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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2002
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM TO
Registrant, State of Incorporation, Address of
Commission File Principal Executive Offices and Telephone I.R.S. employer
Number Number Identification Number
1-8788 SIERRA PACIFIC RESOURCES 88-0198358
P.O. Box 10100
(6100 Neil Road)
Reno, Nevada 89520-0400 (89511)
(775) 834-4011
1-4698 NEVADA POWER COMPANY 88-0045330
6226 West Sahara Avenue
Las Vegas, Nevada 89146
(702) 367-5000
0-508 SIERRA PACIFIC POWER COMPANY 88-0044418
P.O. Box 10100
(6100 Neil Road)
Reno, Nevada 89520-0400 (89511)
(775) 834-4011
Indicate by check mark whether registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes [X] No [ ]
Indicate the number of shares outstanding of each of the issuer's classes of
Common Stock, as of the latest practicable date.
Class Outstanding at November 6, 2002
Common Stock, $1.00 par value 102,138,325 Shares
of Sierra Pacific Resources
Sierra Pacific Resources is the sole holder of the 1,000 shares of outstanding
Common Stock, $1.00 stated value, of Nevada Power Company.
Sierra Pacific Resources is the sole holder of the 1,000 shares of outstanding
Common Stock, $3.75 stated value, of Sierra Pacific Power Company.
This combined Quarterly Report on Form 10-Q is separately filed by Sierra
Pacific Resources, Nevada Power Company and Sierra Pacific Power Company.
Information contained in this document relating to Nevada Power Company is filed
by Sierra Pacific Resources and separately by Nevada Power Company on its own
behalf. Nevada Power Company makes no representation as to information relating
to Sierra Pacific Resources or its subsidiaries, except as it may relate to
Nevada Power Company. Information contained in this document relating to Sierra
Pacific Power Company is filed by Sierra Pacific Resources and separately by
Sierra Pacific Power Company on its own behalf. Sierra Pacific Power Company
makes no representation as to information relating to Sierra Pacific Resources
or its subsidiaries, except as it may relate to Sierra Pacific Power Company.
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SIERRA PACIFIC RESOURCES
NEVADA POWER COMPANY
SIERRA PACIFIC POWER COMPANY
QUARTERLY REPORTS ON FORM 10-Q
FOR THE QUARTER ENDED SEPTEMBER 30, 2002
CONTENTS
PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS (Unaudited)
SIERRA PACIFIC RESOURCES -
Condensed Consolidated Balance Sheets - September 30, 2002 and December 31, 2001.......... 3
Condensed Consolidated Statements of Operations - Three Months and Nine Months
Ended September 30, 2002 and 2001................................................... 4
Condensed Consolidated Statements of Cash Flows - Nine Months
Ended September 30, 2002 and 2001................................................... 5
NEVADA POWER COMPANY -
Condensed Balance Sheets - September 30, 2002 and December 31, 2001....................... 6
Condensed Statements of Operations - Three Months and Nine Months
Ended September 30, 2002 and 2001................................................... 7
Condensed Statements of Cash Flows - Nine Months Ended September 30, 2002 and 2001........ 8
SIERRA PACIFIC POWER COMPANY -
Condensed Consolidated Balance Sheets - September 30, 2002 and December 31, 2001.......... 9
Condensed Consolidated Statements of Operations - Three Months and Nine Months
Ended September 30, 2002 and 2001................................................... 10
Condensed Consolidated Statements of Cash Flows - Nine Months
Ended September 30, 2002 and 2001................................................... 11
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS.............................................. 12
ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations..... 36
Sierra Pacific Resources Results of Operations...................................... 41
Nevada Power Company Results of Operations.......................................... 46
Sierra Pacific Power Company Results of Operations.................................. 53
ITEM 3. Quantitative and Qualitative Disclosures about Market Risk................................ 65
ITEM 4. Controls and Procedures................................................................... 65
PART II - OTHER INFORMATION
ITEM 1. Legal Proceedings......................................................................... 66
ITEM 4. Submission of Matters to a Vote of Security Holders....................................... 66
ITEM 5. Other Information......................................................................... 66
ITEM 6. Exhibits and Reports on Form 8-K.......................................................... 66
Signature Page and Certifications ....................................................................... 68
2
SIERRA PACIFIC RESOURCES
CONDENSED CONSOLIDATED BALANCE SHEETS
(DOLLARS IN THOUSANDS) (UNAUDITED)
SEPTEMBER 30, DECEMBER 31,
2002 2001
------------- -------------
ASSETS
Utility Plant at Original Cost:
Plant in service $ 5,845,229 $ 5,683,296
Less: accumulated provision for depreciation 1,902,630 1,777,517
----------- -----------
3,942,599 3,905,779
Construction work-in-progress 261,691 203,456
----------- -----------
4,204,290 4,109,235
----------- -----------
Investments in subsidiaries and other property, net 182,486 128,892
----------- -----------
Current Assets:
Cash and cash equivalents 360,345 99,109
Restricted cash (Note 1) 22,750 -
Accounts receivable less provision for uncollectible accounts:
2002-$42,001 ; 2001-$39,335 467,881 394,489
Deferred energy costs - electric 254,226 333,062
Deferred energy costs - gas 18,957 19,805
Income tax receivable - 59,630
Materials, supplies and fuel, at average cost 96,053 94,167
Risk management assets (Note 10) 66,494 286,509
Other 24,040 14,071
----------- -----------
1,310,746 1,300,842
----------- -----------
Deferred Charges and Other Assets:
Goodwill (Note 12) 310,441 312,145
Deferred energy costs - electric 767,238 854,778
Deferred energy costs - gas 11,737 23,248
Income tax receivable 266,665 314,619
Regulatory tax asset 168,276 169,738
Other regulatory assets 139,914 102,959
Risk management assets (Note 10) 7,813 61,058
Risk management regulatory assets - net (Note 10) 78,441 664,383
Other 120,557 139,417
----------- -----------
1,871,082 2,642,345
----------- -----------
$ 7,568,604 $ 8,181,314
=========== ===========
CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholders' equity $ 1,413,738 $ 1,702,322
Accumulated other comprehensive loss (Note 10) (4,260) (6,986)
Preferred stock 50,000 50,000
NPC obligated mandatorily redeemable preferred trust securities 188,872 188,872
Long-term debt 2,986,517 3,376,105
----------- -----------
4,634,867 5,310,313
----------- -----------
Current Liabilities:
Short-term borrowings 350,000 177,000
Current maturities of long-term debt 431,327 122,010
Accounts payable 390,660 265,250
Accrued interest 74,294 37,565
Dividends declared 1,045 1,045
Accrued salaries and benefits 16,763 30,145
Deferred taxes on deferred energy costs 94,823 123,503
Risk management liabilities (Note 10) 132,121 855,301
Other current liabilities 28,966 15,678
----------- -----------
1,519,999 1,627,497
----------- -----------
Commitments & Contingencies (Note 11)
Deferred Credits and Other Liabilities:
Deferred federal income taxes 404,666 412,658
Deferred investment tax credit 49,355 51,947
Deferred taxes on deferred energy costs 273,432 307,309
Regulatory tax liability 45,708 46,702
Customer advances for construction 114,447 108,179
Accrued retirement benefits 95,351 82,624
Risk management liabilities (Note 10) 20,454 163,636
Contract termination reserves (Note 11) 315,780 -
Other 94,545 70,449
----------- -----------
1,413,738 1,243,504
----------- -----------
$ 7,568,604 $ 8,181,314
=========== ===========
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS.
3
SIERRA PACIFIC RESOURCES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) (UNAUDITED)
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
--------------------------------- -------------------------------
2002 2001 2002 2001
------------- ------------- ------------- ------------
OPERATING REVENUES:
Electric $ 997,559 $ 1,977,453 $ 2,251,813 $ 3,738,177
Gas 18,473 18,831 99,139 104,725
Other 3,987 5,650 8,328 13,350
------------- ------------- ------------- ------------
1,020,019 2,001,934 2,359,280 3,856,252
------------- ------------- ------------- ------------
OPERATING EXPENSES:
Operation:
Purchased power 604,683 2,195,051 1,546,394 3,636,006
Fuel for power generation 120,668 220,002 356,084 586,136
Gas purchased for resale 9,884 9,294 61,585 105,008
Deferred energy costs disallowed - - 487,224 -
Deferral of energy costs - electric - net (41,425) (737,634) (309,203) (1,080,846)
Deferral of energy costs - gas - net 4,281 3,453 14,649 (23,354)
Other 70,566 81,924 206,004 248,428
Maintenance 12,904 15,475 46,826 53,933
Depreciation and amortization 43,847 40,958 129,606 120,552
Taxes:
Income taxes 41,002 40,087 (145,949) 8,033
Other than income 10,282 11,134 33,585 32,358
------------- ------------- ------------- ------------
876,692 1,879,744 2,426,805 3,686,254
------------- ------------- ------------- ------------
OPERATING INCOME (LOSS) 143,327 122,190 (67,525) 169,998
------------- ------------- ------------- ------------
OTHER INCOME (EXPENSE):
Allowance for other funds used during construction (272) (106) 382 (793)
Other income - net 8,016 16,007 6,472 22,319
------------- ------------- ------------- ------------
7,744 15,901 6,854 21,526
------------- ------------- ------------- ------------
Total Income (Loss) Before Interest Charges 151,071 138,091 (60,671) 191,524
------------- ------------- ------------- ------------
INTEREST CHARGES:
Long-term debt 56,734 47,623 170,973 131,155
Other 11,097 5,474 23,993 20,767
Allowance for borrowed funds used during
construction and capitalized interest (902) (1,225) (3,483) (1,514)
------------- ------------- ------------- ------------
66,929 51,872 191,483 150,408
------------- ------------- ------------- ------------
INCOME (LOSS) BEFORE NPC OBLIGATED MANDATORILY
REDEEMABLE PREFERRED TRUST SECURITIES 84,142 86,219 (252,154) 41,116
Preferred dividend requirements of NPC obligated
mandatorily redeemable preferred trust securities 3,793 4,835 11,379 14,293
------------- ------------- ------------- ------------
INCOME (LOSS) BEFORE PREFERRED STOCK DIVIDENDS 80,349 81,384 (263,533) 26,823
Preferred stock dividend requirements of subsidiary 975 975 2,925 2,725
------------- ------------- ------------- ------------
INCOME (LOSS) FROM CONTINUING OPERATIONS 79,374 80,409 (266,458) 24,098
------------- ------------- ------------- ------------
DISCONTINUED OPERATIONS:
Income from operations of water business
disposed of (net of income taxes of
$0 and $888 in 2001, respectively) - - - 1,022
Gain on disposal of water business
(net of income taxes of $18,237) - - - 25,845
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
PRINCIPLE, NET OF TAX (Note 12) - - (1,566) -
------------- ------------- ------------- ------------
NET INCOME (LOSS) $ 79,374 $ 80,409 $ (268,024) $ 50,965
============= ============= ============= ============
Amounts per share - Basic and Diluted
Income (loss) from continuing operations $ 0.78 $ 0.89 $ (2.61) $ 0.29
Income from discontinued operations - 0.01
Gain on disposal of water business - 0.32
Cumulative effect of change in accounting
principle (net of tax) - (0.01) -
------------- ------------- ------------- ------------
Net income (loss) $ 0.78 $ 0.89 $ (2.62) $ 0.62
============= ============= ============= ============
Weighted Average Shares of Common Stock Outstanding 102,132,465 90,302,825 102,117,926 82,423,032
============= ============= ============= ============
Dividends Paid Per Share of Common Stock $ - $ 0.20 $ 0.20 $ 0.45
============= ============= ============= ============
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS.
4
SIERRA PACIFIC RESOURCES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(DOLLARS IN THOUSANDS) (UNAUDITED)
NINE MONTHS ENDED
SEPTEMBER 30,
-------------------------------
2002 2001
------------ -----------
CASH FLOWS FROM OPERATING ACTIVITIES:
Income (Loss) from continuing operations before preferred dividends $ (263,533) $ 26,823
Income from discontinued operations before preferred dividends - 1,222
Gain on disposal of water business - 25,845
Non-cash items included in income:
Depreciation and amortization 130,097 124,011
Deferred taxes and deferred investment tax credit 79,410 107,795
AFUDC and capitalized interest (3,865) (730)
Amortization of deferred energy costs - electric 130,667 -
Amortization of deferred energy costs - gas 8,950 -
Deferred energy costs disallowed (net of taxes) 317,977 -
Early retirement and severance amortization 2,082 3,121
Gain on disposal of water business - (44,081)
Other non-cash (12,099) 3,676
Changes in certain assets and liabilities:
Accounts receivable (115,247) (498,883)
Deferral of energy costs - electric (123,308) (1,105,698)
Deferral of energy costs - gas 3,408 (25,938)
Materials, supplies and fuel (1,886) (19,849)
Other current assets (32,658) (4,093)
Accounts payable 166,144 543,413
Income tax receivable 108,992 -
Other current liabilities 35,293 18,061
Other - net 32,396 16,827
------------ -----------
Net Cash from Operating Activities 462,820 (828,478)
------------ -----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to utility plant (259,831) (251,458)
AFUDC and other charges to utility plant 3,865 730
Customer advances (refunds) for construction 6,268 (3,219)
Contributions in aid of construction 32,381 24,259
------------ -----------
Net cash used for utility plant (217,317) (229,688)
Proceeds from sale of assets of water business - 318,882
Investments in subsidiaries and other property (53,672) (3,961)
------------ -----------
Net Cash from Investing Activities (270,989) 85,233
------------ -----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Increase in short-term borrowings 173,000 56,487
Proceeds from issuance of long-term debt - 900,000
Retirement of long-term debt (80,272) (536,103)
Sale of common stock 187 340,764
Dividends paid (23,510) (43,366)
------------ -----------
Net Cash from Financing Activities 69,405 717,782
------------ -----------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 261,236 (25,463)
Beginning Balance in Cash and Cash Equivalents 99,109 51,503
------------ -----------
Ending Balance in Cash and Cash Equivalents $ 360,345 $ 26,040
============ ===========
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash paid (received) during period for:
Interest $ 154,754 $ 112,982
Income taxes $ (185,011) $ 28,424
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS
5
NEVADA POWER COMPANY
CONDENSED BALANCE SHEETS
(DOLLARS IN THOUSANDS) (UNAUDITED)
SEPTEMBER 30, DECEMBER 31,
2002 2001
------------ ------------
ASSETS
Utility Plant at Original Cost:
Plant in service $ 3,500,244 $ 3,356,584
Less: accumulated provision for depreciation 999,584 928,939
------------ ------------
2,500,660 2,427,645
Construction work-in-progress 153,529 134,706
------------ ------------
2,654,189 2,562,351
------------ ------------
Investment in Sierra Pacific Resources (Note 2) 236,821 309,259
Investments in subsidiaries and other property, net 20,168 12,721
------------ ------------
256,989 321,980
------------ ------------
Current Assets:
Cash and cash equivalents 207,746 8,505
Restricted cash (Note 1) 10,872 -
Accounts receivable less provision for uncollectible accounts:
2002-$34,269; 2001-$30,861 306,868 210,333
Deferred energy costs - electric 197,542 281,555
Income tax receivable - 18,590
Materials, supplies and fuel, at average cost 45,434 48,511
Risk management assets (Note 10) 49,142 200,829
Other 10,732 6,698
------------ ------------
828,336 775,021
------------ ------------
Deferred Charges and Other Assets:
Deferred energy costs - electric 591,871 698,510
Income tax receivable 245,009 295,818
Regulatory tax asset 108,912 109,859
Other regulatory assets 53,904 31,588
Risk management assets (Note 10) 7,813 49,493
Risk management regulatory assets - net (Note 10) 7,198 351,264
Other 24,948 29,485
------------ ------------
1,039,655 1,566,017
------------ ------------
$ 4,779,169 $ 5,225,369
============ ============
CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholder's equity including $236,821 and $309,259
of equity in Sierra Pacific Resources in 2002 and 2001 (Note 2) $ 1,413,738 $ 1,702,322
Accumulated other comprehensive income 117 520
NPC obligated mandatorily redeemable preferred trust securities 188,872 188,872
Long-term debt 1,393,034 1,607,967
------------ ------------
2,995,761 3,499,681
------------ ------------
Current Liabilities:
Short-term borrowings 200,000 130,500
Current maturities of long-term debt 228,927 19,380
Accounts payable 332,333 202,555
Accrued interest 35,542 19,310
Dividends declared 78 71
Accrued salaries and benefits 5,520 12,450
Deferred taxes on deferred energy costs 68,349 98,544
Risk management liabilities (Note 10) 58,218 522,508
Other current liabilities 20,370 17,710
------------ ------------
949,337 1,023,028
------------ ------------
Commitments & Contingencies (Note 11)
Deferred Credits and Other Liabilities:
Deferred federal income taxes 210,773 223,641
Deferred investment tax credit 22,310 23,533
Deferred taxes on deferred energy costs 207,945 244,479
Regulatory tax liability 18,280 18,604
Customer advances for construction 64,525 61,454
Accrued retirement benefits 36,089 28,104
Risk management liabilities (Note 10) 5,818 78,558
Contract termination reserves (Note 11) 229,002 -
Other 39,329 24,287
------------ ------------
834,071 702,660
------------ ------------
$ 4,779,169 $ 5,225,369
============ ============
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS.
6
NEVADA POWER COMPANY
CONDENSED STATEMENTS OF OPERATIONS
(DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) (UNAUDITED)
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------------------ --------------------------------
2002 2001 2002 2001
------------- ------------- -------------- --------------
OPERATING REVENUES:
Electric $ 712,536 $ 1,395,496 $ 1,545,867 $ 2,562,949
OPERATING EXPENSES:
Operation:
Purchased power 440,559 1,686,816 1,102,551 2,728,176
Fuel for power generation 87,864 131,023 245,060 348,633
Deferred energy costs disallowed - - 434,123 -
Deferral of energy costs-net (43,224) (638,571) (238,059) (908,408)
Other 39,250 45,670 116,520 130,192
Maintenance 8,050 10,331 31,576 36,789
Depreciation and amortization 24,975 23,042 72,924 67,345
Taxes:
Income taxes 39,944 36,197 (116,536) 21,979
Other than income 5,935 6,221 19,122 18,118
------------- ------------- -------------- --------------
603,353 1,300,729 1,667,281 2,442,824
------------- ------------- -------------- --------------
OPERATING INCOME (LOSS) 109,183 94,767 (121,414) 120,125
------------- ------------- -------------- --------------
OTHER INCOME (EXPENSE):
Equity in earnings (losses) of Sierra
Pacific Resources (Note 2) 70 1,658 (51,999) (5,494)
Allowance for other funds used during
construction (262) (87) 239 (560)
Other income (expense) - net 4,933 11,021 (839) 14,189
------------- ------------- -------------- --------------
4,741 12,592 (52,599) 8,135
------------- ------------- -------------- --------------
Total Income (Loss) Before
Interest Charges 113,924 107,359 (174,013) 128,260
------------- ------------- -------------- --------------
INTEREST CHARGES:
Long-term debt 23,714 20,545 70,668 55,504
Other 7,251 3,269 14,133 10,982
Allowance for borrowed funds
used during construction and
capitalized interest (208) (657) (2,169) (570)
------------- ------------- -------------- --------------
30,757 23,157 82,632 65,916
------------- ------------- -------------- --------------
INCOME (LOSS) BEFORE NPC OBLIGATED MANDATORILY
REDEEMABLE PREFERRED TRUST SECURITIES 83,167 84,202 (256,645) 62,344
Preferred dividend requirements of NPC obligated
mandatorily redeemable preferred trust securities 3,793 3,793 11,379 11,379
------------- ------------- -------------- --------------
NET INCOME (LOSS) $ 79,374 $ 80,409 $ (268,024) $ 50,965
============= ============= ============== ==============
Net Income (Loss) Per Share - Basic (Note 2) $ 0.78 $ 0.89 $ (2.62) $ 0.62
============= ============= ============== ==============
- Diluted (Note 2) $ 0.78 $ 0.89 $ (2.62) $ 0.62
============= ============= ============== ==============
Weighted Average Shares of Common
Stock Outstanding (Note 2) 102,132,465 90,302,825 102,117,926 82,423,032
============= ============= ============== ==============
Dividends Paid Per Share of Common Stock (Note 2) $ - $ 0.20 $ 0.20 $ 0.45
============= ============= ============== ==============
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS.
7
NEVADA POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS
(DOLLARS IN THOUSANDS) (UNAUDITED)
NINE MONTHS ENDED
SEPTEMBER 30,
------------------------------
2002 2001
------------ ------------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) $ (268,024) $ 50,965
Non-cash items included in income:
Depreciation and amortization 72,924 67,345
Deferred taxes and deferred investment tax credit 68,430 51,944
AFUDC and capitalized interest (2,408) (10)
Amortization of deferred energy costs 112,959 -
Deferred energy costs disallowed (net of taxes) 282,181 -
Other non-cash (14,184) 2,367
Equity in losses of SPR (Note 2) 51,999 5,494
Changes in certain assets and liabilities:
Accounts receivable (95,791) (411,765)
Deferral of energy costs (127,429) (928,987)
Materials, supplies and fuel 3,077 (5,809)
Other current assets (14,843) (725)
Accounts payable 129,728 523,642
Income tax receivable 70,807 -
Other current liabilities 11,961 12,632
Other - net 18,832 8,780
------------ ------------
Net Cash from Operating Activities 300,219 (624,127)
------------ ------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to utility plant (196,006) (141,414)
AFUDC and other charges to utility plant 2,408 10
Customer advances (refunds) for construction 3,072 (4,054)
Contributions in aid of construction 27,635 5,630
------------ ------------
Net cash used for utility plant (162,891) (139,828)
Investments in subsidiaries and other property (2,200) -
------------ ------------
Net Cash from Investing Activities (165,091) (139,828)
------------ ------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Increase in short-term borrowings 69,500 130,561
Proceeds from issuance of long-term debt - 500,000
Retirement of long-term debt (5,387) (254,112)
Investment by parent company 10,000 394,921
Dividends paid (10,000) (33,014)
------------ ------------
Net Cash from Financing Activities 64,113 738,356
------------ ------------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 199,241 (25,599)
Beginning Balance in Cash and Cash Equivalents 8,505 43,858
------------ ------------
Ending Balance in Cash and Cash Equivalents $ 207,746 $ 18,259
============ ============
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash paid (received) during period for:
Interest $ 66,400 $ 28,160
Income taxes $ (102,904) $ 47,501
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS.
8
SIERRA PACIFIC POWER COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(DOLLARS IN THOUSANDS) (UNAUDITED)
SEPTEMBER 30, DECEMBER 31,
2002 2001
------------ ------------
ASSETS
Utility Plant at Original Cost:
Plant in service $ 2,344,985 $ 2,326,712
Less: accumulated provision for depreciation 903,046 848,578
------------ ------------
1,441,939 1,478,134
Construction work-in-progress 108,162 68,750
------------ ------------
1,550,101 1,546,884
------------ ------------
Investments in subsidiaries and other property, net 54,775 57,185
------------ ------------
Current Assets:
Cash and cash equivalents 143,868 11,772
Restricted cash (Note 1) 9,273 -
Accounts receivable less provision for uncollectible accounts:
2002 - $7,732; 2001 - $8,474 249,692 194,698
Deferred energy costs - electric 56,684 51,507
Deferred energy costs - gas 18,957 19,805
Materials, supplies and fuel, at average cost 46,795 42,290
Income tax receivable - 41,040
Risk management assets (Note 10) 17,352 85,680
Other 10,827 5,935
------------ ------------
553,448 452,727
------------ ------------
Deferred Charges and Other Assets:
Deferred energy costs - electric 175,367 156,268
Deferred energy costs - gas 11,737 23,248
Regulatory tax asset 59,364 59,879
Other regulatory assets 66,107 51,146
Risk management assets (Note 10) - 11,565
Risk management regulatory assets - net (Note 10) 71,243 313,119
Other 12,332 13,886
------------ ------------
396,150 629,111
------------ ------------
$ 2,554,474 $ 2,685,907
============ ============
CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholder's equity $ 670,365 $ 692,654
Accumulated other comprehensive income 56 247
Preferred stock 50,000 50,000
Long-term debt 917,100 923,070
------------ ------------
1,637,521 1,665,971
------------ ------------
Current Liabilities:
Short-term borrowings 150,000 46,500
Current maturities of long-term debt 2,400 2,630
Accounts payable 82,270 95,555
Accrued interest 24,489 8,408
Dividends declared 967 974
Accrued salaries and benefits 8,923 15,466
Deferred taxes on deferred energy costs 26,474 24,959
Risk management liabilities (Note 10) 73,903 332,793
Other current liabilities 7,586 3,387
------------ ------------
377,012 530,672
------------ ------------
Commitments & Contingencies (Note 11)
Deferred Credits and Other Liabilities:
Deferred federal income taxes 186,864 178,533
Deferred investment tax credit 27,045 28,414
Deferred taxes on deferred energy costs 65,487 62,831
Income tax payable 2,345 -
Regulatory tax liability 27,428 28,098
Customer advances for construction 49,922 46,725
Accrued retirement benefits 49,455 43,028
Risk management liabilities (Note 10) 14,636 77,324
Contract termination reserves (Note 11) 86,778 -
Other 29,981 24,311
------------ ------------
539,941 489,264
------------ ------------
$ 2,554,474 $ 2,685,907
============ ============
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS.
9
SIERRA PACIFIC POWER COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(DOLLARS IN THOUSANDS) (UNAUDITED)
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------------ ----------------------------
2002 2001 2002 2001
---------- ----------- ----------- -------------
OPERATING REVENUES:
Electric $ 285,023 $ 581,957 $ 705,946 $ 1,175,228
Gas 18,473 18,831 99,139 104,725
---------- ----------- ----------- -------------
303,496 600,788 805,085 1,279,953
---------- ----------- ----------- -------------
OPERATING EXPENSES:
Operation:
Purchased power 164,124 508,235 443,843 907,830
Fuel for power generation 32,804 88,980 111,024 237,504
Gas purchased for resale 9,884 9,294 61,585 105,008
Deferred energy costs disallowed - - 53,101 -
Deferral of energy costs - electric - net 1,799 (98,702) (71,144) (172,437)
Deferral of energy costs - gas - net 4,281 3,093 14,649 (23,354)
Other 25,064 28,222 75,687 79,090
Maintenance 4,854 5,143 15,250 17,143
Depreciation and amortization 18,592 17,620 55,861 52,328
Taxes:
Income taxes 7,601 8,630 (9,037) 7,974
Other than income 4,472 4,671 14,129 13,639
---------- ----------- ----------- -------------
273,475 575,186 764,948 1,224,725
---------- ----------- ----------- -------------
OPERATING INCOME 30,021 25,602 40,137 55,228
---------- ----------- ----------- -------------
OTHER INCOME (EXPENSE):
Allowance for other funds used during construction (10) (19) 143 (233)
Other income - net 1,954 4,309 4,631 5,322
---------- ----------- ----------- -------------
1,944 4,290 4,774 5,089
---------- ----------- ----------- -------------
Total Income Before Interest Charges 31,965 29,892 44,911 60,317
---------- ----------- ----------- -------------
INTEREST CHARGES:
Long-term debt 16,173 15,380 48,638 38,479
Other 2,943 1,455 7,051 7,437
Allowance for borrowed funds used during construction and
capitalized interest (694) (566) (1,314) (943)
---------- ----------- ----------- -------------
18,422 16,269 54,375 44,973
---------- ----------- ----------- -------------
INCOME (LOSS) BEFORE SPPC OBLIGATED MANDATORILY
REDEEMABLE PREFERRED TRUST SECURITIES 13,543 13,623 (9,464) 15,344
Preferred dividend requirements of SPPC obligated
mandatorily redeemable preferred trust securities - 1,042 - 2,914
---------- ----------- ----------- -------------
INCOME (LOSS) BEFORE PREFERRED DIVIDENDS 13,543 12,581 (9,464) 12,430
Preferred dividend requirements 975 975 2,925 2,725
---------- ----------- ----------- -------------
INCOME (LOSS) FROM CONTINUING OPERATIONS 12,568 11,606 (12,389) 9,705
---------- ----------- ----------- -------------
DISCONTINUED OPERATIONS:
Income from operations of water business disposed of (net of
income taxes of $0 and $888 in 2001, respectively) - - - 1,022
Gain on disposal of water business (net of income taxes of $18,237) - - - 25,845
---------- ----------- ----------- -------------
NET INCOME (LOSS) $ 12,568 $ 11,606 $ (12,389) $ 36,572
========== =========== =========== =============
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS.
10
SIERRA PACIFIC POWER COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(DOLLARS IN THOUSANDS) (UNAUDITED)
NINE MONTHS ENDED
SEPTEMBER 30,
------------------------------
2002 2001
----------- -------------
CASH FLOWS FROM OPERATING ACTIVITIES:
Income (Loss) from continuing operations before preferred dividends $ (9,464) $ 12,430
Income from discontinued operations before preferred dividends - 1,222
Gain on disposal of water business - 25,845
Non-cash items included in income:
Depreciation and amortization 55,861 55,788
Deferred taxes and investment tax credits 10,979 55,807
AFUDC and capitalized interest (1,457) (719)
Amortization of deferred energy costs - electric 17,708 -
Amortization of deferred energy costs - gas 8,950 -
Deferred energy costs disallowed (net of taxes) 35,796 -
Early retirement and severance amortization 2,082 3,121
Gain on disposal of water business - (44,081)
Other non-cash (10,612) (3,580)
Changes in certain assets and liabilities:
Accounts receivable (54,994) (162,234)
Deferral of energy costs - electric 4,121 (176,712)
Deferral of energy costs - gas 3,408 (25,938)
Materials, supplies and fuel (4,506) (11,601)
Other current assets (14,165) (2,728)
Accounts payable (13,285) 80,416
Income tax receivable 43,385 -
Other current liabilities 13,738 13,742
Other-net 12,096 1,596
----------- ------------
Net Cash from Operating Activities 99,641 (177,626)
----------- ------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to utility plant (63,825) (110,043)
AFUDC and other charges to utility plant 1,457 719
Customer advances for construction 3,196 835
Contributions in aid of construction 4,746 18,628
----------- ------------
Net cash used for utility plant (54,426) (89,861)
Proceeds from sale of assets of water business - 318,882
Disposal of subsidiaries and other property - net 2,411 2,102
----------- ------------
Net Cash from Investing Activities (52,015) 231,123
----------- ------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Increase (decrease) in short-term borrowings 103,500 (89,962)
Proceeds from issuance of long-term debt - 400,000
Retirement of long-term debt (6,200) (281,980)
Investment by parent company 10,000 4,948
Dividends paid (22,830) (88,932)
----------- ------------
Net Cash from Financing Activities 84,470 (55,926)
----------- ------------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 132,096 (2,429)
Beginning Balance in Cash and Cash Equivalents 11,772 5,348
----------- ------------
Ending Balance in Cash and Cash Equivalents $ 143,868 $ 2,919
=========== ============
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash paid (received) during period for:
Interest $ 38,294 $ 29,154
Income taxes (62,109) 22,227
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS.
11
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. MANAGEMENT'S STATEMENT (SPR, NPC, SPPC)
In the opinion of the management of Sierra Pacific Resources (SPR),
Nevada Power Company (NPC), and Sierra Pacific Power Company (SPPC), the
accompanying unaudited interim condensed consolidated financial statements
contain all adjustments (consisting of only normal recurring adjustments)
necessary to present fairly the condensed consolidated financial position,
condensed consolidated results of operations and condensed consolidated cash
flows for the periods shown. These condensed consolidated financial statements
do not contain the complete detail or footnote disclosure concerning accounting
policies and other matters which are included in full year financial statements
and therefore, they should be read in conjunction with the audited financial
statements included in SPR's, NPC's, and SPPC's Combined Annual Report on Form
10-K for the year ended December 31, 2001.
The results of operations for the three- and nine-month periods ended
September 30, 2002 are not necessarily indicative of the results to be expected
for the full year.
PRINCIPLES OF CONSOLIDATION
The condensed consolidated financial statements of SPR include the
accounts of SPR and its wholly owned subsidiaries, Nevada Power Company, Sierra
Pacific Power Company, (collectively, the "Utilities"), Tuscarora Gas Pipeline
Company (TGPC), Sierra Gas Holding Company (SGHC), Sierra Energy Company dba
e-three (e-three), Sierra Pacific Energy Company (SPE), Lands of Sierra (LOS),
Sierra Pacific Communications (SPC), and Sierra Water Development Company
(SWDC). All significant intercompany transactions and balances have been
eliminated in consolidation.
FINANCIAL CONDITION, LIQUIDITY AND CAPITAL RESOURCES
The March 29, 2002 decision of the Public Utilities Commission of
Nevada (PUCN) on NPC's deferred energy application to disallow $434 million of
deferred purchased fuel and power costs accumulated between March 1, 2001 and
September 30, 2001 had a significant negative impact on the results of
operations of SPR and NPC for the nine months ended September 30, 2002. Several
of the intervenors from NPC's deferred energy rate case filed petitions with the
PUCN for reconsideration of its decision, seeking additional disallowances
ranging from $12.8 million to $488 million. The petitions for reconsideration
were granted in part and denied in part by the PUCN on May 24, 2002, but no
additional disallowances to the deferred energy balance resulted from that
decision. Although the PUCN's March 29, 2002 decision on NPC's deferred energy
application is being challenged by NPC in a lawsuit filed in Nevada state court
and by various intervenors, as discussed in Note 9, Regulatory Events, the
decision caused the two major national rating agencies to issue an immediate
downgrade of the credit ratings on SPR's, NPC's and SPPC's debt securities
(followed by further downgrades late in April). Following those events, the
market price of SPR's common stock fell substantially, NPC and SPPC were obliged
within 5 business days of the downgrades to issue general and refunding mortgage
bonds to secure their bank lines of credit, NPC was obliged to obtain a waiver
and amendment from its credit facility banks before it was permitted to draw
down on the facility, NPC and SPPC were no longer able to issue commercial
paper, a number of NPC's power suppliers contacted NPC regarding its ability to
pay the purchase price of outstanding contracts, and several power suppliers,
including a subsidiary of Enron Corp., Morgan Stanley Capital Group Inc.,
Reliant Energy Services, Inc. and several smaller suppliers, terminated their
power supply agreements with one or both of the Utilities. As discussed below,
Duke Energy Trading and Marketing ("Duke") agreed to replace the amount of
contracted power and natural gas that would have been supplied by the Utilities'
terminating suppliers during the peak summer period.
