-----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, AQf2MiTifTvsOJSpITPEHWRqpZAav93m+E5A8un5hyOfpi4S+ksIucfU3ELdf7xA 0JFLGuq3gA5ndCl+/upsRw== 0000898430-99-001080.txt : 19990325 0000898430-99-001080.hdr.sgml : 19990325 ACCESSION NUMBER: 0000898430-99-001080 CONFORMED SUBMISSION TYPE: 10-K405 PUBLIC DOCUMENT COUNT: 2 CONFORMED PERIOD OF REPORT: 19981231 FILED AS OF DATE: 19990323 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-K405 SEC ACT: SEC FILE NUMBER: 000-00508 FILM NUMBER: 99570849 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 10-K405 1 FORM 10-K405 ================================================================================ UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 1998 Commission File Number 0-508 SIERRA PACIFIC POWER COMPANY (Exact name of registrant as specified in its charter) NEVADA 88-0044418 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) P.O. Box 10100 (6100 Neil Road) Reno, Nevada 89520-0400 (89511) (Address of principal executive office) (Zip Code) (775) 834-4011 (Registrant's telephone number, including area code) Securities registered pursuant to Section 12(b) of the Act: none. Securities registered pursuant to Section 12(g) of the Act: Preferred Stock: Series A, $2.44 Dividend, $50 par value --------------- Series B, $2.36 Dividend, $50 par value (Title of Class) Series C, $3.90 Dividend, $50 par value Sierra Pacific Power Capital Trust I, $2.15 Dividend, $25 stated value Indicate by check mark whether registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No ________ -------- Indicate by check mark if disclosure of delinquent filers pursuant to item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. X ----- State the aggregate market value of the voting stock held by non-affiliates. As of March 16, 1999: None Indicate the number of shares outstanding of each of the issuer's classes of Common Stock, as of the latest practicable date. Class Outstanding at March 16, 1999: 1,000 shares Common Stock, $3.75 par value ================================================================================ SIERRA PACIFIC POWER COMPANY 1998 ANNUAL REPORT FORM 10-K CONTENTS
PART I............................................................................................3 ITEM 1. BUSINESS.................................................................................3 SIERRA PACIFIC POWER COMPANY (1)...............................................................3 BUSINESS OUTLOOK AND OVERVIEW (1)..............................................................4 MAJOR PROJECTS SUMMARY........................................................................10 NATURAL GAS BUSINESS..........................................................................18 ITEM 2. PROPERTIES.............................................................................26 ITEM 3. LEGAL PROCEEDINGS......................................................................27 ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS....................................27 PART II..........................................................................................28 ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS...............28 ITEM 6. SELECTED FINANCIAL DATA................................................................29 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.............................................................................29 ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.............................45 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS....................................................53 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES............................................................................73 PART III.........................................................................................74 ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS......................................................74 ITEM 11. EXECUTIVE COMPENSATION................................................................79 ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND...................................85 MANAGEMENT............................................................................85 ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS........................................86 PART IV..........................................................................................89 ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.......................89 Appendix E....................................................................................24
2 PART I ITEM 1. BUSINESS SIERRA PACIFIC POWER COMPANY (1) Sierra Pacific Power Company, hereinafter known as the Company or SPPC, is a Nevada corporation organized in 1965 as a successor to a Maine corporation organized in 1912. The Company became a wholly- owned subsidiary of Sierra Pacific Resources (SPR) on May 31, 1984. Its mailing address is Post Office Box 10100 (6100 Neil Road), Reno, Nevada 89520-0400. The Company has four primary subsidiaries: Pinon Pine Corp. (PPC), Pinon Pine Investment Co. (PPIC), GPSF-B, and Sierra Pacific Power Capital I (the Trust). PPC and PPIC own 25% and 75% of a 38% interest in Pinon Pine Company, L.L.C. GPSF-B, a Delaware corporation formally owned by General Electric Capital Corporation and now owned by the Company, owns the remaining 62%. 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 (S) 29 of the Internal Revenue Code. The Capital Trust was created to issue trust securities in order to purchase the Company's junior subordinated debentures. The Company is a public utility primarily engaged in the distribution, transmission, generation, purchase and sale of electric energy. It provides electricity to approximately 294,000 customers in a 50,000 square mile service area including western, central and northeastern Nevada, including the cities of Reno, Sparks, Carson City, Elko and a portion of eastern California, including the Lake Tahoe area. In 1998, electric revenue was 79.8% of total revenue. The Company also provides natural gas in Nevada to approximately 105,000 customers in an area of about 600 square miles in Reno/Sparks and environs. It supplies water service in Nevada to about 67,000 customers in the Reno/Sparks metropolitan area. Natural gas revenues were 13.6% and water revenues were 6.6% of total revenues. The Company used diverse resources to meet its 1998 electric energy requirements, including gas and oil generation (32.8%), coal generation (21.0%), hydroelectric generation (0.6%), and purchased power (45.6%). The Company has no ownership interest in, nor does it operate any nuclear generating units. In 1998, the Company's electric customer count grew by 2.4%; its natural gas customer count increased by 4.0%; and its water customer count increased by 3.0%. Many factors account for this growth, not the least of which are favorable business and tax climates. The Company had 1,446 regular employees as of December 31, 1998, down 1.8% from 1997. The Company's current contract with the International Brotherhood of Electrical Workers, which represents 58.0% of the workforce, was renegotiated in 1997 and is in effect until December 31, 2000. The three-year contract provides for a 2.75% general wage increase for most bargaining unit employees beginning January 1, 1998, with 2.75% increases in both 1999 and 2000. In addition, the contract provides for bargaining unit employees to participate in the incentive compensation program. Nevada is a "right-to-work" state. For a discussion of results of operations refer to Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations. 3 (1) 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 which 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 SPPC's actual results to differ materially from those contemplated in any forward-looking statement include, among others, the following: (1) the pace and extent of the ongoing restructuring of the electric and gas industries in Nevada and California; (2) the outcome of regulatory and legislative proceedings and operational changes related to industry restructuring; (3) the amount SPPC is allowed to recover from its customers for certain costs which prove to be uneconomic in the new competitive market; (4) regulatory delays or conditions imposed by regulatory bodies in approving the merger of SPR with Nevada Power Company; (5) the outcome of ongoing and future regulatory proceedings; (6) management's ability to integrate the operations of SPPC and Nevada Power Company and to implement and realize anticipated cost savings from the Merger; (7) industrial, commercial and residential growth in the service territory of SPPC; (8) fluctuations in electric, gas and other commodity prices and the ability to manage such fluctuations successfully; (9) changes in the capital markets and interest rates affecting the ability to finance capital requirements; (10) the loss of any significant customers; (11) the ability to lessen the risk of the impact of the Year 2000 on internal and external computer and software systems; and (12) the weather and other natural phenomena. 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. SPPC assumes no obligation to update forward-looking statements to reflect actual results, changes in assumptions or changes in other factors affecting forward- looking statements. BUSINESS OUTLOOK AND OVERVIEW (1) General Electric Industry Trends In April 1998, SPR announced a merger with Nevada Power Company. This "merger of equals" combines the two investor-owned utilities in Nevada, the fastest growing state in the United States. The merger will allow the companies to operate more efficiently and to better compete in the new utility environment. See Merger Discussion for more details. ----------------- As a comparison, 19 other mergers of electric and/or gas companies were announced, pending or completed in 1998. Some of the largest national and international utilities announced mergers in 1998, including PacifiCorp & Scottish Power, New England Electric System & National Grid Group, and CalEnergy & MidAmerica Energy Holdings. A third Nevada utility is also involved in a merger with the December 14, 1998 announcement of ONEOK's offer and Southern Union's counteroffer to acquire Southwest Gas Corp. of Las Vegas. Merger and acquisition activity is expected to continue into the next decade, as companies position for continued electric restructuring throughout the United States. 4 Federal and state legislation is moving the electric utility industry toward competition. Federal and state regulators play critical roles in establishing a competitive marketplace. Currently, 13 states have passed restructuring bills, and 21 more states are considering legislation to restructure their electric markets. In addition, the U.S. Congress is considering national legislation that would implement electric restructuring across the nation. Passage of a comprehensive federal bill is expected within the next several years. Regulatory changes generally focus on the unbundling of utility functions into separate products and services. The two major products and services are energy (e.g. kilowatt hours) and the delivery of that energy (e.g. transmission and distribution). Other services such as meter reading and billing may also be opened to competition. The Federal Energy Regulatory Commission (FERC) is considering the potential for Regional Transmission Organizations (RTO's). RTO's which can take the form of independent system operators or independent transmission companies, are independent organizations that oversee the operation of electric power lines on a regional scale. FERC orders 888/889 passed in 1996, implemented open access tariffs that allowed multiple users to access transmission systems without discrimination. Some solutions to open transmission access and multiple rates (pancaked rates) across short distances have been discussed by the FERC for several years. FERC has conducted meetings around the country to explore the possibility of requiring utilities to participate in RTO's as wholesale power markets are opened to competition. A notice of proposed ruling (NOPR) is expected in 1999. The Company is subject to California, Nevada and FERC regulatory jurisdiction. Federal and state regulation will continue to play an active role in the Company's utility business. The Company's electric system demand exceeds the import capabilities of its transmission system. As such, a yet-to-be determined amount of the Company's generation capacity may be identified as "must run" at the time the plants are sold (a condition of the merger) or open access is available to new customers. The output of "must run" facilities may continue to be price regulated by FERC after the deregulation of generation (see Generation Divestiture). FERC will also regulate the Company's electric - ---------------------- transmission system. The states will continue to regulate those retail distribution services determined to be non-competitive. Approximately 69% of SPPC's operating revenues are related to electric sales in Nevada. Nevada passed Assembly Bill 366 (AB366) in July 1997. Pursuant to AB366, the Public Utilities Commission of Nevada (PUCN) authorizes customers to obtain competitive services from alternative sellers starting no later than December 31, 1999, unless the PUCN or the state legislature determines a different date better serves the public interest. AB366 allows the PUCN to authorize full recovery of costs that it determines to be stranded as a result of restructuring. In August 1997, the PUCN opened an investigatory docket of the issues to be considered as a result of restructuring the electric industry. The Company is a participant in this docket. Issues being addressed include: . Definition of noncompetitive services . Unbundling of costs among distribution, transmission, generation components of the electric business . Stranded costs . Affiliate rules . Other actions needed to proceed from regulation to fully competitive energy markets See Nevada Matters for more details on the Company's response to this -------------- restructuring process. California accounts for about 5% of the Company's electric revenue. California required all investor-owned utilities, including SPPC, to offer customers direct access beginning March 31, 1998, and required a 5 10% rate reduction for all residential and small commercial customers effective January 1, 1998. California customers may choose to continue to take service from their incumbent utility at tariff rates, purchase energy from marketers or contract directly with a generator. Any customers choosing to purchase energy from marketers or generators will pay a distribution fee for their use of the Company's transmission and distribution systems. Operating results should not be materially impacted by these regulatory changes because of the continued use of the Company's transmission/distribution facilities and the Company's limited exposure in California. See Item 7, California Matters. ------------------ In preparation for competition, the Company has reduced ongoing costs and improved operations. Nevada electric and gas rates will remain frozen until December 31, 1999. A Nevada rate plan is currently in effect that provides for a 50/50 sharing between customers and shareholders of electric and gas earnings in excess of a 12 percent return on equity. In addition, in lieu of a 50% refund, SPPC can apply excess electric earnings to buy down, or buy out of, higher cost long-term fuel and purchased power contracts. For more information regarding regulatory changes affecting SPPC, see Item 7, Nevada Matters, California Matters, FERC Matters and Note 2 of the Company's -------------- ------------------ ------------ consolidated financial statements. Merger On April 29, 1998, SPR announced a proposed merger with Nevada Power Company, of Las Vegas, NV. The "merger of equals" will create a combined company with assets of approximately $4 billion. On July 7, 1998, SPR and Nevada Power Company issued a press release announcing the filing of a joint merger application with the PUCN for approval of their proposed merger. In the filing, SPR and Nevada Power proposed selling their generating plants, pending merger completion, and a long-term freeze in prices for regulated utility services (transmission and distribution). The application stated that capital raised by the sale of generating plants would be reinvested primarily in new transmission and distribution facilities. An incentive mechanism through which net merger savings and other benefits would be shared by customers and investors was also proposed. Hearings before the Public Utilities Commission of Nevada (PUCN) were held in November/December 1998 in Las Vegas and Carson City. (Hearings were completed on December 2, 1998). Both Sierra Pacific Resources and Nevada Power held special stockholder meetings in October 1998 during which stockholders of both companies voted to approve the proposed merger. On December 31, 1998, the PUCN approved the proposed merger subject to conditions regarding the divestiture of the two companies generating plants, merger cost savings and filing of unbundling cases before the PUCN. More specifically, the conditions require that the companies: file a generation divestiture plan with the PUCN for review and commit to divest pursuant to the plan; file an interim independent system administrator (ISA) proposal at FERC and for PUCN review; file a generation tariff at FERC and for PUCN review; file a general rate case and unbundle costs; after a three year freeze on retail rates, file a rate case to prove and capture synergies; and submit an application to the PUCN to recover stranded costs. The companies filed a formal petition for clarification in January 1999. The petition for clarification was granted on January 29, 1999, with minor language changes acceptable to both companies. The proposed merger is conditioned, among other things, upon further regulatory approvals including the SEC, Department of Justice, the Federal Trade Commission and FERC. The application under the Public Utility Holding Company Act of 1935 was filed with the SEC on February 11, 1999. Hart-Scott-Rodino filings with the Federal Trade Commission and the Department of Justice were made on February 17, 1999. The merger application was filed with the FERC on October 2, 1998, and required responses to interventions have 6 been completed. If all conditions can be resolved satisfactorily between the companies and the regulators, the merger is expected to be completed in the Second Quarter of 1999. Generation Divestiture In June 1998, the Company announced the plan to divest its generation assets. The announcement was included in the merger application filed with the PUCN on July 7, 1998. The Company has 1,051 megawatts (net capacity) of fossil fuel and hydro generation facilities. The fuel mix consists of coal, natural gas and oil. Current total book value for all generation assets, at year-end 1998 was $379 million. The Company has retained an advisor to manage the generation sale and conduct the auction for both SPPC and Nevada Power Company. The merger order, dated December 31, 1998, requires that a divestiture plan be filed with the PUCN as a compliance item, prior to closing the merger. This plan will be filed on or before April 1, 1999. The plan will include details about the auction process, market power mitigation through sales of assets in bundles, description of the generation tariff, and a description of the proposed interim independent system administrator structure for transmission. A generation auction will be held. At this time, the preliminary schedule will include issuance of an offering memorandum in or around July 1999. The offering memorandum will describe the assets, the auction process, and the terms and conditions for bidding. First round bids will be expected in or around October 1999. After evaluation of these bids, a short list of qualified bidders will be selected in the second round. Final bids are expected in or about January 2000, with expected sale and transfer of assets by August 2000. ELECTRIC BUSINESS Business and Competitive Environment The Company's electric business contributed $586 million (79.8%) of 1998 operating revenues. Typically the electric business may peak in either summer or winter. The system has an annual load factor of approximately 71.5%, which is higher than the industry norm. Winter peak loads are due to shorter daylight hours, colder temperatures (which affect space heating requirements) and ski resort demands (snowmaking, hotels, lifts, etc.). Summer peak loads result from air-conditioning, cooling equipment and irrigation pumping. The Company's peak load increased an average of 6% annually over the past five years, reaching 1,423 megawatts (MW) on August 5, 1998. The Company's total electric MWH sales have increased an average of 7.5% annually over the past five years. A significant part of the growth in the Company's electric sales has resulted from growth in the residential area, mining and manufacturing industry in northern Nevada. 7 SPPC's electric customers by class contributed the following percentages toward 1998 megawatt-hour sales:
MWH SALES Residential 20.4% Commercial and Industrial: Mining 27.1% Offices/Schools/Government 10.7% Resorts & Recreation 7.8% Manufacturing / Warehouse 7.6% All Other 11.8% Wholesale 14.6% ---- Total 100.0% =====
Residential and small commercial sectors increased 4.9%, the highest growth rate in recent history for those classes. In response to this growth, SPPC has provided customers with additional choices in the design and installation of electric service. Under this program, customers may select a contractor other than the Company to design and install facilities. Additionally, the Company has worked closely with developers to redesign the new business process that resulted in improved efficiencies and increased customer satisfaction. The Company continues to evaluate new technology such as automated dispatch and mobile data capabilities to enhance efficiency measures. Nevada leads the nation in gold production, accounting for approximately 76% of all U.S. production and 11% of world production, ranking it the third largest gold producer in the world. It is estimated that Nevada gold production for 1998 was approximately 8.8 million ounces. A majority of Nevada's gold mines are customers of the Company. Currently, known gold reserves at existing mines in Nevada total approximately 90 million ounces, over 75% of the nation's known gold reserves. These reserves are sufficient to continue production at current rates for the next decade. During 1998, world gold prices ranged from about $273 per ounce to $315 per ounce. Production costs vary greatly at Nevada mines, along with profitability. Mining industry reports indicate many Nevada gold mines have a production cost of less than $300 per ounce, with some of the larger mines producing within the $192 to $240 per ounce range. When compared to world production costs, Nevada is well below the worldwide average of $262 per ounce. While Nevada's gold mines have the lowest costs in the world, investments in exploration and development have fallen, and may continue to fall. In addition, the low gold price may also shorten the expected mine lives of certain Nevada properties as lower grade ore becomes uneconomic to mine. The Company's territory also has a variety of other mineral producing mines. Approximately 22 million ounces of silver were produced in 1998, worth approximately $122 million, with over 300 million ounces of silver resources identified in the State. Silver demand has been exceeding new supply for most of the decade, drawing down inventories built up in the 1980's. As this situation continues, we will see continued upward pressure on silver prices. Other minerals produced in Nevada include copper, lithium, mercury, barite, diatomite, gypsum, and lime, valued at over $400 million. 8 The Company has nine long-term power sales agreements with major mining customers with terms of at least five years. The final contract expires in 2005. Five of these agreements have been reviewed and approved by the PUCN as part of the Company's new tariff structure designed for major customers. These mining agreements secure over 223 megawatts of present and future mining load, or approximately $74 million in annual revenues, which is 12.6% of the 1998 electric operating revenues. The agreements require that customers maintain minimum demand and load factor levels, and include termination charge provisions to recover all of the Company's customer-specific facilities investment. The resorts and recreation group is comprised of hotels, casinos, and ski resorts. This major customer segment comprises 7.8% of the total electric system retail KWH sales. Tourism and gaming continue to be key contributors to the local economy. The economic impact, on Washoe County, Reno and environs in 1998 was estimated at over 4.3 billion dollars. Several of the largest gaming customers are expanding their properties to differentiate the Reno/Tahoe market by creating a more desirable resort location. These same large gaming customers increased their 1998 electric load by 8,573 MWH (1.1%) over 1997. Growth in the Northern Nevada gaming sector in recent years has provided significant energy sales and revenue growth for the Company. Gaming sector energy sales growth has averaged 3.8% annually over a recent five year period. The advent of increased competition, particularly "Indian gaming" in key feeder markets, and the continuing expansion in Las Vegas, may have a potentially negative impact on the Northern Nevada market share and ultimately energy sales. The passing of Proposition 5 in California, which liberalizes Indian reservation gaming operations, has been predicted to cause a decline in Reno's gaming revenues once implemented. Northern Nevada casinos are evaluating and implementing competitive strategies to expand their entertainment portfolio. The key to this strategy is packaging entertainment value, customer comfort, and reasonable pricing, with the natural attraction of the Sierra Nevada geographic location. The Company's industrial and large commercial customers continue their interest in the electric supply source options potentially available to them under regulatory reforms currently being considered in Nevada and in place in California. The Company continues to prepare for a more competitive environment and has actively participated in regulatory reform deliberations in Nevada. See Item 7, Nevada Matters, California Matters, and FERC Matters. -------------- ------------------ ------------ Over the past five years, MWH sales to wholesale customers have increased at a rate of 21%. During 1998, firm and non-firm sales to wholesale customers comprised about 14.6% of total energy sales. The wholesale market is very competitive and sales into this market are typically made at very low margins. This market is maturing and will become even more competitive in the future.
Percent (MWH) of Total ---------- ---------- Firm Sales 115,856 9.3% Non-firm Sales 150,319 12.1% Firm Off-System Sales 974,490 78.6% ---------- ------ Total 1,240,665 100.0% ========== ======
While the wholesale sales in 1998 represented 14.6% of sales they represent only 5.7% of electric revenues. Recent changes in Federal regulations covering the rules under which transmission systems are 9 operated will increase competition for wholesale sales and may impact the level of firm and non-firm wholesale sales made in the future. See Item 7, FERC ---- Matters. - ------- MAJOR PROJECTS SUMMARY The following projects were approved in previous resource plans. See Rate ---- Proceedings. - ----------- Pinon Pine Power Project In August 1992, the Company executed a cooperative agreement with the U.S. Department of Energy (DOE) for the construction of a coal-gasification power plant. The project, known as the Pinon Pine Power Project (Pinon) was selected by the DOE for funding under the fourth round of the Federal Clean Coal Technology Program. This clean coal integrated gasification combined-cycle power plant is designed to operate on syngas produced from coal, natural gas, and potentially other fuels. The project consists of a coal gasification facility (including solids receipt, handling, preparation and storage), and a Company-owned power island and post gasification facility to partially cool and clean the syngas produced by the gasifier. Its capacity rating is 93 megawatts in the winter and 89 megawatts in the summer. The DOE has committed $168 million of funding for Pinon construction and operation costs. The DOE provided funding for approximately 43% of the estimated construction cost and half of the operating and fuel expenses until the commitment is expended. A dispute has arisen with the Department of Energy (DOE) regarding the historical and future funding of natural gas costs. In February 1999 the DOE informed the Company it will not fund the remaining $14 million under the cooperative agreement until the dispute is resolved. Estimated construction start-up and commissioning costs for Pinon, including the DOE's portion are approximately $301.5 million, which includes permitting, taxes, start-up commissioning, operator training and Allowance for Funds Used During Construction. DOE funding for construction through December 1998 is $132.4 million. The Company's expected cost per kilowatt of capacity net of DOE construction after commissioning of all coal gasification facilities is $1,574 based on the peak winter rating and $1,739 based on the summer rating. Construction began on the project in February 1995, following resource plan approval and the receipt of all permits and other approvals. The natural gas portion (combined cycle combustion turbine) was satisfactorily completed and placed in service December 1, 1996. The balance of the plant was placed in service in June 1998. The construction of the gasifier portion of the project overran the fixed contract price by approximately 12% or $12.6 million. The overrun is primarily due to redesign issues, resolving technical issues relative to start up and other costs due to a later than anticipated in-service date. To date, the Company has not been successful in obtaining sustained operation of the gasifier but work continues to identify problem areas and redesign solutions which will likely require additional capital expenditures. Due to the problems noted above, the Company and Foster Wheeler settled on a portion of the cost overrun and have entered into an alternative dispute resolution process in an attempt to resolve remaining issues on total construction costs. At this time, the Company does not have any estimates as to the outcome of the proceeding. Pinon Pine Corp. and Pinon Investment Co., subsidiaries of the Company, own 25% and 75% of a 38% interest in Pinon Pine Company, L.L.C. GPSF-B, a Delaware corporation formerly owned by General Electric Capital Corporation (GECC) and now also owned by the Company, owns the remaining 62%. The LLC was 10 formed to take advantage of federal income tax credits associated with the alternative fuel (syngas) produced by the coal gasifier available under (S) 29 of the Internal Revenue Code. The Company is contractually obligated to build and operate the gasifier for the LLC and to purchase from the LLC the syngas produced in the gasifier for use in the Company-owned power island. The obligations are contingent on the gasifier meeting the necessary requirements to be eligible for Section 29 credits. The Company also has contractual performance covenants and warranties requiring, among other things, that the gasifier operate at 30% capacity in 1997, and that construction of the facility be completed to GECC's satisfaction before June 30, 1998. Because the gasifier failed to attain an average capacity factor of 30% during 1997 and because it was not completed to GECC's satisfaction prior to June 30, 1998, Sierra was obligated to make a payment to GECC of $2.8 million in 1997 and was obligated to purchase the facility for the amount of capital invested by GECC plus a return on capital. The purchase was completed in February 1999 for $30.4 million. Alturas Intertie The Company completed construction of the Alturas Intertie transmission line in December 1998. The Alturas Intertie was built to enhance service to existing load, to expand service to new customers and to increase significantly the Company's access to lower cost resources in the Pacific Northwest. This 345 kV line originates west of Alturas, California and extends 165 miles south to Reno. Construction commenced on February 9, 1998. The line was placed into commercial operation on December 22, 1998. The Company spent approximately $144 million on the project as of December 31, 1998. The current estimated cost of construction, including AFUDC, is approximately $159 million. Additional environmental and right-of-way restoration activities are expected to continue on the project through 2004. Certain northern California public power groups have challenged the Company's filing with FERC of the interconnection and operating agreements related to the Alturas Intertie in December 1998 and January 1999. The California groups allege 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. One of the California groups, the Transmission Agency of Northern California (TANC), has initiated related proceedings in the United States District Court for the Eastern District of California and the United States Court of Appeals for the Ninth Circuit, in each case alleging that Bonneville Power Administration's (BPA) construction of a small portion of the Alturas Intertie violated the Northwest Power Preference Act and requesting an injunction prohibiting operation of the Alturas Intertie. Each complaint is directed at BPA, which is charged with administering the Northwest Power Preference Act and has determined that its construction activities did not violate that act. The Company is in the process of intervening in these proceedings and opposing TANC's complaint and requested relief. TANC's allegations have already been rejected by the Western Systems Coordinating Council which determined the capacity rating of the Alturas Intertie. The Company's position, supported by Bonneville Power Administration and PacifiCorp, is that under 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 issue is still pending before FERC. Action is expected by the summer of 1999. Even if the California groups prevailed, use of the Alturas Intertie would not be affected other than by certain reductions in imports during peak periods. 11 FACILITIES AND OPERATIONS Total System As of December 31, 1998, the Company's electric transmission facilities consisted of approximately 4,000 overhead pole line miles and 81 substations. Its distribution facilities consisted of approximately 9,000 overhead pole line miles, 4,500 underground cable miles and 178 substations. The Company continues to maintain a wide variety of resources in its generation system. During 1998 the Company generated 54.4% of its total electric energy requirements in its own plants, purchasing the remaining 45.6% as shown below:
Megawatt- Percent Hours of Total ----------------- -------------- Company Generation ------------------ Gas/Oil 3,330,179 32.8% Coal 2,133,351 21.0% Hydro 60,732 0.6% --------- ------ Total Generated 5,524,262 54.4% --------- ------ Purchased Power -------------------- Long-Term Firm: Utility Purchases 3,461,474 34.1% Non-Utility Purchases: Geothermal 754,204 7.4% Other 111,957 1.1% Spot Market 304,716 3.0% --------- ------ Total Purchased 4,632,351/1/ 45.6% --------- ------ Total 10,156,613 100.0% ========== ======
The Company's decision to purchase spot market energy is based on the economics of purchasing "as-available" energy when it is less expensive than the Company's own generation. At the time of the 1998 system peak, the Company had purchased firm capacity under long-term contracts with other utilities and qualifying facilities (QFs) equal to 26% of total peak hour capacity. In 1998, most of the Company's non-utility generation came from QFs, except for 12,224 megawatt hours, which came from two small power producers. - ------------------- /1/ Total purchased megawatt-hours include immaterial inadvertent purchases which are not included in the purchases in the Management Discussion and Analysis. 12 Load and Resources Forecast The Company has committed as part of the merger agreement with PUCN to divest its generation facilities to enhance competition in a deregulated environment. Current plans call for the divestiture to occur in the year 2000. Until such time, the Company will continue to provide energy through generation and purchase power to meet both summer and winter peak loads. The Company's actual total system capability and peak loads for 1998, and as estimated for summer peak demand through 2000 (assuming no curtailment of supply or load and normal weather conditions), are indicated below:
Capacity at 1998 Peak Forecast Summer Peak ------------------------------------------------------------------------------------- MW % 1999 2000 --------------- --------------- --------------- --------------- Company Generation: Existing 1,045 65% 1,045 1,052 --------------- --------------- --------------- --------------- Purchases: Long/Short-Term Firm (1) (2) 251 16% 475 491 Interruptible Customers 2 0% 2 2 Non-Utility Generators 70 4% 70 70 --------------- --------------- --------------- --------------- Subtotal 323 20% 547 563 --------------- --------------- --------------- --------------- Additional Required 248 15% 11 90 --------------- --------------- --------------- Total System Capacity 1,616 100% 1,603 1,705 =============== =============== =============== =============== Net System Peak (3) 1,423 88% 1,407 1,500 Planning Reserve 193 12% 196 205 --------------- --------------- --------------- --------------- Total 1,616 100% 1,603 1,705 =============== =============== =============== =============== Growth over previous year -0.8% 5.5% =============== ===============
(1) Value net of losses. (2) Includes potential short-term firm purchases that are not under contract. Values shown represent purchases within existing transmission system limits. (3) The system peak shown for 1998 is the actual system peak of 1,423 MW, which occurred on August 5, 1998. With regard to total system capacity, the Company is expected to maintain a planning reserve margin consistent with the Western System Coordinating Council guidelines. This reserve margin was 193 megawatts in 1998, which the Company expects will increase to 205 megawatts by 2000. To accommodate the system requirement during the 1999-2000 time period, it will be necessary to secure additional capacity beginning in 1999. The "Additional Required" will be met by short-term purchases through 2000. 13 Generation The Company's total net generating capability for the upcoming 1999 Summer Peak is as follows:
Number of MW Year(s) Name Type/Fuel Units Capacity Installed - ---- --------- ----- -------- --------- Valmy Steam/Coal 2 266 1981 and 1985 Tracy Steam/Gas, Resid. Oil 3 244 1963, 1965, 1974 Pinon Combined Cycle/Coal, Gas 1 89 1996- 1998 Clark Mtn CT's CT/Gas, Diesel Oil 2 138 1994 Ft. Churchill Steam/Gas, Resid. Oil 2 226 1968 and 1971 Other GT/Gas, Diesel Oil, 1899- 1970 Propane, Hydro 33 82 ------- 1,045 ======= (CT) Combustion Turbine (GT) Gas Turbine
The Company is the operator and owns an undivided 50 percent interest in the Valmy plant. Idaho Power Company (Idaho Power) owns the remainder. The capacities shown above for the Valmy plant represent the Company's share only. The Company owns 100 percent of all of its remaining electric generation plants. The table above includes the generation capacity of the 100% SPPC-owned power island portion of the Pinon Pine Power Project. Pinon's current summer net capacity is 89 MW when operating on natural gas. Four of the Company's hydro generation units are located on the Truckee River, which runs approximately 100 miles from Lake Tahoe, through Reno/Sparks, to Pyramid Lake. A 2 MW facility located on the Truckee River at Farad was damaged by the January 1997 flood and will not be available for generation during the 1999 summer peak. The Company had leased two units from the Truckee- Carson Irrigation District under a 30-year operating lease that expired in 1998 prior to the Company's normal summer peak. The units are located in the Lahontan Reservoir area, 70 miles southeast of Reno. Negotiations with the TCID are underway to renew the lease, however, the TCID may keep the two units as a Qualifying Facility. Due to disrepair of the units, it is not expected that any generation will be available for the 1999 summer peak. See Leaseholds. ---------- Purchased Power The Company continues to manage a diverse portfolio of contracted and spot market supplies, as well as its own generation, to minimize its net average system operating costs. During 1998, the Company witnessed a dramatic increase in the price of off system energy, compared to previous years, reflecting the increase in electricity costs nationwide. Nationally, this increase was due, in part, to increased demand resulting from above average summer temperatures. Regionally, below average precipitation in the Northwest aggravated the problem. The Company is a member of the Northwest Power Pool and Western Systems Power Pool. These pools have provided the Company further access to spot market power in the Pacific Northwest and the Southwest. In turn, the Company's generation facilities provide a backup source for other pool members who rely heavily on hydroelectric systems. The Company has an agreement with PacifiCorp's Utah division and Idaho Power in 14 which a portion of the energy purchased by the Company from PacifiCorp is transmitted through the Idaho Power system. The agreement also provides added access to spot market power. The Company purchases hydro and thermally-produced spot market energy, by the hour, based upon economics and system import limits. Also purchased, during peak load periods, is firm block energy as required to maintain adequate operating reserve margins. During drought years, when less spot market hydro energy is available, the Company supplies a higher percentage of its native load utilizing its fossil fuel generation. Of continuing concern to any purchaser of hydro-generated energy are proposals by federal regulators, in the interest of the salmon, recommending closure of some hydro operations on the Snake and Columbia rivers. The amounts of hydro energy available and the price will depend on weather conditions in the Pacific Northwest and proposals by regulators. The amount of excess generating capacity in other systems and the existence of competition in providing utilities with economic incentives to make off system sales are also important factors. Currently, the Company has contracted for a total of 265 megawatts of long-term firm purchased power from the utility suppliers listed below. Several of the Company's firm purchase power contracts contain minimum purchase obligations. Meeting these minimums has not been a problem for the Company in the past, and is not expected to be a problem in the future.
