10-Q 1 b46521spe10vq.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 MARCH 31, 2003 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 1-08788 SIERRA PACIFIC RESOURCES 88-0198358 P.O. Box 10100 (6100 Neil Road) Reno, Nevada 89520-0400 (89511) (775) 834-4011 2-28348 NEVADA POWER COMPANY 88-0420104 6226 West Sahara Avenue Las Vegas, Nevada 89146 (702) 367-5000 0-00508 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 by check mark whether any registrant is an accelerated filer(as defined in Rule 12b-2 of the Act). Sierra Pacific Resources Yes [X] No [ ]; Nevada Power Company Yes [ ] No [X]; Sierra Pacific Power Company Yes [ ] No [X] 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 May 1, 2003 Common Stock, $1.00 par value 117,135,012 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 MARCH 31, 2003 CONTENTS PART I - FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS (Unaudited) SIERRA PACIFIC RESOURCES - Condensed Consolidated Balance Sheets - March 31, 2003 and December 31, 2002................................. 3 Condensed Consolidated Statements of Operations - Three Months Ended March 31, 2003 and 2002................. 4 Condensed Consolidated Statements of Cash Flows - Three Months Ended March 31, 2003 and 2002................. 5 NEVADA POWER COMPANY - Condensed Consolidated Balance Sheets - March 31, 2003 and December 31, 2002................................. 6 Condensed Consolidated Statements of Operations - Three Months Ended March 31, 2003 and 2002................. 7 Condensed Consolidated Statements of Cash Flows - Three Months Ended March 31, 2003 and 2002................. 8 SIERRA PACIFIC POWER COMPANY - Condensed Consolidated Balance Sheets - March 31, 2003 and December 31, 2002................................. 9 Condensed Consolidated Statements of Operations - Three Months Ended March 31, 2003 and 2002................. 10 Condensed Consolidated Statements of Cash Flows - Three Months Ended March 31, 2003 and 2002................. 11 NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS......................................................... 12 ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations........................ 28 Sierra Pacific Resources............................................................................... 38 Nevada Power Company................................................................................... 42 Sierra Pacific Power Company........................................................................... 48 ITEM 3. Quantitative and Qualitative Disclosures about Market Risk................................................... 59 ITEM 4. Controls and Procedures...................................................................................... 59 PART II - OTHER INFORMATION ITEM 1. Legal Proceedings............................................................................................ 60 ITEM 4. Submission of Matters to a Vote of Security Holders.......................................................... 61 ITEM 5. Other Information............................................................................................ 61 ITEM 6. Exhibits and Reports on Form 8-K............................................................................. 61 Signature Page and Certifications........................................................................................... 63
2 SIERRA PACIFIC RESOURCES CONDENSED CONSOLIDATED BALANCE SHEETS (DOLLARS IN THOUSANDS)
MARCH 31, DECEMBER 31, 2003 2002 ---------- ----------- (UNAUDITED) ASSETS Utility Plant at Original Cost: Plant in service $6,095,682 $5,989,701 Less accumulated provision for depreciation 1,992,811 1,944,351 ---------- ---------- 4,102,871 4,045,350 Construction work-in-progress 259,602 263,346 ---------- ---------- 4,362,473 4,308,696 ---------- ---------- Investments and other property, net 136,606 134,068 ---------- ---------- Current Assets: Cash and cash equivalents 387,192 193,386 Restricted cash 67,113 13,705 Accounts receivable less provision for uncollectible accounts: 2003-$42,844 ; 2002-$44,184 315,564 359,083 Deferred energy costs - electric 288,407 268,979 Deferred energy costs - gas 6,431 17,045 Materials, supplies and fuel, at average cost 86,320 87,840 Risk management assets (Note 10) 23,963 29,570 Other 66,391 48,960 ---------- ---------- 1,241,381 1,018,568 ---------- ---------- Deferred Charges and Other Assets: Goodwill (Note 12) 309,971 310,441 Deferred energy costs - electric 589,707 685,875 Regulatory tax asset 162,427 163,889 Other regulatory assets 139,066 136,933 Risk management assets (Note 10) 29,910 368 Risk management regulatory assets - net (Note 10) 47,443 44,970 Other 88,657 92,436 ---------- ---------- 1,367,181 1,434,912 ---------- ---------- $7,107,641 $6,896,244 ========== ========== CAPITALIZATION AND LIABILITIES Capitalization: Common shareholders' equity $1,426,469 $1,327,166 Preferred stock 50,000 50,000 NPC obligated mandatorily redeemable preferred trust securities 188,872 188,872 Long-term debt 3,013,127 3,062,883 ---------- ---------- 4,678,468 4,628,921 ---------- ---------- Current Liabilities: Current maturities of long-term debt 758,858 672,963 Accounts payable 194,892 233,099 Accrued interest 90,339 50,308 Dividends declared 1,052 1,045 Accrued salaries and benefits 19,362 20,828 Deferred taxes 117,202 123,507 Risk management liabilities (Note 10) 67,774 69,953 Other current liabilities 89,671 46,719 ---------- ---------- 1,339,150 1,218,422 ---------- ---------- Commitments & Contingencies (Note 11) Deferred Credits and Other Liabilities: Deferred federal income taxes 336,195 336,144 Deferred investment tax credit 47,629 48,492 Regulatory tax liability 41,722 42,718 Customer advances for construction 119,196 116,032 Accrued retirement benefits 114,205 107,580 Risk management liabilities (Note10) 3,329 3,917 Contract termination reserves (Note11) 312,594 312,594 Other 115,153 81,424 ---------- ---------- 1,090,023 1,048,901 ---------- ---------- $7,107,641 $6,896,244 ========== ==========
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 MARCH 31, ------------------------------ 2003 2002 ------------- ------------- OPERATING REVENUES: Electric $ 537,106 $ 581,026 Gas 64,617 55,083 Other 1,239 2,755 ------------- ------------- 602,962 638,864 ------------- ------------- OPERATING EXPENSES: Operation: Purchased power 206,435 281,483 Fuel for power generation 80,213 130,773 Gas purchased for resale 42,334 38,594 Deferred energy costs disallowed - 434,123 Deferral of energy costs - electric - net 84,187 (14,241) Deferral of energy costs - gas - net 10,803 8,192 Other 73,602 72,045 Maintenance 18,724 16,907 Depreciation and amortization 45,950 48,641 Taxes: Income taxes (16,140) (158,617) Other than income 11,057 11,715 ------------- ------------- 557,165 869,615 ------------- ------------- OPERATING INCOME (LOSS) 45,797 (230,751) ------------- ------------- OTHER INCOME (EXPENSE): Allowance for other funds used during construction 1,760 657 Unrealized gain on derivative instrument ( Note 10) 15,925 - Interest accrued on deferred energy 7,635 (6,124) Other income 6,414 3,580 Other expense (3,731) (8,797) Income taxes (8,418) 4,214 ------------- ------------- 19,585 (6,470) ------------- ------------- Total Income (Loss) Before Interest Charges 65,382 (237,221) ------------- ------------- INTEREST CHARGES: Long-term debt 68,595 58,800 Other 10,273 4,630 Allowance for borrowed funds used during construction and capitalized interest (1,756) (1,503) ------------- ------------- 77,112 61,927 ------------- ------------- Dividend requirements of NPC obligated mandatorily redeemable preferred trust securities 3,793 3,793 ------------- ------------- NET LOSS (15,523) (302,941) ------------- ------------- Preferred stock dividend requirements of SPPC 975 975 ------------- ------------- LOSS APPLICABLE TO COMMON STOCK $ (16,498) $ (303,916) ============= ============= Basic and diluted loss per share of common stock $ (0.15) $ (2.98) Cumulative effect of change in accounting principle (net of tax) per share - - ------------- ------------- Per share loss applicable to common stock $ (0.15) $ (2.98) ============= ============= Weighted Average Shares of Common Stock Outstanding 111,499,881 102,110,536 ============= ============= Dividends Paid Per Share of Common Stock $ - $ 0.20 ============= =============
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)
THREE MONTHS ENDED MARCH 31, ---------------------- 2003 2002 --------- --------- CASH FLOWS FROM OPERATING ACTIVITIES: Net Loss $ (15,523) $(302,941) Non-cash items included in income: Depreciation and amortization 45,950 48,641 Deferred taxes and deferred investment tax credit (12,225) (4,713) AFUDC and capitalized interest (3,516) 537 Amortization of deferred energy costs - electric 44,490 - Amortization of deferred energy costs - gas 6,165 6,404 Deferred energy costs disallowed (net of taxes) - 282,181 Unrealized gain on derivative instrument (net of taxes) (10,351) - Early retirement and severance amortization 624 752 Other non-cash (3,742) (3,954) Changes in certain assets and liabilities: Accounts receivable 43,519 55,204 Deferral of energy costs - electric 32,251 (7,410) Deferral of energy costs - gas 4,448 1,437 Materials, supplies and fuel 1,520 (1,162) Other current assets (70,839) (2,257) Accounts payable (38,207) (56,359) Income tax receivable - 79,333 Derivative instrument associated with convertible debt 72,078 - Other current liabilities 25,364 31,112 Other assets (26,493) - Other liabilities 40,354 72 --------- --------- Net Cash from Operating Activities 135,867 126,877 --------- --------- CASH FLOWS FROM INVESTING ACTIVITIES: Additions to utility plant (99,467) (85,558) AFUDC and other charges to utility plant 3,516 (537) Customer advances (refunds) for construction 3,165 (575) Contributions in aid of construction 3,055 16,148 --------- --------- Net cash used for utility plant (89,731) (70,522) Investments and other property - net (1,350) (1,308) --------- --------- Net Cash from Investing Activities (91,081) (71,830) --------- --------- CASH FLOWS FROM FINANCING ACTIVITIES: Increase in short-term borrowings - 69,672 Proceeds from issuance of long-term debt 228,764 - Retirement of long-term debt (78,775) (3,463) Dividends paid (969) (21,542) --------- --------- Net Cash from Financing Activities 149,020 44,667 --------- --------- NET INCREASE IN CASH AND CASH EQUIVALENTS 193,806 99,714 Beginning Balance in Cash and Cash Equivalents 193,386 99,109 --------- --------- Ending Balance in Cash and Cash Equivalents $ 387,192 $ 198,823 ========= ========= SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION: Cash paid (received) during period for: Interest $ 38,837 $ 39,629 Income taxes $ - $ (79,333) NONCASH FINANCING ACTIVITIES (NOTE 4): Exchanged Floating Rate Notes for SPR common stock $ 8,750 Exchanged Premium Income Equity Securities for SPR common stock $ 104,782
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS 5 NEVADA POWER COMPANY CONDENSED CONSOLIDATED BALANCE SHEETS (DOLLARS IN THOUSANDS)
MARCH 31, DECEMBER 31, 2003 2002 ---------- ------------ (Unaudited) ASSETS Utility Plant at Original Cost: Plant in service $3,631,806 $3,542,300 Less accumulated provision for depreciation 1,047,877 1,017,494 ---------- ---------- 2,583,929 2,524,806 Construction work-in-progress 163,299 173,189 ---------- ---------- 2,747,228 2,697,995 ---------- ---------- Investments and other property, net 19,589 20,295 ---------- ---------- Current Assets: Cash and cash equivalents 90,689 95,009 Restricted cash 3,850 3,850 Accounts receivable less provision for uncollectible accounts: 2003-$33,914; 2002-$33,841 167,366 202,590 Deferred energy costs - electric 230,232 213,193 Materials, supplies and fuel, at average cost 43,687 44,074 Risk management assets (Note 10) 20,206 28,173 Other 49,712 31,602 ---------- ---------- 605,742 618,491 ---------- ---------- Deferred Charges and Other Assets: Deferred energy costs - electric 440,232 524,345 Regulatory tax asset 105,124 106,071 Other regulatory assets 54,607 53,109 Risk management assets (Note 10) 21,846 368 Risk management regulatory assets - net (Note 10) 15,469 1,491 Other 45,247 46,357 ---------- ---------- 682,525 731,741 ---------- ---------- $4,055,084 $4,068,522 ========== ========== CAPITALIZATION AND LIABILITIES Capitalization: Common shareholder's equity $1,134,377 $1,149,131 NPC obligated mandatorily redeemable preferred trust securities 188,872 188,872 Long-term debt 1,486,402 1,488,597 ---------- ---------- 2,809,651 2,826,600 ---------- ---------- Current Liabilities: Current maturities of long-term debt 354,664 354,677 Accounts payable 92,031 143,002 Accounts payable, affiliated companies 2,549 4,287 Accrued interest 47,368 29,892 Dividends declared 78 78 Accrued salaries and benefits 7,217 7,781 Deferred taxes 87,240 90,616 Risk management liabilities (Note 10) 35,662 29,908 Other current liabilities 23,554 22,115 ---------- ---------- 650,363 682,356 ---------- ---------- Commitments & Contingencies (Note 11) Deferred Credits and Other Liabilities: Deferred federal income taxes 124,814 129,687 Deferred investment tax credit 21,495 21,902 Regulatory tax liability 16,974 17,300 Customer advances for construction 68,779 66,434 Accrued retirement benefits 55,983 54,216 Contract termination reserves (Note 11) 225,816 225,816 Other 81,209 44,211 ---------- ---------- 595,070 559,566 ---------- ---------- $4,055,084 $4,068,522 ========== ==========
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS. 6 NEVADA POWER COMPANY CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (DOLLARS IN THOUSANDS) (UNAUDITED)
THREE MONTHS ENDED MARCH 31, ---------------------- 2003 2002 --------- --------- OPERATING REVENUES: Electric $ 331,652 $ 356,272 --------- --------- OPERATING EXPENSES: Operation: Purchased power 119,257 176,066 Fuel for power generation 46,537 83,722 Deferred energy costs disallowed - 434,123 Deferral of energy costs-net 72,785 (9,636) Other 40,540 39,986 Maintenance 13,537 11,650 Depreciation and amortization 25,907 30,809 Taxes: Income taxes (10,548) (156,423) Other than income 6,224 6,734 --------- --------- 314,239 617,031 --------- --------- OPERATING INCOME (LOSS) 17,413 (260,759) --------- --------- OTHER INCOME (EXPENSE): Allowance for other funds used during construction 1,158 421 Interest accrued on deferred energy 5,710 (11,151) Other income 3,338 146 Other expense (1,432) (5,997) Income taxes (2,514) 5,645 --------- --------- 6,260 (10,936) --------- --------- Total Income (Loss) Before Interest Charges 23,673 (271,695) --------- --------- INTEREST CHARGES: Long-term debt 30,102 24,078 Other 6,080 2,530 Allowance for borrowed funds used during construction and capitalized interest (1,056) (1,112) --------- --------- 35,126 25,496 --------- --------- Dividend requirements of obligated mandatorily redeemable preferred trust securities 3,793 3,793 --------- --------- NET LOSS $ (15,246) $(300,984) ========= =========
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS. 7 NEVADA POWER COMPANY CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (DOLLARS IN THOUSANDS) (UNAUDITED)
THREE MONTHS ENDED MARCH 31, ---------------------- 2003 2002 --------- --------- CASH FLOWS FROM OPERATING ACTIVITIES: Net Income (Loss) $ (15,246) $(300,984) Non-cash items included in income: Depreciation and amortization 25,907 30,809 Deferred taxes and deferred investment tax credit (8,035) (4,586) AFUDC and capitalized interest (2,214) 692 Amortization of deferred energy costs 32,331 - Deferred energy costs disallowed (net of taxes) - 282,181 Other non-cash (4,702) (555) Changes in certain assets and liabilities: Accounts receivable 35,224 46,471 Deferral of energy costs 34,744 2,221 Materials, supplies and fuel 387 1,348 Other current assets (18,110) (2,187) Accounts payable (52,709) (51,497) Income tax receivable - 79,333 Other current liabilities 18,351 11,545 Other assets (19,943) - Other liabilities 38,765 540 --------- --------- Net Cash from Operating Activities 64,750 95,331 --------- --------- CASH FLOWS FROM INVESTING ACTIVITIES: Additions to utility plant (74,525) (65,685) AFUDC and other charges to utility plant 2,214 (692) Customer advances (refunds) for construction 2,345 (469) Contributions in aid of construction 2,363 13,592 --------- --------- Net cash used for utility plant (67,603) (53,254) Investments and other property - net 741 (950) --------- --------- Net Cash from Investing Activities (66,862) (54,204) --------- --------- CASH FLOWS FROM FINANCING ACTIVITIES: Increase in short-term borrowings - 68,429 Retirement of long-term debt (2,208) (2,663) Investment by parent company - 10,000 Dividends paid - (9,995) --------- --------- Net Cash from Financing Activities (2,208) 65,771 --------- --------- NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (4,320) 106,898 Beginning Balance in Cash and Cash Equivalents 95,009 8,505 --------- --------- Ending Balance in Cash and Cash Equivalents $ 90,689 $ 115,403 ========= ========= SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION: Cash paid (received) during period for: Interest $ 18,706 $ 14,104 Income taxes $ - $ (79,333)
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS 8 SIERRA PACIFIC POWER COMPANY CONDENSED CONSOLIDATED BALANCE SHEETS (DOLLARS IN THOUSANDS)
MARCH 31, DECEMBER 31, 2003 2002 ---------- ------------ (Unaudited) ASSETS Utility Plant at Original Cost: Plant in service $2,463,876 $2,447,401 Less accumulated provision for depreciation 944,934 926,857 ---------- ---------- 1,518,942 1,520,544 Construction work-in-progress 96,303 90,157 ---------- ---------- 1,615,245 1,610,701 ---------- ---------- Investments and other property, net 953 874 ---------- ---------- Current Assets: Cash and cash equivalents 127,801 88,910 Restricted cash 9,605 9,605 Accounts receivable less provision for uncollectible accounts: 2003 - $8,930; 2002 - $10,343 147,019 154,821 Accounts receivable, affiliated companies 58,598 58,680 Deferred energy costs - electric 58,175 55,786 Deferred energy costs - gas 6,431 17,045 Materials, supplies and fuel, at average cost 40,525 41,727 Risk management assets (Note 10) 3,757 1,397 Other 12,008 12,955 ---------- ---------- 463,919 440,926 ---------- ---------- Deferred Charges and Other Assets: Deferred energy costs - electric 149,475 161,530 Regulatory tax asset 57,303 57,818 Other regulatory assets 64,258 64,149 Risk management assets (Note 10) 8,064 - Risk management regulatory assets - net (Note 10) 31,974 43,479 Other 19,934 19,013 ---------- ---------- 331,008 345,989 ---------- ---------- $2,411,125 $2,398,490 ========== ========== CAPITALIZATION AND LIABILITIES Capitalization: Common shareholder's equity $ 642,548 $ 639,295 Preferred stock 50,000 50,000 Long-term debt 914,425 914,788 ---------- ---------- 1,606,973 1,604,083 ---------- ---------- Current Liabilities: Current maturities of long-term debt 101,400 101,400 Accounts payable 70,540 71,247 Accrued interest 26,199 12,136 Dividends declared 974 968 Accrued salaries and benefits 9,726 10,812 Deferred taxes 29,962 32,891 Risk management liabilities (Note 10) 32,112 40,045 Other current liabilities 7,935 10,864 ---------- ---------- 278,848 280,363 ---------- ---------- Commitments & Contingencies (Note 11) Deferred Credits and Other Liabilities: Deferred federal income taxes 257,420 251,487 Deferred investment tax credit 26,134 26,590 Regulatory tax liability 24,748 25,418 Customer advances for construction 50,417 49,598 Accrued retirement benefits 49,734 44,856 Risk management liabilities (Note 10) 3,329 3,917 Contract termination reserves (Note 11) 86,778 86,778 Other 26,744 25,400 ---------- ---------- 525,304 514,044 ---------- ---------- $2,411,125 $2,398,490 ========== ==========
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 MARCH 31, ---------------------- 2003 2002 --------- --------- OPERATING REVENUES: Electric $ 205,454 $ 224,754 Gas 64,617 55,083 --------- --------- 270,071 279,837 --------- --------- OPERATING EXPENSES: Operation: Purchased power 87,178 105,417 Fuel for power generation 33,676 47,051 Gas purchased for resale 42,334 38,594 Deferral of energy costs - electric - net 11,402 (4,605) Deferral of energy costs - gas - net 10,803 8,192 Other 29,213 27,762 Maintenance 5,187 5,257 Depreciation and amortization 19,706 17,558 Taxes: Income taxes 2,090 4,901 Other than income 4,662 4,776 --------- --------- 246,251 254,903 --------- --------- OPERATING INCOME 23,820 24,934 --------- --------- OTHER INCOME (EXPENSE): Allowance for other funds used during construction 602 236 Interest accrued on deferred energy 1,925 5,027 Other income 1,065 1,837 Other expense (1,905) (2,462) Income taxes (303) (1,432) --------- --------- 1,384 3,206 --------- --------- Total Income Before Interest Charges 25,204 28,140 --------- --------- INTEREST CHARGES: Long-term debt 18,781 16,445 Other 3,125 1,142 Allowance for borrowed funds used during construction and capitalized interest (700) (391) --------- --------- 21,206 17,196 --------- --------- NET INCOME 3,998 10,944 --------- --------- Preferred Dividend Requirements 975 975 --------- --------- Earnings applicable to common stock $ 3,023 $ 9,969 ========= =========
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)
THREE MONTHS ENDED MARCH 31, ---------------------- 2003 2002 --------- --------- CASH FLOWS FROM OPERATING ACTIVITIES: Net income $ 3,998 $ 10,944 Non-cash items included in income: Depreciation and amortization 19,706 17,558 Deferred taxes and deferred investment tax credit 2,393 6,918 AFUDC and capitalized interest (1,302) (155) Amortization of deferred energy costs - electric 12,159 - Amortization of deferred energy costs - gas 6,165 6,404 Early retirement and severance amortization 624 752 Other non-cash (2,313) (1,131) Changes in certain assets and liabilities: Accounts receivable 7,884 3,959 Deferral of energy costs - electric (2,493) (9,631) Deferral of energy costs - gas 4,448 1,437 Materials, supplies and fuel 1,202 (2,399) Other current assets 947 (272) Accounts payable (707) (11,428) Other current liabilities 10,048 10,208 Other assets (6,550) - Other liabilities 6,222 1,467 --------- --------- Net Cash from Operating Activities 62,431 34,631 --------- --------- CASH FLOWS FROM INVESTING ACTIVITIES: Additions to utility plant (24,942) (19,873) AFUDC and other charges to utility plant 1,302 155 Customer advances (refunds) for construction 819 (106) Contributions in aid of construction 692 2,556 --------- --------- Net cash used for utility plant (22,129) (17,268) Disposal of investments and other property - net (79) 577 --------- --------- Net Cash from Investing Activities (22,208) (16,691) --------- --------- CASH FLOWS FROM FINANCING ACTIVITIES: Decrease in short-term borrowings - 1,243 Retirement of long-term debt (363) (800) Investment by parent company - 10,000 Dividends paid (969) (10,969) --------- --------- Net Cash from Financing Activities (1,332) (526) --------- --------- NET INCREASE IN CASH AND CASH EQUIVALENTS 38,891 17,414 Beginning Balance in Cash and Cash Equivalents 88,910 11,772 --------- --------- Ending Balance in Cash and Cash Equivalents $ 127,801 $ 29,186 ========= ========= SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION: Cash paid during period for: Interest $ 7,843 $ 3,019 Income taxes $ - $ -
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, results of operations and 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 Annual Report on Form 10-K for the year ended December 31, 2002. The results of operations of SPR, NPC and SPPC for the three-month period ended March 31, 2003, 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, NPC and SPPC (collectively, the "Utilities"), Tuscarora Gas Pipeline Company (TGPC), Sierra Gas Holding Company (SGHC), Sierra Energy Company dba eo three (eo 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. SIERRA PACIFIC RESOURCES SPR, on a stand-alone basis, had cash and cash equivalents of approximately $166.7 million at March 31, 2003. On April 21, 2003, SPR utilized approximately $133 million of its cash and cash equivalents to repay unsecured Floating Rate Notes due April 20, 2003. Currently, SPR has a substantial amount of debt and other obligations including, but not limited to: $300 million of its unsecured 8 3/4% Senior Notes due 2005; and $240 million of its unsecured 7.93% Senior Notes due 2007; and $300 million of its 7.25% Convertible Notes due 2010. SPR's future liquidity and its ability to pay the principal of and interest on its indebtedness depend on SPPC's ability to continue to pay dividends to SPR, on NPC's financial stability and a restoration of its ability to pay dividends to SPR, and on SPR's ability to access the capital markets or otherwise refinance maturing debt. Further adverse developments at NPC or SPPC, including a material disallowance of deferred energy costs in current and future rate cases or an adverse decision in the pending lawsuit by Enron, could make it difficult to continue to operate outside of bankruptcy. See Note 5, Dividend Restrictions for information regarding the dividend restrictions applicable to NPC and SPPC and Note 11, Commitments and Contingencies for additional information regarding uncertainties that could impact SPR's liquidity and financial condition. The provisions that currently restrict dividends payable by NPC or SPPC have adversely affected SPR's liquidity and will continue to negatively impact SPR's liquidity until those provisions are no longer in effect. Management intends to seek a modification of the financial covenant contained in NPC's first mortgage indenture in the near future. The regulatory limitation contained in the Public Utility Commission of Nevada's (PUCN) Compliance Order, Docket No. 02-4037, dated June 19, 2002, expires on December 31, 2003. Prior to the expiration date of the Compliance Order, management may seek PUCN approval for a payment of dividends by NPC or may seek a waiver from the PUCN of the dividend restriction. Financing Transactions. On February 14, 2003, SPR issued and sold $300 million of its 7.25% Convertible Notes due 2010. Approximately $53.4 million of the net proceeds from the sale of the notes were used to purchase U.S. government securities that were pledged to the trustee for the first five interest payments on the notes payable during the first two and one-half years. A portion of the remaining net proceeds of the notes have been used to repurchase approximately $58.5 million of SPR's Floating Rate Notes due April 20, 2003. Of the remaining net proceeds, approximately $133 million were used to repay the remainder of SPR's Floating Rate Notes due April 20, 2003, and the remaining proceeds will be available for general corporate purposes, including the payment of interest on SPR's other outstanding indebtedness. The Convertible Notes will not be convertible prior to August 14, 2003. At any time on or after August 14, 2003 through the close of business February 14, 2010, holders of the Convertible Notes may convert their notes into shares of SPR's common stock. Until SPR has obtained shareholder approval to fully convert the Convertible Notes into shares of common 12 stock, holders of the Convertible Notes will be entitled to receive 76.7073 shares of common stock and a remaining portion in cash, based on the average closing price of SPR's common stock over five consecutive trading days, for each $1,000 principal amount of notes surrendered for conversion. At an assumed five-day average closing price of $3.87 per share (based on the last reported sale price of SPR's common stock on April 30, 2003), the total amount of the cash payable on conversion of the Convertible Notes would be approximately $165.4 million. If SPR does not obtain shareholder approval, SPR will be required to pay the cash portion of any Convertible Notes as to which the holders request conversion on or after August 14, 2003. Although management does not believe it is likely that a significant amount of the Convertible Notes will be converted in the foreseeable future, in the event that SPR does not have available funds to pay the cash portion of the Convertible Notes upon the requested conversion, SPR may have to issue additional debt to raise the necessary funds. There can be no assurance that SPR will be able to access the capital markets to issue such additional debt. If SPR does obtain shareholder approval, it may elect to satisfy the cash payment component of the conversion price of the Convertible Notes solely with shares of common stock. SPR has agreed to use reasonable efforts to obtain shareholder approval, not later than 180 days after the date of issuance of the Convertible Notes, for approval to issue and deliver shares of SPR's common stock in lieu of the cash payment component of the conversion price of the Convertible Notes. For further information regarding the terms of the Convertible Notes, see Note 4, Long-Term Debt. Effect of Holding Company Structure. Due to its holding company structure, SPR's right as a common shareholder to receive assets of any of its direct or indirect subsidiaries upon a subsidiary's liquidation or reorganization is junior to the claims against the assets of such subsidiary by its creditors. Therefore, SPR's debt obligations are effectively subordinated to all existing and future claims of its subsidiaries' creditors, particularly those of NPC and SPPC, including trade creditors, debt holders, secured creditors, taxing authorities, guarantee holders and NPC's and SPPC's preferred security holders. As of March 31, 2003, NPC, SPPC and their subsidiaries had approximately $2.86 billion of debt and other obligations outstanding and approximately $238.9 million of outstanding preferred securities. Although the Utilities are parties to agreements that limit the amount of additional indebtedness they may incur, the Utilities retain the ability to incur substantial additional indebtedness and other liabilities. The accompanying financial statements do not include any adjustments that might result from the outcome of the uncertainties discussed above. NEVADA POWER COMPANY NPC had cash and cash equivalents of approximately $91 million at March 31, 2003. In addition to anticipated capital requirements for construction, NPC has approximately $355 million of debt maturing in 2003. NPC expects to finance these requirements with internally generated funds, including the recovery of deferred energy, and the issuance of debt. NPC's liquidity would be significantly affected by an adverse decision in the lawsuit by Enron, or by unfavorable rulings by the PUCN in pending or future NPC or SPPC rate cases. Standard and Poors Rating Group, Inc. (S&P) and Moodys Investors Service, Inc. (Moodys) have NPC's credit ratings on "negative" and "stable", respectively. Future downgrades by either S&P or Moody's could preclude NPC's access to the capital markets. Furthermore, if NPC continues to experience financial difficulty or if its credit ratings are further downgraded, NPC may experience considerable difficulty entering into new power supply contracts, particularly under traditional payment terms. If suppliers will not sell power to NPC under traditional payment terms, NPC may have to pre-pay its power requirements. If it does not have sufficient funds or access to liquidity to pre-pay its power requirements, particularly at the onset of the summer months, and is unable to obtain power through other means, NPC's results of operations, financial position, and cash flows will be adversely affected. Adverse developments with respect to any one or a combination of the foregoing could make it difficult to continue to operate outside of bankruptcy. NPC's General and Refunding Mortgage Indenture creates a lien on substantially all of NPC's properties in Nevada that is junior to the lien of the first mortgage indenture. As of March 31, 2003, $870 million of NPC's General and Refunding Mortgage securities were outstanding. Additional securities may be issued under the General and Refunding Mortgage Indenture on the basis of (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. As of March 31, 2003, NPC had the capacity to issue approximately $1.13 billion of additional General and Refunding Mortgage securities. However, the financial covenants contained in NPC's Series E Notes limit NPC's ability to issue additional General and Refunding Mortgage Bonds or other debt. NPC has reserved $125 million of General and Refunding Mortgage bonds for issuance upon the initial funding of NPC's receivables facility. See Note 3, Short-Term Borrowings for information regarding NPC's accounts receivable facility. NPC intends to use its accounts receivable purchase 13 facility as a back-up liquidity facility and does not plan to activate this facility in the foreseeable future. NPC may activate the facility within five days upon the delivery of certain customary funding documentation and the delivery of the $125 million General and Refunding Mortgage Bond. The accompanying financial statements do not include any adjustments that might result from the outcome of the uncertainties discussed above. SIERRA PACIFIC POWER COMPANY SPPC had cash and cash equivalents of approximately $128 million at March 31, 2003. In addition to anticipated capital requirements for construction, and not including $80 million of Bonds subject to remarketing (see Note 4), SPPC has approximately $21 million of debt maturing in 2003. SPPC expects to finance these requirements with internally generated funds, including the recovery of deferred energy. SPPC's future liquidity could be significantly affected by unfavorable rulings by the PUCN in pending or future SPPC or NPC rate cases. S&P and Moody's have SPPC's credit ratings on "negative outlook" and "stable", respectively. Future downgrades by either S&P or Moody's could preclude SPPC's access to the capital markets. Furthermore, if SPPC continues to experience financial difficulty or if its credit ratings are further downgraded, SPPC may experience considerable difficulty entering into new power supply contracts, particularly under traditional payment terms. If suppliers will not sell power to SPPC under traditional payment terms, SPPC may have to pre-pay its power requirements. If it does not have sufficient funds or access to liquidity to pre-pay its power requirements, and is unable to obtain power through other means, SPPC's results of operations, financial position and cash flows will be adversely affected. Adverse developments with respect to any one or a combination of the factors and contingencies set forth above could make it difficult to continue to operate outside of bankruptcy. SPPC's General and Refunding Mortgage Indenture creates a lien on substantially all of SPPC's properties in Nevada that is junior to the lien of the first mortgage indenture. As of March 31, 2003, approximately $419.8 million of SPPC's General and Refunding Mortgage bonds were outstanding. On May 1, 2003, SPPC issued its $80 million General and Refunding Mortgage Note, Series D, due 2004, to secure SPPC's payment obligations with respect to $80 million of Washoe County, Nevada, Water Facilities Refunding Revenue Bonds (Sierra Pacific Power Company Project), Series 2001, which were issued for SPPC's benefit. 