The separate decision of the PUCN on May 28, 2002 on SPPC's deferred
energy application to disallow $53.1 million of deferred purchased fuel and
power costs accumulated between March 1, 2001 and November 30, 2001 had a
significant negative impact on the results of operations of SPR and SPPC for the
nine months ended September 30, 2002. Several of the intervenors from SPPC's
deferred energy rate case filed petitions with the PUCN for reconsideration of
its decision, seeking an additional disallowance of $126 million. On July 18,
2002, the petitions for reconsideration were granted in part and denied in part
by the PUCN, but no additional disallowances to the deferred energy balance
resulted from that decision. The PUCN's May 28, 2002 decision on SPPC's deferred
energy application is being challenged by SPPC in a lawsuit filed August 22,
2002 in Nevada state court, which is discussed in Note 9, Regulatory Events.
NPC expects to file a deferred energy case on November 14, 2002,
requesting recovery and/or an affirmation of prudency for fuel and purchased
power costs incurred and recorded in its deferred energy account for the period
October 1, 2001 through September 30, 2002. The case includes a reduction for
annual fuel and purchased power revenues of $148 million and recovery of the
deferred energy account balance in the amount of $65 million annually for a
three-year period. The net change will result in an annual revenue decrease of
$83 million representing a 5.6% rate decrease for residential customers and a
5.1% rate decrease for all other classes. The balance for the current deferral
period is approximately $425 million, which includes a balance of $196 million
which NPC is requesting recovery over a three-year period and costs of
approximately $229 million accrued for claims made by terminated suppliers for
which NPC is requesting an affirmation of prudency. (See Note 11, Commitment and
Contingencies.) These amounts are subject to whatever adjustments may be ordered
by the PERC in NPC's Section 206 complaints. (See Note 9, Regulatory Events.)
12
SPPC is required to file its next deferred energy case in approximately
mid-January 2003 and will request recovery and/or an affirmation of prudency for
all costs for fuel and purchased power recorded in its deferred energy account
over the period December 1, 2001, through November 30, 2002. That amount is
expected to approximate $100 million, which includes costs of approximately $82
million accrued for claims made by terminated suppliers. (See Note 11,
Commitments and Contingencies.) These amounts are subject to whatever
adjustments may be ordered by the FERC in SPPC's Section 206 complaints. (See
Note 9, Regulatory Events.)
A significant disallowance in future deferred energy rate cases filed
by either Utility could further weaken the financial condition, liquidity, and
capital resources of SPR, NPC, and SPPC. In particular, such a decision or
decisions could cause further downgrades of debt securities by the rating
agencies, could make it impracticable to access the capital markets, and could
cause additional power suppliers to terminate purchased power contracts and seek
liquidated damages. Under such circumstances, there can be no assurance that
SPR, NPC, or SPPC would be able to remain solvent or continue operations. Under
such circumstances, there also can be no assurance that SPR, NPC, or SPPC would
not seek protection under the bankruptcy laws.
In response to the decisions by the PUCN in NPC's rate cases, SPR
implemented certain measures that management expects will positively impact cash
flow by $125 million in 2002. Two major transmission construction projects,
discussed in the Form 10-K for the year ended December 31, 2001, have been
delayed for a total capital preservation impact of $80.8 million. The delay in
NPC's Centennial Plan has an impact of $46.4 million and the delay of SPPC's
Falcon to Gonder Project has an impact of $34.4 million. An additional $28.9
million was reduced from the Utilities' capital budgets by curtailing or
delaying other projects. Management expects that the balance of the $125 million
cash flow enhancement will be obtained from various land sales. Additional
cost-cutting actions by SPR may be necessary.
On March 29 and April 1, 2002, Standard & Poor's Rating Group, Inc.
(S&P) and Moody's Investors Service, Inc. (Moody's) lowered the unsecured debt
ratings of SPR, NPC and SPPC to below investment grade in response to the
decision of the PUCN with respect to NPC's rate cases. On April 23 and 24, 2002,
the unsecured debt ratings of SPR and the Utilities were further downgraded by
both rating agencies, and the Utilities' secured debt ratings were downgraded to
below investment grade. The downgrades have affected SPR's, NPC's and SPPC's
liquidity primarily in two principal areas: (1) their respective financing
arrangements and (2) NPC's and SPPC's contracts for fuel, for purchase and sale
of electricity and for transportation of natural gas. SPR's ability to make
capital contributions to NPC and SPPC also became severely limited. The PUCN's
May 28, 2002 decision on SPPC's deferred energy application did not result in
any further downgrades of the unsecured debt ratings of SPR, NPC or SPPC.
As a result of the ratings downgrades, SPR's, NPC's, and SPPC's ability
to access the capital markets to raise funds is severely limited. On April 3,
2002, SPR terminated its $75 million unsecured revolving credit facility as a
condition to the banks agreeing to an amendment of NPC's recently terminated
$200 million unsecured revolving credit facility that would permit NPC to draw
down funds under that facility.
In connection with the credit downgrades by S&P and Moody's, the
Utilities lost their A2/P2 commercial paper ratings and can no longer issue
commercial paper. At the time NPC and SPPC had commercial paper balances
outstanding of $198.9 million and $47.7 million, respectively, with weighted
average interest rates of 2.52% and 2.49%, respectively. Since the Utilities
were no longer able to roll over their commercial paper, they paid off their
maturing commercial paper with the proceeds of borrowings under their credit
facilities and terminated their commercial paper programs on May 28, 2002. The
Utilities do not expect to have direct access to the commercial paper market for
the foreseeable future.
With respect to NPC's and SPPC's contracts for purchased power, NPC and
SPPC purchase and sell electricity with counterparties under the Western Systems
Power Pool ("WSPP") agreement, which is an industry standard contract. The WSPP
contract is posted on the WSPP website. These contracts provide that a material
adverse change may give rise to a right to request collateral, which, if not
provided within 3 business days, could cause a default. A default must be
declared within 30 days of the event giving rise to the default becoming known.
A default will result in a termination payment equal to the present value of the
net gains and losses for the entire remaining term of all contracts between the
parties aggregated to a single liquidated amount due within 3 business days
following the date the notice of termination is received. The mark-to-market
value, which is substantially based on quoted market prices, can be used to
roughly approximate the termination payment at any point in time. The
mark-to-market value as of November 1, 2002, for all suppliers continuing to
provide power under a WSPP agreement was approximately $90.1 million and $59.9
million, respectively, for NPC and SPPC.
Following the PUCN decisions, a number of power suppliers requested
collateral from NPC and SPPC. On April 4, 2002, the Utilities sent a letter to
their suppliers advising them that, assuming the Utilities could access the
capital markets for secured debt and no other significant negative developments
occurred, the Utilities expected to be able to honor their obligations under the
power supply contracts. However, the Utilities noted that a simultaneous call
for 100% mark-to-market
13
collateral in the short-term would likely not be met. On April 24, 2002, the
Utilities met with representatives of various suppliers to discuss SPR's and the
Utilities' financial situation and plans, and indicated that they intended to
propose extended payment terms for the above-market portions of NPC's existing
power contracts. Such extended payment terms were proposed to NPC's suppliers in
a letter dated May 2, 2002, and proposed paying less than contract prices, but
more than market prices plus interest, for the period May 1 to September 15,
2002, and NPC paying any balances remaining prior to December 2003. NPC also
agreed to extend the suppliers' rights under the WSPP agreement. As of October
29, 2002, NPC paid all of the outstanding balances owed to its continuing
suppliers.
In early May, Enron Power Marketing Inc. ("Enron"), Morgan Stanley
Capital Group Inc., Reliant Energy Services, Inc. and several smaller suppliers
notified the Utilities that they would end power deliveries to the Utilities
based on what they believed to be their contractual right to end deliveries
because of the Utilities' alleged inability to provide adequate assurances of
their ability to perform all of their outstanding material obligations under the
WSPP agreement. Each of these terminating suppliers has asserted, or has
indicated that it will assert, a claim for liquidated damages. As discussed in
Note 11, Commitments and Contingencies, Enron filed suit in its bankruptcy case
in the Bankruptcy Court for the Southern District of New York seeking
approximately $216 million and $93 million from NPC and SPPC, respectively.
Enron initially filed a motion for partial summary judgment to require the
Utilities to make immediate payment of the full amount of Enron's claim, pending
final resolution of the lawsuit. Enron subsequently filed another motion for
summary judgment seeking final payment of its damages claim. In connection with
this suit, the Utilities filed motions to dismiss and/or to stay all proceedings
pending the final outcome of the Utilities' Section 206 complaints against Enron
and others. (See Note 9, Regulatory Events.) Hearings were conducted in
September, October, and early November 2002. In the event the Utilities' motions
are denied, further hearings will be scheduled on Enron's motion for summary
judgment. An adverse decision on Enron's motion for summary judgment or an
adverse decision in the lawsuit itself would have a material adverse affect on
the financial condition and liquidity of SPR and the Utilities and would render
their ability to continue to operate outside of bankruptcy uncertain. At this
time, SPR and the Utilities are not able to predict the outcome of a decision in
this matter.
On June 10, 2002, Duke Energy Trading and Marketing ("Duke") entered
into an agreement with SPR and the Utilities to supply up to 1,000 megawatts of
electricity per hour, as well as natural gas, to fulfill the Utilities' power
requirements during the peak summer period. The effect of the Duke agreement was
to replace the amount of contracted power and natural gas that would have been
supplied by the various terminating suppliers, including Enron. Duke also agreed
to accept deferred payment for a portion of the amount due under its existing
power contracts with NPC for purchases made through September 15, 2002. Several
other continuing suppliers also entered into formal agreements with NPC
regarding deferred payments, and NPC deferred a portion of the payments to such
suppliers, as well as those suppliers who continued to supply but did not sign
agreements, beginning May 1, 2002 for charges incurred through September 15,
2002. As of October 29, 2002, NPC had paid in full all of the outstanding
delayed payments, approximately $101 million, to all continuing suppliers, and,
by the end of 2003, expects to make all payments determined to be due to
terminating suppliers other than Enron. The approximately $101 million paid in
October, and approximately $39 million accrued for amounts owed to terminating
suppliers, are included in SPR's and NPC's Accounts Payable balance as of
September 30, 2002.
Following the PUCN decisions, SPR and the Utilities were also required
to post cash collateral in connection with the surety bonds carried by their
surety company and the disbursement facilities provided by their bank. These
collateral amounts are classified as "Restricted cash" on the Balance Sheets of
SPR and the Utilities.
SPR has a qualified pension plan (the "Plan") that covers substantially
all employees of SPR, NPC and SPPC. The annual net benefit cost for the Plan is
expected to increase for 2003 by an amount between $12 million and $22 million
over the 2002 cost of $18.4 million. Also, the Plan currently has assets with a
fair value that is less than the present value of the accumulated benefit
obligation under the Plan. While the amount of the deficiency has not yet been
determined, SPR and the Utilities expect their combined minimum funding
requirement for 2002 will be at least $24 million. However, SPR and the
Utilities do not expect that their funding obligation for 2002 will have a
material adverse effect on their liquidity.
SPPC's Washoe County, Nevada, Water Facilities Refunding Revenue
Bonds, Series 2001 in the aggregate principal amount of $80,000,000, will be
subject to remarketing on May 1, 2003. In the event that these bonds cannot be
successfully remarketed on that date, SPPC will be required to purchase the
outstanding bonds at a price of 100% of the principal amount, plus accrued
interest.
SPR has a substantial amount of debt and other obligations including,
but not limited to: $200 million of its unsecured Floating Rate Notes due April
20, 2003; $300 million of its unsecured 8 3/4% Senior Notes due 2005; and $345
million of its unsecured 7.93% Senior Notes due 2007. In connection with the
effects of the disallowance of a significant portion of the Utilities' deferred
purchased power costs by the PUCN as stated above, SPR's credit ratings, along
with those of NPC and SPPC, were downgraded to below investment grade. As a
result of the downgrades, SPR's ability to service its debt obligations and
refinance its maturing debt as it becomes due has become uncertain. In the event
that SPR's financial condition does not improve or becomes worse, it may have to
consider other options including the possibility of seeking protection in a
bankruptcy proceeding.
SPR's future liquidity depends, in part, on SPPC's ability to continue
to pay dividends to SPR, on a restoration of NPC to financial stability
including a restoration of its ability to pay dividends to SPR, both as
discussed in Note 5, Dividend Restrictions, and on SPR's ability to access the
capital markets or otherwise refinance debt that matures in 2003 and thereafter.
Further adverse developments at NPC or SPPC, including a material disallowance
of deferred energy costs in future rate cases
14
or an adverse decision in the pending lawsuit by Enron to collect liquidated
damages (including Enron's motion for partial summary judgment to require the
Utilities to make immediate payment of the full amount of Enron's claim), could
cause SPR to become insolvent and would render SPR's ability to continue to
operate outside of bankruptcy uncertain.
NPC's liquidity would also be significantly affected by an adverse
decision in the pending lawsuit by Enron to collect liquidated damages
(including Enron's motion for partial summary judgment to require the Utilities
to make immediate payment of the full amount of Enron's claim), or by
unfavorable rulings by the PUCN in future NPC or SPPC rate cases. Both S&P and
Moody's have NPC's credit ratings on "watch negative" or "possible downgrade",
and any further downgrades could further preclude NPC's access to the capital
markets, and could adversely affect NPC's ability to continue to purchase power
and fuel. Adverse developments with respect to any one or a combination of the
foregoing could cause NPC to become insolvent and would render NPC's ability to
continue to operate outside of bankruptcy uncertain.
SPPC's future liquidity could be significantly affected by unfavorable
rulings by the PUCN in future SPPC or NPC rate cases. Both S&P and Moody's have
SPPC's credit ratings on "watch negative" or "possible downgrade", and any
further downgrades could further preclude SPPC's access to the capital markets
and could adversely affect SPPC's ability to continue purchasing power and fuel.
Adverse developments with respect to any one or a combination of the factors and
contingencies set forth above could cause SPPC to become insolvent and could
render SPPC's ability to continue to operate outside of bankruptcy uncertain.
The accompanying financial statements do not include any adjustments
that might result from the outcome of the uncertainties discussed above.
OTHER MATTERS
On July 7, 2002, the Board of County Commissioners of Clark County,
Nevada, added an Electric Utility Advisory Question to its November 5, 2002
general election ballot, which asked voters whether "the Nevada Legislature
should take appropriate action to enable the electrical energy provider for
southern Nevada to be a locally controlled, not for profit public utility." NPC
filed a lawsuit seeking to remove the question from the ballot, and the lawsuit
was dismissed. Although the referendum is non-binding, the results of this
advisory question, which was approved by a 57% to 43% vote, may impact future
utility legislation by the Nevada Legislature in its next legislative session
which may, in turn, directly or indirectly affect NPC and its operations.
On August 22, 2002, SPR received a letter from the Southern Nevada
Water Authority ("SNWA") stating that it was prepared to enter into good faith
negotiation of definitive agreements to acquire all of NPC's assets and assume
certain of NPC's existing indebtedness. On September 12, 2002, SPR responded
with a letter stating that it did not view the SNWA's letter as an offer and
expressing concerns with the SNWA's financing plans, certain significant legal
issues with the proposal and the SNWA's lack of utility management experience.
The SNWA has responded by reaffirming its purported offer to acquire NPC.
Also see Note 5, Dividend Restrictions, Note 9, Regulatory Events and
Note 11, Commitments and Contingencies.
RECLASSIFICATIONS
Certain items previously reported for years prior to 2002 have been
reclassified to conform to the current year's presentation. Net income and
shareholders' equity were not affected by these reclassifications.
RECENT PRONOUNCEMENTS
In June 2001, the Financial Accounting Standards Board ("FASB") issued
three new pronouncements, Statement of Financial Accounting Standards (SFAS) No.
141, "Business Combinations," SFAS No. 142, "Goodwill and Other Intangible
Assets," and SFAS No. 143, "Accounting for Asset Retirement Obligations."
SFAS No. 141 requires that the purchase method of accounting be used
for all business combinations initiated after June 30, 2001.
See Note 12, Change in Accounting for Goodwill, for a discussion of
SPR's implementation of SFAS No. 142.
SFAS No. 143, effective for fiscal years beginning after June 15, 2002,
requires an entity to record the fair value of a liability for an asset
retirement obligation in the period in which it is incurred. Management does not
expect the adoption of SFAS No. 143 to have a material effect on the financial
position or results of operations of SPR, NPC, and SPPC.
15
In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB
Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
Corrections". Among other things, this statement rescinds SFAS No. 4, "Reporting
Gains and Losses from Extinguishment of Debt" which required all gains and
losses from extinguishment of debt to be aggregated and, if material, classified
as an extraordinary item, net of related income tax effect. As a result, the
criteria in Accounting Principles Board Opinion No. 30, "Reporting the Results
of Operations - Reporting the Effects of Disposal of a Segment of a Business,
and Extraordinary, Unusual and Infrequently Occurring Events and Transactions,"
will now be used to classify those gains and losses. Adoption of this statement
did not have an impact on the financial position or results of operations of
SPR, NPC or SPPC.
In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities". SFAS No. 146 addresses financial
accounting and reporting for costs associated with exit or disposal activities
and nullifies Emerging Issues Task Force Issue No. 94-3, "Liability Recognition
for Certain Employee Termination Benefits and Other Costs to Exit an Activity
(including Certain Costs Incurred in a Restructuring)". SFAS No. 146 requires
that a liability for a cost associated with an exit or disposal activity be
recognized when the liability is incurred. A fundamental conclusion reached by
the FASB in this statement is that an entity's commitment to a plan, by itself,
does not create a present obligation to others that meets the definition of a
liability. Adoption of this statement did not have an impact on the financial
position or results of operations of SPR, NPC or SPPC.
NOTE 2. FINANCIAL STATEMENTS OF NEVADA POWER COMPANY (NPC)
In accordance with Generally Accepted Accounting Principles, the 1999
merger between SPR and NPC was accounted for as a reverse purchase, with NPC
deemed to be the acquirer of SPR as reflected in the SPR Consolidated Financial
Statements. However, after the merger with SPR and as a result of the structure
of the transactions, NPC is a separate legal entity, which is a wholly owned
subsidiary of SPR. As a legal matter, NPC does not own any equity interest in
SPR. The NPC Financial Statements accommodate the presentation of financial
information of NPC on a stand-alone basis by summarizing all non-NPC financial
information into a few items in each of the Financial Statements. These
summarized items are repeated below (in 000's):
Non-NPC Financial Items in the NPC Financial Statements
NPC Balance Sheets: September 30, 2002 December 31, 2001
- ------------------- ------------------ -----------------
Investment in Sierra Pacific Resources $236,821 $309,259
Equity in Sierra Pacific Resources $236,821 $309,259
The Investment in Sierra Pacific Resources reflects the net assets of
SPR, after deducting for all liabilities and preferred stock of SPR not related
to NPC. The Equity in Sierra Pacific Resources reflects the sum of
paid-in-capital and retained earnings of SPR, without the benefit of NPC.
These line items do not represent any asset to which holders of NPC's
securities may look for recovery of their investment. These items must be
disregarded for determining the ability of NPC to satisfy its obligations or to
pay dividends (preferred or common), for calculating NPC's ratios of earnings to
fixed charges and preferred stock dividends and for all of NPC's financial
covenants and earnings tests including those under its charter and First
Mortgage Indenture.
NPC Statements of Operations: Three Months Ended Three Months Ended
- ----------------------------- ------------------ ------------------
September 30, 2002 September 30, 2001
------------------ ------------------
Equity in Earnings of Sierra Pacific Resources $70 $1,658
Nine Months Ended Nine Months Ended
----------------- -----------------
September 30, 2002 September 30, 2001
------------------ ------------------
Equity in Losses of Sierra Pacific Resources $(51,999) $(5,494)
This line does not represent any item of revenue or income to which
holders of NPC's securities may look for recovery of their investment. This item
must be disregarded for determining the ability of NPC to satisfy its
obligations or its ability to pay dividends (preferred or common), for
calculating NPC's ratios of earnings to fixed charges and preferred dividends
and for all of NPC's financial covenants and earnings tests including those
under its charter and First Mortgage Indenture.
Excluding NPC's equity in the losses/earnings of its parent, SPR, NPC
earned approximately $79.3 million and $78.8 million, respectively, for the
three-month periods ended September 30, 2002, and 2001. Excluding NPC's equity
in the losses of its parent, SPR, NPC incurred a loss of approximately ($216.0)
million for the nine months ended September 30, 2002, and earned approximately
$56.5 million for the nine months ended September 30, 2001.
16
Net Income (Loss) Per Share, Weighted Average Shares of Common Stock
Outstanding, and Dividends Paid Per Share of Common Stock refer to stock share
amounts and dividends paid at SPR.
NPC Statements of Cash Flows: Nine Months Ended Nine Months Ended
- ----------------------------- ----------------- -----------------
September 30, 2002 September 30, 2001
------------------ ------------------
Equity in Losses of Sierra Pacific Resources $51,999 $5,494
As in the statement of operations, the Equity in Losses of Sierra
Pacific Resources reflects the nine months of SPR net losses, after SPPC
preferred stock dividends.
This line item does not represent any item of cash flow to which
holders of NPC's securities may look for recovery of their investment. This item
must be disregarded for determining the ability of NPC to satisfy its
obligations or its ability to pay dividends (preferred or common), for
calculating NPC's ratios of earnings to fixed charges and preferred dividends
and for all of NPC's financial covenants and earnings tests including those
under its charter and First Mortgage Indenture.
NOTE 3. SHORT-TERM BORROWINGS (SPR, NPC, SPPC)
SIERRA PACIFIC RESOURCES
On April 3, 2002, SPR terminated its $75 million unsecured revolving
credit facility in connection with the amendment of NPC's $200 million unsecured
revolving credit facility, discussed below.
NEVADA POWER COMPANY
On November 29, 2001, NPC put into place a $200 million unsecured
revolving credit facility for working capital and general corporate purposes,
including commercial paper backup. As a result of NPC's rate case decisions
(discussed in Note 9 - Regulatory Events) and the credit downgrades by S&P and
Moody's, which occurred on March 29 and April 1, 2002, respectively, the banks
participating in NPC's credit facility determined that a material adverse event
had occurred with respect to NPC, thereby precluding NPC from borrowing funds
under its credit facility. The banks agreed to waive the consequences of the
material adverse event in a waiver letter and amendment that was executed on
April 4, 2002. As required under the waiver letter and amendment, NPC issued and
delivered its General and Refunding Mortgage Bond, Series C, due November 28,
2002, in the principal amount of $200 million, to the Administrative Agent for
the credit facility.
As of September 30, 2002, NPC had borrowed the entire $200 million of
funds available under its credit facility at an average interest rate of 3.72%.
On October 30, 2002, NPC paid in full and terminated its $200 million
credit facility and retired its Series C, General & Refunding Bond which secured
the credit facility with the proceeds from the issuance of NPC's $250 million
aggregate principal amount of 107/8% General and Refunding Notes, Series E, due
2009.
On October 29, 2002, NPC established an accounts receivables purchase
facility of up to $125 million, which was arranged by Lehman Brothers. If NPC
elects to activate the receivables purchase facility, NPC will sell all of its
accounts receivable generated from the sale of electricity to customers to its
newly created bankruptcy remote special purpose subsidiary. The receivables
sales will be without recourse except for breaches of customary representations
and warranties made at the time of sale. The subsidiary will, in turn, sell
these receivables to a bankruptcy-remote subsidiary of SPR. SPR's subsidiary
will issue variable rate revolving notes backed by the purchased receivables.
Lehman Brothers Holdings, Inc. will be the sole initial committed purchaser of
all of the variable rate revolving notes. The agreements relating to the
receivables purchase facility contain various conditions to purchase, covenants
and trigger events, termination events and other provisions customary in
receivables transactions. In connection with NPC's receivables facility, SPR has
agreed to guaranty NPC's performance of certain obligations as a seller and
servicer under the facility.
NPC has agreed to issue $125 million principal amount of its General
and Refunding Mortgage Bonds upon activation of the accounts receivables
purchase facility. The full principal amount of the Bond would secure certain of
NPC's obligations as seller and servicer, plus certain interest, fees and
expenses thereon to the extent not paid when due, regardless of the actual
amounts owing with respect to the secured obligations. As a result, in the event
of an NPC bankruptcy or liquidation, the holder of the Bond securing the
receivables facility may recover more on a pro rata basis than the holders of
other General and Refunding Mortgage securities, who could recover less on a pro
rata basis, than they otherwise would recover. However, in no event will the
holder of the Bond recover more than the amount of obligations secured by the
Bond.
NPC intends to use the accounts receivables purchase facility as a
back-up liquidity facility and does not plan to activate this facility in the
foreseeable future. NPC may activate the facility within five days upon the
delivery of certain customary funding documentation and the delivery of the $125
million General and Refunding Mortgage Bond.
17
NPC is in the process of negotiating a 364-day credit facility of up to
$50 million. The 364-day credit facility will be secured by $50 million
aggregate principal amount of NPC's General and Refunding Mortgage Bonds. The
closing of the 364-day credit facility will be subject to the completion of the
lender's due diligence, the negotiation and finalization of documentation and
other customary closing conditions. Although NPC has commenced negotiations of
the terms of the 364-day credit facility, it cannot give assurances that it will
enter into the credit facility or any similar arrangement.
SIERRA PACIFIC POWER COMPANY
On November 29, 2001, SPPC put into place a $150 million unsecured
revolving credit facility for working capital and general corporate purposes,
including commercial paper backup. Under this credit facility, SPPC was
required, in the event of a ratings downgrade of its senior unsecured debt, to
secure the facility with General and Refunding Mortgage Bonds. In satisfaction
of its obligation to secure the credit facility, on April 8, 2002, SPPC issued
and delivered its General and Refunding Mortgage Bond, Series B, due November
28, 2002, in the principal amount of $150 million, to the Administrative Agent
for the credit facility.
As of September 30, 2002, SPPC had borrowed the entire $150 million of
funds available under its credit facility to, in part, pay off maturing
commercial paper, and to maintain a cash balance at SPPC at an average interest
rate of 3.69%.
On October 31, 2002, SPPC paid off and terminated its $150 million
credit facility and retired its Series B, General & Refunding Bond which secured
the credit facility with a combination of cash on hand and proceeds from its
$100 million Term Loan Facility.
On October 29, 2002, SPPC established an accounts receivables purchase
facility of up to $75 million, which was arranged by Lehman Brothers. If SPPC
elects to activate the receivables purchase facility, SPPC will sell all of its
accounts receivable generated from the sale of electricity to customers to its
newly created bankruptcy remote special purpose subsidiary. The receivables
sales will be without recourse except for breaches of customary representations
and warranties made at the time of sale. The subsidiary will, in turn, sell
these receivables to a bankruptcy-remote subsidiary of SPR. SPR's subsidiary
will issue variable rate revolving notes backed by the purchased receivables.
Lehman Brothers Holdings, Inc. will be the sole initial committed purchaser of
all of the variable rate revolving notes. The agreements relating to the
receivables purchase facility contain various conditions to purchase, covenants
and trigger events, termination events and other provisions customary in
receivables transactions. In connection with SPPC's receivables facility, SPR
has agreed to guaranty SPPC's performance of certain obligations as a seller and
servicer under the facility.
SPPC has agreed to issue $75 million principal amount of its General
and Refunding Mortgage Bonds upon activation of the accounts receivables
purchase facility. The full principal amount of the Bond would secure certain of
SPPC's obligations as seller and servicer, plus certain interest, fees and
expenses thereon to the extent not paid when due, regardless of the actual
amounts owing with respect to the secured obligations. As a result, in the event
of an SPPC bankruptcy or liquidation, the holder of the Bond securing the
receivables facility may recover more on a pro rata basis than the holders of
other General and Refunding Mortgage securities, who could recover less on a pro
rata basis, than they otherwise would recover. However, in no event will the
holder of the Bond recover more than the amount of obligations secured by the
Bond.
SPPC intends to use the accounts receivables purchase facility as a
back-up liquidity facility and does not plan to activate this facility in the
foreseeable future. SPPC may activate the facility within five days upon the
delivery of certain customary funding documentation and the delivery of the $75
million General and Refunding Mortgage Bond.
NOTE 4. LONG-TERM DEBT (SPR, NPC, SPPC)
NPC's, SPPC's and SPR's aggregate annual amount of maturities for
long-term debt for the next five years is shown below (in thousands of dollars):
18
SPR Holding Co. SPR
NPC SPPC and Other Subs. Consolidated
------------ ---------- --------------- ------------
2002 $ 15,000 $ - $ - $ 15,000
2003 350,000 20,400 (1) 200,000 570,400 (1)
2004 130,000 2,400 - 132,400
2005 - 2,400 300,000 302,400
2006 - 51,963 - 51,963
------------ ---------- ------------ ------------
Subtotal 495,000 77,163 500,000 1,072,163
Thereafter 1,126,961 842,337 376,383 2,345,681
------------ ---------- ------------ ------------
Total $ 1,621,961 $ 919,500 $ 876,383 $ 3,417,844
============ ========== ============ ============
(1) In addition to the amounts shown in the table, on May 1, 2003, $80,000,000
aggregate principal amount of the Washoe County, Nevada, Water Facilities
Refunding Revenue Bonds (Sierra Pacific Power Company Project) Series 2001, will
be subject to remarketing. In the event that the Bonds cannot be successfully
remarketed on that date, SPPC will be required to purchase the outstanding Bonds
at a price of 100% of the principal amount, plus accrued interest.
SIERRA PACIFIC RESOURCES
On April 20, 2002, $100 million of SPR's floating rate notes matured
and were paid in full. The notes had been issued on April 20, 2000, and the net
proceeds used to make a capital contribution to NPC.
NEVADA POWER COMPANY
On May 13, 2002, NPC issued a General and Refunding Mortgage Bond,
Series D, due April 15, 2004, in the principal amount of $130 million, for the
benefit of the holders of NPC's 6.20% Senior Unsecured Notes, Series B, due
April 15, 2004. The Senior Unsecured Notes Indenture required that in the event
that NPC issued debt secured by liens on NPC's operating property, in excess of
15% of its Net Tangible Assets or Capitalization (as both terms are defined in
the Senior Unsecured Notes Indenture), NPC would equally and ratably secure the
Senior Unsecured Notes. NPC triggered this negative pledge covenant on April 23,
2002, when it borrowed certain amounts under its secured credit facility.
On October 25, 2002 NPC redeemed its 7 5/8% Series L, First Mortgage
Bonds in the aggregate principal amount of $15 million.
On October 29, 2002, NPC issued and sold $250 million of its 10 7/8%
General and Refunding Mortgage Notes, Series E, due 2009 for a purchase price of
$235.6 million. The Series E Notes were issued with registration rights. The
proceeds of the issuance were used to pay off NPC's $200 million credit facility
and for general corporate purposes. The Series E Notes will mature October 15,
2009.
As discussed in Note 5, Dividend Restrictions, NPC's Series E Notes
limit the amount of dividends that NPC may pay to SPR. The terms of the Series E
Notes also restrict NPC from incurring any additional indebtedness unless (i) at
the time the debt is incurred, the ratio of consolidated cash flow to fixed
charges for NPC's most recently ended four quarter period on a pro forma basis
is at least 2 to 1, or (ii) the debt incurred is specifically permitted, which
includes certain credit facility or letter of credit indebtedness, obligations
incurred to finance property construction or improvement, indebtedness incurred
to refinance existing indebtedness, certain intercompany indebtedness, hedging
obligations, indebtedness incurred to support bid, performance or surety bonds,
and certain letters of credit issued to support NPC's obligations with respect
to energy suppliers.
If NPC's Series E Notes are upgraded to investment grade by both
Moody's and S&P, the dividend restrictions and the restrictions on indebtedness
applicable to the Series E Notes will be suspended and will no longer be in
effect so long as the Series E Notes remain investment grade.
Among other things, the Series E Notes also contain restrictions on
liens (other than permitted liens, which include liens to secure certain
permitted debt) and certain sale and leaseback transactions. In the event of a
change of control of NPC,
19
the holders of Series E Notes are entitled to require that NPC repurchase the
Series E Notes for a cash payment equal to 101% of the aggregate principal
amount plus accrued and unpaid interest.
NPC's first mortgage indenture creates a first priority lien on
substantially all of NPC's properties. As of September 30, 2002, $372.5 million
of NPC's first mortgage bonds were outstanding. Although the first mortgage
indenture allows NPC to issue additional mortgage bonds on the basis of (i) 60%
of net utility property additions and/or (ii) the principal amount of retired
mortgage bonds, NPC agreed in connection with its $250 million 10 7/8% General
and Refunding Mortgage Notes, Series E, due 2009 that it would not issue any
more first mortgage bonds.
NPC's General and Refunding Mortgage Indenture creates a lien on
substantially all of NPC's properties in Nevada that is junior to the lien of
the first mortgage indenture. As of September 30, 2002, $820 million of NPC's
General and Refunding Mortgage securities were outstanding. Additional
securities may be issued under the General and Refunding Mortgage Indenture on
the basis of (1) 70% of net utility property additions, (2) the principal amount
of retired General and Refunding Mortgage bonds, and/or (3) the principal amount
of first mortgage bonds retired after delivery to the indenture trustee of the
initial expert's certificate under the General and Refunding Mortgage Indenture.
As of October 1, 2002, NPC had the capacity to issue approximately $871 million
of additional General and Refunding Mortgage securities, not including the
issuance of $250 million Series E Notes and the retirement of $200 million of
General and Refunding Mortgage Bonds that secured NPC's terminated credit
facility. However, the financial covenants contained in the Series E Notes
limits NPC ability to issue additional General and Refunding Mortgage bonds or
other debt. NPC has reserved $125 million of General and Refunding Mortgage
Bonds for issuance upon the initial funding of NPC's receivables facility and
$50 million of its General and Refunding Mortgage Bonds to secure a proposed
364-day facility, discussed below.
NPC also has the ability to release property from the liens of the two
mortgage indentures on the basis of net property additions, cash and/or retired
bonds. To the extent NPC releases property from the lien of its General and
Refunding Mortgage Indenture, it will reduce the amount of bonds issuable under
that indenture.
