-----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, AWViOZ+qFaGI6Oia12N2MrSZ5l3UOt8lqde+AspZVlQXmTYRSvD8zvofH+Msz4n/ RUkOOWIp/GJyC1YxNtNM0Q== 0000898430-99-003189.txt : 19990813 0000898430-99-003189.hdr.sgml : 19990813 ACCESSION NUMBER: 0000898430-99-003189 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 3 CONFORMED PERIOD OF REPORT: 19990630 FILED AS OF DATE: 19990812 FILER: COMPANY DATA: COMPANY CONFORMED NAME: SIERRA PACIFIC RESOURCES CENTRAL INDEX KEY: 0000741508 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC & OTHER SERVICES COMBINED [4931] IRS NUMBER: 880044418 STATE OF INCORPORATION: NV FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: SEC FILE NUMBER: 001-08788 FILM NUMBER: 99684752 BUSINESS ADDRESS: STREET 1: PO BOX 10100 STREET 2: 6100 NEIL RD CITY: RENO STATE: NV ZIP: 89511 BUSINESS PHONE: 7028344011 MAIL ADDRESS: STREET 1: P O BOX 30150 STREET 2: 6100 NEIL ROAD CITY: RENO STATE: NV ZIP: 89511 10-Q 1 FORM 10-Q ================================================================================ UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-Q (Mark One) X QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE - --- ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED June 30, 1999 OR TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE - --- ACT OF 1934 FOR THE TRANSITION PERIOD FROM TO Commission File Number 1-8788 SIERRA PACIFIC RESOURCES (Exact name of registrant as specified in its charter) NEVADA 88-0198358 (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) 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 the number of shares outstanding of each of the issuer's classes of Common Stock, as of the latest practicable date. Class Outstanding at August 9, 1999 Common Stock, $1.00 par value 78,425,720 Shares ================================================================================ 1 SIERRA PACIFIC RESOURCES QUARTERLY REPORT ON FORM 10-Q FOR THE QUARTER ENDED JUNE 30, 1999 CONTENTS PART I - FINANCIAL INFORMATION ------------------------------
Page No. ------- ITEM 1. Financial Statements Report of Independent Accountants.............................................. 3 Condensed Consolidated Balance Sheets - June 30, 1999 and December 31, 1998.......................................................... 4 Condensed Consolidated Statements of Income - Three Months and Six-Months Ended June 30, 1999 and 1998............................................... 5 Condensed Consolidated Statements of Cash Flows - Six Months Ended June 30, 1999 and 1998............................................... 6 Notes to Condensed Consolidated Financial Statements........................... 7 ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.............................................................. 10 ITEM 3. Quantitative and Qualitative Disclosures about Market Risk................................................................ 12
PART II - OTHER INFORMATION --------------------------- ITEM 1. Legal Proceedings.......................................................... 13 ITEM 4. Submission of Matters to a Vote of Security Holders........................ 13 ITEM 5. Other Information.......................................................... 13 ITEM 6. Exhibits and Reports on Form 8-K........................................... 13 Signature Page...................................................................... 14 Appendix............................................................................ 16
2 INDEPENDENT ACCOUNTANTS' REPORT To the Board of Directors and Stockholders of Sierra Pacific Resources Reno, Nevada We have reviewed the accompanying condensed consolidated balance sheet of Sierra Pacific Resources (the "Company") and subsidiaries as of June 30, 1999, and the related condensed consolidated statements of income and cash flows for the three-month and six-month periods ended June 30, 1999 and 1998. These financial statements are the responsibility of the Company's management. We conducted our review in accordance with standards established by the American Institute of Certified Public Accountants. A review of interim financial information consists principally of applying analytical procedures to financial data and of making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with generally accepted auditing standards, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion. Based on our review, we are not aware of any material modifications that should be made to such condensed consolidated financial statements for them to be in conformity with generally accepted accounting principles. We have previously audited, in accordance with generally accepted auditing standards, the consolidated balance sheet and consolidated statement of capitalization of Sierra Pacific Resources and subsidiaries as of December 31, 1998, and the related consolidated statements of income, retained earnings, and cash flows for the year then ended (not presented herein); and in our report dated January 29, 1999 (February 12, 1999 as to notes 1 and 5), we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 1998 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived. DELOITTE & TOUCHE LLP Reno, Nevada August 5, 1999 3 SIERRA PACIFIC RESOURCES CONDENSED CONSOLIDATED BALANCE SHEETS (Dollars in Thousands)
June 30, December 31, 1999 1998 --------------- ------------------ (Unaudited) ASSETS Utility Plant at Original Cost: Plant in service $2,374,322 $2,348,996 Less: accumulated provision for depreciation 762,799 727,624 --------------- ------------------ 1,611,523 1,621,372 Construction work-in-progress 75,141 55,670 --------------- ------------------ 1,686,664 1,677,042 --------------- ------------------ Investments in subsidiaries and other property, net 88,525 59,258 --------------- ------------------ Current Assets: Cash and cash equivalents 8,295 17,674 Accounts receivable less provision for uncollectible accounts 1999-$4,313; 1998-$3,461 103,861 114,870 Materials, supplies and fuel, at average cost 29,879 25,776 Other 2,995 3,048 --------------- ------------------ 145,030 161,368 --------------- ------------------ Deferred Charges: Regulatory tax asset 65,531 65,619 Other regulatory assets 61,888 61,675 Other 21,282 16,434 --------------- ------------------ 148,701 143,728 --------------- ------------------ $2,068,920 $2,041,396 =============== ================== CAPITALIZATION AND LIABILITIES Capitalization: Common shareholder's equity $ 687,168 $ 673,432 Preferred stock 73,115 73,115 Preferred stock subject to mandatory redemption: SPPC-obligated mandatorily redeemable preferred securities of SPPC's subsidiary Sierra Pacific Power Capital I, holding solely $50 million principal amount of 8.6% junior subordinated debentures of SPPC, due 2036 48,500 48,500 Long-term debt 630,111 616,754 --------------- ------------------ 1,438,894 1,411,801 --------------- ------------------ Current Liabilities: Short-term borrowings 123,000 105,000 Current maturities of long-term debt 40,597 40,585 Accounts payable 46,296 60,128 Accrued interest 7,744 7,885 Dividends declared 12,536 11,465 Accrued salaries and benefits 13,154 12,131 Other current liabilities 25,051 28,059 --------------- ------------------ 268,378 265,253 --------------- ------------------ Deferred Credits: Accumulated deferred federal income taxes 172,941 168,602 Accumulated deferred investment tax credit 36,961 37,944 Regulatory tax liability 37,846 38,939 Customer advances for construction 36,462 34,961 Accrued retirement benefits 45,977 42,560 Other 31,461 41,336 --------------- ------------------ 361,648 364,342 --------------- ------------------ $2,068,920 $2,041,396 =============== ==================
The accompanying notes are an integral part of the financial statements. 4 SIERRA PACIFIC RESOURCES CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Dollars in Thousands, Except Per Share Amounts)
Three-Months Ended Six-Months Ended June 30, June 30, ----------------------------------------------------------------------------- 1999 1998 1999 1998 ----------------------------------------------------------------------------- (Unaudited) (Unaudited) (Unaudited) (Unaudited) OPERATING REVENUES: Electric $ 147,348 $ 135,169 $ 291,651 $ 277,308 Gas 18,851 22,112 56,878 53,478 Water 13,619 11,862 23,900 21,079 Other 2,339 2,489 4,514 4,249 ----------------------------------------------------------------------------- 182,157 171,632 376,943 356,114 ----------------------------------------------------------------------------- OPERATING EXPENSES: Operation: Purchased power 42,111 35,377 82,779 73,752 Fuel for power generation 26,367 27,447 52,837 51,327 Gas purchased for resale 12,658 13,510 37,375 32,841 Other 33,853 32,463 60,940 63,479 Maintenance 5,164 6,007 10,660 10,703 Depreciation and amortization 19,624 16,672 38,767 33,593 Taxes: Income taxes 8,228 8,313 19,513 20,699 Other than income 4,849 5,001 9,671 9,906 ----------------------------------------------------------------------------- 152,854 144,790 312,542 296,300 ----------------------------------------------------------------------------- OPERATING INCOME 29,303 26,842 64,401 59,814 ----------------------------------------------------------------------------- OTHER INCOME: Allowance for other funds used during construction - 1,155 - 2,126 Other income - net 221 (242) 259 (2) ----------------------------------------------------------------------------- 221 913 259 2,124 ----------------------------------------------------------------------------- Total Income 29,524 27,755 64,660 61,938 ----------------------------------------------------------------------------- INTEREST CHARGES: Long-term debt 10,245 10,057 20,443 20,320 Other 2,280 1,759 4,883 3,667 Allowance for borrowed funds used during construction and capitalized interest (236) (2,039) (434) (3,721) ----------------------------------------------------------------------------- 12,289 9,777 24,892 20,266 ----------------------------------------------------------------------------- INCOME BEFORE OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES 17,235 17,978 39,768 41,672 Preferred dividend requirements of SPPC-obligated mandatorily redeemable preferred securities (1,043) (1,043) (2,086) (2,086) ----------------------------------------------------------------------------- INCOME BEFORE PREFERRED DIVIDENDS 16,192 16,935 37,682 39,586 Preferred dividend requirements (1,365) (1,365) (2,730) (2,730) ----------------------------------------------------------------------------- INCOME APPLICABLE TO COMMON STOCK $ 14,827 $ 15,570 $ 34,952 $ 36,856 ============================================================================= Net Income Per Share - Basic $ 0.48 $ 0.50 $ 1.13 $ 1.19 Net Income Per Share - Diluted $ 0.48 $ 0.50 $ 1.12 $ 1.19 Weighted Average Shares of Common Stock Outstanding 31,019,641 30,945,868 31,015,010 30,938,332 Dividends Paid Per Share of Common Stock $ 0.340 $ 0.325 $ 0.665 $ 0.635 The accompanying notes are an integral part of the financial statements.
