================================================================================
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2003
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934 FOR THE TRANSITION PERIOD FROM TO
Registrant, State of Incorporation, Address of
Commission File Principal Executive Offices and Telephone I.R.S. employer
Number Number Identification Number
1-08788 SIERRA PACIFIC RESOURCES 88-0198358
P.O. Box 10100
(6100 Neil Road)
Reno, Nevada 89520-0400 (89511)
(775) 834-4011
2-28348 NEVADA POWER COMPANY 88-0420104
6226 West Sahara Avenue
Las Vegas, Nevada 89146
(702) 367-5000
0-00508 SIERRA PACIFIC POWER COMPANY 88-0044418
P.O. Box 10100
(6100 Neil Road)
Reno, Nevada 89520-0400 (89511)
(775) 834-4011
Indicate by check mark whether registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes [X] No [ ]
Indicate by check mark whether any registrant is an accelerated filer(as
defined in Rule 12b-2 of the Act). Sierra Pacific Resources Yes [X] No [ ];
Nevada Power Company Yes [ ] No [X]; Sierra Pacific Power Company Yes [ ] No [X]
Indicate the number of shares outstanding of each of the issuer's classes of
Common Stock, as of the latest practicable date.
Class Outstanding at May 1, 2003
Common Stock, $1.00 par value 117,135,012 Shares
of Sierra Pacific Resources
Sierra Pacific Resources is the sole holder of the 1,000 shares of outstanding
Common Stock, $1.00 stated value, of Nevada Power Company. Sierra Pacific
Resources is the sole holder of the 1,000 shares of outstanding Common Stock,
$3.75 stated value, of Sierra Pacific Power Company.
This combined Quarterly Report on Form 10-Q is separately filed by Sierra
Pacific Resources, Nevada Power Company and Sierra Pacific Power Company.
Information contained in this document relating to Nevada Power Company is filed
by Sierra Pacific Resources and separately by Nevada Power Company on its own
behalf. Nevada Power Company makes no representation as to information relating
to Sierra Pacific Resources or its subsidiaries, except as it may relate to
Nevada Power Company. Information contained in this document relating to Sierra
Pacific Power Company is filed by Sierra Pacific Resources and separately by
Sierra Pacific Power Company on its own behalf. Sierra Pacific Power Company
makes no representation as to information relating to Sierra Pacific Resources
or its subsidiaries, except as it may relate to Sierra Pacific Power Company.
================================================================================
SIERRA PACIFIC RESOURCES
NEVADA POWER COMPANY
SIERRA PACIFIC POWER COMPANY
QUARTERLY REPORTS ON FORM 10-Q
FOR THE QUARTER ENDED MARCH 31, 2003
CONTENTS
PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS (Unaudited)
SIERRA PACIFIC RESOURCES -
Condensed Consolidated Balance Sheets - March 31, 2003 and December 31, 2002................................. 3
Condensed Consolidated Statements of Operations - Three Months Ended March 31, 2003 and 2002................. 4
Condensed Consolidated Statements of Cash Flows - Three Months Ended March 31, 2003 and 2002................. 5
NEVADA POWER COMPANY -
Condensed Consolidated Balance Sheets - March 31, 2003 and December 31, 2002................................. 6
Condensed Consolidated Statements of Operations - Three Months Ended March 31, 2003 and 2002................. 7
Condensed Consolidated Statements of Cash Flows - Three Months Ended March 31, 2003 and 2002................. 8
SIERRA PACIFIC POWER COMPANY -
Condensed Consolidated Balance Sheets - March 31, 2003 and December 31, 2002................................. 9
Condensed Consolidated Statements of Operations - Three Months Ended March 31, 2003 and 2002................. 10
Condensed Consolidated Statements of Cash Flows - Three Months Ended March 31, 2003 and 2002................. 11
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS......................................................... 12
ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations........................ 28
Sierra Pacific Resources............................................................................... 38
Nevada Power Company................................................................................... 42
Sierra Pacific Power Company........................................................................... 48
ITEM 3. Quantitative and Qualitative Disclosures about Market Risk................................................... 59
ITEM 4. Controls and Procedures...................................................................................... 59
PART II - OTHER INFORMATION
ITEM 1. Legal Proceedings............................................................................................ 60
ITEM 4. Submission of Matters to a Vote of Security Holders.......................................................... 61
ITEM 5. Other Information............................................................................................ 61
ITEM 6. Exhibits and Reports on Form 8-K............................................................................. 61
Signature Page and Certifications........................................................................................... 63
2
SIERRA PACIFIC RESOURCES
CONDENSED CONSOLIDATED BALANCE SHEETS
(DOLLARS IN THOUSANDS)
MARCH 31, DECEMBER 31,
2003 2002
---------- -----------
(UNAUDITED)
ASSETS
Utility Plant at Original Cost:
Plant in service $6,095,682 $5,989,701
Less accumulated provision for depreciation 1,992,811 1,944,351
---------- ----------
4,102,871 4,045,350
Construction work-in-progress 259,602 263,346
---------- ----------
4,362,473 4,308,696
---------- ----------
Investments and other property, net 136,606 134,068
---------- ----------
Current Assets:
Cash and cash equivalents 387,192 193,386
Restricted cash 67,113 13,705
Accounts receivable less provision for uncollectible accounts:
2003-$42,844 ; 2002-$44,184 315,564 359,083
Deferred energy costs - electric 288,407 268,979
Deferred energy costs - gas 6,431 17,045
Materials, supplies and fuel, at average cost 86,320 87,840
Risk management assets (Note 10) 23,963 29,570
Other 66,391 48,960
---------- ----------
1,241,381 1,018,568
---------- ----------
Deferred Charges and Other Assets:
Goodwill (Note 12) 309,971 310,441
Deferred energy costs - electric 589,707 685,875
Regulatory tax asset 162,427 163,889
Other regulatory assets 139,066 136,933
Risk management assets (Note 10) 29,910 368
Risk management regulatory assets - net (Note 10) 47,443 44,970
Other 88,657 92,436
---------- ----------
1,367,181 1,434,912
---------- ----------
$7,107,641 $6,896,244
========== ==========
CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholders' equity $1,426,469 $1,327,166
Preferred stock 50,000 50,000
NPC obligated mandatorily redeemable preferred trust securities 188,872 188,872
Long-term debt 3,013,127 3,062,883
---------- ----------
4,678,468 4,628,921
---------- ----------
Current Liabilities:
Current maturities of long-term debt 758,858 672,963
Accounts payable 194,892 233,099
Accrued interest 90,339 50,308
Dividends declared 1,052 1,045
Accrued salaries and benefits 19,362 20,828
Deferred taxes 117,202 123,507
Risk management liabilities (Note 10) 67,774 69,953
Other current liabilities 89,671 46,719
---------- ----------
1,339,150 1,218,422
---------- ----------
Commitments & Contingencies (Note 11)
Deferred Credits and Other Liabilities:
Deferred federal income taxes 336,195 336,144
Deferred investment tax credit 47,629 48,492
Regulatory tax liability 41,722 42,718
Customer advances for construction 119,196 116,032
Accrued retirement benefits 114,205 107,580
Risk management liabilities (Note10) 3,329 3,917
Contract termination reserves (Note11) 312,594 312,594
Other 115,153 81,424
---------- ----------
1,090,023 1,048,901
---------- ----------
$7,107,641 $6,896,244
========== ==========
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS.
3
SIERRA PACIFIC RESOURCES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) (UNAUDITED)
THREE MONTHS ENDED
MARCH 31,
------------------------------
2003 2002
------------- -------------
OPERATING REVENUES:
Electric $ 537,106 $ 581,026
Gas 64,617 55,083
Other 1,239 2,755
------------- -------------
602,962 638,864
------------- -------------
OPERATING EXPENSES:
Operation:
Purchased power 206,435 281,483
Fuel for power generation 80,213 130,773
Gas purchased for resale 42,334 38,594
Deferred energy costs disallowed - 434,123
Deferral of energy costs - electric - net 84,187 (14,241)
Deferral of energy costs - gas - net 10,803 8,192
Other 73,602 72,045
Maintenance 18,724 16,907
Depreciation and amortization 45,950 48,641
Taxes:
Income taxes (16,140) (158,617)
Other than income 11,057 11,715
------------- -------------
557,165 869,615
------------- -------------
OPERATING INCOME (LOSS) 45,797 (230,751)
------------- -------------
OTHER INCOME (EXPENSE):
Allowance for other funds used during construction 1,760 657
Unrealized gain on derivative instrument ( Note 10) 15,925 -
Interest accrued on deferred energy 7,635 (6,124)
Other income 6,414 3,580
Other expense (3,731) (8,797)
Income taxes (8,418) 4,214
------------- -------------
19,585 (6,470)
------------- -------------
Total Income (Loss) Before Interest Charges 65,382 (237,221)
------------- -------------
INTEREST CHARGES:
Long-term debt 68,595 58,800
Other 10,273 4,630
Allowance for borrowed funds used during construction and capitalized interest (1,756) (1,503)
------------- -------------
77,112 61,927
------------- -------------
Dividend requirements of NPC obligated mandatorily
redeemable preferred trust securities 3,793 3,793
------------- -------------
NET LOSS (15,523) (302,941)
------------- -------------
Preferred stock dividend requirements of SPPC 975 975
------------- -------------
LOSS APPLICABLE TO COMMON STOCK $ (16,498) $ (303,916)
============= =============
Basic and diluted loss per share of common stock $ (0.15) $ (2.98)
Cumulative effect of change in accounting principle (net of tax) per share - -
------------- -------------
Per share loss applicable to common stock $ (0.15) $ (2.98)
============= =============
Weighted Average Shares of Common Stock Outstanding 111,499,881 102,110,536
============= =============
Dividends Paid Per Share of Common Stock $ - $ 0.20
============= =============
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS.
4
SIERRA PACIFIC RESOURCES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(DOLLARS IN THOUSANDS) (UNAUDITED)
THREE MONTHS ENDED
MARCH 31,
----------------------
2003 2002
--------- ---------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Loss $ (15,523) $(302,941)
Non-cash items included in income:
Depreciation and amortization 45,950 48,641
Deferred taxes and deferred investment tax credit (12,225) (4,713)
AFUDC and capitalized interest (3,516) 537
Amortization of deferred energy costs - electric 44,490 -
Amortization of deferred energy costs - gas 6,165 6,404
Deferred energy costs disallowed (net of taxes) - 282,181
Unrealized gain on derivative instrument (net of taxes) (10,351) -
Early retirement and severance amortization 624 752
Other non-cash (3,742) (3,954)
Changes in certain assets and liabilities:
Accounts receivable 43,519 55,204
Deferral of energy costs - electric 32,251 (7,410)
Deferral of energy costs - gas 4,448 1,437
Materials, supplies and fuel 1,520 (1,162)
Other current assets (70,839) (2,257)
Accounts payable (38,207) (56,359)
Income tax receivable - 79,333
Derivative instrument associated with convertible debt 72,078 -
Other current liabilities 25,364 31,112
Other assets (26,493) -
Other liabilities 40,354 72
--------- ---------
Net Cash from Operating Activities 135,867 126,877
--------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to utility plant (99,467) (85,558)
AFUDC and other charges to utility plant 3,516 (537)
Customer advances (refunds) for construction 3,165 (575)
Contributions in aid of construction 3,055 16,148
--------- ---------
Net cash used for utility plant (89,731) (70,522)
Investments and other property - net (1,350) (1,308)
--------- ---------
Net Cash from Investing Activities (91,081) (71,830)
--------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Increase in short-term borrowings - 69,672
Proceeds from issuance of long-term debt 228,764 -
Retirement of long-term debt (78,775) (3,463)
Dividends paid (969) (21,542)
--------- ---------
Net Cash from Financing Activities 149,020 44,667
--------- ---------
NET INCREASE IN CASH AND CASH EQUIVALENTS 193,806 99,714
Beginning Balance in Cash and Cash Equivalents 193,386 99,109
--------- ---------
Ending Balance in Cash and Cash Equivalents $ 387,192 $ 198,823
========= =========
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash paid (received) during period for:
Interest $ 38,837 $ 39,629
Income taxes $ - $ (79,333)
NONCASH FINANCING ACTIVITIES (NOTE 4):
Exchanged Floating Rate Notes for SPR common stock $ 8,750
Exchanged Premium Income Equity Securities for SPR common stock $ 104,782
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS
5
NEVADA POWER COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(DOLLARS IN THOUSANDS)
MARCH 31, DECEMBER 31,
2003 2002
---------- ------------
(Unaudited)
ASSETS
Utility Plant at Original Cost:
Plant in service $3,631,806 $3,542,300
Less accumulated provision for depreciation 1,047,877 1,017,494
---------- ----------
2,583,929 2,524,806
Construction work-in-progress 163,299 173,189
---------- ----------
2,747,228 2,697,995
---------- ----------
Investments and other property, net 19,589 20,295
---------- ----------
Current Assets:
Cash and cash equivalents 90,689 95,009
Restricted cash 3,850 3,850
Accounts receivable less provision for uncollectible accounts:
2003-$33,914; 2002-$33,841 167,366 202,590
Deferred energy costs - electric 230,232 213,193
Materials, supplies and fuel, at average cost 43,687 44,074
Risk management assets (Note 10) 20,206 28,173
Other 49,712 31,602
---------- ----------
605,742 618,491
---------- ----------
Deferred Charges and Other Assets:
Deferred energy costs - electric 440,232 524,345
Regulatory tax asset 105,124 106,071
Other regulatory assets 54,607 53,109
Risk management assets (Note 10) 21,846 368
Risk management regulatory assets - net (Note 10) 15,469 1,491
Other 45,247 46,357
---------- ----------
682,525 731,741
---------- ----------
$4,055,084 $4,068,522
========== ==========
CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholder's equity $1,134,377 $1,149,131
NPC obligated mandatorily redeemable preferred trust securities 188,872 188,872
Long-term debt 1,486,402 1,488,597
---------- ----------
2,809,651 2,826,600
---------- ----------
Current Liabilities:
Current maturities of long-term debt 354,664 354,677
Accounts payable 92,031 143,002
Accounts payable, affiliated companies 2,549 4,287
Accrued interest 47,368 29,892
Dividends declared 78 78
Accrued salaries and benefits 7,217 7,781
Deferred taxes 87,240 90,616
Risk management liabilities (Note 10) 35,662 29,908
Other current liabilities 23,554 22,115
---------- ----------
650,363 682,356
---------- ----------
Commitments & Contingencies (Note 11)
Deferred Credits and Other Liabilities:
Deferred federal income taxes 124,814 129,687
Deferred investment tax credit 21,495 21,902
Regulatory tax liability 16,974 17,300
Customer advances for construction 68,779 66,434
Accrued retirement benefits 55,983 54,216
Contract termination reserves (Note 11) 225,816 225,816
Other 81,209 44,211
---------- ----------
595,070 559,566
---------- ----------
$4,055,084 $4,068,522
========== ==========
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS.
6
NEVADA POWER COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(DOLLARS IN THOUSANDS) (UNAUDITED)
THREE MONTHS ENDED
MARCH 31,
----------------------
2003 2002
--------- ---------
OPERATING REVENUES:
Electric $ 331,652 $ 356,272
--------- ---------
OPERATING EXPENSES:
Operation:
Purchased power 119,257 176,066
Fuel for power generation 46,537 83,722
Deferred energy costs disallowed - 434,123
Deferral of energy costs-net 72,785 (9,636)
Other 40,540 39,986
Maintenance 13,537 11,650
Depreciation and amortization 25,907 30,809
Taxes:
Income taxes (10,548) (156,423)
Other than income 6,224 6,734
--------- ---------
314,239 617,031
--------- ---------
OPERATING INCOME (LOSS) 17,413 (260,759)
--------- ---------
OTHER INCOME (EXPENSE):
Allowance for other funds used during construction 1,158 421
Interest accrued on deferred energy 5,710 (11,151)
Other income 3,338 146
Other expense (1,432) (5,997)
Income taxes (2,514) 5,645
--------- ---------
6,260 (10,936)
--------- ---------
Total Income (Loss) Before Interest Charges 23,673 (271,695)
--------- ---------
INTEREST CHARGES:
Long-term debt 30,102 24,078
Other 6,080 2,530
Allowance for borrowed funds used during construction and capitalized interest (1,056) (1,112)
--------- ---------
35,126 25,496
--------- ---------
Dividend requirements of obligated mandatorily
redeemable preferred trust securities 3,793 3,793
--------- ---------
NET LOSS $ (15,246) $(300,984)
========= =========
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS.
7
NEVADA POWER COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(DOLLARS IN THOUSANDS) (UNAUDITED)
THREE MONTHS ENDED
MARCH 31,
----------------------
2003 2002
--------- ---------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income (Loss) $ (15,246) $(300,984)
Non-cash items included in income:
Depreciation and amortization 25,907 30,809
Deferred taxes and deferred investment tax credit (8,035) (4,586)
AFUDC and capitalized interest (2,214) 692
Amortization of deferred energy costs 32,331 -
Deferred energy costs disallowed (net of taxes) - 282,181
Other non-cash (4,702) (555)
Changes in certain assets and liabilities:
Accounts receivable 35,224 46,471
Deferral of energy costs 34,744 2,221
Materials, supplies and fuel 387 1,348
Other current assets (18,110) (2,187)
Accounts payable (52,709) (51,497)
Income tax receivable - 79,333
Other current liabilities 18,351 11,545
Other assets (19,943) -
Other liabilities 38,765 540
--------- ---------
Net Cash from Operating Activities 64,750 95,331
--------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to utility plant (74,525) (65,685)
AFUDC and other charges to utility plant 2,214 (692)
Customer advances (refunds) for construction 2,345 (469)
Contributions in aid of construction 2,363 13,592
--------- ---------
Net cash used for utility plant (67,603) (53,254)
Investments and other property - net 741 (950)
--------- ---------
Net Cash from Investing Activities (66,862) (54,204)
--------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Increase in short-term borrowings - 68,429
Retirement of long-term debt (2,208) (2,663)
Investment by parent company - 10,000
Dividends paid - (9,995)
--------- ---------
Net Cash from Financing Activities (2,208) 65,771
--------- ---------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (4,320) 106,898
Beginning Balance in Cash and Cash Equivalents 95,009 8,505
--------- ---------
Ending Balance in Cash and Cash Equivalents $ 90,689 $ 115,403
========= =========
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash paid (received) during period for:
Interest $ 18,706 $ 14,104
Income taxes $ - $ (79,333)
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS
8
SIERRA PACIFIC POWER COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(DOLLARS IN THOUSANDS)
MARCH 31, DECEMBER 31,
2003 2002
---------- ------------
(Unaudited)
ASSETS
Utility Plant at Original Cost:
Plant in service $2,463,876 $2,447,401
Less accumulated provision for depreciation 944,934 926,857
---------- ----------
1,518,942 1,520,544
Construction work-in-progress 96,303 90,157
---------- ----------
1,615,245 1,610,701
---------- ----------
Investments and other property, net 953 874
---------- ----------
Current Assets:
Cash and cash equivalents 127,801 88,910
Restricted cash 9,605 9,605
Accounts receivable less provision for uncollectible accounts:
2003 - $8,930; 2002 - $10,343 147,019 154,821
Accounts receivable, affiliated companies 58,598 58,680
Deferred energy costs - electric 58,175 55,786
Deferred energy costs - gas 6,431 17,045
Materials, supplies and fuel, at average cost 40,525 41,727
Risk management assets (Note 10) 3,757 1,397
Other 12,008 12,955
---------- ----------
463,919 440,926
---------- ----------
Deferred Charges and Other Assets:
Deferred energy costs - electric 149,475 161,530
Regulatory tax asset 57,303 57,818
Other regulatory assets 64,258 64,149
Risk management assets (Note 10) 8,064 -
Risk management regulatory assets - net (Note 10) 31,974 43,479
Other 19,934 19,013
---------- ----------
331,008 345,989
---------- ----------
$2,411,125 $2,398,490
========== ==========
CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholder's equity $ 642,548 $ 639,295
Preferred stock 50,000 50,000
Long-term debt 914,425 914,788
---------- ----------
1,606,973 1,604,083
---------- ----------
Current Liabilities:
Current maturities of long-term debt 101,400 101,400
Accounts payable 70,540 71,247
Accrued interest 26,199 12,136
Dividends declared 974 968
Accrued salaries and benefits 9,726 10,812
Deferred taxes 29,962 32,891
Risk management liabilities (Note 10) 32,112 40,045
Other current liabilities 7,935 10,864
---------- ----------
278,848 280,363
---------- ----------
Commitments & Contingencies (Note 11)
Deferred Credits and Other Liabilities:
Deferred federal income taxes 257,420 251,487
Deferred investment tax credit 26,134 26,590
Regulatory tax liability 24,748 25,418
Customer advances for construction 50,417 49,598
Accrued retirement benefits 49,734 44,856
Risk management liabilities (Note 10) 3,329 3,917
Contract termination reserves (Note 11) 86,778 86,778
Other 26,744 25,400
---------- ----------
525,304 514,044
---------- ----------
$2,411,125 $2,398,490
========== ==========
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS.
9
SIERRA PACIFIC POWER COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(DOLLARS IN THOUSANDS) (UNAUDITED)
THREE MONTHS ENDED
MARCH 31,
----------------------
2003 2002
--------- ---------
OPERATING REVENUES:
Electric $ 205,454 $ 224,754
Gas 64,617 55,083
--------- ---------
270,071 279,837
--------- ---------
OPERATING EXPENSES:
Operation:
Purchased power 87,178 105,417
Fuel for power generation 33,676 47,051
Gas purchased for resale 42,334 38,594
Deferral of energy costs - electric - net 11,402 (4,605)
Deferral of energy costs - gas - net 10,803 8,192
Other 29,213 27,762
Maintenance 5,187 5,257
Depreciation and amortization 19,706 17,558
Taxes:
Income taxes 2,090 4,901
Other than income 4,662 4,776
--------- ---------
246,251 254,903
--------- ---------
OPERATING INCOME 23,820 24,934
--------- ---------
OTHER INCOME (EXPENSE):
Allowance for other funds used during construction 602 236
Interest accrued on deferred energy 1,925 5,027
Other income 1,065 1,837
Other expense (1,905) (2,462)
Income taxes (303) (1,432)
--------- ---------
1,384 3,206
--------- ---------
Total Income Before Interest Charges 25,204 28,140
--------- ---------
INTEREST CHARGES:
Long-term debt 18,781 16,445
Other 3,125 1,142
Allowance for borrowed funds used during construction and
capitalized interest (700) (391)
--------- ---------
21,206 17,196
--------- ---------
NET INCOME 3,998 10,944
--------- ---------
Preferred Dividend Requirements 975 975
--------- ---------
Earnings applicable to common stock $ 3,023 $ 9,969
========= =========
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS.
10
SIERRA PACIFIC POWER COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(DOLLARS IN THOUSANDS) (UNAUDITED)
THREE MONTHS ENDED
MARCH 31,
----------------------
2003 2002
--------- ---------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 3,998 $ 10,944
Non-cash items included in income:
Depreciation and amortization 19,706 17,558
Deferred taxes and deferred investment tax credit 2,393 6,918
AFUDC and capitalized interest (1,302) (155)
Amortization of deferred energy costs - electric 12,159 -
Amortization of deferred energy costs - gas 6,165 6,404
Early retirement and severance amortization 624 752
Other non-cash (2,313) (1,131)
Changes in certain assets and liabilities:
Accounts receivable 7,884 3,959
Deferral of energy costs - electric (2,493) (9,631)
Deferral of energy costs - gas 4,448 1,437
Materials, supplies and fuel 1,202 (2,399)
Other current assets 947 (272)
Accounts payable (707) (11,428)
Other current liabilities 10,048 10,208
Other assets (6,550) -
Other liabilities 6,222 1,467
--------- ---------
Net Cash from Operating Activities 62,431 34,631
--------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to utility plant (24,942) (19,873)
AFUDC and other charges to utility plant 1,302 155
Customer advances (refunds) for construction 819 (106)
Contributions in aid of construction 692 2,556
--------- ---------
Net cash used for utility plant (22,129) (17,268)
Disposal of investments and other property - net (79) 577
--------- ---------
Net Cash from Investing Activities (22,208) (16,691)
--------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Decrease in short-term borrowings - 1,243
Retirement of long-term debt (363) (800)
Investment by parent company - 10,000
Dividends paid (969) (10,969)
--------- ---------
Net Cash from Financing Activities (1,332) (526)
--------- ---------
NET INCREASE IN CASH AND CASH EQUIVALENTS 38,891 17,414
Beginning Balance in Cash and Cash Equivalents 88,910 11,772
--------- ---------
Ending Balance in Cash and Cash Equivalents $ 127,801 $ 29,186
========= =========
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash paid during period for:
Interest $ 7,843 $ 3,019
Income taxes $ - $ -
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS
11
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. MANAGEMENT'S STATEMENT (SPR, NPC, SPPC)
In the opinion of the management of Sierra Pacific Resources (SPR),
Nevada Power Company (NPC), and Sierra Pacific Power Company (SPPC), the
accompanying unaudited interim condensed consolidated financial statements
contain all adjustments (consisting of only normal recurring adjustments)
necessary to present fairly the condensed consolidated financial position,
results of operations and cash flows for the periods shown. These condensed
consolidated financial statements do not contain the complete detail or footnote
disclosure concerning accounting policies and other matters which are included
in full year financial statements and therefore, they should be read in
conjunction with the audited financial statements included in SPR's, NPC's, and
SPPC's Annual Report on Form 10-K for the year ended December 31, 2002.
The results of operations of SPR, NPC and SPPC for the three-month
period ended March 31, 2003, are not necessarily indicative of the results to be
expected for the full year.
PRINCIPLES OF CONSOLIDATION
The condensed consolidated financial statements of SPR include the
accounts of SPR and its wholly-owned subsidiaries, NPC and SPPC (collectively,
the "Utilities"), Tuscarora Gas Pipeline Company (TGPC), Sierra Gas Holding
Company (SGHC), Sierra Energy Company dba eo three (eo three), Sierra Pacific
Energy Company (SPE), Lands of Sierra (LOS), Sierra Pacific Communications
(SPC), and Sierra Water Development Company (SWDC). All significant intercompany
transactions and balances have been eliminated in consolidation.
SIERRA PACIFIC RESOURCES
SPR, on a stand-alone basis, had cash and cash equivalents of
approximately $166.7 million at March 31, 2003. On April 21, 2003, SPR utilized
approximately $133 million of its cash and cash equivalents to repay unsecured
Floating Rate Notes due April 20, 2003.
Currently, SPR has a substantial amount of debt and other obligations
including, but not limited to: $300 million of its unsecured 8 3/4% Senior Notes
due 2005; and $240 million of its unsecured 7.93% Senior Notes due 2007; and
$300 million of its 7.25% Convertible Notes due 2010.
SPR's future liquidity and its ability to pay the principal of and
interest on its indebtedness depend on SPPC's ability to continue to pay
dividends to SPR, on NPC's financial stability and a restoration of its ability
to pay dividends to SPR, and on SPR's ability to access the capital markets or
otherwise refinance maturing debt. Further adverse developments at NPC or SPPC,
including a material disallowance of deferred energy costs in current and future
rate cases or an adverse decision in the pending lawsuit by Enron, could make it
difficult to continue to operate outside of bankruptcy.
See Note 5, Dividend Restrictions for information regarding the
dividend restrictions applicable to NPC and SPPC and Note 11, Commitments and
Contingencies for additional information regarding uncertainties that could
impact SPR's liquidity and financial condition.
The provisions that currently restrict dividends payable by NPC or SPPC
have adversely affected SPR's liquidity and will continue to negatively impact
SPR's liquidity until those provisions are no longer in effect. Management
intends to seek a modification of the financial covenant contained in NPC's
first mortgage indenture in the near future. The regulatory limitation contained
in the Public Utility Commission of Nevada's (PUCN) Compliance Order, Docket No.
02-4037, dated June 19, 2002, expires on December 31, 2003. Prior to the
expiration date of the Compliance Order, management may seek PUCN approval for a
payment of dividends by NPC or may seek a waiver from the PUCN of the dividend
restriction.
