10-Q 1 b44528spe10vq.txt SIERRA PACIFIC POWER COMPANY ================================================================================ 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, 2002 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 6, 2002 Common Stock, $1.00 par value 102,138,325 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, $3.75 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, 2002 CONTENTS PART I - FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS (Unaudited) SIERRA PACIFIC RESOURCES - Condensed Consolidated Balance Sheets - September 30, 2002 and December 31, 2001.......... 3 Condensed Consolidated Statements of Operations - Three Months and Nine Months Ended September 30, 2002 and 2001................................................... 4 Condensed Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2002 and 2001................................................... 5 NEVADA POWER COMPANY - Condensed Balance Sheets - September 30, 2002 and December 31, 2001....................... 6 Condensed Statements of Operations - Three Months and Nine Months Ended September 30, 2002 and 2001................................................... 7 Condensed Statements of Cash Flows - Nine Months Ended September 30, 2002 and 2001........ 8 SIERRA PACIFIC POWER COMPANY - Condensed Consolidated Balance Sheets - September 30, 2002 and December 31, 2001.......... 9 Condensed Consolidated Statements of Operations - Three Months and Nine Months Ended September 30, 2002 and 2001................................................... 10 Condensed Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2002 and 2001................................................... 11 NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS.............................................. 12 ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations..... 36 Sierra Pacific Resources Results of Operations...................................... 41 Nevada Power Company Results of Operations.......................................... 46 Sierra Pacific Power Company Results of Operations.................................. 53 ITEM 3. Quantitative and Qualitative Disclosures about Market Risk................................ 65 ITEM 4. Controls and Procedures................................................................... 65 PART II - OTHER INFORMATION ITEM 1. Legal Proceedings......................................................................... 66 ITEM 4. Submission of Matters to a Vote of Security Holders....................................... 66 ITEM 5. Other Information......................................................................... 66 ITEM 6. Exhibits and Reports on Form 8-K.......................................................... 66 Signature Page and Certifications ....................................................................... 68
2 SIERRA PACIFIC RESOURCES CONDENSED CONSOLIDATED BALANCE SHEETS (DOLLARS IN THOUSANDS) (UNAUDITED)
SEPTEMBER 30, DECEMBER 31, 2002 2001 ------------- ------------- ASSETS Utility Plant at Original Cost: Plant in service $ 5,845,229 $ 5,683,296 Less: accumulated provision for depreciation 1,902,630 1,777,517 ----------- ----------- 3,942,599 3,905,779 Construction work-in-progress 261,691 203,456 ----------- ----------- 4,204,290 4,109,235 ----------- ----------- Investments in subsidiaries and other property, net 182,486 128,892 ----------- ----------- Current Assets: Cash and cash equivalents 360,345 99,109 Restricted cash (Note 1) 22,750 - Accounts receivable less provision for uncollectible accounts: 2002-$42,001 ; 2001-$39,335 467,881 394,489 Deferred energy costs - electric 254,226 333,062 Deferred energy costs - gas 18,957 19,805 Income tax receivable - 59,630 Materials, supplies and fuel, at average cost 96,053 94,167 Risk management assets (Note 10) 66,494 286,509 Other 24,040 14,071 ----------- ----------- 1,310,746 1,300,842 ----------- ----------- Deferred Charges and Other Assets: Goodwill (Note 12) 310,441 312,145 Deferred energy costs - electric 767,238 854,778 Deferred energy costs - gas 11,737 23,248 Income tax receivable 266,665 314,619 Regulatory tax asset 168,276 169,738 Other regulatory assets 139,914 102,959 Risk management assets (Note 10) 7,813 61,058 Risk management regulatory assets - net (Note 10) 78,441 664,383 Other 120,557 139,417 ----------- ----------- 1,871,082 2,642,345 ----------- ----------- $ 7,568,604 $ 8,181,314 =========== =========== CAPITALIZATION AND LIABILITIES Capitalization: Common shareholders' equity $ 1,413,738 $ 1,702,322 Accumulated other comprehensive loss (Note 10) (4,260) (6,986) Preferred stock 50,000 50,000 NPC obligated mandatorily redeemable preferred trust securities 188,872 188,872 Long-term debt 2,986,517 3,376,105 ----------- ----------- 4,634,867 5,310,313 ----------- ----------- Current Liabilities: Short-term borrowings 350,000 177,000 Current maturities of long-term debt 431,327 122,010 Accounts payable 390,660 265,250 Accrued interest 74,294 37,565 Dividends declared 1,045 1,045 Accrued salaries and benefits 16,763 30,145 Deferred taxes on deferred energy costs 94,823 123,503 Risk management liabilities (Note 10) 132,121 855,301 Other current liabilities 28,966 15,678 ----------- ----------- 1,519,999 1,627,497 ----------- ----------- Commitments & Contingencies (Note 11) Deferred Credits and Other Liabilities: Deferred federal income taxes 404,666 412,658 Deferred investment tax credit 49,355 51,947 Deferred taxes on deferred energy costs 273,432 307,309 Regulatory tax liability 45,708 46,702 Customer advances for construction 114,447 108,179 Accrued retirement benefits 95,351 82,624 Risk management liabilities (Note 10) 20,454 163,636 Contract termination reserves (Note 11) 315,780 - Other 94,545 70,449 ----------- ----------- 1,413,738 1,243,504 ----------- ----------- $ 7,568,604 $ 8,181,314 =========== ===========
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS. 3 SIERRA PACIFIC RESOURCES CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) (UNAUDITED)
THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, --------------------------------- ------------------------------- 2002 2001 2002 2001 ------------- ------------- ------------- ------------ OPERATING REVENUES: Electric $ 997,559 $ 1,977,453 $ 2,251,813 $ 3,738,177 Gas 18,473 18,831 99,139 104,725 Other 3,987 5,650 8,328 13,350 ------------- ------------- ------------- ------------ 1,020,019 2,001,934 2,359,280 3,856,252 ------------- ------------- ------------- ------------ OPERATING EXPENSES: Operation: Purchased power 604,683 2,195,051 1,546,394 3,636,006 Fuel for power generation 120,668 220,002 356,084 586,136 Gas purchased for resale 9,884 9,294 61,585 105,008 Deferred energy costs disallowed - - 487,224 - Deferral of energy costs - electric - net (41,425) (737,634) (309,203) (1,080,846) Deferral of energy costs - gas - net 4,281 3,453 14,649 (23,354) Other 70,566 81,924 206,004 248,428 Maintenance 12,904 15,475 46,826 53,933 Depreciation and amortization 43,847 40,958 129,606 120,552 Taxes: Income taxes 41,002 40,087 (145,949) 8,033 Other than income 10,282 11,134 33,585 32,358 ------------- ------------- ------------- ------------ 876,692 1,879,744 2,426,805 3,686,254 ------------- ------------- ------------- ------------ OPERATING INCOME (LOSS) 143,327 122,190 (67,525) 169,998 ------------- ------------- ------------- ------------ OTHER INCOME (EXPENSE): Allowance for other funds used during construction (272) (106) 382 (793) Other income - net 8,016 16,007 6,472 22,319 ------------- ------------- ------------- ------------ 7,744 15,901 6,854 21,526 ------------- ------------- ------------- ------------ Total Income (Loss) Before Interest Charges 151,071 138,091 (60,671) 191,524 ------------- ------------- ------------- ------------ INTEREST CHARGES: Long-term debt 56,734 47,623 170,973 131,155 Other 11,097 5,474 23,993 20,767 Allowance for borrowed funds used during construction and capitalized interest (902) (1,225) (3,483) (1,514) ------------- ------------- ------------- ------------ 66,929 51,872 191,483 150,408 ------------- ------------- ------------- ------------ INCOME (LOSS) BEFORE NPC OBLIGATED MANDATORILY REDEEMABLE PREFERRED TRUST SECURITIES 84,142 86,219 (252,154) 41,116 Preferred dividend requirements of NPC obligated mandatorily redeemable preferred trust securities 3,793 4,835 11,379 14,293 ------------- ------------- ------------- ------------ INCOME (LOSS) BEFORE PREFERRED STOCK DIVIDENDS 80,349 81,384 (263,533) 26,823 Preferred stock dividend requirements of subsidiary 975 975 2,925 2,725 ------------- ------------- ------------- ------------ INCOME (LOSS) FROM CONTINUING OPERATIONS 79,374 80,409 (266,458) 24,098 ------------- ------------- ------------- ------------ DISCONTINUED OPERATIONS: Income from operations of water business disposed of (net of income taxes of $0 and $888 in 2001, respectively) - - - 1,022 Gain on disposal of water business (net of income taxes of $18,237) - - - 25,845 CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE, NET OF TAX (Note 12) - - (1,566) - ------------- ------------- ------------- ------------ NET INCOME (LOSS) $ 79,374 $ 80,409 $ (268,024) $ 50,965 ============= ============= ============= ============ Amounts per share - Basic and Diluted Income (loss) from continuing operations $ 0.78 $ 0.89 $ (2.61) $ 0.29 Income from discontinued operations - 0.01 Gain on disposal of water business - 0.32 Cumulative effect of change in accounting principle (net of tax) - (0.01) - ------------- ------------- ------------- ------------ Net income (loss) $ 0.78 $ 0.89 $ (2.62) $ 0.62 ============= ============= ============= ============ Weighted Average Shares of Common Stock Outstanding 102,132,465 90,302,825 102,117,926 82,423,032 ============= ============= ============= ============ Dividends Paid Per Share of Common Stock $ - $ 0.20 $ 0.20 $ 0.45 ============= ============= ============= ============
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS. 4 SIERRA PACIFIC RESOURCES CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (DOLLARS IN THOUSANDS) (UNAUDITED)
NINE MONTHS ENDED SEPTEMBER 30, ------------------------------- 2002 2001 ------------ ----------- CASH FLOWS FROM OPERATING ACTIVITIES: Income (Loss) from continuing operations before preferred dividends $ (263,533) $ 26,823 Income from discontinued operations before preferred dividends - 1,222 Gain on disposal of water business - 25,845 Non-cash items included in income: Depreciation and amortization 130,097 124,011 Deferred taxes and deferred investment tax credit 79,410 107,795 AFUDC and capitalized interest (3,865) (730) Amortization of deferred energy costs - electric 130,667 - Amortization of deferred energy costs - gas 8,950 - Deferred energy costs disallowed (net of taxes) 317,977 - Early retirement and severance amortization 2,082 3,121 Gain on disposal of water business - (44,081) Other non-cash (12,099) 3,676 Changes in certain assets and liabilities: Accounts receivable (115,247) (498,883) Deferral of energy costs - electric (123,308) (1,105,698) Deferral of energy costs - gas 3,408 (25,938) Materials, supplies and fuel (1,886) (19,849) Other current assets (32,658) (4,093) Accounts payable 166,144 543,413 Income tax receivable 108,992 - Other current liabilities 35,293 18,061 Other - net 32,396 16,827 ------------ ----------- Net Cash from Operating Activities 462,820 (828,478) ------------ ----------- CASH FLOWS FROM INVESTING ACTIVITIES: Additions to utility plant (259,831) (251,458) AFUDC and other charges to utility plant 3,865 730 Customer advances (refunds) for construction 6,268 (3,219) Contributions in aid of construction 32,381 24,259 ------------ ----------- Net cash used for utility plant (217,317) (229,688) Proceeds from sale of assets of water business - 318,882 Investments in subsidiaries and other property (53,672) (3,961) ------------ ----------- Net Cash from Investing Activities (270,989) 85,233 ------------ ----------- CASH FLOWS FROM FINANCING ACTIVITIES: Increase in short-term borrowings 173,000 56,487 Proceeds from issuance of long-term debt - 900,000 Retirement of long-term debt (80,272) (536,103) Sale of common stock 187 340,764 Dividends paid (23,510) (43,366) ------------ ----------- Net Cash from Financing Activities 69,405 717,782 ------------ ----------- NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 261,236 (25,463) Beginning Balance in Cash and Cash Equivalents 99,109 51,503 ------------ ----------- Ending Balance in Cash and Cash Equivalents $ 360,345 $ 26,040 ============ =========== SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION: Cash paid (received) during period for: Interest $ 154,754 $ 112,982 Income taxes $ (185,011) $ 28,424
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS 5 NEVADA POWER COMPANY CONDENSED BALANCE SHEETS (DOLLARS IN THOUSANDS) (UNAUDITED)
SEPTEMBER 30, DECEMBER 31, 2002 2001 ------------ ------------ ASSETS Utility Plant at Original Cost: Plant in service $ 3,500,244 $ 3,356,584 Less: accumulated provision for depreciation 999,584 928,939 ------------ ------------ 2,500,660 2,427,645 Construction work-in-progress 153,529 134,706 ------------ ------------ 2,654,189 2,562,351 ------------ ------------ Investment in Sierra Pacific Resources (Note 2) 236,821 309,259 Investments in subsidiaries and other property, net 20,168 12,721 ------------ ------------ 256,989 321,980 ------------ ------------ Current Assets: Cash and cash equivalents 207,746 8,505 Restricted cash (Note 1) 10,872 - Accounts receivable less provision for uncollectible accounts: 2002-$34,269; 2001-$30,861 306,868 210,333 Deferred energy costs - electric 197,542 281,555 Income tax receivable - 18,590 Materials, supplies and fuel, at average cost 45,434 48,511 Risk management assets (Note 10) 49,142 200,829 Other 10,732 6,698 ------------ ------------ 828,336 775,021 ------------ ------------ Deferred Charges and Other Assets: Deferred energy costs - electric 591,871 698,510 Income tax receivable 245,009 295,818 Regulatory tax asset 108,912 109,859 Other regulatory assets 53,904 31,588 Risk management assets (Note 10) 7,813 49,493 Risk management regulatory assets - net (Note 10) 7,198 351,264 Other 24,948 29,485 ------------ ------------ 1,039,655 1,566,017 ------------ ------------ $ 4,779,169 $ 5,225,369 ============ ============ CAPITALIZATION AND LIABILITIES Capitalization: Common shareholder's equity including $236,821 and $309,259 of equity in Sierra Pacific Resources in 2002 and 2001 (Note 2) $ 1,413,738 $ 1,702,322 Accumulated other comprehensive income 117 520 NPC obligated mandatorily redeemable preferred trust securities 188,872 188,872 Long-term debt 1,393,034 1,607,967 ------------ ------------ 2,995,761 3,499,681 ------------ ------------ Current Liabilities: Short-term borrowings 200,000 130,500 Current maturities of long-term debt 228,927 19,380 Accounts payable 332,333 202,555 Accrued interest 35,542 19,310 Dividends declared 78 71 Accrued salaries and benefits 5,520 12,450 Deferred taxes on deferred energy costs 68,349 98,544 Risk management liabilities (Note 10) 58,218 522,508 Other current liabilities 20,370 17,710 ------------ ------------ 949,337 1,023,028 ------------ ------------ Commitments & Contingencies (Note 11) Deferred Credits and Other Liabilities: Deferred federal income taxes 210,773 223,641 Deferred investment tax credit 22,310 23,533 Deferred taxes on deferred energy costs 207,945 244,479 Regulatory tax liability 18,280 18,604 Customer advances for construction 64,525 61,454 Accrued retirement benefits 36,089 28,104 Risk management liabilities (Note 10) 5,818 78,558 Contract termination reserves (Note 11) 229,002 - Other 39,329 24,287 ------------ ------------ 834,071 702,660 ------------ ------------ $ 4,779,169 $ 5,225,369 ============ ============
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS. 6 NEVADA POWER COMPANY CONDENSED STATEMENTS OF OPERATIONS (DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) (UNAUDITED)
THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, ------------------------------ -------------------------------- 2002 2001 2002 2001 ------------- ------------- -------------- -------------- OPERATING REVENUES: Electric $ 712,536 $ 1,395,496 $ 1,545,867 $ 2,562,949 OPERATING EXPENSES: Operation: Purchased power 440,559 1,686,816 1,102,551 2,728,176 Fuel for power generation 87,864 131,023 245,060 348,633 Deferred energy costs disallowed - - 434,123 - Deferral of energy costs-net (43,224) (638,571) (238,059) (908,408) Other 39,250 45,670 116,520 130,192 Maintenance 8,050 10,331 31,576 36,789 Depreciation and amortization 24,975 23,042 72,924 67,345 Taxes: Income taxes 39,944 36,197 (116,536) 21,979 Other than income 5,935 6,221 19,122 18,118 ------------- ------------- -------------- -------------- 603,353 1,300,729 1,667,281 2,442,824 ------------- ------------- -------------- -------------- OPERATING INCOME (LOSS) 109,183 94,767 (121,414) 120,125 ------------- ------------- -------------- -------------- OTHER INCOME (EXPENSE): Equity in earnings (losses) of Sierra Pacific Resources (Note 2) 70 1,658 (51,999) (5,494) Allowance for other funds used during construction (262) (87) 239 (560) Other income (expense) - net 4,933 11,021 (839) 14,189 ------------- ------------- -------------- -------------- 4,741 12,592 (52,599) 8,135 ------------- ------------- -------------- -------------- Total Income (Loss) Before Interest Charges 113,924 107,359 (174,013) 128,260 ------------- ------------- -------------- -------------- INTEREST CHARGES: Long-term debt 23,714 20,545 70,668 55,504 Other 7,251 3,269 14,133 10,982 Allowance for borrowed funds used during construction and capitalized interest (208) (657) (2,169) (570) ------------- ------------- -------------- -------------- 30,757 23,157 82,632 65,916 ------------- ------------- -------------- -------------- INCOME (LOSS) BEFORE NPC OBLIGATED MANDATORILY REDEEMABLE PREFERRED TRUST SECURITIES 83,167 84,202 (256,645) 62,344 Preferred dividend requirements of NPC obligated mandatorily redeemable preferred trust securities 3,793 3,793 11,379 11,379 ------------- ------------- -------------- -------------- NET INCOME (LOSS) $ 79,374 $ 80,409 $ (268,024) $ 50,965 ============= ============= ============== ============== Net Income (Loss) Per Share - Basic (Note 2) $ 0.78 $ 0.89 $ (2.62) $ 0.62 ============= ============= ============== ============== - Diluted (Note 2) $ 0.78 $ 0.89 $ (2.62) $ 0.62 ============= ============= ============== ============== Weighted Average Shares of Common Stock Outstanding (Note 2) 102,132,465 90,302,825 102,117,926 82,423,032 ============= ============= ============== ============== Dividends Paid Per Share of Common Stock (Note 2) $ - $ 0.20 $ 0.20 $ 0.45 ============= ============= ============== ==============
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS. 7 NEVADA POWER COMPANY CONDENSED STATEMENTS OF CASH FLOWS (DOLLARS IN THOUSANDS) (UNAUDITED)
NINE MONTHS ENDED SEPTEMBER 30, ------------------------------ 2002 2001 ------------ ------------ CASH FLOWS FROM OPERATING ACTIVITIES: Net income (loss) $ (268,024) $ 50,965 Non-cash items included in income: Depreciation and amortization 72,924 67,345 Deferred taxes and deferred investment tax credit 68,430 51,944 AFUDC and capitalized interest (2,408) (10) Amortization of deferred energy costs 112,959 - Deferred energy costs disallowed (net of taxes) 282,181 - Other non-cash (14,184) 2,367 Equity in losses of SPR (Note 2) 51,999 5,494 Changes in certain assets and liabilities: Accounts receivable (95,791) (411,765) Deferral of energy costs (127,429) (928,987) Materials, supplies and fuel 3,077 (5,809) Other current assets (14,843) (725) Accounts payable 129,728 523,642 Income tax receivable 70,807 - Other current liabilities 11,961 12,632 Other - net 18,832 8,780 ------------ ------------ Net Cash from Operating Activities 300,219 (624,127) ------------ ------------ CASH FLOWS FROM INVESTING ACTIVITIES: Additions to utility plant (196,006) (141,414) AFUDC and other charges to utility plant 2,408 10 Customer advances (refunds) for construction 3,072 (4,054) Contributions in aid of construction 27,635 5,630 ------------ ------------ Net cash used for utility plant (162,891) (139,828) Investments in subsidiaries and other property (2,200) - ------------ ------------ Net Cash from Investing Activities (165,091) (139,828) ------------ ------------ CASH FLOWS FROM FINANCING ACTIVITIES: Increase in short-term borrowings 69,500 130,561 Proceeds from issuance of long-term debt - 500,000 Retirement of long-term debt (5,387) (254,112) Investment by parent company 10,000 394,921 Dividends paid (10,000) (33,014) ------------ ------------ Net Cash from Financing Activities 64,113 738,356 ------------ ------------ NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 199,241 (25,599) Beginning Balance in Cash and Cash Equivalents 8,505 43,858 ------------ ------------ Ending Balance in Cash and Cash Equivalents $ 207,746 $ 18,259 ============ ============ SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION: Cash paid (received) during period for: Interest $ 66,400 $ 28,160 Income taxes $ (102,904) $ 47,501
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS. 8 SIERRA PACIFIC POWER COMPANY CONDENSED CONSOLIDATED BALANCE SHEETS (DOLLARS IN THOUSANDS) (UNAUDITED)
SEPTEMBER 30, DECEMBER 31, 2002 2001 ------------ ------------ ASSETS Utility Plant at Original Cost: Plant in service $ 2,344,985 $ 2,326,712 Less: accumulated provision for depreciation 903,046 848,578 ------------ ------------ 1,441,939 1,478,134 Construction work-in-progress 108,162 68,750 ------------ ------------ 1,550,101 1,546,884 ------------ ------------ Investments in subsidiaries and other property, net 54,775 57,185 ------------ ------------ Current Assets: Cash and cash equivalents 143,868 11,772 Restricted cash (Note 1) 9,273 - Accounts receivable less provision for uncollectible accounts: 2002 - $7,732; 2001 - $8,474 249,692 194,698 Deferred energy costs - electric 56,684 51,507 Deferred energy costs - gas 18,957 19,805 Materials, supplies and fuel, at average cost 46,795 42,290 Income tax receivable - 41,040 Risk management assets (Note 10) 17,352 85,680 Other 10,827 5,935 ------------ ------------ 553,448 452,727 ------------ ------------ Deferred Charges and Other Assets: Deferred energy costs - electric 175,367 156,268 Deferred energy costs - gas 11,737 23,248 Regulatory tax asset 59,364 59,879 Other regulatory assets 66,107 51,146 Risk management assets (Note 10) - 11,565 Risk management regulatory assets - net (Note 10) 71,243 313,119 Other 12,332 13,886 ------------ ------------ 396,150 629,111 ------------ ------------ $ 2,554,474 $ 2,685,907 ============ ============ CAPITALIZATION AND LIABILITIES Capitalization: Common shareholder's equity $ 670,365 $ 692,654 Accumulated other comprehensive income 56 247 Preferred stock 50,000 50,000 Long-term debt 917,100 923,070 ------------ ------------ 1,637,521 1,665,971 ------------ ------------ Current Liabilities: Short-term borrowings 150,000 46,500 Current maturities of long-term debt 2,400 2,630 Accounts payable 82,270 95,555 Accrued interest 24,489 8,408 Dividends declared 967 974 Accrued salaries and benefits 8,923 15,466 Deferred taxes on deferred energy costs 26,474 24,959 Risk management liabilities (Note 10) 73,903 332,793 Other current liabilities 7,586 3,387 ------------ ------------ 377,012 530,672 ------------ ------------ Commitments & Contingencies (Note 11) Deferred Credits and Other Liabilities: Deferred federal income taxes 186,864 178,533 Deferred investment tax credit 27,045 28,414 Deferred taxes on deferred energy costs 65,487 62,831 Income tax payable 2,345 - Regulatory tax liability 27,428 28,098 Customer advances for construction 49,922 46,725 Accrued retirement benefits 49,455 43,028 Risk management liabilities (Note 10) 14,636 77,324 Contract termination reserves (Note 11) 86,778 - Other 29,981 24,311 ------------ ------------ 539,941 489,264 ------------ ------------ $ 2,554,474 $ 2,685,907 ============ ============
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS. 9 SIERRA PACIFIC POWER COMPANY CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (DOLLARS IN THOUSANDS) (UNAUDITED)
THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, ------------------------ ---------------------------- 2002 2001 2002 2001 ---------- ----------- ----------- ------------- OPERATING REVENUES: Electric $ 285,023 $ 581,957 $ 705,946 $ 1,175,228 Gas 18,473 18,831 99,139 104,725 ---------- ----------- ----------- ------------- 303,496 600,788 805,085 1,279,953 ---------- ----------- ----------- ------------- OPERATING EXPENSES: Operation: Purchased power 164,124 508,235 443,843 907,830 Fuel for power generation 32,804 88,980 111,024 237,504 Gas purchased for resale 9,884 9,294 61,585 105,008 Deferred energy costs disallowed - - 53,101 - Deferral of energy costs - electric - net 1,799 (98,702) (71,144) (172,437) Deferral of energy costs - gas - net 4,281 3,093 14,649 (23,354) Other 25,064 28,222 75,687 79,090 Maintenance 4,854 5,143 15,250 17,143 Depreciation and amortization 18,592 17,620 55,861 52,328 Taxes: Income taxes 7,601 8,630 (9,037) 7,974 Other than income 4,472 4,671 14,129 13,639 ---------- ----------- ----------- ------------- 273,475 575,186 764,948 1,224,725 ---------- ----------- ----------- ------------- OPERATING INCOME 30,021 25,602 40,137 55,228 ---------- ----------- ----------- ------------- OTHER INCOME (EXPENSE): Allowance for other funds used during construction (10) (19) 143 (233) Other income - net 1,954 4,309 4,631 5,322 ---------- ----------- ----------- ------------- 1,944 4,290 4,774 5,089 ---------- ----------- ----------- ------------- Total Income Before Interest Charges 31,965 29,892 44,911 60,317 ---------- ----------- ----------- ------------- INTEREST CHARGES: Long-term debt 16,173 15,380 48,638 38,479 Other 2,943 1,455 7,051 7,437 Allowance for borrowed funds used during construction and capitalized interest (694) (566) (1,314) (943) ---------- ----------- ----------- ------------- 18,422 16,269 54,375 44,973 ---------- ----------- ----------- ------------- INCOME (LOSS) BEFORE SPPC OBLIGATED MANDATORILY REDEEMABLE PREFERRED TRUST SECURITIES 13,543 13,623 (9,464) 15,344 Preferred dividend requirements of SPPC obligated mandatorily redeemable preferred trust securities - 1,042 - 2,914 ---------- ----------- ----------- ------------- INCOME (LOSS) BEFORE PREFERRED DIVIDENDS 13,543 12,581 (9,464) 12,430 Preferred dividend requirements 975 975 2,925 2,725 ---------- ----------- ----------- ------------- INCOME (LOSS) FROM CONTINUING OPERATIONS 12,568 11,606 (12,389) 9,705 ---------- ----------- ----------- ------------- DISCONTINUED OPERATIONS: Income from operations of water business disposed of (net of income taxes of $0 and $888 in 2001, respectively) - - - 1,022 Gain on disposal of water business (net of income taxes of $18,237) - - - 25,845 ---------- ----------- ----------- ------------- NET INCOME (LOSS) $ 12,568 $ 11,606 $ (12,389) $ 36,572 ========== =========== =========== =============
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS. 10 SIERRA PACIFIC POWER COMPANY CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (DOLLARS IN THOUSANDS) (UNAUDITED)
NINE MONTHS ENDED SEPTEMBER 30, ------------------------------ 2002 2001 ----------- ------------- CASH FLOWS FROM OPERATING ACTIVITIES: Income (Loss) from continuing operations before preferred dividends $ (9,464) $ 12,430 Income from discontinued operations before preferred dividends - 1,222 Gain on disposal of water business - 25,845 Non-cash items included in income: Depreciation and amortization 55,861 55,788 Deferred taxes and investment tax credits 10,979 55,807 AFUDC and capitalized interest (1,457) (719) Amortization of deferred energy costs - electric 17,708 - Amortization of deferred energy costs - gas 8,950 - Deferred energy costs disallowed (net of taxes) 35,796 - Early retirement and severance amortization 2,082 3,121 Gain on disposal of water business - (44,081) Other non-cash (10,612) (3,580) Changes in certain assets and liabilities: Accounts receivable (54,994) (162,234) Deferral of energy costs - electric 4,121 (176,712) Deferral of energy costs - gas 3,408 (25,938) Materials, supplies and fuel (4,506) (11,601) Other current assets (14,165) (2,728) Accounts payable (13,285) 80,416 Income tax receivable 43,385 - Other current liabilities 13,738 13,742 Other-net 12,096 1,596 ----------- ------------ Net Cash from Operating Activities 99,641 (177,626) ----------- ------------ CASH FLOWS FROM INVESTING ACTIVITIES: Additions to utility plant (63,825) (110,043) AFUDC and other charges to utility plant 1,457 719 Customer advances for construction 3,196 835 Contributions in aid of construction 4,746 18,628 ----------- ------------ Net cash used for utility plant (54,426) (89,861) Proceeds from sale of assets of water business - 318,882 Disposal of subsidiaries and other property - net 2,411 2,102 ----------- ------------ Net Cash from Investing Activities (52,015) 231,123 ----------- ------------ CASH FLOWS FROM FINANCING ACTIVITIES: Increase (decrease) in short-term borrowings 103,500 (89,962) Proceeds from issuance of long-term debt - 400,000 Retirement of long-term debt (6,200) (281,980) Investment by parent company 10,000 4,948 Dividends paid (22,830) (88,932) ----------- ------------ Net Cash from Financing Activities 84,470 (55,926) ----------- ------------ NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 132,096 (2,429) Beginning Balance in Cash and Cash Equivalents 11,772 5,348 ----------- ------------ Ending Balance in Cash and Cash Equivalents $ 143,868 $ 2,919 =========== ============ SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION: Cash paid (received) during period for: Interest $ 38,294 $ 29,154 Income taxes (62,109) 22,227
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS. 11 NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS NOTE 1. MANAGEMENT'S STATEMENT (SPR, NPC, SPPC) In the opinion of the management of Sierra Pacific Resources (SPR), Nevada Power Company (NPC), 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, NPC's, and SPPC's Combined Annual Report on Form 10-K for the year ended December 31, 2001. The results of operations for the three- and nine-month periods ended September 30, 2002 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, (collectively, the "Utilities"), Tuscarora Gas Pipeline Company (TGPC), Sierra Gas Holding Company (SGHC), Sierra Energy Company dba e-three (e-three), Sierra Pacific Energy Company (SPE), Lands of Sierra (LOS), Sierra Pacific Communications (SPC), and Sierra Water Development Company (SWDC). All significant intercompany transactions and balances have been eliminated in consolidation. FINANCIAL CONDITION, LIQUIDITY AND CAPITAL RESOURCES The March 29, 2002 decision of the Public Utilities Commission of Nevada (PUCN) on NPC's deferred energy application to disallow $434 million of deferred purchased fuel and power costs accumulated between March 1, 2001 and September 30, 2001 had a significant negative impact on the results of operations of SPR and NPC for the nine months ended September 30, 2002. Several of the intervenors from NPC's deferred energy rate case filed petitions with the PUCN for reconsideration of its decision, seeking additional disallowances ranging from $12.8 million to $488 million. The petitions for reconsideration were granted in part and denied in part by the PUCN on May 24, 2002, but no additional disallowances to the deferred energy balance resulted from that decision. Although the PUCN's March 29, 2002 decision on NPC's deferred energy application is being challenged by NPC in a lawsuit filed in Nevada state court and by various intervenors, as discussed in Note 9, Regulatory Events, the decision caused the two major national rating agencies to issue an immediate downgrade of the credit ratings on SPR's, NPC's and SPPC's debt securities (followed by further downgrades late in April). Following those events, the market price of SPR's common stock fell substantially, NPC and SPPC were obliged within 5 business days of the downgrades to issue general and refunding mortgage bonds to secure their bank lines of credit, NPC was obliged to obtain a waiver and amendment from its credit facility banks before it was permitted to draw down on the facility, NPC and SPPC were no longer able to issue commercial paper, a number of NPC's power suppliers contacted NPC regarding its ability to pay the purchase price of outstanding contracts, and several power suppliers, including a subsidiary of Enron Corp., Morgan Stanley Capital Group Inc., Reliant Energy Services, Inc. and several smaller suppliers, terminated their power supply agreements with one or both of the Utilities. As discussed below, Duke Energy Trading and Marketing ("Duke") agreed to replace the amount of contracted power and natural gas that would have been supplied by the Utilities' terminating suppliers during the peak summer period. The separate decision of the PUCN on May 28, 2002 on SPPC's deferred energy application to disallow $53.1 million of deferred purchased fuel and power costs accumulated between March 1, 2001 and November 30, 2001 had a significant negative impact on the results of operations of SPR and SPPC for the nine months ended September 30, 2002. Several of the intervenors from SPPC's deferred energy rate case filed petitions with the PUCN for reconsideration of its decision, seeking an additional disallowance of $126 million. On July 18, 2002, the petitions for reconsideration were granted in part and denied in part by the PUCN, but no additional disallowances to the deferred energy balance resulted from that decision. The PUCN's May 28, 2002 decision on SPPC's deferred energy application is being challenged by SPPC in a lawsuit filed August 22, 2002 in Nevada state court, which is discussed in Note 9, Regulatory Events. NPC expects to file a deferred energy case on November 14, 2002, requesting recovery and/or an affirmation of prudency for fuel and purchased power costs incurred and recorded in its deferred energy account for the period October 1, 2001 through September 30, 2002. The case includes a reduction for annual fuel and purchased power revenues of $148 million and recovery of the deferred energy account balance in the amount of $65 million annually for a three-year period. The net change will result in an annual revenue decrease of $83 million representing a 5.6% rate decrease for residential customers and a 5.1% rate decrease for all other classes. The balance for the current deferral period is approximately $425 million, which includes a balance of $196 million which NPC is requesting recovery over a three-year period and costs of approximately $229 million accrued for claims made by terminated suppliers for which NPC is requesting an affirmation of prudency. (See Note 11, Commitment and Contingencies.) These amounts are subject to whatever adjustments may be ordered by the PERC in NPC's Section 206 complaints. (See Note 9, Regulatory Events.) 