separation costs. Employee separation costs were comprised of $17.2 million of employee severance, relocation and related costs, and $4.5 million of pension and post-retirement benefits net of plan curtailment gains. 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 PUCN in its decisions on March 27, 2002 and May 28, 2002, for NPC and SPPC, respectively, decided not to make any determination on the recovery of merger costs until a general rate case is filed with a test year ending on or after December 31, 2002. However, the PUCN did instruct NPC and SPPC to continue to recognize these costs as deferred costs without carrying charges. 153 The extent to which goodwill and merger costs will be recovered in future revenues and the timing of those recoveries is expected to be determined in general rate cases that are required to be filed in 2003. To the extent that the Utilities are not permitted to recover any portion of goodwill in future rates, the amount not recoverable will be reviewed for impairment and accounted for under the provisions of SFAS No. 142. A significant disallowance of goodwill or merger costs by the PUCN could have a material adverse affect on the future financial condition, results of operations and cash flows of SPR, NPC, and SPPC and could make it difficult for one or more of SPR, NPC, or SPPC to continue to operate outside of bankruptcy. NOTE 3. REGULATORY ACTIONS The Utilities are subject to the jurisdiction of the PUCN and, in the case of SPPC, the CPUC with respect to rates, standards of service, siting of and necessity for, generation and certain transmission facilities, accounting, issuance of securities and other matters with respect to electric distribution and transmission operations. NPC and SPPC submit integrated resource plans to the PUCN for approval. Under federal law, the Utilities and Tuscarora Gas Pipeline Company (TGPC) 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. DEFERRED ENERGY ACCOUNTING On April 18, 2001, the Governor of Nevada signed into law AB 369. 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. NEVADA POWER COMPANY 2001 GENERAL RATE CASE On October 1, 2001, NPC filed an application with the PUCN, as required by law, seeking an electric general rate increase. 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, or an overall 1.7% rate increase. The application also sought a return on common equity (ROE) for NPC's total electric operations of 12.25% and an overall rate of return (ROR) of 9.30%. On March 27, 2002, the PUCN issued its decision on the general rate application, ordering a $43 million revenue decrease with an ROE of 10.1% and ROR of 8.37%. The effective date for the decision was April 1, 2002. The decision also resulted in adjustments increasing accumulated depreciation by $6.7 million, and the inclusion of approximately $5 million of revenues related to SO2 Allowances. The PUCN delayed 154 consideration of recovery of SPR/NPC merger costs until a future rate case. NPC was not granted a carrying charge on these deferred costs. NPC plans to renew its request to recover these costs in its next general rate case, which will be filed by the fourth quarter 2003. Recovery of costs related to the generation divestiture project, which supported Nevada's now-abandoned utility restructuring policy, were delayed until the plants are sold or some other mechanism is proposed to allow recovery of the costs. A carrying charge was allowed by the PUCN for the delayed recovery of divestiture costs. On April 15, 2002, NPC filed a petition for reconsideration with the PUCN. On May 24, 2002, the PUCN issued an order on the petition for reconsideration. The PUCN modified its original order reversing the adjustment to accumulated depreciation of $6.7 million, and decreased the SO2 allowance revenue amortization to $3.2 million per year. Revised rates for these changes went into effect on June 1, 2002. NEVADA POWER COMPANY 2001 DEFERRED ENERGY CASE 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, and September 30, 2001, as required by law. The application sought to establish a Deferred Energy Accounting Adjustment (DEAA) rate to clear accumulated purchased fuel and power costs of $922 million and spread the recovery of the deferred costs, together with a carrying charge, over a period of not more than three years. On March 29, 2002, the PUCN issued its decision on the deferred energy application, allowing NPC to recover $478 million over a three-year period, but disallowing $434 million of deferred purchased fuel and power costs and $30.9 million in carrying charges consisting of $10.1 million in carrying charges accrued through September 2001 and $20.8 million in carrying charges accrued from October 2001 through February 2002. The order stated that the disallowance was based on alleged imprudence in incurring the disallowed costs. On April 11, 2002, NPC filed a lawsuit in the First District Court of Nevada seeking to reverse portions of the PUCN's decision. NEVADA POWER COMPANY 2002 DEFERRED ENERGY CASE On November 14, 2002, NPC filed an application with the PUCN seeking to clear deferred balances for purchased fuel and power costs accumulated between October 1, 2001, and September 30, 2002, as required by law. The application seeks to establish a rate to repay accumulated purchased fuel and power costs of $195.7 million, together with a carrying charge, over a period of not more than three years. The application also requests a reduction to the going-forward rate for energy, reflecting reduced wholesale energy costs. The combined effect of these two adjustments results in an overall rate reduction of 5.3%. A hearing is scheduled to begin on April 7, 2003 and a ruling is required by May 15, 2003. SIERRA PACIFIC POWER COMPANY 2001 GENERAL RATE CASE On November 30, 2001, as required by law, SPPC filed an application with the PUCN seeking an electric general rate increase. 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 sought an ROE for SPPC's total electric operations of 12.25% and an overall ROR of 9.42%. On May 28, 2002, the PUCN issued its decision on the general rate application, ordering a $15.3 million revenue decrease with an ROE of 10.17% and ROR of 8.61%. The effective date of the decision was June 1, 2002. The PUCN delayed consideration of recovery of SPR/NPC merger costs until a future rate case, and SPPC was not granted a carrying charge on these deferred costs. SPPC is currently planning to renew its 155 request to recover these costs in a general rate case to be filed by the fourth quarter of 2003. Recovery of costs related to the generation divestiture project, which supported Nevada's now-abandoned utility restructuring policy, were delayed until the plants are sold or some other mechanism is proposed to allow recovery of the costs. A carrying charge was allowed by the PUCN for the delayed recovery of divestiture costs. SIERRA PACIFIC POWER COMPANY 2002 DEFERRED ENERGY CASE On February 1, 2002, SPPC filed an application with the PUCN, as required by law, seeking to clear deferred balances for purchased fuel and power costs accumulated between March 1, 2001 and November 30, 2001. The application sought to establish a DEAA rate to clear accumulated purchased fuel and power costs of $205 million and spread the cost recovery over a period of not more than three years. It also sought to recalculate the Base Tariff Energy Rate to reflect anticipated ongoing purchased fuel and power costs. On May 28, 2002, the PUCN issued its decision on the deferred energy application, allowing SPPC three years to collect $150 million but disallowing $53 million of deferred purchased fuel and power costs and $2 million in carrying charges. On August 22, 2002, SPPC filed a lawsuit in the First District Court of Nevada seeking to reverse portions of the decision of the PUCN denying the recovery of deferred energy costs incurred by SPPC on behalf of its customers in 2001 on the grounds that such power costs were not prudently incurred. SPPC's lawsuit requests that the District Court reverse portions of the order of the PUCN and remand the matter to the PUCN with direction that the PUCN authorize SPPC to immediately establish rates that would allow SPPC to recover its entire deferred energy balance of $205 million, with a carrying charge, over three years. A hearing has been scheduled for October 2003. SIERRA PACIFIC POWER COMPANY 2003 DEFERRED ENERGY CASE On January 14, 2003, SPPC filed an application with the PUCN, as required by law, seeking to clear deferred balances for purchased fuel and power costs accumulated between December 1, 2001 and November 30, 2002. The application seeks to establish a DEAA rate to clear accumulated purchased fuel and power costs of $15.4 million and spread the cost recovery over a period of not more than three years. 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 requested DEAA would amount to 0.01%. A hearing is scheduled to begin on May 12, 2003, and a ruling is required before July 13, 2003. ANNUAL PURCHASED GAS COST ADJUSTMENT (SPPC) On July 1, 2002, SPPC filed a Purchased Gas Cost Adjustment application for its natural gas local distribution company. In the application, SPPC has asked for a reduction of $0.05421 to its Base Purchased Gas Rate and an increase in its Balancing Account Adjustment charge by the same amount. This request would result in no change to revenues or customer rates. This docket was consolidated for hearing purposes with the Liquid Petroleum Gas Cost Adjustment below. On December 23, 2002, the PUCN voted to decrease rates for SPPC's natural gas customers by approximately 3% ($3.2 million plus applicable carrying charges). The PUCN noted that the decrease was due primarily to lower gas costs for SPPC and to a disallowance for imprudent hedging practices. The PUCN adjusted SPPC's costs related to fixed floating hedging contracts. The PUCN also disallowed an alleged $0.7 million customer subsidy under an SPPC optional gas tariff. The new rates were implemented January 1, 2003. 156 SPPC has filed a petition for reconsideration of the decisions to disallow the $3.2 million hedging costs and the $0.7 million alleged customer subsidy. On February 6, 2003, the PUCN granted the petition for reconsideration and a decision is expected by the end of the first quarter 2003. 157 NOTE 4. EARNINGS PER SHARE The following table outlines the calculation for earnings per share (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.
2002 2001 2000 ------------ ------------ ------------ Basic EPS NUMERATOR ($000) Income (loss) from continuing operations $ (305,955) $ 29,866 $ (49,414) Income from discontinued operations -- 1,022 9,634 Gain on disposal of water business -- 25,845 -- Cumulative effect of change in accounting principle (1,566) -- -- ------------ ------------ ------------ Earnings (deficit) applicable to common stock $ (307,521) $ 56,733 $ (39,780) ============ ============ ============ DENOMINATOR Weighted average number of shares outstanding 102,126,079 87,542,441 78,435,405 ============ ============ ============ EARNINGS (DEFICIT) PER SHARE: From continuing operations $ (3.00) $ 0.34 $ (0.63) From discontinued operations -- 0.01 0.12 Gain on disposal of water business -- 0.30 -- Cumulative effect of change in accounting principle (0.01) -- -- ------------ ------------ ------------ Applicable to common stock $ (3.01) $ 0.65 $ (0.51) ============ ============ ============ DILUTED EPS NUMERATOR ($000) Income (loss) from continuing operations $ (305,955) $ 29,866 $ (49,414) Income from discontinued operations -- 1,022 9,634 Gain on disposal of water business -- 25,845 -- Cumulative effect of change in accounting principle (1,566) -- -- ------------ ------------ ------------ Earnings (deficit) applicable to common stock $ (307,521) $ 56,733 $ (39,780) ============ ============ ============ DENOMINATOR(1) Weighted average number of shares outstanding 102,126,079 87,542,441 78,435,405 before dilution Stock options 8,154 14,021 5,645 Executive long term incentive plan - performance shares 8,918 43,693 35,393 Non-Employee stock plan 13,861 9,355 5,885 Employee stock purchase plan 1,163 2,862 2,807 ------------ ------------ ------------ 102,158,175 87,612,372 78,485,135 ============ ============ ============ EARNINGS (DEFICIT) PER SHARE(2) From continuing operations $ (3.00) $ 0.34 $ (0.63) From discontinued operations -- 0.01 0.12 Gain on disposal of water business -- 0.30 -- Cumulative effect of change in accounting principle (0.01) -- -- ------------ ------------ ------------ Applicable to common stock $ (3.01) $ 0.65 $ (0.51) ============ ============ ============
(1) The denominator does not include anti-dilutive stock equivalents for the Stock Option Plan and Corporate PIES due to conversion prices being higher than market prices at December 31, 2002. (2) Because of net losses for the years ended December 31, 2000 and 2002, stock equivalents would be anti-dilutive. Accordingly, Diluted EPS for those periods are computed using weighted average number of shares outstanding before dilution. 158 NOTE 5. INVESTMENTS IN SUBSIDIARIES AND OTHER PROPERTY Investments in subsidiaries and other property consisted of (dollars in thousands): SIERRA PACIFIC RESOURCES
December 31, 2002 2001 ---------- ---------- Investment in Tuscarora Gas Transmission $ 26,912 $ 18,799 Company Non-utility property of SPC and Investment in Sierra Touch America 68,353 15,340 Cash Value-Life Insurance 12,560 12,580 Non-utility property of NEICO 6,555 6,445 Non-utility property of e-three 9,050 9,561 Other non-utility Property 10,638 10,848 ---------- ---------- $ 134,068 $ 73,573 ========== ==========
NEVADA POWER
December 31, 2002 2001 ---------- ---------- Cash Value-Life Insurance $ 12,560 $ 12,580 Non-utility property of NEICO 6,555 -- Non-utility Property 1,180 141 ---------- ---------- $ 20,295 $ 12,721 ========== ==========
SIERRA PACIFIC POWER
December 31, 2002 2001 ---------- ---------- Non-utility Property $ 874 $ 1,866 ========== ==========
NOTE 6. JOINTLY OWNED FACILITIES At December 31, 2002, SPR owned the following undivided interests in jointly owned electric utility facilities:
Construction % Owned by Accumulated Net Plant in Work in Generating Facility Subsidiary Plant in Service Depreciation Service Progress Subsidiary - ------------------- ---------- ---------------- ------------ ------------ ------------ ---------- Navajo Station 11.3 $ 228,133 $ 104,198 $ 123,935 $ 1,572 NPC Mohave Facility 14.0 84,914 39,230 45,684 3,038 NPC Reid Gardner No. 4 32.2 124,321 56,435 67,886 198 NPC Valmy Station 50.0 282,807 133,038 149,769 -- SPPC ---------------- ------------ ------------ ------------ TOTAL $ 720,175 $ 332,901 $ 387,274 $ 4,808 ================ ============ ============ ============
The 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 159 operating expenses for these facilities is included in the corresponding operating expenses in its Consolidated Statements of Operations. NPC's ownership interest in Mohave comprises approximately 10% of NPC's peak generation capacity. Southern California Edison (SCE) is the operating partner of Mohave. On May 17, 2002, SCE filed with the CPUC an application to address the future disposition of SCE's share of Mohave. Mohave obtains all of its coal supply from a mine in northeast Arizona on lands of the Navajo Nation and the Hopi Tribe (the Tribes). This coal is delivered from the mine to Mohave by means of a coal slurry pipeline which requires water that is obtained from groundwater wells located on lands of the Tribes in the mine vicinity. Due to the lack of progress in negotiations with the Tribes and other parties to resolve several coal and water supply issues, SCE's application states that it appears that it probably will not be possible for SCE to extend Mohave's operations beyond 2005. Due to the uncertainty over a post-2005 coal supply, SCE and the other Mohave co-owners have been prevented from commencing the installation of extensive pollution control equipment that must be put in place if Mohave's operations are extended past 2005. NPC is currently evaluating and analyzing all of its options with regard to the Mohave project. 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 its accompanying Consolidated Statements of Operations. NOTE 7. COMMON STOCK AND OTHER PAID-IN CAPITAL 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 issued an aggregate of $345 million senior unsecured notes in connection with the public offering of 6,900,000 of its Corporate Premium Income Equity Securities (PIES). 160 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 pledged as collateral. 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 of December 31, 2002, 3,441,166 shares of common stock were reserved for issuance under the Common Stock Investment Plan (CSIP), Employees' Stock Purchase Plan (ESPP), 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, which can be earned and issued after 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 (offering date) 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 (APB No.) 25. In addition, in 1996 the Company eliminated its outside director retirement plan and converted the present value of each director's vested retirement benefit to phantom stock based on the stock price at the time of conversion. Phantom stock earns dividends, also payable in phantom stock, which are recorded in each Director's phantom account. The value of these accounts is issued in stock or cash, at the election of the Board, at the time the Director leaves the Board. 161 The changes in common stock and additional paid-in capital for 2002, 2001 and 2000, are as follows (dollars in thousands):
Shares Issued Amount -------------------------------------------- -------------------------------------------- 2002 2001 2000 2002 2001 2000 ---------- ---------- ---------- ---------- ---------- ---------- Public Offering -- 23,575,000 -- $ -- $ 340,364 $ -- Merger Exchange -- -- -- -- -- -- CSIP/DRP -- -- 5,389 -- -- 237 ESPP and other 66,873 60,319 55,268 455 361 1,055 ---------- ---------- ---------- ---------- ---------- ---------- 66,873 23,635,319 60,657 $ 455 $ 340,725 $ 1,292 ========== ========== ========== ========== ========== ==========
SUBSEQUENT EVENTS In January 2003, SPR acquired $8.75 million aggregate principal amount of its Floating Rate Notes due April 20, 2003 in exchange for 1,295,211 shares of its common stock, in two privately negotiated transactions exempt from the registration requirements of the Securities Act of 1933. On February 5, 2003, SPR acquired 2,095,650 of its PIES including approximately $104.8 million of 7.93% Senior Notes due 2007 that are a component of the PIES, in exchange for 13,662,393 shares of its common stock, in five privately negotiated transactions exempt from the registration requirements of the Securities Act of 1933. Of the shares issued in these transactions, 7,565,506 shares represented the then current conversion value of the PIES. On February 14, 2003, SPR issued $300 million of its 7.25% Convertible Notes due 2010. Interest on the notes is payable semi-annually in arrears. SPR may redeem some or all of the notes for cash at any time on or after February 14, 2008. SPR used approximately $53.4 million of the proceeds to acquire U.S. Government securities that are pledged to the trustee as security for the notes for the first two and one-half years and which SPR expects to use to pay the first five interest payments on the notes. The proceeds will be used to redeem approximately $133 million of its floating rate notes due April 20, 2003 and for general corporate purposes. The Convertible Notes will not be convertible prior to August 14, 2003. At any time on or after August 14, 2003 through the close of business February 14, 2010, holders of the Convertible Notes may convert each $1,000 principal amount of their notes into 219.1637 shares of SPR's common stock, subject to adjustment upon the occurrence of certain dilution events. Until SPR has obtained shareholder approval to fully convert the Convertible Notes in shares of common stock, holders of the Convertible Notes will be entitled to receive 76.7073 shares of common stock and a remaining portion in cash based on the trading price of SPR's common stock for a certain period prior to conversion. If SPR does obtain shareholder approval, it may elect to satisfy the cash payment component of the conversion price of the Convertible Notes solely with shares of common stock. SPR has agreed to use reasonable efforts to obtain shareholder approval not later than 180 days after the date of issuance of the Convertible Notes for approval to issue and deliver shares of SPR's common stock in lieu of the cash payment component of the conversion price of the Convertible Notes. 162 NOTE 8. PREFERRED STOCK AND PREFERRED TRUST SECURITIES SIERRA PACIFIC POWER COMPANY PREFERRED STOCK SPPC's Restated Articles of Incorporation, as amended on August 19, 1992, authorize an aggregate amount of 11,780,500 shares of preferred stock at any given time. SPPC's preferred stock is superior to SPPC's common stock with respect to dividend payments (which are cumulative) and liquidation rights. On January 30, 2003, a dividend of $975,000 ($0.4875 per share) was declared on SPPC's preferred stock. The dividend is payable on March 1, 2003, to holders of record as of February 14, 2003. The following table indicates the dollar amount and number of shares of SPPC preferred stock outstanding at December 31 of each year:
Amount Shares Outstanding ------------------------- ------------------------- (Dollars in thousands) 2002 2001 2002 2001 --------- --------- --------- --------- 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 ========= ========= ========= =========
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% preferred trust securities (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. Interest payments made by NPC in respect of the QUIPS are sufficient to provide the trust with funds to pay the required cash distribution on the QUIPS and the common securities of the trust. 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. 163 In October 1998, NVP Capital III (Trust), a wholly-owned subsidiary of Nevada Power Company, issued 2,800,000, 7.75% Cumulative Trust Issued Preferred Securities (TIPS) at $25 per security. NPC owns the entire common securities, 86,598 shares issued by the Trust for $2.2 million. The TIPS 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 TIPS and the common securities and using the proceeds thereof to purchase from NPC its 7.75% 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 TIPS 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. Interest payments by NPC in respect of the Junior Subordinated Deferrable Interest Debentures are sufficient to provide the trust with funds to pay the required cash distributions on the TIPS and the common securities of the trust. The TIPS 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 TIPS 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 TIPS. 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. The following table indicates the principal amount and number of shares of NPC preferred trust securities outstanding at December 31 of each year:
Amount Shares Outstanding ----------------------- ----------------------- (Dollars in thousands) 2002 2001 2002 2001 -------- -------- -------- -------- 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 -------- -------- -------- -------- Total Preferred Trust Securities $188,872 $188,872 233,656 233,656 ======== ======== ======== ========
SIERRA PACIFIC RESOURCES SPR has issued neither preferred stock nor preferred trust securities. 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 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 164 Mortgage dated as of October 1, 1953. On January 29, 2002, NPC exchanged 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. On August 20, 2001, $100 million of NPC's floating rate notes matured and were paid in full. 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. On October 18, 2001, NPC issued $140 million of its General and Refunding Mortgage Notes, Floating Rate, Series B, due October 15, 2003. On May 13, 2000, NPC issued a General and Refunding Mortgage Bond, Series D, due April 15, 2004, in the principal amount of $130 million, for the benefit of the holders of NPC's 6.20% Senior Unsecured Notes, Series B, due April 15, 2004. The Senior Unsecured Notes Indenture required that in the event that NPC issued debt secured by liens on NPC's operating property, in excess of 15% of its Net Tangible Assets or Capitalization (as both terms are defined in the Senior Unsecured Notes Indenture), NPC would equally and ratably secure the Senior Unsecured Notes. NPC triggered this negative pledge covenant on April 23, 2002, when it borrowed certain amounts under its secured credit facility. On October 25, 2002 NPC redeemed its 7 5/8% Series L, First Mortgage Bonds in the aggregate principal amount of $15 million. On October 29, 2002, NPC issued and sold $250 million of its 10 7/8% General and Refunding Mortgage Notes, Series E, due 2009 for net proceeds of $235.6 million. The Series E Notes, which were issued with registration rights, were exchanged for registered notes in January 2003. The proceeds of the issuance were used to pay off NPC's $200 million credit facility and for general corporate purposes. The Series E Notes will mature October 15, 2009. As discussed in Note 13, Dividend Restrictions, NPC's Series E Notes limit the amount of dividends that NPC may pay to SPR. The terms of the Series E Notes also restrict NPC from incurring any additional indebtedness unless (i) at the time the debt is incurred, the ratio of consolidated cash flow to fixed charges for NPC's most recently ended four quarter period on a pro forma basis is at least 2 to 1, or (ii) the debt incurred is specifically permitted, which includes certain credit facility or letter of credit indebtedness, obligations incurred to finance property construction or improvement, indebtedness incurred to refinance existing indebtedness, certain intercompany indebtedness, hedging obligations, indebtedness incurred to support bid, performance or surety bonds, and certain letters of credit issued to support NPC's obligations with respect to energy suppliers. If NPC's Series E Notes are upgraded to investment grade by both Moody's and S&P, the dividend restrictions and the restrictions on indebtedness applicable to the Series E Notes will be suspended and will no longer be in effect so long as the Series E Notes remain investment grade. Among other things, the Series E Notes also contain restrictions on liens (other than permitted liens, which include liens to secure certain permitted debt) and certain sale and leaseback transactions. In the event of a change of control of NPC, the holders of Series E Notes are entitled to require that NPC repurchase the Series E Notes for a cash payment equal to 101% of the aggregate principal amount plus accrued and unpaid interest. 165 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. 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. These bonds will be subject to remarketing on May 1, 2003. In the event that these bonds cannot be successfully remarketed, SPPC will be required to purchase the outstanding bonds at a price of 100% of the principal amount, plus accrued interest. 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. On January 29, 2002, SPPC exchanged these bonds for identical bonds, registered under the Securities Act of 1933. 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. On May 23, 2002, SPPC satisfied its obligations with respect to its 2% First Mortgage Bonds due 2011, 5% Series Y First Mortgage Bonds due 2024, and 2% Series Z First Mortgage Bonds due 2004 by depositing $1.2 million, $3.1 million, and $45,000, respectively, with its First Mortgage Trustee. These First Mortgage Bonds were issued to secure loans made to SPPC by the United States under the Rural Electrification Act of 1936, as amended. On October 30, 2002 SPPC entered into a $100 million Term Loan Agreement with several lenders and Lehman Commercial Paper Inc., as Administrative Agent. The net proceeds of $97 million from the Term Loan Facility, along with available cash, were used to pay off SPPC's $150 million credit facility, which was secured by a $150 million Series B General and Refunding Mortgage Bond. As discussed in Note 13, Dividend Restrictions, SPPC's Term Loan Agreement limits the amount of dividends that SPPC may pay to SPR. SPPC's Term Loan Agreement also requires that SPPC maintain a ratio of consolidated total debt to consolidated total capitalization at all times during each of the following quarters in an amount not to exceed (i) .650 to 1.0 for the fiscal quarters ended December 31, 2002 through December 31, 2003, (ii) .625 to 1.0 for the fiscal quarters ended March 31, 2004 through December 31, 2004, and (iii) ..600 to 1.0 for the fiscal quarter ended March 31, 2005 and for each fiscal quarter thereafter. SPPC's Term Loan Agreement also requires that SPPC maintain a consolidated interest coverage ratio for any four consecutive fiscal quarters ending with the fiscal quarter set forth below of not less than (i) 1.75 to 1.00 for the fiscal quarters ended December 31, 2002 and March 31, 2003, (ii) 2.50 to 1.0 for the fiscal quarters ended June 30, 2003 through December 31, 2003, (iii) 2.75 to 1.0 for the fiscal quarters ended March 31, 2004 through September 30, 2004, and (iv) 3.00 to 1.0 for the fiscal quarter ended December 31, 2004 and for each fiscal 166 quarter thereafter. As of December 31, 2002, SPPC was in compliance with these financial covenants. The Term Loan Facility, which is secured by a $100 million Series C General and Refunding Mortgage Bond, will expire October 31, 2005. SIERRA PACIFIC RESOURCES 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 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. As of December 31, 2002, the purchase contract adjustment payment liability was $10.5 million. On April 20, 2002, $100 million of SPR's floating rate notes matured and were paid in full. In January 2003, SPR acquired $8,750,000 aggregate principal amount of its Floating Rate Notes due April 20, 2003 in exchange for 1,295,211 shares of its common stock, in two privately negotiated transactions exempt from the registration requirements of the Securities Act. On February 5, 2003, SPR acquired 2,095,650 of PIES including approximately $104.8 million of 7.93% Senior Notes due 2007 that are a component of the PIES, in exchange for 13,662,393 shares of its 167 common stock, in five privately negotiated transactions exempt from the registration requirements of the Securities Act. On February 14, 2003, SPR issued $300 million of its 7.25% Convertible Notes due 2010. Interest on the notes is payable semi-annually. SPR may redeem some or all of the notes at any time on or after February 14, 2008. SPR used approximately $53.4 million of the proceeds to acquire U.S. Government securities are pledged to the trustee as security for the notes for the first two and one-half years and which SPR expects to use to pay the first five interest payments on the notes. The proceeds will be used to redeem approximately $133 million of its floating rate notes due April 20, 2003 and for general corporate purposes. See Note 7, Common Stock and Other Paid-In Capital for additional information regarding the terms of the convertible notes. The indenture under which the Convertible Notes were issued does not contain any financial covenants or any restrictions on the payment of dividends, the repurchase of SPR's securities or the incurrence of indebtedness. The indenture does allow the holders of the Convertible Notes to require SPR to repurchase all or a portion of the holders' Convertible Notes upon a change of control. The indenture also provides for an event of default if SPR or any of its significant subsidiaries, including NPC and SPPC, fails to pay any indebtedness in excess of $10 million or has any indebtedness of $10 million or more accelerated and declared due and payable. SIERRA PACIFIC COMMUNICATIONS Sierra Touch America LLC (STA), a partnership between SPC and Touch America, formerly Montana Power Company, was formed to construct a fiber optic line between Salt Lake City, Utah and Sacramento, CA. On September 9, 2002, SPC entered into an agreement to purchase and lease certain telecommunications and fiber optic assets from Touch America, subject to successful completion of the construction, in exchange for SPC's partnership units in Sierra Touch America and the execution of a $35 million promissory note for a total purchase price of $48.5 million. The promissory note accrues interest at 8% per annum. The first of twelve monthly payments of $3.3 million will commence on July 31, 2003 and continue until June 30, 2004, at which time all outstanding amounts will be due and payable. The promissory note is secured by all of SPC's assets, and prepayments will shorten the length of the loan, but not reduce the installment payments. 168 As of December 31, 2002 NPC's, SPPC's and SPR's aggregate annual amount of maturities for long-term debt (including obligations related to capital leases) for the next five years is shown below (in thousands of dollars):
SPR Holding Co. SPR NPC SPPC and Other Subs. Consolidated ---------- ---------- --------------- ------------ 2003 $ 354,677 $ 101,400 $ 216,886 $ 672,963 2004 135,570 3,400 14,498 153,468 2005 6,091 100,400 300,000 406,491 2006 6,509 52,400 -- 58,909 2007 5,949 2,400 345,000 353,349 ---------- ---------- --------- ---------- 508,796 260,000 876,384 1,645,180 Thereafter 1,348,384 760,250 0 2,108,634 ---------- ---------- --------- ---------- 1,857,180 1,020,250 876,384 3,753,814 Unamortized (Disc.)/Prem. (13,906) (4,062) -- (17,968) ---------- ---------- --------- ---------- Total $1,843,274 $1,016,188 $ 876,384 $3,735,846 ========== ========== ========= ==========
The preceding table includes obligations related to the following capital lease obligations. 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. Also, NPC has a purchase power contract with Nevada Sun-Peak Limited Partnership. The contract contains a buyout provision for the facility at the end of the contract term in 2016. The facility is situated on NPC property. Future cash payments for these leases, combined, as of December 31, 2002, were as follows (dollars in thousands): 2003 $ 4,664 2004 5,557 2005 6,076 2006 6,494 2007 5,932 Thereafter 44,536
169 NOTE 10. TAXES SIERRA PACIFIC RESOURCES The following reflects the composition of taxes on income (in thousands of dollars):
2002 2001 2000 --------- --------- --------- As Reflected in Statement of Income Federal income taxes $(168,498) $ 1,934 $ (31,468) State income taxes -- (3,164) 446 --------- --------- --------- Federal Income Taxes on Operating Income (168,498) (1,230) (31,022) Other income - net 4,058 14,870 511 --------- --------- --------- Total $(164,440) $ 13,640 $ (30,511) ========= ========= =========
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):
2002 2001 2000 Income (Loss) from continuing operations $(302,055) $ 33,566 $ (45,915) Total income tax expense (benefit) (164,440) 13,640 (30,511) --------- --------- --------- (466,495) 47,206 (76,426) Statutory tax rate 35% 35% 35% --------- --------- --------- Expected income tax expense (benefit) (163,273) 16,522 (26,749) Depreciation related to difference in costs basis for tax purposes 3,081 2,944 2,962 Allowance for funds used during construction - equity 112 85 151 Tax benefit from the disposition of assets (48) (111) (175) ITC amortization (3,454) (3,454) (1,824) State taxes (net of federal benefit) -- (2,057) (1,170) Pension benefit plan 1,400 697 887 Other - net (2,258) (986) (4,593) --------- --------- --------- $(164,440) $ 13,640 $ (30,511) ========= ========= ========= Effective tax rate 35.3% 28.9% 39.9% ========= ========= =========
170 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):
2002 2001 ----------- ----------- Deferred Federal Income Tax Liabilities: Allowance for funds used during construction - debt $ 16,281 $ 12,496 Bond redemptions 11,132 11,508 Excess of tax depreciation over book depreciation 555,811 401,358 Severance programs 5,019 5,299 Tax benefits flowed through to customer 163,889 169,738 Deferred energy 339,640 430,812 Ad Valorem Taxes 3,336 172 Other 18,289 23,706 ----------- ----------- 1,113,397 1,055,089 ----------- ----------- Deferred Federal Income Tax Assets: Net operating loss carryforward 281,866 189,238 Avoided interest capitalized 32,319 23,661 Employee benefit plans 13,421 12,006 Reserve for bad debt 15,121 13,761 Contributions in aid of construction and customer advances 109,877 104,395 Gross-ups received on contribution in aid of construction and customer advances 16,665 11,976 Excess deferred income taxes 16,460 18,656 Unamortized investment tax credit 26,258 28,046 Other Accumulated Comprehensive Income - Additional minimum pension liability 24,905 -- Contract Termination Reserve 109,408 -- Other 7,446 (882) ----------- ----------- 653,746 400,857 ----------- ----------- TOTAL $ 459,651 $ 654,232 =========== ===========
SPR's balance sheets contain a net regulatory asset of $121.3 million at year-end 2002 and $123.0 million at year-end 2001. The net regulatory asset consists of future revenue to be received from customers (a regulatory asset) of $163.9 million at year-end 2002 and $169.7 million at year-end 2001, 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 $16.5 million at year-end 2002 and $18.7 million at year-end 2001, due to temporary differences for liberalized depreciation at rates in excess of current tax rates, and $26.2 million at year-end 2002 and $28.0 million at year-end 2001 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 and 2002, some of this benefit could not be utilized (i.e., deferred energy). In March 2002, NPC received a federal income tax refund of $79.3 million. Additionally, SPR and the Utilities received $105.7 million of refunds in the second quarter of 2002. These refunds were the result of income tax losses generated in 2001. Federal legislation passed in March 2002 changed the allowed carry-back of these losses from two years to five years. This change permitted SPR and the Utilities to accelerate the receipt of a portion of their income tax receivables sooner than expected. The remaining income tax losses of $281.9 million as of December 31, 2002, may be utilized in future periods to reduce taxes payable to the extent that SPR and the Utilities recognize taxable income. The carryforward period for net operating losses incurred 171 is 20 years, and as such the losses incurred in the years ended 12/31/2000, 2001, and 2002 will expire in 2020, 2021, and 2022 respectively. For the year 2000, all inter-company income tax related payables and receivables due to/from affiliates were paid in full as of 12/31/2000. For the year 2001, SPR owed the following income-tax related balances to affiliates: SPPC $62.1 million and NPC $18.6 million. For the year 2001, SPR had a receivable from all other subsidiaries of $8.5 million. There were no income tax-related inter-company payables and receivables due to/from affiliates for the year ended December 31, 2002. The consolidated amount of current and deferred tax expense is allocated among SPR and its subsidiaries on a pro rata basis based on separate company taxable income. Any benefit or detriment associated with the consolidation of the income tax return is also allocated among SPR and its subsidiaries one a pro rata basis based on separate company taxable income. As a large corporate taxpayer, the SPR consolidated group's tax returns are examined by the Internal Revenue Service on a regular basis. The IRS began an audit of the company's consolidated income tax returns in the third quarter of 2002. The years under examination include the separate company returns for NPC and its subsidiaries for 1997 and 1998 and the consolidated returns for SPR and its subsidiaries for 1997 through 2001. The focus of the examination is the net operating losses generated in 2000 and 2001 and carried back to earlier years. The losses reported in 2000 and 2001 are mainly due to the deductions claimed for purchased fuel and purchase power. The losses claimed on the tax returns are mainly timing differences, and as such, are not expected to cause a material impact on SPR's, NPC's or SPPC's future income statements if it is determined they are allowable in a subsequent period. No Notices of Proposed Adjustment have been received to date. NEVADA POWER COMPANY The following reflects the composition of taxes on income (in thousands of dollars):
2002 2001 2000 --------- --------- --------- As Reflected in Statement of Income Federal income taxes $(133,411) $ 18,715 $ (12,162) State income taxes -- (940) -- --------- --------- --------- Federal Income Tax on Operating Income: (133,411) 17,775 (12,162) Other income (expense) 1,627 14,962 1,201 --------- --------- --------- Total $(131,784) $ 32,737 $ (10,961) ========= ========= =========
172 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):
2002 2001 2000 --------- --------- --------- Income (Loss) from continuing operations $(235,070) $ 63,405 $ (7,928) Total income tax expense (131,784) 32,737 (10,961) --------- --------- --------- (366,854) 96,142 (18,889) Statutory tax rate 35% 35% 35% --------- --------- --------- Expected income tax expense (128,399) 33,650 (6,611) Depreciation related to difference in costs basis for tax purposes 1,431 1,431 1,431 Allowance for funds used during construction - equity 153 383 300 Tax benefit from the disposition of assets -- -- -- State taxes (net of federal benefit) -- (611) -- ITC amortization (1,630) (1,630) (1,460) Other - net (3,339) (486) (4,621) --------- --------- --------- $(131,784) $ 32,737 $ (10,961) ========= ========= ========= Effective tax rate 35.9% 34.1% 58.0% ========= ========= =========
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):
2002 2001 --------- --------- Deferred Federal Income Tax Liabilities: Allowance for funds used during construction - debt $ 9,238 $ 7,659 Bond redemptions 5,170 5,460 Excess of tax depreciation over book depreciation 304,002 212,969 Severance programs 2,606 1,982 Tax benefits flowed through to customer 106,070 109,859 Deferred energy 257,614 343,023 Ad Valorem Taxes 3,336 172 Other - net 5,969 5,559 --------- --------- 694,005 686,683 --------- --------- Deferred Federal Income Tax Assets: Net Operating Loss Carryforward 250,054 211,504 Avoided interest capitalized 15,202 11,217 Employee benefit plans 9,025 8,555 Reserve for bad debt 11,501 10,801 Contributions in aid of construction and customer advances 72,018 69,232 Gross-ups received on contributions in aid of construction and customer advances 11,054 6,514 Excess deferred income taxes 5,360 5,859 Unamortized investment tax credit 11,940 12,745 Other Accumulated Comprehensive Income - minimum pension liability 4,838 -- Contract termination reserve 79,036 -- Other - net 3,674 (4,904) --------- --------- 473,702 331,523 --------- --------- Total $ 220,303 $ 355,160 ========= =========
NPC's balance sheets contain a net regulatory asset of $88.8 million at year-end 2002 and $91.3 million at year-end 2001. The net regulatory asset consists of future revenue to be received from customers (a 173 regulatory asset) of $106.1 million at year-end 2002 and $109.9 million at year-end 2001, 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 $5.4 million at year-end 2002 and $5.9 million at year-end 2001 due to temporary differences for liberalized depreciation at rates in excess of current tax rates, and $11.9 million at year-end 2002 and $12.7 million at year-end 2001 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 tax operating loss in 2002, some of this benefit could not be utilized (i.e., deferred energy). SIERRA PACIFIC POWER COMPANY The following reflects the composition of taxes on income (in thousands of dollars):
2002 2001 2000 -------- -------- -------- As Reflected in Statement of Income Federal income taxes $ (6,922) $ 10,731 $ (1,118) State income taxes -- (2,224) 446 -------- -------- -------- Federal Income Tax on Operating Income: (6,922) 8,507 (672) Other income - net 2,431 (91) (690) -------- -------- -------- Total $ (4,491) $ 8,416 $ (1,362) ======== ======== ========
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):
2002 2001 2000 -------- -------- -------- Income (loss) from continuing operations $(13,968) $ 22,743 $ (4,077) Total income tax expense (4,491) 8,416 (1,362) -------- -------- -------- (18,459) 31,159 (5,439) Statutory tax rate 35% 35% 35% -------- -------- -------- Expected income tax expense (6,461) 10,906 (1,904) Depreciation related to difference in costs basis for tax purposes 1,650 1,513 1,531 Allowance for funds used during construction - equity (40) (298) (149) Tax benefit from the disposition of assets (48) (111) (175) ITC amortization (1,824) (1,824) (1,824) State taxes (net of federal benefit) -- (1,446) 290 Pension benefit plan 1,400 697 887 Other - net 832 (1,021) (18) -------- -------- -------- $ (4,491) $ 8,416 $ (1,362) ======== ======== ======== Effective tax rate 24.3% 27.0% 25.0% ======== ======== ========
174 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):
2002 2001 -------- -------- Deferred Federal Income Tax Liabilities: Allowance for funds used during construction - debt $ 7,043 $ 4,837 Bond redemptions 5,962 6,048 Excess of tax depreciation over book depreciation 251,809 188,389 Severance programs 2,413 3,317 Tax benefits flowed through to customer 57,818 59,879 Deferred energy 82,026 87,790 Other 5,801 28,732 -------- -------- 412,872 378,992 -------- -------- Deferred Federal Income Tax Assets: Net operating loss carryforward 237 -- Avoided interest capitalized 17,117 12,444 Employee benefit plans 4,396 3,451 Reserve for bad debt 3,620 2,960 Contributions in aid of construction and customer advances 37,859 35,163 Gross-ups received on contributions in aid of construction and customer advances 5,611 5,462 Excess deferred income taxes 11,100 12,797 Unamortized investment tax credit 14,318 15,301 Other Accumulated Comprehensive Income - Additional minimum pension liability 350 -- Contract termination reserve 30,372 -- Other 3,514 4,022 -------- -------- 128,494 91,600 -------- -------- Accumulated Deferred Federal Income Taxes $284,378 $287,392 ======== ========
SPPC's balance sheets contain a net regulatory asset of $32.4 million at year-end 2002 and $31.8 million at year-end 2001. The net regulatory asset consists of future revenue to be received from customers (a regulatory asset) of $57.8 million at year-end 2002 and $59.9 million at year-end 2001, 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 $11.1 million at year-end 2002 and $12.8 million at year-end 2001, due to temporary differences for liberalized depreciation at rates in excess of current tax rates, and $14.3 million at year-end 2002 and $15.3 million at year-end 2001 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 and 2002 some of this benefit could not be utilized (i.e., deferred energy). NOTE 11. FAIR VALUE OF FINANCIAL INSTRUMENTS The December 31, 2002, 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, 2002, is estimated to be $1.298 billion (excluding current portion) based on quoted market prices for the same or similar issues or on the 175 current rates offered to NPC for debt of the same remaining maturities. The total fair value (excluding current portion) was estimated to be $1.56 billion at December 31, 2001. The estimated fair value of NPC's preferred trust securities is $139.8 million at December 31, 2002. The fair value of NPC's preferred securities was estimated to be $181.5 million at December 31, 2001. The total fair value of SPPC's consolidated long-term debt at December 31, 2002, is estimated to be $851.5 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 $946.5 million as of December 31, 2001. SPPC's preferred trust securities were redeemed on November 29, 2001. The total fair value of SPR's consolidated long-term debt at December 31, 2002, is estimated to be $2.66 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 $3.386 billion as of December 31, 2001. The estimated fair value of SPR's consolidated preferred trust securities is $139.8 million at December 31, 2002. The fair value of SPR's consolidated preferred trust securities was estimated to be $181.5 million at December 31, 2001. NOTE 12. SHORT-TERM BORROWINGS SIERRA PACIFIC RESOURCES On April 3, 2002, SPR terminated its $75 million unsecured revolving credit facility in connection with the amendment of NPC's $200 million unsecured revolving credit facility, discussed below. NEVADA POWER COMPANY On November 29, 2001, NPC put into place a $200 million unsecured revolving credit facility for working capital and general corporate purposes, including commercial paper backup. As a result of NPC's rate case decisions (discussed in Note 3, Regulatory Events) and the credit downgrades by S&P and Moody's, which occurred on March 29 and April 1, 2002, respectively, the banks participating in NPC's credit facility determined that a material adverse event had occurred with respect to NPC, thereby precluding NPC from borrowing funds under its credit facility. The banks agreed to waive the consequences of the material adverse event in a waiver letter and amendment that was executed on April 3, 2002. As required under the waiver letter and amendment, NPC issued and delivered its General and Refunding Mortgage Bond, Series C, due November 28, 2002, in the principal amount of $200 million, to the Administrative Agent for the credit facility. As of September 30, 2002, NPC had borrowed the entire $200 million of funds available under its credit facility at an average interest rate of 3.72%. On October 30, 2002, NPC paid in full and terminated its $200 million credit facility and retired its Series C, General & Refunding Bond which secured the credit facility with the proceeds from the issuance of NPC's $250 million aggregate principal amount of 10 7/8% General and Refunding Notes, Series E, due 2009. On October 29, 2002, NPC established an accounts receivable purchase facility of up to $125 million, which was arranged by Lehman Brothers. If NPC elects to activate the receivables purchase facility, NPC will sell all of its accounts receivable generated from the sale of electricity to customers to its newly created bankruptcy remote special purchase subsidiary. The receivables sales will be without recourse except for breaches of customary representations and warranties made at the time of sale. The subsidiary will, in turn, sell these receivables to a bankruptcy remote subsidiary of SPR. SPR's subsidiary will issue variable rate revolving notes backed by the purchased receivables. Lehman Brothers Holding, Inc. will be the sole initial committed 176 purchaser of all of the variable rate revolving notes. The agreements relating to the receivables purchase facility contain various conditions to purchase, covenants and trigger events, termination events and other provisions customary in receivables transactions. In connection with NPC's receivables facility, SPR has agreed to guaranty NPC's performance of certain obligations as a seller and servicer under the facility. NPC has agreed to issue $125 million principal amount of its General and Refunding Mortgage Bonds upon activation of the accounts receivables purchase facility. The full principal amount of the Bond would secure certain of NPC's obligations as seller and servicer, plus certain interest, fees and expenses thereon to the extent not paid when due, regardless of the actual amounts owing with respect to the secured obligations. As a result, in the event of an NPC bankruptcy or liquidation, the holder of the Bond securing the receivables facility may recover more on a pro rata basis than the holders of other General and Refunding Mortgage securities, who could recover less on a pro rata basis, than they otherwise would recover. However, in no event will the holder of the Bond recover more than the amount of obligations secured by the Bond. NPC intends to use the accounts receivables purchase facility as a back-up liquidity facility and does not plan to activate this facility in the foreseeable future. NPC may activate the facility within five days upon the delivery of certain customary funding documentation and the delivery of the $125 million General and Refunding Mortgage Bond. As of December 31, 2002, this facility has not been activated. NPC does not expect to activate this facility in the foreseeable future. SIERRA PACIFIC POWER COMPANY On November 29, 2001, SPPC put into place a $150 million unsecured revolving credit facility for working capital and general corporate purposes, including commercial paper backup. Under this credit facility, SPPC was required, in the event of a ratings downgrade of its senior unsecured debt, to secure the facility with General and Refunding Mortgage Bonds. In satisfaction of its obligation to secure the credit facility, on April 8, 2002, SPPC issued and delivered its General and Refunding Mortgage Bond, Series B, due November 28, 2002, in the principal amount of $150 million, to the Administrative Agent for the credit facility. As of September 30, 2002, SPPC had borrowed the entire $150 million of funds available under its credit facility to, in part, pay off maturing commercial paper, and to maintain a cash balance at SPPC at an average interest rate of 3.69%. On October 31, 2002, SPPC paid off and terminated its $150 million credit facility and retired its Series B, General & Refunding Bond which secured the credit facility with a combination of cash on hand and proceeds from its $100 million Term Loan Facility. On October 29, 2002, SPPC established an accounts receivable purchase facility of up to $75 million, which was arranged by Lehman Brothers. If SPPC elects to activate the receivables purchase facility, SPPC will sell all of its accounts receivable generated from the sale of electricity to customers to its newly created bankruptcy-remote special purpose subsidiary. The receivables sales will be without recourse except for breaches of customary representations and warranties made at the time of sale. The subsidiary will, in turn, sell these receivables to a bankruptcy-remote subsidiary of SPR. SPR's subsidiary will issue variable rate revolving notes backed by the purchased receivables. Lehman Brothers Holdings, Inc. will be the sole initial committed purchaser of all of the variable rate revolving notes. The agreements relating to the receivables purchase facility contain various conditions to purchase, covenants and trigger events, termination events and other provisions customary in receivables transactions. In connection with SPPC's receivables facility, SPR has agreed to guaranty SPPC's performance of certain obligations as a seller and servicer under the facility. SPPC has agreed to issue $75 million principal amount of its General and Refunding Mortgage Bonds upon activation of the accounts receivables purchase facility. The full principal amount of the Bond would 177 secure certain of SPPC's obligations as seller and servicer, plus certain interest, fees and expenses thereon to the extent not paid when due, regardless of the actual amounts owing with respect to the secured obligations. As a result, in the event of an SPPC bankruptcy or liquidation, the holder of the Bond securing the receivables facility may recover more on a pro rata basis than the holders of other General and Refunding Mortgage securities, who could recover less on a pro rata basis, than they otherwise would recover. However, in no event will the holder of the Bond recover more than the amount of obligations secured by the Bond. SPPC intends to use the accounts receivables purchase facility as a back-up liquidity facility and does not plan to activate this facility in the foreseeable future. SPPC may activate the facility within five days upon the delivery of certain customary funding documentation and the delivery of the $75 million General and Refunding Mortgage Bond. As of December 31, 2002 this facility has not been activated. NOTE 13. DIVIDEND RESTRICTIONS 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 NPC and SPPC 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 that the Utilities may declare and pay, and to federal statutory limitation on the payment of dividends. In addition, certain agreements entered into by the Utilities set restrictions on the amount of dividends they may declare and pay and restrict the circumstances under which such dividends may be declared and paid. The specific restrictions on dividends contained in agreements to which NPC and SPPC are party, as well as specific regulatory limitations on dividends, are summarized below. NEVADA POWER COMPANY First Mortgage Indenture. NPC's first mortgage indenture limits the cumulative amount of dividends and other distributions that NPC may pay on its capital stock to the cumulative net earnings of NPC since 1953, subject to adjustments for the net proceeds of sales of capital stock since 1953. At the present time, this restriction precludes NPC from making further payments of dividends on NPC's common stock and will continue to bar dividends until NPC, over time, generates sufficient earnings to eliminate the deficit under this provision (which was approximately $237 million as of December 31, 2002), unless the restriction is earlier waived, amended, or removed by the consent of the first mortgage bondholders, or the first mortgage bonds are redeemed or defeased. Under this provision, NPC continues to have capacity to repurchase or redeem shares of its capital stock. Series E Notes. NPC's 10 7/8% General and Refunding Mortgage Notes, Series E, due 2009, which were issued on October 29, 2002, limit the amount of payments in respect of common stock that NPC may pay to SPR. However, that limitation does not apply to payments by NPC to enable SPR to pay its reasonable fees and expenses (including, but not limited to, interest on SPR's indebtedness and payment obligations on account of SPR's Premium Income Equity Securities (PIES)) provided that: o those payments do not exceed $60 million for any one calendar year, o those payments comply with any regulatory restrictions then applicable to NPC, and o the ratio of consolidated cash flow to fixed charges for NPC's most recently ended four full fiscal quarters immediately preceding the date of payment is at least 1.75 to 1. The terms of the Series E Notes also permit NPC to make payments to SPR in an aggregate amount not to exceed $15 million from the date of the issuance of the Series E Notes. In addition, NPC may make dividend payments to SPR in excess of the amounts described above so long as, at the time of payment and after giving effect to the payment: 178 o there are no defaults or events of default with respect to the Series E Notes, o NPC can meet a fixed charge coverage ratio test, and o the total amount of such dividends is less than: o the sum of 50% of NPC's consolidated net income measured on a quarterly basis cumulative of all quarters from the date of issuance of the Series E Notes, plus o 100% of NPC's aggregate net cash proceeds from the issuance or sale of certain equity or convertible debt securities of NPC, plus o the lesser of cash return of capital or the initial amount of certain restricted investments, plus o the fair market value of NPC's investment in certain subsidiaries. If NPC's Series E Notes are upgraded to investment grade by both Moody's Investors Service, Inc. (Moody's) and Standard & Poor's Rating Group, Inc. (S&P), these dividend restrictions will be suspended and will no longer be in effect so long as the Series E Notes remain investment grade. Accounts Receivable Facility. On October 29, 2002, NPC established an accounts receivable purchase facility. The agreements relating to the receivables purchase facility contain various conditions, including a limitation on the payment of dividends by NPC to SPR that is identical to the limitation contained in NPC's General and Refunding Mortgage Notes, Series E, described above. Preferred Trust Securities. The terms of NPC's preferred trust securities provide that no dividends may be paid on NPC's common stock if NPC has elected to defer payments on the junior subordinated debentures issued in conjunction with the preferred trust securities. At this time, NPC has not elected to defer payments on the junior subordinated debentures. PUCN Order. The PUCN issued a Compliance Order, Docket No. 02-4037, on June 19, 2002, relating to NPC's request for authority to issue long-term debt. The PUCN order requires that, until such time as the order's authorization expires (December 31, 2003), NPC must either receive the prior approval of the PUCN or reach an equity ratio of 42% before paying any dividends to SPR. If NPC achieves a 42% equity ratio prior to December 31, 2003, the dividend restriction ceases to have effect. As of December 31, 2002, NPC's equity ratio was 36.1%. Federal Power Act. NPC is subject to the provisions of the Federal Power Act that state that dividends cannot be paid out of funds that are properly included in capital account. Although the meaning of this provision is not clear, it could be interpreted to impose an additional material limitation on a utility's ability, in the absence of retained earnings, to pay dividends. SIERRA PACIFIC POWER COMPANY Term Loan Agreement. SPPC's Term Loan Agreement dated October 30, 2002, which expires October 31, 2005, limits the amount of dividends that SPPC may pay to SPR. However, that limitation does not apply to payments by SPPC to enable SPR to pay its reasonable fees and expenses (including, but not limited to, interest on SPR's indebtedness and payment obligations on account of SPR's PIES) provided that those payments do not exceed $90 million, $80 million and $60 million in the aggregate for the twelve month periods ending on October 30, 2003, 2004 and 2005, respectively. The Term Loan Agreement also permits SPPC to make dividend payments to SPR in an aggregate amount not to exceed $10 million during the term of the Term Loan Agreement. In addition, SPPC may make dividend payments to SPR in excess of the amounts described above so long as, at the time of the payment and after giving effect to the payment, there are no defaults or events of default under the Term Loan Agreement, and such amounts, when aggregated with the amount of dividends paid to SPR by SPPC since the date of execution of the Term Loan Agreement, do not exceed the sum of: 179 o (i) 50% of SPPC's Consolidated Net Income for the period commencing January 1, 2003 and ending with last day of fiscal quarter most recently completed prior to the date of the contemplated dividend payment, plus o (ii) the aggregate amount of cash received by SPPC from SPR as equity contributions on its common stock during such period. Accounts Receivable Facility. On October 29, 2002, SPPC established an accounts receivable purchase facility. The agreements relating to the receivables purchase facility contain various conditions, including a limitation on the payment of dividends by SPPC to SPR that is identical to the limitation contained in SPPC's Term Loan Agreement, described above. Articles of Incorporation. SPPC's Articles of Incorporation 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. SPPC's Articles also prohibit SPPC from declaring or paying any dividends on any shares of common stock (other than dividends payable in shares of common stock), or making any other distribution on any shares of common stock or any expenditures for the purchase, redemption or other retirement for a consideration of shares of common stock (other than in exchange for or from the proceeds of the sale of common stock) except from the net income of SPPC, and its predecessor, available for dividends on common stock accumulated subsequent to December 31, 1955, less preferred stock dividends, plus the sum of $500,000. At the present time, SPPC believes that these restrictions do not materially limit its ability to pay dividends and/or to purchase or redeem shares of its common stock. Federal Power Act. SPPC is subject to the provisions of the Federal Power Act that state that dividends cannot be paid out of funds that are properly included in capital account. Although the meaning of this provision is not clear, it could be interpreted to impose an additional material limitation on a utility's ability, in the absence of retained earnings, to pay dividends. 180 NOTE 14. RETIREMENT PLAN AND POST-RETIREMENT BENEFITS 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; the market related value of the plan assets equals fair value. This reconciliation is based on a September 30 measurement date (dollars in thousands).