Financing Transactions. On February 14, 2003, SPR issued and sold $300
million of its 7.25% Convertible Notes due 2010. Approximately $53.4 million of
the net proceeds from the sale of the notes were used to purchase U.S.
government securities that were pledged to the trustee for the first five
interest payments on the notes payable during the first two and one-half years.
A portion of the remaining net proceeds of the notes have been used to
repurchase approximately $58.5 million of SPR's Floating Rate Notes due April
20, 2003. Of the remaining net proceeds, approximately $133 million were used to
repay the remainder of SPR's Floating Rate Notes due April 20, 2003, and the
remaining proceeds will be available for general corporate purposes, including
the payment of interest on SPR's other outstanding indebtedness.
The Convertible Notes will not be convertible prior to August 14, 2003.
At any time on or after August 14, 2003 through the close of business February
14, 2010, holders of the Convertible Notes may convert their notes into shares
of SPR's common stock. Until SPR has obtained shareholder approval to fully
convert the Convertible Notes into shares of common
12
stock, holders of the Convertible Notes will be entitled to receive 76.7073
shares of common stock and a remaining portion in cash, based on the average
closing price of SPR's common stock over five consecutive trading days, for each
$1,000 principal amount of notes surrendered for conversion. At an assumed
five-day average closing price of $3.87 per share (based on the last reported
sale price of SPR's common stock on April 30, 2003), the total amount of the
cash payable on conversion of the Convertible Notes would be approximately
$165.4 million. If SPR does not obtain shareholder approval, SPR will be
required to pay the cash portion of any Convertible Notes as to which the
holders request conversion on or after August 14, 2003. Although management does
not believe it is likely that a significant amount of the Convertible Notes will
be converted in the foreseeable future, in the event that SPR does not have
available funds to pay the cash portion of the Convertible Notes upon the
requested conversion, SPR may have to issue additional debt to raise the
necessary funds. There can be no assurance that SPR will be able to access the
capital markets to issue such additional debt.
If SPR does obtain shareholder approval, it may elect to satisfy the
cash payment component of the conversion price of the Convertible Notes solely
with shares of common stock. SPR has agreed to use reasonable efforts to obtain
shareholder approval, not later than 180 days after the date of issuance of the
Convertible Notes, for approval to issue and deliver shares of SPR's common
stock in lieu of the cash payment component of the conversion price of the
Convertible Notes. For further information regarding the terms of the
Convertible Notes, see Note 4, Long-Term Debt.
Effect of Holding Company Structure. Due to its holding company
structure, SPR's right as a common shareholder to receive assets of any of its
direct or indirect subsidiaries upon a subsidiary's liquidation or
reorganization is junior to the claims against the assets of such subsidiary by
its creditors. Therefore, SPR's debt obligations are effectively subordinated to
all existing and future claims of its subsidiaries' creditors, particularly
those of NPC and SPPC, including trade creditors, debt holders, secured
creditors, taxing authorities, guarantee holders and NPC's and SPPC's preferred
security holders. As of March 31, 2003, NPC, SPPC and their subsidiaries had
approximately $2.86 billion of debt and other obligations outstanding and
approximately $238.9 million of outstanding preferred securities. Although the
Utilities are parties to agreements that limit the amount of additional
indebtedness they may incur, the Utilities retain the ability to incur
substantial additional indebtedness and other liabilities.
The accompanying financial statements do not include any adjustments
that might result from the outcome of the uncertainties discussed above.
NEVADA POWER COMPANY
NPC had cash and cash equivalents of approximately $91 million at March
31, 2003.
In addition to anticipated capital requirements for construction, NPC
has approximately $355 million of debt maturing in 2003. NPC expects to finance
these requirements with internally generated funds, including the recovery of
deferred energy, and the issuance of debt.
NPC's liquidity would be significantly affected by an adverse decision
in the lawsuit by Enron, or by unfavorable rulings by the PUCN in pending or
future NPC or SPPC rate cases. Standard and Poors Rating Group, Inc. (S&P) and
Moodys Investors Service, Inc. (Moodys) have NPC's credit ratings on "negative"
and "stable", respectively. Future downgrades by either S&P or Moody's could
preclude NPC's access to the capital markets. Furthermore, if NPC continues to
experience financial difficulty or if its credit ratings are further downgraded,
NPC may experience considerable difficulty entering into new power supply
contracts, particularly under traditional payment terms. If suppliers will not
sell power to NPC under traditional payment terms, NPC may have to pre-pay its
power requirements. If it does not have sufficient funds or access to liquidity
to pre-pay its power requirements, particularly at the onset of the summer
months, and is unable to obtain power through other means, NPC's results of
operations, financial position, and cash flows will be adversely affected.
Adverse developments with respect to any one or a combination of the foregoing
could make it difficult to continue to operate outside of bankruptcy.
NPC's General and Refunding Mortgage Indenture creates a lien on
substantially all of NPC's properties in Nevada that is junior to the lien of
the first mortgage indenture. As of March 31, 2003, $870 million of NPC's
General and Refunding Mortgage securities were outstanding. Additional
securities may be issued under the General and Refunding Mortgage Indenture on
the basis of (i) 70% of net utility property additions, (ii) the principal
amount of retired General and Refunding Mortgage Bonds, and/or (iii) the
principal amount of first mortgage bonds retired after delivery to the indenture
trustee of the initial expert's certificate under the General and Refunding
Mortgage Indenture.
As of March 31, 2003, NPC had the capacity to issue approximately $1.13
billion of additional General and Refunding Mortgage securities. However, the
financial covenants contained in NPC's Series E Notes limit NPC's ability to
issue additional General and Refunding Mortgage Bonds or other debt. NPC has
reserved $125 million of General and Refunding Mortgage bonds for issuance upon
the initial funding of NPC's receivables facility. See Note 3, Short-Term
Borrowings for information regarding NPC's accounts receivable facility. NPC
intends to use its accounts receivable purchase
13
facility as a back-up liquidity facility and does not plan to activate this
facility in the foreseeable future. NPC may activate the facility within five
days upon the delivery of certain customary funding documentation and the
delivery of the $125 million General and Refunding Mortgage Bond.
The accompanying financial statements do not include any adjustments
that might result from the outcome of the uncertainties discussed above.
SIERRA PACIFIC POWER COMPANY
SPPC had cash and cash equivalents of approximately $128 million at
March 31, 2003.
In addition to anticipated capital requirements for construction, and
not including $80 million of Bonds subject to remarketing (see Note 4), SPPC has
approximately $21 million of debt maturing in 2003. SPPC expects to finance
these requirements with internally generated funds, including the recovery of
deferred energy.
SPPC's future liquidity could be significantly affected by unfavorable
rulings by the PUCN in pending or future SPPC or NPC rate cases. S&P and Moody's
have SPPC's credit ratings on "negative outlook" and "stable", respectively.
Future downgrades by either S&P or Moody's could preclude SPPC's access to the
capital markets. Furthermore, if SPPC continues to experience financial
difficulty or if its credit ratings are further downgraded, SPPC may experience
considerable difficulty entering into new power supply contracts, particularly
under traditional payment terms. If suppliers will not sell power to SPPC under
traditional payment terms, SPPC may have to pre-pay its power requirements. If
it does not have sufficient funds or access to liquidity to pre-pay its power
requirements, and is unable to obtain power through other means, SPPC's results
of operations, financial position and cash flows will be adversely affected.
Adverse developments with respect to any one or a combination of the factors and
contingencies set forth above could make it difficult to continue to operate
outside of bankruptcy.
SPPC's General and Refunding Mortgage Indenture creates a lien on
substantially all of SPPC's properties in Nevada that is junior to the lien of
the first mortgage indenture. As of March 31, 2003, approximately $419.8 million
of SPPC's General and Refunding Mortgage bonds were outstanding. On May 1, 2003,
SPPC issued its $80 million General and Refunding Mortgage Note, Series D, due
2004, to secure SPPC's payment obligations with respect to $80 million of Washoe
County, Nevada, Water Facilities Refunding Revenue Bonds (Sierra Pacific Power
Company Project), Series 2001, which were issued for SPPC's benefit. Additional
securities may be issued under the General and Refunding Mortgage Indenture on
the basis of (1) 70% of net utility property additions, (2) the principal amount
of retired General and Refunding Mortgage bonds, and/or (3) the principal amount
of first mortgage bonds retired after delivery to the indenture trustee of the
initial expert's certificate under the General and Refunding Mortgage Indenture.
At March 31, 2003, SPPC had the capacity to issue approximately $435.7
million of additional General and Refunding Mortgage securities, which amount
does not include SPPC's $80 million General and Refunding Mortgage Note, Series
D, due 2004. However, the financial covenants contained in SPPC's Term Loan
Agreement and Receivable Purchase Facility Agreements limit SPPC's ability to
issue additional General and Refunding Mortgage Securities or other debt. SPPC
has reserved $75 million of General and Refunding Mortgage Bonds for issuance
upon the initial funding of its receivables purchase facility. SPPC intends to
use its accounts receivable purchase facility as a back-up liquidity facility
and does not plan to activate this facility in the foreseeable future. SPPC may
activate the facility within five days upon the delivery of certain customary
funding documentation and the delivery of the $75 million General and Refunding
Mortgage Bond. See Note 3, Short-Term Borrowings for information regarding
SPPC's accounts receivable facility.
The accompanying financial statements do not include any adjustments
that might result from the outcome of the uncertainties discussed above.
RECLASSIFICATIONS
Certain items previously reported have been reclassified to conform to
the current year's presentation. Net income and shareholders' equity were not
affected by these reclassifications.
NEVADA POWER COMPANY FINANCIAL STATEMENTS
The presentation of the condensed consolidated statements of operations
and cash flows of NPC for the three months ended March 31, 2002 have been
revised. Specifically, the effects of the revisions were to eliminate the line
item " Equity in losses of Sierra Pacific Resources" of $(2,932) on NPC's
Condensed Consolidated Statement of Operations and to eliminate the line item
"Equity in losses of SPR" of $(2,932) on NPC's Condensed Consolidated Statement
of Cash Flows. For additional information regarding this change in presentation,
see Note 1, Summary of Significant Accounting Policies of Notes to Financial
Statements in SPR's, NPC's and SPPC's Report on Form 10-K for the year ended
December 31, 2002.
14
DEFERRAL OF ENERGY COSTS
NPC and SPPC implemented deferred energy accounting procedures on March 1, 2001.
See Note 1, Summary of Significant Accounting Policies, of Notes to Financial
Statements in SPR's, NPC's, and SPPC's Annual Report on Form 10-K for the year
ended December 31, 2002, for additional information regarding the implementation
of deferred energy accounting by the Utilities.
The following deferred energy costs were included in the condensed consolidated
balance sheets as of March 31, 2003 (dollars in thousands):
March 31, 2003
-----------------------------------------------
NPC SPPC SPPC SPR
Description Electric Electric Gas Total
--------- --------- --------- ---------
Unamortized balances approved for collection in current rates $ 298,828 $ 108,025 $ 21,559 $ 428,412
Balances pending PUCN approval (1) (2) 191,143 15,380 - 206,523
Balances accrued since end of periods submitted for PUCN approval (3) (51,352) 2,344 (15,128) (64,136)
Terminated suppliers (2) (4) 231,845 81,901 - 313,746
--------- --------- --------- ---------
Total $ 670,464 $ 207,650 $ 6,431 $ 884,545
========= ========= ========= =========
(1)See Note 9, Regulatory Actions, for additional discussion of balances pending
PUCN approval.
(2)Balances adjusted from amounts presented as of December 31, 2002, reflecting,
primarily, a reclassification between amounts for terminated suppliers and
balances pending PUCN approval.
(3)Credits represent over-collections, that is, the extent to which gas or fuel
and purchased power costs recovered through rates exceed actual gas or fuel
and purchased power costs.
(4)Amounts related to terminated suppliers are discussed in Note 17, Commitments
and Contingencies, of Notes to Financial Statements in SPR's, NPC's, and
SPPC's Annual Report on Form 10-K for the year ended December 31, 2002.
STOCK COMPENSATION PLANS
In December 2002, the Financial Accounting Standards Board (FASB)
released Statement of Financial Accounting Standards (SFAS) No. 148, "Accounting
for Stock-Based Compensation-Transition and Disclosure," as an amendment to SFAS
No. 123, "Accounting for Stock-Based Compensation." SPR has previously adopted
the disclosure-only provisions of SFAS No. 123, and as of December 31, 2002 has
adopted the updated disclosure requirements set forth in SFAS No. 148. At March
31, 2003, SPR had several stock-based compensation plans which are described
more fully in Note 15 "Stock Compensation Plans," of Notes to Financial
Statements in SPR's, NPC's, and SPPC's Combined Annual Report on Form 10-K for
the year ended December 31, 2002. SPR applies Accounting Principles Board
Opinion No. 25, "Accounting for Stock Issued to Employees," in accounting for
its stock option plans. Accordingly, no compensation cost has been recognized
for nonqualified stock options and the employee stock purchase plan. Had
compensation cost for SPR's nonqualified stock options and the employee stock
purchase plan been determined based on the fair value at the grant dates for
awards under those plans, consistent with the provisions of SFAS No. 123, SPR's
income applicable to common stock would have been decreased to the pro forma
amounts indicated below (dollars in thousands, except earnings per share):
15
Three Months Ended
March 31,
2003 2002
-----------------------
Stock Compensation Cost included in Net Income
as Reported, net of related tax effects As Reported $ (100) $ 170
=======================
Loss applicable to Common Stock As Reported $ (16,498) $(303,916)
Less: Additional Stock Compensation Cost, net of
related tax effects Pro Forma 1,192 512
-----------------------
Loss applicable to Common Stock Pro Forma $ (17,690) $(304,428)
=======================
Basic Loss Per Share As Reported $ (0.15) $ (2.98)
Pro Forma $ (0.16) $ (2.98)
Diluted Loss Per Share As Reported $ (0.15) $ (2.98)
Pro Forma $ (0.16) $ (2.98)
RECENT PRONOUNCEMENTS
In November 2002, the FASB issued Interpretation No. 45, "Guarantor's Accounting
and Disclosure Requirements for Guarantees" (FIN 45), which elaborates on the
disclosures to be made in interim and annual financial statements of a guarantor
about its obligations under certain guarantees that it has issued. It also
clarifies that a guarantor is required to recognize, at the inception of a
guarantee, a liability for the fair value of the obligation undertaken in
issuing a guarantee. Initial recognition and measurement provisions of FIN 45
are applicable on a prospective basis to guarantees issued or modified after
December 31, 2002. The disclosure requirements are effective for financial
statements of interim or annual periods ending after December 15, 2002. As of
March 31, 2003, any guarantees of SPR and its subsidiaries were intercompany,
whereby the parent issues the guarantees on behalf of its consolidated
subsidiaries to a third party. Therefore there is no impact on the financial
position, results of operation or cash flows of SPR, NPC or SPPC.
In January 2003, the FASB issued Interpretation No. 46, "Consolidation
of Variable Interest Entities" (FIN 46), which elaborates on Accounting Research
Bulletin No. 51, "Consolidated Financial Statements." Among other requirements,
FIN 46 provides that a variable interest entity be consolidated by the
enterprise that is the primary beneficiary of the variable interest entity. FIN
46 applies immediately to variable interest entities created after January 31,
2003, and to variable interest entities in which an enterprise obtains an
interest after that date. It applies in the first fiscal year or interim period
beginning after June 15, 2003, to variable interest entities in which an
enterprise holds a variable interest that it acquired before February 1, 2003.
Management does not expect the adoption of FIN 46 to have an effect on the
financial position, results of operation or cash flows of SPR, NPC or SPPC.
NOTE 2. ASSET RETIREMENT OBLIGATIONS (AROs)
Effective January 1, 2003, the Utilities adopted the provisions of SFAS
No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 generally
applies to legal obligations associated with the retirement of long-lived
assets that result from the acquisition, construction, development and/or the
normal operation of a long-lived asset. SFAS No. 143 requires NPC to recognize
an estimated liability for the retirement of generation plant assets specified
in land leases for NPC's jointly-owned Navajo generating station because the
leases require the lessees to remove the facilities upon request of the Navajo
Nation at the expiration of the leases. However, the retirement obligation and
corresponding charges recognized were immaterial to the financial statements of
NPC. NPC also redesignated amounts from Accumulated Depreciation to a
regulatory liability in order to reflect the estimated costs of removal
collected through rates. NPC amortizes the amount added to Electric Plant In
Service and recognizes accretion expense in connection with the discounted
liability over the estimated remaining life of the Navajo generating station
assets. SPPC has no significant asset retirement obligations.
NPC and SPPC also collect removal costs in rates for certain assets
that do not have associated legal asset retirement obligations. As of March 31,
2003, NPC and SPPC estimate that they had approximately $126 million and $148
million related to removal costs recorded in Accumulated Depreciation,
respectively.
16
NOTE 3. SHORT-TERM BORROWINGS
NEVADA POWER COMPANY
On October 29, 2002, NPC established an accounts receivable purchase
facility of up to $125 million, which was arranged by Lehman Brothers. If NPC
elects to activate the receivables purchase facility, NPC will sell all of its
accounts receivable generated from the sale of electricity to customers to its
newly created bankruptcy remote special purchase subsidiary. The receivables
sales will be without recourse except for breaches of customary representations
and warranties made at the time of sale. The subsidiary will, in turn, sell
these receivables to a bankruptcy remote subsidiary of SPR. SPR's subsidiary
will issue variable rate revolving notes backed by the purchased receivables.
Lehman Brothers Holding, Inc. will be the sole initial committed purchaser of
all of the variable rate revolving notes. The agreements relating to the
receivables purchase facility contain various conditions to purchase, covenants
and trigger events, termination events and other provisions customary in
receivables transactions. In connection with NPC's receivables facility, SPR has
agreed to guaranty NPC's performance of certain obligations as a seller and
servicer under the facility.
NPC has agreed to issue $125 million principal amount of its General
and Refunding Mortgage Bonds upon activation of the accounts receivables
purchase facility. The full principal amount of the Bond would secure certain of
NPC's obligations as seller and servicer, plus certain interest, fees and
expenses thereon to the extent not paid when due, regardless of the actual
amounts owing with respect to the secured obligations. As a result, in the event
of an NPC bankruptcy or liquidation, the holder of the Bond securing the
receivables facility may recover more on a pro rata basis than the holders of
other General and Refunding Mortgage securities, who could recover less on a pro
rata basis, than they otherwise would recover. However, in no event will the
holder of the Bond recover more than the amount of obligations secured by the
Bond.
NPC intends to use the accounts receivables purchase facility as a
back-up liquidity facility and does not plan to activate this facility in the
foreseeable future. NPC may activate the facility within five days upon the
delivery of certain customary funding documentation and the delivery of the $125
million General and Refunding Mortgage Bond. As of March 31, 2003, this facility
has not been activated. NPC does not expect to activate this facility in the
foreseeable future.
SIERRA PACIFIC POWER COMPANY
On October 29, 2002, SPPC established an accounts receivable purchase
facility of up to $75 million, which was arranged by Lehman Brothers. If SPPC
elects to activate the receivables purchase facility, SPPC will sell all of its
accounts receivable generated from the sale of electricity and gas to customers
to its newly created bankruptcy-remote special purpose subsidiary. The
receivables sales will be without recourse except for breaches of customary
representations and warranties made at the time of sale. The subsidiary will, in
turn, sell these receivables to a bankruptcy-remote subsidiary of SPR. SPR's
subsidiary will issue variable rate revolving notes backed by the purchased
receivables. Lehman Brothers Holdings, Inc. will be the sole initial committed
purchaser of all of the variable rate revolving notes. The agreements relating
to the receivables purchase facility contain various conditions to purchase,
covenants and trigger events, termination events and other provisions customary
in receivables transactions. In connection with SPPC's receivables facility, SPR
has agreed to guaranty SPPC's performance of certain obligations as a seller and
servicer under the facility.
SPPC has agreed to issue $75 million principal amount of its General
and Refunding Mortgage Bonds upon activation of the accounts receivables
purchase facility. The full principal amount of the Bond would secure certain of
SPPC's obligations as seller and servicer, plus certain interest, fees and
expenses thereon to the extent not paid when due, regardless of the actual
amounts owing with respect to the secured obligations. As a result, in the event
of an SPPC bankruptcy or liquidation, the holder of the Bond securing the
receivables facility may recover more on a pro rata basis than the holders of
other General and Refunding Mortgage securities, who could recover less on a pro
rata basis, than they otherwise would recover. However, in no event will the
holder of the Bond recover more than the amount of obligations secured by the
Bond.
SPPC intends to use the accounts receivables purchase facility as a
back-up liquidity facility and does not plan to activate this facility in the
foreseeable future. SPPC may activate the facility within five days upon the
delivery of certain customary funding documentation and the delivery of the $75
million General and Refunding Mortgage Bond. As of March 31, 2003, this facility
has not been activated. SPPC does not expect to activate this facility in the
foreseeable future.
17
NOTE 4. LONG-TERM DEBT
Substantially all utility plant is subject to the liens of NPC's and
SPPC's indentures under which their First Mortgage bonds and General and
Refunding Mortgage bonds are issued.
SIERRA PACIFIC RESOURCES
In January 2003, SPR acquired $8.75 million aggregate principal amount
of its Floating Rate Notes due April 20, 2003, in exchange for approximately 1.3
million shares of its common stock, in two privately negotiated transactions
exempt from the registration requirements of the Securities Act.
On February 5, 2003, SPR acquired 2.1 million of Premium Income Equity
Securities (PIES) including approximately $104.8 million of 7.93% Senior Notes
due 2007 that are a component of the PIES, in exchange for approximately 13.66
million shares of its common stock, in five privately negotiated transactions
exempt from the registration requirements of the Securities Act.
On February 14, 2003, SPR issued $300 million of its 7.25% Convertible
Notes due 2010. Interest on the notes is payable semi-annually. At any time on
or after August 14, 2003 through the close of business February 14, 2010,
holders of the Convertible Notes may convert each $1,000 principal amount of
their notes into 219.1637 shares of SPR's common stock, subject to adjustment
upon the occurrence of certain dilution events. Until SPR has obtained
shareholder approval to fully convert the Convertible Notes into shares of
common stock, holders of the Convertible Notes will be entitled to receive
76.7073 shares of common stock and a remaining portion in cash based on the
average closing price of SPR's common stock over five consecutive trading days
for each $1,000 principal amount of notes surrendered for conversion. In the
event SPR obtains shareholder approval, it may elect to satisfy the cash payment
component of the conversion price of the Convertible Notes solely with shares of
common stock.
Because the Convertible Notes may be converted, at the holder's option,
any time after six months from issuance, there is a possibility that SPR may be
required to honor this obligation in less than one year. In addition, until SPR
has obtained shareholder approval to fully convert the Convertible Notes into
shares of common stock, SPR must satisfy part of this obligation in cash.
Accordingly, the portion of the obligation relating to the amount to be settled
upon conversion by issuing shares is classified as a long-term liability and the
portion to be settled with working capital upon demand by the holder is
classified as a current maturity. For further information regarding accounting
for the conversion option, see Note 10, Derivatives and Hedging Activities.
The Convertible Notes provide for the payment of dividends to the
holders in an amount equal to any per share dividends on SPR common stock that
would have been payable to the holders if the holders of the notes had converted
their notes into shares of common stock at the applicable conversion rate on the
record date for such dividend.
SPR may redeem some or all of the notes at any time on or after
February 14, 2008. SPR used approximately $53.4 million of the proceeds to
acquire U.S. Government securities that are pledged to the trustee as security
for the notes for the first two and one-half years and which SPR expects to use
to pay the first five interest payments on the notes. A portion of the remaining
net proceeds of the notes were used to repurchase approximately $58.5 million of
SPR's Floating Rate Notes due April 20, 2003. Of the remaining net proceeds,
approximately $133 million were used to repay the remainder of SPR's Floating
Rate Notes due April 20, 2003, and the remaining proceeds will be available for
general corporate purposes.
The indenture under which the Convertible Notes were issued does not
contain any financial covenants or any restrictions on the payment of dividends,
the repurchase of SPR's securities or the incurrence of indebtedness. The
indenture does allow the holders of the Convertible Notes to require SPR to
repurchase all or a portion of the holders' Convertible Notes upon a change of
control. The indenture also provides for an event of default if SPR or any of
its significant subsidiaries, including NPC and SPPC, fails to pay any
indebtedness in excess of $10 million or has any indebtedness of $10 million or
more accelerated and declared due and payable.
On April 21, 2003, SPR paid the remaining approximate $133 million
unsecured Floating Rate Notes, due April 20, 2003, at maturity.
SIERRA PACIFIC POWER COMPANY
On May 1, 2003, SPPC's $80 million Washoe County, Nevada, Water
Facilities Refunding Revenue Bonds, Series 2001, were successfully remarketed.
The interest rate on the bonds was adjusted from their prior two-year 5.75% term
rate to a 7.50 % term rate for the period of May 1, 2003 to and including May 3,
2004. The bonds will be subject to remarketing on May 3, 2004 and will continue
to be included in current maturities of long-term debt. In the event that the
bonds cannot be successfully remarketed on that date, SPPC will be required to
purchase the outstanding bonds at a price of 100% of principal
18
amount, plus accrued interest. From May 1, 2003 to and including May 3, 2004,
SPPC's payment and purchase obligations in respect of the bonds are secured by
SPPC's $80 million General and Refunding Mortgage Note, Series D, due 2004.
SIERRA PACIFIC COMMUNICATIONS
Sierra Touch America LLC (STA), a partnership between SPC and Touch
America, formerly Montana Power Company, was formed to construct a fiber optic
line between Salt Lake City, Utah and Sacramento, CA. On September 9, 2002, SPC
entered into an agreement to purchase and lease certain telecommunications and
fiber optic assets from Touch America, subject to successful completion of the
construction, in exchange for SPC's partnership units in Sierra Touch America
and the execution of a $35 million promissory note for a total purchase price of
$48.5 million. The promissory note accrues interest at 8% per annum. The
outstanding balance of the promissory note as of March 31, 2003, was $21.3
million.
As of March 31, 2003 NPC's, SPPC's and SPR's aggregate annual amount of
maturities for long-term debt (including obligations related to capital leases)
for the next five years is shown below (in thousands of dollars):
SPR Holding Co. SPR
NPC SPPC and Other Subs. Consolidated
----------- ----------- --------------- ------------
2003 $ 354,664 $ 101,400 $ 302,794 $ 758,858
2004 135,570 3,400 - 138,970
2005 6,091 100,150 300,000 406,241
2006 6,509 52,400 - 58,909
2007 5,949 2,400 240,218 248,567
----------- ----------- --------- ------------
Thereafter 1,345,721 759,533 80,136 2,185,390
----------- ----------- --------- ------------
1,854,504 1,019,283 923,148 3,796,935
Unamortized
(Disc.)/Prem. (13,438) (3,458) (8,054) (24,950)
----------- ----------- --------- ------------
Total $ 1,841,066 $ 1,015,825 $ 915,094 $ 3,771,985
=========== =========== ========= ============
NOTE 5. DIVIDEND RESTRICTIONS
Since SPR is a holding company, substantially all of its cash flow is
provided by dividends paid to SPR by NPC and SPPC on their common stock, all of
which is owned by SPR. Since NPC and SPPC are public utilities, they are subject
to regulation by state utility commissions which may impose limits on investment
returns or otherwise impact the amount of dividends that the Utilities may
declare and pay, and to federal statutory limitation on the payment of
dividends. In addition, certain agreements entered into by the Utilities set
restrictions on the amount of dividends they may declare and pay and restrict
the circumstances under which such dividends may be declared and paid. The
specific restrictions on dividends contained in agreements to which NPC and SPPC
are party, as well as specific regulatory limitations on dividends, are
summarized below.