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. At March 31, 2003, SPPC had the capacity to issue approximately $435.7 million of additional General and Refunding Mortgage securities, which amount does not include SPPC's $80 million General and Refunding Mortgage Note, Series D, due 2004. However, the financial covenants contained in SPPC's Term Loan Agreement and Receivable Purchase Facility Agreements limit SPPC's ability to issue additional General and Refunding Mortgage Securities or other debt. SPPC has reserved $75 million of General and Refunding Mortgage Bonds for issuance upon the initial funding of its receivables purchase facility. SPPC intends to use its accounts receivable purchase facility as a back-up liquidity facility and does not plan to activate this facility in the foreseeable future. SPPC may activate the facility within five days upon the delivery of certain customary funding documentation and the delivery of the $75 million General and Refunding Mortgage Bond. See Note 3, Short-Term Borrowings for information regarding SPPC's accounts receivable facility. The accompanying financial statements do not include any adjustments that might result from the outcome of the uncertainties discussed above. RECLASSIFICATIONS Certain items previously reported have been reclassified to conform to the current year's presentation. Net income and shareholders' equity were not affected by these reclassifications. NEVADA POWER COMPANY FINANCIAL STATEMENTS The presentation of the condensed consolidated statements of operations and cash flows of NPC for the three months ended March 31, 2002 have been revised. Specifically, the effects of the revisions were to eliminate the line item " Equity in losses of Sierra Pacific Resources" of $(2,932) on NPC's Condensed Consolidated Statement of Operations and to eliminate the line item "Equity in losses of SPR" of $(2,932) on NPC's Condensed Consolidated Statement of Cash Flows. For additional information regarding this change in presentation, see Note 1, Summary of Significant Accounting Policies of Notes to Financial Statements in SPR's, NPC's and SPPC's Report on Form 10-K for the year ended December 31, 2002. 14 DEFERRAL OF ENERGY COSTS NPC and SPPC implemented deferred energy accounting procedures on March 1, 2001. See Note 1, Summary of Significant Accounting Policies, of Notes to Financial Statements in SPR's, NPC's, and SPPC's Annual Report on Form 10-K for the year ended December 31, 2002, for additional information regarding the implementation of deferred energy accounting by the Utilities. The following deferred energy costs were included in the condensed consolidated balance sheets as of March 31, 2003 (dollars in thousands):
March 31, 2003 ----------------------------------------------- NPC SPPC SPPC SPR Description Electric Electric Gas Total --------- --------- --------- --------- Unamortized balances approved for collection in current rates $ 298,828 $ 108,025 $ 21,559 $ 428,412 Balances pending PUCN approval (1) (2) 191,143 15,380 - 206,523 Balances accrued since end of periods submitted for PUCN approval (3) (51,352) 2,344 (15,128) (64,136) Terminated suppliers (2) (4) 231,845 81,901 - 313,746 --------- --------- --------- --------- Total $ 670,464 $ 207,650 $ 6,431 $ 884,545 ========= ========= ========= =========
(1)See Note 9, Regulatory Actions, for additional discussion of balances pending PUCN approval. (2)Balances adjusted from amounts presented as of December 31, 2002, reflecting, primarily, a reclassification between amounts for terminated suppliers and balances pending PUCN approval. (3)Credits represent over-collections, that is, the extent to which gas or fuel and purchased power costs recovered through rates exceed actual gas or fuel and purchased power costs. (4)Amounts related to terminated suppliers are discussed in Note 17, Commitments and Contingencies, of Notes to Financial Statements in SPR's, NPC's, and SPPC's Annual Report on Form 10-K for the year ended December 31, 2002. STOCK COMPENSATION PLANS In December 2002, the Financial Accounting Standards Board (FASB) released Statement of Financial Accounting Standards (SFAS) No. 148, "Accounting for Stock-Based Compensation-Transition and Disclosure," as an amendment to SFAS No. 123, "Accounting for Stock-Based Compensation." SPR has previously adopted the disclosure-only provisions of SFAS No. 123, and as of December 31, 2002 has adopted the updated disclosure requirements set forth in SFAS No. 148. At March 31, 2003, SPR had several stock-based compensation plans which are described more fully in Note 15 "Stock Compensation Plans," of Notes to Financial Statements in SPR's, NPC's, and SPPC's Combined Annual Report on Form 10-K for the year ended December 31, 2002. SPR applies Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees," in accounting for its stock option plans. Accordingly, no compensation cost has been recognized for nonqualified stock options and the employee stock purchase plan. Had compensation cost for SPR's nonqualified stock options and the employee stock purchase plan been determined based on the fair value at the grant dates for awards under those plans, consistent with the provisions of SFAS No. 123, SPR's income applicable to common stock would have been decreased to the pro forma amounts indicated below (dollars in thousands, except earnings per share): 15
Three Months Ended March 31, 2003 2002 ----------------------- Stock Compensation Cost included in Net Income as Reported, net of related tax effects As Reported $ (100) $ 170 ======================= Loss applicable to Common Stock As Reported $ (16,498) $(303,916) Less: Additional Stock Compensation Cost, net of related tax effects Pro Forma 1,192 512 ----------------------- Loss applicable to Common Stock Pro Forma $ (17,690) $(304,428) ======================= Basic Loss Per Share As Reported $ (0.15) $ (2.98) Pro Forma $ (0.16) $ (2.98) Diluted Loss Per Share As Reported $ (0.15) $ (2.98) Pro Forma $ (0.16) $ (2.98)
RECENT PRONOUNCEMENTS In November 2002, the FASB issued Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees" (FIN 45), which elaborates on the disclosures to be made in interim and annual financial statements of a guarantor about its obligations under certain guarantees that it has issued. It also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing a guarantee. Initial recognition and measurement provisions of FIN 45 are applicable on a prospective basis to guarantees issued or modified after December 31, 2002. The disclosure requirements are effective for financial statements of interim or annual periods ending after December 15, 2002. As of March 31, 2003, any guarantees of SPR and its subsidiaries were intercompany, whereby the parent issues the guarantees on behalf of its consolidated subsidiaries to a third party. Therefore there is no impact on the financial position, results of operation or cash flows of SPR, NPC or SPPC. In January 2003, the FASB issued Interpretation No. 46, "Consolidation of Variable Interest Entities" (FIN 46), which elaborates on Accounting Research Bulletin No. 51, "Consolidated Financial Statements." Among other requirements, FIN 46 provides that a variable interest entity be consolidated by the enterprise that is the primary beneficiary of the variable interest entity. FIN 46 applies immediately to variable interest entities created after January 31, 2003, and to variable interest entities in which an enterprise obtains an interest after that date. It applies in the first fiscal year or interim period beginning after June 15, 2003, to variable interest entities in which an enterprise holds a variable interest that it acquired before February 1, 2003. Management does not expect the adoption of FIN 46 to have an effect on the financial position, results of operation or cash flows of SPR, NPC or SPPC. NOTE 2. ASSET RETIREMENT OBLIGATIONS (AROs) Effective January 1, 2003, the Utilities adopted the provisions of SFAS No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 generally applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or the normal operation of a long-lived asset. SFAS No. 143 requires NPC to recognize an estimated liability for the retirement of generation plant assets specified in land leases for NPC's jointly-owned Navajo generating station because the leases require the lessees to remove the facilities upon request of the Navajo Nation at the expiration of the leases. However, the retirement obligation and corresponding charges recognized were immaterial to the financial statements of NPC. NPC also redesignated amounts from Accumulated Depreciation to a regulatory liability in order to reflect the estimated costs of removal collected through rates. NPC amortizes the amount added to Electric Plant In Service and recognizes accretion expense in connection with the discounted liability over the estimated remaining life of the Navajo generating station assets. SPPC has no significant asset retirement obligations. NPC and SPPC also collect removal costs in rates for certain assets that do not have associated legal asset retirement obligations. As of March 31, 2003, NPC and SPPC estimate that they had approximately $126 million and $148 million related to removal costs recorded in Accumulated Depreciation, respectively. 16 NOTE 3. SHORT-TERM BORROWINGS NEVADA POWER COMPANY On October 29, 2002, NPC established an accounts receivable purchase facility of up to $125 million, which was arranged by Lehman Brothers. If NPC elects to activate the receivables purchase facility, NPC will sell all of its accounts receivable generated from the sale of electricity to customers to its newly created bankruptcy remote special purchase subsidiary. The receivables sales will be without recourse except for breaches of customary representations and warranties made at the time of sale. The subsidiary will, in turn, sell these receivables to a bankruptcy remote subsidiary of SPR. SPR's subsidiary will issue variable rate revolving notes backed by the purchased receivables. Lehman Brothers Holding, Inc. will be the sole initial committed purchaser of all of the variable rate revolving notes. The agreements relating to the receivables purchase facility contain various conditions to purchase, covenants and trigger events, termination events and other provisions customary in receivables transactions. In connection with NPC's receivables facility, SPR has agreed to guaranty NPC's performance of certain obligations as a seller and servicer under the facility. NPC has agreed to issue $125 million principal amount of its General and Refunding Mortgage Bonds upon activation of the accounts receivables purchase facility. The full principal amount of the Bond would secure certain of NPC's obligations as seller and servicer, plus certain interest, fees and expenses thereon to the extent not paid when due, regardless of the actual amounts owing with respect to the secured obligations. As a result, in the event of an NPC bankruptcy or liquidation, the holder of the Bond securing the receivables facility may recover more on a pro rata basis than the holders of other General and Refunding Mortgage securities, who could recover less on a pro rata basis, than they otherwise would recover. However, in no event will the holder of the Bond recover more than the amount of obligations secured by the Bond. NPC intends to use the accounts receivables purchase facility as a back-up liquidity facility and does not plan to activate this facility in the foreseeable future. NPC may activate the facility within five days upon the delivery of certain customary funding documentation and the delivery of the $125 million General and Refunding Mortgage Bond. As of March 31, 2003, this facility has not been activated. NPC does not expect to activate this facility in the foreseeable future. SIERRA PACIFIC POWER COMPANY On October 29, 2002, SPPC established an accounts receivable purchase facility of up to $75 million, which was arranged by Lehman Brothers. If SPPC elects to activate the receivables purchase facility, SPPC will sell all of its accounts receivable generated from the sale of electricity and gas to customers to its newly created bankruptcy-remote special purpose subsidiary. The receivables sales will be without recourse except for breaches of customary representations and warranties made at the time of sale. The subsidiary will, in turn, sell these receivables to a bankruptcy-remote subsidiary of SPR. SPR's subsidiary will issue variable rate revolving notes backed by the purchased receivables. Lehman Brothers Holdings, Inc. 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. As of March 31, 2003, this facility has not been activated. SPPC does not expect to activate this facility in the foreseeable future. 17 NOTE 4. LONG-TERM DEBT Substantially all utility plant is subject to the liens of NPC's and SPPC's indentures under which their First Mortgage bonds and General and Refunding Mortgage bonds are issued. SIERRA PACIFIC RESOURCES In January 2003, SPR acquired $8.75 million aggregate principal amount of its Floating Rate Notes due April 20, 2003, in exchange for approximately 1.3 million shares of its common stock, in two privately negotiated transactions exempt from the registration requirements of the Securities Act. On February 5, 2003, SPR acquired 2.1 million of Premium Income Equity Securities (PIES) including approximately $104.8 million of 7.93% Senior Notes due 2007 that are a component of the PIES, in exchange for approximately 13.66 million shares of its common stock, in five privately negotiated transactions exempt from the registration requirements of the Securities Act. On February 14, 2003, SPR issued $300 million of its 7.25% Convertible Notes due 2010. Interest on the notes is payable semi-annually. At any time on or after August 14, 2003 through the close of business February 14, 2010, holders of the Convertible Notes may convert each $1,000 principal amount of their notes into 219.1637 shares of SPR's common stock, subject to adjustment upon the occurrence of certain dilution events. Until SPR has obtained shareholder approval to fully convert the Convertible Notes into shares of common stock, holders of the Convertible Notes will be entitled to receive 76.7073 shares of common stock and a remaining portion in cash based on the average closing price of SPR's common stock over five consecutive trading days for each $1,000 principal amount of notes surrendered for conversion. In the event SPR obtains shareholder approval, it may elect to satisfy the cash payment component of the conversion price of the Convertible Notes solely with shares of common stock. Because the Convertible Notes may be converted, at the holder's option, any time after six months from issuance, there is a possibility that SPR may be required to honor this obligation in less than one year. In addition, until SPR has obtained shareholder approval to fully convert the Convertible Notes into shares of common stock, SPR must satisfy part of this obligation in cash. Accordingly, the portion of the obligation relating to the amount to be settled upon conversion by issuing shares is classified as a long-term liability and the portion to be settled with working capital upon demand by the holder is classified as a current maturity. For further information regarding accounting for the conversion option, see Note 10, Derivatives and Hedging Activities. The Convertible Notes provide for the payment of dividends to the holders in an amount equal to any per share dividends on SPR common stock that would have been payable to the holders if the holders of the notes had converted their notes into shares of common stock at the applicable conversion rate on the record date for such dividend. SPR may redeem some or all of the notes at any time on or after February 14, 2008. SPR used approximately $53.4 million of the proceeds to acquire U.S. Government securities that are pledged to the trustee as security for the notes for the first two and one-half years and which SPR expects to use to pay the first five interest payments on the notes. A portion of the remaining net proceeds of the notes were used to repurchase approximately $58.5 million of SPR's Floating Rate Notes due April 20, 2003. Of the remaining net proceeds, approximately $133 million were used to repay the remainder of SPR's Floating Rate Notes due April 20, 2003, and the remaining proceeds will be available for general corporate purposes. The indenture under which the Convertible Notes were issued does not contain any financial covenants or any restrictions on the payment of dividends, the repurchase of SPR's securities or the incurrence of indebtedness. The indenture does allow the holders of the Convertible Notes to require SPR to repurchase all or a portion of the holders' Convertible Notes upon a change of control. The indenture also provides for an event of default if SPR or any of its significant subsidiaries, including NPC and SPPC, fails to pay any indebtedness in excess of $10 million or has any indebtedness of $10 million or more accelerated and declared due and payable. On April 21, 2003, SPR paid the remaining approximate $133 million unsecured Floating Rate Notes, due April 20, 2003, at maturity. SIERRA PACIFIC POWER COMPANY On May 1, 2003, SPPC's $80 million Washoe County, Nevada, Water Facilities Refunding Revenue Bonds, Series 2001, were successfully remarketed. The interest rate on the bonds was adjusted from their prior two-year 5.75% term rate to a 7.50 % term rate for the period of May 1, 2003 to and including May 3, 2004. The bonds will be subject to remarketing on May 3, 2004 and will continue to be included in current maturities of long-term debt. 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 principal 18 amount, plus accrued interest. From May 1, 2003 to and including May 3, 2004, SPPC's payment and purchase obligations in respect of the bonds are secured by SPPC's $80 million General and Refunding Mortgage Note, Series D, due 2004. SIERRA PACIFIC COMMUNICATIONS Sierra Touch America LLC (STA), a partnership between SPC and Touch America, formerly Montana Power Company, was formed to construct a fiber optic line between Salt Lake City, Utah and Sacramento, CA. On September 9, 2002, SPC entered into an agreement to purchase and lease certain telecommunications and fiber optic assets from Touch America, subject to successful completion of the construction, in exchange for SPC's partnership units in Sierra Touch America and the execution of a $35 million promissory note for a total purchase price of $48.5 million. The promissory note accrues interest at 8% per annum. The outstanding balance of the promissory note as of March 31, 2003, was $21.3 million. As of March 31, 2003 NPC's, SPPC's and SPR's aggregate annual amount of maturities for long-term debt (including obligations related to capital leases) for the next five years is shown below (in thousands of dollars):
SPR Holding Co. SPR NPC SPPC and Other Subs. Consolidated ----------- ----------- --------------- ------------ 2003 $ 354,664 $ 101,400 $ 302,794 $ 758,858 2004 135,570 3,400 - 138,970 2005 6,091 100,150 300,000 406,241 2006 6,509 52,400 - 58,909 2007 5,949 2,400 240,218 248,567 ----------- ----------- --------- ------------ Thereafter 1,345,721 759,533 80,136 2,185,390 ----------- ----------- --------- ------------ 1,854,504 1,019,283 923,148 3,796,935 Unamortized (Disc.)/Prem. (13,438) (3,458) (8,054) (24,950) ----------- ----------- --------- ------------ Total $ 1,841,066 $ 1,015,825 $ 915,094 $ 3,771,985 =========== =========== ========= ============
NOTE 5. DIVIDEND RESTRICTIONS Since SPR is a holding company, substantially all of its cash flow is provided by dividends paid to SPR by NPC and SPPC on their common stock, all of which is owned by SPR. Since NPC and SPPC are public utilities, they are subject to regulation by state utility commissions which may impose limits on investment returns or otherwise impact the amount of dividends that the Utilities may declare and pay, and to federal statutory limitation on the payment of dividends. In addition, certain agreements entered into by the Utilities set restrictions on the amount of dividends they may declare and pay and restrict the circumstances under which such dividends may be declared and paid. The specific restrictions on dividends contained in agreements to which NPC and SPPC are party, as well as specific regulatory limitations on dividends, are summarized below. NEVADA POWER COMPANY First Mortgage Indenture. NPC's first mortgage indenture limits the cumulative amount of dividends and other distributions that NPC may pay on its capital stock to the cumulative net earnings of NPC since 1953, subject to adjustments for the net proceeds of sales of capital stock since 1953. At the present time, this restriction precludes NPC from making further payments of dividends on NPC's common stock and will continue to bar dividends until NPC, over time, generates sufficient earnings to eliminate the deficit under this provision (which was approximately $254 million as of March 31, 2003), unless the restriction is waived, amended, or removed by the consent of the first mortgage bondholders, or the first mortgage bonds are redeemed or defeased. Under this provision, NPC continues to have capacity to repurchase or redeem shares of its capital stock. Series E Notes. NPC's 10 7/8% General and Refunding Mortgage Notes, Series E, due 2009, which were issued on October 29, 2002, limit the amount of payments in respect of common stock that NPC may pay to SPR. However, that 19 limitation does not apply to payments by NPC to enable SPR to pay its reasonable fees and expenses (including, but not limited to, interest on SPR's indebtedness and payment obligations on account of SPR's PIES provided that: - those payments do not exceed $60 million for any one calendar year, - those payments comply with any regulatory restrictions then applicable to NPC, and - the ratio of consolidated cash flow to fixed charges for NPC's most recently ended four full fiscal quarters immediately preceding the date of payment is at least 1.75 to 1. The terms of the Series E Notes also permit NPC to make payments to SPR in an aggregate amount not to exceed $15 million from the date of the issuance of the Series E Notes. In addition, NPC may make dividend payments to SPR in excess of the amounts described above so long as, at the time of payment and after giving effect to the payment: - there are no defaults or events of default with respect to the Series E Notes, - NPC can meet a fixed charge coverage ratio test, and - the total amount of such dividends is less than: - 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 - 100% of NPC's aggregate net cash proceeds from the issuance or sale of certain equity or convertible debt securities of NPC, plus - the lesser of cash return of capital or the initial amount of certain restricted investments, plus - the fair market value of NPC's investment in certain subsidiaries. If NPC's Series E Notes are upgraded to investment grade by both Moodys 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. Accounts Receivable Facility. On October 29, 2002, NPC established an accounts receivable purchase facility. The agreements relating to the receivables purchase facility contain various conditions, including a limitation on the payment of dividends by NPC to SPR that is identical to the limitation contained in NPC's General and Refunding Mortgage Notes, Series E, described above. Preferred Trust Securities. The terms of NPC's preferred trust securities provide that no dividends may be paid on NPC's common stock if NPC has elected to defer payments on the junior subordinated debentures issued in conjunction with the preferred trust securities. At this time, NPC has not elected to defer payments on the junior subordinated debentures. PUCN Order. The PUCN issued a Compliance Order, Docket No. 02-4037, on June 19, 2002, relating to NPC's request for authority to issue long-term debt. The PUCN order requires that, until such time as the order's authorization expires (December 31, 2003), NPC must either receive the prior approval of the PUCN or reach an equity ratio of 42% before paying any dividends to SPR. If NPC achieves a 42% equity ratio prior to December 31, 2003, the dividend restriction ceases to have effect. As of March 31, 2003, NPC's equity ratio was 36.0%. Federal Power Act. NPC is subject to the provisions of the Federal Power Act that state that dividends cannot be paid out of funds that are properly included in capital accounts. Although the meaning of this provision is unclear, it could be interpreted to impose an additional material limitation on a utility's ability to pay dividends in the absence of retained earnings. SIERRA PACIFIC POWER COMPANY Term Loan Agreement. SPPC's Term Loan Agreement dated October 30, 2002, which expires October 31, 2005, limits the amount of dividends that SPPC may pay to SPR. However, that limitation does not apply to payments by SPPC to enable SPR to pay its reasonable fees and expenses (including, but not limited to, interest on SPR's indebtedness and payment obligations on account of SPR's PIES) provided that those payments do not exceed $90 million, $80 million and $60 million in the aggregate for the twelve month periods ending on October 30, 2003, 2004 and 2005, respectively. The Term Loan Agreement also permits SPPC to make dividend payments to SPR in an aggregate amount not to exceed $10 million during the term of the Term Loan Agreement. In addition, SPPC may make dividend payments to SPR in excess of the amounts described above so long as, at the time of the payment and after giving effect to the payment, there are no defaults or events of default under the Term Loan Agreement, and such amounts, when aggregated with the amount of dividends paid to SPR by SPPC since the date of execution of the Term Loan Agreement, do not exceed the sum of: - (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. 20 Accounts Receivable Facility. On October 29, 2002, SPPC established an accounts receivable purchase facility. The agreements relating to the receivables purchase facility contain various conditions, including a limitation on the payment of dividends by SPPC to SPR that is identical to the limitation contained in SPPC's Term Loan Agreement, described above. Articles of Incorporation. SPPC's Articles of Incorporation contain restrictions on the payment of dividends on SPPC's common stock in the event of a default in the payment of dividends on SPPC's preferred stock. SPPC's Articles also prohibit SPPC from declaring or paying any dividends on any shares of common stock (other than dividends payable in shares of common stock), or making any other distribution on any shares of common stock or any expenditures for the purchase, redemption or other retirement for a consideration of shares of common stock (other than in exchange for or from the proceeds of the sale of common stock) except from the net income of SPPC, and its predecessor, available for dividends on common stock accumulated subsequent to December 31, 1955, less preferred stock dividends, plus the sum of $500,000. At the present time, SPPC believes that these restrictions do not materially limit its ability to pay dividends and/or to purchase or redeem shares of its common stock. Federal Power Act. SPPC is subject to the provisions of the Federal Power Act that state that dividends cannot be paid out of funds that are properly included in capital accounts. Although the meaning of this provision is unclear, it could be interpreted to impose an additional material limitation on a utility's ability to pay dividends in the absence of retained earnings. 21 NOTE 6. EARNINGS PER SHARE (SPR) The following table outlines the calculation for earnings per share (EPS). The difference, if any, between Basic EPS and Diluted EPS is due to common stock equivalent shares resulting from stock options, the employee stock purchase plan, performance and restricted stock plans and the non-employee director stock plan. However, due to net losses for the three-month periods ended March 31, 2003 and 2002, these items are anti-dilutive. Accordingly, Diluted EPS for these periods are computed using the weighted average shares outstanding before dilution. Common stock equivalents were determined using the treasury stock method.