Contract Operation Termination Minimum Contract Party Capacity Date Date Capacity % - ------------------------------- ------------------ ------------------ --------------------- ------------ Idaho Power(1) 75 MW Nov 1989 May 31, 1999 50% Idaho Power (for Elko) 15 MW Mar 1994 May 31, 2000 40% Tri-State(2) 25 MW June 1991 June 1, 1999 50% PacifiCorp 75 MW June 1989 Feb 28, 2009 70% PacifiCorp/Utah Power(3) 75 MW May 1991 April 30, 2000 78%
(1) The Company will not renew this contract. (2) The Company has provided notice to terminate the Tri-State contract effective May 31, 1999. (3) The Company has provided notice to terminate the PacifiCorp/Utah contract effective April 30, 2000. According to regulations of the Public Utility Regulatory Policies Act, the Company is obligated, under certain conditions, to purchase the generation produced by small power producers and cogeneration facilities at costs determined by the appropriate state utility commission. Generation facilities that meet the specifications of the regulations are known as qualifying facilities (QFs). As of December 31, 1998, the Company had a total of 109 megawatts of maximum contractual firm capacity under 15 contracts with QFs. The Company also had contracts with three projects at fluctuating short-term avoided cost rates. All QF contracts currently delivering power to the Company at long- term rates have been approved by either the PUCN or the CPUC, and have QF status as approved by FERC. One long-term QF contract terminates in 2006, one terminates in 2039, and the remainder terminate between 2014 and 2022. Energy purchased by the Company from QFs constituted 10% of the net system requirements during 1998. These contracts continue to provide useful diversity for the Company in meeting its peak load. All the QFs from which the Company makes firm purchases are either geothermal (87%), hydroelectric or biomass. The actual QF firm capacity output under contract was 64 megawatts during the summer of 1998. The actual QF output for all non-utility generator deliveries during the summer 1998 peak was 83 megawatts. The table on page 12 reflects actual performance during the 1998 summer peak period. A difference exists between the non-utility generator figures and the table on page 12 because the 1998 figure is actual and the remaining 15 years are forecasts. Any capacity shortfall created by under-performance was included in the Company's 1998 amended resource plan. Transmission In planning its transmission capacity, the Company considers generation and purchased power options, as well as the requirements for providing retail and wholesale transmission services. The Company'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, and 250 miles from the Reno area south to Tonopah, Nevada. A 230 KV transmission line connects the Company to facilities near the Utah-Nevada state line, which in turn interconnects the Company to Idaho Power facilities at the Idaho-Nevada state line. The Company also has two 120 KV lines and one 60 KV line which interconnect with Pacific Gas and Electric (PG&E) on the west side of the Company's system at Donner Summit, California. Two 60 KV transmission ties allow wheeling of up to 14 megawatts of power from the Beowawe Geothermal Project, which is located within the Company's service area, to Southern California Edison. These two minor interties are available for use during emergency conditions affecting either party. The Company's transmission intertie system provides access to regional energy sources. Completion of the Alturas Intertie in 1998 provides the means of serving existing native load and new customers, and significantly increases the Company's capacity to import more firm capacity and energy from other regions. See Alturas Intertie discussion, page 11. Fuel Availability The Company's 1998 fuel requirements for electric generation were provided by natural gas (60.7%), coal (39.0%) and oil (0.3%). During 1998 natural gas remained the fuel of choice, over oil, for generation plants other than Valmy, which is a coal-fired plant. The average costs of coal, gas and oil for energy generation per million British thermal units (MMBtu) for the years 1994-1998 were as follows:
Average Consumption Cost ($/MMBtu) 1994 1995 1996 1997 1998 ------------ -------------- -------------- --------------- --------------- Gas $2.19 $1.65 $2.10 $2.03 $2.12 Coal 2.07 2.19 1.88 1.80 1.56 Oil 3.37 3.80 3.48 3.35 3.96
Since beginning commercial operation of its Valmy coal-fired generating units in the early 1980s, the Company operated these units at a higher load level than its gas/oil-fired units because gas and oil fuels had generally been more expensive. However, beginning in 1989, the Company operated its gas/oil- fired units at increased levels due to competitive pricing of natural gas. In September 1996, the Company began purchasing coal on the spot market at prices more competitive than gas, oil and long-term contract coal. As a result, except during periods of low-cost surplus hydro energy availability, load levels on the Valmy units have been consistently high since that time. 16 The Company's long-term contract with Black Butte Coal Company (Black Butte) for coal shipments to Valmy from the mine near Rock Springs, Wyoming, remains in effect until June 30, 2007, or until all volume requirements under the contract are delivered and/or canceled. Due to previous accelerated purchases and cancellations and continuing cancellations of minimum monthly volume obligations (described below), the Company projects it will fully satisfy all volume requirements and that termination of the contract will occur sometime in early to mid-2002. At that time, absent divestiture, the Company will pursue lower fuel cost alternatives, which may include additional purchases of spot market coal should pricing remain favorable. Beginning in June 1996, the Company, along with its joint-ownership partner (Idaho Power Company), implemented an economic cancellation strategy which essentially buys down minimum tonnage requirements under the Black Butte contract rather than taking physical delivery of the coal. Canceling the Black Butte tonnage creates various economic and operating benefits, primarily opportunity to buy lower-cost spot market coal and reduce overall fuel costs. In June 1996, the Company and Idaho Power expended $5 million ($2.5 million each) to cancel all minimum volume requirements for the 1996-97 contract year. The Company agreed with Idaho Power to satisfy even more volume requirements in the fall of 1996 and in June 1997 by matching the dollar cost of Black Butte tonnage purchased by Idaho Power for delivery to Idaho's coal-fired Jim Bridger plant. The Company expended $3.8 million for these matching cancellations. Since July 1997, the Company and Idaho Power have canceled (or delivered to the Bridger plant) minimum Black Butte volume requirements on a monthly basis. During the third quarter 1998, minimum contract quantities were delivered to Idaho Power's Bridger plant, with these deliveries credited to Valmy requirements under the Black Butte contract. The Company's long-term coal contract with Canyon Fuel Company, LLC (Canyon), which provides coal for Valmy from Canyon's SUFCO mine in Central Utah, expires on June 30, 2003. This contract also contains minimum volume requirements which the Company expects to meet each year until termination. The current owner of the SUFCO mine is Arch Coal, Inc., which acquired ARCO Coal (the previous owner of the Canyon Fuel properties, including SUFCO) on June 1, 1998. During 1998, several short-term agreements for the purchase of spot market coal were executed. The source of this coal is the Uinta Basin of Utah. These spot market purchases supplement base volume requirements under the Company's long-term coal contracts at a cost approximately one-half that of contract coal. The total amount of coal burned at the Valmy Power Plant during 1998 was 1.6 million tons. As of December 31, 1998, the coal inventory level was 272,332 tons, or approximately 47.6 days of consumption at 100% capacity. The Company targets an average annual coal stockpile sufficient to provide 30 days supply at full load. Valmy had coal delivered under a June 30, 1986 contract with the Union Pacific Railroad Company (UP). This contract expired on July 31, 1997 and the parties were unable to reach an agreement on a new contract. Subsequently, the UP filed a common carrier rate under which these coal deliveries moved while negotiations were ongoing. On August 1, 1997, the Company and Idaho Power filed a complaint with the Surface Transportation Board (STB) alleging that rates assessed by UP to move coal from Sharp, Utah to Valmy exceeded a maximum reasonable level and that UP possesses market dominance over that traffic. The Company and Idaho Power requested that the STB prescribe maximum reasonable rates, along with related rules and service terms for this movement. UP counterclaimed that no such market dominance exists and consequently, the STB did not have jurisdiction. 17 While this case proceeded, the Company and Idaho Power continued to negotiate a solution to the dispute. Although the Company and Idaho Power were unable to negotiate rates with the UP which were believed to be reasonable based on the railroad's variable cost of transportation, the rates finally obtained were very similar to those in the previous agreement and will allow the utilities to continue shipping contract coal, as well as spot market coal, to the Valmy power plant. Two new 3-year transportation agreements (one UP direct haul and one UP/Utah Railway joint haul) were executed with the UP, with an effective date of June 1, 1998. During 1998, the Company operated the Pinon Pine facility almost exclusively on natural gas. Although no coal was purchased in 1998 for synthetic gas production in the plant's coal gasification facility, approximately 19,000 tons were purchased in 1997. This inventory has been more than sufficient to fuel the gasifier during its limited operation in 1998. Total coal burned in the gasifier during 1998 was 488.5 tons, with another 500 tons being sold to a local manufacturer. Petroleum coke (used for gasifier startup) purchased in 1998 was 404 tons, with 913 tons being burned. The Company expects to purchase additional coal tonnage on a spot market basis from Arch Coal's SUFCO mine to meet any coal gasification requirements. The Company meets its needs for residual oil for generation through purchases on the spot market. With no other mitigating factors, the Company's residual oil inventory policy is to maintain 50,000 to 75,000 barrels at each of its Tracy and Ft. Churchill generating plants. Based on Year 2000 contingency plans, the Company is contemplating the possibility of increasing storage to full capacity prior to 1/1/2000, which would provide up to 17 days' supply at full load operation. The actual residual oil inventory level at these two sites was 114,960 barrels as of December 31, 1998, which is equal to 4.3 days' supply at full load operation. Total residual oil consumption in 1998 was 64,106 barrels. Approximately 83 percent of this consumption occurred in the month of December, with extremely cold temperatures resulting in gas supplies being restricted for retail customer demand. NATURAL GAS BUSINESS BUSINESS AND COMPETITIVE ENVIRONMENT The Company's natural gas business is a local distribution company (LDC) in the Reno/Sparks area that accounted for $99.5 million in 1998 operating revenues, or 13.6% of total Company operating revenues. Growth in the Company's service territory continues to be strong. Residential customer growth during 1998 was 4.4%. Residential sales growth has been boosted by an increase in multi-family housing construction activity and an aggressive residential marketing campaign targeting existing propane and fuel oil conversions. The overall natural gas customer growth rate was 4.0% for the year. Natural gas offers significant economic and environmental advantages over other energy sources for space heating, water heating and other uses in residential, commercial and industrial applications. Growth in the residential and small commercial sector is expected to continue as new developments in the Company's distribution service area are planned. A new record peak day sendout of 125,457 decatherms was reached on December 22, 1998. Competitive Issues Contracts established during the last three years under the Company's Value Based Service Tariff (VBST) are being successfully renewed as the old contracts expire. During 1998, four contracts were renewed and one new contract was signed under the VBST tariff designed to enable the Company to compete with 18 competitive service options for its largest customers. At December 31, 1998, the Company had ten VBST contracts in place with customers. The Company'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. Four customers now secure their own gas supplies, with the Company providing transportation service on its distribution system. FACILITIES AND OPERATIONS The Company has contracted for firm winter-only and annual gas supplies with 12 Canadian and domestic suppliers to meet the firm requirements of its LDC and electric operations. The contracts total 157,000 decatherms per day through February 1999; 152,000 decatherms per day for March 1999; 93,000 decatherms per day through April 1999; 78,000 decatherms per day for May through October 1999 and 65,000 decatherms per day for the remainder of the year. Most of these contracts provide for a fixed price. This ensures that the Company is able to lock in a significant portion of its gas supply cost while retaining the flexibility to purchase spot market supplies. The Company's firm natural gas supply is supplemented with natural gas storage services and supplies from a Northwest Pipeline Co. facility located at Jackson Prairie in southern Washington and a liquified natural gas (LNG) storage from a facility located near Lovelock, Nevada. The LNG facility is operated by Paiute Pipeline Company and is used for meeting peak demand. The Jackson Prairie and LNG facilities can contribute a total of approximately 48,000 decatherms per day of peaking supplies. The Company meets its peak day requirements above Northwest/Paiute capacity with firm transportation capacity on the Tuscarora pipeline and Pacific Gas Transmission Company (PGT) pipeline. Starting November 1, 1996, the Company 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 the Company 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. The Company was able to enter into this agreement due to the ability of its power plants to utilize alternative fuels and its power importation option. Following is a summary of the transportation and approximate storage capacity of the Company's current gas supply program. Firm transportation capacity on the Northwest/Paiute system exists to serve primarily the LDC. Firm transportation capacity on the PGT/Tuscarora system exists primarily to serve the Company's electric generating plants. Storage capacity is generally used for the peaking requirements of the LDC. 19 Transportation Capacity Northwest - 68,696 decatherms per day firm 90,000 decatherms per day interruptible Paiute - 103,774 decatherms per day firm from November through March 61,044 decatherms per day firm from April through October 90,000 decatherms per day interruptible NOVA - 30,000 decatherms per day firm ANG - 30,000 decatherms per day firm PGT - 30,000 decatherms per day firm 40,270 decatherms per day firm (winter only) 90,000 decatherms per day interruptible Tuscarora - 104,000 decatherms per day firm 60,000 decatherms per day interruptible
Storage Capacity Williams - 281,242 decatherms from Jackson Prairie 12,687 decatherms per day from Jackson Prairie Paiute - 463,034 decatherms from Lovelock LNG 35,078 decatherms per day from Lovelock LNG facility
Total LDC decatherm supply requirements in 1998 and 1997 were 14.9 million decatherms and 12.4 million decatherms, respectively. Electric generating fuel requirements for 1998 and 1997 were 35 million decatherms and 32 million decatherms, respectively. As of December 31, 1998, the Company owned and operated 1,296 miles of three-inch equivalent natural gas distribution lines. WATER BUSINESS The water distribution business contributed $49.1 million (6.6%) to the Company's 1998 operating revenues. The PUCN issued an order in April of 1998 on the application filed in 1997, requesting authorization to increase general water rates for all classes of customers to recover approximately $119 million in net plant additions to the water facilities due to the passage of the Safe Drinking Water Act in 1986 and increased capacity. The final order resulted in an overall increase of $4.3 million in general rates. This equates to a 9.4% increase to the average customer. Water production in 1998 totaled 22.1 billion gallons. 2.5 billion gallons were produced from the Company's groundwater wells. The remaining 19.6 billion gallons were treated through the Company's two water treatment facilities; the Chalk Bluff Water Treatment Plant and the Glendale Water Treatment Plant. The Company's peak day send-out of water during 1998 was 130.9 million gallons, a 7.9% increase over the 124 million gallon peak set in 1997. The sizable peak day increase was due to abnormally warm weather with temperatures in excess of 100 degrees for more than a week. Overall weather conditions during the year produced an average snow pack with a cool late spring, thus annual production was down 5.1%. The Company's water supplies are from both surface and groundwater sources, with the addition of drought storage and refill provisions sufficient to withstand prolonged drought conditions. The surface water 20 source is the Truckee River, which originates in Lake Tahoe and flows north and east through the cities of Reno and Sparks to Pyramid Lake, located northeast of Reno. The Company's groundwater comes from 24 supply wells located around the Reno/Sparks area. Man-made contaminants, perchloroethylene, from local business operations have been found at levels exceeding the drinking water standards in five of these wells. All five of these wells have now been fit with treatment equipment which allows them to be returned to operation and deliver water to the system which meets federal standards. The newly formed Washoe County remediation district sent out the first bills to collect funds to reimburse the Company for the cleanup of this groundwater contaminant in these five wells. One of these five wells is currently out of service due to a fuel leak at a near by gas station and the impending threat of MTBE or petroleum contamination. The Company has been putting pressure on the regulatory agencies and the perpetrator to put the appropriate barriers in place so that this well may be pumped for remediation purposes. Additionally, the Company has four wells which currently exceed the federal drinking water standard for naturally occurring arsenic concentrations. Production from three of these wells continues by blending water treated at the Glendale Water Treatment Plant. The fourth well is out of service pending treatment. The Company's water laboratory research staff are developing options to assure that the Company is prepared to meet new arsenic standards. A favorable decision rendered by the state engineer allowing the transfer of agricultural water rights to municipal use for new development in the Truckee Meadows has been appealed by Churchill County and the City of Fallon in District Court. The Company continues to provide a temporary back up of the protested water rights by pledging the Company's certificated rights to back up the protested transfers so the state engineer will continue to sign subdivision maps. This process has enabled water service commitments to continue until protests can be cleared. The Company continues to pursue the Negotiated Settlement which has been under development for several years. The Company is currently operating under a Preliminary Settlement Agreement (PSA) and interim storage contract until negotiations are completed and the final Truckee River Operating Agreement (TROA) is completed. A draft environmental impact statement (EIS) and contract was issued in early 1998 for review and comments and a final EIS will be prepared subsequent to the completion of the TROA. The Negotiated Settlement is a complex set of agreements on Truckee River issues involving the United States, California and Nevada governments, the Pyramid Lake Paiute Tribe and the Company. It is expected the agreement will be finalized this year. During 1998, these negotiations progressed with the resolution of many issues toward the completion of the draft TROA. Once in effect, the new agreement will allow the Company use of federal reservoirs for drought reserve storage. The Company plans to rebuild the Farad dam and put the Farad Hydro plant back into service in 2000. The dam was destroyed during the New Year's flood of 1997. The water rights associated with the hydro facilities and part of the Negotiated Settlement provide for river flows to the water division and therefore, the four Truckee River hydro plants will stay with the water business even after generation divestiture. See Merger/Generation Divestiture discussion at page 6. As a condition of the Negotiated Settlement, the Company's unmetered residential water customers must be converted to metered service. A meter retrofit program was approved by the PUCN and began in 1995. Funding for the program is provided by new business development and administered by the Company. The program has installed 4,897 meters (12% of 1995 unmetered customers) and 8,301 boxes without meters (35% of 1995 customers without facilities for meter installation) since the program's inception. Meter boxes without 21 meters are installed when roads and sidewalks are replaced. When a meter is installed, installation costs are significantly lower if the box is already in place. During 1998, 1,125 meters and 3,099 boxes were installed with contributed funds. At this time, only customers who volunteer for the program may have meters installed. Water meters have been required in all new construction since 1986. The Company has entered into several wholesale water agreements to treat and supply Truckee River water to developments served by Washoe County. In addition, the Company has entered into an agreement to purchase the Silver Lake Water Company pending approval by the PUCN. The Company plans to begin operation of the two Silver Lake wells and metering, billing, and customer services in October 1999 assuming PUCN approval is received. CONSTRUCTION PROGRAM Construction expenditures, including allowance for funds used during construction (AFUDC), for 1998 were $183.4 million (including contributions in aid of construction) and for the period 1994 through 1998 were $804.0 million. Estimated construction expenditures for 1999 and the period 2000-2003 are as follows (dollars in thousands):
Total 1999 2000-2003 5-Year ---- --------- ------ Electric Facilities $ 87,856 $ 414,101 $ 501,957 Water Facilities 20,795 117,448 138,243 Gas Facilities 11,032 40,920 51,952 Common Facilities 5,383 15,208 20,591 -------------------------------------------------------- Total Construction Expenditures $125,066 $ 587,677 $ 712,743 ======================================================== AFUDC ($1,995) ($19,616) ($21,611) Net Salvage, including cost of removal (120) (400) (520) Net Customer Advances and Contributions in Aid of Construction (10,242) (40,620) (50,862) -------------------------------------------------------- Total Cash Requirements $112,709 $ 527,041 $ 639,750 ========================================================
22 Total construction expenditures estimated for 1999 and the 2000-2003 period, for each segment of the Company's business, consist of the following (dollars in thousands):
Total 1999 2000-2003 5-Year ---- --------- ------ Electric Facilities Distribution $49,802 $ 205,546 $255,348 Generation 9,010 - 9,010 Transmission 20,889 191,465 212,354 Other 8,155 17,090 25,245 ---------------------------------------------------------- $87,856 $ 414,101 $501,957 ========================================================== Water Facilities Treatment and Supply $ 5,302 $ 44,140 $ 49,442 Distribution 15,161 72,029 87,190 Other 332 1,279 1,611 ---------------------------------------------------------- $20,795 $ 117,448 $138,243 ========================================================== Gas Facilities Distribution $10,068 $ 35,913 $ 45,981 Other 964 5,007 5,971 ---------------------------------------------------------- $11,032 $ 40,920 $ 51,952 ==========================================================
GENERAL REGULATION The Company is subject to the jurisdiction of the PUCN and 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 operations. The PUCN also has jurisdiction with respect to the Company's gas and water operations. The Company submits integrated resource plans regarding its electric, gas, and water business operations to the PUCN for approval. /2/ Under federal law, the Company is 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 Company's sales of electricity for resale and the transmission of energy for others. The FERC also has jurisdiction over the natural gas pipeline companies from which the Company takes service. As a result of regulation, many of the fundamental business decisions of the Company, as well as the rate of return it is permitted to earn on its utility assets, are subject to the approval of governmental agencies. The Company is also subject to regulation by environmental authorities. See Environment. ----------- RATE PROCEEDINGS During 1998, 87% of the Company's revenues were from retail sales of electricity, natural gas and water in Nevada; 5% from retail sales of electricity in California and 8% from sales of electricity and gas for resale. - ---------------------- /2/ It should be noted that under Assembly Bill 366 it has been proposed that the PUCN begin developing resource planning for electric requirements within the State of Nevada after December 31, 1999. 23 Nevada Matters Effective April 29, 1998, the PUCN approved a $4.3 million annual (or 9.4%), water rate increase. On July 1, 1998, the Company filed its electric resource plan with the PUCN. The plan discussed generation and transmission alternatives that would supply Northern Nevada with electricity for the period 1998 through 2017. On October 6, 1998, hearings on the transmission system impact study were held. The stipulation reached at the hearings required the Company to re-file its resource plan at a later date, with an updated load forecast and more detailed analysis. The plan was re-filed on December 15, 1998 and hearings will be held in early 1999. See Item 7, Nevada Matters for a discussion of Nevada restructuring. ------ California Matters On January 1, 1998, as a result of the CPUC's December 16, 1997 Transition Plan order, the Company implemented a 10%, or a $2.9 million annual, rate reduction for its residential and small commercial customers using less than 20 kw of demand monthly. To mitigate the economic effects, the Company is issuing rate reduction bonds pursuant to securitization authority of the CPUC. See Item 7, Nevada Matters, California Matters, and FERC matters and -------------- ------------------- ------------ Note 2 of the Consolidated Financial Statements. ENVIRONMENT General As with other utilities, the Company is subject to federal, state, and local regulations governing air and water quality, hazardous and solid waste, land use, and other environmental considerations. These considerations affect the construction and operation of electric, gas, and water utility facilities. Nevada's Utility Environmental Protection Act requires approval of the PUCN prior to the construction of major utility generation and transmission facilities. The United States Environmental Protection Agency (EPA) and Nevada's Division of Environmental Protection (NDEP) administer regulations involving air quality; water pollution; and solid, hazardous, and toxic waste. The Company's board of directors has a comprehensive environmental policy and a separate board committee on environmental compliance which oversees corporate performance and achievements related to the environment. The Company's corporate environmental policy emphasizes environmental stewardship. 1998 Activities The Company conducted compliance audits on 38 sites. No additional remediation is required as a result of these audits. In 1995, the Company identified one site formerly used for manufacturing gas from oil. This site was sold in 1997 with full disclosure to the buyer. Shortly after the sale, the buyer notified the Company of its intent to file legal action. To date, no such action has been taken. In July, 1998, the Company entered into an 24 agreement with the buyer to mitigate the contamination on site to an acceptable level. Remediation is scheduled to be completed during the second quarter of 1999. Presently, the total cost for this site is estimated to be $850,000, of which approximately $100,000 has been spent through December 31, 1998. The remaining balance has been accrued as a liability. In September 1994, the Company was notified by Region VII of EPA that the Company was being named as a potentially responsible party (PRP) regarding the past improper handling of Polychlorinated Biphenyls (PCBs) by PCB Treatment, Inc., located in Kansas City, Kansas, and Kansas City, Missouri (the Sites). The EPA is requesting that the Company voluntarily pay an undefined (pro rata) share of the ultimate clean-up costs at the Sites. A number of the largest PRPs formed a steering committee which is chaired by the Company. The responsibility of the Committee is to direct clean-up activities, determine appropriate cost allocation, and pursue actions against recalcitrant parties, if necessary. The EPA issued an administrative order on consent requiring signatories to perform certain investigative work at the Sites. The steering committee has retained a consultant to prepare an analysis regarding the Sites. The Company has recorded a preliminary liability for the Sites of $650,000, of which approximately $120,000 has been spent through December 31, 1998. Once evaluations are completed, the Company will be in a better position to estimate and record the ultimate liabilities for the Sites. The Company continued and initiated several actions in accordance with its policy to be an environmental leader in principle and practice. These actions have: Resulted in reduced pollutant and greenhouse gas emission rates at power plants; Demonstrated stewardship of wildlife and waterfowl habitat on and adjacent to Company property; Improved water quality conditions; and Lowered the cost of compliance with environmental regulations. During 1998, the Company was awarded bonus sulfur dioxide emission allowances by the EPA for its use of geothermal energy, a renewable resource. Under the Acid Rain Rule of the Clean Air Act, bonus emission allowances are generated to utilities that have avoided sulfur dioxide emissions by using renewable energy to generate electricity. In 1998, the Company received 623 bonus allowances. GENERAL FACILITIES Leases The Company continues to sublease available space in Sierra Plaza, its general office complex, to outside companies and other organizations. The largest lease, which is with Microsoft Licensing, Inc. runs until 2002. Also a local law firm has signed a lease providing for occupancy starting in the Fall of 1999. GENERAL - LEASEHOLDS During the year, the Company operated portions of its electric system as lessee under a lease agreement with Truckee-Carson Irrigation District (TCID). The Company also operates a lease agreement with the Mineral County Power System. Under terms of the TCID lease, the Company was obligated to pay an annual lease payment of $108,000 plus 2% of gross revenues derived from operations within the leasehold area. This area covers portions of 25 Washoe (excluding Reno/Sparks), Lyon, Storey and Churchill counties in Nevada. In 1998, the Company paid approximately $410,000 as 2% of gross revenues representing royalties through July 1998 when the lease expired. The lease, which expired in July 1998, obligated TCID to purchase all Company capital improvements unless the lease was renewed. The Company and TCID are currently negotiating a new lease. To date, capital improvements, net of depreciation, total $22.8 million. Under terms of the Mineral County Power Systems lease, the Company is obligated to pay, on a sliding scale, a percentage of gross revenues derived from operations within the leasehold area. The leasehold area includes the towns of Hawthorne, Mina, and Luning, along with other unincorporated towns roughly 100 miles southeast of Reno. During 1998, the Company paid $131,000 on gross revenues of $5.5 million. The lease expires in 2000. As with TCID, Mineral County Power System is obligated to purchase any Company capital improvements unless the lease in renewed. To date, capital improvements, net of depreciation, total $7.0 million. GENERAL - FRANCHISES The Company has nonexclusive franchises or revocable permits, in fact by grant (in most cases for specified terms of years) or in effect by acquiescence, to carry on its business in the localities in which its respective operations are conducted in Nevada and California. The franchise requirements of the various cities and counties in which the Company operates provide for payments based on gross revenues. During 1998, the Company collected $8.2 million in franchise fees based on gross revenues. It also paid and recorded as expense $1.0 million of fees based on net profits.
Franchise Type of Service Expiration Date - ------------------------------------ ---------------------------------- ------------------------------- Reno Electric, Gas and Water January 2006 Sparks Electric May 2006 Sparks Gas May 2007 Sparks Water April 2004 Carson City Electric February 2012 City of Elko Electric April 2017 City of South LakeTahoe Electric April 2018 Washoe County Gas and Water May 2015 Washoe County Electric September 2015 Eureka County Electric July 2018
The Company applies for renewal of franchises in a timely manner prior to their respective expiration dates. GENERAL RESEARCH AND DEVELOPMENT SPPC participates in several utility associations, including the Electric Power Research Institute and Gas Research Institute. ITEM 2. PROPERTIES The general character of SPPC's principle facilities is discussed in Item 1, Business. - -------- 26 Substantially all utility plant is subject to the lien of the Indenture of Mortgage, dated December 1, 1940, and supplemental indentures thereto between the Company and State Street Bank and Trust, as trustee, securing the Company's outstanding first mortgage bonds. ITEM 3. LEGAL PROCEEDINGS SPPC, through the course of its normal business operations, is currently involved in a number of legal actions, none of which has had or, in the opinion of management, is expected to have a significant impact on its financial position or results of operations. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS None. 27 PART II ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS The Company is a wholly-owned subsidiary of Sierra Pacific Resources and, as such, its common stock is not publicly traded and no market exists for it. Cash dividends declared on common stock were as follows (dollars in thousands):
1998 1997 ------- ------- First Quarter $19,000 $18,000 Second Quarter 19,000 18,000 Third Quarter 19,000 18,000 Fourth Quarter 19,000 18,000 ------- ------- Total 1998 $76,000 $72,000 ======= =======
Note: The dividends scheduled above represent payments from the Company to its parent, Sierra Pacific Resources. Dividends declared by SPR on its publicly traded stock totaled $40.3 million during 1998. After provision for payment of dividends on all outstanding shares of preferred stock and subject to limitations in the Company's restated articles of incorporation and its indentures, dividends may be paid on the common stock out of any funds legally available for that purpose when declared by the board of directors. As of December 31, 1998, approximately $84.0 million of retained earnings were available for the payment of dividends on common stock under the most restrictive of these limitations. 28 ITEM 6. SELECTED FINANCIAL DATA
Year Ended December 31, (dollars in thousands) ---------------------------------------------------------- 1998 1997 1996 1995 1994 ------------ ------------ ------------ ------------ ----------- Operating Revenues $ 734,332 $ 657,540 $ 619,724 $ 597,784 $ 603,193 ========== ========== ========== ========== ========== Operating Income $ 126,194 $ 120,172 $ 107,008 $ 101,811 $ 95,983 ========== ========== ========== ========== ========== Income Before Preferred Dividends $ 86,020 $ 83,127 $ 73,651 $ 65,983 $ 60,863 ========== ========== ========== ========== ========== Income Applicable To Common Stock $ 80,561 $ 77,668 $ 67,351 $ 58,609 $ 52,929 ========== ========== ========== ========== ========== Total Assets $2,011,820 $1,912,242 $1,842,628 $1,729,818 $1,605,710 ========== ========== ========== ========== ========== Long-Term Debt and Redeemable Preferred Stock $ 654,950 $ 655,389 $ 655,787 $ 547,124 $ 531,233 ========== ========== ========== ========== ========== Cash Dividends Paid On Common Stock $ 75,000 $ 70,000 $ 63,000 $ 54,000 $ 51,000 ========== ========== ========== ========== ==========
ITEM 7. MANAGEMENT'S DISCUSSIN AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS RESULTS OF OPERATIONS Net income before preferred dividends in 1998 was $86.0 million, an increase of $2.9 million over 1997. The Company was authorized to earn a return on equity of 12% in its Nevada electric operations and 12% and 11.25%, respectively, in its Nevada gas and water operations. The Company earned in excess of its allowed regulated returns for its electric and gas operations and therefore, under its currently effective rate settlement, the Company anticipates it will make refunds to customers reflecting one half of the excess earnings. Appropriate reserves have been recorded to reflect the anticipated refunds. California operations were authorized to earn a return on common equity of 11.6% in 1998. See Regulatory Matters for more discussion of these issues. Nevada, the Company's primary jurisdiction, uses a marginal cost method for setting electric and gas rates by customer class. As a result, changes in sales mix can result in variations in revenues, regardless of changes in total consumption. 29 The components of gross margin are set forth (dollars in thousands):
1998 1997 1996 --------- --------- --------- Operating Revenues: Electric $ 585,657 $ 540,346 $ 507,004 Gas 99,532 70,675 67,376 Water 49,143 46,519 45,344 --------- --------- --------- Total Revenues 734,332 657,540 619,724 --------- --------- --------- Energy Costs: Electric 271,773 231,473 223,177 Gas 65,430 38,135 33,859 --------- --------- --------- Total Energy Costs 337,203 269,608 257,036 --------- --------- --------- Gross Margin $ 397,129 $ 387,932 $ 362,688 ========= ========= ========= Gross Margin by Segment: Electric $ 313,884 $ 308,873 $ 283,827 Gas 34,102 32,540 33,517 Water 49,143 46,519 45,344 --------- --------- --------- Total $ 397,129 $ 387,932 $ 362,688 ========= ========= =========
The causes for significant changes in specific lines comprising the results of operations for the years ended are provided (dollars in thousands):
1998 1997 1996 ---------------------------- ------------------------------- --------------- Change from Change from Amount Prior year Amount Prior year Amount ----------- ------------- ----------- ------------- ----------- Electric Operating Revenues: Residential $ 169,109 3.7% $ 163,003 0.9% $ 161,543 Commercial 178,752 1.9% 175,386 1.2% 173,222 Industrial 184,820 4.7% 176,463 13.9% 154,954 ----------- ---------- ----------- -------- ----------- Retail revenues 532,681 3.5% 514,852 5.1% 489,719 Other 52,976 107.8% 25,494 47.5% 17,285 ----------- ---------- ----------- -------- ----------- Total Revenues $ 585,657 8.4% $ 540,346 6.6% $ 507,004 =========== ========== =========== ======== =========== Total retail sales megawatt-hours (MWH) 8,047,650 3.9% 7,743,799 8.1% 7,161,507 ----------- ---------- ----------- -------- ----------- Average retail revenue per MWH $ 66.19 -0.4% $ 66.49 -2.8% $ 68.38
In 1998, residential and commercial revenues increased due to 2% and 3% increases in customers, respectively. Industrial revenues were higher in 1998 because of higher use per customer, primarily in the mining industry where several of the Company's customers expanded operations during 1998. The increases in revenues for residential, commercial and industrial were all partially offset by a rate reduction that went into effect March 1997. The increase in other revenues primarily resulted from higher wholesale electric sales and a smaller charge for customer refunds. Higher wholesale sales in 1998, $33.1 million compared to $13.3 in 1997, reflect an increased focus on this business opportunity. The 1998 provision for customer refunds was $4.4 million compared to $7.3 million in 1997. 30 Residential and commercial revenues increased slightly in 1997 as a result of a 3% increase in customers. The increase in revenues was partially offset by a rate reduction that went into effect March 1997. Industrial revenues increased because of higher use per customer (primarily in the mining segment). The increase in industrial revenues was also offset by the March 1997 rate reduction. Other revenues were higher in 1997 primarily due to a customer refund charge of $7.3 million compared to $12.7 million in 1996.