NEVADA POWER COMPANY
First Mortgage Indenture. NPC's first mortgage indenture limits the
cumulative amount of dividends and other distributions that NPC may pay on its
capital stock to the cumulative net earnings of NPC since 1953, subject to
adjustments for the net proceeds of sales of capital stock since 1953. At the
present time, this restriction precludes NPC from making further payments of
dividends on NPC's common stock and will continue to bar dividends until NPC,
over time, generates sufficient earnings to eliminate the deficit under this
provision (which was approximately $254 million as of March 31, 2003), unless
the restriction is waived, amended, or removed by the consent of the first
mortgage bondholders, or the first mortgage bonds are redeemed or defeased.
Under this provision, NPC continues to have capacity to repurchase or redeem
shares of its capital stock.
Series E Notes. NPC's 10 7/8% General and Refunding Mortgage Notes,
Series E, due 2009, which were issued on October 29, 2002, limit the amount of
payments in respect of common stock that NPC may pay to SPR. However, that
19
limitation does not apply to payments by NPC to enable SPR to pay its reasonable
fees and expenses (including, but not limited to, interest on SPR's indebtedness
and payment obligations on account of SPR's PIES provided that:
- those payments do not exceed $60 million for any one calendar year,
- those payments comply with any regulatory restrictions then
applicable to NPC, and
- the ratio of consolidated cash flow to fixed charges for NPC's
most recently ended four full fiscal quarters immediately
preceding the date of payment is at least 1.75 to 1.
The terms of the Series E Notes also permit NPC to make payments to SPR in an
aggregate amount not to exceed $15 million from the date of the issuance of the
Series E Notes. In addition, NPC may make dividend payments to SPR in excess of
the amounts described above so long as, at the time of payment and after giving
effect to the payment:
- there are no defaults or events of default with respect to the Series E
Notes,
- NPC can meet a fixed charge coverage ratio test, and
- the total amount of such dividends is less than:
- the sum of 50% of NPC's consolidated net income measured on a
quarterly basis cumulative of all quarters from the date of
issuance of the Series E Notes, plus
- 100% of NPC's aggregate net cash proceeds from the issuance or
sale of certain equity or convertible debt securities of NPC, plus
- the lesser of cash return of capital or the initial amount of
certain restricted investments, plus
- the fair market value of NPC's investment in certain subsidiaries.
If NPC's Series E Notes are upgraded to investment grade by both Moodys
and S&P, these dividend restrictions will be suspended and will no longer be in
effect so long as the Series E Notes remain investment grade.
Accounts Receivable Facility. On October 29, 2002, NPC established an
accounts receivable purchase facility. The agreements relating to the
receivables purchase facility contain various conditions, including a limitation
on the payment of dividends by NPC to SPR that is identical to the limitation
contained in NPC's General and Refunding Mortgage Notes, Series E, described
above.
Preferred Trust Securities. The terms of NPC's preferred trust
securities provide that no dividends may be paid on NPC's common stock if NPC
has elected to defer payments on the junior subordinated debentures issued in
conjunction with the preferred trust securities. At this time, NPC has not
elected to defer payments on the junior subordinated debentures.
PUCN Order. The PUCN issued a Compliance Order, Docket No. 02-4037, on
June 19, 2002, relating to NPC's request for authority to issue long-term debt.
The PUCN order requires that, until such time as the order's authorization
expires (December 31, 2003), NPC must either receive the prior approval of the
PUCN or reach an equity ratio of 42% before paying any dividends to SPR. If NPC
achieves a 42% equity ratio prior to December 31, 2003, the dividend restriction
ceases to have effect. As of March 31, 2003, NPC's equity ratio was 36.0%.
Federal Power Act. NPC is subject to the provisions of the Federal
Power Act that state that dividends cannot be paid out of funds that are
properly included in capital accounts. Although the meaning of this provision is
unclear, it could be interpreted to impose an additional material limitation on
a utility's ability to pay dividends in the absence of retained earnings.
SIERRA PACIFIC POWER COMPANY
Term Loan Agreement. SPPC's Term Loan Agreement dated October 30, 2002,
which expires October 31, 2005, limits the amount of dividends that SPPC may pay
to SPR. However, that limitation does not apply to payments by SPPC to enable
SPR to pay its reasonable fees and expenses (including, but not limited to,
interest on SPR's indebtedness and payment obligations on account of SPR's PIES)
provided that those payments do not exceed $90 million, $80 million and $60
million in the aggregate for the twelve month periods ending on October 30,
2003, 2004 and 2005, respectively. The Term Loan Agreement also permits SPPC to
make dividend payments to SPR in an aggregate amount not to exceed $10 million
during the term of the Term Loan Agreement. In addition, SPPC may make dividend
payments to SPR in excess of the amounts described above so long as, at the time
of the payment and after giving effect to the payment, there are no defaults or
events of default under the Term Loan Agreement, and such amounts, when
aggregated with the amount of dividends paid to SPR by SPPC since the date of
execution of the Term Loan Agreement, do not exceed the sum of:
- (i) 50% of SPPC's Consolidated Net Income for the period commencing
January 1, 2003 and ending with last day of fiscal quarter most
recently completed prior to the date of the contemplated dividend
payment, plus
- (ii) the aggregate amount of cash received by SPPC from SPR as equity
contributions on its common stock during such period.
20
Accounts Receivable Facility. On October 29, 2002, SPPC established an
accounts receivable purchase facility. The agreements relating to the
receivables purchase facility contain various conditions, including a limitation
on the payment of dividends by SPPC to SPR that is identical to the limitation
contained in SPPC's Term Loan Agreement, described above.
Articles of Incorporation. SPPC's Articles of Incorporation contain
restrictions on the payment of dividends on SPPC's common stock in the event of
a default in the payment of dividends on SPPC's preferred stock. SPPC's Articles
also prohibit SPPC from declaring or paying any dividends on any shares of
common stock (other than dividends payable in shares of common stock), or making
any other distribution on any shares of common stock or any expenditures for the
purchase, redemption or other retirement for a consideration of shares of common
stock (other than in exchange for or from the proceeds of the sale of common
stock) except from the net income of SPPC, and its predecessor, available for
dividends on common stock accumulated subsequent to December 31, 1955, less
preferred stock dividends, plus the sum of $500,000. At the present time, SPPC
believes that these restrictions do not materially limit its ability to pay
dividends and/or to purchase or redeem shares of its common stock.
Federal Power Act. SPPC is subject to the provisions of the Federal
Power Act that state that dividends cannot be paid out of funds that are
properly included in capital accounts. Although the meaning of this provision is
unclear, it could be interpreted to impose an additional material limitation on
a utility's ability to pay dividends in the absence of retained earnings.
21
NOTE 6. EARNINGS PER SHARE (SPR)
The following table outlines the calculation for earnings per share
(EPS). The difference, if any, between Basic EPS and Diluted EPS is due to
common stock equivalent shares resulting from stock options, the employee stock
purchase plan, performance and restricted stock plans and the non-employee
director stock plan. However, due to net losses for the three-month periods
ended March 31, 2003 and 2002, these items are anti-dilutive. Accordingly,
Diluted EPS for these periods are computed using the weighted average shares
outstanding before dilution. Common stock equivalents were determined using the
treasury stock method.
Three Months Ended
March 31,
2003 2002
------------ ------------
BASIC EPS
Numerator ($000)
Loss applicable to common stock $ (16,498) $ (303,916)
============ ============
Denominator
Weighted average number of shares outstanding 111,499,881 102,110,536
============ ============
Per-Share Amount
Loss applicable to common stock $ (0.15) $ (2.98)
============ ============
DILUTED EPS
Numerator ($000)
Loss applicable to common stock $ (16,498) $ (303,916)
============ ============
Denominator (1)
Weighted average number of shares outstanding 111,499,881 102,110,536
before dilution
Stock options - 31,612
Executive long term incentive plan - performance shares - 24,694
Executive long term incentive plan - restricted shares 26,440 -
Non-Employee Director stock plan 14,183 9,355
Employee stock purchase plan - 2,660
------------ ------------
111,540,504 102,178,857
============ ============
Per-Share Amount
Loss applicable to common stock $ (0.15) $ (2.98)
============ ============
(1) The denominator does not include anti-dilutive stock equivalents for the
Stock Option Plan, Employee Stock Purchase Plan, Corporate PIES and 7.25%
Convertible Debt due to conversion prices being higher than market prices at
March 31, 2003.
NOTE 7. SEGMENT INFORMATION (SPR)
SPR operates three business segments providing regulated electric and
natural gas services. NPC has one business segment that provides electric
service to Las Vegas and surrounding Clark County. SPPC has two business
segments. One business segment provides electric service in northern Nevada and
the Lake Tahoe area of California and the other segment provides natural gas
service in the Reno-Sparks area of Nevada. Other segment information includes
segments below the quantitative threshold for separate disclosure.
Information as to the operations of the different business segments is
set forth below based on the nature of products and services offered. SPR
evaluates performance based on several factors, of which the primary financial
measure is business segment operating income. Intersegment revenues are not
material.
Financial data for business segments is as follows (in thousands):
22
Three Months Ended NPC SPPC Total
March 31, 2003 Electric Electric Electric Gas Other Consolidated
- ------------------ ---------- --------- ---------- -------- ------- --------------
Operating Revenues $ 331,652 $ 205,454 $ 537,106 $ 64,617 $ 1,239 $ 602,962
========== ========= ========== ======== ======= ==============
Operating Income $ 17,413 $ 20,232 $ 37,645 $ 3,589 $ 4,563 $ 45,797
========== ========= ========== ======== ======= ==============
Three Months Ended NPC SPPC Total
March 31, 2002 Electric Electric Electric Gas Other Consolidated
- ------------------ ---------- --------- ---------- -------- ------- --------------
Operating Revenues $ 356,272 $ 224,754 $ 581,026 $ 55,083 $ 2,755 $ 638,864
========== ========= ========== ======== ======= ==============
Operating Income (Loss) $ (260,759) $ 23,401 $ (237,358) $ 1,533 $ 5,074 $ (230,751)
========== ========= ========== ======== ======= ==============
NOTE 8. DISPOSAL OF LONG-LIVED ASSETS
During 2002, the Utilities began pursuing the sale of several
non-essential properties. As a result, on January 15, 2003, NPC sold a parcel of
land located on Flamingo Road near the Barbary Coast Casino in Las Vegas,
Nevada. NPC received cash proceeds of approximately $18 million for the property
and retained an easement and other rights necessary to maintain aerial power
lines that cross the property. Also, it was agreed that NPC will receive an
additional $2.6 million from the sale if the power lines that cross the property
are removed and the other rights are relinquished within a five-year period from
the date of the sale. The property had been originally transferred to NPC at no
cost. The transaction resulted in a gain of $17.7 million, which will be
recognized into revenue over a period of three years consistent with the
accounting treatment directed by the PUCN.
NPC is pursuing the sale of land parcels located on Flamingo Road from
Koval Lane to Maryland Parkway, commonly known as "the Flamingo Corridor." These
properties are presently under long-term leases with restaurants, convenience
stores, gas stations, etc. On April 21, 2003 NPC provided notice to the tenants
of the Flamingo Corridor properties of its intent to sell the properties at a
public auction. Currently the auction is scheduled for mid-July 2003. The
carrying value of the properties is approximately $.9 million.
On November 11, 2002, SPPC agreed to sell land located in Nevada County
and Sierra County, California, commonly referred to as Independence Lake. The
sale was subject to review by a third party who retained certain rights,
including water rights, after the sale is completed. Also, the sales agreement
included a due diligence review period of 180 days which allowed the buyer to
review and accept a variety of matters agreed to by both parties. In April 2003,
the buyer terminated the agreement during the review period as provided for in
the agreement. The agreed upon sales price was $22 million and the carrying
value of the property is approximately $108,000. SPPC plans to sell the property
and is continuing to work with all potential buyers.
NOTE 9. REGULATORY ACTIONS
NEVADA POWER COMPANY 2002 DEFERRED ENERGY CASE
On November 14, 2002, NPC filed an application with the PUCN seeking to
clear deferred balances for purchased fuel and power costs accumulated between
October 1, 2001, and September 30, 2002, as required by law. The application
seeks to establish a rate to repay accumulated purchased fuel and power costs of
$195.7 million, together with a carrying charge, over a period of not more than
three years. The application also requests a reduction to the going-forward rate
for energy, reflecting reduced wholesale energy costs. The combined effect of
these two adjustments results in an overall rate reduction of 5.3%.
Intervenors filed their direct testimony on March 7, 2003, and
supplemental testimony was filed March 27, 2003, calling for disallowances
between approximately $108 and $300 million of the total fuel and purchased
power costs. The largest of the proposed disallowances are based on the same
alleged imprudence as found in the PUCN order for NPC's 2001 Deferred Energy
Case relating to NPC's failure to enter into power contracts in 1999. Certain
Intervenors' testimony, in the current case, have argued in favor of
disallowances based on the same alleged imprudence as cited in the last deferred
order but have not quantified their proposals and in some cases have argued in
favor of disallowances in excess of the ranges previously indicated. The PUCN
Staff does not support this disallowance but calculated a range of $116 to $347
million in the event that the PUCN disallows deferred energy costs based upon
the same alleged imprudence cited by the PUCN in its 2001 decision relative to
this issue.
23
While all Intervenors have called for the PUCN to reduce NPC's
requested energy rates for recovery of past energy costs, some have also
proposed to increase customers' energy rates for purchases that will occur
during the upcoming deferred accounting period, which would decrease the
accumulation of deferred energy costs.
NPC's rebuttal testimony was filed March 31, 2003. The hearing
commenced on April 7, 2003, and was completed on April 17, 2003. A special
agenda meeting is scheduled for May 9, 2003, at which time a ruling from the
Commission is expected.
SIERRA PACIFIC POWER COMPANY 2003 DEFERRED ENERGY CASE
On January 14, 2003, SPPC filed an application with the PUCN, as
required by law, seeking to clear deferred balances for purchased fuel and power
costs accumulated between December 1, 2001 and November 30, 2002. The
application seeks to establish a Deferred Energy Accounting Adjustment (DEAA)
rate to repay accumulated purchased fuel and power costs of $15.4 million and
spread the cost recovery over a period of not more than three years. It also
seeks to recalculate the Base Tariff Energy Rate to reflect anticipated ongoing
purchased fuel and power costs. The total rate increase resulting from the
requested DEAA would amount to 0.01%. The intervenors' testimony was received
April 25, 2003, and includes proposed disallowances from $34 million to $76
million.
While all Intervenors call for the PUCN to reduce SPPC's requested
energy rates for recovery of past energy costs, some also propose to increase
customers' energy rates for purchases that will occur during the upcoming
deferred accounting period, which would decrease the accumulation of deferred
energy costs. A hearing is scheduled to begin on May 12, 2003, and a ruling is
required before July 13, 2003.
NOTE 10. DERIVATIVES AND HEDGING ACTIVITIES
SPR, SPPC, and NPC apply (SFAS) No. 133, "Accounting for Derivative
Instruments and Hedging Activities," as amended by SFAS No. 138. As amended,
SFAS No. 133 requires that an entity recognize all derivatives as either assets
or liabilities in the statement of financial position, measure those instruments
at fair value, and recognize changes in the fair value of the derivative
instruments in earnings in the period of change unless the derivative qualifies
as an effective hedge.
SPR's and the Utilities' objective in using derivatives is to reduce
exposure to energy price risk and interest rate risk. Energy price risks result
from activities that include the generation, procurement and marketing of power
and the procurement and marketing of natural gas. Derivative instruments used to
manage energy price risk include forwards, options, and swaps. These contracts
allow the Utilities to reduce the risks associated with volatile electricity and
natural gas markets.
At March 31, 2003, the fair value of the derivatives resulted in the
recording of $54 million, $42 million and $12 million in risk management assets
and $71 million, $36 million and $35 million in risk management liabilities in
the Consolidated Balance Sheets of SPR, NPC and SPPC, respectively. Due to
deferred energy accounting under which the Utilities operate, regulatory assets
and liabilities are established to the extent that electricity and natural gas
derivative gains and losses are recoverable or payable through future rates.
Accordingly, at March 31, 2003, $47 million, $15 million and $32 million in net
risk management regulatory assets were recorded in the Consolidated Balance
Sheets of SPR, NPC, and SPPC, respectively. In addition, for the three months
ended March 31, 2003, the unrealized gains and losses resulting from the change
in the fair value of derivatives designated and qualifying as cash flow hedges
for SPR, NPC, and SPPC were recorded in Other Comprehensive Income. Such amounts
are reclassified into earnings when the related transactions are settled or
terminate. Accordingly, $1.1 million relating to SPR's terminated interest rate
swap was reclassified into earnings during the three months ended March 31,
2003.
The effects of SFAS No. 133 on comprehensive income and the components
thereof at March 31, 2003, and 2002, are as follows (in thousands):
24
SPR NPC SPPC
------------- ------------- --------------
Net Income (Loss) for the three months ended March 31, 2003 $ (16,498) $ (15,246) $ 3,023
Change in market value of risk management assets and liabilities as
of March 31, 2003, net of taxes of $1,051, $165, and $125 1,952 492 232
respectively
------------- ------------- --------------
Total Comprehensive Income (Loss) for the
three months ended March 31, 2003 $ (14,546) $ (14,754) $ 3,255
============= ============= ==============
Net Income (Loss) for the three months ended March 31, 2002 $ (303,916) $ (300,984) $ 9,969
Change in market value of risk management assets and liabilities as
of March 31, 2002, net of taxes of ($3,127), ($134), and ($64),
respectively
(5,807) 248 118
------------- ------------- --------------
Total Comprehensive Income for the
three months ended March 31, 2002 $ (309,723) $ (300,736) $ 10,087
============= ============= ==============
In connection with SPR's issuance of its Convertible Notes (see Note 4,
Long-Term Debt), the conversion option, which is treated as a cash-settled
written call option, was separated from the debt and accounted for separately as
a derivative instrument in accordance with FASB's Emerging Issues Task Force
Issue 90-19, "Convertible Bonds with Issuer Option to Settle for Cash upon
Conversion". Upon issuance, the fair value of the option was recorded as a
current liability in Other Current Liabilities. The change in the fair value is
recognized in earnings in the period of the change.
NOTE 11. COMMITMENTS AND CONTINGENCIES
ENVIRONMENTAL
NEVADA POWER COMPANY
The Grand Canyon Trust and Sierra Club filed a lawsuit in the U.S.
District Court, District of Nevada in February 1998 against the owners
(including NPC) of the Mohave Generation Station ("Mohave"), alleging violations
of the Clean Air Act regarding emissions of sulfur dioxide and particulates. An
additional plaintiff, National Parks and Conservation Association, later joined
the suit. The plant owners and plaintiffs have had numerous settlement
discussions and filed a proposed settlement with the court in October 1999. The
consent decree, approved by the court in November 1999, established emission
limits for sulfur dioxide and opacity and required installation of air pollution
controls for sulfur dioxide, nitrogen oxides and particulate matter. The new
emission limits must be met by January 1, 2006 and April 1, 2006 for the first
and second units, respectively. The estimated cost of new controls is $1.1
billion. As a 14% owner in Mohave, NPC's cost could be $154 million.
NPC's ownership interest in Mohave comprises approximately 10% of NPC's
peak generation capacity. Southern California Edison (SCE) is the operating
partner of Mohave. On May 17, 2002, SCE filed with the CPUC an application to
address the future disposition of SCE's share of Mohave. Mohave obtains all of
its coal supply from a mine in northeast Arizona on lands of the Navajo Nation
and the Hopi Tribe (the Tribes). This coal is delivered from the mine to Mohave
by means of a coal slurry pipeline which requires water that is obtained from
groundwater wells located on lands of the Tribes in the mine vicinity.
Due to the lack of progress in negotiations with the Tribes and other
parties to resolve several coal and water supply issues, SCE's application
states that it appears that it probably will not be possible for SCE to extend
Mohave's operations beyond 2005. Due to the uncertainty over a post-2005 coal
supply, SCE and the other Mohave co-owners have been prevented from commencing
the installation of extensive pollution control equipment that must be put in
place if Mohave's operations are extended past 2005.
NPC is currently evaluating and analyzing all of its options with
regard to the Mohave project.
In May 1997, the Nevada Division of Environmental Protection (NDEP)
ordered NPC to submit a plan to eliminate the discharge of Reid Gardner Station
wastewater to groundwater. The NDEP order also required a hydrological
assessment of groundwater impacts in the area. In June 1999, NDEP determined
that wastewater ponds had degraded groundwater quality. In August 1999, NDEP
issued a discharge permit to Reid Gardner Station and an order that requires all
wastewater ponds to be closed or lined with impermeable liners over the next 10
years. This order also required NPC to submit a Site Characterization Plan to
NDEP to ascertain impacts. This plan has been approved by NDEP. NDEP is expected
to identify remediation requirements of
25
contaminated groundwater resulting from these evaporation ponds by July 2003.
New pond construction and lining costs are estimated to cost approximately $25
million, of which, $17 million is expected to be spent by the end of 2003.
At the Reid Gardner Station, the NDEP has determined that there is
additional groundwater contamination that resulted from oil spills at the
facility. NDEP has required NPC to submit a corrective action plan. The extent
of contamination has been determined and remediation is occurring at a modest
rate. A hydro-geologic evaluation of the current remediation was completed, and
a dual phase extraction remediation system, which has been approved by NDEP,
will be constructed beginning in May 2003 at an estimated cost of $150,000.
In May 1999, NDEP issued an order to eliminate the discharge of NPC's
Clark Station wastewater to groundwater. The order also required a hydrological
assessment of groundwater impacts in the area. This assessment, submitted to
NDEP in February 2001, warranted a Corrective Action Plan, which was approved in
June 2002. Remediation costs are expected to be approximately $100,000. In
addition to remediation, NPC spent $663,000 to line all existing treated water
ponds. Lining of all existing treated water ponds was completed in February
2003.
In July 2000, NPC received a request from the EPA for information to
determine the compliance of certain generation facilities at the Clark Station
with the applicable State Implementation Plan. In November 2000, NPC and the
Clark County Health District entered into a Corrective Action Order requiring,
among other steps, capital expenditures at the Clark Station totaling
approximately $3 million. In March 2001, the EPA issued an additional request
for information that could result in remediation beyond that specified in the
November 2000 Corrective Action Order. If the EPA prevails, capital expenditures
and temporary outages of four of Clark Station's generation units could be
required. Additionally, depending on the time of year that the compliance
activity and corresponding generation outage would occur, the incremental cost
to purchase replacement energy could be substantial. To date, EPA has not issued
additional requests for further information.
NEICO, a wholly owned subsidiary of NPC, owns property in Wellington,
Utah, which was the site of a coal washing and load out facility. The site now
has a reclamation estimate supported by a bond of $4.8 million with the Utah
Division of Oil and Gas Mining. The property was under contract for sale and the
contract required the purchaser to provide $1.3 million in escrow towards
reclamation. However, the sales contract was terminated and NEICO took title to
the escrow funds. The property is currently leased with the intention to reclaim
coal fines with subsequent revenues and reduction to the reclamation bond.
SIERRA PACIFIC POWER COMPANY
In September 1994 Region VII of the EPA notified SPPC that it was being
named as a potentially responsible party (PRP) regarding the past improper
handling of Polychlorinated Biphenyls (PCB's) by PCB Treatment, Inc., in two
buildings, one located in Kansas City, Kansas and the other in Kansas City,
Missouri (the Sites). Prior to 1994, SPPC sent PCB contaminated material to PCB
Treatment, Inc. for disposal. Certificates of disposal were issued to SPPC by
PCB Treatment, Inc. however; the contaminated material was not disposed of, but
remained on-site. A number of the largest PRP's formed a steering committee,
which is chaired by SPPC. The steering committee has completed its site
investigations and the EPA has determined that the Sites should be remediated by
removing the buildings to the appropriate landfills. The EPA has issued an
administrative order on consent requiring the steering committee to oversee the
performance of the work. SPPC has recorded a preliminary liability for the Sites
of $650,000 of which approximately $136,000 has been spent through March 31,
2003. The steering committee is obtaining cost estimates for removal of the
buildings. Once these costs have been determined, SPPC will be in a better
position to estimate and record the ultimate liabilities for the Sites.
LANDS OF SIERRA
LOS, a wholly owned subsidiary of SPR, owns property in North Lake
Tahoe, California, which is leased to independent condominium owners. The
property has both soil and groundwater petroleum contamination resulting from an
underground fuel tank that has been removed from the property. Additional
contamination from a third party fuel tank on the property has also been
identified and is undergoing remediation. On February 3, 2003, the Lahontan
Regional Water Quality Control Board re-opened closure of this property. By
October 1, 2003, SPR will complete the evaluation of alternative remediation
technologies and their effectiveness in reducing contamination at this site. An
application for closure will be re-submitted at that time. Additional
remediation costs are expected to be approximately $100,000.
LITIGATIONCONTINGENCIES
NEVADA POWER COMPANY AND SIERRA PACIFIC POWER COMPANY
Enron Power Marketing (Enron) filed a complaint with the United States
Bankruptcy Court for the Southern District of New York seeking to recover
approximately $216 million and $93 million against NPC and SPPC, respectively,
for liquidated damages for power supply contracts terminated by Enron in May
2002 and for power previously delivered to the Utilities. The Utilities have
denied liability on numerous grounds, including deceit and misrepresentation in
the inducement
26
(including, but not limited to, misrepresentation as to Enron's ability to
perform) and fraud, unfair trade practices and market manipulation. The
Utilities filed motions to dismiss for lack of jurisdiction and/or for a stay of
all proceedings pending the actions of the Utilities' proceedings under Section
206 of the Federal Power Act at the FERC. The Utilities have also filed proofs
of claims and counterclaims against Enron, for the full amount of the
approximately $300 million claimed to be owed and additional damages, as well as
for unspecified damages to be determined during the case as a result of acts and
omissions of Enron in manipulating the power markets, wrongful termination of
its transactions with the Utilities, and fraudulent inducement to enter into
transactions with Enron, among other issues.
On December 19, 2002, the bankruptcy judge granted Enron's motion for
partial summary judgment on Enron's claim for $17.7 million and $6.7 million,
respectively, for energy delivered by Enron in April 2002, for which NPC and
SPPC did not pay. The court ordered this money to be deposited into an escrow
account not subject to claims of Enron's creditors and subject to refund
depending on the outcome of the Utilities' FERC cases on the merits. The
Utilities made the deposit as required. The bankruptcy court denied the
Utilities' motion to stay the proceeding pending the outcome of the Utilities'
Section 206 case at the FERC and denied the Utilities' motion to dismiss for
lack of jurisdiction as to Enron's claims for power previously delivered to the
Utilities. The court stated that it would rule in due course on Enron's motion
for partial summary judgment to require NPC and SPPC to post $200 million and
$87 million, respectively pending the outcome of the case on the merits, and for
judgment on the merits on Enron's liquidated damage claim (contract price less
market price on the date of termination) relating to power it did not deliver
under contracts terminated by Enron in May 2002. The court took under advisement
the Utilities' motion to stay or dismiss Enron's claim for liquidated damages
relating to the undelivered power. On April 3, 2003, the court heard arguments
regarding Enron's motion to dismiss the Utilities' counterclaims against Enron
for unspecified damages to be determined during the case, but did not rule on
this matter nor did it indicate when a decision on this matter can be expected.
The Utilities are unable to predict the outcome of these motions. The Utilities
continue to participate in non-binding court-ordered mediation proceedings along
with all of Enron's other terminated purchased power counterparties. The United
States District Court for the Southern District of New York has also denied the
Utilities' motion to withdraw reference of the matter to the bankruptcy court
without prejudice.
The bankruptcy court currently has under submission (1) Enron's motion
to dismiss the Utilities' counterclaims, (2) Enron's motion for partial summary
judgment regarding the amounts alleged to be due for undelivered power and the
posting of collateral for undelivered power, and (3) the Utilities' motion to
dismiss or stay proceeding on Enron's claims relating to delivered power. A
decision adverse to the Utilities on Enron's motion for partial summary
judgment, or an adverse decision in the lawsuit with respect to liability as to
Enron's claims on the merits for undelivered power, would have a material
adverse effect on SPR's and the Utilities' financial condition and liquidity,
and could make it difficult for one or more of SPR, NPC or SPPC to continue to
operate outside of bankruptcy.
