-----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, QLxIQxpdPbbDir1gf1csaWrFYD8LsLR5V/oFeUhDAN2Drv4js2VrAfe7+QTcK84W ogmEFl5Hd3isnit2KKptXQ== /in/edgar/work/0000898430-00-003409/0000898430-00-003409.txt : 20001115 0000898430-00-003409.hdr.sgml : 20001115 ACCESSION NUMBER: 0000898430-00-003409 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 4 CONFORMED PERIOD OF REPORT: 20000930 FILED AS OF DATE: 20001114 FILER: COMPANY DATA: COMPANY CONFORMED NAME: SIERRA PACIFIC RESOURCES CENTRAL INDEX KEY: 0000741508 STANDARD INDUSTRIAL CLASSIFICATION: [4931 ] IRS NUMBER: 880198358 STATE OF INCORPORATION: NV FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: SEC FILE NUMBER: 001-08788 FILM NUMBER: 762919 BUSINESS ADDRESS: STREET 1: PO BOX 30150 STREET 2: 6100 NEIL RD CITY: RENO STATE: NV ZIP: 89511 BUSINESS PHONE: 7758344011 MAIL ADDRESS: STREET 1: P O BOX 30150 STREET 2: 6100 NEIL ROAD CITY: RENO STATE: NV ZIP: 89511 FILER: COMPANY DATA: COMPANY CONFORMED NAME: NEVADA POWER CO CENTRAL INDEX KEY: 0000071180 STANDARD INDUSTRIAL CLASSIFICATION: [4911 ] IRS NUMBER: 880045330 STATE OF INCORPORATION: NV FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: SEC FILE NUMBER: 002-28348 FILM NUMBER: 762920 BUSINESS ADDRESS: STREET 1: 6226 W SAHARA AVE CITY: LAS VEGAS STATE: NV ZIP: 89146 BUSINESS PHONE: 7023675000 MAIL ADDRESS: STREET 1: P O BOX 230 CITY: LAS VEGAS STATE: NV ZIP: 89151 FORMER COMPANY: FORMER CONFORMED NAME: SOUTHERN NEVADA POWER CO DATE OF NAME CHANGE: 19701113 FILER: COMPANY DATA: COMPANY CONFORMED NAME: SIERRA PACIFIC POWER CO CENTRAL INDEX KEY: 0000090144 STANDARD INDUSTRIAL CLASSIFICATION: [4931 ] IRS NUMBER: 880044418 STATE OF INCORPORATION: NV FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: SEC FILE NUMBER: 000-00508 FILM NUMBER: 762921 BUSINESS ADDRESS: STREET 1: 6100 NEIL RD STREET 2: P O BOX 10100 CITY: RENO STATE: NV ZIP: 89520-0400 BUSINESS PHONE: 7026895408 MAIL ADDRESS: STREET 1: 6100 NEIL ROAD STREET 2: P.O. BOX 10100 CITY: RENO STATE: NV ZIP: 89520 10-Q 1 0001.txt FORM 10-Q FOR THE PERIOD ENDED SEPTEMBER 30, 2000 ================================================================================ 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 SEPTEMBER 30, 2000 OR [_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM TO
Registrant, State of Incorporation, Address of Commission File Principal Executive Offices and Telephone I.R.S. employer Number Number Identification Number 1-8788 SIERRA PACIFIC RESOURCES 88-0198358 P.O. Box 10100 (6100 Neil Road) Reno, Nevada 89520-0400 (89511) (775) 834-4011 1-4698 NEVADA POWER COMPANY 88-0045330 6226 West Sahara Avenue Las Vegas, Nevada 89146 (702) 367-5000 0-508 SIERRA PACIFIC POWER COMPANY 88-0044418 P.O. Box 10100 (6100 Neil Road) Reno, Nevada 89520-0400 (89511) (775) 834-4011
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 November 3, 2000 Common Stock, $1.00 par value 78,450,966 Shares of Sierra Pacific Resources Sierra Pacific Resources is the sole holder of the 1,000 shares of outstanding Common Stock, $1.00 stated value, of Nevada Power Company. Sierra Pacific Resources is the sole holder of the 1,000 shares of outstanding Common Stock, $1.00 stated value, of Sierra Pacific Power Company. This combined Quarterly Report on Form 10-Q is separately filed by Sierra Pacific Resources, Nevada Power Company and Sierra Pacific Power Company. Information contained in this document relating to Nevada Power Company is filed by Sierra Pacific Resources and separately by Nevada Power Company on its own behalf. Nevada Power Company makes no representation as to information relating to Sierra Pacific Resources or its subsidiaries, except as it may relate to Nevada Power Company. Information contained in this document relating to Sierra Pacific Power Company is filed by Sierra Pacific Resources and separately by Sierra Pacific Power Company on its own behalf. Sierra Pacific Power Company makes no representation as to information relating to Sierra Pacific Resources or its subsidiaries, except as it may relate to Sierra Pacific Power Company. ================================================================================ SIERRA PACIFIC RESOURCES NEVADA POWER COMPANY SIERRA PACIFIC POWER COMPANY QUARTERLY REPORTS ON FORM 10-Q FOR THE QUARTER ENDED SEPTEMBER 30, 2000 CONTENTS PART I - FINANCIAL INFORMATION ------------------------------ ITEM 1. Financial Statements Sierra Pacific Resources- Condensed Consolidated Balance Sheets-September 30, 2000 and December 31, 1999................................................. 2 Condensed Consolidated Statements of Income-Three Months and Nine Months Ended September 30, 2000 and 1999......................... 3 Condensed Consolidated Statements of Cash Flows-Nine Months Ended September 30, 2000 and 1999...................................... 4 Nevada Power Company- Condensed Balance Sheets - September 30, 2000 and December 31, 1999.............................................................. 5 Condensed Statements of Income - Three and Nine Months Ended September 30, 2000 and 1999....................................... 6 Condensed Statements of Cash Flows - Nine Months Ended September 30, 2000 and 1999...................................................... 7 Sierra Pacific Power Company- Condensed Consolidated Balance Sheets - September 30, 2000 and December 31, 1999................................................. 8 Condensed Consolidated Statements of Income - Three Months and Nine Months Ended September 30, 2000 and 1999.......................... 9 Condensed Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2000 and 1999...................................... 10 Notes to Condensed Consolidated Financial Statements ....................... 11 ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations............................................ 21 Sierra Pacific Resources Results of Operations................... 24 Nevada Power Company Results of Operations ...................... 27 Sierra Pacific Power Company Results of Operations .............. 32 ITEM 3. Quantitative and Qualitative Disclosures about Market Risk........... 42 PART II-OTHER INFORMATION --------------------------- ITEM 1. Legal Proceedings.................................................... 43 ITEM 4. Submission of Matters to a Vote of Security Holders.................. 44 ITEM 5. Other Information.................................................... 44 ITEM 6. Exhibits and Reports on Form 8-K..................................... 44 Signature Page................................................................. 45
1 SIERRA PACIFIC RESOURCES CONDENSED CONSOLIDATED BALANCE SHEETS (Dollars in Thousands)
September 30, December 31, 2000 1999 ------------------ --------------- (Unaudited) ASSETS Utility Plant at Original Cost: Plant in service $ 5,189,875 $ 5,028,204 Less: accumulated provision for depreciation 1,607,945 1,490,600 ------------ ----------- 3,581,930 3,537,604 Construction work-in-progress 342,004 278,530 ------------ ----------- 3,923,934 3,816,134 ------------ ----------- Investments in subsidiaries and other property, net 132,838 105,880 ------------ ----------- Current Assets: Cash and cash equivalents 16,741 4,789 Accounts receivable less provision for uncollectible accounts: 2000-$4,771; 1999-$6,475 416,536 213,452 Materials, supplies and fuel, at average cost 86,113 73,193 Deferred energy costs 900 14,884 Other 52,140 7,003 ------------ ----------- 572,430 313,321 ------------ ----------- Deferred Charges: Goodwill, net of amortization 321,515 327,725 Regulatory tax asset 192,685 192,685 Other regulatory assets 109,993 98,641 Other 123,868 122,677 ------------ ----------- 748,061 741,728 ------------ ----------- Net assets of discontinued operations (Note 9) 260,384 258,574 ------------ ----------- $ 5,637,647 $ 5,235,637 ============ =========== CAPITALIZATION AND LIABILITIES Capitalization: Common shareholders' equity $ 1,397,982 $ 1,477,129 Preferred stock 50,000 50,000 SPPC/ NVP obligated mandatorily redeemable preferred trust securities 237,372 237,372 Long-term debt 2,150,494 1,556,627 ------------ ----------- 3,835,848 3,321,128 ------------ ----------- Current Liabilities: Short-term borrowings 205,175 754,979 Current maturities of long-term debt 455,986 202,709 Accounts payable 272,613 138,448 Accrued interest 43,183 15,394 Dividends declared 19,918 20,850 Accrued salaries and benefits 21,203 15,410 Deferred taxes on deferred energy costs - 5,683 Other current liabilities 17,185 29,773 ------------ ----------- 1,035,263 1,183,246 ------------ ----------- Commitments & Contingencies (Note 10) Deferred Credits: Deferred federal income taxes 415,096 405,594 Deferred investment tax credit 57,285 62,604 Regulatory tax liability 48,391 49,160 Customer advances for construction 111,408 109,422 Accrued retirement benefits 81,825 67,314 Other 52,531 37,169 ------------ ----------- 766,536 731,263 ------------ ----------- $ 5,637,647 $ 5,235,637 ============ ===========
The accompanying notes are an integral part of the financial statements. 2 SIERRA PACIFIC RESOURCES CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Dollars in Thousands, Except Per Share Amounts)
Three Months Ended Nine Months Ended September 30, September 30, --------------------- -------------------- 2000 1999 2000 1999 ------- ------- ------- ------ (Unaudited) (Unaudited) OPERATING REVENUES: Electric $ 852,730 $ 455,617 $ 1,662,592 $ 875,987 Gas 12,967 8,716 64,278 8,716 Other 2,657 2,713 9,165 2,713 --------- --------- ---------- --------- 868,354 467,046 1,736,035 887,416 --------- --------- ---------- --------- OPERATING EXPENSES: Operation: Purchased Power 581,994 136,488 911,773 274,129 Fuel for power generation 151,567 69,697 317,594 135,725 Gas purchased for resale 6,989 6,114 41,310 6,114 Deferral of energy costs net 2,445 4,268 16,719 14,651 Other 56,421 63,305 183,310 130,596 Maintenance 12,288 14,929 40,194 44,158 Depreciation and amortization 39,079 32,340 116,754 71,871 Taxes: Income taxes (14,056) 33,212 (17,310) 40,419 Other than income 11,465 8,782 31,611 19,971 --------- --------- ---------- --------- 848,192 369,135 1,641,955 737,632 --------- --------- ---------- --------- OPERATING INCOME 20,162 97,911 94,080 149,784 --------- --------- ---------- --------- OTHER INCOME: Allowance for other funds used during construction 511 (1,119) 2,486 2,964 Other income (expense) - net 169 (165) 3,578 (1,328) --------- --------- ---------- --------- 680 (1,284) 6,064 1,636 --------- --------- ---------- --------- Total Income Before Interest Charges 20,842 96,627 100,144 151,420 --------- --------- ---------- --------- INTEREST CHARGES: Long term debt 36,227 22,033 89,337 53,499 Other 4,718 6,877 29,618 10,217 Allowance for borrowed funds used during construction and capitalized interest (3,053) 317 (7,779) (3,518) --------- --------- ---------- --------- 37,892 29,227 111,176 60,198 --------- --------- ---------- --------- INCOME (LOSS) BEFORE SPPC/NVP OBLIGATED MANDATORILY REDEEMABLE PREFERRED TRUST SECURITIES (17,050) 67,400 (11,032) 91,222 Preferred dividend requirements of SPPC/NVP obligated mandatorily redeemable preferred trust securities (4,729) (4,421) (14,187) (12,008) --------- --------- ---------- --------- INCOME (LOSS) BEFORE PREFERRED STOCK DIVIDENDS (21,779) 62,979 (25,219) 79,214 Preferred stock dividend requirements of subsidiary (875) (833) (2,624) (917) --------- --------- ---------- --------- INCOME (LOSS) FROM CONTINUING OPERATIONS (22,654) 62,146 (27,843) 78,297 --------- --------- ---------- --------- DISCONTINUED OPERATIONS: Income from operations of water business to be disposed of (net of income taxes of $3,800 and $5,254 in 2000, and $733 and $733 in 1999, respectively) 3,106 2,554 6,282 2,554 --------- --------- ---------- --------- NET INCOME (LOSS) $ (19,548) $ 64,700 $ (21,561) $ 80,851 ========= ========= ========== ========= Income (loss) per share - Basic Income (loss) from continuing operations $ (0.29) $ 0.89 $ (0.35) $ 1.37 Income from discontinued operations 0.04 0.04 0.08 0.04 --------- --------- ---------- --------- Net income (loss) $ (0.25) $ 0.93 $ (0.27) $ 1.41 ========= ========= ========== ========= Income (loss) per share - Diluted Income (loss) from continuing operations $ (0.29) $ 0.89 $ (0.35) $ 1.37 Income from discontinued operations 0.04 0.04 0.08 0.04 --------- --------- ---------- --------- Net income (loss) $ (0.25) $ 0.93 $ (0.27) $ 1.41 ========= ========= ========== ========= Weighted Average Shares of Common Stock Outstanding (000's) 78,446 69,365 78,428 57,298 ========= ========= ========== ========= Dividends Paid Per Share of Common Stock $ 0.250 $ 0.250 $ 0.750 $ 0.750 ========= ========= ========== =========
The accompanying notes are an integral part of the financial statements. 3 SIERRA PACIFIC RESOURCES CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Dollars in Thousands)
Nine Months Ended September 30, ---------------------------- 2000 1999 -------- -------- (Unaudited) CASH FLOWS FROM OPERATING ACTIVITIES: Income before preferred dividends from continuing operations $(25,219) $ 79,214 Income before preferred dividends from discontinued operations 6,583 2,642 Non cash items included in income: Depreciation and amortization 122,269 73,156 Deferred taxes and deferred investment tax credit (1,444) 9,885 AFUDC and capitalized interest (10,567) (6,540) Deferred energy costs 13,984 - Early retirement and severance amortization 3,147 699 Other non cash (310) 12,547 Changes in certain assets and liabilities, net of acquisition: Materials, supplies and fuel (12,830) (23,239) Accounts receivable (203,084) (47,555) Other current assets (45,161) (11,293) Accounts payable 134,165 12,526 Other current liabilities 15,311 34,588 Other-net 37,499 (16,504) ---------- --------- Net Cash Flows From Operating Activities 34,343 120,126 ---------- --------- CASH FLOWS USED IN INVESTING ACTIVITIES: Acquisition of business, net of cash acquired - (448,311) Additions to utility plant (241,221) (195,430) Non cash charges to utility plant 3,573 - Contributions in aid of construction 11,687 - Customer refunds for construction 1,985 10,424 ---------- --------- Net cash used for utility plant (223,976) (633,317) ---------- --------- Investments in subsidiaries and other property - net (26,958) (1,036) ---------- --------- Net Cash Used In Investing Activities (250,934) (634,353) ---------- --------- CASH FLOWS FROM FINANCING ACTIVITIES: Increase (decrease) in short-term borrowings (553,766) 411,025 Proceeds from issuance of long-term debt 1,050,000 230,303 Retirement of long-term debt and preferred stock (202,778) (53,296) Sale of common stock 37 - Dividends paid (64,950) (46,780) ---------- --------- Net Cash Provided By Financing Activities 228,543 541,252 ---------- --------- Net increase in Cash and Cash Equivalents 11,952 27,025 Beginning balance in Cash and Cash Equivalents 4,789 1,770 ---------- --------- Ending balance in Cash and Cash Equivalents $ 16,741 $ 28,795 ========== ========= Supplemental Disclosures of Cash Flow Information: Cash Paid During Period For: Interest $ 99,741 $ 65,458 Income Taxes $ 12,730 $ 17,219
The accompanying notes are an integral part of the financial statements 4 NEVADA POWER COMPANY CONDENSED BALANCE SHEETS (Dollars in Thousands)
September 30, December 31, 2000 1999 ------------ ------------ (Unaudited) ASSETS Utility Plant at Original Cost: Plant in service $ 3,042,565 $ 2,928,973 Less: accumulated provision for depreciation 838,531 772,003 ----------- ----------- 2,204,034 2,156,970 Construction work in progress 225,767 195,671 ----------- ----------- 2,429,801 2,352,641 ----------- ----------- Investments in Sierra Pacific Resources (Note 2) 529,934 654,156 Investments in subsidiaries and other property, net 13,939 15,644 ----------- ----------- 543,873 669,800 ----------- ----------- Current Assets: Cash and cash equivalents 4,669 243 Accounts receivable less provision for uncollectible accounts: 2000-$3,512; 1999-$2,826 258,872 110,955 Materials, supplies and fuel, at average cost 43,984 43,108 Deferred energy costs - 14,884 Other 20,814 3,573 ----------- ----------- 328,339 172,763 ----------- ----------- Deferred Charges: Regulatory tax asset 130,834 130,833 Other regulatory assets 30,818 28,190 Other 22,483 24,258 ----------- ----------- 184,135 183,281 ----------- ----------- $ 3,486,148 $ 3,378,485 =========== =========== CAPITALIZATION AND LIABILITIES Capitalization: Common shareholders' equity including $529,934-2000; $654,156-1999 of equity in Sierra Pacific Resources (Note 2) $ 1,397,982 $ 1,477,129 NVP obligated mandatorily redeemable preferred trust securities 188,872 188,872 Long-term debt 927,118 931,004 ----------- ----------- 2,513,972 2,597,005 ----------- ----------- Current Liabilities: Short-term borrowings 123,063 182,000 Current maturities of long-term debt 253,369 89,842 Accounts payable 147,303 75,088 Accrued interest 18,603 10,098 Dividends declared 16,086 24,126 Accrued salaries and benefits 8,733 7,025 Deferred taxes on deferred energy costs - 5,683 Other current liabilities 15,634 18,536 ----------- ----------- 582,791 412,398 ----------- ----------- Commitments & Contingencies (Note 10) Deferred Credits: Deferred federal income taxes 237,319 236,139 Deferred investment tax credit 25,528 26,624 Regulatory tax liability 14,060 14,993 Customer advances for construction 68,116 69,341 Accrued retirement benefits 29,661 18,262 Other 14,701 3,723 ----------- ----------- 389,385 369,082 ----------- ----------- $ 3,486,148 $ 3,378,485 =========== ===========
The accompanying notes are an integral part of the financial statements. 5 NEVADA POWER COMPANY CONDENSED STATEMENTS OF INCOME (Dollars in Thousands, Except Per Share Amounts)
Three Months Ended Nine Months Ended September 30, September 30, --------------------------- ------------------------- 2000 1999 2000 1999 --------- -------- -------- ------- (Unaudited) (Unaudited) (Unaudited) (Unaudited) OPERATING REVENUES: Electric $ 547,395 $ 349,878 $ 1,022,815 $ 770,248 OPERATING EXPENSES: Operation: Purchased power 385,129 101,070 593,479 238,711 Fuel for power generation 86,140 47,780 178,809 113,808 Deferral of energy costs-net 2,445 4,268 16,719 14,651 Other 33,638 43,952 97,923 111,243 Maintenance 8,126 11,513 27,210 40,740 Depreciation and amortization 21,391 20,613 64,121 60,144 Taxes: Income taxes (5,642) 33,190 (12,461) 40,397 Other than income 6,542 5,626 17,860 16,815 --------- --------- ----------- --------- 537,769 268,012 983,660 636,509 --------- --------- ----------- --------- OPERATING INCOME 9,626 81,866 39,155 133,739 --------- --------- ----------- --------- OTHER INCOME: Equity in earnings of Sierra Pacific Resources (Note 2) (10,766) 1,812 (2,944) 1,812 Allowance for other funds used during construction 430 1,330 2,272 5,413 Other income (expense) - net 1,307 (42) 2,014 (1,205) --------- --------- ----------- --------- (9,029) 3,100 1,342 6,020 --------- --------- ----------- --------- Total Income Before Interest Charges 597 84,966 40,497 139,759 --------- --------- ----------- --------- INTEREST CHARGES: Long term debt 15,980 16,778 46,132 48,244 Other 2,745 1,175 10,677 4,515 Allowance for borrowed funds used during construction and capitalized interest (2,373) (1,491) (6,130) (5,326) --------- --------- ----------- --------- 16,352 16,462 50,679 47,433 --------- --------- ----------- --------- INCOME (LOSS) BEFORE NVP OBLIGATED MANDATORILY REDEEMABLE PREFERRED TRUST SECURITIES (15,755) 68,504 (10,182) 92,326 Preferred dividend requirements of NVP obligated mandatorily redeemable preferred trust securities (3,793) (3,793) (11,379) (11,380) --------- --------- ----------- --------- INCOME (LOSS) BEFORE PREFERRED STOCK DIVIDENDS (19,548) 64,711 (21,561) 80,946 Preferred stock dividend requirements - (11) - (95) --------- --------- ----------- --------- NET INCOME (LOSS) $ (19,548) $ 64,700 $ (21,561) $ 80,851 ========= ========= =========== ========= Net Income (Loss) Per Share -Basic $ (0.25) $ 0.93 $ (0.27) $ 1.41 ========= ========= =========== ========= -Diluted $ (0.25) $ 0.93 $ (0.27) $ 1.41 ========= ========= =========== ========= Weighted Average Shares of Common Stock Outstanding (000's) 78,446 69,365 78,428 57,298 ========= ========= =========== ========= Dividends Paid Per Share of Common Stock $ 0.250 $ 0.250 $ 0.750 $ 0.750 ========= ========= =========== =========