1998 1997 1996 ------------------------------ ------------------------------ ------------ Change from Change from Amount Prior year Amount Prior year Amount ------------ ------------- ------------- ------------- ------------ Gas Operating Revenues: Residential $ 43,833 14.1% $ 38,410 8.5% $ 35,400 Commercial 22,022 12.3% 19,606 6.0% 18,499 Industrial 12,368 6.8% 11,580 6.0% 10,923 Miscellaneous (720) -6.2% (678) -177.9% 870 ------------ ----------- ------------ ---------- ------------ Total retail revenue 77,503 12.5% 68,918 4.9% 65,692 Wholesale revenue 22,029 1153.8% 1,757 4.3% 1,684 ------------ ----------- ------------ ---------- ------------ Total Revenues $ 99,532 40.8% $ 70,675 4.9% $ 67,376 ============ =========== ============ ========== ============ Sales (Decatherms): Retail 14,142,782 13.3% 12,487,087 6.3% 11,749,434 Wholesale 11,738,372 1278.6% 851,459 -27.8% 1,180,072 ------------ ----------- ------------ ---------- ------------ Total 25,881,154 94.0% 13,338,546 3.2% 12,929,506 ------------ ----------- ------------ ---------- ------------ Average revenues per decatherm Retail $ 5.48 -0.7% $ 5.52 -1.3% $ 5.59 Wholesale $ 1.88 -8.7% $ 2.06 44.1% $ 1.43
Residential, commercial and industrial revenues increased in 1998 because of a 4% increase in customers and colder than normal weather during the year. The increase in wholesale revenues reflects the Company's increased focus on this business opportunity. Residential, commercial and industrial operating revenues increased in 1997 as a result of a 5% increase in customers. The increase in industrial revenues was partially offset by lower use per customer. Miscellaneous revenues were lower in 1997 because of a $1.8 million charge for customer refunds. Wholesale revenues did not change materially in 1997.
1998 1997 1996 ------------------------------------ ------------------------------------ --------------- Change from Change from Amount Prior year Amount Prior year Amount -------- ------------- -------- ------------- -------- Water Operating Revenues $ 49,143 5.6% $ 46,519 2.6% $ 45,344 ======== ========== ======== ========= ========
Water revenues were higher in 1998 because of a 3% increase in customers and an April 1998 price increase. The 1997 revenues were also higher due to a 3% increase in customers. 31
1998 1997 1996 ------------------------------------ -------------------------------- ----------- Change from Change from Amount Prior year Amount Prior year Amount ----------- ---------------- ----------- -------------- ----------- Purchased Power $ 156,970 20.2% $ 130,612 6.8% $ 122,272 Purchased Power MWH 4,623,959 20.5% 3,836,975 0.2% 3,829,534 Average cost per MWH of Purchased Power $ 33.95 -0.3% $ 34.04 6.6% $ 31.93
Purchased power costs were significantly higher in 1998 due mostly to the costs associated with higher wholesale electric sales as discussed previously. To a lesser extent system load growth also contributed to higher purchased power costs. Purchased power costs increased in 1997 due to higher costs per MWH because of the reduced availability of low cost hydropower. As a result, the Company only slightly increased the volume of electricity purchased, and instead increased its generation to meet the growing demand.
1998 1997 1996 ----------------------------------------- ----------------------------------- ----------- Change from Change from Amount Prior year Amount Prior year Amount ----------- -------------- ----------- -------------- ----------- Fuel for Power Generation $ 114,803 13.8% $ 100,861 -1.7% $ 102,601 MWHs generated 5,524,262 13.7% 4,859,203 4.1% 4,668,598 Average cost per MWH of Generated Power $ 20.78 0.1% $ 20.76 -5.6% $ 21.98
The costs of fuel for generation increased in 1998 because of higher generation requirements needed to meet continued customer growth and greater use per customer. The cost of fuel for generation decreased slightly in 1997 due to the Company's purchase of lower-cost spot coal and the operation of Pinon Pine Power Project using natural gas. These decreases were partially offset by the requirement to increase generation to meet continued growth. 32
1998 1997 1996 ----------------------------- ------------------------------ ------------ Change from Change from Amount Prior year Amount Prior year Amount ------------ ------------ ------------ ------------ ------------ Gas Purchased for Resale Retail $ 44,473 21.2% $ 36,703 12.9% $ 32,519 Wholesale 20,957 1371.7% 1,424 3.2% 1,380 ------------ ------------ ------------ ----------- $----------- Total $ 65,430 71.6% $ 38,127 12.5% $ 33,899 ============ ============ ============ =========== ============ Gas Purchased for Resale (decatherms) Retail 14,462,505 13.6% 12,727,950 7.6% 11,833,519 Wholesale 11,738,372 1278.6% 851,459 -27.8% 1,180,072 ------------ ------------ ------------ ----------- ------------ Total 26,200,877 92.9% 13,579,409 4.3% 13,013,591 ============ ============ ============ =========== ============ Average cost per decatherm Retail $ 3.08 6.9% $ 2.88 4.7% $ 2.75 Wholesale $ 1.79 7.2% $ 1.67 42.7% $ 1.17
Consistent with the increase in retail gas revenues from customer growth and colder weather in 1998, retail gas purchases (decatherms) were higher in 1998. The average cost per decatherm for all purchases was also higher because of an increase in the unit cost of firm and spot purchases. 1997 costs were higher for the same reasons that applied to the 1998 increases (customer growth and higher unit costs).
1998 1997 1996 ------------------------------ ----------------------------------- ----------------- Change from Change from Amount Prior year Amount Prior year Amount -------- ------------- -------- ------------ ------- Allowance for other funds used during construction $ 3,797 -33.7% $ 5,723 9.4% $ 5,231 Allowance for borrowed funds used during construction 6,414 34.0% 4,785 21.9% 3,924 -------- --------- -------- --------- ------- $ 10,211 -2.8% $ 10,508 14.8% $ 9,155 -------- --------- -------- --------- -------
The total allowance for funds used during construction (AFUDC) was slightly lower in 1998 than 1997. The 1998 amount was lower due to the completion of the Pinon Pine power project in June 1998. AFUDC in 1997 exceeded the 1996 level primarily as a result of higher work in progress balances for the Alturas intertie project. 33
1998 1997 1996 ----------------------------- ------------------------------ --------- Change from Change from Amount Prior year Amount Prior year Amount --------- ------------- --------- ------------- --------- Other operating expense $ 116,076 -3.8% $ 120,600 -1.0% $ 121,798 Maintenance expense 22,266 -4.8% 23,387 13.1% 20,672 Depreciation and amortization 69,435 8.3% 64,117 10.3% 58,118 Income taxes 43,550 7.8% 40,387 11.4% 36,241 Interest charges on long-term debt 38,890 -1.8% 39,609 6.9% 37,051 Interest charges- other 7,659 67.1% 4,583 0.1% 4,579 Preferred dividend requirements of company-obligated preferred securities 4,171 0.0% 4,171 138.5% 1,749
Other operating expense was lower in 1998 due to lower costs for stock compensation, post-retirement benefits, fuel buyouts, lower accruals for delays in the construction of Pinon, and no flood damage costs. Other operating expense for 1997 decreased primarily as a result of early retirement and severance costs incurred in 1996 but not in 1997. The 1997 decrease was offset by expenses incurred by the Pinon subsidiaries, an accrual for delays in construction of Pinon, increased fuel buyouts and flood related costs. Maintenance expense was lower in 1998 because of additional electric plant maintenance performed during the previous year. Maintenance expense for 1997 increased primarily as a result of costs incurred for the repair and replacement of facilities damaged during a flood that occurred in January 1997, and for the cost of more extensive plant outages than occurred in 1996. Depreciation expense increased in 1998 because of additional Pinon Pine facilities placed in service in June 1998. Also, 1998 depreciation was higher due to water division additions and other customer improvements added to plant in service late in 1997. Depreciation increased in 1997 primarily as a result of new facilities being placed in service. The Chalk Bluff water treatment plant and the Pinon Pine power island were placed in service in 1997. In addition, the combustion turbines at Clark Mountain received authorization to be utilized for more hours of generation, as opposed to merely peaking units. The greater expected utilization reduced the estimated service lives of the units and increased depreciation expense. Continued normal additions to the utility plant contributed to the 1996 increase. Operating income taxes increased in 1998 due to increases in pre-tax income and the effective tax rate. Operating income taxes increased in 1997 as a result of improved pre-tax income. See Note 6 for more information. Interest on long-term debt was lower in 1998 because of the redemption of $5 million of 8.65% medium-term notes on June 18, 1998. In 1997, interest on long-term debt increased, reflecting the effect of interest on debt issued during 1996 that was outstanding for all of 1997. Interest charges-other increased in 1998 because of higher short-term debt balances utilized to partially finance the Alturas transmission project. Due to the issuance in the third quarter of 1996 of 8.6% trust originated preferred securities by the Company's subsidiary, Sierra Pacific Power Capital I, preferred dividends on mandatorily redeemable preferred securities increased in 1997. 34 LIQUIDITY AND CAPITAL RESOURCES Construction Expenditures and Financing - --------------------------------------- The table below provides cash construction expenditures and net internally generated cash for 1996 through 1998 (dollars in thousands):
1998 1997 1996 TOTAL ------------ ------------ ------------ ------------ Cash Construction Expenditures $139,098 $110,878 $179,101 $429,077 ============ ============ ============ ============ Net cash flow from operating activities $153,191 $145,455 $110,666 $409,312 Less common and preferred cash dividends paid 80,459 75,459 69,559 225,477 ------------ ------------ ------------ ------------ Internally generated cash 72,732 69,996 41,107 183,835 Add equity contribution from parent 17,250 27,000 36,000 80,250 ------------ ------------ ------------ ------------ Total cash available $ 89,982 $ 96,996 $ 77,107 $264,085 ============ ============ ============ ============ Internally generated cash as a percentage of cash construction expenditures 52% 63% 23% 43% Total cash available as a percentage of cash construction expenditures 64% 87% 43% 61%
The Company's estimated construction expenditures for 1999 through 2003 are $640 million. The Company estimates that 63% of its 1999 cash expenditures of approximately $113 million will be provided by internally generated funds, with the remainder being provided by the issuance of long-term and short-term debt. The anticipated level of internally generated cash utilized for construction of 63% anticipates that the Company will pay all of its net income in dividends to Sierra Pacific Resources. The Company anticipates receiving $26 million of common equity contribution from Sierra Pacific Resources in 1999. Capital Structure - ----------------- In January of 1998 the Company revised its credit facilities resulting in a $150 million 364-day credit facility for the Alturas project, and a $50 million revolving credit facility to support commercial paper activity. The $150 million Alturas credit facility was used primarily to finance the construction of the Alturas Intertie Project and the facility expired on January 29, 1999. The Company utilized $105 million of the facility during 1998. Facility fees for 1998 were approximately $120,000 for the Alturas Credit Facility, and $60,000 for the revolving credit facility. Facility fees for 1997 were approximately $110,000. As of December 31, 1998 the Company had no commercial paper outstanding. The Company's commercial paper is rated P2, A2 by Moody's and Standard and Poor's, respectively. On January 29, 1999, the Company established a new $150 million unsecured credit facility for general corporate purposes. This credit facility will expire on December 31, 1999. SPPC pays the lender a facility fee on the commitment quarterly, in arrears. 35 The Company's actual capital structure at December 31, 1998, 1997, and 1996 was as follows (dollars in thousands):
1998 1997 1996 ----- ----- ----- Short-Term Debt (1) $ 135,473 9% $ 75,454 6% $ 53,434 4% Long-Term Debt 606,450 40% 606,889 42% 607,287 44% Preferred Stock 121,615 8% 121,615 8% 121,615 9% Common Equity 661,367 43% 639,556 44% 606,896 43% ---------- ---- ---------- ---- ---------- ---- $1,524,905 100% $1,443,514 100% $1,389,232 100% ========== ==== ========== ==== ========== ====
(1) Including current maturities of long-term debt and preferred stock. The indenture under which the Company's first mortgage bonds are issued prescribes certain coverage ratios that must be met before additional bonds may be issued. At December 31, 1998, these coverage provisions would allow for the issuance of approximately $621.9 million in additional first mortgage bonds at an assumed interest rate of 8%. The indenture also limits the amount of first mortgage bonds that the Company may issue to 60 percent of unfunded property plus the amount of any previously issued bonds which have since been retired. Based on certifications to the trustee as of December 31, 1998, these indenture provisions would have allowed for the issuance of approximately $705.7 million in additional first mortgage bonds. The Company's long-term debt is rated A3, A- by Moody's and Standard & Poor's, respectively. The Company's pre-tax interest coverages for 1998, 1997 and 1996 were 3.87%, 3.86% and 3.65%, respectively. In December 1998 the Company issued $35 million of collateralized debt securities, previously registered in December 1996. On November 12, 1998 SPPC's board of directors declared a common dividend of $19.0 million, payable on or before February 1, 1999, and a preferred dividend of $1.4 million payable on or before March 1, 1999. On February 22, 1999 the SPPC board declared both a common dividend of $19.0 million and preferred dividends of $1.4 million payable on or before May 1, and June 1, 1999, respectively. REGULATORY Nevada Matters - -------------- The Nevada Legislature passed Assembly Bill 366 (AB 366) and Governor Miller signed it into law on July 16, 1997. This law establishes the framework for competition in the electric and gas industries in Nevada. In August 1997, the Public Utilities Commission of Nevada (PUCN) opened an investigatory docket on the following issues to be considered as a result of restructuring of the electric industry. (1) Identification of all cost components in utility service and establishment of allocation methods necessary for later pricing of noncompetitive services; (2) Designation of services as potentially competitive or noncompetitive; (3) Determination of rate design and non-price terms and conditions for noncompetitive services; (4) Establishment of licensing requirements for alternative sellers of potentially competitive services; (5) Past (stranded) costs; (6) Criteria and standards by which the PUCN will apply the legislative requirements concerning affiliate 36 relations; (7) Criteria and standards by which the PUCN will appoint providers of bundled electric service; (8) Consumer protection; (9) Anti-competitive behavior codes of conduct and enforcement; (10) Price regulation for potentially competitive services in immature markets; (11) Compliance plans in accordance with regulation; (12) Options for complying with legislative mandates for integrated resource planning and portfolio standards; and, (13) Innovative pricing for noncompetitive services. Highlights of restructuring activity follow: Identification of Cost Components On November 5, 1997, the PUCN issued an order containing the approved list of electric services for unbundling. In order to establish rates for the provision of electric services in a restructured environment, Sierra's existing rates will need to be separated, or unbundled, into "potentially competitive" and "non-competitive" functional categories. The PUCN has identified 26 such categories of electric service. In November 1997, Sierra and Nevada Power filed testimony and reports on electric unbundling methodologies. The PUCN held a hearing on the filings. As a result of the hearing, all parties were instructed to work towards consensus on the methodologies. Unbundling Consensus Report No. 2 was filed by Nevada Power on March 19, 1998 on behalf of all parties and reported that consensus was reached on all remaining issues. Designation of Services as Potentially Competitive or Noncompetitive On August 20, 1998 the PUCN issued a final order designating certain services as potentially competitive or noncompetitive. The PUCN deemed that generation and aggregation had already been designated potentially competitive as a result of AB366. Additionally, the PUCN deemed customer services, metering, and billing as potentially competitive services. However, the PUCN also authorized the regulated electric distribution utility to provide billing and customer service to its customers (i.e. alternative sellers) for any services provided to those customers. Distribution Non-price Terms and Conditions The PUCN issued an order adopting final regulations for non-price terms and conditions of distribution services on January 7, 1999. In this order, the PUCN delineated the roles and responsibilities of the electric distribution utility and the alternative sellers for various processes and procedures including new service connections, change orders, basic maintenance processes, etc. Licensing of Alternative Sellers and Consumer Protection Requirements for Alternative Sellers The PUCN issued proposed rules on licensing of alternative sellers and consumer protection requirements for alternative sellers. These rules provide the licensing and reporting requirements of alternative sellers and establish the conduct required when alternative sellers provide generation or aggregation services to residential and small commercial customers. 37 The Company filed comments and attended hearings on the proposed rules during September, October, and November. On November 13, 1998 the PUCN adopted a final rule for consumer protection and voted to reissue the licensing rule for further comment. The PUCN adopted a final licensing rule on January 7, 1999. Past Costs Past costs, commonly referred to as stranded costs in other jurisdictions, are an element of restructuring that will be addressed in 1999. AB366 defines the legislative criteria which must be met in order to recover past costs. The PUCN has not yet adopted any administrative regulations on the subject, although several workshops have been held. Topics addressed in the workshops include the characteristics that define recoverable past costs, criteria for evaluating the effectiveness of mitigation efforts, options for cost recovery mechanisms and identification of applicable tax and accounting issues. On December 28, 1998, the Commission issued a proposed rule that specifies the information requirements a utility must include in its request for recovery of past costs. Comments on the proposed rule were due January 25, 1999. The Commission conducted the rulemaking hearing on January 28, 1999, and is expected to issue a final rule shortly. The final rule will establish the date for a filing to recover past costs. The Company has not released an estimate of its past costs, since such a calculation is dependent on a variety of issues related to restructuring which, at this time, are not fully resolved. Affiliate Transaction Rules On December 18, 1998, the PUCN issued a final rule dealing with business transactions between regulated electric and gas distribution companies and affiliates providing potentially competitive services. The rule includes a prohibition on the use of the corporate utility name and logo by affiliates. Any statement of affiliation to the regulated distribution company used by an affiliate must include a lengthy and no less prominently displayed disclaimer. The rule also prohibits the sharing of corporate services without prior PUCN approval. Provider of Last Resort The provider of last resort (PLR) will provide electric service to customers who choose not to choose and to customers who are not able to obtain service from an alternative seller. There have been several workshops and hearings held on the PLR issue and more discussion of the issue is anticipated. A final order is expected sometime early in 1999. ISA, Load Pockets and Generation Aggregation Tariff The move to retail competition in various states has included the establishment of an entity to ensure reliable operation of transmission systems and to assure equal and non-discriminatory access to those systems by all alternative sellers. In California, an independent system operator (ISO) was established. An ISO was also established in the Midwest. Similar to a proposal being developed in Arizona, Nevada stakeholders are pursuing the development of an interim independent scheduling administrator (ISA) to address these functions as part of the move to retail open access in Nevada. In time, it is expected that regional entities, either ISO's or independent transmission companies (Transcos) will be established to perform these functions. The Company therefore considers the ISA to be an interim solution that would facilitate retail open access in Nevada while 38 regional solutions develop. The PUCN issued an order providing guidance to the parties on the development of an interim ISA on October 12, 1998. The parties, including the Company, began a consensus process to develop the ISA. The efforts of the established working group continue. An ISA proposal is expected to be filed with FERC in April 1999. A workshop on generation tariffs was held in November and proposals from the Company/Nevada Power and PUCN staff were discussed. Subsequently, PUCN staff filed a proposed tariff with the PUCN. The Company and other parties have filed comments on these proposed tariffs. A key issue is whether the tariff should be market based or cost based. The tariffs were discussed with FERC Trial Staff in January 1999. Based on this feedback, the Company is planning not to proceed with the PUCN Staff's proposal, but a cost-based tariff instead. This tariff is expected to be filed with FERC in March 1999. Compliance Plans The Company will prepare a compliance filing showing unbundled costs of service and proposing rates for the non-competitive categories. This filing is expected to be submitted to the PUCN in the Spring of 1999. Gas Restructuring In order to comply with Nevada AB 366 for natural gas deregulation, the PUCN is developing new natural gas rules. The PUCN is following similar processes as in electric restructuring to develop new rules. To date the PUCN has developed a list of unbundled services and has adopted a proposed rule for declaring services potentially competitive. This rule provides the process to be followed to declare services to be potentially competitive and does not apply to services for large commercial and industrial customers which are already eligible for competitive services such as Incentive Natural Gas Rate (INGR), Value Based Service Tariff (VBST), and transportation. The PUCN has also obtained comments, developed a proposed rule, and held workshops on licensing requirements for alternative sellers. This rule is expected to be adopted in the near future. California Matters - ------------------ Direct Access Implementation Plan The Company filed an Advice Letter in February 1998 which contained proposed tariff changes to implement direct access. These changes were in response to the California Public Utilities Commission (CPUC) order on the Company's Direct Access Implementation Plan which was approved on October 30, 1997. 10% Rate Reduction and Revenue Reduction Bond Filing In June 1998, the Company filed for Rate Reduction Bonds in order to recover the cost of the mandated 10% rate reduction. The Company requested approval to issue up to $25 million in revenue reduction bonds. At the suggestion of the CPUC, after the defeat of Proposition 9, the Company filed a Petition for Modification of the Transition Plan Order and requested balancing account treatment in lieu of revenue reduction bonds in September. On December 17, 1998 the CPUC denied the Company's Petition for Modification of the Transition Plan Order. The Company anticipates issuing Rate Reduction Bonds during the second quarter of 1999. 39 Rate Unbundling The Company filed an Advice Letter in February 1998 which contained proposed unbundled rates to be implemented June 1, 1998. The Company also filed its proposal for implementing the three billing options and for revenue cycle unbundling. These filings were in response to the CPUC's order on the Company's Transition Plan. In August, the Company filed its Revenue Cycle Unbundling Proposal. Revenue cycle services include meter ownership, meter services (O&M), meter reading, and billing. Under the Company's proposal, customers who select their own provider of a revenue cycle service would receive a credit on their bill. Transition Costs, Stranded Costs, and Market Valuation On June 30, 1998, the Company requested an extension for California market valuation of generation assets. The Company requested an extension until July 1, 1999, to file its proposed mechanism for establishing the market value of its generation assets. The Transition Plan order required the Company to file this proposal on July 1, 1998. The CPUC granted the Company a 90-day extension to file an application proposing a mechanism for valuing its generation assets on July 6, 1998. The Company requested the extension to allow more time for the PUCN to develop its approach, so a consistent approach could be used. In granting the extension, the CPUC directed the Company to encourage the PUCN to develop an approach during the 90-day extension period. The 90-day extension period expired without the Company making the filing. The Company continues to work with the PUCN and anticipates that a mechanism to establish generation market value will be developed by the third quarter of 2000. Affiliate Transaction Rules The CPUC denied the Company's December 30, 1997 request for an extension on filing its Affiliate Transaction Compliance Plan. However, the CPUC did extend the date for full compliance. The Company filed its Affiliate Transaction Compliance Plan in February 1998 in an Advice Letter. In response to petitions for modification of its December 16, 1997 Affiliate Transaction Rule order, the CPUC revised and clarified portions of its affiliate transaction rules. The revisions include the following: . Allows a "narrow" exception to the rules, which did not permit a utility to temporarily assign its employees to affiliates. The rules now permit the utility to make temporary or intermittent assignments or rotations of utility employees, except those employees involved in marketing, to its affiliates covered by these rules, except to the utility's energy marketing affiliates, under specific conditions contained in the rules. . Provides the utility an opportunity to demonstrate that no fee, or a lesser percentage than 15%, is appropriate for rank-and-file (non-executive) employees whose positions are impacted as a result of electric industry restructuring, under specific conditions contained in the rules. . The decision clarifies the existing rules regarding corporate oversight and governance. . Modifications to the utility products and services section. . Modifications to the timing of the compliance audit and regarding service provider information. On December 19, 1998 the CPUC adopted a final rule on enforcement and penalties. The rule contains provision for enforcing the affiliate transaction rules and penalties for violating the rules. 40 Consumer Protection The CPUC issued the Consumer Protection Decision on March 26, 1998. The CPUC adopted rules to ensure consumers are protected from unfair marketing practices and that Energy Service Providers (ESPs) demonstrate their creditworthiness and technical expertise to engage in power sales to the public as the state's electricity industry is opened to competition. The rules were adopted pursuant to Senate Bill 477 and applied to currently registered ESPs and those seeking registration. Registered ESPs had until June 24, 1998 to comply with the revised requirements, face suspension for non-compliance, or request inactive status by April 15, 1998. The interim standards that ESPs must follow will remain in effect until permanent standards are adopted. In addition, Consumers who do not want ESPs to solicit them by telephone can ask to be placed on a "Don't Call Me list." Any ESP who solicits a customer on the list more than once is liable to the customer for $25 for each contact. ESPs are prohibited from using the list for mailing purposes. A separate "Opt- In" list for those who want to be contacted by ESPs may be developed if there is consumer and energy service provider demand for one. FERC Matters On May 22, 1998, the Company and several other parties filed a "Petition for Review" with the D.C. Court of Appeals requesting review of the FERC's decisions in the Pacific Gas Transmission (PGT) rate case. The FERC had previously denied the Company's protest of a settlement in PGT's last rate case and the Company's request for rehearing. On July 9, 1998, the Administrative Law Judge (ALJ) certified the settlement reached in the Import Limit Case (Dockets ER97-3593 and ER97-4462). The settlement resolves all issues in these cases and provides for a continuation of the current import limit allocation until the Alturas Inter-tie is in service. At that time and until February 28, 2001, Truckee Donner Public Utility District (TDPUD) will receive 30 MW of import capability. After February 28, 2001, allocation of import capacity will be determined by the FERC based on the results of the Company's 1998 PUCN resource plan and a subsequent filing with the FERC in 1999. The settlement now goes to the FERC for approval. Truckee-Carson Irrigation District (TCID) has contested the settlement; however, the ALJ certified the settlement since the opposition by TCID does not raise issues of material fact. On October 2, 1998, the Company and Nevada Power filed an application with the FERC for merger approval. In a separate, concurrent filing, the companies submitted an open access transmission tariff for the merged company. The FERC issued an order requiring additional minor changes to the Company's standards of conduct and related posting on OASIS in October. On November 2, 1998 the FERC issued a letter order approving the Retail Tariff Settlement between the Company and FERC Staff. Also, on November 30th, the FERC issued an order accepting the Alturas interconnection and O&M agreement between the Company and Bonneville Power Administration. The order requires the Company to work with the WSCC members to establish operating procedures to avoid impacting the reliability of other systems. The Company filed an Operating Agreement for the Alturas Inter-tie Project with FERC on December 22, 1998. The Operating Agreement is a three-way agreement between the Company, Bonneville Power Administration and PacifiCorp. 41 Year 2000 Issues To the maximum extent permitted by applicable law, the following information is being designated as a "Year 2000 Readiness Disclosure" pursuant to the "Year 2000 Information and Readiness Disclosure Act" which was signed into law on October 19, 1998. The Company uses business application software programs and relies on computing infrastructure that includes embedded systems that have a Year 2000 (Y2K) affect on the Company. In many cases, the Company's software programs and embedded systems use two-digit years that may recognize a date using `00' as the year 1900 rather than the year 2000. This could result in the computer or device shutting down, performing incorrect computations, or performing in an inconsistent manner. In 1996 the Company established its Y2K project to address the Y2K issues. The project's scope includes: (1) business application systems including, but not limited to, customer information and billing and financial systems including; time reporting, payroll, general ledger, accounts payable and purchasing, and end-user developed systems; (2) embedded systems, including equipment that operates or controls operating facilities including power plants, electric transmission and distribution, water, gas, telecommunications, and information technology systems; (3) customer, vendor, and supplier relationships; and (4) testing and contingency planning. To implement its Y2K strategies, the Company established a Y2K project office currently headed by the Chief Financial Officer. This office includes an oversight committee representing all lines of business, and a "champions team" representing electric generation, transmission and distribution, gas distribution, water production and distribution, telecommunications, systems control, computer infrastructure and building facilities. Also represented are Internal Audit, Engineering, Procurement, Legal, and Human Resources. In addition, the Company has utilized the expertise of outside consultants to assist in the project management and the technical aspects of the project. Business Application Systems The initial focus for the Y2K project team was on the business application systems. In the fall of 1996 the Company purchased software assessment tools and completed its inventory and code assessment for its mainframe business systems. The inventory is comprised of over 7 million lines of COBOL code, and end-user programs. The Company developed and strictly adheres to a Y2K methodology that includes, unit, system wide and Y2K date specific testing. The first major Y2K ready business system, Customer Information and Billing representing more than 2 million lines of code, was successfully implemented in June, 1997. As of this date, the Company has successfully implemented 95% of its business systems and has a target completion date of March, 1999 to complete all systems. The Company is on schedule to meet that date. Embedded Systems The Company hired an outside engineering consultant, Network Systems Engineering Corporation (NSEC), to assist the Company's staff in conducting a thorough and comprehensive inventory of its embedded systems at the component level. All systems have been inventoried and assessed. This inventory identified over 42 2,500 potentially date sensitive items. The Company and NSEC have contacted all manufacturers of those components that they have identified as critical to operations and continue to contact other manufacturers of embedded system components to determine if their components are Y2K ready. As of December 31, 1998, 11% of the embedded systems components are not ready, 25% need further assessment, and 64% are ready or not date sensitive. Testing is underway for those items that are critical to the Company's business continuation. In order for systems to be considered Y2K ready each have undergone the phases of inventory, analysis, correction, testing and implementation. The following chart summarizes the Company's expected preparedness by quarter for 1999.