5 SIERRA PACIFIC RESOURCES CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Dollars in Thousands)
Six-Months Ended June 30, ----------------------------------------------------- 1999 1998 ------------------------ ---------------------- (Unaudited) CASH FLOWS FROM OPERATING ACTIVITIES: Income before preferred dividends $ 37,682 $ 39,586 Non-cash items included in income: Depreciation and amortization 38,767 33,593 Deferred taxes and deferred investment tax credit 2,322 (718) AFUDC and capitalized interest (434) (5,846) Early retirement and severance amortization 2,096 2,109 Other (158) 1,427 Changes in certain assets and liabilities: Accounts receivable 11,009 14,710 Materials, supplies and fuel (4,103) (871) Other current assets 53 (1,480) Accounts payable (13,832) (4,963) Other current liabilities (2,126) 3,724 Other - net (13,216) (763) ------------------------ ---------------------- Net Cash Flows From Operating Activities 58,060 80,508 ------------------------ ---------------------- CASH FLOWS USED IN INVESTING ACTIVITIES: Additions to utility plant (55,708) (66,454) Net customer refunds and contributions in aid construction 9,474 10,319 ------------------------ ---------------------- Net cash used for utility plant (46,234) (56,135) ------------------------ ---------------------- Investments in subsidiaries and other property - net (29,412) (1,676) ------------------------ ---------------------- Net Cash Used In Investing Activities (75,646) (57,811) ------------------------ ---------------------- CASH FLOWS FROM FINANCING ACTIVITIES: Increase in short-term borrowings 17,731 14,037 Proceeds from issuance of long-term debt 23,696 - Reduction of long-term debt (10,345) (15,300) Sale of common stock 476 1,535 Dividends paid (23,351) (22,322) ------------------------ ---------------------- Net Cash Used In Financing Activities 8,207 (22,050) ------------------------ ---------------------- Net (decrease) increase in Cash and Cash Equivalents (9,379) 647 Beginning balance in Cash and Cash Equivalents 17,674 8,901 ------------------------ ---------------------- Ending balance in Cash and Cash Equivalents $ 8,295 $ 9,548 ======================== ====================== Supplemental Disclosures of Cash Flow Information: Cash Paid During Period For: Interest $ 26,837 $ 26,189 Income Taxes $ 12,524 $ 34,350
The accompanying notes are an integral part of the financial statements. 6 NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS ---------------------------------------------------- NOTE 1. MANAGEMENT'S STATEMENT - -------------------------------- In the opinion of the management of Sierra Pacific Resources, hereafter known as the Company, the accompanying unaudited interim condensed consolidated financial statements contain all adjustments (consisting of only normal recurring adjustments) necessary to present fairly the condensed consolidated financial position, condensed consolidated results of operations and consolidated cash flows for the periods shown. These condensed consolidated financial statements do not contain the complete detail or footnote disclosure concerning accounting policies and other matters which are included in full year financial statements and therefore, they should be read in conjunction with the Company's audited financial statements included in the Company's Annual Report on Form 10-K for the year ended December 31, 1998. Deloitte & Touche LLP, the Company's independent accountants, have performed a review of the unaudited condensed consolidated financial statements, and their report has been included in this report. The results of operations for the three-month and six-month period ended June 30, 1999 are not necessarily indicative of the results to be expected for the full year. Principles of Consolidation --------------------------- The condensed consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries, Sierra Pacific Power Company (SPPC), Tuscarora Gas Pipeline Company (TGPC), Sierra Gas Holding Company (formerly Sierra Energy Company), Sierra Energy Company dba e.three (e.three), Sierra Pacific Energy Company (SPE), Lands of Sierra (LOS), and Sierra Water Development Company (SWDC). All significant intercompany transactions and balances have been eliminated in consolidation. Reclassifications ----------------- Certain items previously reported for years prior to 1998 have been reclassified to conform with the current year's presentation. Net income and shareholder's equity were not affected by these reclassifications. NOTE 2. RECENT PRONOUNCEMENTS OF THE FASB - ------------------------------------------- In June 1998, the Financial Accounting Standards Board 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 an entity to recognize all derivatives as either assets or liabilities in the statement of financial position, and measure those instruments at fair value. In May 1999, members of the Financial Accounting Standards agreed to delay the effective date of Statement 133 to fiscal years beginning after June 15, 2000. The Company is still assessing the impact of SFAS 133 on its financial condition and results of operations. 7 NOTE 3. EARNINGS PER SHARE - ------------------------------- The Company follows SFAS No. 128, "Earnings Per Share". The difference between Basic EPS and Diluted EPS is due to common stock equivalent shares resulting from stock options, employee stock purchase plan, performance shares and a non-employee director stock plan. Common stock equivalents were determined using the treasury stock method. The following provides a reconciliation of Basic EPS and Diluted EPS.
Three Months Ended Six Months Ended June 30, June 30, ----------------------------------------------------------- 1999 1998 1999 1998 ----------------------------------------------------------- Basic EPS Numerator Income available to common stockholders ($000) 14,827 15,570 34,952 36,856 ---------- ----------- ----------- ----------- Denominator Weighted average number of shares outstanding 31,019,641 30,945,868 31,015,010 30,938,332 ---------- ----------- ----------- ----------- Per-Share Amount $ 0.48 $ 0.50 $ 1.13 $ 1.19 ========== =========== =========== =========== Diluted EPS Numerator Income available to common stockholders ($000) 14,827 15,570 34,952 36,856 ---------- ----------- ----------- ----------- Denominator Weighted average number of shares outstanding 31,019,641 30,945,868 31,015,010 30,938,332 before dilution Stock options 26,206 62,508 24,909 47,346 Executive long term incentive plan - performance shares 21,947 18,387 20,285 16,807 Non-Employee stock plan 9,666 7,114 9,666 7,114 Employee stock purchase plan 679 1,002 618 1,158 ---------- ----------- ----------- ----------- 31,078,139 31,034,879 31,070,488 31,010,757 ---------- ----------- ----------- ----------- Per-Share Amount $ 0.48 $ 0.50 $ 1.12 $ 1.19 ========== =========== =========== ===========
8 NOTE 4. SEGMENT INFORMATION - ----------------------------- 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. Other segment information includes segments below the quantitative threshold for separate disclosure. 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. Intersegment revenues are not material.