Other Postretirement Pension Benefits Benefits -------------------------- -------------------------- 2002 2001 2002 2001 --------- --------- --------- --------- CHANGE IN BENEFIT OBLIGATIONS Benefit obligation, beginning of year $ 360,677 $ 348,135 $ 75,443 $ 77,790 Service cost 11,954 13,494 1,287 1,922 Interest cost 27,733 27,742 5,599 6,358 Participant contributions -- -- 590 466 Plan amendment & special termination 7,938 476 -- -- Actuarial loss (gain) 50,670 6,864 56,189 (5,201) Special Termination Benefits -- 394 -- -- Acquisitions and divestiture -- -- -- (1,231) Benefits paid (29,997) (36,428) (6,938) (4,661) --------- --------- --------- --------- Benefit obligation, end of year $ 428,975 $ 360,677 $ 132,170 $ 75,443 ========= ========= ========= ========= CHANGE IN PLAN ASSETS Fair value of plan assets, beginning of year $ 275,305 $ 349,153 $ 61,407 $ 81,900 Actual return (loss) on plan assets (23,090) (39,320) (6,817) (15,797) Company contributions 16,616 1,900 183 730 Participant contributions -- -- 590 466 Acquisition and divestiture -- -- -- (1,231) Benefits paid (29,997) (36,428) (6,937) (4,661) --------- --------- --------- --------- Fair value of plan assets, end of year $ 238,834 $ 275,305 $ 48,426 $ 61,407 ========= ========= ========= ========= Funded Status, end of year $(190,142) $ (85,373) (83,744) $ (14,036) Unrecognized net actuarial (gains) losses 154,222 61,750 61,553 (5,365) Unrecognized prior service cost 17,001 10,366 724 -- Unrecognized net transition obligation -- -- 9,311 10,280 Contributions made in 4th quarter 24,495 11,917 -- -- --------- --------- --------- --------- Prepaid (accrued) pension and postretirement benefit obligations $ 5,576 $ (1,340) $ (12,156) $ (9,121) ========= ========= ========= =========
181 Amounts for pension and postretirement benefits recognized in the consolidated balance sheets consist of the following:
Other Postretirement Pension Benefits Benefits ------------------------ ----------------------- 2002 2001 2002 2001 -------- -------- --------- -------- Prepaid pension asset $ 19,813 $ 14,051 N/A N/A Accrued benefit liability (14,237) (15,391) $ (12,156) $ (9,121) Intangible asset 17,001 -- N/A N/A Accumulated other comprehensive income 72,550 1,395 N/A N/A Additional minimum liability (89,551) (1,395) N/A N/A -------- -------- --------- -------- Net amount recognized 5,576 (1,340) (12,156) (9,121) ======== ======== ========= ========
The weighted-average actuarial assumptions as of the measurement date were as follows:
Other Postretirement Pension Benefits Benefits ------------------------------------- ------------------------------------- 2002 2001 2000 2002 2001 2000 ------- ------- ------- ------- ------- ------- Discount rate 6.75% 7.50% 8.00% 6.75% 7.50% 8.00% 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 2002 and all future years. 182 Net periodic pension and other postretirement benefit costs include the following components:
Pension Benefits ---------------------------------------- 2002 2001 2000 -------- -------- -------- Service cost $ 11,954 $ 13,494 $ 11,907 Interest cost 27,733 27,742 26,469 Expected return on assets (22,768) (28,806) (27,186) Amortization of: Transition asset -- -- -- Prior service costs 1,676 1,195 1,201 Actuarial losses 2,252 200 159 -------- -------- -------- Net periodic benefit cost 20,847 13,825 12,550 Special termination charges 1,646 394 -- -------- -------- -------- Total net benefit cost $ 22,493 $ 14,219 $ 12,550 ======== ======== ========
Other Postretirement Benefits ------------------------------------- 2002 2001 2000 ------- ------- ------- Service cost $ 1,287 $ 1,922 $ 1,775 Interest cost 5,599 6,358 5,829 Expected return on assets (5,044) (6,774) (5,327) Amortization of: Prior service costs 187 -- -- Transition obligation 969 969 968 Actuarial gains -- -- (598) ------- ------- ------- Net periodic benefit cost 2,998 2,475 2,647 Special termination charges 58 -- -- ------- ------- ------- Total net benefit cost $ 3,056 $ 2,475 $ 2,647 ======= ======= =======
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 2002 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 $ 1,491 $ (1,206) Effect on accumulated postretirement benefit obligation $ 14,886 $ (12,324)
NOTE 15. STOCK COMPENSATION PLANS At December 31, 2002, Sierra Pacific Resources had several stock-based compensation plans which are described below. 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, 183 separately or in combination: nonqualified and qualified stock options, stock appreciation rights, restricted stock, performance units, performance shares, and bonus stock. During 2002, 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 2002 were issued at an option price not less than market value at the date of the grants. The grants awarded in January and December vest to the participants 33% per year over a three year period from the grant date; the remaining grants awarded in 2002, vest to the participants 100% one year from the grant date. All grants may be exercised for a 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, 2002, 2001, and 2000, and changes during the year is presented below:
2002 2001 2000 --------------------------- --------------------------- ------------------------- Weighted- Weighted- Weighted- Average Average Average Exercise Exercise Exercise Nonqualified Stock Options Shares Price Shares Price Shares Price - -------------------------- --------- ----------- --------- ----------- ------- ----------- Outstanding at beginning of year 1,213,958 $ 18.28 799,428 $ 19.94 839,442 $ 24.33 Granted 502,380 $ 14.05 414,530 $ 15.08 400,000 $ 16.00 Exercised -- -- -- -- 14,107 $ 14.28 Forfeited 197,232 $ 18.07 -- -- 425,907 $ 25.07 Outstanding at end of year 1,519,106 $ 16.91 1,213,958 $ 18.28 799,428 $ 19.94 Options exercisable at year-end 601,371 $ 19.52 262,533 $ 23.03 202,394 $ 22.66 Weighted-average grant date fair value of options granted 1: Average of all grants for: 2002 $4.56 2001 $3.83 2000 $4.10
1. 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 2002, 2001 and 2000:
Average Average Average Risk- Dividend Expected Free Rate of Average Year of Option Grant Yield Volatility Return Expected Life -------------------- -------- ---------- ------------- ------------- 2002 0.00% 38.23% 5.03% 10 years 2001 4.99% 32.31% 5.32% 10 years 2000 4.81% 30.49% 6.14% 9.6 years
184 The following table summarizes information about nonqualified stock options outstanding at December 31, 2002:
Options Outstanding Options Exercisable ---------------------------------- ---------------------------- Average Number Remaining Average Number Exercise Outstanding Contractual Exercise Exercisable at Year of Grant Price at 12/31/02 Life Price 12/31/02 ------------- -------- ----------- -------------- -------- --------------- 1994 $14.24 8,003 1 year $14.24 8,003 1995 $13.02 9,010 2 years $13.02 9,010 1996 $16.23 7,485 3 years $16.23 7,485 1997 $19.97 33,428 4 years $19.97 33,428 1998 $24.93 56,160 5 years $24.93 56,160 1999 $25.11 222,120 6 - 6.6 years $25.11 179,124 2000 $16.00 400,000 7 years $16.00 200,000 2001 $15.95 338,010 8 - 8.6 years $15.95 108,161 2002 $ 7.75 444,890 9 - 9.9 years $ 7.75 -- Weighted Average Remaining Contractual Life 7.54 years
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 2002, 2001 and 2000, SPR granted performance shares in the following numbers and initial values:
1/1/2002 1/1/2001 8/4/2000 1/1/2000 -------- -------- -------- -------- Shares Granted 96,772 144,271 4,798 31,707 Value per Share $15.58 $14.80 $16.00 $26.00
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 January 1, 2001, had 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. SPR, 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 January 1, 2001 would have been paid in SPR stock only, however, this grant has not been approved for payment by SPR Board of Directors. 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. 185 RESTRICTED STOCK SHARES In 2002, SPR granted 4,500 restricted stock shares at an average grant price of $6.88 per share. The grants vest over 4 years at 25% per year. During 2001, SPR granted 13,200 shares of restricted stock at an average grant price of $15.67 per share. The grants vest to the participants over 4 years at 25% per year. In 2002, according to the vesting schedule for each grant, 1,750 shares were issued under these grants. 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. In 2002, 4,000 shares were issued under this grant, in accordance with the vesting schedule. There is no performance criteria associated with the restricted stock grants, except for continued employment with SPR or its subsidiaries, 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 73,321, 33,830 and 46,773 shares to employees in 2002, 2001, and 2000, respectively. For purposes of determining the pro forma disclosure, 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 2002, 2001 and 2000:
Average Average Average Risk- Weighted Dividend Expected Free Rate Average Fair Year Yield Volatility of Return Value ---- -------- ---------- ------------- ------------ 2002 0.00% 38.00% 3.12% $1.45 2001 5.01% 32.43% 2.82% $2.72 2000 4.72% 30.97% 5.86% $3.03
NON-EMPLOYEE DIRECTOR STOCK 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 2002, 2001 and 2000, SPR granted the following total shares and related compensation to directors in SPR stock, respectively: 18,540, 14,573, and 16,915 shares, and $160,000, $210,000, and $250,000. NOTE 16. DISCONTINUED OPERATIONS AND DISPOSAL OF LONG-LIVED ASSETS SALE OF WATER BUSINESS In June 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, 186 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 CPUC. The sale agreement contemplates a second closing for the hydroelectric facilities to accommodate the CPUC's review of the transaction. See Note 3, Regulatory Actions, for a discussion of California legislative and regulatory developments involving the hydroelectric facilities. Pursuant to a stipulation entered into in connection with the sale and approved by the PUCN, SPPC was required to hold in trust for refund to customers $21.5 million of the proceeds from the sale. The refund was credited on the electric bills of SPPC's former water customers over a fifteen-month period ending November 2002. Under a service contract with TMWA, SPPC provided customer service and billing services to TMWA until August 2002. SPPC continues to provide meter-reading services under a one-year contract renewable in one-year increments by TMWA through 2008. Revenues from operations of the water business for the years ended December 31, 2001, and 2000 were $23 million and $57 million, respectively. The net income from operations of the water business, as shown in the Consolidated Statements of Operations of both SPR and SPPC, includes preferred dividends of $200,000 and $401,000 for the years ended December 31, 2001, and 2000, respectively. These amounts are not included in the revenues and income (loss) from continuing operations shown in the accompanying consolidated statements of operations. ASSET SALES During 2002, the Utilities began pursuing the sale of several non-essential properties. As a result, on January 15, 2003, NPC sold a parcel of land located on Flamingo Road near the Barbary Coast Casino in Las Vegas, Nevada. NPC received cash proceeds of approximately $18 million for the property and retained an easement and other rights necessary to maintain aerial power lines that cross the property. Also, it was agreed that NPC will receive an additional $2.6 million from the sale if the power lines that cross the property are removed and the other rights are relinquished within a five-year period from the date of the sale. The property had been originally transferred to NPC at no cost. The transaction resulted in a gain of $17.7 million, which will be recognized into revenue over a period of three years consistent with the accounting treatment directed by the PUCN. On November 11, 2002, SPPC agreed to sell land located in Nevada County and Sierra County, California, commonly referred to as Independence Lake. The sale remains subject to review by a third party who retains certain rights, including water rights, after the sale is completed. Also, the sales agreement includes a due diligence review period of 180 days which allows the buyer to review and accept a variety of matters agreed to by both parties. The buyer may terminate the agreement during the review period by providing written notice or by allowing the review period to expire. The agreed upon sales price is $22 million and the transaction is expected to close, subject to the conditions described, in the second quarter of 2003. The carrying value of the property is approximately $108,000. 187 NOTE 17. COMMITMENTS AND CONTINGENCIES PURCHASED POWER At December 31, 2002, NPC has six long-term contracts for the purchase of electric energy. Expiration of these contracts ranges from 2016 to 2024. SPPC has one long-term contract with an expiration date of 2009. Estimated future commitments under non-cancelable agreements (including agreements with Qualifying Facilities (QF's) as of December 31, 2002 were as follows (dollars in thousands):
Purchased Power NPC SPPC Total 2003 $ 408,656 $138,803 $ 547,459 2004 241,957 42,968 284,925 2005 220,343 28,874 249,217 2006 204,666 29,406 234,072 2007 189,434 30,957 220,391 Thereafter 3,456,297 38,351 3,494,648
According to the regulations under the Public Utility Regulatory 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. As of December 31, 2002, 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, 2002, SPPC had a total of 109 MWs of maximum contractual firm capacity under 15 contracts with QFs. SPPC also has contracts with three projects at variable short-term avoided cost rates. SPPC's long-term QF contracts terminate between 2006 and 2039. 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 2003 to 2027. Estimated future commitments under non-cancelable agreements were as follows (dollars in thousands):
Coal and Gas Transportation --------------------------------------- -------------------------------------- NPC SPPC Total NPC SPPC Total 2003 $ 37,818 $ 31,699 $ 69,517 $ 36,606 $ 61,733 $ 98,339 2004 27,040 15,364 42,404 42,285 60,651 102,936 2005 9,605 15,830 25,435 28,946 56,001 84,947 2006 2,829 16,302 19,131 28,946 53,174 82,120 2007 1,007 0 1,007 28,946 50,270 79,216 Thereafter 4,029 0 4,029 337,312 318,493 655,805
LEASES SPPC has an operating lease for its corporate headquarters building. The primary term of the lease is 25 years, ending 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. 188 SPR's estimated future minimum cash payments, including SPPC's headquarters building, under non-cancelable operating leases as of December 31, 2002, were as follows (dollars in thousands):
Operating Leases --------------------------------------------------------- NPC SPPC Other Subs Total 2003 $2,263 $ 8,357 $ 479 $11,099 2004 1,170 7,080 476 8,726 2005 869 6,425 380 7,674 2006 181 6,177 147 6,505 2007 119 6,173 147 6,439 Thereafter 459 55,153 2,086 57,698
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. In September 2002, the California Legislature approved an amendment, AB 1235, AB 6 that would allow SPPC to complete the sale of the four hydroelectric units to TMWA. Section 851 of the Public Utilities Code requires review and approval of the sale by the CPUC. The sale of the Farad Hydroelectric Unit is conditioned on the completion of the reconstruction of the Farad dam and flume or assignment of SPPC insurance claim for reconstruction of the dam. The Farad Reconstruction Project is currently in the permitting phase with permits expected by mid-2003. The sales agreements for the six bundles provided that they terminate eighteen months after their execution unless the parties agreed to an earlier termination. The parties could have extended the termination another six months to obtain additional regulatory approvals. As a result of the legislative and regulatory developments which rendered the contracts impossible to perform, the Utilities 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. Those discussions ended without agreement to mutually terminate; however, all the contracts have now terminated in accordance with the contract provisions. As of December 31, 2002, the Utilities had incurred costs of approximately $20.1 million at NPC and $12.2 million at SPPC in order to prepare for the sale of generation assets. The Utilities requested recovery of these costs in each Utility's respective general rate case filings with the PUCN. The PUCN delayed recovery of the divestiture costs to a future rate case request but did grant a carrying charge on the costs until such time as recovery is allowed. 189 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. The estimated cost of new controls is $1.1 billion. As a 14% owner in Mohave, NPC's cost could be $154 million. NPC's ownership interest in Mohave comprises approximately 10% of NPC's peak generation capacity. Southern California Edison (SCE) is the operating partner of Mohave. On May 17, 2002, SCE filed with the CPUC an application to address the future disposition of SCE's share of Mohave. Mohave obtains all of its coal supply from a mine in northeast Arizona on lands of the Navajo Nation and the Hopi Tribe (the Tribes). This coal is delivered from the mine to Mohave by means of a coal slurry pipeline which requires water that is obtained from groundwater wells located on lands of the Tribes in the mine vicinity. Due to the lack of progress in negotiations with the Tribes and other parties to resolve several coal and water supply issues, SCE's application states that it appears that it probably will not be possible for SCE to extend Mohave's operations beyond 2005. Due to the uncertainty over a post-2005 coal supply, SCE and the other Mohave co-owners have been prevented from commencing the installation of extensive pollution control equipment that must be put in place if Mohave's operations are extended past 2005. NPC is currently evaluating and analyzing all of its options with regard to the Mohave project. In May 1997, the Nevada Division of Environmental Protection (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 has been approved by NDEP. NDEP is expected to identify remediation requirements of contaminated groundwater resulting from these evaporation ponds by July 2003. New pond construction and lining costs are estimated at $15 million. 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 NPC to submit a corrective action plan. The extent of contamination has been determined and remediation is occurring at a modest rate. A hydro-geologic evaluation of the current remediation was completed, and a dual phase extraction remediation system, which has been approved by NDEP, will be constructed beginning in April 2003 at an estimated cost of $150,000. 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 approved in June 2002. Remediation costs are expected to be approximately $100,000. In addition to remediation, NPC 190 will spend $789,000 to line existing ponds. This project was started in 2002 and is expected to be completed in the first quarter 2003. 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. To date, the EPA has not issued additional requests for further information. NEICO, a wholly owned subsidiary of NPC, 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 $4.8 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. The property is currently leased with the intention to reclaim coal fines with subsequent revenues and reduction to the reclamation bond. SIERRA PACIFIC POWER COMPANY In September 1994 Region VII of the EPA notified SPPC that it was being named as a potentially responsible party (PRP) regarding the past improper handling of Polychlorinated Biphenyls (PCB's) by PCB Treatment, Inc., in two buildings, one located in Kansas City, Kansas and the other in Kansas City, Missouri (the Sites). Prior to 1994, SPPC sent PCB contaminated material to PCB Treatment, Inc. for disposal. Certificates of disposal were issued to SPPC by PCB Treatment, Inc. however; the contaminated material was not disposed of, but remained on-site. A number of the largest PRP's formed a steering committee, which is chaired by SPPC. The steering committee has completed its site investigations and the EPA has determined that the Sites should be remediated by removing the buildings to the appropriate landfills. The EPA has issued an administrative order on consent requiring the steering committee to oversee the performance of the work. SPPC has recorded a preliminary liability for the Sites of $650,000 of which approximately $136,000 has been spent through December 31, 2002. The steering committee is obtaining cost estimates for removal of the buildings. Once these costs have been determined, SPPC will be in a better position to estimate and record the ultimate liabilities for the Sites. LANDS OF SIERRA 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 contamination resulting from an underground fuel tank that has been removed from the property. Additional contamination from a third party fuel tank on the property has also been identified and is undergoing remediation. The Lahontan Regional Water Quality Control Board has approved closure without additional remediation pending a one-year monitoring period. Final closure is anticipated in December 2003. 191 OTHER COMMITMENTS AND CONTINGENCIES In 2000, Sierra Pacific Communications (SPC), a wholly owned subsidiary of SPR, and Touch America (formerly Montana Power), formed Sierra Touch America LLC (STA), a limited liability company whose primary purpose was to engage in communications and fiber optics business projects, including construction of a fiber optic line between Salt Lake City, Utah, and Sacramento, California. The conduits included in the line are to be sold to AT&T, PF Net Corporation, and STA. Construction is expected to be completed in the second quarter of 2003. The project sustained significant cost overruns and several complaints and mechanics liens have been filed by several contractors and subcontractors, including Williams Communications LLC, Bayport Pipeline Company, and Mastec North America. In September 2002, SPC conveyed its membership interest in STA to Touch America and obtained an indemnity for any liabilities associated with STA, all in exchange for title to several fibers in the line and a $35 million promissory note. Several of the mechanics lienors have named SPC as the owner of the project and Bayport Pipeline has suggested it may amend its complaint to name SPC. 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 is 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. The dismissal was affirmed by the Ninth Circuit Court of Appeals, and TANC has now filed a writ of certiorari with the United States Supreme Court. Management believes the final outcome of the appeal is not likely to have a material adverse effect on SPPC's financial position or results of operation. Enron filed a complaint with the United States Bankruptcy Court for the Southern District of New York seeking to recover approximately $216 million and $93 million against NPC and SPPC, respectively, for liquidated damages for power supply contracts terminated by Enron in May 2002 and for power previously delivered to the Utilities. The Utilities have denied liability on numerous grounds, including deceit and misrepresentation in the inducement (including, but not limited to, misrepresentation as to Enron's ability to perform) and fraud, unfair trade practices and market manipulation. The Utilities filed motions to dismiss for lack of jurisdiction and/or for a stay of all proceedings pending the actions of the Utilities' proceedings under Section 206 of the Federal Power Act at the FERC. The Utilities have also filed proofs of claims and counterclaims against Enron, for the full amount of the approximately $300 million claimed to be owed and additional damages, as well as for unspecified damages to be determined during the case as a result of acts and omissions of Enron in manipulating the power markets. On December 19, 2002, the bankruptcy judge granted Enron's motion for partial summary judgment on Enron's claim for $17.7 million and $6.7 million, respectively, for energy delivered by Enron in April 2002, for which NPC and SPPC did not pay. The court ordered this money to be deposited into an escrow account not subject to claims of Enron's creditors and subject to refund depending on the outcome of the Utilities' FERC cases on the merits. The Utilities made the deposit as required. The bankruptcy court denied the Utilities' motion to stay the proceeding pending the outcome of the Utilities' Section 206 case at the FERC and denied the Utilities' motion to dismiss for lack of jurisdiction as to Enron's claims for power previously delivered to the Utilities. The court stated that it would rule in due course on Enron's motion for partial summary judgment to require NPC and SPPC to post $200 million and $87 million, respectively pending the outcome of the case on the merits, and for judgment on the merits on Enron's liquidated damage claim (contract price less market price on the date of termination) relating to power it did not deliver under contracts terminated by Enron in May 192 2002. The court took under advisement the Utilities' motion to stay or dismiss Enron's claim for liquidated damages relating to the undelivered power and set a hearing on Enron's motion to dismiss the Utilities' counterclaims for April 3, 2003. The Utilities are unable to predict the outcome of these motions. The United States District Court for the Southern District of New York also denied the Utilities' motion to withdraw reference of the matter to the bankruptcy court without prejudice. The bankruptcy court currently has under submission (1) Enron's motion to dismiss the Utilities' counterclaims, (2) Enron's motion for partial summary judgment regarding the amounts alleged to be due for undelivered power and the posting of collateral for undelivered power, and (3) the Utilities' motion to dismiss or stay proceeding on Enron's claims relating to delivered power. Enron's motion to dismiss the Utilities' counterclaims is set for hearing on April 3, 2003. A decision adverse to the Utilities on Enron's motion for partial summary judgment, or an adverse decision in the lawsuit with respect to liability as to Enron's claims on the merits for undelivered power, would have a material adverse effect on SPR's and the Utilities' financial condition and liquidity, and could make it difficult for one or more of SPR, NPC or SPPC to continue to operate outside of bankruptcy. On September 5, 2002, Morgan Stanley Capital Group (MSCG) initiated an arbitration pursuant to the arbitration provisions in various power supply contracts terminated by MSCG in April 2002. In the arbitration, MSCG is requesting that the arbitrator compel NPC to pay MSCG $25 million pending the outcome of any dispute regarding the amount owed under the contracts. NPC claims that nothing is owed under the contracts on various grounds, including breach by MSCG in terminating the contracts, and further, that the arbitrator does not have jurisdiction over NPC's contract claims and defenses. On September 30, 2002, plaintiffs Stephen A. Gordon and Gail M. Gordon filed a lawsuit in the District Court for Clark County, Nevada, seeking class action status for themselves and all shareholders of SPR against SPR and all of its directors for an alleged breach of fiduciary duty in failing to meaningfully evaluate and consider an alleged offer from the Southern Nevada Water Authority (SNWA) to purchase NPC. The suit seeks extraordinary relief in the form of an injunction requiring the directors to carefully evaluate and consider such offer, formation of a special stockholders committee to ensure fair and adequate evaluation procedures, and for unspecified damages and/or punitive damages in the event the SNWA withdraws its alleged offer before it can be carefully evaluated. SPR intends to vigorously defend the suit. No answer or responsive pleading has yet been required nor have plaintiffs moved for class certification. On September 30, 2002, plaintiff John Anderson filed a virtually identical lawsuit seeking the same relief. On March 21, 2003, plaintiffs' counsel moved to consolidate the Gordon and Anderson cases with another virtually identical lawsuit filed by John Dedolph. SPR believes that the cases are without merit and plans to file motions to dismiss in the second quarter 2003. On October 21, 2002, Bonneville Square and Union Plaza filed a complaint seeking class certification in the Eighth Judicial District Court for Clark County, Nevada, against NPC for fraud and misrepresentation for allegedly overcharging a certain class of customers for energy delivered over the past several years. Plaintiffs allege that NPC fraudulently placed its meters and measured energy delivered at a point prior to passing through transformers during which process a certain amount of energy is dissipated as heat, instead of placing the meters after they pass through the transformer. NPC's motion to dismiss on jurisdictional grounds was denied and NPC is filing a writ before the Nevada Supreme Court and is being joined in by the PUCN, which agrees with NPC that it has exclusive jurisdiction over the suit. NPC denies that the placement of the meters was fraudulent and alleges that placement of the meters was mandated by either or both customer request or applicable tariff. On April 22, 2002, Reliant Energy Services, Inc. (Reliant), filed and served a cross-complaint against NPC and SPPC in the wholesale electricity antitrust cases, which was consolidated in the Superior Court of the State of California. Plaintiffs in that case seek damages and restitution from the named defendants for alleged fraud, misrepresentation, and anticompetitive conduct in manipulating the energy markets in California resulting in prices far in excess of what would otherwise have been a fair price to the plaintiff class in a 193 competitive market. Reliant filed cross-complaints against all energy suppliers selling energy in California who were not named as original defendants in the complaint, denying liability but alleging that if there is liability, it should be spread among all energy suppliers. The trial court has held all answers to cross-claims in abeyance until such time as it decides demurrers filed by all the defendants. On May 3, 2002 and July 3, 2002, respectively, Reliant Resources and IDACORP Energy, L.P. (Idaho) terminated their power deliveries to NPC. On May 20, 2002 and July 30, 2002, Reliant Resources and Idaho asserted claims for $25.6 million and $8.9 million, respectively, under the Western System Power Pool Agreement (WSPP) for liquidated damages under energy contracts that each company terminated before the delivery dates of the power. Such claims are subject to mandatory mediation and, in some cases, arbitration under the contracts. To date only Idaho has requested mediation of the contracts, which should be completed by the end of second quarter. SPPC alleges that Idaho and Reliant Resources were participants in market manipulation in the West and therefore are not entitled to termination payments under the contract. In August 2002, El Paso Merchant Energy (EPME) terminated contracts for energy it had delivered to NPC under a program that called for delayed payment of the full contract price. In October 2002, EPME asserted a claim against NPC for $19 million in damages representing the approximate amount unpaid under the contracts. NPC alleges that EPME's termination resulted in net payments due to NPC under the WSPP liquidated damages provision as and for liquidated damages measured by the difference between the contract price and market price of energy EPME was to deliver from 2004 to 2012. Both claims are subject to mandatory mediation under the WSPP, but neither party has requested mediation at the present time. In connection with claims by their terminated energy suppliers, the Utilities established reserves, included in their Consolidated Balance Sheets in "Contract termination reserves," totaling approximately $313 million, and pursuant to the deferred energy accounting provisions of AB 369, NPC and SPPC added approximately $228 million and $82 million, respectively, to their deferred energy balances for recovery in rates in future periods. 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, results of operations, or cash flows. See Notes 3, 5, 6, 7, 8, 9, 12, and 14 for additional commitments and contingencies. 194 NOTE 18. 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 and natural gas service. Electric service is provided to Las Vegas and surrounding Clark County, northern Nevada and the Lake Tahoe area of California. Natural gas services are provided in the Reno-Sparks area of Nevada. Other segment information includes segments below the quantitative threshold for separate disclosure. The net assets and operating results of SPPC's water business, divested in 2001, has been reported as discontinued operations in the financial statements for 2001 and 2000. 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. Inter-segment revenues are not material.
Reconciling December 31, 2002 NPC Electric SPPC Electric Total Electric Gas All Other Eliminations Consolidated - ----------------- ------------ ------------- -------------- -------- -------- ------------ ------------ Operating revenues $ 1,901,034 $ 931,251 $ 2,832,285 $149,783 $ 9,635 $2,991,703 Operating income (loss) (104,003) 49,944 (54,059) 5,348 15,655 -- (33,056) Operating income taxes (133,411) (7,236) (140,647) 314 (28,165) (168,498) Depreciation 98,198 70,190 168,388 6,183 1,211 175,782 Interest expense on long-term debt 98,886 62,004 160,890 4,470 69,182 234,542 Assets 4,068,522 2,064,749 6,133,271 208,752 429,232 124,989 6,896,244 Capital expenditures 294,480 90,343 384,823 14,984 -- 399,807
Reconciling December 31, 2001 NPC Electric SPPC Electric Total Electric Gas All Other Eliminations Consolidated - ----------------- ------------ ------------- -------------- --------- --------- ------------ ------------ Operating revenues $ 3,025,103 $ 1,401,778 $ 4,426,881 $ 145,652 $ 18,841 $4,591,374 Operating income (loss) 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 66,393 159,494 5,710 1,181 166,385 Interest expense on long term debt 81,599 50,071 131,670 5,128 51,572 188,370 Assets 4,704,606 2,357,548 7,062,154 264,108 580,494 85,320 7,992,076 Capital expenditures 200,852 116,713 317,565 16,041 -- 333,606
Reconciling December 31, 2000 NPC Electric SPPC Electric Total Electric Gas All Other Eliminations Consolidated - ----------------- ------------ ------------- -------------- --------- --------- ------------ ----------- Operating revenues $ 1,326,192 $ 894,919 $ 2,221,111 $ 100,803 $ 14,199 $ 2,336,113 Operating income 74,182 31,989 106,171 13,420 6,794 126,385 Operating income taxes (12,162) (3,944) (16,106) 3,272 (18,188) (31,022) Depreciation 85,989 66,655 152,644 4,975 696 158,315 Interest expense on long term debt 64,513 23,435 87,948 4,318 42,330 134,596 Assets 3,407,751 1,722,725 5,130,476 151,905 61,768 333,759 5,677,908 Capital expenditures 204,505 117,785 322,290 14,490 23,350 360,130
195 The reconciliation of Capital expenditures for 2000 represents capital expenditures of the discontinued water business. The reconciliation of segment assets at December 31, 2002, 2001, and 2000 to the consolidated total includes the following unallocated amounts:
2002 2001 2000 -------- -------- -------- Other property $ -- $ -- $ 1,998 Cash 98,515 11,772 5,348 Current assets- other 50,862 29,852 Other regulatory assets 24,555 22,626 33,315 Net assets - discontinued operations -- -- 261,479 Deferred charges- other 1,919 60 1,767 -------- -------- -------- $124,989 $ 85,320 $333,759 ======== ======== ========
NOTE 19. DERIVATIVES AND HEDGING ACTIVITIES (SPR, NPC, SPPC) 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, 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. However, 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. 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. On April 1, 2002, SPR paid $9.5 million to terminate an interest rate swap related to $200 million of SPR floating rate notes maturing April 20, 2003. At December 31, 2002, the fair value of the derivatives resulted in the recording of $30 million, $29 million and $1 million in risk management assets and $74 million, $30 million and $44 million in risk management liabilities in the Consolidated Balance Sheets of SPR, NPC and SPPC, respectively. Also, $45 million, $2 million and $43 million in net risk management regulatory assets were recorded in the Consolidated Balance Sheets of SPR, NPC, and SPPC, respectively at December 31, 2002. In addition, for the twelve months ended December 31, 2002, 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 196 settled or terminate. Accordingly, $7.3 million relating to SPR's terminated interest rate swap was reclassified into earnings during the twelve-month period ended December 31, 2002. The effects of the adoption of SFAS No. 133 on comprehensive income have been reported in the consolidated statements of comprehensive income. NOTE 20. CHANGE IN ACCOUNTING FOR GOODWILL (SPR, NPC, SPPC) SFAS No. 142, adopted by SPR, NPC and SPPC on January 1, 2002, changed the accounting for goodwill from an amortization method to one requiring at least an annual review for impairment. Upon adoption, SPR ceased amortizing goodwill. SPR's Consolidated Balance Sheet as of December 31, 2002, includes approximately $306 million of goodwill pertaining to regulated operations resulting from the July 28, 1999 merger between SPR and NPC, net of approximately $19.7 million of amortization that has been deferred as a regulatory asset. The PUCN stipulation approving the merger allows for future recovery of this goodwill in rates charged to customers of SPR's regulated utility subsidiaries, NPC and SPPC, provided that NPC and SPPC demonstrate that merger savings exceed merger costs. The amount and timing of the recovery of this goodwill will be determined by the outcome of general rate cases expected to be filed by the Utilities with the PUCN in late 2003. For additional information, see Note 2, SPR and NPC Merger. SPR's Consolidated Balance Sheet as of December 31, 2001, included approximately $6.2 million of goodwill related to unregulated operations that are reported under the "All Other" segment in Note 18. SFAS No. 142 provides that an impairment loss shall be recognized if the carrying value of each reporting unit's goodwill exceeds its fair value. For purposes of testing goodwill for impairment, a discounted cash flow model was used to determine the fair value of each reporting unit of SPR's unregulated operations. The reporting units included in SPR's unregulated operations evaluated for goodwill impairment were LOS, SPC, TGPC, and "Energy" (a reporting unit consisting of Sierra Energy Company dba e-three and Sierra Pacific Energy Company). As a result of the impairment testing, which included revenue forecasts and appraisal of assets, SPR recorded a transitional goodwill impairment charge of approximately $1.7 million ($1.6 million, net of applicable taxes) as a cumulative effect of a change in accounting principle on SPR's Consolidated Statements of Operations for the twelve months ended December 31, 2002. The goodwill impairment recognized by reporting unit was approximately $131,000, $40,000 and $1.5 million for LOS, SPC and "Energy," respectively. Goodwill assigned to TGPC was determined not to be impaired. The changes in the carrying amount of goodwill for the twelve-month period ended December 31, 2002 are as follows:
REGULATED UNREGULATED (IN $000'S) OPERATIONS OPERATIONS TOTAL ---------- ----------- ----------- Balance as of January 1, 2002 $ 305,982 $ 6,163 $ 312,145 Impairment loss -- (1,704) (1,704) --------- --------- --------- Balance as of December 31, 2002 $ 305,982 $ 4,459 $ 310,441 ========= ========= =========
197 A reconciliation of SPR's previously reported net income (loss) and earnings (loss) per share to the amounts adjusted for the adoption of SFAS No. 142 net of the related income tax effect follows: (DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
YEAR ENDED DECEMBER 31, 2002 2001 2000 ----------- -------- -------- EARNINGS (LOSS): Applicable to Common Stock $ (307,521) $ 56,733 $(39,780) Add back amortization of goodwill, net of tax -- 137 142 ----------- -------- -------- As adjusted (307,521) 56,870 (39,638) Add back cumulative effect of change in accounting principle, net of tax 1,566 -- -- ----------- -------- -------- As adjusted before cumulative effect of change in accounting principle $ (305,955) $ 56,870 $(39,638) =========== ======== ======== BASIC AND DILUTED EARNINGS (LOSS) PER SHARE: As reported $ (3.01) $ 0.65 $ (0.51) Add back amortization of goodwill, net of tax -- -- -- ----------- -------- -------- As adjusted (3.01) 0.65 (0.51) Add back cumulative effect of change in accounting principle, net of tax 0.01 -- -- ----------- -------- -------- As adjusted before cumulative effect of change in accounting principle $ (3.00) $ 0.65 $ (0.51) =========== ======== ========
NOTE 21. PINON PINE (SPR, SPPC) 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 Section 29 of the Internal Revenue Code. The entire project, which includes an LLC-owned gasifier, an SPPC-owned combined cycle generation facility and a 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 was co-funded by the Department of Energy (DOE) under an agreement between SPPC and DOE that expired December 31, 2000. The DOE funded approximately $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 $100 million as of December 31, 2002. To date, SPPC has not been successful in obtaining sustained operation of the gasifier. In 2001, SPPC retained an independent engineering consulting firm, to complete a comprehensive study of the Pinon Pine gasification plant. The scope of the study included evaluation of the potential modifications required to make the facility operational and reliable using several technology scenarios. The evaluation of each scenario included an estimate of the additional capital expenditures necessary for reliable operation of the facility, and the risks associated with that technology. 198 SPPC received a final report of the study in November 2002. The results of the study identified a number of potential modifications to the facility each with varying degrees of technical risk and cost. Modifications considered to provide the highest probability for successful operation of the facility generally were also estimated to be the highest cost options. SPPC is reviewing the various options outlined in the study. If after evaluating the options presented in the draft report, SPPC decides not to pursue modifications intended to make the facility operational, SPPC intends to seek recovery, net of salvage, through regulated rates in its next general rate case based, in part, on the PUCN's approval of Pinon Pine as a demonstration project in an earlier resource plan. However, 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 22. SUBSEQUENT EVENTS See Notes 1, 3, 7, 8, 9, 16 and 17 for discussion of events occurring after December 31, 2002. 199 NOTE 23. 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, 2002 June 30, 2002 September 30, 2002 December 31, 2002 -------------- ------------- ------------------ ----------------- Operating Revenues $ 638,864 $ 701,313 $ 1,020,716 $ 630,810 =========== =========== =========== ========= Operating Income (loss) $ (230,751) $ 19,899 $ 143,327 $ 34,469 =========== =========== =========== ========= Earnings (deficit) applicable to common shareholders $ (305,482) $ (41,916) $ 79,374 $ (39,497) =========== =========== =========== ========= Earnings (deficit) per share-Basic and Diluted: From continuing operations $ (2.97) $ (0.41) $ 0.78 $ (0.39) Cumulative effect of change in accounting principle (0.01) -- -- -- ----------- ----------- ----------- --------- Earnings (deficit) applicable to common shareholders $ (2.98) $ (0.41) $ 0.78 $ (0.39) =========== =========== =========== =========
Quarter Ended ----------------------------------------------------------------------- March 31, 2001 June 30, 2001 September 30, 2001 December 31, 2001 -------------- ------------- ------------------ ----------------- Operating Revenues $ 738,809 $1,156,178 $1,972,427 $ 723,960 ========== ========== ========== ========== Operating Income (loss) $ (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 from disposal of water business -- 25,845 -- -- ---------- ---------- ---------- ---------- Earnings (deficit) applicable to common shareholders $ (83,479) $ 54,035 $ 80,409 $ 5,768 ========== ========== ========== ========== Earnings (deficit) per share-Basic and Diluted: From continuing operations $ (1.07) $ 0.35 $ 0.89 $ 0.06 From discontinued operations 0.01 0.01 -- -- From disposal of water business -- 0.33 -- -- ---------- ---------- ---------- ---------- Earnings (deficit) applicable to common shareholders $ (1.06) $ 0.69 $ 0.89 $ 0.06 ========== ========== ========== ==========
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None 200 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, 2002. There are no family relationships among them. Directors serve three-year terms with three (or four) terms of office expiring at each Annual Meeting, or until their successors have been elected and qualified. DIRECTORS WHOSE TERMS EXPIRE IN 2003: Edward P. Bliss, 70 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, 65 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, 53 Senior Partner of 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, 64 Chief Executive Officer of Terrible Herbst, Inc., a gas station, car wash, convenience store chain and Herbst Supply Co., Inc., a wholesale fuel distributor, both 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 TERM EXPIRES IN 2004: James R. Donnelley, 67 Partner, Stet and Query, Ltd., since June 2000. He is retired from R.R. Donnelley & Sons Company since June 2000, where he served as Vice Chairman of the Board from July 1990 to June 2000 and as a Director of 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. 201 Walter M. Higgins, 58 Chairman, President and Chief Executive Officer of SPR and Director and Chief Executive Officer of NPC and SPPC since August 2000. Mr. Higgins served as Chairman, President and Chief Executive Officer of AGL Resources, Inc., from February 1998 to August 2000. He was Chairman, President and Chief Executive Officer of SPR from January 1994 to January 1998. He also served as President and Chief Operating Officer of Louisville Gas and Electric Company from 1991 to November 1993. He is also a director of AEGIS Insurance Services, Inc., NEETF and American Gas Association. John F. O'Reilly, 57 Chairman and Chief Executive Officer of the law firm of O'Reilly and Ferrario. He is also Chairman and Chief Executive Officer of Business Resource Group, the O'Reilly Gaming Group and related family owned business entities. Mr. O'Reilly is a member of the Community Board of Directors of Wells Fargo Bank Nevada, N.A., a member of the Advisory Council of the UNLV International Gaming Institute, and a member of the UNLV Foundation Board. Mr. O'Reilly is also a member of the Las Vegas Chamber of Commerce Government Affairs Committee, a Board member and Secretary of United Way of Southern Nevada, a Board member of the Nevada Development Authority, Chairman and Chief Executive Officer of Vision 2020. . . TODAY!, Inc., and is a member of the Board of Trustees of Loyola Marymount University in Los Angeles, California. Mr. O'Reilly has served as a Director of NPC since 1995, and was elected a Director of SPR and SPPC in July 1999. DIRECTORS WHOSE TERM EXPIRES IN 2006: Krestine M. Corbin, 65 President and Chief Executive Officer of Sierra Machinery, Incorporated, since 1984 and a director of that company since 1980. 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. Clyde T. Turner, 65 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, SPPC, and NPC in November 2001. Dennis E. Wheeler, 60 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. Messrs. Day and Higgins are Directors of Tuscarora Gas Pipeline Company; Mr. Higgins is a Director of Lands of Sierra, Inc., Sierra Pacific Communications, Sierra Water Development Company, Sierra Gas Holdings Company, Pinon Pine Corp., Pinon Pine Investment Co., and GPSF-B. All of the above-listed companies are subsidiaries of Sierra Pacific Resources, with the exception of Pinon Pine Corp., Pinon Pine Investment Co., and GPSF-B, which are subsidiaries of Sierra Pacific Power Company. 202 (b) EXECUTIVE OFFICERS The following are current executive officers of the companies indicated and their ages as of December 31, 2002. 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, 58, Chairman, President and Chief Executive Officer, Sierra Pacific Resources See above description under Item 10(a), "Directors." Michael W. Yackira, 51, Executive Vice President, Strategy and Policy, Sierra Pacific Resources Mr. Yackira was elected to his position in January 2003. Previously he was the Vice President and CFO of Mars, Inc. from 2001 to 2002. Prior to that, he was with Florida-based FPL Group, Inc. from 1989 to 2000. His positions during that span included President of FPL Energy, Vice President-Finance and CFO of FPL Group, Senior Vice President-Finance and CFO of Florida Power & Light Co., and Senior Vice President of Corporate Planning and Development. Positions in other industries include GTE Corporation and St. Joe Petroleum, Inc. Mr. Yackira is a certified public accountant. Donald L. "Pat" Shalmy, 61, President, Nevada Power Company Mr. Shalmy was elected to his present position in July 2002. He was previously Senior Vice President, NPC since May 2002. Formerly he held the position of Director, Government and Community Relations at Kummer, Kaempfer, Bonner & Renshaw Ltd. He was formerly President of the Las Vegas Chamber of Commerce from 1997 to 2001. From 1979 to 1997 he held various positions with Clark County, Nevada, including Director of Comprehensive Planning and County Manager. Jeffrey L. Ceccarelli, 47, 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. C. Stanley Hunterton, 54, Senior Vice President, General Counsel and Corporate Secretary, Sierra Pacific Resources Mr. Hunterton was elected to his present position in September 2002, and holds the same positions with SPPC and NPC. He continues to serve as a partner at the law firm of Hunterton & Associates in Las Vegas, Nevada, formed in 1986, handling complex civil litigation. Formerly he held the position of Special Attorney, US Department of Justice, Organized Crime and Racketeering Section, Detroit Strike Force and Las Vegas Strike Force. John F. Young, 46, Senior Vice President, Energy Supply, Sierra Pacific Power Company and Nevada Power Company Mr. Young resigned effective February 28, 2003. Mr. Young was elected to the Senior Vice President, Energy Supply position in July 2002. Previously he was President and Chief Executive Officer of Avalon Consulting, a firm specializing in the energy industry. Prior to that, he spent 17 years at Southern Company and its various utility affiliates in Georgia, Florida, Mississippi and Alabama, most recently as Executive Vice 203 President, Southern Generation. He held various other positions with Southern Company, including Vice President, Business Development, General Manager of Fuel Planning and Procurement, and Vice President, Investor Relations. Victor H. Pena, 54, Senior Vice President and Chief Administrative Officer, Sierra Pacific Resources Mr. Pena was elected to his current position in May 2001 and holds the same position at SPPC and NPC. From 1998 to his appointment at SPR, he held various executive positions at AGL Resources, Inc., in Atlanta, Georgia, including Vice President, Business Development, and Vice President, Financial Systems and Controller. Richard K. Atkinson, 50, Vice President and Chief Financial Officer, Sierra Pacific Resources Mr. Atkinson was elected to his present position in December 2002 and holds the same position with SPPC and NPC. He was previously Vice President, Treasurer, and Investor Relations Officer since May 2001. He was formerly Treasurer of SPR, SPPC and NPC since 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. John E. Brown, 52, Vice President and Controller, Sierra Pacific Resources Mr. Brown was elected to his current position in July 2002, and holds the same position at SPPC and NPC. He was formerly Controller since May 2001. 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. Richard J. Coyle, 35, Vice President and Chief Risk Officer, Sierra Pacific Resources Mr. Coyle was elected to his present position in July 2002, and holds the same position for SPPC and NPC. He was previously President and Managing Director of Sierra Energy Company and Sierra Pacific Communications since June 2001. Formerly he held the position of Executive Director, Marketing and Operations for Sierra Pacific Energy Company since June 1999. Mr. Coyle has been with NPC since 1994. Matt H. Davis, 46, Vice President, Distribution, Nevada Power Company Mr. Davis was elected to his present position in 2002. He previously held the position of Vice President, Distribution Services, at 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. Mary O. Simmons, 47, 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 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. 204 Michael R. Smart, 46, Vice President, Distribution Services, Sierra Pacific Power Company Mr. Smart was elected to his present position in July 2002. He was previously Vice President, Resource Management since May 2001, for both SPPC and NPC. 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. 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. Jane Crane, 52, Vice President, Human Resources, Sierra Pacific Power Company and Nevada Power Company Ms. Crane was elected to her present position in July 2002, acting as an outside consultant since April 2002, and joining the Company as Acting Vice President, Human Resources, in May 2002. Formerly she was a consultant in human resources management from April 2000 to April 2002. She previously held the position of Vice President, Human Resources, at ARCO Alaska, Inc. from March 1995 to March 2000. She held various other management positions at ARCO from 1980 to March 1995. Carol Marin, 51, 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 Utilities from August 1999 through 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. Julian C. "Jack" Leone, 65, Vice President, Marketing and Communications, Sierra Pacific Power Company and Nevada Power Company Mr. Leone was elected to his present position in June 2002. He previously held the position of Vice President of Marketing at Caesars Palace since March 2001. Previous to that, he spent two years as a member of Sitrick and Company, a public relations firm based in Los Angeles. From 1984 to 1999, he held a series of senior public relations and marketing positions in the gaming industry, including Caesars World, Inc., MGM Grand Hotel Casino, and Mandalay Bay Resort and Casino. Susan Brennan, 43, 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, for NPC. From 1992 to 1999, Ms. Brennan served in various financial and industry restructuring positions. Ms. Brennan has been with NPC for 10 years. Bob Werner, 65, Vice President, Generation, Sierra Pacific Power Company and Nevada Power Company Mr. Werner was elected to his present position in July 2002. He was a consultant to NPC from October 2001 until July 2002. From 1997 to 2001, he was previously self-employed as a Consulting Engineer working primarily in the areas of electric generation and coal technology. Prior to that, he held various technical and management positions at PacifiCorp. 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 205 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. 206 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 2002, and each of the four most highly compensated officers for services in all capacities to SPR and its subsidiaries. Also included are two individuals who, although not officers at the end of 2002, warranted inclusion due to compensation levels.
Annual Compensation ----------------------------------------- Other Annual Name and Principal Position Year Salary($) Bonus($) Compensation($) (a) (b) (c) (d) (e)(3) --------------------------- ---- --------- ---------- --------------- Walter M. Higgins 2002 $590,000 $ -- $ 98,254 Chairman of the Board, President, 2001 $590,000 $ -- $ 70,970 and Chief Executive Officer 2000 $215,151 $ -- $ 33,690 Mark A. Ruelle(1) 2002 $588,462 $ -- $ -- President, Nevada Power Company 2001 $280,962 $ -- $ 28,108 2000 $250,255 $ -- $ 15,967 Steven C. Oldham(2) 2002 $384,933 $ -- $ -- Senior Vice President, 2001 $219,039 $ -- $ -- Energy Supply 2000 $186,584 $ -- $ 13,750 Victor H. Pena 2002 $230,000 $ -- $ -- Senior Vice President, Chief 2001 $136,231 $ -- $ 5,600 Administrative Officer Jeffrey L. Ceccarelli 2002 $230,000 $ -- $ 35,417 President, Sierra Pacific 2001 $221,539 $ -- $ 13,712 Power Company 2000 $191,539 $ -- $ 19,320 Matt H. Davis 2002 $180,000 $ -- $ 18,367 Vice President, Distribution 2001 $171,539 $ -- $ 17,551 Services, Nevada Power Company 2000 $159,425 $ -- $ 21,017 Michael R. Smart 2002 $180,000 $ 26,376 Vice President, Distribution 2001 $171,116 $ -- $ 10,911 Services 2000 $139,877 $ 41,144 $ 8,239 Long-Term Compensation ---------------------------------------------------------- Awards Payout --------------------------- ---------------------------- Securities Underlying All Restricted Options/ SARs LTIP Other Name and Principal Position Stock Awards($) (#) Payouts($) Compensation($) (a) (f)(4) (g) (h)(5) (i)(6) --------------------------- -------------- ------------- ---------- --------------- Walter M. Higgins $ -- 123,900 $ -- $188,218 Chairman of the Board, President, $ -- 110,130 $ -- $614,129 and Chief Executive Officer $256,000 400,000 $ -- $411,758 Mark A. Ruelle(1) $ -- 45,000 $ -- $ 56,274 President, Nevada Power Company $ 62,080 66,520 $ -- $109,437 $ -- -- $ 59,357 $ 19,160 Steven C. Oldham(2) $ -- 27,000 $ -- $ 90,967 Senior Vice President, $ -- 20,800 $ -- $ 19,775 Energy Supply $ -- -- $ 36,527 $ 19,678 Victor H. Pena $ -- 25,880 $ -- $ 20,402 Senior Vice President, Chief $ 69,187 27,000 $ -- $ 57,696 Administrative Officer Jeffrey L. Ceccarelli $ -- 34,500 $ -- $ 21,999 President, Sierra Pacific $ -- 22,510 $ -- $ 19,429 Power Company $ -- -- $ 36,527 $ 16,781 Matt H. Davis $ -- 12,150 $ -- $ 20,404 Vice President, Distribution $ -- 10,200 $ -- $ 18,872 Services, Nevada Power Company $ -- -- $ 16,410 $ 16,562 Michael R. Smart $ -- 12,150 $ -- $137,676 Vice President, Distribution $ -- 9,540 $ -- $ 97,178 Services $ -- -- $ -- $ 16,520
(1) Mark A. Ruelle: o Mr. Ruelle was President of Nevada Power Company until May 2002; Mr. Shalmy was appointed to that position in July 2002. o Included in column (c) is a severance payment of $450,000, which represents 1.5 times his annual salary. (2) Steven C. Oldham: o Mr. Oldham was Senior Vice President of Energy Supply until his retirement in May 2002. Mr. Young was appointed to that position in July 2002. o Included in column (c) is a severance payment of $245,000, which represents one year annual salary. 207 (3) The table below shows those executive perquisites that exceed 25% of the total perquisites listed in column (e) for each named executive.