Systems 1st qtr 2nd qtr - ---------------------------------------- Electric 37% 100% - ---------------------------------------- Natural gas 50% 100% - ---------------------------------------- Water 50% 100% - ---------------------------------------- Business 100% 100% Systems - ----------------------------------------
The North American Electric Reliability Council expects utilities to have all Y2K testing and remediation complete by June 30, 1999. The Company is trying to minimize outages to its customers by scheduling some Y2K testing and remediation around planned plant maintenance that will occur during non-peak generating periods in the spring of 1999. The Company's embedded systems remediation plans call for all Y2K corrective procedures to be complete by June 1999. Vendors and Suppliers The Company has contacted in writing all vendors and suppliers of products and services that it considers critical to its operations. These contacts have included, but were not limited to, suppliers of interstate transportation capacity for coal supplies, natural gas producers, financial institutions, and telephone service providers. The quality of responses is not uniform or consistent. The next step is to work with the major vendors and suppliers to assess their Y2K readiness. The Company may consider new business and procurement alternatives for products and services as necessary to the extent that alternatives are available. Major Customers The Company has met face to face with some of its major customers to share its progress on Y2K. Also discussed at these meetings is the customer's Y2K readiness. The Company will continue to keep its major customers informed as to its progress on Y2K remediation, testing and contingency planning. Contingency Planning The Company's Y2K strategies include contingency planning for both business and embedded systems. The planning effort includes critical Company areas such as information technology, networks, vendors and suppliers, and operations personnel. Quick action response teams and additional Company personnel are planned to be available for the century rollover. Specific contingency plans are being developed with a completion date for all plans by the end of the 2nd quarter of 1999. 43 As part of its normal business practice, the Company maintains plans to follow during emergency circumstances, some of which could arise from Y2K problems. Presently, the Company continues to develop and refine its contingency plans for potential Y2K related problems. Potential Risks With respect to its internal operations, those over which the Company has direct control, the Company believes the most significant potential risks are: (1) its ability to use electronic devices to control and operate its generation, gas, water, telecommunication, transmission and distribution systems; (2) its ability to render timely bills to its customers; and (3) the ability to maintain continuous operations of its computer systems. The Company depends upon external parties, including customers, suppliers, business partners, gas and electric system operators, government agencies, and financial institutions to reliably deliver their products and services. The Company feels that its most reasonable likely worst case scenario is dependent on the extent to which any of these parties experience Y2K problems in their system. Should any of these critical vendors fail, the impact of any such failure could become a significant challenge to the Company's ability to meet the demands of its customers. Business continuity interruption could also have a material adverse financial impact, including but not limited to, lost sales revenues, increased operating costs, and claims from customer related business interruptions. Based upon the information supplied to date by our critical vendors and suppliers, the Company believes the probability of such failures is low. The Company is monitoring the progress of these critical entities and the Company's contingency plans are addressing the potential failure of an external party to be Y2K ready. Financial Implications To complete its Y2K program, the Company expects to incur expenses of approximately $2.8 million in operations and maintenance (O&M) expenditures to correct its business systems and $3.0 million to correct its embedded systems. In addition, $3.4 million will be spent on capital expenditures for the embedded systems. These expenditures will occur over a three-year period ending in June 1999. From the project's inception through December 31, 1998, the Company has expended approximately $2.1 million on its business systems and $0.4 million on its embedded systems. The Company's Y2K program is progressing and the Company believes it is taking all reasonable steps necessary to be able to operate successfully through and beyond the turn of the century. 44 ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK The Company has evaluated its risk related to financial instruments whose values are subject to market sensitivity. The only such instruments are Company issued fixed-rate and variable-rate debt obligations which were as follows as of December 31, 1998: Long-term debt (Dollars in Thousands):
Expected Weighted Expected Maturity Average Maturity Date Amounts Interest Rates Fair Value - --------------- ---------------- ---------------- ---------------- Fixed Rate 1999 $ 30,500 6.88% 2000 300 9.00% 2001 17,200 5.51% 2002 200 9.00% 2003 18,200 5.60% Thereafter 490,500 6.83% ---------------- ---------------- Total $556,900 $592,373 ======== ============= Variable Rate Due 2020 $ 80,000 *3.55% $ 80,000 ======== =============
* Weighted daily average rate for month ended December 31, 1998. 45 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Page ---- Report of Independent Accountants........................................ 47 Financial Statements: Consolidated Balance Sheets as of December 31, 1998 and 1997......... 48 Consolidated Statements of Income for the Years Ended December 31, 1998, 1997 and 1996................................................ 49 Consolidated Statements of Common Shareholder's Equity for the Years Ended December 31, 1998, 1997 and 1996....................... 50 Consolidated Statements of Cash Flows for the Years Ended December 31, 1998, 1997 and 1996................................... 51 Consolidated Statements of Capitalization as of December 31, 1998 and 1997........................................................... 52 Notes to Consolidated Financial Statements............................... 53
46 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, 1998 and 1997, and the related consolidated statements of income, common shareholder's equity, and cash flows for each of the three years in the period ended December 31, 1998. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 1998 and 1997, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1998 in conformity with generally accepted accounting principles. DELOITTE & TOUCHE LLP Reno, Nevada January 29, 1999 (February 12, 1999 as to Notes 1 and 3) 47 SIERRA PACIFIC POWER COMPANY CONSOLIDATED BALANCE SHEETS (Dollars in Thousands)
December 31, ASSETS 1998 1997 ------ ------------------- ------------------ Utility Plant, at Original Cost: Plant in service $2,348,996 $2,063,269 Less accumulated provision for depreciation 727,624 664,490 ---------- ---------- 1,621,372 1,398,779 Construction work in progress 55,670 202,036 ---------- ---------- 1,677,042 1,600,815 ---------- ---------- Other Investments 34,022 26,791 ---------- ---------- Current Assets: Cash and cash equivalents 15,197 6,920 Accounts receivable less provision for Uncollectible accounts: 1998 - $3,461; 1997 - $1,704 114,380 104,926 Materials, supplies and fuel, at average cost 25,776 25,255 Other 2,692 2,572 ---------- ---------- 158,045 139,673 ---------- ---------- Deferred Charges: Regulatory tax asset 65,619 66,563 Other regulatory assets 61,675 63,476 Other 15,417 14,924 ---------- ---------- 142,711 144,963 ---------- ---------- $2,011,820 $1,912,242 ========== ========== CAPITALIZATION AND LIABILITIES ------------------------------ Capitalization: Common shareholder's equity $ 661,367 $ 639,556 Preferred stock 73,115 73,115 Preferred stock subject to mandatory redemption: Company-obligated mandatorily redeemable preferred securities of the Company's subsidiary trust, Sierra Pacific Power Capital I, holding solely $50 million principal amount of 8.6% junior subordinated debentures of the Company, due 2036 48,500 48,500 Long-term debt 606,450 606,889 ---------- ---------- 1,389,432 1,368,060 ---------- ---------- Current Liabilities: Short-term borrowings 105,000 75,000 Current maturities of long-term debt 30,473 454 Accounts payable 66,032 63,088 Accrued interest 7,535 6,394 Dividends declared 20,365 19,365 Accrued salaries and benefits 12,131 14,978 Other current liabilities 27,759 19,209 ---------- ---------- 269,295 198,488 ---------- ---------- Deferred Credits: Accumulated deferred federal income taxes 161,697 162,627 Accumulated deferred investment tax credits 37,944 39,873 Regulatory tax liability 38,939 40,767 Accrued retirement benefits 42,560 37,456 Customer advances for construction 34,961 38,478 Other 36,992 26,493 ---------- ---------- 353,093 345,694 ---------- ---------- Commitments and Contingencies (Notes 3 and 13) $2,011,820 $1,912,242 ========== ==========
The accompanying notes are an integral part of the financial statements. 48 SIERRA PACIFIC POWER COMPANY CONSOLIDATED STATEMENTS OF INCOME (Dollars in Thousands)
Year Ended December 31, 1998 1997 1996 ------------- ------------- ------------- Operating Revenues: Electric $585,657 $540,346 $507,004 Gas 99,532 70,675 67,376 Water 49,143 46,519 45,344 --------------- --------------- --------------- 734,332 657,540 619,724 --------------- --------------- --------------- Operating Expenses: Operation: Purchased power 156,970 130,612 122,272 Fuel for power generation 114,803 100,861 102,601 Gas purchased for resale 65,430 38,127 33,899 Deferral of energy costs-net - 8 (1,736) Other 116,076 120,600 121,798 Maintenance 22,266 23,387 20,672 Depreciation and amortization 69,435 64,117 58,118 Taxes: Income taxes 43,550 40,387 36,241 Other than income 19,608 19,269 18,851 --------------- --------------- --------------- 608,138 537,368 512,716 --------------- --------------- --------------- Operating Income 126,194 120,172 107,008 --------------- --------------- --------------- Other Income: Allowance for other funds used during construction 3,797 5,723 5,231 Other income-net 335 810 867 --------------- --------------- --------------- 4,132 6,533 6,098 --------------- --------------- --------------- Total Income Before Interest Charges 130,326 126,705 113,106 --------------- --------------- --------------- Interest Charges: Long-term debt 38,890 39,609 37,051 Other 7,659 4,583 4,579 Allowance for borrowed funds used during construction and capitalized interest (6,414) (4,785) (3,924) --------------- --------------- --------------- 40,135 39,407 37,706 --------------- --------------- --------------- Income Before Dividends on Mandatorily Redeemable Preferred Securities 90,191 87,298 75,400 Preferred dividend requirements of company-obligated mandatorily redeemable preferred securities (4,171) (4,171) (1,749) --------------- --------------- --------------- Income Before Preferred Dividend requirements 86,020 83,127 73,651 Preferred dividend requirements (5,459) (5,459) (6,300) --------------- --------------- --------------- Income Applicable to Common Stock $ 80,561 $ 77,668 $ 67,351 =============== =============== ===============
The accompanying notes are an integral part of the financial statements. 49 SIERRA PACIFIC POWER COMPANY CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER'S EQUITY (Dollars in Thousands)
Year ended December 31, 1998 1997 1996 ---------------- ---------------- ---------------- Common Stock - ------------ Balance at Beginning of Year and End of Year $ 4 $ 4 $ 4 -------- -------- -------- Other Paid-In Capital - --------------------- Balance at Beginning of Year 545,434 518,434 482,434 Additional investment by parent company 17,250 27,000 36,000 -------- -------- -------- Balance at End of Year 562,684 545,434 518,434 -------- -------- -------- Retained Earnings - ----------------- Balance at Beginning of Year 94,118 88,458 84,945 Income before preferred dividends 86,020 83,127 73,651 Preferred stock dividends declared (5,459) (5,459) (5,879) Common stock dividends declared (76,000) (72,000) (64,000) Cost of issuing common stock (reimbursement to parent company) - (8) (259) -------- -------- -------- Balance at End of Year 98,679 94,118 88,458 -------- -------- -------- Total Common Shareholder's Equity at End of Year $661,367 $639,556 $606,896 ========= ========= =========
The accompanying notes are an integral part of the financial statements. 50 SIERRA PACIFIC POWER COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (Dollars in Thousands)
Year Ended December 31, 1998 1997 1996 ---- ---- ---- Cash Flows From Operating Activities: - ------------------------------------- Income before preferred dividends $ 86,020 $ 83,127 $ 73,651 Non-Cash items included in income: Depreciation and amortization 69,435 64,117 58,118 Deferred taxes and investment tax credits (3,743) (2,772) 1,233 AFUDC and capitalized interest (10,211) (10,508) (9,155) Deferred energy costs - 8 (1,736) Early Retirement and severance amortization 4,177 4,551 7,877 Merger Costs - (50) 1,909 Other non-cash 2,400 (2,109) 2,803 Changes in certain assets and liabilities: Accounts receivable (13,836) (10,144) (3,520) Materials, supplies and fuel (521) 2,331 2,869 Other current assets (120) 1,376 (1,602) Accounts payable 2,944 9,090 (36,817) Other current liabilities 6,844 1,543 12,475 Other - net 9,802 4,895 2,561 --------- --------- --------- Net Cash Flows From Operating Activities 153,191 145,455 110,666 --------- --------- --------- Cash Flows From Investing Activities: - --------------------------------------- Additions to utility plant (183,384) (147,801) (203,109) Non-cash charges to utility plant 10,587 11,553 9,475 Customer refunds for construction (3,517) (951) (739) Contributions in aid of construction 37,216 26,321 15,272 --------- --------- --------- Net cash used for utility plant (139,098) (110,878) (179,101) (Investment in) disposal of subsidiaries and other non-utility property-net (2,788) (5,254) 681 ---------- --------- -------- Net Cash Used in Investing Activities (141,886) (116,132) (178,420) Cash Flows From Financing Activities: - ------------------------------------- Increase (Decrease) in short-term borrowings 30,637 40,583 (16,059) Proceeds from issuance of long-term debt 35,000 - 80,041 Retirement of long-term debt (5,456) (15,417) (427) Decrease in funds held in trust - - 9,175 Retirement of preferred stock - - (20,400) Proceeds from Company-obligated mandatorily redeemable preferred securities - - 48,500 Additional investment by parent company 17,250 27,000 36,000 Dividends paid (80,459) (75,459) (69,559) --------- --------- --------- Net Cash (Used in) From Financing Activities (3,028) (23,293) 67,271 --------- --------- --------- Net Increase (Decrease) in Cash and Cash Equivalents 8,277 6,030 (483) Beginning Balance in Cash and Cash Equivalents 6,920 890 1,373 --------- --------- --------- Ending Balance in Cash and Cash Equivalents $ 15,197 $ 6,920 $ 890 ========= ========= ========= Supplemental Disclosures of Cash Flow Information: - --------------------------------------------------- Cash Paid During Year For: Interest $ 48,250 $ 46,824 $ 41,256 Income taxes $ 45,963 $ 41,656 $ 39,993
The accompanying notes are an integral part of the financial statements. 51 SIERRA PACIFIC POWER COMPANY CONSOLIDATED STATEMENTS OF CAPITALIZATION (Dollars in Thousands)
December 31, Common Shareholder's Equity: 1998 1997 - --------------------------- ---- ---- Common stock, $3.75 par value, 1,000 shares authorized, issued and outstanding $ 4 $ 4 Other paid-in capital 562,684 545,434 Retained earnings 98,679 94,118 ---------- ---------- Total Common Shareholder's Equity 661,367 639,556 ---------- ---------- Cumulative Preferred Stock: - -------------------------- Not subject to mandatory redemption: $50 par value: Series A; $2.44 dividend 4,025 4,025 Series B; $2.36 dividend 4,100 4,100 Series C; $3.90 dividend 14,990 14,990 $25 stated value: Class A Series 1; $1.95 dividend 50,000 50,000 ---------- ---------- Total Preferred Stock 73,115 73,115 Company-obligated mandatorily redeemable preferred securities of the Company's subsidiary trust, Sierra Pacific Power Capital I, holding solely $50 million principal amount of 8.60% junior subordinated debentures of the Company, due 2036 48,500 48,500 ---------- ---------- Total preferred stock 121,615 121,615 ---------- ---------- Long-Term Debt: - -------------- First Mortgage Bonds: Unamortized bond premium and discount, net (831) (867) Debt Secured by First Mortgage Bonds: 2.00% Series Z due 2004 93 114 2.00% Series O due 2011 1,497 1,618 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 110,000 115,000 7.10% and 7.14% Series B MTN due 2023 58,000 58,000 6.83% and 6.86% Series C MTN due 1999 - 30,000 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 3,207 3,275 6.70% Series II due 2032 21,200 21,200 5.47% Series D MTN due 2001 17,000 - 5.50% Series D MTN due 2003 5,000 - 5.59% Series D MTN due 2003 13,000 - ---------- ---------- Subtotal, excluding current portion 527,047 527,257 Variable Rate Note: Water Facilities Note: maturing 2020 80,000 80,000 Other, excluding current portion 234 499 ---------- ---------- Total Long-Term Debt 606,450 606,889 ---------- ---------- TOTAL CAPITALIZATION $1,389,432 $1,368,060 ========== ==========
The accompanying notes are an integral part of the financial statements. 52 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES The significant accounting policies for both utility and non-utility operations are as follows: General Sierra Pacific Power Company (SPPC), a wholly-owned subsidiary of Sierra Pacific Resources (SPR), is a regulated public utility engaged principally in the generation, purchase, transmission, distribution, and sale of electric energy. It provides electricity to approximately 294,000 customers in a 50,000 square mile territory 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. SPPC also provides water and gas service in the cities of Reno and Sparks, Nevada, and environs. In 1995, SPPC formed two subsidiaries for the specific purpose of forming a partnership to operate the Pinon Pine gasifier facility. These subsidiaries are Pinon Pine Corporation and Pinon Pine Investment Company. In February 1999, SPPC purchased GPSF-B which owns the portion of the gasifier facility which was not already owned by SPPC. They are consolidated into the financial statements of SPPC, with all significant intercompany transactions eliminated. On July 29, 1996, SPPC formed a wholly-owned subsidiary, Sierra Pacific Power Capital I (Trust), for the purpose of completing a public offering of trust originated preferred securities. Refer to Note 4 of SPPC's consolidated financial statements for the stock issuance and Note 3 for the Pinon Pine Power Project. SPPC maintains its accounts for electric and gas operations in accordance with the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission (FERC) and for water operations in accordance with the Uniform System of Accounts prescribed by the National Association of Regulatory Utility Commissioners. The preparation of consolidated financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities. These estimates and assumptions also affect the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of certain revenues and expenses during the reporting period. Actual results could differ from these estimates. Certain reclassifications have been made for comparative purposes but have not affected previously reported net income or common shareholder's equity. SPPC Utility Plant In addition to direct labor and material costs, SPPC also charges to the construction of utility plant: the cost of time spent by administrative employees in planning and directing construction work; property taxes; employee benefits (including such costs as pensions, postretirement and postemployment benefits, vacations and payroll taxes); and an allowance for funds used during construction. 53 The original cost of plant retired or otherwise disposed of and the cost of removal less salvage is generally charged to the accumulated provision for depreciation. The cost of current repairs and minor replacements is charged to operating expenses when incurred. The cost of renewals and betterments is capitalized. Allowance For Funds Used During Construction and Capitalized Interest SPPC capitalizes, as part of construction costs on utility plant, an allowance for funds used during construction (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 use of equity funds and as a reduction of interest charges for the portion representing borrowed funds. Recognition of this item as a cost of utility plant is in accordance with established regulatory ratemaking practices. Such practices permit the utility to earn a fair return on, and recover in rates charged for utility services, all capital costs. This is accomplished by including such costs in rate base and in the provision for depreciation. The AFUDC rates used during 1998, 1997 and 1996 were 7.69%, 8.30% and 8.91%, respectively. As specified by the PUCN, certain projects were assigned a lower AFUDC rate due to specific low-interest-rate financings directly associated with those projects. Depreciation Depreciation is calculated using the straight-line composite method over the estimated remaining service lives of the related properties. The provision, as authorized by the PUCN, for 1998, 1997 and 1996, stated as a percentage of the original cost of depreciable property, was 3.31%, 3.16% and 3.18%, respectively. Cash and Cash Equivalents Cash is comprised of cash on hand and working funds. Cash equivalents consist of high quality investments in money market funds. SPPC engages in short-term investment activity whenever it is deemed beneficial. As of December 31, 1998 and 1997, SPPC's investments in money market funds were $12.4 million and $4.7 million respectively. Regulatory Accounting and Other Regulatory Assets SPPC's rates are currently subject to the approval of the PUCN and are designed to recover the cost of providing generation, transmission and distribution services. As a result, SPPC qualifies for the application of SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation". 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 54 that would otherwise be charged to expense where it is probable that future revenue will be provided to recover these costs. SFAS No. 101, "Regulated Enterprises-Accounting for the Discontinuation of Application of FASB Statement No. 71" requires that an enterprise whose operations cease to meet the qualifying criteria of SFAS 71 discontinue the application of that statement by eliminating the effects of any actions of regulators that had been previously recognized. In 1997, the Emerging Issues Task Force (EITF) released Issue 97-4. In doing so, it reached a consensus that a utility subject to a deregulation plan for its generation business should stop applying SFAS No. 71 to the generating portion of its business no later than the date when a plan with sufficient detail of the effect of the plan is known. EITF 97-4 also reached a consensus that regulatory assets and liabilities that originated in a portion of the business which is discontinuing its application of SFAS No. 71 should be evaluated on the basis of where (that is, the portion of the business in which) the regulated cash flows to realize and settle them will be derived. The result of the consensus is that there is no elimination of regulatory assets which the deregulatory legislation or rate order specifies collection of, if they are recoverable through a portion of the business which remains subject to SFAS No. 71. In conformity with SFAS No. 71, the accounting for SPPC conforms with generally accepted accounting principles as applied to regulated public utilities and as prescribed by agencies and the commissions of the jurisdictions in which it operates. In accordance with these principles, certain costs that would otherwise be charged to expense or capitalized as plant costs are deferred as regulatory assets based on expected recovery from customers in future rates. Management's expected recovery of deferred costs is based upon specific ratemaking decisions or precedent for each item. The following other regulatory assets were included in the consolidated balance sheets as of December 31 (dollars in thousands):
DESCRIPTION 1998 1997 AMORTIZATION PERIODS - ----------- -------- -------- -------------------- Early Retirement and Severance Offers $20,468 $24,644 Various through 2005 Loss on Reacquired Debt 17,918 18,354 Various through 2023 Plant Assets 7,978 8,869 Various through 2031 Conservation and Demand Side Programs 3,787 6,146 Various through 2006 Other Costs 11,524 5,463 Various ------- ------- Total $61,675 $63,476 ======= =======
Currently, the electric utility industry is predominately regulated on a basis designed to recover the cost of providing electric power to its retail and wholesale customers. If cost-based regulation were to be discontinued in the industry for any reason, including competitive pressure on the cost-based prices of electricity, profits could be reduced, and utilities might be required to reduce their asset balances to reflect a market basis less than cost. Discontinuance of cost-based regulation would also require affected utilities to write off their associated regulatory assets. Management cannot predict the potential impact, if any, of these competitive forces on SPPC's future financial position and results of operations. 55 Deferral Of Energy Costs SPPC has suspended deferred energy accounting in its Nevada (except for liquid propane gas) and California jurisdictions. Prior to May 1995 (Nevada) and June 1996 (California), SPPC employed deferred energy accounting procedures in its electric and gas operations, as provided by statutes. The intent of these procedures was to capture fluctuations in the cost of purchased gas, fuel and purchased power. Deferred energy accounting required SPPC to record the difference between actual fuel expense and fuel revenues as deferred energy costs. In Nevada, deferred energy remains suspended until January 1, 2000. At that time, there is a possibility of the Company returning to deferred energy accounting. 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 the parent 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. For regulatory purposes, SPPC is 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, SPPC 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 SPPC 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 SPPC. The deferred investment tax credit balance is being amortized over the estimated service lives of the related properties. Revenues SPPC accrues unbilled utility revenues earned from the dates customers were last billed to the end of the accounting period. These amounts are included in accounts receivable. Recent Pronouncements of The FASB In June 1998, the FASB issued SFAS 133, entitled "Accounting for Derivative Instruments and Hedging Activities". This statement establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, (collectively referred to as derivatives) and for hedging activities. It requires that an entity recognize all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value and is effective for all fiscal quarters of all fiscal years beginning after June 15, 1999. The Company is still assessing the impact of SFAS 133 on its financial condition and results of operations. 56 NOTE 2. REGULATORY ACTIONS Nevada Proceedings As a result of the 1997 rate plan, SPPC made its first earnings sharing filing on April 29, 1998. For its electric customers, SPPC filed to refund $7.3 million based upon calendar year 1997 results. SPPC also proposed a refund of $1.7 million to its gas division customers for results of the same period. In December 1998, a pre-hearing conference was held which set hearings for early 1999. An order is expected before mid-year. The Company has recognized contingent liabilities to provide for its estimate of the outcome of this proceeding. On April 2, 1998, the PUCN issued its order with respect to the SPPC's application for an increase in its water division's general rates. The application was filed in September 1997. The PUCN's decision authorized SPPC to increase its water rates by approximately $4.3 million annually (or 9.4%), effective April 29, 1998. On February 27, 1998, SPPC requested permission from the PUCN to continue to serve customers in the Truckee-Carson Irrigation District (TCID) leasehold area upon expiration of the leasehold agreement. On September 29, 1998, the PUCN determined that SPPC was fit, willing, and able to serve the leasehold area. The PUCN also determined that TCID's application was deficient. However, the PUCN will allow the TCID to reapply for a certificate sometime in the future if it satisfies numerous conditions including obtaining a judicial determination that it owns facilities in the area. The Company continues negotiations with TCID. California Proceedings On January 1, 1998, as a result of the CPUC's December 16, 1997 Transition Plan order, SPPC implemented a 10%, or a $2.9 million annual, rate reduction for its residential and small commercial customers using less than 20 kw of demand monthly. In June 1998, SPPC filed for Revenue Reduction Bonds in order to recover the cost of the 10% rate reduction. SPPC requested approval to issue up to $25 million in revenue reduction bonds. At the suggestion of the CPUC, after the defeat of Proposition 9, SPPC filed a Petition for Modification of the Transition Plan Order and requested balancing account treatment in lieu of revenue reduction bonds in September. On December 17, 1998 the CPUC denied SPPC's Petition for Modification of the Transition Plan Order. SPPC anticipates issuing Revenue Reduction Bonds during the first quarter of 1999. FERC Proceedings On January 21, 1998, SPPC filed its compliance with the FERC's Order in Docket No. ER98-12 (Retail Access Transmission Service). This filing contained changes to the Open Access Transmission Tariff necessary to accommodate retail access in SPPC's California retail jurisdiction. On April 17, 1998, a settlement was filed resolving all outstanding issues. The settlement was certified on May 20, 1998 and approved on November 2, 1998. 57 On February 19, 1998, FERC rejected a zone pricing rate design in the order in one of SPPC's natural gas transportation providers, Northwest Pipeline, (Northwest) Docket No. RP94-220. All other issues in this case were previously settled. FERC also issued an initial decision in Northwest's Docket No. RP95- 409 that covers O&M expenses, depreciation, rate of return and capital structure, rate base adjustments, and billing determinants. On May 22, 1998, the SPPC and several other parties filed a "Petition for Review" with the D.C. Court of Appeals requesting review of the FERC's decisions in the Pacific Gas Transmission (PGT), another of the SPPC's natural gas transportation providers. The FERC had previously denied SPPC's protest of a settlement in PGT's last rate case and the SPPC's request for rehearing. On June 4, 1998, SPPC filed a settlement with all parties in Docket No. ER97-3593-000 et al. The settlement resolves all issues in these cases and upholds the current import limit and the allocation of limited import capacity until the Alturas Intertie is in service. As of December 22, 1998 when the Alturas Intertie became commercially operational and until February 28, 2001, Truckee Donner Public Utility District will receive 30 MW of import capability. After February 28, 2001, allocation of import capacity will be determined by the FERC based on the results of SPPC's 1998 resource plan and a subsequent filing with FERC in 1999. On July 9, 1998, the settlement was certified and is pending FERC approval. On November 30, 1998, the FERC issued an order accepting the Alturas Interconnection and O&M agreement between the Company, Bonneville Power Administration (BPA) and Pacificorp. The order requires SPPC to work with the WSCC members to establish operating procedures to avoid impacting the reliability of other systems. On December 22, 1998, SPPC filed the draft Alturas Operating Agreement between the Company, BPA and Pacificorp. NOTE 3. JOINTLY-OWNED FACILITIES Valmy - ----- SPPC and Idaho Power Company each own an undivided 50% interest in the Valmy generating station, with each company being responsible for financing its share of capital and operating costs. SPPC is the operator of the plant for both parties. SPPC's share of direct operation and maintenance expenses for Valmy is included in the accompanying consolidated statements of income. The following schedule reflects SPPC's 50% ownership interest in jointly- owned electric utility plant at December 31, 1998 (dollars in thousands):
Electric Accumulated Construction MW Plant Provision For Work In Plant Capacity In Service Depreciation Progress ------------ ------------ ---------------- ------------------- ------------------ Valmy #1 129 $127,642 $53,152 $469 Valmy #2 137 $153,684 $52,916 $735
58 Pinon Pine - ---------- Pinon Pine Corp. and Pinon Pine Investment Co., subsidiaries of SPPC, own 25% and 75% of a 38% interest in Pinon Pine Company, L.L.C. GPSF-B, a Delaware corporation formerly owned by General Electric Capital Corporation (GECC) and now also owned by SPPC, owns the remaining 62% as of February 1999. The LLC was formed to take advantage of federal income tax credits associated with the alternative fuel (syngas) produced by the coal gasifier available under (S) 29 of the Internal Revenue Code. The entire project, which includes an LLC-owned gasifier and an SPPC-owned power island and post-gasification facilities to partially cool and clean the syngas, is referred to collectively as the Pinon Pine Power Project. SPPC has a funding arrangement with the Department of Energy (DOE). Under the agreement, the DOE will provide funding towards the construction of the project, and towards the operating and maintenance costs of the facility. The DOE has committed $168 million of funding for Pinon construction and operation costs. The DOE provided funding for approximately 43% of the estimated construction cost and half of the operating and fuel expenses and will provide funding until the commitment is expended. A dispute has arisen with the DOE regarding the historical and future funding of natural gas costs. In February 1999, the DOE informed the Company it will not fund the remaining $14 million under the cooperative agreement until the dispute is resolved. Estimated construction start-up and commissioning costs for Pinon, including the DOE's portion are approximately $301.5 million, which includes permitting taxes, start-up commissioning, operator training and Allowance for Funds Used During Construction. DOE funding for construction through December 1998 is $132.4 million . Construction began on the project in February 1995, following resource plan approval and the receipt of all permits and other approvals. The natural gas portion (combined cycle combustion turbine) was satisfactorily completed and placed in service December 1, 1996. The balance of the plant was completed in June 1998. The construction of the gasifier portion of the project overran the fixed contract price by approximately 12% or $12.6 million. The overrun is primarily due to redesign issues, resolving technical issues relative to start up and other costs due to a later than anticipated completion date. To date, SPPC has not been successful in obtaining sustained operation of the gasifier but work continues to identify problem areas and redesign solutions which will likely require additional capital expenditures. Due to the problems noted above, SPPC and Foster Wheeler settled on a portion of the cost overrun and have entered into an alternative dispute resolution. SPPC had to satisfy certain performance requirements as part of the construction agreement with the LLC. The initial performance warranty required that the gasifier attain an average capacity factor of 30% during 1997, regardless of delays in the in-service date. Since the gasifier was not in service in 1997, the certain performance warranties required by the contract were not met. Consequently, SPPC paid GECC $2.8 million as satisfaction of the performance obligation. 59 NOTE 4. PREFERRED STOCK All issues of SPPC preferred stock are superior to SPR common stock with respect to dividend payments (which are cumulative) and liquidation rights. SPPC's Restated Articles of Incorporation, as amended on August 19, 1992, authorize an aggregate total of 11,780,500 shares of preferred stock at any given time. The following table indicates the number of shares outstanding and the dollar amount thereof at December 31 of each year. The difference between total shares authorized and the amount outstanding represents undesignated shares authorized but not issued.