NEVADA POWER COMPANY
On September 5, 2002, Morgan Stanley Capital Group (MSCG) initiated an
arbitration pursuant to the arbitration provisions in various power supply
contracts terminated by MSCG in April 2002. In the arbitration, MSCG requested
that the arbitrator compel NPC to pay MSCG $25 million pending the outcome of
any dispute regarding the amount owed under the contracts. NPC claimed that
nothing is owed under the contracts on various grounds, including breach by MSCG
in terminating the contracts, and further, that the arbitrator does not have
jurisdiction over NPC's contract claims and defenses. In March 2003, the
arbitrator overseeing the arbitration proceedings dismissed MSCG's demand for
arbitration and agreed that the issues raised by MSCG were not calculation
issues subject to arbitration and that NPC's contract defenses were likewise not
arbitrable.
NPC has since filed a complaint for declaratory relief in the U.S.
District Court for the District of Nevada asking the Court to declare that NPC
is not liable for any damages as a result of MSCG's termination of its power
supply contracts. MSCG has not yet answered or responded to the complaint;
however, on April 17, 2003, MSCG filed a complaint against NPC at the FERC
conceding that the issues raised by NPC were litigable in court but asking the
FERC to declare that under the WSPP agreement NPC should post the $25 million in
dispute as collateral pending the outcome of the litigation. NPC is unable to
predict the outcome of these proceedings.
NOTE 12. SUBSEQUENT EVENTS
See Notes 1, 4, 8, 9 and 11 for discussion of events occurring after
March 31, 2003.
27
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
FORWARD-LOOKING STATEMENTS AND RISK FACTORS
THE INFORMATION IN THIS FORM 10-Q INCLUDES FORWARD-LOOKING STATEMENTS
WITHIN THE MEANING OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995.
THESE FORWARD-LOOKING STATEMENTS RELATE TO ANTICIPATED FINANCIAL PERFORMANCE,
MANAGEMENT'S PLANS AND OBJECTIVES FOR FUTURE OPERATIONS, BUSINESS PROSPECTS,
OUTCOME OF REGULATORY PROCEEDINGS, MARKET CONDITIONS AND OTHER MATTERS. WORDS
SUCH AS "ANTICIPATE," "BELIEVE," "ESTIMATE," "EXPECT," "INTEND," "PLAN" AND
"OBJECTIVE" AND OTHER SIMILAR EXPRESSIONS IDENTIFY THOSE STATEMENTS THAT ARE
FORWARD-LOOKING. THESE STATEMENTS ARE BASED ON MANAGEMENT'S BELIEFS AND
ASSUMPTIONS AND ON INFORMATION CURRENTLY AVAILABLE TO MANAGEMENT. ACTUAL RESULTS
COULD DIFFER MATERIALLY FROM THOSE CONTEMPLATED BY THE FORWARD-LOOKING
STATEMENTS. IN ADDITION TO ANY ASSUMPTIONS AND OTHER FACTORS REFERRED TO
SPECIFICALLY IN CONNECTION WITH SUCH STATEMENTS, FACTORS THAT COULD CAUSE THE
ACTUAL RESULTS OF SIERRA PACIFIC RESOURCES (SPR), NEVADA POWER COMPANY (NPC), OR
SIERRA PACIFIC POWER COMPANY (SPPC) TO DIFFER MATERIALLY FROM THOSE CONTEMPLATED
IN ANY FORWARD-LOOKING STATEMENT INCLUDE, AMONG OTHERS, THE FOLLOWING:
(1) UNFAVORABLE RULINGS IN RATE CASES PREVIOUSLY FILED, CURRENTLY PENDING
AND TO BE FILED BY NPC AND SPPC (THE UTILITIES) WITH THE PUBLIC
UTILITIES COMMISSION OF NEVADA (PUCN), INCLUDING THE PERIODIC
APPLICATIONS TO RECOVER COSTS FOR FUEL AND PURCHASED POWER THAT HAVE
BEEN RECORDED BY THE UTILITIES IN THEIR DEFERRED ENERGY ACCOUNTS, AND
DEFERRED NATURAL GAS RECORDED BY SPPC FOR ITS GAS DISTRIBUTION
BUSINESS;
(2) THE ABILITY OF SPR, NPC, AND SPPC TO ACCESS THE CAPITAL MARKETS TO
SUPPORT THEIR REQUIREMENTS FOR WORKING CAPITAL, INCLUDING AMOUNTS
NECESSARY TO FINANCE DEFERRED ENERGY COSTS, CONSTRUCTION COSTS, AND
THE REPAYMENT OF MATURING DEBT, PARTICULARLY IN THE EVENT OF
ADDITIONAL UNFAVORABLE RULINGS BY THE PUCN, A FURTHER DOWNGRADE OF THE
CURRENT DEBT RATINGS OF SPR, NPC, OR SPPC, AND/OR ADVERSE DEVELOPMENTS
WITH RESPECT TO NPC's OR SPPC'c POWER AND FUEL SUPPLIERS;
(3) WHETHER NPC'S ABILITY TO PAY SPR DIVIDENDS WILL BE RESTORED IN THE
NEAR FUTURE, AND WHETHER SPPC WILL BE ABLE TO CONTINUE TO PAY SPR
DIVIDENDS UNDER THE TERMS OF SPPC's FINANCING AGREEMENTS AND/OR
RESTATED ARTICLES OF INCORPORATION;
(4) WHETHER THE PUCN WILL ISSUE FAVORABLE ORDERS IN A TIMELY MANNER TO
PERMIT THE UTILITIES TO BORROW MONEY AND ISSUE ADDITIONAL SECURITIES
TO FINANCE THE UTILITIES' OPERATIONS AND TO PURCHASE POWER AND FUEL
NECESSARY TO SERVE THEIR RESPECTIVE CUSTOMERS AND TO REPAY MATURING
DEBT;
(5) WHETHER SUPPLIERS, SUCH AS ENRON, WHICH HAVE TERMINATED THEIR POWER
SUPPLY CONTRACTS WITH NPC AND/OR SPPC WILL BE SUCCESSFUL IN PURSUING
THEIR CLAIMS AGAINST THE UTILITIES FOR LIQUIDATED DAMAGES UNDER THEIR
POWER SUPPLY CONTRACTS, AND WHETHER ENRON WILL BE SUCCESSFUL IN ITS
LAWSUIT AGAINST NPC AND SPPC;
(6) WHETHER SPR, NPC, AND SPPC WILL BE ABLE TO MAINTAIN SUFFICIENT
STABILITY WITH RESPECT TO THEIR LIQUIDITY AND RELATIONSHIPS WITH
SUPPLIERS TO BE ABLE TO CONTINUE TO OPERATE OUTSIDE OF BANKRUPTCY;
(7) WHETHER CURRENT SUPPLIERS OF PURCHASED POWER, NATURAL GAS, OR FUEL TO
NPC OR SPPC WILL CONTINUE TO DO BUSINESS WITH NPC OR SPPC OR WILL
TERMINATE THEIR CONTRACTS AND SEEK LIQUIDATED DAMAGES FROM THE
RESPECTIVE UTILITY;
(8) WHETHER THE UTILITIES WILL NEED TO PURCHASE ADDITIONAL POWER ON THE
SPOT MARKET TO MEET UNANTICIPATED POWER DEMANDS (FOR EXAMPLE, DUE TO
UNSEASONABLY HOT WEATHER) AND WHETHER SUPPLIERS WILL BE WILLING TO
SELL SUCH POWER TO THE UTILITIES IN LIGHT OF THEIR WEAKENED FINANCIAL
CONDITION;
(9) WHETHER SPPC WILL BE ABLE TO MAKE THE GASIFIER FACILITY AT THE PINON
PINE POWER PROJECT OPERATIONAL AND, IN ANY EVENT, WHETHER SPPC WILL BE
SUCCESSFUL IN OBTAINING PUCN APPROVAL TO RECOVER THE COSTS OF THE
GASIFIER IN A FUTURE GENERAL RATE CASE;
(10) WHETHER NPC AND SPPC WILL BE SUCCESSFUL IN OBTAINING PUCN APPROVAL TO
RECOVER GOODWILL AND OTHER MERGER COSTS RECORDED IN CONNECTION WITH
THE 1999 MERGER BETWEEN SPR AND NPC IN A FUTURE GENERAL RATE CASE;
(11) WHOLESALE MARKET CONDITIONS, INCLUDING AVAILABILITY OF POWER ON THE
SPOT MARKET, WHICH AFFECT THE PRICES THE UTILITIES HAVE TO PAY FOR
POWER AS WELL AS THE PRICES AT WHICH THE UTILITIES CAN SELL ANY EXCESS
POWER;
28
(12) THE FINAL OUTCOME OF THE UTILITIES' PENDING LAWSUITS IN NEVADA STATE
COURT SEEKING TO REVERSE PORTIONS OF THE PUCN'S ORDERS DENYING THE
RECOVERY OF DEFERRED ENERGY COSTS, INCLUDING THE OUTCOME OF PETITIONS
FILED BY THE BUREAU OF CONSUMER PROTECTION OF THE NEVADA ATTORNEY
GENERAL'S OFFICE SEEKING ADDITIONAL DISALLOWANCES;
(13) WHETHER THE UTILITIES WILL BE ABLE, EITHER THROUGH FEDERAL ENERGY
REGULATORY COMMISSION (FERC) PROCEEDINGS OR NEGOTIATION, TO OBTAIN
LOWER PRICES ON THEIR LONGER-TERM PURCHASED POWER CONTRACTS ENTERED
INTO DURING 2000 AND 2001 THAT ARE PRICED ABOVE CURRENT MARKET PRICES
FOR ELECTRICITY;
(14) THE EFFECT THAT ANY FUTURE TERRORIST ATTACKS, WARS, THREATS OF WAR, OR
EPIDEMICS MAY HAVE ON THE TOURISM AND GAMING INDUSTRIES IN NEVADA,
PARTICULARLY IN LAS VEGAS, AS WELL AS ON THE ECONOMY IN GENERAL;
(15) UNSEASONABLE WEATHER AND OTHER NATURAL PHENOMENA, WHICH CAN HAVE
POTENTIALLY SERIOUS IMPACTS ON THE UTILITIES' ABILITY TO PROCURE
ADEQUATE SUPPLIES OF FUEL OR PURCHASED POWER TO SERVE THEIR RESPECTIVE
CUSTOMERS AND ON THE COST OF PROCURING SUCH SUPPLIES;
(16) INDUSTRIAL, COMMERCIAL, AND RESIDENTIAL GROWTH IN THE SERVICE
TERRITORIES OF THE UTILITIES;
(17) THE LOSS OF ANY SIGNIFICANT CUSTOMERS;
(18) THE EFFECT OF EXISTING OR FUTURE NEVADA, CALIFORNIA, OR FEDERAL
LEGISLATION OR REGULATIONS AFFECTING ELECTRIC INDUSTRY RESTRUCTURING,
INCLUDING LAWS OR REGULATIONS WHICH COULD ALLOW ADDITIONAL CUSTOMERS
TO CHOOSE NEW ELECTRICITY SUPPLIERS OR CHANGE THE CONDITIONS UNDER
WHICH THEY MAY DO SO;
(19) CHANGES IN THE BUSINESS OF MAJOR CUSTOMERS, INCLUDING THOSE ENGAGED IN
GOLD MINING OR GAMING, WHICH MAY RESULT IN CHANGES IN THE DEMAND FOR
SERVICES OF THE UTILITIES, INCLUDING THE EFFECT ON THE NEVADA GAMING
INDUSTRY OF THE OPENING OF ADDITIONAL INDIAN GAMING ESTABLISHMENTS IN
CALIFORNIA AND OTHER STATES;
(20) CHANGES IN ENVIRONMENTAL REGULATIONS, TAX, OR ACCOUNTING MATTERS OR
OTHER LAWS AND REGULATIONS TO WHICH THE UTILITIES ARE SUBJECT;
(21) FUTURE ECONOMIC CONDITIONS, INCLUDING INFLATION OR DEFLATION RATES AND
MONETARY POLICY;
(22) FINANCIAL MARKET CONDITIONS, INCLUDING CHANGES IN AVAILABILITY OF
CAPITAL OR INTEREST RATE FLUCTUATIONS;
(23) UNUSUAL OR UNANTICIPATED CHANGES IN NORMAL BUSINESS OPERATIONS,
INCLUDING UNUSUAL MAINTENANCE OR REPAIRS; AND
(24) EMPLOYEE WORKFORCE FACTORS, INCLUDING CHANGES IN COLLECTIVE BARGAINING
UNIT AGREEMENTS, STRIKES, OR WORK STOPPAGES.
OTHER FACTORS AND ASSUMPTIONS NOT IDENTIFIED ABOVE MAY ALSO HAVE BEEN
INVOLVED IN DERIVING THESE FORWARD-LOOKING STATEMENTS, AND THE FAILURE OF THOSE
OTHER ASSUMPTIONS TO BE REALIZED, AS WELL AS OTHER FACTORS, MAY ALSO CAUSE
ACTUAL RESULTS TO DIFFER MATERIALLY FROM THOSE PROJECTED. SPR, NPC AND SPPC
ASSUME NO OBLIGATION TO UPDATE FORWARD-LOOKING STATEMENTS TO REFLECT ACTUAL
RESULTS, CHANGES IN ASSUMPTIONS OR CHANGES IN OTHER FACTORS AFFECTING
FORWARD-LOOKING STATEMENTS.
CRITICAL ACCOUNTING POLICIES
The following items represent critical accounting policies that under
different conditions or using different assumptions could have a material effect
on the financial condition, liquidity and capital resources of SPR and the
Utilities:
REGULATORY ACCOUNTING
The Utilities' rates are currently subject to the approval of the PUCN
and, in the case of SPPC, they are also subject to the approval of California
Public Utility Commission (CPUC) and are designed to recover the cost of
providing generation, transmission and distribution services. As a result, the
Utilities qualify for the application of Statement of Financial Accounting
Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of
Regulation," issued by the Financial Accounting Standards Board (FASB). This
statement recognizes that the rate actions of a regulator can provide reasonable
assurance of the existence of an asset and requires the capitalization of
incurred costs that would otherwise be charged to expense where it is probable
that future revenue will be provided to recover these costs. SFAS No. 71
prescribes the method to be used to record the financial transactions of a
regulated entity. The criteria for applying SFAS No. 71 include the following:
(i) rates are set
29
by an independent third party regulator, (ii) approved rates are intended to
recover the specific costs of the regulated products or services, and (iii)
rates that are set at levels that will recover costs can be charged to and
collected from customers.
Regulatory assets represent incurred costs that have been deferred
because it is probable they will be recovered through future rates collected
from customers. Regulatory liabilities generally represent obligations to make
refunds to customers for previous collections for costs that are not likely to
be incurred. Management regularly assesses whether the regulatory assets are
probable of future recovery by considering factors such as applicable regulatory
environment changes and the status of any pending or potential deregulation
legislation. Although current rates do not include the recovery of all existing
regulatory assets as discussed further below and in Note 1 in Notes to Financial
Statements in SPR's, NPC's, and SPPC's Annual Report on Form 10-K for the year
ended December 31, 2002, management believes the existing regulatory assets are
probable of recovery. This determination reflects the current political and
regulatory climate in the state, and is subject to change in the future. If
future recovery of costs ceases to be probable, the write-off of regulatory
assets would be required to be recognized as a charge or expensed in current
period earnings.
Regulatory Accounting affects other Critical Accounting Policies,
including Deferred Energy Accounting, Accounting for Goodwill and Merger Costs,
Accounting for Generation Divestiture Costs, Impairment of Long-Lived Assets,
and Accounting for Derivatives and Hedging Activities, all of which are
discussed immediately below.
DEFERRED ENERGY ACCOUNTING
On April 18, 2001, the Governor of Nevada signed into law Assembly Bill
369 (AB 369). The provisions of AB 369 include, among others, a reinstatement of
deferred energy accounting for fuel and purchased power costs incurred by
electric utilities. In accordance with the provisions of SFAS No. 71, the
Utilities implemented deferred energy accounting on March 1, 2001, for their
respective electric operations. Under deferred energy accounting, to the extent
actual fuel and purchased power costs exceed fuel and purchased power costs
recoverable through current rates, that excess is not recorded as a current
expense on the statement of operations but rather is deferred and recorded as an
asset on the balance sheet. Conversely, a liability is recorded to the extent
fuel and purchased power costs recoverable through current rates exceed actual
fuel and purchased power costs. These excess amounts are reflected in
adjustments to rates and recorded as revenue or expense in future time periods,
subject to PUCN review. AB 369 provides that the PUCN may not allow the recovery
of any costs for purchased fuel or purchased power "that were the result of any
practice or transaction that was undertaken, managed or performed imprudently by
the electric utility." In reference to deferred energy accounting, AB 369
specifies that fuel and purchased power costs include all costs incurred to
purchase fuel, to purchase capacity, and to purchase energy. The Utilities also
record, and are eligible under the statute to recover, a carrying charge on such
deferred balances.
The Utilities are exposed to commodity price risk primarily related to
changes in the market price of electricity as well as changes in fuel costs
incurred to generate electricity. See Energy Supply in SPR's, NPC's, and SPPC's
Annual Report on Form 10-K for the year ended December 31, 2002, for a
discussion of the Utilities' purchased power procurement strategies, and
Commodity Price Risk in Item 7A, Quantitative and Qualitative Disclosures About
Market Risk, in SPR's, NPC's, and SPPC's Annual Report on Form 10-K for the year
ended December 31, 2002, for a discussion of the Utilities' commodity risk
management program. As discussed above, deferred energy accounting facilitates
the recovery of costs incurred to procure fuel and purchased power for SPPC and
NPC.
As described in more detail under Regulation and Rate Proceedings,
Nevada Matters, Nevada Power Company 2001 Deferred Energy Case, in SPR's, NPC's,
and SPPC's Annual Report on Form 10-K for the year ended December 31, 2002, on
November 30, 2001, NPC filed an application with the PUCN seeking to establish a
Deferred Energy Accounting Adjustment (DEAA) rate to clear deferred balances for
purchased fuel and power costs accumulated between March 1, 2001 and September
30, 2001. The application sought to establish a rate to clear accumulated
purchased fuel and power costs of $922 million and spread the cost recovery over
a period of not more than three years. On March 29, 2002, the PUCN issued its
decision on the deferred energy application, disallowing $434 million of
deferred purchased fuel and power costs, and allowing NPC to collect the
remaining $478 million over three years beginning April 1, 2002. As a result of
this disallowance, NPC wrote off $465 million of deferred energy costs and
related carrying charges, the two major national rating agencies immediately
downgraded the credit rating on SPR's, NPC's and SPPC's debt securities
(followed by further downgrades late in April 2002), and the market price of
SPR's common stock fell substantially.
As described in more detail under Regulation and Rate Proceedings,
Nevada Matters, Sierra Pacific Power Company 2002 Deferred Energy Case, in
SPR's, NPC's, and SPPC's Annual Report on Form 10-K for the year ended December
31, 2002, SPPC filed an application with the PUCN seeking to establish a DEAA
rate to clear its deferred balances for purchased fuel and power costs
accumulated between March 1, 2001 and November 30, 2001. The application sought
to establish a rate to clear accumulated purchased fuel and power costs of $205
million and spread the cost recovery over a period of not more than three years.
On May 28, 2002, the PUCN issued its decision on SPPC's deferred energy
application, disallowing $53 million of deferred purchased fuel and power costs,
and allowing SPPC to collect the remaining $150 million
30
over three years beginning June 1, 2002. As a result of this decision, SPPC
wrote off $58 million of disallowed deferred energy costs and related carrying
charges in the second quarter of 2002.
Both Utilities have continued to be entitled under AB 369 to utilize
deferred energy accounting for their electric operations. Because of contracts
entered into during the Western energy crisis in 2001 to assure adequate
supplies of electricity for their customers, the Utilities incurred fuel and
purchased power costs in excess of amounts they were permitted to recover in
current rates. As a result, during 2002, both Utilities continued to record
additional amounts in their deferral of energy costs accounts.
On November 14, 2002, NPC filed an application with the PUCN seeking to
clear deferred balances of $195.7 million for purchased fuel and power costs
accumulated between October 1, 2001, and September 30, 2002, and to spread the
recovery of the deferred costs, together with a carrying charge, over a period
of not more than three years.
Intervenors filed their direct testimony on March 7, 2003, and
supplemental testimony was filed March 27, 2003, calling for disallowances
between approximately $108 and $300 million of the total fuel and purchased
power costs. The largest of the proposed disallowances are based on the same
alleged imprudence as found in the PUCN order for NPC's 2001 Deferred Energy
Case relating to NPC's failure to enter into power contracts in 1999. Certain
Intervenors' testimony, in the current case, have argued in favor of
disallowances based on the same alleged imprudence as cited in the last deferred
order but have not quantified their proposals and in some cases have argued in
favor of disallowances in excess of the ranges previously indicated. The PUCN
Staff does not support this disallowance but calculated a range of $116 to $347
million in the event that the PUCN disallows deferred energy costs based upon
the same alleged imprudence cited by the PUCN in its 2001 decision relative to
this issue.
While all Intervenors have called for the PUCN to reduce NPC's
requested energy rates for recovery of past energy costs, some have also
proposed to increase customers' energy rates for purchases that will occur
during the upcoming deferred accounting period, which would decrease the
accumulation of deferred energy costs.
NPC's rebuttal testimony was filed on March 31, 2003, and hearings were
completed on April 17, 2003. The PUCN's decision is scheduled for May 9, 2003.
On January 14, 2003, SPPC filed an application with the PUCN seeking to
clear deferred balances of $15.4 million for purchased fuel and power costs
accumulated between December 1, 2001, and November 30, 2002 The application
seeks to establish a DEAA rate to repay accumulated purchased fuel and power
costs of $15.4 million and spread the cost recovery over a period of not more
than three years. It also seeks to recalculate the Base Tariff Energy Rate to
reflect anticipated ongoing purchased fuel and power costs. The total rate
increase resulting from the requested DEAA would amount to 0.01%. The
intervenors' testimony was received April 25, 2003, and includes proposed
disallowances from $34 million to $76 million.
While all Intervenors call for the PUCN to reduce SPPC's requested
energy rates for recovery of past energy costs, some also propose to increase
customers' energy rates for purchases that will occur during the upcoming
deferred accounting period, which would decrease the accumulation of deferred
energy costs. A hearing is scheduled to begin on May 12, 2003, and a ruling is
required before July 13, 2003.
A significant disallowance in either or both of these deferred energy
rate cases or in future cases to be filed by either Utility would have a
material adverse affect on the future financial position, results of operations,
and liquidity of SPR, NPC, and SPPC and could make it difficult for one or more
of SPR, NPC or SPPC to continue to operate outside of bankruptcy. See Regulation
and Rate Proceedings, later, for additional discussion of the regulatory process
underway to recover these deferred costs.
If not for deferred energy accounting during 2003 and 2002, SPR's,
NPC's and SPPC's results of operations, financial condition, liquidity and
capital resources would have been significantly different. For example, without
the deferred energy accounting provisions of AB 369, the reported purchased fuel
and power costs of SPR, NPC, and SPPC for the quarter ended March 31, 2003,
would have decreased (net of income tax) by approximately $54.7 million, $47.3
million, and $7.4 million, respectively, and the reported interest accrued on
deferred energy of SPR, NPC, and SPPC would have decreased (net of income tax)
by approximately $4.8 million, $3.7 million, and $1.1 million, respectively, for
the same period. Similarly, without the deferred energy accounting provisions of
AB 369, the reported purchased fuel and power costs of SPR, NPC, and SPPC for
the quarter ended March 31, 2002, would have increased (net of income tax) by
approximately $9.3 million, $6.3 million, and $3 million, respectively, and the
reported interest accrued on deferred energy of SPR, NPC, and SPPC would have
decreased (net of income tax) by approximately $15.6 million, $12.9 million, and
$2.7 million, respectively, for the same period. The effects of AB 369 on 2002
purchased fuel and power costs and interest accrued on deferred energy discussed
above exclude the write-off of $465 million pursuant to the PUCN's March 29,
2002 decision discussed earlier.
31
ACCOUNTING FOR GOODWILL AND MERGER COSTS
The order issued by the PUCN in December 1998 approving the merger of
SPR and NPC directed both NPC and SPPC to defer three categories of merger costs
to be reviewed for recovery through future rates. That order specifically
directed both Utilities to defer merger transaction costs, transition costs and
goodwill costs for a three-year period. The deferral of these costs was intended
to allow adequate time for the anticipated savings from the merger to develop.
At the end of the three-year period, the order instructs the Utilities to
propose an amortization period for the merger costs and allows the Utilities to
recover the costs to the extent they are offset by merger savings.
Costs deferred as a result of the PUCN order were $331.2 million of
goodwill and $62.6 million in other merger costs as of March 31, 2003. The
deferred other merger costs consist of $40.9 million of transaction and
transition costs and $21.7 million of employee separation costs. Employee
separation costs were comprised of $17.2 million of employee severance,
relocation and related costs, and $4.5 million of pension and post-retirement
benefits net of plan curtailment gains.
On October 1, 2001, and November 30, 2001, NPC and SPPC, respectively,
filed applications with the PUCN for general rate increases that included, among
other items, requests to recover deferred merger costs, including goodwill. In
its decisions dated March 27, 2002, and May 28, 2002, for NPC and SPPC,
respectively, the PUCN decided not to make any determination on the recovery of
merger costs until general rate cases are filed with test years ending on or
after December 31, 2002. However, the PUCN did instruct the Utilities to
continue to recognize these costs as deferred assets without carrying charges.
The extent to which goodwill and merger costs will be recovered in
future revenues and the timing of those recoveries is expected to be determined
in general rate cases that are required to be filed in 2003. To the extent that
the Utilities are not permitted to recover any portion of goodwill in future
rates, the amount not recoverable will be reviewed for impairment and accounted
for under the provisions of SFAS No. 142. A significant disallowance of goodwill
or merger costs by the PUCN could have a material adverse affect on the future
financial position, results of operations and cash flows of SPR, NPC, and SPPC
and could make it difficult for one or more of SPR, NPC, or SPPC to continue to
operate outside of bankruptcy.
ACCOUNTING FOR GENERATION DIVESTITURE COSTS
As a condition to its approval of the merger between SPR and NPC, the
Utilities filed, and in February 2000 the PUCN approved, a revised Divestiture
Plan stipulation for the sale of the Utilities' generation assets. In May 2000
an agreement was announced for the sale of NPC's 14% undivided interest in the
Mohave Generating Station ("Mohave"). In the fourth quarter of 2000, the
Utilities announced agreements to sell six additional bundles of generation
assets described in the approved Divestiture Plan. The sales were subject to
approval and review by various regulatory agencies.
AB 369, which was signed into law on April 18, 2001, prohibits until
July 2003 the sale of generation assets and directs the PUCN to vacate any of
its orders that had previously approved generation divestiture transactions. In
January 2001, California enacted a law that prohibits until 2006 any further
divestiture of generation properties by California utilities, including SPPC,
and could also affect any sale of NPC's interest in Mohave after July 2003 since
the majority owner of that project is Southern California Edison. SPPC's request
for an exemption from the requirements of a separate California law requiring
approval of the CPUC to divest its plants was denied. In September 2002, the
California Legislature approved an exemption to AB 6 that would allow SPPC to
complete the sale of the hydroelectric units to TMWA subject to review and
approval of the sale by the CPUC.
The sales agreements for the six bundles provided that they terminate
eighteen months after their execution, and all of the agreements have now
terminated in accordance with their respective provisions. As of March 31, 2003,
NPC and SPPC had incurred costs of approximately $20.6 million and $12.4
million, respectively, in order to prepare for the sale of generation assets. In
the fourth quarter of 2001, each Utility requested recovery of its respective
costs in its application for a general rate increase filed with the PUCN. In
2002, the PUCN delayed recovery of divestiture costs to future rate case
requests but did grant a carrying charge on the costs until such time as
recovery is allowed. To the extent that the Utilities are not permitted to
recover any portion of these costs in future rates, the disallowed costs and
related carrying charges would be required to be written off in current period
earnings.