Three Months Ended March 31, 2003 2002 ------------ ------------ BASIC EPS Numerator ($000) Loss applicable to common stock $ (16,498) $ (303,916) ============ ============ Denominator Weighted average number of shares outstanding 111,499,881 102,110,536 ============ ============ Per-Share Amount Loss applicable to common stock $ (0.15) $ (2.98) ============ ============ DILUTED EPS Numerator ($000) Loss applicable to common stock $ (16,498) $ (303,916) ============ ============ Denominator (1) Weighted average number of shares outstanding 111,499,881 102,110,536 before dilution Stock options - 31,612 Executive long term incentive plan - performance shares - 24,694 Executive long term incentive plan - restricted shares 26,440 - Non-Employee Director stock plan 14,183 9,355 Employee stock purchase plan - 2,660 ------------ ------------ 111,540,504 102,178,857 ============ ============ Per-Share Amount Loss applicable to common stock $ (0.15) $ (2.98) ============ ============
(1) The denominator does not include anti-dilutive stock equivalents for the Stock Option Plan, Employee Stock Purchase Plan, Corporate PIES and 7.25% Convertible Debt due to conversion prices being higher than market prices at March 31, 2003. NOTE 7. SEGMENT INFORMATION (SPR) SPR operates three business segments providing regulated electric and natural gas services. NPC has one business segment that provides electric service to Las Vegas and surrounding Clark County. SPPC has two business segments. One business segment provides electric service in northern Nevada and the Lake Tahoe area of California and the other segment provides natural gas service in the Reno-Sparks area of Nevada. Other segment information includes segments below the quantitative threshold for separate disclosure. Information as to the operations of the different business segments is set forth below based on the nature of products and services offered. 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): 22
Three Months Ended NPC SPPC Total March 31, 2003 Electric Electric Electric Gas Other Consolidated ------------------ ---------- --------- ---------- -------- ------- -------------- Operating Revenues $ 331,652 $ 205,454 $ 537,106 $ 64,617 $ 1,239 $ 602,962 ========== ========= ========== ======== ======= ============== Operating Income $ 17,413 $ 20,232 $ 37,645 $ 3,589 $ 4,563 $ 45,797 ========== ========= ========== ======== ======= ==============
Three Months Ended NPC SPPC Total March 31, 2002 Electric Electric Electric Gas Other Consolidated ------------------ ---------- --------- ---------- -------- ------- -------------- Operating Revenues $ 356,272 $ 224,754 $ 581,026 $ 55,083 $ 2,755 $ 638,864 ========== ========= ========== ======== ======= ============== Operating Income (Loss) $ (260,759) $ 23,401 $ (237,358) $ 1,533 $ 5,074 $ (230,751) ========== ========= ========== ======== ======= ==============
NOTE 8. DISPOSAL OF LONG-LIVED ASSETS During 2002, the Utilities began pursuing the sale of several non-essential properties. As a result, on January 15, 2003, NPC sold a parcel of land located on Flamingo Road near the Barbary Coast Casino in Las Vegas, Nevada. NPC received cash proceeds of approximately $18 million for the property and retained an easement and other rights necessary to maintain aerial power lines that cross the property. Also, it was agreed that NPC will receive an additional $2.6 million from the sale if the power lines that cross the property are removed and the other rights are relinquished within a five-year period from the date of the sale. The property had been originally transferred to NPC at no cost. The transaction resulted in a gain of $17.7 million, which will be recognized into revenue over a period of three years consistent with the accounting treatment directed by the PUCN. NPC is pursuing the sale of land parcels located on Flamingo Road from Koval Lane to Maryland Parkway, commonly known as "the Flamingo Corridor." These properties are presently under long-term leases with restaurants, convenience stores, gas stations, etc. On April 21, 2003 NPC provided notice to the tenants of the Flamingo Corridor properties of its intent to sell the properties at a public auction. Currently the auction is scheduled for mid-July 2003. The carrying value of the properties is approximately $.9 million. On November 11, 2002, SPPC agreed to sell land located in Nevada County and Sierra County, California, commonly referred to as Independence Lake. The sale was subject to review by a third party who retained certain rights, including water rights, after the sale is completed. Also, the sales agreement included a due diligence review period of 180 days which allowed the buyer to review and accept a variety of matters agreed to by both parties. In April 2003, the buyer terminated the agreement during the review period as provided for in the agreement. The agreed upon sales price was $22 million and the carrying value of the property is approximately $108,000. SPPC plans to sell the property and is continuing to work with all potential buyers. NOTE 9. REGULATORY ACTIONS NEVADA POWER COMPANY 2002 DEFERRED ENERGY CASE On November 14, 2002, NPC filed an application with the PUCN seeking to clear deferred balances for purchased fuel and power costs accumulated between October 1, 2001, and September 30, 2002, as required by law. The application seeks to establish a rate to repay accumulated purchased fuel and power costs of $195.7 million, together with a carrying charge, over a period of not more than three years. The application also requests a reduction to the going-forward rate for energy, reflecting reduced wholesale energy costs. The combined effect of these two adjustments results in an overall rate reduction of 5.3%. Intervenors filed their direct testimony on March 7, 2003, and supplemental testimony was filed March 27, 2003, calling for disallowances between approximately $108 and $300 million of the total fuel and purchased power costs. The largest of the proposed disallowances are based on the same alleged imprudence as found in the PUCN order for NPC's 2001 Deferred Energy Case relating to NPC's failure to enter into power contracts in 1999. Certain Intervenors' testimony, in the current case, have argued in favor of disallowances based on the same alleged imprudence as cited in the last deferred order but have not quantified their proposals and in some cases have argued in favor of disallowances in excess of the ranges previously indicated. The PUCN Staff does not support this disallowance but calculated a range of $116 to $347 million in the event that the PUCN disallows deferred energy costs based upon the same alleged imprudence cited by the PUCN in its 2001 decision relative to this issue. 23 While all Intervenors have called for the PUCN to reduce NPC's requested energy rates for recovery of past energy costs, some have also proposed to increase customers' energy rates for purchases that will occur during the upcoming deferred accounting period, which would decrease the accumulation of deferred energy costs. NPC's rebuttal testimony was filed March 31, 2003. The hearing commenced on April 7, 2003, and was completed on April 17, 2003. A special agenda meeting is scheduled for May 9, 2003, at which time a ruling from the Commission is expected. SIERRA PACIFIC POWER COMPANY 2003 DEFERRED ENERGY CASE On January 14, 2003, SPPC filed an application with the PUCN, as required by law, seeking to clear deferred balances for purchased fuel and power costs accumulated between December 1, 2001 and November 30, 2002. The application seeks to establish a Deferred Energy Accounting Adjustment (DEAA) rate to repay accumulated purchased fuel and power costs of $15.4 million and spread the cost recovery over a period of not more than three years. It also seeks to recalculate the Base Tariff Energy Rate to reflect anticipated ongoing purchased fuel and power costs. The total rate increase resulting from the requested DEAA would amount to 0.01%. The intervenors' testimony was received April 25, 2003, and includes proposed disallowances from $34 million to $76 million. While all Intervenors call for the PUCN to reduce SPPC's requested energy rates for recovery of past energy costs, some also propose to increase customers' energy rates for purchases that will occur during the upcoming deferred accounting period, which would decrease the accumulation of deferred energy costs. A hearing is scheduled to begin on May 12, 2003, and a ruling is required before July 13, 2003. NOTE 10. DERIVATIVES AND HEDGING ACTIVITIES SPR, SPPC, and NPC apply (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS No. 138. As amended, SFAS No. 133 requires that an entity recognize all derivatives as either assets or liabilities in the statement of financial position, measure those instruments at fair value, and recognize changes in the fair value of the derivative instruments in earnings in the period of change unless the derivative qualifies as an effective hedge. 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. At March 31, 2003, the fair value of the derivatives resulted in the recording of $54 million, $42 million and $12 million in risk management assets and $71 million, $36 million and $35 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 March 31, 2003, $47 million, $15 million and $32 million in net risk management regulatory assets were recorded in the Consolidated Balance Sheets of SPR, NPC, and SPPC, respectively. In addition, for the three months ended March 31, 2003, 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, $1.1 million relating to SPR's terminated interest rate swap was reclassified into earnings during the three months ended March 31, 2003. The effects of SFAS No. 133 on comprehensive income and the components thereof at March 31, 2003, and 2002, are as follows (in thousands): 24
SPR NPC SPPC ------------- ------------- -------------- Net Income (Loss) for the three months ended March 31, 2003 $ (16,498) $ (15,246) $ 3,023 Change in market value of risk management assets and liabilities as of March 31, 2003, net of taxes of $1,051, $165, and $125 1,952 492 232 respectively ------------- ------------- -------------- Total Comprehensive Income (Loss) for the three months ended March 31, 2003 $ (14,546) $ (14,754) $ 3,255 ============= ============= ============== Net Income (Loss) for the three months ended March 31, 2002 $ (303,916) $ (300,984) $ 9,969 Change in market value of risk management assets and liabilities as of March 31, 2002, net of taxes of ($3,127), ($134), and ($64), respectively (5,807) 248 118 ------------- ------------- -------------- Total Comprehensive Income for the three months ended March 31, 2002 $ (309,723) $ (300,736) $ 10,087 ============= ============= ==============
In connection with SPR's issuance of its Convertible Notes (see Note 4, Long-Term Debt), the conversion option, which is treated as a cash-settled written call option, was separated from the debt and accounted for separately as a derivative instrument in accordance with FASB's Emerging Issues Task Force Issue 90-19, "Convertible Bonds with Issuer Option to Settle for Cash upon Conversion". Upon issuance, the fair value of the option was recorded as a current liability in Other Current Liabilities. The change in the fair value is recognized in earnings in the period of the change. NOTE 11. COMMITMENTS AND CONTINGENCIES ENVIRONMENTAL NEVADA POWER COMPANY The Grand Canyon Trust and Sierra Club filed a lawsuit in the U.S. District Court, District of Nevada in February 1998 against the owners (including NPC) of the Mohave Generation Station ("Mohave"), alleging violations of the Clean Air Act regarding emissions of sulfur dioxide and particulates. An additional plaintiff, National Parks and Conservation Association, later joined the suit. The plant owners and plaintiffs have had numerous settlement discussions and filed a proposed settlement with the court in October 1999. The consent decree, approved by the court in November 1999, established emission limits for sulfur dioxide and opacity and required installation of air pollution controls for sulfur dioxide, nitrogen oxides and particulate matter. The new emission limits must be met by January 1, 2006 and April 1, 2006 for the first and second units, respectively. The estimated cost of new controls is $1.1 billion. As a 14% owner in Mohave, NPC's cost could be $154 million. NPC's ownership interest in Mohave comprises approximately 10% of NPC's peak generation capacity. Southern California Edison (SCE) is the operating partner of Mohave. On May 17, 2002, SCE filed with the CPUC an application to address the future disposition of SCE's share of Mohave. Mohave obtains all of its coal supply from a mine in northeast Arizona on lands of the Navajo Nation and the Hopi Tribe (the Tribes). This coal is delivered from the mine to Mohave by means of a coal slurry pipeline which requires water that is obtained from groundwater wells located on lands of the Tribes in the mine vicinity. Due to the lack of progress in negotiations with the Tribes and other parties to resolve several coal and water supply issues, SCE's application states that it appears that it probably will not be possible for SCE to extend Mohave's operations beyond 2005. Due to the uncertainty over a post-2005 coal supply, SCE and the other Mohave co-owners have been prevented from commencing the installation of extensive pollution control equipment that must be put in place if Mohave's operations are extended past 2005. NPC is currently evaluating and analyzing all of its options with regard to the Mohave project. In May 1997, the Nevada Division of Environmental Protection (NDEP) ordered NPC to submit a plan to eliminate the discharge of Reid Gardner Station wastewater to groundwater. The NDEP order also required a hydrological assessment of groundwater impacts in the area. In June 1999, NDEP determined that wastewater ponds had degraded groundwater quality. In August 1999, NDEP issued a discharge permit to Reid Gardner Station and an order that requires all wastewater ponds to be closed or lined with impermeable liners over the next 10 years. This order also required NPC to submit a Site Characterization Plan to NDEP to ascertain impacts. This plan has been approved by NDEP. NDEP is expected to identify remediation requirements of 25 contaminated groundwater resulting from these evaporation ponds by July 2003. New pond construction and lining costs are estimated to cost approximately $25 million, of which, $17 million is expected to be spent by the end of 2003. At the Reid Gardner Station, the NDEP has determined that there is additional groundwater contamination that resulted from oil spills at the facility. NDEP has required NPC to submit a corrective action plan. The extent of contamination has been determined and remediation is occurring at a modest rate. A hydro-geologic evaluation of the current remediation was completed, and a dual phase extraction remediation system, which has been approved by NDEP, will be constructed beginning in May 2003 at an estimated cost of $150,000. In May 1999, NDEP issued an order to eliminate the discharge of NPC's Clark Station wastewater to groundwater. The order also required a hydrological assessment of groundwater impacts in the area. This assessment, submitted to NDEP in February 2001, warranted a Corrective Action Plan, which was approved in June 2002. Remediation costs are expected to be approximately $100,000. In addition to remediation, NPC spent $663,000 to line all existing treated water ponds. Lining of all existing treated water ponds was completed in February 2003. In July 2000, NPC received a request from the EPA for information to determine the compliance of certain generation facilities at the Clark Station with the applicable State Implementation Plan. In November 2000, NPC and the Clark County Health District entered into a Corrective Action Order requiring, among other steps, capital expenditures at the Clark Station totaling approximately $3 million. In March 2001, the EPA issued an additional request for information that could result in remediation beyond that specified in the November 2000 Corrective Action Order. If the EPA prevails, capital expenditures and temporary outages of four of Clark Station's generation units could be required. Additionally, depending on the time of year that the compliance activity and corresponding generation outage would occur, the incremental cost to purchase replacement energy could be substantial. To date, EPA has not issued additional requests for further information. NEICO, a wholly owned subsidiary of NPC, owns property in Wellington, Utah, which was the site of a coal washing and load out facility. The site now has a reclamation estimate supported by a bond of $4.8 million with the Utah Division of Oil and Gas Mining. The property was under contract for sale and the contract required the purchaser to provide $1.3 million in escrow towards reclamation. However, the sales contract was terminated and NEICO took title to the escrow funds. The property is currently leased with the intention to reclaim coal fines with subsequent revenues and reduction to the reclamation bond. SIERRA PACIFIC POWER COMPANY In September 1994 Region VII of the EPA notified SPPC that it was being named as a potentially responsible party (PRP) regarding the past improper handling of Polychlorinated Biphenyls (PCB's) by PCB Treatment, Inc., in two buildings, one located in Kansas City, Kansas and the other in Kansas City, Missouri (the Sites). Prior to 1994, SPPC sent PCB contaminated material to PCB Treatment, Inc. for disposal. Certificates of disposal were issued to SPPC by PCB Treatment, Inc. however; the contaminated material was not disposed of, but remained on-site. A number of the largest PRP's formed a steering committee, which is chaired by SPPC. The steering committee has completed its site investigations and the EPA has determined that the Sites should be remediated by removing the buildings to the appropriate landfills. The EPA has issued an administrative order on consent requiring the steering committee to oversee the performance of the work. SPPC has recorded a preliminary liability for the Sites of $650,000 of which approximately $136,000 has been spent through March 31, 2003. The steering committee is obtaining cost estimates for removal of the buildings. Once these costs have been determined, SPPC will be in a better position to estimate and record the ultimate liabilities for the Sites. LANDS OF SIERRA LOS, a wholly owned subsidiary of SPR, owns property in North Lake Tahoe, California, which is leased to independent condominium owners. The property has both soil and groundwater petroleum contamination resulting from an underground fuel tank that has been removed from the property. Additional contamination from a third party fuel tank on the property has also been identified and is undergoing remediation. On February 3, 2003, the Lahontan Regional Water Quality Control Board re-opened closure of this property. By October 1, 2003, SPR will complete the evaluation of alternative remediation technologies and their effectiveness in reducing contamination at this site. An application for closure will be re-submitted at that time. Additional remediation costs are expected to be approximately $100,000. LITIGATIONCONTINGENCIES NEVADA POWER COMPANY AND SIERRA PACIFIC POWER COMPANY Enron Power Marketing (Enron) filed a complaint with the United States Bankruptcy Court for the Southern District of New York seeking to recover approximately $216 million and $93 million against NPC and SPPC, respectively, for liquidated damages for power supply contracts terminated by Enron in May 2002 and for power previously delivered to the Utilities. The Utilities have denied liability on numerous grounds, including deceit and misrepresentation in the inducement 26 (including, but not limited to, misrepresentation as to Enron's ability to perform) and fraud, unfair trade practices and market manipulation. The Utilities filed motions to dismiss for lack of jurisdiction and/or for a stay of all proceedings pending the actions of the Utilities' proceedings under Section 206 of the Federal Power Act at the FERC. The Utilities have also filed proofs of claims and counterclaims against Enron, for the full amount of the approximately $300 million claimed to be owed and additional damages, as well as for unspecified damages to be determined during the case as a result of acts and omissions of Enron in manipulating the power markets, wrongful termination of its transactions with the Utilities, and fraudulent inducement to enter into transactions with Enron, among other issues. On December 19, 2002, the bankruptcy judge granted Enron's motion for partial summary judgment on Enron's claim for $17.7 million and $6.7 million, respectively, for energy delivered by Enron in April 2002, for which NPC and SPPC did not pay. The court ordered this money to be deposited into an escrow account not subject to claims of Enron's creditors and subject to refund depending on the outcome of the Utilities' FERC cases on the merits. The Utilities made the deposit as required. The bankruptcy court denied the Utilities' motion to stay the proceeding pending the outcome of the Utilities' Section 206 case at the FERC and denied the Utilities' motion to dismiss for lack of jurisdiction as to Enron's claims for power previously delivered to the Utilities. The court stated that it would rule in due course on Enron's motion for partial summary judgment to require NPC and SPPC to post $200 million and $87 million, respectively pending the outcome of the case on the merits, and for judgment on the merits on Enron's liquidated damage claim (contract price less market price on the date of termination) relating to power it did not deliver under contracts terminated by Enron in May 2002. The court took under advisement the Utilities' motion to stay or dismiss Enron's claim for liquidated damages relating to the undelivered power. On April 3, 2003, the court heard arguments regarding Enron's motion to dismiss the Utilities' counterclaims against Enron for unspecified damages to be determined during the case, but did not rule on this matter nor did it indicate when a decision on this matter can be expected. The Utilities are unable to predict the outcome of these motions. The Utilities continue to participate in non-binding court-ordered mediation proceedings along with all of Enron's other terminated purchased power counterparties. The United States District Court for the Southern District of New York has also denied the Utilities' motion to withdraw reference of the matter to the bankruptcy court without prejudice. The bankruptcy court currently has under submission (1) Enron's motion to dismiss the Utilities' counterclaims, (2) Enron's motion for partial summary judgment regarding the amounts alleged to be due for undelivered power and the posting of collateral for undelivered power, and (3) the Utilities' motion to dismiss or stay proceeding on Enron's claims relating to delivered power. A decision adverse to the Utilities on Enron's motion for partial summary judgment, or an adverse decision in the lawsuit with respect to liability as to Enron's claims on the merits for undelivered power, would have a material adverse effect on SPR's and the Utilities' financial condition and liquidity, and could make it difficult for one or more of SPR, NPC or SPPC to continue to operate outside of bankruptcy. NEVADA POWER COMPANY On September 5, 2002, Morgan Stanley Capital Group (MSCG) initiated an arbitration pursuant to the arbitration provisions in various power supply contracts terminated by MSCG in April 2002. In the arbitration, MSCG requested that the arbitrator compel NPC to pay MSCG $25 million pending the outcome of any dispute regarding the amount owed under the contracts. NPC claimed that nothing is owed under the contracts on various grounds, including breach by MSCG in terminating the contracts, and further, that the arbitrator does not have jurisdiction over NPC's contract claims and defenses. In March 2003, the arbitrator overseeing the arbitration proceedings dismissed MSCG's demand for arbitration and agreed that the issues raised by MSCG were not calculation issues subject to arbitration and that NPC's contract defenses were likewise not arbitrable. NPC has since filed a complaint for declaratory relief in the U.S. District Court for the District of Nevada asking the Court to declare that NPC is not liable for any damages as a result of MSCG's termination of its power supply contracts. MSCG has not yet answered or responded to the complaint; however, on April 17, 2003, MSCG filed a complaint against NPC at the FERC conceding that the issues raised by NPC were litigable in court but asking the FERC to declare that under the WSPP agreement NPC should post the $25 million in dispute as collateral pending the outcome of the litigation. NPC is unable to predict the outcome of these proceedings. NOTE 12. SUBSEQUENT EVENTS See Notes 1, 4, 8, 9 and 11 for discussion of events occurring after March 31, 2003. 