Shares Issued Amount --------------------------------------------------- ----------------------------- 1998 1997 1996 1998 1997 1996 ------------- ------------- ------------- ------------- ------------- ------------- (dollars in thousands) Not subject to mandatory redemption: Series A 80,500 80,500 80,500 $ 4,025 $ 4,025 $ 4,025 Series B 82,000 82,000 82,000 4,100 4,100 4,100 Series C 299,800 299,800 299,800 14,990 14,990 14,990 Class A Series I 2,000,000 2,000,000 2,000,000 50,000 50,000 50,000 --------- --------- --------- -------- -------- -------- Subtotal 2,462,300 2,462,300 2,462,300 73,115 73,115 73,115 Subject to mandatory redemption: Preferred securities of Sierra Pacific Power Capital I 1,940,000 1,940,000 1,940,000 48,500 48,500 48,500 ----------------------------------------- ---------------------------------------- Total 4,402,300 4,402,300 4,202,300 $121,615 $121,615 $121,615 ========================================= ========================================
SPPC redeemed 408,000 shares of Series G, 8.24% Preferred Stock, at par value, for $20.4 million on June 3, 1996 using the proceeds from the following issuance of Preferred Securities. On July 29, 1996, Sierra Pacific Power Capital I (the Trust), a wholly- owned subsidiary of SPPC, issued $48.5 million (1,940,000 shares) 8.60% Trust Originated Preferred Securities (the preferred securities). SPPC owns all the common securities of the Trust, 60,000 shares totaling $1.5 million (common securities). The preferred securities and the common securities (the Trust Securities) represent undivided beneficial ownership interests in the assets of the Trust. The existence of the Trust is for the sole purpose of issuing the Trust Securities and using the proceeds thereof to purchase from SPPC its 8.60% Junior Subordinated Debentures due July 30, 2036, in a principal amount of $50 million. The sole asset of the Trust is SPPC's Junior Subordinated Debentures. SPPC's obligations under the guarantee agreement entered into in connection with the preferred securities, when taken together with the SPPC's obligation to make interest and other payments on the junior subordinated debentures issued to the Trust, and SPPC's obligations under its Indenture pursuant to which the junior subordinated debentures are issued and its obligations under the declaration, including its liabilities to pay costs, expenses, debts and liabilities of the Trust, provides a full and unconditional guarantee by SPPC of the Trust's obligations under the Preferred Securities. In addition to retiring the $20.4 million of Series G Preferred Stock, proceeds were used to reduce short-term borrowings. 60 The Preferred Securities of Sierra Pacific Power Capital I are redeemable only in conjunction with the redemption of the related 8.60% junior subordinated debentures. The junior subordinated debentures will mature on July 30, 2036, and may be redeemed, in whole or in part, at any time on or after July 30, 2001, or at any time in certain circumstances upon the occurrence of a tax event. A tax event occurs if an opinion has been received from tax counsel that there is more than an insubstantial risk that: the Trust is, or will be subject to federal income tax with respect to interest accrued or received on the junior subordinated debentures; the Trust is, or will be subject to more than a de minimis amount of other taxes, duties or other governmental charges; interest payable by SPPC to the Trust on the junior subordinated debentures is not, or will not be, deductible, in whole or in part for federal income tax purposes. Upon the redemption of the junior subordinated debentures, payment will simultaneously be applied to redeem preferred securities having an aggregate liquidation amount equal to the aggregate principal amount of the Junior Subordinated Debentures. The preferred securities are redeemable at $25 per preferred security plus accrued dividends. NOTE 5. LONG-TERM DEBT Substantially all utility plant is subject to the lien of the SPPC indenture under which the first mortgage bonds are issued. On June 30, 1997, SPPC redeemed $15 million 6.5% First Mortgage Bonds which had been included in the current liability portion of the consolidated balance sheet. On June 17, 1998, SPPC redeemed $ 5 million 8.65% First Mortgage Bonds before the due date in 2022. In December 1998, SPPC issued $35 million principal amount of collateralized Medium-Term Notes, Series D, consisting of three year non- callable notes, due in 2001, with interest rates of 5.47% and five year non- callable notes, due in 2003, with interest rates ranging from 5.50% to 5.59%. For all notes, interest is payable in semi-annual payments. The proceeds to SPPC from the sale of the notes is to be used for general corporate purposes including but not limited to: the acquisition of property; the construction, completion, extension or improvement of facilities; or discharge or refunding of obligations, including short-term borrowings. SPPC's aggregate annual amounts of maturities for long-term debt for each fiscal year ended 1999 through 2003 are shown below (dollars in thousands): 1999 $30,500 2000 300 2001 17,200 2002 200 2003 18,200
61 NOTE 6. TAXES The following reflects the composition of taxes on income (in thousands of dollars):
1998 1997 1996 --------------------------------------------------------------- Federal: Taxes estimated to be currently payable $46,176 $40,574 $33,070 Deferred taxes related to: Excess of tax depreciation over book depreciation 4,100 3,997 5,217 Deferral of energy costs deducted currently for tax purposes-net - (3) (307) Contributions in aid of construction and customer advances (2,963) (3,966) (2,917) Avoided interest capitalized (875) (1,578) (3,124) Costs of abandoned merger - 301 4,359 Net amortization of investment tax credit (1,930) (1,962) (1,961) Other-net (2,075) 712 (33) State (California) 925 801 754 --------------------------------------------------------------- Total $ 43,358 $ 38,876 $ 35,058 =============================================================== As Reflected in Statement of Income: Federal income taxes $ 42,625 $ 39,586 $ 35,487 State income taxes 925 801 754 --------------------------------------------------------------- Operating Income 43,550 40,387 36,241 Other income-net (192) (1,511) (1,183) --------------------------------------------------------------- Total $ 43,358 $ 38,876 $ 35,058 ===============================================================
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):
1998 1997 1996 --------------------------------------------------------------- Income before preferred dividend requirements $ 86,020 $ 83,127 $ 73,651 Total income tax expense 43,358 38,876 35,058 --------------------------------------------------------------- 129,378 122,003 108,709 Statutory tax rate 35% 35% 35% --------------------------------------------------------------- Expected income tax expense 45,282 42,701 38,048 Depreciation related to difference in cost basis for tax purposes 1,383 1,591 2,456 Allowance for funds used during construction-equity (1,334) (1,912) (1,831) Tax benefit from the disposition of assets 63 (569) (1,130) ITC amortization (1,930) (1,962) (1,961) California franchise taxes (net of federal benefit) 601 521 490 Other-net (707) (1,494) (1,014) --------------------------------------------------------------- $ 43,358 $ 38,876 $ 35,058 =============================================================== Effective tax rate 33.5% 31.9% 32.2%
62 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):
1998 1997 1996 ------------------------------------------------------------- Accumulated Deferred Federal Income Tax Liabilities: AFUDC $ 8,378 $ 7,174 $ 5,745 Bond redemption's 5,865 6,423 6,690 Excess of tax depreciation over book depreciation 157,906 154,240 142,441 Repairs and maintenance 6,180 4,355 3,047 Tax benefits flowed through to customers 65,619 66,563 67,667 Other 3,161 1,498 4,485 ------------------------------------------------------------- Total 247,109 240,253 230,075 ------------------------------------------------------------- Accumulated Deferred Federal Income Tax Assets: Avoided interest capitalized 14,694 13,819 12,241 Employee benefit plans 3,049 1,783 1,132 Contributions in aid of construction and customer advances 33,925 30,697 25,980 Gross-ups received on contributions in aid of construction and advances 4,512 4,197 3,529 Unamortized investment tax credit 20,432 21,471 22,527 Other 8,800 5,659 2,229 ------------------------------------------------------------- Total 85,415 77,626 67,638 ------------------------------------------------------------- Accumulated Deferred Federal Income Taxes $161,697 $162,627 $162,437 =============================================================
The Company's balance sheets contain a net regulatory tax asset of $26.7 million at year-end 1998 and $25.8 million at year-end 1997. The net regulatory asset consists of future revenue to be received from customers (a regulatory tax asset) of $65.6 million at year-end 1998 and $66.6 million at year-end 1997, 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 tax liability), consisting of $18.5 million at year-end 1998 and $19.3 million at year-end 1997, due to temporary differences for liberalized depreciation at rates in excess of current tax rates, and $20.4 million at year-end 1998 and $21.5 million at year-end 1997 due to temporary differences caused by the investment tax credit. The regulatory tax liability for temporary differences related to liberalized depreciation will continue to be amortized using the average rate assumption method required by the Tax Reform Act of 1986. The regulatory tax liability for temporary differences caused by the investment tax credit will be amortized ratably in the same fashion as the accumulated deferred investment credit. NOTE 7. FAIR VALUE OF FINANCIAL INSTRUMENTS The December 31, 1998 carrying amount for cash, cash equivalents, current assets, accounts payable and current liabilities approximates fair value due to the short-term nature of these instruments. 63 The total fair value of SPPC's long-term debt at December 31, 1998, is estimated to be $641.9 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 $640.4 million as of December 31, 1997. NOTE 8. SHORT-TERM BORROWINGS In January of 1998 the Company revised its credit facilities resulting in a $150 million 364-day credit facility for the Alturas project, and a $50 million revolving credit facility to support commercial paper activity. The $150 million Alturas credit facility was used primarily to finance the construction of the Alturas Intertie. This facility expired on January 29, 1999. The Company utilized $105 million of the facility during 1998. Facility fees for 1998 were approximately $120,000 for the Alturas Credit Facility, and $60,000 for the revolving credit facility. Facility fees for 1997 were approximately $101,000. On January 29, 1999 SPPC established a new $150 million unsecured credit facility for general corporate purposes. This credit facility will expire on December 31, 1999. SPPC pays the lender a facility fee on the commitment quarterly, in arrears. At December 31, 1998, SPPC's short-term debt was $105.0 million drawn from the Alturas credit facility at an average interest rate of 5.41%. At December 31, 1997, SPPC had a balance of $75 million in short-term borrowings comprised entirely of commercial paper at an average interest rate of 6.12%. The other subsidiaries of SPPC have no outstanding short-term borrowings at this time. NOTE 9. DIVIDENDS The Restated Articles of Incorporation of SPPC and the indentures relating to the various series of its First Mortgage Bonds contain restrictions as to the payment of dividends on its common stock. Under the most restrictive of these limitations, approximately $84 million of retained earnings were available at December 31, 1998 for the payment of common stock cash dividends. NOTE 10. RETIREMENT PLAN AND POSTRETIREMENT BENEFITS SPPC sponsors a noncontributory defined benefit retirement plan covering all employees who satisfy the service requirement and a defined benefit post- retirement plan that covers administrative employees and those covered under collective bargaining agreements. The plan provides medical, dental and life insurance benefits for retirees. The retirement plan provides benefits based on each covered employee's years of service, highest five-year average compensation, and a step rate benefit formula indirectly integrating the plan with Social Security. 64 Beginning in 1998, retirement plan provisions applicable to employees covered by the collective bargaining agreement were amended to recognize additional compensation as pensionable pay and to reduce the penalty for retirement before age 62. SPPC's funding policy for the retirement plan is to contribute an annual amount to an irrevocable trust that is not less than the minimum funding requirement under the Employee Retirement Income Security Act of 1974, and not in excess of the amount that can be deducted for federal income tax purposes. The plan's assets are invested primarily in common stocks, marketable bonds, and other fixed-income securities. The remainder is held in cash and cash equivalents. None of the plan assets are invested in SPR common or SPPC preferred stock. In April 1995, SPPC offered an early retirement plan to non-bargaining unit employees age 50 or older with at least 15 years of credited service as of January 1, 1996 and whose age and credited years of service equaled at least 70. The present value of termination costs relating to the 112 employees who accepted the offering was originally recorded in 1995 at $16.8 million, but was revalued at $12.8 million during 1996 due to a revision in the measurement date. These termination costs were fully deferred, as a regulatory asset, as of December 31, 1995. During 1996, SPPC began amortizing the termination costs by recognizing expense for both 1995 and 1996. SPPC is using a ten-year amortization period for these costs, consistent with the treatment of previous early retirement programs. For management, professional and administrative employees, the post- retirement plan is contributory for individuals retiring after January 1, 1993, with retiree contributions tied to each retiree's length of service. Additionally, the plan requires employees retiring after January 1, 1993 to participate in Medicare Part "B". Life insurance benefits remain noncontributory for retirees. However, the amount of life insurance provided for retirees is significantly less than that provided to active employees. Also, dental coverage is discontinued for all employees at age 65. Beginning in 1998, post-retirement plan provisions applicable to employees covered by the collective bargaining agreement were amended. Retiree contributions were increased to a minimum of 10% plus an additional amount for each year of service fewer than 20. Also, the plan introduced a managed care option for future retirees. SPPC's funding policy for its post-retirement benefit obligation takes advantage of federal income tax deductions. Contributions are being made to two voluntary employee's beneficiary associations and in IRC (S)401(h) account. Plan assets are invested primarily in common stocks, marketable bonds and other fixed income securities. The remainder is held in cash and cash equivalents. None of the plan assets are invested in SPR common or SPPC preferred stock. Post-retirement health care costs for key executives continue to be paid from SPPC's general assets. 65 The following table sets forth a reconciliation of the funded status of the plans with amounts included in SPPC's consolidated balance sheets for 1998, 1997 and 1996 (dollars in thousands).
Pension Benefits Post-Retirement Benefits 1998 1997 1996 1998 1997 1996 -------------- ------------- -------------- --------------- ---------- ----------- Change in benefit obligation Benefit obligation at beginning Of year $186,612 $157,660 $165,877 $ 65,483 $ 73,526 $ 73,821 Service cost 7,047 5,825 6,652 2,162 2,440 2,587 Interest cost 13,702 11,920 11,778 4,817 5,597 5,269 Plan participant's contributions - - - 67 54 41 Amendments - 5,204 - - (3,520) 415 Actuarial gain 8,310 14,500 (18,540) 6,661 (10,278) (6,277) Benefits paid (8,563) (8,497) (8,107) (2,764) (2,336) (2,330) -------------- ------------- -------------- --------------- ----------- ---------- Benefit obligation at end of year 207,108 186,612 157,660 76,426 65,483 73,526 -------------- ------------- -------------- --------------- ----------- ---------- Change in plan assets Fair value of plan assets at Beginning of year 190,535 167,416 148,300 39,326 32,944 24,620 Actual return on plan assets 23,160 32,534 19,954 7,069 5,202 1,942 Employer contribution - - 8,087 4,143 3,668 8,877 Plan participant's contributions - - - 67 54 41 Expenses paid (1,275) (917) (818) (252) (206) (206) Benefits paid (8,563) (8,498) (8,107) (2,764) (2,336) (2,330) Fair value of plan assets at end -------------- ------------- -------------- --------------- ----------- ---------- of year 203,857 190,535 167,416 47,589 39,326 32,944 -------------- ------------- -------------- --------------- ----------- ---------- Funded status 3,251 (3,923) (9,756) 28,837 26,157 40,582 Unrecognized net actuarial gain 26,519 29,352 26,661 16,716 20,837 8,562 Unrecognized prior service cost (8,404) (9,083) (4,251) - - (415) Unrecognized transition obligation - - - (31,563) (33,818) (39,419) -------------- ------------- -------------- --------------- ----------- ---------- Accrued benefit cost $ 21,366 $ 16,346 $ 12,654 $ 13,990 $ 13,176 $ 9,310 ============== ============= ============== =============== ===========================
In the preceding table, unrecognized net gain represents the net gain attributable to changes in actuarial assumptions and differences between actual experience and actuarial assumptions. Also, service cost represents the benefits earned during the year while interest cost represents the increase in the accumulated benefit obligation due to the passage of time.
Pension Benefits Post-Retirement Benefits 1998 1997 1996 1998 1997 1996 ------------ ------------- ----------- ----------- ----------- ------------ Weighted-average assumptions as of December 31 Discount rate 6.75% 7.25% 7.50% 6.75% 7.25% 7.50% Expected return on plan assets 8.50% 8.50% 8.50% 8.50% 8.50% 8.50% Rate of compensation increase 4.50% 5.00% 5.00% 4.50% 5.00% 5.00%
66 For 1996, the Company used a graduated medical trend rate assumption with an initial rate of 11.25%. This medical trend rate declined by 0.50% over the next ten years to an ultimate rate of 5.75% in 2007, remaining at the level thereafter. Beginning in 1997, the obligation valuation changes to a flat trend rate of 6.00% for each year as well as the adoption of the 1994 Group Annuity Generational Mortality Table.
($000) Pension Benefits Post-Retirement Benefits 1998 1997 1996 1998 1997 1996 ----------- ---------- ----------- --------- ---------- ---------- Components of net periodic benefit cost Service cost $ 7,047 $ 5,825 $ 6,652 $ 2,162 $ 2,440 $ 2,587 Interest cost 13,702 11,920 11,778 4,817 5,597 5,269 Expected return on plan assets (15,800) (13,844) (12,590) (3,495) (2,937) (2,036) Amortization of prior service cost 679 372 372 33 - Amortization of transition obligation - - 2,255 2,464 2,464 Recognized net actuarial gain (609) (581) - (783) (62) ----------- ---------- ----------- --------- ---------- ---------- Net periodic benefit cost: SFAS No. 132 5,019 3,692 6,212 4,956 7,535 8,284 Amount expensed : SFAS No. 71 - Net 2,599 2,599 3,882 805 805 2,044 ----------- ---------- ----------- --------- ---------- ---------- Total net periodic benefit cost $ 7,618 $ 6,291 $ 10,094 $ 5,761 $ 8,340 $10,328 =========== ========== =========== ========= ========== ==========
The amount expensed under SFAS No. 71 for the retirement plan represents the SFAS No. 88 costs arising from the 1989, 1992 and 1995 early retirement programs. Pursuant to PUCN directive and prior precedent, costs for the 1989, 1992, and 1995 programs are being amortized over 10 years. Assumed health care cost trend rates have a significant effect on the amounts reported for post-retirement plans. A one-percentage-point change in the assumed health care cost trend would have the following effects:
1-Percentage- 1-Percentage- Point Increase Point Decrease Effect on total of service and interest cost components $ 1.8 million $(1.4 million) Effect on post-retirement Benefit obligation $14.0 million $(11.0 million)
In addition to the employee retirement plan covering all employees, SPPC has a Supplemental Executive Retirement Plan which is a non-qualified defined benefit plan under which SPPC will pay out of general assets supplemental pension benefits to key executives. SPPC also has a non-qualified supplemental pension plan covering certain employees. This plan provides for incremental pension payments from SPPC's funds so that total pension payments equal amounts that would have been payable from SPPC's principal pension plan if it were not for limitations imposed by income tax regulations. The unfunded liability under these plans as of 67 December 31, 1998, 1997 and 1996 was $5.6 million, $5.2 million and $4.9 million, respectively. NOTE 11. STOCK COMPENSATION PLANS At December 31, 1998 the Company had several stock-based compensation plans which are described below. The Company applies Accounting Principals Board Opinion No. 25 and related Interpretations in accounting for its plans. Accordingly, no compensation cost has been recognized for nonqualified stock options and the employee stock purchase plan. The total compensation cost that has been charged against income for the performance shares, dividend equivalents and the non-employee director stock plans was $.5 million, $1.4 million and $.9 million for 1998, 1997 and 1996, respectively. Had compensation cost for the Company'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 method of Statement of Financial Accounting Standard No. 123, the Company's income applicable to common stock would have been decreased to the pro forma amounts indicated below:
1998 1997 1996 ------------ ------------ ------------- Income applicable to common stock As Reported $80,561 $77,668 $67,351 Pro Forma $80,217 $77,500 $67,284
The Company'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 the Company's common shares to key employees through December 31, 2003. The plan permits the following types of grants, separately or in combination: nonqualified and qualified stock options; stock appreciation rights; restricted stock; performance units; performance shares; and bonus stock. During 1998, 1997 and 1996, the Company issued only nonqualified stock options and performance shares under the plan. Nonqualified stock options granted during 1998, 1997 and 1996 were granted at an option price not less than market value at the date of the grant (January 1, 1998, January 1, 1997 and January 1, 1996, respectively). The 1998 and 1997 options vest to the participants 33 1/3% per year over a three year period from the grant date and may be exercised for a period not exceeding ten years from the date of the grant. The 1996 options vest to the participants 20% per year over a five year period from the grant date and may be exercised for a period not exceeding ten years from the date of the grant. The options may be exercised using either cash or previously acquired shares, valued at the current market price, or a combination of both. The fair value of each nonqualified option has been estimated on the date of grant using the Black-Scholes option-pricing model with the following assumptions used for grants in 1998, 1997 and 1996, respectively: dividend yield of 4.71%, 5.30% and 5.50%; expected volatility of 13.16%, 11.42% and 11.57%; risk-free rates of return of 5.81%, 6.68% and 5.75%; and an expected life of 10 years for all grants. 68 A summary of the status of the Company's nonqualified stock option plan as of December 31, 1998, 1997 and 1996, and changes during those years is presented below:
1998 1997 1996 ---- ---- ---- Weighted Weighted Weighted -Average -Average -Average Shares Exercise Shares Exercise Shares Exercise Nonqualified Stock Options (000) Price (000) Price (000) Price ------------------------------------------------------------------------------------------------------------------------ Outstanding at beginning of year 158 $25.51 89 $20.73 70 $19.59 Granted 125 $35.90 98 $28.75 28 $23.38 Exercised (31) $24.24 (15) $20.28 (1) $19.83 Forfeited (44) $27.12 (14) $23.17 (8) $20.04 Outstanding at end of year 208 $31.62 158 $25.51 89 $20.73 Options exercisable at year-end 38 $24.54 25 $20.32 18 $19.83 Weighted-average fair value of options granted during the year $4.79 $3.51 $2.13
The following table summarizes information about nonqualified stock options outstanding at December 31, 1998:
Options Outstanding Options Exercisable --------------------------------- ------------------------------- Number Remaining Number Exercise Outstanding at Contractual Exercise Exercisable at Price 12/31/98 Life Price 12/31/98 ----------------------------------------------- ------------------------------- $20.500 9,088 5 years $20.500 7,270 $18.750 12,544 6 years $18.750 7,526 $23.375 11,180 7 years $23.375 4,472 $28.750 55,598 8 years $28.750 18,570 $35.900 120,000 9 years $35.900 -
During 1998, 1997 and 1996, the Company granted performance shares in the following numbers and initial values, respectively: 12,700, 14,090 and 8,973 shares; and $35.90, $28.75 and $23.375 per share. The actual number of shares earned is dependent upon SPR achieving certain financial goals over three-year performance periods. The value of performance shares, if earned, will be equal to the market value of SPR's common shares as of the end of the performance periods. The Company, at its sole discretion, may pay earned performance shares in the form of cash or in shares (or a combination thereof). Simultaneous with the grant of both the nonqualified options and 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 from the date of grant through the exercise date, or, in the case of performance shares, 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. 69 Under the Company's employee stock purchase plan, SPR is authorized to issue up to 400,162 shares of common stock to all of its employees with minimum service requirements. Under the terms of the plan, employees can choose twice each year to have up to 15% of their base earnings withheld to purchase the Company'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 15,282, 17,822 and 15,602 shares to employees in 1998, 1997 and 1996, respectively. Compensation cost has been estimated for the employees' purchase rights on the date of grant using the Black-Scholes option-pricing model with the following assumptions used for 1998, 1997 and 1996, respectively: average dividend yield of 4.17%, 4.87% and 5.38%; average expected volatility of 14.16%, 11.57% and 11.51%; and average risk-free interest rates of 4.96%, 5.59% and 5.45%. The weighted average fair value of those purchase rights in 1998, 1997 and 1996 was $4.94, $4.14 and $3.26, respectively. The Company's non-employee director stock plan provides that a portion of the outside directors' annual retainer be paid in Company stock. Effective May 20, 1996, the annual retainer for non-employee directors was increased from $14,000 to $30,000. The minimum amount to be paid in Company stock was also increased from $4,000 to $20,000 per director, over the prior year. During 1998, 1997 and 1996, the Company granted the following total shares and related compensation to directors in Company stock, respectively: 6,391, 8,208 and 9,212 shares; and $233,250, $230,833 and $160,417. NOTE 12. POSTEMPLOYMENT BENEFITS During 1995, SPPC offered a severance program to non-bargaining-unit employees which provided both severance pay and medical benefits continuation totaling $7.0 million and $0.5 million, respectively. These costs were deferred as a regulatory asset as of December 31, 1995. SPPC began amortization of these costs during 1996 over a ten-year period consistent with the period used for pension and post-retirement benefits. There was no remaining liability for unpaid severance and benefits at December 31, 1998, 1997 or 1996. NOTE 13. COMMITMENTS AND CONTINGENCIES SPPC's estimated cash construction expenditures for the year 1999 and the five-year period 1999-2003 are $112.7 million and $639.8 million, respectively. 70 Several of SPPC's purchased power, gas supply and pipeline capacity, and coal supply contracts contain minimum volume provisions, which SPPC is either meeting or exceeding. SPPC anticipates continuing to meet or exceed them in the future. Estimated future commitments under non-cancelable agreements with initial terms of one year or more at December 31, 1998 were as follows (in thousands of dollars): 1999 $170,700 2000 148,900 2001 104,900 2002 83,800 2003 82,300 After 2003 to 2015 425,800
SPPC has an operating lease for its corporate headquarters building, a 334,000 square foot, five-floor, multi-purpose building located in southeast Reno, Nevada. The primary term of the lease is 25 years, ending in 2010. The current annual rental is $5.4 million, which amount remains constant until the end of the primary term. The lease has renewal options for an additional 50 years. SPPC subleases building space to various tenants. These subleases vary from year to year and are shown at net of total lease. The total rental expense under all leases (net) was approximately $7.5 million in 1998, $7.4 million in 1997 and $8.2 million in 1996. Estimated future minimum lease commitments (net of the corporate headquarters building subleases described above) under non-cancelable operating leases with initial terms of one year or more at December 31, 1998 were as follows (in thousands of dollars): 1999 $ 8,700 2000 6,600 2001 6,300 2002 6,200 2003 7,000 After 2003 to 2018 41,800 ------- Total $76,600 =======
SPPC has no material capital lease commitments. See Notes 1, 5, 7, and 10 of SPPC's consolidated financial statements for additional commitments and contingencies. SPPC, through the course of its normal business operations, is currently involved in a number of legal actions, none of which has had or, in the opinion of management, is expected to have a significant impact on its financial position or results of operations. 71 NOTE 14. SEGMENT INFORMATION The Company adopted FASB statement No. 131, Disclosure about Segments of an Enterprise and Related Information, for its annual reports as of December 31, 1998. The Company operates three business segments providing regulated electric, natural gas and water service. Electric service is provided to northern Nevada and the Lake Tahoe area of California. Natural gas and water services are provided in the Reno-Sparks area of Nevada. Information as to the operations of the different business segments is set forth below based on the nature of products and services offered. The Company evaluates performance based on several factors, of which the primary financial measure is business segment operating income. The accounting policies of the business segments are the same as those described in the summary of significant accounting policies (Note 1). Intersegment revenues are not material. Financial data for business segments is as follows (in thousands).
Reconciling December 31, 1998 Electric Gas Water Eliminations Consolidated - --------------------- ----------- ----------- ----------- ------------ --------------- Operating Revenues $ 585,657 $ 99,532 $ 49,143 $ 734,332 ------------ ----------- =========== ============ =============== Operating income $ 103,728 $ 10,534 $ 11,932 $ 126,194 ============ =========== =========== ============ =============== Operating income taxes $ 34,611 $ 5,142 $ 3,797 $ 43,550 ============ =========== =========== ============ =============== Depreciation and Amortization $ 57,180 $ 4,810 $ 7,445 $ 69,435 ============ =========== =========== ============= =============== Interest expense on long term debt $ 28,277 $ 4,001 $ 10,911 $(4,299) $ 38,890 ============ =========== =========== ============ =============== Assets $1,558,322 $139,398 $274,124 $39,976 $2,011,820 ============ =========== =========== ============ =============== Capital expenditures $ 144,080 $ 11,124 $ 28,180 $ 183,384 ============ =========== =========== ============ =============== Reconciling December 31, 1997 Electric Gas Water Eliminations Consolidated - --------------------- ------------ ----------- ----------- ------------ --------------- Operating revenues $ 540,346 $ 70,675 $ 46,519 $ 657,540 ============ =========== =========== ============ =============== Operating income $ 99,671 $ 10,057 $ 10,444 $ 120,172 ============ =========== =========== ============ =============== Operating income taxes $ 33,742 $ 4,223 $ 2,422 $ 40,387 ============ =========== =========== ============ =============== Depreciation and amortization $ 52,239 $ 4,531 $ 7,347 $ 64,117 ============ =========== =========== ============ =============== Interest expense on long term debt $ 31,098 $ 3,653 $ 9,158 $(4,300) $ 39,609 ============ =========== =========== ============ =============== Assets $1,463,969 $130,392 $282,524 $35,357 $1,912,242 ============ =========== =========== ============ =============== Capital expenditures $ 105,531 $ 12,191 $ 30,079 $ 147,801 ============ =========== =========== ============ =============== Reconciling December 31, 1996 Electric Gas Water Eliminations Consolidated - --------------------- ------------ ----------- ----------- ------------ --------------- Operating revenues $ 507,004 $ 67,376 $ 45,344 $ 619,724 ============ =========== ============ ============ =============== Operating income $ 86,428 $ 11,035 $ 9,545 $ 107,008 ============ =========== ============ ============ =============== Operating income taxes $ 27,743 $ 4,872 $ 3,626 $ 36,241 ============ =========== ============ ============ =============== Depreciation and amortization $ 47,797 $ 4,223 $ 6,098 $ 58,118 ============ =========== ============ ============ =============== Interest expense on long term debt $ 27,856 $ 3,480 $ 7,519 $(1,804) $ 37,051 ============ =========== ============ ============ =============== Assets $1,407,927 $122,137 $276,954 $35,610 $1,842,628 ============ =========== ============ ============ =============== Capital expenditures $ 158,482 $ 10,798 $ 33,829 $ 203,109 ============ =========== ============ ============ ===============
72 The reconciliation of segment information to consolidated totals in the preceding table includes an adjustment for intersegment interest expense eliminated from the consolidated totals. The reconciliation of segment assets to the consolidated total includes the following unallocated amounts.