IMPAIRMENT OF LONG-LIVED ASSETS
SPR and the Utilities evaluate their Utility Plant and definite-lived
tangible assets for impairment whenever indicators of impairment exist.
As discussed in more detail in Note 21, Pinon Pine, of Notes to
Financial Statements in SPR's, NPC's, and SPPC's Annual Report on Form 10-K for
the year ended December 31, 2002, SPPC owns a combined cycle generation
facility, a post-gasification facility, and, through its wholly owned
subsidiaries, owns a gasifier that are collectively referred to as the Pinon
32
Pine Power Project ("Pinon Pine"). Construction of Pinon Pine was completed in
June 1998. Included in the Condensed Consolidated Balance Sheets of SPR and SPPC
is the net book value of the gasifier and related assets, which is approximately
$99 million as of March 31, 2003.
To date, SPPC has not been successful in obtaining sustained operation
of the gasifier. In 2001 SPPC retained an independent engineering consulting
firm to complete a comprehensive study of the Pinon Pine gasification plant.
SPPC received a final report of the study in November 2002. SPPC is reviewing
the various options outlined in the study. If after evaluating the options
presented in the draft report, SPPC decides not to pursue modifications intended
to make the facility operational, SPPC intends to seek recovery, net of salvage,
through regulated rates in its next general rate case based, in part, on the
PUCN's approval of Pinon Pine as a demonstration project in an earlier resource
plan. However, if SPPC is unsuccessful in obtaining recovery, there could be a
material adverse effect on SPPC's and SPR's financial position, results of
operations and cash flows.
ACCOUNTING FOR DERIVATIVES AND HEDGING ACTIVITIES
SPR, SPPC, and NPC apply SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities," as amended by SFAS No. 138. As amended,
SFAS No. 133 requires that an entity recognize all derivatives as either assets
or liabilities in the statement of financial position and measure those
instruments at fair value.
In order to manage loads, resources and energy price risk, the
Utilities buy fuel and power under forward contracts. In addition to forward
fuel and power purchase contracts, the Utilities also use options and swaps to
manage price risk. All of these instruments are considered to be derivatives
under SFAS No. 133. The risk management assets and liabilities recorded in the
balance sheets of the Utilities and SPR are primarily comprised of the fair
value of these forward fuel and power purchase contracts and other energy
related derivative instruments.
Fuel and purchased power costs are subject to deferred energy
accounting. Accordingly, the energy related risk management assets and
liabilities and the corresponding unrealized gains and losses (changes in fair
value) are offset with a regulatory asset or liability rather than recognized in
the statements of operations and comprehensive income. Upon settlement of a
derivative instrument, actual fuel and purchased power costs are recognized if
they are currently recoverable or deferred if they are recoverable or payable
through future rates.
The fair values of the forward contracts and swaps are determined based
on quotes obtained from independent brokers and exchanges. The fair values of
options are determined using a pricing model which incorporates assumptions such
as the underlying commodity's forward price curve, time to expiration, strike
price, interest rates, and volatility. The use of different assumptions and
variables in the model could have a significant impact on the valuation of the
instruments.
SPR and the Utilities have other non-energy related derivative
instruments. The changes in fair values of these non-energy related derivatives
are reported in Other comprehensive income until the related transactions are
settled or terminate, at which time the amounts are reclassified into earnings.
In connection with SPR's issuance of its Convertible Notes (see Note 4,
Long-Term Debt), the conversion option, which is treated as a cash-settled
written call option, was separated from the debt and accounted for separately as
a derivative instrument in accordance with FASB's Emerging Issues Task Force
Issue 90-19, "Convertible Bonds with Issuer Option to Settle for Cash upon
Conversion". Upon issuance, the fair value of the option was recorded as a
current liability in Other current liabilities. The change in the fair value is
recognized in earnings in the period of the change.
ENVIRONMENTAL CONTINGENCIES
SPR and its subsidiaries are subject to federal, state and local
regulations governing air and water quality, hazardous and solid waste, land use
and other environmental considerations. Nevada's Utility Environmental
Protection Act requires approval of the PUCN prior to construction of major
utility, generation or transmission facilities. The United States Environmental
Protection Agency (EPA), Nevada Division of Environmental Protection (NDEP), and
Clark County Health District (CCHD) administer regulations involving air and
water quality, solid, hazardous and toxic waste.
SPR and its subsidiaries are subject to rising costs that result from a
steady increase in the number of federal, state and local laws and regulations
designed to protect the environment. These laws and regulations can result in
increased capital, operating, and other costs as a result of compliance,
remediation, containment and monitoring obligations, particularly with laws
relating to power plant emissions. In addition, SPR or its subsidiaries may be a
responsible party for environmental clean up at a site identified by a
regulatory body. The management of SPR and its subsidiaries cannot predict with
certainty the amount and timing of all future expenditures related to
environmental matters because of the difficulty of estimating clean up costs and
compliance and the possibility that changes will be made to the current
environmental laws and regulations. There is also uncertainty in quantifying
liabilities under environmental laws that impose joint and several liability on
all potentially
33
responsible parties. SPR and its subsidiaries accrue for environmental costs
only when they can conclude that it is probable that they have an obligation for
such costs and can reasonably determine the amount of such costs.
Note 11, Commitments and Contingencies, of Notes to Condensed
Consolidated Financial Statements discusses the environmental matters of SPR and
its subsidiaries that have been identified, and the estimated financial effect
of those matters. To the extent that (1) actual results differ from the
estimated financial effects, (2) there are environmental matters not yet
identified for which SPR or its subsidiaries are determined to be responsible,
or (3) the Utilities are unable to recover through future rates the costs to
remediate such environmental matters, there could be a material adverse effect
on the financial condition and future liquidity and results of operations of SPR
and its subsidiaries.
LITIGATION CONTINGENCIES
Note 11, Commitments and Contingencies, of Notes to Condensed
Consolidated Financial Statements discusses the significant legal matters of SPR
and its subsidiaries. SPR and its subsidiaries, through the course of their
normal business operations, are currently involved in a number of other legal
actions, none of which has had or, in the opinion of management, is expected to
have, a significant impact on its financial position or results of operations.
DEFINED BENEFIT PLANS AND OTHER POSTRETIREMENT PLANS
As further explained in Note 14, Retirement Plan and Post-Retirement
Benefits, of Notes to Financial Statements in SPR's, NPC's, and SPPC's Annual
Report on Form 10-K for the year ended December 31, 2002, SPR maintains a
pension plan as well as other postretirement benefit plans that provide health
and life insurance for retired employees. All employees are eligible for these
benefits if they reach retirement age while still working for SPR or its
subsidiaries. These costs are determined in accordance with the provisions of
SFAS No. 87, "Employers' Accounting for Pensions," and SFAS No. 106, "Employers'
Accounting for Postretirement Benefits Other Than Pensions," and ultimately
collected in rates billed to customers. The amounts funded are then used to meet
benefit payments to plan participants. SPR contributed approximately $25.3
million and $41.1 million to its pension plan, and $60,000 and $0.2 million to
the other postretirement benefits plan in 2003 and 2002, respectively. Due to
the sharp decline in United States equity markets since the third quarter of
2000, the value of a significant portion of the assets held in the plans' trusts
to satisfy the obligations of the plans has decreased significantly. As a
result, additional contributions may be required in the future to meet the
requirements of the plan to pay benefits to plan participants.
PENSION PLANS
SPR's reported costs of providing non-contributory defined pension
benefits (described in Note 14, Retirement Plan and Post-Retirement Benefits, of
Notes to Financial Statements in SPR's, NPC's, and SPPC's Annual Report on Form
10-K for the year ended December 31, 2002) are dependent upon numerous factors
resulting from actual plan experience and assumptions of future experience.
For example, pension costs are impacted by actual employee demographics
(including age and employment periods), the level of contributions SPR makes to
the plan, and earnings on plan assets. Changes made to the provisions of the
plan may also impact current and future pension costs. Pension costs may also be
significantly affected by changes in key actuarial assumptions, including
anticipated rates of return on plan assets and the discount rates used in
determining the projected benefit obligation and pension costs.
SPR has made no changes to pension plan provisions in 2002 or 2003 that
have had any significant impact on recorded pension amounts. SPR reduced the
discount rate used in determining pension expense for the calendar year 2003
from 7.5% to 6.75%. This change will not have a significant impact on reported
pension costs for 2003.
SPR's pension plan assets are primarily made up of equity and fixed
income investments. Fluctuations in actual equity market returns as well as
changes in general interest rates may result in increased or decreased pension
costs in future periods. Likewise, changes in assumptions regarding current
discount rates and expected rates of return on plan assets could also increase
or decrease recorded pension costs.
The following chart reflects the sensitivities associated with a change
in certain actuarial assumptions by the indicated percentage. While the chart
below reflects an increase in the percentage for each assumption, SPR and its
actuaries expect that the inverse of this change would impact the projected
benefit obligation (PrBO) and the reported annual pension cost on the income
statement (PeC) by a similar amount in the opposite direction. Each sensitivity
below reflects an evaluation of the change based solely on a change in that
assumption only.
34
- -----------------------------------------------------------------------------
Change in Impact on Impact on
Actuarial Assumption Assumption PrBO PeC
($ millions) Incr/(Decr) Incr/(Decr) Incr/(Decr)
- -----------------------------------------------------------------------------
Discount Rate 1% $ (45.0) $ (4.9)
Rate of Return on Plan Assets 1% $ - $ (2.7)
- -----------------------------------------------------------------------------
In selecting an assumed discount rate, SPR considered the yield on high
quality bonds as measured by the Moody's Investors Service, Inc. (Moody's) Aa
composite bond index.
In selecting an assumed rate of return on plan assets, SPR considers
past performance and economic forecasts for the types of investments held by the
plan. The market value of SPR's plan assets has been affected by sharp declines
in equity markets since the third quarter of 2000.
As a result of SPR's plan asset returns at September 30, 2002, SPR was
required to recognize an additional minimum liability in the amount of $89.6
million, as prescribed by SFAS No. 87. The liability was recorded as a reduction
to common equity through a charge to Accumulated Other Comprehensive Income, and
did not affect net income for 2002. The charge to Accumulated Other
Comprehensive Income will be restored through common equity in future periods to
the extent fair value of trust assets exceeds the accumulated benefit
obligation.
Pension cost and cash funding requirements could increase in future
years without a substantial recovery in the equity markets.
OTHER POSTRETIREMENT BENEFITS
SPR's reported costs of providing other postretirement benefits
(described in Note 14, Retirement Plan and Post-Retirement Benefits, of Notes to
Financial Statements in SPR's, NPC's, and SPPC's Annual Report on Form 10-K for
the year ended December 31, 2002) are dependent upon numerous factors resulting
from actual plan experience and assumptions of future experience.
For example, other postretirement benefit costs are impacted by actual
employee demographics (including age and employment periods), the level of
contributions made to the plan, earnings on plan assets, and health care cost
trends. Changes made to the provisions of the plan may also impact current and
future other postretirement benefit costs. Other postretirement benefit costs
may also be significantly affected by changes in key actuarial assumptions,
including anticipated rates of return on plan assets and the discount rates used
in determining the postretirement benefit obligation and postretirement costs.
SPR has made no changes to other postretirement benefit plan provisions
in 2002 or 2003 that have had any significant impact on recorded benefit plan
amounts. SPR reduced the discount rate used in determining other postretirement
expense for the calendar year 2003 from 7.5% to 6.75%. This change will not have
a significant impact on reported other postretirement benefit costs for 2003.
However, in determining the other postretirement benefit obligation and related
cost, these assumptions can change from period to period, and such changes could
result in material changes to such amounts.
SPR's other postretirement benefit plan assets are primarily made up of
equity and fixed income investments. Fluctuations in actual equity market
returns as well as changes in general interest rates may result in increased or
decreased other postretirement benefit costs in future periods. Likewise,
changes in assumptions regarding current discount rates and expected rates of
return on plan assets could also increase or decrease recorded other
postretirement benefit costs.
The following chart reflects the sensitivities associated with a change
in certain actuarial assumptions by the indicated percentage. While the chart
below reflects an increase in the percentage for each assumption, SPR and its
actuaries expect that the inverse of this change would impact the projected
accumulated other postretirement benefit obligation (APBO) and the reported
annual other postretirement benefit cost on the income statement (PBC) by a
similar amount in the opposite direction. Each sensitivity below reflects an
evaluation of the change based solely on a change in that assumption only.
35
- -----------------------------------------------------------------------------
Change in Impact on Impact on
Actuarial Assumption Assumption APBO PBC
($ millions) Incr/(Decr) Incr/(Decr) Incr/(Decr)
- -----------------------------------------------------------------------------
Discount Rate 1% $ (15.7) $ (1.5)
Health Care Cost Trend Rate 1% $ 14.9 $ 1.5
Rate of Return on Plan Assets 1% N/A $ (0.5)
- -----------------------------------------------------------------------------
In selecting an assumed discount rate, SPR considered the yield on high
quality bonds as measured by Moody's Aa composite bond index.
In selecting an assumed rate of return on plan assets, SPR considers
past performance and economic forecasts for the types of investments held by the
plan. The market value of the SPR's plan assets has been affected by sharp
declines in equity markets since the third quarter of 2000. Also, other
postretirement benefit cost and cash funding requirements could increase in
future years without a substantial recovery in the equity markets.
COST CAPITALIZATION POLICIES
The Utilities continue to devote substantial resources in 2003 on the
Centennial Transmission project at NPC and the Falcon to Gonder Transmission
project at SPPC. In addition, certain operating units of the Utilities are
charged with maintaining, repairing and replacing components of generation,
transmission and distribution systems both on a scheduled basis and on an
as-needed basis. As described in Note 1, Summary of Significant Accounting
Policies, of Notes to Financial Statements in SPR's, NPC's, and SPPC's Annual
Report on Form 10-K for the year ended December 31, 2002, the cost of additions,
including betterments and replacements of units of property, is charged to
utility plant. When units of property are replaced, renewed or retired, their
cost, plus removal or disposal costs less salvage, is charged to accumulated
depreciation. Certain direct and indirect costs are capitalized, including the
cost of debt and equity capital associated with construction and retirement
activity as prescribed by Generally Accepted Accounting Principles (GAAP) and
the FERC's Uniform System of Accounts.
The indirect construction overhead costs capitalized are based upon the
following cost components: the cost of time spent by administrative employees in
planning and directing construction; property taxes; employee benefits including
such costs as pensions, postretirement and post employment benefits, vacations
and payroll taxes; and an allowance for funds used during construction (AFUDC).
The level of indirect construction overhead costs capitalized by the Utilities
is based upon real-time construction activity. Accordingly, payroll and other
costs capitalized will fluctuate based upon seasonal construction activities and
the deployment of resources to those efforts. During periods of higher
maintenance levels, these payroll and other costs will not be capitalized. As
such, operating income could be impacted by the manner in which payroll and
related costs are deployed. However, the total cash flow of the Utilities is not
impacted by the allocation of these costs to various construction or maintenance
activities.
During the three months ended March 31, 2003, and March 31, 2002, NPC
and SPPC capitalized approximately $3.5 million and $2.1 million, respectively,
of AFUDC as a result of construction activity financed primarily by their debt.
This amount is a non-cash component reflected in the Consolidated Statements of
Operations. Recognition of AFUDC as a cost of utility plant is in accordance
with established regulatory ratemaking practices. Such practices permit the
Utility to earn a fair return on, and recover in rates, all capital costs
charged for Utility services.
DEPRECIATION EXPENSE
The Utilities have a significant investment in electric plant. SPPC
also has an investment in gas distribution plant. Depreciable assets of
generation, transmission and distribution operations represent approximately 93%
of the Utilities' investment in utility plant. As described in Note 1, Summary
of Significant Accounting Policies, of Notes to Financial Statements in SPR's,
NPC's, and SPPC's Annual Report on Form 10-K for the year ended December 31,
2002, the Utilities depreciate these assets utilizing a composite rate, which
currently includes a component for net negative salvage. These assets are
depreciated on a straight-line basis over the remaining useful life of the
related assets, which approximates the anticipated physical lives of these
assets in most cases. The Nevada Administrative Code requires the Utilities to
provide a depreciation study every four years in order to substantiate the
remaining physical lives of their investment in utility plant. Adjustments to
the estimated depreciable lives of the Utilities' plant are recorded on a
prospective basis, as prescribed by GAAP and the FERC's Uniform System of
Accounts.
Substantially all of the Utilities' plant is subject to the ratemaking
jurisdiction of the PUCN or the FERC and, in the case of SPPC's California
operations, the CPUC, which also approves any changes the Utilities may make to
depreciation rates
36
utilized for this property. Because the Utilities' periodic depreciation expense
is included as a component of the revenue requirement utilized in the
development of the Utilities' tariff rates, revenue reflects collection of the
recognized depreciation expense. Accordingly, the impact of depreciation on net
income is not significant. However, operating cash flows are positively affected
by the amount of depreciation collected in rates, since depreciation expense is
not a current cash outlay for the Utilities.
ASSET RETIREMENT OBLIGATIONS
In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations." SFAS No. 143 provides accounting requirements for the
recognition and measurement of liabilities associated with the retirement of
tangible long-lived assets. Under the standard, these liabilities will be
recognized at fair value as incurred and capitalized as part of the cost of the
related tangible long-lived assets. Accretion of the liabilities due to the
passage of time will be an operating expense. Retirement obligations associated
with long-lived assets included within the scope of SFAS No. 143 are those for
which a legal obligation exists under enacted laws, statutes written or oral
contracts, including obligations arising under the doctrine of promissory
estoppel. The Utilities adopted SFAS No. 143 on January 1, 2003.
Prior to adopting SFAS 143, costs for removal of most utility assets
were accrued as an additional component of depreciation expense. Under SFAS 143,
only the costs to remove an asset with legally binding retirement obligations
will be accrued over time through accretion of the asset retirement obligation
and depreciation of the capitalized asset retirement cost.
Management's methodology to assess its legal obligation included an
inventory of assets by system and components, and a review of right of ways and
easements, regulatory orders, leases and federal, state, and local environmental
laws. Management assumed in determining its Asset Retirement Obligations that
transmission, distribution and communications systems will be operated in
perpetuity and would continue to be used or sold without land remediation; and,
mass asset properties that are replaced or retired frequently would be
considered normal maintenance.
Management has identified a legal obligation to retire generation plant
assets specified in land leases for NPC's jointly-owned Navajo generating
station. The land on which the Navajo generating station resides is leased from
the Navajo Nation. The provisions of the leases require the lessees to remove
the facilities upon request of the Navajo Nation at the expiration of the
leases. Although the related retirement obligation and corresponding charges
recognized were immaterial to the financial statements of NPC, those amounts
were based on certain estimates and assumptions. The estimated liability is
based on two levels of decommissioning, minimal and full, and two possible
retirement dates. The liability is escalated using average historical Consumer
Price Index inflation factors equal to the estimated retirement dates. The
liability is discounted using credit-adjusted risk-free rates of return for the
respective retirement dates. Changes to future statements of financial position
and results of operations will occur to the extent that actual results differ
from the estimates and assumptions used, including changes in decommissioning
costs, timing or changes in NPC's credit rating. SPPC has no significant asset
retirement obligations.
The Utilities have various transmission and distribution lines as well
as substations that operate under various rights of way that contain end dates
and restorative clauses. Management operates the transmission and distribution
system as though they will be operated in perpetuity and will continue to be
used or sold without land remediation. As a result, the Utilities have not
recorded any costs associated with the removal of the transmission and
distribution systems.
STOCK COMPENSATION PLANS
In December 2002, the FASB released SFAS No. 148, "Accounting for
Stock-Based Compensation-Transition and Disclosure," as an amendment to SFAS No.
123, "Accounting for Stock-Based Compensation." SPR has previously adopted the
disclosure-only provisions of SFAS No. 123, and as of December 31, 2002 has
adopted the updated disclosure requirements set forth in SFAS No. 148. Pursuant
to those updated disclosure requirements, SPR has included the following
discussion on the stock compensation plans. For additional information on SPR's
stock compensation plans, see Note 1, Summary of Significant Accounting
Policies, and Note 15, Stock Compensation Plans, of Notes to Financial
Statements in SPR's, NPC's, and SPPC's Annual Report on Form 10-K for the year
ended December 31, 2002.
At March 31, 2003, SPR had several stock-based compensation plans. SPR
applies Accounting Principles Board Opinion No. 25, Accounting for Stock Issued
to Employees, in accounting for its stock option plans. Accordingly, no
compensation cost has been recognized for nonqualified stock options and the
employee stock purchase plan. SPR has adopted the disclosure-only provisions of
SFAS No. 123, Accounting for Stock Based Compensation, and its related
amendment(s).
UNBILLED RECEIVABLES
Revenues related to the sale of energy are recorded based on meter
reads, which occur on a systematic basis throughout a month, rather than when
the service is rendered or energy is delivered. At the end of each month, the
energy
37
delivered to the customers from the date of their last meter read to the end of
the month is estimated and the corresponding unbilled revenues are calculated.
These estimates of unbilled sales and revenues are based on the ratio of
billable days versus unbilled days, amount of energy procured and generated
during that month, historical customer class usage patterns and the Utilities'
current tariffs. Customer accounts receivable as of March 31, 2003, include
unbilled receivables of $48 million and $53 million for NPC and SPPC,
respectively. Customer accounts receivable as of March 31, 2002, include
unbilled receivables of $57 million and $58 million for NPC and SPPC,
respectively.
PROVISION FOR UNCOLLECTIBLE ACCOUNTS
The Utilities reserve for doubtful accounts based on past experience
writing off uncollectible customer accounts. The adequacy of these reserves will
vary to the extent that future collections differ from past experience.
FINANCIAL CONDITION AND MATERIAL CHANGES IN RESULTS OF OPERATIONS
SIERRA PACIFIC RESOURCES
The operating results of SPR primarily reflect those of NPC and SPPC,
discussed later.
During the first three months of 2003, SPR incurred a net loss of $15.5
million compared to a $302.9 million net loss for the same period during 2002.
Operating results for the three months ended March 31, 2003 were negatively
affected by higher interest costs during the period and lower sales for the
reasons discussed later. During the same period, SPR recorded an unrealized gain
on the derivative instrument associated with the issuance of $300 million of
convertible debt (see Financing Transactions, discussed later). SPR's net loss
of $302.9 million for the three months ended March 31, 2002, reflects the
write-off of approximately $465 million (before taxes) of deferred energy costs
and related carrying charges as a result of PUCN decision in NPC's 2001 deferred
energy rate case.
SPR did not pay or declare a common dividend in the first quarter of
2003. NPC and SPPC did not declare or pay common stock dividends to their
parent, SPR, in the first quarter of 2003. SPPC paid $975,000 in dividends to
holders of its preferred stock during the first quarter of 2003. NPC and SPPC
each received a capital contribution of $10 million from SPR in March 2002.
LIQUIDITY AND CAPITAL RESOURCES (SPR CONSOLIDATED)
SPR, on a stand-alone basis, had cash and cash equivalents of
approximately $166.7 million at March 31, 2003. On April 21, 2003, SPR utilized
approximately $133 million of its cash and cash equivalents to repay unsecured
Floating Rate Notes due April 20, 2003.
SPR's future liquidity and its ability to pay the principal of and
interest on its indebtedness depend on SPPC's ability to continue to pay
dividends to SPR, on NPC's financial stability and the restoration of its
ability to pay dividends to SPR, and on SPR's ability to access the capital
markets or otherwise refinance maturing debt. Further adverse developments at
NPC or SPPC, including a material disallowance of deferred energy costs in
current and future rate cases or an adverse decision in the pending lawsuit by
Enron, could make it difficult for SPR to operate outside of bankruptcy.
DIVIDENDS FROM SUBSIDIARIES
Since SPR is a holding company, substantially all of its cash flow is
provided by dividends paid to SPR by NPC and SPPC on their common stock, all of
which is owned by SPR. Since NPC and SPPC are public utilities, they are subject
to regulation by state utility commissions which may impose limits on investment
returns or otherwise impact the amount of dividends that the Utilities may
declare and pay, and to federal statutory limitation on the payment of
dividends. In addition, certain agreements entered into by the Utilities set
restrictions on the amount of dividends they may declare and pay and restrict
the circumstances under which such dividends may be declared and paid. The
specific restrictions on dividends contained in agreements to which NPC and SPPC
are party, as well as specific regulatory limitations on dividends, are
summarized below.
- NPC's first mortgage indenture limits the cumulative amount of
dividends and other distributions that NPC may pay on its capital
stock to the cumulative net earnings of NPC since 1953, subject to
adjustments for the net proceeds of sales of capital stock since 1953.
At the present time, this restriction precludes NPC from making
further payments of dividends on NPC's common stock and will continue
to bar dividends until NPC, over time, generates sufficient earnings
to eliminate the deficit under this provision (which was approximately
$254 million as of March 31, 2003), unless the restriction is earlier
waived, amended, or removed by the consent of the first mortgage
bondholders, or the first mortgage bonds are redeemed or defeased.
There can be no assurance that any such consent could be obtained or
that any first mortgage bonds could be redeemed prior to their stated
maturity. Under this provision, NPC continues
38
to have capacity to repurchase or redeem shares of its capital stock,
although other restrictions set forth below would limit the amount of
any such repurchases or redemptions.
- NPC's 10 7/8% General and Refunding Mortgage Notes, Series E, due
2009, which were issued on October 29, 2002, limit the amount of
payments in respect of common stock that NPC may pay to SPR. However,
that limitation does not apply to payments by NPC to enable SPR to pay
its reasonable fees and expenses (including, but not limited to,
interest on SPR's indebtedness and payment obligations on account of
SPR's Premium Income Equity Securities (PIES)) provided that:
- those payments do not exceed $60 million for any one
calendar year,
- those payments comply with any regulatory restrictions then
applicable to NPC, and
- the ratio of consolidated cash flow to fixed charges for
NPC's most recently ended four full fiscal quarters
immediately preceding the date of payment is at least 1.75
to 1.
The terms of the Series E Notes also permit NPC to make payments to
SPR in an aggregate amount not to exceed $15 million from the date of
the issuance of the Series E Notes. In addition, NPC may make payments
to SPR in excess of the amounts described above so long as, at the
time of payment and after giving effect to the payment:
- there are no defaults or events of default with respect to
the Series E Notes,
- NPC has a ratio of consolidated cash flow to fixed charges
for NPC's most recently ended four full fiscal quarters
immediately preceding the payment date of at least 2.0 to 1,
and
- the total amount of such dividends is less than:
- the sum of 50% of NPC's consolidated net income
measured on a quarterly basis cumulative of all
quarters from the date of issuance of the Series
E Notes, plus
- 100% of NPC's aggregate net cash proceeds from
contributions to its common equity capital or the
issuance or sale of certain equity or convertible
debt securities of NPC, plus
- the lesser of cash return of capital or the
initial amount of certain restricted investments,
plus
- the fair market value of NPC's investment in
certain subsidiaries.
If NPC's Series E Notes are upgraded to investment grade by both
Moody's Investors Service, Inc. (Moody's) and Standard & Poor's Rating
Group, Inc. (S&P), these restrictions will be suspended and will no
longer be in effect so long as the Series E Notes remain investment
grade.
- On October 29, 2002, NPC established an accounts receivables purchase
facility. The agreements relating to the receivables purchase facility
contain various conditions, including a limitation on payments in
respect of common stock by NPC to SPR that is identical to the
limitation contained in NPC's General and Refunding Mortgage Notes,
Series E, described above.
- The PUCN issued a Compliance Order, Docket No. 02-4037, on June 19,
2002, relating to NPC's request for authority to issue long-term debt.
The PUCN order requires that, until such time as the order's
authorization expires (December 31, 2003), NPC must either receive the
prior approval of the PUCN or reach an equity ratio of 42% before
paying any dividends to SPR. If NPC achieves a 42% equity ratio prior
to December 31, 2003, the dividend restriction ceases to have effect.
As of March 31, 2003, NPC's equity ratio was 36.0%.