The accompanying notes are an integral part of the financial statements. 6 NEVADA POWER COMPANY CONDENSED STATEMENTS OF CASH FLOWS (Dollars in Thousands)
Nine Months Ended September 30, ----------------------------- 2000 1999 --------- --------- (Unaudited CASH FLOWS FROM OPERATING ACTIVITIES: Income (loss) before preferred dividends $ (21,561) $ 80,946 Non cash items included in income: Depreciation and amortization 64,121 60,143 Deferred taxes and deferred investment tax credit (5,597) 6,950 AFUDC and capitalized interest (8,402) (10,740) Deferred energy costs 14,884 (23,239) Other non cash (2,961) 8,080 Equity in earnings of SPR (Note 2) 2,944 (1,812) Changes in certain assets and liabilities, net of acquisition: Materials, supplies and fuel (876) (4,247) Accounts receivable (147,917) (61,246) Other current assets (17,265) (2,482) Accounts payable 72,215 10,545 Other current liabilities 7,311 37,660 Other net 21,150 (9,252) --------- -------- Net Cash Flows From Operating Activities (21,954) 91,306 --------- -------- CASH FLOWS USED IN INVESTING ACTIVITIES: Additions to utility plant (138,698) (171,372) Non cash charges to utility plant 1,349 4,918 Customer refunds for construction (1,225) 4,828 --------- -------- Net cash used for utility plant (138,574) (161,626) --------- -------- Investments in subsidiaries and other property-net 250 (2,311) --------- -------- Net Cash Used In Investing Activities (138,324) (163,937) --------- -------- CASH FLOWS FROM FINANCING ACTIVITIES: Increase (decrease) in short-term borrowings (58,937) 21,930 Proceeds from issuance of long-term debt 250,000 129,900 Retirement of long-term debt (90,359) (48,533) Change in funds held in trust - - Retirement of preferred stock - (3,265) Additional investment of Parent 128,000 - Dividends paid (64,000) (25,808) --------- -------- Net Cash Provided By Financing Activities 164,704 74,224 --------- -------- Net increase in Cash and Cash Equivalents 4,426 1,593 Beginning balance in Cash and Cash Equivalents 243 1,770 --------- -------- Ending balance in Cash and Cash Equivalents $ 4,669 $ 3,363 ========= ======== Supplemental Disclosures of Cash Flow Information: Cash Paid During Period For: Interest $ 48,303 $ 48,187 Income Taxes $ 6,500 $ 17,219
The accompanying notes are an integral part of the financial statements. 7 SIERRA PACIFIC POWER COMPANY CONDENSED CONSOLIDATED BALANCE SHEETS (Dollars in Thousands)
September 30, December 31, 2000 1999 ------------- ----------- (Unaudited) ASSETS Utility Plant at Original Cost: Plant in service $ 2,147,310 $ 2,097,533 Less: accumulated provision for depreciation 769,414 718,597 ----------- ------------ 1,377,896 1,378,936 Construction work-in-progress 116,236 82,859 ----------- ------------ 1,494,132 1,461,795 ----------- ------------ Investments in subsidiaries and other property, net 60,832 62,704 ----------- ------------ Current Assets: Cash and cash equivalents 6,561 3,011 Accounts receivable less provision for uncollectible accounts: 2000 - $1,259; 1999 - $3,649 110,762 111,175 Materials, supplies and fuel, at average cost 41,885 29,642 Deferred energy costs 900 - Other 19,789 3,103 ----------- ------------ 179,897 146,931 ----------- ------------ Deferred Charges: Regulatory tax asset 61,852 61,852 Other regulatory assets 66,551 67,059 Other 21,257 25,512 ----------- ------------ 149,660 154,423 ----------- ------------ Net assets of discontinued operations (Note 9) 260,384 258,574 ----------- ------------ $ 2,144,905 $ 2,084,427 =========== ============ CAPITALIZATION AND LIABILITIES Capitalization: Common shareholder's equity $ 646,177 $ 673,738 Preferred stock 50,000 50,000 SPPC obligated mandatorily redeemable preferred trust securities 48,500 48,500 Long-term debt 623,297 625,430 ----------- ------------ 1,367,974 1,397,668 ----------- ------------ Current Liabilities: Short-term borrowings 82,000 109,584 Current maturities of long-term debt 202,616 102,755 Accounts payable 93,688 78,491 Accrued interest 15,007 5,110 Dividends declared 16,000 19,974 Accrued salaries and benefits 11,794 8,385 Other current liabilities 4,045 10,673 ----------- ------------ 425,150 334,972 ----------- ------------ Commitments & Contingencies (Note 10) Deferred Credits: Deferred federal income taxes 167,326 161,891 Deferred investment tax credit 31,756 35,980 Regulatory tax liability 34,331 34,167 Accrued retirement benefits 42,148 49,052 Customer advances for construction 43,292 40,081 Other 32,928 30,616 ----------- ------------ 351,781 351,787 ----------- ------------ $ 2,144,905 $ 2,084,427 =========== ============
The accompanying notes are an integral part of the financial statements. 8 SIERRA PACIFIC POWER COMPANY CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Dollars in Thousands)
Three Months Ended Nine Months Ended September 30, September 30, --------------------------- ---------------------------- 2000 1999 2000 1999 --------- ---------- ---------- ---------- (Unaudited) (Unaudited) (Unaudited) (Unaudited) OPERATING REVENUES: Electric $ 305,334 $ 163,564 $ 639,776 $ 455,497 Gas 12,967 13,056 64,278 69,934 --------- --------- --------- --------- 318,301 176,902 704,054 525,431 --------- --------- --------- --------- OPERATING EXPENSES: Operation: Purchased power 196,865 52,564 318,294 135,343 Fuel for power generation 65,427 32,560 138,785 85,397 Gas purchased for resale 6,989 9,603 41,310 46,978 Other 18,608 24,060 68,328 67,974 Maintenance 4,162 5,523 12,984 15,233 Depreciation and amortization 17,561 17,410 52,144 52,193 Taxes: Income taxes (4,591) 5,093 6,605 25,175 Other than income 4,711 4,618 13,352 12,902 --------- --------- --------- --------- 309,732 151,431 651,802 441,195 --------- --------- --------- --------- OPERATING INCOME 8,569 25,471 52,252 84,236 --------- --------- --------- --------- OTHER INCOME: Allowance for other funds used during construction 81 (2,451) 215 (2,445) Other income (expense) - net 117 (601) (1,122) (251) --------- --------- --------- --------- 198 (3,052) (907) (2,696) --------- --------- --------- --------- Total Income 8,767 22,419 51,345 81,540 --------- --------- --------- --------- INTEREST CHARGES: Long - term debt 10,952 7,817 26,861 23,548 Other 1,348 2,004 8,519 6,712 Allowance for borrowed funds used during construction and capitalized interest (680) 1,723 (1,649) 1,312 --------- --------- --------- --------- 11,620 11,544 33,731 31,572 --------- --------- --------- --------- INCOME BEFORE SPPC OBLIGATED MANDATORILY REDEEMABLE PREFERRED TRUST SECURITIES (2,853) 10,875 17,614 49,968 Preferred dividend requirements of SPPC obligated mandatorily redeemable preferred trust securities (935) (942) (2,807) (2,807) --------- --------- --------- --------- INCOME BEFORE PREFERRED DIVIDENDS (3,788) 9,933 14,807 47,161 Preferred dividend requirements (875) (1,233) (2,624) (3,674) --------- --------- --------- --------- INCOME (LOSS) FROM CONTINUING OPERATIONS $ (4,663) $ 8,700 $ 12,183 $ 43,487 --------- --------- --------- --------- DISCONTINUED OPERATIONS: Income from operations of water business to be disposed of (net of income taxes of $3,800 and $5,254 in 2000, and $1,790 and $2,117 in 1999, respectively) 3,106 3,750 6,282 5,597 --------- --------- --------- --------- NET INCOME (LOSS) $ (1,557) $ 12,450 $ 18,465 $ 49,084 ========= ========= ========= =========
The accompanying notes are an integral part of the financial statements. 9 SIERRA PACIFIC POWER COMPANY CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Dollars in Thousands)
Nine Months Ended September 30, ----------------------- 2000 1999 ------- ------- (Unaudited) CASH FLOWS FROM OPERATING ACTIVITIES: Income before preferred dividends from continuing operations $ 14,807 $ 47,161 Income before preferred dividends from discontinued operations 6,583 6,017 Non cash items included in income: Depreciation and amortization 57,659 57,927 Deferred taxes and deferred investment tax credit 4,124 6,245 AFUDC and capitalized interest (2,166) 3,665 Deferred energy costs - net (900) - Early retirement and severance amortization 3,147 3,145 Other non cash 2,650 5,934 Changes in certain assets and liabilities: Accounts receivable 413 3,975 Materials, supplies and fuel (12,153) (4,645) Other current assets (16,686) (2,670) Accounts payable 15,197 1,893 Other current liabilities 6,678 (2,762) Other - net (5,333) (19,459) --------- -------- Net Cash Flows From Operating Activities 74,020 106,426 --------- -------- CASH FLOWS USED IN INVESTING ACTIVITIES: Additions to utility plant (102,523) (95,487) Non-cash charges to utility plant 2,224 - Net customer refunds and contributions in aid construction 14,897 16,541 --------- -------- Net cash used for utility plant (85,402) (78,946) (Investments in) disposal of subsidiaries and other property - net 1,597 (28,394) --------- -------- Net Cash Used In Investing Activities (83,805) (107,340) --------- -------- CASH FLOWS FROM FINANCING ACTIVITIES: Increase (decrease) in short-term borrowings (31,434) (41,703) Proceeds from issuance of long-term debt 200,000 124,099 Reduction of long-term debt (102,307) (31,758) Additional investment by parent company 14,000 16,000 Dividends paid (66,924) (61,096) --------- -------- Net Cash Used In Financing Activities 13,335 5,542 --------- -------- Net (decrease) increase in Cash and Cash Equivalents 3,550 4,628 Beginning balance in Cash and Cash Equivalents 3,011 15,197 --------- -------- Ending balance in Cash and Cash Equivalents $ 6,561 $ 19,825 ========= ======== Supplemental Disclosures of Cash Flow Information: Cash Paid During Period For: Interest $ 33,476 $ 34,779 Income Taxes $ 9,644 $ 23,757
The accompanying notes are an integral part of the financial statements. 10 NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS ---------------------------------------------------- NOTE 1. MANAGEMENT'S STATEMENT (SPR, NVP, SPPC) - -------------------------------- In the opinion of the management of Sierra Pacific Resources (SPR), Nevada Power Company (NVP), and Sierra Pacific Power Company (SPPC), 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 audited financial statements included in SPR's, NVP's, and SPPC's Annual Reports on Form 10-K for the year ended December 31, 1999. The results of operations for the nine months ended September 30, 2000 are not necessarily indicative of the results to be expected for the full year. Principles of Consolidation --------------------------- The condensed consolidated financial statements of SPR include the accounts of SPR and its wholly owned subsidiaries, Nevada Power Company, Sierra Pacific Power Company, Tuscarora Gas Pipeline Company, Sierra Gas Holding Company (formerly Sierra Energy Company), Sierra Energy Company dba e three, Sierra Pacific Energy Company, Lands of Sierra, Sierra Pacific Communications, Nevada Electric Investment Company and Sierra Water Development Company. All significant intercompany transactions and balances have been eliminated in consolidation. Reclassifications ----------------- Certain items previously reported for years prior to 2000 have been reclassified to conform to the current year's presentation. Net income and shareholders' equity were not affected by these reclassifications. NOTE 2. FINANCIAL STATEMENTS OF NEVADA POWER COMPANY (NVP) - ------------------------------------------------------ As described in Note 3 that follows, NVP is deemed to be the acquirer of SPR for accounting purposes as reflected in the SPR Consolidated Financial Statements. However, after the merger with SPR and as a result of the structure of the transactions, NVP is a separate legal entity, which is a wholly owned subsidiary of SPR. As a legal matter, NVP does not own any equity interest in SPR. The audited NVP Financial Statements accommodate the presentation of financial information of NVP on a stand-alone basis by summarizing all non-NVP financial information into a few items on each of the Financial Statements. These summarized items are repeated below (in 000's): Non-NVP Financial Items on the NVP Financial Statements
NVP Balance Sheet: September 30, 2000 December 31, 1999 - ------------------ --------------------- ------------------- Investment in Sierra Pacific Resources $529,934 $654,156 Equity in Sierra Pacific Resources $529,934 $654,156
The Investment in Sierra Pacific Resources reflects the net assets, after deducting for all liabilities and preferred stock of Sierra Pacific Resources not related to NVP. The Equity in Sierra Pacific Resources reflects the sum of paid-in-capital and retained earnings of SPR, without the benefit of NVP. These line items are required by the rules of purchase accounting and do not represent any asset to which holders of NVP's securities may look for recovery of their investment. These items must be disregarded for determining the ability of NVP to satisfy its obligations or to pay dividends (preferred or common), for calculating NVP's ratios of earnings to fixed charges and preferred stock dividends and for all of NVP's financial covenants and earnings tests including those under its charter and mortgage. 11
NVP Income Statement: Three Months Ended Three Months Ended - -------------------- -------------------- -------------------- September 30, 2000 September 30, 1999 -------------------- -------------------- Equity in Earnings of Sierra Pacific Resources $(10,766) $1,812 Nine Months Ended Nine Months Ended ------------------- -------------------- September 30, 2000 September 30, 1999 ------------------- -------------------- Equity in Earnings of Sierra Pacific Resources $ (2,944) $1,812
The Equity in Earnings of Sierra Pacific Resources reflects three and nine months, respectively, of SPR net income, after SPPC preferred stock dividends. This line item is required by the rules of purchase accounting and does not represent any item of revenue or income to which holders of NVP's securities may look for recovery of their investment. This item must be disregarded for determining the ability of NVP to satisfy its obligations or its ability to pay dividends (preferred or common), for calculating NVP's ratios of earnings to fixed charges and preferred dividends and for all of NVP's financial covenants and earnings tests including those under its charter and mortgage.
NVP Statement of Cash Flow: Nine Months Ended Nine Months Ended - --------------------------- --------------------- -------------------- September 30, 2000 September 30, 1999 --------------------- -------------------- Equity in Earnings of Sierra Pacific Resources $2,944 $(1,812)
As in the income statement, the Equity in Earnings of Sierra Pacific Resources reflects the nine months of SPR net income, after SPPC preferred stock dividends. This line item is required by the rules of purchase accounting and does not represent any item of cash flow to which holders of NVP's securities may look for recovery of their investment. This item must be disregarded for determining the ability of NVP to satisfy its obligations or its ability to pay dividends (preferred or common), for calculating NVP's ratios of earnings to fixed charges and preferred dividends and for all of NVP's financial covenants and earnings tests including those under its charter and mortgage. NOTE 3. SIERRA PACIFIC RESOURCES AND NEVADA POWER COMPANY MERGER (SPR, NVP) - ------------------------------------------------------------------ On July 28, 1999 the merger between SPR and NVP was consummated. The merger was accounted for as a reverse purchase under generally accepted accounting principles, with NVP considered the acquiring entity even though SPR is the surviving legal entity. In addition, for accounting purposes the merger was deemed to have occurred on August 1, 1999. As a result of this reverse purchase accounting treatment: (i) the historical financial statements of SPR for periods prior to the date of the merger are no longer the financial statements of SPR, and therefore, are no longer presented; (ii) the historical financial statements of SPR for periods prior to the date of the merger are those of NVP; and (iii) SPR's Condensed Consolidated Statements of Income for the three- and nine-month periods ended September 30, 1999 and SPR's Condensed Consolidated Statement of Cash Flows for the nine months ended September 30, 1999 include the financial results of SPR and its pre-merger subsidiaries for the months of August and September 1999. SPPC's separate Condensed Consolidated Statements of Income for the three- and nine-month periods ended September 30, 1999 and Condensed Consolidated Statement of Cash Flows for the nine months ended September 30, 1999 include the financial results of SPPC for the periods indicated. Through September 30, 2000, SPR incurred a total of $56.3 million in capitalized costs since merger work began. The capitalized merger amounts consist of $36.0 million of transaction and transition costs and $20.3 million of employee separation costs. For more information regarding the capitalization of merger costs, see Note 3 of "The Notes To Financial Statements" included in SPR's Annual Report on Form 10-K for the year ended December 31, 1999. Employee severance, relocation, and related costs for SPR were $15.8 million, of which $.9 million remains unpaid as of September 30, 2000. Other costs incurred in connection with employee separations included pension and postretirement benefits net of plan gains of $4.5 million. In accordance with the terms of the merger, each outstanding share of SPR's common stock was converted into the right to receive either $37.55 in cash or 1.44 shares of newly issued SPR common stock. Each outstanding share of NVP common stock was converted to the right to receive either $26.00 in cash or 1.00 share of newly issued SPR common stock. 4,037,000 shares of SPR and 11,716,611 shares of NVP common stock were exchanged for $151.6 million and $304.6 million, respectively. The remaining shares of each company were converted to newly issued shares of SPR common stock. SPR 12 stockholders and NVP stockholders received 38,866,054 and 39,548,506 shares, respectively, of newly issued SPR common stock, resulting in 78,414,560 outstanding shares of SPR on August 1, 1999. The total consideration paid to SPR common stockholders was equal to cash of $151.6 million and 38,866,054 shares of newly issued SPR common stock at a price of $24.18 per share based on the average closing price of NVP common stock between April 22, 1998 and May 6, 1998. The eleven-day average price of NVP common stock used in determining the total stock consideration represents the market price over a reasonable period of time before and after the transaction was announced on April 29, 1998. Goodwill of $331.2 million was recorded in connection with the merger and is being amortized over 40 years. However, the order of the Public Utilities Commission of Nevada (PUCN) approving the merger allowed SPR to defer merger costs (including goodwill) allocable to the regulated utilities for a three-year period. At the end of the deferral period SPR will propose an amortization period for goodwill and other merger costs. Accordingly, goodwill amortization associated with the regulated utility companies is being reclassified to a regulatory asset during the three-year period. Also, because SPR is deferring merger costs as regulatory assets the transaction costs included in the calculation of goodwill represent only costs allocable to SPR's non-regulated subsidiaries. Pro forma unaudited financial information for SPR on a consolidated basis, giving effect to the merger as if it had occurred at the beginning of all periods, is presented below. The pro forma information below includes the operating results and assets of SPPC's water business, as described in Note 9 below. This pro forma information is not necessarily indicative of the results that would have occurred, or that will occur in the future.