1998 1997 1996 -------- ------- ------- Other property $ 1,342 $ 1,928 $ 1,043 Cash 15,197 6,920 890 Current assets-other 2,692 2,572 3,948 Other regulatory assets 21,031 23,876 29,426 Deferred charges-other (286) 61 303 -------- ------- ------- $39,976 $35,357 $35,610 ======== ======= =======
NOTE 15. QUARTERLY FINANCIAL DATA (unaudited) The following represents unaudited quarterly financial data (dollars in thousands):
Quarter Ended ------------- March 31, June 30, Sept. 30, Dec. 31, 1998 1998 1998 1998 ------------------------------------------------------------ Operating Revenues $182,722 $169,143 $187,446 $195,021 ======== ======== ======== ======== Operating Income $ 33,138 $ 27,308 $ 33,626 $ 32,122 ======== ======== ======== ======== Income Before Preferred Dividend Requirement $ 23,194 $ 17,705 $ 23,751 $ 21,370 ======== ======== ======== ======== Income Applicable to Common Stock $ 21,829 $ 16,340 $ 22,386 $ 20,006 ======== ======== ======== ========
Quarter Ended ------------- March 31, June 30, Sept. 30, Dec. 31, 1997 1997 1997 1997 ------------------------------------------------------------- Operating Revenues $171,858 $154,817 $159,783 $171,082 ======== ======== ======== ======== Operating Income $ 32,292 $ 26,637 $ 29,194 $ 32,049 ======== ======== ======== ======== Income Before Preferred ======== ======== ======== ======== Dividend Requirement $ 23,357 $ 17,337 $ 20,142 $ 22,291 ======== ======== ======== ======== Income Applicable to Common Stock $ 21,992 $ 15,972 $ 18,777 $ 20,927 ======== ======== ======== ========
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES None. 73 PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS (a) Directors The following is a listing of all the current directors of SPPC and their ages as of December 31, 1998. There are no family relationships among them. Directors serve one-year terms ending at the next annual meeting or until a successor has been elected and qualified. Edward P. Bliss, 66 Consultant to Scudder Kemper 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 Director of SPPC since 1992 and of SPR since 1991. Krestine M. Corbin, 61 President and Chief Executive Officer of Sierra Machinery, Incorporated since 1984 and a director of that company since 1980. She also serves on the Federal Reserve Bank Twelfth District Head Board. Ms. Corbin has served as a Director of SPPC since 1992 and of SPR since 1989. Theodore J. Day, 49 Senior Partner, Hale, Day, Gallagher Company, a real estate brokerage and investment firm. Mr. Day has served as a Director of SPPC since 1986 and of SPR since 1987. He is also a Director of the W.M. Keck Foundation. Harold P. Dayton, Jr., 76 Retired President of Dayton's Furniture, Inc. Mr. Dayton has served as a Director of SPPC since 1967 and of SPR since 1983. James R. Donnelley, 63 Vice Chairman of the Board, R.R. Donnelley & Sons Company, since July 1990. He was Group President, Corporate Development from June 1987 to July 1990 and Group President, Financial Printing Services Group from January 1985 to January 1988 for R.R. Donnelley and Sons Company. He has been a Director of that Company since 1976. He is also a Director of Pacific Magazines & Printing Limited and Director and Chairman of National Merit Scholarship Corporation. Mr. Donnelley has served as a Director of SPPC since 1992 and of SPR since 1987. 74 Richard N. Fulstone, 71 President and General Manager of R.N. Fulstone Company since 1957 and President and General Manager, F.M. Fulstone, Inc., since 1982. Both companies engage in farming, cattle ranching and investments. Mr. Fulstone has served as a Director of SPPC since 1992 and of SPR since 1986. Malyn K. Malquist, 46, Chairman, President and Chief Executive Officer Mr. Malquist was elected President and Chief Executive Officer of the Company and SPR on January 14, 1998. On February 24, 1998, Mr. Malquist was elected to the additional position of Chairman for both the Company and SPR. He was Sr. Vice President - Distribution Services Business Group and Principal Operations Officer from August 1996 to January 1998. He served as Senior Vice President and Chief Financial Officer of the Company and SPR when he joined the Company in April 1994 to August 1996. Prior to joining the Company, he was with San Diego Gas and Electric, where since 1978 he held various financial positions, including Treasurer in 1990 and Vice President in 1993. James L. Murphy, 69 Certified Public Accountant and retired partner of and consultant to Grant Thornton L.L.P., an international accounting and management consulting firm. He is the owner, independent trustee and general partner of several real estate development projects and numerous rental properties. He is also a retired Colonel in the United States Air Force Reserve. Mr. Murphy has served as a Director of SPPC since 1990 and of SPR since 1992. Ronald K. Remington, 57 President, Great Basin College since June 1989. He was previously Vice President of Instruction at Truckee Meadows Community College. Dr. Remington received his Ph.D. in psychology from the University of Nevada, Reno. Dr. Remington has served as a Director of SPPC since December 1991. Dennis E. Wheeler, 56 Chairman, President and Chief Executive Officer of Coeur d'Alene Mines Corporation since 1986. Mr. Wheeler has served as a Director of SPPC since 1992 and of SPR since 1990. Robert B. Whittington, 71 Retired newspaper executive; former President, Gannett West Newspaper Group; Director, Gannett Company, Inc.; and former publisher, Reno Gazette and Nevada State Journal. Mr. Whittington has served as a Director of both SPPC and SPR since 1985. 75 All of the present Directors, with the exception of Dr. Remington, are Directors of SPR. Messrs. Malquist and Murphy are Directors of Lands of Sierra, Inc.; Messrs. Dayton and Malquist are Directors of Sierra Gas Holdings Co.; Messrs. Fulstone and Malquist are Directors of Sierra Water Development Co.; Messrs. Day and Malquist are Directors of Tuscarora Gas Pipeline Co.; Mr. Malquist is a Director of Sierra Pacific Resources Media Group, GPSF-B, Pinon Pine Corp., and Pinon Pine Investment Co. All of the above listed companies are affiliates of SPPC with the exception of GPSF-B, Pinon Pine Corp., and Pinon Pine Investment Co which are subsidiaries. (b) Executive Officers The following are current executive officers and their ages as of December 31, 1998. There are no family relationships among them. Officers serve a term which extends to and expires at the meeting of the Board of Directors in May of each year or until a successor has been elected and qualified. Malyn K. Malquist, 46, President and Chief Executive Officer See description under Item 10(a), "Directors", page 75. William E. Peterson, 51, Senior Vice President, General Counsel and Corporate Secretary Mr. Peterson was elected to his present position in January 1994, and holds the same position with the Company's parent, SPR. He was previously Senior Vice President, Corporate Counsel from July 1993 to January 1994. Prior to joining the Company in 1993, he served as General Counsel and Resident Agent for SPR since 1992, and as a partner in the Woodburn and Wedge Law Firm since 1982. Mark A. Ruelle, 37, Senior Vice President, Chief Financial Officer and Treasurer Mr. Ruelle was elected to his present position March 1, 1997 and holds the same position with the Company's parent, SPR. Prior to joining the Company, Mr. Ruelle was President of Westar Energy, a subsidiary of Western Resources, Inc. in 1996, and before that served as Vice President, Corporate Development for Western Resources in 1995. Mr. Ruelle was with Western Resources since 1987 and served in numerous positions in regulatory affairs, treasury, finance, corporate development, and strategy planning. Gerald W. Canning, 50, Vice President, Restructuring Group Mr. Canning was appointed to his current position in January, 1998. Prior to this, since November, 1996, he served as Vice President, Power Production and Fuels. He also served as President of Tuscarora Gas Pipeline Company, an affiliate of the Company, from 1995 to 1996. Mr. Canning has been with the Company since 1968, and served in the positions of Vice President - Electric Production and Fuels Business; Vice President and General Manager - Wholesale Energy Business; Vice President - Wholesale Electric Business; Vice President - Electric Operations; and Vice President - Electric Resources. 76 Jeffrey C. Ceccarelli, 44, Vice President -- Distribution Services Mr. Ceccarelli was elected to his current position 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 the Company since 1972 and has held numerous management positions in operations, customer service, design and engineering. Randy Harris, 45, Vice President, Energy Marketing Services Business Group Mr. Harris was elected to his current position in November 1996. His prior management positions include: General Manager, Transmission Services Business Group; Director of Wholesale Business; Director of Operations, Tuscarora Gas Pipeline; and Manager, Electric Operations. Mr. Harris joined the Company in 1974. Steven C. Oldham, 48, Vice President - Transmission Business Group and Strategic Development Mr. Oldham was elected to his current position in November 1996. His previous executive positions include Vice President - Strategic Development; Vice President - Information Resources, Corporate Redesign and Merger Transaction; Vice President Regulation and Treasurer; and Treasurer and Director of Finance. Mr. Oldham has been with the Company since 1976. Mary O. Simmons, 43, Controller Ms. Simmons was elected to her current position in June 1997. Her previous positions include: Director, Water Policy and Planning; Director, Budgets and Financial Services; and Assistant Treasurer, Shareholder Relations for SPR. Ms. Simmons, a certified public accountant, has been with the Company since 1985. Mary Jane Willier, 52, Vice President, Human Resources Ms. Willier was elected to her present position in January 1997. She was previously Vice President, Human Resources Network Group for Bell Atlantic Corporation. Ms. Willier was with Bell Atlantic from 1968 - 1996 and in addition to the Vice President's position, served as Director of Human Resources, Assistant to the President for Consumer Affairs, and several other managerial positions. Although all outstanding shares of the Company'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 four series of non-voting preferred stock still outstanding and registered under the Securities Exchange Act of 1934 ("the Act"). As a technical matter, the Company 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. The Company's officers, all of whom are currently reporting pursuant to Section 16(a) of the Act with respect to SPR's common stock, have now filed reports 77 with respect to the Company's preferred stock, which reports show no past or current beneficial ownership of such preferred stock. 78 ITEM 11. EXECUTIVE COMPENSATION SUMMARY COMPENSATION TABLE The following table sets forth information about the compensation of each Chief Executive Officer that served in that position during 1998, and each of the four most highly compensated officers for services in all capacities to the Company and its subsidiaries.
Long-Term Compensation --------------------------------------- Annual Compensation Awards Payouts --------------------------------------------------------------------------------- Other Securities Annual Restricted Underlying Name and Compen- Stock Options/ LTIP All Other Principal Salary Bonus sation Awards SARS Payouts Compensation Position Year ($) ($) ($) ($) (#) ($) ($) (a) (b) (c) (d) (2) (e) (3) (f) (g) (h) (4) (i) (5) - ----------------------------------------------------------------------------------------------------------------------------------- Walter M. Higgins (1) 1998 $ 63,234 $ 0 $ 0 $ 0 0 $ 0 $ 703 Chairman, President and 1997 $361,497 $ 0 $ 6,020 $ 0 30,000 $ 0 $47,175 Chief Executive Officer 1996 $334,231 $219,869 $ 0 $ 0 9,594 $181,193 $35,054 Malyn K. Malquist (1) 1998 $292,960 $180,900 $16,486 $ 0 61,000 $ 85,184 $15,805 Chairman, President and 1997 $212,803 $ 92,198 $ 2,052 $ 0 14,000 $101,192 $15,279 Chief Executive Officer 1996 $194,077 $ 95,335 $ 0 $ 0 3,504 $ 51,770 $ 9,380 William E. Peterson 1998 $199,385 $ 71,503 $18,918 $ 0 9,000 $ 85,184 $29,939 Senior Vice President 1997 $207,757 $ 78,184 $17,142 $ 0 10,000 $101,192 $29,488 General Counsel and 1996 $191,923 $ 85,445 $ 3,417 $ 0 3,504 $ 70,508 $20,982 Corporate Secretary Mark A. Ruelle 1998 $192,116 $ 72,843 $12,342 $ 0 9,000 $ 50,108 $ 8,974 Senior Vice President 1997 $143,308 $ 65,269 $ 3,808 $ 0 8,384 $ 0 $77,329 Chief Financial Officer 1996 $ 0 $ 0 $ 0 $ 0 0 $ 0 $ 0 Treasurer Mary Jane L. Willier 1998 $159,923 $ 51,975 $10,950 $ 0 5,500 $ 26,868 $ 6,122 Vice President, Human 1997 $135,577 $ 46,027 $ 3,606 $ 0 6,000 $ 0 $72,377 Resources, Sierra 1996 $ 0 $ 0 $ 0 $ 0 0 $ 0 $ 0 Pacific Power Company Randy G. Harris 1998 $155,769 $ 56,454 $10,788 $ 0 5,500 $ 29,063 $ 5,893 Vice President, Energy 1997 $135,328 $ 45,916 $ 2,657 $ 0 6,000 $ 0 $ 4,672 Marketing Services 1996 $100,731 $ 22,424 $ 5,647 $ 0 0 $ 0 $ 4,112 Business Group Sierra Pacific Power Company - ------------------------------------------------------------------------------------------------------------------------------------
79 Notes: (1) Mr. Higgins resigned from his position of Chairman, President and Chief Executive Officer on January 14, 1998. Mr. Malquist was named Chairman, President and Chief Executive Officer on January 15, 1998. (2) Amounts represent incentive pay received pursuant to SPR's "pay for performance" team incentive plan approved by stockholders in May, 1994. (3) No perquisites in the aggregate exceeded the lesser of $50,000 or 10% of salary and bonus for any named executive. Accordingly, no amount perquisites have been reported. (4) Long-term incentive payout relates to performance share payout for the three-year period January 1, 1996 to December 31, 1998. (5) Amounts for All Other Compensation include the following for 1998: . Company contributions under the 401(k) deferred compensation plan for all administrative employees, executive officers and directors, pursuant to which the Company matches 50% of each executive officer's deferral up to 6% of salary. In 1998, the Company matching amount was $4,800 each for Messrs. Malquist, Peterson, Ruelle, and Harris and Ms. Willier. . Company contributions to its nonqualified deferred compensation plan for Messrs. Malquist and Peterson and Ms. Willier were $9,312, $23,157 and 9,016. The additional income on earnings contributed by Messrs. Higgins, Malquist, Peterson and Ms. Willier which was in excess of 120% of the federal rate were $481, $121, $301 and $117. . Imputed income on group term life insurance premiums paid by the Company for Messrs. Higgins, Malquist, Peterson, Ruelle and Harris and Ms. Willier was $222, $707, $855, $186, $365 and $628. . Insurance premiums paid for executive term life policies for Messrs. Malquist, Peterson, Ruelle and Harris and Ms. Willier were $865, $826, $271, $728 and $694. . Mr. Ruelle received a payment of $3,717 from the Company for moving expenses 80 OPTIONS/SAR GRANTS IN LAST FISCAL YEAR The following table shows all grants of options to the named executive officers of SPPC in 1998. Pursuant to Securities and Exchange Commission (SEC) rules, the table also shows the present value of the grant at the date of grant. The exercise price of all options is the market value of the stock as listed on the New York Stock Exchange at the time the options are granted.
- ------------------------------------------------------------------------------------------------------------- Individual Grants (1) - ------------------------------------------------------------------------------------------------------------- Percent of Total Number of Option/SARS Securities Granted to Exercise Underlying Employees of Base Options/SARS in Fiscal Price Expiration Grant Date Name Granted Year ($/sh) Date Present Value (a) (b) (c) (d) (e) (f) (2) - ------------------------------------------------------------------------------------------------------------- Walter M. Higgins 0 0.0% $35.90 1/1/08 $ 0 Malyn K. Malquist 61,000 48.6% $35.90 1/1/08 $275,110 William E. Peterson 9,000 7.2% $35.90 1/1/08 $ 40,590 Mark A. Ruelle 9,000 7.2% $35.90 1/1/08 $ 40,590 Mary Jane L. Willier 5,500 4.4% $35.90 1/1/08 $ 24,805 Randy G. Harris 5,500 4.4% $35.90 1/1/08 $ 24,805 - -------------------------------------------------------------------------------------------------------------
(1) Under the executive long-term incentive plan, the grants of nonqualifying stock options were made on January 1, 1998. One third of these grants vest annually commencing one year after the date of the grant. (2) The hypothetical grant date present values are calculated under the Black- Scholes Model. The Black-Scholes Model is a mathematical formula used to value options traded on stock exchanges. The assumptions used in determining the option grant date present value listed above include the stock's expected volatility (13.2%), risk free rate of return (5.81%), projected dividend yield (4.7%), the stock option term (10 years), and an adjustment for risk of forfeiture during the vesting period (3 years at 3%). No adjustment was made for non-transferability. AGGREGATED OPTION/SAR EXERCISES IN LAST FISCAL YEAR AND FY-END OPTION/SAR VALUES The following table provides information as to the value of the options held by the named executive officers at year end measured in terms of the closing price of Sierra Pacific Resources common stock on December 31, 1998. 81
Number of Securities Value of Unexercised Underlying Unexercised in-the-Money Options/SARS at Fiscal Options/SARS at Fiscal Shares Year-End Year-End Acquired on Value Exercisable/ Exercisable/ Name Exercise Realized Unexercisable Unexercisable (a) (b) (c) (d) (e) - --------------------------------------------------------------------------------------------------------------------------------- Walter M. Higgins 16,402 $161,942 0 / 0 $ 0 / $ 0 Malyn K. Malquist 0 $ 0 12,915 / 72,581 $187,390 / $251,220 William E. Peterson 0 $ 0 12,579 / 17,914 $192,504 / $117,354 Mark A. Ruelle 0 $ 0 2,795 / 14,589 $ 25,851 / $ 70,601 Mary Jane L. Willier 0 $ 0 2,000 / 9,500 $ 18,500 / $ 48,550 Randy G. Harris 0 $ 0 2,000 / 9,500 $ 18,500 / $ 48,550 - ---------------------------------------------------------------------------------------------------------------------------------
(e) Pre-tax gain. Value of in-the-money options based on December 31, 1998 closing trading price of $38.00 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 SPPC. Goals are established for total shareholder return (TSR) compared against the Dow Jones Utility Index and annual growth in earnings per share (EPS). 82 The following table provides information as to the performance shares granted to the named executive officers of Sierra Pacific Power Company in 1998. 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."
Estimated Future Payouts Under Non-Stock Price- Based Plans --------------------------------------------------- Number of Performance Shares, Units or Other Period or Other Until Maturation Name Rights or Payout Threshold $ Target $ Maximum $ (a) (b) (c) (d) (1) (e) (2) (f) (3) - ----------------------------------------------------------------------------------------------------------------------------------- Walter M. Higgins 0 3 years $ 0 $ 0 $ 0 Malyn K. Malquist 4,500 3 years $80,775 $161,550 $282,713 William E. Peterson 1,300 3 years $23,335 $ 46,670 $ 81,673 Mark A. Ruelle 1,300 3 years $23,335 $ 46,670 $ 81,673 Mary Jane L. Willier 800 3 years $14,360 $ 28,720 $ 50,260 Randy G. Harris 800 3 years $14,360 $ 28,720 $ 50,260 - -----------------------------------------------------------------------------------------------------------------------------------
(1) The threshold represents the level of TSR and EPS achieved during the cycle which represents minimum acceptable performance and which, is attained, results in payment of 50% of the target award. Performance below the minimum acceptable level results in no award earned. (2) The target represents the level of TSR and EPS achieved during the cycle which indicates outstanding performance and which, if attained, results in payment of 100% of the target award. (3) The maximum represents the maximum payout possible under the plan and a level of TSR and EPS indicative of exceptional performance which, if attained, results in a payment of 175% of the target award. All levels of awards are made with reference to the price of each performance share at the time of the grant. 83 PENSIONS PLANS The following table shows annual benefits payable on retirement at normal retirement age 65 to elected officers under the Company's defined benefit plans based on various levels of remuneration and years of service which may exist at the time of retirement.
Annual Benefits for Years of Service Indicated Highest Average Five- -------------------------------------------------------------------------------- Years 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
The Company's noncontributory retirement plan provides retirement benefits to eligible employees upon retirement at a specified age. Annual benefits payable are determined by a formula based on years of service and final average earnings consisting of base salary and incentive compensation. Remuneration for the named executives is the amount shown under "Salary" and "Incentive Pay" in the "Summary Compensation Table. Pension costs of the retirement plan to which the Company 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 Company has entered into an arrangement with Mr. Peterson crediting him with four years of service for prior years of service with his previous employer, most of which was dedicated to performing legal services for SPR and SPPC, and an additional one-half year credit for each year of service with the Company for the first ten years of his employment. Years of credited service for Messrs. Malquist, Peterson, Ruelle and Harris and Ms. Willier are 4.6, 10.8, .8, 23.6 and .9, respectively. A supplemental executive retirement plan (SERP) and an excess plan are also offered to the named executive officers. The SERP is intended to ensure the payment of a competitive level of retirement income to attract, retain and motivate selected executives. The excess plan is intended to provide benefits to executive officers whose pension benefits under the Company's retirement plan are limited by law to certain maximum amounts. SEVERANCE ARRANGEMENTS Individual severance allowance plans exist for the named executive officers which provide for severance pay, payable in a lump sum or by purchase of an annuity, if within three 84 years after a change in control of the Company, there is a termination of employment by the Company 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 the Company'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 the Company is not the surviving corporation, the sale of all or substantially all the assets of the company (not the sale of a work unit) or the acquisition by any person or entity of 30% or more of the voting power of the Company. In addition, several merger-related and merger-conditioned severance arrangements have been entered into between the Company and several executives, which are described in the section titled Certain Relationships and Related Transactions. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT Voting Stock SPR owns 100 percent of the voting stock of SPPC. 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 10, 1999 March 10, 1999 - ------------------------------------- ------------------------- -------------------------------------- Edward P. Bliss 14,419 Krestine M. Corbin 10,172 Theodore J. Day 20,613 Harold P. Dayton, Jr. 12,583 James R. Donnelley 18,840 No director or nominee Richard N. Fulstone 14,845 for director owns in excess Walter M. Higgins (1) 100 of one percent. Malyn K. Malquist 43,243 James L. Murphy 10,318 Ronald K. Remington 8,338 Dennis E. Wheeler 9,250 Robert B. Whittington 13,214 ------------------------- 175,935 =========================
85
Common Shares Beneficially Percent of Total Common Owned as of Shares Outstanding as of Executive Officers March 10, 1999 March 10, 1999 - -------------------------------------- -------------------------- ------------------------------------ Walter M. Higgins (1) 100 Malyn K. Malquist 43,243 William E. Peterson 22,451 No executive officer owns Mark A. Ruelle 10,022 in excess of one percent Mary Jane L. Willier 6,318 Randy G. Harris 8,803 -------------------------- 90,937 ========================== All directors and executive officers 297,719 as a group (a) (b) (c) ==========================
(1) Mr. Higgins resigned from his position of Chairman, President and Chief Executive Officer on January 14, 1998. (a) Includes shares acquired through participation in the Employee stock Purchase Plan and/or the 401(k) plan. (b) The number of shares beneficially owned includes shares which the Executive Officers currently have the right to acquire pursuant to stock options granted and performance shares earned under the Executive Long-Term Incentive Plan. Share beneficially owned pursuant to stock options granted to Messrs. Higgins, Malquist, Peterson, Ruelle, Harris, Ms. Willier, and all directors and executive officers as a group are -0-, 37,915, 18,913, 8,589, 5,833, 5,833 and 98,241 shares, respectively. Shares beneficially owned as a result of performance shares earned by Messrs. Higgins, Malquist, Peterson, Ruelle, Harris, Ms. Willier, and all directors and officers as a group are 0, 1,156, 592, 494, 259, 400, and 1,965, respectively. (c) Included in the shares beneficially owned by the Directors are 71,737 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 SPR has entered to an agreement with Hale Day Gallagher Co., a real estate brokerage and investment company, to act as broker for the sale of a property owned by Lands of Sierra, Inc., a subsidiary of SPR. The eventual sale of the property will result in Hale Day Gallagher Co. receiving a standard brokerage commission not to exceed 5% of the selling price. Mr. T.J. Day, a senior partner of Hale Day Gallagher Co. and a Director of the Company, has no relationship with, or interest in, the transaction, will receive no part of the commission, and will receive no direct or indirect benefit from the transaction. Mr. Peterson, formerly a partner with the law firm of Woodburn and Wedge, became Senior Vice President and General Counsel for Sierra Pacific Resources in 1993. Woodburn and 86 Wedge, which has performed legal services for Sierra Pacific Power Company since 1920 and for Sierra Pacific Resources and all of its subsidiaries from their inception, continues to perform legal work for the Company. Mr. Peterson's spouse, an equity partner in the firm since 1982, has performed work for the Company since 1976 and continues to do so from time to time. Susan Oldham, a former employee of SPPC specializing in water resources law, planning and policy accepted the Company's voluntary severance offering in December 1995. Ms. Oldham is the spouse of Steven C. Oldham, Vice President Transmission Business Group and Strategic Development for Sierra Pacific Power Company. Ms. Oldham, a licensed attorney in Nevada and California, has continued to perform specialized legal services in the water resources area for the Company on a contract basis. In April 1994, Mr. Malquist, who was elected President and Chief Executive Officer on January 13, 1998, received a $92,000 interest-free loan related to his employment arrangement with the Company. The loan is payable in four equal annual installments. Any installment due on any anniversary date on which Mr. Malquist is employed by the Company will be discharged by the Company in consideration for services rendered during the previous year. CHANGE IN CONTROL AGREEMENT SPR has entered into severance agreements with certain key executives, including the individuals named in the Summary Compensation Table. These agreements provide that, upon termination of the executive's employment within twenty-four months following a change in control of SPR (as defined in the agreements) either (a) by SPR for reasons other than cause (as defined in the agreements), death or disability, or (b) by the executive for good reason (as defined by the agreement, including a diminution of responsibilities, compensation, or benefits (unless, with respect to reduction in salary or benefits, such reduction is applicable to all senior executives of the Company and the acquirer)), the executive will receive certain payments and benefits. These severance payments and benefits include (i) a lump sum payment equal to three times the sum of the executive's base salary and target bonus, (ii) a lump sum payment equal to the present value of the benefits the executive would have received had be continued to participate in the Company's retirement plans for an additional 3 years (or, in the case of the Company's Supplemental Executive Retirement Plan only, the greater of three years or the period from the date of termination until the executive's early retirement date, as defined in such plan), and (iii) continuation of life, disability, accident and health insurance benefits for a period of thirty-six (36) months immediately following termination of employment. Except for Mr. Malquist, 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. In the case of Mr. Malquist, the agreement provides that SPR will pay an additional amount to hold him harmless from such tax. The Board of Directors entered into these agreements in order to attract and retain excellent management and to encourage and reinforce continued attention to the executives' assigned duties without distraction under circumstances arising from the possibility of a change in control of SPR. In entering into these agreements, the Board was advised by 87 Towers Perrin, the national compensation and benefits consulting firm described above, and Skadden, Arps, Slate, Meager & 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. 88 PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K (a) Financial Statements, Financial Statement Schedules and Exhibits
Page ---- 1. Financial Statements: Report of Independent Auditors........................... 47 Consolidated Balance Sheets as of December 31, 1998 and 1997............................. 2 Consolidated Statements of Income for the Years Ended December 31, 1998, 1997 and 1996................. 2 Consolidated Statements of Common Shareholder's Equity for the Years Ended December 31, 1998, 1997 and 1996... 2 Consolidated Statements of Cash Flows for the Years Ended December 31, 1998, 1997 and 1996........... 2 Consolidated Statements of Capitalization as of December 31, 1998 and 1997............................. 2 Notes to Consolidated Financial Statements............... 53-73 2. Financial Statement Schedules: Report of Independent Auditors........................... 91 Schedule II-Valuation and Qualifying Accounts............ 92
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 93-100 (b) Reports on Form 8-K None. 89 SIGNATURES ---------- Pursuant to the requirements of Section 13 and 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. SIERRA PACIFIC POWER COMPANY By: /s/ Malyn K. Malquist ------------------------ Malyn K. Malquist President and Chief Executive Officer March 19, 1999 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on the 19th day of March, 1999. /s/ Mark A. Ruelle /s/ Mary O. Simmons - ------------------------------------- ------------------------------------- Mark A. Ruelle Mary O. Simmons Senior Vice President, Controller Chief Financial Officer and Treasurer (Principal Accounting Officer) (Principal Financial Officer) /s/ Edward P. Bliss /s/ James L. Murphy - ------------------------------------- ------------------------------------ Edward P. Bliss James L. Murphy Director Director /s/ Krestine M. Corbin /s/ Ronald K. Remington - ------------------------------------- ------------------------------------ Krestine M. Corbin Ronald K. Remington Director Director /s/ Theodore J. Day /s/ Dennis E. Wheeler - ------------------------------------- ------------------------------------- Theodore J. Day Dennis E. Wheeler Director Director /s/ Harold P. Dayton, Jr. /s/ Robert B. Whittington - ------------------------------------- ------------------------------------- Harold P. Dayton, Jr. Robert B. Whittington Director Director /s/ James R. Donnelley /s/ Malyn K. Malquist - ------------------------------------- ------------------------------------- James R. Donnelley Malyn K. Malquist Director Director /s/ Richard N. Fulstone - ------------------------------------- Richard N. Fulstone Director
90 INDEPENDENT AUDITORS' REPORT To the Board of Directors and Stockholder of Sierra Pacific Power Company Reno, Nevada We have audited the consolidated financial statements of Sierra Pacific Power Company and subsidiaries as of December 31, 1998 and 1997, and for each of the three years in the period ended December 31, 1998, and have issued our report thereon dated January 29, 1999 (February 12, 1999 as to Notes 1 and 3). Our audits also included the financial statement schedule listed in the table of contents on page 89. This financial statement schedule is the responsibility of the Corporation's management. Our responsibility is to express an opinion based on our audits. In our opinion, such financial statement schedule, when considered in relation to the basic financial statements taken as a whole, present fairly in all material respects the information set forth therein. DELOITTE & TOUCHE LLP Reno, Nevada February 12, 1999 91 Sierra Pacific Power Company Schedule II - Valuation and Qualifying Accounts For The Years Ended December 31, 1998, 1997 and 1996 (Dollars in Thousands)
Provision for Uncollectible Accounts -------------- Balance at January 1, 1996 $ 1,543 Provision charged to income 1,880 Amounts written off, less recoveries (1,227) -------------- 2,196 Balance at January 1, 1997 2,196 Provision charged to income 1,411 Amounts written off, less recoveries (1,903) -------------- 1,704 Balance at January 1, 1998 1,704 Provision charged to income 3,686 Amounts written off, less recoveries (1,929) -------------- $ 3,461 --------------