27 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 PREVIOUSLY FILED, CURRENTLY PENDING AND TO BE FILED BY NPC AND SPPC (THE UTILITIES) WITH THE PUBLIC UTILITIES COMMISSION OF NEVADA (PUCN), INCLUDING THE PERIODIC APPLICATIONS TO RECOVER COSTS FOR FUEL AND PURCHASED POWER THAT HAVE BEEN RECORDED BY THE UTILITIES IN THEIR DEFERRED ENERGY ACCOUNTS, AND DEFERRED NATURAL GAS RECORDED BY SPPC FOR ITS GAS DISTRIBUTION BUSINESS; (2) THE ABILITY OF SPR, NPC, AND SPPC TO ACCESS THE CAPITAL MARKETS TO SUPPORT THEIR REQUIREMENTS FOR WORKING CAPITAL, INCLUDING AMOUNTS NECESSARY TO FINANCE DEFERRED ENERGY COSTS, CONSTRUCTION COSTS, AND THE REPAYMENT OF MATURING DEBT, PARTICULARLY IN THE EVENT OF ADDITIONAL UNFAVORABLE RULINGS BY THE PUCN, A FURTHER DOWNGRADE OF THE CURRENT DEBT RATINGS OF SPR, NPC, OR SPPC, AND/OR ADVERSE DEVELOPMENTS WITH RESPECT TO NPC's OR SPPC'c POWER AND FUEL SUPPLIERS; (3) WHETHER NPC'S ABILITY TO PAY SPR DIVIDENDS WILL BE RESTORED IN THE NEAR FUTURE, AND WHETHER SPPC WILL BE ABLE TO CONTINUE TO PAY SPR DIVIDENDS UNDER THE TERMS OF SPPC's FINANCING AGREEMENTS AND/OR RESTATED ARTICLES OF INCORPORATION; (4) WHETHER THE PUCN WILL ISSUE FAVORABLE ORDERS IN A TIMELY MANNER TO PERMIT THE UTILITIES TO BORROW MONEY AND ISSUE ADDITIONAL SECURITIES TO FINANCE THE UTILITIES' OPERATIONS AND TO PURCHASE POWER AND FUEL NECESSARY TO SERVE THEIR RESPECTIVE CUSTOMERS AND TO REPAY MATURING DEBT; (5) WHETHER SUPPLIERS, SUCH AS ENRON, WHICH HAVE TERMINATED THEIR POWER SUPPLY CONTRACTS WITH NPC AND/OR SPPC WILL BE SUCCESSFUL IN PURSUING THEIR CLAIMS AGAINST THE UTILITIES FOR LIQUIDATED DAMAGES UNDER THEIR POWER SUPPLY CONTRACTS, AND WHETHER ENRON WILL BE SUCCESSFUL IN ITS LAWSUIT AGAINST NPC AND SPPC; (6) WHETHER SPR, NPC, AND SPPC WILL BE ABLE TO MAINTAIN SUFFICIENT STABILITY WITH RESPECT TO THEIR LIQUIDITY AND RELATIONSHIPS WITH SUPPLIERS TO BE ABLE TO CONTINUE TO OPERATE OUTSIDE OF BANKRUPTCY; (7) WHETHER CURRENT SUPPLIERS OF PURCHASED POWER, NATURAL GAS, OR FUEL TO NPC OR SPPC WILL CONTINUE TO DO BUSINESS WITH NPC OR SPPC OR WILL TERMINATE THEIR CONTRACTS AND SEEK LIQUIDATED DAMAGES FROM THE RESPECTIVE UTILITY; (8) WHETHER THE UTILITIES WILL NEED TO PURCHASE ADDITIONAL POWER ON THE SPOT MARKET TO MEET UNANTICIPATED POWER DEMANDS (FOR EXAMPLE, DUE TO UNSEASONABLY HOT WEATHER) AND WHETHER SUPPLIERS WILL BE WILLING TO SELL SUCH POWER TO THE UTILITIES IN LIGHT OF THEIR WEAKENED FINANCIAL CONDITION; (9) WHETHER SPPC WILL BE ABLE TO MAKE THE GASIFIER FACILITY AT THE PINON PINE POWER PROJECT OPERATIONAL AND, IN ANY EVENT, WHETHER SPPC WILL BE SUCCESSFUL IN OBTAINING PUCN APPROVAL TO RECOVER THE COSTS OF THE GASIFIER IN A FUTURE GENERAL RATE CASE; (10) WHETHER NPC AND SPPC WILL BE SUCCESSFUL IN OBTAINING PUCN APPROVAL TO RECOVER GOODWILL AND OTHER MERGER COSTS RECORDED IN CONNECTION WITH THE 1999 MERGER BETWEEN SPR AND NPC IN A FUTURE GENERAL RATE CASE; (11) WHOLESALE MARKET CONDITIONS, INCLUDING AVAILABILITY OF POWER ON THE SPOT MARKET, WHICH AFFECT THE PRICES THE UTILITIES HAVE TO PAY FOR POWER AS WELL AS THE PRICES AT WHICH THE UTILITIES CAN SELL ANY EXCESS POWER; 28 (12) THE FINAL OUTCOME OF THE UTILITIES' PENDING LAWSUITS IN NEVADA STATE COURT SEEKING TO REVERSE PORTIONS OF THE PUCN'S ORDERS DENYING THE RECOVERY OF DEFERRED ENERGY COSTS, INCLUDING THE OUTCOME OF PETITIONS FILED BY THE BUREAU OF CONSUMER PROTECTION OF THE NEVADA ATTORNEY GENERAL'S OFFICE SEEKING ADDITIONAL DISALLOWANCES; (13) WHETHER THE UTILITIES WILL BE ABLE, EITHER THROUGH FEDERAL ENERGY REGULATORY COMMISSION (FERC) PROCEEDINGS OR NEGOTIATION, TO OBTAIN LOWER PRICES ON THEIR LONGER-TERM PURCHASED POWER CONTRACTS ENTERED INTO DURING 2000 AND 2001 THAT ARE PRICED ABOVE CURRENT MARKET PRICES FOR ELECTRICITY; (14) THE EFFECT THAT ANY FUTURE TERRORIST ATTACKS, WARS, THREATS OF WAR, OR EPIDEMICS MAY HAVE ON THE TOURISM AND GAMING INDUSTRIES IN NEVADA, PARTICULARLY IN LAS VEGAS, AS WELL AS ON THE ECONOMY IN GENERAL; (15) UNSEASONABLE WEATHER AND OTHER NATURAL PHENOMENA, WHICH CAN HAVE POTENTIALLY SERIOUS IMPACTS ON THE UTILITIES' ABILITY TO PROCURE ADEQUATE SUPPLIES OF FUEL OR PURCHASED POWER TO SERVE THEIR RESPECTIVE CUSTOMERS AND ON THE COST OF PROCURING SUCH SUPPLIES; (16) INDUSTRIAL, COMMERCIAL, AND RESIDENTIAL GROWTH IN THE SERVICE TERRITORIES OF THE UTILITIES; (17) THE LOSS OF ANY SIGNIFICANT CUSTOMERS; (18) THE EFFECT OF EXISTING OR FUTURE NEVADA, CALIFORNIA, OR FEDERAL LEGISLATION OR REGULATIONS AFFECTING ELECTRIC INDUSTRY RESTRUCTURING, INCLUDING LAWS OR REGULATIONS WHICH COULD ALLOW ADDITIONAL CUSTOMERS TO CHOOSE NEW ELECTRICITY SUPPLIERS OR CHANGE THE CONDITIONS UNDER WHICH THEY MAY DO SO; (19) CHANGES IN THE BUSINESS OF MAJOR CUSTOMERS, INCLUDING THOSE ENGAGED IN GOLD MINING OR GAMING, WHICH MAY RESULT IN CHANGES IN THE DEMAND FOR SERVICES OF THE UTILITIES, INCLUDING THE EFFECT ON THE NEVADA GAMING INDUSTRY OF THE OPENING OF ADDITIONAL INDIAN GAMING ESTABLISHMENTS IN CALIFORNIA AND OTHER STATES; (20) CHANGES IN ENVIRONMENTAL REGULATIONS, TAX, OR ACCOUNTING MATTERS OR OTHER LAWS AND REGULATIONS TO WHICH THE UTILITIES ARE SUBJECT; (21) FUTURE ECONOMIC CONDITIONS, INCLUDING INFLATION OR DEFLATION RATES AND MONETARY POLICY; (22) FINANCIAL MARKET CONDITIONS, INCLUDING CHANGES IN AVAILABILITY OF CAPITAL OR INTEREST RATE FLUCTUATIONS; (23) UNUSUAL OR UNANTICIPATED CHANGES IN NORMAL BUSINESS OPERATIONS, INCLUDING UNUSUAL MAINTENANCE OR REPAIRS; AND (24) EMPLOYEE WORKFORCE FACTORS, INCLUDING CHANGES IN COLLECTIVE BARGAINING UNIT AGREEMENTS, STRIKES, OR WORK STOPPAGES. OTHER FACTORS AND ASSUMPTIONS NOT IDENTIFIED ABOVE MAY ALSO HAVE BEEN INVOLVED IN DERIVING THESE FORWARD-LOOKING STATEMENTS, AND THE FAILURE OF THOSE OTHER ASSUMPTIONS TO BE REALIZED, AS WELL AS OTHER FACTORS, MAY ALSO CAUSE ACTUAL RESULTS TO DIFFER MATERIALLY FROM THOSE PROJECTED. SPR, NPC AND SPPC ASSUME NO OBLIGATION TO UPDATE FORWARD-LOOKING STATEMENTS TO REFLECT ACTUAL RESULTS, CHANGES IN ASSUMPTIONS OR CHANGES IN OTHER FACTORS AFFECTING FORWARD-LOOKING STATEMENTS. CRITICAL ACCOUNTING POLICIES The following items represent critical accounting policies that under different conditions or using different assumptions could have a material effect on the financial condition, liquidity and capital resources of SPR and the Utilities: REGULATORY ACCOUNTING The Utilities' rates are currently subject to the approval of the PUCN and, in the case of SPPC, they are also subject to the approval of California Public Utility Commission (CPUC) and are designed to recover the cost of providing generation, transmission and distribution services. As a result, the Utilities qualify for the application of Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation," issued by the Financial Accounting Standards Board (FASB). This statement recognizes that the rate actions of a regulator can provide reasonable assurance of the existence of an asset and requires the capitalization of incurred costs that would otherwise be charged to expense where it is probable that future revenue will be provided to recover these costs. SFAS No. 71 prescribes the method to be used to record the financial transactions of a regulated entity. The criteria for applying SFAS No. 71 include the following: (i) rates are set 29 by an independent third party regulator, (ii) approved rates are intended to recover the specific costs of the regulated products or services, and (iii) rates that are set at levels that will recover costs can be charged to and collected from customers. Regulatory assets represent incurred costs that have been deferred because it is probable they will be recovered through future rates collected from customers. Regulatory liabilities generally represent obligations to make refunds to customers for previous collections for costs that are not likely to be incurred. Management regularly assesses whether the regulatory assets are probable of future recovery by considering factors such as applicable regulatory environment changes and the status of any pending or potential deregulation legislation. Although current rates do not include the recovery of all existing regulatory assets as discussed further below and in Note 1 in Notes to Financial Statements in SPR's, NPC's, and SPPC's Annual Report on Form 10-K for the year ended December 31, 2002, management believes the existing regulatory assets are probable of recovery. This determination reflects the current political and regulatory climate in the state, and is subject to change in the future. If future recovery of costs ceases to be probable, the write-off of regulatory assets would be required to be recognized as a charge or expensed in current period earnings. Regulatory Accounting affects other Critical Accounting Policies, including Deferred Energy Accounting, Accounting for Goodwill and Merger Costs, Accounting for Generation Divestiture Costs, Impairment of Long-Lived Assets, and Accounting for Derivatives and Hedging Activities, all of which are discussed immediately below. DEFERRED ENERGY ACCOUNTING On April 18, 2001, the Governor of Nevada signed into law Assembly Bill 369 (AB 369). The provisions of AB 369 include, among others, a reinstatement of deferred energy accounting for fuel and purchased power costs incurred by electric utilities. In accordance with the provisions of SFAS No. 71, the Utilities implemented deferred energy accounting on March 1, 2001, for their respective electric operations. Under deferred energy accounting, to the extent actual fuel and purchased power costs exceed fuel and purchased power costs recoverable through current rates, that excess is not recorded as a current expense on the statement of operations but rather is deferred and recorded as an asset on the balance sheet. Conversely, a liability is recorded to the extent fuel and purchased power costs recoverable through current rates exceed actual fuel and purchased power costs. These excess amounts are reflected in adjustments to rates and recorded as revenue or expense in future time periods, subject to PUCN review. AB 369 provides that the PUCN may not allow the recovery of any costs for purchased fuel or purchased power "that were the result of any practice or transaction that was undertaken, managed or performed imprudently by the electric utility." In reference to deferred energy accounting, AB 369 specifies that fuel and purchased power costs include all costs incurred to purchase fuel, to purchase capacity, and to purchase energy. The Utilities also record, and are eligible under the statute to recover, a carrying charge on such deferred balances. The Utilities are exposed to commodity price risk primarily related to changes in the market price of electricity as well as changes in fuel costs incurred to generate electricity. See Energy Supply in SPR's, NPC's, and SPPC's Annual Report on Form 10-K for the year ended December 31, 2002, for a discussion of the Utilities' purchased power procurement strategies, and Commodity Price Risk in Item 7A, Quantitative and Qualitative Disclosures About Market Risk, in SPR's, NPC's, and SPPC's Annual Report on Form 10-K for the year ended December 31, 2002, for a discussion of the Utilities' commodity risk management program. As discussed above, deferred energy accounting facilitates the recovery of costs incurred to procure fuel and purchased power for SPPC and NPC. As described in more detail under Regulation and Rate Proceedings, Nevada Matters, Nevada Power Company 2001 Deferred Energy Case, in SPR's, NPC's, and SPPC's Annual Report on Form 10-K for the year ended December 31, 2002, on November 30, 2001, NPC filed an application with the PUCN seeking to establish a Deferred Energy Accounting Adjustment (DEAA) rate to clear deferred balances for purchased fuel and power costs accumulated between March 1, 2001 and September 30, 2001. The application sought to establish a rate to clear accumulated purchased fuel and power costs of $922 million and spread the cost recovery over a period of not more than three years. On March 29, 2002, the PUCN issued its decision on the deferred energy application, disallowing $434 million of deferred purchased fuel and power costs, and allowing NPC to collect the remaining $478 million over three years beginning April 1, 2002. As a result of this disallowance, NPC wrote off $465 million of deferred energy costs and related carrying charges, the two major national rating agencies immediately downgraded the credit rating on SPR's, NPC's and SPPC's debt securities (followed by further downgrades late in April 2002), and the market price of SPR's common stock fell substantially. As described in more detail under Regulation and Rate Proceedings, Nevada Matters, Sierra Pacific Power Company 2002 Deferred Energy Case, in SPR's, NPC's, and SPPC's Annual Report on Form 10-K for the year ended December 31, 2002, SPPC filed an application with the PUCN seeking to establish a DEAA rate to clear its deferred balances for purchased fuel and power costs accumulated between March 1, 2001 and November 30, 2001. The application sought to establish a rate to clear accumulated purchased fuel and power costs of $205 million and spread the cost recovery over a period of not more than three years. On May 28, 2002, the PUCN issued its decision on SPPC's deferred energy application, disallowing $53 million of deferred purchased fuel and power costs, and allowing SPPC to collect the remaining $150 million 30 over three years beginning June 1, 2002. As a result of this decision, SPPC wrote off $58 million of disallowed deferred energy costs and related carrying charges in the second quarter of 2002. Both Utilities have continued to be entitled under AB 369 to utilize deferred energy accounting for their electric operations. Because of contracts entered into during the Western energy crisis in 2001 to assure adequate supplies of electricity for their customers, the Utilities incurred fuel and purchased power costs in excess of amounts they were permitted to recover in current rates. As a result, during 2002, both Utilities continued to record additional amounts in their deferral of energy costs accounts. On November 14, 2002, NPC filed an application with the PUCN seeking to clear deferred balances of $195.7 million for purchased fuel and power costs accumulated between October 1, 2001, and September 30, 2002, and to spread the recovery of the deferred costs, together with a carrying charge, over a period of not more than three years. Intervenors filed their direct testimony on March 7, 2003, and supplemental testimony was filed March 27, 2003, calling for disallowances between approximately $108 and $300 million of the total fuel and purchased power costs. The largest of the proposed disallowances are based on the same alleged imprudence as found in the PUCN order for NPC's 2001 Deferred Energy Case relating to NPC's failure to enter into power contracts in 1999. Certain Intervenors' testimony, in the current case, have argued in favor of disallowances based on the same alleged imprudence as cited in the last deferred order but have not quantified their proposals and in some cases have argued in favor of disallowances in excess of the ranges previously indicated. The PUCN Staff does not support this disallowance but calculated a range of $116 to $347 million in the event that the PUCN disallows deferred energy costs based upon the same alleged imprudence cited by the PUCN in its 2001 decision relative to this issue. While all Intervenors have called for the PUCN to reduce NPC's requested energy rates for recovery of past energy costs, some have also proposed to increase customers' energy rates for purchases that will occur during the upcoming deferred accounting period, which would decrease the accumulation of deferred energy costs. NPC's rebuttal testimony was filed on March 31, 2003, and hearings were completed on April 17, 2003. The PUCN's decision is scheduled for May 9, 2003. On January 14, 2003, SPPC filed an application with the PUCN seeking to clear deferred balances of $15.4 million for purchased fuel and power costs accumulated between December 1, 2001, and November 30, 2002 The application seeks to establish a DEAA rate to repay accumulated purchased fuel and power costs of $15.4 million and spread the cost recovery over a period of not more than three years. It also seeks to recalculate the Base Tariff Energy Rate to reflect anticipated ongoing purchased fuel and power costs. The total rate increase resulting from the requested DEAA would amount to 0.01%. The intervenors' testimony was received April 25, 2003, and includes proposed disallowances from $34 million to $76 million. While all Intervenors call for the PUCN to reduce SPPC's requested energy rates for recovery of past energy costs, some also propose to increase customers' energy rates for purchases that will occur during the upcoming deferred accounting period, which would decrease the accumulation of deferred energy costs. A hearing is scheduled to begin on May 12, 2003, and a ruling is required before July 13, 2003. A significant disallowance in either or both of these deferred energy rate cases or in future cases to be filed by either Utility would have a material adverse affect on the future financial position, results of operations, and liquidity of SPR, NPC, and SPPC and could make it difficult for one or more of SPR, NPC or SPPC to continue to operate outside of bankruptcy. See Regulation and Rate Proceedings, later, for additional discussion of the regulatory process underway to recover these deferred costs. If not for deferred energy accounting during 2003 and 2002, SPR's, NPC's and SPPC's results of operations, financial condition, liquidity and capital resources would have been significantly different. For example, without the deferred energy accounting provisions of AB 369, the reported purchased fuel and power costs of SPR, NPC, and SPPC for the quarter ended March 31, 2003, would have decreased (net of income tax) by approximately $54.7 million, $47.3 million, and $7.4 million, respectively, and the reported interest accrued on deferred energy of SPR, NPC, and SPPC would have decreased (net of income tax) by approximately $4.8 million, $3.7 million, and $1.1 million, respectively, for the same period. Similarly, without the deferred energy accounting provisions of AB 369, the reported purchased fuel and power costs of SPR, NPC, and SPPC for the quarter ended March 31, 2002, would have increased (net of income tax) by approximately $9.3 million, $6.3 million, and $3 million, respectively, and the reported interest accrued on deferred energy of SPR, NPC, and SPPC would have decreased (net of income tax) by approximately $15.6 million, $12.9 million, and $2.7 million, respectively, for the same period. The effects of AB 369 on 2002 purchased fuel and power costs and interest accrued on deferred energy discussed above exclude the write-off of $465 million pursuant to the PUCN's March 29, 2002 decision discussed earlier. 31 ACCOUNTING FOR GOODWILL AND MERGER COSTS The order issued by the PUCN in December 1998 approving the merger of SPR and NPC directed both NPC and SPPC to defer three categories of merger costs to be reviewed for recovery through future rates. That order specifically directed both Utilities to defer merger transaction costs, transition costs and goodwill costs for a three-year period. The deferral of these costs was intended to allow adequate time for the anticipated savings from the merger to develop. At the end of the three-year period, the order instructs the Utilities to propose an amortization period for the merger costs and allows the Utilities to recover the costs to the extent they are offset by merger savings. Costs deferred as a result of the PUCN order were $331.2 million of goodwill and $62.6 million in other merger costs as of March 31, 2003. The deferred other merger costs consist of $40.9 million of transaction and transition costs and $21.7 million of employee separation costs. Employee separation costs were comprised of $17.2 million of employee severance, relocation and related costs, and $4.5 million of pension and post-retirement benefits net of plan curtailment gains. On October 1, 2001, and November 30, 2001, NPC and SPPC, respectively, filed applications with the PUCN for general rate increases that included, among other items, requests to recover deferred merger costs, including goodwill. In its decisions dated March 27, 2002, and May 28, 2002, for NPC and SPPC, respectively, the PUCN decided not to make any determination on the recovery of merger costs until general rate cases are filed with test years ending on or after December 31, 2002. However, the PUCN did instruct the Utilities to continue to recognize these costs as deferred assets without carrying charges. The extent to which goodwill and merger costs will be recovered in future revenues and the timing of those recoveries is expected to be determined in general rate cases that are required to be filed in 2003. To the extent that the Utilities are not permitted to recover any portion of goodwill in future rates, the amount not recoverable will be reviewed for impairment and accounted for under the provisions of SFAS No. 142. A significant disallowance of goodwill or merger costs by the PUCN could have a material adverse affect on the future financial position, results of operations and cash flows of SPR, NPC, and SPPC and could make it difficult for one or more of SPR, NPC, or SPPC to continue to operate outside of bankruptcy. ACCOUNTING FOR GENERATION DIVESTITURE COSTS As a condition to its approval of the merger between SPR and NPC, the Utilities filed, and in February 2000 the PUCN approved, a revised Divestiture Plan stipulation for the sale of the Utilities' generation assets. In May 2000 an agreement was announced for the sale of NPC's 14% undivided interest in the Mohave Generating Station ("Mohave"). In the fourth quarter of 2000, the Utilities announced agreements to sell six additional bundles of generation assets described in the approved Divestiture Plan. The sales were subject to approval and review by various regulatory agencies. AB 369, which was signed into law on April 18, 2001, prohibits until July 2003 the sale of generation assets and directs the PUCN to vacate any of its orders that had previously approved generation divestiture transactions. In January 2001, California enacted a law that prohibits until 2006 any further divestiture of generation properties by California utilities, including SPPC, and could also affect any sale of NPC's interest in Mohave after July 2003 since the majority owner of that project is Southern California Edison. SPPC's request for an exemption from the requirements of a separate California law requiring approval of the CPUC to divest its plants was denied. In September 2002, the California Legislature approved an exemption to AB 6 that would allow SPPC to complete the sale of the hydroelectric units to TMWA subject to review and approval of the sale by the CPUC. The sales agreements for the six bundles provided that they terminate eighteen months after their execution, and all of the agreements have now terminated in accordance with their respective provisions. As of March 31, 2003, NPC and SPPC had incurred costs of approximately $20.6 million and $12.4 million, respectively, in order to prepare for the sale of generation assets. In the fourth quarter of 2001, each Utility requested recovery of its respective costs in its application for a general rate increase filed with the PUCN. In 2002, the PUCN delayed recovery of divestiture costs to future rate case requests but did grant a carrying charge on the costs until such time as recovery is allowed. To the extent that the Utilities are not permitted to recover any portion of these costs in future rates, the disallowed costs and related carrying charges would be required to be written off in current period earnings. IMPAIRMENT OF LONG-LIVED ASSETS SPR and the Utilities evaluate their Utility Plant and definite-lived tangible assets for impairment whenever indicators of impairment exist. As discussed in more detail in Note 21, Pinon Pine, of Notes to Financial Statements in SPR's, NPC's, and SPPC's Annual Report on Form 10-K for the year ended December 31, 2002, SPPC owns a combined cycle generation facility, a post-gasification facility, and, through its wholly owned subsidiaries, owns a gasifier that are collectively referred to as the Pinon 32 Pine Power Project ("Pinon Pine"). Construction of Pinon Pine was completed in June 1998. Included in the Condensed Consolidated Balance Sheets of SPR and SPPC is the net book value of the gasifier and related assets, which is approximately $99 million as of March 31, 2003. To date, SPPC has not been successful in obtaining sustained operation of the gasifier. In 2001 SPPC retained an independent engineering consulting firm to complete a comprehensive study of the Pinon Pine gasification plant. SPPC received a final report of the study in November 2002. SPPC is reviewing the various options outlined in the study. If after evaluating the options presented in the draft report, SPPC decides not to pursue modifications intended to make the facility operational, SPPC intends to seek recovery, net of salvage, through regulated rates in its next general rate case based, in part, on the PUCN's approval of Pinon Pine as a demonstration project in an earlier resource plan. However, if SPPC is unsuccessful in obtaining recovery, there could be a material adverse effect on SPPC's and SPR's financial position, results of operations and cash flows. ACCOUNTING FOR DERIVATIVES AND HEDGING ACTIVITIES SPR, SPPC, and NPC apply SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS No. 138. As amended, SFAS No. 133 requires that an entity recognize all derivatives as either assets or liabilities in the statement of financial position and measure those 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 operations and comprehensive income. Upon settlement of a derivative instrument, actual fuel and purchased power costs are recognized if they are currently recoverable or deferred if they are recoverable or payable through future rates. The fair values of the forward contracts and swaps are determined based on quotes obtained from independent brokers and exchanges. The fair values of options are determined using a pricing model which incorporates assumptions such as the underlying commodity's forward price curve, time to expiration, strike price, interest rates, and volatility. The use of different assumptions and variables in the model could have a significant impact on the valuation of the instruments. SPR and the Utilities have other non-energy related derivative instruments. The changes in fair values of these non-energy related derivatives are reported in Other comprehensive income until the related transactions are settled or terminate, at which time the amounts are reclassified into earnings. In connection with SPR's issuance of its Convertible Notes (see Note 4, Long-Term Debt), the conversion option, which is treated as a cash-settled written call option, was separated from the debt and accounted for separately as a derivative instrument in accordance with FASB's Emerging Issues Task Force Issue 90-19, "Convertible Bonds with Issuer Option to Settle for Cash upon Conversion". Upon issuance, the fair value of the option was recorded as a current liability in Other current liabilities. The change in the fair value is recognized in earnings in the period of the change. ENVIRONMENTAL CONTINGENCIES SPR and its subsidiaries are subject to federal, state and local regulations governing air and water quality, hazardous and solid waste, land use and other environmental considerations. Nevada's Utility Environmental Protection Act requires approval of the PUCN prior to construction of major utility, generation or transmission facilities. The United States Environmental Protection Agency (EPA), Nevada Division of Environmental Protection (NDEP), and Clark County Health District (CCHD) administer regulations involving air and water quality, solid, hazardous and toxic waste. SPR and its subsidiaries are subject to rising costs that result from a steady increase in the number of federal, state and local laws and regulations designed to protect the environment. These laws and regulations can result in increased capital, operating, and other costs as a result of compliance, remediation, containment and monitoring obligations, particularly with laws relating to power plant emissions. In addition, SPR or its subsidiaries may be a responsible party for environmental clean up at a site identified by a regulatory body. The management of SPR and its subsidiaries cannot predict with certainty the amount and timing of all future expenditures related to environmental matters because of the difficulty of estimating clean up costs and compliance and the possibility that changes will be made to the current environmental laws and regulations. There is also uncertainty in quantifying liabilities under environmental laws that impose joint and several liability on all potentially 33 responsible parties. SPR and its subsidiaries accrue for environmental costs only when they can conclude that it is probable that they have an obligation for such costs and can reasonably determine the amount of such costs. Note 11, Commitments and Contingencies, of Notes to Condensed Consolidated Financial Statements discusses the environmental matters of SPR and its subsidiaries that have been identified, and the estimated financial effect of those matters. To the extent that (1) actual results differ from the estimated financial effects, (2) there are environmental matters not yet identified for which SPR or its subsidiaries are determined to be responsible, or (3) the Utilities are unable to recover through future rates the costs to remediate such environmental matters, there could be a material adverse effect on the financial condition and future liquidity and results of operations of SPR and its subsidiaries. LITIGATION CONTINGENCIES Note 11, Commitments and Contingencies, of Notes to Condensed Consolidated Financial Statements discusses the significant legal matters of SPR and its subsidiaries. SPR and its subsidiaries, through the course of their normal business operations, are currently involved in a number of other legal actions, none of which has had or, in the opinion of management, is expected to have, a significant impact on its financial position or results of operations. DEFINED BENEFIT PLANS AND OTHER POSTRETIREMENT PLANS As further explained in Note 14, Retirement Plan and Post-Retirement Benefits, of Notes to Financial Statements in SPR's, NPC's, and SPPC's Annual Report on Form 10-K for the year ended December 31, 2002, SPR maintains a pension plan as well as other postretirement benefit plans that provide health and life insurance for retired employees. All employees are eligible for these benefits if they reach retirement age while still working for SPR or its subsidiaries. These costs are determined in accordance with the provisions of SFAS No. 87, "Employers' Accounting for Pensions," and SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," and ultimately collected in rates billed to customers. The amounts funded are then used to meet benefit payments to plan participants. SPR contributed approximately $25.3 million and $41.1 million to its pension plan, and $60,000 and $0.2 million to the other postretirement benefits plan in 2003 and 2002, respectively. Due to the sharp decline in United States equity markets since the third quarter of 2000, the value of a significant portion of the assets held in the plans' trusts to satisfy the obligations of the plans has decreased significantly. As a result, additional contributions may be required in the future to meet the requirements of the plan to pay benefits to plan participants. PENSION PLANS SPR's reported costs of providing non-contributory defined pension benefits (described in Note 14, Retirement Plan and Post-Retirement Benefits, of Notes to Financial Statements in SPR's, NPC's, and SPPC's Annual Report on Form 10-K for the year ended December 31, 2002) are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience. For example, pension costs are impacted by actual employee demographics (including age and employment periods), the level of contributions SPR makes to the plan, and earnings on plan assets. Changes made to the provisions of the plan may also impact current and future pension costs. Pension costs may also be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets and the discount rates used in determining the projected benefit obligation and pension costs. SPR has made no changes to pension plan provisions in 2002 or 2003 that have had any significant impact on recorded pension amounts. SPR reduced the discount rate used in determining pension expense for the calendar year 2003 from 7.5% to 6.75%. This change will not have a significant impact on reported pension costs for 2003. SPR's pension plan assets are primarily made up of equity and fixed income investments. Fluctuations in actual equity market returns as well as changes in general interest rates may result in increased or decreased pension costs in future periods. Likewise, changes in assumptions regarding current discount rates and expected rates of return on plan assets could also increase or decrease recorded pension costs. The following chart reflects the sensitivities associated with a change in certain actuarial assumptions by the indicated percentage. While the chart below reflects an increase in the percentage for each assumption, SPR and its actuaries expect that the inverse of this change would impact the projected benefit obligation (PrBO) and the reported annual pension cost on the income statement (PeC) by a similar amount in the opposite direction. Each sensitivity below reflects an evaluation of the change based solely on a change in that assumption only. 34