12 SPPC is required to file its next deferred energy case in approximately mid-January 2003 and will request recovery and/or an affirmation of prudency for all costs for fuel and purchased power recorded in its deferred energy account over the period December 1, 2001, through November 30, 2002. That amount is expected to approximate $100 million, which includes costs of approximately $82 million accrued for claims made by terminated suppliers. (See Note 11, Commitments and Contingencies.) These amounts are subject to whatever adjustments may be ordered by the FERC in SPPC's Section 206 complaints. (See Note 9, Regulatory Events.) A significant disallowance in future deferred energy rate cases filed by either Utility could further weaken the financial condition, liquidity, and capital resources of SPR, NPC, and SPPC. In particular, such a decision or decisions could cause further downgrades of debt securities by the rating agencies, could make it impracticable to access the capital markets, and could cause additional power suppliers to terminate purchased power contracts and seek liquidated damages. Under such circumstances, there can be no assurance that SPR, NPC, or SPPC would be able to remain solvent or continue operations. Under such circumstances, there also can be no assurance that SPR, NPC, or SPPC would not seek protection under the bankruptcy laws. In response to the decisions by the PUCN in NPC's rate cases, SPR implemented certain measures that management expects will positively impact cash flow by $125 million in 2002. Two major transmission construction projects, discussed in the Form 10-K for the year ended December 31, 2001, have been delayed for a total capital preservation impact of $80.8 million. The delay in NPC's Centennial Plan has an impact of $46.4 million and the delay of SPPC's Falcon to Gonder Project has an impact of $34.4 million. An additional $28.9 million was reduced from the Utilities' capital budgets by curtailing or delaying other projects. Management expects that the balance of the $125 million cash flow enhancement will be obtained from various land sales. Additional cost-cutting actions by SPR may be necessary. On March 29 and April 1, 2002, Standard & Poor's Rating Group, Inc. (S&P) and Moody's Investors Service, Inc. (Moody's) lowered the unsecured debt ratings of SPR, NPC and SPPC to below investment grade in response to the decision of the PUCN with respect to NPC's rate cases. On April 23 and 24, 2002, the unsecured debt ratings of SPR and the Utilities were further downgraded by both rating agencies, and the Utilities' secured debt ratings were downgraded to below investment grade. The downgrades have affected SPR's, NPC's and SPPC's liquidity primarily in two principal areas: (1) their respective financing arrangements and (2) NPC's and SPPC's contracts for fuel, for purchase and sale of electricity and for transportation of natural gas. SPR's ability to make capital contributions to NPC and SPPC also became severely limited. The PUCN's May 28, 2002 decision on SPPC's deferred energy application did not result in any further downgrades of the unsecured debt ratings of SPR, NPC or SPPC. As a result of the ratings downgrades, SPR's, NPC's, and SPPC's ability to access the capital markets to raise funds is severely limited. On April 3, 2002, SPR terminated its $75 million unsecured revolving credit facility as a condition to the banks agreeing to an amendment of NPC's recently terminated $200 million unsecured revolving credit facility that would permit NPC to draw down funds under that facility. In connection with the credit downgrades by S&P and Moody's, the Utilities lost their A2/P2 commercial paper ratings and can no longer issue commercial paper. At the time NPC and SPPC had commercial paper balances outstanding of $198.9 million and $47.7 million, respectively, with weighted average interest rates of 2.52% and 2.49%, respectively. Since the Utilities were no longer able to roll over their commercial paper, they paid off their maturing commercial paper with the proceeds of borrowings under their credit facilities and terminated their commercial paper programs on May 28, 2002. The Utilities do not expect to have direct access to the commercial paper market for the foreseeable future. With respect to NPC's and SPPC's contracts for purchased power, NPC and SPPC purchase and sell electricity with counterparties under the Western Systems Power Pool ("WSPP") agreement, which is an industry standard contract. The WSPP contract is posted on the WSPP website. These contracts provide that a material adverse change may give rise to a right to request collateral, which, if not provided within 3 business days, could cause a default. A default must be declared within 30 days of the event giving rise to the default becoming known. A default will result in a termination payment equal to the present value of the net gains and losses for the entire remaining term of all contracts between the parties aggregated to a single liquidated amount due within 3 business days following the date the notice of termination is received. The mark-to-market value, which is substantially based on quoted market prices, can be used to roughly approximate the termination payment at any point in time. The mark-to-market value as of November 1, 2002, for all suppliers continuing to provide power under a WSPP agreement was approximately $90.1 million and $59.9 million, respectively, for NPC and SPPC. Following the PUCN decisions, a number of power suppliers requested collateral from NPC and SPPC. On April 4, 2002, the Utilities sent a letter to their suppliers advising them that, assuming the Utilities could access the capital markets for secured debt and no other significant negative developments occurred, the Utilities expected to be able to honor their obligations under the power supply contracts. However, the Utilities noted that a simultaneous call for 100% mark-to-market 13 collateral in the short-term would likely not be met. On April 24, 2002, the Utilities met with representatives of various suppliers to discuss SPR's and the Utilities' financial situation and plans, and indicated that they intended to propose extended payment terms for the above-market portions of NPC's existing power contracts. Such extended payment terms were proposed to NPC's suppliers in a letter dated May 2, 2002, and proposed paying less than contract prices, but more than market prices plus interest, for the period May 1 to September 15, 2002, and NPC paying any balances remaining prior to December 2003. NPC also agreed to extend the suppliers' rights under the WSPP agreement. As of October 29, 2002, NPC paid all of the outstanding balances owed to its continuing suppliers. In early May, Enron Power Marketing Inc. ("Enron"), Morgan Stanley Capital Group Inc., Reliant Energy Services, Inc. and several smaller suppliers notified the Utilities that they would end power deliveries to the Utilities based on what they believed to be their contractual right to end deliveries because of the Utilities' alleged inability to provide adequate assurances of their ability to perform all of their outstanding material obligations under the WSPP agreement. Each of these terminating suppliers has asserted, or has indicated that it will assert, a claim for liquidated damages. As discussed in Note 11, Commitments and Contingencies, Enron filed suit in its bankruptcy case in the Bankruptcy Court for the Southern District of New York seeking approximately $216 million and $93 million from NPC and SPPC, respectively. Enron initially filed a motion for partial summary judgment to require the Utilities to make immediate payment of the full amount of Enron's claim, pending final resolution of the lawsuit. Enron subsequently filed another motion for summary judgment seeking final payment of its damages claim. In connection with this suit, the Utilities filed motions to dismiss and/or to stay all proceedings pending the final outcome of the Utilities' Section 206 complaints against Enron and others. (See Note 9, Regulatory Events.) Hearings were conducted in September, October, and early November 2002. In the event the Utilities' motions are denied, further hearings will be scheduled on Enron's motion for summary judgment. An adverse decision on Enron's motion for summary judgment or an adverse decision in the lawsuit itself would have a material adverse affect on the financial condition and liquidity of SPR and the Utilities and would render their ability to continue to operate outside of bankruptcy uncertain. At this time, SPR and the Utilities are not able to predict the outcome of a decision in this matter. On June 10, 2002, Duke Energy Trading and Marketing ("Duke") entered into an agreement with SPR and the Utilities to supply up to 1,000 megawatts of electricity per hour, as well as natural gas, to fulfill the Utilities' power requirements during the peak summer period. The effect of the Duke agreement was to replace the amount of contracted power and natural gas that would have been supplied by the various terminating suppliers, including Enron. Duke also agreed to accept deferred payment for a portion of the amount due under its existing power contracts with NPC for purchases made through September 15, 2002. Several other continuing suppliers also entered into formal agreements with NPC regarding deferred payments, and NPC deferred a portion of the payments to such suppliers, as well as those suppliers who continued to supply but did not sign agreements, beginning May 1, 2002 for charges incurred through September 15, 2002. As of October 29, 2002, NPC had paid in full all of the outstanding delayed payments, approximately $101 million, to all continuing suppliers, and, by the end of 2003, expects to make all payments determined to be due to terminating suppliers other than Enron. The approximately $101 million paid in October, and approximately $39 million accrued for amounts owed to terminating suppliers, are included in SPR's and NPC's Accounts Payable balance as of September 30, 2002. Following the PUCN decisions, SPR and the Utilities were also required to post cash collateral in connection with the surety bonds carried by their surety company and the disbursement facilities provided by their bank. These collateral amounts are classified as "Restricted cash" on the Balance Sheets of SPR and the Utilities. SPR has a qualified pension plan (the "Plan") that covers substantially all employees of SPR, NPC and SPPC. The annual net benefit cost for the Plan is expected to increase for 2003 by an amount between $12 million and $22 million over the 2002 cost of $18.4 million. Also, the Plan currently has assets with a fair value that is less than the present value of the accumulated benefit obligation under the Plan. While the amount of the deficiency has not yet been determined, SPR and the Utilities expect their combined minimum funding requirement for 2002 will be at least $24 million. However, SPR and the Utilities do not expect that their funding obligation for 2002 will have a material adverse effect on their liquidity. SPPC's Washoe County, Nevada, Water Facilities Refunding Revenue Bonds, Series 2001 in the aggregate principal amount of $80,000,000, will be subject to remarketing on May 1, 2003. In the event that these bonds cannot be successfully remarketed on that date, SPPC will be required to purchase the outstanding bonds at a price of 100% of the principal amount, plus accrued interest. SPR has a substantial amount of debt and other obligations including, but not limited to: $200 million of its unsecured Floating Rate Notes due April 20, 2003; $300 million of its unsecured 8 3/4% Senior Notes due 2005; and $345 million of its unsecured 7.93% Senior Notes due 2007. In connection with the effects of the disallowance of a significant portion of the Utilities' deferred purchased power costs by the PUCN as stated above, SPR's credit ratings, along with those of NPC and SPPC, were downgraded to below investment grade. As a result of the downgrades, SPR's ability to service its debt obligations and refinance its maturing debt as it becomes due has become uncertain. In the event that SPR's financial condition does not improve or becomes worse, it may have to consider other options including the possibility of seeking protection in a bankruptcy proceeding. SPR's future liquidity depends, in part, on SPPC's ability to continue to pay dividends to SPR, on a restoration of NPC to financial stability including a restoration of its ability to pay dividends to SPR, both as discussed in Note 5, Dividend Restrictions, and on SPR's ability to access the capital markets or otherwise refinance debt that matures in 2003 and thereafter. Further adverse developments at NPC or SPPC, including a material disallowance of deferred energy costs in future rate cases 14 or an adverse decision in the pending lawsuit by Enron to collect liquidated damages (including Enron's motion for partial summary judgment to require the Utilities to make immediate payment of the full amount of Enron's claim), could cause SPR to become insolvent and would render SPR's ability to continue to operate outside of bankruptcy uncertain. NPC's liquidity would also be significantly affected by an adverse decision in the pending lawsuit by Enron to collect liquidated damages (including Enron's motion for partial summary judgment to require the Utilities to make immediate payment of the full amount of Enron's claim), or by unfavorable rulings by the PUCN in future NPC or SPPC rate cases. Both S&P and Moody's have NPC's credit ratings on "watch negative" or "possible downgrade", and any further downgrades could further preclude NPC's access to the capital markets, and could adversely affect NPC's ability to continue to purchase power and fuel. Adverse developments with respect to any one or a combination of the foregoing could cause NPC to become insolvent and would render NPC's ability to continue to operate outside of bankruptcy uncertain. SPPC's future liquidity could be significantly affected by unfavorable rulings by the PUCN in future SPPC or NPC rate cases. Both S&P and Moody's have SPPC's credit ratings on "watch negative" or "possible downgrade", and any further downgrades could further preclude SPPC's access to the capital markets and could adversely affect SPPC's ability to continue purchasing power and fuel. Adverse developments with respect to any one or a combination of the factors and contingencies set forth above could cause SPPC to become insolvent and could render SPPC's ability to continue to operate outside of bankruptcy uncertain. The accompanying financial statements do not include any adjustments that might result from the outcome of the uncertainties discussed above. OTHER MATTERS On July 7, 2002, the Board of County Commissioners of Clark County, Nevada, added an Electric Utility Advisory Question to its November 5, 2002 general election ballot, which asked voters whether "the Nevada Legislature should take appropriate action to enable the electrical energy provider for southern Nevada to be a locally controlled, not for profit public utility." NPC filed a lawsuit seeking to remove the question from the ballot, and the lawsuit was dismissed. Although the referendum is non-binding, the results of this advisory question, which was approved by a 57% to 43% vote, may impact future utility legislation by the Nevada Legislature in its next legislative session which may, in turn, directly or indirectly affect NPC and its operations. On August 22, 2002, SPR received a letter from the Southern Nevada Water Authority ("SNWA") stating that it was prepared to enter into good faith negotiation of definitive agreements to acquire all of NPC's assets and assume certain of NPC's existing indebtedness. On September 12, 2002, SPR responded with a letter stating that it did not view the SNWA's letter as an offer and expressing concerns with the SNWA's financing plans, certain significant legal issues with the proposal and the SNWA's lack of utility management experience. The SNWA has responded by reaffirming its purported offer to acquire NPC. Also see Note 5, Dividend Restrictions, Note 9, Regulatory Events and Note 11, Commitments and Contingencies. RECLASSIFICATIONS Certain items previously reported for years prior to 2002 have been reclassified to conform to the current year's presentation. Net income and shareholders' equity were not affected by these reclassifications. RECENT PRONOUNCEMENTS In June 2001, the Financial Accounting Standards Board ("FASB") issued three new pronouncements, Statement of Financial Accounting Standards (SFAS) No. 141, "Business Combinations," SFAS No. 142, "Goodwill and Other Intangible Assets," and SFAS No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 141 requires that the purchase method of accounting be used for all business combinations initiated after June 30, 2001. See Note 12, Change in Accounting for Goodwill, for a discussion of SPR's implementation of SFAS No. 142. SFAS No. 143, effective for fiscal years beginning after June 15, 2002, requires an entity to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. Management does not expect the adoption of SFAS No. 143 to have a material effect on the financial position or results of operations of SPR, NPC, and SPPC. 15 In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections". Among other things, this statement rescinds SFAS No. 4, "Reporting Gains and Losses from Extinguishment of Debt" which required all gains and losses from extinguishment of debt to be aggregated and, if material, classified as an extraordinary item, net of related income tax effect. As a result, the criteria in Accounting Principles Board Opinion No. 30, "Reporting the Results of Operations - Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions," will now be used to classify those gains and losses. Adoption of this statement did not have an impact on the financial position or results of operations of SPR, NPC or SPPC. In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities". SFAS No. 146 addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies Emerging Issues Task Force Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)". SFAS No. 146 requires that a liability for a cost associated with an exit or disposal activity be recognized when the liability is incurred. A fundamental conclusion reached by the FASB in this statement is that an entity's commitment to a plan, by itself, does not create a present obligation to others that meets the definition of a liability. Adoption of this statement did not have an impact on the financial position or results of operations of SPR, NPC or SPPC. NOTE 2. FINANCIAL STATEMENTS OF NEVADA POWER COMPANY (NPC) In accordance with Generally Accepted Accounting Principles, the 1999 merger between SPR and NPC was accounted for as a reverse purchase, with NPC deemed to be the acquirer of SPR as reflected in the SPR Consolidated Financial Statements. However, after the merger with SPR and as a result of the structure of the transactions, NPC is a separate legal entity, which is a wholly owned subsidiary of SPR. As a legal matter, NPC does not own any equity interest in SPR. The NPC Financial Statements accommodate the presentation of financial information of NPC on a stand-alone basis by summarizing all non-NPC financial information into a few items in each of the Financial Statements. These summarized items are repeated below (in 000's): Non-NPC Financial Items in the NPC Financial Statements
NPC Balance Sheets: September 30, 2002 December 31, 2001 ------------------- ------------------ ----------------- Investment in Sierra Pacific Resources $236,821 $309,259 Equity in Sierra Pacific Resources $236,821 $309,259
The Investment in Sierra Pacific Resources reflects the net assets of SPR, after deducting for all liabilities and preferred stock of SPR not related to NPC. The Equity in Sierra Pacific Resources reflects the sum of paid-in-capital and retained earnings of SPR, without the benefit of NPC. These line items do not represent any asset to which holders of NPC's securities may look for recovery of their investment. These items must be disregarded for determining the ability of NPC to satisfy its obligations or to pay dividends (preferred or common), for calculating NPC's ratios of earnings to fixed charges and preferred stock dividends and for all of NPC's financial covenants and earnings tests including those under its charter and First Mortgage Indenture.
NPC Statements of Operations: Three Months Ended Three Months Ended ----------------------------- ------------------ ------------------ September 30, 2002 September 30, 2001 ------------------ ------------------ Equity in Earnings of Sierra Pacific Resources $70 $1,658
Nine Months Ended Nine Months Ended ----------------- ----------------- September 30, 2002 September 30, 2001 ------------------ ------------------ Equity in Losses of Sierra Pacific Resources $(51,999) $(5,494)
This line does not represent any item of revenue or income to which holders of NPC's securities may look for recovery of their investment. This item must be disregarded for determining the ability of NPC to satisfy its obligations or its ability to pay dividends (preferred or common), for calculating NPC's ratios of earnings to fixed charges and preferred dividends and for all of NPC's financial covenants and earnings tests including those under its charter and First Mortgage Indenture. Excluding NPC's equity in the losses/earnings of its parent, SPR, NPC earned approximately $79.3 million and $78.8 million, respectively, for the three-month periods ended September 30, 2002, and 2001. Excluding NPC's equity in the losses of its parent, SPR, NPC incurred a loss of approximately ($216.0) million for the nine months ended September 30, 2002, and earned approximately $56.5 million for the nine months ended September 30, 2001. 16 Net Income (Loss) Per Share, Weighted Average Shares of Common Stock Outstanding, and Dividends Paid Per Share of Common Stock refer to stock share amounts and dividends paid at SPR.
NPC Statements of Cash Flows: Nine Months Ended Nine Months Ended ----------------------------- ----------------- ----------------- September 30, 2002 September 30, 2001 ------------------ ------------------ Equity in Losses of Sierra Pacific Resources $51,999 $5,494
As in the statement of operations, the Equity in Losses of Sierra Pacific Resources reflects the nine months of SPR net losses, after SPPC preferred stock dividends. This line item does not represent any item of cash flow to which holders of NPC's securities may look for recovery of their investment. This item must be disregarded for determining the ability of NPC to satisfy its obligations or its ability to pay dividends (preferred or common), for calculating NPC's ratios of earnings to fixed charges and preferred dividends and for all of NPC's financial covenants and earnings tests including those under its charter and First Mortgage Indenture. NOTE 3. SHORT-TERM BORROWINGS (SPR, NPC, SPPC) SIERRA PACIFIC RESOURCES On April 3, 2002, SPR terminated its $75 million unsecured revolving credit facility in connection with the amendment of NPC's $200 million unsecured revolving credit facility, discussed below. NEVADA POWER COMPANY On November 29, 2001, NPC put into place a $200 million unsecured revolving credit facility for working capital and general corporate purposes, including commercial paper backup. As a result of NPC's rate case decisions (discussed in Note 9 - Regulatory Events) and the credit downgrades by S&P and Moody's, which occurred on March 29 and April 1, 2002, respectively, the banks participating in NPC's credit facility determined that a material adverse event had occurred with respect to NPC, thereby precluding NPC from borrowing funds under its credit facility. The banks agreed to waive the consequences of the material adverse event in a waiver letter and amendment that was executed on April 4, 2002. As required under the waiver letter and amendment, NPC issued and delivered its General and Refunding Mortgage Bond, Series C, due November 28, 2002, in the principal amount of $200 million, to the Administrative Agent for the credit facility. As of September 30, 2002, NPC had borrowed the entire $200 million of funds available under its credit facility at an average interest rate of 3.72%. On October 30, 2002, NPC paid in full and terminated its $200 million credit facility and retired its Series C, General & Refunding Bond which secured the credit facility with the proceeds from the issuance of NPC's $250 million aggregate principal amount of 107/8% General and Refunding Notes, Series E, due 2009. On October 29, 2002, NPC established an accounts receivables purchase facility of up to $125 million, which was arranged by Lehman Brothers. If NPC elects to activate the receivables purchase facility, NPC will sell all of its accounts receivable generated from the sale of electricity to customers to its newly created bankruptcy remote special purpose subsidiary. The receivables sales will be without recourse except for breaches of customary representations and warranties made at the time of sale. The subsidiary will, in turn, sell these receivables to a bankruptcy-remote subsidiary of SPR. SPR's subsidiary will issue variable rate revolving notes backed by the purchased receivables. Lehman Brothers Holdings, Inc. will be the sole initial committed purchaser of all of the variable rate revolving notes. The agreements relating to the receivables purchase facility contain various conditions to purchase, covenants and trigger events, termination events and other provisions customary in receivables transactions. In connection with NPC's receivables facility, SPR has agreed to guaranty NPC's performance of certain obligations as a seller and servicer under the facility. NPC has agreed to issue $125 million principal amount of its General and Refunding Mortgage Bonds upon activation of the accounts receivables purchase facility. The full principal amount of the Bond would secure certain of NPC's obligations as seller and servicer, plus certain interest, fees and expenses thereon to the extent not paid when due, regardless of the actual amounts owing with respect to the secured obligations. As a result, in the event of an NPC bankruptcy or liquidation, the holder of the Bond securing the receivables facility may recover more on a pro rata basis than the holders of other General and Refunding Mortgage securities, who could recover less on a pro rata basis, than they otherwise would recover. However, in no event will the holder of the Bond recover more than the amount of obligations secured by the Bond. NPC intends to use the accounts receivables purchase facility as a back-up liquidity facility and does not plan to activate this facility in the foreseeable future. NPC may activate the facility within five days upon the delivery of certain customary funding documentation and the delivery of the $125 million General and Refunding Mortgage Bond. 17 NPC is in the process of negotiating a 364-day credit facility of up to $50 million. The 364-day credit facility will be secured by $50 million aggregate principal amount of NPC's General and Refunding Mortgage Bonds. The closing of the 364-day credit facility will be subject to the completion of the lender's due diligence, the negotiation and finalization of documentation and other customary closing conditions. Although NPC has commenced negotiations of the terms of the 364-day credit facility, it cannot give assurances that it will enter into the credit facility or any similar arrangement. SIERRA PACIFIC POWER COMPANY On November 29, 2001, SPPC put into place a $150 million unsecured revolving credit facility for working capital and general corporate purposes, including commercial paper backup. Under this credit facility, SPPC was required, in the event of a ratings downgrade of its senior unsecured debt, to secure the facility with General and Refunding Mortgage Bonds. In satisfaction of its obligation to secure the credit facility, on April 8, 2002, SPPC issued and delivered its General and Refunding Mortgage Bond, Series B, due November 28, 2002, in the principal amount of $150 million, to the Administrative Agent for the credit facility. As of September 30, 2002, SPPC had borrowed the entire $150 million of funds available under its credit facility to, in part, pay off maturing commercial paper, and to maintain a cash balance at SPPC at an average interest rate of 3.69%. On October 31, 2002, SPPC paid off and terminated its $150 million credit facility and retired its Series B, General & Refunding Bond which secured the credit facility with a combination of cash on hand and proceeds from its $100 million Term Loan Facility. On October 29, 2002, SPPC established an accounts receivables purchase facility of up to $75 million, which was arranged by Lehman Brothers. If SPPC elects to activate the receivables purchase facility, SPPC will sell all of its accounts receivable generated from the sale of electricity to customers to its newly created bankruptcy remote special purpose subsidiary. The receivables sales will be without recourse except for breaches of customary representations and warranties made at the time of sale. The subsidiary will, in turn, sell these receivables to a bankruptcy-remote subsidiary of SPR. SPR's subsidiary will issue variable rate revolving notes backed by the purchased receivables. Lehman Brothers Holdings, Inc. will be the sole initial committed purchaser of all of the variable rate revolving notes. The agreements relating to the receivables purchase facility contain various conditions to purchase, covenants and trigger events, termination events and other provisions customary in receivables transactions. In connection with SPPC's receivables facility, SPR has agreed to guaranty SPPC's performance of certain obligations as a seller and servicer under the facility. SPPC has agreed to issue $75 million principal amount of its General and Refunding Mortgage Bonds upon activation of the accounts receivables purchase facility. The full principal amount of the Bond would secure certain of SPPC's obligations as seller and servicer, plus certain interest, fees and expenses thereon to the extent not paid when due, regardless of the actual amounts owing with respect to the secured obligations. As a result, in the event of an SPPC bankruptcy or liquidation, the holder of the Bond securing the receivables facility may recover more on a pro rata basis than the holders of other General and Refunding Mortgage securities, who could recover less on a pro rata basis, than they otherwise would recover. However, in no event will the holder of the Bond recover more than the amount of obligations secured by the Bond. SPPC intends to use the accounts receivables purchase facility as a back-up liquidity facility and does not plan to activate this facility in the foreseeable future. SPPC may activate the facility within five days upon the delivery of certain customary funding documentation and the delivery of the $75 million General and Refunding Mortgage Bond. NOTE 4. LONG-TERM DEBT (SPR, NPC, SPPC) NPC's, SPPC's and SPR's aggregate annual amount of maturities for long-term debt for the next five years is shown below (in thousands of dollars): 18
SPR Holding Co. SPR NPC SPPC and Other Subs. Consolidated ------------ ---------- --------------- ------------ 2002 $ 15,000 $ - $ - $ 15,000 2003 350,000 20,400 (1) 200,000 570,400 (1) 2004 130,000 2,400 - 132,400 2005 - 2,400 300,000 302,400 2006 - 51,963 - 51,963 ------------ ---------- ------------ ------------ Subtotal 495,000 77,163 500,000 1,072,163 Thereafter 1,126,961 842,337 376,383 2,345,681 ------------ ---------- ------------ ------------ Total $ 1,621,961 $ 919,500 $ 876,383 $ 3,417,844 ============ ========== ============ ============
(1) In addition to the amounts shown in the table, on May 1, 2003, $80,000,000 aggregate principal amount of the Washoe County, Nevada, Water Facilities Refunding Revenue Bonds (Sierra Pacific Power Company Project) Series 2001, will be subject to remarketing. In the event that the Bonds cannot be successfully remarketed on that date, SPPC will be required to purchase the outstanding Bonds at a price of 100% of the principal amount, plus accrued interest. SIERRA PACIFIC RESOURCES On April 20, 2002, $100 million of SPR's floating rate notes matured and were paid in full. The notes had been issued on April 20, 2000, and the net proceeds used to make a capital contribution to NPC. NEVADA POWER COMPANY On May 13, 2002, NPC issued a General and Refunding Mortgage Bond, Series D, due April 15, 2004, in the principal amount of $130 million, for the benefit of the holders of NPC's 6.20% Senior Unsecured Notes, Series B, due April 15, 2004. The Senior Unsecured Notes Indenture required that in the event that NPC issued debt secured by liens on NPC's operating property, in excess of 15% of its Net Tangible Assets or Capitalization (as both terms are defined in the Senior Unsecured Notes Indenture), NPC would equally and ratably secure the Senior Unsecured Notes. NPC triggered this negative pledge covenant on April 23, 2002, when it borrowed certain amounts under its secured credit facility. On October 25, 2002 NPC redeemed its 7 5/8% Series L, First Mortgage Bonds in the aggregate principal amount of $15 million. On October 29, 2002, NPC issued and sold $250 million of its 10 7/8% General and Refunding Mortgage Notes, Series E, due 2009 for a purchase price of $235.6 million. The Series E Notes were issued with registration rights. The proceeds of the issuance were used to pay off NPC's $200 million credit facility and for general corporate purposes. The Series E Notes will mature October 15, 2009. As discussed in Note 5, Dividend Restrictions, NPC's Series E Notes limit the amount of dividends that NPC may pay to SPR. The terms of the Series E Notes also restrict NPC from incurring any additional indebtedness unless (i) at the time the debt is incurred, the ratio of consolidated cash flow to fixed charges for NPC's most recently ended four quarter period on a pro forma basis is at least 2 to 1, or (ii) the debt incurred is specifically permitted, which includes certain credit facility or letter of credit indebtedness, obligations incurred to finance property construction or improvement, indebtedness incurred to refinance existing indebtedness, certain intercompany indebtedness, hedging obligations, indebtedness incurred to support bid, performance or surety bonds, and certain letters of credit issued to support NPC's obligations with respect to energy suppliers. If NPC's Series E Notes are upgraded to investment grade by both Moody's and S&P, the dividend restrictions and the restrictions on indebtedness applicable to the Series E Notes will be suspended and will no longer be in effect so long as the Series E Notes remain investment grade. Among other things, the Series E Notes also contain restrictions on liens (other than permitted liens, which include liens to secure certain permitted debt) and certain sale and leaseback transactions. In the event of a change of control of NPC, 19 the holders of Series E Notes are entitled to require that NPC repurchase the Series E Notes for a cash payment equal to 101% of the aggregate principal amount plus accrued and unpaid interest. NPC's first mortgage indenture creates a first priority lien on substantially all of NPC's properties. As of September 30, 2002, $372.5 million of NPC's first mortgage bonds were outstanding. Although the first mortgage indenture allows NPC to issue additional mortgage bonds on the basis of (i) 60% of net utility property additions and/or (ii) the principal amount of retired mortgage bonds, NPC agreed in connection with its $250 million 10 7/8% General and Refunding Mortgage Notes, Series E, due 2009 that it would not issue any more first mortgage bonds. NPC's General and Refunding Mortgage Indenture creates a lien on substantially all of NPC's properties in Nevada that is junior to the lien of the first mortgage indenture. As of September 30, 2002, $820 million of NPC's General and Refunding Mortgage securities were outstanding. Additional securities may be issued under the General and Refunding Mortgage Indenture on the basis of (1) 70% of net utility property additions, (2) the principal amount of retired General and Refunding Mortgage bonds, and/or (3) the principal amount of first mortgage bonds retired after delivery to the indenture trustee of the initial expert's certificate under the General and Refunding Mortgage Indenture. As of October 1, 2002, NPC had the capacity to issue approximately $871 million of additional General and Refunding Mortgage securities, not including the issuance of $250 million Series E Notes and the retirement of $200 million of General and Refunding Mortgage Bonds that secured NPC's terminated credit facility. However, the financial covenants contained in the Series E Notes limits NPC ability to issue additional General and Refunding Mortgage bonds or other debt. NPC has reserved $125 million of General and Refunding Mortgage Bonds for issuance upon the initial funding of NPC's receivables facility and $50 million of its General and Refunding Mortgage Bonds to secure a proposed 364-day facility, discussed below. NPC also has the ability to release property from the liens of the two mortgage indentures on the basis of net property additions, cash and/or retired bonds. To the extent NPC releases property from the lien of its General and Refunding Mortgage Indenture, it will reduce the amount of bonds issuable under that indenture. SIERRA PACIFIC POWER COMPANY On October 30, 2002 SPPC entered into a $100 million Term Loan Agreement with several lenders and Lehman Commercial Paper Inc., as Administrative Agent. The net proceeds of $97 million from the Term Loan Facility, along with available cash, were used to pay off SPPC's $150 million credit facility, which was secured by a Series B General and Refunding Mortgage Bond. As discussed in Note 5, Dividend Restrictions, SPPC's Term Loan Agreement limits the amount of dividends that SPPC may pay to SPR. SPPC's Term Loan Agreement also requires that SPPC maintain a ratio of consolidated total debt to consolidated total capitalization at all times during each of the following quarters in an amount not to exceed (i) .650 to 1.0 for the fiscal quarters ended December 31, 2002 through December 31, 2003, (ii) .625 to 1.0 for the fiscal quarters ended March 31, 2004 through December 31, 2004, and (iii) .600 to 1.0 for the fiscal quarter ended March 31, 2005 and for each fiscal quarter thereafter. SPPC's Term Loan Agreement also requires that SPPC maintain a consolidated interest coverage ratio for any four consecutive fiscal quarters ending with the fiscal quarter set forth below of not less than (i) 1.75 to 1.00 for the fiscal quarters ended December 31, 2002 and March 31, 2003, (ii) 2.50 to 1.0 for the fiscal quarters ended June 30, 2003 through December 31, 2003, (iii) 2.75 to 1.0 for the fiscal quarters ended March 31, 2004 through September 30, 2004, and (iv) 3.00 to 1.0 for the fiscal quarter ended December 31, 2004 and for each fiscal quarter thereafter. The Term Loan Facility, which is secured by a $100 million Series C General and Refunding Mortgage Bond, will expire October 31, 2005. 