SIERRA PACIFIC POWER COMPANY
On October 30, 2002 SPPC entered into a $100 million Term Loan
Agreement with several lenders and Lehman Commercial Paper Inc., as
Administrative Agent. The net proceeds of $97 million from the Term Loan
Facility, along with available cash, were used to pay off SPPC's $150 million
credit facility, which was secured by a Series B General and Refunding Mortgage
Bond.
As discussed in Note 5, Dividend Restrictions, SPPC's Term Loan
Agreement limits the amount of dividends that SPPC may pay to SPR. SPPC's Term
Loan Agreement also requires that SPPC maintain a ratio of consolidated total
debt to consolidated total capitalization at all times during each of the
following quarters in an amount not to exceed (i) .650 to 1.0 for the fiscal
quarters ended December 31, 2002 through December 31, 2003, (ii) .625 to 1.0 for
the fiscal quarters ended March 31, 2004 through December 31, 2004, and (iii)
..600 to 1.0 for the fiscal quarter ended March 31, 2005 and for each fiscal
quarter thereafter. SPPC's Term Loan Agreement also requires that SPPC maintain
a consolidated interest coverage ratio for any four consecutive fiscal quarters
ending with the fiscal quarter set forth below of not less than (i) 1.75 to 1.00
for the fiscal quarters ended December 31, 2002 and March 31, 2003, (ii) 2.50 to
1.0 for the fiscal quarters ended June 30, 2003 through December 31, 2003, (iii)
2.75 to 1.0 for the fiscal quarters ended March 31, 2004 through September 30,
2004, and (iv) 3.00 to 1.0 for the fiscal quarter ended December 31, 2004 and
for each fiscal quarter thereafter. The Term Loan Facility, which is secured by
a $100 million Series C General and Refunding Mortgage Bond, will expire October
31, 2005.
20
On May 23, 2002, SPPC defeased its 2% First Mortgage Bonds due 2011, 5%
Series Y First Mortgage Bonds due 2024, and 2% Series Z First Mortgage Bonds due
2004 by depositing $1.2 million, $3.1 million, and $45,000, respectively, with
its First Mortgage Trustee. These First Mortgage Bonds were issued to secure
loans made to SPPC by the United States under the Rural Electrification Act of
1936, as amended.
SPPC's first mortgage indenture creates a first priority lien on
substantially all of SPPC's properties in Nevada and California. As of September
30, 2002, $505.3 million of SPPC's first mortgage bonds were outstanding.
Although the first mortgage indenture allows SPPC to issue additional mortgage
bonds on the basis of (i) 60% of net utility property additions and/or (ii) the
principal amount of retired mortgage bonds, SPPC agreed in its General and
Refunding Mortgage Indenture that it would not issue any additional first
mortgage bonds.
SPPC's General and Refunding Mortgage Indenture creates a lien on
substantially all of SPPC's properties in Nevada that is junior to the lien of
the first mortgage indenture. As of September 30, 2002, $470 million of SPPC's
General and Refunding Mortgage bonds were outstanding. Additional securities may
be issued under the General and Refunding Mortgage Indenture on the basis of (i)
70% of net utility property additions, (ii) the principal amount of retired
General and Refunding Mortgage bonds, and/or (iii) the principal amount of first
mortgage bonds retired after delivery to the indenture trustee of the initial
expert's certificate under the General and Refunding Mortgage Indenture. At
September 30, 2002, SPPC had the capacity to issue approximately $363 million of
additional General and Refunding Mortgage securities, not including the issuance
of SPPC's $100 million Series C General and Refunding Mortgage Bond which
secures SPPC's Term Loan Facility and the retirement of $150 million of Series B
General and Refunding Mortgage Bonds that secured SPPC's terminated credit
facility. However, the financial covenants contained in SPPC's Term Loan
Agreement and Receivable Purchase Facility Agreements limit SPPC's ability to
issue additional General and Refunding Mortgage Securities or other debt. SPPC
will reserve $75 million of General and Refunding Mortgage Bonds for issuance
upon the initial funding of its receivables purchase facility.
SPPC also has the ability to release property from the liens of the two
mortgage indentures on the basis of net property additions, cash and/or retired
bonds. To the extent SPPC releases property from the lien of its General and
Refunding Mortgage Indenture, it will reduce the amount of bonds issuable under
that indenture.
NOTE 5. DIVIDEND RESTRICTIONS (SPR, NPC, SPPC)
Since SPR is a holding company, substantially all of its cash flow is
provided by dividends paid to SPR by NPC and SPPC on their common stock, all of
which is owned by SPR. NPC and SPPC are public utilities and are subject to
regulation by state utility commissions which may impose limits on investment
returns or otherwise impact the amount of dividends that the Utilities may
declare and pay. In addition, certain agreements entered into by the Utilities
set restrictions on the amount of dividends they may declare and pay and
restrict the circumstances under which such dividends may be declared and paid.
SPPC's charter also contains a dividend restriction for the benefit of SPPC's
preferred stock holders.
Any of the provisions which restrict dividends payable by NPC or SPPC
could adversely affect the liquidity of SPR.
SIERRA PACIFIC RESOURCES
The Master Amendment to Confirmation Agreements with Duke Energy
Trading and Marketing L.L.C. (discussed below) prohibited SPR from using any
amounts received from NPC to pay a dividend or to make any other payment on
account of SPR's common stock until certain deferred payments to Duke were paid
in full and certain energy and gas deliveries had been made and paid for under
the Agreement. As of October 25, 2002, NPC had paid all of the deferred payments
due under this Agreement, and NPC is current on payment for energy and gas
deliveries under the Agreement.
NEVADA POWER COMPANY
The PUCN issued a Compliance Order, Docket No. 02-4037, on June 19,
2002, relating to NPC's request for authority to issue long-term debt. The PUCN
order requires that, until such time as the order's authorization expires
(December 31, 2003), NPC must either receive the prior approval of the PUCN or
reach an equity ratio of 42% before paying any dividends to SPR. If NPC achieves
a 42% equity ratio prior to December 31, 2003, the dividend restriction ceases
to have effect.
In addition, NPC's first mortgage indenture limits the cumulative
amount of dividends that NPC may pay on its capital stock to the cumulative net
earnings of NPC since 1953. At the present time, this restriction precludes NPC
from making further payments of dividends on NPC's common stock and will
continue to bar such payments unless the restriction is waived or removed by the
consent of the first mortgage bondholders, the first mortgage bonds are redeemed
or defeased, or until, over the passage of time, NPC generates sufficient
earnings to overcome the shortfall created by the write-off of $465 million in
connection with the March 2002 decision in NPC's deferred energy rate case.
21
On June 4, 2002, NPC entered into a Master Amendment to Confirmation Agreements
with Duke Energy Trading and Marketing L.L.C., which, among other things,
limited the amount of dividends NPC could declare or pay on its equity
securities until NPC completed certain deferred payments under the Agreement.
Under the Agreement, until the deferred payments were paid in full, NPC could
not declare any dividend or make any dividend payments other than (1) payments
to SPR to enable SPR to pay its reasonable fees and expenses (including interest
on SPR's debts and payment of obligations under SPR's PIES) incurred in the
ordinary course of business in calendar year 2003, up to a maximum amount of
$20,000,000 and (2) any currently scheduled payments to any of NPC's preferred
trust vehicles on account of NPC's preferred trust securities. As of October 25,
2002, NPC had paid all of the deferred payments due under this Agreement.
On June 25, 2002, NPC entered into Amendment No. 2 to its $200 million
credit agreement. The amendment provides that NPC may not declare or pay any
dividend on its capital stock for the duration of the credit facility which
expires on November 28, 2002. This facility was paid off on October 30, 2002
with proceeds from the issuance of the Series E General & Refunding Mortgage
Notes.
On October 29, 2002 NPC issued $250 million 10 7/8% General and
Refunding Mortgage Notes, Series E, due 2009 the terms of which, among other
things, limit the amount of dividends NPC may pay to SPR. However, that
limitation does not apply to payments by NPC to enable SPR to pay its reasonable
fees and expenses (including, but not limited to, interest on SPR's indebtedness
and payment obligations on account of SPR's premium income equity securities)
provided that those payments do not exceed $60 million for any one calendar
year, those payments comply with any regulatory restrictions then applicable to
NPC, and the ratio of consolidated cash flow to fixed charges for NPC's most
recently ended four full fiscal quarters immediately preceding the date of
payment is at least 1.75 to 1. The terms of the Series E Notes also permit
dividend payments to SPR in an aggregate amount not to exceed $15 million from
the date of the issuance of the Notes. In addition, NPC may make dividend
payments to SPR in excess of the amounts described above so long as, at the time
of payment and after giving effect to the payment: there are no defaults or
events of default with respect to the Series E Notes, NPC can meet a Fixed
Charge Coverage Ratio Test, and the total amount of such dividends is less than
(i) the sum of 50% of NPC's Consolidated Net Income measured on a quarterly
basis cumulative of all quarters from the date of issuance of the Series E
Notes, plus (ii) 100% of NPC's aggregate net cash proceeds from the issuance or
sale of certain equity or convertible debt securities of NPC, plus (iii) the
lesser of cash return of capital or the initial amount of certain restricted
investments, plus (iv) the fair market value of NPC's investment in certain
subsidiaries. If NPC's Series E Notes are upgraded to investment grade by both
Moody's and S&P, these dividend restrictions will be suspended and will no
longer be in effect so long as the Series E Notes remain investment grade.
As described in Note 3, Short-Term Borrowings, on October 29, 2002, NPC
established an accounts receivables purchase facility. The agreements relating
to the receivables purchase facility contain various conditions, including a
limitation on the payment of dividends by NPC to SPR that is identical to the
limitation contained in NPC's General and Refunding Mortgage Notes, Series E,
described above.
Finally, the terms of NPC's preferred trust securities provide that no
dividends may be paid on NPC's common stock if NPC has elected to defer payments
on the junior subordinated debentures issued in conjunction with the preferred
trust securities. At this time, NPC has not elected to defer payments on the
junior subordinated debentures.
SIERRA PACIFIC POWER COMPANY
SPPC's Articles of Incorporation contain restrictions on the payment of
dividends on SPPC's common stock in the event of a default in the payment of
dividends on SPPC's preferred stock and prohibit SPPC from declaring or paying
any dividends on any shares of common stock except from the net income of SPPC,
and its predecessor, available for dividends on common stock accumulated
subsequent to December 31, 1955, less preferred stock dividends plus the sum of
$500,000. As of June 30, 2002, SPPC was not prohibited by these restrictions
from paying dividends.
In addition, on June 25, 2002, SPPC entered into Amendment No. 1 to its
$150 million credit agreement. This amendment prohibits the payment of dividends
on SPPC's capital stock if SPPC is in default under the terms of its credit
facility. On October 31, 2002 SPPC paid off this credit agreement with cash and
proceeds from the $100 million term loan.
On October 30, 2002 SPPC entered into a $100 million Term Loan
Agreement with Lehman Commercial Paper Inc., as administrative agent, which
matures October 31, 2005, and which is secured by a $100 million General and
Refunding Bond, Series C, due October 31, 2005. The Term Loan Agreement limits
the amount of dividends that SPPC may pay to SPR. However, that limitation does
not apply to payments by SPPC to enable SPR to pay its reasonable fees and
expenses (including, but not limited to, interest on SPR's indebtedness and
payment obligations on account of SPR's premium income equity securities)
provided that those payments do not exceed $90 million, $80 million and $60
million in the aggregate for the twelve month periods ending on October 30,
2003, 2004 and 2005, respectively. The Term Loan Agreement also permits SPPC to
make dividend payments to SPR in an aggregate amount not to exceed $10 million
during the term of the Term Loan Agreement. In addition, SPPC may make dividend
payments to SPR in
22
excess of the amounts described above so long as, at the time of the payment and
after giving effect to the payment, there are no defaults or events of default
under the Term Loan Agreement, and such amounts, when aggregated with the amount
of dividends paid to SPR by SPPC since the date of execution of the Term Loan
Agreement, does not exceed the sum of (i) 50% of SPPC's Consolidated Net Income
for the period commencing January 1, 2003 and ending with last day of fiscal
quarter most recently completed prior to the date of the contemplated dividend
payment plus (ii) the aggregate amount of cash received by SPPC from SPR as
equity contributions on its common stock during such period.
As described in Note 3, Short-Term Borrowings, on October 29, 2002,
SPPC established an accounts receivables purchase facility. The agreements
relating to the receivables purchase facility contain various conditions,
including a limitation on the payment of dividends by SPPC to SPR that is
identical to the limitation contained in SPPC's Term Loan Agreement, described
above.
23
NOTE 6. EARNINGS PER SHARE (SPR)
SPR follows SFAS No. 128, "Earnings Per Share". The difference, if any,
between Basic EPS and Diluted EPS would be due to common stock equivalent shares
resulting from stock options, employee stock purchase plan, performance shares
and a non-employee director stock plan. Due to net losses for the nine months
ended September 30, 2002, these items are anti-dilutive for that period. Common
stock equivalents were determined using the treasury stock method.
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
---------------------------- -------------------------------
2002 2001 2002 2001
------------- ----------- ------------- ------------
BASIC EPS
Numerator ($000)
Income (Loss) from continuing operations $ 79,374 $ 80,409 $ (266,458) $ 24,098
Income from discontinued operations - - - 1,022
Gain on disposal of water business - - - 25,845
Cumulative effect of change in accounting principle - - (1,566) -
------------- ----------- ------------- ------------
Net income (loss) $ 79,374 $ 80,409 $ (268,024) $ 50,965
============= =========== ============= ============
Denominator
Weighted average number of shares outstanding 102,132,465 90,302,825 102,117,926 82,423,032
------------- ----------- ------------- ------------
Per-Share Amounts:
Income (Loss) from continuing operations $ 0.78 $ 0.89 $ (2.61) $ 0.29
Income from discontinued operations - - - 0.01
Gain on disposal of water business - - - 0.32
Cumulative effect of change in accounting principle - - (0.01) -
------------- ----------- ------------- ------------
Net income (loss) $ 0.78 $ 0.89 $ (2.62) $ 0.62
============= =========== ============= ============
DILUTED EPS
Numerator ($000)
Income (Loss) from continuing operations $ 79,374 $ 80,409 $ (266,458) $ 24,098
Income from discontinued operations - - - 1,022
Gain on disposal of water business - - - 25,845
Cumulative effect of change in accounting principle - - (1,566) -
------------- ----------- ------------- ------------
Net income (loss) $ 79,374 $ 80,409 $ (268,024) $ 50,965
============= =========== ============= ============
Denominator
Weighted average number of shares outstanding
before dilution 102,132,465 90,302,825 102,117,926 82,423,032
Stock options (1) - 31,645 10,537 18,285
Executive long term incentive plan- performance
shares (1) - 71,593 8,918 37,960
Non-Employee Director stock plan (1) 15,148 9,355 11,930 9,355
Employee stock purchase plan (1) - 3,519 1,619 3,185
------------- ----------- ------------- ------------
102,147,613 90,418,937 102,150,930 82,491,817
------------- ----------- ------------- ------------
Per-Share Amounts (1) :
Income (Loss) from continuing operations $ 0.78 $ 0.89 $ (2.61) $ 0.29
Income from discontinued operations - - - 0.01
Gain on disposal of water business - - - 0.32
Cumulative effect of change in accounting principle - - (0.01) -
------------- ----------- ------------- ------------
Net income (loss) $ 0.78 $ 0.89 $ (2.62) $ 0.62
============= =========== ============= ============
(1) Because of a net loss for the nine months ended September 30, 2002, stock
equivalents would be anti-dilutive. Accordingly, Diluted EPS for this period is
computed using the weighted average number of shares outstanding before
dilution.
24
NOTE 7. SEGMENT INFORMATION (SPR)
SPR operates three business segments providing regulated electric and
natural gas services. NPC provides electric service to Las Vegas and surrounding
Clark County. SPPC provides electric service in northern Nevada and the Lake
Tahoe area of California. SPPC also provides natural gas service in the
Reno-Sparks area of Nevada. Other segment information includes segments below
the quantitative threshold for separate disclosure. On June 11, 2001, SPPC sold
its water utility business. Accordingly, the water business is not included in
the segment information below.
Information as to the operations of the different business segments is
set forth below based on the nature of products and services offered. SPR
evaluates performance based on several factors, of which the primary financial
measure is business segment operating income. Intersegment revenues are not
material.
Financial data for business segments is as follows (in thousands):
Three Months Ended NPC SPPC Total
September 30, 2002 Electric Electric Electric Gas Other Consolidated
- --------------------- ------------ ------------ ------------ ----------- ----------- --------------
Operating Revenues $ 712,536 $ 285,023 $ 997,559 $ 18,473 $ 3,987 $ 1,020,019
============ ============ ============ =========== =========== ==============
Operating Income (Loss) $ 109,183 $ 30,252 $ 139,435 $ (231) $ 4,123 $ 143,327
============ ============ ============ =========== =========== ==============
Three Months Ended NPC SPPC Total
September 30, 2001 Electric Electric Electric Gas Other Consolidated
- --------------------- ------------ ------------ ------------ ----------- ----------- --------------
Operating Revenues $ 1,395,496 $ 581,957 $ 1,977,453 $ 18,831 $ 5,650 $ 2,001,934
============ ============ ============ =========== =========== ==============
Operating Income $ 94,767 $ 25,146 $ 119,913 $ 456 $ 1,821 $ 122,190
============ ============ ============ =========== =========== ==============
Nine Months Ended NPC SPPC Total
September 30, 2002 Electric Electric Electric Gas Other Consolidated
- --------------------- ------------ ------------ ------------ ----------- ----------- --------------
Operating Revenues $ 1,545,867 $ 705,946 $ 2,251,813 $ 99,139 $ 8,328 $ 2,359,280
============ ============ ============ =========== =========== ==============
Operating Income (Loss) $ (121,414) $ 35,311 $ (86,103) $ 4,826 $ 13,752 $ (67,525)
============ ============ ============ =========== =========== ==============
Nine Months Ended NPC SPPC Total
September 30, 2001 Electric Electric Electric Gas Other Consolidated
- --------------------- ------------ ------------ ------------ ----------- ----------- --------------
Operating Revenues $ 2,562,949 $ 1,175,228 $ 3,738,177 $ 104,725 $ 13,350 $ 3,856,252
============ ============ ============ =========== =========== ==============
Operating Income (Loss) $ 120,125 $ 49,123 $ 169,248 $ 6,105 $ (5,355) $ 169,998
============ ============ ============ =========== =========== ==============
NOTE 8. DISCONTINUED OPERATIONS (SPR, SPPC)
As previously reported, SPPC closed the sale of its water business to
the Truckee Meadows Water Authority for $341 million on June 11, 2001.
Accordingly, the water business is reported as a discontinued operation for the
nine months ending September 30, 2001. SPPC recorded a $25.8 million gain on the
sale, net of income taxes, for the same period.
Revenues from operations of the water business were $23.2 million for
the nine-month period ended September 30, 2001. The net income from operations
of the water business, as shown in the Condensed Consolidated Statements of
Operations of SPR and SPPC, includes preferred dividends of approximately
$200,000 for the nine-month period ended September 30, 2001. These amounts are
not included in the revenues and income (loss) from continuing operations shown
in the accompanying statements of operations.
NOTE 9. REGULATORY EVENTS (SPR, NPC, SPPC)
NEVADA MATTERS (NPC, SPPC)
NEVADA POWER COMPANY GENERAL RATE CASE (NPC)
On October 1, 2001, NPC filed an application with the PUCN seeking an
electric general rate increase. This application was mandated by Assembly Bill
369 (AB 369). On December 21, 2001, NPC filed a Certification to its general
rate filing updating costs and revenues pursuant to Nevada regulations. In the
certification filing, NPC requested an increase in its general rates charged to
all classes of electric customers designed to produce an increase in annual
electric revenues of
25
$22.7 million, which is an overall 1.7% rate increase. The application also
sought a return on common equity ("ROE") for Nevada Power's total electric
operations of 12.25% and an overall rate of return ("ROR") of 9.30%.
On March 27, 2002, the PUCN issued its decision on the general rate
application, ordering a $43 million revenue decrease with an ROE of 10.1% and
ROR of 8.37%. The effective date for the decision was April 1, 2002. The
decision also resulted in adverse adjustments to depreciation aggregating $7.9
million, and the adverse treatment of approximately $5 million of revenues
related to SO2 Allowances. On April 15, 2002, NPC filed a petition for
reconsideration with the PUCN. In the petition, NPC raised six issues for
reconsideration: the treatment of revenues related to SO2 Allowances, in
particular the calculation of the annual amortization amount, which appears to
be in error; the adjustment for "excess" capital investment related to common
facilities at the Harry Allen generating station; the rejection of adjustments
to accumulated depreciation reserves related to the establishment of revised
depreciation rates for transmission, distribution and common facilities; the
delay in allowing NPC to recover its merger costs without the benefit of
carrying charges; the finding that NPC has no need for and is entitled to zero
funds cash working capital; and the establishment of a 10.1% ROE. On May 24,
2002, the PUCN issued an order on the petition for reconsideration. In its order
the PUCN reaffirmed its findings in the original order for the issues related to
"excess" capital investment at the Harry Allen generating station, merger costs,
cash working capital, and the 10.1% ROE. The PUCN, however, did modify its
original order to include adjustments related to SO2 Allowances and depreciation
issues. Revised rates for these changes went into effect on June 1, 2002.
NEVADA POWER COMPANY DEFERRED ENERGY CASE (NPC)
On November 30, 2001, NPC filed an application with the PUCN seeking to
clear deferred balances for purchased fuel and power costs accumulated between
March 1, 2001 through September 30, 2001, as mandated by AB 369. The application
sought to establish a Deferred Energy Accounting Adjustment ("DEAA") rate to
clear accumulated purchased fuel and power costs of $922 million and spread the
recovery of the deferred costs, together with a carrying charge, over a period
of not more than three years.
On March 29, 2002, the PUCN issued its decision on the deferred energy
application, allowing NPC to recover $478 million over a three-year period, but
disallowing $434 million of deferred purchased fuel and power costs and $10
million in carrying charges. The order states that the disallowance was based on
alleged imprudence in incurring the disallowed costs. On April 11, 2002, NPC
filed a lawsuit in the First District Court of Nevada seeking to reverse
portions of the PUCN's decision. NPC asserts that, as a result of the PUCN's
decision, NPC's credit rating was reduced to below investment grade, SPR
suffered a reduction in its equity market capitalization by approximately 41%,
and the disallowed costs are effectively imposed upon SPR's shareholders.
In its lawsuit, NPC alleges that the order of the PUCN is: in violation
of constitutional and statutory provisions; made upon unlawful procedure;
affected by other error of law; clearly erroneous in view of the reliable,
probative and substantial evidence on the whole record; arbitrary and capricious
and characterized by abuse of discretion. NPC also states that its decisions
with respect to the purchase of power during the energy crisis in the western
United States were made prudently, as required under AB 369. In early 2001, the
PUCN and the Nevada State Legislature expressly required that NPC secure
sufficient, safe and reliable power for anticipated summer loads and needs for
the summer of 2001. Prior to the April 2001 enactment of AB 369, which prohibits
until July 2003 all divestiture of generation assets, NPC was operating under an
order of the PUCN to divest itself of its electric generating plants. To meet
this requirement, NPC had engaged in an open auction process that led to the
signing of asset sale agreements for a number of its plants, in connection with
which, NPC entered into long-term purchase power contracts with the potential
buyers that would have availed NPC of reasonably priced purchase power over a
long-term period. In its petition, NPC challenges the disallowance by the PUCN
of $180 million of its deferred energy costs relating to an informal offer made
by an agent for Merrill Lynch for the delivery of energy from January 2001 to
March 2003. In addition to certain procedural questions relating to the PUCN's
finding with respect to the Merrill Lynch informal offer, NPC asserts that the
energy being negotiated was not firm (uninterruptible), the obligations, costs
and arrangements for delivery in the informal offer were not specified, the cost
of the energy proposed under the informal offer was above then-current market
price, and that the supplier was a minor market participant and the magnitude of
the transaction proposed was more than 45 times its previously combined annual
transactions.
NPC's lawsuit requests that the District Court reverse portions of the
PUCN's order and remand the matter to the PUCN with direction that the PUCN
authorize NPC to immediately establish rates that would allow NPC to recover its
entire deferred energy balance of $922 million, with a carrying charge, over
three years. A hearing on this matter has been scheduled for February 2003. At
this time, NPC is not able to predict the outcome or the timing of a decision in
this matter.
Various interveners in NPC's deferred energy case before the PUCN filed
petitions with the PUCN for reconsideration of the PUCN's order, seeking
additional disallowances of between $12.8 million and $488 million. On May 24,
2002, the PUCN issued an order denying any further disallowances and granted NPC
the authority to increase the deferred energy cost recovery charge for the month
of June 2002 by one cent per kilowatt-hour. This increase accelerated the
recovery of the deferred balance by approximately $16 million for the month of
June 2002 only. The Bureau of Consumer Protection (BCP) of
26
the Nevada Attorney General's Office has since filed a petition in NPC's pending
state court case seeking additional disallowances.
SIERRA PACIFIC POWER COMPANY GENERAL RATE CASE (SPPC)
On November 30, 2001, SPPC filed an application with the PUCN seeking
an electric general rate increase. This application was mandated by AB 369. On
February 28, 2002, SPPC filed a certification to its general rate filing,
updating costs and revenues pursuant to Nevada regulations. In the certification
filing, SPPC requested an increase in its general rates charged to all classes
of electric customers, which were designed to produce an increase in annual
electric revenues of $15.9 million representing an overall 2.4% rate increase.
The application also sought an ROE for SPPC's total electric operations of
12.25% and an overall ROR of 9.42%.
On May 28, 2002, the PUCN issued its decision on the general rate
application, ordering a $15.3 million revenue decrease with an ROE of 10.17% and
ROR of 8.61%. The effective date of the decision was June 1, 2002. Various
parties to the case had filed petitions for reconsideration of the order. On
July 18, 2002, the PUCN issued a final decision on the petitions for
reconsideration, clarifying issues contained its original order. As a result of
the clarifications, SPPC was ordered to change the total annual electric revenue
decrease from $15.3 million to $15.8 million.
On August 19, 2002, Barrick filed a lawsuit in the First District Court
of Nevada seeking to reverse portions of the decision related to the High
Voltage Distribution facilities contained in the general rate case order.
Barrick alleges that the order of the PUCN is: in violation of constitutional
and statutory provisions; in excess of the statutory authority of the PUCN;
affected by error of law: clearly erroneous in view of the reliable, probative
and substantial evidence on the whole record; and arbitrary or capricious or
characterized by abuse of discretion. A hearing date has not yet been scheduled.
At this time, SPPC is not able to predict the outcome or the timing of a
decision in this matter.
SIERRA PACIFIC POWER COMPANY DEFERRED ENERGY (SPPC)
On February 1, 2002, SPPC filed an application with the PUCN seeking to
clear deferred balances for purchased fuel and power costs accumulated between
March 1, 2001 and November 30, 2001. This application was mandated by AB 369.
The application sought to establish a DEAA rate to clear accumulated purchased
fuel and power costs of $205 million and spread the cost recovery over a period
of not more than three years. It also sought to recalculate the Base Tariff
Energy Rate to reflect anticipated ongoing purchased fuel and power costs. The
total rate increase resulting from the requested DEAA would have amounted to
9.8%. Various parties intervened in SPPC's deferred energy rate case including
the Staff of the PUCN, the BCP from the Nevada Attorney General's office, and
Barrick, among others. Interveners proposed disallowances ranging from $40.4
million to $361 million.
On May 28, 2002, the PUCN issued its decision on the deferred energy
application, allowing SPPC three years to collect $150 million but disallowing
$53 million of deferred purchased fuel and power costs and $2 million in
carrying charges. Several of the interveners from SPPC's deferred energy rate
case filed petitions with the PUCN for reconsideration of its decision, seeking
an additional disallowance of $126 million. On July 18, 2002, the petitions for
reconsideration were granted in part and denied in part by the PUCN, but no
additional disallowances to the deferred energy balance resulted from that
decision.
On August 22, 2002, SPPC filed a lawsuit in the First District Court of
Nevada seeking to reverse portions of the decision of the PUCN denying the
recovery of deferred energy costs incurred by SPPC on behalf of its customers in
2001 on the grounds that such power costs were not prudently incurred. In its
lawsuit, SPPC alleges that the order of the PUCN is: in violation of
constitutional and statutory provisions; in excess of the statutory authority of
the PUCN; made upon unlawful procedure; affected by other error of law; clearly
erroneous in view of the reliable, probative and substantial evidence on the
whole record; arbitrary and capricious and characterized by abuse of discretion.
SPPC's lawsuit requests that the District Court reverse portions of the order of
the PUCN and remand the matter to the PUCN with direction that the PUCN
authorize SPPC to immediately establish rates that would allow SPPC to recover
its entire deferred energy balance of $205 million, with a carrying charge, over
three years. A hearing date has not yet been scheduled.
On August 22, 2002, the BCP from the Nevada Attorney General's office
also filed a lawsuit in the First District Court of Nevada seeking to set aside
the decision of the PUCN so that SPPC is not authorized to reflect in rates any
costs for fuel and purchased power which may have been imprudently incurred. A
hearing date has not yet been scheduled. At this time, SPPC is not able to
predict the outcome or the timing of a decision in these matters.
CUSTOMERS FILE UNDER AB 661 (NPC, SPPC)
Assembly Bill 661 (AB 661), passed by the Nevada legislature in 2001,
allows commercial and governmental customers with an average demand greater than
1 MW to select new energy suppliers. The Utilities would continue to provide
27
transmission, distribution, metering and billing services to such customers. AB
661 requires customers wishing to choose a new supplier to receive the approval
of the PUCN and meet public interest standards. In particular, departing
customers must secure new energy resources that are not under contract to the
Utilities, the departure must not burden the Utilities with increased costs or
cause any remaining customers to pay increased costs, and the departing
customers must pay their portion of any deferred energy balances. The PUCN
adopted regulations prescribing the criteria that will be used to determine if
there will be negative impacts to remaining customers or the Utility. These
regulations place certain limits upon the departure of NPC customers until 2003;
most significantly, the amount of load departing is limited to approximately
1100 MW in peak conditions. Customers wishing to choose a new supplier must
provide 180-day notice to the Utilities. AB 661 permitted customers to file
applications with the PUCN beginning in the fourth quarter of 2001, and
customers could begin to receive service from new suppliers by mid-2002.
On January 10, 2002, Barrick, an approximately 130 MW SPPC customer,
filed an application with the PUCN to exit the system of SPPC and to purchase
energy, capacity and ancillary services from a provider other than SPPC. A
stipulation filed on March 8, 2002 by SPPC and Barrick was rejected by the PUCN
on March 29, 2002. The PUCN indicated a desire for more information regarding
transmission access, the definition of a new electric resource, and the
computation of exit fees. Subsequently, a second application was filed and later
withdrawn by Barrick. Barrick has filed a new application with the PUCN. Barrick
could receive service from a new supplier as early as May 1, 2003. A hearing
date on this application has not yet been scheduled.
During May 2002, Rouse Fashion Show Management LLC, Coast Hotels and
Casinos Inc., Station Casinos, Inc., Gordon Gaming Corporation, MGM Mirage, and
Park Place Entertainment filed separate applications with the PUCN to exit the
system of NPC and to purchase energy, capacity and ancillary services from a
provider other than NPC. The loads of these customers aggregate 260 MW on peak.
Hearings on the applications of all the customers except Park Place
Entertainment were completed on July 19, and the PUCN issued its decision on
July 31, 2002. In its decision, the PUCN approved the applications of these
customers to choose an energy supplier other than NPC. The earliest any of these
customers could have begun taking energy from an alternative provider was
November 1, 2002. If all five customers whose applications were approved were to
leave its system, NPC would incur an annual loss in revenue of $48 million,
which would be offset by a reduction in costs, primarily for fuel and purchased
power, of $46 million with the difference being paid by exit fees from the
departing customers. These customers will also be responsible for their share of
balances in NPC's deferred energy accounts until the time they leave and must
continue to pay their share of these balances after they leave. For example, if
all five customers whose applications were approved had left the system on
November 1, 2002, their remaining share of NPC's previously approved deferred
energy balance is estimated to have been $27 million. Additionally, these
departing customers would be responsible for paying their share of the yet to be
approved accumulated deferred energy balances from October 1, 2001 to their date
of departure. They will also remain accountable to any rulings made by the
District Court on legal actions brought in NPC's past deferred energy case. They
could also benefit from any refunds that might be granted on power contracts
under review with the FERC.
A hearing on the application of Park Place Entertainment was held on
August 2, 2002, and on August 12, 2002, the PUCN approved the application with
terms and conditions similar to those described above for the aforementioned
five customers.
All of the customers approved for departure are addressing compliance
items in their PUCN orders. To date, none of these customers has provided
official notice of departure. Other customers are continuing to express an
interest, and additional gaming properties, including Monte Carlo, Riviera, and
Imperial Palace, have indicated intent to potentially procure energy sources
from a new supplier.
Any customer who departs NPC's system and later decides to return to
NPC as their energy provider will be charged for their energy at a rate
equivalent to NPC's incremental cost of service. A stipulation regarding the
incremental cost of service tariff is currently pending before the PUCN.
NEVADA POWER COMPANY ADDITIONAL FINANCE AUTHORITY (NPC)
On April 26, 2002, Nevada Power filed with the PUCN an application
seeking additional finance authority. In the application NPC asked for authority
to issue secured long-term debt in an aggregate amount not to exceed $450
million through the period ending 2003. On June 19, 2002, the PUCN issued a
Compliance Order, Docket No. 02-4037, authorizing NPC to issue $300 million of
long-term debt. The PUCN order requires NPC, if it is able, to issue the $50
million of remaining authorized short-term debt, before it issues any long-term
debt authorized by the order. Moreover, the order provides that, if NPC is able
to issue short-term debt at any point prior to September 1, 2002 (whether or not
the issuance of short-term debt actually occurs), the amount of long-term debt
authorized by the order will be automatically reduced to $250 million. The PUCN
order also provides that NPC will bear the burden of demonstrating that any
financings undertaken pursuant to the order, including any determination made
regarding the length of such commitment, the type of security or rate, is
reasonable. Finally, the order requires that, until such time as the order's
authorization expires (December 31, 2003), NPC must either receive the prior
approval of the PUCN or reach an equity ratio of 42% before paying any dividends
to SPR. If NPC achieves a 42% equity ratio prior to December 31, 2003, the
dividend restriction ceases to have effect.