Walter M. Jeffrey L. Matt H. Michael R. Description Higgins Ceccarelli Davis Smart ----------- -------- ---------- ------- ---------- Cash in lieu of Forgone Vacation $50,831 $20,417 $ 8,252 $17,576 Tax, Memberships, Automobile & Other $30,000 $15,000 $10,088 $ 8,800
(4) Restricted Stock Grants: o As the result of a promotion in 2001, Mr. Ruelle was awarded a restricted grant of 4,000 shares with dividend equivalents. During 2002, after Mr. Ruelle's separation from SPR, this grant was forfeited, and has no value at December 31, 2002. o Upon his hire in 2001, Mr. Pena was awarded a grant of 4,300 restricted shares with dividend equivalents. At December 31, 2002, the value of the grant was $20,963 at $6.50 per share. The grant will vest over a four year period at 25% per year. In 2002, 1,075 shares from this grant were issued to Mr. Pena, in accordance with the vesting schedule; the year-end value is calculated for the remaining 3,225 shares. o In 2000, Mr. Higgins was awarded a restricted stock grant of 16,000 shares with dividend equivalents. At December 31, 2002, the value of the grant was $78,000 at $6.50 per share. The grant will vest over a four year period in the following manner: September 2002 4,000 shares September 2003 4,000 shares September 2004 8,000 shares In 2002, 4,000 shares from this grant were issued to Mr. Higgins, in accordance with the vesting schedule; the year-end value is calculated for the remaining 12,000 shares. (5) The Long-term incentive payouts for the three-year periods ended December 31, 2001 and 2002, have not been approved for payment by the SPR Board of Directors. (6) Amounts for All Other Compensation include the following for 2002:
--------------------------------------------------------------------------------------- Walter M. Mark A. Steven C. Victor H. Jeffrey L. Matt H. Michael R. Description Higgins Ruelle Oldham Pena Ceccarelli Davis Smart ----------- --------- -------- --------- --------- ---------- -------- ---------- Company contributions to the 401k deferred compensation plan $ 12,000 $ 9,278 $ 9,263 $ 12,000 $ 12,000 $ 11,295 $ 11,000 Company paid portion of Medical/Dental/Vision Benefits $ 8,088 $ 3,707 $ 3,370 $ 6,120 $ 8,088 $ 8,088 $ 8,088 Imputed income on group term life insurance premiums paid by SPR $ 3,612 $ 200 $ 366 $ 814 $ 531 $ 396 $ 396 Insurance premiums paid for executive term life policies $ 19,777 $ 731 $ 559 $ 1,468 $ 1,380 $ 625 $ 1,105 Moving Expense Reimbursement $ 36,997 $ 76,869 Taxable Interest/Refund of Deferred Contributions $ 26,908 $ 42,358 $ 47,309 $ 40,218 Salary bridge to retirement $ 30,100 Housing Allowance $ 80,836 Total $188,218 $ 56,274 $ 90,967 $ 20,402 $ 21,999 $ 20,404 $137,676
208 OPTIONS/SAR GRANTS IN LAST FISCAL YEAR The following table shows all grants of options to the named executive officers of SPR in 2002. Pursuant to Securities and Exchange Commission (SEC) rules, the table also shows the present value of the grant at the date of grant.
Number of Percent of Total Securities Options/SAR's Underlying Granted to Exercise of Options/SAR's Employees in Fiscal Base Price Grant Date Name Granted Year ($/share) Expiration Date Present Value (a) (b)(1) (c)(2) (d) (e) (f)(3) ---- ------------- ------------------ ----------- --------------- ------------- Walter M. Higgins 01/01/2002 Grant date 123,900 24.66% $ 15.58 01/01/2012 $1,079,840 Mark A. Ruelle 01/01/2002 Grant date 45,000 8.96% $ 15.58 01/01/2012 $ 392,194 Steven C. Oldham 01/01/2002 Grant date 27,000 5.37% $ 15.58 01/01/2012 $ 235,316 Victor H. Pena 01/01/2002 Grant date 25,880 5.15% $ 15.58 01/01/2012 $ 225,555 Jeffrey L. Ceccarelli 01/01/2002 Grant date 34,500 6.87% $ 15.58 01/01/2012 $ 300,682 Matt H. Davis 01/01/2002 Grant date 12,150 2.42% $ 15.58 01/01/2012 $ 105,892 Michael R. Smart 01/01/2002 Grant date 12,150 2.42% $ 15.58 01/01/2012 $ 105,892
1. Under the SPR executive long-term incentive plan, the 2002 grants of nonqualifying stock options were made on January 1, 2002. One-third of these grants vest annually commencing one year after the date of the grant. 2. The total number of nonqualifying stock options granted to all employees in 2002 was 502,380. 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 expected volatility (37.78%), risk free rate of return (5.52%), projected dividend yield (0.00%), 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. 209 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, 2002:
Shares Number of Securities Underlying Value of Unexercised Acquired on Value Unexercised Options/SARs at Fiscal in-the-money Options/SAR Name Exercise Realized Year-End at Fiscal Year-End (a) (b) (c) (d) (e) - --------------------- ----------- -------- ------------------------------------- ------------------------------------- Exercisable Unexercisable Exercisable Unexercisable ----------- ------------- ----------- ------------- Walter M. Higgins -- -- 236,706 397,324 $ -- $ -- Mark A. Ruelle -- -- -- -- $ -- $ -- Steven C. Oldham 44,787 44,300 $ -- $ -- Victor H. Pena -- -- 6,750 46,130 $ -- $ -- Jeffrey L. Ceccarelli -- -- 30,210 52,940 $ -- $ -- Matt H. Davis -- -- 18,187 22,383 $ -- $ -- Michael R. Smart -- -- 3,180 18,510 $ -- $ --
(e) Pre-tax gain. Value of in-the-money options based on December 31, 2002, closing trading price of $6.50, less the option exercise price. LONG-TERM INCENTIVE PLANS-AWARDS IN LAST FIVE YEARS The executive long-term incentive plan (LTIP) provides for the granting of stock options (both nonqualified and qualified), stock appreciation rights (SARs), restricted stock performance units, performance shares and bonus stock to participating employees as an incentive for outstanding performance. Incentive compensation is based on the achievement of pre-established financial goals for SPR. Goals are established for total shareholder return (TSR) compared against the Dow Jones Utility Index and annual growth in earnings per share (EPS). 210 The following table provides information as to the performance shares granted to the named executive officers of Sierra Pacific Resources in 2002. 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 of Estimated-Future Number of Other Period Share Payouts Under Non-Stock Shares, Units Until Price Based Plans (number of shares) or Other Maturation of ------------------------------------- Name Rights Payout Threshold Target Maximum (a) (b) (c) (d)(1) (e)(2) (f)(3) - --------------------- ------------- --------------- --------- ------- ------- Walter M. Higgins 23,650 3 years 11,825 23,650 41,388 Mark A. Ruelle 8,590 3 years 4,295 8,590 15,033 Steven C. Oldham 5,150 3 years 2,575 5,150 9,013 Victor H. Pena 4,940 3 years 2,470 4,940 8,645 Jeffrey L. Ceccarelli 6,590 3 years 3,295 6,590 11,533 Matt H. Davis 2,320 3 years 1,160 2,320 4,060 Michael R. Smart 2,320 3 years 1,160 2,320 4,060
All levels of awards are made with reference to the number of shares at the time of the grant, the percentages shown below, and the price of each performance share at the time of the grant was $15.58. 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. 211 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.
Highest Average Annual Benefits for Years of Service Indicated Five-Years ------------------------------------------------------------------------------------------------------ Remuneration 15 Years 20 Years 25 Years 30 Years 35 Years - --------------- -------- -------- -------- -------- -------- $ 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 6.5, Mr. Ruelle 5.8, Mr. Oldham 25.6, Mr. Pena 5.8, Mr. Ceccarelli 28.3 (maximum vesting is 25 years), Mr. Davis 24.5, and Mr. Smart 23.8. 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 9.1, Mr. Ruelle 5.8, Mr. Oldham 25.6, Mr. Pena 5.8, Mr. Ceccarelli 28.3 (maximum vesting is 25 years), Mr. Davis 24.5, and Mr. Smart 0.0. 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, 212 there is a termination of employment by SPR related to such change in control, or a termination of employment by the employee for good reason, in each case as described in the plans. In these circumstances, officers are entitled to a severance allowance not to exceed an amount equal to 36 months of the officer's base salary and any bonus and the continuation for up to 36 months of participation in SPR's group medical and life insurance plans. Change in control is defined in the plans as, among other things, a dissolution or liquidation, a reorganization, merger or consolidation in which SPR is not the surviving corporation, the sale of all or substantially all the assets of SPR (not the sale of a work unit) or the acquisition by any person or entity of 30% or more of the voting power of SPR. In addition, several merger-related and merger-conditioned severance arrangements have been entered into between SPR and several executives, which are described in Item 13, Certain Relationships and Related Transactions. 213 ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT Voting Stock The following table indicates the shares owned by Putnam Investments, the only investor known to Sierra Pacific Resources to be owners of more than 5 percent of any class of its voting stock as of March 11, 2003.
NAME AND ADDRESS OF SHARES BENEFICIALLY TITLE OF CLASS BENEFICIAL OWNER OWNED PERCENT OF CLASS - -------------- ------------------- ------------------- ---------------- Common Stock Putnam Investments 10,379,669 8.86% One Post Office Square Boston, Ma. 02109
The table below sets forth the shares of Sierra Pacific Resources Common Stock beneficially owned by each director, nominee for director, the Chief Executive Officer, and the four other most highly compensated executive officers. No director, nominee for director or executive officer owns, nor do the directors and executive officers as a group own, in excess of one percent of the outstanding Common Stock of SPR. Unless otherwise indicated, all persons named in the table have sole voting and investment power with respect to the shares shown.
COMMON SHARES BENEFICIALLY PERCENT OF TOTAL COMMON OWNED AS OF SHARES OUTSTANDING AS OF NAME OF DIRECTOR OR NOMINEE MARCH 19, 2003 MARCH 19, 2003 - --------------------------- -------------- --------------------------- Edward P. Bliss 33,281 Mary L. Coleman 153,061 Krestine M. Corbin 26,015 Theodore J. Day 38,725 No director or nominee James R. Donnelley 41,336 for director owns in excess Jerry E. Herbst 17,888 of one percent. Walter M. Higgins 290,981 John F. O'Reilly 18,544 Clyde T. Turner 0 Dennis E. Wheeler 23,644 ---------- (d) 643,475 ==========
COMMON SHARES BENEFICIALLY PERCENT OF TOTAL COMMON OWNED AS OF SHARES OUTSTANDING AS OF EXECUTIVE OFFICERS MARCH 19, 2003 MARCH 19, 2003 - ----------------------- -------------- -------------------------- Walter M. Higgins 290,981 Mark A. Ruelle(1) 0 No executive officer owns Steven C. Oldham(2) 89,087 In excess of one percent Victor H. Pena 29,124 Jeffrey L. Ceccarelli 98,149 Matt H. Davis 50,178 Michael R. Smart 28,908 --------- 586,427 ========= All directors and executive officers as a group(a)(b)(c) 1,159,406 =========
214 (1) Mr. Ruelle was President of Nevada Power until the appointment of Mr. Donald L. Shalmy to that position in May 2002. (2) Mr. Oldham was Senior Vice President, Energy Supply of Sierra Pacific Resources until he left the Company in May 2002. (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 under the Executive Long-Term Incentive Plan. Shares beneficially owned pursuant to stock options granted to Messrs. Higgins, Ruelle, Oldham, Pena, Ceccarelli, Davis, Smart and directors and executive officers as a group are 234,030, 0, 89,087, 25,880, 83,150, 40,750, 21,690 shares, and 677,865 respectively. (c) Included in the shares beneficially owned by the Directors are 81,464 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. William E. Peterson became Senior Vice President and General Counsel for Sierra Pacific Resources in 1993 and retired from SPR in October 2002. Following his retirement, Mr. Peterson became associated with Woodburn and Wedge, a law firm in Reno, Nevada in which Mr. Peterson had been a partner until 1993 and at which he performed legal work for SPR and SPPC for 18 years prior to his employment by SPR. Woodburn and Wedge has performed legal services for SPPC since 1920, for NPC since 1999, and for SPR and all of its other subsidiaries from their inception, and continues to perform legal work for SPR. Mr. Peterson's wife, an equity partner in the firm since 1982, has performed work for SPR since 1976 and continues to do so from time to time. In order to facilitate Mr. Hunterton's transition to Mr. Peterson's position and to protect SPR's legal interests during the transition, Mr. Peterson agreed to perform legal work on an as-needed basis from the date of his retirement until the end of the year. Mr. Peterson also agreed to perform a minimum number of hours of legal services for SPR during each of the next three years at his customary hourly rates, subject to satisfactory and timely performance by him within accepted standards of professional practice. In May 2002, SPR entered into severance and release agreement with four executive officers, including Steve C. Oldham, Senior Vice President, Energy Supply, Douglas R. Ponn, Vice President, Public Policy, Paul Heagen, Vice President, Marketing and Communications, for SPPC and NPC, and Mark A. Ruelle, President of NPC. Under the terms of these agreements, each executive officer received approximately 12 months pay, except in the case of Mr. Ruelle, who received 1.5 times his annual salary, all payable in installments over one year. In addition, each executive officer received continued medical and health coverage under SPR plans at SPR's expense until each became reemployed and obtained comparable coverage, and in the case of Mr. Oldham, an additional payment that was intended to bridge retirement pay until he attains his early retirement age (age 55). SPR also retained Mr. Ponn, formerly head of SPR's legislative effort, to assist SPR through the January to May 2003 legislative session. CHANGE IN CONTROL AGREEMENTS SPR has entered into change in control severance agreements with its executive staff, including Walter M. Higgins, Jeffrey L. Ceccarelli, Victor H. Pena, Mary O. Simmons, Susan Brennan, Carol Marin, Richard K. Atkinson, John Brown, Michael R. Smart, Matt H. Davis, Donald L. Shalmy, Julian C. Leone, Michael Yackira, Richard J. Coyle, Bob Werner, and Jane Crane. These agreements expire on December 31, 2004, and provide that, upon termination of the executive's employment during the term of the Agreement (subject to an extension in the event a Potential Change in Control, as defined in the agreement, occurs during the term) 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 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), the executive will 215 receive certain payments and benefits. These severance payments and benefits include (i) a lump sum payment equal to two or, with respect to certain senior officers, 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, except with respect to Mr. Higgins, whose agreement is described in the Employment Agreements section below. The agreements also provide that if any compensation paid, or benefit provided, to the executive, whether or not 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 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. 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 replicated Mr. Higgins' compensation and benefits package provided by his previous employer, AGL Resources, and made him whole for benefits and compensation lost, forgone, or otherwise forfeited as a result of his accepting employment with SPR. The Board of Directors 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 Stockholders at 140%. For the reasons expressed above in connection with the officer group as a whole, Mr. Higgins received no annual incentive or long-term payments for 2002. As part of his employment agreement, 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, five 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. Mr. Higgins is 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 and full vesting in SPR's SERP calculated as though he were age 62 (retirement age). In the event of a termination resulting from 216 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 includes (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) with in a two-year period, a majority of the Directors of SPR at the beginning of such period cease to be directors; (v) the Stockholders of SPR approve a complete liquidation or dissolution of SPR; or (vi) there is consummated a sale of a majority of the stock, or sale of substantially all assets, or complete liquidation or dissolution of either SPPC or NPC. In addition, in connection with SPR's family relocation policy, SPR made a cash equity advance of $800,000 to Mr. Higgins in 2002 to facilitate the permanent location of Mr. Higgins and relocation of his family in Las Vegas while his principal residence was being sold. Mr. Higgins repaid the equity advance in its entirety in 2002 when his prior residence was sold. AFFILIATE TRANSACTIONS AND RELATIONSHIPS Employees of SPR provide certain accounting, treasury, information technology and administrative services to NPC and SPPC. The costs of those services are allocated among the three Utilities according to each Utility's usage. Additionally, many of SPR's officers are also officers of NPC and SPPC. All three companies have the same members of their respective boards of directors. SPR files a consolidated federal income tax return for itself and its subsidiaries. Current income taxes are allocated based on each entity's respective taxable income or loss and investment tax credits as if each subsidiary filed a separate return. SPR does not believe that any significant additional tax liability would be incurred by any of its subsidiaries on behalf of any other subsidiary; however, SPR and its subsidiaries could potentially incur certain tax liabilities as a result of the joint tax filing in the event of a change in applicable law or as a result of an audit. As part of their on-going cash management practices and operations, SPR may make intercompany loans to the Utilities and/or the Utilities may make intercompany loans to each other, subject to any applicable regulatory restrictions. 217 ITEM 14. CONTROLS AND PROCEDURES SPR, NPC, and SPPC maintain disclosure controls and procedures as defined in Rules 13a-14(c) and 15d-14(c) under the Securities Exchange Act of 1934, as amended (the Exchange Act) designed to ensure that they are able to collect the information required to be disclosed in the reports they file with the Securities and Exchange Commission (SEC), and to process, summarize and disclose this information accurately and within the time periods specified in the rules of the SEC. The chief executive officer and chief financial officer of each of SPR, NPC, and SPPC have reviewed and evaluated SPR's, NPC's and SPPC's disclosure controls and procedures as of a date within 90 days prior to the filing date of this report (the Evaluation Date). Based on such evaluation, such officers have concluded that, as of the Evaluation Date, the disclosure controls and procedures of SPR, NPC, and SPPC are effective in bringing to their attention on a timely basis material information relating to SPR, NPC, and SPPC required to be included in periodic filings under the Exchange Act. Since the Evaluation Date, there have not been any significant changes in the internal controls of SPR, NPC, and SPPC, or in other factors that could significantly affect these controls subsequent to the Evaluation Date. 218 PART IV ITEM 15. 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......................................................................118 Consolidated Balance Sheets as of December 31, 2002 and 2001.......................................121 Consolidated Statements of Operations for the Years Ended December 31, 2002, 2001 and 2000.............................................................................122 Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2002, 2001 and 2000................................................................123 Consolidated Statements of Common Shareholders' Equity for the Years Ended December 31, 2002, 2001 and 2000....................................................124 Consolidated Statements of Cash Flows for the Years Ended December 31, 2002, 2001 and 2000................................................................125 Consolidated Statements of Capitalization as of December 31, 2002 and 2001.........................126 Consolidated Balance Sheets for Nevada Power Company as of December 31, 2002 and 2001......................................................................128 Consolidated Statements of Operations for Nevada Power Company for the Years Ended December 31, 2002, 2001 and 2000............................................129 Consolidated Statements of Comprehensive Income (Loss) for Nevada Power Company for the Years Ended December 31, 2002, 2001 and 2000....................................130 Consolidated Statements of Common Shareholder's Equity for Nevada Power Company for the Years Ended December 31, 2002, 2001 and 2000............................................131 Consolidated Statements of Cash Flows for Nevada Power Company for the Years Ended December 31, 2002, 2001 and 2000............................................132 Consolidated Statements of Capitalization for Nevada Power Company as of December 31, 2002 and 2001.........................................................133 Consolidated Balance Sheets for Sierra Pacific Power Company as of December 31, 2002 and 2001......................................................................134 Consolidated Statements of Operations for Sierra Pacific Power Company for the Years Ended December 31, 2002, 2001 and 2000............................................135 Consolidated Statements of Comprehensive Income (Loss) for Sierra Pacific Power Company for the Years Ended December 31, 2002, 2001 and 2000....................................136 Consolidated Statements of Common Shareholder's Equity for Sierra Pacific Power Company for the Years Ended December 31, 2002, 2001 and 2000..............................137 Consolidated Statements of Cash Flows for Sierra Pacific Power Company for the Years Ended December 31, 2002, 2001 and 2000............................................138 Consolidated Statements of Capitalization for Sierra Pacific Power Company as of December 31, 2002 and 2001.........................................................139 Notes to Financial Statements......................................................................140 2. Financial Statement Schedules: Schedule II - Consolidated Valuation and Qualifying Accounts.....................225-226
219 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 227-244. (b) Reports on Form 8-K: Form 8-K dated October 4, 2002, filed by SPR and NPC - Item 5, Other Events Disclosed that, in connection with a private placement of long-term debt, NPC had prepared an Offering Memorandum for distribution to the potential purchasers. Excerpts from the Offering Memorandum were included as an exhibit. Form 8-K dated October 25, 2002, filed by SPR and NPC - Item 5, Other Events Disclosed that, in connection with a private placement of long-term debt, NPC had prepared an Offering Memorandum for distribution to the potential purchasers. Excerpts from the Offering Memorandum were included as an exhibit. Form 8-K dated October 30, 2002, filed by SPR, NPC, and SPPC - Item 5, Other Events Disclosed, and included as an exhibit, NPC's press release dated October 30, 2002, announcing that it had paid in full those power suppliers who earlier had accepted extended payment terms for summer power supplies. Additionally, NPC disclosed that it had refinanced maturing bank debt and secured an accounts receivable purchase facility providing additional liquidity. Also separately disclosed, and included as an exhibit, SPPC's press release dated October 31, 2002, announcing that it had refinanced maturing bank debt and secured an accounts receivable purchase facility providing additional liquidity. Form 8-K dated November 14, 2002, filed by SPR, NPC, and SPPC - Item 5, Other Events Disclosed that, on November 14, 2002, the federal bankruptcy court judge overseeing the bankruptcy case of Enron Power Marketing, Inc. (Enron) had rendered an oral decision relating to a motion filed by the Utilities in connection with the lawsuit filed by Enron in its bankruptcy case asserting claims for damages related to the termination of its power supply agreements with the Utilities. Form 8-K dated December 19, 2002, filed by SPR, NPC, and SPPC - Item 5, Other Events Disclosed that, on December 19, 2002, the FERC Administrative Law Judge (ALJ) issued an order dismissing complaints filed by the Utilities against nine of their major electric energy suppliers under section 206 of the Federal Power Act, and the Utilities' plan to file a brief with the full FERC taking exception to the ALJ's findings. Also separately disclosed that, on December 19, 2002, the federal bankruptcy court judge overseeing the bankruptcy case of Enron had rendered a decision in the lawsuit filed by Enron in its bankruptcy case asserting claims for damages related to the termination of its power supply agreements with the Utilities. 220 Form 8-K dated December 30, 2002, filed by SPR, NPC, and SPPC - Item 5, Other Events Disclosed, and included as an exhibit, SPR's press release dated December 30, 2002, announcing that Richard K. Atkinson had been named vice president and chief financial officer of the corporation succeeding Dennis D. Schiffel as chief financial officer. 221 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 27, 2003 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 27th day of March, 2003. /s/ Richard Atkinson /s/ John Brown - -------------------------------------- ------------------------------------ Richard K. Atkinson John E. Brown Vice President, Vice President, Chief Financial Officer Controller (Principal Financial Officer) (Principal Accounting Officer) /s/ Edward P. Bliss /s/ Jerry E. Herbst - -------------------------------------- ------------------------------------ Edward P. Bliss Jerry E. Herbst Director Director /s/ Mary Lee Coleman /s/ John F. O'Reilly - -------------------------------------- ------------------------------------ Mary Lee Coleman John F. O'Reilly Director Director /s/ Krestine M. Corbin /s/ Clyde T. Turner - -------------------------------------- ------------------------------------ Krestine M. Corbin Clyde T. Turner Director Director /s/ Theodore J. Day /s/ Dennis E. Wheeler - -------------------------------------- ------------------------------------ Theodore J. Day Dennis E. Wheeler Director Director /s/ James R. Donnelley - -------------------------------------- James R. Donnelley Director 222 ANNUAL CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER REQUIRED BY SECTION 302(A) OF THE SARBANES-OXLEY ACT OF 2002 I, Walter M. Higgins III, certify that: 1. I have reviewed the combined annual report on Form 10K of Sierra Pacific Resources, Nevada Power Company and Sierra Pacific Power Company; 2. Based on my knowledge, the combined annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by the combined annual report; 3. Based on my knowledge, the financial statements, and other financial information included in the combined annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrants as of, and for, the periods presented in the combined annual report; 4. The chief financial officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrants and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrants, including their consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which the combined annual report is being prepared; b) evaluated the effectiveness of the registrants' disclosure controls and procedures as of a date within 90 days prior to the filing date of the combined annual report (the "Evaluation Date"); and c) presented in the combined annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The chief financial officer and I have disclosed, based on our most recent evaluation, to the registrants' auditors and the audit committee of registrants' board of directors: a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrants' ability to record, process, summarize and report financial data and have identified for the registrants' auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrants' internal controls; and 6. The chief financial officer and I have indicated in this combined annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. March 28, 2003 /s/ Walter M. Higgins, III -------------------------- Walter M. Higgins III Chief Executive Officer 223 ANNUAL CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER REQUIRED BY SECTION 302(A) OF THE SARBANES-OXLEY ACT OF 2002 I, Richard K. Atkinson, certify that: 1. I have reviewed the combined annual report on Form 10K of Sierra Pacific Resources, Nevada Power Company and Sierra Pacific Power Company; 2. Based on my knowledge, the combined annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by the combined annual report; 3. Based on my knowledge, the financial statements, and other financial information included in the combined annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrants as of, and for, the periods presented in the combined annual report; 4. The chief executive officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrants and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrants, including their consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which the combined annual report is being prepared; b) evaluated the effectiveness of the registrants' disclosure controls and procedures as of a date within 90 days prior to the filing date of the combined annual report (the "Evaluation Date"); and c) presented in the combined annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The chief executive officer and I have disclosed, based on our most recent evaluation, to the registrants' auditors and the audit committee of registrants' board of directors: a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrants' ability to record, process, summarize and report financial data and have identified for the registrants' auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrants' internal controls; and 6. The chief executive officer and I have indicated in this combined annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. March 28, 2003 /s/ Richard K. Atkinson ----------------------- Richard K. Atkinson Chief Financial Officer 224 SIERRA PACIFIC RESOURCES SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000 (DOLLARS IN THOUSANDS)
Provision for Uncollectible Accounts ------------- 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 ======== Balance at January 1, 2002 39,335 Provision charged to income 16,814 Amounts written off, less recoveries (11,965) -------- Balance at December 31, 2002 $ 44,184 ========
NEVADA POWER COMPANY SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000 (DOLLARS IN THOUSANDS)
Provision for Uncollectible Accounts ------------- 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 ======== Balance at January 1, 2002 30,861 Provision charged to income 12,107 Amounts written off, less recoveries (9,127) -------- Balance at December 31, 2002 $ 33,841 ========
225 SIERRA PACIFIC POWER COMPANY SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000 (DOLLARS IN THOUSANDS)
Provision for Uncollectible Accounts ------------- 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 ======== Balance at January 1, 2002 8,474 Provision charged to income 4,707 Amounts written off, less recoveries (2,838) -------- Balance at December 31, 2002 $ 10,343 ========
(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. 226 2002 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 o 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). o *(A) By-laws of Sierra Pacific Resources as amended through August 14, 2002. NEVADA POWER COMPANY o 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). o 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 o 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). o 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). o 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). o 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). o 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). o 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). 227 o 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). o 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 o 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). o Purchase 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). o Corporate PIES Certificate (filed as Exhibit 4.4 to Form 8-K dated November 16, 2001). o Treasury PIES Certificate (filed as Exhibit 4.5 to Form 8-K dated November 16, 2001). o 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). o 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). o 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). o Global 8-3/4% Note due 2005 (filed as Exhibit 4.2 to Form 8-K dated May 22, 2000). o 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). o 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). o 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). o 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). o 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). 228 NEVADA POWER COMPANY o 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). o 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). o 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). o 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). o 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 (filed as Exhibit 4(A) to Form 10-K for the year ended December 30, 2001). o Officer's Certificate establishing the terms of Nevada Power Company's General and Refunding Mortgage Notes, Floating Rate, Series B, due October 15, 2003 (filed as Exhibit 4(B) to Form 10-K for the year ended December 30, 2001). o Form of Nevada Power Company's General and Refunding Mortgage Notes, Floating Rate, Series B, due October 15, 2003 (filed as Exhibit 4(C) to Form 10-K for the year ended December 30, 2001). o Officer's Certificate establishing the terms of Nevada Power Company's General and Refunding Mortgage Bonds, Series D, due April 15, 2004 (filed as Exhibit 4.1 to Form 10-Q for the quarter ended June 30, 2002). o Form of Nevada Power Company's General and Refunding Mortgage Bonds, Series D, due April 15, 2004 (filed as Exhibit 4.2 to Form 10-Q for the quarter ended June 30, 2002). o Officer's Certificate establishing the terms of Nevada Power Company's 10 7/8% General and Refunding Mortgage Notes, Series E, due 2009 (filed as Exhibit 4.1 to Form 10-Q for the quarter ended September 30, 2002). o Form of Nevada Power Company's 10 7/8% General and Refunding Mortgage Notes, Series E, due 2009 (filed as Exhibit 4.2 to Form 10-Q for the quarter ended September 30, 2002). o 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). o 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). 229 o 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). o Trust Agreement of NVP Capital I dated March 1, 1997 (filed as Exhibit 4.03 to Form S-3, File No. 333-21091). o Form of Amended and Restated Trust Agreement dated March 1, 1997 (filed as Exhibit 4.10 to Form S-3, File No. 333-21091). o 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). o Form of Preferred Security Certificate for NVP Capital I and NVP Capital II dated March 1, 1997 (filed as Exhibit 4.11 to Form S-3, File No. 333-21091). o Form of Guarantee Agreement dated March 1, 1997 (filed as Exhibit 4.12 to Form S-3, File No. 333-21091). o 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). o 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). o 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). o 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). o 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). o 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). o 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). o 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). o 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). o 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 230 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). o 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). o 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). o 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). o 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). o 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: o First Supplemental Indenture, dated as of August 1, 1954 (filed as Exhibit 4.2 to Form S-1, File No. 2-11440). o 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). o Second Supplemental Indenture, dated as of September 1, 1956 (filed as Exhibit 4.9 to Form S-1, File No. 2-12566). o Third Supplemental Indenture, dated as of May 1, 1959 (filed as Exhibit 4.13 to Form S-1, File No. 2-14949). o Fourth Supplemental Indenture, dated as of October 1, 1960 (filed as Exhibit 4.5 to S-1, File No. 2-16968). o Fifth Supplemental Indenture, dated as of December 1, 1961 (filed as Exhibit 4.6 to Form S-16, File No. 2-74929). o Sixth Supplemental Indenture, dated as of October 1, 1963 (filed as Exhibit 4.6A to Form S-1, File No. 2-21689). o Seventh Supplemental Indenture, dated as of August 1, 1964 (filed as Exhibit 4.6B to Form S-1, File No. 2-22560). o Eighth Supplemental Indenture, dated as of April 1, 1968 (filed as Exhibit 4.6C to Form S-9, File No. 2-28348. 231 o Ninth Supplemental Indenture, dated as of October 1, 1969 (filed as Exhibit 4.6D to Form S-1, File No. 2-34588). o Tenth Supplemental Indenture, dated as of October 1, 1970 (filed as Exhibit 4.6E to Form S-7, File No. 2-38314). o Eleventh Supplemental Indenture, dated as of November 1, 1972 (filed as Exhibit 2.12 to Form S-7, File No. 2-45728). o Twelfth Supplemental Indenture, dated as of December 1, 1974 (filed as Exhibit 2.13 to Form S-7, File No. 2-52350). o Thirteenth Supplemental Indenture, dated as of October 1, 1976 (filed as Exhibit 4.14 to Form S-16, File No. 2-74929). o Fourteenth Supplemental Indenture, dated as of May 1, 1977 (filed as Exhibit 4.15 to Form S-16, File No. 2-74929). o Fifteenth Supplemental Indenture, dated as of September 1, 1978 (filed as Exhibit 4.16 to Form S-16, File No. 2-74929). o Sixteenth Supplemental Indenture, dated as of December 1, 1981 (filed as Exhibit 4.17 to Form S-16, File No. 2-74929). o Seventeenth Supplemental Indenture, dated as of August 1, 1982 (filed as Exhibit 4.2 to Form 10-K, File No. 1-4698, Year 1982). o Eighteenth Supplemental Indenture, dated as of November 1, 1986 (filed as Exhibit 4.6 to Form S-3, File No. 33-9537). o Nineteenth Supplemental Indenture, dated as of October 1, 1989 (filed as Exhibit 4.2 to Form 10-K, File No. 1-4698, Year 1989). o Twentieth Supplemental Indenture, dated as of May 1, 1992 (filed as Exhibit 4.21 to Form S-3, File No. 33-53034). o Twenty-First Supplemental Indenture, dated as of June 1, 1992 (filed as Exhibit 4.22 to Form S-3, File No. 33-53034). o Twenty-Second Supplemental Indenture, dated as of June 1, 1992 (filed as Exhibit 4.23 to Form S-3, Filed No. 33-53034). o Twenty-Third Supplemental Indenture, dated as of October 1, 1992 (filed as Exhibit 4.23 to Form S-3, File No. 33-53034). o Twenty-Fourth Supplemental Indenture, dated as of October 1, 1992 (filed as Exhibit 4.23 to Form S-3, File No. 33-53034). o Twenty-Fifth Supplemental Indenture, dated as of January 1, 1993 (filed as Exhibit 4.23 to Form S-3, File No. 33-53034). 232 o 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). o 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). o Twenty-Eighth Supplemental Indenture dated as of July 1, 2001 (filed as Exhibit 4(D) to Form 10-K for the year ended December 30, 2001). SIERRA PACIFIC POWER COMPANY o General and Refunding Mortgage Indenture, dated as of May 1, 2001, between Sierra Pacific Power Company and The Bank of New York, as Trustee (filed as Exhibit 4.2(a) to Form 10-Q for the quarter ended June 30, 2001). o First Supplemental Indenture, dated as of May 1, 2001, establishing Sierra Pacific Power Company's 8% General and Refunding Mortgage Bonds, Series A, due June 1, 2008 (filed as Exhibit 4.2(b) to Form 10-Q for the quarter ended June 30, 2001). o Officer's Certificate establishing the terms of Sierra Pacific Power Company's 8% General and Refunding Mortgage Bonds, Series A, due June 1, 2008 (filed as Exhibit 4.2(c) to Form 10-Q for the quarter ended June 30, 2001). o Form of Sierra Pacific Power Company's 8% General and Refunding Mortgage Bonds, Series A, due June 1, 2008 (filed as Exhibit 4.2(d) to Form 10-Q for the quarter ended June 30, 2001). o Officer's Certificate establishing the terms of Sierra Pacific Power Company's General and Refunding Mortgage Bonds, Series C, due October 31, 2005 (filed as Exhibit 4.3 to Form 10-Q for the quarter ended September 30, 2002). o Form of Sierra Pacific Power Company's General and Refunding Mortgage Bonds, Series C, due October 31, 2005 (filed as Exhibit 4.4 to Form 10-Q for the quarter ended September 30, 2002). o 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). o Ninth Supplemental Indenture, dated as of June 1, 1964 (filed as Exhibit 2-M to Registration No. 2-59509). o Tenth Supplemental Indenture, dated as of March 31, 1965 (filed as Exhibit 4-K to Registration No. 2-23932). o Eleventh Supplemental Indenture, dated as of October 1, 1965 (filed as Exhibit 4-L to Registration No. 2-26552). o Twelfth Supplemental Indenture, dated as of July 1, 1967 (filed as Exhibit 4-L to Registration No. 2-36982). o Sixteenth Supplemental Indenture, dated as of October 1, 1975 (filed as Exhibit 2-Y to Registration No. 2-53404). 233 o Nineteenth Supplemental Indenture, dated as of April 1, 1978 (filed as Exhibit (4)(A) to the 1991 Form 10-K). o Twentieth Supplemental Indenture, dated as of October 1, 1978 (filed as Exhibit (4)(B) to the 1991 Form 10-K). o Twenty-Seventh Supplemental Indenture, dated as of August 1, 1989 (filed as Exhibit (4)(A) to the 1989 Form 10-K). o Twenty-Eighth Supplemental Indenture, dated as of May 1, 1992 (filed as Exhibit (4)(A) to the 1992 Form 10-K). o Twenty-Ninth Supplemental Indenture, dated as of June 1, 1992 (filed as Exhibit D to Form 8-K dated July 15, 1992). o Thirtieth Supplemental Indenture, dated as of July 1, 1992 (filed as Exhibit (4)(B) to the 1992 Form 10-K). o Thirty-First Supplemental Indenture, dated as of November 1, 1992 (filed as Exhibit (4)(C) to the 1992 Form 10-K). o Thirty-Second Supplemental Indenture, dated as of June 1, 1993 (filed as Exhibit 4.6 to Registration No. 33-69550). o Thirty-Third Supplemental Indenture, dated as of October 1, 1993 (filed as Exhibit C to Form 8-K dated October 20, 1993). o Thirty-Fourth Supplemental Indenture, dated as of February 1, 1996 (filed as Exhibit C to Form 8-K dated March 11, 1996). o Thirty-Fifth Supplemental Indenture, dated as of February 1, 1997 (filed as Exhibit C to Form 8-K dated March 10, 1997). o 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). o 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). o 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). o 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). 234 o First Supplemental Indenture dated June 1, 1992 (filed as Exhibit C to Form 8-K dated July 15, 1992). o Second Supplemental Indenture dated October 1, 1993 (filed as Exhibit B to Form 8-K dated October 20, 1993). o Third Supplemental Indenture dated as of February 1, 1996 (filed as Exhibit B to Form 8-K dated March 11, 1996). o Fourth Supplemental Indenture dated as of February 1, 1997 (filed as Exhibit B to Form 8-K dated March 10, 1997). o 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 ). o 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). o 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). o Form of Medium-Term Global Fixed-Rate Note, Series D in connection with Sierra Pacific Power Company's medium-term note program (filed as Exhibit D to Form 8-K dated March 10, 1997). (10) SIERRA PACIFIC RESOURCES o Change in Control Agreement dated May 21, 2001, by and between Sierra Pacific Resources and Walter M. Higgins (filed as Exhibit 10(B) to Form 10-K for the year ended December 30, 2001). o 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). o Change in Control Agreement by and among Sierra Pacific Resources and the following officers (individually): Richard K. Atkinson, Jeffrey L. Ceccarelli, Victor H. Pena, Donald L. Shalmy and Michael W. Yackira 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 (filed as Exhibit 10(C) to Form 10-K for the year ended December 30, 2001). o Change in Control Agreement by and among Sierra Pacific Resources and the following officers (individually): Susan Brennan, Richard J. Coyle, Jane Crane, Matt H. Davis, Carol Elmore, Julian C. Leone, Mary O. Simmons, Mike Smart and Bob Werner 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 (filed as Exhibit 10(D) to Form 10-K for the year ended December 30, 2001). o Donald L. Shalmy Employment Letter dated May 21, 2002 (filed as Exhibit 10.1 to Form 10-Q for the quarter ended September 30, 2002). 235 o *(A) Michael W. Yackira Employment Letter dated March 17, 2003. o Severance and Release Agreement, dated May 24, 2002 among Sierra Pacific Resources, its affiliates Nevada Power Company and Sierra Pacific Power Company, and Mark A. Ruelle (filed as Exhibit 10.1 to Form 10-Q for the quarter ended June 30, 2002). o Severance and Release Agreement, dated May 18, 2002 among Sierra Pacific Resources, its affiliates Nevada Power Company and Sierra Pacific Power Company, and Steven C. Oldham (filed as Exhibit 10.2 to Form 10-Q for the quarter ended June 30, 2002). o *(B) Severance and Release Agreement, dated September 2002 among Sierra Pacific Resources, its affiliates Nevada Power Company and Sierra Pacific Power Company, and William E. Peterson. o Sierra Pacific Resources' Executive Long-Term Incentive Plan (filed as Exhibit 99.1 to Form S-8 dated December 13, 1999). o Sierra Pacific Resources' Non-Employee Director Stock Plan (filed as Exhibit 99.2 to Form S-8 dated December 13, 1999). o Sierra Pacific Resources' Employee Stock Purchase Plan (filed as Exhibit 99.3 to Form S-8 dated December 13, 1999). NEVADA POWER COMPANY o 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). o 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). o 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 Demand Industrial Development Revenue Bonds, Series 1989A) (filed as Exhibit 10.72 to Form 10-K, File No. 1-4698, Year 1994). o 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). o 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 236 Demand Industrial Development Revenue Bonds, Series 1985) (filed as Exhibit 10.38 to Form 10-K, File No. 1-4698, Year 1986). o 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). o 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). o 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). o 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). o 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). o 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). o 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). o 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 1995C) (filed as Exhibit 10.77 to Form 10-K, File No. 1-4698, Year 1995). o 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). o 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). 237 o 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). o 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). o 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). o 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). o 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). o Financing Agreement dated as of February 1, 1983 between Clark County, Nevada and Nevada Power Company (relating to Clark County, 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). o Collective Bargaining Agreement dated as of February 1, 2002, effective through February 1, 2005, between Nevada Power Company and the International Brotherhood of Electrical Workers Local Union No. 396 (filed as Exhibit 10.2 to Form 10-Q for the quarter ended March 31, 2002). o *(C) Western Systems Power Pool ("WSPP") Agreement effective September 1, 2002 between Nevada Power Company as a member of WSPP and the other members of the WSPP. o 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). o 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). o 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). o 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). 238 o 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). o 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). o Amended Mohave Project Coal Supply Agreement dated May 26, 1976 between Nevada Power Company and Southern California Edison Company, Department of Water and Power of the City of Los Angeles, Salt River Project Agricultural Improvement and Power District and the Peabody Coal Company (filed as Exhibit 5.35 to Form S-7, File No. 2-56356). o 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). o 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). o 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). o 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). o 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). o 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). o 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. (filed as Exhibit 10(G) to Form 10-K for the year ended December 30, 2001). o 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 239 Company and Mirant Americas Development, Inc. (filed as Exhibit 10(J) to Form 10-K for the year ended December 30, 2001). o *(D) Settlement Agreement, dated April 16, 2002, by and between Nevada Power Company and each of Calpine Corporation, Duke Energy Trading and Marketing, L.L.C., Mirant Las Vegas, LLC, Pinnacle West Energy Corporation and Reliant Energy Services. o *(E) Service Agreement No. 96 for Long-Term Firm Point-To-Point Transmission Service filed with the Federal Energy Regulatory Commission July 9, 2002 between Nevada Power Company and Calpine Corporation. o *(F) Service Agreement No. 97 for Long-Term Firm Point-To-Point Transmission Service filed with the Federal Energy Regulatory Commission July 3, 2002 between Nevada Power Company and Duke Energy Trading and Marketing. o *(G) Service Agreement No. 100 for Long-Term Firm Point-To-Point Transmission Service filed with the Federal Energy Regulatory Commission December 12, 2002 between Nevada Power Company and Reliant Energy Services, Inc. o *(H) Service Agreement No. 101.A for Long-Term Firm Point-To-Point Transmission Service filed with the Federal Energy Regulatory Commission December 12, 2002 between Nevada Power Company and Pinnacle West Energy Corporation. o *(I) Service Agreement No. 101.B for Long-Term Firm Point-To-Point Transmission Service filed with the Federal Energy Regulatory Commission December 12, 2002 between Nevada Power Company and Southern Nevada Water Authority. o 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 (filed as Exhibit 10(M) to Form 10-K for the year ended December 30, 2001). o 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 o Term Loan Agreement, dated as of October 30, 2002, by and among Sierra Pacific Power Company, the several banks and other financial institutions or entities from time to time parties to the Agreement, Lehman Brothers Inc., as advisor, sole lead arranger and sole bookrunner, Lehman Commercial Paper Inc., as syndication agent, and Lehman Commercial Paper Inc., as administrative agent (filed as Exhibit 10.3 to Form 10-Q for the quarter ended September 30, 2002). o 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). 240 o 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 (filed as Exhibit 10(O) to Form 10-K for the year ended December 30, 2001). o 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). o 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). o 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). o 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). o 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). o 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). o 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). o 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). o 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) 241 o 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). o 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). o Western Systems Power Pool (WSPP) Agreement effective September 1, 2002 between Sierra Pacific Power Company as a member of WSPP and the other members of the WSPP (filed as Exhibit 10(c)). o Coal Supply Agreement dated January 1, 2002 between Sierra Pacific Power Company and Arch Coal Sales Company, Inc. (5 year term ending on December 31, 2006) (filed as Exhibit 10(R) to Form 10-K for the year ended December 30, 2001). o 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). o 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). o 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). o 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). o 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). o 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). o 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). o 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). 242 SIERRA PACIFIC COMMUNICATIONS o Unit Redemption, Release, and Sale Agreement entered into by and among Touch America, Inc., Sierra Pacific Communications, and Sierra Touch America LLC, dated as of September 9, 2002 (filed as Exhibit 10.4 to Form 10-Q for the quarter ended September 30, 2002). o Amended and Restated Conduit Sale Agreement dated September 11, 2002, made by and between Sierra Pacific Communications and Qwest Communications Corporation (filed as Exhibit 10.5 to Form 10-Q for the quarter ended September 30, 2002). (11) NEVADA POWER COMPANY AND SIERRA PACIFIC POWER COMPANY o 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 o *(A) Statement regarding computation of Ratios of Earnings to Fixed Charges. NEVADA POWER COMPANY o *(B) Statement regarding computation of Ratios of Earnings to Fixed Charges. SIERRA PACIFIC POWER COMPANY o *(C) Statement regarding computation of Ratios of Earnings to Fixed Charges. (21) SIERRA PACIFIC RESOURCES o 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. 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. SRP Receivables Finance Corporation, a Delaware Corporation. NEVADA POWER COMPANY o Nevada Electric Investment Company, a Nevada Corporation Commonsite, Inc., a Nevada Corporation. NVP Capital I, a Delaware Business Trust. NVP Capital II, a Delaware Business Trust. Nevada Power Receivables Finance Corporation, a Delaware Corporation. 243 SIERRA PACIFIC POWER COMPANY o 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. SPPC Receivables Finance Corporation, a Delaware Corporation. (23) SIERRA PACIFIC RESOURCES o *(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. NEVADA POWER COMPANY o *(B) Consent of Independent Accountants in connection with the Nevada Power Company's Registration Statement No. 333-102727 (Series E Mortgage Notes) on Form S-4. (99) SIERRA PACIFIC RESOURCES, NEVADA POWER COMPANY AND SIERRA PACIFIC POWER COMPANY o *(99.1) Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. o *(99.2) Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 244 EX-3.(A) 3 b45693spexv3wxay.txt BY-LAWS OF SIERRA PACIFIC RESOURCES AS AMENDED Exhibit 3(A) BY-LAWS OF SIERRA PACIFIC RESOURCES (Amended: January 15, 1985) (Amended: May 20, 1985) (Amended: June 30, 1988) (Amended: October 2, 1989) (Amended: November 27, 1989) (Amended: January 11, 1990) (Amended: June 22, 1990) (Amended: October 4, 1990) (Amended Effective: May 20, 1991) (Amended: May 18, 1992) (Amended: October 5, 1992) (Amended: December 7, 1993) (Amended: January 5, 1994) (Amended: March 30, 1994) (Amended: May 16, 1994) (Amended: June 24, 1994) (Amended: March 21, 1995) (Amended: November 13, 1996) (Amended: February 25, 2000) (Amended: August 14, 2002) ARTICLE I NAME The name of the Corporation (hereinafter referred to as this Corporation) shall be as set forth in the Articles of Incorporation or in any lawful amendments thereto from time to time. ARTICLE II STOCKHOLDERS' MEETINGS All meetings of the stockholders shall be held at the principal office of the Corporation in the State of Nevada unless some other place within or without the State of Nevada is stated in the call. No stockholder action required to be taken or which may be taken at any annual or special meeting of stockholders of the Corporation may be taken without a meeting, and the power of stockholders to consent in writing without a meeting to the taking of any action is specifically denied. ARTICLE III ANNUAL STOCKHOLDERS' MEETINGS The Annual Meeting of the Stockholders of the Corporation shall be held at such time and place as directed or selected by a majority of the Board of Directors. ARTICLE IV SPECIAL STOCKHOLDERS' MEETINGS Special meetings of the stockholders of the Corporation for any purpose or purposes permitted by law may be called at any time by a majority of the Board of Directors or by the Chairman of the Board or the President of the Corporation. Such 1 special meetings may not be called by any other person or persons or in any other manner. ARTICLE V NOTICE OF STOCKHOLDERS' MEETINGS Notice stating the place, day and hour of all stockholders' meetings and the purpose or purposes for which such meetings are called, shall be given by the President or a Vice President or the Secretary or an Assistant Secretary not less than ten (10) nor more than sixty (60) days prior to the date of the meeting to each stockholder entitled to vote thereat by leaving such notice with him at his residence or usual place of business, or by mailing it, postage prepaid, addressed to such stockholder at his address as it appears upon the books of this Corporation, and to the Chairman of the Board at the Corporation's main office, the person giving such notice shall make affidavit in relation thereto. ARTICLE VI QUORUM AT STOCKHOLDERS' MEETINGS Except as otherwise provided by law, at any meeting of the stockholders, a majority of the voting power of the shares of capital stock issued and outstanding and entitled to vote represented by such stockholders of record in person or by proxy, shall constitute a quorum, but a less interest may adjourn any meeting sine die or adjourn any meeting from time to time and the meeting may be held as adjourned without further notice. When a quorum is present at any meeting, a majority of the voting power of the stock entitled to vote represented there, it shall 2 decide any question brought before such meeting, unless the question is one upon which by express provision of law, or of the Articles of Incorporation, or of these By-Laws a larger or different vote is required, in which case such express provision shall govern and control the decision of such question. ARTICLE VII PROXY AND VOTING Stockholders of record entitled to vote may vote at any meeting either in person or by proxy in writing, which shall be filed with the Secretary of the meeting before being voted. Such proxies shall entitle the holders thereof to vote at any adjournment of such meeting, but shall not be valid after the final adjournment thereof. No proxy shall be valid after the expiration of six (6) months from the date of its execution unless the stockholder specifies therein the length of time for which it is to continue in force, which in no case shall exceed seven (7) years from the date of its execution. Stockholders entitled to vote shall be entitled to the voting rights as provided in the Articles of Incorporation. ARTICLE VIII BOARD OF DIRECTORS The number of Directors of the Corporation shall be not more than fifteen (15) nor less than three (3), and until amendment of this By-Law by either the stockholders or Directors, the number of Directors shall be ten (10). The Board of Directors shall have authority to fix the compensation of Directors for regular or special services rendered. The members of the Board of Directors shall be divided into 3 classes in the manner provided in Article VI of the Corporation's Articles of Incorporation and shall be elected and serve for such terms of office as are provided therein, each Director shall serve until his or her successor is duly elected and qualified. Newly created directorships resulting from an increase in number of Directors and vacancies occurring in the Board of Directors for any reason shall be filled in the manner specified in Article VI of the Corporation's Articles of Incorporation. Newly created directorships shall be assigned by the Board of Directors to one of the classes described in said Article VI in the manner provided in such Article. ARTICLE IX POWERS OF DIRECTORS The Board of Directors shall have the entire management of the business of this Corporation. In the management and control of the property, business and affairs of this Corporation, the Board of Directors is hereby vested with all the powers possessed by this Corporation itself, so far as this delegation of authority is not inconsistent with the laws of the State of Nevada, with the Articles of Incorporation or with these By-Laws. Except as otherwise provided by law, the Board of Directors shall have power to determine what constitutes net earnings, profits and surplus, respectively, what amount shall be reserved for working capital and for any other purposes, and what amount shall be declared as dividends, and such determination by the Board of Directors shall be final and conclusive. 