Three Months Ended June 30, 1999 Electric Gas Water Other Consolidated - -------------------- ------------------- ---------------- ---------------- -------------------- ----------------- Operating Revenues $147,348 $18,851 $13,619 $2,339 $182,157 =================== ================ ================ ==================== ================= Operating income $ 24,601 $ 1,189 $ 4,047 $ (534) $ 29,303 =================== ================ ================ ==================== ================= Three Months Ended June 30, 1998 Electric Gas Water Other Consolidated - -------------------- ------------------- ---------------- ---------------- -------------------- ----------------- Operating revenues $135,169 $22,112 $11,862 $2,489 $171,632 =================== ================ ================ ==================== ================= Operating income $ 21,546 $ 2,947 $ 2,815 $ (466) $ 26,842 =================== ================ ================ ==================== =================
Six Months Ended June 30, 1999 Electric Gas Water Other Consolidated - --------------------- ----------------- ------------------- ---------------- ------------------- ----------------- Operating Revenues $291,651 $56,878 $23,900 $ 4,514 $376,943 ================= =================== ================ =================== ================= Operating income $ 51,285 $ 7,479 $ 6,846 $(1,209) $ 64,401 ================= =================== ================ =================== ================= Six Months Ended June 30, 1998 Electric Gas Water Other Consolidated - --------------------- ----------------- ------------------- ---------------- ------------------- ----------------- Operating revenues $277,308 $53,478 $21,079 $ 4,249 $356,114 ================= =================== ================ =================== ================= Operating income $ 47,962 $ 8,110 $ 4,374 $ (632) $ 59,814 ================= =================== ================ =================== =================
9 ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The information in this Form 10-Q, or in the Form 10-Q of SPPC attached as an Appendix, 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 SPR's or 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) the outcome of ongoing and future regulatory proceedings; (5) management's ability to integrate the operations of SPR, SPPC and Nevada Power Company and to implement and realize anticipated cost savings from the Merger; (6) industrial, commercial and residential growth in the service territory of SPPC; (7) fluctuations in electric, gas and other commodity prices and the ability to manage such fluctuations successfully; (8) changes in the capital markets and interest rates affecting the ability to finance capital requirements; (9 the loss of any significant customers; (10) the ability to lessen the risk of the impact of the Year 2000 on internal and external computer and software systems; and (11) 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. SPR assumes no obligation to update forward-looking statements to reflect actual results, changes in assumptions or changes in other factors affecting forward-looking statements. Sierra Pacific Power Company (SPPC) - ----------------------------------- Management Discussion and Analysis of SPPC is contained in its Quarterly Report on Form 10-Q for the three and six months ended June 30, 1999, which is attached as an appendix. Tuscarora Gas Pipeline Company - ------------------------------ For the three and six months ended June 30, 1999, Tuscarora Gas Pipeline Company, a wholly-owned subsidiary of the Company, contributed net income of $454 and $933 thousand compared to $405 and $876 thousand for the comparable periods in 1998. The increase in net income for both periods is primarily due to higher firm transportation revenues and interruptible transportation revenue. e.three - ------- For the three and six months ended June 30, 1999, e.three incurred net losses of $.5 million and $1.2 million compared to $.4 million and $.7 million in 1998. The increase in losses is due to delays in signing several sales contracts. The contracts are expected to be signed during the third quarter of this year. Sierra Pacific Energy Company - ----------------------------- For the three and six months ended June 30, 1999, Sierra Pacific Energy Company (SPE) incurred net losses of $.4 and $.8 million. SPE began operations in October 1998. The net loss is due to start-up activity costs. 10 FINANCIAL CONDITION, LIQUIDITY AND CAPITAL RESOURCES ---------------------------------------------------- During the first six months of 1999, the Company earned $37.7 million in income before preferred dividends and declared $21.7 million in common stock dividends. SPPC, the Company's principal subsidiary, declared $2.7 million in preferred stock dividends. Construction Expenditures and Financing - --------------------------------------- Substantially all capital expenditures relate to SPPC. A description of construction expenditures and financing of SPPC is contained in its Quarterly Report Form 10-Q for the period ended June 30, 1999, attached as an appendix. On July 28, 1999, immediately following the consummation of the merger with Nevada Power, the Company put into place a $500 million unsecured revolving credit facility with Mellon Bank, N.A., as Administrative Agent, First Union National Bank and Wells Fargo Bank, N.A., as Syndication Agents, and certain other participating banks. This facility may be used for working capital and general corporate purposes, including for commercial paper backup, and replaced the Company's existing credit facility. At the same time, SPPC and Nevada Power each put into place $150 million unsecured revolving credit facilities with the same banks. These two facilities may also be used for working capital and general corporate purposes, including for commercial paper backup, and replaced all existing credit facilities for those companies. In addition, immediately following the merger, each of the Company and Nevada Power established new commercial paper programs, SPPC revised its existing commercial paper program, and the Company used $456.2 million of commercial paper proceeds to provide temporary funding of the cash portion of the merger consideration. Merger - ------ On July 28, 1999 the merger of the Company and Nevada Power Company was finalized. Clearing the way for completion of the merger was the unanimous approval by the PUCN, on June 11, 1999, of a stipulation between the Company, Nevada Power, PUCN staff and the Utility Consumer Advocate, regarding the merging Companies' joint divestiture plan. As part of the stipulation, the Companies were required to re-file the divestiture plan and file the final Independent System Administrator (ISA) proposal with the PUCN and the Federal Energy Regulatory Commission (FERC). The filings were submitted in June 1999. Upon selling the generating units, both companies can determine how they will use the proceeds of the sales, up to the book value of the plants. Any after-tax gains above book value will be used to offset stranded costs, as determined by the PUCN. Any remaining gains can be used to offset goodwill. After-tax gains may not be sufficient to cover goodwill. However, if the combined Company demonstrates that the divestiture "resulted in a market for generation services that produced market prices that are lower than what could have been achieved otherwise, the combined Company may include in the general rate a request to recover goodwill." The Company expects that the generation sales will be completed by late-2000. Under terms of the stipulation, the merged Company is required to file a general rate case three years after the start of retail competition in the state of Nevada that would give the merged Company the opportunity to recover costs of the merger, provided the merged Company can demonstrate that merger savings exceed merger costs. Merger costs are to be split among the non-competitive, potentially competitive and unregulated services or businesses. An opportunity to recover the non-competitive portion of the merger costs will be addressed in the rate case that follows the start of competition in Nevada. The burden is on the merged Company to prove that merger savings exceed merger costs. The merged Company will also have the opportunity to recover goodwill in the same proceeding. Through June 30, 1999 SPR had incurred a total of $11.2 million in capitalized costs since merger work began. 11 ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK There have been no material changes to the information previously disclosed regarding quantitative and qualitative market risk in the Company's Annual Report on Form 10K. 12 PART II ITEM 1. LEGAL PROCEEDINGS Although the Company is involved in ongoing litigation on a variety of matters, it is management's opinion that none individually or collectively are material to the Company's financial position. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS a) The Company held its 1999 Annual Meeting of Shareholders on May 17, 1999. b) The company solicited proxies pursuant to Regulation 14 under the Securities and Exchange Act of 1934; there was no solicitation in opposition to nominees listed in the proxy statement, and all such nominees were elected to the classes indicated in the proxy statement pursuant to the vote of shareholders. c) Re-elected to the Company's Board of Directors were: Krestine M. Corbin Votes For: 26,536,864 Votes Withheld: 338,851 Theodore J. Day Votes For: 21,537,052 Votes Withheld: 338,661 Dennis E. Wheeler Votes For: 26,538,743 Votes Withheld: 337,972 ITEM 5. OTHER INFORMATION None. ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K (a) Exhibits filed with this Form 10-Q: (15) Letter of independent accountants acknowledging awareness regarding unaudited interim financial information of the Company. (27) The Financial Data Schedule containing summary financial information extracted from the condensed consolidated financial statements on Form 10-Q for the six month period ended June 30, 1999, for Sierra Pacific Resources, and is qualified in its entirety by reference to such financial statements. (b) Reports on Form 8-K: None 13 SIGNATURES Pursuant to the requirements 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 Resources ----------------------------- (Registrant) Date: August 11, 1999 By: /s/ Mark A. Ruelle --------------------- --------------------- Mark A. Ruelle Senior Vice President Treasurer Chief Financial Officer (Principal Financial Officer) (Principal Accounting Officer) 14 ================================================================================ UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-Q (Mark One) X QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE - ---- ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED June 30, 1999 OR [_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM TO 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) 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 the number of shares outstanding of each of the issuer's classes of Common Stock, as of the latest practicable date. Class Outstanding at August 13, 1998 Common Stock, $3.75 par value 1,000 Shares ================================================================================ 1 SIERRA PACIFIC POWER COMPANY QUARTERLY REPORT ON FORM 10-Q FOR THE QUARTER ENDED JUNE 30, 1999 CONTENTS PART I - FINANCIAL INFORMATION ------------------------------
Page ----- ITEM 1 . Financial Statements Report of Independent Accountants................................................................ 3 Condensed Consolidated Balance Sheets June 30, 1999 and December 31, 1998........................................................................... 4 Condensed Consolidated Statements of Income - Three Months and Six Months Ended June 30, 1999 and 1998................................................................ 5 Condensed Consolidated Statements of Cash Flows - Six Months Ended June 30, 1999 and 1998................................................................ 6 Notes to Condensed Consolidated Financial Statements............................................. 7 ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.................................................................................... 9 ITEM 3. Quantitative and Qualitative Disclosures about Market Risk...................................................................................... 23