On July 3, 2002, the Bureau of Consumer Protection of the Nevada
Attorney General's Office filed a petition with the PUCN requesting that the
hearing in Docket No. 02-4037 be reopened to allow for the introduction of
additional evidence or for the PUCN to reconsider its decision granting NPC the
authority to issue long-term debt. On September 11, 2002, the PUCN denied the
petition to reopen the proceeding and rescinded the portion of its Compliance
Order that had previously required NPC to immediately issue $50 million to $100
million of debt.
28
CALIFORNIA MATTERS (SPPC)
RATE STABILIZATION PLAN
SPPC serves approximately 44,500 customers in California. On June 29,
2001, SPPC filed with the California Public Utilities Commission (CPUC) a Rate
Stabilization Plan, which includes two phases. Phase One, which was also filed
June 29, 2001, is an emergency electric rate increase of $10.2 million annually
or 26%. If granted, the typical residential monthly electric bill for a customer
using 650 kilowatt-hours would increase from approximately $47.12 to $60.12. On
August 14, 2001, a pre-hearing conference was held, and a procedural order was
established. On September 27, 2001, the Administrative Law Judge issued an order
stating that no interim or emergency relief could be granted until the end of
the "rate freeze" period mandated by the California restructuring law for
recovery of stranded costs. In accordance with the judge's request, on October
26, 2001, SPPC filed an amendment to its application declaring the rate freeze
period to be over. On December 5 and 11, 2001, hearings were held and on January
11, 2002 and January 25, 2002 opening briefs and reply briefs were filed. On
July 17, 2002, the CPUC approved the requested 2-cent per kilowatt-hour
surcharge, subject to refund and interest pending the outcome of Phase Two. The
increase of $10 million or 26% is applicable to all customers except those
eligible for low-income and medical-needs rates and went into effect July 18,
2002.
Phase Two of the Rate Stabilization Plan was filed with the CPUC on
April 1, 2002, and includes a general rate case and requests the CPUC to
reinstate the Energy Cost Adjustment Clause, which would allow SPPC to file for
periodic rate adjustments to reflect its actual costs for wholesale energy
supplies. Phase Two also includes a proposal to terminate the 10% rate reduction
mandated by AB 1890, but does not include a performance -based rate-making
proposal. This request was for an additional overall increase in revenues of
17.1%, or $8.9 million annually. Hearings are scheduled for February 25 through
March 3, 2003, and a decision by the CPUC is expected in the third quarter of
2003.
CALIFORNIA ASSEMBLY BILL 1235 (SPPC)
On September 24, 2002, the Governor of California signed into law
Assembly Bill 1235 (AB 1235), which allows the transfer of hydroelectric plants
along the Truckee River from SPPC to the Truckee Meadows Water Authority (TMWA).
AB 1235 effectively amends previous California legislation (AB 6X) that
prevented until 2006 private utilities from selling any power plants that
provide energy to California customers. AB 1235 provides an exemption for the
four "run-of-the-river" hydroelectric plants that SPPC sold to TMWA as part of
the sale of its water business in June 2001. AB 1235 was effective September 24,
2002, and the process to transfer the plants from SPPC to TMWA has begun. The
CPUC must now review and approve the transfer of the plants.
FERC MATTERS (SPPC, NPC)
FERC 206 COMPLAINTS
In December 2001, the Utilities filed ten wholesale purchased power
complaints with the FERC under Section 206 of the Federal Power Act seeking
their review of certain forward power purchase contracts that the Utilities
entered into prior to the price caps established by the FERC during the western
United States utility crisis. The Utilities believe the prices under these
purchased power contracts are unjust and unreasonable. The FERC ordered the case
set for hearing and assigned an administrative law judge. A primary issue is
whether or not the dysfunctional short-term market, which was previously
declared by the FERC, impacted the forward market. The Utilities negotiated a
settlement with Duke Energy Trading and Marketing and have engaged in bilateral
settlement discussions with other respondents as well. Written direct and
rebuttal testimony have been filed by the parties that have not negotiated
settlements with the Utilities. Hearings concluded on October 24, 2002, and a
draft decision is expected in December 2002. At this time, the Utilities are not
able to predict the outcome of a decision in this matter.
OPEN ACCESS TRANSMISSION TARIFF
On September 27, 2002, the Utilities filed with the FERC a revised Open
Access Transmission Tariff. The purpose of the filing was to implement changes
that are required to implement retail open access in Nevada. The Utilities have
requested the changes to become effective November 1, 2002, the date retail
access is scheduled to commence in Nevada in accordance with provisions of AB
661, passed in the 2001 session of the Nevada Legislature.
NOTE 10. DERIVATIVES AND HEDGING ACTIVITIES (SPR, NPC, SPPC)
Effective January 1, 2001, SPR, SPPC, and NPC adopted Statement of
Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative
Instruments and Hedging Activities," as amended by SFAS No. 138, both issued by
the Financial Accounting Standards Board. As amended, SFAS No. 133 requires that
an entity recognize all derivatives as either
29
assets or liabilities in the statement of financial position, measure those
instruments at fair value, and recognize changes in the fair value of the
derivative instruments in earnings in the period of change unless the derivative
qualifies as an effective hedge.
SPR's and the Utilities' objective in using derivatives is to reduce
exposure to energy price risk and interest rate risk. Energy price risks result
from activities that include the generation, procurement and marketing of power
and the procurement and marketing of natural gas. Derivative instruments used to
manage energy price risk include forwards, options, and swaps. These contracts
allow the Utilities to reduce the risks associated with volatile electricity and
natural gas markets.
Derivatives used to manage interest rate risk include interest rate
swaps designed to moderate exposure to interest-rate changes and lower the
overall cost of borrowing. On April 1, 2002, SPR paid $9.5 million to terminate
an interest rate swap related to $200 million of SPR floating rate notes
maturing April 20, 2003.
At September 30, 2002, the fair value of the derivatives resulted in
the recording of $74 million, $57 million and $17 million in risk management
assets and $153 million, $64 million and $89 million in risk management
liabilities in the Consolidated Balance Sheets of SPR, NPC and SPPC,
respectively. Due to deferred energy accounting under which the Utilities
operate, regulatory assets and liabilities are established to the extent that
electricity and natural gas derivative gains and losses are recoverable or
payable through future rates. Accordingly, at September 30, 2002, $78 million,
$7 million and $71 million in net risk management regulatory assets were
recorded in the Consolidated Balance Sheets of SPR, NPC, and SPPC, respectively.
In addition, for the nine months ended September 30, 2002, the unrealized gains
and losses resulting from the change in the fair value of derivatives designated
and qualifying as cash flow hedges for SPR, NPC, and SPPC were recorded in Other
Comprehensive Income. Such amounts are reclassified into earnings when the
related transactions are settled or terminate. Accordingly, $1.3 million and
$5.1 million relating to SPR's terminated interest rate swap were reclassified
into earnings during the three- and nine-month periods ended September 30, 2002,
respectively.
The effects of SFAS No. 133 on comprehensive income and the components
thereof at September 30, 2002, and 2001, are as follows (in thousands):
SPR NPC SPPC
------------- ------------- ------------
Net Loss for the nine months ended September 30, 2002 $ (268,024) $ (216,025) (1) $ (12,389)
Change in market value of risk management assets and
liabilities as of September 30, 2002, net of taxes 2,726 (403) (191)
------------- ------------- ------------
Total Comprehensive Loss for the
nine months ended September 30, 2002 $ (265,298) $ (216,428) $ (12,580)
============= ============= ============
Net Income for the nine months ended September 30, 2001 $ 50,965 $ 56,459 (2) $ 36,572
Cumulative effect upon adoption of change in
accounting principle, January 1, 2001, net of taxes (1,923) 444 212
Change in market value of risk management assets and
liabilities as of September 30, 2001, net of taxes (5,048) 230 109
------------- ------------- ------------
Total Comprehensive Income for the
nine months ended September 30, 2001 $ 43,994 $ 57,133 $ 36,893
============= ============= ============
(1) Does not include NPC's equity in SPR's losses of $(51,999).
(2) Does not include NPC's equity in SPR's losses of $(5,494).
NOTE 11. COMMITMENTS AND CONTINGENCIES (SPR, NPC, SPPC)
NEVADA POWER COMPANY AND SIERRA PACIFIC POWER COMPANY
In early May of 2002, Enron Power Marketing Inc. ("Enron"), Morgan
Stanley Capital Group Inc. ("MSCG"), Reliant Energy Services, Inc. and several
smaller suppliers terminated their power deliveries to NPC and SPPC. These
terminating suppliers asserted their contractual right under the WSPP agreement
to terminate deliveries based upon the Utilities' alleged failure to provide
adequate assurances of their performance under the WSPP agreement to any of
their suppliers. Each of these
30
terminating suppliers has asserted, or has indicated that it will assert claims
for liquidated damages against the Utilities under the terminated power supply
contracts.
On June 5, 2002, Enron filed suit in its bankruptcy case in the
Bankruptcy Court for the Southern District of New York asserting claims for
liquidated damages related to the termination of its power supply agreements
with the Utilities of approximately $216 million and $93 million against NPC and
SPPC, respectively. NPC and SPPC have both filed claims in the Bankruptcy Court
alleging, among other things, that NPC and SPPC were fraudulently induced to
enter into the agreements with Enron. Enron's claims are also subject to the
Utilities' defense, as raised in the Utilities' motions to dismiss and or to
stay all proceedings, that such claims are already at issue in the Utilities'
FERC proceeding against Enron and others under Section 206 of the Federal Power
Act challenging the contract prices of the terminated power supply agreements.
Enron initially filed a motion for partial summary judgment to require the
Utilities to make immediate payment of the full amount of Enron's claim, pending
final resolution of the lawsuit. Enron subsequently filed another motion for
summary judgment seeking final payment of its damages claim. Hearings, including
arguments regarding the issue of FERC's primary jurisdiction over the contract
claims, were conducted in September, October, and early November 2002. On
November 14, 2002, the judge is expected to rule on the Utilities' motion to
dismiss or stay until the FERC rules on the Utilities' Section 206 filing. If
the judge decides not to stay Enron's lawsuit pending the outcome of the FERC
hearings, the judge would then schedule additional arguments with respect to
Enron's motion for summary judgment. At this time, the outcome of a decision in
this matter cannot be predicted. An adverse decision on Enron's motion for
summary judgment or an adverse decision in the lawsuit would have a material
adverse affect on the financial condition and liquidity of SPR and the Utilities
and would render their ability to continue to operate outside of bankruptcy
uncertain.
In addition, on September 5, 2002, MSCG filed a Demand for Arbitration
pursuant to the mediation and arbitration procedures of the WSPP agreement
seeking a termination payment from NPC of approximately $25 million under its
terminated power supply agreements with NPC. If this claim is not resolved by
arbitration, NPC expects that MSCG will commence a lawsuit to recover liquidated
damages under the terminated contract.
On September 30, 2002, El Paso Merchant Energy Group ("EPME") notified
NPC that it was terminating all transactions entered into with NPC under the
WSPP agreement. On October 8, 2002, NPC received a letter from EPME seeking a
termination payment of approximately $36 million with respect to the terminated
WSPP agreement transactions. At the present time, NPC disagrees with EPME's
calculation, and expects that net gains and losses relating to the terminated
transactions, including a delayed payment amount of approximately $19 million
owed to EPME for power deliveries through September 15, 2002, will result in a
net payment due to NPC.
In connection with the claims by these energy suppliers, the Utilities
established reserves, included in their Balance Sheets in "Contract termination
reserves," totaling approximately $316 million, and, pursuant to the deferred
energy accounting provisions of AB 369, NPC and SPPC added approximately $229
million and $82 million, respectively, to their deferred energy balances for
recovery in rates in future periods.
NEVADA POWER COMPANY
The Grand Canyon Trust and Sierra Club filed a lawsuit in the U.S.
District Court, District of Nevada, in February 1998, against the owners
(including NPC) of the Mohave Generation Station ("Mohave"), alleging violations
of the Clean Air Act regarding emissions of sulfur dioxide and particulates. An
additional plaintiff, National Parks and Conservation Association, later joined
the suit. The plant owners and plaintiffs have had numerous settlement
discussions and filed a proposed settlement with the court in October 1999. The
consent decree, approved by the court in November 1999, established emission
limits for sulfur dioxide and opacity and required installation of air pollution
controls for sulfur dioxide, nitrogen oxides and particulate matter. The new
emission limits must be met by January 1, 2006 and April 1, 2006 for the first
and second units respectively. The estimated cost of new controls is $395
million. As a 14% owner in the Mohave Station, NPC's cost could be $55 million.
NPC's ownership interest in Mohave comprises approximately 10% of NPC's
peak generation capacity. Southern California Edison (SCE) is the operating
partner of Mohave. On May 17, 2002, SCE filed with the California Public
Utilities Commission (CPUC) an application to address the future disposition of
SCE's share of Mohave. Mohave obtains all of its coal supply from a mine in
northeast Arizona on lands of the Navajo Nation and the Hopi Tribe (the Tribes).
This coal is delivered from the mine to Mohave by means of a coal slurry
pipeline, which requires water that is obtained from groundwater wells located
on lands of the Tribes in the mine vicinity.
Due to the lack of progress in negotiations with the Tribes and other
parties to resolve several coal and water supply issues, SCE's application
states that it appears that it probably will not be possible for SCE to extend
Mohave's operations beyond 2005. Due to the uncertainty over a post-2005 coal
supply, SCE and the other Mohave co-owners have been prevented from starting to
install extensive pollution control equipment that must be put in place if
Mohave's operations are extended past 2005.
NPC is currently evaluating and analyzing all of its options with
regard to the Mohave project.
31
In May 1997, the Nevada Division of Environmental Protection (NDEP)
ordered NPC to submit a plan to eliminate the discharge of Reid Gardner Station
wastewater to groundwater. The NDEP order also required a hydrological
assessment of groundwater impacts in the area. In June 1999, NDEP determined
that wastewater ponds had degraded groundwater quality. In August 1999, NDEP
issued a discharge permit to Reid Gardner Station and an order that requires all
wastewater ponds to be closed or lined with impermeable liners over the next 10
years. This order also required NPC to submit a Site Characterization Plan to
NDEP to ascertain impacts. This plan is under review by NDEP. After approval, an
estimate of remediation costs will be determined by NPC. New pond construction
and lining costs are estimated at $15 million.
At the Reid Gardner Station, the NDEP has determined that there is
additional groundwater contamination that resulted from oil spills at the
facility. NDEP has required submitting a corrective action plan. The extent of
contamination has been determined and remediation is occurring at a modest rate.
A hydro-geologic evaluation of the current remediation was completed and a
vacuum enhanced extraction remediation system will be constructed in the first
quarter of 2003 at an estimated cost of approximately $150,000.
In May 1999, NDEP issued an order to eliminate the discharge of NPC's
Clark Station wastewater to groundwater. The order also required a hydrological
assessment of groundwater impacts in the area. This assessment, submitted to
NDEP in February 2001, warranted a Corrective Action Plan, which was approved in
June 2002. Remediation costs are expected to be approximately $100,000. In
addition to remediation, NPC will spend $789,000 to line existing ponds. After
review and approval of the Corrective Action Plan by NDEP, NPC will implement
remediation.
In July 2000, NPC received a request from the EPA for information to
determine the compliance of certain generation facilities at the Clark Station
with the applicable State Implementation Plan. In November 2000, NPC and the
Clark County Health District entered into a Corrective Action Order requiring,
among other steps, capital expenditures at the Clark Station totaling
approximately $3 million. In March 2001, the EPA issued an additional request
for information that could result in remediation beyond that specified in the
November 2000 Corrective Action Order. If the EPA prevails, capital expenditures
and temporary outages of four of Clark Station's generation units could be
required. Additionally, depending on the time of year that the compliance
activity and corresponding generation outage would occur, the incremental cost
to purchase replacement energy could be substantial.
Nevada Electric Investment Company (NEICO), a wholly owned subsidiary
of NPC, owns property in Wellington, Utah, which was the site of a coal washing
and load out facility. The site now has a reclamation estimate supported by a
bond of $4 million with the Utah Division of Oil and Gas Mining. The property
was under contract for sale and the contract required the purchaser to provide
$1.3 million in escrow towards reclamation. However, the sales contract was
terminated and NEICO took title to the escrow funds. The property is currently
leased with the intention to reclaim coal fines with subsequent reduction to the
reclamation bond.
SIERRA PACIFIC POWER COMPANY
In September 1994, Region VII of EPA notified SPPC that it was being
named as a potentially responsible party (PRP) regarding the past improper
handling of Polychlorinated Biphenyls (PCBs) by PCB Treatment, Inc., located in
Kansas City, Kansas, and Kansas City, Missouri (the Sites). The EPA is
requesting that SPPC voluntarily pay an undefined, pro rata share of the
ultimate clean-up costs at the Sites. A number of the largest PRP's formed a
steering committee, which is chaired by SPPC. The responsibility of the
Committee is to direct clean-up activities, determine appropriate cost
allocation, and pursue actions against recalcitrant parties, if necessary. The
EPA issued an administrative order on consent requiring signatories to perform
certain investigative work at the Sites. The steering committee retained a
consultant to prepare an analysis regarding the Sites. The Site evaluations have
been completed. EPA is developing an allocation formula to allocate the
remediation costs. SPPC has recorded a preliminary liability for the Sites of
$650,000 of which approximately $136,000 has been spent through September 30,
2002. Once evaluations are completed, SPPC will be in a better position to
estimate and record the ultimate liabilities for the Sites.
SIERRA PACIFIC RESOURCES
On September 30, 2002, a lawsuit was filed by two individuals in the
District Court for Clark County, Nevada, on behalf of themselves and all holders
of securities of SPR, against SPR and its directors named individually. The
lawsuit alleges that the defendants violated their fiduciary duties to the
securityholders as a result of SPR's response to letters from the Southern
Nevada Water Authority ("SNWA") in which SNWA stated that it was prepared to
enter into negotiations to acquire NPC's assets and assume certain of NPC's
indebtedness. The lawsuit, which seeks certification as a class action, requests
that the court: (1) declare that the directors have breached their fiduciary
duties, (2) enjoin the defendants to undertake all reasonable efforts to
maximize shareholder value including mandating due consideration of the SNWA
proposal, (3) order the defendants to permit a stockholders' committee to ensure
a fair procedure in connection with any disposition or retention of
32
assets, and (4) if SNWA's purported offer is withdrawn due to the actions or
inactions of the defendants, to award compensatory and/or punitive damages in an
unspecified amount against the defendants. Although SPR and its directors intend
to vigorously defend against the lawsuit, SPR cannot predict the outcome at this
time.
OTHER SUBSIDIARIES OF SPR
LOS, a wholly owned subsidiary of SPR, owns property in North Lake
Tahoe, California, which is leased to independent condominium owners. The
property has both soil and groundwater petroleum contaminate resulting from an
underground fuel tank that has been removed from the property. Additional
contaminate from a third party fuel tank on the property has also been
identified and is undergoing remediation. A closure request is pending Lahontan
Regional Water Quality Control Board approval. Estimated future remediation
costs are not expected to be significant.
In April 2000 Sierra Touch America, LLC, a partnership between Sierra
Pacific Communications (SPC) and Touch America, was formed to construct a fiber
optic line between Salt Lake City, Utah and Sacramento, California. On September
9, 2002, SPC purchased and leased certain telecommunications and fiber optic
assets from Touch America in exchange for SPC's partnership units in Sierra
Touch America and the execution of a $35 million promissory note for a total of
$48.5 million. The assets are currently under construction and are scheduled for
completion in May 2003.
Of the $48.5 million total, $32.5 million relates to the purchase of a
conduit from Sacramento to Salt Lake City, additional conduit in the Reno,
Nevada metropolitan area, and real property in Utah. $16 million of the total
was for the lease of two conduits from Reno to Spanish Fork, Utah and the lease
of 60 strands of fiber from Sacramento to Salt Lake City.
The promissory note accrues interest at 8% per annum. The first of
twelve monthly payments of $3.3 million will commence on July 31, 2003 and
continue until June 30, 2004, at which time all outstanding amounts will be due
and payable. The promissory note is secured by all of SPC's assets, and
prepayments will shorten the length of the loan, but not reduce the installment
payments.
Also, on September 11, 2002, SPC entered into an agreement to sell to a
telecommunications carrier for $20 million the Sacramento to Salt Lake City
conduit acquired from Touch America, and will convey all rights to the conduit
when construction is completed in May 2003.
NOTE 12. CHANGE IN ACCOUNTING FOR GOODWILL (SPR, NPC, SPPC)
SFAS No. 142, adopted January 1, 2002, changed the accounting for
goodwill from an amortization method to one requiring at least an annual review
for impairment. Upon adoption, SPR ceased amortizing goodwill.
SPR's Consolidated Balance Sheet as of September 30, 2002, includes
approximately $325.6 million of goodwill resulting from the July 28, 1999 merger
between SPR and NPC. Approximately $19.6 million of amortization of this
goodwill has been deferred as a regulatory asset. The PUCN stipulation approving
the merger allows for future recovery of this goodwill in rates charged to
customers of SPR's regulated utility subsidiaries, NPC and SPPC, provided that
NPC and SPPC demonstrate that merger savings exceed merger costs. The amount and
timing of the recovery of this goodwill will be determined by the outcome of
general rate cases expected to be filed by the Utilities with the PUCN in late
2003.
SPR's Consolidated Balance Sheet as of December 31, 2001, also included
approximately $6.2 million of goodwill related to unregulated operations. SFAS
No. 142 provides that an impairment loss shall be recognized if the carrying
value of each reporting unit's goodwill exceeds its fair value. For purposes of
testing goodwill for impairment, a discounted cash flow model was used to
determine the fair value of each reporting unit of SPR's unregulated operations.
The reporting units included in SPR's unregulated operations evaluated for
goodwill impairment were Lands of Sierra (LOS), Sierra Pacific Communications
(SPC), Tuscarora Gas Pipeline Company (TGPC), and "Energy" (a reporting unit
consisting of Sierra Energy Company dba e-three, Nevada Electric Investment
Company, and Sierra Pacific Energy Company). As a result of the impairment
testing, which included revenue forecasts and appraisal of assets, SPR recorded
a transitional goodwill impairment charge of approximately $1.7 million ($1.6
million, net of applicable taxes) as a cumulative effect of a change in
accounting principle on SPR's Condensed Consolidated Statements of Operations
for the nine months ended September 30, 2002. The goodwill impairment recognized
by reporting unit was approximately $131,000, $40,000 and $1.5 million for LOS,
SPC and "Energy," respectively. Goodwill assigned to TGPC was determined not to
be impaired.
The changes in the carrying amount of goodwill for the nine-month
period ended September 30, 2002 are as follows:
33
REGULATED UNREGULATED
(IN $000'S) OPERATIONS OPERATIONS TOTAL
-------------- ----------- -------------
Balance as of January 1, 2002 $ 305,982 $ 6,163 $ 312,145
Impairment loss - (1,704) (1,704)
-------------- ------------ -------------
Balance as of September 30, 2002 $ 305,982 $ 4,459 $ 310,441
============== ============ =============
A reconciliation of SPR's previously reported net (losses) income and
(losses) earnings per share to the amounts adjusted for the adoption of SFAS No
142 net of the related income tax effect follows:
(DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
----------------------- -------------------------
2002 2001 2002 2001
--------- --------- ----------- ---------
Net (losses) earnings:
Reported net (loss) earnings $ 79,374 $ 80,409 $ (268,024) $ 50,965
Add back amortization of goodwill, net of
tax - 48 - 144
--------- --------- ----------- ---------
Adjusted net (losses) earnings 79,374 80,457 (268,024) 51,109
Add back cumulative effect of change in
accounting principle, net of tax - - 1,566 -
--------- --------- ----------- ---------
Adjusted (losses) earnings before cumulative effect of
change in accounting principle $ 79,374 $ 80,457 $ (266,458) $ 51,109
========= ========= =========== =========
BASIC AND DILUTED (LOSSES) EARNINGS PER SHARE:
Reported (losses) earnings per share $ 0.89 $ 0.62
Add back amortization of goodwill, net of tax - - - -
--------- --------- ----------- ---------
Adjusted (losses) earnings per share - 0.89 - 0.62
Add back cumulative effect of change in
accounting principle, net of tax - - 0.01 -
--------- --------- ----------- ---------
Adjusted (losses) earnings per share before cumulative
effect of change in accounting principle $ - $ 0.89 $ 0.01 $ 0.62
========= ========= =========== =========
NOTE 13. PINON PINE (SPR, SPPC)
SPPC, through its wholly owned subsidiaries, Pinon Pine Corp., Pinon
Pine Investment Co., and GPSF-B, owns Pinon Pine Company, L.L.C. (the "LLC").
The LLC was formed to take advantage of federal income tax credits associated
with the alternative fuel (syngas) produced by the coal gasifier available under
Section 29 of the Internal Revenue Code. The entire project, which includes an
LLC-owned gasifier and an SPPC-owned power island and post-gasification facility
to partially cool and clean the syngas, is referred to collectively as the Pinon
Pine Power Project ("Pinon Pine"). Construction of Pinon Pine was completed in
June 1998.
Pinon Pine is a project co-funded by the Department of Energy (DOE)
under an agreement between SPPC and DOE that expired December 31, 2000. Through
December 31, 2001, the DOE funded $167 million for construction, operation, and
maintenance of the project. Included in the Consolidated Balance Sheets of SPR
and SPPC is the net book value of the gasifier and related assets, which is
approximately $105 million as of December 31, 2001, of which $50 million is
included in Utility Plant, and $55 million is included in Investments in
subsidiaries and other property.
To date, SPPC has not been successful in obtaining sustained operation
of the gasifier. In 2001 SPPC retained an independent engineering consulting
firm, to complete a comprehensive study of the Pinon Pine gasification plant.
The scope of the study included evaluation of the potential modifications
required to make the facility operational and reliable using several technology
scenarios. The evaluation of each scenario included an estimate of the
additional capital expenditures necessary for reliable operation of the
facility, and the risks associated with that technology.
34
SPPC received a draft report of the study in October 2002. The results
of the study identified a number of potential modifications to the facility each
with varying degrees of technical risk and cost. Modifications considered to
provide the highest probability for successful operation of the facility
generally were also estimated to be the highest cost options. SPPC is reviewing
the various options outlined in the study. If after evaluating the options
presented in the draft report, SPPC decides not to pursue modifications intended
to make the facility operational, SPPC intends to seek recovery, net of salvage,
through regulated rates in its next general rate case based, in part, on the
PUCN's approval of Pinon Pine as a demonstration project in an earlier resource
plan. However, if SPPC is unsuccessful in obtaining recovery, there could be a
material adverse effect on SPPC's and SPR's financial condition and results of
operations.
NOTE 14. SUBSEQUENT EVENTS (SPPC)
On October 29, 2002, SPPC paid a common stock dividend of $25 million
to its parent, SPR.
On November 8, 2002, a dividend of $975,000 ($0.4875 per share) was
declared on SPPC's preferred stock. The dividend is payable on December 1,
2002, to holders of record as of November 22, 2002.
On November 8, 2002, the Board of Directors of SPPC voted to declare a
dividend to SPR of up to $25 million payable on or before February 1, 2003.
35
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
FORWARD-LOOKING STATEMENTS AND RISK FACTORS
The information in this Form 10-Q includes forward-looking statements
within the meaning of the Private Securities Litigation Reform Act of 1995.
These forward-looking statements relate to anticipated financial performance,
management's plans and objectives for future operations, business prospects,
outcome of regulatory proceedings, market conditions and other matters. Words
such as "anticipate," "believe," "estimate," "expect," "intend," "plan" and
"objective" and other similar expressions identify those statements that are
forward-looking. These statements are based on management's beliefs and
assumptions and on information currently available to management. Actual results
could differ materially from those contemplated by the forward-looking
statements. In addition to any assumptions and other factors referred to
specifically in connection with such statements, factors that could cause the
actual results of Sierra Pacific Resources (SPR), Nevada Power Company (NPC), or
Sierra Pacific Power Company (SPPC) to differ materially from those contemplated
in any forward-looking statement include, among others, the following:
(1) unfavorable rulings in rate cases to be filed by NPC and SPPC
(the "Utilities") with the Public Utilities Commission of
Nevada (PUCN), including the periodic applications to recover
costs for fuel and purchased power that have been recorded by
the Utilities in their deferred energy accounts and deferred
natural gas recorded by SPPC for its gas distribution
business;
(2) the outcome of the Utilities' pending lawsuits in Nevada state
court seeking to reverse portions of the PUCN's orders denying
the recovery of deferred energy costs, including the outcome
of petitions filed by the Bureau of Consumer Protection of the
Nevada Attorney General's Office seeking additional
disallowances;
(3) the ability of SPR, NPC and SPPC to access the capital markets
to support their requirements for working capital, including
amounts necessary to finance deferred energy costs,
construction costs and the repayment of maturing debt,
particularly in the event of additional unfavorable rulings by
the PUCN, a further downgrade of the current debt ratings of
SPR, NPC or SPPC and/or adverse developments with respect to
NPC's or SPPC's power and fuel suppliers;
(4) whether suppliers, such as Enron, which have terminated their
power supply contracts with NPC and/or SPPC will be successful
in pursuing their claims against the Utilities for liquidated
damages under their power supply contracts, and whether Enron
will be successful in its lawsuit against NPC and SPPC;
(5) whether SPR, NPC and SPPC will be able to maintain sufficient
stability with respect to their liquidity and relationships
with suppliers to be able to continue to operate outside of
bankruptcy;
(6) whether current suppliers of purchased power, natural gas or
fuel to NPC or SPPC will continue to do business with NPC or
SPPC or will terminate their contracts and seek liquidated
damages from the respective Utility;
(7) whether NPC and SPPC will be able, either through Federal
Energy Regulatory Commission ("FERC") proceedings or
negotiation, to obtain lower prices on their longer-term
purchased power contracts entered into during 2000 and 2001
that are priced above current market prices for electricity;
(8) whether the PUCN will issue favorable orders in a timely
manner to permit the Utilities to borrow money and issue
additional securities to finance the Utilities' operations and
to purchase power and fuel necessary to serve their respective
customers;
(9) whether SPR, NPC, and SPPC will have a significant funding
obligation for 2002 in connection with their currently
underfunded employee pension plan;
(10) whether the Utilities will need to purchase additional power
on the spot market to meet unanticipated power demands (for
example, due to unseasonably hot weather) and whether
suppliers will be willing to sell such power to the Utilities
in light of their weakened financial condition;
(11) wholesale market conditions, including availability of power
on the spot market, which affect the prices the Utilities have
to pay for power as well as the prices at which the Utilities
can sell any excess power;
36
(12) the effect of a non-binding advisory question, which was
included on the ballot in Clark County, Nevada in November
2002 and was approved by a 57% to 43% vote, asking voters
whether "the Nevada Legislature should take appropriate action
to enable the electrical energy provider for southern Nevada
to be a locally controlled, not for profit public utility;"
(13) the outcome of the proposal by the Southern Nevada Water
Authority to enter into negotiations to acquire NPC;
(14) the effect that any future terrorist attacks may have on the
tourism and gaming industries in Nevada, particularly in Las
Vegas, as well as on the economy in general;
(15) the effect of existing or future Nevada, California or federal
legislation or regulations affecting electric industry
restructuring, including laws or regulations which could allow
additional customers to choose new electricity suppliers or
change the conditions under which they may do so;
(16) unseasonable weather and other natural phenomena, which can
have potentially serious impacts on the Utilities' ability to
procure adequate supplies of fuel or purchased power to serve
their respective customers and on the cost of procuring such
supplies;
(17) industrial, commercial and residential growth in the service
territories of the Utilities;
(18) the loss of any significant customers;
(19) changes in the business of major customers, particularly those
engaged in gold mining or gaming, which may result in changes
in the demand for services of the Utilities, including the
effect on the Nevada gaming industry of the opening of
additional Indian gaming establishments in California and
other states;
(20) changes in environmental regulations, tax or accounting
matters or other laws and regulations to which the Utilities
are subject;
(21) future economic conditions, including inflation or deflation
rates and monetary policy;
(22) financial market conditions, including changes in availability
of capital or interest rate fluctuations;
(23) unusual or unanticipated changes in normal business
operations, including unusual maintenance or repairs; and
(24) employee workforce factors, including changes in collective
bargaining unit agreements, strikes or work stoppages.
Other factors and assumptions not identified above may also have been
involved in deriving these forward-looking statements, and the failure of those
other assumptions to be realized, as well as other factors, may also cause
actual results to differ materially from those projected. SPR, NPC and SPPC
assume no obligation to update forward-looking statements to reflect actual
results, changes in assumptions or changes in other factors affecting
forward-looking statements.
CRITICAL ACCOUNTING POLICIES
The following items represent critical accounting policies that under
different conditions or using different assumptions could have a material effect
on the financial condition, liquidity and capital resources of SPR and the
Utilities.
Regulatory Accounting
The Utilities' rates are currently subject to the approval of the PUCN
and are designed to recover the cost of providing generation, transmission and
distribution services. As a result, the Utilities qualify for the application of
Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the
Effects of Certain Types of Regulation", issued by the Financial Accounting
Standards Board (FASB). This statement recognizes that the rate actions of a
regulator can provide reasonable assurance of the existence of an asset and
requires the capitalization of incurred costs that would otherwise be charged to
expense where it is probable that future revenue will be provided to recover
these costs. SFAS No. 71 prescribes the method to be used to record the
financial transactions of a regulated entity. The criteria for applying SFAS No.
71 include the following: (i) rates are set by an independent third party
regulator, (ii) approved rates are intended to recover the specific costs of the
37
regulated products or services, and (iii) rates that are set at levels that will
recover costs can be charged to and collected from customers.
Two of the most significant financial statement effects of regulatory
accounting are deferred energy accounting and accounting for derivatives and
hedging activities, which are discussed below.