Three Months ended Nine Months ended (Dollars and shares in thousands September 30, September 30, ------------------------- -------------------------- except per share amounts) 2000 1999 2000 1999 - ---------------------------------------------- ------------ --------- ------------ ---------- Operating Revenue $ 887,093 $548,431 $1,780,358 $1,346,311 Operating Income $ 26,431 $115,749 $ 108,742 $ 236,434 Income (Loss) Applicable to Common Stock $ (19,548) $ 70,686 $ (21,561) $ 113,511 Net Income (Loss) per share - basic and diluted $ (0.25) $ 0.90 $ (0.27) $ 1.45 Weighted Average Shares of Common Stock Outstanding (000's) 78,446 78,415 78,428 78,415 Total Assets $5,648,341 $5,648,341
NOTE 4. RECENT PRONOUNCEMENTS (SPR, NVP, SPPC) - ------------------------------- FINANCIAL ACCOUNTING STANDARDS BOARD - ------------------------------------ In June 1998, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (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 FASB agreed to delay the effective date of Statement 133 to fiscal years beginning after June 15, 2000. In June 2000, the FASB issued SFAS 138 that amended SFAS 133 in a number of respects. Among other revisions, SFAS 138 exempted from the fair value requirements normal purchases and normal sales (as defined by SFAS 133) that contain settlement provisions, if it is probable that the contracts will not settle net and will result in physical delivery. SPR has evaluated the impact of SFAS 133 and SFAS 138 and considers all derivative transactions identified to date to be either subject to the normal purchases and normal sales exclusion or hedges of forecasted transactions. The change in the fair value of the hedges will be reported on the balance sheet as other comprehensive income on January 1, 2001 and could result in a $25-$35 million loss. This amount will be reclassified into earnings in the same period in which the hedged forecasted transaction affects earnings. Securities and Exchange Commission - ---------------------------------- In December 1999, the Staff of the Securities and Exchange Commission released Staff Accounting Bulletin (SAB) No. 101, which summarizes certain of the staff's views in applying generally accepted accounting principles to revenue 13 recognition in financial statements. Subsequently, SAB No. 101A and SAB No. 101B were released delaying the implementation date of SAB No. 101 until no later than the fourth fiscal quarter of fiscal years beginning after December 15, 1999. SPR does not believe that the SAB will have a material effect on its financial statements. NOTE 5. SHORT-TERM BORROWINGS (SPR, NVP, SPPC) - ------------------------------- SPR's commercial paper balance increased from $463.4 million at December 31, 1999, to approximately $493.2 million at March 31, 2000. On September 30, 2000, SPR had no commercial paper outstanding, as a result of the issuance of long-term debt. See Note 6 - Long-Term Debt (below). NVP's commercial paper balance increased from $82.0 million at December 31, 1999, to approximately $95.3 million at March 31, 2000. On June 30, 2000, NVP had no commercial paper outstanding, but, as the result of the issuance of new commercial paper in the third quarter, had approximately $123.1 million of commercial paper outstanding at an average rate of 6.83% at September 30, 2000. See Note 6 - Long-Term Debt (below). SPPC's commercial paper balance decreased from $109.6 million at December 31, 1999, to approximately $101.8 million at March 31, 2000. On June 30, 2000, SPPC had no commercial paper outstanding, but, as the result of the issuance of new commercial paper in the third quarter, had $82.0 million of commercial paper outstanding at an average rate of 6.83% at September 30, 2000. See Note 6 -Long- Term Debt (below). NOTE 6. LONG-TERM DEBT (SPR, NVP, SPPC) - ------------------------ Sierra Pacific Resources - ------------------------ On March 31, 2000, $10 million of SPR's Series E senior notes matured. On April 20, 2000, SPR issued an aggregate of $300 million floating rate notes, $200 million of which matures on April 20, 2003 and the remaining $100 million of which matures on April 20, 2002. Interest on the notes is payable quarterly. The interest rate on the notes for each interest period is a floating rate, subject to adjustment every three months, equal to the London InterBank Offered Rate (LIBOR) for three-month U.S. dollar deposits plus a spread of 0.60% for the notes maturing in 2003 and a spread of 0.65% for the notes maturing in 2002. These notes are not entitled to any sinking fund. The notes due 2002 will be redeemable, in whole, without premium at the option of SPR beginning on April 20, 2001 and on each interest payment date thereafter. The net proceeds of the $200 million issue were used to retire an equal amount of commercial paper of SPR that was used as temporary funding for the cash portion of the NVP merger consideration. The net proceeds of the $100 million issue were used to make a capital contribution to NVP, which in turn was used to retire $85 million of NVP's maturing First Mortgage Bonds on May 1, 2000 and the remaining proceeds were used to pay off its commercial paper outstanding. On September 26, 2000, SPR entered into a forward swap relating to its $200 million floating rate notes that will mature on April 20, 2003, effectively locking in a LIBOR rate of 6.655%, which will result in an interest rate of 7.255% on the notes until their maturity. This transaction became effective on October 20, 2000. On April 20, 2000, upon issuance of these floating rate notes, SPR reduced its bank credit facility to $300 million from the previous amount of $500 million in accordance with the terms of the credit agreement. On June 21, 2000, SPR further reduced its credit facility to $150 million. The remaining $150 million credit facility was a 3-year credit facility, which has since been terminated by SPR effective August 11, 2000. On May 9, 2000, SPR issued $300 million of notes under its universal shelf registration. These notes bear interest at an annual rate of 8.75% and will mature on May 15, 2005. Interest on the notes is payable semi-annually. The notes are not subject to any sinking fund and are redeemable in whole or in part at any time upon payment of the principal amount of the notes being redeemed, plus accrued interest and a make-whole premium. The net proceeds from the issuance of these notes were used to retire an equal amount of commercial paper of SPR. 14 Nevada Power Company - -------------------- On June 9, 2000, NVP issued $150 million of floating rate notes that will mature on June 12, 2001. Interest on the notes is payable quarterly. The interest rate on the notes for each interest period is a floating rate, subject to adjustment every three months, equal to the London InterBank Offered Rate (LIBOR) for three-month U.S. dollar deposits plus a spread of 0.55%. These notes are not entitled to any sinking fund and are non-callable. The net proceeds of the $150 million issue were used to redeem $100 million of floating rate notes on July 14, 2000, and the remaining proceeds were used to reduce NVP's commercial paper outstanding. On June 22, 2000, Clark County, Nevada issued for NVP's benefit $100 million Industrial Development Refunding Revenue Bonds, Series 2000A, due June 1, 2020. The interest rate is currently being determined by a Dutch Auction based on an auction period of seven days. The Series A bonds were issued to refund $100 million of Clark County's 7.80% Industrial Development Revenue Bonds Series 1990 on June 30, 2000. On July 28, 2000, Clark County, Nevada issued for NVP's benefit $15 million Pollution Control Refunding Revenue Bonds, Series 2000B, due October 1, 2009. The interest rate is currently being determined by a Dutch Auction based on an auction period of seven days. The Series B bonds were issued to refund a like principal amount of Clark County's 7.80% Pollution Control Revenue Bonds Series 1989 on October 2, 2000. The method of determining the interest rate on the Series A and Series B Bonds may be converted from time to time in accordance with the related Indenture so that such bonds would, thereafter, bear interest at a daily, weekly, flexible, term or auction rate. Both Series A and Series B Bonds are insured by AMBAC Assurance Corporation. On July 24, 2000, NVP received a 30-day extension on its $150 million Credit Facility to August 28, 2000, in accordance with the terms of the credit agreement. On August 28, 2000, NVP received a 364-day extension of this facility to August 27, 2001. On August 18, 2000, NVP issued $100 million of floating rate notes that will mature on August 20, 2001. Interest on the notes is payable quarterly commencing on November 18, 2000. The interest rate on the notes for each interest period is a floating rate, subject to adjustment every three months, equal to the London InterBank Offered Rate (LIBOR) for three-month U.S. dollar deposits plus a spread of 0.58%. These notes are not entitled to any sinking fund. The notes are redeemable at the option of NVP in whole or in part from time to time, without premium, beginning on February 18, 2001. The net proceeds of the $100 million issue were used to reduce NVP's commercial paper outstanding. Sierra Pacific Power Company - ---------------------------- On June 9, 2000, SPPC issued $200 million of floating rate notes that will mature on June 12, 2001. Interest on the notes is payable quarterly. The interest rate on the notes for each interest period is a floating rate, subject to adjustment every three months, equal to the London InterBank Offered Rate (LIBOR) for three-month U.S. dollar deposits plus a spread of 0.50%. These notes are not entitled to any sinking fund and are non-callable. The net proceeds of the $200 million issue were used to redeem $100 million of floating rate notes on July 14, 2000, and the remaining proceeds were used to reduce the amount of SPPC's commercial paper outstanding. On July 24, 2000, SPPC received a 30-day extension of its $150 million Credit Facility to August 28, 2000, in accordance with the terms of the credit agreement. On August 28, 2000, SPPC received a 364-day extension of this facility to August 27, 2001. 15 NOTE 7. EARNINGS PER SHARE (SPR) - ------- ------------------ SPR 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 Nine Months Ended September 30, September 30, --------------------------- --------------------------- 2000 1999 2000 1999 ----------- ----------- ----------- ----------- Basic Eps Numerator Income (loss) from continuing operations ($000) $ (22,654) $ 62,146 $ (27,843) $ 78,297 Income from discontinued operations ($000) 3,106 2,554 6,282 2,554 ----------- ----------- ----------- ----------- Net income (loss) ($000) $ (19,548) $ 64,700 $ (21,561) $ 80,851 =========== =========== =========== =========== Denominator Weighted average number of shares outstanding 78,446,264 69,364,746 78,427,523 57,298,327 ----------- ----------- ----------- ----------- Per-Share Amounts: Income (loss) from continuing operations $ (0.29) $ 0.89 $ (0.35) $ 1.37 Income from discontinued operations 0.04 0.04 0.08 0.04 ----------- ----------- ----------- ----------- Net income (loss) $ (0.25) $ 0.93 $ (0.27) $ 1.41 =========== =========== =========== =========== Diluted Eps Numerator Income (loss) from continuing operations ($000) $ (22,654) $ 62,146 $ (27,843) $ 78,297 Income from discontinued operations ($000) 3,106 2,554 6,282 2,554 ----------- ----------- ----------- ----------- Net income (loss) ($000) $ (19,548) $ 64,700 $ (21,561) $ 80,851 =========== =========== =========== =========== Denominator Weighted average number of shares outstanding before dilution 78,446,264 69,364,746 78,427,523 57,298,327 Stock options 3,441 19,641 2,041 23,153 Executive long term incentive plan 44,597 25,124 43,301 21,898 Non-Employee stock plan 4,532 4,532 4,532 4,532 Employee stock purchase plan 5,284 1,380 1,993 860 ----------- ----------- ----------- ----------- 78,504,118 69,415,423 78,479,390 57,348,770 ----------- ----------- ----------- ----------- Per-Share Amounts: Income (loss) from continuing operations $ (0.29) $ 0.89 $ (0.35) $ 1.37 Income from discontinued operations 0.04 0.04 0.08 0.04 ----------- ----------- ----------- ----------- Net income (loss) $ (0.25) $ 0.93 $ (0.27) $ 1.41 =========== =========== =========== ===========
16 NOTE 8. SEGMENT INFORMATION (SPR) - ------- ------------------- SPR operates two business segments providing regulated electric and natural gas services. Electric service is provided to Las Vegas and surrounding Clark County, northern Nevada and the Lake Tahoe area of California. Natural gas service is provided in the Reno-Sparks area of Nevada. Other segment information includes segments below the quantitative threshold for separate disclosure. In September 2000, SPR and SPPC adopted a plan to sell SPPC's water utility business. Accordingly, the water business is not included in the segment information below. Information as to the operations of the different business segments is set forth below based on the nature of products and services offered. SPR evaluates performance based on several factors, of which the primary financial measure is business segment operating income. Intersegment revenues are not material. Financial data for business segments is as follows (in thousands). Segment information for 1999 includes the operating results of SPR and its pre-merger subsidiaries only for the months of August and September 1999. Three Months Ended September 30, 2000 Electric Gas Other Consolidated -------------------- ---------- ------- ------ ------------ Operating Revenues $ 852,730 $12,967 $2,657 $ 868,354 ========== ======= ====== ============ Operating Income $ 16,268 $ 1,927 $1,967 $ 20,162 ========== ======= ====== ============ Three Months Ended September 30, 1999 Electric Gas Other Consolidated -------------------- ---------- ------- ------ ------------ Operating Revenues $ 455,617 $ 8,716 $2,713 $ 467,046 ========== ======= ====== ============ Operating Income $ 96,423 $ 198 $1,290 $ 97,911 ========== ======= ====== ============ Nine Months Ended September 30, 2000 Electric Gas Other Consolidated -------------------- ---------- ------- ------ ------------ Operating Revenues $1,662,592 $64,278 $9,165 $ 1,736,035 ========== ======= ====== ============ Operating Income $ 83,731 $ 7,677 $2,672 $ 94,080 ========== ======= ====== ============ Nine Months Ended September 30, 1999 Electric Gas Other Consolidated -------------------- ---------- ------- ------ ------------ Operating Revenues $ 875,987 $ 8,716 $2,713 $ 887,416 ========== ======= ====== ============ Operating Income $ 148,296 $ 198 $1,290 $ 149,784 ========== ======= ====== ============ NOTE 9. DISCONTINUED OPERATIONS (SPR, SPPC) - ------- ----------------------- On September 7, 2000, SPR and SPPC adopted a plan to sell SPPC's water utility business. Accordingly, the water business is reported as a discontinued operation as of September 30, 2000, and the consolidated financial statements have been reclassified to report separately the net assets and operating results of the water business. SPR's and SPPC's prior year operating results have been restated to reflect continuing operations. Water revenues for the three- and nine-month periods ended September 30, 2000, were $18.7 million and $44.3 million, respectively; and $17.9 million and $41.8 million, respectively, for the same periods in 1999. Net income from operations of the water business for the month of September 2000 was approximately $1.0 million. These amounts are not included in the revenues and income (loss) from continuing operations shown in the accompanying income statements. The income from operations of the water business to be disposed of, as shown in the Condensed Consolidated Statements of Income of SPR, includes (in thousands) preferred dividends of $100 and $88 for the three months ended September 30, 2000 and 1999, respectively, and $301 and $88 for the nine months ended September 30, 2000 and 1999, respectively. The income from operations of the water business to be disposed of, as shown in the Condensed Consolidated Statements of Income of SPPC, includes (in thousands) preferred dividends of $100 and $132 for the three months ended September 30, 2000 and 1999, respectively, and $301 and $420 for the nine months ended September 30, 2000 and 1999, respectively. 17 The transaction is expected to close in the first half of 2001, after a buyer is selected and the necessary regulatory approvals are received. It is anticipated that the sales price will exceed the book value of the net assets to be sold. Management anticipates using the proceeds from the sale to reduce debt and other corporate purposes. Included in the sale will be water storage and supply, transmission, treatment and distribution facilities. Also included in the sale will be four hydroelectric generation plants on the Truckee River. Accounts receivable consist of amounts due from developers for distribution facilities. Regulatory assets included for sale consist primarily of costs incurred in connection with the Truckee River negotiated water settlement. SPPC has received favorable regulatory treatment that allows these costs to be recovered through its water rates. Other unallocated regulatory assets, that may be in part included in the sale, are not reflected in the table of net assets that follows. Assets and liabilities that have been identified for sale consist of the following:
Amounts in thousands September 30, 2000 December 31, 1999 ------------------ ----------------- Plant in service $329,998 $323,195 Less: Accumulated provision for depreciation 86,545 80,502 Construction work-in-progress 15,286 14,702 Accounts receivable 2,520 2,520 Materials 338 428 Regulatory tax asset 3,679 3,679 Other regulatory assets 6,985 6,601 -------- -------- Total Assets $272,261 $270,623 -------- -------- Deferred federal income taxes 8,198 8,370 Regulatory tax liability 3,679 3,679 -------- -------- Net assets to be sold $260,384 $258,574 ======== ========
NOTE 10. COMMITMENTS AND CONTINGENCIES (SPR, NVP, SPPC) - --------------------------------------- The Grand Canyon Trust and Sierra Club filed a lawsuit in the U.S. District Court, District of Nevada, in February 1998, against the owners (including NVP) of the Mohave Generation Station (Mohave), alleging violations of the Clean Air Act regarding emissions of sulfur dioxide and particulates. An additional plaintiff, National Parks and Conservation Association, later joined the suit. The plant owners and plaintiffs have had numerous settlement discussions and filed a proposed settlement with the court on October 6, 1999. The consent decree, approved by the court in November 1999, established emission limits for sulfur dioxide and opacity and required installation of air pollution controls for sulfur dioxide, nitrogen oxides and particulate matter. The new emission limits must be met by January 1, 2006 and April 1, 2006, for the first and second units, respectively. However, if the owners sell their entire ownership interest, with a closing date prior to December 30, 2002, then the new emission limits become effective 36 months and 39 months, respectively, from the date of last closing for the two units. The estimated cost of new controls is $300 million. As a 14% owner in the Mohave Station, NVP's costs could be $42 million. As discussed below, NVP is selling its 14% ownership to AES Corporation Also, the United States Congress authorized the Environmental Protection Agency (EPA) to study the potential impact Mohave may have on visibility in the Grand Canyon area. A final report of the study results was released in March 1999. The study acknowledges that sulfur dioxide emissions from Mojave are transported to the Grand Canyon. EPA has solicited information to determine whether visibility impairment in the Grand Canyon can be reasonably attributed to Mohave. If EPA determines that significant visibility impairment is reasonably attributable to the station, EPA could initiate a review for Best Available Retrofit Technology. Based upon indications from EPA and the National Park Service, the Plant owners believe that terms of the settlement of the suit discussed above are expected to be reflected in a State Implementation Plan for Nevada and resolve any concerns of EPA regarding visibility impairment. 18 In May 1997, the Nevada Division of Environmental Protection (NDEP) issued an Order requiring NVP to submit a plan to eliminate the discharge of Reid Gardner Station wastewater to groundwater. The Order also required a hydrological assessment of groundwater impacts in the area. In June 1999, NDEP determined that wastewater ponds have degraded groundwater quality. In August 1999, NDEP issued a discharge permit to Reid Gardner Station and an Order that requires all wastewater ponds to be closed or lined with impermeable liners over the next 10 years. This Order also required NVP to submit a Site Characterization Plan to NDEP to ascertain impacts. This plan will be submitted in November 2000. Technical information from the Plan will be used to develop a corrective action plan and allow NVP to determine an estimate of remediation costs for cleanup. New pond construction and lining costs are estimated at $20 million. Additionally, SPPC has four water wells which currently exceed the federal drinking water standard for naturally occurring arsenic concentrations. Production from three of these wells continues by blending treated water. The fourth well is out of service pending treatment. SPPC's water laboratory research staff is developing options to assure that SPPC is prepared to meet new arsenic standards. The new arsenic regulations will be promulgated in 2000 and the proposed regulation is expected to require action on 17 of the 25 wells serving SPPC's system. Depending upon final rules from the EPA, SPPC may incur between $70 million and $98 million by 2004 to meet the new standards. As part of the Generation Divestiture Process described below, Phase I and/or Phase II and Phase III Environmental Assessments were conducted at NVP's Harry Allen, Clark, Sunrise and Reid Gardner facilities. These were completed in July, 2000 and submitted to NDEP for their review and any subsequent remediation. Nevada Electric Investment Company (NEICO), a subsidiary of NVP in 1999, owns property in Wellington, Utah, which was the site of a coal washing and load out facility. The site now has a reclamation estimate supported by a bond of $4.9 million with the Utah Division of Oil and Gas Mining. The property was under contract for sale and the contract required the purchaser to provide $1.3 million in escrow towards reclamation. However, the sales contract was recently terminated and NEICO has taken title to the escrow funds. It is NEICO's intention to sell the property. In June 2000 an adjacent property owner filed suit in Utah District Court claiming impacts from coal dust. The coal dust was stabilized with an acrylic polymer to control impacts. NEICO intends to defend itself against the suit, no discovery has been conducted, and no trial date has been set. At this time, management cannot express an opinion on the extent of possible damages or liability related to this matter. In accordance with the revised Divestiture Plan stipulation approved by the PUCN in February 2000 (see the 1999 Annual Report on Form 10-K), SPR's wholly owned utilities are offering for sale generation assets with peak capacity of approximately 2,985 megawatts (MW), with approximately 1045 MW owned by SPPC and approximately 1,940 MW owned by NVP. Letters of interest were issued to potential bidders in February 2000. Upon response from the qualified potential bidders and execution of the confidentiality agreements, offering memoranda and materials were provided to the bidders. First stage indicative bids were received on May 25, 2000. The short list of qualified bidders for each of the seven bundles being offered was completed and bidders notified by June 6, 2000. The second stage due diligence process was started on June 6, 2000, and will continue through mid-November. Final bids and the selection of winning bids will occur in the fourth quarter of 2000. See Note 12 - Subsequent Events. Close of sale and transfer of ownership is expected to occur by mid-2001. On May 10, 2000, AES Corporation announced that it was the successful bidder for the purchase of a controlling interest in the 1,580 MW Mohave Generating Station in Laughlin, Nevada