PART II - OTHER INFORMATION ---------------------------
ITEM 1. Legal Proceedings................................................................................ 24 ITEM 5. Other Information................................................................................ 24 ITEM 6. Exhibits and Reports on Form 8-K................................................................. 24 Signature Page............................................................................................. 25 Appendix................................................................................................... 26
2 INDEPENDENT ACCOUNTANTS' REPORT To the Board of Directors and Stockholder of Sierra Pacific Power Company - ---------------------------- Reno, Nevada We have reviewed the accompanying condensed consolidated balance sheet of Sierra Pacific Power Company (the "Company") and subsidiaries as of June 30, 1999, and the related condensed consolidated statements of income and cash flows for the three-month and six-month periods ended June 30, 1999 and 1998. These financial statements are the responsibility of the Company's management. We conducted our review in accordance with standards established by the American Institute of Certified Public Accountants. A review of interim financial information consists principally of applying analytical procedures to financial data and of making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with generally accepted auditing standards, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion. Based on our review, we are not aware of any material modifications that should be made to such condensed consolidated financial statements for them to be in conformity with generally accepted accounting principles. We have previously audited, in accordance with generally accepted auditing standards, the consolidated balance sheet and consolidated statement of capitalization of Sierra Pacific Power Company and subsidiaries as of December 31, 1998, and the related consolidated statements of income, common shareholder's equity, and cash flows for the year then ended (not presented herein); and in our report dated January 29, 1999, (February 12, 1999 as to Notes 1 and 3) we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 1998, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived. DELOITTE & TOUCHE LLP Reno, Nevada August 5, 1999 3 SIERRA PACIFIC POWER COMPANY CONDENSED CONSOLIDATED BALANCE SHEETS (Dollars in Thousands)
June 30, December 31, 1999 1998 --------------- --------------- (Unaudited) ASSETS Utility Plant at Original Cost: Plant in service $ 2,374,322 $ 2,348,996 Less: accumulated provision for depreciation 762,799 727,624 ------------- ------------ 1,611,523 1,621,372 Construction work-in-progress 75,141 55,670 ------------- ------------ 1,686,664 1,677,042 ------------- ------------ Investments in subsidiaries and other property, net 63,435 34,022 ============= ============ Current Assets: Cash and cash equivalents 6,503 15,197 Accounts receivable less provision for uncollectible accounts: $4,313 -1999 and $3,461 -1998 102,506 114,380 Materials, supplies and fuel, at average cost 29,829 25,776 Other 2,559 2,692 ------------- ------------ 141,397 158,045 ------------- ------------ Deferred Charges: Regulatory tax asset 65,531 65,619 Other regulatory assets 61,888 61,675 Other 14,936 15,417 ------------- ------------ 142,355 142,711 ------------- ------------ $ 2,033,851 $ 2,011,820 ============= ============ CAPITALIZATION AND LIABILITIES Capitalization: Common shareholder's equity $ 668,000 $ 661,367 Preferred stock 73,115 73,115 Preferred stock subject to mandatory redemption: Company-obligated mandatorily redeemable preferred securities of the Company's subsidiary 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 629,919 606,450 ------------- ------------ 1,419,534 1,389,432 ------------- ------------ Current Liabilities: Short-term borrowings 123,000 105,000 Current maturities of long-term debt and preferred stock 30,485 30,473 Accounts payable 50,011 66,032 Accrued interest 7,580 7,535 Dividends declared 15,165 20,365 Accrued salaries and benefits 13,154 12,131 Other current liabilities 24,772 27,759 ------------- ------------ 264,167 269,295 ------------- ------------ Deferred Credits: Accumulated deferred federal income taxes 165,906 161,697 Accumulated deferred investment tax credit 36,961 37,944 Regulatory tax liability 37,846 38,939 Accrued Retirement Benefits 45,977 42,560 Customer advances for construction 36,462 34,961 Other 26,998 36,992 ------------- ------------ 350,150 353,093 ------------- ------------ $ 2,033,851 $ 2,011,820 ============= ============
The accompanying notes are an integral part of the financial statements. 4 SIERRA PACIFIC POWER COMPANY CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Dollars in Thousands, Except Per Share Amounts)
Three-Months Ended Six-Months Ended June 30, June 30, ------------------------------ ------------------------------ 1999 1998 1999 1998 ------------ ------------ -------------- ------------ (Unaudited) (Unaudited) OPERATING REVENUES: Electric $147,348 $135,169 $291,651 $277,308 Gas 18,851 22,112 56,878 53,478 Water 13,619 11,862 23,900 21,079 -------- -------- -------- -------- 179,818 169,143 372,429 351,865 -------- -------- -------- -------- OPERATING EXPENSES: Operation: Purchased power 42,111 35,377 82,779 73,752 Fuel for power generation 26,367 27,447 52,837 51,327 Gas purchased for resale 12,658 13,510 37,375 32,841 Other 30,765 29,092 54,547 57,920 Maintenance 5,164 6,007 10,660 10,703 Depreciation and amortization 19,498 16,672 38,592 33,593 Taxes: Income taxes 8,597 8,742 20,409 21,402 Other than income 4,821 4,988 9,620 9,881 ======== ======== ======== ======== 149,981 141,835 306,819 291,419 -------- -------- -------- -------- OPERATING INCOME 29,837 27,308 65,610 60,446 -------- -------- -------- -------- OTHER INCOME: Allowance for other funds used during construction - 1,155 - 2,126 Other income - net 213 (275) 220 (153) -------- -------- -------- -------- 213 880 220 1,973 -------- -------- -------- -------- Total Income 30,050 28,188 65,830 62,419 -------- -------- -------- -------- INTEREST CHARGES: Long-term debt 10,071 9,720 19,932 19,487 Other 2,280 1,759 4,883 3,668 Allowance for borrowed funds used during construction and capitalized interest (236) (2,039) (434) (3,721) -------- -------- -------- -------- 12,115 9,440 24,381 19,434 -------- -------- -------- -------- INCOME BEFORE OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES 17,935 18,748 41,449 42,985 Preferred dividend requirements of Company-obligated mandatorily redeemable preferred securities (1,043) (1,043) (2,086) (2,086) -------- -------- -------- -------- INCOME BEFORE PREFERRED DIVIDENDS 16,892 17,705 39,363 40,899 Preferred dividend requirements (1,365) (1,365) (2,730) (2,730) -------- -------- -------- -------- INCOME APPLICABLE TO COMMON STOCK $ 15,527 $ 16,340 $ 36,633 $ 38,169 ======== ======== ======== ========
The accompanying notes are an integral part of the financial statements. 5 SIERRA PACIFIC POWER COMPANY CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Dollars in Thousands)
Six Months Ended June 30, -------------------------------------------- 1999 1998 ---------------- ---------------- (Unaudited) CASH FLOWS FROM OPERATING ACTIVITIES: Income before preferred dividends $ 39,363 $ 40,899 Non-cash items included in income: Depreciation and amortization 38,592 33,593 Deferred taxes and deferred investment tax credit 2,222 (1,579) AFUDC and capitalized interest (434) (5,846) Early retirement and severance amortization 2,096 2,109 Other non-cash (158) 1,427 Changes in certain assets and liabilities: Accounts receivable 11,874 16,570 Materials, supplies and fuel (4,053) (871) Other current assets 133 (1,190) Accounts payable (16,021) (5,371) Other current liabilities (1,919) 3,664 Other - net (8,034) 36 ------------- ------------ Net Cash Flows From Operating Activities 63,661 83,441 ------------- ------------ CASH FLOWS USED IN INVESTING ACTIVITIES: Additions to utility plant (55,708) (66,454) Net customer refunds and contributions in aid construction 9,474 10,319 ------------- ------------ Net cash used for utility plant (46,234) (56,135) ------------- ------------ (Investments in) disposal of subsidiaries and other property - net (29,385) 98 ------------- ------------ Net Cash Used In Investing Activities (75,619) (56,037) ------------- ------------ CASH FLOWS FROM FINANCING ACTIVITIES: Increase in short-term borrowings 17,731 14,037 Proceeds from issuance of long-term debt 23,696 - Reduction of long-term debt (233) (5,188) Investment from the parent company 8,000 5,000 Dividends paid (45,930) (40,730) ------------- ------------ Net Cash Used In Financing Activities 3,264 (26,881) ------------- ------------ Net (decrease) increase in Cash and Cash Equivalents (8,694) 523 Beginning balance in Cash and Cash Equivalents 15,197 6,920 ------------- ------------ Ending balance in Cash and Cash Equivalents $ 6,503 $ 7,443 ============= ============ Supplemental Disclosures of Cash Flow Information: Cash Paid During Period For: Interest $ 26,138 $ 25,178 Income Taxes $ 13,522 $ 36,588
The accompanying notes are an integral part of the financial statements. 6 NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS ---------------------------------------------------- NOTE 1. MANAGEMENT'S STATEMENT - --------------------------------- In the opinion of the management of Sierra Pacific Power Company, hereafter referred to as the Company, the accompanying unaudited interim condensed consolidated financial statements contain all adjustments (consisting of only normal recurring adjustments) necessary to present fairly the condensed consolidated financial position, condensed consolidated results of operations and condensed consolidated cash flows for the periods shown. These condensed consolidated financial statements do not contain the complete detail or footnote disclosure concerning accounting policies and other matters which are included in full year financial statements and therefore, they should be read in conjunction with the Company's audited financial statements included in the Company's Annual Report on Form 10-K for the year ended December 31, 1998. The results of operations for the three and six month period ended June 30, 1999 are not necessarily indicative of the results to be expected for the full year. Principles of Consolidation --------------------------- The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries, Sierra Pacific Power Capital I, Pinon Pine Corp., and Pinon Pine Investment Co. The Company accounts for its ownership of GPSF-B, a Delaware corporation acquired in February 1999, using the equity method because the Company intends to own the entity temporarily. All significant intercompany transactions and balances have been eliminated in consolidation. Reclassifications ----------------- Certain items previously reported for years prior to 1999 have been reclassified to conform to the current year's presentation. Net income and shareholder's equity were not affected by these reclassifications. NOTE 2. RECENT PRONOUNCEMENTS OF THE FASB - ------------------------------------------- In June 1998, the Financial Accounting Standards Board 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 an entity to recognize all derivatives as either assets or liabilities in the statement of financial position, and measure those instruments at fair value. In May 1999, members of the Financial Accounting Standards Board agreed to delay the effective date of Statement 133 to fiscal years beginning after June 15, 2000. The Company is still assessing the impact of SFAS 133 on its financial condition and results of operations. 7 NOTE 3. SEGMENT INFORMATION - ----------------------------- 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. Intersegment revenues are not material. Financial data for business segments is as follows (in thousands).