Deferred Energy Accounting
On April 18, 2001, the Governor of Nevada signed into law Assembly Bill
369 (AB 369). The provisions of AB 369, which are described in greater detail in
"Regulation and Rate Proceedings," later, include, among others, a reinstatement
of deferred energy accounting for fuel and purchased power costs incurred by
electric utilities. In accordance with the provisions of SFAS No. 71, the
Utilities implemented deferred energy accounting on March 1, 2001, for their
respective electric operations. Under deferred energy accounting, to the extent
actual fuel and purchased power costs exceed fuel and purchased power costs
recoverable through current rates, that excess is not recorded as a current
expense on the statement of operations but rather is deferred and recorded as an
asset on the balance sheet. Conversely, a liability is recorded to the extent
fuel and purchased power costs recoverable through current rates exceed actual
fuel and purchased power costs. These excess amounts are reflected in
adjustments to rates and recorded as revenue or expense in future time periods,
subject to PUCN review. AB 369 provides that the PUCN may not allow the recovery
of any costs for purchased fuel or purchased power "that were the result of any
practice or transaction that was undertaken, managed or performed imprudently by
the electric utility." In reference to deferred energy accounting, AB 369
specifies that fuel and purchased power costs include all costs incurred to
purchase fuel, to purchase capacity, and to purchase energy. The Utilities also
record, and are eligible under the statute to recover, a carrying charge on such
deferred balances.
As described in more detail under "Regulatory Matters - Nevada Matters
- - Nevada Power Company Deferred Energy Case" below, on November 30, 2001, NPC
filed an application with the PUCN seeking to clear deferred balances for
purchased fuel and power costs accumulated between March 1, 2001 and September
30, 2001. The application sought to establish a rate to clear accumulated
purchased fuel and power costs of $922 million and spread the cost recovery over
a period of not more than three years. On March 29, 2002, the PUCN issued its
decision on the deferred energy application, disallowing $434 million of
deferred purchased fuel and power costs and $10 million in carrying charges, and
allowing NPC to collect the remaining $478 million over three years beginning
April 1, 2002. As a result of this disallowance, NPC wrote off $465 million of
deferred energy costs and related carrying charges, the two major national
rating agencies immediately downgraded the credit rating on SPR's, NPC's and
SPPC's debt securities (followed by further downgrades late in April), and the
market price of SPR's common stock fell substantially.
As described in more detail under "Regulatory Matters - Nevada Matters
- - Sierra Pacific Power Company Deferred Energy Case" below, SPPC filed an
application with the PUCN seeking to clear its deferred balances for purchased
fuel and power costs accumulated between March 1, 2001 and November 30, 2001.
The application sought to establish a rate to clear accumulated purchased fuel
and power costs of $205 million and spread the cost recovery over a period of
not more than three years. On May 28, 2002, the PUCN issued its decision on
SPPC's deferred energy application, disallowing $53 million of deferred
purchased fuel and power costs and $2 million in carrying charges, and allowing
SPPC to collect the remaining $150 million over three years beginning June 1,
2002. As a result of this decision, SPPC wrote off $55 million of disallowed
deferred energy costs and related carrying charges.
Both Utilities have continued to be entitled under AB 369 to utilize
deferred energy accounting for their electric operations. Because of contracts
entered into during the Western energy crisis in 2001 to assure adequate
supplies of electricity for their customers, the Utilities have continued to
incur fuel and purchased power costs in excess of amounts they are permitted to
recover in current rates. As a result, during the nine months ended September
30, 2002, both Utilities continued to record additional amounts in their
deferral of energy costs accounts. If not for deferred energy accounting during
the first nine months of 2002, SPR's, NPC's and SPPC's results of operations,
financial condition, liquidity and capital resources would have been adversely
affected. For example, without the deferred energy accounting provisions of AB
369, the reported net losses of SPR, NPC, and SPPC for the nine months ended
September 30, 2002 of ($268.0) million, ($216.0) million(1), and ($12.4) million
would have been (net of income tax) reported as net losses of ($469.0) million,
($370.8) million(1), and ($58.6) million, respectively. Similarly, the reported
net income of SPR, NPC, and SPPC for the quarter ended September 30, 2002 of
$79.4 million, $79.3 million(1), and $12.6 million would have been (net of
income tax) reported as net income of $52.4 million, $51.2 million(1), and $13.7
million, respectively. A significant disallowance by the PUCN of costs currently
deferred could have a material adverse affect on the future financial position,
results of operations, and liquidity of
- ----------------------------
(1) Excludes equity in losses of SPR
38
SPR, NPC and SPPC. See the Form 10-K for the year ended December 31, 2001 for a
more detailed discussion of deferred energy accounting.
Accounting for Derivatives and Hedging Activities
Effective January 1, 2001, SPR, SPPC, and NPC adopted SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities," as amended by
SFAS No. 138. As amended, SFAS No. 133 requires that an entity recognize all
derivative instruments as either assets or liabilities in the statement of
financial position and measure the instruments at fair value.
In order to manage loads, resources and energy price risk, the
Utilities buy fuel and power under forward contracts. In addition to forward
fuel and power purchase contracts, the Utilities also use options and swaps to
manage price risk. All of these instruments are considered to be derivatives
under SFAS No. 133. The risk management assets and liabilities recorded in the
balance sheets of the Utilities and SPR are primarily comprised of the fair
value of these forward fuel and power purchase contracts and other energy
related derivative instruments.
Fuel and purchased power costs are subject to deferred energy
accounting. Accordingly, the energy related risk management assets and
liabilities and the corresponding unrealized gains and losses (changes in fair
value) are offset with a regulatory asset or liability rather than recognized in
the statements of income and comprehensive income. Upon settlement of a
derivative instrument, actual fuel and purchased power costs are recognized if
they are currently recoverable or deferred if they are recoverable or payable
through future rates.
The fair values of the forward contracts and swaps are determined based
on quotes obtained from independent brokers and exchanges. The fair values of
options are determined using a pricing model which incorporates assumptions such
as the underlying commodity's forward price curve, time to expiration, strike
price, interest rates, and volatility. The use of different assumptions and
variables in the model could have a significant impact on the valuation of the
instruments.
SPR and the Utilities have other non-energy related derivative
instruments such as interest rate swaps. The transition adjustment resulting
from the adoption of SFAS No. 133 related to these types of derivative
instruments was reported as the cumulative effect of a change in accounting
principle in Other Comprehensive Income. Additionally, the changes in fair
values of these non-energy related derivatives are also reported in Other
comprehensive income until the related transactions are settled or terminate, at
which time the amounts are reclassified into earnings. On April 1, 2002, SPR
paid $9.5 million to terminate an interest rate swap of which $1.3 million and
$5.1 million, respectively, were reclassified into earnings during the three-
and nine-month periods ended September 30, 2002. No other amounts were
reclassified into earnings during the three- and nine-month periods ended
September 30, 2002 and 2001.
See Note 22 of "Notes to Financial Statements" in the Form 10-K for the
year ended December 31, 2001, and Note 10 of "Notes to Condensed Consolidated
Financial Statements" and "Item 3 - Quantitative and Qualitative Disclosures
about Market Risk" in this Report for additional information regarding
derivatives and hedging activities.
Provision for Uncollectible Accounts
The Utilities reserve for doubtful accounts based on past experience
writing off uncollectible customer accounts. The collapse of the energy markets
in California, and the subsequent bankruptcy of the California Power Exchange
and the financial difficulties of the Independent System Operator, resulted in
the Utilities reserving for outstanding receivables for power purchases by these
two entities of $19.9 million and $1.5 million (before taxes) for NPC and SPPC,
respectively, for 2001. The weakening economy and the disruption to the leisure
travel industry after September 11th also impacted the Utilities' customer
delinquencies in 2001. As of December 31, 2001, additional amounts of $14.8
million and $6.1 million were reserved for delinquent retail customer accounts
of NPC and SPPC, respectively. During the nine months ended September 30, 2002,
$6.4 million and $2.1 million were added to the provisions for uncollectible
retail customer accounts of NPC and SPPC, respectively. The adequacy of these
reserves will vary to the extent that future collections differ from past
experience. Uncollectible retail customer accounts amounting to $4.1 million and
$3.3 million, respectively, for NPC and SPPC, were written off against these
provisions during the nine months ended September 30, 2002. Significant
collection efforts are underway to recover portions of the rest of the
delinquent accounts.
MAJOR FACTORS AFFECTING RESULTS OF OPERATIONS
As discussed in the results of operations sections that follow,
operating results for the nine months ended September 30, 2002 were severely
affected by the PUCN's March 29, 2002 decision in NPC's deferred energy rate
case to disallow $434 million of deferred purchased fuel and power costs. As a
result of this disallowance, NPC wrote off $465 million of deferred energy costs
and related carrying charges during that quarter. In addition, the decision of
the PUCN on May 28, 2002 on SPPC's deferred energy application to disallow $53.1
million of deferred purchased fuel and power costs accumulated
39
between March 1, 2001 and November 30, 2001 had a significant negative impact on
the results of operations of SPR and SPPC for the quarter and the nine-month
period ended September 30, 2002. As a result of this disallowance, SPPC wrote
off $55.1 million of deferred energy costs and related carrying charges during
that quarter. The discussion below provides the context in which these decisions
were made.
In an effort to mitigate the effects of higher fuel and purchased power
costs that developed in the Western United States in 2000,the Utilities entered
into the Global Settlement with the PUCN in July 2000, which established a
mechanism that initiated incremental rate increases for each Utility. Cumulative
electric rate increases under the Global Settlement were $127 million and $65
million per year for NPC and SPPC, respectively.
However, because the rate adjustment mechanism of the Global Settlement
was subject to certain caps and could not keep pace with the continued
escalation of fuel and purchased power prices, on January 29, 2001, the
Utilities filed a Comprehensive Energy Plan (CEP) with the PUCN. The CEP
included a request for emergency rate increases (CEP Riders). On March 1, 2001,
the PUCN permitted the requested CEP Riders to go into effect subject to later
review. The CEP Riders provided further rate increases of $210 million and $104
million per year, respectively, for NPC and SPPC.
Notwithstanding the increases under the Global Settlement and the CEP
Riders, the Utilities' revenues for fuel and purchased power recovery continued
to be less than the related expenses. Accordingly, the Utilities sought
additional relief pursuant to legislation.
On April 18, 2001, the Governor of Nevada signed into law AB 369. The
provisions of AB 369 include a moratorium on the sale of generation assets by
electric utilities until 2003, the repeal of electric industry restructuring,
and, beginning March 1, 2001, a reinstatement of deferred energy accounting for
fuel and purchased power costs incurred by electric utilities. The stated
purposes of this emergency legislation included, among others, to control
volatility in the price of electricity in the retail market in Nevada and to
ensure that the Utilities have the necessary financial resources to provide
adequate and reliable electric service under present market conditions.
As discussed above in "Critical Accounting Policies," deferred energy
accounting allows the Utilities an opportunity to recover in future periods that
portion of their costs for fuel and purchased power not covered by current rates
and defers to future periods the expense associated with the amounts by which
fuel and purchased power costs exceed the costs to be recovered in current
rates. Recovery is subject to PUCN review as to prudency and other matters.
AB 369 requires each Utility to file general rate applications and
deferred energy applications with the PUCN by specific dates. NPC's deferred
energy application, filed on November 30, 2001, sought to establish a Deferred
Energy Accounting Adjustment ("DEAA") rate, effective on April 1, 2002, to clear
accumulated purchased fuel and power costs of $922 million and spread the cost
recovery over a period of not more than three years, resulting in an average net
increase of 21%. SPPC's deferred energy application, filed on February 1, 2002,
sought to establish a DEAA rate to clear accumulated purchased fuel and power
costs of $205 million and spread the cost recovery over a period of not more
than three years, resulting in an average net increase of 9.8%. See "Regulatory
Matters," later, for a discussion of the Utilities' general rate case filings
and decisions.
The March 29, 2002 decision of the PUCN on NPC's deferred energy
application to disallow $434 million of deferred purchased fuel and power costs
accumulated between March 1, 2001 and September 30, 2001 had a significant
negative impact on the results of operations of SPR and NPC for the nine months
ended September 30, 2002. Several of the intervenors from NPC's deferred energy
rate case filed petitions with the PUCN for reconsideration of its decision,
seeking additional disallowances ranging from $12.8 million to $488 million. The
petitions for reconsideration were granted in part and denied in part by the
PUCN on May 24, 2002, but no additional disallowances to the deferred energy
balance resulted from that decision. The Bureau of Consumer Protection (BCP) of
the Nevada Attorney General's Office has since filed a petition in NPC's pending
state court case seeking additional disallowances. Although the PUCN's March 29,
2002 decision on NPC's deferred energy application is being challenged by NPC in
a lawsuit filed in Nevada state court, which is discussed below under
"Regulatory Matters", the decision caused the two major national rating agencies
to issue an immediate downgrade of the credit ratings on SPR's, NPC's and SPPC's
debt securities (followed by further downgrades late in April). Following those
events, the market price of SPR's common stock fell substantially, NPC and SPPC
were obliged within 5 business days of the downgrades to issue general and
refunding mortgage bonds to secure their bank lines of credit, NPC was obliged
to obtain a waiver and amendment from its credit facility banks before it was
permitted to draw down on the facility, NPC and SPPC were no longer able to
issue commercial paper, a number of NPC's power suppliers contacted NPC
regarding its ability to pay the purchase price of outstanding contracts, and
several power suppliers, including a subsidiary of Enron Corp., terminated their
power supply agreements with one or both of the Utilities.
The separate decision of the PUCN on May 28, 2002 on SPPC's deferred
energy application to disallow $53.1 million of deferred purchased fuel and
power costs accumulated between March 1, 2001 and November 30, 2001 had a
significant negative impact on the results of operations of SPR and SPPC for the
quarter and the nine months ended September 30, 2002.
40
Several of the intervenors from SPPC's deferred energy rate case filed petitions
with the PUCN for reconsideration of its decision, seeking an additional
disallowance of $126 million. On July 18, 2002, the petitions for
reconsideration were granted in part and denied in part by the PUCN, but no
additional disallowances to the deferred energy balance resulted from that
decision. The PUCN's May 28, 2002 decision on SPPC's deferred energy application
is being challenged by SPPC in a lawsuit filed August 22, 2002 in Nevada state
court, which is discussed below under "Regulatory Matters". The BCP of the
Nevada Attorney General's Office has since filed a petition in SPPC's state
action seeking additional disallowances.
A significant disallowance in future deferred energy rate cases filed
by either Utility could further weaken the financial condition, liquidity, and
capital resources of SPR, NPC, and SPPC. In particular, such a decision or
decisions could cause further downgrades of debt securities by the rating
agencies, could make it impracticable to access the capital markets, and could
cause additional power suppliers to terminate purchased power contracts and seek
liquidated damages. Under such circumstances, there can be no assurance that
SPR, NPC, or SPPC would be able to remain solvent or continue operations. Under
such circumstances, there also can be no assurance that SPR, NPC, or SPPC would
not seek protection under the bankruptcy laws.
SIERRA PACIFIC RESOURCES
During the first nine months of 2002, SPR incurred a loss of $265.1
million before preferred stock dividend requirements, and paid $20.6 million in
common stock dividends on March 15, 2002. NPC declared and paid a common stock
dividend of $10 million to its parent, SPR, in the first quarter of 2002. SPPC
declared and paid common stock dividends of $10 million and $9.9 million to its
parent, SPR, in the first and second quarter of 2002, respectively. SPPC also
paid $2.9 million in dividends to holders of its preferred stock during the
first nine months of 2002. NPC and SPPC each received a capital contribution of
$10 million from SPR in March 2002.
On July 7, 2002, the Board of County Commissioners of Clark County,
Nevada, added an Electric Utility Advisory Question to its November 5, 2002
general election ballot, which asked voters whether "the Nevada Legislature
should take appropriate action to enable the electrical energy provider for
southern Nevada to be a locally controlled, not for profit public utility." NPC
filed a lawsuit seeking to remove the question from the ballot, and the lawsuit
was dismissed. Although the referendum is non-binding, the results of this
advisory question, which was approved by a 57% to 43% vote, may impact future
utility legislation by the Nevada Legislature in its next legislative session
which may, in turn, directly or indirectly affect NPC and its operations.
On August 22, 2002, SPR received a letter from the Southern Nevada
Water Authority ("SNWA") stating that it was prepared to enter into good faith
negotiation of definitive agreements to acquire all of NPC's assets and assume
certain of NPC's existing indebtedness. On September 12, 2002, SPR responded
with a letter stating that it did not view the SNWA's letter as an offer and
expressing concerns with the SNWA's financing plans, certain significant legal
issues with the proposal and the SNWA's lack of utility management experience.
The SNWA has responded by reaffirming its purported offer to acquire NPC.
On September 30, 2002, a lawsuit was filed by two individuals in the
District Court for Clark County, Nevada, on behalf of themselves and all holders
of securities of SPR, against SPR and its directors named individually. The
lawsuit alleges that the defendants violated their fiduciary duties to the
securityholders as a result of SPR's response to letters from the SNWA in which
SNWA stated that it was prepared to enter into negotiations to acquire NPC's
assets and assume certain of NPC's indebtedness. The lawsuit, which seeks
certification as a class action, requests that the court: (1) declare that the
directors have breached their fiduciary duties, (2) enjoin the defendants to
undertake all reasonable efforts to maximize shareholder value including
mandating due consideration of the SNWA proposal, (3) order the defendants to
permit a stockholders' committee to ensure a fair procedure in connection with
any disposition or retention of assets, and (4) if SNWA's purported offer is
withdrawn due to the actions or inactions of the defendants, to award
compensatory and/or punitive damages in an unspecified amount against the
defendants. Although SPR and its directors intend to vigorously defend against
the lawsuit, SPR cannot predict the outcome at this time.
FINANCIAL CONDITION, LIQUIDITY AND CAPITAL RESOURCES
SPR, on a stand-alone basis, had cash and cash equivalents of
approximately $5.6 million at September 30, 2002, and approximately $32.7
million at October 31, 2002.
Since SPR is a holding company, substantially all of its cash flow is
provided by dividends paid to SPR by NPC and SPPC on their common stock, all of
which is owned by SPR. Since NPC and SPPC are public utilities, they are subject
to regulation by state utility commissions which may impose limits on investment
returns or otherwise impact the amount of dividends that the Utilities may
declare and pay. In addition, certain agreements entered into by the Utilities
set restrictions on the amount of dividends they may declare and pay and
restrict the circumstances under which such dividends
41
may be declared and paid. The specific restrictions on dividends contained in
agreements to which NPC and SPPC are party, as well as specific regulatory
limitations on dividends, are summarized below.
- NPC's first mortgage indenture limits the cumulative amount of
dividends that NPC may pay on its capital stock to the cumulative net
earnings of NPC since 1953. At the present time, this restriction
precludes NPC from making further payments of dividends on NPC's common
stock and will continue to bar such payments unless the restriction is
waived, amended, or removed by the consent of the first mortgage
bondholders, the first mortgage bonds are redeemed or defeased, or
until, over the passage of time, NPC generates sufficient earnings to
overcome the shortfall created by the write-off of $465 million in
connection with the March 2002 decision in NPC's deferred energy rate
case.
- NPC's 10 7/8% General and Refunding Mortgage Notes, Series E, due 2009
limit the amount of dividends that NPC may pay to SPR. However, that
limitation does not apply to payments by NPC to enable SPR to pay its
reasonable fees and expenses (including, but not limited to, interest
on SPR's indebtedness and payment obligations on account of SPR's
premium income equity securities) provided that those payments do not
exceed $60 million for any one calendar year, those payments comply
with any regulatory restrictions then applicable to NPC, and the ratio
of consolidated cash flow to fixed charges for NPC's most recently
ended four full fiscal quarters immediately preceding the date of
payment is at least 1.75 to 1. The terms of the Series E Notes also
permit dividend payments to SPR in an aggregate amount not to exceed
$15 million from the date of the issuance of the Notes. In addition,
NPC may make dividend payments to SPR in excess of the amounts
described above so long as, at the time of payment and after giving
effect to the payment: there are no defaults or events of default with
respect to the Series E Notes, NPC can meet a fixed charge coverage
ratio test, and the total amount of such dividends is less than (i) the
sum of 50% of NPC's consolidated net income measured on a quarterly
basis cumulative of all quarters from the date of issuance of the
Series E Notes, plus (ii) 100% of NPC's aggregate net cash proceeds
from the issuance or sale of certain equity or convertible debt
securities of NPC, plus (iii) the lesser of cash return of capital or
the initial amount of certain restricted investments, plus (iv) the
fair market value of NPC's investment in certain subsidiaries. If NPC's
Series E Notes are upgraded to investment grade by both Moody's
Investors Service, Inc. (Moody's) and Standard & Poor's Rating Group,
Inc. (S&P), these dividend restrictions will be suspended and will no
longer be in effect so long as the Series E Notes remain investment
grade.
- On October 29, 2002, NPC established an accounts receivables purchase
facility. The agreements relating to the receivables purchase facility
contain various conditions, including a limitation on the payment of
dividends by NPC to SPR that is identical to the limitation contained
in NPC's General and Refunding Mortgage Notes, Series E, described
above.
- The PUCN issued a Compliance Order, Docket No. 02-4037, on June 19,
2002, relating to NPC's request for authority to issue long-term debt.
The PUCN order requires that, until such time as the order's
authorization expires (December 31, 2003), NPC must either receive the
prior approval of the PUCN or reach an equity ratio of 42% before
paying any dividends to SPR. If NPC achieves a 42% equity ratio prior
to December 31, 2003, the dividend restriction ceases to have effect.
- The terms of NPC's preferred trust securities provide that no dividends
may be paid on NPC's common stock if NPC has elected to defer payments
on the junior subordinated debentures issued in conjunction with the
preferred trust securities. At this time, NPC has not elected to defer
payments on the junior subordinated debentures.
- SPPC's Term Loan Agreement limits the amount of dividends that SPPC may
pay to SPR. However, that limitation does not apply to payments by SPPC
to enable SPR to pay its reasonable fees and expenses (including, but
not limited to, interest on SPR's indebtedness and payment obligations
on account of SPR's premium income equity securities) provided that
those payments do not exceed $90 million, $80 million and $60 million
in the aggregate for the twelve month periods ending on October 30,
2003, 2004 and 2005, respectively. The Term Loan Agreement also permits
SPPC to make dividend payments to SPR in an aggregate amount not to
exceed $10 million during the term of the Term Loan Agreement. In
addition, SPPC may make dividend payments to SPR in excess of the
amounts described above so long as, at the time of the payment and
after giving effect to the payment, there are no defaults or events of
default under the Term Loan Agreement, and such amounts, when
aggregated with the amount of dividends paid to SPR by SPPC since the
date of execution of the Term Loan Agreement, does not exceed the sum
of (i) 50% of SPPC's Consolidated Net Income for the period commencing
January 1, 2003 and ending with last day of fiscal quarter most
recently completed prior to the date of the contemplated dividend
payment plus (ii) the aggregate amount of cash received by SPPC from
SPR as equity contributions on its common stock during such period.
- On October 29, 2002, SPPC established an accounts receivables purchase
facility. The agreements relating to the receivables purchase facility
contain various conditions, including a limitation on the payment of
dividends by SPPC to SPR that is identical to the limitation contained
in SPPC's Term Loan Agreement, described above.
- SPPC's Articles of Incorporation contain restrictions on the payment of
dividends on SPPC's common stock in the event of a default in the
payment of dividends on SPPC's preferred stock and prohibit SPPC from
declaring or paying any dividends on any shares of common stock except
from the net income of SPPC, and its predecessor, available for
dividends on common stock accumulated subsequent to December 31, 1955,
less preferred stock dividends, plus the sum of $500,000.
The provisions that currently restrict dividends payable by NPC or SPPC
have adversely affected SPR's liquidity and will continue to negatively impact
SPR's liquidity until those provisions are no longer in effect.
42
On March 29 and April 1, 2002, S&P and Moody's lowered the unsecured
debt ratings of SPR, NPC and SPPC to below investment grade in response to the
decision of the PUCN with respect to NPC's rate cases. On April 23 and 24, 2002,
the unsecured debt ratings of SPR and the Utilities were further downgraded by
both rating agencies, and the Utilities' secured debt ratings were downgraded to
below investment grade. The downgrades have affected SPR's, NPC's and SPPC's
liquidity primarily in two principal areas: (1) their respective financing
arrangements and (2) NPC's and SPPC's contracts for fuel, for purchase and sale
of electricity and for transportation of natural gas.
As a result of the ratings downgrades, SPR's ability to access the
capital markets to raise funds is severely limited. On April 3, 2002, SPR
terminated its $75 million unsecured revolving credit facility as a condition to
the banks agreeing to an amendment of NPC's recently terminated $200 million
unsecured revolving credit facility that would permit NPC to draw down funds
under that facility. See "Nevada Power Company - Financial Condition, Liquidity
and Capital Resources" for more information.
In response to the decisions by the PUCN in NPC's rate cases, SPR has
implemented certain measures that management expects will positively impact cash
flow by $125 million in 2002. Two major transmission construction projects,
discussed in the Form 10-K for the year ended December 31, 2001, have been
delayed for a total capital preservation impact of $80.8 million. The delay in
NPC's Centennial Plan has an impact of $46.4 million and the delay of SPPC's
Falcon to Gonder Project has an impact of $34.4 million. An additional $28.9
million was reduced from the Utilities' capital budgets by curtailing or
delaying other projects. Management expects that the balance of the $125 million
cash flow enhancement will be obtained from various land sales. Additional
cost-cutting actions by SPR may be necessary.
With respect to NPC's and SPPC's contracts for purchased power, NPC and
SPPC purchase and sell electricity with counterparties under the Western Systems
Power Pool ("WSPP") agreement, which is an industry standard contract. The WSPP
contract is posted on the WSPP website. These contracts provide that a material
adverse change may give rise to a right to request collateral, which, if not
provided within 3 business days, could cause a default. A default must be
declared within 30 days of the event giving rise to the default becoming known.
A default will result in a termination payment equal to the present value of the
net gains and losses for the entire remaining term of all contracts between the
parties aggregated to a single liquidated amount due within 3 business days
following the date the notice of termination is received. The mark-to-market
value, which is substantially based on quoted market prices, can be used to
roughly approximate the termination payment at any point in time. The
mark-to-market value as of November 1, 2002, for all suppliers continuing to
provide power under a WSPP agreement was approximately 90.1 million and 59.9
million, respectively, for NPC and SPPC.
Following the PUCN decisions, a number of power suppliers requested
collateral from NPC and SPPC. On April 4, 2002, the Utilities sent a letter to
their suppliers advising them that, assuming the Utilities could access the
capital markets for secured debt and no other significant negative developments
occurred, the Utilities expected to be able to honor their obligations under the
power supply contracts. However, the Utilities noted that a simultaneous call
for 100% mark-to-market collateral in the short-term would likely not be met. On
April 24, 2002, the Utilities met with representatives of various suppliers to
discuss SPR's and the Utilities' financial situation and plans, and indicated
that they intended to propose extended payment terms for the above-market
portions of NPC's existing power contracts. Such extended payment terms were
proposed to NPC's suppliers in a letter dated May 2, 2002, and proposed paying
less than contract prices, but more than market prices plus interest, for the
period May 1 to September 15, 2002 and paying any balances remaining prior to
December 2003. NPC also agreed to extend the suppliers' rights under the WSPP
agreement. As of October 29, 2002, NPC paid all remaining outstanding balances
owed to its continuing suppliers.
In early May of 2002, Enron Power Marketing Inc. ("Enron"), Morgan
Stanley Capital Group Inc. ("MSCG"), Reliant Energy Services, Inc. and several
smaller suppliers terminated their power deliveries to NPC and SPPC. These
terminating suppliers asserted their contractual right under the WSPP agreement
to terminate deliveries based upon the Utilities' alleged failure to provide
adequate assurance of their performance under the WSPP agreement to any of their
suppliers. Each of these terminating suppliers has asserted, or has indicated
that it will assert, claims for liquidated damages against the Utilities under
the terminated power supply contracts.
On June 5, 2002, Enron filed suit in its bankruptcy case in the
Bankruptcy Court for the Southern District of New York asserting claims for
liquidated damages related to the termination of its power supply agreements
with the Utilities of approximately $216 million and $93 million against NPC and
SPPC, respectively. NPC and SPPC have both filed claims in the Bankruptcy Court
alleging, among other things, that NPC and SPPC were fraudulently induced to
enter into the agreements with Enron. Enron's claims are also subject to the
Utilities' defense, as raised in the Utilities' motions to dismiss and or to
stay all proceedings, that such claims are already at issue in the Utilities'
FERC proceeding against Enron and others under Section 206 of the Federal Power
Act challenging the contract prices of the terminated power supply agreements.
Enron initially filed a motion for partial summary judgment to require the
Utilities to make immediate payment of the full amount of Enron's claim, pending
final resolution of the lawsuit. Enron subsequently filed another motion for
summary judgment seeking final payment of its damages claim. Hearings, including
arguments regarding the issue of FERC's primary jurisdiction over the contract
claims, were conducted in September,
43
October, and early November 2002. On November 14, 2002, the judge is expected to
rule on the Utilities' motion to dismiss or stay until the FERC rules on the
Utilities' Section 206 filing. If the judge decides not to stay Enron's lawsuit
pending the outcome of the FERC hearings, the judge would then schedule
additional arguments with respect to Enron's motion for summary judgment. At
this time, the outcome of a decision in this matter cannot be predicted. An
adverse decision on Enron's motion for summary judgment or an adverse decision
in the lawsuit would have a material adverse affect on the financial condition
and liquidity of SPR and the Utilities and would render their ability to
continue to operate outside of bankruptcy uncertain.
On June 10, 2002, Duke Energy Trading and Marketing ("Duke") entered
into an agreement with SPR and the Utilities to supply up to 1,000 megawatts of
electricity per hour, as well as natural gas, to fulfill the Utilities' power
requirements during the peak summer period. The effect of the Duke agreement was
to replace the amount of contracted power and natural gas that would have been
supplied by the various terminating suppliers, including Enron. Duke also agreed
to accept deferred payment for a portion of the amount due under its existing
power contracts with NPC for purchases made through September 15, 2002. On
October 25, 2002 Duke was paid the full amount of the deferred payments.
On September 5, 2002, MSCG filed a Demand for Arbitration pursuant to
the mediation and arbitration procedures of the WSPP agreement seeking a
termination payment from NPC of approximately $25 million under its terminated
power supply agreement with NPC. If this claim is not resolved by arbitration,
NPC expects that MSCG will commence a lawsuit to recover liquidated damages
under the terminated contract.
On September 30, 2002, El Paso Merchant Energy Group ("EPME") notified
NPC that it was terminating all transactions entered into with NPC under the
WSPP agreement. On October 8, 2002, NPC received a letter from EPME seeking a
termination payment of approximately $36 million with respect to the terminated
WSPP agreement transactions. At the present time, NPC disagrees with EPME's
calculation, and expects that net gains and losses relating to the terminated
transactions, including a delayed payment amount of approximately $19 million
that was owed to EPME for power deliveries through September 15, 2002, will
result in a net payment due to NPC.
With respect to the purchase and sale of natural gas, NPC and SPPC use
several types of contracts. Standard industry sponsored agreements include:
- the Gas Industry Standards Board ("GISB") agreement which is used for
physical gas transactions,
- the North American Energy Standards Board ("NAESB") agreement which is
used for physical gas transactions,
- the GasEDI Base Contract for Short Term Sale and Purchase of Natural
Gas which is also used for physical gas transactions,
- the International Swap Dealers Association (ISDA) agreement which is
used for financial gas transactions.
Alternatively, the gas transactions might be governed by a non-standard
bilateral master agreement negotiated between the parties, or by the
confirmation associated with the transaction. The natural gas contract terms and
conditions are more varied than the electric contracts. Consequently, some of
the contracts contain language similar to that found in the WSPP agreement and
other agreements have unique provisions dealing with material adverse changes.
Gas transmission services are provided under the FERC Gas Tariff or a
custom agreement. These contracts require the entities to establish and maintain
creditworthiness to obtain service. These contracts are subject to FERC approved
tariffs which, under certain circumstances, require the Utilities to provide
collateral to continue receiving service. To date, a letter of credit has been
provided to one of SPPC's gas suppliers.
In March 2002, NPC received a federal income tax refund of $79.3
million. Additionally, SPR and the Utilities received $105.7 million of refunds
in the second quarter of 2002. These refunds were the result of income tax
losses generated in 2001. Federal legislation passed in March 2002 changed the
allowed carry-back of these losses from two years to five years. This change
permitted SPR and the Utilities to accelerate the receipt of a portion of their
income tax receivables sooner than expected. The income tax receivable of $266.7
million as of September 30, 2002, will be utilized in future periods to reduce
taxes payable when SPR and the Utilities recognize taxable income.
On October 29, 2002, NPC and SPPC established accounts receivables
purchase facilities of up to $125 million and $75 million, respectively, which
were arranged by Lehman Brothers. If NPC or SPPC elect to activate their
receivables purchase facilities, they will sell all of their accounts receivable
generated from the sale of electricity and natural gas to customers to their
newly created bankruptcy remote special purpose subsidiaries. The receivables
sales will be without recourse except for breaches of customary representations
and warranties made at the time of sale. The subsidiaries will, in turn, sell
these receivables to a bankruptcy-remote subsidiary of SPR. SPR's subsidiary
will issue variable rate revolving notes backed by the purchased receivables.
Lehman Brothers Holdings, Inc. will be the sole initial committed purchaser of
all of the variable rate revolving notes. The agreements relating to the
receivables purchase facilities contain various conditions to
44
purchase, covenants and trigger events, termination events and other provisions
customary in receivables transactions. In connection with these facilities, SPR
has agreed to guaranty the performance by NPC and SPPC of certain obligations as
sellers and servicers under the accounts receivables facilities. NPC and SPPC
intend to use their accounts receivables purchase facilities as back-up
liquidity facilities and do not plan to activate these facilities in the
foreseeable future.
SPR has a qualified pension plan (the "Plan") that covers substantially
all employees of SPR, NPC and SPPC. The annual net benefit cost for the Plan is
expected to increase for 2003 by an amount between $12 million and $22 million
over the 2002 cost of $18.4 million. Also, the Plan currently has assets with a
fair value that is less than the present value of the accumulated benefit
obligation under the Plan. While the amount of the deficiency has not yet been
determined, SPR and the Utilities expect their combined minimum funding
requirement for 2002 will be at least $24 million. However, SPR and the
Utilities do not expect that their funding obligation for 2002 will have a
material adverse effect on their liquidity.