for approximately $667 million. NVP owns a 14% undivided interest in the facility. Mohave Generating Station is a 2- unit, coal-fired power plant located on 2,500 acres along the Colorado River, approximately 80 miles south of Las Vegas. AES executed Asset Sale Agreements with the sellers, NVP (14%) and Southern California Edison Company (56%), for a 70% undivided interest in the facility. The acquisition is subject to approval by the Federal Energy Regulatory Commission (FERC) and the California Public Utilities Commission, and review by the PUCN and is expected to close in 2001. NOTE 11. NEVADA RESTRUCTURING ACTIVITIES (SPR, NVP, SPPC) - ----------------------------------------- Competition in the Nevada electricity market was originally scheduled to start on March 1, 2000. However, in February 2000 the Governor of Nevada delayed the start date of competition indefinitely. Generally, restructuring regulations and PUCN decisions during the first and second quarters of 2000 proceeded slowly. Numerous hearings and workshops have been held by the Public Utilities Commission of Nevada (PUCN) regarding two important regulations, "provider of last resort" and "past costs" regulations. On March 28, 2000, SPR, NVP and SPPC filed a federal lawsuit challenging Nevada's laws providing for competition in the electric utility industry and the PUCN's implementation of competition. See SPR's and NVP's Form 8-K, filed on April 17, 2000. On July 20, 2000, the PUCN approved stipulated agreements that resolved pending state and federal lawsuits and major restructuring issues including past costs. See the Form 8-K filed July 26, 2000. On August 3, 2000, the PUCN approved 19 revisions to the stipulated agreements. The stipulations paved the way for open access to occur in a phased manner beginning in November 2000 for large commercial customers and continuing until September 2001 for residential customers. On October 4, 2000, the Governor announced that he had decided to delay the opening of the electricity market in order to allow the state to develop a comprehensive energy policy. The Governor also appointed a bipartisan panel to develop a long-term strategy and report its findings by January 15, 2001, prior to the start of the 2001 legislative session. Management believes it is probable that changes will be made to restructuring legislation and/or PUCN restructuring rules. In accordance with SFAS 71, "Accounting for the Effects of Certain Types of Regulation," SPPC's and NVP's financial statements reflect the effects of rate regulation and decisions by regulatory commissions. For example, expenses may be deferred as regulatory assets on the balance sheet and subsequently be amortized to the income statement when they are recovered from customers in future periods. Similarly, certain items may be deferred as regulatory liabilities, which are also eventually amortized to the income statement. Management periodically assesses whether the requirements for application of SFAS 71 are satisfied. In 1997, the Emerging Issues Task Force of the FASB concluded that once sufficiently detailed deregulation guidance is issued, an entity should discontinue applying SFAS 71 to the separable potion of their business whose pricing is being deregulated. However, an entity may continue to recognize regulatory assets previously associated with that separable portion of their business provided that the transition plan provides for their recovery through the regulatory process. Given the uncertainty related to the current restructuring legislation and PUCN restructuring rules that would ultimately enable retail competition in Nevada, SPPC and NVP continue to apply regulatory accounting to the generation, transmission and distribution portions of their businesses. NOTE 12. SUBSEQUENT EVENTS (SPR, SPPC) - --------------------------- On October 19, 2000, SPR and SPPC announced an agreement to sell SPPC's 50% interest in the Valmy Power Station to NRG Energy of Minneapolis, Minnesota. Under the agreement, SPPC will have the right to buy energy and ancillary services from the Valmy Power Station for agreed upon prices subject to a collar, through early 2003. The sale price of the asset bundle, which includes the Battle Mountain Diesel Plant and the Winnemucca Gas Plant, is $273.3 million, net of a payment from SPPC to NRG for the power purchase agreement, subject to taxes and other adjustments. The Valmy Power Station sells electricity in northern Nevada and surrounding markets. SPPC's net capacity interest in the Valmy Power Station totals 286 MW. Located forty miles from Winnemucca, Nevada, the Valmy Power Station consists of two similar coal-fired units and is owned jointly by SPPC and Idaho Power Co. SPPC owns 50% of the station and operates the plant. The sale of the Valmy Power Station bundle, which is subject to approval and review by various regulatory agencies, is expected to close in mid-2001. On October 27, 2000, SPR and SPPC announced an agreement to sell SPPC's Tracy/Pinon Power Station to WPS Power Development, Inc., a wholly owned subsidiary of WPS Resources Corporation of Green Bay, Wisconsin. Under the agreement, SPPC will have the right to buy energy and ancillary services from WPS Power Development for agreed upon prices subject to a collar from closing of the agreement through February 2003. The sale price of the asset bundle, which includes the Tracy Plant, Pinon Pine, and the Brunswick, Gabbs and Valley Road diesel generators, is $249.8 million, subject to taxes and other adjustments at closing. In conjunction with the purchase, SPPC negotiated the right to buy energy and ancillary services from WPS Power Development for agreed upon prices, subject to a collar, from closing up until March 1, 2003, at a cost ranging from $80 million to $150 million, based on time of closing. The Tracy/Pinon Power Station sells electricity in northern Nevada and surrounding markets. Tracy is also the site of the Pinon Pine Integrated Coal Gasification Combined Cycle project co-funded by the U.S. Department of Energy as part of the Clean Coal Technology Program. SPPC's average capacity in the Tracy/Pinon Power Station totals 525 megawatts. Located approximately 20 miles from Reno, Nevada, the Tracy/Pinon Power Station consists of three similar gas- and oil-fired units, four gas turbines, and the Pinon Pine facility (a combined cycle unit). The sale of the Tracy/Pinon Power Station, which is subject to approval and review by various regulatory agencies, is expected to close no later than June 2001. 20 ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The information in this Form 10-Q includes forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These forward-looking statements relate to anticipated financial performance, management's plans and objectives for future operations, business prospects, outcome of regulatory proceedings, market conditions and other matters. Words such as "anticipate," "believe," "estimate," "expect," "intend," "plan" and "objective" and other similar expressions identify those statements that are forward-looking. These statements are based on management's beliefs and assumptions and on information currently available to management. Actual results could differ materially from those contemplated by the forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with such statements, factors that could cause the actual results of Sierra Pacific Resources (SPR), Nevada Power Company (NVP), or Sierra Pacific Power Company (SPPC) to differ materially from those contemplated in any forward-looking statement include, among others, the following: (1) a continuation of the lag in recovery of increased purchased power and fuel costs resulting from the historical test year mechanism of measuring such costs as provided in the settlement agreement approved by the PUCN in July 2000; (2) fluctuations in electric, gas and other commodity prices, particularly a continuation of the extremely high and volatile purchased power prices in the western United States, and the ability of NVP and SPPC to manage such fluctuations successfully; (3) the pace and extent of the ongoing restructuring of the electric and gas industries in Nevada and California; (4) the outcome of regulatory and legislative proceedings and operational changes related to industry restructuring; (5) the amount NVP and SPPC are allowed to recover from customers for certain costs that prove to be uneconomic in the new competitive market; (6) regulatory delays or conditions imposed by regulatory bodies in approving the acquisition of Portland General Electric; (7) the outcome of ongoing and future regulatory proceedings; (8) management's ability to integrate the operations of SPR, NVP, SPPC, and Portland General Electric and to implement and realize anticipated cost savings from the merger of SPR and NVP and the acquisition of Portland General Electric; (9) the results of the contemplated sales by NVP and SPPC of their Nevada generating assets; (10) industrial, commercial and residential growth in the service territories of NVP and SPPC; (11) changes in the capital markets and interest rates affecting the ability to finance capital requirements; (12) the loss of any significant customers; (13) the potentially serious impact on the utilities' costs and earnings which can result from unseasonable weather and other natural phenomena; and (14) changes in the business of major customers which may result in changes in the demand for services of NVP or SPPC. Other factors and assumptions not identified above may also have been involved in deriving these forward-looking statements, and the failure of those other assumptions to be realized, as well as other factors, may also cause actual results to differ materially from those projected. SPR, NVP and SPPC assume no obligation to update forward-looking statements to reflect actual results, changes in assumptions or changes in other factors affecting forward-looking statements. 21 RESULTS OF OPERATIONS --------------------- SIERRA PACIFIC RESOURCES CONSOLIDATING STATEMENTS OF INCOME (Dollars in Thousands)
Three Months Ended September 30, 2000 Three Months Ended September 30, 1999 ----------------------------------------------- ----------------------------------------------- Sierra Sierra Nevada Pacific Nevada Pacific Power Power Other Total Power Power Other Total ----------- ----------- ----------- ----------- ----------- ----------- ---------- ------------ (Unaudited) (Unaudited) (Unaudited) (Unaudited) (Unaudited) (Unaudited) (Unaudited) (Unaudited) OPERATING REVENUES: Electric $ 547,395 $ 305,334 $ 1 852,730 $ 349,878 $ 105,739 $ - $ 455,617 Gas 12,967 - 12,967 - 8,716 - 8,716 Other - - 2,657 2,657 - - 2,713 2,713 ---------- ----------- --------- ---------- ---------- ----------- ----------- ---------- 547,395 318,301 2,658 868,354 349,878 114,455 2,713 467,046 ---------- ----------- --------- ---------- ---------- ----------- ----------- ---------- OPERATING EXPENSES: Operation: Purchased power 385,129 196,865 - 581,994 101,070 35,418 - 136,488 Fuel for power generation 86,140 65,427 - 151,567 47,780 21,917 - 69,697 Gas purchased for resale - 6,989 - 6,989 - 6,114 - 6,114 Deferral of energy costs-net 2,445 - - 2,445 4,268 - - 4,268 Other 33,638 18,608 4,175 56,421 43,952 16,191 3,162 63,305 Maintenance 8,126 4,162 - 12,288 11,513 3,416 - 14,929 Depreciation and amortization 21,391 17,561 127 39,079 20,613 11,618 109 32,340 Taxes: Income taxes (5,642) (4,591) (3,823) (14,056) 33,190 1,906 (1,884) 33,212 Other than income 6,542 4,711 212 11,465 5,626 3,120 36 8,782 ---------- ----------- --------- ---------- ---------- ----------- ----------- ---------- 537,769 309,732 691 848,192 268,012 99,700 1,423 369,135 ---------- ----------- --------- ---------- ---------- ----------- ----------- ---------- OPERATING INCOME 9,626 8,569 1,967 20,162 81,866 14,755 1,290 97,911 ---------- ----------- --------- ---------- ---------- ----------- ----------- ---------- OTHER INCOME: Allowance for other funds used during construction 430 81 - 511 1,330 (2,449) - (1,119) Other income - net 1,307 117 (1,255) 169 (42) (432) 309 (165) ---------- ----------- --------- ---------- ---------- ----------- ----------- ---------- 1,737 198 (1,255) 680 1,288 (2,881) 309 (1,284) ---------- ----------- --------- ---------- ---------- ----------- ----------- ---------- Total Income 11,363 8,767 712 20,842 83,154 11,874 1,599 96,627 ---------- ----------- --------- ---------- ---------- ----------- ----------- ---------- INTEREST CHARGES: Long-term debt 15,980 10,952 9,295 36,227 16,778 5,139 116 22,033 Other 2,745 1,348 625 4,718 1,175 1,311 4,391 6,877 Allowance for borrowed funds used during construction and capitalized interest (2,373) (680) - (3,053) (1,491) 1,808 - 317 ---------- ----------- --------- ---------- ---------- ----------- ----------- ---------- 16,352 11,620 9,920 37,892 16,462 8,258 4,507 29,227 ---------- ----------- --------- ---------- ---------- ----------- ----------- ---------- INCOME (LOSS) BEFORE SPPC/NVP 66,692 3,616 (2,908) 67,400 OBLIGATED MANDATORILY REDEEMABLE PREFERRED TRUST SECURITIES (4,989) (2,853) (9,208) (17,050) Preferred dividend requirements of mandatorily redeemable preferred trust securities (3,793) (935) (1) (4,729) (3,793) (628) - (4,421) ---------- ----------- --------- ---------- ---------- ----------- ----------- ---------- INCOME (LOSS) BEFORE PREFERRED STOCK DIVIDENDS (8,782) (3,788) (9,209) (21,779) 62,899 2,988 (2,908) 62,979 Preferred stock dividend requirements - (875) - (875) (11) (822) - (833) ---------- ----------- --------- ---------- ---------- ----------- ----------- ---------- INCOME (LOSS) APPLICABLE TO COMMON STOCK (8,782) (4,663) (9,209) (22,654) 62,888 2,166 (2,908) 62,146 ---------- ----------- --------- ---------- ------------ ----------- ----------- ---------- INCOME FROM DISCONTINUED OPERATIONS - 3,106 - 3,106 - 2,554 - 2,554 ---------- ----------- --------- ---------- ------------ ----------- ----------- ---------- NET INCOME (LOSS) $ (8,782) $ (1,557) $ (9,209) $(19,548) $ 62,888 $ 4,720 $ (2,908) $ 64,700 ========== =========== ========= ========== ============ =========== =========== ==========
22 SIERRA PACIFIC RESOURCES CONSOLIDATING STATEMENTS OF INCOME (Dollars in Thousands)
Nine Months Ended September 30, 2000 Nine Months Ended September 30, 1999 ----------------------------------------------- ----------------------------------------------- Sierra Sierra Nevada Pacific Nevada Pacific Power Power Other Total Power Power Other Total ---------- ---------- ---------- ---------- ---------- ---------- ---------- ----------- (Unaudited) (Unaudited) (Unaudited) (Unaudited) (Unaudited) (Unaudited) (Unaudited) (Unaudited) OPERATING REVENUES: Electric $1,022,816 $ 639,776 $ - 1,662,592 $ 770,248 $ 105,739 $ - 875,987 Gas - 64,278 - 64,278 - 8,716 - 8,716 Other - - 9,165 9,165 - - 2,713 2,713 ---------- ---------- -------- --------- ---------- --------- -------- --------- 1,022,816 704,054 9,165 1,736,035 770,248 114,455 2,713 887,416 ---------- ---------- -------- --------- ---------- --------- -------- --------- OPERATING EXPENSES: Operation: Purchased power 593,479 318,294 - 911,773 238,711 35,418 - 274,129 Fuel for power generation 178,809 138,785 - 317,594 113,808 21,917 - 135,725 Gas purchased for resale - 41,310 - 41,310 - 6,114 - 6,114 Deferral of energy costs-net 16,719 - - 16,719 14,651 - - 14,651 Other 97,923 68,328 17,059 183,310 111,243 16,191 3,162 130,596 Maintenance 27,210 12,984 - 40,194 40,740 3,416 - 44,156 Depreciation and amortization 64,121 52,144 489 116,754 60,144 11,618 109 71,871 Taxes: Income taxes (12,461) 6,605 (11,454) (17,310) 40,397 1,906 (1,884) 40,419 Other than income 17,860 13,352 399 31,611 16,815 3,120 36 19,971 ---------- ---------- -------- --------- ---------- --------- -------- --------- 983,660 651,802 6,493 1,641,955 636,509 99,700 1,423 737,632 ---------- ---------- -------- --------- ---------- --------- -------- --------- OPERATING INCOME 39,156 52,252 2,672 94,080 133,739 14,755 1,290 149,784 ---------- ---------- -------- --------- ---------- --------- -------- --------- INCOME: Allowance for other funds used during construction 2,271 215 - 2,486 5,413 (2,449) - 2,964 Other income - net 2,014 (1,122) 2,686 3,578 (1,205) (432) 309 (1,328) ---------- ---------- -------- --------- ---------- --------- -------- --------- 4,285 (907) 2,686 6,064 4,208 (2,881) 309 1,636 ---------- ---------- -------- --------- ---------- --------- -------- --------- Total Income 43,441 51,345 5,358 100,144 137,947 11,874 1,599 151,420 ---------- ---------- -------- --------- ---------- --------- -------- --------- INTEREST CHARGES: Long-term debt 46,132 26,861 16,344 89,337 48,244 5,139 116 53,499 Other 10,677 8,519 10,422 29,618 4,515 1,311 4,391 10,217 Allowance for borrowed funds used during construction and capitalized interest (6,130) (1,649) - (7,779) (5,326) 1,808 - (3,518) ---------- ---------- -------- --------- ---------- --------- -------- --------- 50,679 33,731 26,766 111,176 47,433 8,258 4,507 60,198 ---------- ---------- -------- --------- ---------- --------- -------- --------- INCOME (LOSS) BEFORE SPPC/NVP OBLIGATED MANDATORILY REDEEMABLE PREFERRED TRUST SECURITIES (7,238) 17,614 (21,408) (11,032) 90,514 3,616 (2,908) 91,222 Preferred dividend requirements of mandatorily redeemable preferred trust securities (11,379) (2,807) (1) (14,187) (11,380) (628) - (12,008) ---------- ---------- -------- --------- ---------- --------- -------- --------- INCOME (LOSS) BEFORE PREFERRED STOCK DIVIDENDS (18,617) 14,807 (21,409) (25,219) 79,134 2,988 (2,908) 79,214 Preferred stock dividend requirements - (2,624) - (2,624) (95) (822) - (917) ---------- ---------- -------- --------- ---------- --------- -------- --------- INCOME (LOSS) FROM CONTINUING OPERATIONS (18,617) 12,183 (21,409) (27,843) 79,039 2,166 (2,908) 78,297 ---------- ---------- -------- --------- ---------- --------- -------- --------- INCOME FROM DISCONTINUED OPERATIONS - 6,282 - 6,282 - 2,554 - 2,554 ---------- ---------- -------- --------- ---------- --------- -------- --------- NET INCOME (LOSS) $ (18,617) $ 18,465 $(21,409) $ (21,561) $ 79,039 $ 4,720 $(2,908) $ 80,851 ========== ========== ======== ========= ========== ========= ======== =========
23 Sierra Pacific Resources ------------------------ Financial Condition, Liquidity And Capital Resources During the first nine months of 2000, SPR incurred a loss of $25.2 million from continuing operations before preferred stock dividend requirements and declared $59.0 million in common stock dividends. NVP and SPPC, SPR's principal subsidiaries, declared common stock dividends to their parent, SPR, of $64 million and $61 million, respectively. SPPC also declared $1.95 million in dividends to holders of its preferred stock. As discussed in the results of operations sections that follow, operating results for the second and third quarters of 2000 were negatively affected by higher fuel and purchased power costs during the same periods. These costs were reflective of significantly higher and extremely volatile prices for purchased power and fuel that developed in May 2000 in the western United States and have continued since. SPR, NVP, and SPPC cannot predict how long these unprecedented market conditions will persist. If such market conditions persist, they could have a material adverse effect on the future earnings of SPR, NVP and SPPC. In order to mitigate the effect of these higher fuel and purchased power costs, NVP and SPPC entered into stipulations permitting each of them to increase electric rates. With respect to NVP, the stipulation established a Fuel and Purchase Power (F&PP) Rider beginning September 1, 2000. This rider is based on the incremental increase in F&PP costs between two historic 12-month periods, subject to certain caps. The first filing by NVP under this mechanism was based on comparing NVP's F&PP costs for the 12 months ended May 2000 with those costs for the 12 months ended April 2000. The second filing was based on comparing those costs for the 12 months ended June 2000 with the 12 months ended May 2000. Future filings will follow the same pattern of comparison. The stipulation requires that filings be made by NVP each month, with the last filing to be made December 15, 2002, for rates effective February 1, 2003. The stipulation also imposed caps on the amount of increase or decrease permitted to NVP pursuant to each filing. For NVP's first six monthly filings, the cap is 0.95 mills per kilowatt-hour (kWh), for the second six monthly filings the cap is 1.15 mills/kWh, for the third six monthly filings the cap is 1.35 mills/kWh, for the fourth six monthly filings the cap is 1.55 mills/kWh, and for the remaining monthly filings the cap is 1.75 mills/kWh. After each sixth filing, the amount of increases or decreases not recognized as a result of the caps will be calculated. In the next filing thereafter, 50% of the unrecognized amount will be added to the incremental increase or decrease in F&PP costs for that filing, up to the cap for that filing. Any of the 50% of unrecognized increases or decreases not reflected in that filing because of the cap can be added to the next filing. As a result of the stipulation, in addition to a net rate increase of $48 million that became effective as of August 1, 2000, the following monthly filings have been made to date for NVP: Increase Allowed Annual Filing Filed Effective Mills/kWh Mills/kWh (in millions) ------ ----- --------- --------- --------- ------------- 1 Aug-1 Sep-1 1.1 0.95 15.1 2 Aug-15 Oct-1 2.56 0.95 15.3 3 Sep-15 Nov-1 2.97 0.95 15.6 4 Oct-15 Dec-1 2.91 0.95 15.8 To date, the PUCN has approved and NVP has implemented the first three of the above rate increases. In each monthly filing, the NVP must include a calculation of its Fixed Charge Coverage Ratio for the 12-month period (May 2000 for the first filing). If the Fixed Charge Coverage Ratio is at or above 2.5, then no increase in the rider is allowed for that filing. In addition, every six months an audit of fuel and purchase power practices will be conducted Any findings by the PUCN of imprudence are to be reflected in future F&PP rider filings. SPPC also entered into a stipulation permitting it to file monthly fuel and purchased power adjustment cases. Beginning November 1, 2000, a F&PP Rider was established for SPPC. As with NVP, the rider is based on the incremental increase in F&PP costs between two 12-month periods, subject to certain caps. The first such filing for SPPC was based on comparing SPPC's F&PP costs for the 12 months ended July 2000 with SPPC's Base Tariff Energy Rate (BTER). The second filing was based on comparing F&PP costs for the 12 months ended August 2000 with those costs for the 12 months ended July 2000, with future filings following the pattern of comparison. The stipulation requires SPPC to make a filing each month, with the last filing to be made December 15, 2002, for rates effective February 1, 2003. 