Three Months Ended June 30, 1999 Electric Gas Water Consolidated - ---------------------- ------------ ------------ ----------- ------------ Operating Revenues $ 147,348 $ 18,851 $ 13,619 $ 179,818 ============ ============ ============ ============ Operating income $ 24,601 $ 1,189 $ 4,047 $ 29,837 ============ ============ ============ ============ Three Months Ended June 30, 1998 Electric Gas Water Consolidated - ---------------------- ------------ ------------ ----------- ------------ Operating revenues $ 135,169 $ 22,112 $ 11,862 $ 169,143 ============ ============ ============ ============ Operating income $ 21,546 $ 2,947 $ 2,815 $ 27,308 ============ ============ ============ ============ Six Months Ended June 30, 1999 Electric Gas Water Consolidated - ---------------------- ------------ ------------ ----------- ------------ Operating Revenues $ 291,651 $ 56,878 $ 23,900 $ 372,429 ============ ============ ============ ============ Operating income $ 51,285 $ 7,479 $ 6,846 $ 65,610 ============ ============ ============ ============ Six Months Ended June 30, 1998 Electric Gas Water Consolidated - ---------------------- ------------ ------------ ----------- ------------ Operating revenues $ 277,308 $ 53,478 $ 21,079 $ 351,865 ============ ============ ============ ============ Operating income $ 47,962 $ 8,110 $ 4,374 $ 60,446 ============ ============ ============ ============
8 ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The information in this Form 10-K includes forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These forward-looking statements relate to anticipated financial performance, management's plans and objectives for future operations, business prospects, outcome of regulatory proceedings, market conditions and other matters. Words such as "anticipate," "believe," "estimate," "expect," "intend," "plan" and "objective," and other similar expressions identify those statements 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) the outcome of ongoing and future regulatory proceedings; (5) management's ability to integrate the operations of SPPC and Nevada Power Company and to implement and realize anticipated cost savings from the Merger; (6) industrial, commercial and residential growth in the service territory of SPPC; (7) fluctuations in electric, gas and other commodity prices and the ability to manage such fluctuations successfully; (8) changes in the capital markets and interest rates affecting the ability to finance capital requirements; (9) the loss of any significant customers; (10) the ability to lessen the risk of the impact of the Year 2000 on internal and external computer and software systems; and (11) 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. 9 RESULTS OF OPERATIONS - --------------------- The components of gross margin are set forth below (dollars in thousands):
Three Months Six Months Ended June 30, Ended June 30, -------------- -------------- Change from Change from 1999 1998 Prior Year % 1999 1998 Prior Year % ------------ ------------ ------------ ------------ ------------ ------------ Operating Revenues: Electric $147,348 $135,169 9.0% $291,651 $277,308 5.2% Gas 18,851 22,112 -14.7% 56,878 53,478 6.4% Water 13,619 11,862 14.8% 23,900 21,079 13.4% ------------ ------------ ------------ ------------ ------------ ------------ Total Revenues 179,818 169,143 6.3% 372,429 351,865 5.8% Energy Costs: Electric 68,478 62,824 9.0% 135,616 125,079 8.4% Gas 12,628 13,510 -6.5% 37,375 32,841 13.8% ------------ ------------ ------------ ------------ ------------ ------------ Total Energy Costs 81,106 76,334 6.3% 172,991 157,920 9.5% ------------ ------------ ------------ ------------ ------------ ------------ Gross Margin 98,712 92,809 6.4% 199,438 193,945 2.8% ============ ============ ============ ============ ============ ============ Gross Margin by Segment: Electric 78,870 72,345 9.0% 156,035 152,229 2.5% Gas 6,223 8,602 -27.7% 19,503 20,637 -5.5% Water 13,619 11,862 14.8% 23,900 21,079 13.4% ------------ ------------ ------------ ------------ ------------ ------------ Total $ 98,712 $ 92,809 6.4% $199,438 $193,945 2.8% ============ ============ ============ ============ ============ ============
The causes for significant changes in specific lines comprising the results of operations are as follows (dollars in thousands):
Three Months Six Months Ended June 30, Ended June 30, -------------- ------------- Change from Change from 1999 1998 Prior Year % 1999 1998 Prior Year % ------------ ------------ ------------ ------------ ------------ ------------ Electric Operating Reveunes: Residential $ 38,486 $ 37,117 3.7% $ 86,011 $ 83,643 2.8% Commercial 46,294 42,068 10.0% 89,699 83,870 7.0% Industrial 46,548 45,758 1.7% 91,915 89,750 2.4% ------------ ------------ ------------ ------------ ------------ ------------ Retail revenues 131,328 124,943 5.1% 267,625 257,263 4.0% Other 16,020 10,226 56.7% 24,026 20,045 19.9% ------------ ------------ ------------ ------------ ------------ ------------ Total Revenues $ 147,348 $ 135,169 9.0% $ 291,651 $ 277,308 5.2% ============ ============ ============ ============ ============ ============ Retail sales in megawatt-hours (MWH) 2,045,998 1,945,699 5.2% 4,139,765 3,970,214 4.3% ------------ ------------ ------------ ------------ ------------ ------------ Average retail revenue per MWH $ 64.19 $ 64.21 0.0% $ 64.65 $ 64.80 -0.2%
Residential revenues increased for the three months and six months ended June 30, 1999 due to a 2.4% increase in total customers over the prior periods and to a lesser extent higher use per customer. 10 Commercial revenues increased for the second quarter of this year compared with the second quarter of 1998 primarily due to higher use per customer. Higher average use per customer resulted from the addition of larger customers included in the commercial classification. Commercial revenues increased for the six months ended June 30, 1999, also due to higher use per customer and a total increase in customers of 2.8%. Industrial revenues increased slightly for the second quarter compared to the prior year primarily due to a 1.1% increase in customers. Industrial revenues increased for six months ended June 30, 1999 due to customer growth and, to a lesser extent, higher use per customer. The increase in use per customer was primarily due to increased production at two of the Company's large gold mining customers' facilities. As reported in the Company's 1998 10-K, gold production costs vary greatly at Nevada mines, along with profitability. Mining reports indicate many of Nevada mines have a production cost of less than $300 per ounce, with some 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, low gold prices may also shorten the expected mine lives of certain Nevada properties as lower grade ore becomes uneconomic to mine. Other electric revenues were higher in the second quarter of 1999 compared to the prior year primarily due to a $5.8 million increase in wholesale electric revenues. Other electric revenues were higher for the six months ended June 30, 1999 due to a $7.8 million increase in wholesale electric sales. This increase was partially offset by a $4.3 million reclassification from operating expense to revenues reflecting a customer refund that resulted from a decision by the Public Utilities Commission of Nevada.
Three Months Six Months Ended June 30, Ended June 30, -------------- -------------- Change from Change from 1999 1998 Prior Year % 1999 1998 Prior Year % ------------ ------------ ------------ ------------ ------------ ------------ Gas Operating Reveunes: Residential $ 8,273 $ 8,457 -2.2% $ 25,216 $ 24,527 2.8% Commercial 4,311 4,458 -3.3% 13,149 13,102 0.4% Industrial 2,391 2,721 -12.1% 6,118 6,569 -6.9% Miscellaneous 412 312 32.1% 943 647 45.7% ------------ ------------ ------------ ------------ ------------ ------------ Total retail revenue 15,387 15,948 -3.5% 45,426 44,845 1.3% Wholesale revenue 3,464 6,164 -43.8% 11,452 8,633 32.7% ------------ ------------ ------------ ------------ ------------ ------------ Total Revenues $ 18,851 $ 22,112 -14.7% $ 56,878 $ 53,478 6.4% ============ ============ ============ ============ ============ ============ Sales Decatherms (Dth): Retail 2,621,342 2,810,977 -6.7% 8,021,177 8,061,047 -0.5% Wholesale 1,797,396 3,334,923 -46.1% 5,548,332 4,582,449 21.1% ------------ ------------ ------------ ------------ ------------ ------------ Total 4,418,738 6,145,900 -28.1% 13,569,509 12,643,496 7.3% ------------ ------------ ------------ ------------ ------------ ------------ Average revenues per Dth Retail $ 5.87 $ 5.67 3.5% $ 5.66 $ 5.56 1.8% Wholesale $ 1.93 $ 1.85 4.3% $ 2.06 $ 1.88 9.6%
Residential and commercial revenues were lower for the second quarter of 1999 compared to the same period in 1998 due to lower usage per customer resulting from warmer weather in Northern Nevada during 1999. This reduction in revenues was partially offset by increases in customers of 4.0% and 4.2%, respectively. Residential and commercial revenues increased for the six months ended June 30, 1999 compared to the prior year because of a 4.0% increase in customers for both customer classifications. The increase in revenues was partially offset by lower use per customer as a result of warmer weather in 1999. 11 Industrial revenues were lower for the three and six months ended June 30, 1998 due to lower use per customer as a result of warmer weather in 1999. Wholesale gas revenues were lower for the second quarter of 1999 compared to the prior year due to less wholesale opportunities. Wholesale revenues were higher for the six months ended June 30, 1999 due to several large gas contracts during the first quarter of 1999.
Three Months Six Months Ended June 30, Ended June 30, -------------- -------------- Change from Change from 1999 1998 Prior Year % 1999 1998 Prior Year % ------------ ------------ ------------ ------------ ------------ ------------ Water Operating Revenues $13,619 $11,862 14.8% $23,900 $21,079 13.4% ============ ============ ============ ============ ============ ============
Water revenues were higher for the second quarter of 1999 due mostly to increased use per customer resulting from warmer weather and less precipitation during 1999. A 3.4% increase in customers during 1999 also contributed to higher revenues during the second quarter. Water revenues increased for the six months ended June 30, 1999 compared to the prior year for the same reasons that second quarter 1999 earnings were higher. A price increase effective April 2, 1999 also contributed to higher year to date revenues in 1999.