- The terms of NPC's preferred trust securities provide that no
dividends may be paid on NPC's common stock if NPC has elected to
defer payments on the junior subordinated debentures issued in
conjunction with the preferred trust securities. At this time, NPC has
not elected to defer payments on the junior subordinated debentures.
- SPPC's Term Loan Agreement dated October 30, 2002, which expires
October 31, 2005, limits the amount of payments that SPPC may pay to
SPR. However, that limitation does not apply to payments by SPPC to
enable SPR to pay its reasonable fees and expenses (including, but not
limited to, interest on SPR's indebtedness and payment obligations on
account of SPR's PIES) provided that those payments do not exceed $90
million, $80 million and $60 million in the aggregate for the twelve
month periods ending on October 30, 2003, 2004 and 2005, respectively.
The Term Loan Agreement also permits SPPC to make payments to SPR in
an aggregate amount not to exceed $10 million during the term of the
Term Loan Agreement. In addition, SPPC may make payments to SPR in
excess of the amounts described above so long as, at the time of the
payment and after giving effect to the payment, there are no defaults
or events of default under the Term Loan Agreement, and such amounts,
when aggregated with the amount of payments to SPR by SPPC since the
date of execution of the Term Loan Agreement, do not exceed the sum
of:
- 50% of SPPC's Consolidated Net Income for the period
commencing January 1, 2003 and ending with last day of
fiscal quarter most recently completed prior to the date of
the contemplated dividend payment, plus
39
- the aggregate amount of cash received by SPPC from SPR as
equity contributions on its common stock during such period.
- On October 29, 2002, SPPC established an accounts receivables purchase
facility. The agreements relating to the receivables purchase facility
contain various conditions, including a limitation on the payment of
dividends by SPPC to SPR that is identical to the limitation contained
in SPPC's Term Loan Agreement, described above.
- SPPC's Articles of Incorporation contain restrictions on the payment
of dividends on SPPC's common stock in the event of a default in the
payment of dividends on SPPC's preferred stock. SPPC's Articles also
prohibit SPPC from declaring or paying any dividends on any shares of
common stock (other than dividends payable in shares of common stock),
or making any other distribution on any shares of common stock or any
expenditures for the purchase, redemption or other retirement for a
consideration of shares of common stock (other than in exchange for or
from the proceeds of the sale of common stock) except from the net
income of SPPC, and its predecessor, available for dividends on common
stock accumulated subsequent to December 31, 1955, less preferred
stock dividends, plus the sum of $500,000. At the present time, SPPC
believes that these restrictions do not materially limit its ability
to pay dividends and/or to purchase or redeem shares of its common
stock
- The Utilities are subject to the provision of the Federal Power Act
that states that dividends cannot be paid out of funds that are
properly included in capital accounts. Although the meaning of this
provision is unclear, it could be interpreted to impose an additional
material limitation on a utility's ability to pay dividends in the
absence of retained earnings..
Management intends to seek a modification of the financial covenant
contained in NPC's first mortgage indenture in the near future. The regulatory
limitation contained in the PUCN's Compliance Order, Docket No. 02-4037, dated
June 19, 2002, expires on December 31, 2003. Prior to the expiration date of the
Compliance Order, management may seek PUCN approval for a payment of dividends
by NPC or may seek a waiver from the PUCN of the dividend restriction.
EFFECTS OF RATE CASE DECISIONS
On March 29 and April 1, 2002, S&P and Moody's lowered the unsecured
debt ratings of SPR, NPC and SPPC to below investment grade in response to the
decision of the PUCN with respect to NPC's rate cases. On April 23 and 24, 2002,
the unsecured debt ratings of SPR and the Utilities were further downgraded by
both rating agencies, and the Utilities' secured debt ratings were downgraded to
below investment grade. The downgrades affected SPR's, NPC's and SPPC's
liquidity primarily in two principal areas: (1) their respective financing
arrangements, and (2) NPC's and SPPC's contracts for fuel, for purchase and sale
of electricity and for transportation of natural gas.
For more detailed discussion of these effects please see SPR's, NPC's
and SPPC's Annual Report on Form 10-K for the year ended December 31, 2002.
ACCOUNTS RECEIVABLE FACILITY
On October 29, 2002, NPC and SPPC established accounts receivable
purchase facilities of up to $125 million and $75 million, respectively, which
expire on August 28, 2003 unless either NPC or SPPC has activated its respective
facility before that date, in which case such facility will be automatically
extended to, and will expire on, October 28, 2003. If NPC or SPPC elect to
activate their receivables purchase facilities, they will sell all of their
accounts receivable generated from the sale of electricity and natural gas to
customers to their newly created bankruptcy remote special purpose subsidiaries.
The receivables sales will be without recourse except for breaches of customary
representations and warranties made at the time of sale. The subsidiaries will,
in turn, sell these receivables to a bankruptcy-remote subsidiary of SPR. SPR's
subsidiary will issue variable rate revolving notes backed by the purchased
receivables. Lehman Brothers Holdings, Inc. has committed to be the sole initial
committed purchaser of all of the variable rate revolving notes.
The agreements relating to the receivables purchase facilities contain
various conditions to purchase, covenants and trigger events, and other
provisions customary in receivables transactions. In addition to customary
termination and mandatory repurchase events, each Utilities' receivables
purchase facility may terminate in the event that the Utility or SPR defaults
(i) on the payment of indebtedness, or (ii) on the payment of amounts due under
a swap agreement, and such defaults aggregate to greater than $10 million and $5
million for the Utility and SPR, respectively. Under the terms of the agreements
relating to the receivables purchase facility, each Utility's facility may not
be activated or, if activated, will be terminated in the event of a material
adverse change in the condition, operations or business prospects of the
Utility. SPR has agreed to guaranty the performance by NPC and SPPC of certain
obligations as sellers and servicers under the receivables purchase facilities.
NPC and SPPC intend to use their accounts receivables purchase facilities as
back-up liquidity facilities and do not plan to activate these facilities in the
foreseeable future.
40
CROSS DEFAULT PROVISIONS
Certain financing agreements of SPR and the Utilities contain
cross-default provisions that would result in an event of default under such
financing agreements if there is a failure under other financing agreements of
SPR and the Utilities to meet payment terms or to observe other covenants that
would result in an acceleration of payments due. Most of these default
provisions (other than ones relating to a failure to pay other indebtedness)
provide for a cure period of 30-60 days from the occurrence of a specified event
during which time, SPR or the Utilities may rectify or correct the situation
before it becomes an event of default. The primary cross-default provisions in
SPR's and the Utilities' various financing agreements are briefly summarized
below:
- - The indenture pursuant to which SPR issued its 7.25% Convertible Notes due
2010 provides for an event of default if SPR or any of its significant
subsidiaries (NPC and SPPC) fails to pay indebtedness in excess of $10
million or has any indebtedness of $10 million or more accelerated and
declared due and payable;
- - NPC's General and Refunding Mortgage Indenture provides for an event of
default if a matured event of default under NPC's First Mortgage Indenture
occurs;
- - The terms of NPC's Series E Notes provide that a default with respect to
the payment of principal, interest or premium beyond the applicable grace
period under any mortgage, indenture or other security instrument, by NPC
or any of its restricted subsidiaries, relating to debt in excess of $15
million, triggers a right of the holders of the Series E Notes to require
NPC to redeem the Series E Notes at a price equal to 100% of the aggregate
principal amount plus accrued and unpaid interest and liquidated damages,
if any, upon notice given by at least 25% of the outstanding Series E Notes
holders;
- - NPC's receivables purchase facility may terminate in the event that either
NPC or SPR defaults (i) in the payment of indebtedness, or (ii) in the
payment of amounts due under hedge agreements, and such defaults aggregate
to greater than $10 million and $5 million for NPC and SPR, respectively;
- - SPPC's General and Refunding Mortgage Indenture provides for an event of
default if a matured event of default under SPPC's First Mortgage Indenture
occurs;
- - SPPC's Term Loan Agreement provides for an event of default if (a) SPPC or
any of its subsidiaries default (i) in the payment of indebtedness, or (ii)
in the payment of amounts due under hedge agreements, and such defaults
aggregate to greater than $10 million, or (b) SPPC's General and Refunding
Mortgage Indenture ceases to be enforceable; and
- - SPPC's receivables purchase facility may terminate in the event that either
SPPC or SPR defaults (i) in the payment of indebtedness, or (ii) in the
payment of amounts due under hedge agreements, and such defaults aggregate
to greater than $10 million and $5 million for SPPC and SPR, respectively.
FINANCING TRANSACTIONS
In January 2003, SPR acquired $8.75 million aggregate principal amount
of its Floating Rate Notes due April 20, 2003 in exchange for approximately 1.3
million shares of its common stock, in two privately-negotiated transactions
exempt from the registration requirements of the Securities Act of 1933.
On February 5, 2003, SPR issued approximately 13.66 million shares of
common stock in exchange for a total of 2.1 million of its PIES in five
privately-negotiated transactions exempt from the registration requirements of
the Securities Act of 1933.
On February 14, 2003, SPR issued and sold $300 million of its 7.25%
Convertible Notes due 2010. Approximately $53.4 million of the net proceeds from
the sale of the notes were used to purchase U.S. government securities that were
pledged to the trustee for the first five interest payments on the notes payable
during the first two and one-half years. A portion of the remaining net proceeds
of the notes were used to repurchase approximately $58.5 million of SPR's
Floating Rate Notes due April 20, 2003. Of the remaining net proceeds,
approximately $133 million were used to repay the remainder of SPR's Floating
Rate Notes due April 20, 2003, and the remaining proceeds will be available for
general corporate purposes. The Convertible Notes were issued with registration
rights.
The Convertible Notes will not be convertible prior to August 14, 2003.
At any time on or after August 14, 2003 through the close of business February
14, 2010, holders of the Convertible Notes may convert their notes into shares
of SPR's common stock. Until SPR has obtained shareholder approval to fully
convert the Convertible Notes into shares of common stock, holders of the
Convertible Notes will be entitled to receive 76.7073 shares of common stock and
a remaining portion in cash, based on the average closing price of SPR's common
stock over five consecutive trading days, for each $1,000 principal amount of
notes surrendered for conversion. At an assumed five-day average closing price
of $3.87 per share (based on the
41
last reported sale price of SPR's common stock on April 30, 2003), the total
amount of the cash payable on conversion of the Convertible Notes would be
approximately $165.4 million. If SPR does not obtain shareholder approval, SPR
will be required to pay the cash portion of any Convertible Notes as to which
the holders request conversion on or after August 14, 2003. Although management
does not believe it is likely that a significant amount of the Convertible Notes
will be converted in the foreseeable future, in the event that SPR does not have
available funds to pay the cash portion of the Convertible Notes upon the
requested conversion, SPR may have to issue additional debt to raise the
necessary funds. There can be no assurance that SPR will be able to access the
capital markets to issue such additional debt.
If SPR does obtain shareholder approval, it may elect to satisfy the
cash payment component of the conversion price of the Convertible Notes solely
with shares of common stock. SPR has agreed to use reasonable efforts to obtain
shareholder approval, not later than 180 days after the date of issuance of the
Convertible Notes, to issue and deliver shares of SPR's common stock in lieu of
the cash payment component of the conversion price of the Convertible Notes. For
further information regarding the terms of the Convertible Notes, see Note 4,
Long-Term Debt.
The indenture under which the Convertible Notes were issued does not
contain any financial covenants or any restrictions on the payment of dividends,
the repurchase of SPR's securities or the incurrence of indebtedness. The
indenture does allow the holders of the Convertible Notes to require SPR to
repurchase all or a portion of the holders' Convertible Notes upon a change of
control. The indenture also provides for an event of default if SPR or any of
its significant subsidiaries, including NPC and SPPC, fails to pay any
indebtedness in excess of $10 million or has any indebtedness of $10 million or
more accelerated and declared due and payable.
EFFECT OF HOLDING COMPANY STRUCTURE
Currently, SPR (on a stand-alone basis) has a substantial amount of
debt and other obligations including, but not limited to: $300 million of its
unsecured 8 3/4% Senior Notes due 2005; and $240 million of its unsecured 7.93%
Senior Notes due 2007; and $300 million of its 7.25% Convertible Notes due 2010.
Due to the holding company structure, SPR's right as a common
shareholder to receive assets of any of its direct or indirect subsidiaries upon
a subsidiary's liquidation or reorganization is junior to the claims against the
assets of such subsidiary by its creditors and preferred stockholders.
Therefore, SPR's debt obligations are effectively subordinated to all existing
and future claims of its subsidiaries' creditors, particularly those of NPC and
SPPC, including trade creditors, debt holders, secured creditors, taxing
authorities, guarantee holders, NPC's preferred trust security holders and
SPPC's preferred stockholders. As of March 31, 2003, NPC, SPPC and their
subsidiaries had approximately $2.86 billion of debt and other obligations
outstanding and approximately $238.9 million of outstanding preferred
securities. Although the Utilities are parties to agreements that limit the
amount of additional indebtedness they may incur, the Utilities retain the
ability to incur substantial additional indebtedness and other liabilities.
NEVADA POWER COMPANY
During the quarter ended March 31, 2003, NPC incurred a net loss of
$15.2 million and did not pay or declare a common stock dividend to its parent,
SPR. The causes for significant changes in specific lines comprising the results
of operations for NPC are as follows:
42
ELECTRIC OPERATING REVENUE
THREE MONTHS
ENDED MARCH 31,
--------------------------------------------
Change from
2003 2002 Prior Year %
------------ ------------ ------------
ELECTRIC OPERATING REVENUES ($000):
Residential $ 121,707 $ 131,106 -7.2%
Commercial 74,917 69,691 7.5%
Industrial 92,388 88,760 4.1%
------------ ------------
Retail revenues 289,012 289,557 -0.2%
Other 42,640 66,715 -36.1%
------------ ------------
TOTAL REVENUES $ 331,652 $ 356,272 -6.9%
============ ============
Retail sales in thousands
of megawatt-hours (MWH) 3,400 3,570 -4.8%
Average retail revenue per MWH $ 85.00 $ 81.11 4.8%
NPC's residential revenues decreased for the three months ended March
31, 2003, over the same period in 2002 due to a decrease in electric usage as a
result of warmer than normal weather and company sponsored conservation
programs. This decrease in revenues was partially offset by an increase in
customer growth of 5.3% and an overall rate increase that was effective April 1,
2002.
The increase in commercial and industrial revenues for the three months
ended March 31, 2003, over the same period in 2002 were due to an overall rate
increase effective April 1, 2002 and customer growth. Commercial and industrial
growth, 5.7% and 3.3%, respectively, is attributed to the opening of several new
elementary and secondary schools, shopping centers, office buildings, casino
expansion projects, and new Las Vegas Valley Water District pumping plants in
the Las Vegas area.
The decrease in other electric revenues for the three month period
ended March 31, 2003 over the same period in 2002 was due to lower sales of
wholesale power to other utilities as a result of changing market conditions.
See NPC's Annual Report on Form 10-K for the year ended December 31, 2002, Item
7, Management's Discussion and Analysis of Financial Condition and Results of
Operation, Energy Supply, for a discussion of NPC's purchased power procurement
strategies.
PURCHASED POWER
THREE MONTHS
ENDED MARCH 31,
--------------------------------------------
Change from
2003 2002 Prior Year %
------------ ------------ ------------
PURCHASED POWER ($000) $ 119,257 $ 176,066 -32.3%
Purchased Power in thousands
of MWHs 2,271 2,188 3.8%
Average cost per MWH of
Purchased Power $ 52.51 $ 80.47 -34.7%
NPC'S purchased power costs were lower for the three months ended March
31, 2003 compared to the same period in 2002 although the volume of energy
purchased was slightly greater. The decrease in cost was the result of lower
prices of Short-Term Firm energy purchased. Because it was more economical to
purchase rather than generate power, mega-watt hours purchased increased as
compared to the same period in 2003. See NPC's Annual Report on Form 10-K for
the year ended December 31, 2002, Item 7, Management's Discussion and Analysis
of Financial Condition and Results of Operation, Energy Supply, for a discussion
of NPC's purchased power procurement strategies.
43
FUEL FOR POWER GENERATION
THREE MONTHS
ENDED MARCH 31,
--------------------------------------------
Change from
2003 2002 Prior Year %
------------ ------------ ------------
FUEL FOR POWER GENERATION ($000) $ 46,537 $ 83,722 -44.4%
Thousands of MWHs generated 1,875 2,241 -16.3%
Average cost per MWH of
Generated Power $ 24.82 $ 37.36 -33.6%
Fuel for generation costs for the three months ended March 31, 2003,
were significantly lower than the prior year due to substantial decreases in the
price of natural gas and total mega-watt hours generated. The decrease in
mega-watt hours generated was due to an overall decrease in the system load
requirements. See the earlier explanation of electric operating revenues that
corresponds with the reduced load requirements. In addition, Reid Gardner
Stations 2 and 3 were down for scheduled maintenance, and Clark Stations 1-3 and
Sunrise Unit #1 were not being used because it was more economical to purchase
power than generate.
DEFERRED ENERGY COSTS
THREE MONTHS
ENDED MARCH 31,
--------------------------------------------
Change from
2003 2002 Prior Year %
------------ ------------ ------------
DEFERRED ENERGY COSTS DISALLOWED ($000) - 434,123 N/A
DEFERRED ENERGY COSTS - NET ($000) $ 72,785 $ (9,636) N/A
Deferred energy costs disallowed for the three months ended March 31,
2002, reflects the write-off of $434 million of deferred energy costs incurred
during the seven months ended September 30, 2001, that were disallowed by the
PUCN in NPC's 2001 deferred energy rate case.
Deferral of energy costs-electric-net increased for the three months
ended March 31, 2003, as a result of the amortization of prior deferred costs
pursuant to the PUCN decision in NPC's 2001 deferred energy rate case, that
resulted in increased rates beginning April 1, 2002. The increase in 2003 also
includes additional expense to the extent fuel and purchased power costs
recovered through current rates exceeded actual fuel and purchased power costs
during the three months ended March 31, 2003. Deferred energy costs - net for
the three mounts ended March 31, 2002, reflects the deferral of energy costs to
the extent actual fuel and purchased power costs exceeded fuel and purchased
power costs recovered through rates during that period.
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFUDC)
THREE MONTHS
ENDED MARCH 31,
--------------------------------------------
Change from
2003 2002 Prior Year %
------------ ------------ ------------
ALLOWANCE FOR OTHER FUNDS
USED DURING CONSTRUCTION ($000) $ 1,158 $ 421 175.1%
ALLOWANCE FOR BORROWED FUNDS
USED DURING CONSTRUCTION ($000) $ 1,056 $ 1,112 -5.0%
------------ ------------
$ 2,214 $ 1,533 44.4%
============ ============
44
NPC's total allowance for funds used during construction is higher for
the three-month period ended March 31, 2003 as a result of an increase in
Construction Work in Progress (CWIP) including capital expenditures for the
Centennial Project and an increase in the AFUDC equity rate. This increase was
offset in part by a decrease in the AFUDC debt rate.
OTHER (INCOME) AND EXPENSES
THREE MONTHS
ENDED MARCH 31,
--------------------------------------------
Change from
($000) 2003 2002 Prior Year %
------------ ------------ ------------
OTHER OPERATING EXPENSE $ 40,540 $ 39,986 1.4%
MAINTENANCE EXPENSE $ 13,537 $ 11,650 16.2%
DEPRECIATION AND AMORTIZATION $ 25,907 $ 30,809 -15.9%
INCOME TAXES $ (10,548) $ (156,423) -93.3%
TAXES OTHER THAN INCOME TAXES $ 6,224 $ 6,734 -7.6%
INTEREST CHARGES ON LONG-TERM DEBT $ 30,102 $ 24,078 25.0%
INTEREST CHARGES-OTHER $ 6,080 $ 2,530 140.3%
INTEREST ACCRUED ON DEFERRED ENERGY $ (5,710) $ 11,151 N/A
OTHER INCOME $ (3,338) $ (146) 2186.3%
OTHER EXPENSE $ 1,432 $ 5,997 -76.1%
INCOME TAXES - OTHER INCOME AND EXPENSE $ 2,514 $ (5,645) N/A
Other operating expense for the three-month period ending March 31,
2003 was comparable to the same period in 2002.
Maintenance costs for the three-month period ending March 31, 2003,
increased from the prior year due to timing of scheduled plant maintenance.
Depreciation and amortization was lower for the three-month period
ended March 31, 2003 compared to the same period in 2002 as a result of
depreciation adjustments made pursuant to a PUCN order on March 29, 2002. This
decrease was offset in part by an increase in the computer depreciation rate and
additions to plant-in-service.
NPC's income tax benefit for the three months ended March 31, 2003,
decreased compared to the same period in 2002, due to a corresponding decrease
in first quarter 2003 pre-tax loss compared to the prior year.
Taxes other than income taxes for the three months ended March 31,
2003, was comparable to the amount recognized during the same period in 2002.
Interest charges on long-term debt for the three-month period ending
March 31, 2003, increased over the same period in 2002 due, primarily, to the
issuance in October 2002 of $250 million additional debt at an interest rate of
10.875%. The redemption, in October 2002, of $15 million debt slightly offset
the increase in interest during 2003 over 2002.
Interest charges-other for the three-month period ending March 31,
2003, increased over the prior year due to interest on delayed/terminated
contracts, charges related to fees associated with NPC's credit facilities and
receivables conduit and to the amortization of increased debt discount charges
related to the issuance in October 2002 of $250 million additional debt.
Interest accrued on deferred energy of $5.7 million during the
three-month period ending March 31, 2003 compared favorably to the loss of $11.2
million during the same period in 2002. This was due to the first quarter 2002
write-off of approximately $20.1 million of carrying charges, net of taxes, on
deferred energy costs that were disallowed by the PUCN in their March 29, 2002
decision on NPC's deferred energy rate case. The 2002 write-off was offset, in
part, by the recording of carrying charges on deferred energy costs incurred.
Other income for the three months ended March 31, 2003, increased over
the same period in 2002 due to the following factors: a) In 2003, NPC recognized
income from the disposition of SO2 allowances of approximately $.8 million; (b)
NPC also recognized an increase in gains from the disposition of non-utility
property in 2003 of $1.6 million; and (c) NPC recognized carrying charges
related to divestiture costs, ordered by the PUCN, totaling $.4 million during
the first quarter of 2003.
Other expense decreased during the three months ended March 31, 2003,
compared to the same period in 2002 due, primarily, to the 2002 write-off of
$5.0 million relating to the disposition of SO2 allowances as ordered by the
PUCN. The
45
decrease in expense relating to the SO2 emissions was offset partially by
increases in charges related to depreciation on non-utility property and
corporate advertising.
NPC's income tax expense on other income and expense changed from a tax
benefit during the three months ended March 31, 2002, to a tax expense in the
three months ended March 31, 2003. This was due to a corresponding change from
pre-tax losses in 2002 to pre-tax income in 2003.
ANALYSIS OF CASH FLOWS
NPC's cash flows were less during the three-months ended March 31,
2003, compared to the same period in 2002, resulting primarily from decreases in
cash flows from operating and financing activities and, to a lesser extent, an
increase in cash used for investing activities. The decrease in cash from
operating activities was substantially as a result of the receipt in 2002 of an
income tax refund. The decrease operating cash flow was partially offset by the
collection of previously deferred energy costs due to the PUCN decision in NPC's
2001 deferred energy rate case, that resulted in increased rates beginning April
1, 2002. Cash flows from financing activities were lower in 2003 because of cash
provided by short-term borrowings during 2002. NPC also utilized additional cash
for financing activities in 2003 for the Centennial Plan and other construction
projects.
LIQUIDITY AND CAPITAL RESOURCES
NPC had cash and cash equivalents of approximately $91 million at March
31, 2003.
NPC's liquidity would be significantly affected by an adverse decision
in the lawsuit by Enron, or by unfavorable rulings by the PUCN in pending or
future NPC or SPPC rate cases. S&P and Moody's have NPC's credit ratings on
"negative outlook" and "stable," respectively. Future downgrades by either S&P
or Moody's could preclude NPC's access to the capital markets, and could
adversely affect NPC's ability to continue to purchase power and fuel. Adverse
developments with respect to any one or a combination of the foregoing could
have a material adverse effect on NPC's financial condition and liquidity, and
could make it difficult for NPC to continue to operate outside of bankruptcy.
EFFECT OF RATE CASE DECISIONS
On March 29 and April 1, 2002, following the decision by the PUCN in
NPC's deferred energy rate case, S&P and Moody's lowered NPC's unsecured debt
ratings to below investment grade. On April 23 and 24, 2002, NPC's unsecured
debt ratings were further downgraded and its secured debt ratings were
downgraded to below investment grade. As a result of these downgrades, NPC's
ability to access the capital markets to raise funds were severely limited.
Since SPR's credit ratings were similarly downgraded, SPR's ability to make
capital contributions to NPC also became severely limited.
For more detailed discussion of these effects please see NPC's Annual
Report on Form 10-K for the year ended December 31, 2002.
ACCOUNTS RECEIVABLE FACILITY
On October 29, 2002, NPC established an accounts receivable purchase
facility of up to $125 million, which was arranged by Lehman Brothers. The
receivables purchase facility expires on August 28, 2003 unless NPC has
activated the facility prior to that date, in which case the facility will be
automatically extended to, and will expire on, October 28, 2003. If NPC elects
to activate the receivables purchase facility, NPC will sell all of its accounts
receivable generated from the sale of electricity to customers to its newly
created bankruptcy remote special purpose subsidiary. The receivables sales will
be without recourse except for breaches of customary representations and
warranties made at the time of sale. The subsidiary will, in turn, sell these
receivables to a bankruptcy-remote subsidiary of SPR. SPR's subsidiary will
issue variable rate revolving notes backed by the purchased receivables. Lehman
Brothers Holdings, Inc. has committed to be the sole initial committed purchaser
of all of the variable rate revolving notes.
The agreements relating to the receivables purchase facility contain
various conditions to purchase, covenants and trigger events, and other
provisions customary in receivables transactions. In addition to customary
termination and mandatory repurchase events, the receivables purchase facility
may terminate in the event that either NPC or SPR defaults (i) in the payment of
indebtedness, or (ii) in the payment of amounts due under a swap agreement, and
such defaults aggregate to greater than $10 million and $5 million for NPC and
SPR, respectively. Under the terms of the agreements relating to the receivables
purchase facility, NPC's facility may not be activated or, if activated, will be
terminated in the event of a material adverse change in the condition,
operations or business prospects of NPC. In addition, the agreements contain a
limitation on the payment of dividends by NPC to SPR that is identical to the
limitation contained in NPC's General and Refunding Mortgage Notes, Series E,
described below. SPR has agreed to guaranty NPC's performance of certain
obligations as a seller and servicer under the receivables purchase facility.
46
NPC has agreed to issue $125 million principal amount of its General
and Refunding Mortgage Bonds upon activation of the receivables purchase
facility. The full principal amount of the bond would secure certain of NPC's
obligations as seller and servicer, plus certain interest, fees and expenses
thereon to the extent not paid when due, regardless of the actual amounts owing
with respect to the secured obligations. As a result, in the event of an NPC
bankruptcy or liquidation, the holder of the bond securing the receivables
purchase facility may recover more on a pro rata basis than the holders of other
General and Refunding Mortgage securities, who could recover less on a pro rata
basis, than they otherwise would recover. However, in no event will the holder
of the bond recover more than the amount of obligations secured by the bond.
NPC intends to use the accounts receivable purchase facility as a
back-up liquidity facility and does not plan to activate this facility in the
foreseeable future. NPC may activate the facility within five days upon the
delivery of certain customary funding documentation and the delivery of the $125
million General and Refunding Mortgage Bond.
MORTGAGE INDENTURES
NPC's first mortgage indenture creates a first priority lien on
substantially all of NPC's properties. As of March 31, 2003, $372.5 million of
NPC's first mortgage bonds were outstanding. NPC agreed in connection with its
Series E Notes that it would not issue any more first mortgage bonds.