20 On May 23, 2002, SPPC defeased its 2% First Mortgage Bonds due 2011, 5% Series Y First Mortgage Bonds due 2024, and 2% Series Z First Mortgage Bonds due 2004 by depositing $1.2 million, $3.1 million, and $45,000, respectively, with its First Mortgage Trustee. These First Mortgage Bonds were issued to secure loans made to SPPC by the United States under the Rural Electrification Act of 1936, as amended. SPPC's first mortgage indenture creates a first priority lien on substantially all of SPPC's properties in Nevada and California. As of September 30, 2002, $505.3 million of SPPC's first mortgage bonds were outstanding. Although the first mortgage indenture allows SPPC to issue additional mortgage bonds on the basis of (i) 60% of net utility property additions and/or (ii) the principal amount of retired mortgage bonds, SPPC agreed in its General and Refunding Mortgage Indenture that it would not issue any additional first mortgage bonds. SPPC's General and Refunding Mortgage Indenture creates a lien on substantially all of SPPC's properties in Nevada that is junior to the lien of the first mortgage indenture. As of September 30, 2002, $470 million of SPPC's General and Refunding Mortgage bonds were outstanding. Additional securities may be issued under the General and Refunding Mortgage Indenture on the basis of (i) 70% of net utility property additions, (ii) the principal amount of retired General and Refunding Mortgage bonds, and/or (iii) the principal amount of first mortgage bonds retired after delivery to the indenture trustee of the initial expert's certificate under the General and Refunding Mortgage Indenture. At September 30, 2002, SPPC had the capacity to issue approximately $363 million of additional General and Refunding Mortgage securities, not including the issuance of SPPC's $100 million Series C General and Refunding Mortgage Bond which secures SPPC's Term Loan Facility and the retirement of $150 million of Series B General and Refunding Mortgage Bonds that secured SPPC's terminated credit facility. However, the financial covenants contained in SPPC's Term Loan Agreement and Receivable Purchase Facility Agreements limit SPPC's ability to issue additional General and Refunding Mortgage Securities or other debt. SPPC will reserve $75 million of General and Refunding Mortgage Bonds for issuance upon the initial funding of its receivables purchase facility. SPPC also has the ability to release property from the liens of the two mortgage indentures on the basis of net property additions, cash and/or retired bonds. To the extent SPPC releases property from the lien of its General and Refunding Mortgage Indenture, it will reduce the amount of bonds issuable under that indenture. NOTE 5. DIVIDEND RESTRICTIONS (SPR, NPC, SPPC) Since SPR is a holding company, substantially all of its cash flow is provided by dividends paid to SPR by NPC and SPPC on their common stock, all of which is owned by SPR. NPC and SPPC are public utilities and are subject to regulation by state utility commissions which may impose limits on investment returns or otherwise impact the amount of dividends that the Utilities may declare and pay. In addition, certain agreements entered into by the Utilities set restrictions on the amount of dividends they may declare and pay and restrict the circumstances under which such dividends may be declared and paid. SPPC's charter also contains a dividend restriction for the benefit of SPPC's preferred stock holders. Any of the provisions which restrict dividends payable by NPC or SPPC could adversely affect the liquidity of SPR. SIERRA PACIFIC RESOURCES The Master Amendment to Confirmation Agreements with Duke Energy Trading and Marketing L.L.C. (discussed below) prohibited SPR from using any amounts received from NPC to pay a dividend or to make any other payment on account of SPR's common stock until certain deferred payments to Duke were paid in full and certain energy and gas deliveries had been made and paid for under the Agreement. As of October 25, 2002, NPC had paid all of the deferred payments due under this Agreement, and NPC is current on payment for energy and gas deliveries under the Agreement. NEVADA POWER COMPANY The PUCN issued a Compliance Order, Docket No. 02-4037, on June 19, 2002, relating to NPC's request for authority to issue long-term debt. The PUCN order requires that, until such time as the order's authorization expires (December 31, 2003), NPC must either receive the prior approval of the PUCN or reach an equity ratio of 42% before paying any dividends to SPR. If NPC achieves a 42% equity ratio prior to December 31, 2003, the dividend restriction ceases to have effect. In addition, NPC's first mortgage indenture limits the cumulative amount of dividends that NPC may pay on its capital stock to the cumulative net earnings of NPC since 1953. At the present time, this restriction precludes NPC from making further payments of dividends on NPC's common stock and will continue to bar such payments unless the restriction is waived or removed by the consent of the first mortgage bondholders, the first mortgage bonds are redeemed or defeased, or until, over the passage of time, NPC generates sufficient earnings to overcome the shortfall created by the write-off of $465 million in connection with the March 2002 decision in NPC's deferred energy rate case. 21 On June 4, 2002, NPC entered into a Master Amendment to Confirmation Agreements with Duke Energy Trading and Marketing L.L.C., which, among other things, limited the amount of dividends NPC could declare or pay on its equity securities until NPC completed certain deferred payments under the Agreement. Under the Agreement, until the deferred payments were paid in full, NPC could not declare any dividend or make any dividend payments other than (1) payments to SPR to enable SPR to pay its reasonable fees and expenses (including interest on SPR's debts and payment of obligations under SPR's PIES) incurred in the ordinary course of business in calendar year 2003, up to a maximum amount of $20,000,000 and (2) any currently scheduled payments to any of NPC's preferred trust vehicles on account of NPC's preferred trust securities. As of October 25, 2002, NPC had paid all of the deferred payments due under this Agreement. On June 25, 2002, NPC entered into Amendment No. 2 to its $200 million credit agreement. The amendment provides that NPC may not declare or pay any dividend on its capital stock for the duration of the credit facility which expires on November 28, 2002. This facility was paid off on October 30, 2002 with proceeds from the issuance of the Series E General & Refunding Mortgage Notes. On October 29, 2002 NPC issued $250 million 10 7/8% General and Refunding Mortgage Notes, Series E, due 2009 the terms of which, among other things, limit the amount of dividends NPC may pay to SPR. However, that limitation does not apply to payments by NPC to enable SPR to pay its reasonable fees and expenses (including, but not limited to, interest on SPR's indebtedness and payment obligations on account of SPR's premium income equity securities) provided that those payments do not exceed $60 million for any one calendar year, those payments comply with any regulatory restrictions then applicable to NPC, and the ratio of consolidated cash flow to fixed charges for NPC's most recently ended four full fiscal quarters immediately preceding the date of payment is at least 1.75 to 1. The terms of the Series E Notes also permit dividend payments to SPR in an aggregate amount not to exceed $15 million from the date of the issuance of the Notes. In addition, NPC may make dividend payments to SPR in excess of the amounts described above so long as, at the time of payment and after giving effect to the payment: there are no defaults or events of default with respect to the Series E Notes, NPC can meet a Fixed Charge Coverage Ratio Test, and the total amount of such dividends is less than (i) the sum of 50% of NPC's Consolidated Net Income measured on a quarterly basis cumulative of all quarters from the date of issuance of the Series E Notes, plus (ii) 100% of NPC's aggregate net cash proceeds from the issuance or sale of certain equity or convertible debt securities of NPC, plus (iii) the lesser of cash return of capital or the initial amount of certain restricted investments, plus (iv) the fair market value of NPC's investment in certain subsidiaries. If NPC's Series E Notes are upgraded to investment grade by both Moody's and S&P, these dividend restrictions will be suspended and will no longer be in effect so long as the Series E Notes remain investment grade. As described in Note 3, Short-Term Borrowings, on October 29, 2002, NPC established an accounts receivables purchase facility. The agreements relating to the receivables purchase facility contain various conditions, including a limitation on the payment of dividends by NPC to SPR that is identical to the limitation contained in NPC's General and Refunding Mortgage Notes, Series E, described above. Finally, the terms of NPC's preferred trust securities provide that no dividends may be paid on NPC's common stock if NPC has elected to defer payments on the junior subordinated debentures issued in conjunction with the preferred trust securities. At this time, NPC has not elected to defer payments on the junior subordinated debentures. SIERRA PACIFIC POWER COMPANY SPPC's Articles of Incorporation contain restrictions on the payment of dividends on SPPC's common stock in the event of a default in the payment of dividends on SPPC's preferred stock and prohibit SPPC from declaring or paying any dividends on any shares of common stock except from the net income of SPPC, and its predecessor, available for dividends on common stock accumulated subsequent to December 31, 1955, less preferred stock dividends plus the sum of $500,000. As of June 30, 2002, SPPC was not prohibited by these restrictions from paying dividends. In addition, on June 25, 2002, SPPC entered into Amendment No. 1 to its $150 million credit agreement. This amendment prohibits the payment of dividends on SPPC's capital stock if SPPC is in default under the terms of its credit facility. On October 31, 2002 SPPC paid off this credit agreement with cash and proceeds from the $100 million term loan. On October 30, 2002 SPPC entered into a $100 million Term Loan Agreement with Lehman Commercial Paper Inc., as administrative agent, which matures October 31, 2005, and which is secured by a $100 million General and Refunding Bond, Series C, due October 31, 2005. The Term Loan Agreement limits the amount of dividends that SPPC may pay to SPR. However, that limitation does not apply to payments by SPPC to enable SPR to pay its reasonable fees and expenses (including, but not limited to, interest on SPR's indebtedness and payment obligations on account of SPR's premium income equity securities) provided that those payments do not exceed $90 million, $80 million and $60 million in the aggregate for the twelve month periods ending on October 30, 2003, 2004 and 2005, respectively. The Term Loan Agreement also permits SPPC to make dividend payments to SPR in an aggregate amount not to exceed $10 million during the term of the Term Loan Agreement. In addition, SPPC may make dividend payments to SPR in 22 excess of the amounts described above so long as, at the time of the payment and after giving effect to the payment, there are no defaults or events of default under the Term Loan Agreement, and such amounts, when aggregated with the amount of dividends paid to SPR by SPPC since the date of execution of the Term Loan Agreement, does not exceed the sum of (i) 50% of SPPC's Consolidated Net Income for the period commencing January 1, 2003 and ending with last day of fiscal quarter most recently completed prior to the date of the contemplated dividend payment plus (ii) the aggregate amount of cash received by SPPC from SPR as equity contributions on its common stock during such period. As described in Note 3, Short-Term Borrowings, on October 29, 2002, SPPC established an accounts receivables purchase facility. The agreements relating to the receivables purchase facility contain various conditions, including a limitation on the payment of dividends by SPPC to SPR that is identical to the limitation contained in SPPC's Term Loan Agreement, described above. 23 NOTE 6. EARNINGS PER SHARE (SPR) SPR follows SFAS No. 128, "Earnings Per Share". The difference, if any, between Basic EPS and Diluted EPS would be due to common stock equivalent shares resulting from stock options, employee stock purchase plan, performance shares and a non-employee director stock plan. Due to net losses for the nine months ended September 30, 2002, these items are anti-dilutive for that period. Common stock equivalents were determined using the treasury stock method.
THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, ---------------------------- ------------------------------- 2002 2001 2002 2001 ------------- ----------- ------------- ------------ BASIC EPS Numerator ($000) Income (Loss) from continuing operations $ 79,374 $ 80,409 $ (266,458) $ 24,098 Income from discontinued operations - - - 1,022 Gain on disposal of water business - - - 25,845 Cumulative effect of change in accounting principle - - (1,566) - ------------- ----------- ------------- ------------ Net income (loss) $ 79,374 $ 80,409 $ (268,024) $ 50,965 ============= =========== ============= ============ Denominator Weighted average number of shares outstanding 102,132,465 90,302,825 102,117,926 82,423,032 ------------- ----------- ------------- ------------ Per-Share Amounts: Income (Loss) from continuing operations $ 0.78 $ 0.89 $ (2.61) $ 0.29 Income from discontinued operations - - - 0.01 Gain on disposal of water business - - - 0.32 Cumulative effect of change in accounting principle - - (0.01) - ------------- ----------- ------------- ------------ Net income (loss) $ 0.78 $ 0.89 $ (2.62) $ 0.62 ============= =========== ============= ============ DILUTED EPS Numerator ($000) Income (Loss) from continuing operations $ 79,374 $ 80,409 $ (266,458) $ 24,098 Income from discontinued operations - - - 1,022 Gain on disposal of water business - - - 25,845 Cumulative effect of change in accounting principle - - (1,566) - ------------- ----------- ------------- ------------ Net income (loss) $ 79,374 $ 80,409 $ (268,024) $ 50,965 ============= =========== ============= ============ Denominator Weighted average number of shares outstanding before dilution 102,132,465 90,302,825 102,117,926 82,423,032 Stock options (1) - 31,645 10,537 18,285 Executive long term incentive plan- performance shares (1) - 71,593 8,918 37,960 Non-Employee Director stock plan (1) 15,148 9,355 11,930 9,355 Employee stock purchase plan (1) - 3,519 1,619 3,185 ------------- ----------- ------------- ------------ 102,147,613 90,418,937 102,150,930 82,491,817 ------------- ----------- ------------- ------------ Per-Share Amounts (1) : Income (Loss) from continuing operations $ 0.78 $ 0.89 $ (2.61) $ 0.29 Income from discontinued operations - - - 0.01 Gain on disposal of water business - - - 0.32 Cumulative effect of change in accounting principle - - (0.01) - ------------- ----------- ------------- ------------ Net income (loss) $ 0.78 $ 0.89 $ (2.62) $ 0.62 ============= =========== ============= ============
(1) Because of a net loss for the nine months ended September 30, 2002, stock equivalents would be anti-dilutive. Accordingly, Diluted EPS for this period is computed using the weighted average number of shares outstanding before dilution. 24 NOTE 7. SEGMENT INFORMATION (SPR) SPR operates three business segments providing regulated electric and natural gas services. NPC provides electric service to Las Vegas and surrounding Clark County. SPPC provides electric service in northern Nevada and the Lake Tahoe area of California. SPPC also provides natural gas service in the Reno-Sparks area of Nevada. Other segment information includes segments below the quantitative threshold for separate disclosure. On June 11, 2001, SPPC sold its 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):
Three Months Ended NPC SPPC Total September 30, 2002 Electric Electric Electric Gas Other Consolidated --------------------- ------------ ------------ ------------ ----------- ----------- -------------- Operating Revenues $ 712,536 $ 285,023 $ 997,559 $ 18,473 $ 3,987 $ 1,020,019 ============ ============ ============ =========== =========== ============== Operating Income (Loss) $ 109,183 $ 30,252 $ 139,435 $ (231) $ 4,123 $ 143,327 ============ ============ ============ =========== =========== ==============
Three Months Ended NPC SPPC Total September 30, 2001 Electric Electric Electric Gas Other Consolidated --------------------- ------------ ------------ ------------ ----------- ----------- -------------- Operating Revenues $ 1,395,496 $ 581,957 $ 1,977,453 $ 18,831 $ 5,650 $ 2,001,934 ============ ============ ============ =========== =========== ============== Operating Income $ 94,767 $ 25,146 $ 119,913 $ 456 $ 1,821 $ 122,190 ============ ============ ============ =========== =========== ==============
Nine Months Ended NPC SPPC Total September 30, 2002 Electric Electric Electric Gas Other Consolidated --------------------- ------------ ------------ ------------ ----------- ----------- -------------- Operating Revenues $ 1,545,867 $ 705,946 $ 2,251,813 $ 99,139 $ 8,328 $ 2,359,280 ============ ============ ============ =========== =========== ============== Operating Income (Loss) $ (121,414) $ 35,311 $ (86,103) $ 4,826 $ 13,752 $ (67,525) ============ ============ ============ =========== =========== ==============
Nine Months Ended NPC SPPC Total September 30, 2001 Electric Electric Electric Gas Other Consolidated --------------------- ------------ ------------ ------------ ----------- ----------- -------------- Operating Revenues $ 2,562,949 $ 1,175,228 $ 3,738,177 $ 104,725 $ 13,350 $ 3,856,252 ============ ============ ============ =========== =========== ============== Operating Income (Loss) $ 120,125 $ 49,123 $ 169,248 $ 6,105 $ (5,355) $ 169,998 ============ ============ ============ =========== =========== ==============
NOTE 8. DISCONTINUED OPERATIONS (SPR, SPPC) As previously reported, SPPC closed the sale of its water business to the Truckee Meadows Water Authority for $341 million on June 11, 2001. Accordingly, the water business is reported as a discontinued operation for the nine months ending September 30, 2001. SPPC recorded a $25.8 million gain on the sale, net of income taxes, for the same period. Revenues from operations of the water business were $23.2 million for the nine-month period ended September 30, 2001. The net income from operations of the water business, as shown in the Condensed Consolidated Statements of Operations of SPR and SPPC, includes preferred dividends of approximately $200,000 for the nine-month period ended September 30, 2001. These amounts are not included in the revenues and income (loss) from continuing operations shown in the accompanying statements of operations. NOTE 9. REGULATORY EVENTS (SPR, NPC, SPPC) NEVADA MATTERS (NPC, SPPC) NEVADA POWER COMPANY GENERAL RATE CASE (NPC) On October 1, 2001, NPC filed an application with the PUCN seeking an electric general rate increase. This application was mandated by Assembly Bill 369 (AB 369). On December 21, 2001, NPC filed a Certification to its general rate filing updating costs and revenues pursuant to Nevada regulations. In the certification filing, NPC requested an increase in its general rates charged to all classes of electric customers designed to produce an increase in annual electric revenues of 25 $22.7 million, which is an overall 1.7% rate increase. The application also sought a return on common equity ("ROE") for Nevada Power's total electric operations of 12.25% and an overall rate of return ("ROR") of 9.30%. On March 27, 2002, the PUCN issued its decision on the general rate application, ordering a $43 million revenue decrease with an ROE of 10.1% and ROR of 8.37%. The effective date for the decision was April 1, 2002. The decision also resulted in adverse adjustments to depreciation aggregating $7.9 million, and the adverse treatment of approximately $5 million of revenues related to SO2 Allowances. On April 15, 2002, NPC filed a petition for reconsideration with the PUCN. In the petition, NPC raised six issues for reconsideration: the treatment of revenues related to SO2 Allowances, in particular the calculation of the annual amortization amount, which appears to be in error; the adjustment for "excess" capital investment related to common facilities at the Harry Allen generating station; the rejection of adjustments to accumulated depreciation reserves related to the establishment of revised depreciation rates for transmission, distribution and common facilities; the delay in allowing NPC to recover its merger costs without the benefit of carrying charges; the finding that NPC has no need for and is entitled to zero funds cash working capital; and the establishment of a 10.1% ROE. On May 24, 2002, the PUCN issued an order on the petition for reconsideration. In its order the PUCN reaffirmed its findings in the original order for the issues related to "excess" capital investment at the Harry Allen generating station, merger costs, cash working capital, and the 10.1% ROE. The PUCN, however, did modify its original order to include adjustments related to SO2 Allowances and depreciation issues. Revised rates for these changes went into effect on June 1, 2002. NEVADA POWER COMPANY DEFERRED ENERGY CASE (NPC) On November 30, 2001, NPC filed an application with the PUCN seeking to clear deferred balances for purchased fuel and power costs accumulated between March 1, 2001 through September 30, 2001, as mandated by AB 369. The application sought to establish a Deferred Energy Accounting Adjustment ("DEAA") rate to clear accumulated purchased fuel and power costs of $922 million and spread the recovery of the deferred costs, together with a carrying charge, over a period of not more than three years. On March 29, 2002, the PUCN issued its decision on the deferred energy application, allowing NPC to recover $478 million over a three-year period, but disallowing $434 million of deferred purchased fuel and power costs and $10 million in carrying charges. The order states that the disallowance was based on alleged imprudence in incurring the disallowed costs. On April 11, 2002, NPC filed a lawsuit in the First District Court of Nevada seeking to reverse portions of the PUCN's decision. NPC asserts that, as a result of the PUCN's decision, NPC's credit rating was reduced to below investment grade, SPR suffered a reduction in its equity market capitalization by approximately 41%, and the disallowed costs are effectively imposed upon SPR's shareholders. In its lawsuit, NPC alleges that the order of the PUCN is: in violation of constitutional and statutory provisions; made upon unlawful procedure; affected by other error of law; clearly erroneous in view of the reliable, probative and substantial evidence on the whole record; arbitrary and capricious and characterized by abuse of discretion. NPC also states that its decisions with respect to the purchase of power during the energy crisis in the western United States were made prudently, as required under AB 369. In early 2001, the PUCN and the Nevada State Legislature expressly required that NPC secure sufficient, safe and reliable power for anticipated summer loads and needs for the summer of 2001. Prior to the April 2001 enactment of AB 369, which prohibits until July 2003 all divestiture of generation assets, NPC was operating under an order of the PUCN to divest itself of its electric generating plants. To meet this requirement, NPC had engaged in an open auction process that led to the signing of asset sale agreements for a number of its plants, in connection with which, NPC entered into long-term purchase power contracts with the potential buyers that would have availed NPC of reasonably priced purchase power over a long-term period. In its petition, NPC challenges the disallowance by the PUCN of $180 million of its deferred energy costs relating to an informal offer made by an agent for Merrill Lynch for the delivery of energy from January 2001 to March 2003. In addition to certain procedural questions relating to the PUCN's finding with respect to the Merrill Lynch informal offer, NPC asserts that the energy being negotiated was not firm (uninterruptible), the obligations, costs and arrangements for delivery in the informal offer were not specified, the cost of the energy proposed under the informal offer was above then-current market price, and that the supplier was a minor market participant and the magnitude of the transaction proposed was more than 45 times its previously combined annual transactions. NPC's lawsuit requests that the District Court reverse portions of the PUCN's order and remand the matter to the PUCN with direction that the PUCN authorize NPC to immediately establish rates that would allow NPC to recover its entire deferred energy balance of $922 million, with a carrying charge, over three years. A hearing on this matter has been scheduled for February 2003. At this time, NPC is not able to predict the outcome or the timing of a decision in this matter. Various interveners in NPC's deferred energy case before the PUCN filed petitions with the PUCN for reconsideration of the PUCN's order, seeking additional disallowances of between $12.8 million and $488 million. On May 24, 2002, the PUCN issued an order denying any further disallowances and granted NPC the authority to increase the deferred energy cost recovery charge for the month of June 2002 by one cent per kilowatt-hour. This increase accelerated the recovery of the deferred balance by approximately $16 million for the month of June 2002 only. The Bureau of Consumer Protection (BCP) of 26 the Nevada Attorney General's Office has since filed a petition in NPC's pending state court case seeking additional disallowances. SIERRA PACIFIC POWER COMPANY GENERAL RATE CASE (SPPC) On November 30, 2001, SPPC filed an application with the PUCN seeking an electric general rate increase. This application was mandated by AB 369. On February 28, 2002, SPPC filed a certification to its general rate filing, updating costs and revenues pursuant to Nevada regulations. In the certification filing, SPPC requested an increase in its general rates charged to all classes of electric customers, which were designed to produce an increase in annual electric revenues of $15.9 million representing an overall 2.4% rate increase. The application also sought an ROE for SPPC's total electric operations of 12.25% and an overall ROR of 9.42%. On May 28, 2002, the PUCN issued its decision on the general rate application, ordering a $15.3 million revenue decrease with an ROE of 10.17% and ROR of 8.61%. The effective date of the decision was June 1, 2002. Various parties to the case had filed petitions for reconsideration of the order. On July 18, 2002, the PUCN issued a final decision on the petitions for reconsideration, clarifying issues contained its original order. As a result of the clarifications, SPPC was ordered to change the total annual electric revenue decrease from $15.3 million to $15.8 million. On August 19, 2002, Barrick filed a lawsuit in the First District Court of Nevada seeking to reverse portions of the decision related to the High Voltage Distribution facilities contained in the general rate case order. Barrick alleges that the order of the PUCN is: in violation of constitutional and statutory provisions; in excess of the statutory authority of the PUCN; affected by error of law: clearly erroneous in view of the reliable, probative and substantial evidence on the whole record; and arbitrary or capricious or characterized by abuse of discretion. A hearing date has not yet been scheduled. At this time, SPPC is not able to predict the outcome or the timing of a decision in this matter. SIERRA PACIFIC POWER COMPANY DEFERRED ENERGY (SPPC) On February 1, 2002, SPPC filed an application with the PUCN seeking to clear deferred balances for purchased fuel and power costs accumulated between March 1, 2001 and November 30, 2001. This application was mandated by AB 369. The application sought to establish a DEAA rate to clear accumulated purchased fuel and power costs of $205 million and spread the cost recovery over a period of not more than three years. It also sought to recalculate the Base Tariff Energy Rate to reflect anticipated ongoing purchased fuel and power costs. The total rate increase resulting from the requested DEAA would have amounted to 9.8%. Various parties intervened in SPPC's deferred energy rate case including the Staff of the PUCN, the BCP from the Nevada Attorney General's office, and Barrick, among others. Interveners proposed disallowances ranging from $40.4 million to $361 million. On May 28, 2002, the PUCN issued its decision on the deferred energy application, allowing SPPC three years to collect $150 million but disallowing $53 million of deferred purchased fuel and power costs and $2 million in carrying charges. Several of the interveners from SPPC's deferred energy rate case filed petitions with the PUCN for reconsideration of its decision, seeking an additional disallowance of $126 million. On July 18, 2002, the petitions for reconsideration were granted in part and denied in part by the PUCN, but no additional disallowances to the deferred energy balance resulted from that decision. On August 22, 2002, SPPC filed a lawsuit in the First District Court of Nevada seeking to reverse portions of the decision of the PUCN denying the recovery of deferred energy costs incurred by SPPC on behalf of its customers in 2001 on the grounds that such power costs were not prudently incurred. In its lawsuit, SPPC alleges that the order of the PUCN is: in violation of constitutional and statutory provisions; in excess of the statutory authority of the PUCN; made upon unlawful procedure; affected by other error of law; clearly erroneous in view of the reliable, probative and substantial evidence on the whole record; arbitrary and capricious and characterized by abuse of discretion. SPPC's lawsuit requests that the District Court reverse portions of the order of the PUCN and remand the matter to the PUCN with direction that the PUCN authorize SPPC to immediately establish rates that would allow SPPC to recover its entire deferred energy balance of $205 million, with a carrying charge, over three years. A hearing date has not yet been scheduled. On August 22, 2002, the BCP from the Nevada Attorney General's office also filed a lawsuit in the First District Court of Nevada seeking to set aside the decision of the PUCN so that SPPC is not authorized to reflect in rates any costs for fuel and purchased power which may have been imprudently incurred. A hearing date has not yet been scheduled. At this time, SPPC is not able to predict the outcome or the timing of a decision in these matters. CUSTOMERS FILE UNDER AB 661 (NPC, SPPC) Assembly Bill 661 (AB 661), passed by the Nevada legislature in 2001, allows commercial and governmental customers with an average demand greater than 1 MW to select new energy suppliers. The Utilities would continue to provide 27 transmission, distribution, metering and billing services to such customers. AB 661 requires customers wishing to choose a new supplier to receive the approval of the PUCN and meet public interest standards. In particular, departing customers must secure new energy resources that are not under contract to the Utilities, the departure must not burden the Utilities with increased costs or cause any remaining customers to pay increased costs, and the departing customers must pay their portion of any deferred energy balances. The PUCN adopted regulations prescribing the criteria that will be used to determine if there will be negative impacts to remaining customers or the Utility. These regulations place certain limits upon the departure of NPC customers until 2003; most significantly, the amount of load departing is limited to approximately 1100 MW in peak conditions. Customers wishing to choose a new supplier must provide 180-day notice to the Utilities. AB 661 permitted customers to file applications with the PUCN beginning in the fourth quarter of 2001, and customers could begin to receive service from new suppliers by mid-2002. On January 10, 2002, Barrick, an approximately 130 MW SPPC customer, filed an application with the PUCN to exit the system of SPPC and to purchase energy, capacity and ancillary services from a provider other than SPPC. A stipulation filed on March 8, 2002 by SPPC and Barrick was rejected by the PUCN on March 29, 2002. The PUCN indicated a desire for more information regarding transmission access, the definition of a new electric resource, and the computation of exit fees. Subsequently, a second application was filed and later withdrawn by Barrick. Barrick has filed a new application with the PUCN. Barrick could receive service from a new supplier as early as May 1, 2003. A hearing date on this application has not yet been scheduled. During May 2002, Rouse Fashion Show Management LLC, Coast Hotels and Casinos Inc., Station Casinos, Inc., Gordon Gaming Corporation, MGM Mirage, and Park Place Entertainment filed separate applications with the PUCN to exit the system of NPC and to purchase energy, capacity and ancillary services from a provider other than NPC. The loads of these customers aggregate 260 MW on peak. Hearings on the applications of all the customers except Park Place Entertainment were completed on July 19, and the PUCN issued its decision on July 31, 2002. In its decision, the PUCN approved the applications of these customers to choose an energy supplier other than NPC. The earliest any of these customers could have begun taking energy from an alternative provider was November 1, 2002. If all five customers whose applications were approved were to leave its system, NPC would incur an annual loss in revenue of $48 million, which would be offset by a reduction in costs, primarily for fuel and purchased power, of $46 million with the difference being paid by exit fees from the departing customers. These customers will also be responsible for their share of balances in NPC's deferred energy accounts until the time they leave and must continue to pay their share of these balances after they leave. For example, if all five customers whose applications were approved had left the system on November 1, 2002, their remaining share of NPC's previously approved deferred energy balance is estimated to have been $27 million. Additionally, these departing customers would be responsible for paying their share of the yet to be approved accumulated deferred energy balances from October 1, 2001 to their date of departure. They will also remain accountable to any rulings made by the District Court on legal actions brought in NPC's past deferred energy case. They could also benefit from any refunds that might be granted on power contracts under review with the FERC. A hearing on the application of Park Place Entertainment was held on August 2, 2002, and on August 12, 2002, the PUCN approved the application with terms and conditions similar to those described above for the aforementioned five customers. All of the customers approved for departure are addressing compliance items in their PUCN orders. To date, none of these customers has provided official notice of departure. Other customers are continuing to express an interest, and additional gaming properties, including Monte Carlo, Riviera, and Imperial Palace, have indicated intent to potentially procure energy sources from a new supplier. Any customer who departs NPC's system and later decides to return to NPC as their energy provider will be charged for their energy at a rate equivalent to NPC's incremental cost of service. A stipulation regarding the incremental cost of service tariff is currently pending before the PUCN. NEVADA POWER COMPANY ADDITIONAL FINANCE AUTHORITY (NPC) On April 26, 2002, Nevada Power filed with the PUCN an application seeking additional finance authority. In the application NPC asked for authority to issue secured long-term debt in an aggregate amount not to exceed $450 million through the period ending 2003. On June 19, 2002, the PUCN issued a Compliance Order, Docket No. 02-4037, authorizing NPC to issue $300 million of long-term debt. The PUCN order requires NPC, if it is able, to issue the $50 million of remaining authorized short-term debt, before it issues any long-term debt authorized by the order. Moreover, the order provides that, if NPC is able to issue short-term debt at any point prior to September 1, 2002 (whether or not the issuance of short-term debt actually occurs), the amount of long-term debt authorized by the order will be automatically reduced to $250 million. The PUCN order also provides that NPC will bear the burden of demonstrating that any financings undertaken pursuant to the order, including any determination made regarding the length of such commitment, the type of security or rate, is reasonable. Finally, the order requires that, until such time as the order's authorization expires (December 31, 2003), NPC must either receive the prior approval of the PUCN or reach an equity ratio of 42% before paying any dividends to SPR. If NPC achieves a 42% equity ratio prior to December 31, 2003, the dividend restriction ceases to have effect. On July 3, 2002, the Bureau of Consumer Protection of the Nevada Attorney General's Office filed a petition with the PUCN requesting that the hearing in Docket No. 02-4037 be reopened to allow for the introduction of additional evidence or for the PUCN to reconsider its decision granting NPC the authority to issue long-term debt. On September 11, 2002, the PUCN denied the petition to reopen the proceeding and rescinded the portion of its Compliance Order that had previously required NPC to immediately issue $50 million to $100 million of debt. 28 CALIFORNIA MATTERS (SPPC) RATE STABILIZATION PLAN SPPC serves approximately 44,500 customers in California. On June 29, 2001, SPPC filed with the California Public Utilities Commission (CPUC) a Rate Stabilization Plan, which includes two phases. Phase One, which was also filed June 29, 2001, is an emergency electric rate increase of $10.2 million annually or 26%. If granted, the typical residential monthly electric bill for a customer using 650 kilowatt-hours would increase from approximately $47.12 to $60.12. On August 14, 2001, a pre-hearing conference was held, and a procedural order was established. On September 27, 2001, the Administrative Law Judge issued an order stating that no interim or emergency relief could be granted until the end of the "rate freeze" period mandated by the California restructuring law for recovery of stranded costs. In accordance with the judge's request, on October 26, 2001, SPPC filed an amendment to its application declaring the rate freeze period to be over. On December 5 and 11, 2001, hearings were held and on January 11, 2002 and January 25, 2002 opening briefs and reply briefs were filed. On July 17, 2002, the CPUC approved the requested 2-cent per kilowatt-hour surcharge, subject to refund and interest pending the outcome of Phase Two. The increase of $10 million or 26% is applicable to all customers except those eligible for low-income and medical-needs rates and went into effect July 18, 2002. Phase Two of the Rate Stabilization Plan was filed with the CPUC on April 1, 2002, and includes a general rate case and requests the CPUC to reinstate the Energy Cost Adjustment Clause, which would allow SPPC to file for periodic rate adjustments to reflect its actual costs for wholesale energy supplies. Phase Two also includes a proposal to terminate the 10% rate reduction mandated by AB 1890, but does not include a performance -based rate-making proposal. This request was for an additional overall increase in revenues of 17.1%, or $8.9 million annually. Hearings are scheduled for February 25 through March 3, 2003, and a decision by the CPUC is expected in the third quarter of 2003. CALIFORNIA ASSEMBLY BILL 1235 (SPPC) On September 24, 2002, the Governor of California signed into law Assembly Bill 1235 (AB 1235), which allows the transfer of hydroelectric plants along the Truckee River from SPPC to the Truckee Meadows Water Authority (TMWA). AB 1235 effectively amends previous California legislation (AB 6X) that prevented until 2006 private utilities from selling any power plants that provide energy to California customers. AB 1235 provides an exemption for the four "run-of-the-river" hydroelectric plants that SPPC sold to TMWA as part of the sale of its water business in June 2001. AB 1235 was effective September 24, 2002, and the process to transfer the plants from SPPC to TMWA has begun. The CPUC must now review and approve the transfer of the plants. FERC MATTERS (SPPC, NPC) FERC 206 COMPLAINTS In December 2001, the Utilities filed ten wholesale purchased power complaints with the FERC under Section 206 of the Federal Power Act seeking their review of certain forward power purchase contracts that the Utilities entered into prior to the price caps established by the FERC during the western United States utility crisis. The Utilities believe the prices under these purchased power contracts are unjust and unreasonable. The FERC ordered the case set for hearing and assigned an administrative law judge. A primary issue is whether or not the dysfunctional short-term market, which was previously declared by the FERC, impacted the forward market. The Utilities negotiated a settlement with Duke Energy Trading and Marketing and have engaged in bilateral settlement discussions with other respondents as well. Written direct and rebuttal testimony have been filed by the parties that have not negotiated settlements with the Utilities. Hearings concluded on October 24, 2002, and a draft decision is expected in December 2002. At this time, the Utilities are not able to predict the outcome of a decision in this matter. OPEN ACCESS TRANSMISSION TARIFF On September 27, 2002, the Utilities filed with the FERC a revised Open Access Transmission Tariff. The purpose of the filing was to implement changes that are required to implement retail open access in Nevada. The Utilities have requested the changes to become effective November 1, 2002, the date retail access is scheduled to commence in Nevada in accordance with provisions of AB 661, passed in the 2001 session of the Nevada Legislature. NOTE 10. DERIVATIVES AND HEDGING ACTIVITIES (SPR, NPC, SPPC) Effective January 1, 2001, SPR, SPPC, and NPC adopted Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS No. 138, both issued by the Financial Accounting Standards Board. As amended, SFAS No. 133 requires that an entity recognize all derivatives as either 29 assets or liabilities in the statement of financial position, measure those instruments at fair value, and recognize changes in the fair value of the derivative instruments in earnings in the period of change unless the derivative qualifies as an effective hedge. SPR's and the Utilities' objective in using derivatives is to reduce exposure to energy price risk and interest rate risk. Energy price risks result from activities that include the generation, procurement and marketing of power and the procurement and marketing of natural gas. Derivative instruments used to manage energy price risk include forwards, options, and swaps. These contracts allow the Utilities to reduce the risks associated with volatile electricity and natural gas markets. Derivatives used to manage interest rate risk include interest rate swaps designed to moderate exposure to interest-rate changes and lower the overall cost of borrowing. On April 1, 2002, SPR paid $9.5 million to terminate an interest rate swap related to $200 million of SPR floating rate notes maturing April 20, 2003. At September 30, 2002, the fair value of the derivatives resulted in the recording of $74 million, $57 million and $17 million in risk management assets and $153 million, $64 million and $89 million in risk management liabilities in the Consolidated Balance Sheets of SPR, NPC and SPPC, respectively. Due to deferred energy accounting under which the Utilities operate, regulatory assets and liabilities are established to the extent that electricity and natural gas derivative gains and losses are recoverable or payable through future rates. Accordingly, at September 30, 2002, $78 million, $7 million and $71 million in net risk management regulatory assets were recorded in the Consolidated Balance Sheets of SPR, NPC, and SPPC, respectively. In addition, for the nine months ended September 30, 2002, the unrealized gains and losses resulting from the change in the fair value of derivatives designated and qualifying as cash flow hedges for SPR, NPC, and SPPC were recorded in Other Comprehensive Income. Such amounts are reclassified into earnings when the related transactions are settled or terminate. Accordingly, $1.3 million and $5.1 million relating to SPR's terminated interest rate swap were reclassified into earnings during the three- and nine-month periods ended September 30, 2002, respectively. The effects of SFAS No. 133 on comprehensive income and the components thereof at September 30, 2002, and 2001, are as follows (in thousands):