92 SIERRA PACIFIC POWER COMPANY 1998 FORM 10-K EXHIBIT INDEX Exhibits filed with this Form 10-K are denoted with an asterisk (*). The other listed exhibits have been previously filed with the Securities and Exchange Commission and are incorporated herein by reference. (3) . Restated Articles of Incorporation of the Company dated May 19, 1987 (originally filed as Exhibit (3)(A) to the 1987 Form 10-K - refiled as Exhibit (3)(A) to the 1993 Form 10-K) . Certificate of Amendments dated August 26, 1992 to Restated Articles of Incorporation of the Company dated May 19, 1987, in connection with the Company's preferred stock (Exhibit 3.1 to Form 8-K dated August 26, 1992) . Certificate of Designation, Preferences and Rights dated August 31, 1992 to Restated Articles of Incorporation of the Company dated May 19, 1987, in connection with the Company's Series C Preferred Stock (Exhibit 4.1 to Form 8-K dated August 26, 1992) . Certificate of Designation, Preferences and Rights dated August 31, 1992 to Restated Articles of Incorporation of the Company dated May 19, 1987, in connection with the Company's Series G Preferred Stock (Exhibit 4.2 to Form 8-K dated August 26, 1992) . Certificate of Designation, Preferences and Rights dated August 31, 1992 to Restated Articles of Incorporation of the Company dated May 19, 1987, in connection with the Company's Class A Series 1 Preferred Stock (Exhibit 4.3 to Form 8-K dated August 26, 1992) . By-laws of the Company, as amended through June 30, 1988 (Exhibit (3)(A) to the 1989 Form 10-K) . Articles of Incorporation of Pinon Pine Corp., dated December 11, 1995 (Exhibit (3)(A) to the 1995 Form 10-K) . Articles of Incorporation of Pinon Pine Investment Co., dated December 11, 1995 (Exhibit (3)(B) to the 1995 Form 10-K) . 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 (Exhibit (3)(C) to the 1995 Form 10-K) . By-laws of the Company, in its entirety, as amended through November 13, 1996 (Exhibit (3)(A) to the 1996 Form 10-K) 93 (4) . Mortgage Indentures of the Company defining the rights of the holders of the Company's First Mortgage Bonds: Original Indenture (Exhibit 7-A to Registration No. 2-7475); Ninth Supplemental Indenture (Exhibit 2-M to Registration No. 2-59509); Tenth Supplemental Indenture (Exhibit 4-K to Registration No. 2-23932); Eleventh Supplemental Indenture (Exhibit 4-L to Registration No. 2- 26552); Twelfth Supplemental Indenture (Exhibit 4-Lto Registration No. 2-36982); Sixteenth Supplemental Indenture (Exhibit 2-Y to Registration No. 2-53404); Nineteenth Supplemental Indenture (originally filed as Exhibit (2)(B) to the 1978 Form 10-K - refiled as Exhibit (4)(A) to the 1991 Form 10-K; Twentieth Supplemental Indenture (originally filed as Exhibit (2)(C) to the 1978 Form 10-K-refiled as Exhibit (4)(B) to the 1991 Form 10-K); Twenty- Seventh Supplemental Indenture (Exhibit (4)(A) to the 1989 Form 10-K); Twenty-Eighth Supplemental Indenture (Exhibit (4)(A) to the 1992 Form 10-K); Twenty-Ninth Supplemental Indenture (Exhibit D to Form 8-K dated July 15, 1992 in connection with the Company's medium-term note program); Thirtieth Supplemental Indenture (Exhibit (4)(B) to the 1992 Form 10-K); Thirty-First Supplemental Indenture (Exhibit (4)(C) to the 1992 Form 10-K); Thirty-Second Supplemental Indenture (Exhibit 4.6 to Registration No.99-69550); Thirty-Third Supplemental Indenture (Exhibit C to Form 8-K dated October 20, 1993 in connection with the Company's medium-term note program) . Collateral Trust Indenture dated June 1, 1992 between the Company and Bankers Trust Company, as Trustee, relating to the Company's medium-term Note program (Exhibit B to Form 8-K dated July 15, 1992 in connection with the Company's medium-term note program) . First Supplemental Indenture dated June 1, 1992 to Collateral Trust Indenture dated June 1, 1992 between the Company and Bankers Trust Company, as Trustee, relating to the Company's medium-term note program (Exhibit C to Form 8-K dated July 15, 1992 in connection with the Company's medium-term note program) . Second Supplemental Indenture dated October 1, 1993 to Collateral Trust Indenture dated June 1, 1992 between the Company and Bankers Trust Company, as Trustee, relating to the Company's medium-term note program (Exhibit B to Form 8-K dated October 20, 1993 in connection with the Company's medium-term note program) . Form of Medium-Term Global Floating Rate Note, Series A (Exhibit E to Form 8-K dated July 15, 1992 in connection with the Company's medium-term note program) . Form of Medium-Term Global Floating Rate Note, Series B (Exhibit D to Form 8-K dated October 20, 1993 in connection with the Company's medium-term note program) 94 (4) - Continued . Distribution Agreement to final forms of exhibits to the Company's Registration Statement (No. 333-1374) in connection with its offering of $80 million of Collateralized Debt Securities (the Debt Securities) subsequently referred to as Series C Medium Term Notes and Collateralized Debt Securities. (Exhibit A on Form 8-K dated March 11, 1996). . Third Supplemental Indenture dated as of February 1, 1996 to Collateral Trust Indenture dated as of June 1, 1992 between the Company and Bankers Trust Company, as Trustee, relating to the Company's Medium Term Note Program. (Exhibit B to Form 8-K dated March 11, 1996). . Thirty-fourth Supplemental Indenture dated as of February 1, 1996 to Indenture of Mortgage dated as of December 1, 1940 defining the rights of the Company's First Mortgage Bonds. (Exhibit C to Form 8- K dated March 11, 1996). . Form of Medium-Term Global Fixed Rate Note, Series C. (Exhibit D to Form 8-K dated March 11, 1996). . Amended and Restated Declaration of Trust of Sierra Pacific Power Capital I (the Trust) dated July 24, 1996 in connection with the offering of the Preferred Securities of the Trust. (Exhibit 4.1 Form 8-K dated August 2, 1996) . Indenture between the Company and IBJ Schroder Bank and Trust Company as Trustee dated July 1, 1996 in connection with the offering of the Preferred Securities of the Trust. (Exhibit 4.2 Form 8-K dated August 2, 1996) . First Supplemental Indenture to the Indenture used in connection with the issuance of Junior Subordinated Debentures dated July 24, 1996 in connection with the offering of the Preferred Securities of the Trust. (Exhibit 4.3 Form 8-K dated August 2, 1996). . Guarantee with respect to Preferred Securities dated July 29, 1996 in connection with the offering of the Preferred Securities of the Trust. (Exhibit 4.4 Form 8-K dated August 2, 1996). . Guarantee with respect to Common Securities dated July 29, 1996 in connection with the offering of the Preferred Securities of the Trust. (Exhibit 4.5 Form 8-K dated August 2, 1996). . Form of medium-term Global Fixed Rate Note, Series D. (Exhibit D to Form 8-K dated March 10, 1997. 95 (10) . Coal Sales Agreement dated May 16, 1978 between the Company and Coastal States Energy Company (confidential portions omitted and filed separately with the Securities and Exchange Commission) (Exhibit 5-GG to Registration No. 2-62476) . Amendment No. 1 dated November 8, 1983 to Coal Sales Agreement dated May 16, 1978 between the Company and Coastal States Energy Company (originally filed as Exhibit (10)(B) to the 1983 Form 10-K -refiled as Exhibit (10)(B) to the 1991 Form 10-K) . Amendment No. 2 dated February 25, 1987 to Coal Sales Agreement dated May 16, 1978 between the Company and Coastal States Energy Company (originally filed as Exhibit (10)(G) to the 1986 Form 10-K as amended by Form 8 filed May 19, 1987 -refiled as Exhibit (10)(A) to the 1993 Form 10-K) . Amendment No. 3 dated May 8, 1992 to Coal Sales Agreement dated May 16, 1978 between the Company and Coastal States Energy Company (Exhibit (10)(B) to the 1992 Form 10-K; confidential portions omitted and filed separately with the Securities and Exchange Commission) . Coal Purchase Contract dated June 19, 1986 between the Company, Black Butte Coal Company and Idaho Power Company (originally filed as Exhibit (10)(B) to the 1986 Form 10-K - refiled as Exhibit (10)(C) to the 1992 Form 10-K) . Settlement Agreement and Mutual Release dated May 8, 1992 between the Company and Coastal States Energy Company (Exhibit (10)(D) to the 1992 Form 10-K; confidential portions omitted and filed separately with the Securities and Exchange Commission) . Interconnection Agreement dated May 29, 1981 between the Company and Idaho Power Company (originally filed as Exhibit (10)(A) to the 1981 Form 10-K -refiled as Exhibit (10)(C) to the 1991 Form 10-K) . Amendatory Agreement dated February 14, 1992 to Interconnection Agreement dated May 29, 1981 between the Company and Idaho Power Company (Exhibit (10)(D) to the 1991 Form 10-K) . Agreement dated February 23, 1989 between the Company and Idaho Power Company for the supply of power and energy (Exhibit (10)(A) to the 1988 Form 10-K) . Cooperative Agreement dated July 31, 1992 between the Company and the United States Department of Energy in connection with the Pinon Pine Integrated Coal Gasification Combined Cycle Project (Exhibit (10)(H) to the 1992 Form 10-K) 96 (10) - Continued . Revised Intercompany Pool Agreement dated July 19, 1982 pertaining to the Company's membership (originally filed as Exhibit (10)(C) to the 1982 Form 10-K- refiled as Exhibit (10)(E) to the 1991 Form 10- K) . Agreement dated November 7, 1986 between the Company and Western Systems Power Pool (Exhibit (10)(C) to the 1988 Form 10-K) . Memorandum dated October 1, 1988 to Agreement dated November 7, 1986 between the Company and Western Systems Power Pool (Exhibit (10)(D) to the 1988 Form 10-K) . General Transfer Agreement dated February 25, 1988 between the Company and the United States of America Department of Energy acting by and through the Bonneville Power Administration (Exhibit (10)(E) to the 1988 Form 10-K) . Rail Transportation Contract dated June 30, 1986 between the Company and Idaho Power Company as shippers and Union Pacific and Western Pacific Railroad Companies as carriers (originally confidentially filed as Exhibit (10)(H) to the 1986 Form 10-K as amended by Form 8 filed May 19, 1987 - refiled as Exhibit (10)(C) to the 1993 Form 10-K) . Addendum dated October 9, 1993 to Rail Transportation Contract dated June 30, 1986 between the Company and Idaho Power Company as shippers and Union Pacific Railroad Companies as carriers (Exhibit (10)(D) to the 1993 Form 10-K) . Financing Agreement dated March 1, 1987 between the 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 (originally filed as Exhibit (10)(C) to the 1987 Form 10-K - refiled as Exhibit (10)(E) to the 1993 Form 10-K) . Financing Agreement dated March 1, 1987 between the 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 (originally filed as Exhibit (10)(E) to the 1987 Form 10-K-refiled as Exhibit (10)(F) to the 1993 Form 10-K) . Financing Agreement dated June 1, 1987 between the 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 (originally filed as Exhibit (10)(G) to the 1987 Form 10-K - refiled as Exhibit (10)(G) to the 1993 Form 10-K) 97 (10) - Continued . Financing Agreement dated December 1, 1987 between the 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 (originally filed as Exhibit (10)(I) to the 1987 Form 10-K - refiled as Exhibit (10)(H) to the 1993 Form 10-K) . Financing Agreement dated September 1, 1990 between the Company and Washoe County, Nevada relating to the Washoe County, Nevada Gas Facilities Revenue Bonds (Sierra Pacific Power Company Project) Series 1990 (Exhibit (10)(C) to the 1990 Form 10-K) . Financing Agreement dated December 1, 1990 between the Company and Washoe County, Nevada relating to the Washoe County, Nevada Water Facilities Revenue Bonds (Sierra Pacific Power Company Project) Series 1990 (Exhibit (10)(E) to the 1990 Form 10-K) . First Amendment dated August 12, 1991 to Financing Agreement dated December 1, 1990 between the Company and Washoe County, Nevada relating to the Washoe County, Nevada Water Facilities Revenue Bonds (Sierra Pacific Power Company Project) Series 1990 (Exhibit (10)(J) to the 1991 Form 10-K) . Letter of Credit, Reimbursement and Security Agreement dated December 12, 1990 between the Company and Union Bank of Switzerland relating to the Washoe County, Nevada Water Facilities Revenue Bonds (Sierra Pacific Power Company Project) Series 1990 (Exhibit (10)(F) to the 1990 Form 10-K) . Financing Agreement dated June 1, 1993 between the Company and Washoe County, Nevada relating to the Washoe County, Nevada Water Facilities Refunding Revenue Bonds (Sierra Pacific Power Company Project) Series 1993A (Exhibit (10) (I) to the 1993 Form 10-K) . Financing Agreement dated June 1, 1993 between the 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 (Exhibit (10) (J) to the 1993 Form 10-K) . Credit Agreement dated January 3, 1995 by and among the Company, The Lenders Parties hereto from time to time and Mellon Bank, N.A., as Agent. (Exhibit (10)(A) to the 1994 Form 10-K) . Agreement dated May 1, 1991 between the Company and the Inter- national Brotherhood of Electrical Workers (Exhibit (10)(K) to the 1991 Form 10-K) 98 (10) - Continued . Ratified changes to the Agreement between the Company and the International Brotherhood of Electrical Workers dated October 31, 1994 (Exhibit (10)(B) to the 1994 Form 10-K) . Lease dated January 30, 1986 between the Company and Silliman Associates Limited Partnership relating to the Company's corporate headquarters building (originally filed as Exhibit (10)(C) to the 1986 Form 10-K - refiled as Exhibit (10)(I) to the 1992 Form 10-K) . Letter of Amendment dated May 18, 1987 to Lease dated January 30, 1986 between the Company and Silliman Associates Limited Partnership relating to the Company's corporate headquarters building (Exhibit (10)(L) to the 1987 Form 10-K- refiled as Exhibit (10) (K) to the 1993 Form 10-K) . Natural gas Transportation Service Agreement, dated January 11, 1995 between the Company and Tuscarora Gas Transmission Company (Filed with 1995 Form 10-K) . Fixed-Price Turn-Key Construction Agreement, dated December 15, 1995 between the Company and Pinon Pine Company, L.L.C (Filed with 1995 Form 10-K) . Operation and Maintenance Agreement, dated December 15, 1995 between the Company and Pinon Pine Company, L.L.C. (Filed with 1995 Form 10-K) . Syngas Purchase Agreement, dated December 15, 1995 between the Company and Pinon Pine Company, L.L.C. (Filed with 1995 Form 10-K) . The Amended and Restated Nonqualified Deferred Compensation Plan in which any director or any executive officer of the Company may participate. The Plan was amended and restated January 1, 1996 (Filed with 1996 Form 10-K) . Distribution Agreement related to the Company's offering of $35 million Collateralized Medium-term Notes, Series D (Exhibit A on Form 8-K, dated March 10, 1997) . Change in Control Agreement dated February 18, 1997 by and among Sierra Pacific Resources and the following officers (individually): Gerald W. Canning, Jeffrey L. Ceccarelli, Randy G. Harris, Malyn K. Malquist, Steven C. Oldham, Victor H. Pena, William E. Peterson, Mark A. Ruelle, Mary O. Simmons, Doug Ponn, and Mary Jane Willier. . Agreement dated January 1, 1998 between the Company and the International Brotherhood of Electrical Workers. (Filed with 1997 Form 10-K) . Notice of Termination of Power Purchase from PacifiCorp under the Interconnection Agreement of May 19, 1971. 99 (11) . The Company is a wholly owned subsidiary and, in accordance with Paragraph 6 of SFAS No. 128 (Earnings Per Share), earnings per share data have been omitted. (12) (A) . Calculation of Pre-Tax Interest Coverages for the Periods 1998, 1997 and 1996. (16) . Letter from Coopers & Lybrand L.L.P. dated November 21, 1996 regarding the change in certifying accountants. (Exhibit filed with Form 8-K/A dated November 22, 1996) (21) . Subsidiaries of the Registrant: Pinon Pine Company Pinon Pine Investment Company Sierra Pacific Power Capital Trust I (The Trust) (23) . Consent of Independent Auditors in connection with the Registration Statement of Sierra Pacific Power Company (File No. 333-17041), regarding its issuance of Series D Medium-Term Notes. (Filed with 1997 10-K) (27) *(A) The Financial Data Schedule containing summary financial information extracted from the consolidated financial statements filed on Form 10-K from the twelve month period ending December 31, 1998. 100 PURCHASE AND SALE AND ASSIGNMENT AND ASSUMPTION AGREEMENT DATED AS OF FEBRUARY 9, 1999 BY AND BETWEEN GENERAL ELECTRIC CAPITAL CORPORATION AND SIERRA PACIFIC POWER COMPANY
TABLE OF CONTENTS Page ARTICLE I..........................................................................................................2 1.1 General 2 1.2 Definitions................................................................................................2 1.3 Interpretation.............................................................................................5 ARTICLE II.........................................................................................................5 PURCHASE AND SALE AND ASSIGNMENT AND ASSUMPTION..................................................................5 2.1 Purchase and Sale and Assignment..........................................................................5 2.2 Payment of the Purchase Price.............................................................................5 2.3 Assumption................................................................................................5 ARTICLE III........................................................................................................6 REPRESENTATIONS AND WARRANTIES OF SELLER.........................................................................6 3.1 Corporate Status; Authority of Seller; Enforceability.....................................................6 3.2 Documents.................................................................................................7 3.3 Liens 7 3.4 Assignment................................................................................................7 3.5 Compliance with Laws......................................................................................7 3.6 Litigation................................................................................................7 3.7 Bankruptcy................................................................................................7 3.8 Personnel Identification..................................................................................8 3.9 Capitalization; Subsidiaries..............................................................................8 3.10 Title to Purchased Shares.................................................................................8 3.11 Tax Matters...............................................................................................8 3.12 Real Property............................................................................................10 3.13 Consents 10 3.14 Broker's or Consultant's Fees............................................................................10 3.15 Banking Arrangements.....................................................................................10 3.16 Powers of Attorney.......................................................................................10 3.17 Loans 10 ARTICLE IV........................................................................................................11 REPRESENTATIONS AND WARRANTIES OF PURCHASER.....................................................................11 4.1 Corporate Status.........................................................................................11 4.2 Due Authorization........................................................................................11 4.3 Authority of Purchaser...................................................................................11 4.4 Enforceability...........................................................................................11 4.5 Consents 11 4.6 Broker's or Consultant's Fees............................................................................11
-cii- ARTICLE V.........................................................................................................12 COVENANTS.......................................................................................................12 5.1 Required Filings.........................................................................................12 5.2 Pre-Closing Taxes........................................................................................12 5.3 Tax Reports; Returns.....................................................................................12 5.4 Optional Section 338(h)(10) Elections....................................................................12 5.5 Further Assurance........................................................................................13 ARTICLE VI........................................................................................................13 CONDITIONS PRECEDENT TO PURCHASER'S OBLIGATIONS.................................................................13 6.1 Obligations to be Satisfied on or Prior to Closing Date..................................................13 ARTICLE VII.......................................................................................................14 CONDITIONS PRECEDENT TO SELLER'S OBLIGATIONS....................................................................14 7.1 Obligations to Be Satisfied on or Prior to Closing Date..................................................14 ARTICLE VIII......................................................................................................15 CLOSING.........................................................................................................15 8.1 Time and Place...........................................................................................15 8.2 Closing Transactions.....................................................................................15 8.3 Deliveries by Seller to Purchaser........................................................................15 8.4 Deliveries by Purchaser to Seller........................................................................16 ARTICLE IX........................................................................................................16 INDEMNIFICATION...............................................................................................16 9.1 Indemnification by Seller................................................................................16 9.2 Indemnification by Purchaser.............................................................................17 9.3 Procedure for Indemnification............................................................................18 9.4 Payment 18 ARTICLE X.........................................................................................................18 MISCELLANEOUS PROVISIONS........................................................................................18 10.1 Post-Closing Deliveries..................................................................................18 10.2 Notices 19 10.3 Assignment...............................................................................................19 10.4 Benefit of the Agreement.................................................................................20 10.5 Exhibits and Schedules...................................................................................20 10.6 Headings 20 10.8 Modifications and Waivers................................................................................20 10.9 Counterparts.............................................................................................20 10.10 Severability.............................................................................................20 10.11 GOVERNING LAW............................................................................................20
-ciii- 10.12 Expenses 21 10.13 Tax Consequences.........................................................................................21
EXHIBIT - ------- Exhibit A Form of Withholding Certificate -civ- PURCHASE AND SALE ----------------- AND ASSIGNMENT AND ASSUMPTION AGREEMENT --------------------------------------- THIS PURCHASE AND SALE AND ASSIGNMENT AND ASSUMPTION AGREEMENT is entered into as of this 9th day of February, 1999, by and between SIERRA PACIFIC POWER COMPANY, a Nevada corporation (together with its successors and permitted assigns, "Purchaser"), and GENERAL ELECTRIC CAPITAL CORPORATION, a New York --------- corporation (together with its successors and permitted assigns, "Seller"). ------ RECITALS -------- WHEREAS, Purchaser and Seller are parties to that certain Membership Interest Acquisition Agreement dated as of December 15, 1995 (the "Membership ---------- Interest Acquisition Agreement") together with Pinon Pine Corp., a Nevada - ------------------------------ corporation ("Member A1"), Pinon Pine Investment Co., a Nevada corporation --------- ("Member A2") (collectively, Member A1 and Member A2 shall be referred to as the - ----------- "A Members"), and GPSF-B Inc., a Delaware corporation ("Member B"), pursuant to --------- -------- which (a) each of Purchaser and Seller made certain contributions of tangible and intangible property to the A Members and to Member B, respectively, in exchange for the issuance of shares of the capital stock of the A Members and Member B, respectively, and (b) each of the A Members and Member B made certain contributions of tangible and intangible property to Pinon Pine Company, L.L.C., a Delaware limited liability company (the "Company"), in exchange for their ------- respective interests in the Company; WHEREAS, the Company was formed pursuant to that certain Agreement of Limited Liability Company of Pinon Pine Company, L.L.C. dated as of December 15, 1995 (the "LLC Agreement") by and among the A Members and Member B for the ------------- purpose of owning and operating the Facility; WHEREAS, Purchaser and the Company have entered into that certain Fixed- Price Turn-Key Construction Agreement dated as of December 15, 1995 (the "Construction Agreement") pursuant to which Purchaser agreed to construct and - ----------------------- start-up the Facility; WHEREAS, Purchaser has failed to complete the construction of the Facility before June 30, 1998 to the satisfaction of Member B as required by Section 4.3 ----------- of the Construction Agreement and the Company's sole remedy is to cause Purchaser to acquire the Facility; WHEREAS, in lieu of acquiring the Facility, Purchaser desires to exercise its option under Section 4.3(a) of the Construction Agreement to acquire the -------------- stock of Member B; WHEREAS, Member B is in the business of holding a membership interest in the Company ("Member B's Interest") (the "Business"); ------------------- -------- WHEREAS, Seller owns, through GE Capital Services Structured Finance Group, Inc., a Delaware corporation and a wholly-owned subsidiary of Seller ("GESFG"), ----- all of the issued and outstanding shares of capital stock of Member B, consisting of 1,000 shares of common stock, $1.00 par value (the "Shares"); ------ WHEREAS, Purchaser desires to acquire from Seller and Seller desires to sell and transfer to Purchaser, the Investor Interest (excluding the Reserved Rights (each as defined in Section 1.2 hereof)), all subject to the terms and ----------- conditions set forth below; NOW, THEREFORE, in consideration of the foregoing Recitals and the mutual agreements and covenants contained herein, and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, Purchaser and Seller hereby agree as follows: ARTICLE I --------- DEFINITIONS ----------- I.1 General. Each term defined in the first paragraph of this Agreement ------- and in the Recitals shall have the meaning set forth above whenever used herein, unless otherwise expressly provided or unless the context clearly requires otherwise. I.2 Definitions. As used herein, the following terms shall have the ----------- meanings ascribed to them in this Section 1.2 or, to the extent not defined in ----------- this Section 1.2, in Appendix A to the Membership Interest Acquisition ----------- Agreement: A Members. As defined in the Recitals hereto. --------- Adverse Consequences. All allegations, charges, complaints, actions, -------------------- suits, proceedings, hearings, investigations, claims, demands, judgments, orders, decrees, stipulations, injunctions, damages, dues, penalties, fines, costs, amounts paid in settlement, Liabilities, Taxes, interest, Liens, losses, expenses and fees, including all accounting, consultant and attorneys' fees and court costs, costs of expert witnesses and other expenses of litigation. Affiliate. As set forth in Rule 12b-2 of the regulations promulgated --------- under the Securities Exchange Act of 1934. Agreement. This Purchase and Sale and Assignment and Assumption --------- Agreement, together with all Exhibits and Schedules referred to herein, as amended, modified or supplemented from time to time in accordance with the terms hereof. Authority. Any governmental, regulatory or administrative body, --------- agency or authority, any court of judicial authority, any arbitrator or any public, private or industry regulatory authority, whether foreign, federal, state or local. Business. As defined in the Recitals hereto. -------- -2- Closing. The actual conveyance, transfer, assignment and delivery of ------- the Investor Interest to Purchaser in exchange for the consideration payable to Seller pursuant to this Agreement. Closing Date. Friday, February 12, 1999, or such other date as ------------ Purchaser and the Seller may mutually agree in writing, in either case, upon which the Closing shall occur. Code. Internal Revenue Code of 1986. ---- Company. As defined in the Recitals hereto. ------- Construction Agreement. As defined in the Recitals hereto. ---------------------- HSR Act. The Hart-Scott-Rodino Antitrust Improvements Act of 1976, ------- as amended. Indemnified Party. As defined in Section 9.3. ----------------- ----------- Indemnifying Party. As defined in Section 9.3. ------------------ ----------- Investor Interest (i) All of the Seller's and GESFG's right, title ----------------- and interest in the Shares, (ii) all of Seller's rights as Investor in, to and under the Documents (other than the Reserved Rights) and (iii) all of Seller's obligations as Investor under the Documents to the extent arising or to be performed on or after the Closing Date. IRS. Internal Revenue Service. --- Law. Any law, statute, regulation, rule, ordinance, requirement, --- announcement or other binding action or requirement of an Authority. Liabilities. Any obligation or liability (whether known or unknown, ----------- whether asserted or unasserted, whether absolute or contingent, whether accrued or unaccrued, whether liquidated or unliquidated and whether due or to become due), including, without limitation, any liability for Taxes. Lien. Any lien (statutory or other), mortgage, pledge, hypothecation, ---- assignment, deposit arrangement, encumbrance or preference, priority or security agreement or preferential arrangement of any kind or nature whatsoever (including, without limitation, the interest of a vendor or lessor under any conditional sale, capitalized lease or other title retention agreement). LLC Agreement. As defined in the Recitals hereto. ------------- Member A1. As defined in the Recitals hereto. --------- -3- Member A2. As defined in the Recitals hereto. --------- Member B. As defined in the Recitals hereto. -------- Member B's Interest. As defined in the Recitals hereto. ------------------- Membership Interest Acquisition Agreement. As defined in the ----------------------------------------- Recitals hereto. Order. Any decree, order, judgment, writ, award, injunction, ----- stipulation or consent of or by an Authority. Ordinary Course of Business. The ordinary course of business of --------------------------- Member B in accordance with past custom and practice (including with respect to quantity and frequency). Person. Any natural person, corporation, limited liability company, ------ partnership, firm, joint venture, joint-stock company, trust, association, Authority, unincorporated entity or organization of any kind. Prior Claim. Any Claim, indemnity or other right to payment that ----------- Seller may have as "Investor" under the Documents or as owner of the Shares, to the extent such Claim accrues, arises from or relates to any period prior to the Closing Date, whether known or unknown, contingent or otherwise; it being understood that any such Claim, indemnity or other right to payment arising from any payment or performance obligation under any Documents which by its terms is to be paid or performed on or after the Closing Date is not to be considered a Prior Claim. Purchase Price. As defined in Section 2.2. -------------- ----------- Purchaser. As defined in the paragraph preceding the Recitals. --------- Purchaser Warranty Claim. As defined in Section 9.1(a). ------------------------ -------------- Reserved Rights. Any of the right, title and interest of Seller (and --------------- its affiliates, successors and assigns (other than Purchaser and its successors and assigns), agents, servants, representatives, directors and officers) in and to each and every Prior Claim (but not to the exclusion of the Purchaser). Section 338 Elections. As defined in Section 5.4. --------------------- ----------- Section 338 Election Forms. As defined in Section 5.4. -------------------------- ----------- Seller. As defined in the Recitals hereto. ------ Seller Warranty Claim. As defined in Section 9.2. --------------------- ----------- -4- Seller's Knowledge. Seller's actual knowledge after due inquiry and ------------------ reasonable investigation. Shares. As defined in the Recitals hereto. ------ Taxes. As defined in Section 3.11(a). ----- --------------- Transaction Parties. Collectively, each party to the Membership ------------------- Interest Acquisition Agreement. I.3 Interpretation. Unless otherwise expressly provided or unless the -------------- context requires otherwise, (a) all references in this Agreement to Articles, Sections, Schedules and Exhibits shall mean and refer to Articles, Sections, Schedules and Exhibits of this Agreement; (b) all references to statutes and related regulations shall include all amendments of the same and any successor or replacement statutes and regulations; (c) words using the singular or plural number also shall include the plural and singular number, respectively; (d) references to "hereof", "herein", "hereby" and similar terms shall refer to this entire Agreement (including the Schedules and Exhibits hereto); and (e) references to any Person shall be deemed to mean and include the successors and permitted assigns of such Person (or, in the case of an Authority, Persons succeeding to the relevant functions of such Person). ARTICLE II PURCHASE AND SALE AND ASSIGNMENT AND ASSUMPTION ----------------------------------------------- II.1 Purchase and Sale and Assignment. Subject to the terms and -------------------------------- conditions of this Agreement, and in reliance upon the representations, warranties, covenants and agreements made in this Agreement by Seller and Purchaser, Purchaser shall purchase and accept from Seller, and Seller shall sell, transfer, convey, assign and deliver to Purchaser, on the Closing Date, the Investor Interest (including without limitation causing GESFG to sell, transfer, convey, assign and deliver to Purchaser the Shares) subject to Section ------- 2.3(b). - ------ II.2 Payment of the Purchase Price. The purchase price (the "Purchase ----------------------------- -------- Price") payable by Purchaser to Seller in consideration for the Investor - ----- Interest shall be Twenty-Nine Million Eight Hundred Seventy Thousand Four Hundred Seventy-Three Dollars and Three Cents ($29,870,473.03) plus interest from November 30, 1998 up to and including the Closing Date, at an interest rate equal to the applicable pre-tax yield provided for in the definition of "Book Investment" as defined in Appendix A to the Membership Interest Acquisition Agreement, payable on the Closing Date by wire transfer of immediately available federal funds to an account designated in writing to Purchaser by Seller in writing prior to the Closing. II.3 Assumption. (a) Upon the Closing Date, Purchaser accepts the ---------- assignment set forth above and confirms that it shall be deemed the Investor and as such a party to the Documents, and Purchaser agrees to be bound by all of the terms of and assumes all of the duties and obligations of the Investor pursuant to the Documents (other than duties and obligations relating to Prior Claims and Reserved Rights). From and after the Closing Date, Seller shall be -5- released and discharged from, and shall not be responsible to Purchaser or to any Person for, the discharge or performance of any duty or obligation as Investor pursuant to or in connection with the Documents (other than duties or obligations occurring or arising prior to the Closing Date or relating to Prior Claims and Reserved Rights) and Purchaser shall be substituted in lieu of Seller as Investor with respect to each of the Documents to which Seller is a party as Investor. From and after the Closing Date, Purchaser shall not be responsible to any Person for the discharge or performance of any duty or obligation of Seller as Investor in connection with the Documents occurring or arising prior to the Closing Date or any duty or obligation in connection with any Prior Claim or Reserved Right. (b) From and after the Closing Date, neither Seller nor any Affiliate of Seller will claim any tax benefits, file any tax returns or take any other action that would be inconsistent with the status of Purchaser as the sole owner of the Investor Interest, including the Shares, for federal, state and local tax purposes, or with the treatment of Purchaser as the owner of the Shares, except for the period of Seller's ownership prior to the Closing Date. ARTICLE III REPRESENTATIONS AND WARRANTIES OF SELLER ---------------------------------------- As an inducement to Purchaser to enter into and perform its obligations under this Agreement, and in consideration of the covenants of Purchaser contained herein, Seller represents and warrants to Purchaser as of the date of this Agreement and as of the Closing Date (which representations and warranties shall survive the Closing regardless of what examinations, inspections, audits and other investigations Purchaser has heretofore made, or may hereafter make, with respect to such representations and warranties) as follows: III.1 Corporate Status; Authority of Seller; Enforceability. ----------------------------------------------------- (a) Each of Seller, GESFG and Member B is a corporation duly organized, validly existing and in good standing under the laws of the state of its organization and in each other jurisdiction where the failure to so qualify could have a material adverse effect on its business, operations or condition or on the Business. Each of Seller and Member B has the corporate power and authority necessary to perform its obligations under the Documents. (b) Seller has the corporate power and authority to execute and deliver this Agreement and to perform its obligations hereunder. The execution, delivery and performance by Seller of this Agreement have been duly authorized by all necessary corporate action on its part and neither the execution and delivery thereof, nor the consummation of the transactions contemplated thereby, nor compliance by it with any of the terms and provisions thereof requires or will require any approval of stockholders of, or approval or consent of any trustee or holders of any indebtedness or obligations of Seller other than such consents and approvals as have been obtained and are in full force and effect. This Agreement has been duly executed and delivered by Seller and (assuming the due authorization, execution, delivery by Purchaser) constitutes its legal, valid and binding obligation enforceable against Seller in accordance with its terms, -6- subject to bankruptcy, insolvency, reorganization and other laws affecting creditors' rights generally and by general principles of equity (whether in a proceeding at law or in equity). (c) Except as may arise from the activities contemplated by the Documents, neither the execution or delivery of this Agreement by Seller nor the performance by Seller of its obligations under this Agreement will conflict with or result in a breach of any of the terms or provisions of, or constitute a default under, any contract, lease, license, franchise, permit, indenture, mortgage, deed of trust, note agreement or other agreement or instrument to which Seller, GESFG or Member B is a party or is bound, the articles of incorporation or by-laws of Seller, GESFG or Member B or any applicable Law or Order to which Seller, GESFG or Member B is a party or by which Seller, GESFG or Member B is bound or would result in any Lien on the Shares or the Investor Interest. III.2 Documents. Each Document to which Seller, in its capacity as --------- Investor, or Member B is a party has been duly authorized by all necessary corporate action on behalf of Seller or Member B, and has been executed and delivered by Seller or Member B. Seller has delivered to Purchaser the minutes of all directors and shareholder meetings of Member B. As of the Closing Date, Member B will not be a party to any contract or agreement other than the Documents and such other documents which are contemplated by the Documents. From and after the Closing Date, Member B will have no assets other than the assets, rights and interests which are in connection with the Pinon Pine Project and which are contemplated by the Documents. Member B was formed on October 2, 1995, and since such date has not conducted any business or incurred any liability or obligation other than its obligations under the Documents or obligations or liabilities arising from the activities contemplated by the Documents. III.3 Liens. Purchaser will acquire the Shares free of any Liens ----- attributable to Member B, GESFG or Seller (other than Liens created pursuant to the Documents). III.4 Assignment. Except pursuant to this Agreement or the Documents, ---------- Member B has not assigned or transferred any of its right, title or interest in or under the Documents, the Property or the Pinon Pine Project. III.5 Compliance with Laws. Except as may result from the transactions -------------------- contemplated by the Documents, Member B has complied with all, and is not in violation of any, applicable Laws or Orders (including, without limitation, any applicable building, zoning, environmental protection, occupational health and safety, employment or disability rights law, ordinance or regulation) affecting its properties or the operation of its Business. III.6 Litigation. Except as may result from the transactions ---------- contemplated by the Documents, there are no actions, proceedings, claims, suits, investigations, inquiries, or similar actions pending or, to the best of Seller's Knowledge, threatened, against it, GESFG or Member B before any Authority, arbitral or tribunal in law or equity that questions the validity or enforceability of this Agreement or any Document to which Seller or Member B is or is to become a party or that would materially and adversely affect Seller's, GESFG's or Member B's -7- ability to perform their respective obligations under this Agreement or the Documents to which such person is a party. III.7 Bankruptcy. There is not pending against Seller, GESFG or Member B ---------- any voluntary petition in bankruptcy or petition or answer seeking any reorganization, liquidation, dissolution or similar relief under any federal or state bankruptcy, insolvency, or other law relating to relief for debtors, and neither Seller nor any Affiliate has sought or consented to or acquiesced in the appointment of any trustee, receiver, conservator or liquidator of all or any part of its properties or its interest in or Seller's, GESFG's or Member B's rights to the Pinon Pine Project, the Investor Interest or the Shares. No court of competent jurisdiction has entered an order, judgment, or decree approving a petition filed against Seller, GESFG or Member B seeking any reorganization, arrangement, composition, readjustment, liquidation, dissolution or similar relief under any federal bankruptcy or insolvency act or other law relating to relief for debtors, and no other liquidator has been appointed for the Seller, GESFG or Member B or of all or any part of its properties or its rights to the Pinon Pine Project, the Investor Interest or the Shares and no such action is pending. III.8 Personnel Identification. All officers and directors of Member B ------------------------ shall resign as of the Closing Date. III.9 Capitalization; Subsidiaries. (a) The total number of shares of ---------------------------- capital stock and the par value thereof which Member B is authorized to issue and the number of such shares which are issued and outstanding are as follows:
Issued and Class Authorized Shares Outstanding Shares ----- ----------------- ------------------ - ---------------------------------------------------------------------------------------------- Common Stock, $1.00 par value 1,000 1,000 - ----------------------------------------------------------------------------------------------
No shares of Member B's capital stock are held as treasury stock. (b) Except for Purchaser's option, which the Purchaser is exercising hereunder, to acquire the Shares pursuant to Section 4.3 of the Construction ----------- Agreement, there are no outstanding options, conversion rights, phantom stock plans, warrants or other rights in existence to acquire from Member B any of its shares of capital stock. (c) The Shares have been duly and validly issued and are fully paid and nonassessable and are not subject to any preemptive rights; and there are no voting trust agreements or other contracts, agreements or arrangements restricting voting or dividend rights or transferability with respect to the outstanding shares of capital stock of Member B. (d) Member B has not violated in any material respect any federal, state or local Law in connection with the offer for sale or sale and issuance of its outstanding shares of capital stock or any other securities issued by it. -8- (e) Member B does not own any securities or any other direct or indirect interest in any other Person other than those contemplated by the Documents. III.10 Title to Purchased Shares. GESFG owns all of the Shares of ------------------------- Member B. GESFG is of the record and beneficial owner of all of the issued and outstanding capital stock of Member B. The Shares constitute all of the issued and outstanding shares of capital stock of Member B and upon delivery of and payment by Purchaser to Seller of the Purchase Price, Purchaser will acquire good and marketable title to the Shares free and clear of all Liens. III.11 Tax Matters. ----------- (a) The term "Taxes" means all net income, capital gains, gross income, ----- gross receipts, sales, use, transfer, ad valorem, franchise, profits, license, capital, withholding, payroll, employment, excise, goods and services, severance, stamp, occupation, premium, property, assessments or other governmental charges of any kind whatsoever, together with any interest, fines and any penalties, additions to tax or additional amounts incurred or accrued under applicable federal, state, local or foreign tax law or assessed, charged or imposed by any Authority, domestic or foreign, provided that any interest, penalties, additions to tax or additional amounts that relate to Taxes for any taxable period (including any portion of any taxable period ending on or before the Closing Date) shall be deemed to be Taxes for such period, regardless of when such items are incurred, accrued, assessed or charged. (b) Member B has duly and timely filed (and prior to the Closing Date will duly and timely file) true, correct and complete Tax returns, reports or estimates, all prepared in accordance with applicable Laws, for all years and periods (and portions thereof), for all jurisdictions (whether federal, state, local or foreign) in which any such returns, reports or estimates were due, and for all such returns, reports and estimates which are required to be filed by any applicable Law on or prior to the Closing Date. All Taxes shown as due and payable on such returns, reports and estimates have been paid (or will be paid prior to the Closing), and there is no current liability for any Taxes due and payable in connection with any such returns. There are no existing liens for Taxes upon any of Member B's assets. (c) Member B has (i) withheld all required amounts from its employees, agents, contractors and nonresidents and remitted such amounts to the proper Authorities; (ii) paid all employer contributions and premiums; and (iii) filed all federal, state, local and foreign returns and reports with respect to employee income Tax withholding, and social security and unemployment Taxes and premiums, all in compliance with the withholding provisions of the Code, or any prior provision of the Code and other applicable Laws. (d) Other than as provided within the Documents, Member B's assets consist solely of the Member B Interest. (e) Member B does not engage (and has not previously engaged) in a trade or business within the meaning of the Code, other than that of owning the Member B Interest and the Business. -9- (f) Member B is not a foreign person within the meaning of Code Section 1445. (g) Member B is and always has been taxable as a corporation for federal income tax purposes. (h) Neither the Code nor any other provision of Law requires Purchaser to withhold any portion of the Purchase Price. (i) Other than as provided within the Documents, Member B is not a party to any joint venture, partnership or other arrangement that could be treated as a partnership for federal income Tax purposes. (j) No federal, state, local or foreign Tax audits or other administrative proceedings, discussions or court proceedings are presently pending with regard to any Taxes or Tax returns of Member B and no additional issues are being asserted against Member B in connection with any existing audits of Member B, other than any such items which relate to the Business or the Company. (k) Other than as provided within the Documents, Member B has not entered into any agreement relating to Taxes which affects any taxable year ending after the Closing Date. (l) Member B has not agreed to and it is not required to make any adjustment by reason of a change in accounting methods that affects any taxable year ending after the Closing Date, other than any such adjustment made by the Company. Neither the IRS nor any other Authority has proposed any such adjustment or change in accounting methods that affects any taxable year ending after the Closing Date. Member B has no application pending with any taxing authority requesting permission for any changes in accounting methods that relate to its business or operations and that affects any taxable year ending after the Closing Date, other than any such application made by the Company. (m) Member B has not consented to the application of Code section 341(f). (n) There is no contract, agreement, plan or arrangement covering any employee or former employee of Member B that, individually or collectively, could give rise to the payment by Member B of any amount that would not be deductible by reason of Code section 280G. III.12 Real Property. Except as may be contemplated by the Documents, ------------- Member B has no title to or interests in any real property. III.13 Consents. Except for filings pursuant to the HSR Act, no -------- consent, approval, order or authorization of, or registration, declaration or filing with, any Authority or any other Person is required to be obtained or made by the Seller, GESFG or Member B in connection with the execution and delivery of this Agreement or the performance by the Seller of its obligations hereunder which has not been obtained. -10- III.14 Broker's or Consultant's Fees. Seller represents and warrants ----------------------------- that it has dealt with no broker, finder or consultant in connection with any of the transactions contemplated by this Agreement, and, to the Seller's Knowledge, no Person is entitled to any commission, broker's or finder's fee in connection with the sale of the Shares to Purchaser. III.15 Banking Arrangements. Member B has no banking, borrowing or -------------------- depository relationship, or accounts or deposits of funds. III.16 Powers of Attorney. No Person holds any power of attorney from ------------------ Member B. III.17 Loans. There are no loans (including, without limitation, ----- principal, interest and fees) due and owing to Member B from Seller or any of Member B's Affiliates, employees, officers or directors. ARTICLE IV REPRESENTATIONS AND WARRANTIES OF PURCHASER ------------------------------------------- As an inducement to Seller to enter into and perform their obligations under this Agreement, and in consideration of the covenants of Seller contained herein, Purchaser represents and warrants to Seller as of the date hereof and as of the Closing Date (which representations and warranties shall survive the Closing regardless of what examinations, inspections, audits and other investigations Seller has heretofore made, or may hereafter make, with respect to such representations and warranties) as follows: IV.1 Corporate Status. Purchaser is a corporation duly organized, ---------------- validly existing and in good standing under the laws of the State of Nevada. IV.2 Due Authorization. The execution and delivery by Purchaser of this ----------------- Agreement, and the performance by Purchaser of its obligations hereunder, have been duly and validly authorized and approved by all necessary corporate action on the part of Purchaser. IV.3 Authority of Purchaser. Purchaser has the corporate power and ---------------------- authority to execute and deliver this Agreement and to perform its obligations hereunder. The execution, delivery and performance of this Agreement have been duly authorized by all necessary action on the Purchaser's part and neither the execution and delivery thereof, nor the consummation of the transactions contemplated thereby, nor compliance by it with any of the terms and provisions thereof requires or will require any approval of members or managers of, or approval or consent of any trustee or holders of any indebtedness or obligations of Purchaser, other than such consents and approvals as have been obtained and are in full force and effect. Neither the execution or delivery of this Agreement by Purchaser nor the performance by Purchaser of its obligations under this Agreement will conflict with or result in a breach of any of the terms or provisions of, or constitute a default under, any contract, lease, license, franchise, permit, indenture, mortgage, deed of trust, note agreement or other agreement or instrument to which Purchaser is a party or is bound, its articles of incorporation, by-laws or any applicable Law or Order to which Purchaser is a party or by which Purchaser is bound. -11- IV.4 Enforceability. This Agreement has been duly executed and -------------- delivered by Purchaser and (assuming the due authorization, execution and delivery by Seller) constitutes its legal, valid and binding obligation enforceable against Purchaser in accordance with its terms, subject to bankruptcy, insolvency, reorganization and other laws affecting creditors' rights generally and by principles of equity (whether in a proceeding at law or in equity). IV.5 Consents. Except for filings pursuant to the HSR Act or as -------- otherwise contemplated by this Agreement, no consent, approval, Order or authorization of, or registration, declaration or filing with, any Authority or any other Person is required to be obtained or made by Purchaser in connection with its execution and delivery of this Agreement or the performance by it of its obligations hereunder. IV.6 Broker's or Consultant's Fees. Purchaser represents and warrants ----------------------------- that it has dealt with no broker, finder or consultant in connection with any of the transactions contemplated by this Agreement, and, to its knowledge, no Person is entitled to any commission or finder's fee in connection with the sale of the Shares to Purchaser. ARTICLE V COVENANTS --------- Seller and Purchaser covenant and agree that: V.1 Required Filings. Prior to the Closing, Seller and Purchaser agree ---------------- to (a) promptly file, or cause to be promptly filed, with all appropriate Authorities all notices, registrations, declarations, applications and other documents as may be necessary as a result of the consummation of the transactions contemplated hereby and (b) to diligently pursue all consents, approvals and authorizations from such Authorities as may be necessary as a result of the consummation of the transactions contemplated hereby. Seller and Purchaser each covenant to (i) request early termination of the waiting period required under the HSR Act, (ii) furnish to the other party such necessary or appropriate information and reasonable assistance as such other party may reasonably request in connection with its preparation of necessary filings and submissions pursuant to the HSR Act and (iii) comply with a request for additional information issued by any Authority as promptly as practical. Purchaser shall pay the HSR Act filing fee. V.2 Pre-Closing Taxes. Seller shall be liable for all Taxes imposed on ----------------- or incurred by Member B or its assets for any taxable period ending on or before the Closing Date, except to the extent provided otherwise in the Documents. V.3 Tax Reports; Returns. Seller and Purchaser shall provide each other -------------------- with such assistance as may reasonably be requested by the others in connection with the preparation of any return or report of Taxes, any audit or other examination by any taxing authority, or any judicial or administrative proceedings relating to liabilities for Taxes. Seller and Purchaser will retain for the full period of any statute of limitations and provide the others with any records or information which may be relevant to such preparation, audit, examination, proceeding or determination. Seller shall be responsible for causing Member B to file all Tax returns and -12- reports of Member B due on or prior to the Closing Date, which such returns and reports shall be prepared and filed timely and on a basis consistent with existing procedures for preparing such returns or reports and consistent with prior practice with respect to the treatment of specific items on the returns or reports. V.4 Optional Section 338(h)(10) Elections. ------------------------------------- (a) At the Purchaser's sole discretion and upon prior written notice the Purchaser and the Seller shall make, or cause to be made, in an appropriate and timely manner the elections provided for by Code section 338(h)(10) (and, to the extent necessary to allow for such election under Code section 338(h)(10), an election under Code section 338(g)) and any corresponding election under state or local law with respect to the Purchaser's acquisition of the stock of Member B ("Section 338 Elections"). --------------------- (b) Upon the Purchaser's delivery of written notice that the Section 338 Elections are to made pursuant to Section 5.4(a): -------------- (i) The Purchaser and the Seller will cooperate with each other to take all actions necessary or appropriate to effect and preserve the Section 338 Elections, including, but not limited to, preparing a Form 8023-A (Corporate Qualified Stock Purchase Agreement) and any related and comparable forms for state or local law ("Section 338 Election Forms"). -------------------------- (ii) The Purchaser shall have delivered to the Seller executed and completed Section 338 Election Forms prepared in accordance with Law and allocating the Modified Aggregate Deemed Sales Price (as defined in Treasury Regulation section 1.338(h)(10)-1(f)(2)) among the assets of the Member B in accordance with the applicable Regulations promulgated under Code section 338. The Seller shall have such forms duly executed by the appropriate persons and delivered to the Purchaser in a timely manner. The Purchaser shall file in a timely manner, or cause to be filed in a timely manner, all Section 338 Election Forms with the appropriate office of the IRS. (iii) The Purchaser and Seller agree to report, or cause to be reported, the Purchaser's purchase of the stock of the Member B consistent with the Section 338 Elections and shall take no position on any return, or in any audit, examination, investigation, or other proceeding that is inconsistent with such elections or the allocation of the Modified Aggregate Deemed Sales Price among the Assets of Member B as set forth in the Section 338 Election Forms. (iv) The Purchaser agrees to indemnify Seller against any United States federal and state Taxes incurred by Seller upon the sale of the stock of Member B that Seller would not have incurred had Member B instead sold its interest in the Company for the Purchase Price, and then liquidated into Seller. -13- V.5 Further Assurance. At any time and from time to time from and after ----------------- the Closing Date, Seller and Purchaser will, at the request and expense of the other parties hereto, execute, acknowledge and deliver, or cause to be executed, acknowledged and delivered, such instruments and other documents and perform or cause to be performed such acts and provide such information, as may reasonably be required to evidence or effectuate the sale, conveyance, transfer, assignment and delivery to Purchaser of the Shares or for the performance by Seller or Purchaser of any of their other respective obligations under this Agreement. ARTICLE VI CONDITIONS PRECEDENT TO PURCHASER'S OBLIGATIONS ----------------------------------------------- 6.1 Obligations to be Satisfied on or Prior to Closing Date. The ------------------------------------------------------- obligation of Purchaser to purchase the Investor Interest under this Agreement is subject to the satisfaction (or waiver by Purchaser), on or prior to the Closing Date, of the following conditions: (a) Accuracy of Representations and Warranties. Each of the ------------------------------------------ representations and warranties made by the Seller in this Agreement shall be true and correct in all material respects on and as of the Closing Date as though made on and as of such date except to the extent that any representation or warranty is made herein as of a specified date, in which case such representation or warranty shall be true and correct in all material respects and in all respects as of such date. (b) Compliance with Agreement. The Seller shall have performed or ------------------------- complied in all material respects with the covenants, agreements and obligations required by this Agreement to be performed or complied with by the Seller on or prior to the Closing Date. (c) HSR Act Waiting Period. All applicable waiting periods (and any ---------------------- extensions thereof) under the HSR Act shall have expired or otherwise been terminated. (d) Closing Documents. The Seller shall have delivered all reports, ----------------- agreements, certificates, instruments, opinions and other documents required to be delivered by the Seller on the Closing Date pursuant to Section 8.3. ----------- ARTICLE VII CONDITIONS PRECEDENT TO SELLER'S OBLIGATIONS -------------------------------------------- 7.1 Obligations to Be Satisfied on or Prior to Closing Date. The ------------------------------------------------------- obligations of the Seller to sell the Investor Interest under this Agreement are subject to the satisfaction (or waiver by the Seller), on or prior to the Closing Date, of the following conditions: (a) Accuracy of Representations and Warranties. Each of the ------------------------------------------ representations and warranties made by Purchaser in this Agreement shall be true and correct in all material respects on the Closing Date as though made on and as of such date, except to the -14- extent that any representation or warranty is made herein as of a specified date, in which case such representation or warranty shall be true and correct in all material respects as of such date. (b) Compliance with Agreement. The Purchaser shall have each ------------------------- performed or complied in all material respects with the covenants, agreements and obligations required by this Agreement to be performed or complied with by it on or prior to the Closing Date. (c) HSR Act Waiting Period. All applicable waiting periods (and any ---------------------- extensions thereof) under the HSR Act shall have expired or otherwise been terminated. (d) Closing Documents. Purchaser shall have delivered all reports, ----------------- agreements, certificates, instruments, opinions and other documents required to be delivered by it on the Closing Date pursuant to Section 8.4. ----------- ARTICLE VIII CLOSING ------- 8.1 Time and Place. The Closing shall take place at 10:00 a.m. (Chicago -------------- time) on the Closing Date at the offices of Winston & Strawn, 35 West Wacker Drive, Chicago, Illinois. 8.2 Closing Transactions. All documents and other instruments required -------------------- to be delivered at the Closing shall be regarded as having been delivered simultaneously, and no document or other instrument shall be regarded as having been delivered until all have been delivered. 8.3 Deliveries by Seller to Purchaser. At the Closing, Seller shall --------------------------------- deliver or cause to be delivered to Purchaser: (a) certificates representing all of the Shares which such certificates shall be either duly endorsed or accompanied by stock powers duly endorsed; (b) a certificate of the Secretary or Assistant Secretary of Member B, dated as of the Closing Date, certifying as to (i) the certificate of incorporation of Member B and (ii) the by-laws of Member B; (c) certificate of good standing for Member B from the State of Delaware; (d) a certificate of the Attesting Secretary of Seller, dated as of the Closing Date, certifying to (i) the articles of incorporation of Seller; (ii) the by-laws of Seller; (iii) resolutions of the Board of Directors of Seller and (iv) incumbency and signatures of the officers of Seller executing this Agreement and any other certificate or document delivered in connection herewith; (e) certificate of good standing for Seller from the State of New York; -15- (f) a certificate of the Secretary or the Assistant Secretary of GESFG, dated as of the Closing Date, certifying to (i) the certificate of incorporation of GESFG, (ii) the by-laws of GESFG; (iii) resolutions of the Board of Directors of GESFG and (iv) incumbency and signatures of the officers of GESFG executing any certificate or document delivered in connection with this Agreement; (g) certificate of good standing for GESFG from the State of Delaware; (h) a withholding certificate, in the form of Exhibit A executed by --------- GESFG; (i) opinion, dated the Closing Date, of counsel to Seller addressed to Purchaser; (j) original minute book, stock ledger, corporate seal, books of account, financial records and similar corporate records, of Member B, to the extent such exist; (k) evidence of resignations of all directors and officers of Member B effective on the Closing Date; and (l) such other instruments and documents as are: (i) required by any other provisions of this Agreement to be delivered on the Closing Date by Seller to Purchaser; or (ii) reasonably necessary, in the opinion of Purchaser, to effect the performance of this Agreement by Seller. 8.4 Deliveries by Purchaser to Seller. At the Closing, Purchaser shall --------------------------------- deliver or cause to be delivered to Seller: (a) the Purchase Price in accordance with Section 2.2; ----------- (b) a certificate of the Secretary or an Assistant Secretary of Purchaser, dated as of the Closing Date, certifying to (i) the articles of incorporation of Purchaser, (ii) the by-laws of Purchaser; (iii) resolutions of the Board of Directors of Purchaser; and (iv) incumbency and signatures of the officers of Purchaser executing this Agreement and any other certificate or document delivered in connection herewith; (c) certificate of good standing for Purchaser from the State of Nevada; (d) written consents duly executed by Purchaser and dated the Closing Date electing eligible persons as directors of Member B and written consents of such directors appointing eligible persons as officers of Member B; (e) such other instruments and documents as are: (i) required by any other provisions of this Agreement to be delivered on the Closing Date by Purchaser to Seller; -16- or (ii) reasonably necessary, in the opinion of Seller, to effect the performance of this Agreement by Purchaser; and (f) confirmation by Purchaser and A Members that neither Seller nor Member B nor any Affiliate is in default under any Document as of the Closing Date. ARTICLE IX INDEMNIFICATION --------------- 9.1 Indemnification by Seller. Seller agrees to indemnify, defend, ------------------------- hold harmless and waive any claim for contribution against Purchaser, Member B and all of their officers, directors, shareholders, Affiliates, employees and agents (the "Purchaser Indemnified Persons") after the Closing from and against ----------------------------- any Adverse Consequence arising out of or resulting from: (a) the untruth, inaccuracy or incompleteness of any representation or warranty of Seller contained in this Agreement or Schedules hereto (or in any document, writing, certificate, data or financial statements delivered by Seller under this Agreement) (each a "Purchaser Warranty ------------------ Claim") or the failure by Seller to perform any of its covenants or ----- obligations hereunder; (b) any brokers' commissions, finders' fees or other like payments incurred or alleged to have been incurred by Seller or Member B in connection with the sale of the Investor Interest or the consummation of the transactions contemplated by this Agreement; (c) except as otherwise provided in the Documents, all Taxes imposed on, payable by or attributable to Member B or its assets for taxable periods ending on or before the Closing Date, and for its allocable share of Taxes for any period that begins prior to the Closing Date and ends after the Closing Date (including, in each case, any payment due from Member B under any agreement sharing or apportioning any such Taxes). Seller's allocable share of Taxes determined by reference to income, capital gains, gross income, gross receipts, sales, net profits, windfall profits and similar gains, shall be determined based on the date on which such items accrued. For all other Taxes, Seller's allocable share shall be determined pro rata based on the number of days in the taxable period for which each party is liable for Taxes hereunder; and (d) All Taxes imposed on, payable by or attributable to Member B or its assets that do not relate to the Business (including any consolidated return joint liability for federal income taxes under Treasury Regulation section 1.1502-6), except to the extent attributable to operations in respect of the Company or actions taken by Member B after the Closing Date. -17- 9.2 Indemnification by Purchaser. Purchaser agrees to indemnify, defend ---------------------------- and hold harmless Seller after the Closing from and against any Adverse Consequences arising out of or resulting from: (a) the untruth, inaccuracy or incompleteness as of the date hereof or on the Closing Date of any representation or warranty of Purchaser contained in this Agreement (or in any document, writing or certificate delivered by Purchaser under this Agreement) (each a "Seller Warranty --------------- Claim") or the failure by Purchaser to perform any of its covenants or ----- obligations hereunder; (b) any claim, including any liability or obligation of Purchaser or Member B to be satisfied or performed on or after the Closing Date; (c) any act, condition or event with respect to the Investor Interest arising or relating to the period on and after the Closing Date, including, without limitation, any breach or default by Seller or Member B of its obligations pursuant to the Documents on and after the Closing Date; (d) except as otherwise provided in the Documents, all Taxes imposed on, payable by or attributable to Member B or its assets for taxable periods beginning on or after the Closing Date, and for its allocable share of Taxes for any period that begins prior to the Closing Date and ends after the Closing Date (including, in each case, any payment due from Member B under any agreement sharing or apportioning any such Taxes). Purchaser's allocable share of Taxes determined by reference to income, capital gains, gross income, gross receipts, sales, net profits, windfall profits and similar gains, shall be determined based on the date on which such items accrued. For all other Taxes, Purchaser's allocable share shall be determined pro rata based on the number of days in the taxable period for which each party is liable for Taxes hereunder; and (e) to the extent required under the Documents with respect to Prior Claims. 9.3 Procedure for Indemnification. If any Person shall claim ----------------------------- indemnification (the "Indemnified Party") hereunder for any claim other than a ----------------- third party claim, the Indemnified Party shall promptly give written notice to the other party from whom indemnification is sought (the "Indemnifying Party") ------------------ of the nature and amount of the claim. If an Indemnified Party shall claim indemnification hereunder arising from any claim or demand of a third party, the Indemnified Party shall promptly give written notice (a "Third-Party Notice") to ------------------ the Indemnifying Party of the basis for such claim or demand, setting forth the nature of the claim or demand in detail. The Indemnifying Party shall have the right to compromise or, if appropriate, defend at its own cost and through counsel of its own choosing, any claim or demand set forth in a Third-Party Notice giving rise to such claim for indemnification. In the event the Indemnifying Party undertakes to compromise or defend any such claim or demand, it shall promptly (and in any event, no later than fifteen (15) days after receipt of the Third-Party Notice) notify the Indemnified Party in writing of its intention to do so. The Indemnified Party shall fully cooperate with the Indemnifying Party and its counsel in the defense or compromise of such -18- claim or demand. After the assumption of the defense by the Indemnifying Party, the Indemnified Party shall not be liable for any legal or other expenses subsequently incurred by the Indemnifying Party, in connection with such defense, but the Indemnified Party may participate in such defense at its own expense. No settlement of a third party claim or demand defended by the Indemnifying Party shall be made without the written consent of the Indemnified Party, such consent not to be unreasonably withheld. The Indemnifying Party shall not, except with the written consent of the Indemnified Party, consent to the entry of a judgment or settlement which does not include as an unconditional term thereof, the giving by the claimant or plaintiff to the Indemnified Party of an unconditional release from all liability in respect of such third party claim or demand. With respect to claims arising prior to the date hereof, if the Documents provide other than as provided in this Section 9.3, then the ----------- Documents shall control the procedure for indemnification. 9.4 Payment. Except for third-party claims being defended in good faith ------- by the Indemnifying Party in accordance with Section 9.3, the Indemnifying Party ----------- shall satisfy its obligations hereunder within fifteen (15) days after receipt of notice of a claim. Any amount not paid to the Indemnified Party by such date shall bear interest at a rate equal to Overdue Rate from the date due until the date paid. ARTICLE X MISCELLANEOUS PROVISIONS ------------------------ 10.1 Post-Closing Deliveries. After the Closing, any monies, checks, ----------------------- instruments, invoices, bills, receipts, notices, mail and other communications received by one party but directed toward or due to another shall be promptly delivered to the other party. Seller shall cooperate with Purchaser after the Closing to ensure the orderly transition of the operation of the Business from Seller to Purchaser and to minimize any disruption in the business of Purchaser that might result from the transactions contemplated hereby. 10.2 Notices. All notices or other communications required or permitted ------- by this Agreement shall be in writing and shall be deemed to have been duly received (a) if given by telecopier, when transmitted and the appropriate telephonic confirmation received if transmitted on a business day and during normal business hours of the recipient, and otherwise on the next business day following transmission, (b) if given by certified or registered mail, return receipt requested, postage prepaid, three business days after being deposited in the U.S. mails and (c) if given by courier or other means, when received or personally delivered, and, in any such case, addressed as follows: -19- (i) if to Purchaser: Sierra Pacific Power Company 6100 Neil Road Reno, Nevada 89520 Attention: Richard Atkinson Facsimile: (702) 834-3815 with a copy to: Winston & Strawn 35 West Wacker Drive Chicago, Illinois 60601 Attention: John C. Lorentzen Facsimile: (312) 558-5700 (ii) if to Seller: General Electric Capital Corporation Structured Finance Group 120 Long Ridge Road, 3rd Floor Stamford, Connecticut 06927 Attention: Compliance Officer, GPSF-B Inc. 760-1 Facsimile: (203) 961-2017 or to such other addresses as may be specified by any such Person to the other Person pursuant to notice given by such Person in accordance with the provisions of this Section 10.2. ------------ 10.3 Assignment. No party may assign or transfer any or all of its ---------- rights or obligations under this Agreement without the prior written approval of all the other parties; provided, however, that Purchaser may assign or transfer -------- ------- all or less than all of its rights and obligations under this Agreement to any Person. 10.4 Benefit of the Agreement. This Agreement shall be binding upon and ------------------------ inure to the benefit of the parties hereto and their respective successors and permitted assigns. This Agreement shall not be construed so as to confer any right or benefit upon any Person, other than the parties hereto and their respective successors and permitted assigns. 10.5 Exhibits and Schedules. The Exhibits and Schedules hereto shall be ---------------------- construed with and as an integral part of this Agreement to the same effect as if the contents thereof had been set forth verbatim herein. -20- 10.6 Headings. The headings used in this Agreement are for convenience -------- of reference only and shall not be deemed to limit, characterize or in any way affect the interpretation of any provision of this Agreement. 10.7 Entire Agreement. Except as otherwise specifically provided herein, ---------------- this Agreement contains the entire agreement and understanding of the parties with respect to the subject matter hereof, and no other representations, promises, agreements or understandings regarding the subject matter hereof shall be of any force or effect unless in writing, executed by the party to be bound thereby and dated on or after the date hereof. 10.8 Modifications and Waivers. No change, modification or waiver of ------------------------- any provision of this Agreement shall be valid or binding unless it is in writing, dated subsequent to the date hereof and signed by Purchaser and Seller. No waiver of any breach, term or condition of this Agreement by any party shall constitute a subsequent waiver of the same or any other breach, term or condition. 10.9 Counterparts. This Agreement may be executed in counterparts, each ------------ of which shall be deemed an original, but all of which together shall constitute one and the same instrument. 10.10 Severability. In case any one or more of the provisions contained ------------ herein for any reason shall be held to be invalid, illegal or unenforceable in any respect, such invalidity, illegality or unenforceability shall not affect any other provision of this Agreement, but this Agreement shall be construed as if such invalid, illegal or unenforceable provision or provisions had never been contained herein. 10.11 GOVERNING LAW. THIS AGREEMENT SHALL BE GOVERNED BY AND CONSTRUED ------------- IN ACCORDANCE WITH THE LAWS OF THE STATE OF NEW YORK. 10.12 Expenses. Except as otherwise expressly provided herein, -------- Purchaser shall pay all of both the Purchaser's and the Seller's costs and expenses incurred or to be incurred in negotiating and preparing this Agreement and in closing and carrying out the transactions contemplated by this Agreement ("Agreement Expenses"); provided, however, that the Seller shall pay all ------------------ -------- ------- Agreement Expenses it incurs in excess of $40,000. 10.13 Tax Consequences. Except as set forth herein, Purchaser shall ---------------- have no liability for the tax consequences to Seller, and Seller shall have no liability for the tax consequences to Purchaser as a result of the purchase of the Investor Interest as contemplated hereby. -21- IN WITNESS WHEREOF, the parties hereto have executed this Purchase and Sale and Assignment and Assumption Agreement as of the date first written above. PURCHASER: SIERRA PACIFIC POWER COMPANY By:_____________________________________ Title:__________________________________ SELLER: GENERAL ELECTRIC CAPITAL CORPORATION By:_____________________________________ Title:__________________________________ -22- EXHIBIT A FORM OF WITHHOLDING CERTIFICATE I, _________________, hereby certify as to the following on behalf of GE Capital Services Structured Finance Group, Inc. (the "Transferor"): 1. Transferor is not a foreign corporation, foreign partnership, foreign trust, or foreign estate (as those terms are defined in the Internal Revenue Code and Income Tax Regulations); 2. Transferor's U.S. employer identification number is 08-1154651; and 3. Transferor's office address is 120 Long Ridge Road, Stamford, Connecticut 06927. The undersigned understands that this certification may be disclosed to the Internal Revenue Service by the transferee and that any false statement contained herein could be punished by fine, imprisonment, or both. Under penalties of perjury, I declare that I have examined this certification and to the best of my knowledge and belief it is true, correct, and complete, and I further declare that I have authority to sign this document on behalf of Transferor. GE CAPITAL SERVICES STRUCTURED FINANCE GROUP, INC. By: ____________________________________ Printed Name: ___________________________ Its:_____________________________________ _______________________________ Date -23- EX-27.A 2 FINANCIAL DATA SCHEDULE
UT THE SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE COMPANY'S FINANCIAL RECORDS AND IS QUALFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 12-MOS DEC-31-1998 DEC-31-1998 PER-BOOK 1,677,042 34,022 158,045 142,711 0 2,011,820 0 0 0 661,367 48,500 73,115 606,450 105,000 0 0 30,473 0 0 0 486,915 2,011,820 734,332 43,550 564,588 608,138 126,194 4,132 130,326 40,135 90,191 9,630 80,561 76,000 35,933 153,191 0 0 SIERRA PACIFIC POWER COMPANY IS A WHOLLY OWNED SUBSIDIARY OF SIERRA PACIFIC RESOURCES AND AS SUCH ITS COMMON STOCK IS NOT PUBLICLY TRADED. SPPC DOES NOT REPORT EPPS INFORMATION.
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