Three Months Six Months Ended June 30, Ended June 30, ---------------- ---------------- Change from Change from 1999 1998 Prior Year % 1999 1998 Prior Year % ------------ ------------ ------------ ------------ ------------ ------------ Purchased Power $ 42,111 $ 35,377 19.0% $ 82,779 $ 73,752 12.2% Purchased Power MWH 1,703,474 1,168,352 45.8% 3,023,269 2,356,554 28.3% Average cost per MWH of Purchased Power $ 24.72 $ 30.28 -18.4% $ 27.38 $ 31.30 -12.5%
Purchased power costs were higher for the three and six months ended June 30, 1999 because of increased retail and wholesale electric revenues as discussed previously and as a result of a generation outage. The higher costs were partially offset by lower average unit prices for electricity.
Three Months Six Months Ended June 30, Ended June 30, ---------------- ---------------- Change from Change from 1999 1998 Prior Year % 1999 1998 Prior Year % ------------ ------------ ------------ ------------ ------------ ------------ Fuel for Power Generation $ 26,367 $ 27,447 -3.9% $ 52,837 $ 51,327 2.9% MWHs generated 1,146,340 1,223,265 -6.3% 2,318,707 2,453,018 -5.5% Average cost per MWH of Generated Power $ 23.00 $ 22.44 2.5% $ 22.79 $ 20.92 8.9%
12 Fuel for generation costs were lower for the second quarter of 1999 because of a longer than anticipated plant outage for scheduled maintenance. Fuel for generation costs increased for the six months ended June 30, 1999 because of higher gas unit prices and the absence of Department of Energy co-funding of fuel costs at the Pinon Pine project. However, the increase in fuel for generation costs was partially offset by lower coal prices and reduced generation due to the plant outage discussed previously.
Three Months Six Months Ended June 30, Ended June 30, ---------------- ---------------- Change from Change from 1999 1998 Prior Year % 1999 1998 Prior Year % ------------ ------------ ------------ ------------ ------------ ------------ Gas Purchased for Resale Retail $ 9,444 $ 7,808 21.0% $ 27,005 $ 24,709 9.3% Wholesale 3,214 5,702 -43.6% 10,370 8,132 27.5% ------------ ------------ ------------ ------------ ------------ ------------ Total 12,658 13,510 -6.3% 37,375 32,841 13.8% ============ ============ ============ ============ ============ ============ Gas Purchased for Resale Dth Retail 2,621,426 2,881,142 -9.0% 8,024,967 8,129,377 -1.3% Wholesale 1,797,396 3,337,397 -46.1% 5,548,332 4,584,923 21.0% ------------ ------------ ------------ ------------ ------------ ------------ Total 4,418,822 6,218,539 -28.9% 13,573,299 12,714,300 6.8% ============ ============ ============ ============ ============ ============ Average cost per Dth Retail $ 3.60 $ 2.71 32.8% $ 3.37 $ 3.04 10.9% Wholesale $ 1.79 $ 1.71 4.7% $ 1.87 $ 1.77 5.6%
The cost of retail gas purchased for resale increased for the three and six months ended June 30, 1999 because of considerably higher gas unit prices. The increase in gas unit prices is attributable to increased demand for gas in the Pacific Northwest and additional transportation fees.
Three Months Six Months Ended June 30, Ended June 30, -------------- -------------- Change from Change from 1999 1998 Prior Year % 1999 1998 Prior Year % ------------ ------------ ------------ ------------ ------------ ------------ Allowance for other funds used during construction $ - $1,155 -100.0% $ - $2,126 -100.0% Allowance for borrowed funds used during construction 236 2,039 -88.4% 434 3,721 -88.3% ------------ ------------ ------------ ------------ ------------ ------------ $ 236 $3,194 -92.6% $ 434 $5,847 -92.6% ============ ============ ============ ============ ============ ============
Total allowance for funds used during construction (AFUDC) is lower for the three and six months ended June 30, 1999 because of construction completed in June and December 1998 for the Pinon and Alturas projects, respectively. The current AFUDC rate calculation results in the entire amount being reflected as borrowed funds in 1999. 13
Three Months Six Months Ended June 30, Ended June 30, -------------- -------------- Change from Change from 1999 1998 Prior Year % 1999 1998 Prior Year % ------------ ------------ ------------ ------------ ------------ ------------ Other operating expense $30,765 $29,092 5.8% $54,547 $57,920 -5.8% Maintenance expense 5,164 6,007 -14.0% 10,660 10,703 -0.4% Depreciation and amortization 19,498 16,672 17.0% 38,592 33,593 14.9% Income taxes 8,597 8,742 -1.7% 20,409 21,402 -4.6% Interest charges-other 2,280 1,759 29.6% 4,883 3,668 33.1%
Other operating expense was higher for the second quarter of 1999 due higher claims reserves during the current year and adjustments that reduced costs during 1998 related to stock compensation and the water rate case decision. Operating expense was primarily lower for the six months ended June 30, 1999 due to a reclassification of $4.3 million from expense to a contra-revenue in order to reflect a refund resulting from the 1997 earnings sharing decision by the Public Utilities Commission of Nevada. The decrease in costs was partially offset by the costs increases that occurred in the second quarter of 1999 as described above. Maintenance costs were lower for the second quarter of 1999 because of lower program costs to replace electric insulators during the current year. Maintenance costs for the six months ended June 30, 1999 were comparable with prior year amounts. Depreciation and amortization expense increased for the three and six months ended due to the completion of the Alturas intertie in December 1998 and Pinon post-gasification facilities closed to plant in June 1998. Operating income taxes decreased for the three and six months ended June 30, 1999 due to lower operating income before income taxes and a lower effective tax rate during the current year. Interest charges-other were higher for the three and six months ended June 30, 1999 because of a Public Utilities Commission of Nevada's decision to assess partial interest to amounts payable in the 1997 earnings sharing case and higher short-term borrowing in 1999. FINANCIAL CONDITION, LIQUIDITY AND CAPITAL RESOURCES ---------------------------------------------------- During the first six months of 1999, the Company earned $39.4 million in income before preferred dividends. It declared $2.7 million in dividends to holders of its preferred stock and declared $38 million in common stock dividends to its parent, Sierra Pacific Resources. Cash flows during the six months ended June 30, 1999 decreased compared to the same period in 1998. Cash flows were less in 1999 due to less cash provided from operating activities, more cash used for investing activities. The decrease in current year cash flows was partially offset by cash provided from financing activities during the current year. The decrease in cash provided from operating activities was primarily due to cash utilized for customer refunds and financing costs paid in connection with the merger. The increase in cash used for investing activities was due to the Company's acquisition of General Electric Capital Corporation's interest in Pinon Pine Company L.L.C. GPSF-B. Cash provided by financing activities resulted from the issuance of California rate reductions bonds. See the Regulatory Matters section for more details regarding the California bonds. 14 Construction Expenditures and Financing - --------------------------------------- The Company's construction program and capital requirements for the period 1999-2003 were originally discussed in the Company's 1998 Annual Report on Form 10-K. Of the amount projected for 1999 ($112.7 million), $46.2 million (41.0%) had been spent as of June 30, 1999. Internally-generated funds exceeded all construction expenditures. On July 28, 1999, immediately following the consummation of the merger between SPR and Nevada Power Company, the Company put into place a $150 million unsecured revolving credit facility with Mellon Bank, N.A., as Administrative Agent, First Union National Bank and Wells Fargo Bank, N.A., as Syndication Agents, and certain other participating banks. This facility may be used for working capital and general corporate purposes, including for commercial paper backup, and replaced all existing credit facilities of the Company. At the same time, the Company revised its existing commercial paper program. Pinon Pine Power Project - ------------------------ As reported in its Annual Report on Form 10K, the Company has been in dispute with the DOE concerning funding of the remaining $14 million under the cooperative agreement and the allowance of previously incurred natural gas fuel cost paid by the DOE. Negotiations have been occurring and a partial settlement has been reached. The DOE has agreed to resume funding of the O&M costs as well as fuel charges incurred during startup of the gasifier. On July 26, 1999, the DOE transferred $2.7 million for O&M and fuel charges for the period January through May 1999. The Company is still in negotiations regarding the natural gas charges incurred while the gasifier was not operational. The negotiations should be finalized by the end of the third quarter, 1999. The Company is continuing in its efforts to obtain sustained operation of the gasifier by identifying and redesigning problem areas. On July 28, 1999, immediately following the consummation of the merger between SPR and Nevada Power Company, the Company put into place a $150 million unsecured revolving credit facility with Mellon Bank, N.A., as Administrative Agent, First Union National Bank and Wells Fargo Bank, N.A., as Syndication Agents, and certain other participating banks. This facility may be used for working capital and general corporate purposes, including for commercial paper backup, and replaced all existing credit facilities of the Company. At the same time, the Company revised its existing commercial paper program. Merger - ------ On July 28, 1999 the merger between the Company's parent (Sierra Pacific Resources) and Nevada Power Company was finalized. Following approvals from the Department of Justice (April 16, 1999) and the SEC (expiration of comment period on June 8, 1999), the PUCN gave unanimous approval, on June 11, 1999, of a stipulation between the merging companies, PUCN staff and the Utility Consumer Advocate, regarding the merging companies' joint divestiture plan. As part of the stipulation, the companies were required to re-file the divestiture plan and file the final Independent System Administrator (ISA) proposal with the PUCN and the Federal Energy Regulatory Commission (FERC). The filings were submitted in July 1999. The PUCN merger order provides that upon selling the generating units, both companies can determine how they will use the proceeds of the sales, up to the book value of the plants. Any after-tax gains above book value will be used to offset stranded costs, as determined by the PUCN. Any remaining gains can be used to offset goodwill. After-tax gains may not be sufficient to cover goodwill. However, if the combined Company demonstrates that the divestiture "resulted in a market for generation services that produced market prices that are lower than what could have been achieved otherwise, the combined Company may include in the general rate a request to recover goodwill." The Company expects that the generation sales will be completed by late-2000. Under terms of the stipulation, the merged company is required to file a general rate case three years after the start of retail competition in the state of Nevada that would give the merged company the opportunity to recover costs of the merger, provided the merged company can demonstrate that merger savings exceed merger costs. Merger costs are to be split among the non-competitive, potentially competitive and unregulated services or businesses. An opportunity to recover the non-competitive portion of the merger costs will be addressed in the rate case that follows the start of competition in Nevada. The burden is on the merged Company to prove that merger savings exceed merger costs. The merged company will also have the opportunity to recover goodwill in the same proceeding. 