SPR NPC SPPC ------------- ------------- ------------ Net Loss for the nine months ended September 30, 2002 $ (268,024) $ (216,025) (1) $ (12,389) Change in market value of risk management assets and liabilities as of September 30, 2002, net of taxes 2,726 (403) (191) ------------- ------------- ------------ Total Comprehensive Loss for the nine months ended September 30, 2002 $ (265,298) $ (216,428) $ (12,580) ============= ============= ============ Net Income for the nine months ended September 30, 2001 $ 50,965 $ 56,459 (2) $ 36,572 Cumulative effect upon adoption of change in accounting principle, January 1, 2001, net of taxes (1,923) 444 212 Change in market value of risk management assets and liabilities as of September 30, 2001, net of taxes (5,048) 230 109 ------------- ------------- ------------ Total Comprehensive Income for the nine months ended September 30, 2001 $ 43,994 $ 57,133 $ 36,893 ============= ============= ============
(1) Does not include NPC's equity in SPR's losses of $(51,999). (2) Does not include NPC's equity in SPR's losses of $(5,494). NOTE 11. COMMITMENTS AND CONTINGENCIES (SPR, NPC, SPPC) NEVADA POWER COMPANY AND SIERRA PACIFIC POWER COMPANY In early May of 2002, Enron Power Marketing Inc. ("Enron"), Morgan Stanley Capital Group Inc. ("MSCG"), Reliant Energy Services, Inc. and several smaller suppliers terminated their power deliveries to NPC and SPPC. These terminating suppliers asserted their contractual right under the WSPP agreement to terminate deliveries based upon the Utilities' alleged failure to provide adequate assurances of their performance under the WSPP agreement to any of their suppliers. Each of these 30 terminating suppliers has asserted, or has indicated that it will assert claims for liquidated damages against the Utilities under the terminated power supply contracts. On June 5, 2002, Enron filed suit in its bankruptcy case in the Bankruptcy Court for the Southern District of New York asserting claims for liquidated damages related to the termination of its power supply agreements with the Utilities of approximately $216 million and $93 million against NPC and SPPC, respectively. NPC and SPPC have both filed claims in the Bankruptcy Court alleging, among other things, that NPC and SPPC were fraudulently induced to enter into the agreements with Enron. Enron's claims are also subject to the Utilities' defense, as raised in the Utilities' motions to dismiss and or to stay all proceedings, that such claims are already at issue in the Utilities' FERC proceeding against Enron and others under Section 206 of the Federal Power Act challenging the contract prices of the terminated power supply agreements. Enron initially filed a motion for partial summary judgment to require the Utilities to make immediate payment of the full amount of Enron's claim, pending final resolution of the lawsuit. Enron subsequently filed another motion for summary judgment seeking final payment of its damages claim. Hearings, including arguments regarding the issue of FERC's primary jurisdiction over the contract claims, were conducted in September, October, and early November 2002. On November 14, 2002, the judge is expected to rule on the Utilities' motion to dismiss or stay until the FERC rules on the Utilities' Section 206 filing. If the judge decides not to stay Enron's lawsuit pending the outcome of the FERC hearings, the judge would then schedule additional arguments with respect to Enron's motion for summary judgment. At this time, the outcome of a decision in this matter cannot be predicted. An adverse decision on Enron's motion for summary judgment or an adverse decision in the lawsuit would have a material adverse affect on the financial condition and liquidity of SPR and the Utilities and would render their ability to continue to operate outside of bankruptcy uncertain. In addition, on September 5, 2002, MSCG filed a Demand for Arbitration pursuant to the mediation and arbitration procedures of the WSPP agreement seeking a termination payment from NPC of approximately $25 million under its terminated power supply agreements with NPC. If this claim is not resolved by arbitration, NPC expects that MSCG will commence a lawsuit to recover liquidated damages under the terminated contract. On September 30, 2002, El Paso Merchant Energy Group ("EPME") notified NPC that it was terminating all transactions entered into with NPC under the WSPP agreement. On October 8, 2002, NPC received a letter from EPME seeking a termination payment of approximately $36 million with respect to the terminated WSPP agreement transactions. At the present time, NPC disagrees with EPME's calculation, and expects that net gains and losses relating to the terminated transactions, including a delayed payment amount of approximately $19 million owed to EPME for power deliveries through September 15, 2002, will result in a net payment due to NPC. In connection with the claims by these energy suppliers, the Utilities established reserves, included in their Balance Sheets in "Contract termination reserves," totaling approximately $316 million, and, pursuant to the deferred energy accounting provisions of AB 369, NPC and SPPC added approximately $229 million and $82 million, respectively, to their deferred energy balances for recovery in rates in future periods. NEVADA POWER COMPANY The Grand Canyon Trust and Sierra Club filed a lawsuit in the U.S. District Court, District of Nevada, in February 1998, against the owners (including NPC) of the Mohave Generation Station ("Mohave"), alleging violations of the Clean Air Act regarding emissions of sulfur dioxide and particulates. An additional plaintiff, National Parks and Conservation Association, later joined the suit. The plant owners and plaintiffs have had numerous settlement discussions and filed a proposed settlement with the court in October 1999. The consent decree, approved by the court in November 1999, established emission limits for sulfur dioxide and opacity and required installation of air pollution controls for sulfur dioxide, nitrogen oxides and particulate matter. The new emission limits must be met by January 1, 2006 and April 1, 2006 for the first and second units respectively. The estimated cost of new controls is $395 million. As a 14% owner in the Mohave Station, NPC's cost could be $55 million. NPC's ownership interest in Mohave comprises approximately 10% of NPC's peak generation capacity. Southern California Edison (SCE) is the operating partner of Mohave. On May 17, 2002, SCE filed with the California Public Utilities Commission (CPUC) an application to address the future disposition of SCE's share of Mohave. Mohave obtains all of its coal supply from a mine in northeast Arizona on lands of the Navajo Nation and the Hopi Tribe (the Tribes). This coal is delivered from the mine to Mohave by means of a coal slurry pipeline, which requires water that is obtained from groundwater wells located on lands of the Tribes in the mine vicinity. Due to the lack of progress in negotiations with the Tribes and other parties to resolve several coal and water supply issues, SCE's application states that it appears that it probably will not be possible for SCE to extend Mohave's operations beyond 2005. Due to the uncertainty over a post-2005 coal supply, SCE and the other Mohave co-owners have been prevented from starting to install extensive pollution control equipment that must be put in place if Mohave's operations are extended past 2005. NPC is currently evaluating and analyzing all of its options with regard to the Mohave project. 31 In May 1997, the Nevada Division of Environmental Protection (NDEP) ordered NPC to submit a plan to eliminate the discharge of Reid Gardner Station wastewater to groundwater. The NDEP order also required a hydrological assessment of groundwater impacts in the area. In June 1999, NDEP determined that wastewater ponds had degraded groundwater quality. In August 1999, NDEP issued a discharge permit to Reid Gardner Station and an order that requires all wastewater ponds to be closed or lined with impermeable liners over the next 10 years. This order also required NPC to submit a Site Characterization Plan to NDEP to ascertain impacts. This plan is under review by NDEP. After approval, an estimate of remediation costs will be determined by NPC. New pond construction and lining costs are estimated at $15 million. At the Reid Gardner Station, the NDEP has determined that there is additional groundwater contamination that resulted from oil spills at the facility. NDEP has required submitting a corrective action plan. The extent of contamination has been determined and remediation is occurring at a modest rate. A hydro-geologic evaluation of the current remediation was completed and a vacuum enhanced extraction remediation system will be constructed in the first quarter of 2003 at an estimated cost of approximately $150,000. In May 1999, NDEP issued an order to eliminate the discharge of NPC's Clark Station wastewater to groundwater. The order also required a hydrological assessment of groundwater impacts in the area. This assessment, submitted to NDEP in February 2001, warranted a Corrective Action Plan, which was approved in June 2002. Remediation costs are expected to be approximately $100,000. In addition to remediation, NPC will spend $789,000 to line existing ponds. After review and approval of the Corrective Action Plan by NDEP, NPC will implement remediation. In July 2000, NPC received a request from the EPA for information to determine the compliance of certain generation facilities at the Clark Station with the applicable State Implementation Plan. In November 2000, NPC and the Clark County Health District entered into a Corrective Action Order requiring, among other steps, capital expenditures at the Clark Station totaling approximately $3 million. In March 2001, the EPA issued an additional request for information that could result in remediation beyond that specified in the November 2000 Corrective Action Order. If the EPA prevails, capital expenditures and temporary outages of four of Clark Station's generation units could be required. Additionally, depending on the time of year that the compliance activity and corresponding generation outage would occur, the incremental cost to purchase replacement energy could be substantial. Nevada Electric Investment Company (NEICO), a wholly owned subsidiary of NPC, owns property in Wellington, Utah, which was the site of a coal washing and load out facility. The site now has a reclamation estimate supported by a bond of $4 million with the Utah Division of Oil and Gas Mining. The property was under contract for sale and the contract required the purchaser to provide $1.3 million in escrow towards reclamation. However, the sales contract was terminated and NEICO took title to the escrow funds. The property is currently leased with the intention to reclaim coal fines with subsequent reduction to the reclamation bond. SIERRA PACIFIC POWER COMPANY In September 1994, Region VII of EPA notified SPPC that it was being named as a potentially responsible party (PRP) regarding the past improper handling of Polychlorinated Biphenyls (PCBs) by PCB Treatment, Inc., located in Kansas City, Kansas, and Kansas City, Missouri (the Sites). The EPA is requesting that SPPC voluntarily pay an undefined, pro rata share of the ultimate clean-up costs at the Sites. A number of the largest PRP's formed a steering committee, which is chaired by SPPC. The responsibility of the Committee is to direct clean-up activities, determine appropriate cost allocation, and pursue actions against recalcitrant parties, if necessary. The EPA issued an administrative order on consent requiring signatories to perform certain investigative work at the Sites. The steering committee retained a consultant to prepare an analysis regarding the Sites. The Site evaluations have been completed. EPA is developing an allocation formula to allocate the remediation costs. SPPC has recorded a preliminary liability for the Sites of $650,000 of which approximately $136,000 has been spent through September 30, 2002. Once evaluations are completed, SPPC will be in a better position to estimate and record the ultimate liabilities for the Sites. SIERRA PACIFIC RESOURCES On September 30, 2002, a lawsuit was filed by two individuals in the District Court for Clark County, Nevada, on behalf of themselves and all holders of securities of SPR, against SPR and its directors named individually. The lawsuit alleges that the defendants violated their fiduciary duties to the securityholders as a result of SPR's response to letters from the Southern Nevada Water Authority ("SNWA") in which SNWA stated that it was prepared to enter into negotiations to acquire NPC's assets and assume certain of NPC's indebtedness. The lawsuit, which seeks certification as a class action, requests that the court: (1) declare that the directors have breached their fiduciary duties, (2) enjoin the defendants to undertake all reasonable efforts to maximize shareholder value including mandating due consideration of the SNWA proposal, (3) order the defendants to permit a stockholders' committee to ensure a fair procedure in connection with any disposition or retention of 32 assets, and (4) if SNWA's purported offer is withdrawn due to the actions or inactions of the defendants, to award compensatory and/or punitive damages in an unspecified amount against the defendants. Although SPR and its directors intend to vigorously defend against the lawsuit, SPR cannot predict the outcome at this time. OTHER SUBSIDIARIES OF SPR LOS, a wholly owned subsidiary of SPR, owns property in North Lake Tahoe, California, which is leased to independent condominium owners. The property has both soil and groundwater petroleum contaminate resulting from an underground fuel tank that has been removed from the property. Additional contaminate from a third party fuel tank on the property has also been identified and is undergoing remediation. A closure request is pending Lahontan Regional Water Quality Control Board approval. Estimated future remediation costs are not expected to be significant. In April 2000 Sierra Touch America, LLC, a partnership between Sierra Pacific Communications (SPC) and Touch America, was formed to construct a fiber optic line between Salt Lake City, Utah and Sacramento, California. On September 9, 2002, SPC purchased and leased certain telecommunications and fiber optic assets from Touch America in exchange for SPC's partnership units in Sierra Touch America and the execution of a $35 million promissory note for a total of $48.5 million. The assets are currently under construction and are scheduled for completion in May 2003. Of the $48.5 million total, $32.5 million relates to the purchase of a conduit from Sacramento to Salt Lake City, additional conduit in the Reno, Nevada metropolitan area, and real property in Utah. $16 million of the total was for the lease of two conduits from Reno to Spanish Fork, Utah and the lease of 60 strands of fiber from Sacramento to Salt Lake City. The promissory note accrues interest at 8% per annum. The first of twelve monthly payments of $3.3 million will commence on July 31, 2003 and continue until June 30, 2004, at which time all outstanding amounts will be due and payable. The promissory note is secured by all of SPC's assets, and prepayments will shorten the length of the loan, but not reduce the installment payments. Also, on September 11, 2002, SPC entered into an agreement to sell to a telecommunications carrier for $20 million the Sacramento to Salt Lake City conduit acquired from Touch America, and will convey all rights to the conduit when construction is completed in May 2003. NOTE 12. CHANGE IN ACCOUNTING FOR GOODWILL (SPR, NPC, SPPC) SFAS No. 142, adopted January 1, 2002, changed the accounting for goodwill from an amortization method to one requiring at least an annual review for impairment. Upon adoption, SPR ceased amortizing goodwill. SPR's Consolidated Balance Sheet as of September 30, 2002, includes approximately $325.6 million of goodwill resulting from the July 28, 1999 merger between SPR and NPC. Approximately $19.6 million of amortization of this goodwill has been deferred as a regulatory asset. The PUCN stipulation approving the merger allows for future recovery of this goodwill in rates charged to customers of SPR's regulated utility subsidiaries, NPC and SPPC, provided that NPC and SPPC demonstrate that merger savings exceed merger costs. The amount and timing of the recovery of this goodwill will be determined by the outcome of general rate cases expected to be filed by the Utilities with the PUCN in late 2003. SPR's Consolidated Balance Sheet as of December 31, 2001, also included approximately $6.2 million of goodwill related to unregulated operations. SFAS No. 142 provides that an impairment loss shall be recognized if the carrying value of each reporting unit's goodwill exceeds its fair value. For purposes of testing goodwill for impairment, a discounted cash flow model was used to determine the fair value of each reporting unit of SPR's unregulated operations. The reporting units included in SPR's unregulated operations evaluated for goodwill impairment were Lands of Sierra (LOS), Sierra Pacific Communications (SPC), Tuscarora Gas Pipeline Company (TGPC), and "Energy" (a reporting unit consisting of Sierra Energy Company dba e-three, Nevada Electric Investment Company, and Sierra Pacific Energy Company). As a result of the impairment testing, which included revenue forecasts and appraisal of assets, SPR recorded a transitional goodwill impairment charge of approximately $1.7 million ($1.6 million, net of applicable taxes) as a cumulative effect of a change in accounting principle on SPR's Condensed Consolidated Statements of Operations for the nine months ended September 30, 2002. The goodwill impairment recognized by reporting unit was approximately $131,000, $40,000 and $1.5 million for LOS, SPC and "Energy," respectively. Goodwill assigned to TGPC was determined not to be impaired. The changes in the carrying amount of goodwill for the nine-month period ended September 30, 2002 are as follows: 33
REGULATED UNREGULATED (IN $000'S) OPERATIONS OPERATIONS TOTAL -------------- ----------- ------------- Balance as of January 1, 2002 $ 305,982 $ 6,163 $ 312,145 Impairment loss - (1,704) (1,704) -------------- ------------ ------------- Balance as of September 30, 2002 $ 305,982 $ 4,459 $ 310,441 ============== ============ =============
A reconciliation of SPR's previously reported net (losses) income and (losses) earnings per share to the amounts adjusted for the adoption of SFAS No 142 net of the related income tax effect follows:
(DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, ----------------------- ------------------------- 2002 2001 2002 2001 --------- --------- ----------- --------- Net (losses) earnings: Reported net (loss) earnings $ 79,374 $ 80,409 $ (268,024) $ 50,965 Add back amortization of goodwill, net of tax - 48 - 144 --------- --------- ----------- --------- Adjusted net (losses) earnings 79,374 80,457 (268,024) 51,109 Add back cumulative effect of change in accounting principle, net of tax - - 1,566 - --------- --------- ----------- --------- Adjusted (losses) earnings before cumulative effect of change in accounting principle $ 79,374 $ 80,457 $ (266,458) $ 51,109 ========= ========= =========== ========= BASIC AND DILUTED (LOSSES) EARNINGS PER SHARE: Reported (losses) earnings per share $ 0.89 $ 0.62 Add back amortization of goodwill, net of tax - - - - --------- --------- ----------- --------- Adjusted (losses) earnings per share - 0.89 - 0.62 Add back cumulative effect of change in accounting principle, net of tax - - 0.01 - --------- --------- ----------- --------- Adjusted (losses) earnings per share before cumulative effect of change in accounting principle $ - $ 0.89 $ 0.01 $ 0.62 ========= ========= =========== =========
NOTE 13. PINON PINE (SPR, SPPC) SPPC, through its wholly owned subsidiaries, Pinon Pine Corp., Pinon Pine Investment Co., and GPSF-B, owns Pinon Pine Company, L.L.C. (the "LLC"). The LLC was formed to take advantage of federal income tax credits associated with the alternative fuel (syngas) produced by the coal gasifier available under Section 29 of the Internal Revenue Code. The entire project, which includes an LLC-owned gasifier and an SPPC-owned power island and post-gasification facility to partially cool and clean the syngas, is referred to collectively as the Pinon Pine Power Project ("Pinon Pine"). Construction of Pinon Pine was completed in June 1998. Pinon Pine is a project co-funded by the Department of Energy (DOE) under an agreement between SPPC and DOE that expired December 31, 2000. Through December 31, 2001, the DOE funded $167 million for construction, operation, and maintenance of the project. Included in the Consolidated Balance Sheets of SPR and SPPC is the net book value of the gasifier and related assets, which is approximately $105 million as of December 31, 2001, of which $50 million is included in Utility Plant, and $55 million is included in Investments in subsidiaries and other property. To date, SPPC has not been successful in obtaining sustained operation of the gasifier. In 2001 SPPC retained an independent engineering consulting firm, to complete a comprehensive study of the Pinon Pine gasification plant. The scope of the study included evaluation of the potential modifications required to make the facility operational and reliable using several technology scenarios. The evaluation of each scenario included an estimate of the additional capital expenditures necessary for reliable operation of the facility, and the risks associated with that technology. 34 SPPC received a draft report of the study in October 2002. The results of the study identified a number of potential modifications to the facility each with varying degrees of technical risk and cost. Modifications considered to provide the highest probability for successful operation of the facility generally were also estimated to be the highest cost options. SPPC is reviewing the various options outlined in the study. If after evaluating the options presented in the draft report, SPPC decides not to pursue modifications intended to make the facility operational, SPPC intends to seek recovery, net of salvage, through regulated rates in its next general rate case based, in part, on the PUCN's approval of Pinon Pine as a demonstration project in an earlier resource plan. However, if SPPC is unsuccessful in obtaining recovery, there could be a material adverse effect on SPPC's and SPR's financial condition and results of operations. NOTE 14. SUBSEQUENT EVENTS (SPPC) On October 29, 2002, SPPC paid a common stock dividend of $25 million to its parent, SPR. On November 8, 2002, a dividend of $975,000 ($0.4875 per share) was declared on SPPC's preferred stock. The dividend is payable on December 1, 2002, to holders of record as of November 22, 2002. On November 8, 2002, the Board of Directors of SPPC voted to declare a dividend to SPR of up to $25 million payable on or before February 1, 2003. 35 ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FORWARD-LOOKING STATEMENTS AND RISK FACTORS 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 (NPC), or Sierra Pacific Power Company (SPPC) to differ materially from those contemplated in any forward-looking statement include, among others, the following: (1) unfavorable rulings in rate cases to be filed by NPC and SPPC (the "Utilities") with the Public Utilities Commission of Nevada (PUCN), including the periodic applications to recover costs for fuel and purchased power that have been recorded by the Utilities in their deferred energy accounts and deferred natural gas recorded by SPPC for its gas distribution business; (2) the outcome of the Utilities' pending lawsuits in Nevada state court seeking to reverse portions of the PUCN's orders denying the recovery of deferred energy costs, including the outcome of petitions filed by the Bureau of Consumer Protection of the Nevada Attorney General's Office seeking additional disallowances; (3) the ability of SPR, NPC and SPPC to access the capital markets to support their requirements for working capital, including amounts necessary to finance deferred energy costs, construction costs and the repayment of maturing debt, particularly in the event of additional unfavorable rulings by the PUCN, a further downgrade of the current debt ratings of SPR, NPC or SPPC and/or adverse developments with respect to NPC's or SPPC's power and fuel suppliers; (4) whether suppliers, such as Enron, which have terminated their power supply contracts with NPC and/or SPPC will be successful in pursuing their claims against the Utilities for liquidated damages under their power supply contracts, and whether Enron will be successful in its lawsuit against NPC and SPPC; (5) whether SPR, NPC and SPPC will be able to maintain sufficient stability with respect to their liquidity and relationships with suppliers to be able to continue to operate outside of bankruptcy; (6) whether current suppliers of purchased power, natural gas or fuel to NPC or SPPC will continue to do business with NPC or SPPC or will terminate their contracts and seek liquidated damages from the respective Utility; (7) whether NPC and SPPC will be able, either through Federal Energy Regulatory Commission ("FERC") proceedings or negotiation, to obtain lower prices on their longer-term purchased power contracts entered into during 2000 and 2001 that are priced above current market prices for electricity; (8) whether the PUCN will issue favorable orders in a timely manner to permit the Utilities to borrow money and issue additional securities to finance the Utilities' operations and to purchase power and fuel necessary to serve their respective customers; (9) whether SPR, NPC, and SPPC will have a significant funding obligation for 2002 in connection with their currently underfunded employee pension plan; (10) whether the Utilities will need to purchase additional power on the spot market to meet unanticipated power demands (for example, due to unseasonably hot weather) and whether suppliers will be willing to sell such power to the Utilities in light of their weakened financial condition; (11) wholesale market conditions, including availability of power on the spot market, which affect the prices the Utilities have to pay for power as well as the prices at which the Utilities can sell any excess power; 36 (12) the effect of a non-binding advisory question, which was included on the ballot in Clark County, Nevada in November 2002 and was approved by a 57% to 43% vote, asking voters whether "the Nevada Legislature should take appropriate action to enable the electrical energy provider for southern Nevada to be a locally controlled, not for profit public utility;" (13) the outcome of the proposal by the Southern Nevada Water Authority to enter into negotiations to acquire NPC; (14) the effect that any future terrorist attacks may have on the tourism and gaming industries in Nevada, particularly in Las Vegas, as well as on the economy in general; (15) the effect of existing or future Nevada, California or federal legislation or regulations affecting electric industry restructuring, including laws or regulations which could allow additional customers to choose new electricity suppliers or change the conditions under which they may do so; (16) unseasonable weather and other natural phenomena, which can have potentially serious impacts on the Utilities' ability to procure adequate supplies of fuel or purchased power to serve their respective customers and on the cost of procuring such supplies; (17) industrial, commercial and residential growth in the service territories of the Utilities; (18) the loss of any significant customers; (19) changes in the business of major customers, particularly those engaged in gold mining or gaming, which may result in changes in the demand for services of the Utilities, including the effect on the Nevada gaming industry of the opening of additional Indian gaming establishments in California and other states; (20) changes in environmental regulations, tax or accounting matters or other laws and regulations to which the Utilities are subject; (21) future economic conditions, including inflation or deflation rates and monetary policy; (22) financial market conditions, including changes in availability of capital or interest rate fluctuations; (23) unusual or unanticipated changes in normal business operations, including unusual maintenance or repairs; and (24) employee workforce factors, including changes in collective bargaining unit agreements, strikes or work stoppages. Other factors and assumptions not identified above may also have been involved in deriving these forward-looking statements, and the failure of those other assumptions to be realized, as well as other factors, may also cause actual results to differ materially from those projected. SPR, NPC and SPPC assume no obligation to update forward-looking statements to reflect actual results, changes in assumptions or changes in other factors affecting forward-looking statements. CRITICAL ACCOUNTING POLICIES The following items represent critical accounting policies that under different conditions or using different assumptions could have a material effect on the financial condition, liquidity and capital resources of SPR and the Utilities. Regulatory Accounting The Utilities' rates are currently subject to the approval of the PUCN and are designed to recover the cost of providing generation, transmission and distribution services. As a result, the Utilities qualify for the application of Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation", issued by the Financial Accounting Standards Board (FASB). This statement recognizes that the rate actions of a regulator can provide reasonable assurance of the existence of an asset and requires the capitalization of incurred costs that would otherwise be charged to expense where it is probable that future revenue will be provided to recover these costs. SFAS No. 71 prescribes the method to be used to record the financial transactions of a regulated entity. The criteria for applying SFAS No. 71 include the following: (i) rates are set by an independent third party regulator, (ii) approved rates are intended to recover the specific costs of the 37 regulated products or services, and (iii) rates that are set at levels that will recover costs can be charged to and collected from customers. Two of the most significant financial statement effects of regulatory accounting are deferred energy accounting and accounting for derivatives and hedging activities, which are discussed below. Deferred Energy Accounting On April 18, 2001, the Governor of Nevada signed into law Assembly Bill 369 (AB 369). The provisions of AB 369, which are described in greater detail in "Regulation and Rate Proceedings," later, include, among others, a reinstatement of deferred energy accounting for fuel and purchased power costs incurred by electric utilities. In accordance with the provisions of SFAS No. 71, the Utilities implemented deferred energy accounting on March 1, 2001, for their respective electric operations. Under deferred energy accounting, to the extent actual fuel and purchased power costs exceed fuel and purchased power costs recoverable through current rates, that excess is not recorded as a current expense on the statement of operations but rather is deferred and recorded as an asset on the balance sheet. Conversely, a liability is recorded to the extent fuel and purchased power costs recoverable through current rates exceed actual fuel and purchased power costs. These excess amounts are reflected in adjustments to rates and recorded as revenue or expense in future time periods, subject to PUCN review. AB 369 provides that the PUCN may not allow the recovery of any costs for purchased fuel or purchased power "that were the result of any practice or transaction that was undertaken, managed or performed imprudently by the electric utility." In reference to deferred energy accounting, AB 369 specifies that fuel and purchased power costs include all costs incurred to purchase fuel, to purchase capacity, and to purchase energy. The Utilities also record, and are eligible under the statute to recover, a carrying charge on such deferred balances. As described in more detail under "Regulatory Matters - Nevada Matters - Nevada Power Company Deferred Energy Case" below, on November 30, 2001, NPC filed an application with the PUCN seeking to clear deferred balances for purchased fuel and power costs accumulated between March 1, 2001 and September 30, 2001. The application sought to establish a rate to clear accumulated purchased fuel and power costs of $922 million and spread the cost recovery over a period of not more than three years. On March 29, 2002, the PUCN issued its decision on the deferred energy application, disallowing $434 million of deferred purchased fuel and power costs and $10 million in carrying charges, and allowing NPC to collect the remaining $478 million over three years beginning April 1, 2002. As a result of this disallowance, NPC wrote off $465 million of deferred energy costs and related carrying charges, the two major national rating agencies immediately downgraded the credit rating on SPR's, NPC's and SPPC's debt securities (followed by further downgrades late in April), and the market price of SPR's common stock fell substantially. As described in more detail under "Regulatory Matters - Nevada Matters - Sierra Pacific Power Company Deferred Energy Case" below, SPPC filed an application with the PUCN seeking to clear its deferred balances for purchased fuel and power costs accumulated between March 1, 2001 and November 30, 2001. The application sought to establish a rate to clear accumulated purchased fuel and power costs of $205 million and spread the cost recovery over a period of not more than three years. On May 28, 2002, the PUCN issued its decision on SPPC's deferred energy application, disallowing $53 million of deferred purchased fuel and power costs and $2 million in carrying charges, and allowing SPPC to collect the remaining $150 million over three years beginning June 1, 2002. As a result of this decision, SPPC wrote off $55 million of disallowed deferred energy costs and related carrying charges. Both Utilities have continued to be entitled under AB 369 to utilize deferred energy accounting for their electric operations. Because of contracts entered into during the Western energy crisis in 2001 to assure adequate supplies of electricity for their customers, the Utilities have continued to incur fuel and purchased power costs in excess of amounts they are permitted to recover in current rates. As a result, during the nine months ended September 30, 2002, both Utilities continued to record additional amounts in their deferral of energy costs accounts. If not for deferred energy accounting during the first nine months of 2002, SPR's, NPC's and SPPC's results of operations, financial condition, liquidity and capital resources would have been adversely affected. For example, without the deferred energy accounting provisions of AB 369, the reported net losses of SPR, NPC, and SPPC for the nine months ended September 30, 2002 of ($268.0) million, ($216.0) million(1), and ($12.4) million would have been (net of income tax) reported as net losses of ($469.0) million, ($370.8) million(1), and ($58.6) million, respectively. Similarly, the reported net income of SPR, NPC, and SPPC for the quarter ended September 30, 2002 of $79.4 million, $79.3 million(1), and $12.6 million would have been (net of income tax) reported as net income of $52.4 million, $51.2 million(1), and $13.7 million, respectively. A significant disallowance by the PUCN of costs currently deferred could have a material adverse affect on the future financial position, results of operations, and liquidity of ---------------------------- (1) Excludes equity in losses of SPR 38 SPR, NPC and SPPC. See the Form 10-K for the year ended December 31, 2001 for a more detailed discussion of deferred energy accounting. Accounting for Derivatives and Hedging Activities Effective January 1, 2001, SPR, SPPC, and NPC adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS No. 138. As amended, SFAS No. 133 requires that an entity recognize all derivative instruments as either assets or liabilities in the statement of financial position and measure the instruments at fair value. In order to manage loads, resources and energy price risk, the Utilities buy fuel and power under forward contracts. In addition to forward fuel and power purchase contracts, the Utilities also use options and swaps to manage price risk. All of these instruments are considered to be derivatives under SFAS No. 133. The risk management assets and liabilities recorded in the balance sheets of the Utilities and SPR are primarily comprised of the fair value of these forward fuel and power purchase contracts and other energy related derivative instruments. Fuel and purchased power costs are subject to deferred energy accounting. Accordingly, the energy related risk management assets and liabilities and the corresponding unrealized gains and losses (changes in fair value) are offset with a regulatory asset or liability rather than recognized in the statements of income and comprehensive income. Upon settlement of a derivative instrument, actual fuel and purchased power costs are recognized if they are currently recoverable or deferred if they are recoverable or payable through future rates. The fair values of the forward contracts and swaps are determined based on quotes obtained from independent brokers and exchanges. The fair values of options are determined using a pricing model which incorporates assumptions such as the underlying commodity's forward price curve, time to expiration, strike price, interest rates, and volatility. The use of different assumptions and variables in the model could have a significant impact on the valuation of the instruments. SPR and the Utilities have other non-energy related derivative instruments such as interest rate swaps. The transition adjustment resulting from the adoption of SFAS No. 133 related to these types of derivative instruments was reported as the cumulative effect of a change in accounting principle in Other Comprehensive Income. Additionally, the changes in fair values of these non-energy related derivatives are also reported in Other comprehensive income until the related transactions are settled or terminate, at which time the amounts are reclassified into earnings. On April 1, 2002, SPR paid $9.5 million to terminate an interest rate swap of which $1.3 million and $5.1 million, respectively, were reclassified into earnings during the three- and nine-month periods ended September 30, 2002. No other amounts were reclassified into earnings during the three- and nine-month periods ended September 30, 2002 and 2001. See Note 22 of "Notes to Financial Statements" in the Form 10-K for the year ended December 31, 2001, and Note 10 of "Notes to Condensed Consolidated Financial Statements" and "Item 3 - Quantitative and Qualitative Disclosures about Market Risk" in this Report for additional information regarding derivatives and hedging activities. Provision for Uncollectible Accounts The Utilities reserve for doubtful accounts based on past experience writing off uncollectible customer accounts. The collapse of the energy markets in California, and the subsequent bankruptcy of the California Power Exchange and the financial difficulties of the Independent System Operator, resulted in the Utilities reserving for outstanding receivables for power purchases by these two entities of $19.9 million and $1.5 million (before taxes) for NPC and SPPC, respectively, for 2001. The weakening economy and the disruption to the leisure travel industry after September 11th also impacted the Utilities' customer delinquencies in 2001. As of December 31, 2001, additional amounts of $14.8 million and $6.1 million were reserved for delinquent retail customer accounts of NPC and SPPC, respectively. During the nine months ended September 30, 2002, $6.4 million and $2.1 million were added to the provisions for uncollectible retail customer accounts of NPC and SPPC, respectively. The adequacy of these reserves will vary to the extent that future collections differ from