4 ARTICLE X COMPENSATION OF DIRECTORS AND OTHERS Directors may be compensated for their services on an annual basis and/or they may receive a fixed sum plus expenses of attendance, if any, for attendance at each regular or special meeting of the Board, such compensation or fixed sum to be fixed from time to time by resolution of the Board of Directors, provided that nothing herein contained shall be construed to preclude any director from serving this Corporation in any other capacity and receiving compensation therefor. Members of special or standing committees may receive like compensation for their services on an annual basis and/or fixed sum for attendance at each committee meeting. Any compensation so fixed and determined by the Board of Directors shall be subject to revision or amendment by the stockholders. ARTICLE XI EXECUTIVE AND OTHER COMMITTEES The Board of Directors may, by resolution or vote passed by a majority of the whole Board, designate from their number an Executive Committee of not less than three (3) nor more than a majority of the members of the whole Board as at the time constituted, which Committee shall have and may exercise the powers of the Board of Directors in the management of the business and affairs of this Corporation when the Board is not in session. The Executive Committee may make rules for the notice, holding and conduct of its meetings and keeping of the records thereof. The Executive Committee shall serve until the first Directors' meeting following the next Annual Stockholders' Meeting, and until their successors shall be designated and 5 shall qualify, and, a majority of the members of said Committee shall constitute a quorum for the transaction of business. The Board of Directors shall, by resolution or vote passed by a majority of the whole Board, designate from their members who are not employees of the Corporation, and designate a representative from the Board of Directors of the Corporation's wholly-owned subsidiaries, who is not an employee, to serve on an Audit Committee. The Audit Committee shall not be less than three (3) nor more than a majority of the whole Board at the time constituted, to nominate auditors for the annual audit of the Corporation's books and records, to develop the scope of the audit program, to discuss the results of such audits with the audit firm, and to take any other action they may deem necessary or advisable in carrying out the work of the Audit Committee. The Audit Committee shall serve until their successors shall be designated and shall qualify, and, a majority of the members of the Audit Committee shall constitute a quorum for the transaction of business. The Board of Directors shall, by resolution or vote passed by a majority of the whole Board, designate from their number members to serve on a Compensation and Organization Committee, the Compensation and Organization Committee shall not be less than three (3), nor more than the entire group of directors of the Corporation who are not employees of the Corporation; provided, however, that no more than one (1) member of the Compensation and Organization Committee may be a Board member who is also an employee of the Corporation or its wholly-owned subsidiaries. The Compensation and Organization Committee shall have such duties and responsibilities as the whole Board shall from time to time direct; provided, 6 however, that the Compensation and Organization Committee shall have the duties and responsibilities at least to review and approve the programs, policies and organizational structure of the Corporation, to recommend the personnel required by the Corporation to conduct its affairs, to receive nominations to the Board of Directors (which nominations will be reviewed with the whole Board and presented to the shareholders for election or re-election as positions are available or as terms of office expire), and to consider and recommend to the whole Board the appropriate number and appropriate members to serve on the various committees of the Board. The Compensation and Organization Committee shall serve until their successors shall be designated and shall qualify, and a majority of the members of the Compensation and Organization Committee shall constitute a quorum for the transaction of business. The Board of Directors of this Corporation may also appoint other committees from time to time, membership composition and numbers on such committees, inclusive of representatives of Board of Directors from the wholly-owned subsidiaries, and committee powers conferred upon the same to be determined by resolution or vote of the Board of Directors of this Corporation. ARTICLE XII DIRECTORS' MEETINGS Regular meetings of the Board of Directors shall be held at such places within or without the State of Nevada and at such times as the Board by resolution or vote may determine from time to time, and if so determined no notice thereof need be given. Special meetings of the Board of Directors may be held at any time or place within or without the State of Nevada whenever called by the Chairman of the Board, 7 the President, a Vice President, a Secretary, an Assistant Secretary or two or more Directors, notice thereof being given to each Director by the Secretary, an Assistant Secretary or officer calling the meeting, or at any time without formal notice provided all the Directors are present or those not present waive notice thereof. Notice of Special meetings, stating the time and place thereof, shall be given by mailing the same to each Director at his residence or business address at least two days before the meeting, unless, in case of exigency, the President or in his absence the Secretary shall prescribe a shorter notice to be given personally or by telephoning or telegraphing each Director at his residence or business address. Such Special meetings shall be held at such times and places as the notices thereof or waiver shall specify. Meetings of the Board of Directors may be conducted by means of a conference telephone network or a similar communications method by which all persons participating in the meeting can hear each other. The minutes of such meeting shall be submitted to the Board of Directors, for approval, at a subsequent meeting. Unless otherwise restricted by the Articles of Incorporation or these By-Laws, any action required or permitted to be taken at any meeting of the Board of Directors or of any committee thereof may be taken without a meeting if a written consent thereto is signed by all the members of the Board of Directors or of such committee. Such written consent shall be filed with the minutes of meetings of the Board or Committee. 8 ARTICLE XIII QUORUM AT DIRECTORS' MEETING Except as otherwise provided by law, by the Articles of Incorporation, or by these By-Laws, a majority of the members of the Board of Directors shall constitute a quorum for the transaction of business, but a lesser number may adjourn any meeting from time to time, and the meeting may be held as adjourned without further notice. When a quorum is present at any meeting, a majority of the members present shall decide any question brought before such meeting. ARTICLE XIV WAIVER OF NOTICE Whenever any notice whatever of any meeting of the stockholders, Board of Directors or any committee is required to be given by these By-Laws or the Articles of Incorporation of this Corporation or any of the laws of the State of Nevada, a waiver thereof in writing, signed by the person or persons entitled to said notice whether before or after the time stated therein, shall be deemed equivalent to such notice so required. The presence at any meeting of a person or persons entitled to notice thereof shall be deemed a waiver of such notice as to such person or persons. ARTICLE XV OFFICERS The officers of this Corporation shall be a President, one or more Vice Presidents, a Secretary and a Treasurer. The Board of Directors at its discretion may elect a Chairman of the Board of Directors. The Chairman of the Board of Directors, if one is to be elected, the President, the Vice Presidents, the Secretary and the 9 Treasurer shall be elected annually by the Board of Directors after its election by the stockholders and shall hold office until their successors are duly elected and qualified, subject, however, to other provisions contained in these By-Laws, and a meeting of the Directors may be held without notice for this purpose immediately after the annual meeting of the stockholders and at the same place. ARTICLE XVI ELIGIBILITY OF OFFICERS Any two or more offices may be held by the same person except the offices of Chairman of the Board of Directors or President and Secretary shall not be held by the same person. The Chairman of the Board of Directors and the President may, but need not, be stockholders and shall be Directors of the Corporation. The Vice Presidents, Secretary, Treasurer and such other officers as may be elected or appointed need not be stockholders or Directors of this Corporation. ARTICLE XVII ADDITIONAL OFFICERS AND AGENTS The Board of Directors, at its discretion, may appoint one or more Assistant Secretaries and one or more Assistant Treasurers and such other officers or agents as it may deem advisable, and prescribe their duties. All officers and agents appointed pursuant to this Article may hold office during the pleasure of the Board of Directors. 10 ARTICLE XVIII CHAIRMAN OF THE BOARD, CHIEF EXECUTIVE OFFICER AND PRESIDENT (A) Chairman of the Board: The Chairman of the Board, if there be such position, shall, if present, preside at all meetings of the Board of Directors and shall have such powers and perform such other duties as may be assigned to him from time to time by the Board of Directors. (B) Chief Executive Officer: Subject to the control of the Board of Directors, the Chief Executive Officer shall be the principal and chief managerial officer of the corporation and shall have the general supervision, direction and control of the business and officers of the corporation. The Chief Executive Officer shall preside at all meetings of the shareholders. In the absence or inability of the Chairman of the Board of Directors or during the vacancy of the office thereof, the Chief Executive Officer shall preside at all meetings of the Board of Directors and shall have such other powers and perform such other duties as may be assigned to him from time to time by the Board of Directors including, but not limited to, the signing or countersigning of certificates of stocks, bonds, notes, contracts or other instruments of the Corporation. He shall be an ex-officio member of all standing committees with the exception of the Audit Committee. (C) President: In the absence or inability of the Chief Executive Officer or during any vacancy in the office thereof, the President shall perform all of the duties of the Chief Executive Officer and when so acting shall have all the power of and be subject to all the restrictions upon the Chief Executive Officer. Unless another officer is elected by the Board to hold the office of Chief Operating Officer, the President shall 11 also be the Chief Operating Officer with such duties as the Board of Directors or the Chief Executive Officer may from time to time prescribe. ARTICLE XIX VICE PRESIDENTS Except as especially limited by resolution or vote of the Board of Directors, any Vice President shall perform the duties and have the powers of the President during the absence or disability of the President and shall have power to sign all certificates of stock, deeds and contracts of this Corporation. He shall perform such other duties and have such other powers as the Board of Directors shall designate from time to time. ARTICLE XX SECRETARY The Secretary shall keep accurate minutes of all meetings of the Board of Directors, the Executive Committee and the Stockholders, shall perform all the duties commonly incident to this office, and shall perform such other duties and have such other powers as the Board of Directors shall from time to time designate. The Secretary shall have power, together with the Chairman of the Board or the President or a Vice President, to sign certificates of stock of this Corporation. In his absence, an Assistant Secretary or Secretary pro tempore shall perform his duties. 12 ARTICLE XXI TREASURER The Treasurer, subject to the order of the Board of Directors, shall have the care and custody of the money, funds, valuable papers and documents of this Corporation (other than his own bond which shall be in the custody of the President) and shall have and exercise, under the supervision of the Board of Directors, all the powers and duties commonly incident to his office, and shall give bond in such form and with such sureties as may be required by the Board of Directors. He shall deposit all funds of this Corporation in such bank or banks, trust company or trust companies or with such firm or firms doing banking businesses as the Directors shall designate or approve. He may endorse for deposit or collection all checks, notes, etc., payable to this Corporation or to its order, may accept drafts on behalf of this Corporation and, together with the Chairman of the Board or the President or a Vice President, may sign certificates of stock. He shall keep accurate books of account of this Corporation's transactions which shall be the property of this Corporation and, together with all its property of this Corporation, shall be subject at all times to the inspection and control of the Board of Directors. ARTICLE XXII RESIGNATIONS AND REMOVALS Any Director or officer of this Corporation may resign at any time by giving written notice to the Board of Directors or to the President or to the Secretary of this Corporation, and any member of any committee may resign by giving written notice either as aforesaid or to the committee of which he is a member or to the 13 chairman thereof. Any such resignation shall take effect at the time specified therein or, if the time be not specified, upon receipt thereof; and, unless otherwise specified therein, the acceptance of such resignation shall not be necessary to make it effective. The stockholders at any meeting called for that purpose may remove any director from office in the manner provided in Article VI of the Articles of Incorporation. The Board of Directors by the vote of not less than a majority of those present at a duly called meeting, may remove from office any officer, agent or member or members of any committee elected or appointed by it or by the executive committee. The Compensation and Organization Committee, at any meeting called for that purpose, or the Chief Executive Officer, or, in his absence, the President of the Company, may immediately suspend from his or her office and the performance of his or her duties any officer of the Company pending any meeting of the Board of Directors called for the purpose of removing an officer of the Corporation. ARTICLE XXIII VACANCIES If an officer or agent, one or more, becomes vacant by reason of death, resignation, removal, disqualification or otherwise, the Directors may, by majority vote of the Board of Directors choose a successor or successors who shall hold office for the unexpired term. Vacancies in the Board of Directors shall be filled by the Directors in the manner provided in Article VI of the Articles of Incorporation. 14 ARTICLE XXIV CAPITAL STOCK The amount of capital stock shall be as fixed in the Articles of Incorporation or in any lawful amendments thereto from time to time. ARTICLE XXV CERTIFICATES OF STOCK Every stockholder shall be entitled to a certificate or certificates of the capital stock of this Corporation in such form as may be prescribed by the Board of Directors, duly numbered and sealed with the corporate seal of this Corporation and setting forth the number of shares to which each stockholder is entitled. Such certificates shall be signed by the Chairman of the Board or the President, or a Vice President and by the Treasurer or an Assistant Treasurer or the Secretary or an Assistant Secretary. The Board of Directors may also appoint one or more Transfer Agents and/or Registrars for its capital stock of any class or classes and may require stock certificates to be countersigned and/or registered by one or more of such transfer agents and/or registrars. If certificates of capital stock of this Corporation are signed by a transfer agent and by a registrar, the signatures thereon of the Chairman of the Board or the President or a Vice President and the Treasurer or an Assistant Treasurer or the Secretary or an Assistant Secretary of this Corporation and the seal of this Corporation thereon may be facsimiles, engraved or printed. Any provisions of these By-Laws with reference to the signing and sealing of stock certificates shall include, in cases above permitted, such facsimiles. In case any officer or officers who shall have signed, or whose facsimile signature or signatures shall have been used 15 on, any such certificate or certificates shall cease to be such officer or officers of this Corporation, whether because of death, resignation or otherwise, before such certificate or certificates shall have been delivered by this Corporation, such certificate or certificates may nevertheless be adopted by the Board of Directors of this Corporation and be issued and delivered as though the person or persons who signed such certificate or certificates or whose facsimile signature or signatures shall have been used thereon had not ceased to be such officer or officers of this Corporation. ARTICLE XXVI TRANSFER OF STOCK Shares of stock may be transferred by delivery of the certificate accompanied either by an assignment in writing on the back of the certificate or by a written power of attorney to sell, assign and transfer the same on the books of this Corporation, signed by the person appearing by the certificate to be the owner of the shares represented thereby, and shall be transferable on the books of this Corporation upon surrender thereof so assigned or endorsed. The person registered on the books of this Corporation as the owner of any shares of stock shall exclusively, be entitled as the owner of such shares, to receive dividends and to vote as such owner in respect thereof. It shall be the duty of every Stockholder to notify this Corporation of his address. 16 ARTICLE XXVII TRANSFER BOOKS The transfer books of the stock of this Corporation may be closed for such period from time to time, not exceeding sixty (60) days, in anticipation of stockholders' meetings or the payment of dividends or the allotment of rights as the Directors from time to time may determine, provided, however, that in lieu of closing the transfer books as aforesaid, the Board of Directors may fix in advance a date, not exceeding sixty (60) days, as of which stockholders shall be entitled to vote at any meeting of the stockholders or to receive dividends or rights, and in such case such stockholders and only such stockholders as shall be stockholders of record as of the date so fixed shall be entitled to vote at any such meeting and at any adjournment or adjournments thereof or to receive dividends or rights, as the case may be, notwithstanding any transfer of any stock on the books of this Corporation after such record date fixed as aforesaid. ARTICLE XXVIII LOSS OF CERTIFICATES In case of the loss, mutilation or destruction of a certificate of stock a duplicate certificate may be issued upon such terms consistent with the laws of the State of Nevada as the Directors shall prescribe. ARTICLE XXIX SEAL The seal of this Corporation shall consist of a flat-faced circular die with the corporate name of this Corporation, the year of its incorporation and the words 17 "Corporate Seal Nevada" cut or engraved thereon. Said seal may be used by causing it or a facsimile thereof to be impressed or affixed or reproduced or otherwise. ARTICLE XXX VOTING OF STOCK HELD Unless otherwise provided by resolution or vote of the Board of Directors, the Chairman of the Board, the President or any Vice President, may from time to time appoint an attorney or attorneys or agent or agents of this Corporation, in the name on behalf of this Corporation to cast the votes which this Corporation may be entitled to cast as a stockholder or otherwise in any other corporation, any of whose stock or securities may be held by this Corporation, at meetings of the holders of the stock or other securities of such other corporations, or to consent in writing to any action by any such other corporation, and may instruct the person or persons so appointed as to the manner of casting such votes or giving such consent and may execute or cause to be executed on behalf of this Corporation and under its corporate seal, or otherwise such written proxies, consents, waivers or other instruments as he may deem necessary or proper in the premises; or the Chairman of the Board or the President or any Vice President may himself attend any meeting of the holders of stock or other securities of such other corporation and thereat vote or exercise any or all other powers of this Corporation as the holder of such stock or other securities of such other corporation. The Chairman of the Board or the President or any Vice President may appoint one or more nominees in whose name or names stock or securities acquired by this Corporation may be taken. With the approval of the Chairman of the Board or 18 the President or any Vice President of the Corporation (which approval may be evidenced by his signature as witness on the instruments hereinafter referred to) any such nominee may execute such written proxies, consents, waivers or other instruments as he may be entitled to execute as the record holder of stock or other securities owned by this Corporation. ARTICLE XXXI EXECUTION OF CHECKS, DRAFTS, NOTES, ETC. All checks, drafts, notes or other obligations for the payment of money shall be signed by such officer or officers, agent or agents, as the Board of Directors shall by resolution or vote direct. The Board of Directors may also, in its discretion, require, by resolution or vote, that checks, drafts, notes or other obligations for the payment of money shall be countersigned or registered as a condition to their validity by such officer or officers, agent or agents as shall be directed in such resolution or vote. Checks for the total amount of any payroll and/or branch office current expenses may be drawn in accordance with the foregoing provisions and deposited in a special fund or funds. Checks upon such fund or funds may be drawn by such person or persons as the Treasurer shall designate and need not be countersigned. ARTICLE XXXII SPECIAL PROVISIONS Section 1: The private property of the stockholders, Directors or officers shall not be subject to the payment of any corporate debts to any extent whatsoever. 19 Section 2: (A) To the fullest extent that the laws of the State of Nevada, as in effect on March 18, 1987, or as thereafter amended, permit elimination or limitation of the liability of directors and officers, no Director, officer, employee, fiduciary or authorized representative of the Company shall be personally liable for monetary damages as such for any action taken, or any failure to take any action, as a Director, officer or other representative capacity. (B) This Article shall not apply to any action filed prior to March 18, 1987, nor to any breach of performance or failure of performance of duty by a Director, officer, employee, fiduciary or authorized representative occurring prior to March, 1987. Any amendment or repeal of this Article which has the effect of increasing Director liability shall operate prospectively only, and shall not affect any action taken, or any failure to act, prior to its adoption. Section 3: (A) Right to Indemnification. Except as prohibited by law, every Director and officer of the Company shall be entitled as a matter of right to be indemnified by the Company against reasonable expense and any liability paid or incurred by such person in connection with any actual or threatened claim, action, suit or proceeding, civil, criminal, administrative, investigative or other, whether brought by or in the right of the Company or otherwise, in which he or she may be involved, as a party or otherwise, by reason of such person being or having been a Director or officer of the 20 Company or by reason of the fact that such person is or was serving at the request of the Company as a Director, officer, employee, fiduciary or other representative of the Corporation or another corporation, partnership, joint venture, trust, employee benefit plan or other entity (such claim, action, suit or proceeding hereafter being referred to as "action"); provided, however, that no such right of indemnification shall exist with respect to an action brought by a Director or officer against the Company (other than a suit for indemnification as provided in paragraph (B)). Such indemnification shall include the right to have expenses incurred by such person in connection with an action paid in advance by the Company prior to final disposition of such action, subject to such conditions as may be prescribed by law. As used herein, "expense" shall include fees and expenses of counsel selected by such person; and "liability" shall include amounts of judgments, excise taxes, fines and penalties, and amounts paid in settlement. (B) Right of Claimant to Bring Suit. If a claim under paragraph (A) of this Section is not paid in full by the Company within thirty (30) days after a written claim has been received by the Company, the claimant may at any time thereafter bring suit against the Company to recover the unpaid amount of the claim, and, if successful in whole or in part, the claimant shall also be entitled to be paid the expense of prosecuting such claim. It shall be a defense to any such action that the conduct of the claimant was such that under Nevada law the Company would be prohibited from indemnifying the claimant for the amount claimed, but the burden of proving such defense shall be on the Company. Neither the failure of the Company (including its Board of Directors, independent legal counsel and its stockholders) to have made a 21 determination prior to the commencement of such action that indemnification of the claimant is proper in the circumstances because the conduct of the claimant was not such that indemnification would be prohibited by law, nor an actual determination by the Company (including the Board of Directors, independent legal counsel or its stockholders) that the conduct of the claimant was such that indemnification would be prohibited by law, shall be a defense to the action or create a presumption that the conduct of the claimant was such that indemnification would be prohibited by law. (C) Insurance and Funding. The Company may purchase and maintain insurance to protect itself and any person eligible to be indemnified hereunder against any liability or expense asserted or incurred by such person in connection with any action, whether or not the Company would have the power to indemnify such person against such liability or expense by law or under the provisions of this Section 3. The Company may make other financial arrangements which include a trust fund, program of self-insurance, grant a security interest or other lien on any assets of the corporation, establish a letter of credit, guaranty or surety as set forth in 1987 Statutes of Nevada, Chapter 28 to ensure the payment of such sums as may become necessary to effect indemnification as provided herein. (D) Non-Exclusive; Nature and Extent of Rights. The right of indemnification provided for herein (1) shall not be deemed exclusive of any other rights, whether now existing or hereafter created, to which those seeking indemnification hereunder may be entitled under any agreement, by-law or article provision, vote of stockholders or directors or otherwise, (2) shall be deemed to create contractual rights in favor of persons entitled to indemnification hereunder, (3) shall continue as to persons who 22 have ceased to have the status pursuant to which they were entitled or were denominated as entitled to indemnification hereunder and shall inure to the benefit of the heirs and legal representatives of persons entitled to indemnification hereunder and (4) shall be applicable to actions, suits or proceedings commenced after the adoption hereof, whether arising from acts or omissions occurring before or after the adoption hereof. The right of indemnification provided for herein may not be amended, modified or repealed so as to limit in any way the indemnification provided for herein with respect to any acts or omissions occurring prior to the adoption of any such amendment or repeal. Section 4: In furtherance, and not in limitation, of the powers conferred by statute, the Board of Directors, by a majority vote of those present at any called meeting, is expressly authorized: (A) To hold its meetings, to have one or more offices and to keep the books of the Corporation, except as may be otherwise specifically required by the laws of the State of Nevada, within or without the State of Nevada, at such places as may be from time to time designated by it. (B) To determine from time to time whether, and if allowed under what conditions and regulations, the accounts and books of the Corporation (other than the books required by law to be kept at the principal office of the Corporation in Nevada), or any of them, shall be open to inspection of the stockholders, and the stockholders' rights in this respect are and shall be restricted or limited accordingly. 23 (C) To make, alter, amend and rescind the By-Laws of the Corporation, to fix the amount to be reserved as working capital, to fix the times for the declaration and payment of dividends, and to authorize and cause to be executed mortgages and liens upon the real and personal property of the Corporation. (D) To designate from its number an executive committee, which, to the extent provided by the By-Laws of the Corporation or by resolution of the Board of Directors, shall have and may exercise in the intervals between meetings of the Board of Directors, the powers thereof which may lawfully be delegated in respect of the management of the business and the affairs of the Corporation, and shall have power to authorize the seal of the Corporation to be affixed to such papers as may require it. The Board of Directors may also, in its discretion, designate from its number a finance committee and delegate thereto such of the powers of the Board of Directors as may be lawfully delegated, to be exercised when the Board is not in session. Section 5: In furtherance, and not in limitation, of the powers conferred by Section 78.378 to Section 78.3793, inclusive, of the General Corporation Law of the State of Nevada, the Corporation, by resolution of the Board of Directors, may call for redemption of control shares under the circumstances and in the manner provided by Section 78.3792 of the General Corporation Law of the State of Nevada as it may be amended from time to time. 24 ARTICLE XXXIII PROPOSALS AT STOCKHOLDERS' MEETINGS Section 1: Advance Notification of Proposals at Stockholders' Meetings. If a stockholder desires to submit a proposal for consideration at an annual or special stockholders' meeting, or to nominate persons for election as directors at any stockholders' meeting duly called for the election of directors, written notice of such stockholder's intent to make such a proposal or nomination must be given and received by the Secretary of the Corporation at the principal executive offices of the Corporation either by personal delivery or by United States mail not later than (i) with respect to an annual meeting of stockholders, one hundred twenty (120) days prior to the anniversary date of the immediately preceding annual meeting, and (ii) with respect to a special meeting of stockholders, the close of business on the tenth day following the date on which notice of such meeting is first given to stockholders. Each notice shall describe the proposal or nomination in sufficient detail for the proposal or nomination to be summarized on the agenda for the meeting and shall set forth (i) the name and address, as it appears on the books of the Corporation, of the stockholder who intends to make the proposal or nomination; (ii) a representation that the stockholder is a holder of record of stock of the Corporation entitled to vote at such meeting and intends to appear in person or by proxy at the meeting to present such proposal or nomination; and (iii) the class and number of shares of the Corporation which are beneficially owned by the stockholder. In addition, in the case of a stockholder proposal, the notice shall set forth the reasons for conducting such proposed business at the meeting and any material interest of the stockholder in such business. In the case of a nomination of any person for election 25 as a director, the notice shall set forth: (i) the name and address of any person to be nominated; (ii) a description of all arrangements or understandings between the stockholder and each nominee and any other person or persons (naming such person or persons) pursuant to which the nomination or nominations are to be made by the stockholder; (iii) such other information regarding such nominee proposed by such stockholder as would be required to be included in a proxy statement filed pursuant to the proxy rules of the Securities and Exchange Commission; and (iv) the consent of each nominee to serve as a director of the Corporation if so elected. The presiding officer of the annual or special meeting shall, if the facts warrant, refuse to acknowledge a proposal or nomination not made in compliance with the foregoing procedure, and any such proposal or nomination not properly brought before the meeting shall not be transacted. Section 2: Advisory Stockholder Votes. In order for the stockholders to adopt or approve any proposal submitted to them for the purpose of advising the Board of Directors of the stockholders' wishes, a majority of the outstanding stock of the Corporation entitled to vote thereon must be voted for the proposal. ARTICLE XXXIV AMENDMENTS Except as otherwise specifically provided herein, these By-Laws may be amended, added to, altered or repealed in whole or in part at any annual or special meeting of the stockholders by vote in either case of at least two-thirds of 26 the voting power of the capital stock issued and outstanding and entitled to vote, provided notice of the general nature or character of the proposed amendment, addition, alteration or repeal is given in the notice of said meeting, or by the affirmative vote of a majority of the Board of Directors present at a called regular or special meeting of the Board of Directors, provided notice of the general nature or character of the proposed amendment, addition, alteration or repeal is given in the notice of said meeting. ARTICLE XXXV NEVADA CONTROL SHARE Pursuant to NRS Section 78.378, the Company opts out of the Nevada Control Share statute, and specifically that the provisions of NRS Sections 78.378 to 78.3793 do not apply to the corporation or to an acquisition of a controlling interest by existing or future stockholders. 27 EX-10.(A) 4 b45693spexv10wxay.txt MICHAEL W. YACKIRA EMPLOYMENT LETTER 3-17-03 Exhibit 10(A) January 27, 2003 Mr. Michael W. Yackira 2355 N.W. 49th Lane Boca Raton, Florida 33431 Dear Michael, On behalf of the Board of Directors, I am pleased to offer you employment as Executive Vice President, Strategy and Policy for Sierra Pacific Resources. Your work location will be at Sierra Pacific-Nevada Power headquarters in Las Vegas, Nevada. You will report directly to me in this position. We expect that you will assume your duties as soon as possible. Your starting base salary in this position will be $300,000. You will also be eligible for an annual cash incentive, Short Term Incentive Program (STIP) of 45% (target) of your base salary. Payment of the Short Term Incentive is at the discretion of the Board of Directors and is based on corporate, business unit, and personal performance. Actual payout may vary from 0% to 150% of target. Your participation for FY 2003 will be effective January 1, 2003 assuming you begin full-time employment on January 27, 2003, arriving in Las Vegas that evening. Long-term incentives for this position are in accordance with the plan approved by the shareholders and administered by the Board of Directors. At this time, long-term incentives consist of Non-Qualified Stock Options (NQSO's) and performance shares. For your position the long-term incentive is targeted at 75% of your base salary, 60% delivered through NQSO's and 40% delivered through Performance Shares. The NQSO's vest one-third per year and are fully vested after the third year. Performance shares have a three-year term and are earned based on measures established by the Board for each grant. You will also be eligible to participate on a pro-rata basis (24 of 36 months) in the 2003-2004 Performance Share grant made in 2002. In addition you will also be able to participate in the 2001-2003 Performance Share grant for the remaining 12 of the original 36 months. New options and performance share grants will be reviewed by the Board of Directors at the January 30-31, 2003 meeting (which is the timeframe each year when the Board reviews officer salaries and incentive plan matters). As a special inducement for you to join SPR, the Board has also authorized the following incentives. A one-time signing bonus of $50,000, grossed up for Federal Income Tax. In addition, you will receive a special stock option grant of 30,000 NQSO's at a strike price to be set based on the closing stock price on the day you accept this offer by signing it and informing me that you have done so. These options will vest at the end of one year, or upon change of control if such an event were to occur before the end of one year. As an Executive Vice President, you will be expected to achieve and maintain one and a half times your annual compensation in SPR stock. You will have five years to achieve this level. 1 You will be eligible for normal Sierra Pacific Resources Senior Officer change in control protection as may be put in place for company officers by the Board of Directors. You will be eligible to participate in the Company's Supplemental Executive Retirement Plan (SERP) and eligible for benefits under this Plan including a maximum benefit of 50% of your Final Average Earnings, depending on years of service at time of retirement. The Company will also provide you life insurance coverage of $400,000 (which may require completion of a physical exam performed by a doctor selected by our insurance carrier). This will be in addition to a $1,000,000 policy in the event that you die while traveling on Company business and company provided group life insurance equivalent to 1.5 times your annual salary. You will be eligible for all regular employee benefits including a 401K plan that matches employee contributions dollar for dollar up to 6% and SPR's Deferred Compensation Plan. You will receive a perquisite allowance of $9,100 per year to cover such expenses as a car, tax preparation and club memberships. (Note that the Perc allowance amount is currently being reviewed by our compensation consultant.) You will receive paid time off (PTO) based on your total years of professional work experience (31). Your annual paid time off allowance will be 33.4 days, plus 11 paid holidays. In 2003, it will be pro rated based on your hire date. Upon acceptance of this agreement, you will be eligible for the relocation program for senior officers of Sierra Pacific Resources. A summary of this program is enclosed. In addition to the benefits described above, in the event you are terminated for reasons other than (1) reasons relating to moral turpitude, (2) conviction of any crime amounting to a felony, or (3) on your own volition and without actually being requested to resign by the Board, you will receive within thirty days of termination, one year of base salary. This payment shall be conditioned on the execution of appropriate releases in favor of the Company for any and all claims connected with or arising out of your employment or termination and will require continued maintenance of confidential and proprietary information, a non-compete for one year and agreement not to disparage the Company. As is Sierra's policy, all hiring offers are contingent on a drug analysis test. We can arrange for you to have this test at a time and place convenient for you. Also you will need to provide us proof of U.S. Citizenship on your first day of work. This could include a copy of your Birth Certificate, Driver's License, or Social Security Card. The position being offered to you is one of trust and confidence. In accepting the position you are agreeing that, in addition to any other limitation and regardless of the circumstances or any future limitation of your employment, you will not communicate to any person, firm or other entity any knowledge relating to documents, transactions or any other confidential knowledge which you might acquire with respect to the business of Sierra Pacific Resources or any of its affiliated companies. To indicate acceptance of this offer, please sign below and return one signed original of this letter to me as soon as possible. If you have questions about elements of this offer, you may call me or discuss them with Victor H. Pena, Senior Vice President and CAO. 2 On behalf of the Board of Directors and the officers of the company, I am delighted that you have accepted the opportunity to join the Sierra Pacific team. We believe, with your leadership, expertise and dedication we will accomplish great results for our shareholders, customers, employees and communities. Welcome! Sincerely, /s/ Unidentified Signature Accepted: ----------------------------- Michael W. Yackira Date ------------------------ 3 EX-10.(B) 5 b45693spexv10wxby.txt SEVERANCE AND RELEASE AGREEMENT, DATED MAY 18 Exhibit 10(B) SEVERANCE AND RELEASE AGREEMENT PARTIES The parties to this Severance and Release Agreement ("Agreement") are Sierra Pacific Resources and its affiliates, Nevada Power Company and Sierra Pacific Power Company (collectively referred to as "Company"), and William E. Peterson ("Employee"). RECITALS a. Employee currently holds the positions of Senior Vice-President, General Counsel and Corporate Secretary with Company. This Agreement is not based upon any change in control or in the ownership of a substantial portion of the Company's assets. b. Employee has had access to Confidential Information, as hereinafter defined. Employee has occupied a position of trust and confidence with respect to such Confidential Information. c. Employee and Company desire to terminate the employment relationship presently existing between them and to enter into an independent contractor attorney client relationship on terms and conditions as hereinafter set forth. d. This Agreement provides Employee and Company with rights and benefits that exceed the rights and benefits contained in the existing Employment Agreement (as defined below) and is adequate consideration for this Agreement. TERMS OF AGREEMENT 1. DEFINED TERMS 1.1 "Competing Organization" means persons or organizations, including Employee, engaged in, or who may become engaged in, research or development, production, distribution, marketing, providing or selling of a Competing Product or Service. 1.2 "Competing Products or Services" means products, processes, or services of any person or organization, other than Company, in existence or under development, which are substantially the same as or which compete with the products, processes, or services being developed, manufactured, or sold by Company during the time of Employee's employment with Company, including, but not limited to, products, processes and services related to the generation, transmission, or distribution of electric energy and/or the buying, selling, scheduling of electric energy or capacity, or any risk management activities associated therewith. 1.3 "Restricted Area" means the State of Nevada and the service territories of the Company. 1.4 "Confidential Information" means any plan, specification, pattern, procedure, profile, design, device, list, compilation, data, or information relating to the present or planned business of Company which has not been released publicly by authorized representatives of Company, or which is not common to industry practice, including, but not limited to trade secrets as defined in NRS 600A.010, et seq. Confidential Information may include inventions; marketing and sales plans or programs; customer and supplier information; financial data; purchasing, pricing, or supply information; product engineering information; technological know-how; designs, plans or specifications regarding products and materials; manufacturing processes and techniques; regulatory approval strategies; computer programs, data, formulae and compositions; service techniques and protocols; and new product strategies, plans and designs. Confidential Information also includes information that if disclosed, could negatively affect the Company's reputation and it's relationship with business, governmental agencies and customers. Confidential Information includes all information received by Company under an obligation of confidentiality to a third party. 1.5 "Employment Agreement" means all previous agreements, express or implied, between Company and Employee, including change in control or letter agreements. 1.6 "STIP" means short-term cash incentive payment. 1.7 "SERP" means Supplemental Executive Retirement Plan. 2. TERMINATION OF PRESENT EMPLOYMENT 2.1 Employee agrees to forego retirement at the present time and remain with Company and discharge each and every of his present duties and responsibilities until such time as Company finds a replacement satisfactory to Company or February 1, 2003, whichever date occurs sooner ("Termination Date"). 2.2 Until the Termination Date, Employee shall receive the compensation and benefits to which he is presently entitled or may become entitled 2 without change or alteration. Any accrued and unused Paid Time Off will be included in Employee's final paycheck. 3. SERVICES AS INDEPENDENT CONTRACTOR 3.1 After the Termination Date, Company will retain Employee as outside counsel. Employee shall be entitled to compensation as follows: 3.1.1 Employee shall perform legal and other services for Company as directed by managerial level employees of Company for the first twelve months following the Termination Date ("First Twelve Month Period") in an amount not less than 1000 hours at an hourly rate of $300.00 per hour (exclusive of actual costs). This provision shall be subject to satisfactory and timely performance by Employee within accepted standards of professional practice. 3.1.2 Employee shall perform legal and or other services for Company as directed by managerial level employees of Company for the twelve-month period following the First Twelve-Month Period ("Second Twelve-Month Period") in an amount not less than 1000 hours at an hourly rate of $325.00 per hour (exclusive of actual costs). This provision shall be subject to satisfactory and timely performance by Employee within accepted standards of professional practice. 3.1.3 Employee shall perform legal and or other services for Company as directed by managerial level employees of Company for the twelve-month period following the Second Twelve-Month Period ("Third Twelve-Month Period") in an amount not less than 1000 hours at an hourly rate of $350.00 per hour (exclusive of actual costs). This provision shall be subject to satisfactory and timely performance by Employee within accepted standards of professional practice. 3.1.4 Billings shall occur monthly and payment shall be made 30 days after billing. 3.1.5 Hours above 1000 hours for the First Twelve Month Period shall not be credited against the 1000 minimum hours for the Second or Third Twelve-Month Periods and hours above the minimum for the Second Twelve-Month Period shall not be credited against the 1,000 minimum hours for the Third Twelve-Month Period. Should the minimum hours not be billed after the First Twelve-Month Period or the Second Twelve-Month Period or the Third Twelve-Month Period, then Employee shall remit a bill for the full amount of any deficiency in the first month following 3 the end of the First and Second or Third Twelve-Month Periods, respectively. 4. BENEFITS TO EMPLOYEE Commencing on the Termination Date, Employee shall be entitled to the following benefits: 4.1 Employee shall be entitled to whatever qualified pension benefits Employee may be entitled under the terms and conditions of the existing qualified retirement plan without change, modification or enhancement. 4.2 Employee shall be entitled to withdraw in a lump sum and be paid within 30 days of the Termination Date all nonqualified retirement benefits to which he may be entitled calculated in accordance with the existing terms and conditions of said unqualified plans but altered, changed and or modified so as to treat Employee for purposes of said calculations as though Employee were 62 years of age on the day prior to the Termination Date and as though Employee had completed 10 years of actual service with respect to all such plans and also with respect to his existing Employment Contract which provides Employee with one and one half year of service credit for each year of actual service performed for the first ten years of service. 4.3 Employee shall be entitled to whatever health and welfare benefits, including, but not limited to, medical, prescriptive drugs, dental, vision and EAP benefits, are available to retirees at Employee's age and their dependents, and on the same terms and conditions except that such benefits shall be calculated and made available without any actuarial deduction or other penalty resulting from having retired before age 65 or age 62, and, in addition, had completed ten years of actual service with respect to all of such plans as well as with respect to the extra credit earned under his existing Employment Contract which gives Employee one and one-half year of service for each year of service performed for the first ten years of employment. 4.4 If ever in the future any of the Company's existing, retired, or separated officers are paid a STIP for the year 2000 ("2000 STIP") then the Employee shall be paid the 2000 STIP at the same time and in the form and manner paid to the other officer recipient(s). The 2000 STIP shall be subject to withholding, deductions, assessments, and taxes, if applicable. If ever any of the Company's existing, retired or separated officers are paid a STIP for the year 2001 ("2001 STIP"), then the Employee shall be paid the 2001 STIP at the same time and in the 4 form and manner paid to the other officer recipients(s). The 2001 STIP shall be subject to withholding, deductions, assessments, and taxes, if applicable. If ever any of the Company's existing, retired or separated officers are paid a STIP for the year 2002 ("2002 STIP"), then the Employee shall be paid a prorated portion of the 2002 STIP at the same time and in the form and manner paid to the other officer recipient(s). Employee's prorated portion of the 2002 STIP shall be calculated by dividing the actual number of hours worked by Employee during 2002 (1/1/02 through Termination Date) by 2080, and Employee shall be entitled to receive the resulting percentage of the 2002 STIP. The 2002 STIP shall be subject to withholding, deductions, assessments, and taxes, if applicable. 4.5 Employee shall be entitled to withdraw all accumulated deferred compensation under the terms and conditions of the existing deferred compensation plan except that, on the Termination Date, Company agrees that Employee shall be deemed and considered a terminated employee and shall have the right to withdraw such compensation. 4.6 Employee is covered under Supplemental Executive Life insurance. Employee shall continue to be covered under such insurance until July 31, 2003, with all premiums paid by Company until July 31, 2003, at which time Employee shall have the option of converting such insurance in strict accordance with the terms of such policy and paying any and all premiums due thereon as required by any SERP, restoration, life insurance, or other plan maintained by Company as though employee had completed 10 years of service under his Employment Contract at age 55. 5. CONFIDENTIALITY 5.1 Employee shall preserve as confidential all Confidential Information. Employee shall not use Confidential Information for the benefit of Employee or any third party. Employee shall not disclose to others any Confidential Information or any copy or notes made from any Item embodying Confidential Information. If Employee is required to disclose Confidential Information pursuant to a valid order of a court or other governmental entity or any political subdivision thereof; then Employee shall first give notice to Company so that Company shall have a reasonable opportunity to interpose an objection or obtain a protective order requiring that the Confidential Information and/or documents so disclosed be used only for the purposes for which the order was issued. The confidentiality provisions herein shall expire 36 months from the date of this agreement. 5 6. NON-COMPETITION 6.1 Without express consent of the Company's CEO for a period of one year after Employee's Termination Date or last serving as outside counsel under the terms and provisions of this Agreement and as otherwise governed by applicable rules of professional conduct, Employee shall not, directly or indirectly, assist, provide services or consultation to, enter into, engage in or acquire any ownership interest in, or become employed by or associated with, any Competing Organization doing business or seeking to commence doing business in the Restricted Area. This includes, but is not limited to, services rendered to such Competing Organization in an executive, managerial, administrative, legal or consulting capacity in connection with Competing Products or Services in support of actual competition in geographic areas other than where the services are performed and thus may fall within the prohibition of the Agreement, regardless of where such services physically are rendered. This limitation includes, but is not limited to, any contact or solicitation, either for Employee's benefit or for the benefit of any other person or entity, and Employee will not in any manner assist any person or entity in making any such contact or solicitation. 6.2 Employee shall not solicit any employee of Company to terminate his or her employment or relationship with Company or to perform any service for employee or for any Competing Organization. 6.3 Employee agrees that the restrictions set forth in paragraphs 6.1 and are fair and reasonable and are reasonably required for the protection of the interests of the Company and compliance with those provisions will not cause Employee undue hardship nor unreasonably interfere with Employee's ability to earn a livelihood. 7. RELEASE 7.1 Except for rights and benefits under any existing or future insurance policy of Company and/or Employee and rights of indemnification under any such policies or rights of indemnification under the articles or by-laws of Company or under statutory or common law, or under any agreement, and/or any claims for benefits reserved under this Agreement or claims arising under any breach of this Agreement, all of which are expressly reserved, Employee hereby waives and releases Company and its officers, directors, agents, and employees (collectively referred to as "Company Agents") from any claims, rights, contracts or causes of action existing or accrued as of the effective date of this Agreement that Employee may have against Company or Company Agents (collectively referred to as "Claims") which arise out 6 of or are related to Employee's employment with Company (collectively referred to as "Release") or the termination of the Employment Agreement. This Release includes, but is not limited to, the following: 7.1.1 Claims which are known or unknown as of the effective date of this Agreement; 7.1.2 Claims which arise under any state or federal laws, including, but not limited to, the Civil Rights Act of 1964, as amended, and the Age Discrimination in Employment Act of 1967, as amended, which have arisen on or before the effective date of this Agreement; and 7.1.3 Claims based upon any contract of employment, including but not limited to, the Change in Control Agreement, except as set forth herein. 7.2 Employee shall not commence any action against Company or Company Agents in violation of this Release. 7.3 Employee does not waive any Claim which arises after the effective date of this Agreement. 7.4 Employee further expressly acknowledges and agrees that: 7.4.1 Employee has been advised to consult with an attorney before signing this Agreement; 7.4.2 This Agreement is being offered only to Employee at this time. 7.4.3 Employee was given a copy of the Agreement on or about August __, 2002. Employee was informed that Employee had 21 days within which to consider the Agreement. If Employee fails to execute this Agreement within said 21-day period, then the terms and conditions contained in this Agreement are automatically withdrawn without further action or notice by Company. 7.4.4 Employee was informed and understands that Employee has seven days following the date Employee executes this Agreement in which to revoke this Agreement. Any revocation of the Agreement must be in writing and delivered to the Vice President of Human Resources of Company during the revocation period. This Agreement will become effective and enforceable seven days following execution by Employee, unless it is revoked during the seven-day period. 7 8. MISCELLANEOUS PROVISIONS 8.1. Confidentiality of Agreement: Unless and until the terms of this Agreement, and the amount of any payment eligible to be paid or actually paid under this Agreement, are disclosed in writing to the public by Company pursuant to any applicable legal duty to disclose such information, it shall be a condition of eligibility to receive or retain any payment pursuant to this Agreement that Employee hold the terms of this Agreement and the amount of any payment hereunder in strict confidence. Employee may disclose such information on a confidential basis to Employee's family and to any financial counselor, tax advisor or legal counsel retained by Employee. 8.2 Assignment by Company: The obligations of Company hereunder shall be the obligations of any and all successors and assigns of Company. Company may assign this Agreement without Employee's consent to any affiliate or subsidiary of Company, provided that such assignment does not relieve the Company's obligations hereunder. Company may assign this Agreement without Employee's consent to any company that acquires all or substantially all of the stock or assets of Company, or into which or with which Company is merged or consolidated. The Employee may not assign the Agreement, and no person other than Employee or Employee's estate may enforce the rights of Employee under this Agreement. 8.3 Waiver: The waiver by Employee or Company of a violation or breach respectively by Company or by Employee of any provision of this Agreement shall not be construed as a waiver of any subsequent violation or breach. 8.4 Severability: The provisions of this Agreement shall be severable, and in the event that any portion or provision of it is found by any court to be unenforceable, in whole or in part, the remainder of this Agreement shall nevertheless be enforceable and binding on the parties. In the event that any restriction set forth in this Agreement shall be declared by a court of competent jurisdiction to exceed the maximum restriction such court deems reasonable and enforceable, the restriction deemed reasonable and enforceable by the court shall become and thereafter be the maximum restriction hereunder. 8.5 Review of Agreement: Employee acknowledges that Employee had sufficient opportunity to review this Agreement with an attorney or, if Employee did not do so, it is because Employee read and understood this Agreement and did not believe that legal advice was necessary. 8 Employee agrees that any restrictions contained in this Agreement are fair and appropriate under the circumstances. 8.6 Dispute Resolution: Any dispute between the parties which is covered by, arises out of, or is based upon this Agreement shall be settled by final and binding arbitration. Any award or determination rendered by the arbitrator may be entered as a judgment in any court having jurisdiction thereof. The arbitration is subject to the following: 8.6.1 The arbitration shall be administered by the American Arbitration Association ("AAA") in accordance with its Employment Dispute Resolution Rules ("Rules") in effect at the time of the arbitration. 8.6.2 The arbitration shall be heard by one neutral arbitrator. The arbitrator shall be an attorney admitted to the practice of law in at least one state. 8.6.3 The arbitrator shall have the authority to award any remedy or relief that a state or federal court having jurisdiction over the persons and subject matter is authorized to grant. 8.6.4 The Company shall pay all of the costs and/or fees charged by AAA and the arbitrator. The arbitrator shall have the authority to award attorney's fees and costs pursuant to sub-section 8.6.3 above. 8.7 Jurisdiction: This Agreement shall be construed under the laws of the State of Nevada except where Federal laws are applicable. Venue for any arbitration or action to enforce the arbitration provisions of this Agreement shall be in the State of Nevada. 8.8 Effective Date: This Agreement will become effective and enforceable seven days following execution by Employee, unless it is revoked during the seven-day period in accordance with the provisions of 7.4.4 above. 8.9 Final Agreement: This Agreement supercedes all prior understandings, statements or agreements concerning the subject matter of this Agreement, including the Employment Agreement or Change in Control Agreement. Any amendment to this Agreement shall be in writing and signed by both parties. This Agreement contains all of the terms and conditions agreed upon by the parties. There are no understandings or agreements which conflict or modify the terms of this Agreement. Company has made no representations or promises upon which Employee relies in signing this Agreement except the 9 terms set forth herein. Company has made no representations upon which Employee relies concerning the tax characteristics or status of the benefits described in this Agreement. 8.10 Cooperation. Company and Employee agree to cooperate fully and execute any and all supplementary documents and to take all additional actions which may be necessary or appropriate to give full force and effect to the terms and intent of this Agreement 8.11 Binding Obligation. Company represents and warrants to Employee that Company has taken all requisite corporate action to approve this Agreement and that this Agreement constitutes a valid, binding and enforceable obligation of the Company. COMPANY WILLIAM E. PETERSON By:___________________________ _____________________________ Date: September ____, 2002 Date: September ____, 2002 10 EX-10.(C) 6 b45693spexv10wxcy.txt WESTERN SYSTEMS POWER POOL AGREEMENT Exhibit 10(C) Western Systems Power Pool . Rate Schedule FERC No. 6 WESTERN SYSTEMS POWER POOL AGREEMENT Issued by: Michael E. Small, General Counsel to Effective: September 1, 2002 Western Systems Power Pool Issued on: July 2, 2002 Western Systems Power Pool Original Sheet No. 1 Rate Schedule FERC No. 6 TABLE OF CONTENTS
