<PAGE>
================================================================================
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE
ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2000
OR
[_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM TO
<TABLE>
<CAPTION>
Registrant, State of Incorporation, Address of
Commission File Principal Executive Offices and Telephone I.R.S. employer
Number Number Identification Number
<S> <C> <C>
1-8788 SIERRA PACIFIC RESOURCES 88-0198358
P.O. Box 10100
(6100 Neil Road)
Reno, Nevada 89520-0400 (89511)
(775) 834-4011
1-4698 NEVADA POWER COMPANY 88-0045330
6226 West Sahara Avenue
Las Vegas, Nevada 89146
(702) 367-5000
0-508 SIERRA PACIFIC POWER COMPANY 88-0044418
P.O. Box 10100
(6100 Neil Road)
Reno, Nevada 89520-0400 (89511)
(775) 834-4011
</TABLE>
Indicate by check mark whether registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes X No ___
-----
Indicate the number of shares outstanding of each of the issuer's classes of
Common Stock, as of the latest practicable date.
Class Outstanding at November 3, 2000
Common Stock, $1.00 par value 78,450,966 Shares
of Sierra Pacific Resources
Sierra Pacific Resources is the sole holder of the 1,000 shares of outstanding
Common Stock, $1.00 stated value, of Nevada Power Company.
Sierra Pacific Resources is the sole holder of the 1,000 shares of outstanding
Common Stock, $1.00 stated value, of Sierra Pacific Power Company.
This combined Quarterly Report on Form 10-Q is separately filed by Sierra
Pacific Resources, Nevada Power Company and Sierra Pacific Power Company.
Information contained in this document relating to Nevada Power Company is filed
by Sierra Pacific Resources and separately by Nevada Power Company on its own
behalf. Nevada Power Company makes no representation as to information relating
to Sierra Pacific Resources or its subsidiaries, except as it may relate to
Nevada Power Company. Information contained in this document relating to Sierra
Pacific Power Company is filed by Sierra Pacific Resources and separately by
Sierra Pacific Power Company on its own behalf. Sierra Pacific Power Company
makes no representation as to information relating to Sierra Pacific Resources
or its subsidiaries, except as it may relate to Sierra Pacific Power Company.
================================================================================
<PAGE>
SIERRA PACIFIC RESOURCES
NEVADA POWER COMPANY
SIERRA PACIFIC POWER COMPANY
QUARTERLY REPORTS ON FORM 10-Q
FOR THE QUARTER ENDED SEPTEMBER 30, 2000
CONTENTS
PART I - FINANCIAL INFORMATION
------------------------------
<TABLE>
<S> <C>
ITEM 1. Financial Statements
Sierra Pacific Resources-
Condensed Consolidated Balance Sheets-September 30, 2000 and
December 31, 1999................................................. 2
Condensed Consolidated Statements of Income-Three Months and Nine
Months Ended September 30, 2000 and 1999......................... 3
Condensed Consolidated Statements of Cash Flows-Nine Months Ended
September 30, 2000 and 1999...................................... 4
Nevada Power Company-
Condensed Balance Sheets - September 30, 2000 and December 31,
1999.............................................................. 5
Condensed Statements of Income - Three and Nine Months Ended
September 30, 2000 and 1999....................................... 6
Condensed Statements of Cash Flows - Nine Months Ended September 30,
2000 and 1999...................................................... 7
Sierra Pacific Power Company-
Condensed Consolidated Balance Sheets - September 30, 2000 and
December 31, 1999................................................. 8
Condensed Consolidated Statements of Income - Three Months and Nine
Months Ended September 30, 2000 and 1999.......................... 9
Condensed Consolidated Statements of Cash Flows - Nine Months Ended
September 30, 2000 and 1999...................................... 10
Notes to Condensed Consolidated Financial Statements ....................... 11
ITEM 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations............................................ 21
Sierra Pacific Resources Results of Operations................... 24
Nevada Power Company Results of Operations ...................... 27
Sierra Pacific Power Company Results of Operations .............. 32
ITEM 3. Quantitative and Qualitative Disclosures about Market Risk........... 42
PART II-OTHER INFORMATION
---------------------------
ITEM 1. Legal Proceedings.................................................... 43
ITEM 4. Submission of Matters to a Vote of Security Holders.................. 44
ITEM 5. Other Information.................................................... 44
ITEM 6. Exhibits and Reports on Form 8-K..................................... 44
Signature Page................................................................. 45
</TABLE>
1
<PAGE>
SIERRA PACIFIC RESOURCES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
<TABLE>
<CAPTION>
September 30, December 31,
2000 1999
------------------ ---------------
(Unaudited)
<S> <C> <C>
ASSETS