----------------------------------------------------------------------------- Change in Impact on Impact on Actuarial Assumption Assumption PrBO PeC ($ millions) Incr/(Decr) Incr/(Decr) Incr/(Decr) ----------------------------------------------------------------------------- Discount Rate 1% $ (45.0) $ (4.9) Rate of Return on Plan Assets 1% $ - $ (2.7) -----------------------------------------------------------------------------
In selecting an assumed discount rate, SPR considered the yield on high quality bonds as measured by the Moody's Investors Service, Inc. (Moody's) Aa composite bond index. In selecting an assumed rate of return on plan assets, SPR considers past performance and economic forecasts for the types of investments held by the plan. The market value of SPR's plan assets has been affected by sharp declines in equity markets since the third quarter of 2000. As a result of SPR's plan asset returns at September 30, 2002, SPR was required to recognize an additional minimum liability in the amount of $89.6 million, as prescribed by SFAS No. 87. The liability was recorded as a reduction to common equity through a charge to Accumulated Other Comprehensive Income, and did not affect net income for 2002. The charge to Accumulated Other Comprehensive Income will be restored through common equity in future periods to the extent fair value of trust assets exceeds the accumulated benefit obligation. Pension cost and cash funding requirements could increase in future years without a substantial recovery in the equity markets. OTHER POSTRETIREMENT BENEFITS SPR's reported costs of providing other postretirement benefits (described in Note 14, Retirement Plan and Post-Retirement Benefits, of Notes to Financial Statements in SPR's, NPC's, and SPPC's Annual Report on Form 10-K for the year ended December 31, 2002) are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience. For example, other postretirement benefit costs are impacted by actual employee demographics (including age and employment periods), the level of contributions made to the plan, earnings on plan assets, and health care cost trends. Changes made to the provisions of the plan may also impact current and future other postretirement benefit costs. Other postretirement benefit costs may also be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets and the discount rates used in determining the postretirement benefit obligation and postretirement costs. SPR has made no changes to other postretirement benefit plan provisions in 2002 or 2003 that have had any significant impact on recorded benefit plan amounts. SPR reduced the discount rate used in determining other postretirement expense for the calendar year 2003 from 7.5% to 6.75%. This change will not have a significant impact on reported other postretirement benefit costs for 2003. However, in determining the other postretirement benefit obligation and related cost, these assumptions can change from period to period, and such changes could result in material changes to such amounts. SPR's other postretirement benefit plan assets are primarily made up of equity and fixed income investments. Fluctuations in actual equity market returns as well as changes in general interest rates may result in increased or decreased other postretirement benefit costs in future periods. Likewise, changes in assumptions regarding current discount rates and expected rates of return on plan assets could also increase or decrease recorded other postretirement benefit costs. The following chart reflects the sensitivities associated with a change in certain actuarial assumptions by the indicated percentage. While the chart below reflects an increase in the percentage for each assumption, SPR and its actuaries expect that the inverse of this change would impact the projected accumulated other postretirement benefit obligation (APBO) and the reported annual other postretirement benefit cost on the income statement (PBC) by a similar amount in the opposite direction. Each sensitivity below reflects an evaluation of the change based solely on a change in that assumption only. 35
----------------------------------------------------------------------------- Change in Impact on Impact on Actuarial Assumption Assumption APBO PBC ($ millions) Incr/(Decr) Incr/(Decr) Incr/(Decr) ----------------------------------------------------------------------------- Discount Rate 1% $ (15.7) $ (1.5) Health Care Cost Trend Rate 1% $ 14.9 $ 1.5 Rate of Return on Plan Assets 1% N/A $ (0.5) -----------------------------------------------------------------------------
In selecting an assumed discount rate, SPR considered the yield on high quality bonds as measured by Moody's Aa composite bond index. In selecting an assumed rate of return on plan assets, SPR considers past performance and economic forecasts for the types of investments held by the plan. The market value of the SPR's plan assets has been affected by sharp declines in equity markets since the third quarter of 2000. Also, other postretirement benefit cost and cash funding requirements could increase in future years without a substantial recovery in the equity markets. COST CAPITALIZATION POLICIES The Utilities continue to devote substantial resources in 2003 on the Centennial Transmission project at NPC and the Falcon to Gonder Transmission project at SPPC. In addition, certain operating units of the Utilities are charged with maintaining, repairing and replacing components of generation, transmission and distribution systems both on a scheduled basis and on an as-needed basis. As described in Note 1, Summary of Significant Accounting Policies, of Notes to Financial Statements in SPR's, NPC's, and SPPC's Annual Report on Form 10-K for the year ended December 31, 2002, the cost of additions, including betterments and replacements of units of property, is charged to utility plant. When units of property are replaced, renewed or retired, their cost, plus removal or disposal costs less salvage, is charged to accumulated depreciation. Certain direct and indirect costs are capitalized, including the cost of debt and equity capital associated with construction and retirement activity as prescribed by Generally Accepted Accounting Principles (GAAP) and the FERC's Uniform System of Accounts. The indirect construction overhead costs capitalized are based upon the following cost components: the cost of time spent by administrative employees in planning and directing construction; property taxes; employee benefits including such costs as pensions, postretirement and post employment benefits, vacations and payroll taxes; and an allowance for funds used during construction (AFUDC). The level of indirect construction overhead costs capitalized by the Utilities is based upon real-time construction activity. Accordingly, payroll and other costs capitalized will fluctuate based upon seasonal construction activities and the deployment of resources to those efforts. During periods of higher maintenance levels, these payroll and other costs will not be capitalized. As such, operating income could be impacted by the manner in which payroll and related costs are deployed. However, the total cash flow of the Utilities is not impacted by the allocation of these costs to various construction or maintenance activities. During the three months ended March 31, 2003, and March 31, 2002, NPC and SPPC capitalized approximately $3.5 million and $2.1 million, respectively, of AFUDC as a result of construction activity financed primarily by their debt. This amount is a non-cash component reflected in the Consolidated Statements of Operations. Recognition of AFUDC as a cost of utility plant is in accordance with established regulatory ratemaking practices. Such practices permit the Utility to earn a fair return on, and recover in rates, all capital costs charged for Utility services. DEPRECIATION EXPENSE The Utilities have a significant investment in electric plant. SPPC also has an investment in gas distribution plant. Depreciable assets of generation, transmission and distribution operations represent approximately 93% of the Utilities' investment in utility plant. As described in Note 1, Summary of Significant Accounting Policies, of Notes to Financial Statements in SPR's, NPC's, and SPPC's Annual Report on Form 10-K for the year ended December 31, 2002, the Utilities depreciate these assets utilizing a composite rate, which currently includes a component for net negative salvage. These assets are depreciated on a straight-line basis over the remaining useful life of the related assets, which approximates the anticipated physical lives of these assets in most cases. The Nevada Administrative Code requires the Utilities to provide a depreciation study every four years in order to substantiate the remaining physical lives of their investment in utility plant. Adjustments to the estimated depreciable lives of the Utilities' plant are recorded on a prospective basis, as prescribed by GAAP and the FERC's Uniform System of Accounts. Substantially all of the Utilities' plant is subject to the ratemaking jurisdiction of the PUCN or the FERC and, in the case of SPPC's California operations, the CPUC, which also approves any changes the Utilities may make to depreciation rates 36 utilized for this property. Because the Utilities' periodic depreciation expense is included as a component of the revenue requirement utilized in the development of the Utilities' tariff rates, revenue reflects collection of the recognized depreciation expense. Accordingly, the impact of depreciation on net income is not significant. However, operating cash flows are positively affected by the amount of depreciation collected in rates, since depreciation expense is not a current cash outlay for the Utilities. ASSET RETIREMENT OBLIGATIONS In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 provides accounting requirements for the recognition and measurement of liabilities associated with the retirement of tangible long-lived assets. Under the standard, these liabilities will be recognized at fair value as incurred and capitalized as part of the cost of the related tangible long-lived assets. Accretion of the liabilities due to the passage of time will be an operating expense. Retirement obligations associated with long-lived assets included within the scope of SFAS No. 143 are those for which a legal obligation exists under enacted laws, statutes written or oral contracts, including obligations arising under the doctrine of promissory estoppel. The Utilities adopted SFAS No. 143 on January 1, 2003. Prior to adopting SFAS 143, costs for removal of most utility assets were accrued as an additional component of depreciation expense. Under SFAS 143, only the costs to remove an asset with legally binding retirement obligations will be accrued over time through accretion of the asset retirement obligation and depreciation of the capitalized asset retirement cost. Management's methodology to assess its legal obligation included an inventory of assets by system and components, and a review of right of ways and easements, regulatory orders, leases and federal, state, and local environmental laws. Management assumed in determining its Asset Retirement Obligations that transmission, distribution and communications systems will be operated in perpetuity and would continue to be used or sold without land remediation; and, mass asset properties that are replaced or retired frequently would be considered normal maintenance. Management has identified a legal obligation to retire generation plant assets specified in land leases for NPC's jointly-owned Navajo generating station. The land on which the Navajo generating station resides is leased from the Navajo Nation. The provisions of the leases require the lessees to remove the facilities upon request of the Navajo Nation at the expiration of the leases. Although the related retirement obligation and corresponding charges recognized were immaterial to the financial statements of NPC, those amounts were based on certain estimates and assumptions. The estimated liability is based on two levels of decommissioning, minimal and full, and two possible retirement dates. The liability is escalated using average historical Consumer Price Index inflation factors equal to the estimated retirement dates. The liability is discounted using credit-adjusted risk-free rates of return for the respective retirement dates. Changes to future statements of financial position and results of operations will occur to the extent that actual results differ from the estimates and assumptions used, including changes in decommissioning costs, timing or changes in NPC's credit rating. SPPC has no significant asset retirement obligations. The Utilities have various transmission and distribution lines as well as substations that operate under various rights of way that contain end dates and restorative clauses. Management operates the transmission and distribution system as though they will be operated in perpetuity and will continue to be used or sold without land remediation. As a result, the Utilities have not recorded any costs associated with the removal of the transmission and distribution systems. STOCK COMPENSATION PLANS In December 2002, the FASB released SFAS No. 148, "Accounting for Stock-Based Compensation-Transition and Disclosure," as an amendment to SFAS No. 123, "Accounting for Stock-Based Compensation." SPR has previously adopted the disclosure-only provisions of SFAS No. 123, and as of December 31, 2002 has adopted the updated disclosure requirements set forth in SFAS No. 148. Pursuant to those updated disclosure requirements, SPR has included the following discussion on the stock compensation plans. For additional information on SPR's stock compensation plans, see Note 1, Summary of Significant Accounting Policies, and Note 15, Stock Compensation Plans, of Notes to Financial Statements in SPR's, NPC's, and SPPC's Annual Report on Form 10-K for the year ended December 31, 2002. At March 31, 2003, SPR had several stock-based compensation plans. SPR applies Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees, in accounting for its stock option plans. Accordingly, no compensation cost has been recognized for nonqualified stock options and the employee stock purchase plan. SPR has adopted the disclosure-only provisions of SFAS No. 123, Accounting for Stock Based Compensation, and its related amendment(s). UNBILLED RECEIVABLES Revenues related to the sale of energy are recorded based on meter reads, which occur on a systematic basis throughout a month, rather than when the service is rendered or energy is delivered. At the end of each month, the energy 37 delivered to the customers from the date of their last meter read to the end of the month is estimated and the corresponding unbilled revenues are calculated. These estimates of unbilled sales and revenues are based on the ratio of billable days versus unbilled days, amount of energy procured and generated during that month, historical customer class usage patterns and the Utilities' current tariffs. Customer accounts receivable as of March 31, 2003, include unbilled receivables of $48 million and $53 million for NPC and SPPC, respectively. Customer accounts receivable as of March 31, 2002, include unbilled receivables of $57 million and $58 million for NPC and SPPC, respectively. PROVISION FOR UNCOLLECTIBLE ACCOUNTS The Utilities reserve for doubtful accounts based on past experience writing off uncollectible customer accounts. The adequacy of these reserves will vary to the extent that future collections differ from past experience. FINANCIAL CONDITION AND MATERIAL CHANGES IN RESULTS OF OPERATIONS SIERRA PACIFIC RESOURCES The operating results of SPR primarily reflect those of NPC and SPPC, discussed later. During the first three months of 2003, SPR incurred a net loss of $15.5 million compared to a $302.9 million net loss for the same period during 2002. Operating results for the three months ended March 31, 2003 were negatively affected by higher interest costs during the period and lower sales for the reasons discussed later. During the same period, SPR recorded an unrealized gain on the derivative instrument associated with the issuance of $300 million of convertible debt (see Financing Transactions, discussed later). SPR's net loss of $302.9 million for the three months ended March 31, 2002, reflects the write-off of approximately $465 million (before taxes) of deferred energy costs and related carrying charges as a result of PUCN decision in NPC's 2001 deferred energy rate case. SPR did not pay or declare a common dividend in the first quarter of 2003. NPC and SPPC did not declare or pay common stock dividends to their parent, SPR, in the first quarter of 2003. SPPC paid $975,000 in dividends to holders of its preferred stock during the first quarter of 2003. NPC and SPPC each received a capital contribution of $10 million from SPR in March 2002. LIQUIDITY AND CAPITAL RESOURCES (SPR CONSOLIDATED) SPR, on a stand-alone basis, had cash and cash equivalents of approximately $166.7 million at March 31, 2003. On April 21, 2003, SPR utilized approximately $133 million of its cash and cash equivalents to repay unsecured Floating Rate Notes due April 20, 2003. SPR's future liquidity and its ability to pay the principal of and interest on its indebtedness depend on SPPC's ability to continue to pay dividends to SPR, on NPC's financial stability and the restoration of its ability to pay dividends to SPR, and on SPR's ability to access the capital markets or otherwise refinance maturing debt. Further adverse developments at NPC or SPPC, including a material disallowance of deferred energy costs in current and future rate cases or an adverse decision in the pending lawsuit by Enron, could make it difficult for SPR to operate outside of bankruptcy. DIVIDENDS FROM SUBSIDIARIES Since SPR is a holding company, substantially all of its cash flow is provided by dividends paid to SPR by NPC and SPPC on their common stock, all of which is owned by SPR. Since NPC and SPPC are public utilities, they are subject to regulation by state utility commissions which may impose limits on investment returns or otherwise impact the amount of dividends that the Utilities may declare and pay, and to federal statutory limitation on the payment of dividends. In addition, certain agreements entered into by the Utilities set restrictions on the amount of dividends they may declare and pay and restrict the circumstances under which such dividends may be declared and paid. The specific restrictions on dividends contained in agreements to which NPC and SPPC are party, as well as specific regulatory limitations on dividends, are summarized below. - NPC's first mortgage indenture limits the cumulative amount of dividends and other distributions that NPC may pay on its capital stock to the cumulative net earnings of NPC since 1953, subject to adjustments for the net proceeds of sales of capital stock since 1953. At the present time, this restriction precludes NPC from making further payments of dividends on NPC's common stock and will continue to bar dividends until NPC, over time, generates sufficient earnings to eliminate the deficit under this provision (which was approximately $254 million as of March 31, 2003), unless the restriction is earlier waived, amended, or removed by the consent of the first mortgage bondholders, or the first mortgage bonds are redeemed or defeased. There can be no assurance that any such consent could be obtained or that any first mortgage bonds could be redeemed prior to their stated maturity. Under this provision, NPC continues 38 to have capacity to repurchase or redeem shares of its capital stock, although other restrictions set forth below would limit the amount of any such repurchases or redemptions. - NPC's 10 7/8% General and Refunding Mortgage Notes, Series E, due 2009, which were issued on October 29, 2002, limit the amount of payments in respect of common stock that NPC may pay to SPR. However, that limitation does not apply to payments by NPC to enable SPR to pay its reasonable fees and expenses (including, but not limited to, interest on SPR's indebtedness and payment obligations on account of SPR's Premium Income Equity Securities (PIES)) provided that: - those payments do not exceed $60 million for any one calendar year, - those payments comply with any regulatory restrictions then applicable to NPC, and - the ratio of consolidated cash flow to fixed charges for NPC's most recently ended four full fiscal quarters immediately preceding the date of payment is at least 1.75 to 1. The terms of the Series E Notes also permit NPC to make payments to SPR in an aggregate amount not to exceed $15 million from the date of the issuance of the Series E Notes. In addition, NPC may make 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 has a ratio of consolidated cash flow to fixed charges for NPC's most recently ended four full fiscal quarters immediately preceding the payment date of at least 2.0 to 1, and - the total amount of such dividends is less than: - 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 - 100% of NPC's aggregate net cash proceeds from contributions to its common equity capital or the issuance or sale of certain equity or convertible debt securities of NPC, plus - the lesser of cash return of capital or the initial amount of certain restricted investments, plus - 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 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 payments in respect of common stock by NPC to SPR that is identical to the limitation contained in NPC's General and Refunding Mortgage Notes, Series E, described above. - The PUCN issued a Compliance Order, Docket No. 02-4037, on June 19, 2002, relating to NPC's request for authority to issue long-term debt. The PUCN order requires that, until such time as the order's authorization expires (December 31, 2003), NPC must either receive the prior approval of the PUCN or reach an equity ratio of 42% before paying any dividends to SPR. If NPC achieves a 42% equity ratio prior to December 31, 2003, the dividend restriction ceases to have effect. As of March 31, 2003, NPC's equity ratio was 36.0%. - 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 dated October 30, 2002, which expires October 31, 2005, limits the amount of payments that SPPC may pay to SPR. However, that limitation does not apply to payments by SPPC to enable SPR to pay its reasonable fees and expenses (including, but not limited to, interest on SPR's indebtedness and payment obligations on account of SPR's PIES) provided that those payments do not exceed $90 million, $80 million and $60 million in the aggregate for the twelve month periods ending on October 30, 2003, 2004 and 2005, respectively. The Term Loan Agreement also permits SPPC to make payments to SPR in an aggregate amount not to exceed $10 million during the term of the Term Loan Agreement. In addition, SPPC may make payments to SPR in excess of the amounts described above so long as, at the time of the payment and after giving effect to the payment, there are no defaults or events of default under the Term Loan Agreement, and such amounts, when aggregated with the amount of payments to SPR by SPPC since the date of execution of the Term Loan Agreement, do not exceed the sum of: - 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 39 - 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. SPPC's Articles also prohibit SPPC from declaring or paying any dividends on any shares of common stock (other than dividends payable in shares of common stock), or making any other distribution on any shares of common stock or any expenditures for the purchase, redemption or other retirement for a consideration of shares of common stock (other than in exchange for or from the proceeds of the sale of common stock) except from the net income of SPPC, and its predecessor, available for dividends on common stock accumulated subsequent to December 31, 1955, less preferred stock dividends, plus the sum of $500,000. At the present time, SPPC believes that these restrictions do not materially limit its ability to pay dividends and/or to purchase or redeem shares of its common stock - The Utilities are subject to the provision of the Federal Power Act that states that dividends cannot be paid out of funds that are properly included in capital accounts. Although the meaning of this provision is unclear, it could be interpreted to impose an additional material limitation on a utility's ability to pay dividends in the absence of retained earnings.. Management intends to seek a modification of the financial covenant contained in NPC's first mortgage indenture in the near future. The regulatory limitation contained in the PUCN's Compliance Order, Docket No. 02-4037, dated June 19, 2002, expires on December 31, 2003. Prior to the expiration date of the Compliance Order, management may seek PUCN approval for a payment of dividends by NPC or may seek a waiver from the PUCN of the dividend restriction. EFFECTS OF RATE CASE DECISIONS On March 29 and April 1, 2002, S&P and Moody's lowered the unsecured debt ratings of SPR, NPC and SPPC to below investment grade in response to the decision of the PUCN with respect to NPC's rate cases. On April 23 and 24, 2002, the unsecured debt ratings of SPR and the Utilities were further downgraded by both rating agencies, and the Utilities' secured debt ratings were downgraded to below investment grade. The downgrades affected SPR's, NPC's and SPPC's liquidity primarily in two principal areas: (1) their respective financing arrangements, and (2) NPC's and SPPC's contracts for fuel, for purchase and sale of electricity and for transportation of natural gas. For more detailed discussion of these effects please see SPR's, NPC's and SPPC's Annual Report on Form 10-K for the year ended December 31, 2002. ACCOUNTS RECEIVABLE FACILITY On October 29, 2002, NPC and SPPC established accounts receivable purchase facilities of up to $125 million and $75 million, respectively, which expire on August 28, 2003 unless either NPC or SPPC has activated its respective facility before that date, in which case such facility will be automatically extended to, and will expire on, October 28, 2003. If NPC or SPPC elect to activate their receivables purchase facilities, they will sell all of their accounts receivable generated from the sale of electricity and natural gas to customers to their newly created bankruptcy remote special purpose subsidiaries. The receivables sales will be without recourse except for breaches of customary representations and warranties made at the time of sale. The subsidiaries will, in turn, sell these receivables to a bankruptcy-remote subsidiary of SPR. SPR's subsidiary will issue variable rate revolving notes backed by the purchased receivables. Lehman Brothers Holdings, Inc. has committed to be the sole initial committed purchaser of all of the variable rate revolving notes. The agreements relating to the receivables purchase facilities contain various conditions to purchase, covenants and trigger events, and other provisions customary in receivables transactions. In addition to customary termination and mandatory repurchase events, each Utilities' receivables purchase facility may terminate in the event that the Utility or SPR defaults (i) on the payment of indebtedness, or (ii) on the payment of amounts due under a swap agreement, and such defaults aggregate to greater than $10 million and $5 million for the Utility and SPR, respectively. Under the terms of the agreements relating to the receivables purchase facility, each Utility's facility may not be activated or, if activated, will be terminated in the event of a material adverse change in the condition, operations or business prospects of the Utility. SPR has agreed to guaranty the performance by NPC and SPPC of certain obligations as sellers and servicers under the receivables purchase facilities. NPC and SPPC intend to use their accounts receivables purchase facilities as back-up liquidity facilities and do not plan to activate these facilities in the foreseeable future. 