PAGE 1. PARTIES................................................................4 2. RECITALS...............................................................4 3. AGREEMENT..............................................................5 4. DEFINITIONS............................................................5 5. TERM AND TERMINATION..................................................11 6. SERVICE SCHEDULES AND WSPP DEFAULT TRANSMISSION TARIFF................12 7. HUB AND OPERATING AGENT...............................................13 8. ORGANIZATION AND ADMINISTRATION.......................................16 9. PAYMENTS..............................................................20 10. UNCONTROLLABLE FORCES.................................................22 11. WAIVERS...............................................................24 12. NOTICES...............................................................24 13. APPROVALS.............................................................25 14. TRANSFER OF INTEREST IN AGREEMENT.....................................27 15. SEVERABILITY..........................................................28 16. MEMBERSHIP............................................................28 17. RELATIONSHIP OF PARTIES...............................................29 18. NO DEDICATION OF FACILITIES...........................................30
Issued by: Michael E. Small, General Counsel to Effective: July 1, 2000 Western Systems Power Pool Issued on: September 29, 2000 Filed to comply with order of the Federal Energy Regulatory Commission, Docket Nos. ER00-3338, et al., issued September 15, 2000. Western Systems Power Pool First Revised Sheet No. 2 Rate Schedule FERC No. 6 Superseding Original Sheet No. 2 TABLE OF CONTENTS
PAGE 19. NO RETAIL SERVICES....................................................30 20. THIRD PARTY BENEFICIARIES.............................................30 21. LIABILITY AND DAMAGES.................................................30 22. DEFAULT OF TRANSACTIONS UNDER THIS AGREEMENT AND CONFIRMATION AGREEMENTS...............................................34 23. OTHER AGREEMENTS......................................................43 24. GOVERNING LAW.........................................................43 25. JUDGMENTS AND DETERMINATIONS..........................................43 26. COMPLETE AGREEMENT....................................................44 27. CREDITWORTHINESS......................................................44 28. NETTING AND SET-OFF...................................................46 29. TAXES................................................................47A 30. CONFIDENTIALITY.......................................................48 31. TRANSMISSION TARIFF...................................................49 32. TRANSACTION SPECIFIC TERMS AND ORAL AGREEMENTS........................49 33. PERFORMANCE, TITLE, AND WARRANTIES FOR TRANSACTIONS UNDER SERVICE SCHEDULES..............................................52A 34. DISPUTE RESOLUTION....................................................53 35. FORWARD CONTRACTS.....................................................56
Issued by: Michael E. Small, General Counsel to Effective: March 1, 2002 Western Systems Power Pool Issued on: December 21, 2001 Western Systems Power Pool Third Revised Sheet No. 3 Rate Schedule FERC No. 6 Superseding Second Revised Sheet No. 3 TABLE OF CONTENTS
PAGE 36. TRADE OPTION EXCEPTION................................................56 37. ADDITIONAL REPRESENTATIONS AND WARRANTIES.............................57 38. FLOATING PRICES.......................................................58 39. AMENDMENT............................................................58B 40. EXECUTION BY COUNTERPARTS............................................58B 41. WITNESS...............................................................59
EXHIBIT A: NETTING EXHIBIT B: FORM OF COUNTERPARTY GUARANTEE AGREEMENT EXHIBIT C: SAMPLE FORM FOR CONFIRMATION EXHIBIT D: WSPP MEDIATION AND ARBITRATION PROCEDURES SERVICE SCHEDULES A. ECONOMY ENERGY SERVICE B. UNIT COMMITMENT SERVICE C. FIRM CAPACITY/ENERGY SALE OR EXCHANGE SERVICE LIST OF MEMBERS Issued by: Michael E. Small, General Counsel to Effective: March 1, 2002 Western Systems Power Pool Issued on: December 21, 2001 Western Systems Power Pool Original Sheet No. 4 Rate Schedule FERC No. 6 1. PARTIES: The Parties to this Western Systems Power Pool Agreement (hereinafter referred to as "Agreement") are those entities that have executed this Agreement, hereinafter sometimes referred to individually as "Party" and collectively as "Parties," but excluding any such entity that withdraws its participation in the Agreement. 2. RECITALS: 2.1 The WSPP experiment has been successfully concluded. Its main purpose was to determine the feasibility of a marketing arrangement which would increase the efficiency of interconnected power system operations above that already being accomplished with existing agreements through increased market knowledge and market pricing of commodities. 2.2 The Parties now desire to proceed with a similar marketing arrangement on a long term basis for prescheduled and real-time coordinated power transactions, such as economy energy transactions, unit commitment service, firm system capacity/energy sales or exchanges. Accordingly, this Agreement, together with any applicable Confirmation Agreement, sets forth the terms and conditions to implement these services within any applicable rate ceilings set forth in the Service Schedules in conformance with FERC orders where applicable. Issued by: Michael E. Small, General Counsel to Effective: July 1, 2000 Western Systems Power Pool Issued on: September 29, 2000 Filed to comply with order of the Federal Energy Regulatory Commission, Docket Nos. ER00-3338, et al., issued September 15, 2000. Western Systems Power Pool First Revised Sheet No. 5 Rate Schedule FERC No. 6 Superseding Original Sheet No. 5 2.3 Each Party meets the membership requirements set out in Section 16. 2.4 The Parties are willing to utilize their respective electric generation and transmission systems or contractual rights thereto to the extent of their respective obligations which are set forth in this Agreement. 3. AGREEMENT: In consideration of the mutual covenants and promises herein set forth, the Parties agree as follows: 4. DEFINITIONS: The following terms, when used herein with initial capitalization, whether in the singular or in the plural, shall have the meanings specified: 4.1 Agreement: This Western Systems Power Pool Agreement, including the Service Schedules and Exhibits attached hereto, as amended; provided, however, that Confirmation Agreements are not included within this definition. 4.1a Broker: An entity or person that arranges trades or brings together Purchasers and Sellers without taking title to the power. 4.1b Business Day(s): Any day other than a Saturday or Sunday or a national (United States or Canadian, whichever is applicable) holiday. United States holidays shall be holidays observed by Federal Reserve member banks in New York City. Where both the Seller and the Purchaser have their principal place of business in the United States, Canadian holidays shall not apply. Similarly, where both the Issued by: Michael E. Small, General Counsel to Effective: March 1, 2002 Western Systems Power Pool Issued on: December 21, 2001 Western Systems Power Pool Third Revised Sheet No. 6 Rate Schedule FERC No. 6 Superseding Second Revised Sheet No. 6 Seller and the Purchaser have their principal place of business in Canada, United States holidays shall not apply. In situations where one Party has its principal place of business within the United States and the other Party's principal place of business is within Canada, both United States and Canadian holidays shall be observed. 4.1c California ISO: The California Independent System Operator Corporation or any successor organization. 4.1d Confirmation Agreement(s): Any oral agreement or written documentation for transactions under the Service Schedules which sets forth terms and conditions for transactions that are in addition to, substitute, or modify those set forth in the Agreement. A sample written confirmation document is included as Exhibit C. Section 32 of this Agreement provides for such Confirmation Agreements. The Parties may agree to modify terms of this Agreement for more than one transaction pursuant to a separate written agreement. The changes to the Agreement agreed to through such written agreements shall be considered part of the Confirmation Agreement and shall apply to all transactions entered into between the two Parties under the Agreement unless the Parties specifically agree to override such changes for a particular transaction consistent with Section 32 of this Agreement. 4.1e Contract Price: The price agreed to between the Seller and the Purchaser for a transaction under the Agreement and any Confirmation Agreement. Issued by: Michael E. Small, General Counsel to Effective: September 1, 2002 Western Systems Power Pool Issued on: July 2, 2002 Western Systems Power Pool Second Revised Sheet No. 6A Rate Schedule FERC No. 6 Superseding First Revised Sheet No. 6A 4.1f Contract Quantity: The amount of electric energy and/or capacity to be supplied for a transaction under a Service Schedule as agreed to through any Confirmation Agreement. 4.2 Control Area: Shall mean an electric system capable of regulating its generation in order to maintain its interchange schedule with other electric systems and to contribute its frequency bias obligation to the interconnection as specified in the North American Electric Reliability Council (NERC) Operating Guidelines. 4.2a Costs: As defined in Section 22.3 of this Agreement. 4.2b Dealer: An entity or person that buys or sells power and takes title to the power at some point. 4.2c Defaulting Party: As defined in Section 22.1 of this Agreement. 4.2d Determination Period: As defined in Section 38.2 of this Agreement. 4.3 Economy Energy Service: Non-firm energy transaction whereby the Seller has agreed to sell or exchange and the Purchaser has agreed to buy or exchange energy that is subject to immediate interruption upon notification, in accordance with the Agreement, including Service Schedule A, and any applicable Confirmation Agreement. Issued by: Michael E. Small, General Counsel to Effective: September 1, 2002 Western Systems Power Pool Issued on: July 2, 2002 Western Systems Power Pool Second Revised Sheet No. 7 Rate Schedule FERC No. 6 Superseding First Revised Sheet No. 7 4.4 Electric Utility: An entity or lawful association which (i) is a public utility, Independent Power Producer, or Power Marketer regulated under applicable state law or the Federal Power Act, or (ii) is exempted from such regulation under the Federal Power Act because it is the United States, a State or any political subdivision thereof or an agency of any of the foregoing, or a Rural Utilities Service cooperative, or (iii) is a public utility, Independent Power Producer, or Power Marketer located in Canada or Mexico that is similarly regulated. 4.4a ERCOT: Electric Reliability Council of Texas, Inc., the corporation that administers Texas's power grid and is a regional reliability council. 4.4b Event of Default: As defined in Section 22.1 of this Agreement. 4.5 Executive Committee: That committee established pursuant to Section 8 of this Agreement. 4.6 FERC: The Federal Energy Regulatory Commission or its regulatory successor. 4.7 Firm Capacity/Energy Sale or Exchange Service: Firm capacity and/or energy transaction whereby the Seller has agreed to sell or exchange and the Purchaser has agreed to buy or exchange for a specified period available capacity with or without associated energy which may include a Physically-Settled Option and a capacity transaction in accordance with the Agreement, including Service Schedule C, and any applicable Confirmation Agreement. Issued by: Michael E. Small, General Counsel to Effective: September 1, 2002 Western Systems Power Pool Issued on: July 2, 2002 Western Systems Power Pool Original Sheet No. 7A Rate Schedule FERC No. 6 4.7a First Party: As defined in Section 27 of this Agreement. 4.7b Floating Price: As defined in Section 38.1 of this Agreement. 4.7c Gains: As defined in Section 22.3 of this Agreement. 4.7d Guarantee Agreement: An agreement providing a guarantee issued by a parent company or another entity guaranteeing responsibility for specific obligations for transactions under this Agreement and Confirmation Agreements. A sample form of guarantee is provided in Exhibit B. 4.7e Guarantor: The entity providing a guarantee pursuant to a Guarantee Agreement. Issued by: Michael E. Small, General Counsel to Effective: September 1, 2002 Western Systems Power Pool Issued on: July 2, 2002 Western Systems Power Pool Second Revised Sheet No. 8 Rate Schedule FERC No. 6 Superseding First Revised Sheet No. 8 4.8 Hub: An electronic communication center that functions as a central point to electronically receive and assemble data for offers to buy or sell power or transmission service from each Party and make that data electronically available concurrently to all Parties. 4.9 Incremental Cost: The forecasted expense incurred by the Seller in providing an additional increment of energy or capacity during a given hour. 4.10 Independent Power Producer: An entity which is a non-traditional public utility that produces and sells electricity but which does not have a retail service franchise. 4.11 Interconnected Transmission System: The total of all transmission facilities owned or operated by the Parties, including transmission facilities over which Parties have scheduling rights. 4.11a Letter of Credit: An irrevocable, transferable, standby letter of credit, issued by an issuer acceptable to the Party requiring the Letter of Credit. 4.11b Losses: As defined in Section 22.3 of this Agreement. 4.11c Market Disruption Event: As defined in Section 38.2 of this Agreement. 4.11d NERC: North American Electric Reliability Council or any successor organization. 4.11e Non-Defaulting Party: As defined in Section 22.1(a) of this Agreement. 4.11f Non-Performing Party: As defined in Section 21.3(a) of this Agreement. Issued by: Michael E. Small, General Counsel to Effective: September 1, 2002 Western Systems Power Pool Issued on: July 2, 2002 Western Systems Power Pool Original Sheet No. 8A Rate Schedule FERC No. 6 4.11g Non-Standard Confirmation Provisions: As defined in Section 32.5 of this Agreement. 4.11h NYMEX: New York Mercantile Exchange, the physical commodity futures exchange and a trading forum for energy and precious metals. 4.12 Operating Agent: Arizona Public Service Company, or its successor as may be designated by the Executive Committee. 4.13 Operating Committee: That committee established pursuant to Section 8 of this Agreement. 4.13a Party or Parties: As defined in Section 1 of this Agreement. 4.13b Performing Party: As defined in Section 21.3(a) of this Agreement. Issued by: Michael E. Small, General Counsel to Effective: September 1, 2002 Western Systems Power Pool Issued on: July 2, 2002 Western Systems Power Pool First Revised Sheet No. 9 Rate Schedule FERC No. 6 Superseding Original Sheet No. 9 4.14 Power Marketer: An entity which buys, sells, and takes title to electric energy, transmission and/or other services from traditional utilities and other suppliers. 4.14a Physically-Settled Option: Includes (i) a call option which is the right, but not the obligation, to buy an underlying power product as defined under Service Schedules B or C according to the price and exercise terms set forth in the Confirmation Agreement; and (ii) a put option which is the right, but not the obligation, to sell an underlying power product as defined under Service Schedules B or C according to the price and exercise terms set forth in the Confirmation Agreement. 4.14b Premium: The amount paid by the Purchaser of a Physically-Settled Option to the Seller of such Option by the date agreed to by the Parties in the Confirmation Agreement. 4.14c Present Value Rate: As defined in Section 22.3(b) of this Agreement. 4.15 Purchaser: Any Party which agrees to buy or receive from one or more of the other Parties any service pursuant to the Agreement under any Service Schedule and any applicable Confirmation Agreement. 4.16 Qualifying Facility: A facility which is a qualifying small power production facility or a qualifying cogeneration facility as these terms are defined in Federal Power Act Sections 3(17)(A), 3(17)(C), 3(18)(A), and 3(18)(B); which meets the requirements set forth in 18 C.F.R. Sections 292.203-292.209; or a facility in Canada or Mexico that complies with similar requirements. Issued by: Michael E. Small, General Counsel to Effective: September 1, 2002 Western Systems Power Pool Issued on: July 2, 2002 Western Systems Power Pool Second Revised Sheet No. 10 Rate Schedule FERC No. 6 Superseding First Revised Sheet No. 10 4.16a Replacement Price: The price at which the Purchaser, acting in a commercially reasonable manner, effects a purchase of substitute electric energy in place of the electric energy not delivered by the Seller or, absent such a purchase, the market price for such quantity of electric energy, as determined by the Purchaser in a commercially reasonable manner, at the delivery point (agreed upon by the Seller and the Purchaser for the transaction). 4.16b Retail Entity: A retail aggregator or supplier or retail customer; provided, however, only those Retail Entities eligible for transmission service under the FERC's pro forma open access transmission tariff are eligible to become members of the WSPP. 4.16c Sales Price: The price at which the Seller, acting in a commercially reasonable manner, effects a resale of the electric energy not received by the Purchaser or, absent such a resale, the market price for such quantity of electric energy at the delivery point (agreed upon by the Seller and the Purchaser), as determined by the Seller in a commercially reasonable manner. 4.16d Second Party: As defined in Section 27 of this Agreement. 4.17 Seller: Any Party which agrees to sell or provide to one or more of the other Parties any service pursuant to the Agreement under any Service Schedule and any applicable Confirmation Agreement. 4.18 Service Schedule: A schedule of services established pursuant to Section 6 of this Agreement. Issued by: Michael E. Small, General Counsel to Effective: September 1, 2002 Western Systems Power Pool Issued on: July 2, 2002 Western Systems Power Pool First Revised Sheet No. 10A Rate Schedule FERC No. 6 Superseding Original Sheet No. 10A 4.18a Successor in Operation: The successor entity which takes over the wholesale electric trading operations of the first entity either through a merger or restructuring. A Successor in Operation shall not include an entity which merely acquires power sales contracts from the first entity either through a purchase or other means without taking over the wholesale electric trading operations of the first entity. 4.18b Terminated Transaction: As defined in Section 22.2 of this Agreement. 4.18c Termination Payment: As defined in Section 22.2 of this Agreement. 4.18d Trading Day: As defined in Section 38.2 of this Agreement. 4.19 Uncontrollable Forces: As defined in Section 10 of this Agreement or in a Confirmation Agreement. 4.20 Unit Commitment Service: A capacity and associated scheduled energy transaction or a Physically-Settled Option which the Seller has agreed to sell and the Purchaser has agreed to buy from a specified unit(s) for a specified period, in Issued by: Michael E. Small, General Counsel to Effective: September 1, 2002 Western Systems Power Pool Issued on: July 2, 2002 Western Systems Power Pool First Revised Sheet No. 11 Rate Schedule FERC No. 6 Superseding Original Sheet No. 11 accordance with the Agreement, including Service Schedule B, and any applicable Confirmation Agreement. 4.20a WSPP: The Western Systems Power Pool. 4.20b WSPP Default Transmission Tariff: The transmission tariff filed on behalf of WSPP Members with FERC as it may be amended from time to time. 4.20c WSPP Homepage: WSPP's internet web site, www.wspp.org. 5. TERM AND TERMINATION: 5.1 This Agreement shall become effective as of July 27, 1991 when acceptance or approvals required under Section 13.2 of this Agreement with respect to those Parties that are subject to FERC jurisdiction have been obtained; provided, however, that this Agreement shall not become effective as to any Party in the event the pre-grant of termination requested under Section 13.3 is not allowed by FERC, absent that Party's consent; and provided, further, that this Agreement shall not become effective as to any Party if any terms, conditions or requirements imposed by FERC are found unacceptable by that Party. This Agreement shall continue in effect for a period of ten (10) years from said effective date and thereafter on a year to year basis until terminated by the Parties; provided, however, that any Party may withdraw its participation at any time after the effective date of this Agreement on thirty (30) days prior written notice to all other Parties. Issued by: Michael E. Small, General Counsel to Effective: September 1, 2002 Western Systems Power Pool Issued on: July 2, 2002 Western Systems Power Pool Original Sheet No. 11A Rate Schedule FERC No. 6 5.2 As of the effective date of any withdrawal, the withdrawing Party shall have no further rights or obligations under this Agreement except the right to collect Issued by: Michael E. Small, General Counsel to Effective: September 1, 2002 Western Systems Power Pool Issued on: July 2, 2002 Western Systems Power Pool First Revised Sheet No. 12 Rate Schedule FERC No. 6 Superseding Original Sheet No. 12 money or receive service owed to it for transactions under any Service Schedule and the obligation to pay such amounts due to another Party and to complete any transactions agreed to under any Service Schedule as of said date. No Party shall oppose, before any court or regulatory agencies having jurisdiction, any other Party's withdrawal as provided in this Section. 5.3 Except as provided for in Section 5.2, after termination, or withdrawal with respect to the withdrawing Party, all rights to services provided under this Agreement or any tariff or rate schedule which results from or incorporates this Agreement shall cease, and no Party shall claim or assert any continuing right to such services under this Agreement. Except as provided for in Section 5.2, no Party shall be required to provide services based in whole or in part on the existence of this Agreement or on the provision of services under this Agreement beyond the termination date, or date of withdrawal with respect to the withdrawing Party. 6. SERVICE SCHEDULES AND WSPP DEFAULT TRANSMISSION TARIFF: 6.1 The Parties contemplate that they may, from time to time, add or remove Service Schedules under this Agreement. The attached Service Schedules A through C for Economy Energy Service, Unit Commitment Service, and Firm Capacity/Energy Sale or Exchange Service are hereby approved and made a part of this Agreement. Nothing contained herein shall be construed as affecting in any way the right of the Parties to jointly make application to FERC for a change Issued by: Michael E. Small, General Counsel to Effective: September 1, 2002 Western Systems Power Pool Issued on: July 2, 2002 Western Systems Power Pool Original Sheet No. 13 Rate Schedule FERC No. 6 in the rates and charges, classification, service, terms, or conditions affecting WSPP transactions under Section 205 of the Federal Power Act and pursuant to FERC rules and regulations promulgated thereunder. Subject to the provisions of Section 13, future Service Schedules, if any, shall be adopted only by amendment of this Agreement and shall be attached hereto and become a part of this Agreement. 6.2 [RESERVED] 6.3 When the WSPP Default Transmission Tariff applies as specified in the preamble to such Default Transmission Tariff, Transmission Service under it shall be available both to Parties and nonParties under this Agreement; provided, however, each Party or nonParty must be an eligible customer under the WSPP Default Transmission Tariff in order to receive service. 7. HUB AND OPERATING AGENT: 7.1 The Operating Agent shall act for itself and as agent for the Parties to carry out its designated responsibilities under this Agreement. 7.2 The Operating Agent shall, as directed by the Operating Committee pursuant to Section 8.2.4, and on behalf of the Parties, either (i) purchase or lease, and install or have installed, operate and maintain the necessary equipment to operate the Hub or (ii) contract for Hub services. Issued by: Michael E. Small, General Counsel to Effective: July 1, 2000 Western Systems Power Pool Issued on: September 29, 2000 Filed to comply with order of the Federal Energy Regulatory Commission, Docket Nos. ER00-3338, et al., issued September 15, 2000. Western Systems Power Pool Original Sheet No. 14 Rate Schedule FERC No. 6 7.3 The Operating Agent's estimated total costs to be incurred under Section 7.2 shall be subject to review by the Operating Committee and approval by the Executive Committee. 7.4 At least sixty (60) days prior to each calendar year that this Agreement is in effect, the Operating Agent shall prepare a budget for said year of operation under this Agreement and shall submit same to the Operating Committee for review, and to the Executive Committee for approval. Subsequent budget revisions shall be submitted to the Operating Committee for review and to the Executive Committee for approval. 7.5 The Operating Agent shall perform other administrative tasks necessary to implement this Agreement as directed by the Executive Committee. 7.6 Except as provided in Section 7.7, all Parties shall share equally in all costs of the Operating Agent incurred under this Agreement, including but not limited to initial FERC filing fees and any reasonable legal fees. 7.7 Each Party, in coordination with the Operating Agent, shall at its own expense acquire, install, operate, and maintain all necessary software and hardware on its system and the necessary communications link to the Hub to conduct transactions under this Agreement. 7.8 The Operating Agent shall bill the Parties for costs incurred under this Agreement on an estimated basis reasonably in advance of when due, and such billings shall be paid by the Parties when due. Such billings shall be adjusted in the following Issued by: Michael E. Small, General Counsel to Effective: July 1, 2000 Western Systems Power Pool Issued on: September 29, 2000 Filed to comply with order of the Federal Energy Regulatory Commission, Docket Nos. ER00-3338, et al., issued September 15, 2000. Western Systems Power Pool Original Sheet No. 15 Rate Schedule FERC No. 6 month(s) to reflect recorded costs. Billing and payment of the Operating Agent's costs shall otherwise be implemented in accordance with the provisions of Section 9. 7.9 The Operating Agent, at reasonable times and places, shall make available its records and documentation supporting costs for bills rendered under this Agreement for the inspection of any Party for a period of time not to exceed two (2) years from the time such bills were rendered. 7.9.1 A Party requesting review of the Operating Agent's records shall give the Operating Agent sufficient notice of its intent, but in no event less than thirty (30) days. 7.9.2 The requesting Party may perform this review using personnel from its own staff or designate a certified public accounting firm for the purpose of this review. 7.9.3 All costs incurred to perform this review shall be at the requesting Party's own expense. 7.9.4 The Party performing the review shall not voluntarily release the Operating Agent's records or disclose any information contained therein to any third party unless the written consent of the Operating Agent and the Executive Committee has been obtained. 7.10 Upon the termination of this Agreement, unless otherwise directed by the Executive Committee, the Operating Agent shall either dispose of any Hub Issued by: Michael E. Small, General Counsel to Effective: July 1, 2000 Western Systems Power Pool Issued on: September 29, 2000 Filed to comply with order of the Federal Energy Regulatory Commission, Docket Nos. ER00-3338, et al., issued September 15, 2000. Western Systems Power Pool Original Sheet No. 16 Rate Schedule FERC No. 6 equipment which it has purchased, or have the right of first refusal to purchase such equipment at original cost less depreciation, and shall apply any net proceeds from the sale of the Hub equipment against its costs incurred under this Agreement. The Operating Agent shall refund any excess proceeds equally to the Parties. 8. ORGANIZATION AND ADMINISTRATION: As a means of securing effective and timely cooperation within the activities hereunder and as a means of dealing on a prompt and orderly basis with various problems which may arise in connection with system coordination and operation under changing conditions, the Parties hereby establish an Executive Committee and an Operating Committee. 8.1 Executive Committee: The Executive Committee shall consist of one representative and an alternate from each Party designated pursuant to Section 8.5 herein. The responsibilities of the Executive Committee are as follows: 8.1.1 To establish sub-committees as it may from time to time deem necessary. 8.1.2 To review at least annually the service activities hereunder to ensure that such activities are consistent with the spirit and intent of this Agreement. 8.1.3 To review any unresolved issues which may arise hereunder and endeavor to resolve the issues. Issued by: Michael E. Small, General Counsel to Effective: July 1, 2000 Western Systems Power Pool Issued on: September 29, 2000 Filed to comply with order of the Federal Energy Regulatory Commission, Docket Nos. ER00-3338, et al., issued September 15, 2000. Western Systems Power Pool Original Sheet No. 17 Rate Schedule FERC No. 6 8.1.4 To review and approve the Operating Agent's annual budget under this Agreement, and any revision thereto, within thirty (30) days of recommendation by the Operating Committee. 8.1.5 To establish and approve any additional budgets under this Agreement as may be deemed necessary. 8.1.6 To review and recommend to the Parties for approval any additions or amendments to this Agreement, including Service Schedules. 8.1.7 To review and act on the application of an entity to become a Party to this Agreement. 8.1.8 To designate a successor to the Operating Agent, if necessary. 8.1.9 To do such other things and carry out such duties as specifically required or authorized by this Agreement; provided, however, that the Executive Committee shall have no authority to amend this Agreement. 8.1.10 To notify any Party of the rescission of its interest in this Agreement due to its failure to continue to meet the requirements of Section 16.1. 8.1.11 To arrange for legal representation for filing this Agreement (and any subsequent amendments) with FERC and supporting the Agreement (or amendments) in any FERC proceeding, and for other purposes as required. 8.2 Operating Committee: Issued by: Michael E. Small, General Counsel to Effective: July 1, 2000 Western Systems Power Pool Issued on: September 29, 2000 Filed to comply with order of the Federal Energy Regulatory Commission, Docket Nos. ER00-3338, et al., issued September 15, 2000. Western Systems Power Pool Original Sheet No. 18 Rate Schedule FERC No. 6 The Operating Committee shall consist of one representative and an alternate from each Party designated pursuant to Section 8.5. The responsibilities of the Operating Committee are as follows: 8.2.1 To establish, review, approve, or modify procedures and standard practices, consistent with the provisions hereof, for the guidance of load dispatchers and other operating employees in the Parties' electric systems as to matters affecting transactions under this Agreement. 8.2.2 To submit to the Executive Committee any proposed new or revised Service Schedules. 8.2.3 To establish, review, approve, or modify any scheduling or operating procedures required in connection with transactions under this Agreement. 8.2.4 To direct the Operating Agent in matters governed by this Agreement. 8.2.5 To review and make recommendations to the Executive Committee for approval of the Operating Agent's annual budget under this Agreement, including any proposed revisions thereto, within thirty (30) days of receipt from the Operating Agent. 8.2.6 To review and recommend as necessary the types and arrangement of equipment for intersystem communication facilities to enhance transactions and benefits under this Agreement. 8.2.7 To review the Operating Agent's estimated total costs of providing, having provided or contracting for a Hub. Issued by: Michael E. Small, General Counsel to Effective: July 1, 2000 Western Systems Power Pool Issued on: September 29, 2000 Filed to comply with order of the Federal Energy Regulatory Commission, Docket Nos. ER00-3338, et al., issued September 15, 2000. Western Systems Power Pool Original Sheet No. 19 Rate Schedule FERC No. 6 8.2.8 To review new member applications for membership to this Agreement and make recommendations on said applications to the Executive Committee. 8.2.9 To do such other things and carry out such duties as specifically required or authorized by this Agreement or as directed by the Executive Committee; provided, however, that the Operating Committee shall have no authority to amend this Agreement. 8.3 All matters which require Operating Committee or Executive Committee approval as provided in this Agreement shall be by no less than ninety percent (90%) affirmative agreement of the committee members present. 8.4 Unless otherwise agreed by all committee members, the chairperson of each committee shall provide the other Parties at least ten (10) Business Days advance notification of all committee meetings, including an agenda of matters to be discussed and voted on at the meeting. All material issues to be submitted to a vote of the committee shall appear on the agenda. Prior to the selection of a chairperson the Operating Agent shall provide such advance notice for the initial meeting of each committee. 8.5 Each Party shall give written notice to the other Parties of the name of its designated representative and alternate representative (to act in the absence of the designated representative) on each committee within thirty (30) days after the execution of this Agreement. Notice of any change of representative or alternate Issued by: Michael E. Small, General Counsel to Effective: July 1, 2000 Western Systems Power Pool Issued on: September 29, 2000 Filed to comply with order of the Federal Energy Regulatory Commission, Docket Nos. ER00-3338, et al., issued September 15, 2000. Western Systems Power Pool First Revised Sheet No. 20 Rate Schedule FERC No. 6 Superseding Original Sheet No. 20 representative shall be given by written notice to the other Parties. Each Party's designated representative shall be authorized to act on its behalf with respect to those committee responsibilities provided herein. 8.6 Each committee shall meet as necessary or at the request of any Party. 8.7 Each committee shall elect a chairperson and other officers at its first meeting. 9. PAYMENTS: 9.1 The accounting and billing period for transactions under Service Schedules to this Agreement shall be one (1) calendar month, unless otherwise specified in a Service Schedule agreed to through a Confirmation Agreement. Bills sent to any Party shall be sent to the appropriate billing address as set forth on the WSPP homepage or as otherwise specified by such Party. 9.2 Payments for amounts billed under Service Schedules hereto shall be paid so that such payments are received by the Party to be paid on the 20th day of the invoicing month or the tenth (10) day after receipt of the bill, whichever is later. Notwithstanding the foregoing, Premiums shall be paid within three (3) Business Days of receipt of the invoice therefor. Payment shall be made at the location designated by the Party to which payment is due. Payment shall be considered received when payment is received by the Party to which Payment is due at the location designated by that Party. If the due date falls on a non-Business Day of either Party, then the payment shall be due on the next following Business Day. Issued by: Michael E. Small, General Counsel to Effective: July 1, 2001 Western Systems Power Pool Issued on: May 2, 2001 Western Systems Power Pool Original Sheet No. 20A Rate Schedule FERC No. 6 9.3 Amounts not paid on or before the due date shall be payable with interest accrued at the rate of one percent (1%) per month, or the maximum interest rate permitted Issued by: Michael E. Small, General Counsel to Effective: July 1, 2001 Western Systems Power Pool Issued on: May 2, 2001 Western Systems Power Pool First Revised Sheet No. 21 Rate Schedule FERC No. 6 Superseding Original Sheet No. 21 by law, if any, whichever is less, prorated by days from the due date to the date of payment unless and until the Executive Committee shall determine another rate. 9.4 In case any portion of any bill is in dispute, the entire bill shall be paid when due. Any excess amount of bills which, through inadvertent errors or as a result of a dispute, may have been overpaid shall be returned by the owing Party upon determination of the correct amount, with interest accrued at the rate of one percent (1%) per month, or the maximum interest rate permitted by law, if any, whichever is less, prorated by days from the date of overpayment to the date of refund unless and until the Executive Committee shall determine another rate. The Parties shall have no rights to dispute the accuracy of any bill or payment after a period of two (2) years from the date on which the first bill was delivered for a specific transaction. 9.5 If a Party's records reveal that a bill was not delivered for a specific transaction, then the Party may deliver to the appropriate Party a bill within two (2) years from the date on which the bill would have been delivered under Section 9.1 of this Agreement. The right to payment is waived with respect to transactions, or portions thereof, not billed within such two (2) year period. 9.6 Each Party, or any third party representative of a Party, shall keep complete and accurate records, and shall maintain such data as may be necessary for the purpose of ascertaining the accuracy of all relevant data, estimates, or statements Issued by: Michael E. Small, General Counsel to Effective: July 1, 2001 Western Systems Power Pool Issued on: May 2, 2001 Western Systems Power Pool Original Sheet No. 21A Rate Schedule FERC No. 6 of charges submitted hereunder for a period of two (2) years from the date the first bill was delivered for a specific transaction completed under this Agreement. Issued by: Michael E. Small, General Counsel to Effective: July 1, 2001 Western Systems Power Pool Issued on: May 2, 2001 Western Systems Power Pool First Revised Sheet No. 22 Rate Schedule FERC No. 6 Superseding Original Sheet No. 22 Within a two (2) year period from the date the first bill was delivered under this Agreement, any Party to that transaction may request in writing copies of the records of the other Party for that transaction to the extent reasonably necessary to verify the accuracy of any statement or charge. The Party from which documents or data has been requested shall cooperate in providing the documents and data within a reasonable time period. 10. UNCONTROLLABLE FORCES: No Party shall be considered to be in breach of this Agreement or any applicable Confirmation Agreement to the extent that a failure to perform its obligations under this Agreement or any such Confirmation Agreement shall be due to an Uncontrollable Force. The term "Uncontrollable Force" means an event or circumstance which prevents one Party from performing its obligations under one or more transactions, which event or circumstance is not within the reasonable control of, or the result of the negligence of the claiming Party, and which by the exercise of due diligence, the claiming Party is unable to avoid, cause to be avoided, or overcome. "Uncontrollable Forces" may include and are not restricted to flood, drought, earthquake, storm, fire, lightning, epidemic, war, riot, civil disturbance or disobedience, labor dispute, labor or material shortage, sabotage, restraint by court order or public authority, and action or nonaction by, or failure to obtain the necessary authorizations or approvals from, any governmental agency or authority. Issued by: Michael E. Small, General Counsel to Effective: February 1, 2001 Western Systems Power Pool Issued on: December 1, 2000 Filed to comply with order of the Federal Energy Regulatory Commission, Docket Nos. ER00-3338, et al., issued September 15, 2000. Western Systems Power Pool Original Sheet No. 22A Rate Schedule FERC No. 6 The following shall not be considered "Uncontrollable Forces": (i) the price of electricity faced by Seller; or (ii) Purchaser's inability due to price to use or resell the power purchased hereunder. No Party shall, however, be relieved of liability for failure of performance to the extent that such failure is due to causes arising out of its own negligence or due to removable or remediable causes which it fails to remove or remedy within a reasonable time period. Nothing contained herein shall be construed to require a Issued by: Michael E. Small, General Counsel to Effective: February 1, 2001 Western Systems Power Pool Issued on: December 1, 2000 Filed to comply with order of the Federal Energy Regulatory Commission, Docket Nos. ER00-3338, et al., issued September 15, 2000. Western Systems Power Pool First Revised Sheet No. 23 Rate Schedule FERC No. 6 Superseding Original Sheet No. 23 Party to settle any strike or labor dispute in which it may be involved. Any Party rendered unable to fulfill any of its obligations by reason of an Uncontrollable Force shall give prompt notice of such fact and shall exercise due diligence, as provided above, to remove such inability within a reasonable time period. If oral notice is provided, it shall be promptly followed by written notice. Notwithstanding the "due diligence" obligations or obligations to remove or remedy the causes set forth in the foregoing paragraph (which do not apply to this paragraph except as specified below), where the entity providing transmission services for transactions under any Service Schedule interrupts such transmission service, the interruption in transmission service shall be considered an Uncontrollable Force under this Section 10 only in the following two sets of circumstances: (1) An interruption in transmission service shall be considered an Uncontrollable Force if (a) the Parties agreed on a transmission path for that transaction at the time the transaction under this Agreement was entered into by the Parties' thereto, (b) firm transmission involving that transmission path was obtained pursuant to a transmission tariff or contract to effectuate the transaction under the applicable Service Schedule, and (c) the entity providing transmission service curtailed or interrupted such firm transmission pursuant to the applicable transmission tariff or contract; (2) if the Parties did not agree on the transmission path for a transaction at the time the transaction was entered into, an interruption in transmission service shall be Issued by: Michael E. Small, General Counsel to Effective: July 1, 2000 Western Systems Power Pool Issued on: September 29, 2000 Filed to comply with order of the Federal Energy Regulatory Commission, Docket Nos. ER00-3338, et al., issued September 15, 2000. Western Systems Power Pool Original Sheet No. 24 Rate Schedule FERC No. 6 considered an Uncontrollable Force only if (a) the Party contracting for transmission services shall have made arrangements with the entity providing transmission service for firm transmission to effectuate the transaction under the applicable Service Schedule, (b) the entity providing transmission service curtailed or interrupted such transmission service due to an event of Uncontrollable Forces or provision of like effect, and (c) the Party which contracted for such firm transmission services could not obtain alternate energy at the delivery point, alternate transmission services, or alternate means of delivering energy after exercising due diligence. No Party shall be relieved by operation of this Section 10 of any liability to pay for power delivered to the Purchaser or to make payments then due or which the Party is obligated to make with respect to performance which occurred prior to the Uncontrollable Force. 11. WAIVERS: Any waiver at any time by any Party of its rights with respect to a default under this Agreement or any Confirmation Agreements, or any other matter under this Agreement, shall not be deemed a waiver with respect to any subsequent default of the same or any other matter. 12. NOTICES: 12.1 Except for the oral notice provided for in Section 10 of this Agreement, any formal notice, demand or request provided for in this Agreement shall be in Issued by: Michael E. Small, General Counsel to Effective: July 1, 2000 Western Systems Power Pool Issued on: September 29, 2000 Filed to comply with order of the Federal Energy Regulatory Commission, Docket Nos. ER00-3338, et al., issued September 15, 2000. Western Systems Power Pool First Revised Sheet No. 25 Rate Schedule FERC No. 6 Superseding Original Sheet No. 25 writing and shall be deemed properly served, given or made if delivered in person, or sent by either registered or certified mail (postage prepaid), prepaid telegram, fax, overnight delivery (with record of receipt), or other means agreed to by the Parties. 12.2 RESERVED 12.3 Notices and requests of a routine nature applicable to delivery or receipt of power or energy or operation of facilities shall be given in such manner as the committees from time to time or the Parties to a transaction shall prescribe. 13. APPROVALS: 13.1 This Agreement is subject to valid laws, orders, rules and regulations of duly constituted authorities having jurisdiction. Nothing contained in this Agreement shall give FERC jurisdiction over those Parties not otherwise subject to such jurisdiction or be construed as a grant of jurisdiction over any Party by any state or federal agency not otherwise having jurisdiction by law. 13.2 This Agreement, including any Service Schedule hereto, shall become effective as to any Party when it is accepted for filing by FERC, without changes or conditions unacceptable to such Party, for application to the Parties subject to FERC jurisdiction under the Federal Power Act; provided, however, that nothing in this Agreement is intended to restrict the authority of the Bonneville Power Administration (BPA) pursuant to applicable statutory authority to use its existing Issued by: Michael E. Small, General Counsel to Effective: September 1, 2002 Western Systems Power Pool Issued on: July 2, 2002 Western Systems Power Pool Original Sheet No. 25A Rate Schedule FERC No. 6 wholesale power and transmission rates or to adopt new rates, rate schedules, or general rate schedule provisions for application under this Agreement and obtain Issued by: Michael E. Small, General Counsel to Effective: September 1, 2002 Western Systems Power Pool Issued on: July 2, 2002 Western Systems Power Pool Original Sheet No. 26 Rate Schedule FERC No. 6 interim or final approval of those rates from FERC pursuant to Section 7 of the Pacific Northwest Electric Power Planning and Conservation Act, 16 U.S.C. Sec. 839e, provided such rates do not exceed the maximum rates in the applicable Service Schedule and are consistent with the terms and conditions of said Service Schedule. If, upon filing of this Agreement by Parties subject to FERC jurisdiction under the Federal Power Act, FERC orders a hearing to determine whether this Agreement or a Service Schedule under this Agreement is just and reasonable under the Federal Power Act, the Agreement or Service Schedule shall not become effective until the date when an order issued by FERC, determining this Agreement or the Service Schedule to be just and reasonable without changes or new conditions unacceptable to the Parties, is no longer subject to judicial review. Any changes or conditions imposed by any agency or court, including FERC ordering a hearing, shall be cause for immediate withdrawal by any nonconsenting Party. 13.3 The Parties subject to FERC jurisdiction under the Federal Power Act shall have the right to terminate their participation in this Agreement, and any rate schedule or services included herein, pursuant to the terms of Section 5 of this Agreement and without the necessity of further filing with or approval by FERC. 13.4 Any amendment or change in maximum rates specified in the Service Schedules shall not become effective with regard to any Party that is subject to FERC jurisdiction under the Federal Power Act until it is accepted for filing or Issued by: Michael E. Small, General Counsel to Effective: July 1, 2000 Western Systems Power Pool Issued on: September 29, 2000 Filed to comply with order of the Federal Energy Regulatory Commission, Docket Nos. ER00-3338, et al., issued September 15, 2000. Western Systems Power Pool First Revised Sheet No. 27 Rate Schedule FERC No. 6 Superseding Original Sheet No. 27 confirmed and approved by FERC as specified in and subject to the conditions of Section 13.2. 13.5 Nothing contained in this Agreement shall be construed to establish any precedent for any other agreement or to grant any rights to or impose any obligations on any Party beyond the scope and term of this Agreement. 14. TRANSFER OF INTEREST IN AGREEMENT: No Party shall voluntarily transfer its membership under this Agreement without the written consent and approval of all other Parties except to a Successor in Operation of such Party. With regard to the transfer of the rights and obligations of any Party associated with transactions under the Service Schedules, neither Party may assign such rights or obligations unless (a) the other Party provides its prior written consent which shall not be unreasonably withheld; or (b) the assignment is to a Successor in Operation which provides reasonable creditworthiness assurances (see Section 27 for examples of such assurances) if required by the non-assigning Party based upon its reasonably exercised discretion. Any successor or assignee of the rights of any Party, whether by voluntary transfer, judicial or foreclosure sale or otherwise, shall be subject to all the provisions and conditions of this Agreement and Confirmation Agreements (where applicable) to the same extent as though such successor or assignee were the original Party under this Agreement or the Confirmation Agreements, and no assignment or transfer of any rights under this Agreement or any Confirmation Issued by: Michael E. Small, General Counsel to Effective: September 1, 2002 Western Systems Power Pool Issued on: July 2, 2002 Western Systems Power Pool Original Sheet No. 27A Rate Schedule FERC No. 6 Agreement shall be effective unless and until the assignee or transferee agrees in writing to assume all of the obligations of the assignor or transferor and to be bound by all of the provisions and Issued by: Michael E. Small, General Counsel to Effective: September 1, 2002 Western Systems Power Pool Issued on: July 2, 2002 Western Systems Power Pool First Revised Sheet No. 28 Rate Schedule FERC No. 6 Superseding Original Sheet No. 28 conditions of this Agreement and any Confirmation Agreement (where applicable). The execution of a mortgage or trust deed or a judicial or foreclosure sale made thereunder shall not be deemed a voluntary transfer within the meaning of this Section 14. 15. SEVERABILITY: In the event that any of the terms, covenants or conditions of this Agreement or any Confirmation Agreement, or the application of any such term, covenant or condition, shall be held invalid as to any person or circumstance by any court, regulatory agency, or other regulatory body having jurisdiction, all other terms, covenants or conditions of this Agreement and the Confirmation Agreement and their application shall not be affected thereby, but shall remain in force and effect unless a court, regulatory agency, or other regulatory body holds that the provisions are not separable from all other provisions of this Agreement or such Confirmation Agreement. 16. MEMBERSHIP: 16.1 Any Electric Utility, Retail Entity or Qualifying Facility may become a Party to this Agreement. The Executive Committee shall notify such Electric Utility, Retail Entity or Qualifying Facility of its decision within sixty (60) days of a request to become a Party to this Agreement, and any acceptable entity shall become a Party hereto by the execution of this Agreement or a counterpart hereof, payment of costs pursuant to Section 16.4, and concluding any necessary acceptance or approval referred to in Section 13. Any such Party, if it is subject to the ratemaking jurisdiction of FERC, Issued by: Michael E. Small, General Counsel to Effective: July 1, 2001 Western Systems Power Pool Issued on: May 2, 2001 Western Systems Power Pool Original Sheet No. 29 Rate Schedule FERC No. 6 shall be responsible for any FERC filing necessary for it to implement its performance under this Agreement. 16.2 Each Party shall continue to meet the requirements of Section 16.1 in order to remain a Party to this Agreement 16.3 Being a Party to this Agreement shall not serve as a substitute for contractual arrangements that may be needed between any Party which operates a Control Area and any other Party which operates within that Control Area. 16.4 Any entity that becomes a Party to this Agreement which was not a party to the experimental Western Systems Power Pool Agreement shall pay a one time fee of $25,000 under this Agreement in recognition of prior efforts and costs incurred by the parties to the experimental Western Systems Power Pool Agreement, which efforts greatly facilitated development of this Agreement. Such fee shall be credited to future costs of the Operating Agent incurred hereunder. 17. RELATIONSHIP OF PARTIES: 17.1 Nothing contained herein or in any Confirmation Agreement shall be construed to create an association, joint venture, trust, or partnership, or impose a trust or partnership covenant, obligation, or liability on or with regard to any one or more of the Parties. Each Party shall be individually responsible for its own covenants, obligations, and liabilities under this Agreement and under any applicable Confirmation Agreement. Issued by: Michael E. Small, General Counsel to Effective: July 1, 2000 Western Systems Power Pool Issued on: September 29, 2000 Filed to comply with order of the Federal Energy Regulatory Commission, Docket Nos. ER00-3338, et al., issued September 15, 2000. Western Systems Power Pool Second Revised Sheet No. 30 Rate Schedule FERC No. 6 Superseding First Revised Sheet No. 30 17.2 All rights of the Parties are several, not joint. No Party shall be under the control of or shall be deemed to control another Party. Except as expressly provided in this Agreement, no Party shall have a right or power to bind another Party without its express written consent. 18. NO DEDICATION OF FACILITIES: Any undertaking by one Party to another Party under any provision of this Agreement shall not constitute the dedication of the electric system or any portion thereof of the undertaking Party to the public or to the other Party, and it is understood and agreed that any such undertaking under any provision of this Agreement by a Party shall cease upon the termination of such Party's obligations under this Agreement. 19. NO RETAIL SERVICES: Nothing contained in this Agreement shall grant any rights to or obligate any Party to provide any services hereunder directly to or for retail customers of any Party. 20. THIRD PARTY BENEFICIARIES: This Agreement shall not be construed to create rights, in, or to grant remedies to, any third party as a beneficiary of this Agreement or of any duty, obligation or undertaking established herein except as provided for in Section 14. 21. LIABILITY AND DAMAGES: 21.1a This Agreement contains express remedies or measures of damages in Sections 21.3 and 22 for non-performance or default. Issued by: Michael E. Small, General Counsel to Effective: September 1, 2002 Western Systems Power Pool Issued on: July 2, 2002 Western Systems Power Pool First Revised Sheet No. 30A Rate Schedule FERC No. 6 Superseding Original Sheet No. 30A ALL OTHER DAMAGES OR REMEDIES ARE HEREBY WAIVED. Therefore, except as provided in Sections 21.3 and 22, no Party or its directors, members of its governing bodies, officers or employees shall be liable to any other Party or Parties for any loss or damage to property, loss of earnings. 