24 As with NVP, the stipulation imposes caps on the amount of increase or decrease permitted under each filing by SPPC. For SPPC's first filing, the cap is 4.5 mills/kWh. For subsequent filings the caps are the same as for NVP's F&PP rider (i.e. 0.95 mills for the next six months, 1.15 mills for following six months, 1.35 for the following six months, 1.55 mills for the following six months, and 1.75 mills for each month thereafter). The treatment for unrecognized amounts due to the cap is the same as for NVP. As a result of the stipulation, SPPC has filed with the PUCN for approval of the following electric rate increases: Increase Allowed Annual Filing Filed Effective Mills/kWh Mills/kWh $Millions ------ ----- --------- --------- --------- ------------- 1 Sept. 15 Nov. 1 3.2 3.2 25.7 2 Oct. 15 Dec 1 1.5 0.95 7.7 To date, the PUCN has approved and SPPC has implemented the first of the above rate increases. The Fixed Charge Coverage Ratio and audit provisions are the same for SPPC as for NVP. Although both utilities are increasing electric rates to recover higher fuel and purchased power costs, the mechanism described above for adjusting rates lags changes in actual energy costs. Consequently, high fuel and purchased power costs are likely to continue affecting earnings negatively until these costs stabilize and/or electric rates reflect the higher costs. In addition to the above rate filings, on November 1, SPPC filed with the PUCN to recover $26.8 million in additional costs to its natural gas distribution segment, to account for the higher cost of natural gas that SPPC pays to its suppliers. The earliest that all or a portion of this increase could go into effect would be December 1, 2000. Comparative fuel and purchased power cost information is included in each utility's results of operations discussion that follows. Also see "Regulatory Matters" below. SPR's cash flows during the nine months ended September 30, 2000 decreased slightly compared to the same period in 1999. Decreases in cash flows from operating activities and financing activities were largely offset by a decrease in cash flows used in investing activities. Cash flows from operating activities were less in 2000 than in 1999 due primarily to a decrease in operating income and an increase in accounts receivable, offset, in part, by increases in accounts payable and depreciation and amortization. The decrease in cash flows used in investing activities resulted mainly from 1999 including the cash used for the merger of SPR and NVP. Cash flows from financing activities decreased in 2000 as compared to 1999 due to most of 2000's net increase in long-term debt being used to retire short-term borrowings, while the nine months ended September 30, 1999, included net increases in both long-term debt and short-term borrowings. FINANCING On April 20, 2000, SPR issued an aggregate of $300 million floating rate notes, $200 million of which matures on April 20, 2003 and the remaining $100 million of which matures on April 20, 2002. Interest on the notes is payable quarterly. The interest rate on the notes for each interest period is a floating rate, subject to adjustment every three months, equal to the London InterBank Offered Rate (LIBOR) for three-month U.S. dollar deposits plus a spread of 0.60% for the notes maturing in 2003 and a spread of 0.65% for the notes maturing in 2002. These notes are not entitled to any sinking fund. The notes due 2002 will be redeemable, in whole, without premium at the option of SPR beginning on April 20, 2001 and on each interest payment date thereafter. The net proceeds of the $200 million issue were used to retire an equal amount of commercial paper of SPR that was used as temporary funding for the cash portion of the NVP merger consideration. The net proceeds of the $100 million issue were used to make a capital contribution to NVP, which in turn was used to retire $85 million of NVP's maturing First Mortgage Bonds on May 1, 2000 and the remaining proceeds were used to pay off its commercial paper outstanding. On September 26, 2000, SPR entered into a forward swap relating to its $200 million floating rate notes that will mature on April 20, 2003, effectively locking in a LIBOR rate of 6.655%, which will result in an interest rate of 7.255% on the notes until their maturity. This transaction became effective on October 20, 2000. On April 20, 2000, upon issuance of these floating rate notes, SPR also reduced its bank credit facility to $300 million from the previous amount of $500 million in accordance with the terms of the credit agreement. On June 21, 2000, SPR further reduced its credit facility to $150 million. The remaining $150 million credit facility was a 3-year credit facility, which has since been terminated by SPR effective August 11, 2000. On May 9, 2000, SPR issued $300 million of notes under its universal shelf registration. These notes bear interest at an annual rate of 8.75% and will mature on May 15, 2005. Interest on the notes is payable semi-annually. The notes are not subject to any sinking fund and are redeemable in whole or in part at any time upon payment of the principal amount of the 25 notes being redeemed, plus accrued interest and a make-whole premium. The net proceeds from the issuance of these notes were used to retire an equal amount of commercial paper of SPR. Also see Portland General Electric Acquisition, below. 26 Nevada Power Company - --------------------- The causes for significant changes in specific lines comprising the results of operations for NVP are as follows (dollars in thousands):
Three Months Nine Months Ended September 30, Ended September 30, ------------------- ------------------- Change from Change from 2000 1999 Prior Year% 2000 1999 Prior Year% -------- -------- ----------- ---------- -------- ----------- Electric Operating Revenues ($000): Residential $184,290 $159,022 15.9% $ 393,402 $334,789 17.5% Commercial 68,680 60,461 13.6% 174,387 154,152 13.1% Industrial 120,227 104,397 15.2% 252,675 227,459 11.1% -------- -------- ---------- ---------- -------- ---------- Retail revenues 373,197 323,880 15.2% 820,464 716,400 14.5% Other 174,198 25,998 570.0% 202,351 53,848 275.8% -------- -------- ---------- ---------- -------- ---------- Total Revenues $547,395 $349,878 56.5% $1,022,815 $770,248 32.8% ======== ======== ========== ========== ======== ========== Total retail sales in thousands of megawatt-hours (MWH) 5,385 4,858 10.8% 12,846 11,380 12.9% Average retail revenue per MWH $ 69.30 $ 66.67 4.0% $ 63.87 $ 62.95 1.5%
Residential electric revenues increased for the three and nine months ended September 30, 2000, due to increases in the number of customers and above-normal temperatures. For the three and nine month periods ended September 30, 2000, the number of residential customers increased by 5.5% and 5.7%, respectively, over the same periods of 1999. Hotter than normal weather also increased revenues in both the three and nine month periods ended September 30, 2000, over the same periods the previous year. Residential revenues were also affected by rate increases effective March 1, 1999, August 1, 2000, and September 1, 2000. Both commercial and industrial electric revenues increased for the three and nine months ended September 30, 2000, due, in part, to increases in the number of customers. For the three and nine month periods ended September 30, 2000, the number of commercial customers increased by 4.6% and 4.8%, respectively, over the same periods of 1999. For the three and nine month periods ended September 30, 2000, the number of industrial customers increased by 9.2% and 7.1%, respectively, over the same periods of 1999. The opening of several new schools and large casinos along with new business and energy rate increases effective August 1, 2000, and September 1, 2000, contributed to increased 2000 revenues despite an overall rate decrease associated with deferred energy effective May 1, 2000. The May 1, 2000 deferred energy rate change that ended August 1, 2000, resulted in an increase in residential rates and a decrease in rates to all other customers. The increase in other electric revenues for the three and nine month periods ended September 30, 2000, over the same periods in 1999 was mainly due to large increases in wholesale power sales at much higher prices. NVP's wholesale power revenues have increased in response to its hedging program. NVP purchases fixed cost energy at a delivery point where the energy can either be delivered to its control area or traded, should NVP not require the energy. The energy is also traded if replacement energy can be obtained less expensively than transporting the energy to the control area. Historically, less of these trades have taken place. NVP neither purchases nor sells energy on a speculative basis. Also included in other electric revenues for these periods is $7.2 million from the sale of sulfur dioxide allowances from the Navajo Generation Station. The sale of these allowances occurred at this time to take advantage of beneficial market conditions and trends. 27
Three Months Nine Months Ended September 30, Ended September 30, ------------------ ------------------ Change from Change from 2000 1999 Prior Year % 2000 1999 Prior Year % -------- -------- ------------ -------- -------- ------------ Purchased Power ($000) $385,129 $101,070 281.1% $593,479 $238,711 148.6% Purchased Power in thousands of MWHs 4,711 2,836 66.1% 8,426 6,387 31.9% Average cost per MWH of Purchased Power $ 81.75 $ 35.64 129.4% $ 70.43 $ 37.37 88.5%
Purchased power costs were significantly higher for the three and nine months ended September 30, 2000 as Short-Term Firm and Economy Energy prices increased substantially. In addition, volumes purchased increased to accommodate system load and increased wholesale sales.
Three Months Nine Months Ended September 30, Ended September 30, ------------------- ------------------- Change from Change from 2000 1999 Prior Year % 2000 1999 Prior Year % -------- --------- ------------ -------- -------- ------------ FUEL FOR POWER GENERATION $ 86,140 $ 47,780 80.3% $178,809 $113,808 57.1% ($000) Thousands of MWHs generated 3,052 2,811 8.6% 7,769 6,823 13.9% Average cost per MWH of Generated Power $ 28.22 $ 17.00 66.0% $ 23.02 $ 16.68 38.0%
Fuel for generation costs for the three and nine months ended September 30, 2000, were significantly higher than the prior year as volumes generated were higher to accommodate system load. Furthermore, natural gas prices have increased over 50% from the prior year.
Three Months Nine Months Ended September 30, Ended September 30, ------------------- ------------------- Change From Change From 2000 1999 Prior Year % 2000 1999 Prior Year % ------ ------- ------------ ------- ------- ----------- Deferral of energy costs-net ($000) $2,445 $4,268 -42.7% $16,719 $14,651 14.1% ====== ====== =========== ======= ======= ===========
Deferral of energy costs-net decreased for the three months ended September 30, 2000, because NVP discontinued deferred energy cost recognition in September 2000 pursuant to the July 2000 settlement with the PUCN. (See "Regulatory Matters" below.) Deferral of energy costs-net for the nine months ended September 30, 2000 increased as a result of deferred energy rate increases granted in 1999 to reflect the increased cost of fuel and purchased power. 28
Three Months Nine Months Ended September 30, Ended September 30, (in $000's) (in $000's) ---------- ----------- Change from Change from 2000 1999 Prior Year % 2000 1999 Prior Year % ------ ------ ------------ ------ -------- ------------- Allowance for other funds used during construction $ 430 $1,330 -67.7% $2,272 $ 5,413 -58.0% Allowance for borrowed funds used during construction $2,373 $1,491 59.2% 6,130 5,326 15.1% ------ ------ ----------- ------ ------- ----------- $2,803 $2,821 -0.6% $8,402 $10,739 -21.8% ====== ====== =========== ====== ======= ===========
Total allowance for funds used during construction (AFUDC) for the nine- month period ending September 30, 2000, is lower compared to 1999 because of reductions in construction-work-in-progress resulting primarily from the completion of the Crystal Transmission Project in May 1999 and because of a reduction in the overall AFUDC rate. Total AFUDC was comparable for the three- month periods ending September 30, 1999 and 2000.
Three Months Nine Months Ended September 30, Ended September 30, ------------------- ------------------- Change From Change From 2000 1999 Prior Year % 2000 1999 Prior Year % ------- ------- ------------ ------- -------- ------------ Other operating expense $33,638 $43,952 -23.5% $97,923 $111,243 -12.0% Maintenance expense $ 8,126 $11,513 -29.4% 27,210 40,740 -33.2% Depreciation and amortization $21,391 $20,613 3.8% 64,121 60,144 6.6% Income taxes $(5,642) $33,190 -117.0% (12,461) 40,397 -130.8% Taxes other than income taxes $ 6,542 $ 5,626 16.3% 17,860 16,815 6.2% Interest charges- Long-term debt $15,980 $16,778 -4.8% 46,132 48,244 -4.4% Interest charges-other $ 2,745 $ 1,175 133.6% 10,677 4,515 136.5%
Other operating expense for the three- and nine-month periods ending September 30, 2000 decreased compared to the same periods in 1999 primarily due to reduced labor and benefit costs in 2000 as a result of merger efficiencies and unfilled vacancies. Maintenance costs for the three- and nine-month periods ending September 30, 2000, decreased from the prior year primarily as a result of fewer planned plant maintenance activities at NVP's coal generation facilities. In addition, crews have been performing required activities of a capital nature, thereby reducing the amount of maintenance expense. Finally, in 1999 maintenance expenses were higher than normal. Depreciation and amortization expense increased for the three- and nine- month periods ending September 30, 2000, due to an increase in electric plant- in-service over the prior year. Income taxes decreased for both the three- and nine-month periods ending September 30, 2000, due to net pre-tax losses in the third quarter and lower pre-tax income for the nine months ended September 30, 2000 versus periods of higher net pre-tax income in 1999. Taxes other than income taxes increased for both the three- and nine-month periods ending September 30, 2000 compared to the same periods in 1999 reflecting increases in both revenues and electric plant-in-service. Interest charges-Long-term debt decreased for the three and nine months ended September 30, 2000 due to lower average long-term debt balances compared to 1999. Although floating rate notes are classified as long-term debt on the balance sheet, the associated interest costs are included in Interest charges- other. Interest charges-other increased for the both three- and nine-month periods ending September 30, 2000, because of interest incurred on $100 million of floating rate notes issued in October 1999, interest on $150 million of floating rate notes 29 issued in June 2000, $150 million of floating rate notes issued in August 2000, and due to the utilization of commercial paper in 2000. Financial Condition, Liquidity And Capital Resources During the first nine months of 2000, NVP incurred a loss of approximately $21.6 million and declared $64.0 million in dividends on its common stock, all of which is held by its parent, Sierra Pacific Resources. Cash flows during the nine months ended September 30, 2000 increased slightly compared to the same period in 1999. A reduction in cash flows from operating activities, mainly due to a decrease in operating income, was offset by a decrease in cash used for investing activities and an increase in cash flows from financing activities. A reduction in cash used for utility plant was the main cause of the decrease in cash used for investing activities. The increase in cash flows from financing activities was due to funding received from SPR offset, in part, by an increase in dividends paid. Construction Expenditures And Financing NVP's construction program and capital requirements for the period 2000- 2004 were originally discussed in the combined SPR/NVP Annual Report on Form 10- K for the year ending December 31, 1999. Of NVP's amount projected for 2000 ($190.5 million), $138.6 million (72.8%) was spent as of September 30, 2000. Construction expenditures were funded from sources other than internally generated funds. NVP may utilize internally generated cash and the proceeds from secured and unsecured borrowings and preferred securities to meet capital expenditure requirements through 2000. Financing On April 20, 2000, SPR issued an aggregate of $300 million floating rate notes, $200 million of which matures on April 20, 2003 and the remaining $100 million of which matures on April 20, 2002. Interest on the notes is payable quarterly. The net proceeds of the $100 million issue were used to make a capital contribution to NVP, which in turn was used to retire $85 million of NVP's maturing First Mortgage Bonds on May 1, 2000 and the remaining proceeds were used to pay off its commercial paper outstanding. On June 9, 2000, NVP issued $150 million of floating rate notes that will mature on June 12, 2001. Interest on the notes is payable quarterly. The interest rate on the notes for each interest period is a floating rate, subject to adjustment every three months, equal to the London InterBank Offered Rate (LIBOR) for three-month U.S. dollar deposits plus a spread of 0.55%. These notes are not entitled to any sinking fund and are non-callable. The net proceeds of the $150 million issue were used to redeem $100 million of floating rate notes on July 14, 2000, and the remaining proceeds were used to reduce NVP's commercial paper outstanding. On June 22, 2000, Clark County, Nevada issued for NVP's benefit $100 million Industrial Development Refunding Revenue Bonds, Series 2000A, due June 1, 2020. The interest rate is currently being determined by a Dutch Auction based on an auction period of seven days. The Series A bonds were issued to refund $100 million of Clark County's 7.80% Industrial Development Revenue Bonds Series 1990 on June 30, 2000. On July 28, 2000, Clark County, Nevada issued for NVP's benefit $15 million Pollution Control Refunding Revenue Bonds, Series 2000B, due October 1, 2009. The interest rate is currently being determined by a Dutch Auction based on an auction period of seven days. The Series B bonds were issued to refund a like principal amount of Clark County's 7.80% Pollution Control Revenue Bonds Series 1989 on October 2, 2000. The method of determining the interest rate on the Series A and Series B Bonds may be converted from time to time in accordance with the related Indenture so that such bonds would, thereafter, bear interest at a daily, weekly, flexible, term or auction rate. Both Series A and Series B Bonds are insured by AMBAC Assurance Corporation. On July 24, 2000, NVP received a 30-day extension on its $150 million Credit Facility to August 28, 2000, in accordance with the terms of the credit agreement. On August 28, 2000, NVP received a 364-day extension of this facility to August 27, 2001. On August 18, 2000, NVP issued $100 million of floating rate notes that will mature on August 20, 2001. Interest on the notes is payable quarterly commencing on November 18, 2000. The interest rate on the notes for each interest period is a floating rate, subject to adjustment every three months, equal to the London InterBank Offered Rate (LIBOR) for three-month U.S. dollar deposits plus a spread of 0.58%. These notes are not entitled to any sinking fund. The notes are redeemable at the 30 option of NVP in whole or in part from time to time, without premium, beginning on February 18, 2001. The net proceeds of the $100 million issue were used to reduce NVP's commercial paper outstanding. 31 SIERRA PACIFIC POWER COMPANY - ---------------------------- The components of gross margin are set forth below (dollars in thousands):
Three Months Nine Months Ended September 30, Ended September 30, ------------------- ------------------- Change from Change from 2000 1999 Prior Year % 2000 1999 Prior Year % -------- -------- ------------ -------- -------- ------------ Operating Revenues: Electric $305,334 $163,846 86.4% $639,776 $455,497 40.5% Gas 12,967 13,056 -0.7% 64,278 69,934 -8.1% -------- -------- -------- -------- Total Revenues 318,301 176,902 79.9% 704,054 525,431 34.0% -------- -------- -------- -------- Energy Costs: Electric 262,292 85,124 208.1% 457,079 220,740 107.1% Gas 6,989 9,603 -27.2% 41,310 46,978 -12.1% -------- -------- -------- -------- Total Energy Costs 269,281 94,727 184.3% 498,389 267,718 86.2% -------- -------- -------- -------- Gross Margin 49,020 82,175 -40.3% 205,665 257,713 -20.2% ======== ======== ======== ======== Gross Margin by Segment: Electric 43,042 78,722 -45.3% 182,697 234,757 -22.2% Gas 5,978 3,453 73.1% 22,968 22,956 0.1% -------- -------- -------- -------- Total $ 49,020 $ 82,175 -40.3% $205,665 $257,713 -20.2% ======== ======== ======== ========
The causes for significant changes in specific lines comprising the results of operations for SPPC are as follows (dollars in thousands):
Three Months Nine Months Ended September 30, Ended September 30, ------------------- ------------------- Change from Change from 2000 1999 Prior Year % 2000 1999 Prior Year % -------- -------- ------------ ------- -------- ------------ Electric Operating Revenues: Residential $ 45,114 $ 41,892 7.7% $131,304 $127,903 2.7% Commercial 54,327 52,175 4.1% 147,753 141,874 4.1% Industrial 49,670 47,878 3.7% 143,684 139,793 2.8% -------- -------- ---------- -------- -------- -------- Retail revenues 149,111 141,945 5.0% 422,741 409,570 3.2% Other 156,223 21,901 613.3% 217,035 45,927 372.6% -------- -------- ---------- -------- -------- -------- Total Revenues $305,334 $163,846 86.4% $639,776 $455,497 40.5% ======== ======== ========== ======== ======== ======== Retail sales in thousands of megawatt-hours (MWH) 2,336 2,193 6.5% 6,584 6,333 4.0% -------- -------- ---------- -------- -------- -------- Average retail revenue per MWH $ 63.83 $ 64.73 -1.4% $ 64.21 $ 64.67 -0.7%
Residential revenues increased for both the three- and nine-month periods ended September 30, 2000. These changes were due to growth in total customers and increases in cooling degree-days over the three- and nine-month periods in 1999. Commercial revenues also were higher for both the three months and nine months ended September 30, 2000. This was due primarily to 3.1% increases in total customers and, to a lesser extent, the increases in cooling degree-days mentioned above. Industrial revenues also increased for both the three months and nine months ended September 30, 2000. This was due to significant increases in usage per customer, primarily by mining customers, more than offsetting the migration of some customers to the commercial class. 32 Other electric revenues were higher in the three and nine-month periods ended September 30, 2000, compared to the prior year primarily due to $124 million and $157 million increases, respectively, in wholesale electric revenues. SPPC's wholesale power revenues have increased in response to its hedging program. SPPC purchases fixed cost energy at a delivery point where the energy can either be delivered to its control area or traded, should SPPC not require the energy. The energy is also traded if replacement energy can be obtained less expensively than transporting the energy to the control area. Historically, less of these trades have taken place. SPPC neither purchases nor sells energy on a speculative basis. The increase for the nine months ended September 30, 2000, was also due in part to the 1999 reclassification of a $4.3 million reserve to revenues from operating expense, that was made in order to reflect a refund resulting from an agreement with the PUCN to refund a share of earnings.
Three Months Nine Months Ended September 30, Ended September 30, ------------------- ------------------- Change From Change From 2000 1999 Prior Year % 2000 1999 Prior Year% ------------ ---------- ------------ ---------- ----------- ------------ Gas Operating Revenues ($000): Residential $ 4,316 $ 3,813 13.2% $ 27,254 $ 29,029 -6.1% Commercial 2,382 2,189 8.8% 14,098 15,338 -8.1% Industrial 1,852 1,781 4.0% 7,309 7,899 -7.5% Deferred Energy 180 - - 900 - - Miscellaneous 216 (194) -211.3% 1,224 749 63.4% ---------- ---------- ---------- ------------ ----------- -------- Total retail revenue 8,946 7,589 17.9% 50,785 53,015 -4.2% Wholesale revenue 4,021 5,467 -26.4% 13,493 16,919 -20.2% ---------- ---------- ---------- ------------ ----------- -------- Total Revenues $ 12,967 $ 13,056 -0.7% $ 64,278 $ 69,934 -8.1% ========== ========== ========== ============ =========== ======== Sales Decatherms (Dth): Retail 1,348,000 1,248,372 8.0% 8,414,300 9,269,549 -9.2% Wholesale 1,110,459 2,440,570 -54.5% 4,652,635 7,988,902 -41.8% ---------- ---------- ---------- ------------ ----------- -------- Total 2,458,459 3,688,942 -33.4% 13,066,935 17,258,451 -24.3% ---------- ---------- ---------- ------------ ----------- -------- Average revenues per Dth Retail $ 6.64 $ 6.08 9.2% $ 6.04 $ 5.72 5.5% Wholesale $ 3.62 $ 2.24 61.6% $ 2.90 $ 2.12 36.9%
The three months ended September 30, 2000, reflected increased gas revenues among residential and commercial customers, primarily the result of higher usage per customer as well as increases in residential and commercial customers of 4.9% and 2.5%, respectively. However, the nine-month period ended September 30, 2000, reflected reductions in usage by all classes of retail customers largely due to a 12% decrease in the number of heating degree-days, offset, in part, by increases in residential and commercial customers of 4.9% and 2.8%, respectively. Wholesale gas revenues declined for both the third quarter and the nine- month period ended September 30, 2000 over the same periods in 1999 as a result of less gas available for wholesale sales because of significant increases in the usage of gas supplies for electricity generation offset, in part, by much higher unit prices.