40 CROSS DEFAULT PROVISIONS Certain financing agreements of SPR and the Utilities contain cross-default provisions that would result in an event of default under such financing agreements if there is a failure under other financing agreements of SPR and the Utilities to meet payment terms or to observe other covenants that would result in an acceleration of payments due. Most of these default provisions (other than ones relating to a failure to pay other indebtedness) provide for a cure period of 30-60 days from the occurrence of a specified event during which time, SPR or the Utilities may rectify or correct the situation before it becomes an event of default. The primary cross-default provisions in SPR's and the Utilities' various financing agreements are briefly summarized below: - The indenture pursuant to which SPR issued its 7.25% Convertible Notes due 2010 provides for an event of default if SPR or any of its significant subsidiaries (NPC and SPPC) fails to pay indebtedness in excess of $10 million or has any indebtedness of $10 million or more accelerated and declared due and payable; - NPC's General and Refunding Mortgage Indenture provides for an event of default if a matured event of default under NPC's First Mortgage Indenture occurs; - The terms of NPC's Series E Notes provide that a default with respect to the payment of principal, interest or premium beyond the applicable grace period under any mortgage, indenture or other security instrument, by NPC or any of its restricted subsidiaries, relating to debt in excess of $15 million, triggers a right of the holders of the Series E Notes to require NPC to redeem the Series E Notes at a price equal to 100% of the aggregate principal amount plus accrued and unpaid interest and liquidated damages, if any, upon notice given by at least 25% of the outstanding Series E Notes holders; - NPC's receivables purchase facility may terminate in the event that either NPC or SPR defaults (i) in the payment of indebtedness, or (ii) in the payment of amounts due under hedge agreements, and such defaults aggregate to greater than $10 million and $5 million for NPC and SPR, respectively; - SPPC's General and Refunding Mortgage Indenture provides for an event of default if a matured event of default under SPPC's First Mortgage Indenture occurs; - SPPC's Term Loan Agreement provides for an event of default if (a) SPPC or any of its subsidiaries default (i) in the payment of indebtedness, or (ii) in the payment of amounts due under hedge agreements, and such defaults aggregate to greater than $10 million, or (b) SPPC's General and Refunding Mortgage Indenture ceases to be enforceable; and - SPPC's receivables purchase facility may terminate in the event that either SPPC or SPR defaults (i) in the payment of indebtedness, or (ii) in the payment of amounts due under hedge agreements, and such defaults aggregate to greater than $10 million and $5 million for SPPC and SPR, respectively. FINANCING TRANSACTIONS In January 2003, SPR acquired $8.75 million aggregate principal amount of its Floating Rate Notes due April 20, 2003 in exchange for approximately 1.3 million shares of its common stock, in two privately-negotiated transactions exempt from the registration requirements of the Securities Act of 1933. On February 5, 2003, SPR issued approximately 13.66 million shares of common stock in exchange for a total of 2.1 million of its PIES in five privately-negotiated transactions exempt from the registration requirements of the Securities Act of 1933. On February 14, 2003, SPR issued and sold $300 million of its 7.25% Convertible Notes due 2010. Approximately $53.4 million of the net proceeds from the sale of the notes were used to purchase U.S. government securities that were pledged to the trustee for the first five interest payments on the notes payable during the first two and one-half years. A portion of the remaining net proceeds of the notes were used to repurchase approximately $58.5 million of SPR's Floating Rate Notes due April 20, 2003. Of the remaining net proceeds, approximately $133 million were used to repay the remainder of SPR's Floating Rate Notes due April 20, 2003, and the remaining proceeds will be available for general corporate purposes. The Convertible Notes were issued with registration rights. The Convertible Notes will not be convertible prior to August 14, 2003. At any time on or after August 14, 2003 through the close of business February 14, 2010, holders of the Convertible Notes may convert their notes into shares of SPR's common stock. Until SPR has obtained shareholder approval to fully convert the Convertible Notes into shares of common stock, holders of the Convertible Notes will be entitled to receive 76.7073 shares of common stock and a remaining portion in cash, based on the average closing price of SPR's common stock over five consecutive trading days, for each $1,000 principal amount of notes surrendered for conversion. At an assumed five-day average closing price of $3.87 per share (based on the 41 last reported sale price of SPR's common stock on April 30, 2003), the total amount of the cash payable on conversion of the Convertible Notes would be approximately $165.4 million. If SPR does not obtain shareholder approval, SPR will be required to pay the cash portion of any Convertible Notes as to which the holders request conversion on or after August 14, 2003. Although management does not believe it is likely that a significant amount of the Convertible Notes will be converted in the foreseeable future, in the event that SPR does not have available funds to pay the cash portion of the Convertible Notes upon the requested conversion, SPR may have to issue additional debt to raise the necessary funds. There can be no assurance that SPR will be able to access the capital markets to issue such additional debt. If SPR does obtain shareholder approval, it may elect to satisfy the cash payment component of the conversion price of the Convertible Notes solely with shares of common stock. SPR has agreed to use reasonable efforts to obtain shareholder approval, not later than 180 days after the date of issuance of the Convertible Notes, to issue and deliver shares of SPR's common stock in lieu of the cash payment component of the conversion price of the Convertible Notes. For further information regarding the terms of the Convertible Notes, see Note 4, Long-Term Debt. The indenture under which the Convertible Notes were issued does not contain any financial covenants or any restrictions on the payment of dividends, the repurchase of SPR's securities or the incurrence of indebtedness. The indenture does allow the holders of the Convertible Notes to require SPR to repurchase all or a portion of the holders' Convertible Notes upon a change of control. The indenture also provides for an event of default if SPR or any of its significant subsidiaries, including NPC and SPPC, fails to pay any indebtedness in excess of $10 million or has any indebtedness of $10 million or more accelerated and declared due and payable. EFFECT OF HOLDING COMPANY STRUCTURE Currently, SPR (on a stand-alone basis) has a substantial amount of debt and other obligations including, but not limited to: $300 million of its unsecured 8 3/4% Senior Notes due 2005; and $240 million of its unsecured 7.93% Senior Notes due 2007; and $300 million of its 7.25% Convertible Notes due 2010. Due to the holding company structure, SPR's right as a common shareholder to receive assets of any of its direct or indirect subsidiaries upon a subsidiary's liquidation or reorganization is junior to the claims against the assets of such subsidiary by its creditors and preferred stockholders. Therefore, SPR's debt obligations are effectively subordinated to all existing and future claims of its subsidiaries' creditors, particularly those of NPC and SPPC, including trade creditors, debt holders, secured creditors, taxing authorities, guarantee holders, NPC's preferred trust security holders and SPPC's preferred stockholders. As of March 31, 2003, NPC, SPPC and their subsidiaries had approximately $2.86 billion of debt and other obligations outstanding and approximately $238.9 million of outstanding preferred securities. Although the Utilities are parties to agreements that limit the amount of additional indebtedness they may incur, the Utilities retain the ability to incur substantial additional indebtedness and other liabilities. NEVADA POWER COMPANY During the quarter ended March 31, 2003, NPC incurred a net loss of $15.2 million and did not pay or declare a common stock dividend to its parent, SPR. The causes for significant changes in specific lines comprising the results of operations for NPC are as follows: 42 ELECTRIC OPERATING REVENUE
THREE MONTHS ENDED MARCH 31, -------------------------------------------- Change from 2003 2002 Prior Year % ------------ ------------ ------------ ELECTRIC OPERATING REVENUES ($000): Residential $ 121,707 $ 131,106 -7.2% Commercial 74,917 69,691 7.5% Industrial 92,388 88,760 4.1% ------------ ------------ Retail revenues 289,012 289,557 -0.2% Other 42,640 66,715 -36.1% ------------ ------------ TOTAL REVENUES $ 331,652 $ 356,272 -6.9% ============ ============ Retail sales in thousands of megawatt-hours (MWH) 3,400 3,570 -4.8% Average retail revenue per MWH $ 85.00 $ 81.11 4.8%
NPC's residential revenues decreased for the three months ended March 31, 2003, over the same period in 2002 due to a decrease in electric usage as a result of warmer than normal weather and company sponsored conservation programs. This decrease in revenues was partially offset by an increase in customer growth of 5.3% and an overall rate increase that was effective April 1, 2002. The increase in commercial and industrial revenues for the three months ended March 31, 2003, over the same period in 2002 were due to an overall rate increase effective April 1, 2002 and customer growth. Commercial and industrial growth, 5.7% and 3.3%, respectively, is attributed to the opening of several new elementary and secondary schools, shopping centers, office buildings, casino expansion projects, and new Las Vegas Valley Water District pumping plants in the Las Vegas area. The decrease in other electric revenues for the three month period ended March 31, 2003 over the same period in 2002 was due to lower sales of wholesale 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, 2002, Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operation, Energy Supply, for a discussion of NPC's purchased power procurement strategies. PURCHASED POWER
THREE MONTHS ENDED MARCH 31, -------------------------------------------- Change from 2003 2002 Prior Year % ------------ ------------ ------------ PURCHASED POWER ($000) $ 119,257 $ 176,066 -32.3% Purchased Power in thousands of MWHs 2,271 2,188 3.8% Average cost per MWH of Purchased Power $ 52.51 $ 80.47 -34.7%
NPC'S purchased power costs were lower for the three months ended March 31, 2003 compared to the same period in 2002 although the volume of energy purchased was slightly greater. The decrease in cost was the result of lower prices of Short-Term Firm energy purchased. Because it was more economical to purchase rather than generate power, mega-watt hours purchased increased as compared to the same period in 2003. See NPC's Annual Report on Form 10-K for the year ended December 31, 2002, Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operation, Energy Supply, for a discussion of NPC's purchased power procurement strategies. 43 FUEL FOR POWER GENERATION
THREE MONTHS ENDED MARCH 31, -------------------------------------------- Change from 2003 2002 Prior Year % ------------ ------------ ------------ FUEL FOR POWER GENERATION ($000) $ 46,537 $ 83,722 -44.4% Thousands of MWHs generated 1,875 2,241 -16.3% Average cost per MWH of Generated Power $ 24.82 $ 37.36 -33.6%
Fuel for generation costs for the three months ended March 31, 2003, were significantly lower than the prior year due to substantial decreases in the price of natural gas and total mega-watt hours generated. The decrease in mega-watt hours generated was due to an overall decrease in the system load requirements. See the earlier explanation of electric operating revenues that corresponds with the reduced load requirements. In addition, Reid Gardner Stations 2 and 3 were down for scheduled maintenance, and Clark Stations 1-3 and Sunrise Unit #1 were not being used because it was more economical to purchase power than generate. DEFERRED ENERGY COSTS
THREE MONTHS ENDED MARCH 31, -------------------------------------------- Change from 2003 2002 Prior Year % ------------ ------------ ------------ DEFERRED ENERGY COSTS DISALLOWED ($000) - 434,123 N/A DEFERRED ENERGY COSTS - NET ($000) $ 72,785 $ (9,636) N/A
Deferred energy costs disallowed for the three months ended March 31, 2002, reflects the write-off of $434 million of deferred energy costs incurred during the seven months ended September 30, 2001, that were disallowed by the PUCN in NPC's 2001 deferred energy rate case. Deferral of energy costs-electric-net increased for the three months ended March 31, 2003, as a result of the amortization of prior deferred costs pursuant to the PUCN decision in NPC's 2001 deferred energy rate case, that resulted in increased rates beginning April 1, 2002. The increase in 2003 also includes additional expense to the extent fuel and purchased power costs recovered through current rates exceeded actual fuel and purchased power costs during the three months ended March 31, 2003. Deferred energy costs - net for the three mounts ended March 31, 2002, reflects the deferral of energy costs to the extent actual fuel and purchased power costs exceeded fuel and purchased power costs recovered through rates during that period. ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFUDC)
THREE MONTHS ENDED MARCH 31, -------------------------------------------- Change from 2003 2002 Prior Year % ------------ ------------ ------------ ALLOWANCE FOR OTHER FUNDS USED DURING CONSTRUCTION ($000) $ 1,158 $ 421 175.1% ALLOWANCE FOR BORROWED FUNDS USED DURING CONSTRUCTION ($000) $ 1,056 $ 1,112 -5.0% ------------ ------------ $ 2,214 $ 1,533 44.4% ============ ============
44 NPC's total allowance for funds used during construction is higher for the three-month period ended March 31, 2003 as a result of an increase in Construction Work in Progress (CWIP) including capital expenditures for the Centennial Project and an increase in the AFUDC equity rate. This increase was offset in part by a decrease in the AFUDC debt rate. OTHER (INCOME) AND EXPENSES
THREE MONTHS ENDED MARCH 31, -------------------------------------------- Change from ($000) 2003 2002 Prior Year % ------------ ------------ ------------ OTHER OPERATING EXPENSE $ 40,540 $ 39,986 1.4% MAINTENANCE EXPENSE $ 13,537 $ 11,650 16.2% DEPRECIATION AND AMORTIZATION $ 25,907 $ 30,809 -15.9% INCOME TAXES $ (10,548) $ (156,423) -93.3% TAXES OTHER THAN INCOME TAXES $ 6,224 $ 6,734 -7.6% INTEREST CHARGES ON LONG-TERM DEBT $ 30,102 $ 24,078 25.0% INTEREST CHARGES-OTHER $ 6,080 $ 2,530 140.3% INTEREST ACCRUED ON DEFERRED ENERGY $ (5,710) $ 11,151 N/A OTHER INCOME $ (3,338) $ (146) 2186.3% OTHER EXPENSE $ 1,432 $ 5,997 -76.1% INCOME TAXES - OTHER INCOME AND EXPENSE $ 2,514 $ (5,645) N/A
Other operating expense for the three-month period ending March 31, 2003 was comparable to the same period in 2002. Maintenance costs for the three-month period ending March 31, 2003, increased from the prior year due to timing of scheduled plant maintenance. Depreciation and amortization was lower for the three-month period ended March 31, 2003 compared to the same period in 2002 as a result of depreciation adjustments made pursuant to a PUCN order on March 29, 2002. This decrease was offset in part by an increase in the computer depreciation rate and additions to plant-in-service. NPC's income tax benefit for the three months ended March 31, 2003, decreased compared to the same period in 2002, due to a corresponding decrease in first quarter 2003 pre-tax loss compared to the prior year. Taxes other than income taxes for the three months ended March 31, 2003, was comparable to the amount recognized during the same period in 2002. Interest charges on long-term debt for the three-month period ending March 31, 2003, increased over the same period in 2002 due, primarily, to the issuance in October 2002 of $250 million additional debt at an interest rate of 10.875%. The redemption, in October 2002, of $15 million debt slightly offset the increase in interest during 2003 over 2002. Interest charges-other for the three-month period ending March 31, 2003, increased over the prior year due to interest on delayed/terminated contracts, charges related to fees associated with NPC's credit facilities and receivables conduit and to the amortization of increased debt discount charges related to the issuance in October 2002 of $250 million additional debt. Interest accrued on deferred energy of $5.7 million during the three-month period ending March 31, 2003 compared favorably to the loss of $11.2 million during the same period in 2002. This was due to the first quarter 2002 write-off of approximately $20.1 million of carrying charges, net of taxes, on deferred energy costs that were disallowed by the PUCN in their March 29, 2002 decision on NPC's deferred energy rate case. The 2002 write-off was offset, in part, by the recording of carrying charges on deferred energy costs incurred. Other income for the three months ended March 31, 2003, increased over the same period in 2002 due to the following factors: a) In 2003, NPC recognized income from the disposition of SO2 allowances of approximately $.8 million; (b) NPC also recognized an increase in gains from the disposition of non-utility property in 2003 of $1.6 million; and (c) NPC recognized carrying charges related to divestiture costs, ordered by the PUCN, totaling $.4 million during the first quarter of 2003. Other expense decreased during the three months ended March 31, 2003, compared to the same period in 2002 due, primarily, to the 2002 write-off of $5.0 million relating to the disposition of SO2 allowances as ordered by the PUCN. The 45 decrease in expense relating to the SO2 emissions was offset partially by increases in charges related to depreciation on non-utility property and corporate advertising. NPC's income tax expense on other income and expense changed from a tax benefit during the three months ended March 31, 2002, to a tax expense in the three months ended March 31, 2003. This was due to a corresponding change from pre-tax losses in 2002 to pre-tax income in 2003. ANALYSIS OF CASH FLOWS NPC's cash flows were less during the three-months ended March 31, 2003, compared to the same period in 2002, resulting primarily from decreases in cash flows from operating and financing activities and, to a lesser extent, an increase in cash used for investing activities. The decrease in cash from operating activities was substantially as a result of the receipt in 2002 of an income tax refund. The decrease operating cash flow was partially offset by the collection of previously deferred energy costs due to the PUCN decision in NPC's 2001 deferred energy rate case, that resulted in increased rates beginning April 1, 2002. Cash flows from financing activities were lower in 2003 because of cash provided by short-term borrowings during 2002. NPC also utilized additional cash for financing activities in 2003 for the Centennial Plan and other construction projects. LIQUIDITY AND CAPITAL RESOURCES NPC had cash and cash equivalents of approximately $91 million at March 31, 2003. NPC's liquidity would be significantly affected by an adverse decision in the lawsuit by Enron, or by unfavorable rulings by the PUCN in pending or future NPC or SPPC rate cases. S&P and Moody's have NPC's credit ratings on "negative outlook" and "stable," respectively. Future downgrades by either S&P or Moody's could preclude NPC's access to the capital markets, and could adversely affect NPC's ability to continue to purchase power and fuel. Adverse developments with respect to any one or a combination of the foregoing could have a material adverse effect on NPC's financial condition and liquidity, and could make it difficult for NPC to continue to operate outside of bankruptcy. EFFECT OF RATE CASE DECISIONS On March 29 and April 1, 2002, following the decision by the PUCN in NPC's deferred energy rate case, S&P and Moody's lowered NPC's unsecured debt ratings to below investment grade. On April 23 and 24, 2002, NPC's unsecured debt ratings were further downgraded and its secured debt ratings were downgraded to below investment grade. As a result of these downgrades, NPC's ability to access the capital markets to raise funds were severely limited. Since SPR's credit ratings were similarly downgraded, SPR's ability to make capital contributions to NPC also became severely limited. For more detailed discussion of these effects please see NPC's Annual Report on Form 10-K for the year ended December 31, 2002. ACCOUNTS RECEIVABLE FACILITY On October 29, 2002, NPC established an accounts receivable purchase facility of up to $125 million, which was arranged by Lehman Brothers. The receivables purchase facility expires on August 28, 2003 unless NPC has activated the facility prior to that date, in which case the facility will be automatically extended to, and will expire on, October 28, 2003. If NPC elects to activate the receivables purchase facility, NPC will sell all of its accounts receivable generated from the sale of electricity to customers to its newly created bankruptcy remote special purpose subsidiary. The receivables sales will be without recourse except for breaches of customary representations and warranties made at the time of sale. The subsidiary will, in turn, sell these receivables to a bankruptcy-remote subsidiary of SPR. SPR's subsidiary will issue variable rate revolving notes backed by the purchased receivables. Lehman Brothers Holdings, Inc. has committed to be the sole initial committed purchaser of all of the variable rate revolving notes. The agreements relating to the receivables purchase facility contain various conditions to purchase, covenants and trigger events, and other provisions customary in receivables transactions. In addition to customary termination and mandatory repurchase events, the receivables purchase facility may terminate in the event that either NPC or SPR defaults (i) in the payment of indebtedness, or (ii) in the payment of amounts due under a swap agreement, and such defaults aggregate to greater than $10 million and $5 million for NPC and SPR, respectively. Under the terms of the agreements relating to the receivables purchase facility, NPC's facility may not be activated or, if activated, will be terminated in the event of a material adverse change in the condition, operations or business prospects of NPC. In addition, the agreements contain a limitation on the payment of dividends by NPC to SPR that is identical to the limitation contained in NPC's General and Refunding Mortgage Notes, Series E, described below. SPR has agreed to guaranty NPC's performance of certain obligations as a seller and servicer under the receivables purchase facility. 46 NPC has agreed to issue $125 million principal amount of its General and Refunding Mortgage Bonds upon activation of the receivables purchase facility. The full principal amount of the bond would secure certain of NPC's obligations as seller and servicer, plus certain interest, fees and expenses thereon to the extent not paid when due, regardless of the actual amounts owing with respect to the secured obligations. As a result, in the event of an NPC bankruptcy or liquidation, the holder of the bond securing the receivables purchase facility may recover more on a pro rata basis than the holders of other General and Refunding Mortgage securities, who could recover less on a pro rata basis, than they otherwise would recover. However, in no event will the holder of the bond recover more than the amount of obligations secured by the bond. NPC intends to use the accounts receivable purchase facility as a back-up liquidity facility and does not plan to activate this facility in the foreseeable future. NPC may activate the facility within five days upon the delivery of certain customary funding documentation and the delivery of the $125 million General and Refunding Mortgage Bond. MORTGAGE INDENTURES NPC's first mortgage indenture creates a first priority lien on substantially all of NPC's properties. As of March 31, 2003, $372.5 million of NPC's first mortgage bonds were outstanding. NPC agreed in connection with its Series E Notes that it would not issue any more first mortgage bonds. NPC's General and Refunding Mortgage Indenture creates a lien on substantially all of NPC's properties in Nevada that is junior to the lien of the first mortgage indenture. As of March 31, 2003, $870 million of NPC's General and Refunding Mortgage securities were outstanding. Additional securities may be issued under the General and Refunding Mortgage Indenture on the basis of (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. As of March 31, 2003, NPC had the capacity to issue approximately $1.13 billion of additional General and Refunding Mortgage securities. However, the financial covenants contained in the Series E Notes limits NPC ability to issue additional General and Refunding Mortgage Bonds or other debt. NPC has reserved $125 million of General and Refunding Mortgage bonds for issuance upon the initial funding of NPC's receivables facility. NPC also has the ability to release property from the liens of the two mortgage indentures on the basis of net property additions, cash and/or retired bonds. To the extent NPC releases property from the lien of its General and Refunding Mortgage Indenture, it will reduce the amount of bonds issuable under that indenture. CROSS DEFAULT PROVISIONS Certain financing agreements of NPC contain cross-default provisions that would result in an event of default under such financing agreements if there is a failure under other financing agreements of NPC and SPR to meet payment terms or to observe other covenants that would result in an acceleration of payments due. Most of these default provisions (other than ones relating to a failure to pay other indebtedness) provide for a cure period of 30-60 days from the occurrence of a specified event during which time, NPC or SPR may rectify or correct the situation before it becomes an event of default. The primary cross-default provisions in NPC's various financing agreements are briefly summarized below: - NPC's General and Refunding Mortgage Indenture provides for an event of default if a matured event of default under NPC's First Mortgage Indenture occurs; - The terms of NPC's Series E Notes provide that a default with respect to the payment of principal, interest or premium beyond the applicable grace period under any mortgage, indenture or other security instrument, by NPC or any of its restricted subsidiaries, relating to debt in excess of $15 million, triggers a right of the holders of the Series E Notes to require NPC to redeem the Series E Notes at a price equal to 100% of the aggregate principal amount plus accrued and unpaid interest and liquidated damages, if any, upon notice given by at least 25% of the outstanding Series E Notes holders; and - NPC's receivables purchase facility may terminate in the event that either NPC or SPR defaults (i) in the payment of indebtedness, or (ii) in the payment of amounts due under hedge agreements, and such defaults aggregate to greater than $10 million and $5 million for NPC and SPR, respectively. 47 SIERRA PACIFIC POWER COMPANY During the quarter ended March 31, 2003, SPPC recognized net income of $4.0 million and did not pay or declare a common stock dividend to its parent, SPR. During the same period, SPPC paid $975,000 in dividends to holders of its preferred stock and neither declared nor paid dividends on its common stock, all of which is held by its parent, SPR. The components of SPPC's gross margin are set forth below (dollars in thousands):