21.1b Notwithstanding any other provision in this Agreement, any Party due monies under this Agreement, the amounts of which are not in dispute or if disputed have been the subject of a decision awarding such amounts, (i) shall have the right to seek payment of such monies in any forum having competent jurisdiction and (ii) shall possess the right to seek relief directly from that forum without first utilizing the mediation or arbitration provisions of this Agreement. Issued by: Michael E. Small, General Counsel to Effective: September 1, 2002 Western Systems Power Pool Issued on: July 2, 2002 Western Systems Power Pool Original Sheet No. 31 Rate Schedule FERC No. 6 or revenues, personal injury, or any other direct, indirect, or consequential damages or injury, or punitive damages, which may occur or result from the performance or non-performance of this Agreement (including any applicable Confirmation Agreement), including any negligence arising hereunder. Any liability or damages faced by an officer or employee of a Federal agency or by that agency that would result from the operation of this provision shall not be inconsistent with Federal law. 21.2 [RESERVED] 21.3 The following damages provision shall apply to transactions under Service Schedules B and C. For transactions under Service Schedule A, this damages provision or some other damages provision will apply only if such a damages provision is agreed to through a Confirmation Agreement. The damages under this Section 21.3 apply to a Party's failure to deliver or receive electric power or energy in violation of the terms of the Agreement and any Confirmation Agreement. The Contract Quantity and Contract Price referred to in this Section 21.3 are part of the agreement between the Parties for which damages are being calculated under this Section. (a) If either Party fails to deliver or receive, as the case may be, the quantities of electric power or energy due under the Agreement and any Confirmation Agreement (thereby becoming a "Non-Performing Party" for the purposes of this Section 21.3), the other party (the "Performing Issued by: Michael E. Small, General Counsel to Effective: July 1, 2000 Western Systems Power Pool Issued on: September 29, 2000 Filed to comply with order of the Federal Energy Regulatory Commission, Docket Nos. ER00-3338, et al., issued September 15, 2000. Western Systems Power Pool Original Sheet No. 32 Rate Schedule FERC No. 6 Party") shall be entitled to receive from the Non-Performing Party an amount calculated as follows (unless performance is excused by Uncontrollable Forces as provided in Section 10, the applicable Service Schedule, or by the Performing Party): (1) If the amount the Purchaser scheduled or received in any hour is less than the applicable hourly Contract Quantity, then the Purchaser shall be liable for (a) the product of the amount (whether positive or negative), if any, by which the Contract Price differed from the Sales Price (Contract Price - Sales Price) and the amount by which the quantity received by the Purchaser was less than the hourly Contract Quantity; plus (b) the amount of transmission charge(s), if any, for firm transmission service upstream of the delivery point, which the Seller incurred to achieve the Sales Price, less the reduction, if any, in transmission charge(s) achieved as a result of the reduction in the Purchaser's schedule or receipt of electric energy (based on Seller's reasonable commercial efforts to achieve such reduction). If the total amounts for all hours calculated under this paragraph (1) are negative, then neither the Purchaser nor the Seller shall pay any amount under this Section 21.3(a)(1). Issued by: Michael E. Small, General Counsel to Effective: July 1, 2000 Western Systems Power Pool Issued on: September 29, 2000 Filed to comply with order of the Federal Energy Regulatory Commission, Docket Nos. ER00-3338, et al., issued September 15, 2000. Western Systems Power Pool Original Sheet No. 33 Rate Schedule FERC No. 6 (2) If the amount the Seller scheduled or delivered in any hour is less than the applicable hourly Contract Quantity, then the Seller shall be liable for (a) the product of the amount (whether positive or negative), if any, by which the Replacement Price differed from the Contract Price (Replacement Price - Contract Price) and the amount by which the quantity delivered by the Seller was less than the hourly Contract Quantity; plus (b) the amount of transmission charge(s), if any, for firm transmission service downstream of the delivery point, which the Purchaser incurred to achieve the Replacement Price, less the reduction, if any, in transmission charge(s) achieved as a result of the reduction in the Seller's schedule or delivery (based on Purchaser's reasonable commercial effort to achieve such reduction). If the total amounts for all hours calculated under this paragraph (2) are negative, then neither the Purchaser nor the Seller shall pay any amount under this Section 21.3(a)(2). (3) The Non-Performing Party shall pay any amount due from it under this section within the billing period as specified in Section 9 of this Agreement or agreed to in the applicable Confirmation Agreement if the Parties agreed to revise the billing period in Section 9. Issued by: Michael E. Small, General Counsel to Effective: July 1, 2000 Western Systems Power Pool Issued on: September 29, 2000 Filed to comply with order of the Federal Energy Regulatory Commission, Docket Nos. ER00-3338, et al., issued September 15, 2000. Western Systems Power Pool Original Sheet No. 34 Rate Schedule FERC No. 6 (b) The Parties agree that the amounts recoverable under this Section 21.3 are a reasonable estimate of loss and not a penalty, and represent the sole and exclusive remedy for the Performing Party. Such amounts are payable for the loss of bargain and the loss of protection against future risks. (c) Each Party agrees that it has a duty to mitigate damages in a commercially reasonable manner to minimize any damages it may incur as a result of the other Party's performance or non-performance of this Agreement. (d) In the event the Non-Performing Party disputes the calculation of the damages under this Section 21.3, the Non-Performing Party shall pay the full amount of the damages as required by Section 9 of this Agreement to the Performing Party. After informal dispute resolution as required by Section 34.1, any remaining dispute involving the calculation of the damages shall be referred to binding dispute resolution as provided by Section 34.2 of this Agreement. If resolution or agreement results in refunds or the need for refunds to the Non-Performing Party, such refunds shall be calculated in accordance with Section 9.4 of this Agreement. 22. DEFAULT OF TRANSACTIONS UNDER THIS AGREEMENT AND CONFIRMATION AGREEMENTS: 22.1 EVENTS OF DEFAULT An "Event of Default" shall mean with respect to a Party ("Defaulting Party"): Issued by: Michael E. Small, General Counsel to Effective: July 1, 2000 Western Systems Power Pool Issued on: September 29, 2000 Filed to comply with order of the Federal Energy Regulatory Commission, Docket Nos. ER00-3338, et al., issued September 15, 2000. Western Systems Power Pool First Revised Sheet No. 35 Rate Schedule FERC No. 6 Superseding Original Sheet No. 35 (a) the failure by the Defaulting Party to make, when due, any payment required pursuant to this Agreement or Confirmation Agreement if such failure is not remedied within two (2) Business Days after written notice of such failure is given to the Defaulting Party by the other Party ("the Non-Defaulting Party"). The Non-Defaulting Party shall provide the notice by facsimile to the designated contact person for the Defaulting Party and also shall send the notice by overnight delivery to such contact person; or (b) the failure by the Defaulting Party to provide clear and good title as required by Section 33.3, or to have made accurate representations and warranties as required by Section 37 and such failure is not cured within five (5) Business Days after written notice thereof to the Defaulting Party; or (c) The institution, with respect to the Defaulting Party, by the Defaulting Party or by another person or entity of a bankruptcy, reorganization, moratorium, liquidation or similar insolvency proceeding or other relief under any bankruptcy or insolvency law affecting creditor's rights or a petition is presented or instituted for its winding-up or liquidation; or (d) The failure by the Defaulting Party to provide adequate assurances of its ability to perform all of its outstanding material obligations to the Non-Defaulting Party under the Agreement or Confirmation Agreement Issued by: Michael E. Small, General Counsel to Effective: February 1, 2001 Western Systems Power Pool Issued on: December 1, 2000 Filed to comply with order of the Federal Energy Regulatory Commission, Docket Nos. ER00-3338, et al., issued September 15, 2000. Western Systems Power Pool Second Revised Sheet No. 36 Rate Schedule FERC No. 6 Superseding First Revised Sheet No. 36 pursuant to Section 27 of this Agreement or any substitute or modified provision in the Confirmation Agreement. (e) With respect to its Guarantor, if any: (i) if a material representation or warranty made by a Guarantor in connection with this Agreement, or any transaction entered into hereunder, is false or misleading in any material respect when made or when deemed made or repeated; or (ii) the failure of a Guarantor to make any payment required or to perform any other material covenant or obligation in any guarantee made in connection with this Agreement, including any transaction entered into hereunder, and such failure shall not be remedied within three (3) Business Days after written notice; or (iii) the institution, with respect to the Guarantor, by the Guarantor or by another person or entity of a bankruptcy, reorganization, moratorium, liquidation or similar insolvency proceeding or other relief under any bankruptcy or insolvency law affecting creditor's rights or a petition is presented or instituted for its winding-up or liquidation; or (iv) the failure, without written consent of the other Party, of a Guarantor's guarantee to be in full force and effect for purposes of this Agreement (other than in accordance with its terms) prior to Western Systems Power Pool First Revised Sheet No. 36A Rate Schedule FERC No. 6 Superseding Original Sheet No. 36A the satisfaction of all obligations of such Party under each transaction to which such guarantee shall relate; or (v) a Guarantor shall repudiate, disaffirm, disclaim, or reject, in whole or in part, or challenge the validity of, any guarantee. 22.2 REMEDIES FOR EVENTS OF DEFAULT If an Event of Default occurs, the Non-Defaulting Party shall possess the right to terminate all transactions between the Parties under this Agreement upon written notice (by facsimile or other reasonable means) to the Defaulting Party, such notice of termination to be effective immediately upon receipt. If the Non-Defaulting Party fails to exercise this right of termination within thirty (30) days following the time when the Event of Default becomes known (or more than thirty days if the Non-Defaulting and Defaulting Parties agree to an extension), then such right of termination shall no longer be available to the Non-Defaulting Party as a remedy for the Event(s) of Default. The Non-Defaulting Party terminating transaction(s) under this Section 22.2 may do so without making a filing at FERC. Upon termination, the Non-Defaulting Party shall liquidate all transactions as soon as practicable, provided that in no event will the Non-Defaulting Party be allowed to liquidate Service Schedule A transactions. The payment associated with termination ("Termination Payment") shall be calculated in accordance with this Section 22.2 and Section 22.3. The Termination Payment shall be the sole and exclusive remedy for the Non-Defaulting Party for each terminated Issued by: Michael E. Small, General Counsel to Effective: September 1, 2002 Western Systems Power Pool Issued on: July 2, 2002 Western Systems Power Pool Original Sheet No. 36B Rate Schedule FERC No. 6 transaction ("Terminated Transaction") for the time period beginning at the time notice of termination under this Section 22 is received. Prior to receipt Issued by: Michael E. Small, General Counsel to Effective: September 1, 2002 Western Systems Power Pool Issued on: July 2, 2002 Western Systems Power Pool Original Sheet No. 37 Rate Schedule FERC No. 6 of such notice of termination by the Defaulting Party, the Non-Defaulting Party may exercise any remedies available to it under Section 21.3 of this Agreement or Confirmation Agreement(s), and any other remedies available to it at law or otherwise. Upon termination, the Non-Defaulting Party may withhold any payments it owes the Defaulting Party for any obligations incurred prior to termination under this Agreement or Confirmation Agreement(s) until the Defaulting Party pays the Termination Payment to the Non-Defaulting Party. The Non-Defaulting Party shall possess the right to set-off the amount due it under this Section 22 by any such payments due the Defaulting Party as provided in Section 22.3(d). 22.3 LIQUIDATION CALCULATION OPTIONS The Non-Defaulting Party shall calculate the Termination Payment as follows: (a) The Gains and Losses shall be determined by comparing the value of the remaining term, transaction quantities, and transaction prices under each Terminated Transaction had it not been terminated to the equivalent quantities and relevant market prices for the remaining term either quoted by a bona fide third-party offer or which are reasonably expected to be available in the market under a replacement contract for each Terminated Transaction. To ascertain the market prices of a replacement contract, the Non-Defaulting Party may consider, among other valuations, quotations Issued by: Michael E. Small, General Counsel to Effective: July 1, 2000 Western Systems Power Pool Issued on: September 29, 2000 Filed to comply with order of the Federal Energy Regulatory Commission, Docket Nos. ER00-3338, et al., issued September 15, 2000. Western Systems Power Pool First Revised Sheet No. 38 Rate Schedule FERC No. 6 Superseding Original Sheet No. 38 from Dealers in energy contracts, any or all of the settlement prices of the NYMEX power futures contracts (or NYMEX power options contracts in the case of Physically-Settled Options) and other bona fide third party offers, all adjusted for the length of the remaining term and differences in transmission. It is expressly agreed that the Non-Defaulting Party shall not be required to enter into replacement transactions in order to determine the Termination Payment. (b) The Gains and Losses calculated under paragraph (a) shall be discounted to present value using the Present Value Rate as of the time of termination (to take account to the period between the time notice of termination was effective and when such amount would have otherwise been due pursuant to the relevant transaction). The "Present Value Rate" shall mean the sum of 0.50% plus the yield reported on page "USD" of the Bloomberg Financial Markets Services Screen (or, if not available, any other nationally recognized trading screen reporting on-line intraday trading in United States government securities) at 11:00 a.m. (New York City, New York time) for the United States government securities having a maturity that matches the average remaining term of the Terminated Transactions; and (c) The Non-Defaulting Party shall set off or aggregate, as appropriate, the Gains and Losses (as calculated in Section 22.3(a)) and Costs and notify Issued by: Michael E. Small, General Counsel to Effective: September 1, 2002 Western Systems Power Pool Issued on: July 2, 2002 Western Systems Power Pool Original Sheet No. 39 Rate Schedule FERC No. 6 the Defaulting Party. If the Non-Defaulting Party's aggregate Losses and Costs exceed its aggregate Gains, the Defaulting Party shall, within three (3) Business Days of receipt of such notice, pay the Termination Payment to the Non-Defaulting Party, which amount shall bear interest at the Present Value rate from the time notice of termination was received until paid. If the Non-Defaulting Party's aggregate Gains exceed its aggregate Losses and Costs, the Non-Defaulting Party, after any set-off as provided in paragraph (d), shall pay the remaining amount to the Defaulting Party within three (3) Business Days of the date notice of termination was received including interest at the Present Value from the time notice of termination was received until the Defaulting Party receives payment. (d) The Non-Defaulting Party shall aggregate or set off, as appropriate, at its election, any or all other amounts owing between the Parties (discounted at the Present Value Rate) under this Agreement and any Confirmation Agreements against the Termination Payment so that all such amounts are aggregated and/or netted to a single liquidated amount. The net amount due from any such liquidation shall be paid within three (3) Business Days following the date notice of termination is received. If the Defaulting Party disagrees with the calculation of the Termination Payment and the Parties cannot otherwise resolve their differences, the calculation issue shall be submitted to informal dispute resolution as provided in Section 34.1 Issued by: Michael E. Small, General Counsel to Effective: July 1, 2000 Western Systems Power Pool Issued on: September 29, 2000 Filed to comply with order of the Federal Energy Regulatory Commission, Docket Nos. ER00-3338, et al., issued September 15, 2000. Western Systems Power Pool First Revised Sheet No. 40 Rate Schedule FERC No. 6 Superseding Original Sheet No. 40 of this Agreement and thereafter binding dispute resolution pursuant to Section 34.2 if the informal dispute resolution does not succeed in resolving the dispute. Pending resolution of the dispute, the Defaulting Party shall pay the full amount of the Termination Payment calculated by the Non-Defaulting Party within three (3) Business Days of receipt of notice as set forth in Sections 22.3(c) and (d) subject to the Non-Defaulting Party refunding, with interest, pursuant to Section 9.4, any amounts determined to have been overpaid. For purposes of this Section 22.3: (i) "Gains" means the economic benefit (exclusive of Costs), if any, resulting from the termination of the Terminated Transactions, determined in a commercially reasonable manner as calculated in accordance with this Section 22.3; (ii) "Losses" means the economic loss (exclusive of Costs), if any, resulting from the termination of the Terminated Transactions, determined in a commercially reasonable manner as calculated in accordance with this Section 22.3; (iii) "Costs" means brokerage fees, commissions and other similar transaction costs and expenses reasonably incurred in terminating any specifically related arrangements which replace a Terminated Transaction, transmission and ancillary service costs associated with Terminated Transactions, and reasonable attorneys' fees, if any, incurred in connection Issued by: Michael E. Small, General Counsel to Effective: September 1, 2002 Western Systems Power Pool Issued on: July 2, 2002 Western Systems Power Pool Original Sheet No. 41 Rate Schedule FERC No. 6 with the Non-Defaulting Party enforcing its rights with regard to the Terminated Transactions. The Non-Defaulting Party shall use reasonable efforts to mitigate or eliminate these Costs. (iv) In no event, however, shall a Party's Gains, Losses or Costs include any penalties or similar charges imposed by the Non-Defaulting Party. 22A. DEFAULT IN PAYMENT OF WSPP OPERATING COSTS: 22A.1 A Party shall be deemed to be in default in payment of its share of WSPP operating costs pursuant to Section 7 of this Agreement, if any, when payment is not received within ten (10) days after receipt of written notice. A default by any Party in such payment obligations shall be cured by payment of all overdue amounts together with interest accrued at the rate of one percent (1%) per month, or the maximum interest rate permitted by law, if any, whichever is less, prorated by days from the due date to the date the payment curing the default is made unless and until the Executive Committee shall determine another rate. 22A.2 A defaulting Party, which is in default under Section 22.A1, shall be liable for all costs, including costs of collection and reasonable attorney fees, plus interest as provided in Section 22.A1 hereof. 22A.3 The rights under this Agreement of a Party which is in default of its obligation to pay operating costs under this Agreement for a period of three (3) months or more may be revoked by a vote of the non-defaulting Issued by: Michael E. Small, General Counsel to Effective: July 1, 2000 Western Systems Power Pool Issued on: September 29, 2000 Filed to comply with order of the Federal Energy Regulatory Commission, Docket Nos. ER00-3338, et al., issued September 15, 2000. Western Systems Power Pool Original Sheet No. 42 Rate Schedule FERC No. 6 Parties' representatives on the Executive Committee consistent with Section 8.3. The defaulting Party's rights shall not be revoked, however, unless said Party has received at least thirty (30) days written notice of the non-defaulting Parties' intent to revoke such rights. Said notice shall state the date on which the revocation of rights shall become effective if the default is not cured and shall state all actions which must be taken or amounts which must be paid to cure the default. This provision allowing the non-defaulting Parties to revoke such rights is in addition to any other remedies provided in this Agreement or at law and shall in no way limit the non-defaulting Parties' ability to seek judicial enforcement of the defaulting Party's obligations to pay its share of the operating costs under this Agreement. Upon the effective date of such revocation of rights, the defaulting party shall not be allowed to enter into any new transactions under this Agreement. The defaulting party under the Agreement or any Confirmation Agreements shall be required to carry out all obligations that existed prior to the effective date of such revocation. If a defaulting Party's rights under this Agreement have been revoked, the Executive Committee may restore that Party's rights upon the defaulting Party paying all amounts due and owing under this Agreement. 22A.4 Upon revocation of the rights of a defaulting Party under this Agreement, Operating Agent costs hereunder shall be equally shared among the Issued by: Michael E. Small, General Counsel to Effective: July 1, 2000 Western Systems Power Pool Issued on: September 29, 2000 Filed to comply with order of the Federal Energy Regulatory Commission, Docket Nos. ER00-3338, et al., issued September 15, 2000. Western Systems Power Pool First Revised Sheet No. 43 Rate Schedule FERC No. 6 Superseding Original Sheet No. 43 remaining Parties. Cost allocation adjustments shall be retroactive to the date of the default. 23. OTHER AGREEMENTS: No provision of this Agreement shall preclude any Party from entering into other agreements or conducting transactions under existing agreements with other Parties or third parties. This Agreement shall not be deemed to modify or change any rights or obligations under any prior contracts or agreements between or among any of the Parties. 24. GOVERNING LAW: This Agreement and any Confirmation Agreement shall be governed by and construed in accordance with the laws of the State of Utah, without regard to the conflicts of laws rules thereof. The foregoing notwithstanding, (1) if both the Seller and Purchaser are organized under the laws of Canada, then the laws of the province of the Seller shall govern, or (2) if the Seller or Purchaser is an agency of or part of the United States Government, then the laws of the United States of America shall govern. 25. JUDGMENTS AND DETERMINATIONS: Whenever it is provided in this Agreement that a Party shall be the sole judge of whether, to what extent, or under what conditions it will provide a given service, its exercise of its judgment shall be final and not subject to challenge. Whenever it is provided that (i) a service under a given transaction may be curtailed under certain conditions or circumstances, the existence of which are determined by or in the judgment of a Party, or (ii) the existence of qualifications for membership shall be determined by Issued by: Michael E. Small, General Counsel to Effective: September 1, 2002 Western Systems Power Pool Issued on: July 2, 2002 Western Systems Power Pool Original Sheet No. 44 Rate Schedule FERC No. 6 the Executive Committee pursuant to Section 16, that Party's or the Executive Committee's determination or exercise of judgment shall be final and not subject to challenge if it is made in good faith and not made arbitrarily or capriciously. 26. COMPLETE AGREEMENT: This Agreement and any subsequent amendments, including the Service Schedules and Exhibits incorporated herein, and any Confirmation Agreement, shall constitute the full and complete agreement of the Parties with respect to the subject matter hereof, and all prior or contemporaneous representations, statements, negotiations, understandings and inducements are fully merged and incorporated in this Agreement. 27. CREDITWORTHINESS: Should a Party's creditworthiness, financial responsibility, or performance viability become unsatisfactory to the other Party in such other Party's reasonably exercised discretion with regard to any transaction pursuant to this Agreement and any Confirmation Agreement (after the transaction is agreed to or begins), the dissatisfied Party (the "First Party") may require the other Party (the "Second Party") to provide, at the Second Party's option (but subject to the First Party's acceptance based upon reasonably exercised discretion), either (1) the posting of a Letter of Credit, (2) a cash prepayment, (3) the posting of other acceptable collateral or security by the Second Party, (4) a Guarantee Agreement executed by a creditworthy entity; or (5) some other mutually agreeable method of satisfying the First Party. The Second Party's obligations under this Section 27 shall be limited to a reasonable estimate of the damages to the First Party Issued by: Michael E. Small, General Counsel to Effective: July 1, 2000 Western Systems Power Pool Issued on: September 29, 2000 Filed to comply with order of the Federal Energy Regulatory Commission, Docket Nos. ER00-3338, et al., issued September 15, 2000. Western Systems Power Pool Original Sheet No. 45 Rate Schedule FERC No. 6 (consistent with Section 21.3 of this Agreement) if the Second Party were to fail to perform its obligations. Events which may trigger the First Party questioning the Second Party's creditworthiness, financial responsibility, or performance viability include, but are not limited to, the following: (1) The First Party has knowledge that the Second Party (or its Guarantor if applicable) are failing to perform or defaulting under other contracts. (2) The Second Party has exceeded any credit or trading limit set out in the Confirmation Agreement or other agreement between the Parties. (3) The Second Party or its Guarantor has debt which is rated as investment grade and that debt falls below the investment grade rating by at least one rating agency or is below investment grade and the rating of that debt is downgraded further by at least one rating agency. (4) Other material adverse changes in the Second Party's financial condition occur. (5) Substantial changes in market prices which materially and adversely impact the Second Party's ability to perform under this Agreement or any Confirmation Agreement occur. If the Second Party fails to provide such reasonably satisfactory assurances of its ability to perform a transaction hereunder within three (3) Business Days of demand therefore, that will be considered an Event of Default under Section 22 of this Agreement and the First Party shall have the right to exercise any of the remedies provided for under Issued by: Michael E. Small, General Counsel to Effective: July 1, 2000 Western Systems Power Pool Issued on: September 29, 2000 Filed to comply with order of the Federal Energy Regulatory Commission, Docket Nos. ER00-3338, et al., issued September 15, 2000. Western Systems Power Pool First Revised Sheet No. 46 Rate Schedule FERC No. 6 Superseding Original Sheet No. 46 that Section 22. Nothing contained in this Section 27 shall affect any credit agreement or arrangement, if any, between the Parties. 28. NETTING: 28.1 If the Purchaser and the Seller are each required to pay an amount to each other in the same calendar month for transactions under this Agreement, then such amounts with respect to each Party may be aggregated and the Parties may discharge their obligations to pay through netting of the respective amounts due, in which case the Party, if any, owing the greater aggregate amount may pay to the other Party the difference between the amounts owed. Each Party reserves to itself all rights, set-offs, counterclaims, and other remedies and defenses (to the extent not expressly herein waived or denied) which such Party has or may be entitled to arising from or out of this Agreement and any applicable Confirmation Agreements. 28.2 Parties shall net payments (associated with transactions under this Agreement and Confirmation Agreement) in accordance with Exhibit A, if such Parties have executed the form attached as Exhibit A. The Parties obligation to net shall include the netting of all payments received by the Parties in the same calendar month. Parties that have executed Exhibit A shall provide a signed copy of Issued by: Michael E. Small, General Counsel to Effective: March 1, 2002 Western Systems Power Pool Issued on: December 21, 2001 Western Systems Power Pool First Revised Sheet No. 47 Rate Schedule FERC No. 6 Superseding Original Sheet No. 47 Exhibit A to a representative of the WSPP and to any Party that requests a copy and indicate on the WSPP Homepage that they have so executed Exhibit A (once the WSPP Homepage possesses the necessary capability). If a Party indicated its election to net payments on the WSPP Homepage and that Party desires to withdraw its agreement to net, that Party shall provide at least 30 days notice on the WSPP Homepage of the change in its election to net and also shall provide, concurrent with its withdrawal notice, written notice to all Parties with which it has ongoing transactions or with which it has committed to future transactions under the Agreement at the time of the notice. Any such changes in netting status shall apply beginning at least 30 days after notice required by this Section 28.2 is provided and only shall apply to transactions agreed to beginning on or after the date the change in netting status becomes effective. 28.3 The Parties may by separate agreement either through a Confirmation Agreement or some other agreement set out specific terms relating to the implementation of the netting in addition to or in lieu of Exhibit A. Issued by: Michael E. Small, General Counsel to Effective: March 1, 2002 Western Systems Power Pool Issued on: December 21, 2001 Western Systems Power Pool Original Sheet No. 47A Rate Schedule FERC No. 6 29. TAXES: The Contract Price for all transactions under the Service Schedules shall include full reimbursement for, and the Seller is liable for and shall pay, or cause to be paid, or reimburse the Purchaser for if the Purchaser has paid, all taxes applicable to a transaction that arise prior to the delivery point. If the Purchaser is required to remit such tax, the amount shall be deducted from any sums due to the Seller. The Seller shall indemnify, Issued by: Michael E. Small, General Counsel to Effective: March 1, 2002 Western Systems Power Pool Issued on: December 21, 2001 Western Systems Power Pool Original Sheet No. 48 Rate Schedule FERC No. 6 defend, and hold harmless the Purchaser from any claims for such taxes. The Contract Price does not include reimbursement for, and the Purchaser is liable for and shall pay, cause to be paid, or reimburse the Seller for if the Seller has paid, all taxes applicable to a transaction arising at and from the delivery point, including any taxes imposed or collected by a taxing authority with jurisdiction over the Purchaser. The Purchaser shall indemnify, defend, and hold harmless the Seller from any claims for such taxes. Either Party, upon written request of the other Party, shall provide a certificate of exemption or other reasonably satisfactory evidence of exemption if either Party is exempt from taxes, and shall use reasonable efforts to obtain and cooperate with the other Party in obtaining any exemption from or reduction of any tax. Taxes are any amounts imposed by a taxing authority associated with the transaction. 30. CONFIDENTIALITY: The terms of any transaction under the Service Schedules or any other information exchanged by the Purchaser and Seller relating to the transaction shall not be disclosed to any person not employed or retained by the Purchaser or the Seller or their affiliates, except to the extent disclosure is (1) required by law, (2) reasonably deemed by the disclosing Party to be required to be disclosed in connection with a dispute between or among the Parties, or the defense of any litigation or dispute, (3) otherwise permitted by consent of the other Party, which consent shall not be unreasonably withheld, (4) required to be made in connection with regulatory proceedings (including proceedings relating to FERC, the United States Securities and Exchange Commission or any other Issued by: Michael E. Small, General Counsel to Effective: July 1, 2000 Western Systems Power Pool Issued on: September 29, 2000 Filed to comply with order of the Federal Energy Regulatory Commission, Docket Nos. ER00-3338, et al., issued September 15, 2000. Western Systems Power Pool Original Sheet No. 49 Rate Schedule FERC No. 6 federal, state or provincial regulatory agency); (5) required to comply with North American Electric Reliability Organization, regional reliability council, or successor organization requirements; or (6) necessary to obtain transmission service. In the event disclosure is made pursuant to this provision, the Parties shall use reasonable efforts to minimize the scope of any disclosure and have the recipients maintain the confidentiality of any documents or confidential information covered by this provision, including, if appropriate, seeking a protective order or similar mechanism in connection with any disclosure. This provision shall not apply to any information that was or is hereafter in the public domain (except as a result of a breach of this provision). 31. TRANSMISSION TARIFF: Pursuant to FERC Order No. 888, issued on April 24, 1996, and FERC orders where applicable, the WSPP Default Transmission Tariff has been filed and has become effective. The Parties agree to be bound by the terms of that Tariff for so long as they are Western Systems Power Pool members. 32. TRANSACTION SPECIFIC TERMS AND ORAL AGREEMENTS: 32.1 The Parties' agreement to transaction specific terms which constitute the Confirmation Agreement shall be made by one of the following methods: (1) provision of pertinent information through written Confirmation Agreements (see Exhibit C for a sample); or (2) oral conversation, provided that such oral conversation is recorded electronically. By mutual agreement and consistent with and pursuant to the provisions of this Section 32, the Parties to a transaction under Issued by: Michael E. Small, General Counsel to Effective: July 1, 2000 Western Systems Power Pool Issued on: September 29, 2000 Filed to comply with order of the Federal Energy Regulatory Commission, Docket Nos. ER00-3338, et al., issued September 15, 2000. Western Systems Power Pool Third Revised Sheet No. 50 Rate Schedule FERC No. 6 Superseding Second Revised Sheet No. 50 this Agreement may agree to modify any term of this Agreement which applies to such transaction (but not to provisions regarding the operation of the WSPP as an organization including Sections 7 and 8), such agreement to be reflected in a Confirmation Agreement. Written confirmation shall be required for all transactions of one week or more. Upon request of the Purchaser or at the election of the Seller, the Seller shall provide written confirmation which must be received by the Purchaser within five Business Days of the date of the agreement or request. The Purchaser shall have five Business Days from date of receipt to respond to the confirmation. If the Purchaser does not respond within that time period, the Seller's written confirmation shall be considered as accepted and final except as provided in Section 32.5. If the Seller fails to provide any required written confirmation within five Business Days, as described above, then the Purchaser may submit a written confirmation to the Seller. The Purchaser shall submit such written confirmation within five Business Days after the deadline for submitting a written confirmation applicable to the Seller as set forth above has expired. If the Seller fails to respond to Purchaser's confirmation within five Business Days, then the Purchaser's written confirmation shall be considered as accepted and final except as provided in Section 32.5. Notwithstanding the foregoing, any failure of the Seller or the Purchaser to provide written confirmation of the transaction shall not invalidate any oral agreement of the Parties except for oral agreements prohibited by Section 32.5. Nor shall any oral agreement of the Parties be considered invalidated Issued by: Michael E. Small, General Counsel to Effective: September 1, 2002 Western Systems Power Pool Issued on: July 2, 2002 Western Systems Power Pool First Revised Sheet No. 50A Rate Schedule FERC No. 6 Superseding Original Sheet No. 50A before and during the time period the confirmation process is ongoing and no final Confirmation Agreement under these procedures or through mutual agreement has been reached. Issued by: Michael E. Small, General Counsel to Effective: March 1, 2002 Western Systems Power Pool Issued on: December 21, 2001 Western Systems Power Pool Original Sheet No. 51 Rate Schedule FERC No. 6 32.2 The Parties agree not to contest, or assert any defense with respect to, the validity or enforceability of any agreement to the terms concerning a specific transaction(s), on the basis that documentation of such terms fails to comply with the requirements of any statute that agreements be written or signed. Each Party consents to the recording by the other Party, without any further notice, of telephone conversations between representatives of the Parties, which contain agreements to or discussion concerning the terms of a specific transaction(s). All such recordings may be introduced and admitted into evidence for the purpose of proving agreements to terms, and any objection to such introduction or admission for such purpose is hereby expressly waived. The terms documented hereunder, whether stated in a written document or a recording, are intended by the Parties as a final expression of their agreement with respect to such terms as are included therein and may not be contradicted by evidence of any prior agreement, but may be supplemented by course of dealing, performance, usage of trade and evidence of consistent additional mutually agreed-upon terms. 32.3 For individual transactions under the Service Schedules, the Agreement as it may be modified or supplemented by a Confirmation Agreement shall bind the Parties and govern the transactions; provided, however, if the Parties to a transaction do not reach agreement on such modification or change to a term of the Agreement, or the Confirmation Agreement is not considered accepted and final pursuant to Section 32.1, then the term or terms of the Agreement, which the Parties could not Issued by: Michael E. Small, General Counsel to Effective: July 1, 2000 Western Systems Power Pool Issued on: September 29, 2000 Filed to comply with order of the Federal Energy Regulatory Commission, Docket Nos. ER00-3338, et al., issued September 15, 2000. Western Systems Power Pool Second Revised Sheet No. 52 Rate Schedule FERC No. 6 Superseding First Revised Sheet No. 52 reach agreement to modify or change or which are not considered modified pursuant to Section 32.1, shall apply to that transaction. In the event of a conflict between a binding and effective Confirmation Agreement and this Agreement, the Confirmation Agreement shall govern. 32.4 The Seller shall not be required to file written confirmations with FERC except as provided in the Service Schedules. 32.5 When a Confirmation Agreement contains Non-Standard Confirmation Provisions which are provisions other than those set forth in paragraphs (a) - (l) of Exhibit C, those Non-Standard Confirmation Provisions shall not be deemed to be accepted pursuant to Section 32.1 unless agreed to: (i) orally, with that oral agreement recorded (provided that such oral agreement option only shall be available for transactions of less than one week); or (ii) in a writing executed by both Parties. 32.6 Other Products and Service Levels: The Parties may agree to use a product/service level defined by a different agreement (e.g., the California ISO tariff, the ERCOT agreement or the EEI agreement) for a particular transaction under this Agreement. Unless the Parties expressly state and agree that all the terms and conditions of such other agreement will apply to any such transaction, the transaction shall be subject to all the terms of this Agreement, except that (1) all service level/product definitions, (2) force majeure/uncontrollable force definitions, and (3) other terms as mutually agreed shall have the meaning Issued by: Michael E. Small, General Counsel to Effective: September 1, 2002 Western Systems Power Pool Issued on: July 2, 2002 Western Systems Power Pool Original Sheet No. 52A Rate Schedule FERC No. 6 ascribed to them in the different agreement or in the applicable confirmation notice or agreement. 32.7 Written confirmation pursuant to this Section 32 may be provided in electronic format so long as the Parties to the affected transaction or transactions have agreed on the procedures and format for doing so. 33. PERFORMANCE, TITLE, AND WARRANTIES FOR TRANSACTIONS UNDER SERVICE SCHEDULES: 33.1 Performance 33.1.1 The Seller shall deliver to the delivery point(s) as agreed to in the applicable Confirmation Agreement and sell to the Purchaser in accordance with the terms of the Agreement and such Confirmation Agreement. 33.1.2 The Purchaser shall receive and purchase the Contract Quantity, as agreed to by the Parties in the applicable Confirmation Agreement, at the delivery point(s) and purchase from the Seller in accordance with the terms of the Agreement and such Confirmation Agreement. 33.2 Title and Risk of Loss Title to and risk of loss of the electric energy shall pass from the Seller to the Purchaser at the delivery point agreed to in the Confirmation Agreement; provided, however, with regard to federal agencies or parts of the United States Issued by: Michael E. Small, General Counsel to Effective: March 1, 2002 Western Systems Power Pool Issued on: December 21, 2001 Western Systems Power Pool Original Sheet No. 53 Rate Schedule FERC No. 6 Government, title to and risk of loss shall pass to Purchaser to the extent permitted by and consistent with applicable law. 33.3 Warranties The Seller warrants that it will transfer to the Purchaser good title to the electric energy sold under the Agreement and any Confirmation Agreement, free and clear of all liens, claims, and encumbrances arising or attaching prior to the delivery point and that Seller's sale is in compliance with all applicable laws and regulations. THE SELLER HEREBY DISCLAIMS ALL OTHER WARRANTIES, EXPRESS OR IMPLIED, INCLUDING ANY WARRANTY OF MERCHANTABILITY OR FITNESS FOR A PARTICULAR PURPOSE. 34. DISPUTE RESOLUTION: 34.1 INFORMAL DISPUTE RESOLUTION Before binding dispute resolution or any other form of litigation may proceed, any dispute between the Parties to a transaction under this Agreement first shall be referred to nonbinding mediation. The Parties shall attempt to agree upon a mediator from a list of ten (10) candidates provided by the Chairman of the WSPP Operating Committee or his or her designee. If the Parties are unable to agree, then the Chairman or the designee shall appoint a mediator for the dispute. Neither the mediator nor the person involved on behalf of the WSPP in developing a list of mediators for the Parties to choose from or in selecting the Issued by: Michael E. Small, General Counsel to Effective: July 1, 2000 Western Systems Power Pool Issued on: September 29, 2000 Filed to comply with order of the Federal Energy Regulatory Commission, Docket Nos. ER00-3338, et al., issued September 15, 2000. Western Systems Power Pool Original Sheet No. 54 Rate Schedule FERC No. 6 mediator (if the Parties are unable to do so) shall possess a direct or indirect interest in either Party or the subject matter of the mediation. The WSPP shall establish procedures for the appointment of mediators and the conduct of mediation and those procedures shall apply to the mediation. 34.2 BINDING DISPUTE RESOLUTION The Parties to a dispute may elect binding dispute resolution using the following process unless binding arbitration of certain disputes is required under this Agreement in which event the Parties shall use the process set forth in this Section 34.2 to resolve such disputes, unless the Parties otherwise agree: (a) WSPP Dispute Resolution: A Party to a dispute (if binding dispute resolution is required) or all Parties to a dispute (if agreement of the Parties is required for binding dispute resolution) may initiate binding dispute resolution under WSPP procedures by notifying the Chairman of the WSPP Operating Committee or his or her designee. The Chairman or his or her designee shall provide the Parties with a list of ten (10) eligible arbitrators. Within ten (10) days of receiving the list, the Parties shall agree on a single arbitrator from the list to conduct the arbitration, or notify the Chairman of the Operating Committee or the designee of their inability to reach agreement. If notified of the Parties inability to reach agreement, then the Chairman or the designee shall choose the arbitrator from the list within five (5) days. Neither the arbitrator nor the person Issued by: Michael E. Small, General Counsel to Effective: July 1, 2000 Western Systems Power Pool Issued on: September 29, 2000 Filed to comply with order of the Federal Energy Regulatory Commission, Docket Nos. ER00-3338, et al., issued September 15, 2000. Western Systems Power Pool Original Sheet No. 55 Rate Schedule FERC No. 6 involved on behalf of the WSPP in developing a list of arbitrators for the Parties to choose from or in selecting the arbitrator (if the Parties are unable to do so) shall possess a direct or indirect interest in either Party or the subject matter of the arbitration. The Procedures to be used for this arbitration shall follow the arbitration procedures which shall be developed and maintained by the WSPP and the procedures will be generally consistent with the commercial arbitration rules of the American Arbitration Association though not involving the Association. If the Parties agree to binding dispute resolution under this Section 34.2, each Party understands that it will not be able to bring a lawsuit concerning any dispute that may arise which is covered by this arbitration provision. Notwithstanding the foregoing, nothing herein is intended to waive any provision of the Federal Arbitration Act, 9 U.S.C. Section 1, et. seq., or anY right under state statute or common law to challenge an arbitration award or to prevent any action to enforce any arbitration award. A Party's liability and damages under any arbitration award resulting from the process set forth in this Section 34.2 shall be limited as provided in this Agreement or in any Confirmation Agreement. Issued by: Michael E. Small, General Counsel to Effective: July 1, 2000 Western Systems Power Pool Issued on: September 29, 2000 Filed to comply with order of the Federal Energy Regulatory Commission, Docket Nos. ER00-3338, et al., issued September 15, 2000. Western Systems Power Pool Original Sheet No. 56 Rate Schedule FERC No. 6 34.3 COSTS Each Party shall be responsible for its own costs and those of its counsel and representatives. The Parties shall equally divide the costs of the arbitrator or mediator and the hearing. 34.4 CONFIDENTIALITY Any arbitration or mediation under this Section 34 shall be conducted on a confidential basis and not disclosed, including any documents or results which shall be considered confidential, unless the Parties otherwise agree or such disclosure is required by law. 35. FORWARD CONTRACTS: The Parties acknowledge and agree that all transactions under the Agreement and Confirmation Agreement(s) are forward contracts and that the Parties are forward contract merchants, as those terms are used in the United States Bankruptcy Code. The Parties acknowledge and agree that all of their transactions, together with this Agreement and the related Confirmation Agreement(s) form a single, integrated agreement, and agreements and transactions are entered into in reliance on the fact that the agreements and each transaction form a single agreement between the Parties. 36. TRADE OPTION EXCEPTION The Parties intend that any Physically Settled Option under this Agreement shall qualify under the trade option exception, 17 C.F.R. Section 32.4. Accordingly, each Party buying or selling a Physically Settled Option agrees and warrants that any such option Issued by: Michael E. Small, General Counsel to Effective: July 1, 2000 Western Systems Power Pool Issued on: September 29, 2000 Filed to comply with order of the Federal Energy Regulatory Commission, Docket Nos. ER00-3338, et al., issued September 15, 2000. Western Systems Power Pool Original Sheet No. 57 Rate Schedule FERC No. 6 shall be offered only to a provider, user, or merchant and that the entities entering into the options are doing so solely for purposes related to their business. 37. ADDITIONAL REPRESENTATIONS AND WARRANTIES: Each Party warrants and represents to the other(s) that it possesses the necessary corporate, governmental and legal authority, right and power to enter into and agree to the applicable Confirmation Agreement for a transaction or transactions and to perform each and every duty imposed, and that the Parties' agreement to buy and sell power under this Agreement and the Confirmation Agreement represents a contract. Each Party also warrants and represents to the other(s) that each of its representatives executing or agreeing through a Confirmation Agreement to a transaction under this Agreement is authorized to act on its behalf. Each Party further warrants and represents that entering into and performing this Agreement and any applicable Confirmation Agreement does not violate or conflict with its Charter, By-laws or comparable constituent document, any law applicable to it, any order or judgment of any court or other agency of government applicable to it or any agreement to which it is a party and that this Agreement and applicable Confirmation Agreement(s), constitute a legal, valid and binding obligation enforceable against such Party in accordance with the terms of such agreements. Each Party also represents that it is solvent and that on each delivery this representation shall be deemed renewed unless notice to the contrary is given in writing by the Purchaser to the Seller before delivery. Issued by: Michael E. Small, General Counsel to Effective: July 1, 2000 Western Systems Power Pool Issued on: September 29, 2000 Filed to comply with order of the Federal Energy Regulatory Commission, Docket Nos. ER00-3338, et al., issued September 15, 2000. Western Systems Power Pool First Revised Sheet No. 58 Rate Schedule FERC No. 6 Superseding Original Sheet No. 58 38. FLOATING PRICES: 38.1 In the event the Parties intend that the price for a transaction is to be based on an index, exchange or any other kind of variable reference price (such price being a "Floating Price"), the Parties shall specify the "Floating Price" to be used to calculate the amounts in a Confirmation Agreement due Seller for that transaction. 38.2 Market Disruption. If a Market Disruption Event has occurred and is continuing during the Determination Period, the Floating Price for the affected Trading Day shall be determined as follows. The Parties shall negotiate in good faith to agree on a Floating Price (or a method for determining a Floating Price) for the affected Trading Day. If the Parties have not so agreed on or before the twelfth Business Day following the first Trading Day on which the Market Disruption Event occurred or existed, then the Floating Price shall be determined in good faith by the Parties based upon (1) quotes from Dealers in energy contracts; and/or (2) quotes from Brokers in energy contracts. Each Party may obtain up to a maximum of four quotes which must be provided to the other Party no later than twenty-two Business Days following the first Business Day on which the Market Disruption Event occurred or existed. These quotes shall reflect transacted prices. The Floating Price for the affected Trading Day shall equal a simple average of the quotes obtained and provided by the Parties consistent with the provisions of this Section 38. Each Party providing quote(s) to the other Party also shall Issued by: Michael E. Small, General Counsel to Effective: March 1, 2002 Western Systems Power Pool Issued on: December 21, 2001 Western Systems Power Pool Original Sheet No. 58A Rate Schedule FERC No. 6 identify to that other Party the Dealer(s) and/or the Broker(s) who provided each of the quotes to allow verification. "Determination Period" means each calendar month during the term of the relevant transaction; provided that if the term of the transaction is less than one calendar month the Determination Period shall be the term of the transaction. "Market Disruption Event" means, with respect to an index, any of the following events (the existence of which shall be determined in good faith by the Parties): (a) the failure of the index to announce or publish information necessary for determining the Floating Price; (b) the failure of trading to commence or the permanent discontinuation or material suspension of trading in the relevant options contract or commodity on the exchange or market acting as the index; (c) the temporary or permanent discontinuance or unavailability of the index; (d) the temporary or permanent closing of any exchange acting as the index; or (e) a material change in the formula for or the method of determining the Floating Price. "Trading Day" means a day in respect of which the relevant price source published the relevant price or would have published the relevant price but for the Market Disruption Event. 38.3 Calculation of Floating Price. For the purposes of the calculation of a Floating Price, all numbers shall be rounded to three (3) decimal places. If the fourth (4th) decimal number is five (5) or greater, then the third (3rd) decimal number shall be Issued by: Michael E. Small, General Counsel to Effective: March 1, 2002 Western Systems Power Pool Issued on: December 21, 2001 Western Systems Power Pool Original Sheet No. 58B Rate Schedule FERC No. 6 increased by one (1), and if the fourth (4th) decimal number is less than five (5), then the third (3rd) decimal number shall remain unchanged. 39. AMENDMENT: 39.1 This Agreement may be amended upon the submission to FERC and acceptance by FERC of that amendment. The Parties through the Executive Committee shall direct the filing of any amendments. The Parties to this Agreement agree to bound by this Agreement as it may be amended, provided that the Parties possess the right to challenge any amendments at FERC and to exercise any applicable withdrawal rights under this Agreement. 39.2 Unless otherwise stated in the amendment, all amendments shall apply only to new transactions entered into or agreed to on or after the effective date of the amendment. Preexisting agreements and transactions shall operate under the version of the WSPP Agreement effective at the time of the agreement for the transaction unless the Parties to a transaction or transactions mutually agree otherwise. 39.3 An agreement modifying this Agreement or a Confirmation Agreement for a transaction needs no consideration to be binding. 40. EXECUTION BY COUNTERPARTS: This Agreement may be executed in any number of counterparts, and upon execution by all Parties, each executed counterpart shall have the same force and effect as Issued by: Michael E. Small, General Counsel to Effective: March 1, 2002 Western Systems Power Pool Issued on: December 21, 2001 Western Systems Power Pool First Revised Sheet No. 59 Rate Schedule FERC No. 6 Superseding Original Sheet No. 59 an original instrument and as if all Parties had signed the same instrument. Any signature page of this Agreement may be detached from any counterpart of this Agreement without impairing the legal effect of any signatures thereon, and may be attached to another counterpart of this Agreement identical in form hereto but having attached to it one or more signature pages. 41. WITNESS: IN WITNESS WHEREOF, the Parties have caused this Agreement to be executed by their duly authorized representative as of the 27th day of July, 1991 (or as of the date of execution of this Agreement by each Party's duly authorized representation, in the case of any Party that becomes a signatory to this Agreement subsequent to July 27, 1991). By:________________________________ Name: Title: Issued by: Michael E. Small, General Counsel to Effective: March 1, 2002 Western Systems Power Pool Issued on: December 21, 2001 Western Systems Power Pool Original Sheet No. 60 Rate Schedule FERC No. 6 EXHIBIT A NETTING Each Party that executes this Exhibit A to the Agreement agrees to net payments for transactions under WSPP Service Schedule A, B, and C with any other Party or Parties which also have agreed to net payments by executing a copy of this Exhibit A. The Party executing this Exhibit A shall indicate below when it desires that its agreement to net becomes effective. A Party agreeing to net under this Exhibit A shall comply with the provisions of Section 28.2 of the Agreement. Defined terms used herein are as defined in the WSPP Agreement. Netting shall be done in accordance with the following provision: If the Purchaser and Seller are each required to pay an amount on the payment due date in the same month for transactions under the Agreement or Confirmation Agreement, then such amounts with respect to each Party will be aggregated and the Parties will discharge their obligations to pay through netting, in which case the Party owing the greater aggregate amount will pay to the other party the difference between the amounts owed consistent with the payment times in Section 9.2 of the Agreement, unless the Parties have otherwise agreed to a different payment time as allowed by the Agreement. Each Party reserves to itself all rights, set-offs, counterclaims and other remedies and/or defenses to which it is or may be entitled, arising from or out of the Agreement. All outstanding payments between the Parties which are to be netted pursuant to this Exhibit A for transactions under WSPP Service Schedule A, B, and C shall be offset against each other or set off or recouped therefrom. - ---------------------------------- -------------------------- Name of Authorized Representative Effective Date for Netting - ---------------------------------- Name of WSPP Member - ---------------------------------- -------------------------- Signature of Authorized Date of Execution Representative Issued by: Michael E. Small, General Counsel to Effective: July 1, 2000 Western Systems Power Pool Issued on: September 29, 2000 Filed to comply with order of the Federal Energy Regulatory Commission, Docket Nos. ER00-3338, et al., issued September 15, 2000. Western Systems Power Pool Original Sheet No. 61 Rate Schedule FERC No. 6 [WSPP SAMPLE FORM - PARTIES ARE FREE TO USE THIS OR DISREGARD IT.] EXHIBIT B FORM OF COUNTERPARTY GUARANTEE AGREEMENT This Guarantee Agreement (this "Guarantee"), dated, as of [__________], 199[__], is made and entered into by [_____________], a [__________] corporation ("Guarantor"). WITNESSETH: WHEREAS, [___________________] (the "Company") may enter into transactions involving power sales under the Western Systems Power Pool ("WSPP Agreement") and related confirmation agreements(1) (collectively "Agreements") with [Company Name] ("Guaranteed Party"); and WHEREAS, Guarantor will directly or indirectly benefit from the Agreements. NOW THEREFORE, in consideration of the Guaranteed Party agreeing to conduct business with Company, Guarantor hereby covenants and agrees as follows: 1. GUARANTY. Subject to the provisions hereof, Guarantor hereby irrevocably and unconditionally guarantees the timely payment when due of the obligations of Company (the "Obligations") to the Guaranteed Party in accordance with the Agreements. If Company fails to pay any Obligations, Guarantor shall promptly pay to the Guaranteed Party no later than the next Business Day (as defined in the WSPP Agreement), after notification, the amount due in the same currency and manner provided for in the Agreements. This Guarantee shall constitute a guarantee of payment and not of collection. Guarantor shall have no right of subrogation with respect to any payments it makes under this Guarantee until all of the Obligations of Company to the Guaranteed Party are paid in full. The liability of Guarantor under the Guarantee shall be subject to the following: (a) Guarantor's liability hereunder shall be and is specifically limited to payments expressly required to be made in accordance with the Agreements (even if such payments are deemed to be damages) and, except to the extent specifically provided in the Agreements, in no event shall Guarantor be subject hereunder to consequential, exemplary, equitable, loss of profits, punitive, tort, or any other even if such fees together with the payments - --------------------------------------- (1) Issued by: Michael E. Small, General Counsel to Effective: July 1, 2000 Western Systems Power Pool Issued on: September 29, 2000 Filed to comply with order of the Federal Energy Regulatory Commission, Docket Nos. ER00-3338, et al., issued September 15, 2000. Western Systems Power Pool Original Sheet No. 62 Rate Schedule FERC No. 6 exceed the cap in Section 1(b), damages, costs, except that Guarantor shall be required to pay reasonable attorney fees. (b) The aggregate liability of the Guarantor shall not exceed [_____] Million U.S. Dollars [___________]. 2. DEMANDS AND NOTICE. If Company fails or refuses to pay any Obligations, the Guaranteed Party may make a demand upon Guarantor (hereinafter referred to as a "Payment Demand"). A Payment Demand shall be in writing and shall reasonably and briefly specify in what manner and what amount Company has failed to pay and an explanation of why such payment is due, with a specific statement that the Guaranteed Party is calling upon Guarantor to pay under this Guarantee. A Payment Demand satisfying the foregoing requirements shall be deemed sufficient notice to Guarantor that it must pay the Obligations. A single written Payment Demand shall be effective as to any specific default during the continuance of such default, until Company or Guarantor has cured such default, and additional Payment Demands concerning such default shall not be required until such default is cured. 3. REPRESENTATIONS AND WARRANTIES. Guarantor represents and warrants that: (a) it is a corporation duly organized and validly existing under the laws of the State of [_____________] and has the corporate power and authority to execute, deliver and carry out the terms and provisions of this Guarantee; (b) no authorization, approval, consent or order of, or registration or filing with, any court or other governmental body having jurisdiction over Guarantor is required on the part of Guarantor for the execution and delivery of this Guarantee; and (c) this Guarantee constitutes a valid and legally binding agreement of Guarantor enforceable against Guarantor in accordance with its terms, except as the enforceability of this Guarantee may be limited by the effect of any applicable bankruptcy, insolvency, reorganization, moratorium or similar laws affecting creditors' rights generally and by general principles of equity. 