NPC's General and Refunding Mortgage Indenture creates a lien on
substantially all of NPC's properties in Nevada that is junior to the lien of
the first mortgage indenture. As of March 31, 2003, $870 million of NPC's
General and Refunding Mortgage securities were outstanding. Additional
securities may be issued under the General and Refunding Mortgage Indenture on
the basis of (i) 70% of net utility property additions, (ii) the principal
amount of retired General and Refunding Mortgage Bonds, and/or (iii) the
principal amount of first mortgage bonds retired after delivery to the indenture
trustee of the initial expert's certificate under the General and Refunding
Mortgage Indenture. As of March 31, 2003, NPC had the capacity to issue
approximately $1.13 billion of additional General and Refunding Mortgage
securities. However, the financial covenants contained in the Series E Notes
limits NPC ability to issue additional General and Refunding Mortgage Bonds or
other debt. NPC has reserved $125 million of General and Refunding Mortgage
bonds for issuance upon the initial funding of NPC's receivables facility.
NPC also has the ability to release property from the liens of the two
mortgage indentures on the basis of net property additions, cash and/or retired
bonds. To the extent NPC releases property from the lien of its General and
Refunding Mortgage Indenture, it will reduce the amount of bonds issuable under
that indenture.
CROSS DEFAULT PROVISIONS
Certain financing agreements of NPC contain cross-default provisions
that would result in an event of default under such financing agreements if
there is a failure under other financing agreements of NPC and SPR to meet
payment terms or to observe other covenants that would result in an acceleration
of payments due. Most of these default provisions (other than ones relating to a
failure to pay other indebtedness) provide for a cure period of 30-60 days from
the occurrence of a specified event during which time, NPC or SPR may rectify or
correct the situation before it becomes an event of default. The primary
cross-default provisions in NPC's various financing agreements are briefly
summarized below:
- - NPC's General and Refunding Mortgage Indenture provides for an event of
default if a matured event of default under NPC's First Mortgage Indenture
occurs;
- - The terms of NPC's Series E Notes provide that a default with respect to
the payment of principal, interest or premium beyond the applicable grace
period under any mortgage, indenture or other security instrument, by NPC
or any of its restricted subsidiaries, relating to debt in excess of $15
million, triggers a right of the holders of the Series E Notes to require
NPC to redeem the Series E Notes at a price equal to 100% of the aggregate
principal amount plus accrued and unpaid interest and liquidated damages,
if any, upon notice given by at least 25% of the outstanding Series E Notes
holders; and
- - NPC's receivables purchase facility may terminate in the event that either
NPC or SPR defaults (i) in the payment of indebtedness, or (ii) in the
payment of amounts due under hedge agreements, and such defaults aggregate
to greater than $10 million and $5 million for NPC and SPR, respectively.
47
SIERRA PACIFIC POWER COMPANY
During the quarter ended March 31, 2003, SPPC recognized net income of
$4.0 million and did not pay or declare a common stock dividend to its parent,
SPR. During the same period, SPPC paid $975,000 in dividends to holders of its
preferred stock and neither declared nor paid dividends on its common stock, all
of which is held by its parent, SPR.
The components of SPPC's gross margin are set forth below (dollars in
thousands):
THREE MONTHS
ENDED MARCH 31,
------------------------------------
Change from
2003 2002 Prior Year %
-------- -------- ------------
Operating Revenues:
Electric $205,454 $224,754 -8.6%
Gas 64,617 55,083 17.3%
-------- --------
Total Revenues $270,071 $279,837 -3.5%
======== ========
Energy Costs:
Electric $132,256 $147,863 -10.6%
Gas 53,137 46,786 13.6%
-------- --------
Total Energy Costs 185,393 194,649 -4.8%
======== ========
Gross Margin by Segment:
Electric $ 73,198 $ 76,891 -4.8%
Gas 11,480 8,297 38.4%
-------- --------
Total $ 84,678 $ 85,188 -0.6%
======== ========
The causes for significant changes in specific lines comprising the
results of operations for SPPC are as follows:
ELECTRIC OPERATING REVENUES
THREE MONTHS
ENDED MARCH 31,
--------------------------------------------
Change from
2003 2002 Prior year %
-------- -------- ------------
ELECTRIC OPERATING REVENUES ($000):
Residential $ 59,869 $ 60,403 -0.9%
Commercial 63,128 62,716 0.7%
Industrial 66,178 63,132 4.8%
-------- --------
Retail revenues 189,175 186,251 1.6%
Other 16,279 38,503 -57.7%
-------- --------
TOTAL REVENUES $205,454 $224,754 -8.6%
======== ========
Retail sales in thousands of
MWH 2,134 2,136 -0.1%
Average retail revenue per MWH $ 88.65 $ 87.20 1.7%
SPPC's retail revenues for the three months ending March 31, 2003 were
comparable to the same period in the prior year. An overall rate increase for
the residential and commercial customers, which was effective June 1, 2002, was
offset by lower sales due to warmer than normal temperatures during the first
quarter of 2003.
The decrease in other electric operating revenues for the three-month
period ended March 31, 2003, compared to the same period in 2002 was due to a
decrease in wholesale sales to other utilities. See SPPC's Annual Report on Form
10-K for the year ended December 31, 2002 Item 7, Management's Discussion and
Analysis of Financial Condition and Results of Operation, Energy Supply, for a
discussion of SPPC's purchased power procurement strategies.
48
GAS OPERATING REVENUES
THREE MONTHS
ENDED MARCH 31,
------------------------------------------
Change from
2003 2002 Prior year %
------- ------- ------------
GAS OPERATING REVENUES ($000):
Residential $28,624 $29,472 -2.9%
Commercial 14,274 17,004 -16.1%
Industrial 4,839 7,664 -36.9%
------- -------
Retail revenue 47,737 54,140 -11.8%
Wholesale revenue 16,377 547 2894.0%
Miscellaneous 503 396 27.0%
------- -------
TOTAL REVENUES $64,617 $55,083 17.3%
======= =======
Retail sales in thousands
of decatherms 5,029 6,006 -16.3%
Average retail revenues per decatherm $ 9.49 $ 9.01 5.3%
Retail revenues for the three-month period ended March 31, 2002 were
lower than the same period in the prior year due to a decrease in gas usage as a
result of warmer than normal temperatures in the first quarter of 2003. Also,
industrial revenues decreased as a result of some SPPC's industrial customers
who switched to a gas transportation tariff, which gave them the ability to
procure the commodity from another source other than SPPC. Under SPPC's gas
transportation tariff, those customers are billed for only the transportation of
the commodity and the associated revenues are reflected under miscellaneous
revenues.
Wholesale gas revenues for the three months ended March 31, 2003 were
higher than for the same period in 2002. The increase in wholesale gas sales was
primarily a result of utilizing idle gas transportation capacity to move gas
from Canada to California for resale.
PURCHASED POWER
THREE MONTHS
ENDED MARCH 31,
------------------------------------------
Change from
2003 2002 Prior Year %
-------- -------- ------------
PURCHASED POWER ($000): $ 87,178 $105,417 -17.3%
Purchased Power in thousands
of MWHs 1,593 1,703 -6.5%
Average cost per MWH of
Purchased Power $ 54.73 $ 61.90 -11.6%
Purchased power costs were lower for the three-month period ended March
31, 2003, than the prior year because the majority of SPPC's total energy
requirements were satisfied by Short-Term Firm power purchases for which costs
have decreased as compared to a year ago. In addition, volumes of and prices for
SPPC's risk management activities have decreased. Risk management activities
include transactions entered into for hedging purposes and to minimize purchased
power costs. See SPPC's Annual Report on Form 10-K for the year ended December
31, 2002, Item 7, Management's Discussion and Analysis of Financial Condition
and Results of Operation, Energy Supply, for a discussion of SPPC's purchased
power procurement strategies.
49
FUEL FOR POWER GENERATION
THREE MONTHS
ENDED MARCH 31,
---------------------------------------------
Change from
2003 2002 Prior Year %
------- ------- ------------
FUEL FOR POWER GENERATION ($000) $33,676 $47,051 -28.4%
Thousands of MWHs generated 963 1,212 -20.5%
Average fuel cost per MWH
of Generated Power $ 34.97 $ 38.82 -9.9%
Fuel for power generation costs for the three-month period ended March
31, 2003 were lower than the same period in the prior year as both volumes
generated and natural gas prices decreased. Generation as well as purchase power
volumes are down as total system requirements decreased in comparison to last
year.
GAS PURCHASED FOR RESALE
THREE MONTHS
ENDED MARCH 31,
----------------------------------------------
Change from
2003 2002 Prior Year %
------- ------- ------------
GAS PURCHASED FOR RESALE ($000) $42,334 $38,594 9.7%
Gas Purchased for Resale
(thousands of decatherms) 7,621 5,960 27.9%
Average cost per decatherm $ 5.55 $ 6.48 -14.4%
Gas purchased for resale increased significantly for the three-month
period ended March 31, 2003, compared to the prior year as an increase in
wholesale activity more than offset the decrease in gas prices.
DEFERRED ENERGY COSTS
THREE MONTHS
ENDED MARCH 31,
-------------------------------------------
Change from
2003 2002 Prior Year %
------- ------- ------------
DEFERRED ENERGY COSTS - ELECTRIC - NET ($000) $11,402 $(4,605) N/A
DEFERRED ENERGY COSTS - GAS - NET ($000) $10,803 $ 8,192 31.9%
The increase in deferral of energy costs-electric-net for the three
month period ended March 31, 2003, reflects the amortization of prior deferred
costs pursuant to the PUCN decision in SPPC's 2002 deferred energy rate case,
that resulted in increased rates beginning June 1, 2002. The 2003 increase was
offset, in part, by the recording of current year deferrals of electric energy
costs to the extent actual fuel and purchased power costs for the three months
ended March 31, 2003, exceeded fuel and purchased power costs recovered through
current rates during that period. Deferral of energy costs-electric-net for the
three months ended March 31, 2002, reflects the deferral of electric energy
costs in 2002 that were in excess of purchased power costs recovered through
rates at that time.
SPPC's deferred energy costs-gas-net, for the three months ended March
31, 2003 reflects the amortization of prior deferred costs due to the
PUCN-authorized recovery of those costs. The increase in 2003 also includes
additional expense to the extent natural gas costs recovered through current
rates exceeded actual natural gas costs.
50
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFUDC)
THREE MONTHS
ENDED MARCH 31,
--------------------------------------
Change from
2003 2002 Prior Year %
------ ------ ------------
ALLOWANCE FOR OTHER FUNDS
USED DURING CONSTRUCTION ($000) $ 602 $ 236 155.1%
ALLOWANCE FOR BORROWED FUNDS
USED DURING CONSTRUCTION ($000) 700 391 79.0%
------ ------
$1,302 $ 627 107.7%
====== ======
Total allowance for funds used during construction increased for the
three-month period ended March 31, 2003, compared to the prior year due to an
increase in CWIP and an increase in the AFUDC Rate.
OTHER (INCOME) AND EXPENSES
THREE MONTHS
ENDED MARCH 31,
------------------------------------------
Change from
($000) 2003 2002 Prior Year %
-------- -------- ------------
OTHER OPERATING EXPENSE $ 29,213 $ 27,762 5.2%
MAINTENANCE EXPENSE $ 5,187 $ 5,257 -1.3%
DEPRECIATION AND AMORTIZATION $ 19,706 $ 17,558 12.2%
INCOME TAXES $ 2,090 $ 4,901 -57.4%
TAXES OTHER THAN INCOME TAXES $ 4,662 $ 4,776 -2.4%
INTEREST CHARGES ON LONG-TERM DEBT $ 18,781 $ 16,445 14.2%
INTEREST CHARGES-OTHER $ 3,125 $ 1,142 173.6%
INTEREST ACCRUED ON DEFERRED ENERGY $ (1,925) $ (5,027) -61.7%
OTHER INCOME $ (1,065) $ (1,837) -42.0%
OTHER EXPENSE $ 1,905 $ 2,462 -22.6%
INCOME TAXES - OTHER INCOME AND EXPENSE $ 303 $ 1,432 -78.8%
Other operating expense for the three-month period ending March 31,
2003 was greater than the prior year, due to credits associated with the
discontinuation of billing services for Truckee Meadows Water Authority in July
2002 along with increased billing/collection efforts associated with delinquent
customer accounts and higher employee labor overhead costs in 2003.
Maintenance costs for the three-month period ending March 31, 2003 were
comparable to amounts recognized during the same period in 2002.
Depreciation and amortization increased for the three-month period
ended March 31, 2003, compared to the same period in 2002 as a result of an
increase in additions to plant-in-service assets.
SPPC recorded lower operating income tax expense for the three months
ended March 31, 2003 compared to the same period in 2002. This decrease is due
to a corresponding decrease in first quarter 2003 pre-tax income compared to the
prior year.
Taxes other than income taxes for the three months ended March 31,
2003, was comparable to the amount recognized during the same period in 2002.
Interest charges on long-term debt for the three-month period ending
March 31, 2003, increased over the same period in 2002 due, primarily, to the
issuance in October 2002 of $100 million additional debt at an interest rate of
10.5%.
Interest charges-other for the three-month period ending March 31,
2003, increased over the prior year due to interest on delayed/terminated
contracts, charges related to fees associated with SPPC's credit facilities and
receivables conduit, and to
51
the increase of amortization resulting from increased debt discount charges
related to the issuance, in October 2002 of $100 million additional debt.
Interest accrued on deferred energy decreased for the three-month
period ending March 31, 2003, compared to the same period, 2002, due to lower
deferred fuel and purchased power balances during 2003.
Other income for the three months ended March 31, 2003, decreased
compared to the same period in the prior year due, primarily, to a decrease in
interest income and subsidiary earnings, partially offset by increases in lease
revenues and miscellaneous non-operating income.
Other expense for the three months ended March 31, 2003, decreased,
compared to the prior year, due, primarily, to the occurrence in 2002 of
miscellaneous charges related to SPPC's sale of its water division. The decrease
in 2003 was offset partially by higher charges related to corporate advertising,
during 2003.
SPPC recorded lower income tax expense on other income and expense for
the three months ended March 31, 2003, compared to 2002 due to lower net other
income during 2003.
ANALYSIS OF CASH FLOWS
SPPC's cash flows during the three-months ended March 31, 2003,
improved compared to the same period in 2002, as a result of an increase in cash
flows from operating activities, partially offset, by an increase in cash used
for investing activities. Cash flows from operating activities improved
primarily as a result of the collection of previously deferred energy costs due
to the PUCN decision in SPPC's 2002 deferred energy rate case, that resulted in
increased rates beginning June 1, 2002. Cash flows from investing activities
decreased in 2003 because of additional cash requirements for increased
construction activity during 2003. Cash flows from financing activities were
comparable for both periods.
LIQUIDITY AND CAPITAL RESOURCES
SPPC had cash and cash equivalents of approximately $128 million at
March 31, 2003.
SPPC's future liquidity could be significantly affected by unfavorable
rulings by the PUCN in pending or future SPPC or NPC rate cases. S&P and Moody's
have SPPC's credit ratings on "negative outlook" and "stable", respectively.
Future downgrades by either S&P or Moody's could preclude SPPC's access to the
capital markets and could adversely affect SPPC's ability to continue purchasing
power and fuel. Adverse developments with respect to any one or a combination of
the factors and contingencies set forth above could have a material adverse
effect on SPPC's financial condition and liquidity, and could make it difficult
to continue to operate outside of bankruptcy.
EFFECT OF RATE CASE DECISIONS
On March 29 and April 1, 2002, following the decision by the PUCN in
NPC's deferred energy rate case, S&P and Moody's lowered SPPC's unsecured debt
ratings to below investment grade. On April 23 and 24, 2002, SPPC's unsecured
debt ratings were further downgraded and its secured debt ratings were
downgraded to below investment grade. The decision of the PUCN on May 29, 2002,
on SPPC's deferred energy application to disallow $53 million of deferred
purchased fuel and power costs accumulated between March 1, 2001 and November
30, 2001, did not result in any further downgrades of SPPC's securities. As a
result of the downgrades, SPPC's ability to access the capital markets to raise
funds is severely limited. Since SPR's credit ratings were similarly downgraded,
SPR's ability to make capital contributions to SPPC also became severely
limited.
For more detailed discussion of these effects please see SPPC's Annual
Report on Form 10-K for the year ended December 31, 2002.
ACCOUNTS RECEIVABLE FACILITY
On October 29, 2002, SPPC established an accounts receivable purchase
facility of up to $75 million, which was arranged by Lehman Brothers. The
receivables purchase facility expires on August 28, 2003 unless SPPC has
activated the facility prior to that date, in which case the facility will be
automatically extended to, and will expire on, October 28, 2003. If SPPC elects
to activate the receivables purchase facility, SPPC will sell all of its
accounts receivable generated from the sale of electricity and natural gas to
customers to its newly created bankruptcy remote special purpose subsidiary. The
receivables sales will be without recourse except for breaches of customary
representations and warranties made at the time of sale. The subsidiary will, in
turn, sell these receivables to a bankruptcy-remote subsidiary of SPR. SPR's
subsidiary will issue variable rate revolving notes backed by the purchased
receivables. Lehman Brothers Holdings, Inc. has committed to be the sole initial
committed purchaser of all of the variable rate revolving notes.
52
The agreements relating to the receivables purchase facility contain
various conditions to purchase, covenants and trigger events, and other
provisions customary in receivables transactions. In additional to customary
termination and mandatory repurchase events, the receivables purchase facility
may terminate in the event that either SPPC or SPR defaults (1) on the payment
of indebtedness, or (2) on the payment of amounts due under a swap agreement,
and such defaults aggregate to greater than $10 million and $5 million for SPPC
and SPR, respectively. Under the terms of the agreements relating to the
receivables purchase facility, SPPC's facility may not be activated or, if
activated, will be terminated in the event of a material adverse change in the
condition, operations or business prospects of SPPC. In addition, the agreements
contain a limitation on the payment of dividends by SPPC to SPR that is
identical to the limitation contained in SPPC's Term Loan Agreement, described
below. SPR has agreed to guaranty SPPC's performance of certain obligations as a
seller and servicer under the receivables purchase facility.
SPPC has agreed to issue $75 million principal amount of its General
and Refunding Mortgage Bonds upon activation of the receivables purchase
facility. The full principal amount of the bond would secure certain of SPPC's
obligations as seller and servicer, plus certain interest, fees and expenses
thereon to the extent not paid when due, regardless of the actual amounts owing
with respect to the secured obligations. As a result, in the event of an SPPC
bankruptcy or liquidation, the holder of the bond securing the receivables
purchase facility may recover more on a pro rata basis than the holders of other
General and Refunding Mortgage securities, who could recover less on a pro rata
basis, than they otherwise would recover. However, in no event will the holder
of the bond recover more than the amount of obligations secured by the bond.
SPPC intends to use the accounts receivable purchase facility as a
back-up liquidity facility and does not plan to activate this facility in the
foreseeable future. SPPC may activate the facility within five days upon the
delivery of certain customary funding documentation and the delivery of the $75
million General and Refunding Mortgage Bond.
MORTGAGE INDENTURES
SPPC's First Mortgage Indenture creates a first priority lien on
substantially all of SPPC's properties in Nevada and California. As of March 31,
2003, $505.3 million of SPPC's first mortgage bonds were outstanding. SPPC
agreed in its General and Refunding Mortgage Indenture that it would not issue
any additional first mortgage bonds.
SPPC's General and Refunding Mortgage Indenture creates a lien on
substantially all of SPPC's properties in Nevada that is junior to the lien of
the first mortgage indenture. As of March 31, 2003, $419.8 million of SPPC's
General and Refunding Mortgage bonds were outstanding. Additional securities may
be issued under the General and Refunding Mortgage Indenture on the basis of (1)
70% of net utility property additions, (2) the principal amount of retired
General and Refunding Mortgage bonds, and/or (3) the principal amount of first
mortgage bonds retired after delivery to the indenture trustee of the initial
expert's certificate under the General and Refunding Mortgage Indenture. At
March 31, 2003, SPPC had the capacity to issue approximately $435.7 million of
additional General and Refunding Mortgage securities, which amount does not
include SPPC's $80 million General and Refunding Mortgage Note, Series D, due
2004. However, the financial covenants contained in SPPC's Term Loan Agreement
and Receivable Purchase Facility Agreements limit SPPC's ability to issue
additional General and Refunding Mortgage Securities or other debt. SPPC has
reserved $75 million of General and Refunding Mortgage Bonds for issuance upon
the initial funding of its receivables purchase facility.
SPPC also has the ability to release property from the liens of the two
mortgage indentures on the basis of net property additions, cash and/or retired
bonds. To the extent SPPC releases property from the lien of its General and
Refunding Mortgage Indenture, it will reduce the amount of bonds issuable under
that indenture.
FINANCING TRANSACTIONS AND COVENANTS
On May 1, 2003, SPPC's $80 million Washoe County, Nevada, Water
Facilities Refunding Revenue Bonds, Series 2001, were successfully remarketed.
The interest rate on the bonds was adjusted from their prior two-year 5.75% term
rate to a 7.50% term rate for the period of May 1, 2003 to and including May 3,
2004. The bonds will be subject to remarketing on May 3, 2004. In the event that
the bonds cannot be successfully remarketed on that date, SPPC will be required
to purchase the outstanding bonds at a price of 100% of principal amount, plus
accrued interest. From May 1, 2003 to and including May 3, 2004, SPPC's payment
and purchase obligations in respect of the bonds are secured by SPPC's $80
million General and Refunding Mortgage Note, Series D, due 2004.
SPPC's $100 million Term Loan Agreement, entered into on October 30,
2002 with several lenders and Lehman Commercial Paper Inc., as Administrative
Agent, contains two financial maintenance covenants. The first requires that
SPPC maintain a ratio of consolidated total debt to consolidated total
capitalization at all times during each of the following quarters in an amount
not to exceed (i) .650 to 1.0 for the fiscal quarters ended December 31, 2002
through December 31, 2003, (ii) .625 to 1.0 for the fiscal quarters ended March
31, 2004 through December 31, 2004, and (iii) .600 to 1.0 for the fiscal quarter
ended March 31, 2005 and for each fiscal quarter thereafter. The second covenant
requires that SPPC maintain a consolidated
53
interest coverage ratio for the four consecutive fiscal quarters ending with
each of the following fiscal quarters of not less than (i) 1.75 to 1.00 for the
fiscal quarters ended December 31, 2002 and March 31, 2003, (ii) 2.50 to 1.0 for
the fiscal quarters ended June 30, 2003 through December 31, 2003, (iii) 2.75 to
1.0 for the fiscal quarters ended March 31, 2004 through September 30, 2004, and
(iv) 3.00 to 1.0 for the fiscal quarter ended December 31, 2004 and for each
fiscal quarter thereafter. SPPC expects to deliver a certificate to the
Administrative Agent on or before May 15, 2003 as required by the Term Loan
Agreement stating that SPPC was in compliance with these covenants as of March
31, 2003. The Term Loan Facility, which is secured by a $100 million Series C
General and Refunding Mortgage Bond, will expire October 31, 2005.
CROSS DEFAULT PROVISIONS
Certain financing agreements of SPPC contain cross-default provisions
that would result in an event of default under such financing agreements if
there is a failure under other financing agreements of SPPC and SPR to meet
payment terms or to observe other covenants that would result in an acceleration
of payments due. Most of these default provisions (other than ones relating to a
failure to pay other indebtedness) provide for a cure period of 30-60 days from
the occurrence of a specified event during which time, SPPC or SPR may rectify
or correct the situation before it becomes an event of default. The primary
cross-default provisions in SPPC's various financing agreements are briefly
summarized below:
- - SPPC's General and Refunding Mortgage Indenture provides for an event of
default if a matured event of default under SPPC's First Mortgage Indenture
occurs;
- - SPPC's Term Loan Agreement provides for an event of default if (a) SPPC or
any of its subsidiaries default (i) in the payment of indebtedness, or (ii)
in the payment of amounts due under hedge agreements, and such defaults
aggregate to greater than $10 million, or (b) SPPC's General and Refunding
Mortgage Indenture ceases to be enforceable; and
- - SPPC's receivables purchase facility may terminate in the event that either
SPPC or SPR defaults (i) in the payment of indebtedness, or (ii) in the
payment of amounts due under hedge agreements, and such defaults aggregate
to greater than $10 million and $5 million for SPPC and SPR, respectively.
SIERRA PACIFIC RESOURCES (HOLDING COMPANY)
The Condensed Consolidated Statements of Operations of SPR for the
three-months ended March 31, 2003, include the operating results of the holding
company. The holding company recognized higher interest costs, $20.1 million in
2003 compared to $19.2 million in 2002, due to the issuance of $300 million of
convertible notes in February 2003.
TUSCARORA GAS PIPELINE COMPANY
The Condensed Consolidated Statements of Operations of SPR for the
three months ended March 31, 2003, and March 31, 2002, include the operating
results of Tuscarora Gas Pipeline Company (TGPC), a wholly owned subsidiary of
SPR. TGPC contributed $.9 million in net income for both the three-month periods
ended March 31, 2003, and March 31, 2002.
e [MID DOT] THREE
The Condensed Consolidated Statements of Operations of SPR for the
three months ended March 31, 2003, and March 31, 2002, include the operating
results of e [MID DOT] three, a wholly owned subsidiary of SPR. e [MID DOT]
three incurred net losses of $.3 and $.2 million, respectively, for the three-
month periods ended March 31, 2003 and March 31, 2002, respectively.
SIERRA PACIFIC COMMUNICATIONS
The Condensed Consolidated Statements of Operations of SPR for the
three months-ended March 31, 2003, and March 31, 2002, include the operating
results of Sierra Pacific Communications (SPC), a wholly owned subsidiary of
SPR. SPC incurred net losses of $.9 million and $.7 million for the three-month
periods ended March 31, 2003, and March 31, 2002, respectively.
REGULATORY MATTERS
Substantially all of the utility operations of both NPC and SPPC are
conducted in Nevada. As a result both Utilities are subject to utility
regulation within Nevada and therefore deal with many of the same regulatory
issues.
54
NEVADA MATTERS
NEVADA POWER COMPANY 2001 DEFERRED ENERGY CASE
On November 30, 2001, NPC filed an application with the PUCN seeking
repayment for purchased fuel and power costs accumulated between March 1, 2001,
and September 30, 2001, as required by law. The application sought to establish
a rate to repay accumulated purchased fuel and power costs of $922 million and
spread the recovery of the deferred costs, together with a carrying charge, over
a period of not more than three years.
On March 29, 2002, the PUCN issued its decision on the deferred energy
application, allowing NPC to recover $478 million over a three-year period, but
disallowing $434 million of deferred purchased fuel and power costs and $30.9
million in carrying charges consisting of $10.1 million in carrying charges
accrued through September 2001 and $20.8 million in carrying charges accrued
from October 2001 through February 2002. The order stated that the disallowance
was based on alleged imprudence in incurring the disallowed costs.
On April 11, 2002, NPC filed a lawsuit in the First District Court of
Nevada seeking to reverse portions of the PUCN's decision. NPC's lawsuit
requested that the District Court reverse portions of the PUCN's order and
remand the matter to the PUCN with direction that the PUCN authorize NPC to
immediately establish rates that would allow NPC to recover its entire deferred
energy balance of $922 million, with a carrying charge, over three years. The
Bureau of Consumer Protection (BCP) of the Nevada Attorney General's Office
filed a petition in the case seeking additional disallowances. On April 28,
2003, the District Court issued its decision, denying NPC's requests and
affirming the PUCN's order, and also denying the BCP's petition. NPC's
management is evaluating its options in regard to the District Court's decision.
Various interveners in NPC's deferred energy case before the PUCN filed
petitions with the PUCN for reconsideration of the PUCN's order, seeking
additional disallowances of between $12.8 million and $488 million. On May 24,
2002, the PUCN issued an order denying any further disallowances and granted NPC
the authority to increase the deferred energy cost recovery charge for the month
of June 2002 by one cent per kilowatt-hour. This increase accelerated the
recovery of the deferred balance by approximately $16 million for the month of
June 2002 only.