past experience. Uncollectible retail customer accounts amounting to $4.1 million and $3.3 million, respectively, for NPC and SPPC, were written off against these provisions during the nine months ended September 30, 2002. Significant collection efforts are underway to recover portions of the rest of the delinquent accounts. MAJOR FACTORS AFFECTING RESULTS OF OPERATIONS As discussed in the results of operations sections that follow, operating results for the nine months ended September 30, 2002 were severely affected by the PUCN's March 29, 2002 decision in NPC's deferred energy rate case to disallow $434 million of deferred purchased fuel and power costs. As a result of this disallowance, NPC wrote off $465 million of deferred energy costs and related carrying charges during that quarter. In addition, the decision of the PUCN on May 28, 2002 on SPPC's deferred energy application to disallow $53.1 million of deferred purchased fuel and power costs accumulated 39 between March 1, 2001 and November 30, 2001 had a significant negative impact on the results of operations of SPR and SPPC for the quarter and the nine-month period ended September 30, 2002. As a result of this disallowance, SPPC wrote off $55.1 million of deferred energy costs and related carrying charges during that quarter. The discussion below provides the context in which these decisions were made. In an effort to mitigate the effects of higher fuel and purchased power costs that developed in the Western United States in 2000,the Utilities entered into the Global Settlement with the PUCN in July 2000, which established a mechanism that initiated incremental rate increases for each Utility. Cumulative electric rate increases under the Global Settlement were $127 million and $65 million per year for NPC and SPPC, respectively. However, because the rate adjustment mechanism of the Global Settlement was subject to certain caps and could not keep pace with the continued escalation of fuel and purchased power prices, on January 29, 2001, the Utilities filed a Comprehensive Energy Plan (CEP) with the PUCN. The CEP included a request for emergency rate increases (CEP Riders). On March 1, 2001, the PUCN permitted the requested CEP Riders to go into effect subject to later review. The CEP Riders provided further rate increases of $210 million and $104 million per year, respectively, for NPC and SPPC. Notwithstanding the increases under the Global Settlement and the CEP Riders, the Utilities' revenues for fuel and purchased power recovery continued to be less than the related expenses. Accordingly, the Utilities sought additional relief pursuant to legislation. On April 18, 2001, the Governor of Nevada signed into law AB 369. The provisions of AB 369 include a moratorium on the sale of generation assets by electric utilities until 2003, the repeal of electric industry restructuring, and, beginning March 1, 2001, a reinstatement of deferred energy accounting for fuel and purchased power costs incurred by electric utilities. The stated purposes of this emergency legislation included, among others, to control volatility in the price of electricity in the retail market in Nevada and to ensure that the Utilities have the necessary financial resources to provide adequate and reliable electric service under present market conditions. As discussed above in "Critical Accounting Policies," deferred energy accounting allows the Utilities an opportunity to recover in future periods that portion of their costs for fuel and purchased power not covered by current rates and defers to future periods the expense associated with the amounts by which fuel and purchased power costs exceed the costs to be recovered in current rates. Recovery is subject to PUCN review as to prudency and other matters. AB 369 requires each Utility to file general rate applications and deferred energy applications with the PUCN by specific dates. NPC's deferred energy application, filed on November 30, 2001, sought to establish a Deferred Energy Accounting Adjustment ("DEAA") rate, effective on April 1, 2002, to clear accumulated purchased fuel and power costs of $922 million and spread the cost recovery over a period of not more than three years, resulting in an average net increase of 21%. SPPC's deferred energy application, filed on February 1, 2002, sought to establish a DEAA rate to clear accumulated purchased fuel and power costs of $205 million and spread the cost recovery over a period of not more than three years, resulting in an average net increase of 9.8%. See "Regulatory Matters," later, for a discussion of the Utilities' general rate case filings and decisions. The March 29, 2002 decision of the PUCN on NPC's deferred energy application to disallow $434 million of deferred purchased fuel and power costs accumulated between March 1, 2001 and September 30, 2001 had a significant negative impact on the results of operations of SPR and NPC for the nine months ended September 30, 2002. Several of the intervenors from NPC's deferred energy rate case filed petitions with the PUCN for reconsideration of its decision, seeking additional disallowances ranging from $12.8 million to $488 million. The petitions for reconsideration were granted in part and denied in part by the PUCN on May 24, 2002, but no additional disallowances to the deferred energy balance resulted from that decision. The Bureau of Consumer Protection (BCP) of the Nevada Attorney General's Office has since filed a petition in NPC's pending state court case seeking additional disallowances. Although the PUCN's March 29, 2002 decision on NPC's deferred energy application is being challenged by NPC in a lawsuit filed in Nevada state court, which is discussed below under "Regulatory Matters", the decision caused the two major national rating agencies to issue an immediate downgrade of the credit ratings on SPR's, NPC's and SPPC's debt securities (followed by further downgrades late in April). Following those events, the market price of SPR's common stock fell substantially, NPC and SPPC were obliged within 5 business days of the downgrades to issue general and refunding mortgage bonds to secure their bank lines of credit, NPC was obliged to obtain a waiver and amendment from its credit facility banks before it was permitted to draw down on the facility, NPC and SPPC were no longer able to issue commercial paper, a number of NPC's power suppliers contacted NPC regarding its ability to pay the purchase price of outstanding contracts, and several power suppliers, including a subsidiary of Enron Corp., terminated their power supply agreements with one or both of the Utilities. The separate decision of the PUCN on May 28, 2002 on SPPC's deferred energy application to disallow $53.1 million of deferred purchased fuel and power costs accumulated between March 1, 2001 and November 30, 2001 had a significant negative impact on the results of operations of SPR and SPPC for the quarter and the nine months ended September 30, 2002. 40 Several of the intervenors from SPPC's deferred energy rate case filed petitions with the PUCN for reconsideration of its decision, seeking an additional disallowance of $126 million. On July 18, 2002, the petitions for reconsideration were granted in part and denied in part by the PUCN, but no additional disallowances to the deferred energy balance resulted from that decision. The PUCN's May 28, 2002 decision on SPPC's deferred energy application is being challenged by SPPC in a lawsuit filed August 22, 2002 in Nevada state court, which is discussed below under "Regulatory Matters". The BCP of the Nevada Attorney General's Office has since filed a petition in SPPC's state action seeking additional disallowances. A significant disallowance in future deferred energy rate cases filed by either Utility could further weaken the financial condition, liquidity, and capital resources of SPR, NPC, and SPPC. In particular, such a decision or decisions could cause further downgrades of debt securities by the rating agencies, could make it impracticable to access the capital markets, and could cause additional power suppliers to terminate purchased power contracts and seek liquidated damages. Under such circumstances, there can be no assurance that SPR, NPC, or SPPC would be able to remain solvent or continue operations. Under such circumstances, there also can be no assurance that SPR, NPC, or SPPC would not seek protection under the bankruptcy laws. SIERRA PACIFIC RESOURCES During the first nine months of 2002, SPR incurred a loss of $265.1 million before preferred stock dividend requirements, and paid $20.6 million in common stock dividends on March 15, 2002. NPC declared and paid a common stock dividend of $10 million to its parent, SPR, in the first quarter of 2002. SPPC declared and paid common stock dividends of $10 million and $9.9 million to its parent, SPR, in the first and second quarter of 2002, respectively. SPPC also paid $2.9 million in dividends to holders of its preferred stock during the first nine months of 2002. NPC and SPPC each received a capital contribution of $10 million from SPR in March 2002. On July 7, 2002, the Board of County Commissioners of Clark County, Nevada, added an Electric Utility Advisory Question to its November 5, 2002 general election ballot, which asked voters whether "the Nevada Legislature should take appropriate action to enable the electrical energy provider for southern Nevada to be a locally controlled, not for profit public utility." NPC filed a lawsuit seeking to remove the question from the ballot, and the lawsuit was dismissed. Although the referendum is non-binding, the results of this advisory question, which was approved by a 57% to 43% vote, may impact future utility legislation by the Nevada Legislature in its next legislative session which may, in turn, directly or indirectly affect NPC and its operations. On August 22, 2002, SPR received a letter from the Southern Nevada Water Authority ("SNWA") stating that it was prepared to enter into good faith negotiation of definitive agreements to acquire all of NPC's assets and assume certain of NPC's existing indebtedness. On September 12, 2002, SPR responded with a letter stating that it did not view the SNWA's letter as an offer and expressing concerns with the SNWA's financing plans, certain significant legal issues with the proposal and the SNWA's lack of utility management experience. The SNWA has responded by reaffirming its purported offer to acquire NPC. On September 30, 2002, a lawsuit was filed by two individuals in the District Court for Clark County, Nevada, on behalf of themselves and all holders of securities of SPR, against SPR and its directors named individually. The lawsuit alleges that the defendants violated their fiduciary duties to the securityholders as a result of SPR's response to letters from the SNWA in which SNWA stated that it was prepared to enter into negotiations to acquire NPC's assets and assume certain of NPC's indebtedness. The lawsuit, which seeks certification as a class action, requests that the court: (1) declare that the directors have breached their fiduciary duties, (2) enjoin the defendants to undertake all reasonable efforts to maximize shareholder value including mandating due consideration of the SNWA proposal, (3) order the defendants to permit a stockholders' committee to ensure a fair procedure in connection with any disposition or retention of assets, and (4) if SNWA's purported offer is withdrawn due to the actions or inactions of the defendants, to award compensatory and/or punitive damages in an unspecified amount against the defendants. Although SPR and its directors intend to vigorously defend against the lawsuit, SPR cannot predict the outcome at this time. FINANCIAL CONDITION, LIQUIDITY AND CAPITAL RESOURCES SPR, on a stand-alone basis, had cash and cash equivalents of approximately $5.6 million at September 30, 2002, and approximately $32.7 million at October 31, 2002. Since SPR is a holding company, substantially all of its cash flow is provided by dividends paid to SPR by NPC and SPPC on their common stock, all of which is owned by SPR. Since NPC and SPPC are public utilities, they are subject to regulation by state utility commissions which may impose limits on investment returns or otherwise impact the amount of dividends that the Utilities may declare and pay. In addition, certain agreements entered into by the Utilities set restrictions on the amount of dividends they may declare and pay and restrict the circumstances under which such dividends 41 may be declared and paid. The specific restrictions on dividends contained in agreements to which NPC and SPPC are party, as well as specific regulatory limitations on dividends, are summarized below. - NPC's first mortgage indenture limits the cumulative amount of dividends that NPC may pay on its capital stock to the cumulative net earnings of NPC since 1953. At the present time, this restriction precludes NPC from making further payments of dividends on NPC's common stock and will continue to bar such payments unless the restriction is waived, amended, or removed by the consent of the first mortgage bondholders, the first mortgage bonds are redeemed or defeased, or until, over the passage of time, NPC generates sufficient earnings to overcome the shortfall created by the write-off of $465 million in connection with the March 2002 decision in NPC's deferred energy rate case. - NPC's 10 7/8% General and Refunding Mortgage Notes, Series E, due 2009 limit the amount of dividends that NPC may pay to SPR. However, that limitation does not apply to payments by NPC to enable SPR to pay its reasonable fees and expenses (including, but not limited to, interest on SPR's indebtedness and payment obligations on account of SPR's premium income equity securities) provided that those payments do not exceed $60 million for any one calendar year, those payments comply with any regulatory restrictions then applicable to NPC, and the ratio of consolidated cash flow to fixed charges for NPC's most recently ended four full fiscal quarters immediately preceding the date of payment is at least 1.75 to 1. The terms of the Series E Notes also permit dividend payments to SPR in an aggregate amount not to exceed $15 million from the date of the issuance of the Notes. In addition, NPC may make dividend payments to SPR in excess of the amounts described above so long as, at the time of payment and after giving effect to the payment: there are no defaults or events of default with respect to the Series E Notes, NPC can meet a fixed charge coverage ratio test, and the total amount of such dividends is less than (i) the sum of 50% of NPC's consolidated net income measured on a quarterly basis cumulative of all quarters from the date of issuance of the Series E Notes, plus (ii) 100% of NPC's aggregate net cash proceeds from the issuance or sale of certain equity or convertible debt securities of NPC, plus (iii) the lesser of cash return of capital or the initial amount of certain restricted investments, plus (iv) the fair market value of NPC's investment in certain subsidiaries. If NPC's Series E Notes are upgraded to investment grade by both Moody's Investors Service, Inc. (Moody's) and Standard & Poor's Rating Group, Inc. (S&P), these dividend restrictions will be suspended and will no longer be in effect so long as the Series E Notes remain investment grade. - On October 29, 2002, NPC established an accounts receivables purchase facility. The agreements relating to the receivables purchase facility contain various conditions, including a limitation on the payment of dividends by NPC to SPR that is identical to the limitation contained in NPC's General and Refunding Mortgage Notes, Series E, described above. - The PUCN issued a Compliance Order, Docket No. 02-4037, on June 19, 2002, relating to NPC's request for authority to issue long-term debt. The PUCN order requires that, until such time as the order's authorization expires (December 31, 2003), NPC must either receive the prior approval of the PUCN or reach an equity ratio of 42% before paying any dividends to SPR. If NPC achieves a 42% equity ratio prior to December 31, 2003, the dividend restriction ceases to have effect. - The terms of NPC's preferred trust securities provide that no dividends may be paid on NPC's common stock if NPC has elected to defer payments on the junior subordinated debentures issued in conjunction with the preferred trust securities. At this time, NPC has not elected to defer payments on the junior subordinated debentures. - SPPC's Term Loan Agreement limits the amount of dividends that SPPC may pay to SPR. However, that limitation does not apply to payments by SPPC to enable SPR to pay its reasonable fees and expenses (including, but not limited to, interest on SPR's indebtedness and payment obligations on account of SPR's premium income equity securities) provided that those payments do not exceed $90 million, $80 million and $60 million in the aggregate for the twelve month periods ending on October 30, 2003, 2004 and 2005, respectively. The Term Loan Agreement also permits SPPC to make dividend payments to SPR in an aggregate amount not to exceed $10 million during the term of the Term Loan Agreement. In addition, SPPC may make dividend payments to SPR in excess of the amounts described above so long as, at the time of the payment and after giving effect to the payment, there are no defaults or events of default under the Term Loan Agreement, and such amounts, when aggregated with the amount of dividends paid to SPR by SPPC since the date of execution of the Term Loan Agreement, does not exceed the sum of (i) 50% of SPPC's Consolidated Net Income for the period commencing January 1, 2003 and ending with last day of fiscal quarter most recently completed prior to the date of the contemplated dividend payment plus (ii) the aggregate amount of cash received by SPPC from SPR as equity contributions on its common stock during such period. - On October 29, 2002, SPPC established an accounts receivables purchase facility. The agreements relating to the receivables purchase facility contain various conditions, including a limitation on the payment of dividends by SPPC to SPR that is identical to the limitation contained in SPPC's Term Loan Agreement, described above. - SPPC's Articles of Incorporation contain restrictions on the payment of dividends on SPPC's common stock in the event of a default in the payment of dividends on SPPC's preferred stock and prohibit SPPC from declaring or paying any dividends on any shares of common stock except from the net income of SPPC, and its predecessor, available for dividends on common stock accumulated subsequent to December 31, 1955, less preferred stock dividends, plus the sum of $500,000. The provisions that currently restrict dividends payable by NPC or SPPC have adversely affected SPR's liquidity and will continue to negatively impact SPR's liquidity until those provisions are no longer in effect. 42 On March 29 and April 1, 2002, S&P and Moody's lowered the unsecured debt ratings of SPR, NPC and SPPC to below investment grade in response to the decision of the PUCN with respect to NPC's rate cases. On April 23 and 24, 2002, the unsecured debt ratings of SPR and the Utilities were further downgraded by both rating agencies, and the Utilities' secured debt ratings were downgraded to below investment grade. The downgrades have affected SPR's, NPC's and SPPC's liquidity primarily in two principal areas: (1) their respective financing arrangements and (2) NPC's and SPPC's contracts for fuel, for purchase and sale of electricity and for transportation of natural gas. As a result of the ratings downgrades, SPR's ability to access the capital markets to raise funds is severely limited. On April 3, 2002, SPR terminated its $75 million unsecured revolving credit facility as a condition to the banks agreeing to an amendment of NPC's recently terminated $200 million unsecured revolving credit facility that would permit NPC to draw down funds under that facility. See "Nevada Power Company - Financial Condition, Liquidity and Capital Resources" for more information. In response to the decisions by the PUCN in NPC's rate cases, SPR has implemented certain measures that management expects will positively impact cash flow by $125 million in 2002. Two major transmission construction projects, discussed in the Form 10-K for the year ended December 31, 2001, have been delayed for a total capital preservation impact of $80.8 million. The delay in NPC's Centennial Plan has an impact of $46.4 million and the delay of SPPC's Falcon to Gonder Project has an impact of $34.4 million. An additional $28.9 million was reduced from the Utilities' capital budgets by curtailing or delaying other projects. Management expects that the balance of the $125 million cash flow enhancement will be obtained from various land sales. Additional cost-cutting actions by SPR may be necessary. With respect to NPC's and SPPC's contracts for purchased power, NPC and SPPC purchase and sell electricity with counterparties under the Western Systems Power Pool ("WSPP") agreement, which is an industry standard contract. The WSPP contract is posted on the WSPP website. These contracts provide that a material adverse change may give rise to a right to request collateral, which, if not provided within 3 business days, could cause a default. A default must be declared within 30 days of the event giving rise to the default becoming known. A default will result in a termination payment equal to the present value of the net gains and losses for the entire remaining term of all contracts between the parties aggregated to a single liquidated amount due within 3 business days following the date the notice of termination is received. The mark-to-market value, which is substantially based on quoted market prices, can be used to roughly approximate the termination payment at any point in time. The mark-to-market value as of November 1, 2002, for all suppliers continuing to provide power under a WSPP agreement was approximately 90.1 million and 59.9 million, respectively, for NPC and SPPC. Following the PUCN decisions, a number of power suppliers requested collateral from NPC and SPPC. On April 4, 2002, the Utilities sent a letter to their suppliers advising them that, assuming the Utilities could access the capital markets for secured debt and no other significant negative developments occurred, the Utilities expected to be able to honor their obligations under the power supply contracts. However, the Utilities noted that a simultaneous call for 100% mark-to-market collateral in the short-term would likely not be met. On April 24, 2002, the Utilities met with representatives of various suppliers to discuss SPR's and the Utilities' financial situation and plans, and indicated that they intended to propose extended payment terms for the above-market portions of NPC's existing power contracts. Such extended payment terms were proposed to NPC's suppliers in a letter dated May 2, 2002, and proposed paying less than contract prices, but more than market prices plus interest, for the period May 1 to September 15, 2002 and paying any balances remaining prior to December 2003. NPC also agreed to extend the suppliers' rights under the WSPP agreement. As of October 29, 2002, NPC paid all remaining outstanding balances owed to its continuing suppliers. In early May of 2002, Enron Power Marketing Inc. ("Enron"), Morgan Stanley Capital Group Inc. ("MSCG"), Reliant Energy Services, Inc. and several smaller suppliers terminated their power deliveries to NPC and SPPC. These terminating suppliers asserted their contractual right under the WSPP agreement to terminate deliveries based upon the Utilities' alleged failure to provide adequate assurance of their performance under the WSPP agreement to any of their suppliers. Each of these terminating suppliers has asserted, or has indicated that it will assert, claims for liquidated damages against the Utilities under the terminated power supply contracts. On June 5, 2002, Enron filed suit in its bankruptcy case in the Bankruptcy Court for the Southern District of New York asserting claims for liquidated damages related to the termination of its power supply agreements with the Utilities of approximately $216 million and $93 million against NPC and SPPC, respectively. NPC and SPPC have both filed claims in the Bankruptcy Court alleging, among other things, that NPC and SPPC were fraudulently induced to enter into the agreements with Enron. Enron's claims are also subject to the Utilities' defense, as raised in the Utilities' motions to dismiss and or to stay all proceedings, that such claims are already at issue in the Utilities' FERC proceeding against Enron and others under Section 206 of the Federal Power Act challenging the contract prices of the terminated power supply agreements. Enron initially filed a motion for partial summary judgment to require the Utilities to make immediate payment of the full amount of Enron's claim, pending final resolution of the lawsuit. Enron subsequently filed another motion for summary judgment seeking final payment of its damages claim. Hearings, including arguments regarding the issue of FERC's primary jurisdiction over the contract claims, were conducted in September, 43 October, and early November 2002. On November 14, 2002, the judge is expected to rule on the Utilities' motion to dismiss or stay until the FERC rules on the Utilities' Section 206 filing. If the judge decides not to stay Enron's lawsuit pending the outcome of the FERC hearings, the judge would then schedule additional arguments with respect to Enron's motion for summary judgment. At this time, the outcome of a decision in this matter cannot be predicted. An adverse decision on Enron's motion for summary judgment or an adverse decision in the lawsuit would have a material adverse affect on the financial condition and liquidity of SPR and the Utilities and would render their ability to continue to operate outside of bankruptcy uncertain. On June 10, 2002, Duke Energy Trading and Marketing ("Duke") entered into an agreement with SPR and the Utilities to supply up to 1,000 megawatts of electricity per hour, as well as natural gas, to fulfill the Utilities' power requirements during the peak summer period. The effect of the Duke agreement was to replace the amount of contracted power and natural gas that would have been supplied by the various terminating suppliers, including Enron. Duke also agreed to accept deferred payment for a portion of the amount due under its existing power contracts with NPC for purchases made through September 15, 2002. On October 25, 2002 Duke was paid the full amount of the deferred payments. On September 5, 2002, MSCG filed a Demand for Arbitration pursuant to the mediation and arbitration procedures of the WSPP agreement seeking a termination payment from NPC of approximately $25 million under its terminated power supply agreement with NPC. If this claim is not resolved by arbitration, NPC expects that MSCG will commence a lawsuit to recover liquidated damages under the terminated contract. On September 30, 2002, El Paso Merchant Energy Group ("EPME") notified NPC that it was terminating all transactions entered into with NPC under the WSPP agreement. On October 8, 2002, NPC received a letter from EPME seeking a termination payment of approximately $36 million with respect to the terminated WSPP agreement transactions. At the present time, NPC disagrees with EPME's calculation, and expects that net gains and losses relating to the terminated transactions, including a delayed payment amount of approximately $19 million that was owed to EPME for power deliveries through September 15, 2002, will result in a net payment due to NPC. With respect to the purchase and sale of natural gas, NPC and SPPC use several types of contracts. Standard industry sponsored agreements include: - the Gas Industry Standards Board ("GISB") agreement which is used for physical gas transactions, - the North American Energy Standards Board ("NAESB") agreement which is used for physical gas transactions, - the GasEDI Base Contract for Short Term Sale and Purchase of Natural Gas which is also used for physical gas transactions, - the International Swap Dealers Association (ISDA) agreement which is used for financial gas transactions. Alternatively, the gas transactions might be governed by a non-standard bilateral master agreement negotiated between the parties, or by the confirmation associated with the transaction. The natural gas contract terms and conditions are more varied than the electric contracts. Consequently, some of the contracts contain language similar to that found in the WSPP agreement and other agreements have unique provisions dealing with material adverse changes. Gas transmission services are provided under the FERC Gas Tariff or a custom agreement. These contracts require the entities to establish and maintain creditworthiness to obtain service. These contracts are subject to FERC approved tariffs which, under certain circumstances, require the Utilities to provide collateral to continue receiving service. To date, a letter of credit has been provided to one of SPPC's gas suppliers. In March 2002, NPC received a federal income tax refund of $79.3 million. Additionally, SPR and the Utilities received $105.7 million of refunds in the second quarter of 2002. These refunds were the result of income tax losses generated in 2001. Federal legislation passed in March 2002 changed the allowed carry-back of these losses from two years to five years. This change permitted SPR and the Utilities to accelerate the receipt of a portion of their income tax receivables sooner than expected. The income tax receivable of $266.7 million as of September 30, 2002, will be utilized in future periods to reduce taxes payable when SPR and the Utilities recognize taxable income. On October 29, 2002, NPC and SPPC established accounts receivables purchase facilities of up to $125 million and $75 million, respectively, which were arranged by Lehman Brothers. If NPC or SPPC elect to activate their receivables purchase facilities, they will sell all of their accounts receivable generated from the sale of electricity and natural gas to customers to their newly created bankruptcy remote special purpose subsidiaries. The receivables sales will be without recourse except for breaches of customary representations and warranties made at the time of sale. The subsidiaries will, in turn, sell these receivables to a bankruptcy-remote subsidiary of SPR. SPR's subsidiary will issue variable rate revolving notes backed by the purchased receivables. Lehman Brothers Holdings, Inc. will be the sole initial committed purchaser of all of the variable rate revolving notes. The agreements relating to the receivables purchase facilities contain various conditions to 44 purchase, covenants and trigger events, termination events and other provisions customary in receivables transactions. In connection with these facilities, SPR has agreed to guaranty the performance by NPC and SPPC of certain obligations as sellers and servicers under the accounts receivables facilities. NPC and SPPC intend to use their accounts receivables purchase facilities as back-up liquidity facilities and do not plan to activate these facilities in the foreseeable future. SPR has a qualified pension plan (the "Plan") that covers substantially all employees of SPR, NPC and SPPC. The annual net benefit cost for the Plan is expected to increase for 2003 by an amount between $12 million and $22 million over the 2002 cost of $18.4 million. Also, the Plan currently has assets with a fair value that is less than the present value of the accumulated benefit obligation under the Plan. While the amount of the deficiency has not yet been determined, SPR and the Utilities expect their combined minimum funding requirement for 2002 will be at least $24 million. However, SPR and the Utilities do not expect that their funding obligation for 2002 will have a material adverse effect on their liquidity. SPR has a substantial amount of debt and other obligations including, but not limited to: $200 million of its unsecured Floating Rate Notes due April 20, 2003; $300 million of its unsecured 8 3/4% Senior Notes due 2005; and $345 million of its unsecured 7.93% Senior Notes due 2007. In connection with the effects of the disallowance of a significant portion of the Utilities' deferred purchased power costs by the PUCN as stated above, SPR's credit ratings, along with those of NPC and SPPC, were downgraded to below investment grade. As a result of the downgrades, SPR's ability to service its debt obligations and refinance its maturing debt as it becomes due has become uncertain. In the event that SPR's financial condition does not improve or becomes worse, it may have to consider other options including the possibility of seeking protection in a bankruptcy proceeding. On October 29, 2002, SPPC paid a common stock dividend of $25 million to its parent, SPR. On November 8, 2002, the Board of Directors of SPPC voted to declare a dividend to SPR of up to $25 million payable on or before February 1, 2003. SPR's future liquidity depends, in part, on SPPC's ability to continue to pay dividends to SPR, on a restoration of NPC to financial stability including a restoration of its ability to pay dividends to SPR, and on SPR's ability to access the capital markets or otherwise refinance debt that matures in 2003 and thereafter. Further adverse developments at NPC or SPPC, including a material disallowance of deferred energy costs in future rate cases or an adverse decision in the pending lawsuit by Enron, could cause SPR to become insolvent and would render SPR's ability to continue to operate outside of bankruptcy uncertain. 45 NEVADA POWER COMPANY During the quarter ended September 30, 2002, NPC earned approximately $79.3 million (excluding NPC's equity in the losses of its parent, SPR) and paid no dividends on its common stock. During the nine months ended September 30, 2002, NPC incurred a loss of approximately $216.0 million (excluding NPC's equity in the losses of its parent, SPR), and paid $10 million in dividends on its common stock, all of which was reinvested in NPC as a contribution to capital. On July 7, 2002, the Board of County Commissioners of Clark County, Nevada, added an Electric Utility Advisory Question to its November 5, 2002 general election ballot, which asked voters whether "the Nevada Legislature should take appropriate action to enable the electrical energy provider for southern Nevada to be a locally controlled, not for profit public utility." NPC filed a lawsuit seeking to remove the question from the ballot, and the lawsuit was dismissed. Although the referendum is non-binding, the results of this advisory question, which was approved by a 57% to 43% vote, may impact future utility legislation by the Nevada Legislature in its next legislative session which may, in turn, directly or indirectly affect NPC and its operations. On August 22, 2002, SPR received a letter from the Southern Nevada Water Authority ("SNWA") stating that it was prepared to enter into good faith negotiation of definitive agreements to acquire all of NPC's assets and assume certain of NPC's existing indebtedness. On September 12, 2002, SPR responded with a letter stating that it did not view the SNWA's letter as an offer and expressing concerns with the SNWA's financing plans, certain significant legal issues with the proposal and the SNWA's lack of utility management experience. The SNWA has responded by reaffirming its purported offer to acquire NPC. The causes for significant changes in specific lines comprising the results of operations for NPC are as follows:
THREE MONTHS NINE MONTHS ENDED SEPTEMBER 30, ENDED SEPTEMBER 30, -------------------------------------- ----------------------------------------- Change from Change from 2002 2001 Prior Year % 2002 2001 Prior Year % ---------- ----------- ------------ ----------- ------------ ------------ ELECTRIC OPERATING REVENUES ($000): Residential $ 266,508 $ 253,631 5.1% $ 564,439 $ 529,330 6.6% Commercial 103,367 94,262 9.7% 263,425 233,391 12.9% Industrial 189,440 159,041 19.1% 413,602 349,866 18.2% ---------- ----------- ----------- ------------ Retail revenues 559,315 506,934 10.3% 1,241,466 1,112,587 11.6% Other (1) 153,221 888,562 -82.8% 304,401 1,450,362 -79.0% ---------- ----------- ----------- ------------ Total Revenues $ 712,536 $ 1,395,496 -48.9% $ 1,545,867 $ 2,562,949 -39.7% ========== =========== =========== ============ Retail sales in thousands of megawatt-hours (MWH) 5,814 5,540 4.9% 13,699 13,296 3.0% Average retail revenue per MWH $ 96.20 $ 91.50 5.1% $ 90.62 $ 83.68 8.3%
(1) Primarily wholesale, as discussed below Residential electric revenues increased for the three months ending September 30, 2002 compared to the same period last year due to increased rates in 2002 and an increase in cooling degree-days resulting in higher sales per residential customer. Residential electric revenues increased for the nine months ended September 30, 2002 due to an overall increase in rates resulting from an increase in rates effective March 1, 2001, pursuant to the Comprehensive Energy Plan (CEP), and a rate change effective April 1, 2002, that included a new Deferred Energy Accounting Adjustment (DEAA) rate. See NPC's Annual Report on Form 10-K for the year ended December 31, 2001 for a discussion of the Global Settlement and the CEP, and the Regulatory Matters section of this third quarter Form 10-Q for more detailed DEAA and rate information. Both commercial and industrial electric revenues increased for the three- and nine-month periods due, in part, to increases in the number of customers and rates. The opening of several new schools, commercial shopping centers and large casinos helped to increase 2002 revenues. The decreases in Electric Operating Revenues - Other for the three- and nine-month periods ended September 30, 2002, compared to the same periods in 2001 were due to the decrease in prices and sales volumes of wholesale electric power to other utilities, as a result of changing market conditions. See NPC's Annual Report on Form 10-K for the year ended December 31, 2001, Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operation, Purchased Power Procurement, for a discussion of NPC's purchased power procurement strategies. 46
THREE MONTHS NINE MONTHS ENDED SEPTEMBER 30, ENDED SEPTEMBER 30, --------------------------------------- ---------------------------------------- Change from Change from 2002 2001 Prior Year % 2002 2001 Prior Year % ---------- ------------- ------------ ----------- ------------ ------------ PURCHASED POWER ($000) $ 440,559 $ 1,686,816 -73.9% $ 1,102,55 $ 2,728,176 -59.6% Purchased Power in thousands of MWHs 5,330 8,330 -36.0% 11,112 16,015 -30.6% Average cost per MWH of Purchased Power (1) $ 82.66 $ 202.50 -59.2% $ 78.61 $ 170.35 -53.9%
(1) Not including contract termination costs, discussed below NPC's purchased power costs and volume were lower for both the three- and nine-month periods ended September 30, 2002 than for the same period of the prior year. These decreases were the result of lower volumes and prices of Short-Term Firm energy purchased. The decrease for the nine-month period was offset, in part, by a $229 million reserve recorded in the second quarter for terminated contracts, which are part of the power portfolio costs and which are described in more detail in "Financial Condition, Liquidity, and Capital Resources." Purchases associated with risk management activities, which are included in Short-Term Firm energy, also decreased significantly in 2002, for both the current quarter and year-to-date. Risk management activities include transactions entered into for hedging purposes and to minimize purchased power costs. See NPC's Annual Report on Form 10-K for the year ended December 31, 2001, Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operation, Purchased Power Procurement, for a discussion of NPC's purchased power procurement strategies.