Three Months Nine Months Ended September 30, Ended September 30, ------------------- ------------------- Change From Change From 2000 1999 Prior Year % 2000 1999 Prior Year% ------------ ---------- ------------ ---------- ----------- ------------ Purchased Power ($000) $ 196,865 $ 52,564 274.5% $318,294 $135,343 135.2% Purchased Power in thousands of MWHs 2,511 1,543 62.7% 5,810 4,566 27.2% Average cost per MWH of Purchased Power $ 78.40 $ 34.07 130.1% $ 54.78 $ 29.64 84.8%
Purchased power costs were higher for the three and nine months ended September 30, 2000 because total purchased power requirements were higher than in the same periods in 1999, and SPPC fulfilled more of its total energy requirements 33 with more expensive economy energy purchased power. SPPC also took advantage of additional hedging opportunities and the price was substantially higher.
Three Months Nine Months Ended September 30, Ended September 30, -------------------- --------------------- Change from Change from 2000 1999 Prior Year % 2000 1999 Prior Year -------- -------- ------------- --------- ---------- ------------ Fuel for Power Generation ($000) $65,427 $32,560 100.9% $138,785 $85,397 62.5% Thousands of MWHs generated $ 1,612 $ 1,382 16.6% 4,155 3,701 12.3% Average cost per MWH of Generated Power $ 40.59 $ 23.56 72.3% $ 33.40 $ 23.07 44.8%
Fuel for generation costs for the both the three month and nine month periods ended September 30, 2000, were significantly higher than the same periods of the prior year as gas prices increased significantly and volumes were higher to accommodate greater system load.
Three Months Nine Months Ended September 30, Ended September 30, ------------------- ------------------- Change from Change from 2000 1999 Prior Year % 2000 1999 Prior Year ------- ------- ------------ -------- -------- ---------- Gas Purchased for Resale ($000) Retail $ 2,740 $ 5,043 -45.7% $ 27,638 $ 32,048 -13.8% Wholesale 4,249 4,560 -6.8% 13,672 14,930 -8.4% ------- ------- -------- -------- Total 6,989 9,603 -27.2% 41,310 46,978 -12.1% ======= ======= ======== ======== Gas Purchased for Resale (thousands of decatherms) Retail 1,391 1,248 11.5% 7,976 9,273 -14.0% Wholesale 1,110 2,441 -54.5% 4,653 7,989 -41.8% ------- ------- -------- -------- Total 2,501 3,689 -32.2% 12,629 17,262 -26.8% ======= ======= ======== ======== Average cost per decatherm Retail $ 1.97 $ 4.04 -51.2% $ 3.47 $ 3.46 0.3% Wholesale $ 3.83 $ 1.87 104.8% $ 2.94 $ 1.87 57.2%
The quantity of retail gas purchased for resale increased for the three months and decreased for the nine months ended September 30, 2000, corresponding to the increased and decreased retail demand, respectively, for the same periods. The cost of retail gas purchased for resale for the three and nine months ended September 30, 2000, has been reduced by an adjustment of $3.0 million made in August 2000. The adjustment represented a historical reclassification of gas costs that SPPC determined were properly allocable as fuel for power generation costs. Excluding the adjustment, the average retail cost per decatherm for the three and nine months ended September 30, 2000, would have been $4.14 and $3.84, respectively, reflecting higher gas costs in 2000. 34
Three Months Nine Months Ended September 30, Ended September 30, (in $000's) (in $000's) ------------------ ------------------- Change from Change from 2000 1999 Prior Year % 2000 1999 Prior Year ------- --------- ------------ ------- --------- ----------- Allowance for other funds used during construction $ 81 $ (2,451) N/A $ 215 $ (2,445) N/A Allowance for borrowed funds used during construction 680 (1,723) N/A 1,649 (1,312) N/A ------- --------- ------- --------- $ 761 $ (4,174) N/A $1,864 $ (3,757) N/A ======= ========= ======= =========
Total allowance for funds used during construction (AFUDC) is higher for the three and nine months ended September 30, 2000, as compared to the same periods in 1999 because of higher construction-work-in-progress balances in 2000 and due to a September 1999 adjustment reducing AFUDC for the Pinon Pine project.
Three Months Nine Months Ended September 30, Ended September 30, (in $000's) (in $000's) ------------------ ------------------- Change from Change from 2000 1999 Prior Year % 2000 1999 Prior Year ------- --------- ------------ ------- --------- ----------- Other operating expense $18,608 $24,060 -22.7% $68,328 $67,974 0.5% Maintenance expense 4,162 5,523 -24.6% 12,984 15,233 -14.8% Income taxes (4,591) 5,093 -190.1% 6,605 25,175 -73.8% Interest charges- Long-term debt 10,952 7,817 40.1% 26,861 23,548 14.1% Interest charges-other 1,348 2,004 -32.7% 8,519 6,712 26.9%
Other operating expense was lower for the third quarter of 2000 due to reduced labor and benefit costs in 2000 as a result of merger efficiencies and other unfilled vacancies, and due to higher fire-related claims reserves in 1999. Other operating expense for the nine months ended September 30, 2000 was comparable to the same period in 1999. Maintenance costs for the three-and nine-month periods ended September 30, 2000 were decreased compared to the same periods in 1999, due to fewer outages and lower plant maintenance expenses. Income taxes decreased for both the three and nine months periods ended September 30, 2000, due to comparable reductions in pre-tax income in 2000 as compared to the same periods in 1999. Interest charges-Long-term debt increased for the three and nine months ended September 30, 2000 due to higher average long-term debt balances compared to 1999. Interest charges-other decreased for the three months ended September 30, 2000 due to lower average commercial paper balances compared to 1999. However, commercial paper balances were higher for the nine months ended September 30, 2000, which accounted for most of the increase in Interest charges-other for the nine-month period. Financial Condition, Liquidity And Capital Resources During the first nine months of 2000, SPPC earned approximately $14.8 million in income from continuing operations before preferred stock dividends. SPPC declared $1.95 million in dividends to holders of its preferred stock and declared $61.0 million in dividends on its common stock, all of which is held by its parent, Sierra Pacific Resources. 35 Cash flows during the nine months ended September 30, 2000, were comparable to the same period in 1999. A reduction in cash flows from operating activities, mainly due to a decrease in operating income, was largely offset by a decrease in cash used for investing activities. The decrease in cash used for investing activities was primarily due to SPPC's 1999 acquisition of General Electric Capital Corporation's interest in Pinon Pine Company L.L.C. Cash flows from financing activities increased slightly compared to the prior year due to an increase in net long-term debt issued and a decrease in the reduction in short-term borrowings. Construction Expenditures and Financing SPPC's construction program and capital requirements for the period 2000- 2004 were originally discussed in SPPC's 1999 Annual Report on Form 10-K. Of the amount projected for 2000 ($137.7 million), $85.4 million (62.0%) had been spent as of September 30, 2000. Internally generated funds provided 8.3% of construction expenditures. SPPC may utilize internally generated cash and the proceeds from secured and unsecured borrowings and preferred securities to meet capital expenditure requirements through 2000. Financing On June 9, 2000, SPPC issued $200 million of floating rate notes that will mature on June 12, 2001. Interest on the notes is payable quarterly. The interest rate on the notes for each interest period is a floating rate, subject to adjustment every three months, equal to the London InterBank Offered Rate (LIBOR) for three-month U.S. dollar deposits plus a spread of 0.50%. These notes are not entitled to any sinking fund and are non-callable. The net proceeds of the $200 million issue were used to redeem $100 million of floating rate notes on July 14, 2000, and the remaining proceeds were used to reduce the amount of SPPC's commercial paper outstanding. On July 24, 2000, SPPC received a 30-day extension of its $150 million Credit Facility to August 28, 2000, in accordance with the terms of the credit agreement. On August 28, 2000, SPPC received a 364-day extension of this facility to August 27, 2001. Sierra Pacific Resources (Holding Company) - ------------------------------------------ The Condensed Consolidated Statements of Income of Sierra Pacific Resources for the three and nine months ended September 30, 2000 include the operating results of the holding company. The holding company operating results included approximately $14.0 million and $27.0 million, respectively, of interest costs for the three- and nine-month periods ended September 30, 2000, primarily as a result of financing the merger between SPR and NVP. For additional merger information, see Note 3 to the Condensed Consolidated Financial Statements included in this report. SPR's Condensed Consolidated Statements of Income for the three- and nine-month periods ended September 30, 1999, include only two months' operating results of SPR and its pre-merger subsidiaries. Tuscarora Gas Pipeline Company - ------------------------------ The Condensed Consolidated Statements of Income of Sierra Pacific Resources for the three and nine months ended September 30, 2000 include the operating results of Tuscarora Gas Pipeline Company (TGPC), a wholly owned subsidiary of SPR. TGPC contributed $.5 million and $1.6 million, respectively, in net income for the three- and nine-month periods ended September 30, 2000. Although not fully reflected in the Condensed Consolidated Statements of Income of SPR for the three- and nine-month periods ended September 30, 1999 included in this report, TGPC contributed $.5 million and $1.4 million, respectively, in net income for those periods. e.three - ------- The Condensed Consolidated Statements of Income of Sierra Pacific Resources for the three and nine months ended September 30, 2000 include the operating results of e.three, a wholly owned subsidiary of SPR. e.three incurred a loss of $56,000 for the three-months ended September 30, 2000 and contributed $235,000 in net income for the nine-month period ended September 30, 2000. Although not fully reflected in the Condensed Consolidated Statements of Income of SPR for the three- and nine-month periods ended September 30, 1999 included in this report, e.three incurred net losses of $16,000 and $1.2 million, respectively, for those periods due to start-up activities. 36 Sierra Pacific Energy Company - ----------------------------- The Condensed Consolidated Statements of Income of Sierra Pacific Resources for the three and nine months ended September 30, 2000 include the operating results of Sierra Pacific Energy Company (SPE), a wholly owned subsidiary of SPR. SPE incurred net losses of $.5 million and $4.3 million, respectively, for the three- and nine-month periods ended September 30, 2000. The losses are the result of costs incurred to exit the retail energy-sales business. Although not fully reflected in the Condensed Consolidated Statements of Income of SPR for the three- and nine-month periods ended September 30, 1999 included in this report, SPE incurred net losses of $1.4 million and $2.2 million, respectively, for those periods. Sierra Pacific Communications - ----------------------------- The Condensed Consolidated Statements of Income of Sierra Pacific Resources include the operating results of Sierra Pacific Communications (SPC), a wholly owned subsidiary of SPR. SPC incurred net losses of $305,000 and $380,000, respectively, for the three- and nine-month periods ended September 30, 2000. SPC began operations in the third quarter of 1999. In the first quarter of 2000, SPC finalized a partnership, called Sierra Touch America LLC, with Touch America, a subsidiary of Montana Power Company. The partnership was formed to construct and operate a fiber optic connection between Salt Lake City, Utah and Sacramento, CA. The route is being constructed for AT&T, PF Net Corporation, and Sierra Touch America. SPC's share is approximately $25 million of a total estimated construction cost of $120 million. Right-of-way and permitting is in progress. Construction activity between Sacramento and Reno commenced in July and completion is expected in the fourth quarter of 2000. PORTLAND GENERAL ELECTRIC ACQUISITION ------------------------------------- On November 8, 1999, SPR and Enron Corporation (Enron) announced they had entered into a purchase and sale agreement for Enron's wholly owned electric utility subsidiary, Portland General Electric Company (PGE). PGE is an electric utility serving more than 700,000 retail customers in northwest Oregon. PGE will become a wholly owned subsidiary of SPR. Under terms of the agreement, Enron will sell PGE to SPR for $2.02 billion to $2.1 billion, depending upon the level of liabilities assumed at the time of close. In addition, $1.0 billion in PGE debt and preferred stock will be reflected in SPR's consolidated financial statements. In addition to other regulatory approvals discussed below, the PGE acquisition is subject to the approval of the Securities and Exchange Commission (the "SEC") under the Public Utility Holding Company Act ("PUHCA"), and SPR has applied to the SEC to become a registered public utility holding company under PUHCA. In connection with that application, SPR has made certain representations to the SEC regarding the methods of financing the PGE acquisition and regarding the capital structure of SPR following the acquisition. According to those representations, SPR expects to finance the transaction initially primarily through a bank loan or other form of debt. Ultimately, the transaction is expected to be financed through proceeds from the sale of generation assets of NVP and SPPC and the issuance by SPR of debt and equity securities. Immediately after the acquisition of PGE, SPR expects that its consolidated common equity will be approximately 23 percent of total consolidated capitalization. During the two years following the acquisition, however, SPR has indicated that it intends to increase consolidated common equity to approximately 29 percent by paying down a portion of the acquisition debt with proceeds from the sale of the electric generation assets of NVP and SPPC, the sale of non-strategic assets, the sale of additional common stock, and increased retained earnings from the combined operations of the three utility subsidiaries. SPR's ability to increase its common equity will depend upon, among other things, market conditions and the results of operations of these subsidiaries. The proposed transaction is subject to closing conditions, including, without limitation, the receipt of all necessary governmental approvals, including the Federal Energy Regulatory Commission (FERC), the Federal Trade Commission/Department of Justice (FTC/DOJ), the Securities and Exchange Commission (SEC), the Oregon Public Utility Commission (OPUC), and the Nuclear Regulatory Commission (NRC). SPR's filings have been made and the federal and state regulatory processes continue. As of May 3, 2000, the FTC/DOJ investigation concluded and the waiting period under Hart-Scott-Rodino expired with no action taken. On July 27, 2000, the NRC approved PGE's transfer application filed in January. On August 25, SPR filed additional market power and pricing information requested by the FERC in its late July draft order. On October 30, 2000, the OPUC approved SPR's application to acquire PGE. The OPUC approved a September 1 settlement agreement that calls for a six-year price freeze for PGE customers and a $95 million credit for Oregon consumers. The "acquisition credit" will be shown on monthly power bills as soon as the transaction is complete and will continue through September 30, 2007. PGE will retain its ability to adjust rates to reflect changes in the prices for wholesale electricity and fuel 37 purchased to operate its power plants. It is anticipated that remaining approvals will be received in the fourth quarter of 2000 or in 2001. GENERATION DIVESTITURE ---------------------- In accordance with the revised Divestiture Plan stipulation approved by the PUCN in February 2000 (see the 1999 Annual Report on Form 10-K), SPR is offering for sale generation assets with peak capacity of approximately 2,985 megawatts (MW), with approximately 1,045 MW owned by SPPC and approximately 1,940 MW owned by NVP. Letters of interest were issued to potential bidders in February 2000. Upon response from the qualified potential bidders and execution of the confidentiality agreements, offering memoranda and materials were provided to the bidders. First stage indicative bids were received on May 25, 2000. The short list of qualified bidders for each of the seven bundles being offered was completed and bidders notified by June 6, 2000. The second stage due diligence process was started on June 6, 2000, and will continue through mid-November. Final bids and the selection of winning bids will occur in the Fourth Quarter of 2000. The sale and transfer of ownership is expected to close by mid-2001. Each sale will include an executed Transitional Purchase Power Agreement (TPPA) between the utility and the new owner of the divested generation. The TPPAs will provide price protection by enabling the utilities to buy back energy and ancillary services from the divested plants at prices not to exceed 1998 costs. The term of the TPPAs will begin at closing and end at a date no later than March 1, 2003. On May 10, 2000, AES Corporation announced that it was the successful bidder for the purchase of a controlling interest in the 1,580 MW Mohave Generating Station in Laughlin, Nevada for approximately $667 million. NVP owns a 14% undivided interest in the facility. Mohave Generating Station is a 2- unit, coal-fired power plant located on 2,500 acres along the Colorado River, approximately 80 miles south of Las Vegas. AES executed Asset Sale Agreements with the sellers, NVP (14%) and Southern California Edison Company (56%), for a 70% undivided interest in the facility. The acquisition is subject to approval by the FERC and the California Public Utilities Commission and review by the PUCN, and is expected to close in 2001. On October 19, 2000, SPR and SPPC announced an agreement to sell SPPC's 50% interest in the Valmy Power Station to NRG Energy of Minneapolis, Minnesota. Under the agreement, SPPC will have the right to buy energy and ancillary services from the Valmy Power Station for agreed upon prices subject to a collar, through early 2003. The sale price of the asset bundle, which includes the Battle Mountain Diesel Plant and the Winnemucca Gas Plant, is $273.3 million, net of a payment from SPPC to NRG for the power purchase agreement, subject to taxes and other adjustments. The Valmy Power Station sells electricity in northern Nevada and surrounding markets. SPPC's net capacity interest in the Valmy Power Station totals 286 MW. Located forty miles from Winnemucca, Nevada, the Valmy Power Station consists of two similar coal-fired units and is owned jointly by SPPC and Idaho Power Co. SPPC owns 50% of the station and operates the plant. The sale of the Valmy Power Station bundle, which is subject to approval and review by various regulatory agencies, is expected to close in mid-2001. On October 27, 2000, SPR and SPPC announced an agreement to sell SPPC's Tracy/Pinon Power Station to WPS Power Development, Inc., a wholly owned subsidiary of WPS Resources Corporation of Green Bay, Wisconsin. Under the agreement, SPPC will have the right to buy energy and ancillary services from WPS Power Development for agreed upon prices subject to a collar from closing of the agreement through February 2003. The sale price of the asset bundle, which includes the Tracy Plant, Pinon Pine, and the Brunswick, Gabbs and Valley Road diesel generators, is $249.8 million, subject to taxes and other adjustments at closing. In conjunction with the purchase, SPPC negotiated the right to buy energy and ancillary services from WPS Power Development for agreed upon prices, subject to a collar, from closing up until March 1, 2003, at a cost ranging from $80 million to $150 million, based on time of closing. The Tracy/Pinon Power Station sells electricity in northern Nevada and surrounding markets. Tracy is also the site of the Pinon Pine Integrated Coal Gasification Combined Cycle project co-funded by the U.S. Department of Energy as part of the Clean Coal Technology Program. SPPC's average capacity in the Tracy/Pinon Power Station totals 525 megawatts. Located approximately 20 miles from Reno, Nevada, the Tracy/Pinon Power Station consists of three similar gas- and oil-fired units, four gas turbines, and the Pinon Pine facility (a combined cycle unit). The sale of the Tracy/Pinon Power Station, which is subject to approval and review by various regulatory agencies, is expected to close no later than June 2001. SALE OF WATER BUSINESS ---------------------- On September 7, 2000, SPR and SPPC announced their intention to sell SPPC's water utility business as part of a strategy to concentrate on SPR's core electric, gas and telecommunications businesses. SPPC expects to exit the entire water business. Expected to be included in the sale is water storage and supply, treatment facilities, and transmission and distribution facilities. Also included in the sale will be four hydroelectric generation plants on the Truckee River, totaling approximately nine MW of installed (name plate) generation capacity. The transaction is expected to close in the first half of 2001, after a buyer is selected and the necessary regulatory approvals are received. 38 The water utility business currently employs approximately 87 direct employees. As of December 31, 1999, total assets were approximately $268 million and net utility plant was about $257 million. For the nine months ended September 30, 2000, revenues were $44.3 million. The water business serves approximately 71,000 customers in the Reno/Sparks area. REGULATORY MATTERS ------------------ Substantially all of the utility operations of both NVP and SPPC (collectively the "utilities") are conducted in Nevada. As a result both companies are subject to utility regulation within Nevada and therefore deal with many of the same regulatory issues. Nevada Electric Restructuring Activities - ---------------------------------------- Competition was originally scheduled to start on March 1, 2000. However, in February 2000 the Governor of Nevada delayed the start date of competition indefinitely. Generally, restructuring regulations and PUCN decisions during the first and second quarters of 2000 proceeded slowly. Numerous hearings and workshops have been held by the Public Utilities Commission of Nevada (PUCN) regarding two important regulations, Provider of Last Resort and Past Costs regulations. On March 28, 2000, SPR, NVP and SPPC filed a federal lawsuit challenging Nevada's laws providing for competition in the electric utility industry and the PUCN's implementation of competition. See SPR's and NVP's Form 8-K, filed on April 17, 2000. On July 20, 2000, the PUCN approved stipulated agreements that resolved pending state and federal lawsuits and major restructuring issues including past costs. See the Form 8-K filed July 26, 2000. On August 3, 2000, the PUCN approved revisions to the stipulated agreements. The stipulations paved the way for open access to occur in a phased manner beginning in November 2000 for large commercial customers and continuing until September 2001 for residential customers. On October 4, 2000, the Governor announced that he had decided to delay the opening of the electricity market in order to allow the state to develop a comprehensive energy policy. The Governor also appointed a bipartisan panel to develop a long-term strategy and report its findings by January 15, 2001, prior to the start of the 2001 legislative session. Management believes it is probable that changes will be made to restructuring legislation and / or PUCN restructuring rules. The following are highlights of the stipulations: Incentives for Utilities to Meet Open Access Dates Provided that open access procedures including billing and settlement are in place by the open access dates, NVP and SPPC will be allowed to retain up to $16 million and $9 million, respectively, from any gain on the divestiture of generation assets. Past Costs Major past cost issues are resolved by the stipulations. The utilities have waived their rights to the collection of any past costs other than those provided for in the stipulations. The parties have agreed that the stipulations eliminate the need for a past cost regulation. Generation The gain on the sale of generation facilities for regulatory purposes will be calculated based upon recorded book values as of the date of sale and includes costs of sale, less applicable taxes and amounts related to the Transitional Purchase Power Agreements (See Generation Divestiture, above). Common and general plant allocable to generation will be recoverable from the gain. NVP is to receive the first $15 million dollars in settlement for certain deferred energy costs. Additional gain, if any, from the sale of NVP's generation facilities will be applied to the allowed incentive to NVP for meeting retail open access dates, as described above. Additional gain, if any, up to $9 million, from the sale of SPPC's generation facilities will be applied to the allowed incentives to SPPC for meeting retail open access dates, as described above. Any remaining gains will be set aside in escrow accounts to be utilized to pay down costs associated with above-market purchased power contracts. 