15 Through June 30, 1999 the Company had incurred a total of $11.2 million in capitalized costs since merger work began. Note: See Regulatory Matters - Electric Restructuring Activities, ------------------- --------------------------------- regarding Senate Bill 438, and its impact on the merged company and generation divestiture. Regulatory Matters - ------------------ Nevada Matters Earnings Sharing -------------- - ---------------- In February 1997, the PUCN approved a rate plan that provided for a 50/50 sharing between customers and Company shareholders of electric and gas utility earnings in excess of a 12 percent return on average equity. In lieu of refunds, the Company has an opportunity, subject to certain conditions, to apply excess earnings toward buying out of long-term fuel and purchased power contracts. The earnings sharing agreement applies to each of the three years ending December 31, 1999, 1998 and 1997. On April 21, the PUCN approved refunds of $8.0 million in electric and $1.5 in gas, plus interest, for the 1997 earnings sharing case. The gas refund reflects the PUCN's acceptance of the Company's recommendation to apply $ 0.4 million of the refund to offset the variable interest receivable balance. The PUCN deferred its decision on several issues which could result in an additional $ 1.5 million of refunds in the 1997 earnings sharing case. The Company had originally requested to refund $ 7.3 million for electric and $ 1.7 million for gas. All amounts are provided for in the financial statements. On April 30, 1999, the Company filed an earnings sharing request, based on 1998 earnings, of $7.0 million for electric customers and $1.9 million for gas customers. The Company reached a tentative settlement on this issue with the staff of the PUCN in July 1999. Affiliate Transaction Rules and Affiliate Applications to Provide Potentially Competitive Services The Company and Nevada Power filed a joint motion to set aside or modify the affiliate transaction rules adopted by the PUCN on January 14, 1999. The companies requested the PUCN to modify the rules related to name/logo, sharing services, sharing officers and directors, and transfer pricing. To date the PUCN has not acted on this motion. On March 30, 1999 the Company and Nevada Power filed with the District Court a "Complaint and Petition for Declaratory and Injunctive Relief and for Judicial Review" relating to the Affiliate Transaction Rules. The companies asked that the court find that the rules "violate plaintiff's federal and state constitutional guarantees, are unlawful and invalid because they were enacted in violation of the procedural and substantive provisions of the Administrative Procedures Act, and are unlawful and invalid because they exceed the authority of the PUCN and are unsupported by the evidence." The companies asked that the court order the PUCN "to cease and desist from enforcing the regulations." There has been no action in the court case. The PUCN issued an order consolidating the merging companies applications for authorization to provide potentially competitive services, and hearings began on June 28, 1999. The PUCN order is expected in the third quarter. 16 Electric Restructuring Activities In July 1997, the Governor of Nevada signed into law Assembly Bill 366 (AB366) which provides for competition to be implemented in the electric utility industry in the state no later than December 31, 1999. However, in early February 1999, the PUCN recommended to the state legislature that the start date for competition be delayed to allow more time for consideration of issues as a result of restructuring. On April 19, 1999, the Nevada Senate passed SB438, which is an amendment to AB366. In July 1999 the Governor of Nevada signed SB438 into law. The new law, contingent upon the completion of the SPR/NPC merger, contains the following provisions: . Adds metering and billing as potentially competitive services. . Changes start date for competition to March 1, 2000; any decision to further delay the start date to be made by the governor, not the PUCN. . Electric distribution utility is the Provider of Last Resort (PLR) until alternate methods go into effect. . Sets PLR rates at existing rates, except that Nevada Power may submit one more deferred energy case before October 1, 1999; PLR may reduce rates below this level. . Only the PLR may request a reduction in its rates during the period March 1, 2000 through March 1, 2003. . Allows the use of the net proceeds of generation divestiture to pay for any reduction in PLR rates below the cap described above, during the period March 1, 2000 to March 1, 2003. . Repeals deferred energy for electric on October 1, 1999. . Permits alternative sellers to submit bids to provide PLR service after July 1, 2001, subject to a PUCN public interest finding and a PUCN-held auction. . Requires utilities to comply with terms of existing purchase power obligations; specifies criteria for recovery of purchase power costs; prevents PUCN from direct or indirect action to modify or terminate any purchase power obligation. . If utility purchases generation from a divested unit for PLR service the PUCN cannot impute a value of the generation unit other than the sales price of the unit. . PUCN must consider in determining recoverable costs, the failure of a utility to minimize income tax effect of gains and losses of assets and obligations. . PUCN must include in recoverable costs any reasonable costs incurred by the utility for severance, early retirement, and related items. . Allows affiliates providing potentially competitive services to use name and logo of utility. . SB 438 does not impair rights under existing electric service contracts or labor agreements. . Utilities may enter into contracts with customers prior to March 1, 2000; specifies that alternative sellers may aggregate two or more customers; prohibits PUCN from limiting ability of alternative sellers to aggregate customers and for customers to form groups for aggregation. . Allows the PUCN to use "hearing officers" to conduct hearings. The following are highlights of recent restructuring activity: Compliance Plan (Dockets 99-4001/4002) On April 1, 1999, the Company filed Phase I, the revenue requirements and unbundling study portions, of the Restructuring Compliance Filing with the PUCN. The filing includes the development of electric revenue requirements for the test period 1998. In the unbundling study, the revenue requirements were assigned and allocated to a number of service components including generation, aggregation, transmission, distribution, metering, billing, and customer services. On April 30, 1999, the Company filed Phase II, which included the proposed bundled rate design. Phase III will be filed 15 days following a PUCN decision on Phases I and II and will include full proposed tariffs for distribution service and all other noncompetitive services. Intervenors will be 17 required to file testimony or alternative proposals at the same time. The hearings were held July 26th through August 2nd. Distribution Open Access Tariffs On January 7, 1999, the PUCN issued an order adopting a final rule for distribution tariffs (adopted as a temporary regulation). On February 1, 1999 the Company filed proposed language for distribution tariffs and filed testimony in support of its distribution tariffs filing on March 9, 1999. On April 9, 1999 a stipulation resolving most issues and agreeing to further filings on unresolved issues was filed with the PUCN. The merging companies conducted informal workshops with the appropriate parties to resolve issues related to Rules 9 (Line Extensions) and 15 (Nom- Utility Generation Facilities) of the Distribution Open Access Tariffs. Settlements resolving both were reached and filed with the PUCN. Past Costs Past costs, which are commonly referred to as stranded costs in other jurisdictions, will continue to be addressed in 1999. AB366 permits the recovery of generation costs pursuant to specified legal criteria. The PUCN has conducted several workshops on past costs in which various topics were discussed, including the characteristics that define recoverable past costs, criteria for evaluating the effectiveness of mitigation efforts, options for cost recovery mechanisms and applicable tax and accounting issues. On April 8, 1999, the PUCN issued a revised proposed rule that specifies the information a utility must include in its request for recovery of past costs. On June 1, 1999, the PUCN began and suspended the hearing on the proposed past cost rule. Due to the passage of SB 438, the PUCN determined that this rule and other regulations should be evaluated to investigate the impact of SB 438. The Company has not completed an estimate of its past costs, since such a calculation is dependent on a variety of issues related to restructuring which are not resolved at this time. These rules are expected to be completed and any required past cost filing to be made by the end of 1999. Provider of Last Resort The provider of last resort (PLR) will provide electric service to customers who do not select an electricity provider and to customers who are not able to obtain service from an alternative seller after the date competition begins. SB 438 specifically provides for the electric distribution utility to provide PLR services until July 1, 2001. The proposed PLR rule will be included in the evaluation of SB 438 impacts addressed in Procedural Order 13. Gas Restructuring 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. Gas Licensing On January 7, 1998, the PUCN issued an order adopting a final rule for licensing which was adopted as a temporary regulation. On February 9, 1999, the PUCN issued a proposed rule for gas licensing fees. On March 23, 1999 the PUCN held a workshop on the proposed rule for licensing fees for alternative sellers. The hearing, also scheduled for this day, was postponed. The PUCN will re-issue the proposed rule and hold hearings at a later date. 18 California Matters ------------------ Rate Reduction Bonds California's electricity restructuring statute (Assembly Bill 1890, Chapter 854, California Statutes of 1996, as amended), permits California investor-owned utilities, including the Company, to finance the recovery of a reduction in electricity rates for residential and small commercial customers through the issuance of rate reduction certificates. Transition costs consist of the costs of generation-related assets and obligations that may become uneconomic as a result of a competitive generation market, together with certain other costs associated therewith. In order for the Company to recover transition and associated costs, the California Public Utilities Commission (CPUC) authorized the establishment of nonbypassable, usage-based, per kilowatt hour charges ("FTA Charges") to be included in the regular utility bills of residential and small commercial consumers located in the historical