THREE MONTHS NINE MONTHS ENDED SEPTEMBER 30, ENDED SEPTEMBER 30, --------------------------------------- ---------------------------------------- Change from Change from 2002 2001 Prior Year % 2002 2001 Prior Year % ---------- ---------- ------------ ----------- ----------- ------------ FUEL FOR POWER GENERATION ($000) $ 87,864 $ 131,023 -32.9% $ 245,060 $ 348,633 -29.7% Thousands of MWHs generated 2,936 2,436 20.5% 7,592 7,510 1.1% Average cost per MWH of Generated Power $ 29.93 $ 53.79 -44.4% $ 32.28 $ 46.42 -30.5%
Fuel for generation costs for both the three and nine months ended September 30, 2002, were significantly lower than the prior year due to the substantial decrease in natural gas prices. For the three months ended September 30, 2002, the decrease was offset, in part, by higher volumes, because it was more economical to generate power than to purchase power.
THREE MONTHS NINE MONTHS ENDED SEPTEMBER 30, ENDED SEPTEMBER 30, ----------------------------------------- ----------------------------------------- Change from Change from DEFERRAL OF ENERGY COSTS-NET ($000) 2002 2001 Prior Year % 2002 2001 Prior Year % ---------- ----------- ------------ ---------- ---------- ------------ Deferred energy costs - net $ (43,224) $ (638,571) -93.2% $ (238,059) $ (908,408) -73.8% Deferred energy costs disallowed - - N/A 434,123 - N/A ---------- ----------- ---------- ---------- $ (43,224) $ (638,571) -93.2% $ 196,064 $ (908,408) N/A ========== =========== ========== ==========
Deferral of energy costs-net for the three- and nine-month periods ended September 30, 2002, reflects deferrals of electric energy costs, reflecting the extent to which actual fuel and purchased power costs exceeded the fuel and purchased power costs recovered through current rates. These deferrals are offset in part by the amortization of prior deferred costs resulting from an increase in rates beginning April 1, 2002, pursuant to the PUCN's March 29, 2002, decision on NPC's deferred energy rate case, and the one-time rate increase of $0.01 per kilowatt-hour for the month of June 2002. Deferral of energy costs-net for the nine-months ended September 30, 2002, also reflects the deferral in the second quarter of 2002 of approximately $229 million for contract termination costs, as described in more detail in "Financial Condition, Liquidity, and Capital Resources," and reflects the write-off of $434 million of deferred energy costs for the seven months ended 47 September 30, 2001, that were disallowed by the PUCN in their decision on NPC's deferred energy rate case. For both the three- and nine-month periods ended September 30, 2001, NPC recorded large deferrals of electric energy costs, as shown in the table above.
THREE MONTHS NINE MONTHS ENDED SEPTEMBER 30, ENDED SEPTEMBER 30, ----------------------------------- --------------------------------------- Change from Change from 2002 2001 Prior Year % 2002 2001 Prior Year % -------- ------ ------------ ------- ------- ------------ ALLOWANCE FOR OTHER FUNDS USED DURING CONSTRUCTION ($000) $ (262) $ (87) $ 239 $ (560) ALLOWANCE FOR BORROWED FUNDS USED DURING CONSTRUCTION ($000) $ 208 $ 657 $ 2,169 $ 570 ------- ------ ------- ------- $ (54) $ 570 -109.5% $ 2,408 $ 10 23980.0% ======= ====== ======= =======
NPC's total allowance for funds used during construction (AFUDC) is lower for the three-month period ended September 30, 2002 as a result of adjustments in 2002 to refine amounts assigned to specific components of facilities that were completed in different periods and a decrease in the AFUDC rate. The decrease was offset in part due to an increase in capital expenditures for the Centennial Plan. AFUDC is higher for the nine-month period ended September 30, 2002 as a result of an increase in capital expenditures for the Centennial Plan and adjustments in 2001 to refine amounts assigned to specific components of facilities that were completed in different periods. The increase is offset in part by a decrease in the AFUDC rate in 2002 as a result of an increase in short-term debt.
THREE MONTHS NINE MONTHS ENDED SEPTEMBER 30, ENDED SEPTEMBER 30, --------------------------------------- ----------------------------------------- Change from Change from ($000) 2002 2001 Prior Year % 2002 2001 Prior Year % ---------- ----------- ------------ ------------ ---------- ------------ OTHER OPERATING EXPENSE $ 39,250 $ 45,670 -14.1% $ 116,520 $ 130,192 -10.5% MAINTENANCE EXPENSE $ 8,050 $ 10,331 -22.1% $ 31,576 $ 36,789 -14.2% DEPRECIATION AND AMORTIZATION $ 24,975 $ 23,042 8.4% $ 72,924 $ 67,345 8.3% INCOME TAXES $ 39,944 $ 36,197 10.4% $ (116,536) $ 21,979 -630.2% INTEREST CHARGES ON LONG-TERM DEBT $ 23,714 $ 20,545 15.4% $ 70,668 $ 55,504 27.3% INTEREST CHARGES-OTHER $ 7,251 $ 3,269 121.8% $ 14,133 $ 10,982 28.7% OTHER INCOME (EXPENSE) - NET $ 4,933 $ 11,021 -55.2% $ (839) $ 14,189 -105.9%
Other operating expense for the three-month period ending September 30, 2002 was lower, compared with the same period in the prior year, primarily due to a third quarter 2001 increase in the provision for uncollectible accounts of approximately $10 million offset, in part, by a decrease in the provision for uncollectible accounts in 2001 related to the California Power Exchange. The decrease in Other operating expense for the nine-month period ending September 30, 2002, compared with the same period in the prior year, reflects the third quarter 2001 increase in the provision for uncollectible accounts, a $12.5 million increase in the provision for uncollectible accounts in 2001 related to the California Power Exchange, and the 2002 reversal of a $3 million reserve provision established in 2001 as a result of the conclusion of electric industry restructuring in Nevada. These decreases were offset, in part, by increased expenses related to a new Credit and Collections Action Plan, and legal fees associated with the PUCN's Deferred Energy Rate Case decision. Maintenance costs for the three- and nine- month periods ending September 30, 2002, decreased from the prior year due to delayed planned outages at Reid Gardner and Clark Station. Depreciation and amortization is higher for the three- and nine-month periods ended September 30, 2002 compared to the same periods in 2001 as a result of an increase in the computer depreciation rate and additions to plant-in-service. This increase was offset in part by plant-in-service asset reconciliations pursuant to a PUCN order. NPC's income tax expense for the three months ended September 30, 2002, increased compared to the same period in 2001, due to a corresponding increase in third quarter 2002 pre-tax income compared to the prior year. For the nine months ended September 30, 2002, NPC recorded a significant income tax benefit reflecting a large 2002 pre-tax loss; NPC recorded income tax expense for the nine months ended September 30, 2001, corresponding to the pre-tax income for the period. 48 Interest charges on long-term debt for the three- and nine- month periods ending September 30, 2002, increased over the same periods in 2001 due net increases in long-term debt outstanding between the comparable periods. Interest charges-other for the three- and nine-month periods ended September 30, 2002, increased from the prior year due primarily to interest expense on deferred payments to energy suppliers in the current year. Other income (expense) - net for the three months ended September 30, 2002, decreased compared to the same period in the prior year primarily due to a $6 million decrease, net of taxes, in carrying charges for deferred energy. The decrease in Other income (expense) - net for the nine months ended September 30, 2002, compared to the prior year also reflects the first quarter 2002 write-off of approximately $20.1 million, net of taxes, of carrying charges on deferred energy costs that were disallowed by the PUCN in their March 29, 2002 decision on NPC's deferred energy rate case. The write-off was offset in part by the recording of current year carrying charges on deferred energy costs. ANALYSIS OF CASH FLOWS NPC's cash flows improved during the nine months ended September 30, 2002, compared to the same period in 2001, resulting primarily from an increase in cash flows from operating activities offset in part by a decrease in cash flows from financing activities. Although NPC recorded a substantial loss for the nine months ended September 30, 2002, compared to net income for the same period in 2001, the current year's loss resulted largely from the write-off of disallowed deferred energy costs for which the cash outflow had occurred in 2001. Current year cash flows from operating activities also benefited from improved collections on accounts receivable compared to the prior year and from lower energy prices. Cash flows from operating activities in the current year also reflect the receipt of an income tax refund. Cash flows from financing activities were lower because of decreases in both net long-term debt issued and cash invested by NPC's parent, SPR, during the nine months ended September 30, 2002 compared to the same period in 2001. FINANCIAL CONDITION, LIQUIDITY AND CAPITAL RESOURCES NPC had cash and cash equivalents of approximately $207.7 million at September 30, 2002, and $146.7 million at October 31, 2002. As discussed in "Management's Discussion and Analysis of Financial Condition and Results of Operations - Nevada Power Company - Construction Expenditures and Financing" and " - Capital Structure" in the Annual Report on Form 10-K for the year ended December 31, 2001, NPC anticipated external capital requirements for construction costs and for the repayment of maturing short-term and long-term debt during 2002 totaling approximately $403 million, which NPC planned to fund through a combination of (i) internally generated funds, (ii) the issuance of short-term debt and preferred stock, and (iii) capital contributions from SPR. On March 29 and April 1, 2002, following the decision by the PUCN in NPC's deferred energy rate case, S&P and Moody's lowered NPC's unsecured debt ratings to below investment grade. On April 23 and 24, 2002, NPC's unsecured debt ratings were further downgraded and its secured debt ratings were downgraded to below investment grade. As a result of these downgrades, NPC's ability to access the capital markets to raise funds is severely limited. Since SPR's credit ratings were similarly downgraded, SPR's ability to make capital contributions to NPC also became severely limited. In connection with the credit downgrades by S&P and Moody's, NPC lost its A2/P2 commercial paper ratings and can no longer issue commercial paper. NPC had a commercial paper balance outstanding of $198.9 million at the time with a weighted average interest rate of 2.52%. Since NPC was no longer able to roll over its commercial paper, it paid off its maturing commercial paper with the proceeds of borrowings under its credit facility and terminated its commercial paper program on May 28, 2002. NPC does not expect to have direct access to the commercial paper market for the foreseeable future. NPC's $200 million unsecured revolving credit facility was also affected by the decision in the deferred energy rate case. Following the announcement of that decision, the banks participating in NPC's credit facility determined that a material adverse event had occurred with respect to NPC, thereby precluding NPC from borrowing funds under its credit facility. The banks agreed to waive the consequences of the material adverse event in a waiver letter and amendment that was executed on April 4, 2002. As required under the waiver letter and amendment, NPC issued and delivered its General and Refunding Mortgage Bond, Series C, due November 28, 2002, in the principal amount of $200 million, to the Administrative Agent as security for the credit facility. This facility was paid in full and terminated on October 30, 2002 with proceeds from the issuance of NPC's $250 million 10 7/8% General and Refunding Mortgage Notes, Series E, due 2009. On October 29, 2002, NPC established an accounts receivables purchase facility of up to $125 million, which was arranged by Lehman Brothers. If NPC elects to activate the receivables purchase facility, NPC will sell all of its accounts receivable generated from the sale of electricity to customers to its newly created bankruptcy remote special purpose 49 subsidiary. The receivables sales will be without recourse except for breaches of customary representations and warranties made at the time of sale. The subsidiary will, in turn, sell these receivables to a bankruptcy-remote subsidiary of SPR. SPR's subsidiary will issue variable rate revolving notes backed by the purchased receivables. Lehman Brothers Holdings, Inc. will be the sole initial committed purchaser of all of the variable rate revolving notes. The agreements relating to the receivables purchase facility contain various conditions to purchase, covenants and trigger events, termination events and other provisions customary in receivables transactions. In addition, the agreements contain a limitation on the payment of dividends by NPC to SPR that is identical to the limitation contained in NPC's General and Refunding Mortgage Notes, Series E, described below. In connection with NPC's receivables facility, SPR has agreed to guaranty NPC's performance of certain obligations as a seller and servicer under the facility. NPC has agreed to issue $125 million principal amount of its General and Refunding Mortgage Bonds upon activation of the accounts receivables purchase facility. The full principal amount of the Bond would secure certain of NPC's obligations as seller and servicer, plus certain interest, fees and expenses thereon to the extent not paid when due, regardless of the actual amounts owing with respect to the secured obligations. As a result, in the event of an NPC bankruptcy or liquidation, the holder of the Bond securing the receivables facility may recover more on a pro rata basis than the holders of other General and Refunding Mortgage securities, who could recover less on a pro rata basis, than they otherwise would recover. However, in no event will the holder of the Bond recover more than the amount of obligations secured by the Bond. NPC intends to use the accounts receivables purchase facility as a back-up liquidity facility and does not plan to activate this facility in the foreseeable future. NPC may activate the facility within five days upon the delivery of certain customary funding documentation and the delivery of the $125 million General and Refunding Mortgage Bond. NPC's first mortgage indenture creates a first priority lien on substantially all of NPC's properties. As of September 30, 2002, $372.5 million of NPC's first mortgage bonds were outstanding. Although the first mortgage indenture allows NPC to issue additional mortgage bonds on the basis of (i) 60% of net utility property additions and/or (ii) the principal amount of retired mortgage bonds, NPC agreed in connection with its $250 million 10 7/8% General and Refunding Mortgage Notes, Series E, due 2009 that it would not issue any more first mortgage bonds. NPC's General and Refunding Mortgage Indenture creates a lien on substantially all of NPC's properties in Nevada that is junior to the lien of the first mortgage indenture. As of September 30, 2002, $820 million of NPC's General and Refunding Mortgage securities were outstanding. Additional securities may be issued under the General and Refunding Mortgage Indenture on the basis of (1) 70% of net utility property additions, (2) the principal amount of retired General and Refunding Mortgage bonds, and/or (3) the principal amount of first mortgage bonds retired after delivery to the indenture trustee of the initial expert's certificate under the General and Refunding Mortgage Indenture. As of October 1, 2002, NPC had the capacity to issue approximately $871 million of additional General and Refunding Mortgage securities, not including the issuance of $250 million Series E Notes and the retirement of $200 million of General and Refunding Mortgage Bonds that secured NPC's terminated credit facility. However, the financial covenants contained in the Series E Notes limits NPC ability to issue additional General and Refunding Mortgage bonds or other debt. NPC has reserved $125 million of General and Refunding Mortgage Bonds for issuance upon the initial funding of NPC's receivables facility and $50 million of its General and Refunding Mortgage Bonds to secure a proposed 364-day facility, discussed below. NPC also has the ability to release property from the liens of the two mortgage indentures on the basis of net property additions, cash and/or retired bonds. To the extent NPC releases property from the lien of its General and Refunding Mortgage Indenture, it will reduce the amount of bonds issuable under that indenture. On June 19, 2002, the PUCN issued a Compliance Order, Docket No. 02-4037, authorizing NPC to issue $300 million of long-term debt. The PUCN order requires NPC, if it is able, to issue the $50 million of remaining authorized short-term debt, before it issues any long-term debt authorized by the order. Moreover, the order provides that, if NPC is able to issue short-term debt at any point prior to September 1, 2002 (whether or not the issuance of short-term debt actually occurs), the amount of long-term debt authorized by the order will be automatically reduced to $250 million. The PUCN order also provides that NPC will bear the burden of demonstrating that any financings undertaken pursuant to the order, including any determination made regarding the length of such commitment, the type of security or rate, is reasonable. Finally, the order requires that, until such time as the order's authorization expires (December 31, 2003), NPC must either receive the prior approval of the PUCN or reach an equity ratio of 42% before paying any dividends to SPR. If NPC achieves a 42% equity ratio prior to December 31, 2003, the dividend restriction ceases to have effect. On July 3, 2002, the BCP of the Nevada Attorney General's Office filed a petition with the PUCN requesting that the hearing in Docket No. 02-4037 be reopened to allow for the introduction of additional evidence or for the PUCN to reconsider its decision granting NPC the authority to issue long-term debt. On September 11, 2002, the PUCN denied the petition to reopen the proceeding and rescinded the portion of its Compliance Order that had previously required NPC to immediately issue $50 million to $100 million of debt. 50 In early May of 2002, Enron, MSCG, Reliant Energy Services, Inc. and several smaller suppliers terminated their power deliveries to NPC. These terminating suppliers asserted their contractual right under the WSPP agreement to terminate deliveries based upon NPC's alleged failure to provide adequate assurance of its performance under the WSPP agreement to any of its suppliers. Each of these terminating suppliers has asserted, or has indicated that it will assert, a claim for liquidated damages under the terminated power supply contracts. On June 5, 2002, Enron filed suit in its bankruptcy case in the Bankruptcy Court for the Southern District of New York asserting claims for liquidated damages related to the termination of its power supply agreements with NPC of approximately $216 million. NPC has filed claims in the Bankruptcy Court alleging, among other things, that NPC was fraudulently induced to enter into the agreements with Enron. Enron's claims are also subject to NPC's defense, as raised in NPC's motions to dismiss and or to stay all proceedings, that such claims are already at issue in NPC's FERC proceeding against Enron and others under Section 206 of the Federal Power Act challenging the contract prices of the terminated power supply agreements. Enron initially filed a motion for partial summary judgment to require NPC to make immediate payment of the full amount of Enron's claim, pending final resolution of the lawsuit. Enron subsequently filed another motion for summary judgment seeking final payment of its damages claim. Hearings, including arguments regarding the issue of FERC's primary jurisdiction over the contract claims, were conducted in September, October, and early November 2002. On November 14, 2002, the judge is expected to rule on the Utilities' motion to dismiss or stay until the FERC rules on the Utilities' Section 206 filing. If the judge decides not to stay Enron's lawsuit pending the outcome of the FERC hearings, the judge would then schedule additional arguments with respect to Enron's motion for summary judgment. At this time, the outcome of a decision in this matter cannot be predicted. An adverse decision on Enron's motion for summary judgment or an adverse decision in the lawsuit would have a material adverse affect on the financial condition and liquidity of NPC and would render its ability to continue to operate outside of bankruptcy uncertain. On June 10, 2002, Duke Energy Trading and Marketing ("Duke") entered into an agreement with NPC, SPR and SPPC to supply up to 1,000 megawatts of electricity per hour, as well as natural gas, to fulfill NPC's customers' power requirements during the peak summer period. The effect of the Duke agreement was to replace the amount of contracted power and natural gas that would have been supplied by the various terminating suppliers, including Enron. Duke also agreed to accept deferred payment for a portion of the amount due under its existing power contracts with NPC for purchases made through September 15, 2002. On October 25, 2002, Duke was paid in full with respect to these delayed payment amounts. On September 5, 2002, MSCG filed a Demand for Arbitration pursuant to the mediation and arbitration procedures of the WSPP agreement seeking a termination payment of approximately $25 million under its terminated power supply agreement. If this claim is not resolved by arbitration, NPC expects that MSCG will commence a lawsuit to recover liquidated damages under the terminated contract. On September 30, 2002, EPME notified NPC that it was terminating all transactions entered into with NPC under the WSPP agreement. On October 8, 2002, NPC received a letter from EPME seeking a termination payment of approximately $36 million with respect to the terminated WSPP agreement transactions. At the present time, NPC disagrees with EPME's calculation, and expects that net gains and losses relating to the terminated transactions, including a delayed payment amount of approximately $19 million owed to EPME for power deliveries through September 15, 2002, will result in a net payment due to NPC. On October 25, 2002 NPC redeemed its 7 5/8% Series L, First Mortgage Bonds in the aggregate principal amount of $15 million. On October 29, 2002, NPC issued and sold $250 million of its 10 7/8% General and Refunding Mortgage Notes, Series E, due 2009 for a purchase price of $235.6 million. The Series E Notes were issued with registration rights. The proceeds of the issuance were used to pay off NPC's $200 million credit facility and for general corporate purposes. The Series E Notes limit the amount of dividends that NPC may pay to SPR. However, that limitation does not apply to payments by NPC to enable SPR to pay its reasonable fees and expenses (including, but not limited to, interest on SPR's indebtedness and payment obligations on account of SPR's premium income equity securities) provided that those payments do not exceed $60 million for any one calendar year, those payments comply with any regulatory restrictions then applicable to NPC, and the ratio of consolidated cash flow to fixed charges for NPC's most recently ended four full fiscal quarters immediately preceding the date of payment is at least 1.75 to 1. The terms of the Series E Notes also permit dividend payments to SPR in an aggregate amount not to exceed $15 million from the date of the issuance of the Series E Notes. In addition, NPC may make dividend payments to SPR in excess of the amounts described above so long as, at the time of payment and after giving effect to the payment: there are no defaults or events of default with respect to the Series E Notes, NPC can meet a fixed charge coverage ratio test, and the total amount of such dividends is less than (i) the sum of 50% of NPC's consolidated net income measured on a quarterly basis cumulative of all quarters from the date of issuance of the Series E Notes, plus (ii) 100% of NPC's aggregate net cash proceeds from the issuance or sale of certain equity or convertible debt securities of NPC, plus (iii) the lesser of cash return of capital or the initial amount of certain restricted investments, plus (iv) the fair market value of NPC's investment in certain subsidiaries. 51 The terms of the Series E Notes also restrict NPC from incurring any additional indebtedness unless (i) at the time the debt is incurred, the ratio of consolidated cash flow to fixed charges for NPC's most recently ended four quarter period on a pro forma basis is at least 2 to 1, or (ii) the debt incurred is specifically permitted, which includes certain credit facility or letter of credit indebtedness, obligations incurred to finance property construction or improvement, indebtedness incurred to refinance existing indebtedness, certain intercompany indebtedness, hedging obligations, indebtedness incurred to support bid, performance or surety bonds, and certain letters of credit issued to support NPC's obligations with respect to energy suppliers. If NPC's Series E Notes are upgraded to investment grade by both Moody's and S&P, the dividend restrictions and the restrictions on indebtedness applicable to the Series E Notes will be suspended and will no longer be in effect so long as the Series E Notes remain investment grade. Among other things, the Series E Notes also contain restrictions on liens (other than permitted liens, which include liens to secure certain permitted debt) and certain sale and leaseback transactions. In the event of a change of control of NPC, the holders of Series E Notes are entitled to require that NPC repurchase the Series E Notes for a cash payment equal to 101% of the aggregate principal amount plus accrued and unpaid interest. The Series E Notes will mature October 15, 2009. NPC is in the process of negotiating a 364-day credit facility of up to $50 million. The 364-day credit facility will be secured by $50 million aggregate principal amount of NPC's General and Refunding Mortgage Bonds. The closing of the 364-day credit facility will be subject to the completion of the lender's due diligence, the negotiation and finalization of documentation and other customary closing conditions. Although NPC has commenced negotiations of the terms of the 364-day credit facility, it cannot give assurances that it will enter into the credit facility or any similar arrangement. SPR has a qualified pension plan (the "Plan") that covers substantially all employees of SPR, NPC and SPPC. The annual net benefit cost for the Plan is expected to increase for 2003 by an amount between $12 million and $22 million over the 2002 cost of $18.4 million. Also, the Plan currently has assets with a fair value that is less than the present value of the accumulated benefit obligation under the Plan. While the amount of the deficiency has not yet been determined, SPR and the Utilities expect their combined minimum funding requirement for 2002 will be at least $24 million. However, SPR and the Utilities do not expect that their funding obligation for 2002 will have a material adverse effect on their liquidity. NPC's liquidity would also be significantly affected by an adverse decision in the lawsuit by Enron, or by unfavorable rulings by the PUCN in future NPC or SPPC rate cases. Both S&P and Moody's have NPC's credit ratings on "watch negative" or "possible downgrade," and any further downgrades could further preclude NPC's access to the capital markets, and could adversely affect NPC's ability to continue to purchase power and fuel. Adverse developments with respect to any one or a combination of the foregoing could cause NPC to become insolvent and would render NPC's ability to continue to operate outside of bankruptcy uncertain. 52 SIERRA PACIFIC POWER COMPANY During the quarter ended September 30, 2002, SPPC earned approximately $13.5 million before preferred stock dividends. During this period, SPPC paid $975,000 in dividends to holders of its preferred stock and paid no dividends on its common stock, all of which is held by its parent, SPR. During the nine months ended September 30, 2002, SPPC incurred a loss of approximately $9.5 million before preferred stock dividends. During this period, SPPC paid $2.9 million in dividends to holders of its preferred stock and paid $19.9 million in dividends on its common stock, $10 million of which was reinvested in SPPC as a contribution to capital. On October 29, 2002, SPPC paid a common stock dividend of $25 million to its parent, SPR. The components of SPPC's gross margin are set forth below (dollars in thousands):
THREE MONTHS NINE MONTHS ENDED SEPTEMBER 30, ENDED SEPTEMBER 30, ------------------------------------------- ------------------------------------------- Change from Change from 2002 2001 Prior Year % 2002 2001 Prior Year % ------------ ----------- ------------ ----------- ------------ ------------ Operating Revenues: Electric $ 285,023 $ 581,957 -51.0% $ 705,946 $ 1,175,228 -39.9% Gas 18,473 18,831 -1.9% 99,139 104,725 -5.3% ------------ ----------- ----------- ------------ Total Revenues 303,496 600,788 -49.5% 805,085 1,279,953 -37.1% ------------ ----------- ----------- ------------ Energy Costs: Electric 198,727 498,513 -60.1% 536,824 972,897 -44.8% Gas 14,165 12,387 14.4% 76,234 81,654 -6.6% ------------ ----------- ----------- ------------ Total Energy Costs 212,892 510,900 -58.3% 613,058 1,054,551 -41.9% ------------ ----------- ----------- ------------ Gross Margin $ 90,604 $ 89,888 0.8% $ 192,027 $ 225,402 -14.8% ============ =========== =========== ============ Gross Margin by Segment: Electric $ 86,296 $ 83,444 3.4% $ 169,122 $ 202,331 -16.4% Gas 4,308 6,444 -33.1% 22,905 23,071 -0.7% ------------ ----------- ----------- ------------ Total $ 90,604 $ 89,888 0.8% $ 192,027 $ 225,402 -14.8% ============ =========== =========== ============
The causes for significant changes in specific lines comprising the results of operations for SPPC are as follows:
THREE MONTHS NINE MONTHS ENDED SEPTEMBER 30, ENDED SEPTEMBER 30, ---------------------------------------- ---------------------------------------- Change from Change from 2002 2001 Prior year % 2002 2001 Prior year % --------- --------- ------------ ---------- ---------- ------------ ELECTRIC OPERATING REVENUES ($000): Residential $ 59,145 $ 58,670 0.8% $ 164,598 $ 157,144 4.7% Commercial 81,856 71,387 14.7% 203,211 182,681 11.2% Industrial 76,776 67,590 13.6% 199,902 187,498 6.6% --------- --------- ---------- ---------- Retail revenues 217,777 197,647 10.2% 567,711 527,323 7.7% Other (1) 67,246 384,310 -82.5% 138,235 647,905 -78.7% --------- --------- ---------- ---------- TOTAL REVENUES $ 285,023 $ 581,957 -51.0% $ 705,946 $1,175,228 -39.9% ========= ========= ========== ========== Retail sales in thousands of megawatt-hours (MWH) 2,327 2,309 0.8% 6,607 6,538 1.1% Average retail revenue per MWH $ 93.59 $ 85.60 9.3% $ 85.93 $ 80.66 6.5%
(1) Primarily wholesale, as discussed below Retail electric revenues were higher for the three months ending September 30, 2002, compared to the same period the previous year. The increase was primarily a result of an overall rate increase that was effective June 1, 2002 (refer to Note 9, Regulatory Events), and, to a lesser extent, warmer than normal weather in July. Retail electric revenues increased for the nine months ended September 30, 2002, compared to the prior year primarily due to rate increases resulting from the 2001 Global Settlement and 2001 Comprehensive Energy Plan (CEP). During the first quarter 2001, these rate increases were being phased in on a monthly basis whereas retail revenues for the first quarter of 2002 reflect the cumulative impact of those increases. The third quarter 2002 weather effects resulted in a minimal revenue impact for the nine months ending September 30, 2002. 53 The decreases in Electric Operating Revenues - Other for the three- and nine-month periods ended September 30, 2002, compared to the same periods in 2001 were due to the decrease in prices and sales volume of wholesale electric power to other utilities, as a result of changing market conditions. See SPPC's Annual Report on Form 10-K for the year ended December 31, 2001, Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operation, Purchased Power Procurement, for a discussion of SPPC's purchased power procurement strategies.