THREE MONTHS ENDED MARCH 31, ------------------------------------ Change from 2003 2002 Prior Year % -------- -------- ------------ Operating Revenues: Electric $205,454 $224,754 -8.6% Gas 64,617 55,083 17.3% -------- -------- Total Revenues $270,071 $279,837 -3.5% ======== ======== Energy Costs: Electric $132,256 $147,863 -10.6% Gas 53,137 46,786 13.6% -------- -------- Total Energy Costs 185,393 194,649 -4.8% ======== ======== Gross Margin by Segment: Electric $ 73,198 $ 76,891 -4.8% Gas 11,480 8,297 38.4% -------- -------- Total $ 84,678 $ 85,188 -0.6% ======== ========
The causes for significant changes in specific lines comprising the results of operations for SPPC are as follows: ELECTRIC OPERATING REVENUES
THREE MONTHS ENDED MARCH 31, -------------------------------------------- Change from 2003 2002 Prior year % -------- -------- ------------ ELECTRIC OPERATING REVENUES ($000): Residential $ 59,869 $ 60,403 -0.9% Commercial 63,128 62,716 0.7% Industrial 66,178 63,132 4.8% -------- -------- Retail revenues 189,175 186,251 1.6% Other 16,279 38,503 -57.7% -------- -------- TOTAL REVENUES $205,454 $224,754 -8.6% ======== ======== Retail sales in thousands of MWH 2,134 2,136 -0.1% Average retail revenue per MWH $ 88.65 $ 87.20 1.7%
SPPC's retail revenues for the three months ending March 31, 2003 were comparable to the same period in the prior year. An overall rate increase for the residential and commercial customers, which was effective June 1, 2002, was offset by lower sales due to warmer than normal temperatures during the first quarter of 2003. The decrease in other electric operating revenues for the three-month period ended March 31, 2003, compared to the same period in 2002 was due to a decrease in wholesale sales to other utilities. See SPPC's Annual Report on Form 10-K for the year ended December 31, 2002 Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operation, Energy Supply, for a discussion of SPPC's purchased power procurement strategies. 48 GAS OPERATING REVENUES
THREE MONTHS ENDED MARCH 31, ------------------------------------------ Change from 2003 2002 Prior year % ------- ------- ------------ GAS OPERATING REVENUES ($000): Residential $28,624 $29,472 -2.9% Commercial 14,274 17,004 -16.1% Industrial 4,839 7,664 -36.9% ------- ------- Retail revenue 47,737 54,140 -11.8% Wholesale revenue 16,377 547 2894.0% Miscellaneous 503 396 27.0% ------- ------- TOTAL REVENUES $64,617 $55,083 17.3% ======= ======= Retail sales in thousands of decatherms 5,029 6,006 -16.3% Average retail revenues per decatherm $ 9.49 $ 9.01 5.3%
Retail revenues for the three-month period ended March 31, 2002 were lower than the same period in the prior year due to a decrease in gas usage as a result of warmer than normal temperatures in the first quarter of 2003. Also, industrial revenues decreased as a result of some SPPC's industrial customers who switched to a gas transportation tariff, which gave them the ability to procure the commodity from another source other than SPPC. Under SPPC's gas transportation tariff, those customers are billed for only the transportation of the commodity and the associated revenues are reflected under miscellaneous revenues. Wholesale gas revenues for the three months ended March 31, 2003 were higher than for the same period in 2002. The increase in wholesale gas sales was primarily a result of utilizing idle gas transportation capacity to move gas from Canada to California for resale. PURCHASED POWER
THREE MONTHS ENDED MARCH 31, ------------------------------------------ Change from 2003 2002 Prior Year % -------- -------- ------------ PURCHASED POWER ($000): $ 87,178 $105,417 -17.3% Purchased Power in thousands of MWHs 1,593 1,703 -6.5% Average cost per MWH of Purchased Power $ 54.73 $ 61.90 -11.6%
Purchased power costs were lower for the three-month period ended March 31, 2003, than the prior year because the majority of SPPC's total energy requirements were satisfied by Short-Term Firm power purchases for which costs have decreased as compared to a year ago. In addition, volumes of and prices for SPPC's risk management activities have decreased. 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, 2002, Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operation, Energy Supply, for a discussion of SPPC's purchased power procurement strategies. 49 FUEL FOR POWER GENERATION
THREE MONTHS ENDED MARCH 31, --------------------------------------------- Change from 2003 2002 Prior Year % ------- ------- ------------ FUEL FOR POWER GENERATION ($000) $33,676 $47,051 -28.4% Thousands of MWHs generated 963 1,212 -20.5% Average fuel cost per MWH of Generated Power $ 34.97 $ 38.82 -9.9%
Fuel for power generation costs for the three-month period ended March 31, 2003 were lower than the same period in the prior year as both volumes generated and natural gas prices decreased. Generation as well as purchase power volumes are down as total system requirements decreased in comparison to last year. GAS PURCHASED FOR RESALE
THREE MONTHS ENDED MARCH 31, ---------------------------------------------- Change from 2003 2002 Prior Year % ------- ------- ------------ GAS PURCHASED FOR RESALE ($000) $42,334 $38,594 9.7% Gas Purchased for Resale (thousands of decatherms) 7,621 5,960 27.9% Average cost per decatherm $ 5.55 $ 6.48 -14.4%
Gas purchased for resale increased significantly for the three-month period ended March 31, 2003, compared to the prior year as an increase in wholesale activity more than offset the decrease in gas prices. DEFERRED ENERGY COSTS
THREE MONTHS ENDED MARCH 31, ------------------------------------------- Change from 2003 2002 Prior Year % ------- ------- ------------ DEFERRED ENERGY COSTS - ELECTRIC - NET ($000) $11,402 $(4,605) N/A DEFERRED ENERGY COSTS - GAS - NET ($000) $10,803 $ 8,192 31.9%
The increase in deferral of energy costs-electric-net for the three month period ended March 31, 2003, reflects the amortization of prior deferred costs pursuant to the PUCN decision in SPPC's 2002 deferred energy rate case, that resulted in increased rates beginning June 1, 2002. The 2003 increase was offset, in part, by the recording of current year deferrals of electric energy costs to the extent actual fuel and purchased power costs for the three months ended March 31, 2003, exceeded fuel and purchased power costs recovered through current rates during that period. Deferral of energy costs-electric-net for the three months ended March 31, 2002, reflects the deferral of electric energy costs in 2002 that were in excess of purchased power costs recovered through rates at that time. SPPC's deferred energy costs-gas-net, for the three months ended March 31, 2003 reflects the amortization of prior deferred costs due to the PUCN-authorized recovery of those costs. The increase in 2003 also includes additional expense to the extent natural gas costs recovered through current rates exceeded actual natural gas costs. 50 ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFUDC)
THREE MONTHS ENDED MARCH 31, -------------------------------------- Change from 2003 2002 Prior Year % ------ ------ ------------ ALLOWANCE FOR OTHER FUNDS USED DURING CONSTRUCTION ($000) $ 602 $ 236 155.1% ALLOWANCE FOR BORROWED FUNDS USED DURING CONSTRUCTION ($000) 700 391 79.0% ------ ------ $1,302 $ 627 107.7% ====== ======
Total allowance for funds used during construction increased for the three-month period ended March 31, 2003, compared to the prior year due to an increase in CWIP and an increase in the AFUDC Rate. OTHER (INCOME) AND EXPENSES
THREE MONTHS ENDED MARCH 31, ------------------------------------------ Change from ($000) 2003 2002 Prior Year % -------- -------- ------------ OTHER OPERATING EXPENSE $ 29,213 $ 27,762 5.2% MAINTENANCE EXPENSE $ 5,187 $ 5,257 -1.3% DEPRECIATION AND AMORTIZATION $ 19,706 $ 17,558 12.2% INCOME TAXES $ 2,090 $ 4,901 -57.4% TAXES OTHER THAN INCOME TAXES $ 4,662 $ 4,776 -2.4% INTEREST CHARGES ON LONG-TERM DEBT $ 18,781 $ 16,445 14.2% INTEREST CHARGES-OTHER $ 3,125 $ 1,142 173.6% INTEREST ACCRUED ON DEFERRED ENERGY $ (1,925) $ (5,027) -61.7% OTHER INCOME $ (1,065) $ (1,837) -42.0% OTHER EXPENSE $ 1,905 $ 2,462 -22.6% INCOME TAXES - OTHER INCOME AND EXPENSE $ 303 $ 1,432 -78.8%
Other operating expense for the three-month period ending March 31, 2003 was greater than the prior year, due to credits associated with the discontinuation of billing services for Truckee Meadows Water Authority in July 2002 along with increased billing/collection efforts associated with delinquent customer accounts and higher employee labor overhead costs in 2003. Maintenance costs for the three-month period ending March 31, 2003 were comparable to amounts recognized during the same period in 2002. Depreciation and amortization increased for the three-month period ended March 31, 2003, compared to the same period in 2002 as a result of an increase in additions to plant-in-service assets. SPPC recorded lower operating income tax expense for the three months ended March 31, 2003 compared to the same period in 2002. This decrease is due to a corresponding decrease in first quarter 2003 pre-tax income compared to the prior year. Taxes other than income taxes for the three months ended March 31, 2003, was comparable to the amount recognized during the same period in 2002. Interest charges on long-term debt for the three-month period ending March 31, 2003, increased over the same period in 2002 due, primarily, to the issuance in October 2002 of $100 million additional debt at an interest rate of 10.5%. Interest charges-other for the three-month period ending March 31, 2003, increased over the prior year due to interest on delayed/terminated contracts, charges related to fees associated with SPPC's credit facilities and receivables conduit, and to 51 the increase of amortization resulting from increased debt discount charges related to the issuance, in October 2002 of $100 million additional debt. Interest accrued on deferred energy decreased for the three-month period ending March 31, 2003, compared to the same period, 2002, due to lower deferred fuel and purchased power balances during 2003. Other income for the three months ended March 31, 2003, decreased compared to the same period in the prior year due, primarily, to a decrease in interest income and subsidiary earnings, partially offset by increases in lease revenues and miscellaneous non-operating income. Other expense for the three months ended March 31, 2003, decreased, compared to the prior year, due, primarily, to the occurrence in 2002 of miscellaneous charges related to SPPC's sale of its water division. The decrease in 2003 was offset partially by higher charges related to corporate advertising, during 2003. SPPC recorded lower income tax expense on other income and expense for the three months ended March 31, 2003, compared to 2002 due to lower net other income during 2003. ANALYSIS OF CASH FLOWS SPPC's cash flows during the three-months ended March 31, 2003, improved compared to the same period in 2002, as a result of an increase in cash flows from operating activities, partially offset, by an increase in cash used for investing activities. Cash flows from operating activities improved primarily as a result of the collection of previously deferred energy costs due to the PUCN decision in SPPC's 2002 deferred energy rate case, that resulted in increased rates beginning June 1, 2002. Cash flows from investing activities decreased in 2003 because of additional cash requirements for increased construction activity during 2003. Cash flows from financing activities were comparable for both periods. LIQUIDITY AND CAPITAL RESOURCES SPPC had cash and cash equivalents of approximately $128 million at March 31, 2003. SPPC's future liquidity could be significantly affected by unfavorable rulings by the PUCN in pending or future SPPC or NPC rate cases. S&P and Moody's have SPPC's credit ratings on "negative outlook" and "stable", respectively. Future downgrades by either S&P or Moody's could preclude SPPC's access to the capital markets and could adversely affect SPPC's ability to continue purchasing power and fuel. Adverse developments with respect to any one or a combination of the factors and contingencies set forth above could have a material adverse effect on SPPC's financial condition and liquidity, and could make it difficult to continue to operate outside of bankruptcy. EFFECT OF RATE CASE DECISIONS On March 29 and April 1, 2002, following the decision by the PUCN in NPC's deferred energy rate case, S&P and Moody's lowered SPPC's unsecured debt ratings to below investment grade. On April 23 and 24, 2002, SPPC's unsecured debt ratings were further downgraded and its secured debt ratings were downgraded to below investment grade. The decision of the PUCN on May 29, 2002, on SPPC's deferred energy application to disallow $53 million of deferred purchased fuel and power costs accumulated between March 1, 2001 and November 30, 2001, did not result in any further downgrades of SPPC's securities. As a result of the downgrades, SPPC's ability to access the capital markets to raise funds is severely limited. Since SPR's credit ratings were similarly downgraded, SPR's ability to make capital contributions to SPPC also became severely limited. For more detailed discussion of these effects please see SPPC's Annual Report on Form 10-K for the year ended December 31, 2002. ACCOUNTS RECEIVABLE FACILITY On October 29, 2002, SPPC established an accounts receivable purchase facility of up to $75 million, which was arranged by Lehman Brothers. The receivables purchase facility expires on August 28, 2003 unless SPPC has activated the facility prior to that date, in which case the facility will be automatically extended to, and will expire on, October 28, 2003. If SPPC elects to activate the receivables purchase facility, SPPC will sell all of its accounts receivable generated from the sale of electricity and natural gas to customers to its newly created bankruptcy remote special purpose subsidiary. The receivables sales will be without recourse except for breaches of customary representations and warranties made at the time of sale. The subsidiary will, in turn, sell these receivables to a bankruptcy-remote subsidiary of SPR. SPR's subsidiary will issue variable rate revolving notes backed by the purchased receivables. Lehman Brothers Holdings, Inc. has committed to be the sole initial committed purchaser of all of the variable rate revolving notes. 52 The agreements relating to the receivables purchase facility contain various conditions to purchase, covenants and trigger events, and other provisions customary in receivables transactions. In additional to customary termination and mandatory repurchase events, the receivables purchase facility may terminate in the event that either SPPC or SPR defaults (1) on the payment of indebtedness, or (2) on the payment of amounts due under a swap agreement, and such defaults aggregate to greater than $10 million and $5 million for SPPC and SPR, respectively. Under the terms of the agreements relating to the receivables purchase facility, SPPC's facility may not be activated or, if activated, will be terminated in the event of a material adverse change in the condition, operations or business prospects of SPPC. In addition, the agreements contain a limitation on the payment of dividends by SPPC to SPR that is identical to the limitation contained in SPPC's Term Loan Agreement, described below. SPR has agreed to guaranty SPPC's performance of certain obligations as a seller and servicer under the receivables purchase facility. SPPC has agreed to issue $75 million principal amount of its General and Refunding Mortgage Bonds upon activation of the receivables purchase facility. The full principal amount of the bond would secure certain of SPPC's obligations as seller and servicer, plus certain interest, fees and expenses thereon to the extent not paid when due, regardless of the actual amounts owing with respect to the secured obligations. As a result, in the event of an SPPC bankruptcy or liquidation, the holder of the bond securing the receivables purchase facility may recover more on a pro rata basis than the holders of other General and Refunding Mortgage securities, who could recover less on a pro rata basis, than they otherwise would recover. However, in no event will the holder of the bond recover more than the amount of obligations secured by the bond. SPPC intends to use the accounts receivable purchase facility as a back-up liquidity facility and does not plan to activate this facility in the foreseeable future. SPPC may activate the facility within five days upon the delivery of certain customary funding documentation and the delivery of the $75 million General and Refunding Mortgage Bond. MORTGAGE INDENTURES SPPC's First Mortgage Indenture creates a first priority lien on substantially all of SPPC's properties in Nevada and California. As of March 31, 2003, $505.3 million of SPPC's first mortgage bonds were outstanding. SPPC agreed in its General and Refunding Mortgage Indenture that it would not issue any additional first mortgage bonds. SPPC's General and Refunding Mortgage Indenture creates a lien on substantially all of SPPC's properties in Nevada that is junior to the lien of the first mortgage indenture. As of March 31, 2003, $419.8 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 (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. At March 31, 2003, SPPC had the capacity to issue approximately $435.7 million of additional General and Refunding Mortgage securities, which amount does not include SPPC's $80 million General and Refunding Mortgage Note, Series D, due 2004. However, the financial covenants contained in SPPC's Term Loan Agreement and Receivable Purchase Facility Agreements limit SPPC's ability to issue additional General and Refunding Mortgage Securities or other debt. SPPC has reserved $75 million of General and Refunding Mortgage Bonds for issuance upon the initial funding of its receivables purchase facility. SPPC also has the ability to release property from the liens of the two mortgage indentures on the basis of net property additions, cash and/or retired bonds. To the extent SPPC releases property from the lien of its General and Refunding Mortgage Indenture, it will reduce the amount of bonds issuable under that indenture. FINANCING TRANSACTIONS AND COVENANTS On May 1, 2003, SPPC's $80 million Washoe County, Nevada, Water Facilities Refunding Revenue Bonds, Series 2001, were successfully remarketed. The interest rate on the bonds was adjusted from their prior two-year 5.75% term rate to a 7.50% term rate for the period of May 1, 2003 to and including May 3, 2004. The bonds will be subject to remarketing on May 3, 2004. 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 principal amount, plus accrued interest. From May 1, 2003 to and including May 3, 2004, SPPC's payment and purchase obligations in respect of the bonds are secured by SPPC's $80 million General and Refunding Mortgage Note, Series D, due 2004. SPPC's $100 million Term Loan Agreement, entered into on October 30, 2002 with several lenders and Lehman Commercial Paper Inc., as Administrative Agent, contains two financial maintenance covenants. The first 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. The second covenant requires that SPPC maintain a consolidated 53 interest coverage ratio for the four consecutive fiscal quarters ending with each of the following fiscal quarters 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. SPPC expects to deliver a certificate to the Administrative Agent on or before May 15, 2003 as required by the Term Loan Agreement stating that SPPC was in compliance with these covenants as of March 31, 2003. The Term Loan Facility, which is secured by a $100 million Series C General and Refunding Mortgage Bond, will expire October 31, 2005. CROSS DEFAULT PROVISIONS Certain financing agreements of SPPC contain cross-default provisions that would result in an event of default under such financing agreements if there is a failure under other financing agreements of SPPC and SPR to meet payment terms or to observe other covenants that would result in an acceleration of payments due. Most of these default provisions (other than ones relating to a failure to pay other indebtedness) provide for a cure period of 30-60 days from the occurrence of a specified event during which time, SPPC or SPR may rectify or correct the situation before it becomes an event of default. The primary cross-default provisions in SPPC's various financing agreements are briefly summarized below: - SPPC's General and Refunding Mortgage Indenture provides for an event of default if a matured event of default under SPPC's First Mortgage Indenture occurs; - SPPC's Term Loan Agreement provides for an event of default if (a) SPPC or any of its subsidiaries default (i) in the payment of indebtedness, or (ii) in the payment of amounts due under hedge agreements, and such defaults aggregate to greater than $10 million, or (b) SPPC's General and Refunding Mortgage Indenture ceases to be enforceable; and - SPPC's receivables purchase facility may terminate in the event that either SPPC or SPR defaults (i) in the payment of indebtedness, or (ii) in the payment of amounts due under hedge agreements, and such defaults aggregate to greater than $10 million and $5 million for SPPC and SPR, respectively. SIERRA PACIFIC RESOURCES (HOLDING COMPANY) The Condensed Consolidated Statements of Operations of SPR for the three-months ended March 31, 2003, include the operating results of the holding company. The holding company recognized higher interest costs, $20.1 million in 2003 compared to $19.2 million in 2002, due to the issuance of $300 million of convertible notes in February 2003. TUSCARORA GAS PIPELINE COMPANY The Condensed Consolidated Statements of Operations of SPR for the three months ended March 31, 2003, and March 31, 2002, include the operating results of Tuscarora Gas Pipeline Company (TGPC), a wholly owned subsidiary of SPR. TGPC contributed $.9 million in net income for both the three-month periods ended March 31, 2003, and March 31, 2002. e [MID DOT] THREE The Condensed Consolidated Statements of Operations of SPR for the three months ended March 31, 2003, and March 31, 2002, include the operating results of e [MID DOT] three, a wholly owned subsidiary of SPR. e [MID DOT] three incurred net losses of $.3 and $.2 million, respectively, for the three- month periods ended March 31, 2003 and March 31, 2002, respectively. SIERRA PACIFIC COMMUNICATIONS The Condensed Consolidated Statements of Operations of SPR for the three months-ended March 31, 2003, and March 31, 2002, include the operating results of Sierra Pacific Communications (SPC), a wholly owned subsidiary of SPR. SPC incurred net losses of $.9 million and $.7 million for the three-month periods ended March 31, 2003, and March 31, 2002, respectively. 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. 54 NEVADA MATTERS NEVADA POWER COMPANY 2001 DEFERRED ENERGY CASE On November 30, 2001, NPC filed an application with the PUCN seeking repayment for purchased fuel and power costs accumulated between March 1, 2001, and September 30, 2001, as required by law. The application sought to establish a rate to repay accumulated purchased fuel and power costs of $922 million and spread the recovery of the deferred costs, together with a carrying charge, over a period of not more than three years. On March 29, 2002, the PUCN issued its decision on the deferred energy application, allowing NPC to recover $478 million over a three-year period, but disallowing $434 million of deferred purchased fuel and power costs and $30.9 million in carrying charges consisting of $10.1 million in carrying charges accrued through September 2001 and $20.8 million in carrying charges accrued from October 2001 through February 2002. The order stated that the disallowance was based on alleged imprudence in incurring the disallowed costs. On April 11, 2002, NPC filed a lawsuit in the First District Court of Nevada seeking to reverse portions of the PUCN's decision. NPC's lawsuit requested 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. The Bureau of Consumer Protection (BCP) of the Nevada Attorney General's Office filed a petition in the case seeking additional disallowances. On April 28, 2003, the District Court issued its decision, denying NPC's requests and affirming the PUCN's order, and also denying the BCP's petition. NPC's management is evaluating its options in regard to the District Court's decision. 