39 Purchased Power Contracts The utilities will auction their purchased power contracts on an annual basis in the wholesale markets. If the auction does not yield sufficient proceeds to pay for the purchased power contracts, the utilities will collect the difference from all customers through a non-bypassable wires charge. This Purchased Power Agreement Adjustment Mechanism (PPAAM) charge will be in place when the market opens. NVP and SPPC each filed its first PPAAM with the PUCN on October 2, 2000. To the extent that there are tax or market advantages, the utilities will pursue a competitive permanent auction of purchased power contracts. Such an auction would be funded by an amount not to exceed the principal and interest in the escrow accounts that were funded by the gain on the sale of generation assets. If the permanent auction does not proceed or if such auction does not exhaust the generation escrow accounts, the PPAAM charge will be reduced by an annuity calculated on any remaining amount in the generation escrow account. Metering Customers will have the opportunity to purchase metering equipment directly from the utilities or through an alternative seller. Such assets will be sold at net book value. Transition Costs The ability of the utilities to recover costs they expect to spend to open the market, referred to as transition costs, was not resolved by the stipulations. The utilities expect to petition the PUCN in the near future to request recovery of their transition costs. In other matters related to restructuring, the PUCN has continued rulemaking and discussion related to a number of topics including: Transmission Access for Retail Competition On July 19, 2000, the utilities filed with the FERC a modified Open Access Tariff that would govern transmission access for retail competition in Nevada until a Regional Transmission Organization (RTO) becomes operational. The modified Open Access Tariff was approved by FERC on October 25, 2000, to become effective when retail competition begins in Nevada. The utilities also continue to pursue compliance with FERC Order 2000, which calls for utilities to form RTO's. Also see FERC Matters, below. Unbundling of Utility Services In May 2000, the PUCN issued final orders (the "Orders") that were consistent with its September 1999 interim order. See the utilities' 1999 Annual Reports on Form 10-K for additional information on the interim order. The Orders reduce the utilities' revenue requirements and returns on equity for distribution service for those customers who choose to leave the utilities upon the start of retail competition. NVP and SPPC filed Petitions for Reconsideration with the PUCN. The petitions were granted by the PUCN in the first half of July 2000. As part of the July 20, 2000 Settlement, the utilities withdrew their Petitions for Reconsideration of all issues arising out of the Commission's Interim and Compliance Orders with the exception of two issues related to plant depreciation rates and treatment of merger costs and savings. Provider Of Last Resort (PLR) The PLR will provide electric service to customers who do not select an electricity provider and to customers who are not able to obtain service from an alternative seller after the date competition begins The PUCN has conducted several hearings on the PLR regulation and is nearing completion of this regulation. Some of the negative provisions of the regulation have been modified including language that restricted the PLR's ability to finance costs. However the proposed regulation continues to contain a strict standard of conduct to govern the relationship between electric distribution utility (EDU) and PLR functions. Implementation of these provisions could have negative financial ramifications. 40 Ferc Matters - ------------ Regional Transmission Organization (RTO) On May 1, 2000, NVP, SPPC, and Avista Corporation, Bonneville Power Administration (BPA), Idaho Power Company, The Montana Power Company, PacifiCorp, Portland General Electric, and Puget Sound Energy, Inc. formed RTO West and filed articles of incorporation in the State of Washington. RTO West will be a non-profit independent system operator governed by an independent board of directors with a stakeholder advisory board. RTO West would be the single provider of transmission services, and controller of transmission operations in an eight-state region. RTO West submitted a compliance filing on October 16, 2000 with FERC. Supplemental material, which provided details of the formation of RTO West, was submitted on October 23. The creation of RTO West is subject to regulatory approvals from FERC and the states served by the investor-owned utilities. The organization will begin operations after all approvals are obtained. FERC's goal is for all RTO's to be operational by December 15, 2001. The proposed operational date in the RTO West filing is approximately one year later. Independent Transmission Company On October 16, 2000, NVP, SPPC, and Portland General Electric Company, Avista Corporation, The Montana Power Company, and Puget Sound Energy filed jointly with FERC to form TransConnect, a for-profit Independent Transmission Company. The creation of TransConnect is subject to regulatory approvals from FERC, state regulators, and the board of directors of each company. TransConnect would own or lease the transmission facilities of the six utilities in Oregon, Washington, Nevada and Montana and parts of Idaho and California. Those facilities are within the proposed territory for RTO West. RTO West would deal with TransConnect, instead of the six utilities. TransConnect expects to begin operations by December 15, 2001. Open Access Transmission Rates In May 1999, NVP filed an application with the FERC to increase its Open Access Transmission rates. On March 30, 2000, the FERC approved the settlement filed on February 8, 2000 with rates becoming effective on March 1, 2000. Also on March 30, 2000, NVP filed a Loss Study that NVP agreed to provide in the settlement. On May 23, 2000, the FERC accepted NVP's Loss Study and the docket was completed. In March 1999, SPPC filed an application with the FERC to increase its Open Access Transmission rates. See the SPPC's 1999 Annual Report on Form 10-K. On March 30, 2000, SPPC filed a Loss Study that SPPC agreed to provide in the partial settlement that was approved in January 2000. On April 26, 2000, a settlement was filed by SPPC on issues raised by the City of Fallon and on August 1, 2000, the FERC approved the settlement. On July 18, 2000 a settlement was filed by SPPC on issues raised by the Mines which provides that the issues not be resolved in this case, but at a later date. On September 18, 2000, the FERC approved the settlement On July 7, 2000, a settlement was filed by SPPC resolving all Loss Study issues in the case and on September 18, 2000, the FERC approved the settlement. Revised Generation Tariffs And Transitional Purchase Power Agreements On March 31, 2000, the utilities filed for approval of Generation Tariffs that contain the rates, terms and conditions under which the new owners of divested generation facilities could sell energy and ancillary services. The filing also included pro-forma Transitional Purchase Power Agreements (TPPAs) between the utilities and the new owners of the divested generation facilities. Final signed versions of the TPPAs will be submitted to the FERC as part of the Asset Sale Agreements between the utilities and the new owners of the divested generation. On May 31, 2000, the FERC accepted for filing the Generation Tariff and the TPPAs. The FERC required one modification to the TPPAs in that the utilities were required to notify the new owners day-ahead of real-time of their intended use of the generation or release the capacity to the new owners. The FERC also set for hearing the rates in the generation tariff and in the TPPAs. The utilities have reached a settlement with the FERC Staff, PUCN and the Bureau of Consumer Protection regarding the rates in the Generation Tariff and TPPAs. The settlement has not yet been submitted to the FERC for approval. 41 California Matters (SPPC) - ------------------------- Generation Divestiture On March 2, 2000, SPPC filed a new application requesting exemption from California Public Utility Commission (CPUC) approval of the Nevada-based generation divestiture transaction. SPPC cited several reasons for the exemption including that the PUCN and FERC oversight of the generation divestiture will assure reliability and market power mitigation as required by California's electric restructuring legislation. On September 18, 2000, a proposed settlement agreement was filed with the CPUC. Distribution Performance-based Rate-making (PBR) On May 4, 2000, the CPUC dismissed without prejudice SPPC's January 3, 2000 distribution PBR proposal (see the SPPC's 1999 Annual Report on Form 10-K). The order accepted the application as meeting the compliance requirement but directed SPPC to re-file it when the cost of capital and cost of service studies are available. On May 8, 2000, SPPC filed its 2001 Cost of Capital application. On July 3, 2000, SPPC re-submitted the PBR proposal along with the Cost of Service Study. In September 2000, hearings were held on SPPC's Cost of Capital filing. On September 20, 2000 a pre-hearing conference was held on SPPC's Cost of Service and Distribution PBR filing which established the procedural schedule. Litigation Regarding California Power Market. In response to complaints and requests for relief filed by California utilities and their customers, the FERC issued an order on August 23, 2000 initiating hearing proceedings under section 206 of the Federal Power Act ("FPA") to address matters affecting bulk power markets and wholesale energy prices (including price volatility) in California. On November 1, 2000, the FERC proposed specific remedies to address problems that it found in California's wholesale bulk power markets and to ensure just and reasonable wholesale power rates by public utility sellers in California. This ongoing proceeding, together with proceedings currently pending before the CPUC, may result in significant changes to the California power markets. Some parties to these proceedings have requested refunds from sellers of electrical power for past market transactions. The FERC denied this request for sales prior to October 2, 2000. However, the FERC held that sales made after October 2, 2000 are subject to refund, with the level and extent of any refund to be determined in future orders. Although a relatively small portion of SPPC's electricity customers are in the California, SPR, SPPC and NVP are monitoring the developments in California and at the FERC to determine what effect, if any, those developments may have on SPPC's California operations, on bulk sales of power by either utility and on general market prices for wholesale energy in the western United States. ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK See "Results of Operations" above for a discussion of recent increased prices and volatility in the markets for purchased power and fuel, which have had a negative effect on the financial performance of NVP, SPPC, and SPR. 42 PART II ITEM 1. LEGAL PROCEEDINGS On March 28, 2000, SPR, NVP, and SPPC filed a lawsuit in Federal District Court in Nevada asking the court to declare unconstitutional certain aspects of the Nevada laws that created the framework for a deregulated electric market in Nevada. In response to the certain PUCN decisions described in SPR's Annual Report on Form 10-K for the period ending December 31, 1999 and in SPR's Quarterly Report on Form 10-Q for the period ending March 31, 2000, NVP filed a lawsuit against the PUCN on March 30, 2000 in the First Judicial District of Nevada in Carson City. On July 20, 2000, the PUCN approved a stipulation (the "Settlement") entered into among the parties to the state and federal lawsuits permitting NVP to increase its rates effective August 1, 2000, by approximately $48 million annually to recover increased costs of fuel and purchased power, and to update its going-forward costs of fuel and purchased power thereafter with monthly fuel and purchased power filings up to March 2003. Increases and/or decreases are capped at incrementally increased or decreased rates over successive six-month periods at .95 mils for the first six months, 1.15 mils for the second six months, 1.25 mils for the third six months, 1.55 mils for the next six months, and 1.75 mils for the remaining period. The Settlement also permits SPPC to commence filing monthly fuel and purchased power adjustment cases on the same basis to commence not later than November 1, 2000. SPPC fuel and purchased power increases and/or decreases are also capped at incrementally increased or decreased rates over successive six-month periods starting October 1, 2000 at 4.5 mils for the first six-month period followed by .95, 1.15, 1.35, 1.55, and 1.75 mils for each successive six-month period. The Settlement also resolved numerous other issues relating to the restructuring of the electric industry in Nevada, including phased-in access to competitive markets by customer class, recovery of stranded costs, auctioning out-of-market qualified facility and other purchased power contracts, imposition of a wires charge to recover any balance, and filing of new proceedings to address metering costs and transition costs. Recovery is still subject to future regulatory proceedings relating to the filing of monthly fuel and purchased power cases, recovery of stranded costs, and divestiture of generation proceeds. The outcome of the dockets and proceedings cannot be predicted at this time; however, unfavorable treatment of any of these proceedings would have a negative effect on the economic value of the Settlement. See the Form 8-K filed July 26, 2000 and Regulatory Matters, above, for additional details. Although SPR is involved in other ongoing litigation on a variety of matters, it is management's opinion that none individually or collectively are material to SPR's financial position. 43 ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS None ITEM 5. OTHER INFORMATION None ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K (a) Exhibits filed with this Form 10-Q: (10.A) Stipulation and Agreement To Compromise and Settle - Federal (10.B) Stipulation and Agreement To Compromise and Settle - State (27) The Financial Data Schedule containing summary financial information extracted from the condensed consolidated financial statements on Form 10-Q for the nine month period ended September 30, 2000, for Sierra Pacific Resources, and is qualified in its entirety by reference to such financial statements. (b) Reports on Form 8-K: Form 8-K filed on July 14, 2000 by SPR, NVP, and SPPC- Item 5, Other Events Described, and included as an exhibit, SPR's press release dated July 12, 2000, announcing that fuel and purchased power costs would negatively impact earnings for the second quarter and the remainder of 2000. Form 8-K filed on July 26, 2000 by SPR, NVP, and SPPC - Item 5, Other Events Described, and included as an exhibit, SPR's press release dated July 20, 2000, announcing that the Company, Nevada regulators and several other parties took steps toward a settlement of issues involving restructuring the electric utility industry in the state, setting new electric rates for NVP's and SPPC's customers and resolving other issues involved in state and federal court cases filed by NVP and SPPC. Form 8-K filed on September 12, 2000 by SPR and SPPC - Item 5, Other Events Described, and included as an exhibit, SPR's press release dated September 7, 2000, announcing that its SPPC subsidiary intends to sell its water business. 44 SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the registrants have duly caused this report to be signed on their behalf by the undersigned thereunto duly authorized. Sierra Pacific Resources ------------------------ (Registrant) Date: November 14, 2000 By: /s/ Mark A. Ruelle ----------------- ----------------------------- Mark A. Ruelle Senior Vice President Treasurer Chief Financial Officer (Principal Financial Officer) Date: November 14, 2000 By: /s/ Mary O. Simmons ----------------------------- Mary O. Simmons Controller (Principal Accounting Officer) Nevada Power Company -------------------- (Registrant) Date: November 14, 2000 By: /s/ Mark A. Ruelle ----------------- ----------------------------- Mark A. Ruelle Senior Vice President Treasurer Chief Financial Officer (Principal Financial Officer) Date: November 14, 2000 By: /s/ Mary O. Simmons ----------------------------- Mary O. Simmons Controller (Principal Accounting Officer) SIERRA PACIFIC POWER COMPANY ---------------------------- (Registrant) Date: November 14, 2000 By: /s/ Mark A. Ruelle ----------------- ----------------------------- Mark A. Ruelle Senior Vice President Treasurer Chief Financial Officer (Principal Financial Officer) Date: November 14, 2000 By: /s/ Mary O. Simmons ----------------------------- Mary O. Simmons Controller (Principal Accounting Officer) 45 EX-10.A 2 0002.txt STIPULATION & AGMT. TO COMPROMISE & SETTLE-FEDERAL EXHIBIT 10A AGREEMENT AND STIPULATION This Stipulation And Agreement To Compromise and Settle ("Stipulation") is intended as a formal settlement and compromise among the Parties as to various matters set forth herein. For valuable consideration, the receipt of which is hereby acknowledged by the Parties, the Parties agree as follows: 1. The Stipulation and Agreement to Compromise and Settle pertaining to Case Nos. 97-00742A, 99-00470A, 99-00754A, and 00-00416A, attached hereto as Exhibit A, are incorporated herein by reference and made a part of this Stipulation as though fully set forth in this paragraph. 2. Immediately upon entry by the Public Utilities Commission of Nevada ("PUCN") of final, unappealed and unappealable orders approving the first filed monthly applications pursuant to Paragraph 6 of Exhibit A and Paragraph 3 below, Nevada Power Company ("NPC"), Sierra Pacific Resources ("SPR"), and Sierra Pacific Power Company ("SPPC") will dismiss with prejudice Case No. CV-N- 157 DWH VPC filed in the United States District Court for the District of Nevada. In the event that this Stipulation, including any stipulation and/or agreements incorporated by reference herein, or any terms or conditions set forth herein, are not approved, or adopted and/or implemented in full and strict accordance with the terms specified herein, or if any Court precludes the enforcement of any of the rights and remedies set forth in said agreements for any reasons, the parties hereto specifically agree that said dismissal with prejudice shall not preclude SPPC, SPR or NPC from asserting any claims which accrue 1 subsequent to such dismissal, or that dismissal with prejudice cannot be raised as a bar to any claims, of whatsoever kind or nature based on unconstitutional takings or deprivations of any property rights under the Federal and/or State Constitutions.. 3. SPPC will implement a monthly fuel and purchased power ("F&PP") rider with rate schedules to be effective forty-five (45) days after the date of each filing. SPPC's first F&PP rider filing will be made no earlier than August 15, 2000, and no later than November 1, 2000. SPPC's initial F&PP rider will not exceed 4.5 mils per kWh from its current BTER. SPPC shall file monthly applications thereafter to adjust the F&PP rider. 3.1 The monthly change in the F&PP rider will be determined as the difference between the Nevada jurisdictional total fuel and purchased power costs for the twelve month period beginning fourteen months prior to the adjustment month divided by the Nevada jurisdictional kWh sales for the same period, and the Nevada jurisdictional total fuel and purchased power costs for the twelve month period beginning fifteen months prior to the adjustment month divided by the Nevada jurisdictional kWh sales for the same period. The methodology for calculation of the F&PP rider is attached as Exhibit B. 4. After the initial F&PP filing, monthly adjustments to the F&PP rider shall not result in changes, upward or downward, that exceed those in the following schedule: (a) 0.95 mils per kWh for each of the first six monthly filings. (b) 1.15 mils per kWh for each of the second six monthly filings. (c) 1.35 mils per kWh for each of the next six monthly filings. 2 (d) 1.55 mils per kWh for each of the next six monthly filings. (e) 1.75 mils per kWh on a monthly basis for filings through December 15, 2002 for rates effective February 1, 2003 to February 28, 2003 4.1 These adjustments are calculated exclusive of any Purchased Power Agreement Adjustment Mechanism ("PPAAM") incorporated into this F&PP rider. It is also recognized that with the implementation of any PPAAM that the F&PP rider calculation will be adjusted to recognize the impact of the PPAAM. 4.2 No later than October 1, 2002, SPPC will make a filing in the form of a general rate case to reset all components of rates, such rates to be effective March 1, 2003. 5. The Parties to this Stipulation are of the opinion that such monthly F&PP filings to be made by SPPC are lawful under NRS Chapter 704, and that such filings should be accepted by the Public Utilities Commission of Nevada ("Commission") for review, and warrant that they will not oppose such filings for review nor challenge the legality of such filings in any administrative or court proceeding. The Parties, other than the Commission, will not seek to suspend the schedules implementing the rate changes set forth in the monthly F&PP filings, and will support SPPC's request not to suspend such schedules. The Parties agree to support expedited treatment of such filings. 6. SPPC will include with each F&PP monthly filing a statement of its separate fixed charge coverage ratio calculations for the 12-month period covered by the F&PP rider filing. If the acquisition of Portland General Electric is consummated, any goodwill amortization expense associated with the transaction shall not be included 3 in the calculation of the fixed charge coverage ratio. The form of the calculation is attached hereto as Exhibit C. SPPC will not implement an increase in the F&PP rider when its respective fixed charge ratio is at or exceeds 2.5 times. Nothing in this paragraph 6 will be deemed to permit adjustments to the F&PP rider that would exceed the limitations to the F&PP rider outlined in Paragraph 4 above. 7. Six months following the implementation of the F&PP rider mechanism, and every six months thereafter (unless changed by the Commission) SPPC will file with the Commission an independent audit of fuel and purchased power purchasing practices. Any findings of imprudence by the Commission will be reflected in future F&PP adjustment filings, and all parties retain any and all rights with respect to said F&PP filings except those specifically involved herein. Such fixed charge covenants shall be calculated before giving effect to extraordinary gains or losses. The Company will not object to such audit results being made available by the Commission to any party to this Stipulation or as required under any applicable law. 8. General rates (non-fuel and non-purchased power) for SPPC will remain capped until March 1, 2003 as required by NRS (S) 704.982 and NRS (S)704.9823. 8.1 NPC and SPPC hereby agree to retain and support the pricing structure of the TPPCs filed in FERC Dockets ER00-2015 and ER00-2018 on June 29, 2000. The parties are free to pursue remedies associated with all other issues related to these dockets. 