THREE MONTHS NINE MONTHS ENDED SEPTEMBER 30, ENDED SEPTEMBER 30, --------------------------------------- -------------------------------------- Change from Change from 2002 2001 Prior year % 2002 2001 Prior year % ---------- ---------- ------------ ---------- ---------- ------------ GAS OPERATING REVENUES ($000): Residential $ 6,627 $ 7,861 -15.7% $ 49,735 $ 39,615 25.5% Commercial 4,027 4,267 -5.6% 26,112 20,331 28.4% Industrial 3,436 6,333 -45.7% 14,996 12,962 15.7% Miscellaneous 219 (542) -140.4% 1,627 86 1791.9% ---------- ---------- ---------- ---------- Total retail revenue 14,309 17,919 -20.1% 92,470 72,994 26.7% Wholesale revenue 4,164 912 356.6% 6,669 31,731 -79.0% ---------- ---------- ---------- ---------- TOTAL REVENUES $ 18,473 $ 18,831 -1.9% $ 99,139 $ 104,725 -5.3% ========= ========== ========== ========== Retail sales in thousands of decatherms 1,311 1,336 -1.9% 9,550 8,819 8.3% Average retail revenues per decatherm $ 10.91 $ 13.41 -18.6% $ 9.68 $ 8.28 16.9%
Retail gas revenues for the three-month period ended September 30, 2002 are lower than the same period in the prior year largely due to the refinement of revenue amounts from the first and second quarters of 2001 in the third quarter of 2001. The result caused the revenues for the third quarter of 2001 to be higher than in the current year. The decrease in third quarter 2002 revenues is also minimally due to large customers with alternative fuel capability using oil instead of natural gas in 2002. Retail gas revenues for the nine-month period ended September 30, 2002 were significantly higher than the same period in the prior year primarily due to PUCN-authorized rate increases effective on February 1 and November 5, 2001. Wholesale gas revenues for the nine-month period ended September 30, 2002 were significantly lower than the same period in 2001, primarily due to lower wholesale sales. The three months ended September 30, 2002 reflect higher wholesale gas revenues over the same period last year due to SPPC utilizing idle transportation to move gas from Canada and resell it in California in order to mitigate costs.
THREE MONTHS NINE MONTHS ENDED SEPTEMBER 30, ENDED SEPTEMBER 30, -------------------------------------- --------------------------------------- Change from Change from 2002 2001 Prior Year % 2002 2001 Prior Year % --------- ---------- ------------ ---------- ----------- ------------ PURCHASED POWER ($000): $ 164,124 $ 508,235 -67.7% $ 443,843 $ 907,830 -51.1% Purchased Power in thousands of MWHs 2,318 2,688 -13.8% 5,642 5,838 -3.4% Average cost per MWH of Purchased Power (1) $ 70.80 $ 189.08 -62.6% $ 63.29 $ 155.50 -59.3%
(1) Not including contract termination costs, discussed below Purchased power costs were lower for the three- and nine-month periods ended September 30, 2002, than the prior year because the majority of SPPC's total energy requirements utilize Short-Term Firm purchased power for which costs have significantly decreased from those a year ago. The nine-month decrease for the period ended September 30, 2002 was offset, in part, by an $86.8 million reserve recorded in the second quarter for terminated contracts, which are described in more detail in "Financial Condition, Liquidity, and Capital Resources." Prices for SPPC's risk management activities also decreased substantially. Risk management activities include transactions entered into for hedging purposes and to minimize purchased power costs. See SPPC's Annual Report on Form 10-K for the year ended December 31, 2001, Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operation, Purchased Power Procurement, for a discussion of SPPC's purchased power procurement strategies. 54
THREE MONTHS NINE MONTHS ENDED SEPTEMBER 30, ENDED SEPTEMBER 30, -------------------------------------- ------------------------------------- Change from Change from 2002 2001 Prior Year % 2002 2001 Prior Year % --------- ----------- ------------ ----------- ---------- ------------- FUEL FOR POWER GENERATION ($000) $32,804 $ 88,980 -63.1% $ 111,024 $ 237,504 -53.3% Thousands of MWHs generated 1,264 1,593 -20.7% 3,605 4,668 -22.8% Average fuel cost per MWH of Generated Power $ 25.95 $ 55.86 -53.5% $ 30.80 $ 50.88 -39.5%
Fuel for Power Generation costs for the three- and nine-month periods ended September 30, 2002 were significantly lower than the same period of the prior year as both volumes generated and natural gas prices decreased significantly.
THREE MONTHS NINE MONTHS ENDED SEPTEMBER 30, ENDED SEPTEMBER 30, -------------------------------------- ------------------------------------- Change from Change from 2002 2001 Prior Year % 2002 2001 Prior Year % --------- ----------- ------------ ----------- ---------- ------------- GAS PURCHASED FOR RESALE ($000) $ 9,884 $ 9,294 6.3% $ 61,585 $ 105,008 -41.4% Gas Purchased for Resale (thousands of decatherms) 2,882 1,660 73.6% 11,384 11,610 -1.9% Average cost per decatherm $ 3.43 $ 5.60 -38.8% $ 5.41 $ 9.04 -40.2%
Gas Purchased for Resale increased significantly for the three-month period ended September 30, 2002, compared to the prior year as an increase wholesale activity more than offset the decrease in gas prices. Gas Purchased for Resale decreased significantly for the nine months ended September 30, 2002, compared to the prior year because of much lower natural gas prices.
THREE MONTHS NINE MONTHS ENDED SEPTEMBER 30, ENDED SEPTEMBER 30, --------------------------------------- ---------------------------------------- Change from Change from 2002 2001 Prior Year % 2002 2001 Prior Year % ---------- ----------- ------------- ------------ ------------ ------------ DEFERRAL OF ENERGY COSTS-NET ($000) Deferred energy costs - electric - net $ 1,799 $ (98,702) N/A $ (71,144) $ (172,437) -58.7% Deferred energy costs disallowed - electric - - N/A 53,101 - N/A Deferred energy costs - gas - net 4,281 3,093 38.4% 14,649 (23,354) N/A --------- --------- ---------- ----------- Total $ 6,080 $ (95,609) N/A $ (3,394) (195,791) -98.3% ========= ========= ========== ===========
The change in Deferral of energy costs electric - net for the three- and nine-month periods ended September 30, 2002, compared to the same periods the prior year reflects the amortization in 2002 of prior deferred costs pursuant to the PUCN's decision on SPPC's deferred energy rate case, which resulted in increased rates beginning June 1, 2002. The amortization was offset, in part, by the recording of current year deferrals of electric energy costs, reflecting the extent to which actual fuel and purchased power costs exceeded the fuel and purchased power costs recovered through current rates. Deferral of energy costs-net for the nine months ended September 30, 2002, also reflects the deferral in the second quarter of 2002 of approximately $82 million for contract termination costs, as described in more detail in "Financial Condition, Liquidity, and Capital Resources" and the second quarter write-off of $53 million of electric deferred energy costs incurred in the nine months ended November 30, 2001, that were disallowed by the PUCN in their May 28, 2002, decision on SPPC's deferred energy rate case. For both the three- and nine-month periods ended September 30, 2001, SPPC recorded large deferrals of electric energy costs, as shown in the table above. SPPC's deferred energy costs gas - net for the three- and nine-month periods ended September 30, 2002 reflects the amortization of prior deferred costs due to the PUCN-authorized recovery of those costs. Deferred energy costs gas - net for the three-and nine-month periods ended September 30, 2002 also reflects additional expense to the extent natural gas costs recovered through current rates exceeded actual natural gas costs, which had decreased significantly. Deferral of energy costsnet for gas for the nine months ended September 30, 2001 reflects undercollections of such costs because revenue received from 2001 base purchased gas rates did not cover the increased cost of natural gas experienced by SPPC. 55
THREE MONTHS NINE MONTHS ENDED SEPTEMBER 30, ENDED SEPTEMBER 30, --------------------------------------- ------------------------------------------- Change from Change from 2002 2001 Prior Year % 2002 2001 Prior Year % ---------- ----------- ------------ ------------ ------------ ------------- ALLOWANCE FOR OTHER FUNDS USED DURING CONSTRUCTION ($000) $ (10) $ (19) $ 143 $ (233) ALLOWANCE FOR BORROWED FUNDS USED DURING CONSTRUCTION ($000) 694 566 1,314 943 --------- ---------- ------------ ----------- $ 684 $ 547 25.0% $ 1,457 $ 710 105.2% ========= ========== ============ ===========
Total allowance for funds used during construction (AFUDC) increased for the three-month period ended September 30, 2002, compared to the prior year due to an increase in Construction Work-in-Progress (CWIP). Total AFUDC for the nine-month period ended September 30, 2002, increased over the prior year due to an increase in CWIP and because AFUDC in 2001 reflected an adjustment to refine amounts assigned to specific components of facilities that were completed in different periods. This increase was offset, in part, by a decrease in the AFUDC rate.
THREE MONTHS NINE MONTHS ENDED SEPTEMBER 30, ENDED SEPTEMBER 30, ----------------------------------------- -------------------------------------- Change from Change from (000's) 2002 2001 Prior Year % 2002 2001 Prior Year % ------------ ----------- ------------ ----------- ---------- ------------ Other operating expense $ 25,064 $ 28,222 -11.2% $ 75,687 $ 79,090 -4.3% Maintenance expense $ 4,854 $ 5,143 -5.6% $ 15,250 $ 17,143 -11.0% Depreciation and amortization $ 18,592 $ 17,620 5.5% $ 55,861 $ 52,328 6.8% Income taxes $ 7,601 $ 8,630 -11.9% $ (9,037) $ 7,974 -213.3% Interest charges on long-term debt $ 16,173 $ 15,380 5.2% $ 48,638 $ 38,479 26.4% Interest charges - other $ 2,943 $ 1,455 102.3% $ 7,051 $ 7,437 -5.2% Other income (expense) - net $ 1,954 $ 4,309 -54.7% $ 4,631 $ 5,322 -13.0%
Other operating expense for the three-month period ending September 30, 2002 was lower than the same period in the prior year due to a third quarter 2001 increase in the provision for uncollectible accounts of approximately $4 million, and the reversal in 2002 of SPPC's Short-term Incentive Plan accrual offset, in part, by a 2001 decrease in the provision for uncollectible accounts related to the California Power Exchange and increased legal fees in 2002 associated with the PUCN's Deferred Energy Rate Case decision. The decrease in Other operating expense for the nine-month period ending September 30, 2002, compared with the same period in the prior year, reflects the third quarter 2001 increase in the provision for uncollectible accounts, a $2.7 million increase in the provision for uncollectible accounts in 2001 related to the California Power Exchange, and the 2002 reversal of a $3.5 million reserve provision established in 2001 as a result of the conclusion of electric industry restructuring in Nevada. These decreases were offset, in part, by increased expenses in 2002 related to a new Credit and Collections Action Plan, insurance premiums, and costs associated with obtaining a tax refund. Maintenance costs for the three- and nine- month periods ended September 30, 2002 were less than the same period last year as the 2001 costs included turbine repairs on Unit 1 at Valmy. Depreciation and amortization increased for the three-month period ended September 30, 2002, compared to the same period in 2001 as a result of additions to plant-in-service assets. Depreciation and amortization increased for the nine-month period ended September 30, 2002, compared to the same period in 2001 as a result of additions to plant-in-service assets and an increase to depreciation of $1.8 million to reflect an adjustment to depreciation rates related to combustion turbines. These increases were offset in part by a PUCN-ordered reduction in depreciation rates that was implemented June 1, 2002. SPPC recorded lower operating income tax expense for the three months ended September 30, 2002, compared to the same period in 2001. This decrease resulted from a 2001 reclassification of income taxes included in other income to operating income taxes that more than offset taxes on higher pre-tax income in 2002. For the nine months ended September 30, 2002, SPPC recorded an income tax benefit compared to income tax expense for the same period in 2001, as a result of a pre-tax loss in the current year compared to pre-tax income in the prior year. Interest charges on long-term debt for the three-month period ending September 30, 2002, increased over the same period in 2001 due to debt incurred at higher interest rates. An increased level of long-term debt at higher rates was also responsible for the increase in interest for the nine months ended September 30, 2002, over the comparable period in 2001. 56 Interest charges-other increased during the three-month period ending September 30, 2002, compared to 2001 due to higher short-term borrowings in the 2002 period. However, the decrease for the nine months ended September 30, 2002, as compared to the same period in 2001 was attributable to lower commercial paper and short-term debt balances during the nine-month period in 2002. Other income (expense) - net for the three months ended September 30, 2002, decreased compared to the same period in the prior year primarily due to a decrease in carrying charges for deferred energy. The decrease in Other income (expense) - net for the nine months ended September 30, 2002, compared to the prior year also reflects the second quarter 2002 write-off of approximately $2 million, net of taxes, of carrying charges on deferred energy costs that were disallowed by the PUCN in their May 28, 2002 decision on SPPC's deferred energy rate case. The write-off was offset in part by the recording of current year carrying charges on deferred fuel and purchased power costs. ANALYSIS OF CASH FLOWS SPPC's cash flows during the nine months ended September 30, 2002, improved compared to the same period in 2001, as increases in cash flows from operating and financing activities were offset in part by cash used for investing activities. Although SPPC recorded a loss for the nine months ended September 30, 2002, compared to net income for the same period in 2001, the current year's loss resulted largely from the write-off of disallowed deferred energy costs for which the cash outflow had occurred in 2001. Other factors contributing to 2002's improved cash flows from operating activities include lower energy prices and improved collections on accounts receivable, offset in part by lower accounts payable balances. Also, cash flows from operating activities in the current year reflect the receipt of an income tax refund. Cash flows from investing activities decreased in 2002 because 2001 investing activities included cash provided from the sale of the assets of SPPC's water business. Cash flows from financing activities increased due to an increase in short-term borrowings and a decrease in common dividends paid in 2002, offset in part by a decrease in net long-term debt issued in 2002, compared to the same period in 2001. FINANCIAL CONDITION, LIQUIDITY AND CAPITAL RESOURCES SPPC had cash and cash equivalents of approximately $143.9 million at September 30, 2002, and approximately $56.2 million at October 31, 2002. As discussed in "Management's Discussion and Analysis of Financial Condition and Results of Operations - Sierra Pacific Power Company - Construction Expenditures and Financing" and " - Capital Structure" in the Annual Report on Form 10-K for the year ended December 31, 2001, SPPC anticipated having capital requirements for construction costs and for the repayment of maturing short-term and long-term debt during 2002 totaling approximately $189 million, which SPPC would need to fund through a combination of (i) internally generated funds, (ii) the issuance of short-term debt, and (iii) capital contributions from SPR. On March 29 and April 1, 2002, following the decision by the PUCN in NPC's deferred energy rate case, S&P and Moody's lowered SPPC's unsecured debt ratings to below investment grade. On April 23 and 24, 2002, SPPC's unsecured debt ratings were further downgraded and its secured debt ratings were downgraded to below investment grade. The decision of the PUCN on May 29, 2002 on SPPC's deferred energy application to disallow $53.1 million of deferred purchased fuel and power costs accumulated between March 1, 2001 and November 30, 2001 did not result in any further downgrades of SPPC's securities. As a result of the downgrades, SPPC's ability to access the capital markets to raise funds is severely limited. Since SPR's credit ratings were similarly downgraded, SPR's ability to make capital contributions to SPPC also became severely limited. In connection with the credit ratings downgrades referenced above, SPPC lost its A2/P2 commercial paper ratings and can no longer issue commercial paper. At the time, SPPC had a commercial paper balance outstanding of $47.7 million with a weighted average interest rate of 2.49%. SPPC paid off its maturing commercial paper with the proceeds of borrowings under its credit facility and terminated its commercial paper program on May 28, 2002. SPPC does not expect to have direct access to the commercial paper market for the foreseeable future. SPPC's $150 million unsecured revolving credit facility was also affected by the downgrade in SPPC's credit rating. Under this facility, SPPC was required, in the event of a ratings downgrade of its senior unsecured debt, to secure the facility with General and Refunding Mortgage Bonds. In satisfaction of its obligation to secure the credit facility, on April 8, 2002, SPPC issued and delivered its General and Refunding Mortgage Bond, Series B, due November 28, 2002, in the principal amount of $150 million, to the Administrative Agent for the credit facility. As of May 10, 2002, SPPC had borrowed the entire $150 million of funds available under its credit facility to, in part, pay off maturing commercial paper, maintaining a cash balance at SPPC. This facility was paid in full and terminated on October 31, 2002 with available cash and proceeds from SPPC's $100 million Term Loan Facility. On October 29, 2002, SPPC established an accounts receivables purchase facility of up to $75 million, which was arranged by Lehman Brothers. If SPPC elects to activate the receivables purchase facility, SPPC will sell all of its accounts 57 receivable generated from the sale of electricity to customers to its newly created bankruptcy remote special purpose subsidiary. The receivables sales will be without recourse except for breaches of customary representations and warranties made at the time of sale. The subsidiary will, in turn, sell these receivables to a bankruptcy-remote subsidiary of SPR. SPR's subsidiary will issue variable rate revolving notes backed by the purchased receivables. Lehman Brothers Holdings, Inc. will be the sole initial committed purchaser of all of the variable rate revolving notes. The agreements relating to the receivables purchase facility contain various conditions to purchase, covenants and trigger events, termination events and other provisions customary in receivables transactions. In addition, the agreements contain a limitation on the payment of dividends by SPPC to SPR that is identical to the limitation contained in SPPC's Term Loan Agreement, described below. In connection with SPPC's receivables facility, SPR has agreed to guaranty SPPC's performance of certain obligations as a seller and servicer under the facility. SPPC has agreed to issue $75 million principal amount of its General and Refunding Mortgage Bonds upon activation of the accounts receivables purchase facility. The full principal amount of the Bond would secure certain of SPPC's obligations as seller and servicer, plus certain interest, fees and expenses thereon to the extent not paid when due, regardless of the actual amounts owing with respect to the secured obligations. As a result, in the event of an SPPC bankruptcy or liquidation, the holder of the Bond securing the receivables facility may recover more on a pro rata basis than the holders of other General and Refunding Mortgage securities, who could recover less on a pro rata basis, than they otherwise would recover. However, in no event will the holder of the Bond recover more than the amount of obligations secured by the Bond. SPPC intends to use the accounts receivables purchase facility as a back-up liquidity facility and does not plan to activate this facility in the foreseeable future. SPPC may activate the facility within five days upon the delivery of certain customary funding documentation and the delivery of the $75 million General and Refunding Mortgage Bond. SPPC's first mortgage indenture creates a first priority lien on substantially all of SPPC's properties in Nevada and California. As of September 30, 2002, $505.3 million of SPPC's first mortgage bonds were outstanding. Although the first mortgage indenture allows SPPC to issue additional mortgage bonds on the basis of (i) 60% of net utility property additions and/or (ii) the principal amount of retired mortgage bonds, SPPC agreed in its General and Refunding Mortgage Indenture that it would not issue any additional first mortgage bonds. SPPC's General and Refunding Mortgage Indenture creates a lien on substantially all of SPPC's properties in Nevada that is junior to the lien of the first mortgage indenture. As of September 30, 2002, $470 million of SPPC's General and Refunding Mortgage bonds were outstanding. Additional securities may be issued under the General and Refunding Mortgage Indenture on the basis of (i) 70% of net utility property additions, (ii) the principal amount of retired General and Refunding Mortgage bonds, and/or (iii) the principal amount of first mortgage bonds retired after delivery to the indenture trustee of the initial expert's certificate under the General and Refunding Mortgage Indenture. At September 30, 2002, SPPC had the capacity to issue approximately $363 million of additional General and Refunding Mortgage securities, not including the issuance of SPPC's $100 million Series C General and Refunding Mortgage Bond which secures SPPC's Term Loan Facility and the retirement of $150 million of Series B General and Refunding Mortgage Bonds that secured SPPC's terminated credit facility. However, the financial covenants contained in SPPC's Term Loan Agreement and Receivable Purchase Facility Agreements limit SPPC's ability to issue additional General and Refunding Mortgage Securities or other debt. SPPC will reserve $75 million of General and Refunding Mortgage Bonds for issuance upon the initial funding of its receivables purchase facility. SPPC also has the ability to release property from the liens of the two mortgage indentures on the basis of net property additions, cash and/or retired bonds. To the extent SPPC releases property from the lien of its General and Refunding Mortgage Indenture, it will reduce the amount of bonds issuable under that indenture. In early May of 2002, Enron, MSCG, Reliant Energy Services, Inc. and several smaller suppliers terminated their power deliveries to SPPC. These terminating suppliers asserted their contractual right under the WSPP agreement to terminate deliveries based upon SPPC's alleged failure to provide adequate assurance of its performance under the WSPP agreement to any of its suppliers. Each of these terminating suppliers has asserted, or has indicated that it will assert, a claim for liquidated damages under the terminated power supply contracts. On June 5, 2002, Enron filed suit in its bankruptcy case in the Bankruptcy Court for the Southern District of New York asserting claims for liquidated damages related to the termination of its power supply agreements with SPPC of approximately $93 million. SPPC has filed claims in the Bankruptcy Court alleging, among other things, that SPPC was fraudulently induced to enter into the agreements with Enron. Enron's claims are also subject to SPPC's defense, as raised in SPPC's motions to dismiss and or to stay all proceedings, that such claims are already at issue in SPPC's FERC proceeding against Enron and others under Section 206 of the Federal Power Act challenging the contract prices of the terminated power supply agreements. Enron initially filed a motion for partial summary judgment to require SPPC to make immediate payment of the full amount of Enron's claim, pending final resolution of the lawsuit. Enron subsequently filed another motion for summary judgment seeking final payment of its damages claim. Hearings, including arguments regarding the issue of FERC's primary jurisdiction over the contract claims, were conducted in September, October, and early November 2002. On November 14, 2002, the judge is expected to rule on the Utilities' motion to dismiss or stay until the FERC rules on the Utilities' Section 206 filing. If the judge decides not to stay Enron's lawsuit pending the outcome 58 of the FERC hearings, the judge would then schedule additional arguments with respect to Enron's motion for summary judgment. At this time, the outcome of a decision in this matter cannot be predicted. An adverse decision on Enron's motion for summary judgment or an adverse decision in the lawsuit would have a material adverse affect on the financial condition and liquidity of SPPC and would render its ability to continue to operate outside of bankruptcy uncertain. On May 23, 2002, SPPC defeased its 2% First Mortgage Bonds due 2011, 5% Series Y First Mortgage Bonds due 2024, and 2% Series Z First Mortgage Bonds due 2004 by depositing $1.2 million, $3.1 million, and $45,000, respectively, with its First Mortgage Trustee. These First Mortgage Bonds were issued to secure loans made to SPPC by the United States under the Rural Electrification Act of 1936, as amended. On October 30, 2002, SPPC entered into a $100 million Term Loan Agreement with several lenders and Lehman Commercial Paper Inc., as Administrative Agent. The net proceeds of $97 million from the Term Loan Facility, along with available cash, were used to pay off SPPC's $150 million credit facility, which was secured by a Series B General and Refunding Mortgage Bond. SPPC's Term Loan Agreement limits the amount of dividends that SPPC may pay to SPR. However, that limitation does not apply to payments by SPPC to enable SPR to pay its reasonable fees and expenses (including, but not limited to, interest on SPR's indebtedness and payment obligations on account of SPR's premium income equity securities) provided that those payments do not exceed $90 million, $80 million and $60 million in the aggregate for the twelve month periods ending on October 30, 2003, 2004 and 2005, respectively. The Term Loan Agreement also permits SPPC to make dividend payments to SPR in an aggregate amount not to exceed $10 million during the term of the Term Loan Agreement. In addition, SPPC may make dividend payments to SPR in excess of the amounts described above so long as, at the time of the payment and after giving effect to the payment, there are no defaults or events of default under the Term Loan Agreement, and such amounts, when aggregated with the amount of dividends paid to SPR by SPPC since the date of execution of the Term Loan Agreement, does not exceed the sum of (i) 50% of SPPC's Consolidated Net Income for the period commencing January 1, 2003 and ending with last day of fiscal quarter most recently completed prior to the date of the contemplated dividend payment plus (ii) the aggregate amount of cash received by SPPC from SPR as equity contributions on its common stock during such period. SPPC's Term Loan Agreement requires that SPPC maintain a ratio of consolidated total debt to consolidated total capitalization at all times during each of the following quarters in an amount not to exceed (i) .650 to 1.0 for the fiscal quarters ended December 31, 2002 through December 31, 2003, (ii) .625 to 1.0 for the fiscal quarters ended March 31, 2004 through December 31, 2004, and (iii) .600 to 1.0 for the fiscal quarter ended March 31, 2005 and for each fiscal quarter thereafter. SPPC's Term Loan Agreement also requires that SPPC maintain a consolidated interest coverage ratio for any four consecutive fiscal quarters ending with the fiscal quarter set forth below of not less than (i) 1.75 to 1.00 for the fiscal quarters ended December 31, 2002 and March 31, 2003, (ii) 2.50 to 1.0 for the fiscal quarters ended June 30, 2003 through December 31, 2003, (iii) 2.75 to 1.0 for the fiscal quarters ended March 31, 2004 through September 30, 2004, and (iv) 3.00 to 1.0 for the fiscal quarter ended December 31, 2004 and for each fiscal quarter thereafter. The Term Loan Facility, which is secured by a $100 million Series C General and Refunding Mortgage Bond, will expire October 31, 2005. SPR has a qualified pension plan (the "Plan") that covers substantially all employees of SPR, NPC and SPPC. The annual net benefit cost for the Plan is expected to increase for 2003 by an amount between $12 million and $22 million over the 2002 cost of $18.4 million. Also, the Plan currently has assets with a fair value that is less than the present value of the accumulated benefit obligation under the Plan. While the amount of the deficiency has not yet been determined, SPR and the Utilities expect their combined minimum funding requirement for 2002 will be at least $24 million. However, SPR and the Utilities do not expect that their funding obligation for 2002 will have a material adverse effect on their liquidity. SPPC's Washoe County, Nevada, Water Facilities Refunding Revenue Bonds, Series 2001 in the aggregate principal amount of $80,000,000, will be subject to remarketing on May 1, 2003. In the event that these bonds cannot be successfully remarketed on that date, SPPC will be required to purchase the outstanding bonds at a price of 100% of the principal amount, plus accrued interest. SPPC's future liquidity could be significantly affected by unfavorable rulings by the PUCN in future SPPC or NPC rate cases. Both S&P and Moody's have SPPC's credit ratings on "watch negative" or "possible downgrade," and any further downgrades could further preclude SPPC's access to the capital markets and could adversely affect SPPC's ability to continue purchasing power and fuel. Adverse developments with respect to any one or a combination of the factors and contingencies set forth above could cause SPPC to become insolvent and could render SPPC's ability to continue to operate outside of bankruptcy uncertain. SIERRA PACIFIC RESOURCES (HOLDING COMPANY) The Condensed Consolidated Statements of Operations of SPR include the operating results of the holding company. For the nine months ending September 30, 2002, the holding company recognized higher interest costs, $53.8 million in 2002 compared to $40.3 million in 2001, due primarily to the issuance of $345 million of additional debt associated with its issuance of Premium Income Equity Securities in November of 2001. 59 TUSCARORA GAS PIPELINE COMPANY The Condensed Consolidated Statements of Operations of SPR include the operating results of Tuscarora Gas Pipeline Company (TGPC), a wholly owned subsidiary of SPR. For the three-and nine-month periods ended September 30, 2002, TGPC contributed $.7 million and $2.3 million, respectively, in net income. For the three-and nine-month periods ended September 30, 2001, TGPC contributed $.6 million and $1.9 million, respectively, in net income. E-THREE The Condensed Consolidated Statements of Operations of SPR include the operating results of e-three, a wholly owned subsidiary of SPR. For the three-and nine-month periods ended September 30, 2002, e-three incurred net losses of $14,000 and $.8 million, respectively. For the three-and nine-month periods ended September 30, 2001, e-three contributed $.3 million and $.2 million in net income, respectively. SIERRA PACIFIC COMMUNICATIONS The Condensed Consolidated Statements of Operations of SPR include the operating results of Sierra Pacific Communications (SPC), a wholly owned subsidiary of SPR. For the three- and nine-month periods ended September 30, 2002, SPC incurred net losses of $1.1 million and $2.4 million, respectively. SPC incurred net losses of $1.7 million and $2.4 million, respectively, for the three- and nine-month periods ended September 30, 2001. In April 2000 Sierra Touch America, LLC, a partnership between SPC and Touch America, was formed to construct a fiber optic line between Salt Lake City, Utah and Sacramento, California. On September 9, 2002, SPC purchased and leased certain telecommunications and fiber optic assets from Touch America in exchange for SPC's partnership units in Sierra Touch America and the execution of a $35 million promissory note for a total of $48.5 million. The assets are currently under construction and are scheduled for completion in May 2003. Of the $48.5 million total, $32.5 million relates to the purchase of a conduit from Sacramento to Salt Lake City, additional conduit in the Reno, Nevada metropolitan area, and real property in Utah. $16 million of the total was for the lease of two conduits from Reno to Spanish Fork, Utah and the lease of 60 strands of fiber from Sacramento to Salt Lake City. The promissory note accrues interest at 8% per annum. The first of twelve monthly payments of $3.3 million will commence on July 31, 2003 and continue until June 30, 2004, at which time all outstanding amounts will be due and payable. The promissory note is secured by all of SPC's assets, and prepayments will shorten the length of the loan, but not reduce the installment payments. Also, on September 11, 2002, SPC entered into an agreement to sell to a telecommunications carrier for $20 million the Sacramento to Salt Lake City conduit acquired from Touch America, and will convey all rights to the conduit when construction is completed in May 2003. REGULATORY MATTERS Substantially all of the utility operations of both NPC and SPPC are conducted in Nevada. As a result both Utilities are subject to utility regulation within Nevada and therefore deal with many of the same regulatory issues. NEVADA MATTERS NEVADA POWER COMPANY GENERAL RATE CASE (NPC) On October 1, 2001, NPC filed an application with the PUCN seeking an electric general rate increase. This application was mandated by AB 369. On December 21, 2001, NPC filed a Certification to its general rate filing updating costs and revenues pursuant to Nevada regulations. In the certification filing, NPC requested an increase in its general rates charged to all classes of electric customers designed to produce an increase in annual electric revenues of $22.7 million, which is an overall 1.7% rate increase. The application also sought a return on common equity ("ROE") for Nevada Power's total electric operations of 12.25% and an overall rate of return ("ROR") of 9.30%. On March 27, 2002, the PUCN issued its decision on the general rate application, ordering a $43 million revenue decrease with an ROE of 10.1% and ROR of 8.37%. The effective date for the decision was April 1, 2002. The decision also resulted in adverse adjustments to depreciation aggregating $7.9 million, and the adverse treatment of approximately $5 million of revenues related to SO2 Allowances. On April 15, 2002, NPC filed a petition for reconsideration with the PUCN. In the petition, NPC raised six issues for reconsideration: the treatment of revenues related to SO2 Allowances, in particular the 60 calculation of the annual amortization amount, which appears to be in error; the adjustment for "excess" capital investment related to common facilities at the Harry Allen generating station; the rejection of adjustments to accumulated depreciation reserves related to the establishment of revised depreciation rates for transmission, distribution and common facilities; the delay in allowing NPC to recover its merger costs without the benefit of carrying charges; the finding that NPC has no need for and is entitled to zero funds cash working capital; and the establishment of a 10.1% ROE. On May 24, 2002, the PUCN issued an order on the petition for reconsideration. In its order the PUCN reaffirmed its findings in the original order for the issues related to "excess" capital investment at the Harry Allen generating station, merger costs, cash working capital, and the 10.1% ROE. The PUCN, however, did modify its original order to include adjustments related to SO2 Allowances and depreciation issues. Revised rates for these changes went into effect on June 1, 