NEVADA POWER COMPANY 2002 DEFERRED ENERGY CASE
On November 14, 2002, NPC filed an application with the PUCN seeking
repayment for purchased fuel and power costs accumulated between October 1,
2001, and September 30, 2002, as required by law. The application seeks to
establish a rate to repay accumulated purchased fuel and power costs of $195.7
million, together with a carrying charge, over a period of not more than three
years. The application also requests a reduction to the going-forward rate for
energy, reflecting reduced wholesale energy costs. The combined effect of these
two adjustments results in an overall rate reduction of 5.3%.
Intervenors filed their direct testimony on March 7, 2003, and
supplemental testimony was filed March 27, 2003, calling for disallowances
between approximately $108 and $300 million of the total fuel and purchased
power costs. The largest of the proposed disallowances are based on the same
alleged imprudence as found in the PUCN order for NPC's 2001 Deferred Energy
Case relating to NPC's failure to enter into power contracts in 1999. Certain
Intervenors' testimony, in the current case, have argued in favor of
disallowances based on the same alleged imprudence as cited in the last deferred
order but have not quantified their proposals and in some cases have argued in
favor of disallowances in excess of the ranges previously indicated. The PUCN
Staff does not support this disallowance but calculated a range of $116 to $347
million in the event that the PUCN disallows deferred energy costs based upon
the same alleged imprudence cited by the PUCN in its 2001 decision relative to
this issue.
While all Intervenors have called for the PUCN to reduce NPC's
requested energy rates for recovery of past energy costs, some have also
proposed to increase customers' energy rates for purchases that will occur
during the upcoming deferred accounting period, which would decrease the
accumulation of deferred energy costs.
NPC's rebuttal testimony was filed March 31, 2003. The hearing
commenced on April 7, and was completed on April 17, 2003. A special agenda
meeting is scheduled for May 9, 2003, at which time a ruling from the Commission
is expected.
55
NEVADA POWER COMPANY DEMAND REDUCTION PROGRAMS
On November 14, 2002, NPC filed an application with the PUCN seeking
recovery of expenses incurred in the implementation and operation of programs
for energy conservation and load management. In the filing, NPC requested a
one-year recovery of approximately $1.9 million. This would result in an average
0.12% increase in present rates. NPC asked for this increase to become effective
simultaneously with the rate change to be ordered in its 2002 deferred energy
case discussed above. The parties to the case subsequently negotiated a
settlement agreement which approved NPC's request for cost recovery with the
exception of a small disallowance ($14,673). The stipulation was approved at the
agenda meeting held April 4, 2003.
SIERRA PACIFIC POWER COMPANY 2003 DEFERRED ENERGY CASE
On January 14, 2003, SPPC filed an application with the PUCN, as
required by law, seeking to clear deferred balances for purchased fuel and power
costs accumulated between December 1, 2001 and November 30, 2002. The
application seeks to establish a DEAA rate to clear accumulated purchased fuel
and power costs of $15.4 million and spread the cost recovery over a period of
not more than three years. It also seeks to recalculate the Base Tariff Energy
Rate to reflect anticipated ongoing purchased fuel and power costs. The total
rate increase resulting from the requested DEAA would amount to 0.01%. The
intervenors' testimony was received April 25, 2003, and includes proposed
disallowances from $34 million to $76 million. While all Intervenors call for
the PUCN to reduce SPPC's requested energy rates for recovery of past energy
costs, some also propose to increase customers' energy rates for purchases that
will occur during the upcoming deferred accounting period, which would decease
the accumulation of deferred energy costs. A hearing is scheduled to begin on
May 12, 2003, and a ruling is required before July 13, 2003.
SIERRA PACIFIC POWER COMPANY DEMAND REDUCTION PROGRAMS
On January 14, 2003, SPPC filed with the PUCN an application seeking
recovery of expenses incurred in the implementation and operation of programs
for energy conservation and load management. In the filing, SPPC requested a
one-year recovery of approximately $0.9 million. This would result in an average
0.12% increase in present rates. SPPC asked for this increase to become
effective simultaneously with the rate change to be ordered in its 2003 deferred
energy case discussed above. The parties to the case subsequently negotiated a
settlement agreement that is expected to be approved by the PUCN coincident with
its 2003 deferred energy ruling. The agreement called for complete recovery of
the $0.9 million balance.
CUSTOMERS FILE TO BE SERVED BY NEW PROVIDERS UNDER NRS 704B (AB 661)
AB 661, passed by the Nevada legislature in 2001 and incorporated into
Nevada Revised Statutes as NRS 704B, allows commercial and governmental
customers with an average demand greater than 1 MW to select new energy
suppliers. The Utilities would continue to provide transmission, distribution,
metering and billing services to such customers. NRS 704B requires customers
wishing to choose a new supplier to receive the approval of the PUCN and meet
public interest standards. In particular, departing customers must secure new
energy resources that are not under contract to the Utilities, the departure
must not burden the Utilities with increased costs or cause any remaining
customers to pay increased costs, and the departing customers must pay their
portion of any deferred energy balances. The PUCN adopted regulations
prescribing the criteria that will be used to determine if there will be
negative impacts to remaining customers or the Utility. Customers wishing to
choose a new supplier must provide 180-day notice to the Utilities.
Twelve applications for departure are pending for NPC. These
applications total approximately 350 MW of peak load. In eleven of these
applications stipulations have been reached that addressed all issues except
treatment of Base Tariff General Rate (BTGR) revenue impacts arising from
departure. The commission has issued a compliance order for these eleven
applications that will allow the customers to depart upon completion of items in
the compliance order. The remaining application is pending with a decision
anticipated in second quarter of 2003.
NPC continues to pursue resolution of the BTGR revenue impact issue.
The most recent departure orders allow NPC to establish a regulatory asset to
recover the BTGR revenue impact. According to the commission's order, the BTGR
revenue impact will be offset by load growth from new customers. NPC has
requested clarification of the land growth calculation methodology. The Bureau
of Consumer Protection is opposed to the regulatory asset for BTGR impacts and
has filed for reconsideration. A decision from the PUCN is expected in the
second quarter of 2003.
As this issue is being resolved, the customers seeking to depart are
continuing to address the requirements of the compliance order which include
executing supply, transmission, and distribution contracts. All compliance items
must be filed no later than 100 days after the date of their compliance order.
Some such customers are also proceeding with the implementation of metering and
communications equipment. However, at this point, no customer has provided
written notice of their intent to proceed with departure from NPC. NPC is
obligated to plan for and secure energy supplies for these customers until
official departure notice is received. The written departure notice must provide
a minimum of 60 days notice.
56
Should customers elect to proceed with departure, such departures would begin in
the third quarter of 2003 and generally are anticipated to be phased in based
upon each customer's implementation plan.
CALIFORNIA MATTERS (SPPC)
RATE STABILIZATION PLAN
SPPC serves approximately 44,500 customers in California. On June 29,
2001, SPPC filed with the California Public Utilities Commission (CPUC) a Rate
Stabilization Plan, which included two phases. Phase One, which was also filed
June 29, 2001, was an emergency electric rate increase of $10.2 million annually
or 26%. The increase was applicable to all customers except those eligible for
low-income and medical-needs rates and went into effect July 18, 2002.
Phase Two of the Rate Stabilization Plan was filed with the CPUC on
April 1, 2002, and includes a general rate case and requests the CPUC to
reinstate the Energy Cost Adjustment Clause, which would allow SPPC to file for
periodic rate adjustments to reflect its actual costs for wholesale energy
supplies. Phase Two also includes a proposal to terminate the 10% rate reduction
mandated by AB 1890, but does not include a performance -based rate-making
proposal. This request was for an additional overall increase in revenues of
17.1%, or $8.9 million annually.
On December 19, 2002, SPPC filed an amendment to the Phase Two
application reducing the requested increase by $4.1 million to $4.8 million or
9.2% annually. SPPC agreed to make certain changes to the application and file
the amendment following discussions with the CPUC Office of Ratepayer Advocates.
In February 2003, the Office of the Ratepayer Advocates (ORA) filed testimony on
cost of service proposing to reduce SPPC's request by $3.2 million resulting in
a $1.6 million increase or 3.3%. On March 14, 2003, SPPC filed rebuttal
testimony. On March 10, 2003, the ORA filed testimony on revenue allocation and
rate design and on April 2, 2003, Sierra and the California Ski Areas
Association filed rebuttal testimony. Hearings were held on April 9, 2003. A
comparative table of issues is due by April 30 with opening and reply briefs
scheduled for May 16, 2003 and June 13, 2003, respectively. A decision by the
CPUC regarding the Energy Cost Adjustment Clause is expected in May 2003 and a
decision on all other issues is expected in late 2003.
CALIFORNIA ASSEMBLY BILL 1235
On September 24, 2002, the Governor of California signed into law
Assembly Bill 1235 (AB 1235), which allows the transfer of hydroelectric plants
along the Truckee River from SPPC to the Truckee Meadows Water Authority (TMWA).
AB 1235 effectively amends previous California legislation (AB 6X) that
prevented until 2006 private utilities from selling any power plants that
provide energy to California customers. AB 1235 provides an exemption for the
four "run-of-the-river" hydroelectric plants that SPPC sold to TMWA as part of
the sale of its water business in June 2001.
On November 9, 2002, SPPC filed an application with the CPUC for
authority to sell the four hydroelectric plants. On January 13, 2003, the CPUC
issued a ruling that the California Environmental Quality Act applies to this
proceeding and SPPC must supplement the application with a certified
environmental document. SPPC has begun informal discussions with the CPUC on the
environmental issues and cannot yet predict the outcome of this proceeding. On
April 17, 2003, the CPUC issued a ruling dismissing the application without
prejudice. The decision allows SPPC to re-file the application including an
environmental assessment. Sierra plans to file a new application by the end of
the second quarter of 2003.
FERC MATTERS (SPPC, NPC)
In December 2001, the Utilities filed ten wholesale purchased power
complaints with the FERC under Section 206 of the Federal Power Act seeking to
reduce prices of certain forward power purchase contracts that the Utilities
entered into prior to the price caps established by the FERC during the western
United States utility crisis. The Utilities believe the prices under these
purchased power contracts are unjust and unreasonable. The Utilities negotiated
a settlement with Duke Energy Trading and Marketing, but were unable to reach
agreement in bilateral settlement discussions with other respondents.
The Utilities have already paid the full contact price for all power
actually delivered by these suppliers, but are contesting claims made for
terminated power suppliers, including those terminated by Enron.
The Administrative Law Judge ("ALJ") overseeing the Utilities'
complaints and proceedings under Section 206 of the Federal Power Act issued an
initial decision on December 19, 2002 which stated that the Utilities'
complaints did not meet the public interest standard of proof, which the ALJ
believed applied to the reformation of their contracts. NPC, SPPC and other
parties to these proceedings filed Briefs on Exceptions to the ALJ's initial
order with the FERC. Oral argument before the three commissioners of the FERC
took place on April 23, 2003. We are unable to predict the timing or outcome of
the FERC's decision on the Utilities' Section 206 complaints. FERC is expected
to issue a decision in this matter by May 31, 2003.
57
On March 26, 2003, the Staff of the FERC (the Staff) concluded that
supply-demand imbalance, flawed market design and inconsistent rules made
significant market manipulation possible in the Western states in 2000 and 2001.
The FERC has not decided how or if this manipulation impacted NPC's and SPPC's
claims to the FERC in their Section 206 proceedings.
Additionally, the Staff recommended that certain market participants
identified in the Cal ISO Report released January 6, 2003, including SPPC, be
directed to show cause why their behavior did not constitute gaming in violation
of the Cal ISO and Cal PX tariffs. In its report, the Cal ISO indicated that it
was unclear as to the reason SPPC received certain revenues in the amount of
approximately $6 thousand. The total revenues for all companies for which the
Staff recommended show cause orders are approximately $2.8 million. SPPC was one
of the over 30 market participants included in the Staff's recommendation. On
April 7, 2003, SPR submitted documentation to the FERC demonstrating that SPPC
did not engage in gaming in violation of the Cal ISO or Cal PX tariffs, nor in
the manipulation of the Western energy market. The FERC has not yet decided
whether to issue a show cause order to SPPC or to any of the other companies
identified by the FERC staff. The Staff also recommended that the Cal ISO fully
explain the screen that was used to identify the subject transactions and that
the information should be made available to the public.
For more information regarding the Section 206 proceedings, please see
Item 7, Management's Discussion and Analysis of Financial Condition and Results
of Operations - Regulation and Rate Proceedings - FERC Matters - FERC 206
Complaints in SPR's, NPC's and SPPC's Annual Report on Form 10-K for the year
ended December 31, 2002.
OPEN ACCESS TRANSMISSION TARIFF
On September 27, 2002, the Utilities filed with the FERC a revised Open
Access Transmission Tariff. The purpose of the filing was to implement changes
that are required to implement retail open access in Nevada. The Utilities
requested the changes to become effective November 1, 2002, the date retail
access was scheduled to commence in Nevada in accordance with provisions of AB
661, passed in the 2001 session of the Nevada Legislature.
On October 11, 2002, the Utilities filed with the FERC, revised rates,
terms, and conditions for ancillary services offered in the OATT designated
Docket No. ER03-37-000. On November 25, 2002, the FERC suspended the rates in
Docket No. ER03-37-000 for a nominal period and made them effective subject to
refund on January 1, 2003, as requested by the Utilities.
On November 21, 2002, the FERC suspended the revised OATT in Docket No.
ER02-2607-000 for a nominal period, made it effective subject to refund, set
certain issues for hearing, and directed the Utilities to make a compliance
filing. The compliance filing was submitted on December 23, 2002. This order
additionally established hearing procedures and consolidated the two dockets for
hearing. On March 11, 2003, all parties to these dockets reached a settlement in
principle regarding all issues. The settlement agreement is expected to be filed
with the FERC on or before May 2003.
58
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
See the Annual Report on Form 10-K of SPR, NPC, and SPPC for the year
ended December 31, 2002, Item 7A, Quantitative And Qualitative Disclosures About
Market Risk for disclosures about market risk. There have been no material
changes to the information previously disclosed in that report, except as
described in the following discussion.
CREDIT RISK
The Utilities monitor and manage credit risk with their trading
counterparties. As of March 31, 2003, the Utilities had outstanding transactions
with over 40 energy and financial services companies. The Utilities credit risk
associated with these transactions was approximately $25 million as of March 31,
2003.
ITEM 4. CONTROLS AND PROCEDURES
SPR, NPC, and SPPC maintain disclosure controls and procedures as
defined in Rules 13a-14(c) and 15d-14(c) under the Securities Exchange Act of
1934, as amended (the "Exchange Act") designed to ensure that they are able to
collect the information required to be disclosed in the reports they file with
the Securities and Exchange Commission (SEC), and to process, summarize and
disclose this information accurately and within the time periods specified in
the rules of the SEC. The chief executive officer and chief financial officer of
each of SPR, NPC, and SPPC have reviewed and evaluated SPR's, NPC's and SPPC's
disclosure controls and procedures as of a date within 90 days prior to the
filing date of this report (the "Evaluation Date"). Based on such evaluation,
such officers have concluded that, as of the Evaluation Date, the disclosure
controls and procedures of SPR, NPC, and SPPC are effective in bringing to their
attention on a timely basis material information relating to SPR, NPC, and SPPC
required to be included in periodic filings under the Exchange Act.
Since the Evaluation Date, there have not been any significant changes
in the internal controls of SPR, NPC, and SPPC, or in other factors that could
significantly affect these controls subsequent to the Evaluation Date.
59
PART II
ITEM 1. LEGAL PROCEEDINGS
Refer to Item 3 of SPR's, NPC's and SPPC's Annual Report on Form 10-K
for the year ended December 31, 2002, and Note 18 to SPR's consolidated
financial statements contained in that report and Note 11 to SPR's condensed
consolidated financial statements contained in this report for a description of
legal proceedings presently pending. Except as set forth below, there are no
additional material legal proceedings or material developments with respect to
previously reported proceedings involving SPR, NPC or SPPC.
SIERRA PACIFIC RESOURCES AND NEVADA POWER COMPANY
Lawsuit Against Merrill Lynch and Allegheny Energy, Inc.
On April 2, 2003, SPR and NPC filed a complaint in the U.S. District
Court for the District of Nevada against Merrill Lynch & Co., Inc. and Merrill
Lynch Capital Services, Inc. (collectively, "Merrill Lynch") and Allegheny
Energy, Inc., and Allegheny Energy Supply Company, LLC (collectively,
"Allegheny") seeking actual and punitive damages in excess of $850 million and
demanding a jury trial for all claims triable by jury. The complaint alleges
that the Merrill Lynch defendants engaged in misrepresentation, suppression and
concealment, breach of fiduciary duty, wrongful hiring and supervision of Daniel
Gordon, and breach of contract and alleges that both Merrill Lynch and Allegheny
engaged in intentional interference with contractual and prospective advantage,
conspiracy and racketeering (in violation of Nevada Revised Statutes Section
207.470). The complaint also alleges that the improper behavior of Merrill Lynch
and Allegheny was the direct and proximate cause of the March 2002 decision by
the PUCN to disallow $180 million of rate adjustments in NPC's 2001 deferred
energy accounting adjustment rate application.
Lawsuit Against Natural Gas Providers
On April 21, 2003, SPR and NPC filed a complaint in the U.S. District
Court for the District of Nevada against natural gas providers El Paso
Corporation, El Paso Natural Gas Company, El Paso Merchant Energy Company, El
Paso Tennessee Pipeline Company, El Paso Merchant Energy-Gas Company, Sempra
Energy, Southern California Gas Company, San Diego Gas and Electric Company,
Dynegy Holdings, Inc., Dynegy Energy Services, Inc., and Does 1-100, seeking
$600 million in total damages. The complaint alleges, among other things, that
as a result of the defendants' conspiracies and fraudulent behavior, SPR and NPC
were forced to enter into natural gas purchase contracts "at artificially high,
supracompetitive prices." The complaint further states that between 1996 and
2001, certain of the defendants and their subsidiaries conspired, in secret
meetings, to decrease competition by restricting the amount of pipeline capacity
and fuel available to NPC while other defendants decreased natural gas supplies
and drove up prices by illegally withholding pipeline capacity, maintained
control over output and prices by manipulating natural gas price indexes, and
harmed market competition and the plaintiffs by driving up prices and increasing
the volatility of natural gas supplies. SPR and NPC assert that the defendants
conspired to prevent the construction of new gas transportation capacity to
deliver gas to the southern Nevada area by preventing the planned expansion of
the Kern River Pipeline upon which NPC relies for its primary supply of natural
gas for its generation facilities. The complaint also alleges that certain of
the defendants "systematically misrepresented the price and volume of their
trades" to key trade publications, creating the appearance of supply volatility
and escalating prices starting in 2000 and continuing through the beginning of
2002. SPR and NPC assert claims for fraud, violation of Nevada's RICO Act and
conspiracy to violate Nevada's RICO Act, compensatory damages, treble damages,
punitive damages, legal fees, interest and other such relief deemed just and
proper by the court.
NEVADA POWER COMPANY AND SIERRA PACIFIC POWER COMPANY
Enron Litigation
Hearings were held on April 3, 2003, in the Bankruptcy Court for the
Southern District of New York, in the lawsuit filed by Enron against NPC and
SPPC for liquidated damages in the amount of approximately $216 million and $87
million, respectively, related to its termination of its power supply agreement
with NPC and SPPC and for power previously delivered to the Utilities. The
Bankruptcy Court heard arguments regarding Enron's motion to dismiss the
Utilities' counterclaims against Enron for unspecified damages to be determined
during the case. The Utilities' counterclaims seek damages for acts and
omissions of Enron in manipulating the power markets, wrongful termination of
its transactions with the Utilities, and fraudulent inducement to enter into
transactions with Enron, among other issues. The Court has not ruled on this
matter nor has it indicated when a decision on this matter can be expected. The
Utilities continue to participate in non-binding court-ordered mediation
proceedings along with all of Enron's other terminated purchased power
counterparties. For more information regarding the Enron litigation, please see
Note 11 to SPR's condensed consolidated financial statements contained in this
report and Item 3 - Legal Proceedings in SPR's, NPC's and SPPC's Annual Report
on Form 10-K for the year ended December 31, 2002.
60
NEVADA POWER COMPANY
Morgan Stanley Proceedings
In March 2003, the arbitrator overseeing the arbitration proceedings
initiated by Morgan Stanley Capital Group ("MSCG") regarding various power
supply contract terminated by MSCG in April 2002 dismissed MSCG's demand for
arbitration and agreed that the issues raised by MSCG were not calculation
issues subject to arbitration and that NPC's contract defenses were likewise not
arbitrable. For more information regarding the MSCG arbitration proceedings,
please see Note 11 to SPR's condensed consolidated financial statements
contained in this report and tem 3 - Legal Proceedings in SPR's, NPC's and
SPPC's Annual Report on Form 10-K for the year ended December 31, 2002. NPC has
since filed a complaint for declaratory relief in the U.S. District Court for
the District of Nevada asking the Court to declare that NPC is not liable for
any damages as a result of MSCG's termination of its power supply contracts.
MSCG has not yet answered or responded to the complaint; however, on April 17,
2003, MSCG filed a complaint against NPC at the FERC conceding that the issues
raised by NPC were litigable in court but asking the FERC to declare that under
the WSPP agreement NPC should post the $25 million in dispute as collateral
pending the outcome of the litigation. NPC is unable to predict the outcome of
these proceedings.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None
ITEM 5. OTHER INFORMATION
None
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits filed with this Form 10-Q:
SIERRA PACIFIC RESOURCES
Exhibit 4.1 Indenture dated as of February 14, 2003 between Sierra Pacific
Resources and The Bank of New York, as Trustee, in connection
with the issuance of 7.25% Convertible Notes due 2010.
Exhibit 4.2 Form of Sierra Pacific Resources' 7.25% Convertible Note due
2010.
NEVADA POWER COMPANY AND SIERRA PACIFIC POWER COMPANY
Exhibit 10.1 Western Systems Power Pool ("WSPP") Agreement effective February
1, 2003 between Nevada Power Company as a member of the WSPP,
Sierra Pacific Power Company as a member of the WSPP and the
other members of the WSPP.
SIERRA PACIFIC RESOURCES, NEVADA POWER COMPANY AND SIERRA PACIFIC POWER COMPANY
Exhibit 99.1 Certification Pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
Exhibit 99.2 Certification Pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
(b) Reports on Form 8-K:
Form 8-K dated January 16, 2003, filed by SPR- Item 5, Other Events
Disclosed SPR agreements to acquire $8,750,000 aggregate principal
amount of its Floating Rate Notes due April 20, 2003 in exchange for 1,295,211
shares of its common stock in two privately-negotiated transactions.
Form 8-K dated February 3, 2003, filed by SPR - Item 5, Other Events
Disclosed, and included as an exhibit, SPR's press release dated
February 3, 2003, announcing SPR reached agreements to exchange 30% of its
Premium Income Equity Securities ("PIES") for shares of its common stock, par
value
61
$1.00 per share. Under terms of the privately-negotiated agreements, with a
limited number of investors, the Company issued approximately 13.66 million
shares of common stock in exchange for a total of 2,095,650 PIES.
Form 8-K dated February 10, 2003, filed by SPR, NPC and SPPC - Item 5, Other
Events
Disclosed, and included as an exhibit, SPR's press release dated
Febraury 10, 2003, reporting financial results for the quarter ended December
31, 2002.
Form 8-K dated February 10, 2003, filed by SPR- Item 5, Other Events
Disclosed, and included as an exhibit, SPR's press release regarding an
offering of $250 million aggregate principal amounts of its convertible Notes
due 2010 under Rule 144A..
Form 8-K dated February 11, 2003, filed by SPR, NPC and SPPC - Item 5, Other
Events
Disclosed SPR's Preliminary Offering Memorandum for distribution to
potential purchasers. The long-term convertible debt issued in the form of 7.25%
Convertible Notes due 2010. Also disclosed as an exhibit were excerpts from the
Preliminary Offering Memorandum.
62
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrants have duly caused this report to be signed on their behalf by the
undersigned thereunto duly authorized.
SIERRA PACIFIC RESOURCES
-----------------------------
(Registrant)
Date: May 6, 2003 By: /s/ Richard K. Atkinson
-----------------------------
Richard K. Atkinson
Vice President
Chief Financial Officer
(Principal Financial Officer)
Date: May 6, 2003 By: /s/ John E. Brown
------------------------------
John E. Brown
Vice President
Controller
(Principal Accounting Officer)
NEVADA POWER COMPANY
------------------------------
(Registrant)
Date: May 6, 2003 By: /s/ Richard K. Atkinson
------------------------------
Richard K. Atkinson
Vice President
Chief Financial Officer
(Principal Financial Officer)
Date: May 6, 2003 By: /s/ John E. Brown
------------------------------
John E. Brown
Vice President
Controller
(Principal Accounting Officer)
SIERRA PACIFIC POWER COMPANY
------------------------------
(Registrant)
Date: May 6, 2003 By: /s/ Richard K. Atkinson
------------------------------
Richard K. Atkinson
Vice President
Chief Financial Officer
(Principal Financial Officer)
Date: May 6, 2003 By: /s/ John E. Brown
-----------------------------
John E. Brown
Vice President
Controller
(Principal Accounting Officer)
63
QUARTERLY CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER REQUIRED BY SECTION
302(A) OF THE SARBANES-OXLEY ACT OF 2002
I, Walter M. Higgins III, certify that:
1. I have reviewed this quarterly report of Sierra Pacific Resources,
Nevada Power Company and Sierra Pacific Power Company on Form 10-Q for
the period ending March 31, 2003;
2. Based on my knowledge, the combined quarterly report does not contain
any untrue statement of a material fact or omit to state a material
fact necessary to make the statements made, in light of the
circumstances under which such statements were made, not misleading
with respect to the period covered by this quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrants as of, and for, the periods presented in
this quarterly report;
4. The chief financial officer and I are responsible for establishing and
maintaining disclosure controls and procedures (as defined in Exchange
Act Rules 13a-14 and 15d-14) for the registrants and we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrants, including their
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this
quarterly report is being prepared;
b) evaluated the effectiveness of the registrants' disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;
5. The chief financial officer and I have disclosed, based on our most
recent evaluation, to the registrants' auditors and the audit committee
of registrants' board of directors:
a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrants'
ability to record, process, summarize and report financial data
and have identified for the registrants' auditors any material
weaknesses in internal controls; and
64
b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrants'
internal controls; and
6. The chief financial officer and I have indicated in this quarterly
report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant
deficiencies and material weaknesses.
May 5, 2003
/s/ Walter M. Higgins III
-------------------------------------
Walter M. Higgins III
Chief Executive Officer
65
QUARTERLY CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER REQUIRED BY SECTION
302(A) OF THE SARBANES-OXLEY ACT OF 2002
I, Richard K. Atkinson, certify that:
1. I have reviewed this quarterly report of Sierra Pacific Resources,
Nevada Power Company and Sierra Pacific Power Company on Form 10-Q for
the period ending March 31, 2003;
2. Based on my knowledge, the combined quarterly report does not contain
any untrue statement of a material fact or omit to state a material
fact necessary to make the statements made, in light of the
circumstances under which such statements were made, not misleading
with respect to the period covered by this quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrants as of, and for, the periods presented in
this quarterly report;
4. The chief executive officer and I are responsible for establishing and
maintaining disclosure controls and procedures (as defined in Exchange
Act Rules 13a-14 and 15d-14) for the registrants and we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrants, including their
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this
quarterly report is being prepared;
b) evaluated the effectiveness of the registrants' disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;
5. The chief executive officer and I have disclosed, based on our most
recent evaluation, to the registrants' auditors and the audit committee
of registrants' board of directors:
a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrants'
ability to record, process, summarize and report financial data
and have identified for the registrants' auditors any material
weaknesses in internal controls; and
66
b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrants'
internal controls; and
6. The chief executive officer and I have indicated in this quarterly
report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant
deficiencies and material weaknesses.
May 5, 2003
/s/ Richard K. Atkinson
Richard K. Atkinson
Chief Financial Officer
67