SPR has a substantial amount of debt and other obligations including,
but not limited to: $200 million of its unsecured Floating Rate Notes due April
20, 2003; $300 million of its unsecured 8 3/4% Senior Notes due 2005; and $345
million of its unsecured 7.93% Senior Notes due 2007. In connection with the
effects of the disallowance of a significant portion of the Utilities' deferred
purchased power costs by the PUCN as stated above, SPR's credit ratings, along
with those of NPC and SPPC, were downgraded to below investment grade. As a
result of the downgrades, SPR's ability to service its debt obligations and
refinance its maturing debt as it becomes due has become uncertain. In the event
that SPR's financial condition does not improve or becomes worse, it may have to
consider other options including the possibility of seeking protection in a
bankruptcy proceeding.
On October 29, 2002, SPPC paid a common stock dividend of $25 million
to its parent, SPR. On November 8, 2002, the Board of Directors of SPPC voted to
declare a dividend to SPR of up to $25 million payable on or before February 1,
2003. SPR's future liquidity depends, in part, on SPPC's ability to continue to
pay dividends to SPR, on a restoration of NPC to financial stability including a
restoration of its ability to pay dividends to SPR, and on SPR's ability to
access the capital markets or otherwise refinance debt that matures in 2003 and
thereafter. Further adverse developments at NPC or SPPC, including a material
disallowance of deferred energy costs in future rate cases or an adverse
decision in the pending lawsuit by Enron, could cause SPR to become insolvent
and would render SPR's ability to continue to operate outside of bankruptcy
uncertain.
45
NEVADA POWER COMPANY
During the quarter ended September 30, 2002, NPC earned approximately
$79.3 million (excluding NPC's equity in the losses of its parent, SPR) and paid
no dividends on its common stock. During the nine months ended September 30,
2002, NPC incurred a loss of approximately $216.0 million (excluding NPC's
equity in the losses of its parent, SPR), and paid $10 million in dividends on
its common stock, all of which was reinvested in NPC as a contribution to
capital.
On July 7, 2002, the Board of County Commissioners of Clark County,
Nevada, added an Electric Utility Advisory Question to its November 5, 2002
general election ballot, which asked voters whether "the Nevada Legislature
should take appropriate action to enable the electrical energy provider for
southern Nevada to be a locally controlled, not for profit public utility." NPC
filed a lawsuit seeking to remove the question from the ballot, and the lawsuit
was dismissed. Although the referendum is non-binding, the results of this
advisory question, which was approved by a 57% to 43% vote, may impact future
utility legislation by the Nevada Legislature in its next legislative session
which may, in turn, directly or indirectly affect NPC and its operations.
On August 22, 2002, SPR received a letter from the Southern Nevada
Water Authority ("SNWA") stating that it was prepared to enter into good faith
negotiation of definitive agreements to acquire all of NPC's assets and assume
certain of NPC's existing indebtedness. On September 12, 2002, SPR responded
with a letter stating that it did not view the SNWA's letter as an offer and
expressing concerns with the SNWA's financing plans, certain significant legal
issues with the proposal and the SNWA's lack of utility management experience.
The SNWA has responded by reaffirming its purported offer to acquire NPC.
The causes for significant changes in specific lines comprising the
results of operations for NPC are as follows:
THREE MONTHS NINE MONTHS
ENDED SEPTEMBER 30, ENDED SEPTEMBER 30,
-------------------------------------- -----------------------------------------
Change from Change from
2002 2001 Prior Year % 2002 2001 Prior Year %
---------- ----------- ------------ ----------- ------------ ------------
ELECTRIC OPERATING REVENUES ($000):
Residential $ 266,508 $ 253,631 5.1% $ 564,439 $ 529,330 6.6%
Commercial 103,367 94,262 9.7% 263,425 233,391 12.9%
Industrial 189,440 159,041 19.1% 413,602 349,866 18.2%
---------- ----------- ----------- ------------
Retail revenues 559,315 506,934 10.3% 1,241,466 1,112,587 11.6%
Other (1) 153,221 888,562 -82.8% 304,401 1,450,362 -79.0%
---------- ----------- ----------- ------------
Total Revenues $ 712,536 $ 1,395,496 -48.9% $ 1,545,867 $ 2,562,949 -39.7%
========== =========== =========== ============
Retail sales in thousands
of megawatt-hours (MWH) 5,814 5,540 4.9% 13,699 13,296 3.0%
Average retail revenue per MWH $ 96.20 $ 91.50 5.1% $ 90.62 $ 83.68 8.3%
(1) Primarily wholesale, as discussed below
Residential electric revenues increased for the three months ending
September 30, 2002 compared to the same period last year due to increased rates
in 2002 and an increase in cooling degree-days resulting in higher sales per
residential customer. Residential electric revenues increased for the nine
months ended September 30, 2002 due to an overall increase in rates resulting
from an increase in rates effective March 1, 2001, pursuant to the Comprehensive
Energy Plan (CEP), and a rate change effective April 1, 2002, that included a
new Deferred Energy Accounting Adjustment (DEAA) rate. See NPC's Annual Report
on Form 10-K for the year ended December 31, 2001 for a discussion of the Global
Settlement and the CEP, and the Regulatory Matters section of this third quarter
Form 10-Q for more detailed DEAA and rate information.
Both commercial and industrial electric revenues increased for the
three- and nine-month periods due, in part, to increases in the number of
customers and rates. The opening of several new schools, commercial shopping
centers and large casinos helped to increase 2002 revenues.
The decreases in Electric Operating Revenues - Other for the three- and
nine-month periods ended September 30, 2002, compared to the same periods in
2001 were due to the decrease in prices and sales volumes of wholesale electric
power to other utilities, as a result of changing market conditions. See NPC's
Annual Report on Form 10-K for the year ended December 31, 2001, Item 7,
Management's Discussion and Analysis of Financial Condition and Results of
Operation, Purchased Power Procurement, for a discussion of NPC's purchased
power procurement strategies.
46
THREE MONTHS NINE MONTHS
ENDED SEPTEMBER 30, ENDED SEPTEMBER 30,
--------------------------------------- ----------------------------------------
Change from Change from
2002 2001 Prior Year % 2002 2001 Prior Year %
---------- ------------- ------------ ----------- ------------ ------------
PURCHASED POWER ($000) $ 440,559 $ 1,686,816 -73.9% $ 1,102,55 $ 2,728,176 -59.6%
Purchased Power in thousands
of MWHs 5,330 8,330 -36.0% 11,112 16,015 -30.6%
Average cost per MWH of
Purchased Power (1) $ 82.66 $ 202.50 -59.2% $ 78.61 $ 170.35 -53.9%
(1) Not including contract termination costs, discussed below
NPC's purchased power costs and volume were lower for both the three-
and nine-month periods ended September 30, 2002 than for the same period of the
prior year. These decreases were the result of lower volumes and prices of
Short-Term Firm energy purchased. The decrease for the nine-month period was
offset, in part, by a $229 million reserve recorded in the second quarter for
terminated contracts, which are part of the power portfolio costs and which are
described in more detail in "Financial Condition, Liquidity, and Capital
Resources." Purchases associated with risk management activities, which are
included in Short-Term Firm energy, also decreased significantly in 2002, for
both the current quarter and year-to-date. Risk management activities include
transactions entered into for hedging purposes and to minimize purchased power
costs. See NPC's Annual Report on Form 10-K for the year ended December 31,
2001, Item 7, Management's Discussion and Analysis of Financial Condition and
Results of Operation, Purchased Power Procurement, for a discussion of NPC's
purchased power procurement strategies.
THREE MONTHS NINE MONTHS
ENDED SEPTEMBER 30, ENDED SEPTEMBER 30,
--------------------------------------- ----------------------------------------
Change from Change from
2002 2001 Prior Year % 2002 2001 Prior Year %
---------- ---------- ------------ ----------- ----------- ------------
FUEL FOR POWER GENERATION ($000) $ 87,864 $ 131,023 -32.9% $ 245,060 $ 348,633 -29.7%
Thousands of MWHs generated 2,936 2,436 20.5% 7,592 7,510 1.1%
Average cost per MWH of
Generated Power $ 29.93 $ 53.79 -44.4% $ 32.28 $ 46.42 -30.5%
Fuel for generation costs for both the three and nine months ended
September 30, 2002, were significantly lower than the prior year due to the
substantial decrease in natural gas prices. For the three months ended September
30, 2002, the decrease was offset, in part, by higher volumes, because it was
more economical to generate power than to purchase power.
THREE MONTHS NINE MONTHS
ENDED SEPTEMBER 30, ENDED SEPTEMBER 30,
----------------------------------------- -----------------------------------------
Change from Change from
DEFERRAL OF ENERGY COSTS-NET ($000) 2002 2001 Prior Year % 2002 2001 Prior Year %
---------- ----------- ------------ ---------- ---------- ------------
Deferred energy costs - net $ (43,224) $ (638,571) -93.2% $ (238,059) $ (908,408) -73.8%
Deferred energy costs disallowed - - N/A 434,123 - N/A
---------- ----------- ---------- ----------
$ (43,224) $ (638,571) -93.2% $ 196,064 $ (908,408) N/A
========== =========== ========== ==========
Deferral of energy costs-net for the three- and nine-month periods
ended September 30, 2002, reflects deferrals of electric energy costs,
reflecting the extent to which actual fuel and purchased power costs exceeded
the fuel and purchased power costs recovered through current rates. These
deferrals are offset in part by the amortization of prior deferred costs
resulting from an increase in rates beginning April 1, 2002, pursuant to the
PUCN's March 29, 2002, decision on NPC's deferred energy rate case, and the
one-time rate increase of $0.01 per kilowatt-hour for the month of June 2002.
Deferral of energy costs-net for the nine-months ended September 30, 2002, also
reflects the deferral in the second quarter of 2002 of approximately $229
million for contract termination costs, as described in more detail in
"Financial Condition, Liquidity, and Capital Resources," and reflects the
write-off of $434 million of deferred energy costs for the seven months ended
47
September 30, 2001, that were disallowed by the PUCN in their decision on NPC's
deferred energy rate case. For both the three- and nine-month periods ended
September 30, 2001, NPC recorded large deferrals of electric energy costs, as
shown in the table above.
THREE MONTHS NINE MONTHS
ENDED SEPTEMBER 30, ENDED SEPTEMBER 30,
----------------------------------- ---------------------------------------
Change from Change from
2002 2001 Prior Year % 2002 2001 Prior Year %
-------- ------ ------------ ------- ------- ------------
ALLOWANCE FOR OTHER FUNDS
USED DURING CONSTRUCTION ($000) $ (262) $ (87) $ 239 $ (560)
ALLOWANCE FOR BORROWED FUNDS
USED DURING CONSTRUCTION ($000) $ 208 $ 657 $ 2,169 $ 570
------- ------ ------- -------
$ (54) $ 570 -109.5% $ 2,408 $ 10 23980.0%
======= ====== ======= =======
NPC's total allowance for funds used during construction (AFUDC) is
lower for the three-month period ended September 30, 2002 as a result of
adjustments in 2002 to refine amounts assigned to specific components of
facilities that were completed in different periods and a decrease in the AFUDC
rate. The decrease was offset in part due to an increase in capital expenditures
for the Centennial Plan. AFUDC is higher for the nine-month period ended
September 30, 2002 as a result of an increase in capital expenditures for the
Centennial Plan and adjustments in 2001 to refine amounts assigned to specific
components of facilities that were completed in different periods. The increase
is offset in part by a decrease in the AFUDC rate in 2002 as a result of an
increase in short-term debt.
THREE MONTHS NINE MONTHS
ENDED SEPTEMBER 30, ENDED SEPTEMBER 30,
--------------------------------------- -----------------------------------------
Change from Change from
($000) 2002 2001 Prior Year % 2002 2001 Prior Year %
---------- ----------- ------------ ------------ ---------- ------------
OTHER OPERATING EXPENSE $ 39,250 $ 45,670 -14.1% $ 116,520 $ 130,192 -10.5%
MAINTENANCE EXPENSE $ 8,050 $ 10,331 -22.1% $ 31,576 $ 36,789 -14.2%
DEPRECIATION AND AMORTIZATION $ 24,975 $ 23,042 8.4% $ 72,924 $ 67,345 8.3%
INCOME TAXES $ 39,944 $ 36,197 10.4% $ (116,536) $ 21,979 -630.2%
INTEREST CHARGES ON LONG-TERM DEBT $ 23,714 $ 20,545 15.4% $ 70,668 $ 55,504 27.3%
INTEREST CHARGES-OTHER $ 7,251 $ 3,269 121.8% $ 14,133 $ 10,982 28.7%
OTHER INCOME (EXPENSE) - NET $ 4,933 $ 11,021 -55.2% $ (839) $ 14,189 -105.9%
Other operating expense for the three-month period ending September 30,
2002 was lower, compared with the same period in the prior year, primarily due
to a third quarter 2001 increase in the provision for uncollectible accounts of
approximately $10 million offset, in part, by a decrease in the provision for
uncollectible accounts in 2001 related to the California Power Exchange. The
decrease in Other operating expense for the nine-month period ending September
30, 2002, compared with the same period in the prior year, reflects the third
quarter 2001 increase in the provision for uncollectible accounts, a $12.5
million increase in the provision for uncollectible accounts in 2001 related to
the California Power Exchange, and the 2002 reversal of a $3 million reserve
provision established in 2001 as a result of the conclusion of electric industry
restructuring in Nevada. These decreases were offset, in part, by increased
expenses related to a new Credit and Collections Action Plan, and legal fees
associated with the PUCN's Deferred Energy Rate Case decision.
Maintenance costs for the three- and nine- month periods ending
September 30, 2002, decreased from the prior year due to delayed planned outages
at Reid Gardner and Clark Station.
Depreciation and amortization is higher for the three- and nine-month
periods ended September 30, 2002 compared to the same periods in 2001 as a
result of an increase in the computer depreciation rate and additions to
plant-in-service. This increase was offset in part by plant-in-service asset
reconciliations pursuant to a PUCN order.
NPC's income tax expense for the three months ended September 30, 2002,
increased compared to the same period in 2001, due to a corresponding increase
in third quarter 2002 pre-tax income compared to the prior year. For the nine
months ended September 30, 2002, NPC recorded a significant income tax benefit
reflecting a large 2002 pre-tax loss; NPC recorded income tax expense for the
nine months ended September 30, 2001, corresponding to the pre-tax income for
the period.
48
Interest charges on long-term debt for the three- and nine- month
periods ending September 30, 2002, increased over the same periods in 2001 due
net increases in long-term debt outstanding between the comparable periods.
Interest charges-other for the three- and nine-month periods ended
September 30, 2002, increased from the prior year due primarily to interest
expense on deferred payments to energy suppliers in the current year.
Other income (expense) - net for the three months ended September 30,
2002, decreased compared to the same period in the prior year primarily due to a
$6 million decrease, net of taxes, in carrying charges for deferred energy. The
decrease in Other income (expense) - net for the nine months ended September 30,
2002, compared to the prior year also reflects the first quarter 2002 write-off
of approximately $20.1 million, net of taxes, of carrying charges on deferred
energy costs that were disallowed by the PUCN in their March 29, 2002 decision
on NPC's deferred energy rate case. The write-off was offset in part by the
recording of current year carrying charges on deferred energy costs.
ANALYSIS OF CASH FLOWS
NPC's cash flows improved during the nine months ended September 30,
2002, compared to the same period in 2001, resulting primarily from an increase
in cash flows from operating activities offset in part by a decrease in cash
flows from financing activities. Although NPC recorded a substantial loss for
the nine months ended September 30, 2002, compared to net income for the same
period in 2001, the current year's loss resulted largely from the write-off of
disallowed deferred energy costs for which the cash outflow had occurred in
2001. Current year cash flows from operating activities also benefited from
improved collections on accounts receivable compared to the prior year and from
lower energy prices. Cash flows from operating activities in the current year
also reflect the receipt of an income tax refund. Cash flows from financing
activities were lower because of decreases in both net long-term debt issued and
cash invested by NPC's parent, SPR, during the nine months ended September 30,
2002 compared to the same period in 2001.
FINANCIAL CONDITION, LIQUIDITY AND CAPITAL RESOURCES
NPC had cash and cash equivalents of approximately $207.7 million at
September 30, 2002, and $146.7 million at October 31, 2002.
As discussed in "Management's Discussion and Analysis of Financial
Condition and Results of Operations - Nevada Power Company - Construction
Expenditures and Financing" and " - Capital Structure" in the Annual Report on
Form 10-K for the year ended December 31, 2001, NPC anticipated external capital
requirements for construction costs and for the repayment of maturing short-term
and long-term debt during 2002 totaling approximately $403 million, which NPC
planned to fund through a combination of (i) internally generated funds, (ii)
the issuance of short-term debt and preferred stock, and (iii) capital
contributions from SPR.
On March 29 and April 1, 2002, following the decision by the PUCN in
NPC's deferred energy rate case, S&P and Moody's lowered NPC's unsecured debt
ratings to below investment grade. On April 23 and 24, 2002, NPC's unsecured
debt ratings were further downgraded and its secured debt ratings were
downgraded to below investment grade. As a result of these downgrades, NPC's
ability to access the capital markets to raise funds is severely limited. Since
SPR's credit ratings were similarly downgraded, SPR's ability to make capital
contributions to NPC also became severely limited.
In connection with the credit downgrades by S&P and Moody's, NPC lost
its A2/P2 commercial paper ratings and can no longer issue commercial paper. NPC
had a commercial paper balance outstanding of $198.9 million at the time with a
weighted average interest rate of 2.52%. Since NPC was no longer able to roll
over its commercial paper, it paid off its maturing commercial paper with the
proceeds of borrowings under its credit facility and terminated its commercial
paper program on May 28, 2002. NPC does not expect to have direct access to the
commercial paper market for the foreseeable future.
NPC's $200 million unsecured revolving credit facility was also
affected by the decision in the deferred energy rate case. Following the
announcement of that decision, the banks participating in NPC's credit facility
determined that a material adverse event had occurred with respect to NPC,
thereby precluding NPC from borrowing funds under its credit facility. The banks
agreed to waive the consequences of the material adverse event in a waiver
letter and amendment that was executed on April 4, 2002. As required under the
waiver letter and amendment, NPC issued and delivered its General and Refunding
Mortgage Bond, Series C, due November 28, 2002, in the principal amount of $200
million, to the Administrative Agent as security for the credit facility. This
facility was paid in full and terminated on October 30, 2002 with proceeds from
the issuance of NPC's $250 million 10 7/8% General and Refunding Mortgage Notes,
Series E, due 2009.
On October 29, 2002, NPC established an accounts receivables purchase
facility of up to $125 million, which was arranged by Lehman Brothers. If NPC
elects to activate the receivables purchase facility, NPC will sell all of its
accounts receivable generated from the sale of electricity to customers to its
newly created bankruptcy remote special purpose
49
subsidiary. The receivables sales will be without recourse except for breaches
of customary representations and warranties made at the time of sale. The
subsidiary will, in turn, sell these receivables to a bankruptcy-remote
subsidiary of SPR. SPR's subsidiary will issue variable rate revolving notes
backed by the purchased receivables. Lehman Brothers Holdings, Inc. will be the
sole initial committed purchaser of all of the variable rate revolving notes.
The agreements relating to the receivables purchase facility contain various
conditions to purchase, covenants and trigger events, termination events and
other provisions customary in receivables transactions. In addition, the
agreements contain a limitation on the payment of dividends by NPC to SPR that
is identical to the limitation contained in NPC's General and Refunding Mortgage
Notes, Series E, described below. In connection with NPC's receivables facility,
SPR has agreed to guaranty NPC's performance of certain obligations as a seller
and servicer under the facility.
NPC has agreed to issue $125 million principal amount of its General
and Refunding Mortgage Bonds upon activation of the accounts receivables
purchase facility. The full principal amount of the Bond would secure certain of
NPC's obligations as seller and servicer, plus certain interest, fees and
expenses thereon to the extent not paid when due, regardless of the actual
amounts owing with respect to the secured obligations. As a result, in the event
of an NPC bankruptcy or liquidation, the holder of the Bond securing the
receivables facility may recover more on a pro rata basis than the holders of
other General and Refunding Mortgage securities, who could recover less on a pro
rata basis, than they otherwise would recover. However, in no event will the
holder of the Bond recover more than the amount of obligations secured by the
Bond.
NPC intends to use the accounts receivables purchase facility as a
back-up liquidity facility and does not plan to activate this facility in the
foreseeable future. NPC may activate the facility within five days upon the
delivery of certain customary funding documentation and the delivery of the $125
million General and Refunding Mortgage Bond.
NPC's first mortgage indenture creates a first priority lien on
substantially all of NPC's properties. As of September 30, 2002, $372.5 million
of NPC's first mortgage bonds were outstanding. Although the first mortgage
indenture allows NPC to issue additional mortgage bonds on the basis of (i) 60%
of net utility property additions and/or (ii) the principal amount of retired
mortgage bonds, NPC agreed in connection with its $250 million 10 7/8% General
and Refunding Mortgage Notes, Series E, due 2009 that it would not issue any
more first mortgage bonds.
NPC's General and Refunding Mortgage Indenture creates a lien on
substantially all of NPC's properties in Nevada that is junior to the lien of
the first mortgage indenture. As of September 30, 2002, $820 million of NPC's
General and Refunding Mortgage securities were outstanding. Additional
securities may be issued under the General and Refunding Mortgage Indenture on
the basis of (1) 70% of net utility property additions, (2) the principal amount
of retired General and Refunding Mortgage bonds, and/or (3) the principal amount
of first mortgage bonds retired after delivery to the indenture trustee of the
initial expert's certificate under the General and Refunding Mortgage Indenture.
As of October 1, 2002, NPC had the capacity to issue approximately $871 million
of additional General and Refunding Mortgage securities, not including the
issuance of $250 million Series E Notes and the retirement of $200 million of
General and Refunding Mortgage Bonds that secured NPC's terminated credit
facility. However, the financial covenants contained in the Series E Notes
limits NPC ability to issue additional General and Refunding Mortgage bonds or
other debt. NPC has reserved $125 million of General and Refunding Mortgage
Bonds for issuance upon the initial funding of NPC's receivables facility and
$50 million of its General and Refunding Mortgage Bonds to secure a proposed
364-day facility, discussed below.
NPC also has the ability to release property from the liens of the two
mortgage indentures on the basis of net property additions, cash and/or retired
bonds. To the extent NPC releases property from the lien of its General and
Refunding Mortgage Indenture, it will reduce the amount of bonds issuable under
that indenture.
On June 19, 2002, the PUCN issued a Compliance Order, Docket No.
02-4037, authorizing NPC to issue $300 million of long-term debt. The PUCN order
requires NPC, if it is able, to issue the $50 million of remaining authorized
short-term debt, before it issues any long-term debt authorized by the order.
Moreover, the order provides that, if NPC is able to issue short-term debt at
any point prior to September 1, 2002 (whether or not the issuance of short-term
debt actually occurs), the amount of long-term debt authorized by the order will
be automatically reduced to $250 million. The PUCN order also provides that NPC
will bear the burden of demonstrating that any financings undertaken pursuant to
the order, including any determination made regarding the length of such
commitment, the type of security or rate, is reasonable. Finally, the order
requires that, until such time as the order's authorization expires (December
31, 2003), NPC must either receive the prior approval of the PUCN or reach an
equity ratio of 42% before paying any dividends to SPR. If NPC achieves a 42%
equity ratio prior to December 31, 2003, the dividend restriction ceases to have
effect.
On July 3, 2002, the BCP of the Nevada Attorney General's Office filed
a petition with the PUCN requesting that the hearing in Docket No. 02-4037 be
reopened to allow for the introduction of additional evidence or for the PUCN to
reconsider its decision granting NPC the authority to issue long-term debt. On
September 11, 2002, the PUCN denied the petition to reopen the proceeding and
rescinded the portion of its Compliance Order that had previously required NPC
to immediately issue $50 million to $100 million of debt.
50
In early May of 2002, Enron, MSCG, Reliant Energy Services, Inc. and
several smaller suppliers terminated their power deliveries to NPC. These
terminating suppliers asserted their contractual right under the WSPP agreement
to terminate deliveries based upon NPC's alleged failure to provide adequate
assurance of its performance under the WSPP agreement to any of its suppliers.
Each of these terminating suppliers has asserted, or has indicated that it will
assert, a claim for liquidated damages under the terminated power supply
contracts.
On June 5, 2002, Enron filed suit in its bankruptcy case in the
Bankruptcy Court for the Southern District of New York asserting claims for
liquidated damages related to the termination of its power supply agreements
with NPC of approximately $216 million. NPC has filed claims in the Bankruptcy
Court alleging, among other things, that NPC was fraudulently induced to enter
into the agreements with Enron. Enron's claims are also subject to NPC's
defense, as raised in NPC's motions to dismiss and or to stay all proceedings,
that such claims are already at issue in NPC's FERC proceeding against Enron and
others under Section 206 of the Federal Power Act challenging the contract
prices of the terminated power supply agreements. Enron initially filed a motion
for partial summary judgment to require NPC to make immediate payment of the
full amount of Enron's claim, pending final resolution of the lawsuit. Enron
subsequently filed another motion for summary judgment seeking final payment of
its damages claim. Hearings, including arguments regarding the issue of FERC's
primary jurisdiction over the contract claims, were conducted in September,
October, and early November 2002. On November 14, 2002, the judge is expected to
rule on the Utilities' motion to dismiss or stay until the FERC rules on the
Utilities' Section 206 filing. If the judge decides not to stay Enron's lawsuit
pending the outcome of the FERC hearings, the judge would then schedule
additional arguments with respect to Enron's motion for summary judgment. At
this time, the outcome of a decision in this matter cannot be predicted. An
adverse decision on Enron's motion for summary judgment or an adverse decision
in the lawsuit would have a material adverse affect on the financial condition
and liquidity of NPC and would render its ability to continue to operate outside
of bankruptcy uncertain.
On June 10, 2002, Duke Energy Trading and Marketing ("Duke") entered
into an agreement with NPC, SPR and SPPC to supply up to 1,000 megawatts of
electricity per hour, as well as natural gas, to fulfill NPC's customers' power
requirements during the peak summer period. The effect of the Duke agreement was
to replace the amount of contracted power and natural gas that would have been
supplied by the various terminating suppliers, including Enron. Duke also agreed
to accept deferred payment for a portion of the amount due under its existing
power contracts with NPC for purchases made through September 15, 2002. On
October 25, 2002, Duke was paid in full with respect to these delayed payment
amounts.
On September 5, 2002, MSCG filed a Demand for Arbitration pursuant to
the mediation and arbitration procedures of the WSPP agreement seeking a
termination payment of approximately $25 million under its terminated power
supply agreement. If this claim is not resolved by arbitration, NPC expects that
MSCG will commence a lawsuit to recover liquidated damages under the terminated
contract.
On September 30, 2002, EPME notified NPC that it was terminating all
transactions entered into with NPC under the WSPP agreement. On October 8, 2002,
NPC received a letter from EPME seeking a termination payment of approximately
$36 million with respect to the terminated WSPP agreement transactions. At the
present time, NPC disagrees with EPME's calculation, and expects that net gains
and losses relating to the terminated transactions, including a delayed payment
amount of approximately $19 million owed to EPME for power deliveries through
September 15, 2002, will result in a net payment due to NPC.
On October 25, 2002 NPC redeemed its 7 5/8% Series L, First Mortgage
Bonds in the aggregate principal amount of $15 million.
On October 29, 2002, NPC issued and sold $250 million of its 10 7/8%
General and Refunding Mortgage Notes, Series E, due 2009 for a purchase price of
$235.6 million. The Series E Notes were issued with registration rights. The
proceeds of the issuance were used to pay off NPC's $200 million credit facility
and for general corporate purposes. The Series E Notes limit the amount of
dividends that NPC may pay to SPR. However, that limitation does not apply to
payments by NPC to enable SPR to pay its reasonable fees and expenses
(including, but not limited to, interest on SPR's indebtedness and payment
obligations on account of SPR's premium income equity securities) provided that
those payments do not exceed $60 million for any one calendar year, those
payments comply with any regulatory restrictions then applicable to NPC, and the
ratio of consolidated cash flow to fixed charges for NPC's most recently ended
four full fiscal quarters immediately preceding the date of payment is at least
1.75 to 1. The terms of the Series E Notes also permit dividend payments to SPR
in an aggregate amount not to exceed $15 million from the date of the issuance
of the Series E Notes. In addition, NPC may make dividend payments to SPR in
excess of the amounts described above so long as, at the time of payment and
after giving effect to the payment: there are no defaults or events of default
with respect to the Series E Notes, NPC can meet a fixed charge coverage ratio
test, and the total amount of such dividends is less than (i) the sum of 50% of
NPC's consolidated net income measured on a quarterly basis cumulative of all
quarters from the date of issuance of the Series E Notes, plus (ii) 100% of
NPC's aggregate net cash proceeds from the issuance or sale of certain equity or
convertible debt securities of NPC, plus (iii) the lesser of cash return of
capital or the initial amount of certain restricted investments, plus (iv) the
fair market value of NPC's investment in certain subsidiaries.
51
The terms of the Series E Notes also restrict NPC from incurring any
additional indebtedness unless (i) at the time the debt is incurred, the ratio
of consolidated cash flow to fixed charges for NPC's most recently ended four
quarter period on a pro forma basis is at least 2 to 1, or (ii) the debt
incurred is specifically permitted, which includes certain credit facility or
letter of credit indebtedness, obligations incurred to finance property
construction or improvement, indebtedness incurred to refinance existing
indebtedness, certain intercompany indebtedness, hedging obligations,
indebtedness incurred to support bid, performance or surety bonds, and certain
letters of credit issued to support NPC's obligations with respect to energy
suppliers.
If NPC's Series E Notes are upgraded to investment grade by both
Moody's and S&P, the dividend restrictions and the restrictions on indebtedness
applicable to the Series E Notes will be suspended and will no longer be in
effect so long as the Series E Notes remain investment grade.
Among other things, the Series E Notes also contain restrictions on
liens (other than permitted liens, which include liens to secure certain
permitted debt) and certain sale and leaseback transactions. In the event of a
change of control of NPC, the holders of Series E Notes are entitled to require
that NPC repurchase the Series E Notes for a cash payment equal to 101% of the
aggregate principal amount plus accrued and unpaid interest. The Series E Notes
will mature October 15, 2009.
NPC is in the process of negotiating a 364-day credit facility of up to
$50 million. The 364-day credit facility will be secured by $50 million
aggregate principal amount of NPC's General and Refunding Mortgage Bonds. The
closing of the 364-day credit facility will be subject to the completion of the
lender's due diligence, the negotiation and finalization of documentation and
other customary closing conditions. Although NPC has commenced negotiations of
the terms of the 364-day credit facility, it cannot give assurances that it will
enter into the credit facility or any similar arrangement.
SPR has a qualified pension plan (the "Plan") that covers substantially
all employees of SPR, NPC and SPPC. The annual net benefit cost for the Plan is
expected to increase for 2003 by an amount between $12 million and $22 million
over the 2002 cost of $18.4 million. Also, the Plan currently has assets with a
fair value that is less than the present value of the accumulated benefit
obligation under the Plan. While the amount of the deficiency has not yet been
determined, SPR and the Utilities expect their combined minimum funding
requirement for 2002 will be at least $24 million. However, SPR and the
Utilities do not expect that their funding obligation for 2002 will have a
material adverse effect on their liquidity.
NPC's liquidity would also be significantly affected by an adverse
decision in the lawsuit by Enron, or by unfavorable rulings by the PUCN in
future NPC or SPPC rate cases. Both S&P and Moody's have NPC's credit ratings on
"watch negative" or "possible downgrade," and any further downgrades could
further preclude NPC's access to the capital markets, and could adversely affect
NPC's ability to continue to purchase power and fuel. Adverse developments with
respect to any one or a combination of the foregoing could cause NPC to become
insolvent and would render NPC's ability to continue to operate outside of
bankruptcy uncertain.
52
SIERRA PACIFIC POWER COMPANY
During the quarter ended September 30, 2002, SPPC earned approximately
$13.5 million before preferred stock dividends. During this period, SPPC paid
$975,000 in dividends to holders of its preferred stock and paid no dividends on
its common stock, all of which is held by its parent, SPR. During the nine
months ended September 30, 2002, SPPC incurred a loss of approximately $9.5
million before preferred stock dividends. During this period, SPPC paid $2.9
million in dividends to holders of its preferred stock and paid $19.9 million in
dividends on its common stock, $10 million of which was reinvested in SPPC as a
contribution to capital. On October 29, 2002, SPPC paid a common stock dividend
of $25 million to its parent, SPR.
The components of SPPC's gross margin are set forth below (dollars in
thousands):
THREE MONTHS NINE MONTHS
ENDED SEPTEMBER 30, ENDED SEPTEMBER 30,
------------------------------------------- -------------------------------------------
Change from Change from
2002 2001 Prior Year % 2002 2001 Prior Year %
------------ ----------- ------------ ----------- ------------ ------------
Operating Revenues:
Electric $ 285,023 $ 581,957 -51.0% $ 705,946 $ 1,175,228 -39.9%
Gas 18,473 18,831 -1.9% 99,139 104,725 -5.3%
------------ ----------- ----------- ------------
Total Revenues 303,496 600,788 -49.5% 805,085 1,279,953 -37.1%
------------ ----------- ----------- ------------
Energy Costs:
Electric 198,727 498,513 -60.1% 536,824 972,897 -44.8%
Gas 14,165 12,387 14.4% 76,234 81,654 -6.6%
------------ ----------- ----------- ------------
Total Energy Costs 212,892 510,900 -58.3% 613,058 1,054,551 -41.9%
------------ ----------- ----------- ------------
Gross Margin $ 90,604 $ 89,888 0.8% $ 192,027 $ 225,402 -14.8%
============ =========== =========== ============
Gross Margin by Segment:
Electric $ 86,296 $ 83,444 3.4% $ 169,122 $ 202,331 -16.4%
Gas 4,308 6,444 -33.1% 22,905 23,071 -0.7%
------------ ----------- ----------- ------------
Total $ 90,604 $ 89,888 0.8% $ 192,027 $ 225,402 -14.8%
============ =========== =========== ============
The causes for significant changes in specific lines comprising the
results of operations for SPPC are as follows:
THREE MONTHS NINE MONTHS
ENDED SEPTEMBER 30, ENDED SEPTEMBER 30,
---------------------------------------- ----------------------------------------
Change from Change from
2002 2001 Prior year % 2002 2001 Prior year %
--------- --------- ------------ ---------- ---------- ------------
ELECTRIC OPERATING REVENUES ($000):
Residential $ 59,145 $ 58,670 0.8% $ 164,598 $ 157,144 4.7%
Commercial 81,856 71,387 14.7% 203,211 182,681 11.2%
Industrial 76,776 67,590 13.6% 199,902 187,498 6.6%
--------- --------- ---------- ----------
Retail revenues 217,777 197,647 10.2% 567,711 527,323 7.7%
Other (1) 67,246 384,310 -82.5% 138,235 647,905 -78.7%
--------- --------- ---------- ----------
TOTAL REVENUES $ 285,023 $ 581,957 -51.0% $ 705,946 $1,175,228 -39.9%
========= ========= ========== ==========
Retail sales in thousands of
megawatt-hours (MWH) 2,327 2,309 0.8% 6,607 6,538 1.1%
Average retail revenue per MWH $ 93.59 $ 85.60 9.3% $ 85.93 $ 80.66 6.5%
(1) Primarily wholesale, as discussed below
Retail electric revenues were higher for the three months ending
September 30, 2002, compared to the same period the previous year. The increase
was primarily a result of an overall rate increase that was effective June 1,
2002 (refer to Note 9, Regulatory Events), and, to a lesser extent, warmer than
normal weather in July.