4. EFFECT OF BANKRUPTCY BY COMPANY. The Guarantor's obligation to pay under this Guarantee shall not be affected in any way by the institution with respect to the Company of a bankruptcy, reorganization, moratorium or similar insolvency proceeding or other relief under any bankruptcy or insolvency law affecting creditor's rights or a petition for the Company's winding-up or liquidation. 5. AMENDMENT. No term or provision of this Guarantee shall be amended, modified, altered, waived, or supplemented except in a writing signed by the Guarantor and Guaranteed Party hereto. Issued by: Michael E. Small, General Counsel to Effective: July 1, 2000 Western Systems Power Pool Issued on: September 29, 2000 Filed to comply with order of the Federal Energy Regulatory Commission, Docket Nos. ER00-3338, et al., issued September 15, 2000. Western Systems Power Pool Original Sheet No. 63 Rate Schedule FERC No. 6 6. WAIVERS. Guarantor hereby waives (a) notice of acceptance of this Guarantee; (b) presentment and demand concerning the liabilities of Guarantor, except as expressly hereinabove set forth; and (c) any right to require that any action or proceeding be brought against Company or any other person, or except as expressly hereinabove set forth, to require that the Guaranteed Party seek enforcement of any performance against Company or any other person, prior to any action against Guarantor under the terms hereof. Except as to applicable statutes of limitation, no delay of the Guaranteed Party in the exercise of, or failure to exercise, any rights hereunder shall operate as a waiver of such rights, a waiver of any other rights or a release of Guarantor from any obligations hereunder. Guarantor consents to the renewal, compromise, extension, acceleration or other changes in the time of payment of or other changes in the terms of the Obligations, or any part thereof or any changes or modifications to the terms of the Agreements. Guarantor may terminate this Guarantee by providing written notice of such termination to the Guaranteed Party and upon the effectiveness of such termination, Guarantor shall have no further liability hereunder, except as provided in the last sentence of this paragraph. No such termination shall be effective until fifteen (15) Business Days after receipt by the Guaranteed Party of such termination notice. No such termination shall affect Guarantor's liability with respect to any obligations arising under any transaction entered into prior to the time the termination is effective, which transaction shall remain guaranteed pursuant to the terms of this Guarantee. 7. ASSIGNMENT. The Guarantor shall not assign this Guarantee without the express written consent of the Guaranteed Party. The Guaranteed Party shall be entitled to assign its rights under this Agreement in its sole discretion. 8. NOTICE. Any Payment Demand, to the Guaranteed Party or the Guarantor notice, request, instruction, correspondence or other document to be given hereunder by any party to another (herein collectively called "Notice") shall be in writing and delivered personally or mailed by certified mail, postage prepaid and return receipt requested, or by telegram or telecopier, as follows: Issued by: Michael E. Small, General Counsel to Effective: July 1, 2000 Western Systems Power Pool Issued on: September 29, 2000 Filed to comply with order of the Federal Energy Regulatory Commission, Docket Nos. ER00-3338, et al., issued September 15, 2000. Western Systems Power Pool Original Sheet No. 64 Rate Schedule FERC No. 6 To [Name of Guaranteed Party] ____________________________ ____________________________ ____________________________ Attn: ____________________________ Fax No.: (___) ___________________ To Guarantor: ____________________________ ____________________________ ____________________________ Attn: ____________________________ Fax No.: (___) ___________________ Notice given by personal delivery or mail shall be effective upon actual receipt. Notice given by telegram or telecopier shall be effective upon actual receipt if received during the recipient's normal business hours, or at the beginning of the recipient's next business day after receipt if not received during the recipient's normal business hours. All Notices by telegram or telecopier shall be confirmed promptly after transmission in writing by certified mail or personal delivery. Any party may change any address to which Notice is to be given to it by giving notice as provided above of such change of address. 8. MISCELLANEOUS. THIS GUARANTEE SHALL IN ALL RESPECTS BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF [State], WITHOUT REGARD TO PRINCIPLES OF CONFLICTS OF LAWS. This Guarantee shall be binding upon Guarantor, its successors and assigns and inure to the benefit of and be enforceable by the Guaranteed Party, its successors and assigns. The Guarantee embodies the entire agreement and understanding between Guarantor and the Guaranteed Party and supersedes all prior agreements and understandings relating to the subject matter hereof. The headings in this Guarantee are for purposes of reference only, and shall not affect the meaning hereof. This Guarantee may be executed in any number of counterparts, each of which shall be an original, but all of which together shall constitute one instrument. EXECUTED as of the day and year first above written. [_____________________________] By: __________________________ Name: ________________________ Title: _______________________ Issued by: Michael E. Small, General Counsel to Effective: July 1, 2000 Western Systems Power Pool Issued on: September 29, 2000 Filed to comply with order of the Federal Energy Regulatory Commission, Docket Nos. ER00-3338, et al., issued September 15, 2000. Western Systems Power Pool Second Revised Sheet No. 65 Rate Schedule FERC No. 6 Superseding First Revised Sheet No. 65 EXHIBIT C SAMPLE FORM FOR CONFIRMATION 1. TRANSACTION SPECIFIC AGREEMENTS The undersigned Parties agree to sell and purchase electric energy, or a Physically-Settled Option, pursuant to the WSPP Agreement as it is supplemented and modified below: (a) Seller: __________________________________ (b) Purchaser: __________________________________ (c) Period of Delivery: From __\__\__ To __\__\__ (d) Schedule (Days and Hours): __________________ (e) Delivery Rate:________________________________ (f) Delivery Point(s): __________________________ (g) Type of Service (Check as Applicable) Service Schedule A _________ Service Schedule B _________ Service Schedule C _________ Physically-Settled Option Service Schedule B ______ Physically-Settled Option Service Schedule C ______ Other products per Section 32.6 _________________ [DESCRIBE PRODUCT] (h) Contract Quantity: ________ Total MWhrs. (i) Contract or Strike Price: _____________________ (j) Transmission Path for the Transaction (If Applicable): (k) Date of Agreement if different: _____________ (l) Additional Information for Physically-Settled Options (i) Option Type: Put __________ Call______________ (ii) Option Style: __________ (iii) Exercise Date or Period: __________ (iv) Premium: __________ (v) Premium Payment Date: _________ (vi) Method for providing notice of exercise__________________ (m) Special Terms and Exceptions: See Attachment A [Special Terms and Exceptions shall be shown on an Attachment to this Confirmation.] - ---------------------------- --------------------------- Name of Trader for Purchaser Name of Trader for Seller Issued by: Michael E. Small, General Counsel to Effective: March 1, 2002 Western Systems Power Pool Issued on: December 21, 2001 Western Systems Power Pool Original Sheet No. 66 Rate Schedule FERC No. 6 - --------------------------- --------------------------- Authorized Signature Authorized Signature for Purchaser for Seller - --------------------------- --------------------------- Date Date Issued by: Michael E. Small, General Counsel to Effective: July 1, 2000 Western Systems Power Pool Issued on: September 29, 2000 Filed to comply with order of the Federal Energy Regulatory Commission, Docket Nos. ER00-3338, et al., issued September 15, 2000. Western Systems Power Pool Original Sheet No. 67 Rate Schedule FERC No. 6 EXHIBIT D WSPP MEDIATION AND ARBITRATION PROCEDURES I. MEDIATION A. INFORMAL MEDIATION. WSPP members with a dispute or a potential dispute involving transactions under the WSPP Agreement may request non-binding, informal mediation by contacting the WSPP's General Counsel and by providing a brief explanation in writing of the dispute and the remedy being sought. All parties to the dispute must request this Informal Mediation for it to become effective. After this contact, a telephonic conference call will be arranged among the affected WSPP members and the WSPP's General Counsel, the Chairman of the Operating Committee, and/or some other independent and knowledgeable person requested by the Chairman of the Operating Committee to participate. The purpose of the conference call will be to discuss the issues and to have an independent person or persons state their views. Best efforts will be made to set up this conference call within five Business Days after the WSPP's General Counsel is contacted subject to accommodating the schedules of all involved. This Informal Mediation shall be considered as satisfying the Mediation requirements of Section 34.1 of the WSPP Agreement. Issued by: Michael E. Small, General Counsel to Effective: July 1, 2000 Western Systems Power Pool Issued on: September 29, 2000 Filed to comply with order of the Federal Energy Regulatory Commission, Docket Nos. ER00-3338, et al., issued September 15, 2000. Western Systems Power Pool Original Sheet No. 68 Rate Schedule FERC No. 6 B. INITIATING FORMAL MEDIATION. A WSPP member which believes that it possesses a claim against another WSPP member relating to a WSPP transaction, which is unable to resolve the dispute through agreement with the other member to the transaction, and which desires to pursue that claim shall initiate non-binding formal mediation pursuant to Section 34.1 of the WSPP Agreement. The member initiating such mediation shall do so by Serving written notice to the Chairman of the WSPP Operating Committee, the WSPP's General Counsel, and the other members against which the claim is directed. Such notice shall state the nature of the dispute, the remedy sought, and support the claim. C. RESPONSE TO DOCUMENT INITIATING FORMAL MEDIATION. Within eight days, the member or members against which the claim is directed may provide a response to the notice which shall be Served on the member which initiated the Mediation, the Chairman of the WSPP's Operating Committee, and the WSPP's General Counsel. D. CHOOSING THE MEDIATOR. The Mediator shall be chosen in accordance with the procedures set forth in Section 34.1 of the WSPP Agreement. Each Party may suggest persons to be included on the list of Mediators to be presented to the Parties provided that these suggested persons shall be provided to the WSPP Representative together with relevant personal histories within two Business Days Issued by: Michael E. Small, General Counsel to Effective: July 1, 2000 Western Systems Power Pool Issued on: September 29, 2000 Filed to comply with order of the Federal Energy Regulatory Commission, Docket Nos. ER00-3338, et al., issued September 15, 2000. Western Systems Power Pool Original Sheet No. 69 Rate Schedule FERC No. 6 of the date by which time the list of Mediators is to be sent out. The WSPP Representative shall allow at least one person suggested by each Party to be added to the list of Mediators. A brief personal history of each person on the list of potential mediators shall be provided to the Parties, with that history showing the person's employment over the last five years and any other relevant facts. The WSPP Representative shall provide the Parties with the list of Mediators within five days of receipt of notice of the dispute. The Parties then shall have five days in which to reach agreement on a Mediator or inform the WSPP Representative that they were unable to reach agreement in which event the WSPP Representative shall appoint the Mediator consistent with Section 34.1 of the WSPP Agreement. Upon request of the Parties for expedition, the WSPP Representative shall use best efforts to expedite this process. E. LOCATION FOR THE FORMAL MEDIATION. The Parties shall agree on a location for the Mediation. If the Parties fail to reach agreement, then the WSPP Representative shall set the location which shall be convenient for the Parties and the Mediator. F. TIME FOR THE FORMAL MEDIATION. The Parties shall agree on the time for the Mediation after consultation with the Mediator if one has been appointed. If the Parties fail to reach agreement, then the WSPP Representative shall set the time Issued by: Michael E. Small, General Counsel to Effective: July 1, 2000 Western Systems Power Pool Issued on: September 29, 2000 Filed to comply with order of the Federal Energy Regulatory Commission, Docket Nos. ER00-3338, et al., issued September 15, 2000. Western Systems Power Pool Original Sheet No. 70 Rate Schedule FERC No. 6 which shall not be more than twenty-one days after the notice initiating the Mediation is received after consultation with the Parties and any Mediator. G. CONDUCT OF THE FORMAL MEDIATION. The Mediator shall have the ability to conduct the Mediation in any manner which the Mediator believes is appropriate to facilitate resolution of the dispute. Each Party shall have at least one representative with the authority to settle the dispute present at the Mediation. The Mediation shall be private and confidential and the Mediator shall have the authority to exclude any person not directly involved unless the Parties agree otherwise in writing. At the Mediation, each Party shall have the right to make a brief presentation of its case and to question the other Party. Each Party also may be represented by counsel. H. REPLACEMENT OF THE MEDIATOR. If the Mediator resigns, withdraws or is no longer able to serve, then the Parties shall have two Business Days in which to agree on a new Mediator. If the Parties are unable to agree within such time, the WSPP Representative shall appoint a replacement Mediator from the list used to select the first Mediator within two Business Days after being notified that the Parties are unable to agree. The dates and deadlines in this section may require modification if the mediator is replaced. Any extensions shall be as limited as possible. Issued by: Michael E. Small, General Counsel to Effective: July 1, 2000 Western Systems Power Pool Issued on: September 29, 2000 Filed to comply with order of the Federal Energy Regulatory Commission, Docket Nos. ER00-3338, et al., issued September 15, 2000. Western Systems Power Pool Original Sheet No. 71 Rate Schedule FERC No. 6 II. ARBITRATION A. INITIATING ARBITRATION. A WSPP member which initiates Arbitration pursuant to Section 34.2 of the WSPP Agreement shall do so by Serving the Chairman of the WSPP Operating Committee, the WSPP General Counsel and the members against which the claim is directed with written notice of its demand for arbitration. Such notice shall state the nature of the dispute, the remedy sought, and support the claim. B. RESPONSE. Within ten days of receipt of the notice, any member or members against which the claim is directed may provide a response to the notice. Such response must include any counterclaims which the member believes are appropriate. If a counterclaim is submitted, then the member which submitted the notice may respond to the counterclaim within ten days of receipt. All such responses shall be Served on the Parties, the Chairman of the WSPP Operating Committee, and the WSPP General Counsel. C. CHOOSING THE ARBITRATOR. The Arbitrator shall be chosen in accordance with the procedures set forth in Section 34.2 of the WSPP Agreement. Each Party may suggest persons to be included on the list of Arbitrators to be presented to the Parties provided that these suggested persons are provided to the WSPP Representative together with relevant personal histories within two business days Issued by: Michael E. Small, General Counsel to Effective: July 1, 2000 Western Systems Power Pool Issued on: September 29, 2000 Filed to comply with order of the Federal Energy Regulatory Commission, Docket Nos. ER00-3338, et al., issued September 15, 2000. Western Systems Power Pool Original Sheet No. 72 Rate Schedule FERC No. 6 of the date by which time the list of Arbitrators is to be sent out. The WSPP Representative shall allow at least one person suggested by each Party to be added to the list of potential Arbitrators. A brief personal history of each person on the list of potential Arbitrators shall be provided to the Parties, with that history showing the person's employment over the last five years and any other relevant facts. The WSPP Representative shall provide the Parties with the list of Arbitrators within seven days of receipt of notice of the request for Arbitration. The Parties then shall have ten days in which to reach agreement on the Arbitrator or to inform the WSPP Representative that they were unable to reach agreement in which event the WSPP Representative shall appoint the Arbitrator consistent with Section 34.2 of the Agreement. Upon request of the Parties for expedition, the WSPP Representative shall use best efforts to cause this process to be expedited. D. LOCATION FOR THE ARBITRATION. The Parties shall agree on a location for the Arbitration. If the Parties fail to reach agreement, then the WSPP Representative shall set the location which shall be convenient for the Parties and the Arbitrator. E. TIME FOR THE ARBITRATION. The Parties shall agree on the time for the Arbitration and coordinate that time with the Arbitrator if one has been agreed to or appointed. If the Parties fail to reach agreement, then the WSPP Representative Issued by: Michael E. Small, General Counsel to Effective: July 1, 2000 Western Systems Power Pool Issued on: September 29, 2000 Filed to comply with order of the Federal Energy Regulatory Commission, Docket Nos. ER00-3338, et al., issued September 15, 2000. Western Systems Power Pool Original Sheet No. 73 Rate Schedule FERC No. 6 shall set the time which shall not be more than 60 days after the notice is received. The WSPP Representative shall set a time after consultation with the Parties and the Arbitrator to check their schedules. F. DISCOVERY. After appointment of the Arbitrator, each Party shall be entitled to obtain relevant documents from the other Parties and to take depositions. Each Party shall respond to such a document request within seven days of receipt of the request and make its employees or consultants available for depositions to the extent that the employee or consultant possesses knowledge and information relevant to the dispute. Each Party shall disclose documents that are confidential or commercially sensitive subject to a reasonable protective order. Any disputes concerning discovery shall be promptly referred to the Arbitrator who shall have authority to resolve such disputes, including the authority to require attendance of witnesses at depositions. The Federal Rules of Civil Procedure shall apply to discovery under these procedures. G. CONDUCT OF ARBITRATION IF THE PARTIES AGREE TO WAIVE AN ORAL HEARING. If the Parties agree to waive an oral hearing, then the Parties shall Serve Initial Briefs no later than 35 days after the notice is received or notify the Arbitrator that they do not wish to submit any additional documents. Parties shall Serve any Reply Briefs no later than ten days after the date for Service of Initial Briefs. Issued by: Michael E. Small, General Counsel to Effective: July 1, 2000 Western Systems Power Pool Issued on: September 29, 2000 Filed to comply with order of the Federal Energy Regulatory Commission, Docket Nos. ER00-3338, et al., issued September 15, 2000. Western Systems Power Pool Original Sheet No. 74 Rate Schedule FERC No. 6 H. CONDUCT OF THE ARBITRATION HEARING. No later than fifteen days before any hearing, any Party may Serve an Initial Brief or notify the Arbitrator that they do not wish to submit any additional documents. A Party shall Serve any Reply Brief no later than five Business Days before any hearing. The Arbitrator shall preside over any hearing and rule on all objections including objections as to the admissibility of evidence or whether the questioning is proper. All testimony shall be submitted under oath. The Arbitrator is not bound to follow any particular rules governing the conduct of the proceeding. The Arbitrator may rely on legal advice provided through the WSPP. The Arbitrator may require any person employed by a Party to attend and testify at the hearing. Each Party shall possess the right to present evidence, including witnesses, and to cross-examine other Parties' witnesses. The Arbitration shall be private and the Arbitrator shall have the authority to exclude any person not directly involved unless the Parties otherwise agree. Each Party may be represented by counsel. A stenographic record of the Arbitration shall be kept. I. DECISION. Within ten Business Days after the end of the Arbitration hearing, the Arbitrator shall issue his award in writing. If the Parties waived the right to an oral hearing, then the Arbitrator shall issue the award within ten Business Days of the last date Briefs were to be submitted. The Arbitrator is not limited in the Issued by: Michael E. Small, General Counsel to Effective: July 1, 2000 Western Systems Power Pool Issued on: September 29, 2000 Filed to comply with order of the Federal Energy Regulatory Commission, Docket Nos. ER00-3338, et al., issued September 15, 2000. Western Systems Power Pool Original Sheet No. 75 Rate Schedule FERC No. 6 remedies he may order so long as any arbitration award is consistent with the provisions and limitations of the WSPP Agreement and any applicable Confirmation Agreement with respect to the liability and damages of any Party; provided, however, upon agreement of the Parties to the dispute, the Arbitrator's choice of remedies may be limited. J. REPLACEMENT OF THE ARBITRATOR. If the Arbitrator resigns, withdraws, or is no longer able to serve then the Parties shall have two Business Days in which to agree on a new Arbitrator. If the Parties are unable to agree within such time, the WSPP Representative shall appoint a replacement Arbitrator from the list used to select the first Arbitrator within two Business Days after being notified that the Parties are unable to agree. The dates and deadlines in this section may require modification if the mediator is replaced. Any extensions shall be as limited as possible. III. MISCELLANEOUS A. CONFIDENTIALITY. Any Arbitration or Mediation shall be confidential as provided in Section 34.4 of the WSPP Agreement. B. COSTS. Costs shall be borne by Parties as provided in Section 34.3 of the WSPP Agreement. Issued by: Michael E. Small, General Counsel to Effective: July 1, 2000 Western Systems Power Pool Issued on: September 29, 2000 Filed to comply with order of the Federal Energy Regulatory Commission, Docket Nos. ER00-3338, et al., issued September 15, 2000. Western Systems Power Pool Original Sheet No. 76 Rate Schedule FERC No. 6 C. RESTRICTIONS ON LAWSUITS. Each Party shall be subject to the restrictions provided in Section 34.2 of the WSPP Agreement. D. ATTORNEY-CLIENT/ATTORNEY WORKPRODUCT. The Arbitrator or Mediator shall not take any action which would result in disclosure of information in violation of the attorney-client privilege or attorney workproduct doctrine. IV. DEFINITIONS A. ARBITRATOR OR ARBITRATION. The Arbitrator appointed pursuant to these procedures and Section 34.2 of the WSPP Agreement and the Arbitration pursuant to these procedures and the WSPP Agreement. B. INITIAL OR REPLY BRIEFS. Written documents submitted by the Parties to support their positions and respond to each others positions. Such documents shall be limited to 25 pages. C. BUSINESS DAYS. Defined as in the WSPP Agreement. D. MEDIATOR OR MEDIATION. The Mediator appointed pursuant to these procedures and Section 34.1 of the WSPP Agreement and the Mediation pursuant to these procedures and the WSPP Agreement. E. PARTIES. The WSPP members involved in the Mediation or Arbitration which have a direct interest in the dispute. Issued by: Michael E. Small, General Counsel to Effective: July 1, 2000 Western Systems Power Pool Issued on: September 29, 2000 Filed to comply with order of the Federal Energy Regulatory Commission, Docket Nos. ER00-3338, et al., issued September 15, 2000. Western Systems Power Pool Original Sheet No. 77 Rate Schedule FERC No. 6 F. SERVICE, SERVING, OR SERVED. The method of service shall be by fax, unless impracticable because of the size of the document. In all events, the document should be delivered to the Party by overnight mail. Parties also should attempt to send the document out by email if possible. Service will be accomplished to a Party if sent to the Party's contact person for the disputed transaction. If there are multiple contact persons for one Party, service to one such person shall suffice. Service shall be to those individuals or entities specified in this procedures, but must include service to the Parties, the Mediator or Arbitrator (if either has been appointed), and to the WSPP General Counsel. G. WSPP REPRESENTATIVE. The Chairman of the WSPP Operating Committee or his or her designee for the purposes of the Arbitration or Mediation. Issued by: Michael E. Small, General Counsel to Effective: July 1, 2000 Western Systems Power Pool Issued on: September 29, 2000 Filed to comply with order of the Federal Energy Regulatory Commission, Docket Nos. ER00-3338, et al., issued September 15, 2000. Western Systems Power Pool Original Sheet No. 78 Rate Schedule FERC No. 6 SERVICE SCHEDULE A ECONOMY ENERGY SERVICE A-1 PARTIES: This Service Schedule is agreed upon as a part of this Agreement by the Parties. A-2 PURPOSE: The purpose of this Service Schedule is to define additional specific procedures, terms and conditions for requesting and providing Economy Energy Service. A-3 TERMS: A-3.1 A Party may schedule Economy Energy Service from another Party by mutual agreement; provided, however, that each Party shall be the sole judge as to the extent to and the conditions under which it is willing to provide or receive such service hereunder consistent with statutory requirements and contractual commitments including the Agreement and any applicable Confirmation Agreement. A-3.2 Scheduling of Economy Energy Service hereunder shall be a responsibility of the Parties involved. A-3.3 Each Seller/Purchaser may prepare a daily estimate of the amount of Economy Energy Service that it is willing and able to sell/buy each hour and the associated hourly sale/purchase price for the next Business Day, plus the weekend and Issued by: Michael E. Small, General Counsel to Effective: July 1, 2000 Western Systems Power Pool Issued on: September 29, 2000 Filed to comply with order of the Federal Energy Regulatory Commission, Docket Nos. ER00-3338, et al., issued September 15, 2000. Western Systems Power Pool Original Sheet No. 79 Rate Schedule FERC No. 6 holidays, and communicate this information to all other Parties via the Hub. A-3.4 Purchasers shall arrange purchases directly with Sellers, and shall be responsible for transmission arrangements. A-3.5 Unless otherwise mutually agreed between the Purchaser and the Seller, all Economy Energy Service transactions shall be pre-scheduled, and billings shall be based on amounts and prices agreed to in advance by schedulers, subject to Paragraphs A-3.6 and 3.7 and subject to change by mutual agreement between dispatchers or schedulers due to system changes. A-3.6 The price for Economy Energy Service shall be mutually agreed to in advance between Seller and Purchaser and shall not be subject to the rate caps specified in Section A-3.7 in either of the following two circumstances: (1) where the Seller is a FERC regulated public utility and that Seller has been authorized to sell power like that provided for under this Service Schedule at market-based rates; or (2) where the Seller is not a FERC regulated public utility. A Party is a FERC regulated public utility if it is a "public utility" as defined in Section 201(e) of the Federal Power Act, 16 U.S.C. Section 824(e). A-3.7 Except as provided for in Section A-3.6, the price shall not exceed the Seller's forecasted Incremental Cost plus up to: $7.32/kW/ month; $1.68/kW/week; Issued by: Michael E. Small, General Counsel to Effective: July 1, 2000 Western Systems Power Pool Issued on: September 29, 2000 Filed to comply with order of the Federal Energy Regulatory Commission, Docket Nos. ER00-3338, et al., issued September 15, 2000. Western Systems Power Pool Original Sheet No. 80 Rate Schedule FERC No. 6 33.78(cent)/kW/day; 14.07 mills/kWh; or 21.11 mills/kWh for service of sixteen (16) hours or less per day. The hourly rate is capped at the Seller's forecasted Incremental Cost plus 33.78(cent)/kW/ day. The total demand charge revenues in any consecutive seven-day period shall not exceed the product of the weekly rate and the highest demand experienced on any day in the seven-day period. In lieu of payment, such Parties may mutually agree to exchange economy energy at a ratio not to exceed that ratio provided for in Section C-3.7 of Service Schedule C. The Seller's forecasted Incremental Cost discussed above also may include any transmission and/or ancillary service costs associated with the sale, including the cost of any transmission and/or ancillary services that the Seller must take on its own system. Any such transmission and/or ancillary services charges shall be separately identified by the Seller to the Purchaser for transactions under this Schedule including the exchange of economy energy. The transmission and ancillary service rate ceilings shall be available through the WSPP's Hub or homepage. Any such transmission services (and ancillary service provided in conjunction with such transmission service) by Seller shall be provided pursuant to any applicable transmission tariff or agreement, and the rates therefore shall be consistent with such tariff or agreement. A-3.8 Unless otherwise agreed, the Purchaser shall be responsible for maintaining Issued by: Michael E. Small, General Counsel to Effective: July 1, 2000 Western Systems Power Pool Issued on: September 29, 2000 Filed to comply with order of the Federal Energy Regulatory Commission, Docket Nos. ER00-3338, et al., issued September 15, 2000. Western Systems Power Pool Original Sheet No. 81 Rate Schedule FERC No. 6 operating reserve requirements as back-up for Economy Energy Service purchased and the Seller shall not be required to maintain such operating reserve. A-3.9 Each Party that is a FERC regulated public utility as defined in A-3.6 shall file the Confirmation Agreement with FERC for each transaction under this Service Schedule with a term in excess of one year no later than 30 days after service begins if that Party would have been required to file such Confirmation Agreements or similar agreements with FERC under an applicable FERC accepted market based rate schedule. Issued by: Michael E. Small, General Counsel to Effective: July 1, 2000 Western Systems Power Pool Issued on: September 29, 2000 Filed to comply with order of the Federal Energy Regulatory Commission, Docket Nos. ER00-3338, et al., issued September 15, 2000. Western Systems Power Pool Original Sheet No. 82 Rate Schedule FERC No. 6 SERVICE SCHEDULE B UNIT COMMITMENT SERVICE B-1 PARTIES: This Service Schedule is agreed upon as part of this Agreement by the Parties. B-2 PURPOSE: The purpose of this Service Schedule is to define additional specific procedures, terms, and conditions for requesting and providing Unit Commitment Service. B-3 TERMS: B-3.1 A Party may schedule Unit Commitment Service from another Party by mutual agreement; provided, however, that each Party shall be the sole judge as to the extent to and the conditions under which it is willing to provide or receive such service hereunder consistent with statutory requirements and contractual commitments including the Agreement and any applicable Confirmation Agreement. Once an agreement is reached, then the obligation for Unit Commitment Service becomes a firm commitment, for both Parties, for the agreed capacity and terms. B-3.2 Unless otherwise mutually agreed by the Parties involved in a Unit Commitment Service transaction, the terms set forth in this Service Schedule B shall govern such transaction. Issued by: Michael E. Small, General Counsel to Effective: July 1, 2000 Western Systems Power Pool Issued on: September 29, 2000 Filed to comply with order of the Federal Energy Regulatory Commission, Docket Nos. ER00-3338, et al., issued September 15, 2000. Western Systems Power Pool Original Sheet No. 83 Rate Schedule FERC No. 6 B-3.3 Unless otherwise agreed between the Purchaser and the Seller, all transactions shall be prescheduled, subject to any conditions agreed to by schedulers, for a specified unit for a specified period of time. B-3.4 Purchasers shall arrange purchases directly with Sellers. B-3.5 The price for Unit Commitment Service shall be mutually agreed to in advance between Seller and Purchaser and shall not be subject to the rate caps specified in Section B-3.6 in either of the following two circumstances: (1) where the Seller is a FERC regulated public utility and that Seller has been authorized to sell power like that provided for under this Service Schedule at market-based rates; or (2) where the Seller is not a FERC regulated public utility. A Party is a FERC regulated public utility if it is a "public utility" as defined in Section 201(e) of the Federal Power Act, 16 U.S.C. Section 824(e). B-3.6 Except as provided for in Section B-3.5, the price shall not exceed the Seller's forecasted Incremental Cost plus up to: $7.32/kW/month; $1.68/kW/week; 33.78(cent)/kW/day; 14.07 mills/kWh; or 21.11 mills/kWh for service of sixteen (16) hours or less per day. The hourly rate is capped at the Seller's forecasted Incremental Cost plus 33.78(cent)/kW/day. The total demand charge revenues in any consecutive seven-day period shall not exceed the product of the weekly rate and the Issued by: Michael E. Small, General Counsel to Effective: July 1, 2000 Western Systems Power Pool Issued on: September 29, 2000 Filed to comply with order of the Federal Energy Regulatory Commission, Docket Nos. ER00-3338, et al., issued September 15, 2000. Western Systems Power Pool Original Sheet No. 84 Rate Schedule FERC No. 6 highest demand experienced on any day in the seven-day period. The Seller's forecasted Incremental Cost discussed above also may include any transmission and/or ancillary service costs associated with the sale, including the cost of any transmission and/or ancillary services that the Seller must take on its own system. Any such transmission and/or ancillary service charges shall be separately identified by the Seller to the Purchaser. The transmission and ancillary service rate ceilings shall be available through the WSPP's Hub or homepage. B-3.7 Start-up costs and no-load costs if included by the Seller shall be stated separately in the price. B-3.8 Energy schedules for the Purchaser's share of a unit may be modified by the Purchaser with not less than a thirty (30) minute notice before the hour in which the change is to take place, unless otherwise mutually agreed or unforeseen system operating conditions occur. B-3.9 Unit Commitment Service is intended to have assured availability; however, scheduled energy deliveries may be interrupted or curtailed as follows: (a) By the Seller by giving proper recall notice to the Purchaser if the Seller and the Purchaser have mutually agreed to recall provisions, (b) By the Seller when all or a portion of the output of the unit is unavailable, by an amount in proportion to the amount of the reduction in the output of the Issued by: Michael E. Small, General Counsel to Effective: July 1, 2000 Western Systems Power Pool Issued on: September 29, 2000 Filed to comply with order of the Federal Energy Regulatory Commission, Docket Nos. ER00-3338, et al., issued September 15, 2000. Western Systems Power Pool Original Sheet No. 85 Rate Schedule FERC No. 6 unit, unless otherwise agreed by the schedulers, (c) By the Seller to prevent system separation during an emergency, provided the Seller has exercised all prudent operating alternatives prior to the interruption or curtailment, (d) Where applicable, by the Seller to meet its public utility or statutory obligations to its customers, or (e) By either the Seller or the Purchaser due to the unavailability of transmission capacity necessary for the delivery of scheduled energy. B-3.10 Each Party that is a FERC regulated public utility as defined above in B-3.5 shall file the Confirmation Agreement with FERC for each transaction under this Service Schedule with a term in excess of one year no later than 30 days after service begins if that Party would have been required to file such Confirmation Agreements or similar agreements with FERC under an applicable FERC accepted market based rate schedule. B-4 BILLING AND PAYMENT PROVISIONS: B-4.1 Except as provided in Sections B-4.2 and B-5, billing for Unit Commitment Service shall be computed based upon the agreed upon prices. B-4.2 In the event the Seller requests recall of Unit Commitment Service in a shorter time frame than was mutually agreed pursuant to Section B-3.9(a) and the Issued by: Michael E. Small, General Counsel to Effective: July 1, 2000 Western Systems Power Pool Issued on: September 29, 2000 Filed to comply with order of the Federal Energy Regulatory Commission, Docket Nos. ER00-3338, et al., issued September 15, 2000. Western Systems Power Pool Original Sheet No. 86 Rate Schedule FERC No. 6 Purchaser agrees to allow such recall, the Purchaser shall be relieved of any obligation to pay start-up costs. B-5 TERMINATION PROVISION: In the event Unit Commitment Service is curtailed or interrupted except as provided in Section B-3.9(a), the Purchaser shall have the option to cancel the Unit Commitment Service at any time by paying the Seller for (i) all energy deliveries scheduled up to the notice of termination and (ii) all separately stated start-up and no-load costs. Issued by: Michael E. Small, General Counsel to Effective: July 1, 2000 Western Systems Power Pool Issued on: September 29, 2000 Filed to comply with order of the Federal Energy Regulatory Commission, Docket Nos. ER00-3338, et al., issued September 15, 2000. Western Systems Power Pool First Revised Sheet No. 87 Rate Schedule FERC No. 6 Superseding Original Sheet No. 87 SERVICE SCHEDULE C FIRM CAPACITY/ENERGY SALE OR EXCHANGE SERVICE C-1 PARTIES: This Service Schedule is agreed upon as a part of this Agreement by the Parties. C-2 PURPOSE: The purpose of this Service Schedule is to define additional specific procedures, terms, and conditions for requesting and providing Firm Capacity/Energy Sale or Exchange Service. C-3 TERMS: C-3.1 A Party may schedule Firm Capacity/Energy Sale or Exchange Service from another Party by mutual agreement; provided, however, that each Party shall be the sole judge as to the extent to and the conditions under which it is willing to provide or receive such service hereunder consistent with statutory requirements and contractual commitments including the Agreement and any applicable Confirmation Agreement. Once an agreement is reached, then the obligation for Firm Capacity/Energy Sale or Exchange Service becomes a firm commitment, for both Parties, for the agreed service and terms. C-3.2 Unless otherwise agreed between the Purchaser and the Seller, all transactions shall be prescheduled, subject to any conditions agreed to by schedulers. C-3.3 Firm capacity transactions shall include buying, selling, or exchanging capacity between Parties with or without associated energy. Firm capacity is deemed a capacity sale from the Seller's resources and backed by the Seller's Issued by: Michael E. Small, General Counsel to Effective: February 1, 2001 Western Systems Power Pool Issued on: December 1, 2000 Filed to comply with order of the Federal Energy Regulatory Commission, Docket Nos. ER00-3338, et al., issued September 15, 2000. Western Systems Power Pool First Revised Sheet No. 88 Rate Schedule FERC No. 6 Superseding Original Sheet No. 88 capacity reserves. C-3.4 Firm energy transactions shall include buying, selling, or exchanging firm energy between Parties. Subject to mutual agreement, firm energy is deemed a quantity of energy the Seller has agreed to sell and deliver and the Purchaser has agreed to buy within a specified time period. C-3.5 Purchaser shall arrange purchases directly with Sellers. C-3.6 The price for Firm Capacity/Energy Sale or Exchange Service shall be mutually agreed to in advance between Seller and Purchaser and shall not be subject to the rate caps specified in Section C-3.7 in either of the following two circumstances: (1) where the Seller is a FERC regulated public utility and that Seller has been authorized to sell power like that provided for under this Service Schedule at market-based rates; or (2) where the Seller is not a FERC regulated public utility. A Party is a FERC regulated public utility if it is a "public utility" as defined in Section 201(e) of the Federal Power Act, 16 U.S.C. Section 824(e). C-3.7 Except as provided for in Section C-3.6, the price shall not exceed the Seller's forecasted Incremental Cost plus up to: $7.32/kW/month; $1.68/kW/week; 33.78(cent)/kW/day; 14.07 mills/kWh; or 21.11 mills/kWh for service of sixteen (16) hours or less per day. The hourly rate is capped at the Seller's forecasted Incremental Cost plus 33.78(cent)/kW/day. The total demand charge revenues in any consecutive seven-day period shall not exceed the product of the weekly rate and the Issued by: Michael E. Small, General Counsel to Effective: February 1, 2001 Western Systems Power Pool Issued on: December 1, 2000 Filed to comply with order of the Federal Energy Regulatory Commission, Docket Nos. ER00-3338, et al., issued September 15, 2000. Western Systems Power Pool First Revised Sheet No. 89 Rate Schedule FERC No. 6 Superseding Original Sheet No. 89 highest demand experienced on any day in the seven-day period. Exchange ratios among such Parties shall be as mutually agreed between the Purchaser and the Seller, but shall not exceed the ratio of 1.5 to 1.0. The Seller's forecasted Incremental Cost discussed above also may include any transmission and/or ancillary service costs associated with the sale, including the cost of any transmission and/or ancillary services that the Seller must take on its own system. Any such transmission and/or ancillary service charges shall be separately identified by the Seller to the Purchaser for transactions under this Schedule including exchanges. The transmission and ancillary service rate ceiling shall be available through the WSPP's Hub or homepage. Any such transmission service (and ancillary services provided in conjunction with such transmission service) by Seller shall be provided pursuant to any applicable transmission tariff or agreement, and the rates therefore shall be consistent with such tariff or agreement. C-3.8 Firm Capacity/Energy Sale or Exchange Service shall be interruptible only if the interruption is: (a) within the recall time or allowed by other applicable provisions governing interruptions of service under this Service Schedule mutually agreed to by the Seller and the Purchaser, (b) due to an Uncontrollable Force as provided in Section 10 of this Agreement; or (c) where applicable, to meet Seller's public utility or statutory obligations to its customers. If service under this Service Schedule is interrupted under Section C-3.8(a) or (b), neither Seller nor Purchaser shall be obligated to pay any damages under this Agreement or Confirmation Agreement. If service under this Service Schedule is interrupted for any reason Issued by: Michael E. Small, General Counsel to Effective: February 1, 2001 Western Systems Power Pool Issued on: December 1, 2000 Filed to comply with order of the Federal Energy Regulatory Commission, Docket Nos. ER00-3338, et al., issued September 15, 2000. Western Systems Power Pool Original Sheet No. 89A Rate Schedule FERC No. 6 other than pursuant to Section C-3.8(a) or (b), the Non-Performing Party shall be responsible for payment of damages as provided in Section 21.3 of this Agreement or in any Confirmation. Issued by: Michael E. Small, General Counsel to Effective: February 1, 2001 Western Systems Power Pool Issued on: December 1, 2000 Filed to comply with order of the Federal Energy Regulatory Commission, Docket Nos. ER00-3338, et al., issued September 15, 2000. Western Systems Power Pool First Revised Sheet No. 90 Rate Schedule FERC No. 6 Superseding Original Sheet No. 90 C-3.9 Each Party that is a FERC regulated public utility as defined in Section C-3.6 shall file the Confirmation Agreement with FERC for each transaction under this Service Schedule with a term in excess of one year no later than 30 days after service begins if that Party would have been required to file such Confirmation Agreements or similar agreements with FERC under an applicable FERC accepted market based rate schedule. C-3.10 Seller shall be responsible for ensuring that Service Schedule C transactions are scheduled as firm power consistent with the most recent rules adopted by the applicable NERC regional reliability council. Wspp/WSPP Agreement 12-12 edits nonredlined version Issued by: Michael E. Small, General Counsel to Effective: February 1, 2001 Western Systems Power Pool Issued on: December 1, 2000 Filed to comply with order of the Federal Energy Regulatory Commission, Docket Nos. ER00-3338, et al., issued September 15, 2000. Western Systems Power Pool First Revised Sheet No. 91 Rate Schedule FERC No. 6 Superseding Original Sheet No. 91 LIST OF MEMBERS ACN Power, Inc. AES NewEnergy, Inc. Allegheny Energy Supply Co., LLC Amerada Hess Corporation Ameren Energy Generating Company American Electric Power Service Corporation as agent for Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company APS Energy Services Company, Inc. Aquila Energy Marketing Corporation Arizona Electric Power Co. Arizona Public Service Co. Arkansas Electric Coop. Corp. Associated Electric Cooperative, Inc. Astra Oil Company, Inc. Avista Corporation Avista Energy, Inc. Basin Electric Power Cooperative Benton Public Utility District No. 1 of Benton County Blackhills Power & Light Company Bonneville Power Adm. BP Energy Company Burbank, City of Calif. Dept. of Water Resources Calpine Energy Services, L.P. Candela Energy Corporation Cargill-Alliant, LLC Carolina Power & Light Company Cheyenne Light, Fuel and Power Co. Cinergy Capital & Trading, Inc. Cinergy Operating Companies City of Anaheim, Public Utilities Dept. City of Azusa City of Banning City of Glendale Water & Power Dept. City of Independence City of Klamath Falls City of Palo Alto City of Riverside, California City of Santa Clara Electric Department City of Sikeston, Board of Municipal Utilities City Utilities of Springfield, Missouri City Water & Light (Jonesboro, AR) Clatskanie PUD Cleco Marketing & Trading LLC Cleco Power LLC CMS Marketing, Services and Trading Company CNG Power Services Corp. Colorado River Commission of Nevada Colorado Springs Utilities Colton, City of Columbia Energy Power Marketing Columbia Power Corporation Cominco, Ltd. Commonwealth Energy Corporation ConAgra Energy Services, Inc. Conectiv Energy Supply, Inc. Conoco Gas & Power Marketing - a division of Conoco Inc. Constellation Power Source Cook Inlet Energy Supply Coral Power, L.L.C. Deseret G&T DTE Energy Trading, Inc. Duke Energy Trading & Marketing, LLC Duke Power Duke Solutions, Inc. Duke/Louis Dreyfuss, LLC Dynegy Power Marketing, Inc. Dynegy Power Services, Inc. E prime Edison Mission Marketing & Trading, Inc. Edison Source Edmonton Power Authority, Alberta El Paso Electric El Paso Merchant Energy, L.P. Empire District Electric Co. Energy Transfer Group, LLC EnerZ Corporation Issued by: Michael E. Small, General Counsel to Effective: March 1, 2002 Western Systems Power Pool Issued on: December 21, 2001 Western Systems Power Pool First Revised Sheet No. 92 Rate Schedule FERC No. 6 Superseding Original Sheet No. 92 Engage Energy America LLC Engelhard Power Marketing, Inc. ENMAX Energy Corporation ENMAX Energy Marketing Inc. Enron Power Marketing, Inc. Enserco Energy Inc. Entergy Arkansas, Inc. Entergy Gulf States, Inc. Entergy Louisiana, Inc. Entergy Mississippi, Inc. Entergy New Orleans, Inc. Entergy Power, Inc. Entergy Services, Inc. as agent for the Entergy Operating Companies Entergy-Koch Trading, LP Equitable Power Services Co. Eugene Water & Electric Board Exelon Generation Company, LLC Farmington, City of Federal Energy Sales, Inc. FPL Energy Power Marketing Inc. Golden Spread Electric Cooperative Grand River Dam Authority Hafslund Energy Trading, LLC Hetch-Hetchy Water & Power Hinson Power Co., LLC Howard Energy Co., Inc. IDACORP Energy L.P. Idaho Power Company IGI Resources, Inc. Illinova Energy Partners, Inc. Imperial Irrigation District Industrial Energy Applications, Inc. InterCoast Power Marketing J. Aron & Company KAMO Electric Cooperative, Inc. Kansas City Board of Public Utilities Kansas City Power & Light KN Energy Marketing Lafayette Utilities System LG&E Energy Marketing Inc. Lincoln Electric System Los Alamos County Los Angeles Dept. of Water & Power Louisiana Generating LLC Louisville Gas & Electric Company Maclaren Energy Inc. Mason County PUD No. 3 McMinnville Water & Light Merchant Energy Group of the Americas, Inc. Merrill Lynch Capital Services, Inc. Metropolitan Water District MidAmerican Energy Company MidCon Power Services Corp. MIECO, Inc. Minnesota Power, Inc. Mirant Americas Energy Marketing, LP Missouri Joint Municipal Electric Utility Comm. Modesto Irrigation District Morgan Stanley Capital Group, Inc. M-S-R Public Power Agency Municipal Energy Agency of Mississippi Municipal Energy Agency of Nebraska Nebraska Public Power District Nevada Power Co. New West Energy NorthPoint Energy Solutions Inc. Northern California Power Agency Northern States Power Company NP Energy Inc. NRG Power Marketing Inc. OGE Energy Resources, Inc. Oklahoma Gas & Electric Oklahoma Municipal Power Authority Omaha Public Power District ONEOK Power Marketing Company Otter Tail Power Company Pacific Gas & Electric Co. Pacific Northwest Generating Coop. PacifiCorp PacifiCorp Power Marketing, Inc. PanCanadian Energy Services Pasadena, City of PG&E Energy Services PG&E Energy Trading - Power, L.P. PG&E Power Services Company Issued by: Michael E. Small, General Counsel to Effective: March 1, 2002 Western Systems Power Pool Issued on: December 21, 2001 Western Systems Power Pool Sixth Revised Sheet No. 93 Rate Schedule FERC No. 6 Superseding Fifth Sheet No. 93 Phibro Inc. Pinnacle West Capital Corporation Plains Elec. Gen. & Trans. Coop. Inc. Platte River Power Authority Portland General Electric Co. Power Exchange Corporation Powerex PPL Electric Utilities Corporation PPL EnergyPlus, LLC PPL Montana, LLC Public Service Co. of NM Public Service Co. of Colorado Public Util. Dist. No. 1 of Douglas Cty. Public Util. Dist. No. 1 of Franklin Cty. PUD No. 1 of Chelan County PUD No. 1 of Grays Harbor County PUD No. 1 of Snohomish County PUD No. 2 of Grant County Puget Sound Energy QST Energy Trading Inc. Questar Energy Trading Rainbow Energy Marketing Corporation Redding, City of Reliant Energy Services, Inc. Rocky Mountain Generation Coop., Inc. Roseville Electric Sacramento Municipal Utility District Salt River Project San Diego Gas & Electric Co. Seattle City Light Sempra Energy Resources Sempra Energy Solutions Sempra Energy Trading Corp. Sierra Pacific Power Co. Southern Calif. Edison Co. Southern California Water Company Southern Company Services, Inc. Southern Illinois Power Cooperative Southwest Power Administration Southwestern Public Service Split Rock Energy LLC Statoil Energy Trading, Inc. Strategic Energy LLC Sunflower Electric Power Corp. Tacoma Power Tenaska Power Services Co. Tennessee Valley Authority Texaco Energy Services Texas-New Mexico Power Company The Detroit Edison Co. The Energy Authority The Montana Power Company The Power Company of America, LP Tractebel Energy Marketing, Inc. TransAlta Energy Marketing (US) Inc. TransCanada Power, div. of TransCanada Energy Ltd. Tri-State Generation and Transmission Assoc. Tucson Electric Power Turlock Irrigation District TXU Energy Trading Company Union Electric Company Utah Associated Municipal Power Systems UtiliCorp United Vastar Power Marketing, Inc. Vernon, City of VIASYN, Inc. Virginia Electric and Power Company Vitol Gas & Electric LLC WAPA-Colorado River Storage Project Management Center WAPA-Desert Southwest Region WAPA-Rocky Mountain Region WAPA-Upper Great Plains Region WAPA-Sierra Nevada Region West Kootenay Power Ltd. Western Farmers Electric Co-op Western Power Services, Inc. Western Resources, Inc. Williams Energy Marketing & Trading Co. WPS Energy Services, Inc. XCEL Energy Services, Inc. Issued by: Michael E. Small, General Counsel to Effective: March 1, 2002 Western Systems Power Pool Issued on: December 21, 2001 EX-10.(D) 7 b45693spexv10wxdy.txt SETTLEMENT AGREEMENT, DATED APRIL 16, 2002 Exhibit 10(D) UNITED STATES OF AMERICA BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION NEVADA POWER COMPANY ) DOCKET NOS. ER01-2754-002, ER01-2755-002, ER01-2758-002, AND ER01-2759-002 (NOT CONSOLIDATED) SETTLEMENT AGREEMENT This Settlement Agreement (the "Agreement"), dated April 16, 2002, is by and between Nevada Power Company ("NPC"); and each of Calpine Corporation ("Calpine"); Duke Energy Trading and Marketing, L.L.C. ("Duke"); Mirant Las Vegas, LLC ("Mirant"); Pinnacle West Energy Corporation ("Pinnacle"); and Reliant Energy Services, Inc. ("Reliant"). Calpine, Duke, Mirant, Pinnacle and Reliant are referred-to collectively as the "Generators." WHEREAS, NPC filed separate transmission service agreements ("TSAs") under its open Access Transmission Tariff ("Tariff") with each of the Generators at the Federal Energy Regulatory Commission ("FERC") in the above-referenced proceedings; and WHEREAS, in order to provide the transmission service provided for under the TSAs and to meet native load needs it is necessary for NPC to construct a 3000 MW transmission project known as the "Centennial Project;" and WHEREAS, on December 20, 2001, FERC issued an Order (the "December 20 Order") that, among other things; (1) set for settlement proceedings the issue of how much security NPC could require of the Generators in connection with the construction of the Centennial Project; (2) required NPC to negotiate with Calpine regarding the service, if any, that can be required under Service Agreement No. 95 that provides for service from the Crystal substation to the NPC Control Area; and (3) required NPC to make a compliance filing with respect to the remaining Calpine TSA and the Duke, Pinnacle and Reliant TSAs that implemented the December 20 Order's ruling regarding rollover rights; and WHEREAS, on February 27, 2002, NPC made its compliance filing (the "Compliance Filing"); and WHEREAS, the parties have negotiated regarding Centennial security, rollover rights and Calpine's Service Agreement No. 95; NOW THEREFORE, the parties agree as follows: 1. CENTENNIAL SECURITY. a. The amount of each Generator's responsibility for Centennial security is specified on Exhibit A to this Agreement. Such security shall be in a form as specified in paragraph 1(b), and if not already in place shall be put in place no later than 5 business days after FERC issues an order approving this Agreement. b. The following are acceptable forms of security: i. The Generator has, or provides a corporate guarantee in a form reasonably acceptable to NPC from an entity that has, a credit rating of BBB+/Baa1 or better (an "Acceptable Credit Rating"). ii. The Generator posts a letter of credit in a form reasonably acceptable to NPC from a bank acceptable to NPC. iii. The Generator posts a surety bond from an entity acceptable to NPC. iv. Any other form of security reasonably acceptable to NPC that provides NPC with at least the same level of security as items (i)-(iii) above; provided, however, that a Generator may without NPC's consent replace its existing security with any form of security listed in (i)-(iii) above. As of the date of this Agreement, all of the Generators except for Pinnacle have provided acceptable security in the specified amount and thus have satisfied Section 1 of this Agreement. c. Once service commences under a TSA, a Generator's security required under paragraph 1(a) shall be reduced annually on the anniversary of the commencement of service in an amount equal to the revenues received by NPC under the TSA in the previous year. When the initial term of the TSA expires, the security required under this Agreement shall be reduced to zero regardless of whether the TSA is renewed, at which time the security provisions of NPC's Tariff shall apply. NPC shall have the discretion to determine whether, upon the commencement of commercial operations of a Generator's facility, it is necessary or desirable to require the maintenance of security required by this paragraph 1. d. After NPC has received one year's worth of transmission revenues from a Generator under a TSA, the Acceptable Credit Rating requirement for that Generator will be reduced from BBB+/Baa1 to BBB/Baa2. 2. ROLLOVER RIGHTS. The rights of the Generator under the Duke, Pinnacle and Reliant TSAs to rollover long-term firm transmission service at the expiration of such TSAs will be governed by the provisions of Section 2.2 of NPC's Tariff or of the applicable provisions of any successor tariff, as such provisions may be modified in accordance with 2 FERC policy. Duke, Pinnacle and Reliant agree to engage in nonbinding communications with NPC regarding their intention to exercise rollover rights at the expiration of the TSAs that are the subject of this Agreement, so that NPC may plan its system accordingly. In order to effectuate this commitment, NPC will file amended TSAs that will include a new Section 5.0 in the form set forth in Exhibit B to this Agreement. 3. CALPINE SERVICE AGREEMENT NO. 95. a. Calpine Service Agreement No. 95 will be terminated, and Calpine's queue position with respect to its unfulfilled requests for transmission service made during the year 2000 will be restored. NPC will process Calpine's request for service into the NPC control area simultaneously with Calpine's later-filed request for service out of the NPC control area, with the goal of determining the additional facilities necessary to provide service into and out of the NPC control area under a single TSA (the "Revised Calpine TSA"). Such processing by NPC shall be in accordance with the procedures and priorities established by FERC under Order No. 888, including application of Order No. 888's first-in-time principles. b. NPC will execute a written release of the existing surety bond for Service Agreement No. 95 within 5 business days of the earlier to occur of: (a) the certification of this Agreement to FERC as an uncontested settlement; or (b) FERC's approval of this Agreement. c. NPC recognizes that Calpine has a single generation project that will rely on both its existing 400 MW Crystal to Mead TSA (the "Existing TSA") and the Revised Calpine TSA for transmission capacity for its project. In order for Calpine's project to be viable, Calpine needs assurances that the Revised Calpine TSA will provide for transmission rates and an in-service date that are compatible with its project. Therefore, an amendment to the Existing TSA will be filed with a new Section 9.0 regarding termination, as set forth in Exhibit C to this Agreement. d. In order to ensure that service under the Existing TSA and the Revised TSA commence at the same time, the date for commencement of service under the Existing TSA will be amended to provide that service will commence on January 1, 2005. 4. AMENDED 2000 RESOURCE PLAN. a. Within 90 days of the approval of this Agreement by FERC, NPC will file an amended 2000 Resource Plan, pursuant to NAC 704.9503 and NAC 704.9503(5), 3 at the Public Utilities Commission of Nevada ("PUCN") that will reflect the following native load uses of the Centennial Project: i. The 500 MW of capacity made available by terminating the Calpine Service Agreement No. 95; ii. Transmission capacity associated with any future sale of generation capacity from any of the Generators to NPC where the Generator either uses its own transmission rights to deliver the capacity to NPC or elects not to renew its TSA; iii. Transmission capacity associated with the Existing TSA if that agreement is terminated by Calpine as provided in paragraph 3(c); and iv. The potential to use the remaining unsubscribed 150 MW of Centennial capacity, provided that an appropriate transmission project is constructed that would allow such capacity to be delivered to the NPC control area. b. The filing by NPC of the amended 2000 Resource Plan pursuant to Paragraph 4(a) shall not affect the PUCN's full resource approval of the Centennial Project. c. Nothing in this Agreement obligates the PUCN to approve the amended 2000 Resource Plan to be filed under paragraph 4(a) or in any way has any impact on the PUCN's ruling on that filing. If NPC proposes in its amendment a new utility facility not previously approved by the PUCN, PUCN acceptance will be required in order for the new utility facility to be deemed a prudent investment pursuant to NRS 704.110(10). 5. TERM AND TERMINATION. This Agreement shall become effective as of the date that it is approved by FERC, and shall remain in effect until all security required by paragraph 1 has been terminated. The provisions of this Agreement are not severable and if the Agreement is not approved in whole by FERC, the Agreement shall be deemed null and void. 6. THIRD-PARTY BENEFICIARY RIGHTS. The PUCN is a third-party beneficiary of Paragraph 4 of this Agreement. This Agreement shall not in any way foreclose, limit, impair or otherwise encumber the ability, authority or jurisdiction of the PUCN to take any action on any issue or matter consistent with the law. With respect to the Generators, nothing in this Agreement shall be construed to constitute a representation, warranty, covenant, surety of obligation, guarantee, joint undertaking or joint venture, or any similar right, obligation, or relationship. No Generator may assert a claim of any type whatsoever against another Generator on the basis of any third-party beneficiary rights that may be presumed or implied as a result of this Agreement. Notwithstanding any provision in this Agreement, the obligations of the Generators are individual, not joint and several, and no Generator shall be liable to any other Generator, NPC, the PUCN or any third-party for any act or omission of any other party to this Agreement. 4 7. SUPPORT FOR EXPEDITIOUS APPROVAL. NPC and Generators agree to act to achieve expeditious PUCN and FERC approval of this Agreement. NPC will file this Agreement at FERC as a settlement within three business days of its execution by all Generators, and will pursue expeditious PUCN consideration. NPC will request, and Generators hereby support, comment periods at FERC as necessary so that final comments are due no later than five business days after the date that the PUCN considers the Agreement at a meeting. 8. CONSTRUCTION OF CENTENNIAL PROJECT. Nevada Power shall use reasonable efforts to complete the Centennial Project in time to provide service as contemplated under the TSAs. 9. COUNTERPARTS. This Agreement may be executed in counterparts, each one of which shall be deemed an original. IN WITNESS WHEREOF, the parties hereby have executed this Agreement as of the date set forth above. NEVADA POWER COMPANY CALPINE CORPORATION By: By: ------------------------ ---------------------------- DUKE ENERGY TRADING AND MARKETING L.L.C. MIRANT LAS VEGAS, LLC By: By: ------------------------ ---------------------------- PINNACLE WEST ENERGY CORPORATION RELIANT ENERGY SERVICES, INC. By: By: ------------------------ ---------------------------- 5 EXHIBIT A SECURITY REQUIREMENTS TOTAL CENTENNIAL COSTS $254 MILLION Calpine $33.33 million Duke $50 million Mirant $40.67 million Pinnacle $29.67 million Reliant $41.67 million Remainder (assumed by NPC) $58.66 million