9. SPPC's obligations to make monthly F&PP filings, all limitations on F&PP adjustments, and the requirement to perform and to file independent audits of the F&PP shall cease December 15, 2002, with an audit covering purchases up to 4 October 31, 2002. Notwithstanding the provisions of Paragraph 4, if SPPC's obligation to provide provider of last resort ("PLR") service ends prior to March 1, 2003, the F&PP adjustment mechanism will terminate at that time and SPPC will file a final audit covering the period ending on the date of termination. Disposition of amounts identified by the final audit will be determined by the Commission. If SPPC remains obligated to provide PLR service through an affiliate, such affiliate will also be permitted the use of the F&PP rider pursuant to the terms of this Stipulation. Retail Open Access 10. NPC agrees to have in place, and Parties agree to support, procedures including but not limited to accurate and timely billing procedures, that will accommodate and result in the opening of the retail market in potentially competitive services pursuant to NRS (S)704.976 for customers of NPC according to the following schedule: November 1, 2000: Distribution rate classes C-4, C-5, and all C-3 accounts which are also C-4 and/or C-5 customers. April 1, 2001: Distribution rate classes C-3, except those provided for above. June 1, 2001: Distribution rate classes C-1 and C-2 September 1, 2001 to All remaining customers will be eligible on a December 31, 2001: phased- in basis. 11. Subject to existing contractual obligations and tariffs filed by SPPC and approved by the Commission, customers eligible for service distribution rate 5 classes SG and LIG may acquire generation, aggregation, metering and billing services from an alternative seller beginning November 1, 2000. 12. The Parties agree to jointly seek an amendment to SB 438 that permits the distribution utility ("EDU") acting as the provider of last resort ("PLR") serving customers in NPC's or SPPC's service territories to implement the F&PP rider. 13. Upon the effective date of legislation described in paragraph 12 above, SPPC agrees to have in place, and Parties agree to support, procedures including but not limited to accurate and timely billing procedures, that will accommodate and result in, the opening of the retail market in potentially competitive services pursuant to NRS (S)704.976 for customers of SPPC according to the following schedule: April 1, 2001 Distribution rate class SG, LIG, and LPG June 1, 2001 Distribution rate classes LSG, IMIG, IMPG, IMSG, MIG, MPG, and MSG September 1, 2001 All remaining customers will be eligible on to December 31, 2001 a phased-in basis. 14. NPC and SPPC will file tariffs necessary for prudent supply management for the PLR including: notice appropriate for each class of customers electing open access, notice appropriate for each class of customers electing to return to the PLR, and such pricing and other terms and conditions as are necessary and appropriate to accommodate customers' return to PLR service, and so as to not frustrate the recovery of costs to be collected in the F&PP rider. 15. The Parties agree to support legislation eliminating the requirements of NRS (S) 704.982(5) and NRS (S) 704.9829 to promote the efficient transfer of PLR functions to other qualified suppliers. 6 Generation Proceeds and PPA Mitigation 16. Gain on the sale of the generation will be determined based on the net proceeds of each bundle after tax less cost of the sale and the sum of recorded book value on the closing date, with the accuracy of such recorded book values verified by the Companies' independent auditors. Book values for each of the bundles will be adjusted only for normal additions, retirements and scheduled depreciation. For illustrative purposes only, unaudited book values as of March 31, 2000, are attached as Exhibit D. 16.1 The Parties agree that, taken as a whole for the Tracy bundle, any gains on the sale of the bundle shall be treated the same as other gains on other bundles. If, however, taken as a whole, the Tracy bundle sells for below book value, such proceeds received by the Company shall not entitle the Company to claim additional amounts up to book value. 17. NPC and SPPC will recover from the gain (as defined in paragraph 16 above), the value of common and general plant determined by the Commission and allocated to the generation function. NPC and SPPC will make a corresponding reduction to common and general plant rate base reflecting the amount of recovery described herein. 18. Except as provided in paragraphs 18.1 and 18.2, all remaining gain after distribution of proceeds as set forth in paragraph 5 of Exhibit A and paragraph 17 above will be placed into separate escrow accounts by NPC and SPPC ("Generation Proceeds Escrow Accounts") promptly upon final receipt of the proceeds from each sale and invested by a third party professional manager, approved by the Commission for the 7 purposes of disbursements in accordance with Paragraphs19(A)and 19(B) below, and recovery of any out-of-market costs associated with those purchased power agreements ("PPAs") listed on Exhibit E. Any surplus remaining after satisfying all over-market costs associated with PPAs will be refunded to customers. 18.1 SPPC will receive from next available proceeds up to the amount of $9,000,000 so long as it meets the deadlines set forth in Paragraph 13 above. Such proceeds shall be disbursed as follows: (a) 20% ($1,800,000) Opening of retail energy market to rate classes SG, LIG, and LPG (b) 40% ($3,600,000) Opening of retail energy market to rate classes LSG, IMIG, IMPG, IMSG, MIG, MPG, and MSG (c) 40% ($3,600,000) Opening of energy market to all remaining rate classes. Deviations from the above schedule pursuant to, necessitated or caused by regulatory or legislative act or acts do not constitute a waiver or forfeiture of the timing or amounts set forth above. 18.2 Nevada Power will receive from next available proceeds up to the amount of $16,000,000 so long as it meets the deadlines set forth in Paragraph 10 above. Such proceeds shall be disbursed as follows: (a) 25% ($4,000,000) Opening of retail energy market to rate classes C-4, C-5 and all C-3 accounts which are also C-4 and/or C-5 customers. (b) 25% ($4,000,000) Opening of retail energy market to remaining C-3 rate classes. (c) 25% ($4,000,000) Opening of retail energy market to rate classes C-1 and C-2. 8 (d) 25% ($4,000,000) Opening of retail energy market to remaining rate classes. Deviations from the above schedule pursuant to, necessitated or caused by regulatory or legislative act or acts do not constitute a waiver or forfeiture of the timing or amounts set forth above. 18.3 Any revenue Nevada Power receives from the sale of S02 allowances shall be treated consistent with prior Commission orders. 19. The parties shall exercise good faith to mitigate costs associated with PPAs, pursuant to the following methods. (A) Permanent Auction: to the extent there are tax or market advantages, ------------------ and if approved by the Commission, NPC and SPPC will execute a competitive, permanent auction of PPAs within two months of the completion of the divestiture of 50 percent or more of the respective Company's generation capacity, funded with an amount up to, but not exceeding the balance remaining on escrowed gains from the sale of generation. Any PPAs not divested in the permanent auction shall have their energy and capacity auctioned in the Annual Auction described below. NPC and SPPC shall hold a permanent auction for all remaining PPAs at least every two years following the initial permanent auction. In no event shall the Companies be required to fund any such auction or buyout with other than funds escrowed pursuant to Paragraph 19 above. (B) Annual Auction: The Companies, in collaboration with the Staff and -------------- the BCP, will secure the services of an independent agent. The function of 9 the independent agent is to determine market price for and to market PPA energy and capacity annually on the wholesale markets. Amounts received from the annual wholesale auction shall be an additional source of funds to meet the obligations under the PPAs. (C) The Parties agree that (A) and (B) above constitute adequate mitigation pursuant to NRS (S) 704.983 and (S) 704.9865. 20. The Parties agree that the following PPAAM will be implemented. PPA costs not collected through paragraph 19 (A) and (B) will be collected concurrently through a non-bypassable wires charge calculated and collected in a competitively neutral manner as provided herein. Such wires charge, which will be collected from all customers, will be effective with retail open access on November 1, 2000, determined pursuant to (B) above. Such wires charge will be credited with an annuity calculated based on the value of the principal and interest from the invested net proceeds described in paragraph 19 and the remaining life of the PPA obligations. An illustration of this mechanism is attached hereto as Exhibit F. Transition and Past Costs 21. All parties reserve all claims with respect to recovery of transition costs, and except as provided in paragraphs 16 through 20 and 21.1 herein, NPC and SPPC remit, release, and waive whatever rights and claims they may have to collect past costs as set forth and described at NRS (S) 704.983. 10 21.1 The Parties to the Stipulation, except the Commission, agree to seek to close the past cost portion of Docket No. 97-8001, as that proposed regulation is no longer necessary. 21.2 The parties agree that to the extent that any Commission order results in the stranding of NPC and/or SPPC's metering assets, NPC and/or SPPC will either continue to recover the book value of such stranded metering assets as plant in service, or recover the book value of such stranded metering assets through a charge established for this purpose. SPPC and NPC agree to offer to transfer ownership of any meter previously used to serve a customer to that customer or to an alternative seller chosen by the customer at net book value. SPPC and NPC shall file with the Commission, a proposed tariff for the transfer of ownership of meters at net book value within sixty (60) days of the effective date of this Stipulation. Transmission 22. The Companies will promptly, but in no event later than July 19 , 2000, file with the FERC modifications to their open access transmission tariffs ("OATT") to facilitate retail open access. 23. The Companies will diligently pursue compliance with FERC Order 2000 and the formation of a regional transmission organization ("RTO"). The Companies will not form a separate affiliate to provide generation and/or aggregation services in Nevada prior to the transfer of transmission facilities to an RTO established pursuant to FERC Order 2000 and approved by the FERC. 11 24. Until such time as an RTO is implemented, the Companies agrees to "Glass House" procedures as set forth below to assure the effectiveness of open access. (a) Companies will fund up to $250,000 annually for professional and technical salaries and benefits. (b) Companies will provide reasonable in-kind office accommodations, access, equipment and supplies. (c) Consistent with FERC rules, the Companies will provide real-time audit access to systems and records related to transmission scheduling. Other Provisions 25. Except as necessitated or caused by legislative or regulatory act, NPC assumes any and all risks of losing the two-county exemption for reason of merger. 26. SPR will hold Nevada customers harmless for any increase in costs associated with SPR's acquisition of Portland General Electric ("PGE"). The Company will only recover costs associated with the PGE acquisition, including goodwill, to the extent that it demonstrates in a proceeding before the Commission net savings sufficient to offset costs attributable to the transaction. The Company agrees that net savings (i.e. savings net of transaction costs) associated with the acquisition, including economies of scale, shall be used to reduce cost of service. 27. The provisions of this Stipulation are not severable and, in the event any aspect or provision of this Stipulation is not fulfilled, adopted, and fully enforced in accordance with its terms by the PUCN, it shall be deemed withdrawn, null 12 and void, and of no further effect, and without prejudice to any claims or contentions which may have been made in any proceeding by any party, and shall not be admissible as evidence, or described or discussed in any legal proceeding. 28. This Stipulation is subject to the Commission's approval and is made upon the express understanding that it constitutes a negotiated settlement of all issues set forth herein, and is contingent upon Commission approval of the stipulations concurrently submitted in Commission Docket Nos. 00-5003, 00- 5005, 99-4001, 99-4002, 99-4005, 99-4006, Case No. CV-99-01743 in the Second Judicial District Court in the State of Nevada in and for Washoe County, and Case No. 00-00416A in the First Judicial District Court in the State of Nevada in and for Carson City. 29. Except for those rights, claims and/or defenses as are expressly waived herein, all Parties reserve any and all rights, claims and defenses of whatsoever kind or nature with respect to any proceeding contemplated herein. The Parties agree to take all possible action to support this Stipulation, and to take no action, direct or indirect, in opposition to the request for approval of this Stipulation. PUBLIC UTILITIES COMMISSION BUREAU OF CONSUMER PROTECTION OF NEVADA By______________________________ By______________________________ Jeff Parker, General Counsel Timothy Hay, Consumer Advocate REGULATORY OPERATIONS STAFF, PUCN By_________________________________ Jackie Rombardo, Staff Counsel 13 NEVADA POWER COMPANY MANDALAY BAY PARK PLACE SIERRA PACIFIC POWER COMPANY ENTERTAINMENT, MIRAGE SIERRA PACIFIC RESOURCES (MPPM) GROUP By_______________________________ By_________________________________ William E. Peterson, General Counsel Martha Ashcraft, Esquire 14 EX-10.B 3 0003.txt STIPULATION & AGMT. TO COMPROMISE & SETTLE-STATE EXHIBIT 10B Case No.: 00-00416A Department No.: 1 FIRST JUDICIAL DISTRICT COURT OF THE STATE OF NEVADA IN AND FOR CARSON CITY NEVADA POWER COMPANY, ) ) Petitioner, ) ) STIPULATION AND AGREEMENT TO versus ) COMPROMISE AND SETTLE ) PUBLIC UTILITIES COMMISSION OF NEVADA, ) ) Defendant. ) _________________________ / This Stipulation And Agreement To Compromise And Settle ("Stipulation") is intended as a formal settlement and compromise among the Parties as to any and all claims for relief and causes of action asserted in the actions set forth in Case Nos. 97-00742A, 99-00470A, 99-00754A, and 00-00416A, which pertain to the judicial review of deferred energy dockets, orders and decisions which form the subject matter of said action. 1. Nevada Power Company ("Nevada Power") will dismiss with prejudice First Judicial District Court of Nevada Case Nos. 97-00742A, 99-00470A, 99-00754A, and 00-00416A, and release, without limitation, any and all rights, claims, -1- demands, and causes of action set forth in said actions or which could have been litigated in such proceedings. 2. Nevada Power will release any and all claims for any and all remaining deferred energy balances of whatsoever kind or nature claimed in Docket Nos. 97-00742A, 99-00470A, 99-0754A, and 00-00416A. 3. Nevada Power will remit, release, and waive whatever rights and claims it may have to collect the shortfall set forth and described at NRS (S) 704.9826. BTER Adjustment 4. On August 1, 2000, Nevada Power will adjust its Base Tariff Energy Rates ("BTER") to produce the revenues as allocated in Exhibit 1, attached hereto, which exhibit is fully incorporated herein by reference and made a part hereof as though fully set forth in this paragraph. DEAA Adjustment 5. Nevada Power's current deferred energy accounting adjustment ("DEAA") rates, effective May 1, 2000, will terminate effective August 1, 2000. In consideration of such termination and the covenants and conditions contained in this Stipulation, Nevada Power shall recover out of the first-available after-tax proceeds from the sale of Nevada Power generation assets above book value and costs of sale, the sum of $15,000,000. Until such recovery is completed Nevada Power may accrue carrying charges at an annual rate of 9.5% on the unrecovered balance. Fuel and Purchase Power Rider 6. Nevada Power will implement a monthly Fuel and Purchase Power ("F&PP") rider. Nevada Power's first F&PP rider filing will be made no later -2- than August 1, 2000, with rate schedules effective September 1, 2000. Thereafter, Nevada Power will make monthly filings to adjust the F&PP rider with rate schedules to be effective forty-five (45) days after the date of each filing. 6.1 The monthly change in the F&PP rider for each rate class will be determined as the difference between the Nevada jurisdictional total fuel and purchased power costs for the twelve month period beginning fourteen months prior to the adjustment month divided by the Nevada jurisdictional kWh sales for the same period, and the total Nevada jurisdictional fuel and purchased power costs for the twelve month period beginning fifteen months prior to the adjustment month divided by the Nevada jurisdictional kWh sales for the same period. The methodology for calculating the F&PP rider is attached as Exhibit 2. 6.2 Monthly adjustments to the F&PP rider will not result in changes upward or downward that exceed those in the following schedule: (a) 0.95 mils per kWh for each of the first six monthly filings. (b) 1.15 mils per kWh for each of the second six monthly filings. (c) 1.35 mils per kWh for each of the next six monthly filings. (d) 1.55 mils per kWh for each of the next six monthly filings. (e) 1.75 mils per kWh on a monthly basis for filings through December 15, 2002 for rates effective February 1, 2003 to February 28, 2003. 6.3 These adjustments are calculated exclusive of any Purchased Power Agreement Adjustment Mechanism ("PPAAM") incorporated into this F&PP rider. It is also recognized that with the implementation of any PPAAM that the F&PP rider calculation will be adjusted to recognize the impact of the PPAAM. -3- 6.4 No later than October 1, 2002, Nevada Power will make a filing in the form of a general rate case to reset all components of rates such rates to be effective March 1, 2003. 7. The Parties to this Stipulation are of the opinion that such monthly F&PP filings to be made by Nevada Power are lawful under NRS Chapter 704, and that such filing should be accepted by the Public Utilities Commission of Nevada ("Commission") for review, and warrant that they will not oppose such filing for review nor challenge the legality of such filing in any administrative or court proceeding. The Parties, other than the Commission, will not seek to suspend the schedules implementing the rate changes set forth in the monthly F&PP filings, and will support Nevada Power's request not to suspend such schedules. The Parties agree to support expedited treatment of such filings. 8. Nevada Power will include with each F&PP monthly filing a statement of its separate fixed charge coverage ratio calculations for the 12- month period covered by the F&PP rider filing. If the acquisition of Portland General Electric is consummated, any goodwill amortization expense associated with the transaction shall not be included in the calculation of the fixed charge coverage ratio. The form of the calculation is attached hereto as Exhibit 3. Such fixed charge covenants shall be calculated before giving effect to extraordinary gains or losses. Nevada Power will not implement an increase in the F&PP rider when its respective fixed charge ratio is at or exceeds 2.5 times. Nothing in this paragraph 8 will be deemed to permit adjustments to the F&PP rider that would exceed the limitations to the F&PP rider outlined in Paragraph 6.2 above. -4- 9. Within sixty (60) days after the effective date of this Stipulation, an independent audit of Nevada Power's financial condition will be conducted to verify the need for the BTER adjustment referenced in Paragraph 4 of this Stipulation. Such audit shall also include an investigation of Nevada Power's fuel and purchased power costs for the 12-month period ending on July 31, 2000. If that audit fails to satisfy and demonstrate that the F&PP costs during the period were prudently incurred, then any interested party may petition for hearing before the Commission. If, after hearing, the Commission finds that Nevada Power's prudently incurred annual F&PP costs for the twelve month period ended July 31, 2000 were less than the revenue requirement set forth in Exhibit 1, the BTER and F&PP rates shall be readjusted to reflect the proper amount. Any amounts overcollected pursuant to such rates, or collected in excess of the maximum rate increase that would have been allowed pursuant to any subsequent F&PP adjustment had the proper amount been originally implemented, shall be refunded in accordance with a refund plan specified by the Commission in its order. 10. Six months following the implementation of the F&PP rider mechanism, and every six months thereafter (unless changed by the Commission) Nevada Power will file with the Commission an independent audit of fuel and purchased power purchasing practices. Any findings of imprudence by the Commission will be reflected in future F&PP adjustment filings, and all parties retain any and all rights with respect to said F&PP filings except those specifically involved herein. The Company will not object to such audit results being made available by the Commission to any party to this Stipulation or as required under any applicable law. -5- 11. Nevada Power's obligations to make monthly F&PP filings, all limitations on F&PP adjustments, and the requirement to perform and to file independent audits of the F&PP shall cease December 15, 2002, with an audit covering purchases up to October 31, 2002. Notwithstanding the provisions of Paragraph 6, if Nevada Power's obligation to provide provider of last resort ("PLR") service ends prior to March 1, 2003, the F&PP adjustment mechanism will terminate at that time and Nevada Power will file a final audit covering the period ending on the date of termination. Disposition of amounts identified by the final audit will be determined by the Commission. If Nevada Power remains obligated to provide PLR service through an affiliate, such affiliate will also be permitted the use of the F&PP rider pursuant to the terms of this Stipulation. 12. Exhibits 1 and 2 reflect and account for the Hoover B benefit prescribed in Nevada Power's contract with the Colorado River Commission as set forth in a stipulation entered into in Commission Docket No. 99-7035 and previously approved by the Commission. Other Provisions 13. General rates (non-fuel and non-purchased power) for Nevada Power will remain capped until March 1, 2003 as required by NRS (S) 704.982 and NRS (S)704.9823. 14. The provisions of this Stipulation are not severable and, in the event this Stipulation is not approved by the Commission in an open meeting and not approved by the Court in its entirety as set forth herein, it shall be deemed withdrawn without prejudice to any claims or contentions which may have been made in this -6- proceeding by any party, and it shall not be admissible as evidence, or described or discussed in any future proceeding. 15. This Stipulation is subject to the Commission's approval and is made upon the express understanding that it constitutes a negotiated settlement of all issues set forth herein, and is contingent upon Commission approval of the stipulations concurrently submitted in Commission Docket Nos. 00-5003, 00- 5005, 99-4001, 99-4002, 99-4005, 99-4006, Case No. CV-99-01743 in the Second Judicial District in the State of Nevada in and for Washoe County, and Case No. CV-N-157DWH VPC filed in the United States District Court for the District of Nevada.. 16. Except for those rights, claims and/or defenses as are expressly waived herein, all Parties reserve any and all rights, claims and defenses of whatsoever kind or nature with respect to any proceeding contemplated herein. The Parties agree to take all possible action to support this Stipulation, and to take no action, direct or indirect, in opposition to the request for approval of this Stipulation. PUBLIC UTILITIES COMMISSION BUREAU OF CONSUMER OF NEVADA PROTECTION By________________________________ By_______________________________ Jeff Parker, General Counsel Timothy Hay, Consumer Advocate MIRAGE RESORTS, PARK PLACE NEVADA POWER COMPANY ENTERTAINMENT, INC., MANDALAY RESORTS By________________________________ By___________________________ Martha Ashcraft William E. Peterson -7- EX-27 4 0004.txt FINANCIAL DATA SCHEDULE
UT The schedule contains summary financial information extracted from the SPR's financial records and is qualified in its entirety by reference to such financial statements. SIERRA PACIFIC RESOURCES 0000741508 9-MOS DEC-31-2000 SEP-30-2000 PER-BOOK 3,923,934 132,838 572,430 748,061 260,384 5,637,647 78,451 1,294,412 25,119 1,397,982 0 50,000 2,072,147 205,175 0 0 452,716 0 78,347 3,270 1,378,010 5,637,647 1,736,035 (17,310) 1,659,265 1,641,955 94,080 6,064 100,144 111,176 (11,032) 2,624 (21,561) 59,000 89,337 34,343 (0.27) (0.27)
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