Retail electric revenues increased for the nine months ended September
30, 2002, compared to the prior year primarily due to rate increases resulting
from the 2001 Global Settlement and 2001 Comprehensive Energy Plan (CEP). During
the first quarter 2001, these rate increases were being phased in on a monthly
basis whereas retail revenues for the first quarter of 2002 reflect the
cumulative impact of those increases. The third quarter 2002 weather effects
resulted in a minimal revenue impact for the nine months ending September 30,
2002.
53
The decreases in Electric Operating Revenues - Other for the three- and
nine-month periods ended September 30, 2002, compared to the same periods in
2001 were due to the decrease in prices and sales volume of wholesale electric
power to other utilities, as a result of changing market conditions. See SPPC's
Annual Report on Form 10-K for the year ended December 31, 2001, Item 7,
Management's Discussion and Analysis of Financial Condition and Results of
Operation, Purchased Power Procurement, for a discussion of SPPC's purchased
power procurement strategies.
THREE MONTHS NINE MONTHS
ENDED SEPTEMBER 30, ENDED SEPTEMBER 30,
--------------------------------------- --------------------------------------
Change from Change from
2002 2001 Prior year % 2002 2001 Prior year %
---------- ---------- ------------ ---------- ---------- ------------
GAS OPERATING REVENUES ($000):
Residential $ 6,627 $ 7,861 -15.7% $ 49,735 $ 39,615 25.5%
Commercial 4,027 4,267 -5.6% 26,112 20,331 28.4%
Industrial 3,436 6,333 -45.7% 14,996 12,962 15.7%
Miscellaneous 219 (542) -140.4% 1,627 86 1791.9%
---------- ---------- ---------- ----------
Total retail revenue 14,309 17,919 -20.1% 92,470 72,994 26.7%
Wholesale revenue 4,164 912 356.6% 6,669 31,731 -79.0%
---------- ---------- ---------- ----------
TOTAL REVENUES $ 18,473 $ 18,831 -1.9% $ 99,139 $ 104,725 -5.3%
========= ========== ========== ==========
Retail sales in thousands
of decatherms 1,311 1,336 -1.9% 9,550 8,819 8.3%
Average retail revenues per decatherm $ 10.91 $ 13.41 -18.6% $ 9.68 $ 8.28 16.9%
Retail gas revenues for the three-month period ended September 30, 2002
are lower than the same period in the prior year largely due to the refinement
of revenue amounts from the first and second quarters of 2001 in the third
quarter of 2001. The result caused the revenues for the third quarter of 2001 to
be higher than in the current year. The decrease in third quarter 2002 revenues
is also minimally due to large customers with alternative fuel capability using
oil instead of natural gas in 2002.
Retail gas revenues for the nine-month period ended September 30, 2002
were significantly higher than the same period in the prior year primarily due
to PUCN-authorized rate increases effective on February 1 and November 5, 2001.
Wholesale gas revenues for the nine-month period ended September 30,
2002 were significantly lower than the same period in 2001, primarily due to
lower wholesale sales. The three months ended September 30, 2002 reflect higher
wholesale gas revenues over the same period last year due to SPPC utilizing idle
transportation to move gas from Canada and resell it in California in order to
mitigate costs.
THREE MONTHS NINE MONTHS
ENDED SEPTEMBER 30, ENDED SEPTEMBER 30,
-------------------------------------- ---------------------------------------
Change from Change from
2002 2001 Prior Year % 2002 2001 Prior Year %
--------- ---------- ------------ ---------- ----------- ------------
PURCHASED POWER ($000): $ 164,124 $ 508,235 -67.7% $ 443,843 $ 907,830 -51.1%
Purchased Power in thousands
of MWHs 2,318 2,688 -13.8% 5,642 5,838 -3.4%
Average cost per MWH of
Purchased Power (1) $ 70.80 $ 189.08 -62.6% $ 63.29 $ 155.50 -59.3%
(1) Not including contract termination costs, discussed below
Purchased power costs were lower for the three- and nine-month periods
ended September 30, 2002, than the prior year because the majority of SPPC's
total energy requirements utilize Short-Term Firm purchased power for which
costs have significantly decreased from those a year ago. The nine-month
decrease for the period ended September 30, 2002 was offset, in part, by an
$86.8 million reserve recorded in the second quarter for terminated contracts,
which are described in more detail in "Financial Condition, Liquidity, and
Capital Resources." Prices for SPPC's risk management activities also decreased
substantially. Risk management activities include transactions entered into for
hedging purposes and to minimize purchased power costs. See SPPC's Annual Report
on Form 10-K for the year ended December 31, 2001, Item 7, Management's
Discussion and Analysis of Financial Condition and Results of Operation,
Purchased Power Procurement, for a discussion of SPPC's purchased power
procurement strategies.
54
THREE MONTHS NINE MONTHS
ENDED SEPTEMBER 30, ENDED SEPTEMBER 30,
-------------------------------------- -------------------------------------
Change from Change from
2002 2001 Prior Year % 2002 2001 Prior Year %
--------- ----------- ------------ ----------- ---------- -------------
FUEL FOR POWER GENERATION ($000) $32,804 $ 88,980 -63.1% $ 111,024 $ 237,504 -53.3%
Thousands of MWHs generated 1,264 1,593 -20.7% 3,605 4,668 -22.8%
Average fuel cost per MWH
of Generated Power $ 25.95 $ 55.86 -53.5% $ 30.80 $ 50.88 -39.5%
Fuel for Power Generation costs for the three- and nine-month periods
ended September 30, 2002 were significantly lower than the same period of the
prior year as both volumes generated and natural gas prices decreased
significantly.
THREE MONTHS NINE MONTHS
ENDED SEPTEMBER 30, ENDED SEPTEMBER 30,
-------------------------------------- -------------------------------------
Change from Change from
2002 2001 Prior Year % 2002 2001 Prior Year %
--------- ----------- ------------ ----------- ---------- -------------
GAS PURCHASED FOR RESALE ($000) $ 9,884 $ 9,294 6.3% $ 61,585 $ 105,008 -41.4%
Gas Purchased for Resale
(thousands of decatherms) 2,882 1,660 73.6% 11,384 11,610 -1.9%
Average cost per decatherm $ 3.43 $ 5.60 -38.8% $ 5.41 $ 9.04 -40.2%
Gas Purchased for Resale increased significantly for the three-month
period ended September 30, 2002, compared to the prior year as an increase
wholesale activity more than offset the decrease in gas prices. Gas Purchased
for Resale decreased significantly for the nine months ended September 30, 2002,
compared to the prior year because of much lower natural gas prices.
THREE MONTHS NINE MONTHS
ENDED SEPTEMBER 30, ENDED SEPTEMBER 30,
--------------------------------------- ----------------------------------------
Change from Change from
2002 2001 Prior Year % 2002 2001 Prior Year %
---------- ----------- ------------- ------------ ------------ ------------
DEFERRAL OF ENERGY COSTS-NET ($000)
Deferred energy costs - electric - net $ 1,799 $ (98,702) N/A $ (71,144) $ (172,437) -58.7%
Deferred energy costs disallowed - electric - - N/A 53,101 - N/A
Deferred energy costs - gas - net 4,281 3,093 38.4% 14,649 (23,354) N/A
--------- --------- ---------- -----------
Total $ 6,080 $ (95,609) N/A $ (3,394) (195,791) -98.3%
========= ========= ========== ===========
The change in Deferral of energy costs electric - net for the three-
and nine-month periods ended September 30, 2002, compared to the same periods
the prior year reflects the amortization in 2002 of prior deferred costs
pursuant to the PUCN's decision on SPPC's deferred energy rate case, which
resulted in increased rates beginning June 1, 2002. The amortization was offset,
in part, by the recording of current year deferrals of electric energy costs,
reflecting the extent to which actual fuel and purchased power costs exceeded
the fuel and purchased power costs recovered through current rates. Deferral of
energy costs-net for the nine months ended September 30, 2002, also reflects the
deferral in the second quarter of 2002 of approximately $82 million for contract
termination costs, as described in more detail in "Financial Condition,
Liquidity, and Capital Resources" and the second quarter write-off of $53
million of electric deferred energy costs incurred in the nine months ended
November 30, 2001, that were disallowed by the PUCN in their May 28, 2002,
decision on SPPC's deferred energy rate case. For both the three- and nine-month
periods ended September 30, 2001, SPPC recorded large deferrals of electric
energy costs, as shown in the table above.
SPPC's deferred energy costs gas - net for the three- and nine-month
periods ended September 30, 2002 reflects the amortization of prior deferred
costs due to the PUCN-authorized recovery of those costs. Deferred energy costs
gas - net for the three-and nine-month periods ended September 30, 2002 also
reflects additional expense to the extent natural gas costs recovered through
current rates exceeded actual natural gas costs, which had decreased
significantly. Deferral of energy costsnet for gas for the nine months ended
September 30, 2001 reflects undercollections of such costs because revenue
received from 2001 base purchased gas rates did not cover the increased cost of
natural gas experienced by SPPC.
55
THREE MONTHS NINE MONTHS
ENDED SEPTEMBER 30, ENDED SEPTEMBER 30,
--------------------------------------- -------------------------------------------
Change from Change from
2002 2001 Prior Year % 2002 2001 Prior Year %
---------- ----------- ------------ ------------ ------------ -------------
ALLOWANCE FOR OTHER FUNDS USED
DURING CONSTRUCTION ($000) $ (10) $ (19) $ 143 $ (233)
ALLOWANCE FOR BORROWED FUNDS USED
DURING CONSTRUCTION ($000) 694 566 1,314 943
--------- ---------- ------------ -----------
$ 684 $ 547 25.0% $ 1,457 $ 710 105.2%
========= ========== ============ ===========
Total allowance for funds used during construction (AFUDC) increased for
the three-month period ended September 30, 2002, compared to the prior year due
to an increase in Construction Work-in-Progress (CWIP). Total AFUDC for the
nine-month period ended September 30, 2002, increased over the prior year due to
an increase in CWIP and because AFUDC in 2001 reflected an adjustment to refine
amounts assigned to specific components of facilities that were completed in
different periods. This increase was offset, in part, by a decrease in the AFUDC
rate.
THREE MONTHS NINE MONTHS
ENDED SEPTEMBER 30, ENDED SEPTEMBER 30,
----------------------------------------- --------------------------------------
Change from Change from
(000's) 2002 2001 Prior Year % 2002 2001 Prior Year %
------------ ----------- ------------ ----------- ---------- ------------
Other operating expense $ 25,064 $ 28,222 -11.2% $ 75,687 $ 79,090 -4.3%
Maintenance expense $ 4,854 $ 5,143 -5.6% $ 15,250 $ 17,143 -11.0%
Depreciation and amortization $ 18,592 $ 17,620 5.5% $ 55,861 $ 52,328 6.8%
Income taxes $ 7,601 $ 8,630 -11.9% $ (9,037) $ 7,974 -213.3%
Interest charges on long-term debt $ 16,173 $ 15,380 5.2% $ 48,638 $ 38,479 26.4%
Interest charges - other $ 2,943 $ 1,455 102.3% $ 7,051 $ 7,437 -5.2%
Other income (expense) - net $ 1,954 $ 4,309 -54.7% $ 4,631 $ 5,322 -13.0%
Other operating expense for the three-month period ending September 30,
2002 was lower than the same period in the prior year due to a third quarter
2001 increase in the provision for uncollectible accounts of approximately $4
million, and the reversal in 2002 of SPPC's Short-term Incentive Plan accrual
offset, in part, by a 2001 decrease in the provision for uncollectible accounts
related to the California Power Exchange and increased legal fees in 2002
associated with the PUCN's Deferred Energy Rate Case decision. The decrease in
Other operating expense for the nine-month period ending September 30, 2002,
compared with the same period in the prior year, reflects the third quarter 2001
increase in the provision for uncollectible accounts, a $2.7 million increase in
the provision for uncollectible accounts in 2001 related to the California Power
Exchange, and the 2002 reversal of a $3.5 million reserve provision established
in 2001 as a result of the conclusion of electric industry restructuring in
Nevada. These decreases were offset, in part, by increased expenses in 2002
related to a new Credit and Collections Action Plan, insurance premiums, and
costs associated with obtaining a tax refund.
Maintenance costs for the three- and nine- month periods ended
September 30, 2002 were less than the same period last year as the 2001 costs
included turbine repairs on Unit 1 at Valmy.
Depreciation and amortization increased for the three-month period
ended September 30, 2002, compared to the same period in 2001 as a result of
additions to plant-in-service assets. Depreciation and amortization increased
for the nine-month period ended September 30, 2002, compared to the same period
in 2001 as a result of additions to plant-in-service assets and an increase to
depreciation of $1.8 million to reflect an adjustment to depreciation rates
related to combustion turbines. These increases were offset in part by a
PUCN-ordered reduction in depreciation rates that was implemented June 1, 2002.
SPPC recorded lower operating income tax expense for the three months
ended September 30, 2002, compared to the same period in 2001. This decrease
resulted from a 2001 reclassification of income taxes included in other income
to operating income taxes that more than offset taxes on higher pre-tax income
in 2002. For the nine months ended September 30, 2002, SPPC recorded an income
tax benefit compared to income tax expense for the same period in 2001, as a
result of a pre-tax loss in the current year compared to pre-tax income in the
prior year.
Interest charges on long-term debt for the three-month period ending
September 30, 2002, increased over the same period in 2001 due to debt incurred
at higher interest rates. An increased level of long-term debt at higher rates
was also responsible for the increase in interest for the nine months ended
September 30, 2002, over the comparable period in 2001.
56
Interest charges-other increased during the three-month period ending
September 30, 2002, compared to 2001 due to higher short-term borrowings in the
2002 period. However, the decrease for the nine months ended September 30, 2002,
as compared to the same period in 2001 was attributable to lower commercial
paper and short-term debt balances during the nine-month period in 2002.
Other income (expense) - net for the three months ended September 30,
2002, decreased compared to the same period in the prior year primarily due to a
decrease in carrying charges for deferred energy. The decrease in Other income
(expense) - net for the nine months ended September 30, 2002, compared to the
prior year also reflects the second quarter 2002 write-off of approximately $2
million, net of taxes, of carrying charges on deferred energy costs that were
disallowed by the PUCN in their May 28, 2002 decision on SPPC's deferred energy
rate case. The write-off was offset in part by the recording of current year
carrying charges on deferred fuel and purchased power costs.
ANALYSIS OF CASH FLOWS
SPPC's cash flows during the nine months ended September 30, 2002,
improved compared to the same period in 2001, as increases in cash flows from
operating and financing activities were offset in part by cash used for
investing activities. Although SPPC recorded a loss for the nine months ended
September 30, 2002, compared to net income for the same period in 2001, the
current year's loss resulted largely from the write-off of disallowed deferred
energy costs for which the cash outflow had occurred in 2001. Other factors
contributing to 2002's improved cash flows from operating activities include
lower energy prices and improved collections on accounts receivable, offset in
part by lower accounts payable balances. Also, cash flows from operating
activities in the current year reflect the receipt of an income tax refund. Cash
flows from investing activities decreased in 2002 because 2001 investing
activities included cash provided from the sale of the assets of SPPC's water
business. Cash flows from financing activities increased due to an increase in
short-term borrowings and a decrease in common dividends paid in 2002, offset in
part by a decrease in net long-term debt issued in 2002, compared to the same
period in 2001.
FINANCIAL CONDITION, LIQUIDITY AND CAPITAL RESOURCES
SPPC had cash and cash equivalents of approximately $143.9 million at
September 30, 2002, and approximately $56.2 million at October 31, 2002.
As discussed in "Management's Discussion and Analysis of Financial
Condition and Results of Operations - Sierra Pacific Power Company -
Construction Expenditures and Financing" and " - Capital Structure" in the
Annual Report on Form 10-K for the year ended December 31, 2001, SPPC
anticipated having capital requirements for construction costs and for the
repayment of maturing short-term and long-term debt during 2002 totaling
approximately $189 million, which SPPC would need to fund through a combination
of (i) internally generated funds, (ii) the issuance of short-term debt, and
(iii) capital contributions from SPR.
On March 29 and April 1, 2002, following the decision by the PUCN in
NPC's deferred energy rate case, S&P and Moody's lowered SPPC's unsecured debt
ratings to below investment grade. On April 23 and 24, 2002, SPPC's unsecured
debt ratings were further downgraded and its secured debt ratings were
downgraded to below investment grade. The decision of the PUCN on May 29, 2002
on SPPC's deferred energy application to disallow $53.1 million of deferred
purchased fuel and power costs accumulated between March 1, 2001 and November
30, 2001 did not result in any further downgrades of SPPC's securities. As a
result of the downgrades, SPPC's ability to access the capital markets to raise
funds is severely limited. Since SPR's credit ratings were similarly
downgraded, SPR's ability to make capital contributions to SPPC also became
severely limited.
In connection with the credit ratings downgrades referenced above, SPPC
lost its A2/P2 commercial paper ratings and can no longer issue commercial
paper. At the time, SPPC had a commercial paper balance outstanding of $47.7
million with a weighted average interest rate of 2.49%. SPPC paid off its
maturing commercial paper with the proceeds of borrowings under its credit
facility and terminated its commercial paper program on May 28, 2002. SPPC does
not expect to have direct access to the commercial paper market for the
foreseeable future.
SPPC's $150 million unsecured revolving credit facility was also
affected by the downgrade in SPPC's credit rating. Under this facility, SPPC was
required, in the event of a ratings downgrade of its senior unsecured debt, to
secure the facility with General and Refunding Mortgage Bonds. In satisfaction
of its obligation to secure the credit facility, on April 8, 2002, SPPC issued
and delivered its General and Refunding Mortgage Bond, Series B, due November
28, 2002, in the principal amount of $150 million, to the Administrative Agent
for the credit facility. As of May 10, 2002, SPPC had borrowed the entire $150
million of funds available under its credit facility to, in part, pay off
maturing commercial paper, maintaining a cash balance at SPPC. This facility was
paid in full and terminated on October 31, 2002 with available cash and proceeds
from SPPC's $100 million Term Loan Facility.
On October 29, 2002, SPPC established an accounts receivables purchase
facility of up to $75 million, which was arranged by Lehman Brothers. If SPPC
elects to activate the receivables purchase facility, SPPC will sell all of its
accounts
57
receivable generated from the sale of electricity to customers to its newly
created bankruptcy remote special purpose subsidiary. The receivables sales will
be without recourse except for breaches of customary representations and
warranties made at the time of sale. The subsidiary will, in turn, sell these
receivables to a bankruptcy-remote subsidiary of SPR. SPR's subsidiary will
issue variable rate revolving notes backed by the purchased receivables. Lehman
Brothers Holdings, Inc. will be the sole initial committed purchaser of all of
the variable rate revolving notes. The agreements relating to the receivables
purchase facility contain various conditions to purchase, covenants and trigger
events, termination events and other provisions customary in receivables
transactions. In addition, the agreements contain a limitation on the payment of
dividends by SPPC to SPR that is identical to the limitation contained in SPPC's
Term Loan Agreement, described below. In connection with SPPC's receivables
facility, SPR has agreed to guaranty SPPC's performance of certain obligations
as a seller and servicer under the facility.
SPPC has agreed to issue $75 million principal amount of its General
and Refunding Mortgage Bonds upon activation of the accounts receivables
purchase facility. The full principal amount of the Bond would secure certain of
SPPC's obligations as seller and servicer, plus certain interest, fees and
expenses thereon to the extent not paid when due, regardless of the actual
amounts owing with respect to the secured obligations. As a result, in the event
of an SPPC bankruptcy or liquidation, the holder of the Bond securing the
receivables facility may recover more on a pro rata basis than the holders of
other General and Refunding Mortgage securities, who could recover less on a pro
rata basis, than they otherwise would recover. However, in no event will the
holder of the Bond recover more than the amount of obligations secured by the
Bond.
SPPC intends to use the accounts receivables purchase facility as a
back-up liquidity facility and does not plan to activate this facility in the
foreseeable future. SPPC may activate the facility within five days upon the
delivery of certain customary funding documentation and the delivery of the $75
million General and Refunding Mortgage Bond.
SPPC's first mortgage indenture creates a first priority lien on
substantially all of SPPC's properties in Nevada and California. As of September
30, 2002, $505.3 million of SPPC's first mortgage bonds were outstanding.
Although the first mortgage indenture allows SPPC to issue additional mortgage
bonds on the basis of (i) 60% of net utility property additions and/or (ii) the
principal amount of retired mortgage bonds, SPPC agreed in its General and
Refunding Mortgage Indenture that it would not issue any additional first
mortgage bonds.
SPPC's General and Refunding Mortgage Indenture creates a lien on
substantially all of SPPC's properties in Nevada that is junior to the lien of
the first mortgage indenture. As of September 30, 2002, $470 million of SPPC's
General and Refunding Mortgage bonds were outstanding. Additional securities may
be issued under the General and Refunding Mortgage Indenture on the basis of (i)
70% of net utility property additions, (ii) the principal amount of retired
General and Refunding Mortgage bonds, and/or (iii) the principal amount of first
mortgage bonds retired after delivery to the indenture trustee of the initial
expert's certificate under the General and Refunding Mortgage Indenture. At
September 30, 2002, SPPC had the capacity to issue approximately $363 million of
additional General and Refunding Mortgage securities, not including the issuance
of SPPC's $100 million Series C General and Refunding Mortgage Bond which
secures SPPC's Term Loan Facility and the retirement of $150 million of Series B
General and Refunding Mortgage Bonds that secured SPPC's terminated credit
facility. However, the financial covenants contained in SPPC's Term Loan
Agreement and Receivable Purchase Facility Agreements limit SPPC's ability to
issue additional General and Refunding Mortgage Securities or other debt. SPPC
will reserve $75 million of General and Refunding Mortgage Bonds for issuance
upon the initial funding of its receivables purchase facility.
SPPC also has the ability to release property from the liens of the two
mortgage indentures on the basis of net property additions, cash and/or retired
bonds. To the extent SPPC releases property from the lien of its General and
Refunding Mortgage Indenture, it will reduce the amount of bonds issuable under
that indenture.
In early May of 2002, Enron, MSCG, Reliant Energy Services, Inc. and
several smaller suppliers terminated their power deliveries to SPPC. These
terminating suppliers asserted their contractual right under the WSPP agreement
to terminate deliveries based upon SPPC's alleged failure to provide adequate
assurance of its performance under the WSPP agreement to any of its suppliers.
Each of these terminating suppliers has asserted, or has indicated that it will
assert, a claim for liquidated damages under the terminated power supply
contracts.
On June 5, 2002, Enron filed suit in its bankruptcy case in the
Bankruptcy Court for the Southern District of New York asserting claims for
liquidated damages related to the termination of its power supply agreements
with SPPC of approximately $93 million. SPPC has filed claims in the Bankruptcy
Court alleging, among other things, that SPPC was fraudulently induced to enter
into the agreements with Enron. Enron's claims are also subject to SPPC's
defense, as raised in SPPC's motions to dismiss and or to stay all proceedings,
that such claims are already at issue in SPPC's FERC proceeding against Enron
and others under Section 206 of the Federal Power Act challenging the contract
prices of the terminated power supply agreements. Enron initially filed a motion
for partial summary judgment to require SPPC to make immediate payment of the
full amount of Enron's claim, pending final resolution of the lawsuit. Enron
subsequently filed another motion for summary judgment seeking final payment of
its damages claim. Hearings, including arguments regarding the issue of FERC's
primary jurisdiction over the contract claims, were conducted in September,
October, and early November 2002. On November 14, 2002, the judge is expected to
rule on the Utilities' motion to dismiss or stay until the FERC rules on the
Utilities' Section 206 filing. If the judge decides not to stay Enron's lawsuit
pending the outcome
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of the FERC hearings, the judge would then schedule additional arguments with
respect to Enron's motion for summary judgment. At this time, the outcome of a
decision in this matter cannot be predicted. An adverse decision on Enron's
motion for summary judgment or an adverse decision in the lawsuit would have a
material adverse affect on the financial condition and liquidity of SPPC and
would render its ability to continue to operate outside of bankruptcy uncertain.
On May 23, 2002, SPPC defeased its 2% First Mortgage Bonds due 2011, 5%
Series Y First Mortgage Bonds due 2024, and 2% Series Z First Mortgage Bonds due
2004 by depositing $1.2 million, $3.1 million, and $45,000, respectively, with
its First Mortgage Trustee. These First Mortgage Bonds were issued to secure
loans made to SPPC by the United States under the Rural Electrification Act of
1936, as amended.
On October 30, 2002, SPPC entered into a $100 million Term Loan
Agreement with several lenders and Lehman Commercial Paper Inc., as
Administrative Agent. The net proceeds of $97 million from the Term Loan
Facility, along with available cash, were used to pay off SPPC's $150 million
credit facility, which was secured by a Series B General and Refunding Mortgage
Bond. SPPC's Term Loan Agreement limits the amount of dividends that SPPC may
pay to SPR. However, that limitation does not apply to payments by SPPC to
enable SPR to pay its reasonable fees and expenses (including, but not limited
to, interest on SPR's indebtedness and payment obligations on account of SPR's
premium income equity securities) provided that those payments do not exceed $90
million, $80 million and $60 million in the aggregate for the twelve month
periods ending on October 30, 2003, 2004 and 2005, respectively. The Term Loan
Agreement also permits SPPC to make dividend payments to SPR in an aggregate
amount not to exceed $10 million during the term of the Term Loan Agreement. In
addition, SPPC may make dividend payments to SPR in excess of the amounts
described above so long as, at the time of the payment and after giving effect
to the payment, there are no defaults or events of default under the Term Loan
Agreement, and such amounts, when aggregated with the amount of dividends paid
to SPR by SPPC since the date of execution of the Term Loan Agreement, does not
exceed the sum of (i) 50% of SPPC's Consolidated Net Income for the period
commencing January 1, 2003 and ending with last day of fiscal quarter most
recently completed prior to the date of the contemplated dividend payment plus
(ii) the aggregate amount of cash received by SPPC from SPR as equity
contributions on its common stock during such period.
SPPC's Term Loan Agreement requires that SPPC maintain a ratio of
consolidated total debt to consolidated total capitalization at all times during
each of the following quarters in an amount not to exceed (i) .650 to 1.0 for
the fiscal quarters ended December 31, 2002 through December 31, 2003, (ii) .625
to 1.0 for the fiscal quarters ended March 31, 2004 through December 31, 2004,
and (iii) .600 to 1.0 for the fiscal quarter ended March 31, 2005 and for each
fiscal quarter thereafter. SPPC's Term Loan Agreement also requires that SPPC
maintain a consolidated interest coverage ratio for any four consecutive fiscal
quarters ending with the fiscal quarter set forth below of not less than (i)
1.75 to 1.00 for the fiscal quarters ended December 31, 2002 and March 31, 2003,
(ii) 2.50 to 1.0 for the fiscal quarters ended June 30, 2003 through December
31, 2003, (iii) 2.75 to 1.0 for the fiscal quarters ended March 31, 2004 through
September 30, 2004, and (iv) 3.00 to 1.0 for the fiscal quarter ended December
31, 2004 and for each fiscal quarter thereafter. The Term Loan Facility, which
is secured by a $100 million Series C General and Refunding Mortgage Bond, will
expire October 31, 2005.
SPR has a qualified pension plan (the "Plan") that covers substantially
all employees of SPR, NPC and SPPC. The annual net benefit cost for the Plan is
expected to increase for 2003 by an amount between $12 million and $22 million
over the 2002 cost of $18.4 million. Also, the Plan currently has assets with a
fair value that is less than the present value of the accumulated benefit
obligation under the Plan. While the amount of the deficiency has not yet been
determined, SPR and the Utilities expect their combined minimum funding
requirement for 2002 will be at least $24 million. However, SPR and the
Utilities do not expect that their funding obligation for 2002 will have a
material adverse effect on their liquidity.
SPPC's Washoe County, Nevada, Water Facilities Refunding Revenue
Bonds, Series 2001 in the aggregate principal amount of $80,000,000, will be
subject to remarketing on May 1, 2003. In the event that these bonds cannot be
successfully remarketed on that date, SPPC will be required to purchase the
outstanding bonds at a price of 100% of the principal amount, plus accrued
interest.
SPPC's future liquidity could be significantly affected by unfavorable
rulings by the PUCN in future SPPC or NPC rate cases. Both S&P and Moody's have
SPPC's credit ratings on "watch negative" or "possible downgrade," and any
further downgrades could further preclude SPPC's access to the capital markets
and could adversely affect SPPC's ability to continue purchasing power and fuel.
Adverse developments with respect to any one or a combination of the factors and
contingencies set forth above could cause SPPC to become insolvent and could
render SPPC's ability to continue to operate outside of bankruptcy uncertain.
SIERRA PACIFIC RESOURCES (HOLDING COMPANY)
The Condensed Consolidated Statements of Operations of SPR include the
operating results of the holding company. For the nine months ending September
30, 2002, the holding company recognized higher interest costs, $53.8 million in
2002 compared to $40.3 million in 2001, due primarily to the issuance of $345
million of additional debt associated with its issuance of Premium Income Equity
Securities in November of 2001.
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TUSCARORA GAS PIPELINE COMPANY
The Condensed Consolidated Statements of Operations of SPR include the
operating results of Tuscarora Gas Pipeline Company (TGPC), a wholly owned
subsidiary of SPR. For the three-and nine-month periods ended September 30,
2002, TGPC contributed $.7 million and $2.3 million, respectively, in net
income. For the three-and nine-month periods ended September 30, 2001, TGPC
contributed $.6 million and $1.9 million, respectively, in net income.
E-THREE
The Condensed Consolidated Statements of Operations of SPR include the
operating results of e-three, a wholly owned subsidiary of SPR. For the
three-and nine-month periods ended September 30, 2002, e-three incurred
net losses of $14,000 and $.8 million, respectively. For the three-and
nine-month periods ended September 30, 2001, e-three contributed $.3
million and $.2 million in net income, respectively.
SIERRA PACIFIC COMMUNICATIONS
The Condensed Consolidated Statements of Operations of SPR include the
operating results of Sierra Pacific Communications (SPC), a wholly owned
subsidiary of SPR. For the three- and nine-month periods ended September 30,
2002, SPC incurred net losses of $1.1 million and $2.4 million, respectively.
SPC incurred net losses of $1.7 million and $2.4 million, respectively, for the
three- and nine-month periods ended September 30, 2001.
In April 2000 Sierra Touch America, LLC, a partnership between SPC and
Touch America, was formed to construct a fiber optic line between Salt Lake
City, Utah and Sacramento, California. On September 9, 2002, SPC purchased and
leased certain telecommunications and fiber optic assets from Touch America in
exchange for SPC's partnership units in Sierra Touch America and the execution
of a $35 million promissory note for a total of $48.5 million. The assets are
currently under construction and are scheduled for completion in May 2003.
Of the $48.5 million total, $32.5 million relates to the purchase of a
conduit from Sacramento to Salt Lake City, additional conduit in the Reno,
Nevada metropolitan area, and real property in Utah. $16 million of the total
was for the lease of two conduits from Reno to Spanish Fork, Utah and the lease
of 60 strands of fiber from Sacramento to Salt Lake City.
The promissory note accrues interest at 8% per annum. The first of
twelve monthly payments of $3.3 million will commence on July 31, 2003 and
continue until June 30, 2004, at which time all outstanding amounts will be due
and payable. The promissory note is secured by all of SPC's assets, and
prepayments will shorten the length of the loan, but not reduce the installment
payments.
Also, on September 11, 2002, SPC entered into an agreement to sell to a
telecommunications carrier for $20 million the Sacramento to Salt Lake City
conduit acquired from Touch America, and will convey all rights to the conduit
when construction is completed in May 2003.
REGULATORY MATTERS
Substantially all of the utility operations of both NPC and SPPC are
conducted in Nevada. As a result both Utilities are subject to utility
regulation within Nevada and therefore deal with many of the same regulatory
issues.
NEVADA MATTERS
NEVADA POWER COMPANY GENERAL RATE CASE (NPC)
On October 1, 2001, NPC filed an application with the PUCN seeking an
electric general rate increase. This application was mandated by AB 369. On
December 21, 2001, NPC filed a Certification to its general rate filing updating
costs and revenues pursuant to Nevada regulations. In the certification filing,
NPC requested an increase in its general rates charged to all classes of
electric customers designed to produce an increase in annual electric revenues
of $22.7 million, which is an overall 1.7% rate increase. The application also
sought a return on common equity ("ROE") for Nevada Power's total electric
operations of 12.25% and an overall rate of return ("ROR") of 9.30%.