service territory of the Company in California. The right to receive payments made in respect of the FTA Charges is referred to as Transition Property. On April 9, 1999, The Company sold the Transition Property to SPPC Funding LLC, a Delaware special purpose limited liability company whose sole member is the Company, in exchange for the proceeds of the SPPC Funding LLC Notes, Series 1999-1 (the "Underlying Notes"). SPPC Funding LLC then issued and sold the Underlying Notes to the California Infrastructure and Economic Development Bank Special Purpose Trust SPPC-1 (the "Trust") in exchange for the proceeds of the sale of the Trust's $24.0 million 6.4% Rate Reduction Certificates, Series 1999- 1 (the "Certificates"). The Trust, which had been established by the California Infrastructure and Economic Development Bank, issued and sold the Certificates in a private placement pursuant to Rule 144A under the Securities Act of 1933, as amended. The Certificates are one of a series of rate reduction certificates that may be issued from time to time by the Trust and sold to investors upon terms determined at the time of sale. Revenue Cycle Unbundling On February 18, 1999, the CPUC approved the Company's proposed Revenue Cycle Services Credits (RCSC) application filed February 2, 1998. The RCSC addresses meter ownership, meter services, meter reading, and billing and applies to customers who select their own provider of a revenue cycle service. On April 9, 1999, the Company made a compliance tariff filing which reflects the approved credits. Direct Access Tariffs On April 5, 1999, the CPUC approved the Company's compliance filing, effective back to March 18, 1998, which proposed tariff changes to implement direct access. Rate Unbundling On April 5, 1999, the CPUC approved the Company's proposed unbundled rates effective back to June 1, 1998. Distribution Competition The CPUC has opened a docket item to solicit comments and proposals on distributed generation and competition in electric distribution service. It is too early to determine how this proceeding may affect the Company. Generation Divestiture - ---------------------- The Company has filed with the CPUC its request for approval to sell its generation plants. 19 FERC Matters ------------ Alturas On April 15, 1999 the FERC approved the settlement in the Import Limit Case which had previously been certified by the ALJ in June 1998. The settlement provides for a continuation of the current import limit allocation until the Alturas intertie 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 Resource Plan and a subsequent filing with the FERC in 1999. Regional Transmission Organizations On May 13, 1999, the FERC issued a Notice of Proposed Rulemaking (NOPR) on Regional Transmission Organizations (RTOs). The FERC proposed characteristics of an RTO and also the requirement for utilities to form or join RTOs. Merger On April 14, 1999, the FERC voted to approve the merger of SPR, the Company and Nevada Power, as proposed. In approving the merger the FERC required the companies to divest of their generation facilities (as proposed by the companies) and required Nevada Power to file for an update its transmission rates (also proposed by the companies). On July 14, 1999 the FERC denied TDPUD's rehearing request re the FERC approval. Transmission Rate Case On March 30, 1999, the Company filed with the FERC to increase its open access transmission rates. The Company requested an increase of $16 million in the annual revenue requirement for network service. The point-to-point rate would increase from $ 2.80 /kW-mo. to $ 3.21 /kW-mo. This filing incorporates the Alturas intertie, completed in December 1998, and the reclassification of transmission and distribution facilities approved by the PUCN last summer. On May 28, 1999, as expected, the FERC issued an order setting the rate case for hearing. The proposed rates are accepted subject to refund and suspended until November 1, 1999. On June 14, 1999, as required by the May 28 order, the Company filed additional information on the proposed transmission and distribution (T&D) reclassification. The Company also requested that the FERC accept the filing and approve the T&D split. On July 29, 1999 the FERC accepted the Company's proposed T&D reclassification. Generation Tariffs On March 31, 1999, the Company filed Docket No. ER99-2332 with the FERC for approval of generation tariffs that contain the rates, terms and conditions under which the new owners of the Company's generation would operate after divestiture. The tariffs permit market-based rates after the offering of capacity under a cost-based recourse approach. After motions to intervene protesting the Company's filing were filed by several entities, the Company, on May 5, 1999, filed an answer to the protests. On July 20, 1999 the Company filed a motion to expedite FERC's consideration of the tariff. Consistent with the Nevada merger "Joint Proposal", the Company requested that the FERC approve the tariff by September 30, as the PUCN issues have been resolved. 20 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 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 such as 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 Company has successfully completed implemented 100% of its business systems. 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 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 continues to contact other manufacturers of embedded system components to determine if their components are Y2K ready. As of June 30, 1999, 100% of the Company's mission critical embedded systems are Y2K ready. The Company's Y2K readiness activities are tracked and reported monthly to the North American Electric Reliability Council (NERC), an association comprised of all segments of the electric industry. NERC expects utilities to have completed all Y2K testing and remediation by June 30, 1999. The Company has met that expectation and has filed a letter with NERC expressing its readiness. 21 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 Company has met one on one with several of its critical vendors and suppliers to assess their Y2K readiness. From these meetings, the Company feels that these vendors and suppliers have a viable Y2K program and that they will meet their commitments to the Company. If it becomes necessary, 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 many 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 electric generation, water, gas, telecommunications, building facilities, 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. Additionally, the Company's Emergency Operations Center (EOC) will be activated for the century rollover. Generation, Systems Control, and Transmission/Distribution contingency plans are complete. The remaining Company plans will be complete by the end of September, 1999. 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 from Y2K problems 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 believes that its most reasonable likely worst case scenario is the extent to which any of these parties experiences 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 customers related to 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 contingency plans are being developed to address the potential failure of an external party to be Y2K ready. 22 Financial Implications With 100% of mission critical components tested, findings indicate that the transition through critical Y2K dates is expected to have minimal impact on the Company's Electric, Gas, and Water operations. These results are reflected in reduced costs discussed below. The Company currently estimates that its total incremental expenditures for the Y2K effort, since it began identification of Y2K cost, will be approximately $5.9 million, through December 1999. This estimate has been reduced from amounts previously reported based on updated assessments of the project costs. Y2K costs include assessment, remediation, testing and contingency planning activities. Of the total project costs, about $3.7 million has been incurred through June 30, 1999. Approximately $2.4 million of the expenditures relate to business systems, and $1.3 million relate to the Company's embedded systems. The Company anticipates that the remaining expenditures will be spent on remediating non-mission critical systems, and equipment necessitated by the contingency plans. 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. ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK There have been no material changes to the information previously disclosed regarding quantitative and qualitative market risk in the Company's Annual Report on Form 10K. 23 PART II ------- ITEM 1. LEGAL PROCEEDINGS None. ITEM 5. OTHER INFORMATION None ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K (a) Exhibits filed with this Form 10-Q. (27) The Financial Data Schedule containing summary financial information extracted from the condensed consolidated financial statements filed on Form 10-Q for the six month period ended June 30, 1999, for Sierra Pacific Power Company and is qualified in its entirety by reference to such financial statements. (b) Reports on Form 8-K None 24 SIGNATURES Pursuant to the requirements 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 ------------------------------- (Registrant) Date: August 11, 1999 By /s/ Mark A. Ruelle ----------------------------- ------------------------------ Mark A. Ruelle Senior Vice President and Chief Financial Officer (Principal Financial Officer) Date: August 11, 1999 By /s/ Mary O. Simmons ------------------------------ ------------------------------ Mary O. Simmons Controller (Principal Accounting Officer) 25 EX-15 2 LETTER OF INDEPENDENT ACCOUNTANTS Exhibit 15 to the June 30, 1998 Form 10-Q of Sierra Pacific Resources Sierra Pacific Resources 6100 Neil Road Reno, Nevada 89511 We have made a review, in accordance with standards established by the American Institute of Certified Public Accountants, of the unaudited interim financial information of Sierra Pacific Resources and subsidiaries for the periods ended June 30, 1999 and 1998, as indicated in our report dated August 5, 1999; because we did not perform an audit, we expressed no opinion on that information. We are aware that our report referred to above, which is included in your Quarterly Report on Form 10-Q for the quarter ended June 30, 1998, is incorporated by reference in Registration Statement No. 333-4374 of Sierra Pacific Resources on Form S-3, Registration Statement No. 333-62895 on Form S-4, and Registration Nos. 2-92454, 33-87646, and 33-48152 on Forms S-8. We also are aware that the aforementioned report, pursuant to Rule 436(c) under the Securities Act of 1933, is not considered a part of the Registration Statement prepared or certified by an accountant or a report prepared or certified by an accountant within the meaning of Sections 7 and 11 of that Act. DELOITTE & TOUCHE LLP Reno, Nevada August 9, 1999 15 EX-27 3 FINANCIAL DATA SCHEDULE
UT The schedule contains summary financial information extracted from the Company's financial records and is qualified in its entirety by reference to such financial statements. 6-MOS DEC-31-1998 JUN-30-1999 PER-BOOK 1,686,664 88,535 145,030 148,701 0 2,068,920 31,027 457,975 198,166 687,168 48,500 73,115 630,111 123,000 0 0 40,597 0 0 0 466,429 2,068,920 376,943 19,513 293,029 312,542 64,401 259 64,660 24,892 39,768 2,086 37,682 21,693 0 58,060 .50 .50
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