2002. NEVADA POWER COMPANY DEFERRED ENERGY CASE (NPC) On November 30, 2001, NPC filed an application with the PUCN seeking to clear deferred balances for purchased fuel and power costs accumulated between March 1, 2001 through September 30, 2001,as mandated by AB 369. The application sought to establish a Deferred Energy Accounting Adjustment ("DEAA") rate to clear accumulated purchased fuel and power costs of $922 million and spread the recovery of the deferred costs, together with a carrying charge, over a period of not more than three years. On March 29, 2002, the PUCN issued its decision on the deferred energy application, allowing NPC to recover $478 million over a three-year period, but disallowing $434 million of deferred purchased fuel and power costs and $10 million in carrying charges. The order states that the disallowance was based on alleged imprudence in incurring the disallowed costs. On April 11, 2002, NPC filed a lawsuit in the First District Court of Nevada seeking to reverse portions of the PUCN's decision. NPC asserts that, as a result of the PUCN's decision, NPC's credit rating was reduced to below investment grade, SPR suffered a reduction in its equity market capitalization by approximately 41%, and the disallowed costs are effectively imposed upon SPR's shareholders. In its lawsuit, NPC alleges that the order of the PUCN is: in violation of constitutional and statutory provisions; made upon unlawful procedure; affected by other error of law; clearly erroneous in view of the reliable, probative and substantial evidence on the whole record; arbitrary and capricious and characterized by abuse of discretion. NPC also states that its decisions with respect to the purchase of power during the energy crisis in the western United States were made prudently, as required under AB 369. In early 2001, the PUCN and the Nevada State Legislature expressly required that NPC secure sufficient, safe and reliable power for anticipated summer loads and needs for the summer of 2001. Prior to the April 2001 enactment of AB 369, which prohibits until July 2003 all divestiture of generation assets, NPC was operating under an order of the PUCN to divest itself of its electric generating plants. To meet this requirement, NPC had engaged in an open auction process that led to the signing of asset sale agreements for a number of its plants, in connection with which, NPC entered into long-term purchase power contracts with the potential buyers that would have availed NPC of reasonably priced purchase power over a long-term period. In its petition, NPC challenges the disallowance by the PUCN of $180 million of its deferred energy costs relating to an informal offer made by an agent for Merrill Lynch for the delivery of energy from January 2001 to March 2003. In addition to certain procedural questions relating to the PUCN's finding with respect to the Merrill Lynch informal offer, NPC asserts that the energy being negotiated was not firm (uninterruptible), the obligations, costs and arrangements for delivery in the informal offer were not specified, the cost of the energy proposed under the informal offer was above then-current market price, and that the supplier was a minor market participant and the magnitude of the transaction proposed was more than 45 times its previously combined annual transactions. NPC's lawsuit requests that the District Court reverse portions of the PUCN's order and remand the matter to the PUCN with direction that the PUCN authorize NPC to immediately establish rates that would allow NPC to recover its entire deferred energy balance of $922 million, with a carrying charge, over three years. A hearing on this matter has been scheduled for February 2003. At this time, NPC is not able to predict the outcome or the timing of a decision in this matter. Various interveners in NPC's deferred energy case before the PUCN filed petitions with the PUCN for reconsideration of the PUCN's order, seeking additional disallowances of between $12.8 million and $488 million. On May 24, 2002, the PUCN issued an order denying any further disallowances and granted NPC the authority to increase the deferred energy cost recovery charge for the month of June 2002 by one cent per kilowatt-hour. This increase accelerated the recovery of the deferred balance by approximately $16 million for the month of June 2002 only. The BCP of the Nevada Attorney General's Office has since filed a petition in NPC's pending state court case seeking additional disallowances. SIERRA PACIFIC POWER COMPANY GENERAL RATE CASE (SPPC) On November 30, 2001, SPPC filed an application with the PUCN seeking an electric general rate increase. This application was mandated by AB 369. On February 28, 2002, SPPC filed a certification to its general rate filing, updating costs and revenues pursuant to Nevada regulations. In the certification filing, SPPC requested an increase in its general rates charged to all classes of electric customers, which were designed to produce an increase in annual electric revenues of 61 $15.9 million representing an overall 2.4% rate increase. The application also sought an ROE for SPPC's total electric operations of 12.25% and an overall ROR of 9.42%. On May 28, 2002, the PUCN issued its decision on the general rate application, ordering a $15.3 million revenue decrease with an ROE of 10.17% and ROR of 8.61%. The effective date of the decision was June 1, 2002. Various parties to the case had filed petitions for reconsideration of the order. On July 18, 2002, the PUCN issued a final decision on the petitions for reconsideration, clarifying issues contained its original order. As a result of the clarifications, SPPC was ordered to change the total annual electric revenue decrease from $15.3 million to $15.8 million. On August 19, 2002, Barrick filed a lawsuit in the First District Court of Nevada seeking to reverse portions of the decision related to the High Voltage Distribution facilities contained in the general rate case order. Barrick alleges that the order of the PUCN is: in violation of constitutional and statutory provisions; in excess of the statutory authority of the PUCN; affected by error of law: clearly erroneous in view of the reliable, probative and substantial evidence on the whole record; and arbitrary or capricious or characterized by abuse of discretion. A hearing date has not yet been scheduled. At this time, SPPC is not able to predict the outcome or the timing of a decision in this matter. SIERRA PACIFIC POWER COMPANY DEFERRED ENERGY (SPPC) On February 1, 2002, SPPC filed an application with the PUCN seeking to clear deferred balances for purchased fuel and power costs accumulated between March 1, 2001 and November 30, 2001. This application was mandated by AB 369. The application sought to establish a DEAA rate to clear accumulated purchased fuel and power costs of $205 million and spread the cost recovery over a period of not more than three years. It also sought to recalculate the Base Tariff Energy Rate to reflect anticipated ongoing purchased fuel and power costs. The total rate increase resulting from the requested DEAA would have amounted to 9.8%. Various parties intervened in SPPC's deferred energy rate case including the Staff of the PUCN, the BCP from the Nevada Attorney General's office, and Barrick, among others. Interveners proposed disallowances ranging from $40.4 million to $361 million. On May 28, 2002, the PUCN issued its decision on the deferred energy application, allowing SPPC three years to collect $150 million but disallowing $53 million of deferred purchased fuel and power costs and $2 million in carrying charges. Several of the interveners from SPPC's deferred energy rate case filed petitions with the PUCN for reconsideration of its decision, seeking an additional disallowance of $126 million. On July 18, 2002, the petitions for reconsideration were granted in part and denied in part by the PUCN, but no additional disallowances to the deferred energy balance resulted from that decision. On August 22, 2002, SPPC filed a lawsuit in the First District Court of Nevada seeking to reverse portions of the decision of the PUCN denying the recovery of deferred energy costs incurred by SPPC on behalf of its customers in 2001 on the grounds that such power costs were not prudently incurred. In its lawsuit, SPPC alleges that the order of the PUCN is: in violation of constitutional and statutory provisions; in excess of the statutory authority of the PUCN; made upon unlawful procedure; affected by other error of law; clearly erroneous in view of the reliable, probative and substantial evidence on the whole record; arbitrary and capricious and characterized by abuse of discretion. SPPC's lawsuit requests that the District Court reverse portions of the order of the PUCN and remand the matter to the PUCN with direction that the PUCN authorize SPPC to immediately establish rates that would allow SPPC to recover its entire deferred energy balance of $205 million, with a carrying charge, over three years. A hearing date has not yet been scheduled. On August 22, 2002, the BCP from the Nevada Attorney General's office also filed a lawsuit in the First District Court of Nevada seeking to set aside the decision of the PUCN so that SPPC is not authorized to reflect in rates any costs for fuel and purchased power which may have been imprudently incurred. A hearing date has not yet been scheduled. At this time, SPPC is not able to predict the outcome or the timing of a decision in these matters. CUSTOMERS FILE UNDER AB 661 (NPC, SPPC) Assembly Bill 661 (AB 661), passed by the Nevada legislature in 2001, allows commercial and governmental customers with an average demand greater than 1 MW to select new energy suppliers. The Utilities would continue to provide transmission, distribution, metering and billing services to such customers. AB 661 requires customers wishing to choose a new supplier to receive the approval of the PUCN and meet public interest standards. In particular, departing customers must secure new energy resources that are not under contract to the Utilities, the departure must not burden the Utilities with increased costs or cause any remaining customers to pay increased costs, and the departing customers must pay their portion of any deferred energy balances. The PUCN adopted regulations prescribing the criteria that will be used to determine if there will be negative impacts to remaining customers or the Utility. These regulations place certain limits upon the departure of NPC customers until 2003; most significantly, the amount of load departing is limited to approximately 1100 MW in peak conditions. Customers wishing to choose a new supplier must provide 180-day notice to the Utilities. AB 661 permitted 62 customers to file applications with the PUCN beginning in the fourth quarter of 2001, and customers could begin to receive service from new suppliers by mid-2002. On January 10, 2002, Barrick, an approximately 130 MW SPPC customer, filed an application with the PUCN to exit the system of SPPC and to purchase energy, capacity and ancillary services from a provider other than SPPC. A stipulation filed on March 8, 2002 by SPPC and Barrick was rejected by the PUCN on March 29, 2002. The PUCN indicated a desire for more information regarding transmission access, the definition of a new electric resource, and the computation of exit fees. Subsequently, a second application was filed and later withdrawn by Barrick. Barrick has filed a new application with the PUCN. Barrick could receive service from a new supplier as early as May 1, 2003. A hearing date on this application has not yet been scheduled. During May 2002, Rouse Fashion Show Management LLC, Coast Hotels and Casinos Inc., Station Casinos, Inc., Gordon Gaming Corporation, MGM Mirage, and Park Place Entertainment filed separate applications with the PUCN to exit the system of NPC and to purchase energy, capacity and ancillary services from a provider other than NPC. The loads of these customers aggregate 260 MW on peak. Hearings on the applications of all the customers except Park Place Entertainment were completed on July 19, and the PUCN issued its decision on July 31, 2002. In its decision, the PUCN approved the applications of these customers to choose an energy supplier other than NPC. The earliest any of these customers could have begun taking energy from an alternative provider was November 1, 2002. If all five customers whose applications were approved were to leave its system, NPC would incur an annual loss in revenue of $48 million, which would be offset by a reduction in costs, primarily for fuel and purchased power, of $46 million with the difference being paid by exit fees from the departing customers. These customers will also be responsible for their share of balances in NPC's deferred energy accounts until the time they leave and must continue to pay their share of these balances after they leave. For example, if all five customers whose applications were approved had left the system on November 1, 2002, their remaining share of NPC's previously approved deferred energy balance is estimated to have been $27 million. Additionally, these departing customers would be responsible for paying their share of the yet to be approved accumulated deferred energy balances from October 1, 2001 to their date of departure. They will also remain accountable to any rulings made by the District Court on legal actions brought in NPC's past deferred energy case. They could also benefit from any refunds that might be granted on power contracts under review with the FERC. A hearing on the application of Park Place Entertainment was held on August 2, 2002, and on August 12, 2002, the PUCN approved the application with terms and conditions similar to those described above for the aforementioned five customers. All of the customers approved for departure are addressing compliance items in their PUCN orders. To date, none of these customers has provided official notice of departure. Other customers are continuing to express an interest, and additional gaming properties, including Monte Carlo, Riviera, and Imperial Palace, have indicated intent to potentially procure energy sources from a new supplier. Any customer who departs NPC's system and later decides to return to NPC as their energy provider will be charged for their energy at a rate equivalent to NPC's incremental cost of service. A stipulation regarding the incremental cost of service tariff is currently pending before the PUCN. NEVADA POWER COMPANY ADDITIONAL FINANCE AUTHORITY (NPC) On April 26, 2002, Nevada Power filed with the PUCN an application seeking additional finance authority. In the application NPC asked for authority to issue secured long-term debt in an aggregate amount not to exceed $450 million through the period ending 2003. On June 19, 2002, the PUCN issued a Compliance Order, Docket No. 02-4037, authorizing NPC to issue $300 million of long-term debt. The PUCN order requires NPC, if it is able, to issue the $50 million of remaining authorized short-term debt, before it issues any long-term debt authorized by the order. Moreover, the order provides that, if NPC is able to issue short-term debt at any point prior to September 1, 2002 (whether or not the issuance of short-term debt actually occurs), the amount of long-term debt authorized by the order will be automatically reduced to $250 million. Other provisions of the PUCN's order are discussed in NPC's "Financial Condition, Liquidity, and Capital Resources." ANNUAL PURCHASED GAS COST ADJUSTMENT (SPPC) On July 1, 2002, SPPC filed a Purchased Gas Cost Adjustment application for its natural gas local distribution company. In the application SPPC has asked for a reduction of $0.05421 to its Base Purchased Gas Rate (BPGR) and an increase in its Balancing Account Adjustment charge (BAA) by the same amount. This request would result in no change to revenues or customer rates. Hearings have been scheduled to begin November 18, 2002. This docket was consolidated for hearing purposes with the Liquid Petroleum Gas Cost Adjustment below. LIQUID PETROLEUM GAS COST ADJUSTMENT (SPPC) On July 1, 2002, SPPC filed an application to adjust rates for its liquid petroleum gas (LPG) distribution company. In the application SPPC has asked for an increase of $0.04133 to its current LPG rate and a decrease in its Balancing Account 63 Adjustment charge (BAA) by the same amount. This request would result in no change to revenues or customer rates. Hearings have been scheduled to begin November 18, 2002. This docket was consolidated for hearing purposes with the annual Purchased Gas Cost Adjustment above. CALIFORNIA MATTERS (SPPC) RATE STABILIZATION PLAN SPPC serves approximately 44,500 customers in California. On June 29, 2001, SPPC filed with the California Public Utilities Commission (CPUC) a Rate Stabilization Plan, which includes two phases. Phase One, which was also filed June 29, 2001, is an emergency electric rate increase of $10.2 million annually or 26%. If granted, the typical residential monthly electric bill for a customer using 650 kilowatt-hours would increase from approximately $47.12 to $60.12. On August 14, 2001, a pre-hearing conference was held, and a procedural order was established. On September 27, 2001, the Administrative Law Judge issued an order stating that no interim or emergency relief could be granted until the end of the "rate freeze" period mandated by the California restructuring law for recovery of stranded costs. In accordance with the judge's request, on October 26, 2001, SPPC filed an amendment to its application declaring the rate freeze period to be over. On December 5 and 11, 2001, hearings were held and on January 11, 2002 and January 25, 2002 opening briefs and reply briefs were filed. On July 17, 2002, the CPUC approved the requested 2-cent per kilowatt-hour surcharge, subject to refund and interest pending the outcome of Phase Two. The increase of $10 million or 26% is applicable to all customers except those eligible for low-income and medical-needs rates and went into effect July 18, 2002. Phase Two of the Rate Stabilization Plan was filed with the CPUC on April 1, 2002, and includes a general rate case and requests the CPUC to reinstate the Energy Cost Adjustment Clause, which would allow SPPC to file for periodic rate adjustments to reflect its actual costs for wholesale energy supplies. Phase Two also includes a proposal to terminate the 10% rate reduction mandated by AB 1890, but does not include a performance -based rate-making proposal. This request was for an additional overall increase in revenues of 17.1%, or $8.9 million annually. Hearings are scheduled for February 25 through March 3, 2003, and a decision by the CPUC is expected in the third quarter of 2003. CALIFORNIA ASSEMBLY BILL 1235 (SPPC) On September 24, 2002, the Governor of California signed into law Assembly Bill 1235 (AB 1235), which allows the transfer of hydroelectric plants along the Truckee River from SPPC to the Truckee Meadows Water Authority (TMWA). AB 1235 effectively amends previous California legislation (AB 6X) that prevented until 2006 private utilities from selling any power plants that provide energy to California customers. AB 1235 provides an exemption for the four "run-of-the-river" hydroelectric plants that SPPC sold to TMWA as part of the sale of its water business in June 2001. AB 1235 was effective September 24, 2002, and the process to transfer the plants from SPPC to TMWA has begun. The CPUC must now review and approve the transfer of the plants. FERC MATTERS (SPPC, NPC) FERC 206 COMPLAINTS In December 2001, the Utilities filed ten wholesale purchased power complaints with the FERC under Section 206 of the Federal Power Act seeking their review of certain forward power purchase contracts that the Utilities entered into prior to the price caps established by the FERC during the western United States utility crisis. The Utilities believe the prices under these purchased power contracts are unjust and unreasonable. The FERC ordered the case set for hearing and assigned an administrative law judge. A primary issue is whether or not the dysfunctional short-term market, which was previously declared by the FERC, impacted the forward market. The Utilities negotiated a settlement with Duke Energy Trading and Marketing and have engaged in bilateral settlement discussions with other respondents as well. Written direct and rebuttal testimony have been filed by the parties that have not negotiated settlements with the Utilities. Hearings concluded on October 24, 2002, and a draft decision is expected in December 2002. At this time, the Utilities are not able to predict the outcome of a decision in this matter. OPEN ACCESS TRANSMISSION TARIFF On September 27, 2002, the Utilities filed with the FERC a revised Open Access Transmission Tariff. The purpose of the filing was to implement changes that are required to implement retail open access in Nevada. The Utilities have requested the changes to become effective November 1, 2002, the date retail access is scheduled to commence in Nevada in accordance with provisions of AB 661, passed in the 2001 session of the Nevada Legislature. 64 ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK SPR has evaluated its risk related to financial instruments whose values are subject to market sensitivity, such as fixed and variable rate debt and preferred trust securities obligations. As shown in SPR's Form 10-K for the year ended December 31, 2001, the fair market value of SPR's consolidated long-term debt and preferred trust securities was $3.684 billion, as of December 31, 2001. Due to the credit ratings downgrades by S&P and Moody's, SPR's valuations for its market-sensitive financial instruments show a decline of approximately 23% in the fair market value of these financial instruments to $2.85 billion from December 31, 2001 to September 30, 2002, as shown in the table below. Fair market value is determined using quoted market price for the same or similar issues or on the current rates offered for debt of the same remaining maturities. Long-term debt (dollars in thousands): Expected Maturity Date
------------------------------------------------------------------------------------------------------------------------------- Expected Maturities Amounts Weighted Avg Int Rate Fair Market Value ------------------------------------------------------------------------------- --------------------------------------------- Fixed Rate NPC SPPC SPR Consolidated Consolidated Consolidated ------------------------------------------------------------------------------- ----------------------- ----------------- 2002 $ 15,000 $ - $ - $ 15,000 7.63% 2003 210,000 20,400 - 230,400 5.97% 2004 130,000 2,400 - 132,400 6.20% 2005 - 2,400 300,000 302,400 8.73% 2006 - 51,963 - 51,963 6.72% Thereafter 938,835 843,242 345,000 2,127,077 6.88% ------------------------------------------------------------------------------- ----------------------- ----------------- Total Fixed Rate $ 1,293,835 $ 920,405 $ 645,000 $ 2,859,240 $ 2,350,527 ------------------------------------------------------------------------------- ----------------------- ----------------- Variable Rate 2002 $ - $ - $ - $ - 2003 140,000 - 200,000 340,000 2.94% 2004 - - - - 2005 - - - - 2006 - - - - Thereafter 115,000 - - 115,000 1.74% ------------------------------------------------------------------------------- ----------------------- ----------------- $ 255,000 $ - $ 200,000 $ 455,000 $ 381,850 ------------------------------------------------------------------------------- ----------------------- ----------------- Preferred securities (fixed rate) After 2006 $ 188,872 $ - $ - $ 188,872 8.03% ------------------------------------------------------------------------------- ----------------------- ----------------- $ 188,872 $ - $ - $ 188,872 $ 117,866 ------------------------------------------------------------------------------- ----------------------- ----------------- Total $ 1,737,707 $ 920,405 $ 845,000 $ 3,503,112 $ 2,850,243 =============================================================================== ======================= =================
See the combined Form 10-K of SPR, NPC, and SPPC for the year ended December 31, 2001, for a discussion of Commodity Price Risk. ITEM 4. CONTROLS AND PROCEDURES SPR, NPC, and SPPC maintain disclosure controls and procedures as defined in Rules 13a-14(c) and 15d-14(c) under the Securities Exchange Act of 1934, as amended (the "Exchange Act") designed to ensure that they are able to collect the information required to be disclosed in the reports they file with the Securities and Exchange Commission (SEC), and to process, summarize and disclose this information accurately and within the time periods specified in the rules of the SEC. The chief executive officer and chief financial officer of each of SPR, NPC, and SPPC have reviewed and evaluated SPR's, NPC's and SPPC's disclosure controls and procedures as of a date within 90 days prior to the filing date of this report (the "Evaluation Date"). Based on such evaluation, such officers have concluded that, as of the Evaluation Date, these disclosure controls and procedures of SPR, NPC, and SPPC are effective in bringing to their attention on a timely basis material information relating to SPR, NPC, and SPPC required to be included in periodic filings under the Exchange Act. Since the Evaluation Date, there have not been any significant changes in the internal controls of SPR, NPC, and SPPC, or in other factors that could significantly affect these controls subsequent to the Evaluation Date. 65 PART II ITEM 1. LEGAL PROCEEDINGS Refer to SPR's, NPC's, and SPPC's Combined Annual Report on Form 10-K for the year ended December 31, 2001, and to Item 2, Management's Discussion and Analysis of Financial Condition and Results of Operation, in this Quarterly Report on Form 10-Q, for a discussion of current legal matters. Although SPR, NPC, and SPPC are involved in ongoing litigation on a variety of other matters, in management's opinion, none of these other matters individually or collectively is material to SPR's, NPC's, or SPPC's financial position, results of operations, or liquidity. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS The 2002 Annual Meeting of the Shareholders of Sierra Pacific Resources was held on July 22, 2002. SPR solicited proxies pursuant to Regulation 14 under the Securities and Exchange Act of 1934. There was no solicitation in opposition to the nominees for Director listed in the proxy statement, and all such nominees were elected to the classes indicated in the proxy statement pursuant to the vote of shareholders as follows. Reelected to SPR's Board of Directors to serve until the Annual Meeting in 2005, or until their successors are elected, were: Krestine M. Corbin Votes For: 84,745,644 Votes Against or Withheld: 1,943,949 Clyde T. Turner Votes For: 79,486,897 Votes Against or Withheld: 7,258,696 Dennis E. Wheeler Votes For: 83,479,848 Votes Against or Withheld: 3,265,745
ITEM 5. OTHER INFORMATION None ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K (a) Exhibits filed with this Form 10-Q: NEVADA POWER COMPANY Exhibit 4.1 Officer's Certificate establishing the terms of Nevada Power Company's 10 7/8% General and Refunding Mortgage Notes, Series E, due 2009 Exhibit 4.2 Form of Nevada Power Company's 10 7/8% General and Refunding Mortgage Notes, Series E, due 2009 SIERRA PACIFIC POWER COMPANY Exhibit 4.3 Officer's Certificate establishing the terms of Sierra Pacific Power Company's General and Refunding Mortgage Bonds, Series C, due October 31, 2005 Exhibit 4.4 Form of Sierra Pacific Power Company's General and Refunding Mortgage Bonds, Series C, due October 31, 2005 SIERRA PACIFIC RESOURCES Exhibit 10.1 Donald L. Shalmy Employment Letter dated May 21, 2002 Exhibit 10.2 John F. Young Employment Letter dated May 22, 2002 66 SIERRA PACIFIC POWER COMPANY Exhibit 10.3 Term Loan Agreement, dated as of October 30, 2002, by and among Sierra Pacific Power Company, the several banks and other financial institutions or entities from time to time parties to the Agreement, Lehman Brothers Inc., as advisor, sole lead arranger and sole bookrunner, Lehman Commercial Paper Inc., as syndication agent, and Lehman Commercial Paper Inc., as administrative agent SIERRA PACIFIC COMMUNICATIONS Exhibit 10.4 Unit Redemption, Release, and Sale Agreement entered into by and among Touch America, Inc., Sierra Pacific Communications, and Sierra Touch America LLC, dated as of September 9, 2002 Exhibit 10.5 Amended And Restated Conduit Sale Agreement dated September 11, 2002, made by and between Sierra Pacific Communications and Qwest Communications Corporation. SIERRA PACIFIC RESOURCES, NEVADA POWER COMPANY AND SIERRA PACIFIC POWER COMPANY Exhibit 99.1 Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. Exhibit 99.2 Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (b) Reports on Form 8-K: Form 8-K dated August 14, 2002, filed by SPR- Item 9, Regulation FD Disclosure Disclosed, and included as exhibits, the sworn statements of SPR's Chief Executive Officer and Chief Financial Officer in accordance with Securities and Exchange Commission Order No. 4-460. Form 8-K dated August 14, 2002, filed by SPR, NPC and SPPC - Item 5, Other Events Disclosed, and included as an exhibit, SPR's press release dated August 14, 2002, reporting financial results for the quarter ended June 30, 2002, and included as an exhibit a transcript of the August 14, 2002 conference call by senior management of SPR, NPC, and SPPC discussing those financial results. Form 8-K dated August 22, 2002, filed by SPR and SPPC - Item 5, Other Events Disclosed, and included as an exhibit, the petition for judicial review filed on August 22, 2002, by SPPC in District Court in Nevada seeking to reverse portions of the May 28, 2002 decision of the PUCN denying the recovery of $55.8 million of deferred energy costs incurred by SPPC on behalf of its customers in 2001. Form 8-K dated August 22, 2002, filed by SPR and NPC - Item 5, Other Events Disclosed, and included as an exhibit, SPR's press release dated August 22, 2002, announcing that SPR had received from the Southern Nevada Water Authority (SNWA) a letter stating that SNWA is prepared to enter into good faith negotiation of definitive agreements to acquire all of the assets and assume certain existing publicly disclosed indebtedness of NPC. Form 8-K dated September 12, 2002, filed by SPR and NPC - Item 5, Other Events Disclosed, and included as an exhibit, SPR's press release dated September 12, 2002, announcing that SPR had delivered a letter to the SNWA in response to their letter regarding the agency's proposal to enter into negotiations for the possible purchase of NPC. Form 8-K dated September 30, 2002, filed by SPR and NPC - Item 5, Other Events Disclosed that El Paso Merchant Energy Group (EPME) had notified NPC that EPME was terminating all transactions entered into between NPC and EPME under the Western Systems Power Pool Agreement, and that NPC believes it has adequate power and fuel supplies and availability to meet current needs despite the EPME termination. Also separately disclosed that NPC had reached delayed payment agreements for summer 2002 power deliveries with BP Energy, Mirant, Constellation, and Tractabel. Previously, NPC and Duke Energy Trading and Marketing had reached a delayed payment agreement for summer 2002 deliveries. 67 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, 2002 By: /s/ Dennis D. Schiffel ----------------- ---------------------------------- Dennis D. Schiffel Senior Vice President Chief Financial Officer (Principal Financial Officer) Date: November 14, 2002 By: /s/ John E. Brown ----------------- ---------------------------------- John E. Brown Controller (Principal Accounting Officer) NEVADA POWER COMPANY (Registrant) Date: November 14, 2002 By: /s/ Dennis D. Schiffel ----------------- ---------------------------------- Dennis D. Schiffel Senior Vice President Chief Financial Officer (Principal Financial Officer) Date: November 14, 2002 By: /s/ John E. Brown ------------------ ---------------------------------- John E. Brown Controller (Principal Accounting Officer) SIERRA PACIFIC POWER COMPANY (Registrant) Date: November 14, 2002 By: /s/ Dennis D. Schiffel ----------------- ---------------------------------- Dennis D. Schiffel Senior Vice President Chief Financial Officer (Principal Financial Officer) Date: November 14, 2002 By: /s/ John E. Brown ------------------ ----------------------------------- John E. Brown Controller (Principal Accounting Officer) 68 QUARTERLY CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER REQUIRED BY SECTION 302(a) OF THE SARBANES-OXLEY ACT OF 2002 I, Walter M. Higgins III, certify that: 1. I have reviewed the combined quarterly report on Form 10-Q of Sierra Pacific Resources, Nevada Power Company and Sierra Pacific Power Company; 2. Based on my knowledge, the combined quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by the combined quarterly report; 3. Based on my knowledge, the financial statements, and other financial information included in the combined quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrants as of, and for, the periods presented in the combined quarterly report; 4. The chief financial officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrants and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrants, including their consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which the combined quarterly report is being prepared; b) evaluated the effectiveness of the registrants' disclosure controls and procedures as of a date within 90 days prior to the filing date of the combined quarterly report (the "Evaluation Date"); and c) presented in the combined quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The chief financial officer and I have disclosed, based on our most recent evaluation, to the registrants' auditors and the audit committee of registrants' board of directors: a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrants' ability to record, process, summarize and report financial data and have identified for the registrants' auditors any material weaknesses in internal controls; and 69 b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrants' internal controls; and 6. The chief financial officer and I have indicated in this combined quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. November 14, 2002 /s/ Walter M. Higgins III -------------------------------- Walter M. Higgins III Chief Executive Officer 70 QUARTERLY CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER REQUIRED BY SECTION 302(a) OF THE SARBANES-OXLEY ACT OF 2002 I, Dennis Schiffel, certify that: 1. I have reviewed the combined quarterly report on Form 10-Q of Sierra Pacific Resources, Nevada Power Company and Sierra Pacific Power Company; 2. Based on my knowledge, the combined quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by the combined quarterly report; 3. Based on my knowledge, the financial statements, and other financial information included in the combined quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrants as of, and for, the periods presented in the combined quarterly report; 4. The chief executive officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrants and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrants, including their consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which the combined quarterly report is being prepared; b) evaluated the effectiveness of the registrants' disclosure controls and procedures as of a date within 90 days prior to the filing date of the combined quarterly report (the "Evaluation Date"); and c) presented in the combined quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The chief executive officer and I have disclosed, based on our most recent evaluation, to the registrants' auditors and the audit committee of registrants' board of directors: a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrants' ability to record, process, summarize and report financial data and have identified for the registrants' auditors any material weaknesses in internal controls; and 71 b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrants' internal controls; and 6. The chief executive officer and I have indicated in this combined quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. November 14, 2002 /s/ Dennis Schiffel ------------------------------ Dennis Schiffel Chief Financial Officer 72