On March 27, 2002, the PUCN issued its decision on the general rate
application, ordering a $43 million revenue decrease with an ROE of 10.1% and
ROR of 8.37%. The effective date for the decision was April 1, 2002. The
decision also resulted in adverse adjustments to depreciation aggregating $7.9
million, and the adverse treatment of approximately $5 million of revenues
related to SO2 Allowances. On April 15, 2002, NPC filed a petition for
reconsideration with the PUCN. In the petition, NPC raised six issues for
reconsideration: the treatment of revenues related to SO2 Allowances, in
particular the
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calculation of the annual amortization amount, which appears to be in error; the
adjustment for "excess" capital investment related to common facilities at the
Harry Allen generating station; the rejection of adjustments to accumulated
depreciation reserves related to the establishment of revised depreciation rates
for transmission, distribution and common facilities; the delay in allowing NPC
to recover its merger costs without the benefit of carrying charges; the finding
that NPC has no need for and is entitled to zero funds cash working capital; and
the establishment of a 10.1% ROE. On May 24, 2002, the PUCN issued an order on
the petition for reconsideration. In its order the PUCN reaffirmed its findings
in the original order for the issues related to "excess" capital investment at
the Harry Allen generating station, merger costs, cash working capital, and the
10.1% ROE. The PUCN, however, did modify its original order to include
adjustments related to SO2 Allowances and depreciation issues. Revised rates for
these changes went into effect on June 1, 2002.
NEVADA POWER COMPANY DEFERRED ENERGY CASE (NPC)
On November 30, 2001, NPC filed an application with the PUCN seeking to
clear deferred balances for purchased fuel and power costs accumulated between
March 1, 2001 through September 30, 2001,as mandated by AB 369. The application
sought to establish a Deferred Energy Accounting Adjustment ("DEAA") rate to
clear accumulated purchased fuel and power costs of $922 million and spread the
recovery of the deferred costs, together with a carrying charge, over a period
of not more than three years.
On March 29, 2002, the PUCN issued its decision on the deferred energy
application, allowing NPC to recover $478 million over a three-year period, but
disallowing $434 million of deferred purchased fuel and power costs and $10
million in carrying charges. The order states that the disallowance was based on
alleged imprudence in incurring the disallowed costs. On April 11, 2002, NPC
filed a lawsuit in the First District Court of Nevada seeking to reverse
portions of the PUCN's decision. NPC asserts that, as a result of the PUCN's
decision, NPC's credit rating was reduced to below investment grade, SPR
suffered a reduction in its equity market capitalization by approximately 41%,
and the disallowed costs are effectively imposed upon SPR's shareholders.
In its lawsuit, NPC alleges that the order of the PUCN is: in violation
of constitutional and statutory provisions; made upon unlawful procedure;
affected by other error of law; clearly erroneous in view of the reliable,
probative and substantial evidence on the whole record; arbitrary and capricious
and characterized by abuse of discretion. NPC also states that its decisions
with respect to the purchase of power during the energy crisis in the western
United States were made prudently, as required under AB 369. In early 2001, the
PUCN and the Nevada State Legislature expressly required that NPC secure
sufficient, safe and reliable power for anticipated summer loads and needs for
the summer of 2001. Prior to the April 2001 enactment of AB 369, which prohibits
until July 2003 all divestiture of generation assets, NPC was operating under an
order of the PUCN to divest itself of its electric generating plants. To meet
this requirement, NPC had engaged in an open auction process that led to the
signing of asset sale agreements for a number of its plants, in connection with
which, NPC entered into long-term purchase power contracts with the potential
buyers that would have availed NPC of reasonably priced purchase power over a
long-term period. In its petition, NPC challenges the disallowance by the PUCN
of $180 million of its deferred energy costs relating to an informal offer made
by an agent for Merrill Lynch for the delivery of energy from January 2001 to
March 2003. In addition to certain procedural questions relating to the PUCN's
finding with respect to the Merrill Lynch informal offer, NPC asserts that the
energy being negotiated was not firm (uninterruptible), the obligations, costs
and arrangements for delivery in the informal offer were not specified, the cost
of the energy proposed under the informal offer was above then-current market
price, and that the supplier was a minor market participant and the magnitude of
the transaction proposed was more than 45 times its previously combined annual
transactions.
NPC's lawsuit requests that the District Court reverse portions of the
PUCN's order and remand the matter to the PUCN with direction that the PUCN
authorize NPC to immediately establish rates that would allow NPC to recover its
entire deferred energy balance of $922 million, with a carrying charge, over
three years. A hearing on this matter has been scheduled for February 2003. At
this time, NPC is not able to predict the outcome or the timing of a decision in
this matter.
Various interveners in NPC's deferred energy case before the PUCN filed
petitions with the PUCN for reconsideration of the PUCN's order, seeking
additional disallowances of between $12.8 million and $488 million. On May 24,
2002, the PUCN issued an order denying any further disallowances and granted NPC
the authority to increase the deferred energy cost recovery charge for the month
of June 2002 by one cent per kilowatt-hour. This increase accelerated the
recovery of the deferred balance by approximately $16 million for the month of
June 2002 only. The BCP of the Nevada Attorney General's Office has since filed
a petition in NPC's pending state court case seeking additional disallowances.
SIERRA PACIFIC POWER COMPANY GENERAL RATE CASE (SPPC)
On November 30, 2001, SPPC filed an application with the PUCN seeking
an electric general rate increase. This application was mandated by AB 369. On
February 28, 2002, SPPC filed a certification to its general rate filing,
updating costs and revenues pursuant to Nevada regulations. In the certification
filing, SPPC requested an increase in its general rates charged to all classes
of electric customers, which were designed to produce an increase in annual
electric revenues of
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$15.9 million representing an overall 2.4% rate increase. The application also
sought an ROE for SPPC's total electric operations of 12.25% and an overall ROR
of 9.42%.
On May 28, 2002, the PUCN issued its decision on the general rate
application, ordering a $15.3 million revenue decrease with an ROE of 10.17% and
ROR of 8.61%. The effective date of the decision was June 1, 2002. Various
parties to the case had filed petitions for reconsideration of the order. On
July 18, 2002, the PUCN issued a final decision on the petitions for
reconsideration, clarifying issues contained its original order. As a result of
the clarifications, SPPC was ordered to change the total annual electric revenue
decrease from $15.3 million to $15.8 million.
On August 19, 2002, Barrick filed a lawsuit in the First District Court
of Nevada seeking to reverse portions of the decision related to the High
Voltage Distribution facilities contained in the general rate case order.
Barrick alleges that the order of the PUCN is: in violation of constitutional
and statutory provisions; in excess of the statutory authority of the PUCN;
affected by error of law: clearly erroneous in view of the reliable, probative
and substantial evidence on the whole record; and arbitrary or capricious or
characterized by abuse of discretion. A hearing date has not yet been scheduled.
At this time, SPPC is not able to predict the outcome or the timing of a
decision in this matter.
SIERRA PACIFIC POWER COMPANY DEFERRED ENERGY (SPPC)
On February 1, 2002, SPPC filed an application with the PUCN seeking to
clear deferred balances for purchased fuel and power costs accumulated between
March 1, 2001 and November 30, 2001. This application was mandated by AB 369.
The application sought to establish a DEAA rate to clear accumulated purchased
fuel and power costs of $205 million and spread the cost recovery over a period
of not more than three years. It also sought to recalculate the Base Tariff
Energy Rate to reflect anticipated ongoing purchased fuel and power costs. The
total rate increase resulting from the requested DEAA would have amounted to
9.8%. Various parties intervened in SPPC's deferred energy rate case including
the Staff of the PUCN, the BCP from the Nevada Attorney General's office, and
Barrick, among others. Interveners proposed disallowances ranging from $40.4
million to $361 million.
On May 28, 2002, the PUCN issued its decision on the deferred energy
application, allowing SPPC three years to collect $150 million but disallowing
$53 million of deferred purchased fuel and power costs and $2 million in
carrying charges. Several of the interveners from SPPC's deferred energy rate
case filed petitions with the PUCN for reconsideration of its decision, seeking
an additional disallowance of $126 million. On July 18, 2002, the petitions for
reconsideration were granted in part and denied in part by the PUCN, but no
additional disallowances to the deferred energy balance resulted from that
decision.
On August 22, 2002, SPPC filed a lawsuit in the First District Court of
Nevada seeking to reverse portions of the decision of the PUCN denying the
recovery of deferred energy costs incurred by SPPC on behalf of its customers in
2001 on the grounds that such power costs were not prudently incurred. In its
lawsuit, SPPC alleges that the order of the PUCN is: in violation of
constitutional and statutory provisions; in excess of the statutory authority of
the PUCN; made upon unlawful procedure; affected by other error of law; clearly
erroneous in view of the reliable, probative and substantial evidence on the
whole record; arbitrary and capricious and characterized by abuse of discretion.
SPPC's lawsuit requests that the District Court reverse portions of the order of
the PUCN and remand the matter to the PUCN with direction that the PUCN
authorize SPPC to immediately establish rates that would allow SPPC to recover
its entire deferred energy balance of $205 million, with a carrying charge, over
three years. A hearing date has not yet been scheduled.
On August 22, 2002, the BCP from the Nevada Attorney General's office
also filed a lawsuit in the First District Court of Nevada seeking to set aside
the decision of the PUCN so that SPPC is not authorized to reflect in rates any
costs for fuel and purchased power which may have been imprudently incurred. A
hearing date has not yet been scheduled. At this time, SPPC is not able to
predict the outcome or the timing of a decision in these matters.
CUSTOMERS FILE UNDER AB 661 (NPC, SPPC)
Assembly Bill 661 (AB 661), passed by the Nevada legislature in 2001,
allows commercial and governmental customers with an average demand greater than
1 MW to select new energy suppliers. The Utilities would continue to provide
transmission, distribution, metering and billing services to such customers. AB
661 requires customers wishing to choose a new supplier to receive the approval
of the PUCN and meet public interest standards. In particular, departing
customers must secure new energy resources that are not under contract to the
Utilities, the departure must not burden the Utilities with increased costs or
cause any remaining customers to pay increased costs, and the departing
customers must pay their portion of any deferred energy balances. The PUCN
adopted regulations prescribing the criteria that will be used to determine if
there will be negative impacts to remaining customers or the Utility. These
regulations place certain limits upon the departure of NPC customers until 2003;
most significantly, the amount of load departing is limited to approximately
1100 MW in peak conditions. Customers wishing to choose a new supplier must
provide 180-day notice to the Utilities. AB 661 permitted
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customers to file applications with the PUCN beginning in the fourth quarter of
2001, and customers could begin to receive service from new suppliers by
mid-2002.
On January 10, 2002, Barrick, an approximately 130 MW SPPC customer,
filed an application with the PUCN to exit the system of SPPC and to purchase
energy, capacity and ancillary services from a provider other than SPPC. A
stipulation filed on March 8, 2002 by SPPC and Barrick was rejected by the PUCN
on March 29, 2002. The PUCN indicated a desire for more information regarding
transmission access, the definition of a new electric resource, and the
computation of exit fees. Subsequently, a second application was filed and later
withdrawn by Barrick. Barrick has filed a new application with the PUCN. Barrick
could receive service from a new supplier as early as May 1, 2003. A hearing
date on this application has not yet been scheduled.
During May 2002, Rouse Fashion Show Management LLC, Coast Hotels and
Casinos Inc., Station Casinos, Inc., Gordon Gaming Corporation, MGM Mirage, and
Park Place Entertainment filed separate applications with the PUCN to exit the
system of NPC and to purchase energy, capacity and ancillary services from a
provider other than NPC. The loads of these customers aggregate 260 MW on peak.
Hearings on the applications of all the customers except Park Place
Entertainment were completed on July 19, and the PUCN issued its decision on
July 31, 2002. In its decision, the PUCN approved the applications of these
customers to choose an energy supplier other than NPC. The earliest any of these
customers could have begun taking energy from an alternative provider was
November 1, 2002. If all five customers whose applications were approved were to
leave its system, NPC would incur an annual loss in revenue of $48 million,
which would be offset by a reduction in costs, primarily for fuel and purchased
power, of $46 million with the difference being paid by exit fees from the
departing customers. These customers will also be responsible for their share of
balances in NPC's deferred energy accounts until the time they leave and must
continue to pay their share of these balances after they leave. For example, if
all five customers whose applications were approved had left the system on
November 1, 2002, their remaining share of NPC's previously approved deferred
energy balance is estimated to have been $27 million. Additionally, these
departing customers would be responsible for paying their share of the yet to be
approved accumulated deferred energy balances from October 1, 2001 to their date
of departure. They will also remain accountable to any rulings made by the
District Court on legal actions brought in NPC's past deferred energy case. They
could also benefit from any refunds that might be granted on power contracts
under review with the FERC.
A hearing on the application of Park Place Entertainment was held on
August 2, 2002, and on August 12, 2002, the PUCN approved the application with
terms and conditions similar to those described above for the aforementioned
five customers.
All of the customers approved for departure are addressing compliance
items in their PUCN orders. To date, none of these customers has provided
official notice of departure. Other customers are continuing to express an
interest, and additional gaming properties, including Monte Carlo, Riviera, and
Imperial Palace, have indicated intent to potentially procure energy sources
from a new supplier.
Any customer who departs NPC's system and later decides to return to
NPC as their energy provider will be charged for their energy at a rate
equivalent to NPC's incremental cost of service. A stipulation regarding the
incremental cost of service tariff is currently pending before the PUCN.
NEVADA POWER COMPANY ADDITIONAL FINANCE AUTHORITY (NPC)
On April 26, 2002, Nevada Power filed with the PUCN an application
seeking additional finance authority. In the application NPC asked for authority
to issue secured long-term debt in an aggregate amount not to exceed $450
million through the period ending 2003. On June 19, 2002, the PUCN issued a
Compliance Order, Docket No. 02-4037, authorizing NPC to issue $300 million of
long-term debt. The PUCN order requires NPC, if it is able, to issue the $50
million of remaining authorized short-term debt, before it issues any long-term
debt authorized by the order. Moreover, the order provides that, if NPC is able
to issue short-term debt at any point prior to September 1, 2002 (whether or not
the issuance of short-term debt actually occurs), the amount of long-term debt
authorized by the order will be automatically reduced to $250 million. Other
provisions of the PUCN's order are discussed in NPC's "Financial Condition,
Liquidity, and Capital Resources."
ANNUAL PURCHASED GAS COST ADJUSTMENT (SPPC)
On July 1, 2002, SPPC filed a Purchased Gas Cost Adjustment application
for its natural gas local distribution company. In the application SPPC has
asked for a reduction of $0.05421 to its Base Purchased Gas Rate (BPGR) and an
increase in its Balancing Account Adjustment charge (BAA) by the same amount.
This request would result in no change to revenues or customer rates. Hearings
have been scheduled to begin November 18, 2002. This docket was consolidated for
hearing purposes with the Liquid Petroleum Gas Cost Adjustment below.
LIQUID PETROLEUM GAS COST ADJUSTMENT (SPPC)
On July 1, 2002, SPPC filed an application to adjust rates for its
liquid petroleum gas (LPG) distribution company. In the application SPPC has
asked for an increase of $0.04133 to its current LPG rate and a decrease in its
Balancing Account
63
Adjustment charge (BAA) by the same amount. This request would result in no
change to revenues or customer rates. Hearings have been scheduled to begin
November 18, 2002. This docket was consolidated for hearing purposes with the
annual Purchased Gas Cost Adjustment above.
CALIFORNIA MATTERS (SPPC)
RATE STABILIZATION PLAN
SPPC serves approximately 44,500 customers in California. On June 29,
2001, SPPC filed with the California Public Utilities Commission (CPUC) a Rate
Stabilization Plan, which includes two phases. Phase One, which was also filed
June 29, 2001, is an emergency electric rate increase of $10.2 million annually
or 26%. If granted, the typical residential monthly electric bill for a customer
using 650 kilowatt-hours would increase from approximately $47.12 to $60.12. On
August 14, 2001, a pre-hearing conference was held, and a procedural order was
established. On September 27, 2001, the Administrative Law Judge issued an order
stating that no interim or emergency relief could be granted until the end of
the "rate freeze" period mandated by the California restructuring law for
recovery of stranded costs. In accordance with the judge's request, on October
26, 2001, SPPC filed an amendment to its application declaring the rate freeze
period to be over. On December 5 and 11, 2001, hearings were held and on January
11, 2002 and January 25, 2002 opening briefs and reply briefs were filed. On
July 17, 2002, the CPUC approved the requested 2-cent per kilowatt-hour
surcharge, subject to refund and interest pending the outcome of Phase Two. The
increase of $10 million or 26% is applicable to all customers except those
eligible for low-income and medical-needs rates and went into effect July 18,
2002.
Phase Two of the Rate Stabilization Plan was filed with the CPUC on
April 1, 2002, and includes a general rate case and requests the CPUC to
reinstate the Energy Cost Adjustment Clause, which would allow SPPC to file for
periodic rate adjustments to reflect its actual costs for wholesale energy
supplies. Phase Two also includes a proposal to terminate the 10% rate reduction
mandated by AB 1890, but does not include a performance -based rate-making
proposal. This request was for an additional overall increase in revenues of
17.1%, or $8.9 million annually. Hearings are scheduled for February 25 through
March 3, 2003, and a decision by the CPUC is expected in the third quarter of
2003.
CALIFORNIA ASSEMBLY BILL 1235 (SPPC)
On September 24, 2002, the Governor of California signed into law
Assembly Bill 1235 (AB 1235), which allows the transfer of hydroelectric plants
along the Truckee River from SPPC to the Truckee Meadows Water Authority (TMWA).
AB 1235 effectively amends previous California legislation (AB 6X) that
prevented until 2006 private utilities from selling any power plants that
provide energy to California customers. AB 1235 provides an exemption for the
four "run-of-the-river" hydroelectric plants that SPPC sold to TMWA as part of
the sale of its water business in June 2001. AB 1235 was effective September 24,
2002, and the process to transfer the plants from SPPC to TMWA has begun. The
CPUC must now review and approve the transfer of the plants.
FERC MATTERS (SPPC, NPC)
FERC 206 COMPLAINTS
In December 2001, the Utilities filed ten wholesale purchased power
complaints with the FERC under Section 206 of the Federal Power Act seeking
their review of certain forward power purchase contracts that the Utilities
entered into prior to the price caps established by the FERC during the western
United States utility crisis. The Utilities believe the prices under these
purchased power contracts are unjust and unreasonable. The FERC ordered the case
set for hearing and assigned an administrative law judge. A primary issue is
whether or not the dysfunctional short-term market, which was previously
declared by the FERC, impacted the forward market. The Utilities negotiated a
settlement with Duke Energy Trading and Marketing and have engaged in bilateral
settlement discussions with other respondents as well. Written direct and
rebuttal testimony have been filed by the parties that have not negotiated
settlements with the Utilities. Hearings concluded on October 24, 2002, and a
draft decision is expected in December 2002. At this time, the Utilities are not
able to predict the outcome of a decision in this matter.
OPEN ACCESS TRANSMISSION TARIFF
On September 27, 2002, the Utilities filed with the FERC a revised Open
Access Transmission Tariff. The purpose of the filing was to implement changes
that are required to implement retail open access in Nevada. The Utilities have
requested the changes to become effective November 1, 2002, the date retail
access is scheduled to commence in Nevada in accordance with provisions of AB
661, passed in the 2001 session of the Nevada Legislature.
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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
SPR has evaluated its risk related to financial instruments whose values
are subject to market sensitivity, such as fixed and variable rate debt and
preferred trust securities obligations. As shown in SPR's Form 10-K for the year
ended December 31, 2001, the fair market value of SPR's consolidated long-term
debt and preferred trust securities was $3.684 billion, as of December 31, 2001.
Due to the credit ratings downgrades by S&P and Moody's, SPR's valuations for
its market-sensitive financial instruments show a decline of approximately 23%
in the fair market value of these financial instruments to $2.85 billion from
December 31, 2001 to September 30, 2002, as shown in the table below. Fair
market value is determined using quoted market price for the same or similar
issues or on the current rates offered for debt of the same remaining
maturities.
Long-term debt (dollars in thousands):
Expected Maturity
Date
- -------------------------------------------------------------------------------------------------------------------------------
Expected Maturities Amounts Weighted Avg Int Rate Fair Market Value
- ------------------------------------------------------------------------------- ---------------------------------------------
Fixed Rate NPC SPPC SPR Consolidated Consolidated Consolidated
- ------------------------------------------------------------------------------- ----------------------- -----------------
2002 $ 15,000 $ - $ - $ 15,000 7.63%
2003 210,000 20,400 - 230,400 5.97%
2004 130,000 2,400 - 132,400 6.20%
2005 - 2,400 300,000 302,400 8.73%
2006 - 51,963 - 51,963 6.72%
Thereafter 938,835 843,242 345,000 2,127,077 6.88%
- ------------------------------------------------------------------------------- ----------------------- -----------------
Total Fixed Rate $ 1,293,835 $ 920,405 $ 645,000 $ 2,859,240 $ 2,350,527
- ------------------------------------------------------------------------------- ----------------------- -----------------
Variable Rate
2002 $ - $ - $ - $ -
2003 140,000 - 200,000 340,000 2.94%
2004 - - - -
2005 - - - -
2006 - - - -
Thereafter 115,000 - - 115,000 1.74%
- ------------------------------------------------------------------------------- ----------------------- -----------------
$ 255,000 $ - $ 200,000 $ 455,000 $ 381,850
- ------------------------------------------------------------------------------- ----------------------- -----------------
Preferred securities
(fixed rate)
After 2006 $ 188,872 $ - $ - $ 188,872 8.03%
- ------------------------------------------------------------------------------- ----------------------- -----------------
$ 188,872 $ - $ - $ 188,872 $ 117,866
- ------------------------------------------------------------------------------- ----------------------- -----------------
Total $ 1,737,707 $ 920,405 $ 845,000 $ 3,503,112 $ 2,850,243
=============================================================================== ======================= =================
See the combined Form 10-K of SPR, NPC, and SPPC for the year ended
December 31, 2001, for a discussion of Commodity Price Risk.
ITEM 4. CONTROLS AND PROCEDURES
SPR, NPC, and SPPC maintain disclosure controls and procedures as defined
in Rules 13a-14(c) and 15d-14(c) under the Securities Exchange Act of 1934, as
amended (the "Exchange Act") designed to ensure that they are able to collect
the information required to be disclosed in the reports they file with the
Securities and Exchange Commission (SEC), and to process, summarize and disclose
this information accurately and within the time periods specified in the rules
of the SEC. The chief executive officer and chief financial officer of each of
SPR, NPC, and SPPC have reviewed and evaluated SPR's, NPC's and SPPC's
disclosure controls and procedures as of a date within 90 days prior to the
filing date of this report (the "Evaluation Date"). Based on such evaluation,
such officers have concluded that, as of the Evaluation Date, these disclosure
controls and procedures of SPR, NPC, and SPPC are effective in bringing to their
attention on a timely basis material information relating to SPR, NPC, and SPPC
required to be included in periodic filings under the Exchange Act.
Since the Evaluation Date, there have not been any significant changes in
the internal controls of SPR, NPC, and SPPC, or in other factors that could
significantly affect these controls subsequent to the Evaluation Date.
65
PART II
ITEM 1. LEGAL PROCEEDINGS
Refer to SPR's, NPC's, and SPPC's Combined Annual Report on Form 10-K
for the year ended December 31, 2001, and to Item 2, Management's Discussion and
Analysis of Financial Condition and Results of Operation, in this Quarterly
Report on Form 10-Q, for a discussion of current legal matters. Although SPR,
NPC, and SPPC are involved in ongoing litigation on a variety of other matters,
in management's opinion, none of these other matters individually or
collectively is material to SPR's, NPC's, or SPPC's financial position, results
of operations, or liquidity.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
The 2002 Annual Meeting of the Shareholders of Sierra Pacific Resources
was held on July 22, 2002. SPR solicited proxies pursuant to Regulation 14 under
the Securities and Exchange Act of 1934. There was no solicitation in opposition
to the nominees for Director listed in the proxy statement, and all such
nominees were elected to the classes indicated in the proxy statement pursuant
to the vote of shareholders as follows.
Reelected to SPR's Board of Directors to serve until the Annual Meeting
in 2005, or until their successors are elected, were:
Krestine M. Corbin
Votes For: 84,745,644
Votes Against or Withheld: 1,943,949
Clyde T. Turner
Votes For: 79,486,897
Votes Against or Withheld: 7,258,696
Dennis E. Wheeler
Votes For: 83,479,848
Votes Against or Withheld: 3,265,745
ITEM 5. OTHER INFORMATION
None
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits filed with this Form 10-Q:
NEVADA POWER COMPANY
Exhibit 4.1 Officer's Certificate establishing the terms of Nevada Power
Company's 10 7/8% General and Refunding Mortgage Notes,
Series E, due 2009
Exhibit 4.2 Form of Nevada Power Company's 10 7/8% General and Refunding
Mortgage Notes, Series E, due 2009
SIERRA PACIFIC POWER COMPANY
Exhibit 4.3 Officer's Certificate establishing the terms of Sierra
Pacific Power Company's General and Refunding Mortgage
Bonds, Series C, due October 31, 2005
Exhibit 4.4 Form of Sierra Pacific Power Company's General and Refunding
Mortgage Bonds, Series C, due October 31, 2005
SIERRA PACIFIC RESOURCES
Exhibit 10.1 Donald L. Shalmy Employment Letter dated May 21, 2002
Exhibit 10.2 John F. Young Employment Letter dated May 22, 2002
66
SIERRA PACIFIC POWER COMPANY
Exhibit 10.3 Term Loan Agreement, dated as of October 30, 2002, by and
among Sierra Pacific Power Company, the several banks and
other financial institutions or entities from time to time
parties to the Agreement, Lehman Brothers Inc., as advisor,
sole lead arranger and sole bookrunner, Lehman Commercial
Paper Inc., as syndication agent, and Lehman Commercial
Paper Inc., as administrative agent
SIERRA PACIFIC COMMUNICATIONS
Exhibit 10.4 Unit Redemption, Release, and Sale Agreement entered into by
and among Touch America, Inc., Sierra Pacific
Communications, and Sierra Touch America LLC, dated as of
September 9, 2002
Exhibit 10.5 Amended And Restated Conduit Sale Agreement dated
September 11, 2002, made by and between Sierra Pacific
Communications and Qwest Communications Corporation.
SIERRA PACIFIC RESOURCES, NEVADA POWER COMPANY AND SIERRA PACIFIC POWER COMPANY
Exhibit 99.1 Certification Pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
Exhibit 99.2 Certification Pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
(b) Reports on Form 8-K:
Form 8-K dated August 14, 2002, filed by SPR- Item 9, Regulation FD Disclosure
Disclosed, and included as exhibits, the sworn statements of SPR's
Chief Executive Officer and Chief Financial Officer in accordance with
Securities and Exchange Commission Order No. 4-460.
Form 8-K dated August 14, 2002, filed by SPR, NPC and SPPC - Item 5, Other
Events
Disclosed, and included as an exhibit, SPR's press release dated August
14, 2002, reporting financial results for the quarter ended June 30, 2002, and
included as an exhibit a transcript of the August 14, 2002 conference call by
senior management of SPR, NPC, and SPPC discussing those financial results.
Form 8-K dated August 22, 2002, filed by SPR and SPPC - Item 5, Other Events
Disclosed, and included as an exhibit, the petition for judicial review
filed on August 22, 2002, by SPPC in District Court in Nevada seeking to reverse
portions of the May 28, 2002 decision of the PUCN denying the recovery of $55.8
million of deferred energy costs incurred by SPPC on behalf of its customers in
2001.
Form 8-K dated August 22, 2002, filed by SPR and NPC - Item 5, Other Events
Disclosed, and included as an exhibit, SPR's press release dated August
22, 2002, announcing that SPR had received from the Southern Nevada Water
Authority (SNWA) a letter stating that SNWA is prepared to enter into good faith
negotiation of definitive agreements to acquire all of the assets and assume
certain existing publicly disclosed indebtedness of NPC.
Form 8-K dated September 12, 2002, filed by SPR and NPC - Item 5, Other Events
Disclosed, and included as an exhibit, SPR's press release dated
September 12, 2002, announcing that SPR had delivered a letter to the SNWA in
response to their letter regarding the agency's proposal to enter into
negotiations for the possible purchase of NPC.
Form 8-K dated September 30, 2002, filed by SPR and NPC - Item 5, Other Events
Disclosed that El Paso Merchant Energy Group (EPME) had notified NPC
that EPME was terminating all transactions entered into between NPC and EPME
under the Western Systems Power Pool Agreement, and that NPC believes it has
adequate power and fuel supplies and availability to meet current needs despite
the EPME termination.
Also separately disclosed that NPC had reached delayed payment
agreements for summer 2002 power deliveries with BP Energy, Mirant,
Constellation, and Tractabel. Previously, NPC and Duke Energy Trading and
Marketing had reached a delayed payment agreement for summer 2002 deliveries.
67
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934,
the registrants have duly caused this report to be signed on their behalf by the
undersigned thereunto duly authorized.
SIERRA PACIFIC RESOURCES
(REGISTRANT)
Date: November 14, 2002 By: /s/ Dennis D. Schiffel
----------------- ----------------------------------
Dennis D. Schiffel
Senior Vice President
Chief Financial Officer
(Principal Financial Officer)
Date: November 14, 2002 By: /s/ John E. Brown
----------------- ----------------------------------
John E. Brown
Controller
(Principal Accounting Officer)
NEVADA POWER COMPANY
(Registrant)
Date: November 14, 2002 By: /s/ Dennis D. Schiffel
----------------- ----------------------------------
Dennis D. Schiffel
Senior Vice President
Chief Financial Officer
(Principal Financial Officer)
Date: November 14, 2002 By: /s/ John E. Brown
------------------ ----------------------------------
John E. Brown
Controller
(Principal Accounting Officer)
SIERRA PACIFIC POWER COMPANY
(Registrant)
Date: November 14, 2002 By: /s/ Dennis D. Schiffel
----------------- ----------------------------------
Dennis D. Schiffel
Senior Vice President
Chief Financial Officer
(Principal Financial Officer)
Date: November 14, 2002 By: /s/ John E. Brown
------------------ -----------------------------------
John E. Brown
Controller
(Principal Accounting Officer)
68
QUARTERLY CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER REQUIRED BY
SECTION 302(a) OF THE SARBANES-OXLEY ACT OF 2002
I, Walter M. Higgins III, certify that:
1. I have reviewed the combined quarterly report on Form 10-Q of Sierra
Pacific Resources, Nevada Power Company and Sierra Pacific Power
Company;
2. Based on my knowledge, the combined quarterly report does not contain
any untrue statement of a material fact or omit to state a material
fact necessary to make the statements made, in light of the
circumstances under which such statements were made, not misleading
with respect to the period covered by the combined quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in the combined quarterly report, fairly present
in all material respects the financial condition, results of
operations and cash flows of the registrants as of, and for, the
periods presented in the combined quarterly report;
4. The chief financial officer and I are responsible for establishing and
maintaining disclosure controls and procedures (as defined in Exchange
Act Rules 13a-14 and 15d-14) for the registrants and we have:
a) designed such disclosure controls and procedures to ensure
that material information relating to the registrants,
including their consolidated subsidiaries, is made known to
us by others within those entities, particularly during the
period in which the combined quarterly report is being
prepared;
b) evaluated the effectiveness of the registrants' disclosure
controls and procedures as of a date within 90 days prior to
the filing date of the combined quarterly report (the
"Evaluation Date"); and
c) presented in the combined quarterly report our conclusions
about the effectiveness of the disclosure controls and
procedures based on our evaluation as of the Evaluation
Date;
5. The chief financial officer and I have disclosed, based on our most
recent evaluation, to the registrants' auditors and the audit
committee of registrants' board of directors:
a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the
registrants' ability to record, process, summarize and
report financial data and have identified for the
registrants' auditors any material weaknesses in internal
controls; and
69
b) any fraud, whether or not material, that involves management
or other employees who have a significant role in the
registrants' internal controls; and
6. The chief financial officer and I have indicated in this combined
quarterly report whether or not there were significant changes in
internal controls or in other factors that could significantly affect
internal controls subsequent to the date of our most recent
evaluation, including any corrective actions with regard to
significant deficiencies and material weaknesses.
November 14, 2002
/s/ Walter M. Higgins III
--------------------------------
Walter M. Higgins III
Chief Executive Officer
70
QUARTERLY CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER REQUIRED BY
SECTION 302(a) OF THE SARBANES-OXLEY ACT OF 2002
I, Dennis Schiffel, certify that:
1. I have reviewed the combined quarterly report on Form 10-Q of Sierra
Pacific Resources, Nevada Power Company and Sierra Pacific Power
Company;
2. Based on my knowledge, the combined quarterly report does not contain
any untrue statement of a material fact or omit to state a material
fact necessary to make the statements made, in light of the
circumstances under which such statements were made, not misleading
with respect to the period covered by the combined quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in the combined quarterly report, fairly present
in all material respects the financial condition, results of
operations and cash flows of the registrants as of, and for, the
periods presented in the combined quarterly report;
4. The chief executive officer and I are responsible for establishing and
maintaining disclosure controls and procedures (as defined in Exchange
Act Rules 13a-14 and 15d-14) for the registrants and we have:
a) designed such disclosure controls and procedures to ensure
that material information relating to the registrants,
including their consolidated subsidiaries, is made known to
us by others within those entities, particularly during the
period in which the combined quarterly report is being
prepared;
b) evaluated the effectiveness of the registrants' disclosure
controls and procedures as of a date within 90 days prior to
the filing date of the combined quarterly report (the
"Evaluation Date"); and
c) presented in the combined quarterly report our conclusions
about the effectiveness of the disclosure controls and
procedures based on our evaluation as of the Evaluation
Date;
5. The chief executive officer and I have disclosed, based on our most
recent evaluation, to the registrants' auditors and the audit
committee of registrants' board of directors:
a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the
registrants' ability to record, process, summarize and
report financial data and have identified for the
registrants' auditors any material weaknesses in internal
controls; and
71
b) any fraud, whether or not material, that involves management
or other employees who have a significant role in the
registrants' internal controls; and
6. The chief executive officer and I have indicated in this combined
quarterly report whether or not there were significant changes in
internal controls or in other factors that could significantly affect
internal controls subsequent to the date of our most recent
evaluation, including any corrective actions with regard to
significant deficiencies and material weaknesses.
November 14, 2002
/s/ Dennis Schiffel
------------------------------
Dennis Schiffel
Chief Financial Officer
72