EXHIBIT B SECTION 5.0 OF DUKE, RELIANT AND PINNACLE TSAs 5.0 The Transmission Customer's renewal rights under this agreement shall be as specified in Section 2.2 of the Transmission Provider's Tariff as it may be amended from time to time in accordance with FERC policy. In addition, in order to assist the Transmission Provider in planning its system appropriately, the Transmission Customer will communicate with the Transmission Provider on a nonbinding basis regarding its assessment of whether it will renew this agreement as follows: 5.1 In the event the Transmission Customer signs a power sales contract that: (1) utilizes the transmission capacity provided for under this agreement, and (2) extends beyond this agreement's initial term, the Transmission Customer shall so notify the Transmission Provider (without identifying the parties to the power sales contract) and shall provide the Transmission Provider with the Transmission Customer's assessment of the likely impact of such contract on its intent to renew this agreement. 5.2 The Transmission Customer will on an annual basis, starting five years prior to the end of the initial term of this agreement, provide the Transmission Provider with a nonbinding statement of its current assessment of whether it will renew this agreement. The Transmission Customer will, on Transmission Provider's request, answer any reasonable questions the Transmission Provider has about such assessment; provided that the Transmission Customer shall not be obligated to provide any confidential market data to the Transmission Provider. 5.3 The Transmission Provider's transmission personnel shall treat as confidential and proprietary all information provided by Transmission Customer under this Section 5.0, and shall comply with FERC's affiliate regulations and other applicable provisions of Order No. 889, or any successor requirements, in its treatment of such information; provided that this Section 5.3 shall not prevent the Transmission Provider from providing information to FERC, the PUCN or any other agency of competent jurisdiction in accordance with applicable requirements of such agency or from compliance with any valid court order requiring the production of such information. The Transmission Provider shall give the Transmission Customer notice of any such agency request or court order so that the Transmission Customer may take any action deemed necessary by the Transmission Customer to protect the confidentiality of the requested information. 2 EXHIBIT C CALPINE TERMINATION RIGHTS 9.0 The Transmission Customer may terminate this agreement prior to the date specified in Section 1.0 as follows: 9.1 The Transmission Customer has submitted requests for service that would result in a transmission service request for capacity leading from the Crystal substation to delivery points in the El Dorado Valley (the "Second Service Request"). The Transmission Customer shall have the right to terminate this agreement under this Section 9.0 if the Transmission Provider's processing of the Second Service Request does not result in a transmission service agreement filed at FERC no later than October 15, 2002, that has the following attributes: 9.1.1 Firm point-to-point Transmission service for a 25-year term for 500 MW from the Crystal substation to delivery points in the El Dorado Valley, provided at the Transmission Provider's rolled-in transmission rates. 9.1.2 Transmission service to commence no later than January 1, 2005. 9.1.3 The amount of the Transmission Customer's regional required upgrades resulting from the interconnection of the Transmission Customer's generation facility to the Transmission Provider's system has not increased solely as a consequence of the Second Service Request. 9.1.4 Transmission Provider will accept as security any of the acceptable forms of security listed in the Settlement Agreement in Docket Nos. ER01-2754, et al. If any upgrades necessary for the Second Service Request are made exclusively for the Second Service Request, Transmission Provider will permit a ramped-up security arrangement whereby security will be required only as Transmission Provider makes expenditures for the upgrades. If necessary upgrades are made for the Second Service Request and other service requests as a group, Transmission Provider will permit a ramped-up security arrangement to the extent practical. 9.2 In the event that a transmission service agreement with the above attributes is not filed at FERC by October 15, 2002, then the Transmission Customer shall have thirty days to provide the Transmission Provider with notice of termination of this agreement. If notice of termination is not provided within 30 days, then the Transmission Customer shall no longer have any right to terminate under this Section 9.0. 9.3 In the event that the Transmission Customer does terminate this agreement pursuant to this Section 9.0, it shall be responsible for all nonmitigable damages incurred by the Transmission Provider, provided that in no event shall the Transmission Customer be obligated to pay more than $10,000,000 in damages (the "Damages Cap"). The Transmission Provider shall use its reasonable efforts to mitigate any damages, including but not limited to, permitting another credit worthy customer to assume all or part of the Transmission Customer's rights and obligations or reducing the scope of the upgrade facilities to the extent it is possible to do so and still satisfy all other requests for service to be satisfied with such facilities. The Damages Cap shall not be construed to be a liquidated damages provision and shall not relieve the Transmission Provider of its obligation to mitigate its damages or prove the amount of its claim. 2 EX-10.(E) 8 b45693spexv10wxey.txt SERVICE AGREEMENT NO. 96 FOR LONG-TERM FIRM POINT EXHIBIT 10(E) SIERRA PACIFIC RESOURCES OPERATING COMPANIES FERC ELECTRIC TARIFF FIRST REVISED VOLUME NO. 1 SERVICE AGREEMENT NO. 96 OPEN ACCESS TRANSMISSION TARIFF Page 1 of 6 SERVICE AGREEMENT FOR LONG-TERM FIRM POINT-TO-POINT TRANSMISSION SERVICE 1.0 This Service Agreement, dated as of July 9, 2002, is entered into, by and between Sierra Pacific Power Company and/or Nevada Power Company as appropriate ("Transmission Provider"), and Calpine Corporation, (Calpine) ("Transmission Customer"). 2.0 The Transmission Customer has been determined by the Transmission Provider to have a Completed Application for Firm Point-To-Point Transmission Service under the Tariff. 3.0 The Transmission Customer has provided to the Transmission Provider an Application deposit in accordance with the provisions of Section 17.3 of the Tariff. 4.0 Service under this agreement shall commence on the later of (l) the requested service commencement date, or (2) the date on which construction of any Direct Assignment Facilities and/or Network Upgrades are completed, or (3) such other date as it is permitted to become effective by the Commission. Service under this agreement shall terminate on the actual termination date or such date as mutually agreed upon by the parties. 5.0 The Transmission Provider agrees to provide and the Transmission Customer agrees to take and pay for Firm Point-To-Point Transmission Service in accordance with the provisions of Part II of the Tariff and this Service Agreement. 6.0 Any notice or request made to or by either Party regarding this Service Agreement shall be made to the representative of the other Party as indicated below. EXHIBIT 10(E) SIERRA PACIFIC RESOURCES OPERATING COMPANIES FERC ELECTRIC TARIFF FIRST REVISED VOLUME NO. 1 SERVICE AGREEMENT NO. 96 OPEN ACCESS TRANSMISSION TARIFF Page 2 of 6 7.0 If any event occurs that will materially affect the time for completion of new facilities or the ability to complete them, Transmission Provider shall promptly notify the Transmission Customer. A technical meeting between the Parties shall be held to evaluate the alternatives available. If the Transmission Provider and the Transmission Customer mutually agree that no other reasonable alternatives exist and the requested service cannot be provided out of existing capability under the conditions of Part II of the Tariff, the obligation to provide the requested Firm Point-To-Point Transmission Service shall terminate and any deposit made by the Transmission Customer shall be returned with interest pursuant to Commission regulations 35.19a(a)(2)(iii). However, the Transmission Customer shall be responsible for all prudently incurred costs by the Transmission Provider through the time construction was suspended. Transmission Provider: Director, Regional Transmission Nevada Power Company P.O. Box 230 Las Vegas, NV 89151 Transmission Customer: Calpine Corporation 50 West San Fernando Street San Jose, CA 95133 8.0 The Tariff is incorporated herein and made a part hereof. 9.0 The Transmission Customer may terminate this agreement prior to the date specified in Section 1.0 as follows: 9.1 The Transmission Customer has submitted requests for service that would result in a transmission service request for capacity leading from the Crystal substation to delivery points in the El Dorado Valley (the "Second Service Request"). The Transmission Customer shall have the right to terminate this agreement under this Section 9.0 if the Transmission Provider's processing of the Second Service Request does not result in a transmission service agreement filed at FERC no later than October 15, 2002, that has the following attributes: 9.1.1 Firm point-to-point Transmission service for a 25-year term for 500 MW from the Crystal substation to delivery points in the El Dorado Valley, provided at the Transmission Provider's rolled-in transmission rates. EXHIBIT 10(E) SIERRA PACIFIC RESOURCES OPERATING COMPANIES FERC ELECTRIC TARIFF FIRST REVISED VOLUME NO. 1 SERVICE AGREEMENT NO. 96 OPEN ACCESS TRANSMISSION TARIFF Page 3 of 6 9.1.2 Transmission service to commence no later than January 1, 2005. 9.1.3 The amount of the Transmission Customer's regional required upgrades resulting from the interconnection of the Transmission Customer's generation facility to the Transmission Provider's system has not increased solely as a consequence of the Second Service Request. 9.1.4 Transmission Provider will accept as security any of the acceptable forms of security listed in the Settlement Agreement in Docket Nos. ER01-2754, et al. If any upgrades necessary for the Second Service Request are made exclusively for the Second Service Request, Transmission Provider will permit a ramped-up security arrangement whereby security will be required only as Transmission Provider makes expenditures for the upgrades. If necessary upgrades are made for the Second Service Request and other service requests as a group, Transmission Provider will permit a ramped-up security arrangement to the extent practical. 9.2 In the event that a transmission service agreement with the above attributes is not filed at FERC by October 15, 2002, then the Transmission Customer shall have thirty days to provide the Transmission Provider with notice of termination of this agreement. If notice of termination is not provided within 30 days, then the Transmission Customer shall no longer have any right to terminate under this Section 9.0. 9.3 In the event that the Transmission Customer does terminate this agreement pursuant to this Section 9.0, it shall be responsible for all nonmitigable damages incurred by the Transmission Provider, provided that in no event shall the Transmission Customer be obligated to pay more than $10,000,000 in damages (the "Damages Cap"). The Transmission Provider shall use its reasonable efforts to mitigate any damages, including but not limited to, permitting another credit worthy customer to assume all or part of the Transmission Customer's rights and obligations or reducing the scope of the upgrade facilities to the extent it is possible to do so and still satisfy all other requests for service to be satisfied with such facilities. The Damages Cap shall not be construed to be a liquidated damages provision and shall not relieve the Transmission Provider of its obligation to mitigate its damages or prove the amount of its claim. EXHIBIT 10(E) SIERRA PACIFIC RESOURCES OPERATING COMPANIES FERC ELECTRIC TARIFF FIRST REVISED VOLUME NO. 1 SERVICE AGREEMENT NO. 96 OPEN ACCESS TRANSMISSION TARIFF Page 4 of 6 IN WITNESS WHEREOF, the Parties have caused this Service Agreement to be executed by their respective authorized officials. Transmission Provider: By: __________________________ __________________ __________________ Name Title Date Transmission Customer: By:___________________________ __________________ __________________ Name Title Date EXHIBIT 10(E) SIERRA PACIFIC RESOURCES OPERATING COMPANIES FERC ELECTRIC TARIFF FIRST REVISED VOLUME NO. 1 SERVICE AGREEMENT NO. 96 OPEN ACCESS TRANSMISSION TARIFF Page 5 of 6 Specifications For Long-Term Firm Point-To-Point Transmission Service 1.0 Term of Transaction: 25 Year(s) Start Date: 01-01-05 Termination Date: 12-31-29 2.0 Description of capacity and energy to be transmitted by Transmission Provider including the electric Control Area in which the transaction originates. 400 MW from Crystal 500 kV Substation in Nevada Power Company's Control Area to Mead 230 kV Substation . 3.0 Point of Receipt Delivering Party CRYSTAL 500 KV SUBSTATION CALPINE CORPORATION 4.0 Point of Delivery Receiving Party MEAD 230 KV SUBSTATION MARKET Nevada Power will propose the addition of a Mead 500/230 kV transformer such that this contract path would allow for deliveries to Mead 230 kV. Nevada Power will work with the appropriate third party utilities to accomplish the interconnection. Any firm service that is offered by Nevada Power to Mead 230 kV using this contract path is contingent upon the successful completion of the transformer installation. 5.0 Maximum amount of capacity and energy to be transmitted (Reserved Capacity): 400 MW 6.0 Designation of party(ies) subject to reciprocal service obligation: None 7.0 Name(s) of any Intervening Systems providing transmission service: None EXHIBIT 10(E) SIERRA PACIFIC RESOURCES OPERATING COMPANIES FERC ELECTRIC TARIFF FIRST REVISED VOLUME NO. 1 SERVICE AGREEMENT NO. 96 OPEN ACCESS TRANSMISSION TARIFF Page 6 of 6 8.0 Service under this Agreement may be subject to some combination of the charges detailed below. (The appropriate charges for individual transactions will be determined in accordance with the terms and conditions of the Tariff.) 8.1 Transmission Charge: $1.21/kW-mo. 8.2 System Impact and/or Facilities Study Charge(s): Pending finalization, $30,000 deposit in place. Calpine will be responsible for the final actual costs. 8.3 Direct Assignment Facilities Charge: None under this TSA. However, Direct Assignment Facilities will be required to provide the associated interconnection and are defined in the Interconnection & Operation Agreement. 8.4 Ancillary Services Charges: As negotiated in the future or as defined in Interconnection and Operation Agreement. 8.5. Power Factor Requirements: As defined in Interconnection and Operation Agreement. EX-10.(F) 9 b45693spexv10wxfy.txt SERVICE AGREEMENT NO. 97 FOR LONG-TERM FIRM POINT EXHIBIT 10(F) SIERRA PACIFIC RESOURCES OPERATING COMPANIES FERC ELECTRIC TARIFF FIRST REVISED VOLUME NO. 1 SERVICE AGREEMENT NO. 97 OPEN ACCESS TRANSMISSION TARIFF Page 1 of 5 SERVICE AGREEMENT FOR LONG-TERM FIRM POINT-TO-POINT TRANSMISSION SERVICE 1.0 This Service Agreement, dated as of July 3, 2002, is entered into, by and between Sierra Pacific Power Company and/or Nevada Power Company as appropriate ("Transmission Provider"), and Duke Energy Trading and Marketing, (Duke) ("Transmission Customer"). 2.0 The Transmission Customer has been determined by the Transmission Provider to have a Completed Application for Firm Point-To-Point Transmission Service under the Tariff. 3.0 The Transmission Customer has provided to the Transmission Provider an Application deposit in accordance with the provisions of Section 17.3 of the Tariff. 4.0 Service under this agreement shall commence on the later of (l) the requested service commencement date, or (2) the date on which construction of any Direct Assignment Facilities and/or Network Upgrades are completed, or (3) such other date as it is permitted to become effective by the Commission. Service under this agreement shall terminate on the actual termination date or such date as mutually agreed upon by the parties. 5.0 The Transmission Customer's renewal rights under this agreement shall be as specified in Section 2.2 of the Transmission Provider's Tariff as it may be amended from time to time in accordance with FERC policy. In addition, in order to assist the Transmission Provider in planning its system appropriately, the Transmission Customer will communicate with the Transmission Provider on a nonbinding basis regarding its assessment of whether it will renew this agreement as follows: 5.1 In the event the Transmission Customer signs a power sales contract that: (1) utilizes the transmission capacity provided for under this agreement, and (2) extends beyond this agreement's initial term, the Transmission Customer shall so notify the Transmission Provider (without identifying the parties to the power sales contract) and shall provide the Transmission Provider with the Transmission Customer's assessment of the likely impact of such contract on its intent to renew this agreement. EXHIBIT 10(F) SIERRA PACIFIC RESOURCES OPERATING COMPANIES FERC ELECTRIC TARIFF FIRST REVISED VOLUME NO. 1 SERVICE AGREEMENT NO. 97 OPEN ACCESS TRANSMISSION TARIFF Page 2 of 5 5.2 The Transmission Customer will on an annual basis, starting five years prior to the end of the initial term of this agreement, provide the Transmission Provider with a nonbinding statement of its current assessment of whether it will renew this agreement. The Transmission Customer will, on Transmission Provider's request, answer any reasonable questions the Transmission Provider has about such assessment; provided that the Transmission Customer shall not be obligated to provide any confidential market data to the Transmission Provider. 5.3 The Transmission Provider's transmission personnel shall treat as confidential and proprietary all information provided by Transmission Customer under this Section 5.0, and shall comply with FERC's affiliate regulations and other applicable provisions of Order No. 889, or any successor requirements, in its treatment of such information; provided that this Section 5.3 shall not prevent the Transmission Provider from providing information to FERC, the PUCN or any other agency of competent jurisdiction in accordance with applicable requirements of such agency or from compliance with any valid court order requiring the production of such information. The Transmission Provider shall give the Transmission Customer notice of any such agency request or court order so that the Transmission Customer may take any action deemed necessary by the Transmission Customer to protect the confidentiality of the requested information. 6.0 The Transmission Provider agrees to provide and the Transmission Customer agrees to take and pay for Firm Point-To-Point Transmission Service in accordance with the provisions of Part II of the Tariff and this Service Agreement. 7.0 Any notice or request made to or by either Party regarding this Service Agreement shall be made to the representative of the other Party as indicated below. EXHIBIT 10(F) SIERRA PACIFIC RESOURCES OPERATING COMPANIES FERC ELECTRIC TARIFF FIRST REVISED VOLUME NO. 1 SERVICE AGREEMENT NO. 97 OPEN ACCESS TRANSMISSION TARIFF Page 3 of 5 8.0 If any event occurs that will materially affect the time for completion of new facilities or the ability to complete them, Transmission Provider shall promptly notify the Transmission Customer. A technical meeting between the Parties shall be held to evaluate the alternatives available. If the Transmission Provider and the Transmission Customer mutually agree that no other reasonable alternatives exist and the requested service cannot be provided out of existing capability under the conditions of Part II of the Tariff, the obligation to provide the requested Firm Point-To-Point Transmission Service shall terminate and any deposit made by the Transmission Customer shall be returned with interest pursuant to Commission regulations 35.19a(a)(2)(iii). However, the Transmission Customer shall be responsible for all prudently incurred costs by the Transmission Provider through the time construction was suspended. Transmission Provider: Director, Regional Transmission Nevada Power Company P.O. Box 230 Las Vegas, NV 89151 Transmission Customer: Manager, New Business Development Duke Energy Trading and Marketing 4 Triad Center Suite 1000 Salt Lake City, UT 84180 9.0 The Tariff is incorporated herein and made a part hereof. IN WITNESS WHEREOF, the Parties have caused this Service Agreement to be executed by their respective authorized officials. Transmission Provider: By: __________________________ __________________ __________________ Name Title Date Transmission Customer: By:___________________________ __________________ __________________ Name Title Date EXHIBIT 10(F) SIERRA PACIFIC RESOURCES OPERATING COMPANIES FERC ELECTRIC TARIFF FIRST REVISED VOLUME NO. 1 SERVICE AGREEMENT NO. 97 OPEN ACCESS TRANSMISSION TARIFF Page 4 of 5 Specifications For Long-Term Firm Point-To-Point Transmission Service 1.0 Term of Transaction: 5 Year(s) Start Date: 07-31-03 Termination Date: 07-30-08 2.0 Description of capacity and energy to be transmitted by Transmission Provider including the electric Control Area in which the transaction originates. 600 MW from Harry Allen 500 kV Substation in Nevada Power Company's Control Area to Mead 230 kV Substation. 3.0 Point of Receipt Delivering Party HARRY ALLEN 500 KV SUBSTATION DUKE ENERGY TRADING AND MARKETING 4.0 Point of Delivery Receiving Party MEAD 230 KV SUBSTATION DUKE ENERGY TRADING AND MARKETING Nevada Power will propose the addition of a Mead 500/230 kV transformer such that this contract path would allow for deliveries to Mead 230 kV. Nevada Power will work with the appropriate third party utilities to accomplish the interconnection. Any firm service that is offered by Nevada Power to Mead 230 kV using this contract path is contingent upon the successful completion of the transformer installation. 5.0 Maximum amount of capacity and energy to be transmitted (Reserved Capacity): 600 MW 6.0 Designation of party(ies) subject to reciprocal service obligation: None 7.0 Name(s) of any Intervening Systems providing transmission service: None EXHIBIT 10(F) SIERRA PACIFIC RESOURCES OPERATING COMPANIES FERC ELECTRIC TARIFF FIRST REVISED VOLUME NO. 1 SERVICE AGREEMENT NO. 97 OPEN ACCESS TRANSMISSION TARIFF Page 5 of 5 8.0 Service under this Agreement may be subject to some combination of the charges detailed below. (The appropriate charges for individual transactions will be determined in accordance with the terms and conditions of the Tariff.) 8.1 Transmission Charge: $1.21/kW-mo. 8.2 System Impact and/or Facilities Study Charge(s): Pending finalization, $30,000 deposit in place. Duke will be responsible for the final actual costs. 8.3 Direct Assignment Facilities Charge: None under this TSA. However, Direct Assignment Facilities will be required to provide the associated interconnection and are defined in the Interconnection & Operation Agreement. 8.4 Ancillary Services Charges: As negotiated in the future or as defined in Interconnection and Operation Agreement. 8.5. Power Factor Requirements: As defined in Interconnection and Operation Agreement. EX-10.(G) 10 b45693spexv10wxgy.txt SERVICE AGREEMENT NO. 100 FOR LONG-TERM FIRM POINT EXHIBIT 10(G) SIERRA PACIFIC RESOURCES OPERATING COMPANIES FERC ELECTRIC TARIFF FIRST REVISED VOLUME NO. 1 SERVICE AGREEMENT NO. 100 OPEN ACCESS TRANSMISSION TARIFF (ASSIGNED FROM PINNACLE WEST TSA NO. 100) Page 1 of 5 SERVICE AGREEMENT FOR LONG-TERM FIRM POINT-TO-POINT TRANSMISSION SERVICE 1.0 This Service Agreement, dated as of December 12, 2002, is entered into, by and between Sierra Pacific Power Company and/or Nevada Power Company as appropriate ("Transmission Provider"), and Reliant Energy Services, Inc., (Reliant - Arrow Canyon) ("Transmission Customer"). 2.0 The Transmission Customer has been determined by the Transmission Provider to have a Completed Application for Firm Point-To-Point Transmission Service under the Tariff. 3.0 The Transmission Customer has provided to the Transmission Provider an Application deposit in accordance with the provisions of Section 17.3 of the Tariff. 4.0 Service under this agreement shall commence on the later of (l) the requested service commencement date, or (2) the date on which construction of any Direct Assignment Facilities and/or Network Upgrades are completed, or (3) such other date as it is permitted to become effective by the Commission. Service under this agreement shall terminate on the actual termination date or such date as mutually agreed upon by the parties. 5.0 The Transmission Customer's renewal rights under this agreement shall be as specified in Section 2.2 of the Transmission Provider's Tariff as it may be amended from time to time in accordance with FERC policy. In addition, in order to assist the Transmission Provider in planning its system appropriately, the Transmission Customer will communicate with the Transmission Provider on a nonbinding basis regarding its assessment of whether it will renew this agreement as follows: 5.1 In the event the Transmission Customer signs a power sales contract that: (1) utilizes the transmission capacity provided for under this agreement, and (2) extends beyond this agreement's initial term, the Transmission Customer shall so notify the Transmission Provider (without identifying the parties to the power sales contract) and shall provide the Transmission Provider with the Transmission Customer's assessment of the likely impact of such contract on its intent to renew this agreement. EXHIBIT 10(G) SIERRA PACIFIC RESOURCES OPERATING COMPANIES FERC ELECTRIC TARIFF FIRST REVISED VOLUME NO. 1 SERVICE AGREEMENT NO. 100 OPEN ACCESS TRANSMISSION TARIFF (ASSIGNED FROM PINNACLE WEST TSA NO. 100) Page 2 of 5 5.2 The Transmission Customer will on an annual basis, starting five years prior to the end of the initial term of this agreement, provide the Transmission Provider with a nonbinding statement of its current assessment of whether it will renew this agreement. The Transmission Customer will, on Transmission Provider's request, answer any reasonable questions the Transmission Provider has about such assessment; provided that the Transmission Customer shall not be obligated to provide any confidential market data to the Transmission Provider. 5.3 The Transmission Provider's transmission personnel shall treat as confidential and proprietary all information provided by Transmission Customer under this Section 5.0, and shall comply with FERC's affiliate regulations and other applicable provisions of Order No. 889, or any successor requirements, in its treatment of such information; provided that this Section 5.3 shall not prevent the Transmission Provider from providing information to FERC, the PUCN or any other agency of competent jurisdiction in accordance with applicable requirements of such agency or from compliance with any valid court order requiring the production of such information. The Transmission Provider shall give the Transmission Customer notice of any such agency request or court order so that the Transmission Customer may take any action deemed necessary by the Transmission Customer to protect the confidentiality of the requested information. 6.0 The Transmission Provider agrees to provide and the Transmission Customer agrees to take and pay for Firm Point-To-Point Transmission Service in accordance with the provisions of Part II of the Tariff and this Service Agreement. 7.0 Any notice or request made to or by either Party regarding this Service Agreement shall be made to the representative of the other Party as indicated below. EXHIBIT 10(G) SIERRA PACIFIC RESOURCES OPERATING COMPANIES FERC ELECTRIC TARIFF FIRST REVISED VOLUME NO. 1 SERVICE AGREEMENT NO. 100 OPEN ACCESS TRANSMISSION TARIFF (ASSIGNED FROM PINNACLE WEST TSA NO. 100) Page 3 of 5 8.0 If any event occurs that will materially affect the time for completion of new facilities or the ability to complete them, Transmission Provider shall promptly notify the Transmission Customer. A technical meeting between the Parties shall be held to evaluate the alternatives available. If the Transmission Provider and the Transmission Customer mutually agree that no other reasonable alternatives exist and the requested service cannot be provided out of existing capability under the conditions of Part II of the Tariff, the obligation to provide the requested Firm Point-To-Point Transmission Service shall terminate and any deposit made by the Transmission Customer shall be returned with interest pursuant to Commission regulations 35.19a(a)(2)(iii). However, the Transmission Customer shall be responsible for all prudently incurred costs by the Transmission Provider through the time construction was suspended. Transmission Provider: Director, Regional Transmission Nevada Power Company P.O. Box 230 Las Vegas, NV 89151 Transmission Customer: West Trading Group - Transmission Reliant Energy Services, Inc. P.O. Box 4455 Houston, TX 77210-4455 9.0 The Tariff is incorporated herein and made a part hereof. IN WITNESS WHEREOF, the Parties have caused this Service Agreement to be executed by their respective authorized officials. Transmission Provider: By: __________________________ __________________ __________________ Name Title Date Transmission Customer: By:___________________________ __________________ __________________ Name Title Date EXHIBIT 10(G) SIERRA PACIFIC RESOURCES OPERATING COMPANIES FERC ELECTRIC TARIFF FIRST REVISED VOLUME NO. 1 SERVICE AGREEMENT NO. 100 OPEN ACCESS TRANSMISSION TARIFF (ASSIGNED FROM PINNACLE WEST TSA NO. 100) Page 4 of 5 Specifications For Long-Term Firm Point-To-Point Transmission Service 1.0 Term of Transaction: 10 Year(s) Start Date: 06-01-04 Termination Date: 05-31-14 2.0 Description of capacity and energy to be transmitted by Transmission Provider including the electric Control Area in which the transaction originates. 350 MW from Harry Allen 500 kV Substation in Nevada Power Company's Control Area to Mead 500 kV Substation using the Contract Path HA 500 kV - Mead 500 kV. 3.0 Point of Receipt Delivering Party HARRY ALLEN 500 KV SUBSTATION RELIANT ENERGY SERVICES, INC. 4.0 Point of Delivery Receiving Party MEAD 500 KV SUBSTATION MARKET 5.0 Maximum amount of capacity and energy to be transmitted (Reserved Capacity): 350 MW 6.0 Designation of party(ies) subject to reciprocal service obligation: None 7.0 Name(s) of any Intervening Systems providing transmission service: None EXHIBIT 10(G) SIERRA PACIFIC RESOURCES OPERATING COMPANIES FERC ELECTRIC TARIFF FIRST REVISED VOLUME NO. 1 SERVICE AGREEMENT NO. 100 OPEN ACCESS TRANSMISSION TARIFF (ASSIGNED FROM PINNACLE WEST TSA NO. 100) Page 5 of 5 8.0 Service under this Agreement may be subject to some combination of the charges detailed below. (The appropriate charges for individual transactions will be determined in accordance with the terms and conditions of the Tariff.) 8.1 Transmission Charge: $1.21/kW-mo. 8.2 System Impact and/or Facilities Study Charge(s): Pending finalization, $30,000 deposit in place. Pinnacle West will be responsible for the final actual costs. 8.3 Direct Assignment Facilities Charge: None under this TSA. However, Direct Assignment Facilities will be required to provide the associated interconnection and are defined in the Interconnection & Operation Agreement. 8.4 Ancillary Services Charges: As negotiated in the future or as defined in Interconnection and Operation Agreement. 8.5. Power Factor Requirements: As defined in Interconnection and Operation Agreement. EX-10.(H) 11 b45693spexv10wxhy.txt SERVICE AGREEMENT NO. 101.A FOR LONG-TERM FIRM EXHIBIT 10(H) SIERRA PACIFIC RESOURCES OPERATING COMPANIES FERC ELECTRIC TARIFF FIRST REVISED VOLUME NO. 1 SERVICE AGREEMENT NO. 101.A (ASSIGNED) OPEN ACCESS TRANSMISSION TARIFF Page 1 of 5 SERVICE AGREEMENT FOR LONG-TERM FIRM POINT-TO-POINT TRANSMISSION SERVICE 1.0 This Service Agreement, dated as of December 12, 2002, is entered into, by and between Sierra Pacific Power Company and/or Nevada Power Company as appropriate ("Transmission Provider"), and Pinnacle West Energy Corporation, (Pinnacle West) ("Transmission Customer"). 2.0 The Transmission Customer has been determined by the Transmission Provider to have a Completed Application for Firm Point-To-Point Transmission Service under the Tariff. 3.0 The Transmission Customer has provided to the Transmission Provider an Application deposit in accordance with the provisions of Section 17.3 of the Tariff. 4.0 Service under this agreement shall commence on the later of (l) the requested service commencement date, or (2) the date on which construction of any Direct Assignment Facilities and/or Network Upgrades are completed, or (3) such other date as it is permitted to become effective by the Commission. Service under this agreement shall terminate on the actual termination date or such date as mutually agreed upon by the parties. 5.0 The Transmission Customer's renewal rights under this agreement shall be as specified in Section 2.2 of the Transmission Provider's Tariff as it may be amended from time to time in accordance with FERC policy. In addition, in order to assist the Transmission Provider in planning its system appropriately, the Transmission Customer will communicate with the Transmission Provider on a nonbinding basis regarding its assessment of whether it will renew this agreement as follows: 5.1 In the event the Transmission Customer signs a power sales contract that: (1) utilizes the transmission capacity provided for under this agreement, and (2) extends beyond this agreement's initial term, the Transmission Customer shall so notify the Transmission Provider (without identifying the parties to the power sales contract) and shall provide the Transmission Provider with the Transmission Customer's assessment of the likely impact of such contract on its intent to renew this agreement. EXHIBIT 10(H) SIERRA PACIFIC RESOURCES OPERATING COMPANIES FERC ELECTRIC TARIFF FIRST REVISED VOLUME NO. 1 SERVICE AGREEMENT NO. 101.A (ASSIGNED) OPEN ACCESS TRANSMISSION TARIFF Page 2 of 5 5.2 The Transmission Customer will on an annual basis, starting five years prior to the end of the initial term of this agreement, provide the Transmission Provider with a nonbinding statement of its current assessment of whether it will renew this agreement. The Transmission Customer will, on Transmission Provider's request, answer any reasonable questions the Transmission Provider has about such assessment; provided that the Transmission Customer shall not be obligated to provide any confidential market data to the Transmission Provider. 5.3 The Transmission Provider's transmission personnel shall treat as confidential and proprietary all information provided by Transmission Customer under this Section 5.0, and shall comply with FERC's affiliate regulations and other applicable provisions of Order No. 889, or any successor requirements, in its treatment of such information; provided that this Section 5.3 shall not prevent the Transmission Provider from providing information to FERC, the PUCN or any other agency of competent jurisdiction in accordance with applicable requirements of such agency or from compliance with any valid court order requiring the production of such information. The Transmission Provider shall give the Transmission Customer notice of any such agency request or court order so that the Transmission Customer may take any action deemed necessary by the Transmission Customer to protect the confidentiality of the requested information. 6.0 The Transmission Provider agrees to provide and the Transmission Customer agrees to take and pay for Firm Point-To-Point Transmission Service in accordance with the provisions of Part II of the Tariff and this Service Agreement. 7.0 Any notice or request made to or by either Party regarding this Service Agreement shall be made to the representative of the other Party as indicated below. EXHIBIT 10(H) SIERRA PACIFIC RESOURCES OPERATING COMPANIES FERC ELECTRIC TARIFF FIRST REVISED VOLUME NO. 1 SERVICE AGREEMENT NO. 101.A (ASSIGNED) OPEN ACCESS TRANSMISSION TARIFF Page 3 of 5 8.0 If any event occurs that will materially affect the time for completion of new facilities or the ability to complete them, Transmission Provider shall promptly notify the Transmission Customer. A technical meeting between the Parties shall be held to evaluate the alternatives available. If the Transmission Provider and the Transmission Customer mutually agree that no other reasonable alternatives exist and the requested service cannot be provided out of existing capability under the conditions of Part II of the Tariff, the obligation to provide the requested Firm Point-To-Point Transmission Service shall terminate and any deposit made by the Transmission Customer shall be returned with interest pursuant to Commission regulations 35.19a(a)(2)(iii). However, the Transmission Customer shall be responsible for all prudently incurred costs by the Transmission Provider through the time construction was suspended. Transmission Provider: Director, Regional Transmission Nevada Power Company P.O. Box 230 Las Vegas, NV 89151 Transmission Customer: Pinnacle West Energy Corporation P.O. Box 53999, Mail Station 8985 Phoenix, AZ 85072-3999 9.0 The Tariff is incorporated herein and made a part hereof. IN WITNESS WHEREOF, the Parties have caused this Service Agreement to be executed by their respective authorized officials. Transmission Provider: By: __________________________ __________________ __________________ Name Title Date Transmission Customer: By:___________________________ __________________ __________________ Name Title Date EXHIBIT 10(H) SIERRA PACIFIC RESOURCES OPERATING COMPANIES FERC ELECTRIC TARIFF FIRST REVISED VOLUME NO. 1 SERVICE AGREEMENT NO. 101.A (ASSIGNED) OPEN ACCESS TRANSMISSION TARIFF Page 4 of 5 Specifications For Long-Term Firm Point-To-Point Transmission Service 1.0 Term of Transaction: 5 Year(s) Start Date: 07-31-03 Termination Date: 07-30-08 2.0 Description of capacity and energy to be transmitted by Transmission Provider including the electric Control Area in which the transaction originates. 375 MW from Harry Allen 500 kV Substation in Nevada Power Company's Control Area to Mead 230 kV Substation. 3.0 Point of Receipt Delivering Party HARRY ALLEN 500 KV SUBSTATION PINNACLE WEST ENERGY CORPORATION 4.0 Point of Delivery Receiving Party MEAD 230 KV SUBSTATION MARKET 5.0 Maximum amount of capacity and energy to be transmitted (Reserved Capacity): 375 MW 6.0 Designation of party(ies) subject to reciprocal service obligation: None 7.0 Name(s) of any Intervening Systems providing transmission service: None EXHIBIT 10(H) SIERRA PACIFIC RESOURCES OPERATING COMPANIES FERC ELECTRIC TARIFF FIRST REVISED VOLUME NO. 1 SERVICE AGREEMENT NO. 101.A (ASSIGNED) OPEN ACCESS TRANSMISSION TARIFF Page 5 of 5 8.0 Service under this Agreement may be subject to some combination of the charges detailed below. (The appropriate charges for individual transactions will be determined in accordance with the terms and conditions of the Tariff.) 8.1 Transmission Charge: $1.21/kW-mo. 8.2 System Impact and/or Facilities Study Charge(s): Pending finalization, $30,000 deposit in place. Reliant - Arrow Canyon will be responsible for the final actual costs. 8.3 Direct Assignment Facilities Charge: None under this TSA. However, Direct Assignment Facilities will be required to provide the associated interconnection and are defined in the Interconnection & Operation Agreement. 8.4 Ancillary Services Charges: As negotiated in the future or as defined in Interconnection and Operation Agreement. 8.5. Power Factor Requirements: As defined in Interconnection and Operation Agreement. EX-10.(I) 12 b45693spexv10wxiy.txt SERVICE AGREEMENT NO. 101.B FOR LONG-TERM FIRM EXHIBIT 10(I) SIERRA PACIFIC RESOURCES OPERATING COMPANIES FERC ELECTRIC TARIFF FIRST REVISED VOLUME NO. 1 SERVICE AGREEMENT NO. 101.B OPEN ACCESS TRANSMISSION TARIFF (ASSIGNED FROM RELIANT TSA NO. 101) Page 1 of 5 SERVICE AGREEMENT FOR LONG-TERM FIRM POINT-TO-POINT TRANSMISSION SERVICE 1.0 This Service Agreement, dated as of December 12, 2002, is entered into, by and between Sierra Pacific Power Company and/or Nevada Power Company as appropriate ("Transmission Provider"), and Southern Nevada Water Authority, (SNWA) ("Transmission Customer"). 2.0 The Transmission Customer has been determined by the Transmission Provider to have a Completed Application for Firm Point-To-Point Transmission Service under the Tariff. 3.0 The Transmission Customer has provided to the Transmission Provider an Application deposit in accordance with the provisions of Section 17.3 of the Tariff. 4.0 Service under this agreement shall commence on the later of (l) the requested service commencement date, or (2) the date on which construction of any Direct Assignment Facilities and/or Network Upgrades are completed, or (3) such other date as it is permitted to become effective by the Commission. Service under this agreement shall terminate on the actual termination date or such date as mutually agreed upon by the parties. 5.0 The Transmission Customer's renewal rights under this agreement shall be as specified in Section 2.2 of the Transmission Provider's Tariff as it may be amended from time to time in accordance with FERC policy. In addition, in order to assist the Transmission Provider in planning its system appropriately, the Transmission Customer will communicate with the Transmission Provider on a nonbinding basis regarding its assessment of whether it will renew this agreement as follows: 5.1 In the event the Transmission Customer signs a power sales contract that: (1) utilizes the transmission capacity provided for under this agreement, and (2) extends beyond this agreement's initial term, the Transmission Customer shall so notify the Transmission Provider (without identifying the parties to the power sales contract) and shall provide the Transmission Provider with the Transmission Customer's assessment of the likely impact of such contract on its intent to renew this agreement. EXHIBIT 10(I) SIERRA PACIFIC RESOURCES OPERATING COMPANIES FERC ELECTRIC TARIFF FIRST REVISED VOLUME NO. 1 SERVICE AGREEMENT NO. 101.B OPEN ACCESS TRANSMISSION TARIFF (ASSIGNED FROM RELIANT TSA NO. 101) Page 2 of 5 5.2 The Transmission Customer will on an annual basis, starting five years prior to the end of the initial term of this agreement, provide the Transmission Provider with a nonbinding statement of its current assessment of whether it will renew this agreement. The Transmission Customer will, on Transmission Provider's request, answer any reasonable questions the Transmission Provider has about such assessment; provided that the Transmission Customer shall not be obligated to provide any confidential market data to the Transmission Provider. 5.3 The Transmission Provider's transmission personnel shall treat as confidential and proprietary all information provided by Transmission Customer under this Section 5.0, and shall comply with FERC's affiliate regulations and other applicable provisions of Order No. 889, or any successor requirements, in its treatment of such information; provided that this Section 5.3 shall not prevent the Transmission Provider from providing information to FERC, the PUCN or any other agency of competent jurisdiction in accordance with applicable requirements of such agency or from compliance with any valid court order requiring the production of such information. The Transmission Provider shall give the Transmission Customer notice of any such agency request or court order so that the Transmission Customer may take any action deemed necessary by the Transmission Customer to protect the confidentiality of the requested information. 6.0 The Transmission Provider agrees to provide and the Transmission Customer agrees to take and pay for Firm Point-To-Point Transmission Service in accordance with the provisions of Part II of the Tariff and this Service Agreement. 7.0 Any notice or request made to or by either Party regarding this Service Agreement shall be made to the representative of the other Party as indicated below. EXHIBIT 10(I) SIERRA PACIFIC RESOURCES OPERATING COMPANIES FERC ELECTRIC TARIFF FIRST REVISED VOLUME NO. 1 SERVICE AGREEMENT NO. 101.B OPEN ACCESS TRANSMISSION TARIFF (ASSIGNED FROM RELIANT TSA NO. 101) Page 3 of 5 8.0 If any event occurs that will materially affect the time for completion of new facilities or the ability to complete them, Transmission Provider shall promptly notify the Transmission Customer. A technical meeting between the Parties shall be held to evaluate the alternatives available. If the Transmission Provider and the Transmission Customer mutually agree that no other reasonable alternatives exist and the requested service cannot be provided out of existing capability under the conditions of Part II of the Tariff, the obligation to provide the requested Firm Point-To-Point Transmission Service shall terminate and any deposit made by the Transmission Customer shall be returned with interest pursuant to Commission regulations 35.19a(a)(2)(iii). However, the Transmission Customer shall be responsible for all prudently incurred costs by the Transmission Provider through the time construction was suspended. Transmission Provider: Director, Regional Transmission Nevada Power Company P.O. Box 230 Las Vegas, NV 89151 Transmission Customer: Southern Nevada Water Authority 1900 E. Flamingo Rd. Suite 170 Las Vegas, NV 89119 9.0 The Tariff is incorporated herein and made a part hereof. IN WITNESS WHEREOF, the Parties have caused this Service Agreement to be executed by their respective authorized officials. Transmission Provider: By: __________________________ __________________ __________________ Name Title Date Transmission Customer: By:___________________________ __________________ __________________ Name Title Date EXHIBIT 10(I) SIERRA PACIFIC RESOURCES OPERATING COMPANIES FERC ELECTRIC TARIFF FIRST REVISED VOLUME NO. 1 SERVICE AGREEMENT NO. 101.B OPEN ACCESS TRANSMISSION TARIFF (ASSIGNED FROM RELIANT TSA NO. 101) Page 4 of 5 Specifications For Long-Term Firm Point-To-Point Transmission Service 1.0 Term of Transaction: 5 Year(s) Start Date: 07-31-03 Termination Date: 07-30-08 2.0 Description of capacity and energy to be transmitted by Transmission Provider including the electric Control Area in which the transaction originates. 125 MW from Harry Allen 500 kV Substation in Nevada Power Company's Control Area to Mead 230 kV Substation. 3.0 Point of Receipt Delivering Party HARRY ALLEN 500 KV SUBSTATION SOUTHERN NEVADA WATER AUTHORITY 4.0 Point of Delivery Receiving Party MEAD 230 KV SUBSTATION MARKET 5.0 Maximum amount of capacity and energy to be transmitted (Reserved Capacity): 125 MW 6.0 Designation of party(ies) subject to reciprocal service obligation: None 7.0 Name(s) of any Intervening Systems providing transmission service: None EXHIBIT 10(I) SIERRA PACIFIC RESOURCES OPERATING COMPANIES FERC ELECTRIC TARIFF FIRST REVISED VOLUME NO. 1 SERVICE AGREEMENT NO. 101.B OPEN ACCESS TRANSMISSION TARIFF (ASSIGNED FROM RELIANT TSA NO. 101) Page 5 of 5 8.0 Service under this Agreement may be subject to some combination of the charges detailed below. (The appropriate charges for individual transactions will be determined in accordance with the terms and conditions of the Tariff.) 8.1 Transmission Charge: $1.21/kW-mo. 8.2 System Impact and/or Facilities Study Charge(s): Pending finalization, $30,000 deposit in place. Reliant - Arrow Canyon will be responsible for the final actual costs. 8.3 Direct Assignment Facilities Charge: None under this TSA. However, Direct Assignment Facilities will be required to provide the associated interconnection and are defined in the Interconnection & Operation Agreement. 8.4 Ancillary Services Charges: As negotiated in the future or as defined in Interconnection and Operation Agreement. 8.5. Power Factor Requirements: As defined in Interconnection and Operation Agreement. EX-12.(A) 13 b45693spexv12wxay.txt STATEMENT REGARDING COMPUTATION OF RATIOS . . . EXHIBIT 12 (A) SIERRA PACIFIC RESOURCES RATIOS OF EARNINGS TO FIXED CHARGES
Year Ended December 31, ------------------------------------------------------------------------------- Amounts in 000's 2002 2001 2000 1999 1998 EARNINGS AS DEFINED: Income (Loss) From Continuing Operations After Interest Charges $(286,883) $ 52,336 $ (27,001) $ 67,152 $ 94,686 Income Taxes (164,440) 15,531 (28,936) 26,570 45,471 --------- --------- --------- --------- --------- Income (Loss) From Continuing Operations before Income Taxes (451,323) 67,867 (55,937) 93,722 140,157 Fixed Charges 301,029 244,022 210,368 133,515 81,238 Capitalized Interest (5,270) (2,801) (10,634) (8,000) (6,080) Preference Security Dividend Requirements (21,172) (24,462) (24,297) (20,127) (11,013) --------- --------- --------- --------- --------- Total $(176,736) $ 284,626 $ 119,500 $ 199,110 $ 204,302 ========= ========= ========= ========= ========= FIXED CHARGES AS DEFINED: Interest Expensed and Capitalized (1) $ 279,857 $ 219,560 $ 186,071 $ 113,388 $ 70,225 Preference Security Dividend Requirements 21,172 24,462 24,297 20,127 11,013 --------- --------- --------- --------- --------- Total $ 301,029 $ 244,022 $ 210,368 $ 133,515 $ 81,238 ========= ========= ========= ========= ========= RATIO OF EARNINGS TO FIXED CHARGES -- 1.17 -- 1.49 2.51 DEFICIENCY $ 477,765 $ -- $ 90,868 $ -- $ --
(1) Includes amortization of premiums, discounts, and capitalized debt expense and interest component of rent expense. For the purpose of calculating the ratios of earnings to fixed charges, "Fixed charges" represent the aggregate of interest charges on short-term and long-term debt and distributions on preferred securities of consolidated subsidiaries, allowance for borrowed funds used during construction (AFUDC) and capitalized interest, the portion of rental expense deemed to be attributable to interest, and the pre-tax preferred stock dividend requirements of consolidated subsidiaries. "Earnings" represent the aggregate of income (or loss) from continuing operations before obligated mandatorily redeemable preferred securities, income taxes, and fixed charges, less AFUDC and capitalized interest, and pre-tax preferred stock dividend requirements of consolidated subsidiaries. EX-12.(B) 14 b45693spexv12wxby.txt NEVADA POWER STATEMENT REGARDING COMPUTATION . . . EXHIBIT 12 (B) NEVADA POWER COMPANY RATIOS OF EARNINGS TO FIXED CHARGES
Year Ended December 31, ------------------------------------------------------------------ Amounts in 000's 2002 2001 2000 1999 1998 EARNINGS AS DEFINED: Income (Loss) From Continuing Operations After Interest Charges $(219,898) $ 78,577 $ 7,244 $ 53,959 $ 94,686 Income Taxes (131,784) 32,783 (9,386) 21,213 45,471 --------- --------- --------- --------- --------- Income (Loss) From Continuing Operations before Income Taxes (351,682) 111,360 (2,142) 75,172 140,157 Fixed Charges 140,911 114,015 103,933 97,734 81,238 Capitalized Interest (3,412) (2,141) (7,855) (8,356) (6,080) Preference Security Dividend Requirements of Consolidated Subsidiaries (15,172) (15,172) (15,172) (15,172) (11,013) --------- --------- --------- --------- --------- Total $(229,355) $ 208,062 $ 78,764 $ 149,378 $ 204,302 ========= ========= ========= ========= ========= FIXED CHARGES AS DEFINED: Interest Expensed and Capitalized (1) $ 125,739 $ 98,843 $ 88,761 $ 82,562 $ 70,225 Preference Security Dividend Requirements of Consolidated Subsidiaries 15,172 15,172 15,172 15,172 11,013 --------- --------- --------- --------- --------- Total $ 140,911 $ 114,015 $ 103,933 $ 97,734 $ 81,238 ========= ========= ========= ========= ========= RATIO OF EARNINGS TO FIXED CHARGES -- 1.82 -- 1.53 2.51 DEFICIENCY $ 370,266 $ -- $ 25,169 $ -- $ --
(1) Includes amortization of premiums, discounts, and capitalized debt expense and interest component of rent expense. For the purpose of calculating the ratios of earnings to fixed charges, "Fixed charges" represent the aggregate of interest charges on short-term and long-term debt and distributions on preferred securities of consolidated subsidiaries, allowance for borrowed funds used during construction (AFUDC) and capitalized interest, and the portion of rental expense deemed to be attributable to interest. "Earnings" represent the aggregate of income (or loss) from operations before obligated mandatorily redeemable preferred securities, income taxes, and fixed charges, less AFUDC and capitalized interest. EX-12.(C) 15 b45693spexv12wxcy.txt SIERRA PACIFIC POWER CO STATEMENT RE: COMPUTATION . . . EXHIBIT 12 (C) SIERRA PACIFIC POWER COMPANY RATIOS OF EARNINGS TO FIXED CHARGES
Year Ended December 31, ------------------------------------------------------------------------ Amounts in 000's 2002 2001 2000 1999 1998 EARNINGS AS DEFINED: Income (Loss) From Continuing Operations After Interest Charges $ (13,968) $ 26,341 $ (335) $ 68,364 $ 88,646 Income Taxes (4,491) 10,260 (1,362) 33,489 39,561 --------- --------- --------- --------- --------- Income (Loss) From Continuing Operations before Income Taxes (18,459) 36,601 (1,697) 101,853 128,207 Fixed Charges 81,161 68,965 56,753 48,503 47,526 Capitalized Interest (1,858) (660) (2,779) (141) (6,000) Preference Security Dividend Requirements of Consolidated Subsidiaries -- (3,598) (3,742) (3,749) (4,171) --------- --------- --------- --------- --------- Total $ 60,844 $ 101,308 $ 48,535 $ 146,466 $ 165,562 ========= ========= ========= ========= ========= FIXED CHARGES AS DEFINED: Interest Expensed and Capitalized(1) $ 81,161 $ 65,367 $ 53,011 $ 44,754 $ 43,355 Preference Security Dividend Requirements of Consolidated Subsidiaries -- 3,598 3,742 3,749 4,171 --------- --------- --------- --------- --------- Total $ 81,161 $ 68,965 $ 56,753 $ 48,503 $ 47,526 ========= ========= ========= ========= ========= RATIO OF EARNINGS TO FIXED CHARGES -- 1.47 -- 3.02 3.48 DEFICIENCY $ 20,317 $ -- $ 8,218 $ -- $ --
(1) Includes amortization of premiums, discounts, and capitalized debt expense and interest component of rent expense. For the purpose of calculating the ratios of earnings to fixed charges, "Fixed charges" represent the aggregate of interest charges on short-term and long-term debt and distributions on preferred securities of consolidated subsidiaries, allowance for borrowed funds used during construction (AFUDC) and capitalized interest, and the portion of rental expense deemed to be attributable to interest. "Earnings" represent the aggregate of income (or loss) from continuing operations before obligated mandatorily redeemable preferred securities, income taxes, and fixed charges, less AFUDC and capitalized interest. EX-23.(A) 16 b45693spexv23wxay.txt CONSENT OF INDEPENDENT ACCOUNTANTS EXHIBIT 23(A) INDEPENDENT AUDITORS' CONSENT We consent to the incorporation by reference in Registration Statement No. 333-77523 of Sierra Pacific Resources on Form S-3, Registration Statement No. 333-92651 of Sierra Pacific Resources on Form S-8, and Registration Statement No. 333-72160 of Sierra Pacific Resources on Form S-3/A of our report dated February 28, 2003, which includes an explanatory paragraph related to the adoption of Statement of Financial Accounting Standards No. 142, appearing in this Annual Report on Form 10-K of Sierra Pacific Resources for the year ended December 31, 2002. Deloitte & Touche LLP Reno, Nevada March 26, 2002 EX-23.(B) 17 b45693spexv23wxby.txt NEVADA POWER CO CONSENT OF INDEPENT ACCOUNTANTS EXHIBIT 23(B) INDEPENDENT AUDITORS' CONSENT We consent to the incorporation by reference in Registration Statement No. 333-102727 of Nevada Power Company on Form S-4 of our report dated February 28, 2003 appearing in this Annual Report on Form 10-K of Nevada Power Company for the year ended December 31, 2002. Deloitte & Touche LLP Reno, Nevada March 26, 2002 EX-99.1 18 b45693spexv99w1.txt CERTIFICATION PURSUANT TO SECTION 906 - HIGGINS EXHIBIT 99.1 CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the combined Annual Report of Sierra Pacific Resources, Nevada Power Company and Sierra Pacific Power Company (the "Companies") on Form 10K for the period ending December 31, 2002 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I, Walter M. Higgins, III, Chief Executive Officer of the Companies, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that: (1) the combined Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and (2) the information contained in the combined Report fairly presents, in all material respects, the financial condition and results of operations of the Companies. /s/ Walter M. Higgins, III - -------------------------- Walter M. Higgins, III Chief Executive Officer March 28, 2003 This Certification accompanies this Report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and shall not, except to the extent required by the Sarbanes-Oxley Act of 2002, be deemed filed by the Company for purposes of Section 18 of the Securities Exchange Act of 1934, as amended. A signed original of this written statement required by Section 906 has been provided to the Companies and will be retained by the Companies and furnished to the Securities and Exchange Commission or its staff upon request. EX-99.2 19 b45693spexv99w2.txt CERTIFICATION PURSUANT TO SECTION 906 - ATKINSON EXHIBIT 99.2 CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the combined Annual Report of Sierra Pacific Resources, Nevada Power Company and Sierra Pacific Power Company (the "Companies") on Form 10K for the period ending December 31, 2002 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I, Richard K. Atkinson, Chief Financial Officer of the Companies, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that: (1) the combined Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and (2) the information contained in the combined Report fairly presents, in all material respects, the financial condition and results of operations of the Companies. /s/ Richard K. Atkinson - ------------------------------ Richard K. Atkinson Chief Financial Officer March 28, 2003 This Certification accompanies this Report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and shall not, except to the extent required by the Sarbanes-Oxley Act of 2002, be deemed filed by the Company for purposes of Section 18 of the Securities Exchange Act of 1934, as amended. A signed original of this written statement required by Section 906 has been provided to the Companies and will be retained by the Companies and furnished to the Securities and Exchange Commission or its staff upon request. -----END PRIVACY-ENHANCED MESSAGE-----