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. NEVADA POWER COMPANY 2002 DEFERRED ENERGY CASE On November 14, 2002, NPC filed an application with the PUCN seeking repayment for purchased fuel and power costs accumulated between October 1, 2001, and September 30, 2002, as required by law. The application seeks to establish a rate to repay accumulated purchased fuel and power costs of $195.7 million, together with a carrying charge, over a period of not more than three years. The application also requests a reduction to the going-forward rate for energy, reflecting reduced wholesale energy costs. The combined effect of these two adjustments results in an overall rate reduction of 5.3%. Intervenors filed their direct testimony on March 7, 2003, and supplemental testimony was filed March 27, 2003, calling for disallowances between approximately $108 and $300 million of the total fuel and purchased power costs. The largest of the proposed disallowances are based on the same alleged imprudence as found in the PUCN order for NPC's 2001 Deferred Energy Case relating to NPC's failure to enter into power contracts in 1999. Certain Intervenors' testimony, in the current case, have argued in favor of disallowances based on the same alleged imprudence as cited in the last deferred order but have not quantified their proposals and in some cases have argued in favor of disallowances in excess of the ranges previously indicated. The PUCN Staff does not support this disallowance but calculated a range of $116 to $347 million in the event that the PUCN disallows deferred energy costs based upon the same alleged imprudence cited by the PUCN in its 2001 decision relative to this issue. While all Intervenors have called for the PUCN to reduce NPC's requested energy rates for recovery of past energy costs, some have also proposed to increase customers' energy rates for purchases that will occur during the upcoming deferred accounting period, which would decrease the accumulation of deferred energy costs. NPC's rebuttal testimony was filed March 31, 2003. The hearing commenced on April 7, and was completed on April 17, 2003. A special agenda meeting is scheduled for May 9, 2003, at which time a ruling from the Commission is expected. 55 NEVADA POWER COMPANY DEMAND REDUCTION PROGRAMS On November 14, 2002, NPC filed an application with the PUCN seeking recovery of expenses incurred in the implementation and operation of programs for energy conservation and load management. In the filing, NPC requested a one-year recovery of approximately $1.9 million. This would result in an average 0.12% increase in present rates. NPC asked for this increase to become effective simultaneously with the rate change to be ordered in its 2002 deferred energy case discussed above. The parties to the case subsequently negotiated a settlement agreement which approved NPC's request for cost recovery with the exception of a small disallowance ($14,673). The stipulation was approved at the agenda meeting held April 4, 2003. SIERRA PACIFIC POWER COMPANY 2003 DEFERRED ENERGY CASE On January 14, 2003, SPPC filed an application with the PUCN, as required by law, seeking to clear deferred balances for purchased fuel and power costs accumulated between December 1, 2001 and November 30, 2002. The application seeks to establish a DEAA rate to clear accumulated purchased fuel and power costs of $15.4 million and spread the cost recovery over a period of not more than three years. It also seeks to recalculate the Base Tariff Energy Rate to reflect anticipated ongoing purchased fuel and power costs. The total rate increase resulting from the requested DEAA would amount to 0.01%. The intervenors' testimony was received April 25, 2003, and includes proposed disallowances from $34 million to $76 million. While all Intervenors call for the PUCN to reduce SPPC's requested energy rates for recovery of past energy costs, some also propose to increase customers' energy rates for purchases that will occur during the upcoming deferred accounting period, which would decease the accumulation of deferred energy costs. A hearing is scheduled to begin on May 12, 2003, and a ruling is required before July 13, 2003. SIERRA PACIFIC POWER COMPANY DEMAND REDUCTION PROGRAMS On January 14, 2003, SPPC filed with the PUCN an application seeking recovery of expenses incurred in the implementation and operation of programs for energy conservation and load management. In the filing, SPPC requested a one-year recovery of approximately $0.9 million. This would result in an average 0.12% increase in present rates. SPPC asked for this increase to become effective simultaneously with the rate change to be ordered in its 2003 deferred energy case discussed above. The parties to the case subsequently negotiated a settlement agreement that is expected to be approved by the PUCN coincident with its 2003 deferred energy ruling. The agreement called for complete recovery of the $0.9 million balance. CUSTOMERS FILE TO BE SERVED BY NEW PROVIDERS UNDER NRS 704B (AB 661) AB 661, passed by the Nevada legislature in 2001 and incorporated into Nevada Revised Statutes as NRS 704B, 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. NRS 704B 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. Customers wishing to choose a new supplier must provide 180-day notice to the Utilities. Twelve applications for departure are pending for NPC. These applications total approximately 350 MW of peak load. In eleven of these applications stipulations have been reached that addressed all issues except treatment of Base Tariff General Rate (BTGR) revenue impacts arising from departure. The commission has issued a compliance order for these eleven applications that will allow the customers to depart upon completion of items in the compliance order. The remaining application is pending with a decision anticipated in second quarter of 2003. NPC continues to pursue resolution of the BTGR revenue impact issue. The most recent departure orders allow NPC to establish a regulatory asset to recover the BTGR revenue impact. According to the commission's order, the BTGR revenue impact will be offset by load growth from new customers. NPC has requested clarification of the land growth calculation methodology. The Bureau of Consumer Protection is opposed to the regulatory asset for BTGR impacts and has filed for reconsideration. A decision from the PUCN is expected in the second quarter of 2003. As this issue is being resolved, the customers seeking to depart are continuing to address the requirements of the compliance order which include executing supply, transmission, and distribution contracts. All compliance items must be filed no later than 100 days after the date of their compliance order. Some such customers are also proceeding with the implementation of metering and communications equipment. However, at this point, no customer has provided written notice of their intent to proceed with departure from NPC. NPC is obligated to plan for and secure energy supplies for these customers until official departure notice is received. The written departure notice must provide a minimum of 60 days notice. 56 Should customers elect to proceed with departure, such departures would begin in the third quarter of 2003 and generally are anticipated to be phased in based upon each customer's implementation plan. 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 included two phases. Phase One, which was also filed June 29, 2001, was an emergency electric rate increase of $10.2 million annually or 26%. The increase was applicable to all customers except those eligible for low-income and medical-needs rates and went into effect July 18, 2002. Phase Two of the Rate Stabilization Plan was filed with the CPUC on April 1, 2002, and includes a general rate case and requests the CPUC to reinstate the Energy Cost Adjustment Clause, which would allow SPPC to file for periodic rate adjustments to reflect its actual costs for wholesale energy supplies. Phase Two also includes a proposal to terminate the 10% rate reduction mandated by AB 1890, but does not include a performance -based rate-making proposal. This request was for an additional overall increase in revenues of 17.1%, or $8.9 million annually. On December 19, 2002, SPPC filed an amendment to the Phase Two application reducing the requested increase by $4.1 million to $4.8 million or 9.2% annually. SPPC agreed to make certain changes to the application and file the amendment following discussions with the CPUC Office of Ratepayer Advocates. In February 2003, the Office of the Ratepayer Advocates (ORA) filed testimony on cost of service proposing to reduce SPPC's request by $3.2 million resulting in a $1.6 million increase or 3.3%. On March 14, 2003, SPPC filed rebuttal testimony. On March 10, 2003, the ORA filed testimony on revenue allocation and rate design and on April 2, 2003, Sierra and the California Ski Areas Association filed rebuttal testimony. Hearings were held on April 9, 2003. A comparative table of issues is due by April 30 with opening and reply briefs scheduled for May 16, 2003 and June 13, 2003, respectively. A decision by the CPUC regarding the Energy Cost Adjustment Clause is expected in May 2003 and a decision on all other issues is expected in late 2003. CALIFORNIA ASSEMBLY BILL 1235 On September 24, 2002, the Governor of California signed into law Assembly Bill 1235 (AB 1235), which allows the transfer of hydroelectric plants along the Truckee River from SPPC to the Truckee Meadows Water Authority (TMWA). AB 1235 effectively amends previous California legislation (AB 6X) that prevented 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. On November 9, 2002, SPPC filed an application with the CPUC for authority to sell the four hydroelectric plants. On January 13, 2003, the CPUC issued a ruling that the California Environmental Quality Act applies to this proceeding and SPPC must supplement the application with a certified environmental document. SPPC has begun informal discussions with the CPUC on the environmental issues and cannot yet predict the outcome of this proceeding. On April 17, 2003, the CPUC issued a ruling dismissing the application without prejudice. The decision allows SPPC to re-file the application including an environmental assessment. Sierra plans to file a new application by the end of the second quarter of 2003. FERC MATTERS (SPPC, NPC) In December 2001, the Utilities filed ten wholesale purchased power complaints with the FERC under Section 206 of the Federal Power Act seeking to reduce prices of certain forward power purchase contracts that the Utilities entered into prior to the price caps established by the FERC during the western United States utility crisis. The Utilities believe the prices under these purchased power contracts are unjust and unreasonable. The Utilities negotiated a settlement with Duke Energy Trading and Marketing, but were unable to reach agreement in bilateral settlement discussions with other respondents. The Utilities have already paid the full contact price for all power actually delivered by these suppliers, but are contesting claims made for terminated power suppliers, including those terminated by Enron. The Administrative Law Judge ("ALJ") overseeing the Utilities' complaints and proceedings under Section 206 of the Federal Power Act issued an initial decision on December 19, 2002 which stated that the Utilities' complaints did not meet the public interest standard of proof, which the ALJ believed applied to the reformation of their contracts. NPC, SPPC and other parties to these proceedings filed Briefs on Exceptions to the ALJ's initial order with the FERC. Oral argument before the three commissioners of the FERC took place on April 23, 2003. We are unable to predict the timing or outcome of the FERC's decision on the Utilities' Section 206 complaints. FERC is expected to issue a decision in this matter by May 31, 2003. 57 On March 26, 2003, the Staff of the FERC (the Staff) concluded that supply-demand imbalance, flawed market design and inconsistent rules made significant market manipulation possible in the Western states in 2000 and 2001. The FERC has not decided how or if this manipulation impacted NPC's and SPPC's claims to the FERC in their Section 206 proceedings. Additionally, the Staff recommended that certain market participants identified in the Cal ISO Report released January 6, 2003, including SPPC, be directed to show cause why their behavior did not constitute gaming in violation of the Cal ISO and Cal PX tariffs. In its report, the Cal ISO indicated that it was unclear as to the reason SPPC received certain revenues in the amount of approximately $6 thousand. The total revenues for all companies for which the Staff recommended show cause orders are approximately $2.8 million. SPPC was one of the over 30 market participants included in the Staff's recommendation. On April 7, 2003, SPR submitted documentation to the FERC demonstrating that SPPC did not engage in gaming in violation of the Cal ISO or Cal PX tariffs, nor in the manipulation of the Western energy market. The FERC has not yet decided whether to issue a show cause order to SPPC or to any of the other companies identified by the FERC staff. The Staff also recommended that the Cal ISO fully explain the screen that was used to identify the subject transactions and that the information should be made available to the public. For more information regarding the Section 206 proceedings, please see Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations - Regulation and Rate Proceedings - FERC Matters - FERC 206 Complaints in SPR's, NPC's and SPPC's Annual Report on Form 10-K for the year ended December 31, 2002. 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 requested the changes to become effective November 1, 2002, the date retail access was scheduled to commence in Nevada in accordance with provisions of AB 661, passed in the 2001 session of the Nevada Legislature. On October 11, 2002, the Utilities filed with the FERC, revised rates, terms, and conditions for ancillary services offered in the OATT designated Docket No. ER03-37-000. On November 25, 2002, the FERC suspended the rates in Docket No. ER03-37-000 for a nominal period and made them effective subject to refund on January 1, 2003, as requested by the Utilities. On November 21, 2002, the FERC suspended the revised OATT in Docket No. ER02-2607-000 for a nominal period, made it effective subject to refund, set certain issues for hearing, and directed the Utilities to make a compliance filing. The compliance filing was submitted on December 23, 2002. This order additionally established hearing procedures and consolidated the two dockets for hearing. On March 11, 2003, all parties to these dockets reached a settlement in principle regarding all issues. The settlement agreement is expected to be filed with the FERC on or before May 2003. 58 ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK See the Annual Report on Form 10-K of SPR, NPC, and SPPC for the year ended December 31, 2002, Item 7A, Quantitative And Qualitative Disclosures About Market Risk for disclosures about market risk. There have been no material changes to the information previously disclosed in that report, except as described in the following discussion. CREDIT RISK The Utilities monitor and manage credit risk with their trading counterparties. As of March 31, 2003, the Utilities had outstanding transactions with over 40 energy and financial services companies. The Utilities credit risk associated with these transactions was approximately $25 million as of March 31, 2003. 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, the disclosure controls and procedures of SPR, NPC, and SPPC are effective in bringing to their attention on a timely basis material information relating to SPR, NPC, and SPPC required to be included in periodic filings under the Exchange Act. Since the Evaluation Date, there have not been any significant changes in the internal controls of SPR, NPC, and SPPC, or in other factors that could significantly affect these controls subsequent to the Evaluation Date. 59 PART II ITEM 1. LEGAL PROCEEDINGS Refer to Item 3 of SPR's, NPC's and SPPC's Annual Report on Form 10-K for the year ended December 31, 2002, and Note 18 to SPR's consolidated financial statements contained in that report and Note 11 to SPR's condensed consolidated financial statements contained in this report for a description of legal proceedings presently pending. Except as set forth below, there are no additional material legal proceedings or material developments with respect to previously reported proceedings involving SPR, NPC or SPPC. SIERRA PACIFIC RESOURCES AND NEVADA POWER COMPANY Lawsuit Against Merrill Lynch and Allegheny Energy, Inc. On April 2, 2003, SPR and NPC filed a complaint in the U.S. District Court for the District of Nevada against Merrill Lynch & Co., Inc. and Merrill Lynch Capital Services, Inc. (collectively, "Merrill Lynch") and Allegheny Energy, Inc., and Allegheny Energy Supply Company, LLC (collectively, "Allegheny") seeking actual and punitive damages in excess of $850 million and demanding a jury trial for all claims triable by jury. The complaint alleges that the Merrill Lynch defendants engaged in misrepresentation, suppression and concealment, breach of fiduciary duty, wrongful hiring and supervision of Daniel Gordon, and breach of contract and alleges that both Merrill Lynch and Allegheny engaged in intentional interference with contractual and prospective advantage, conspiracy and racketeering (in violation of Nevada Revised Statutes Section 207.470). The complaint also alleges that the improper behavior of Merrill Lynch and Allegheny was the direct and proximate cause of the March 2002 decision by the PUCN to disallow $180 million of rate adjustments in NPC's 2001 deferred energy accounting adjustment rate application. Lawsuit Against Natural Gas Providers On April 21, 2003, SPR and NPC filed a complaint in the U.S. District Court for the District of Nevada against natural gas providers El Paso Corporation, El Paso Natural Gas Company, El Paso Merchant Energy Company, El Paso Tennessee Pipeline Company, El Paso Merchant Energy-Gas Company, Sempra Energy, Southern California Gas Company, San Diego Gas and Electric Company, Dynegy Holdings, Inc., Dynegy Energy Services, Inc., and Does 1-100, seeking $600 million in total damages. The complaint alleges, among other things, that as a result of the defendants' conspiracies and fraudulent behavior, SPR and NPC were forced to enter into natural gas purchase contracts "at artificially high, supracompetitive prices." The complaint further states that between 1996 and 2001, certain of the defendants and their subsidiaries conspired, in secret meetings, to decrease competition by restricting the amount of pipeline capacity and fuel available to NPC while other defendants decreased natural gas supplies and drove up prices by illegally withholding pipeline capacity, maintained control over output and prices by manipulating natural gas price indexes, and harmed market competition and the plaintiffs by driving up prices and increasing the volatility of natural gas supplies. SPR and NPC assert that the defendants conspired to prevent the construction of new gas transportation capacity to deliver gas to the southern Nevada area by preventing the planned expansion of the Kern River Pipeline upon which NPC relies for its primary supply of natural gas for its generation facilities. The complaint also alleges that certain of the defendants "systematically misrepresented the price and volume of their trades" to key trade publications, creating the appearance of supply volatility and escalating prices starting in 2000 and continuing through the beginning of 2002. SPR and NPC assert claims for fraud, violation of Nevada's RICO Act and conspiracy to violate Nevada's RICO Act, compensatory damages, treble damages, punitive damages, legal fees, interest and other such relief deemed just and proper by the court. NEVADA POWER COMPANY AND SIERRA PACIFIC POWER COMPANY Enron Litigation Hearings were held on April 3, 2003, in the Bankruptcy Court for the Southern District of New York, in the lawsuit filed by Enron against NPC and SPPC for liquidated damages in the amount of approximately $216 million and $87 million, respectively, related to its termination of its power supply agreement with NPC and SPPC and for power previously delivered to the Utilities. The Bankruptcy Court heard arguments regarding Enron's motion to dismiss the Utilities' counterclaims against Enron for unspecified damages to be determined during the case. The Utilities' counterclaims seek damages for acts and omissions of Enron in manipulating the power markets, wrongful termination of its transactions with the Utilities, and fraudulent inducement to enter into transactions with Enron, among other issues. The Court has not ruled on this matter nor has it indicated when a decision on this matter can be expected. The Utilities continue to participate in non-binding court-ordered mediation proceedings along with all of Enron's other terminated purchased power counterparties. For more information regarding the Enron litigation, please see Note 11 to SPR's condensed consolidated financial statements contained in this report and Item 3 - Legal Proceedings in SPR's, NPC's and SPPC's Annual Report on Form 10-K for the year ended December 31, 2002. 60 NEVADA POWER COMPANY Morgan Stanley Proceedings In March 2003, the arbitrator overseeing the arbitration proceedings initiated by Morgan Stanley Capital Group ("MSCG") regarding various power supply contract terminated by MSCG in April 2002 dismissed MSCG's demand for arbitration and agreed that the issues raised by MSCG were not calculation issues subject to arbitration and that NPC's contract defenses were likewise not arbitrable. For more information regarding the MSCG arbitration proceedings, please see Note 11 to SPR's condensed consolidated financial statements contained in this report and tem 3 - Legal Proceedings in SPR's, NPC's and SPPC's Annual Report on Form 10-K for the year ended December 31, 2002. NPC has since filed a complaint for declaratory relief in the U.S. District Court for the District of Nevada asking the Court to declare that NPC is not liable for any damages as a result of MSCG's termination of its power supply contracts. MSCG has not yet answered or responded to the complaint; however, on April 17, 2003, MSCG filed a complaint against NPC at the FERC conceding that the issues raised by NPC were litigable in court but asking the FERC to declare that under the WSPP agreement NPC should post the $25 million in dispute as collateral pending the outcome of the litigation. NPC is unable to predict the outcome of these proceedings. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS None ITEM 5. OTHER INFORMATION None ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K (a) Exhibits filed with this Form 10-Q: SIERRA PACIFIC RESOURCES Exhibit 4.1 Indenture dated as of February 14, 2003 between Sierra Pacific Resources and The Bank of New York, as Trustee, in connection with the issuance of 7.25% Convertible Notes due 2010. Exhibit 4.2 Form of Sierra Pacific Resources' 7.25% Convertible Note due 2010. NEVADA POWER COMPANY AND SIERRA PACIFIC POWER COMPANY Exhibit 10.1 Western Systems Power Pool ("WSPP") Agreement effective February 1, 2003 between Nevada Power Company as a member of the WSPP, Sierra Pacific Power Company as a member of the WSPP and the other members of the WSPP. 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 January 16, 2003, filed by SPR- Item 5, Other Events Disclosed SPR agreements to acquire $8,750,000 aggregate principal amount of its Floating Rate Notes due April 20, 2003 in exchange for 1,295,211 shares of its common stock in two privately-negotiated transactions. Form 8-K dated February 3, 2003, filed by SPR - Item 5, Other Events Disclosed, and included as an exhibit, SPR's press release dated February 3, 2003, announcing SPR reached agreements to exchange 30% of its Premium Income Equity Securities ("PIES") for shares of its common stock, par value 61 $1.00 per share. Under terms of the privately-negotiated agreements, with a limited number of investors, the Company issued approximately 13.66 million shares of common stock in exchange for a total of 2,095,650 PIES. Form 8-K dated February 10, 2003, filed by SPR, NPC and SPPC - Item 5, Other Events Disclosed, and included as an exhibit, SPR's press release dated Febraury 10, 2003, reporting financial results for the quarter ended December 31, 2002. Form 8-K dated February 10, 2003, filed by SPR- Item 5, Other Events Disclosed, and included as an exhibit, SPR's press release regarding an offering of $250 million aggregate principal amounts of its convertible Notes due 2010 under Rule 144A.. Form 8-K dated February 11, 2003, filed by SPR, NPC and SPPC - Item 5, Other Events Disclosed SPR's Preliminary Offering Memorandum for distribution to potential purchasers. The long-term convertible debt issued in the form of 7.25% Convertible Notes due 2010. Also disclosed as an exhibit were excerpts from the Preliminary Offering Memorandum. 62 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: May 6, 2003 By: /s/ Richard K. Atkinson ----------------------------- Richard K. Atkinson Vice President Chief Financial Officer (Principal Financial Officer) Date: May 6, 2003 By: /s/ John E. Brown ------------------------------ John E. Brown Vice President Controller (Principal Accounting Officer) NEVADA POWER COMPANY ------------------------------ (Registrant) Date: May 6, 2003 By: /s/ Richard K. Atkinson ------------------------------ Richard K. Atkinson Vice President Chief Financial Officer (Principal Financial Officer) Date: May 6, 2003 By: /s/ John E. Brown ------------------------------ John E. Brown Vice President Controller (Principal Accounting Officer) SIERRA PACIFIC POWER COMPANY ------------------------------ (Registrant) Date: May 6, 2003 By: /s/ Richard K. Atkinson ------------------------------ Richard K. Atkinson Vice President Chief Financial Officer (Principal Financial Officer) Date: May 6, 2003 By: /s/ John E. Brown ----------------------------- John E. Brown Vice President Controller (Principal Accounting Officer) 63 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 this quarterly report of Sierra Pacific Resources, Nevada Power Company and Sierra Pacific Power Company on Form 10-Q for the period ending March 31, 2003; 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 this quarterly report; 3. Based on my knowledge, the financial statements, and other financial information included in this 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 this 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 this 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 this quarterly report (the "Evaluation Date"); and c) presented in this 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 64 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 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. May 5, 2003 /s/ Walter M. Higgins III ------------------------------------- Walter M. Higgins III Chief Executive Officer 65 QUARTERLY CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER REQUIRED BY SECTION 302(A) OF THE SARBANES-OXLEY ACT OF 2002 I, Richard K. Atkinson, certify that: 1. I have reviewed this quarterly report of Sierra Pacific Resources, Nevada Power Company and Sierra Pacific Power Company on Form 10-Q for the period ending March 31, 2003; 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 this quarterly report; 3. Based on my knowledge, the financial statements, and other financial information included in this 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 this 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 this 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 this quarterly report (the "Evaluation Date"); and c) presented in this 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 66 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 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. May 5, 2003 /s/ Richard K. Atkinson Richard K. Atkinson Chief Financial Officer 67