Utility Plant at Original Cost:
Plant in service $ 5,189,875 $ 5,028,204
Less: accumulated provision for depreciation 1,607,945 1,490,600
------------ -----------
3,581,930 3,537,604
Construction work-in-progress 342,004 278,530
------------ -----------
3,923,934 3,816,134
------------ -----------
Investments in subsidiaries and other property, net 132,838 105,880
------------ -----------
Current Assets:
Cash and cash equivalents 16,741 4,789
Accounts receivable less provision for uncollectible accounts:
2000-$4,771; 1999-$6,475 416,536 213,452
Materials, supplies and fuel, at average cost 86,113 73,193
Deferred energy costs 900 14,884
Other 52,140 7,003
------------ -----------
572,430 313,321
------------ -----------
Deferred Charges:
Goodwill, net of amortization 321,515 327,725
Regulatory tax asset 192,685 192,685
Other regulatory assets 109,993 98,641
Other 123,868 122,677
------------ -----------
748,061 741,728
------------ -----------
Net assets of discontinued operations (Note 9) 260,384 258,574
------------ -----------
$ 5,637,647 $ 5,235,637
============ ===========
CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholders' equity $ 1,397,982 $ 1,477,129
Preferred stock 50,000 50,000
SPPC/ NVP obligated mandatorily redeemable preferred trust securities 237,372 237,372
Long-term debt 2,150,494 1,556,627
------------ -----------
3,835,848 3,321,128
------------ -----------
Current Liabilities:
Short-term borrowings 205,175 754,979
Current maturities of long-term debt 455,986 202,709
Accounts payable 272,613 138,448
Accrued interest 43,183 15,394
Dividends declared 19,918 20,850
Accrued salaries and benefits 21,203 15,410
Deferred taxes on deferred energy costs - 5,683
Other current liabilities 17,185 29,773
------------ -----------
1,035,263 1,183,246
------------ -----------
Commitments & Contingencies (Note 10)
Deferred Credits:
Deferred federal income taxes 415,096 405,594
Deferred investment tax credit 57,285 62,604
Regulatory tax liability 48,391 49,160
Customer advances for construction 111,408 109,422
Accrued retirement benefits 81,825 67,314
Other 52,531 37,169
------------ -----------
766,536 731,263
------------ -----------
$ 5,637,647 $ 5,235,637
============ ===========
</TABLE>
The accompanying notes are an integral part of the financial statements.
2
<PAGE>
SIERRA PACIFIC RESOURCES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Dollars in Thousands, Except Per Share Amounts)
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
--------------------- --------------------
2000 1999 2000 1999
------- ------- ------- ------
(Unaudited) (Unaudited)
<S> <C> <C> <C> <C>
OPERATING REVENUES:
Electric $ 852,730 $ 455,617 $ 1,662,592 $ 875,987
Gas 12,967 8,716 64,278 8,716
Other 2,657 2,713 9,165 2,713
--------- --------- ---------- ---------
868,354 467,046 1,736,035 887,416
--------- --------- ---------- ---------
OPERATING EXPENSES:
Operation:
Purchased Power 581,994 136,488 911,773 274,129
Fuel for power generation 151,567 69,697 317,594 135,725
Gas purchased for resale 6,989 6,114 41,310 6,114
Deferral of energy costs net 2,445 4,268 16,719 14,651
Other 56,421 63,305 183,310 130,596
Maintenance 12,288 14,929 40,194 44,158
Depreciation and amortization 39,079 32,340 116,754 71,871
Taxes:
Income taxes (14,056) 33,212 (17,310) 40,419
Other than income 11,465 8,782 31,611 19,971
--------- --------- ---------- ---------
848,192 369,135 1,641,955 737,632
--------- --------- ---------- ---------
OPERATING INCOME 20,162 97,911 94,080 149,784
--------- --------- ---------- ---------
OTHER INCOME:
Allowance for other funds used during construction 511 (1,119) 2,486 2,964
Other income (expense) - net 169 (165) 3,578 (1,328)
--------- --------- ---------- ---------
680 (1,284) 6,064 1,636
--------- --------- ---------- ---------
Total Income Before Interest Charges 20,842 96,627 100,144 151,420
--------- --------- ---------- ---------
INTEREST CHARGES:
Long term debt 36,227 22,033 89,337 53,499
Other 4,718 6,877 29,618 10,217
Allowance for borrowed funds used during construction and
capitalized interest (3,053) 317 (7,779) (3,518)
--------- --------- ---------- ---------
37,892 29,227 111,176 60,198
--------- --------- ---------- ---------
INCOME (LOSS) BEFORE SPPC/NVP OBLIGATED MANDATORILY
REDEEMABLE PREFERRED TRUST SECURITIES (17,050) 67,400 (11,032) 91,222
Preferred dividend requirements of SPPC/NVP obligated
mandatorily redeemable preferred trust securities (4,729) (4,421) (14,187) (12,008)
--------- --------- ---------- ---------
INCOME (LOSS) BEFORE PREFERRED STOCK DIVIDENDS (21,779) 62,979 (25,219) 79,214
Preferred stock dividend requirements of subsidiary (875) (833) (2,624) (917)
--------- --------- ---------- ---------
INCOME (LOSS) FROM CONTINUING OPERATIONS (22,654) 62,146 (27,843) 78,297
--------- --------- ---------- ---------
DISCONTINUED OPERATIONS:
Income from operations of water business to be disposed of
(net of income taxes of $3,800 and $5,254 in 2000, and
$733 and $733 in 1999, respectively) 3,106 2,554 6,282 2,554
--------- --------- ---------- ---------
NET INCOME (LOSS) $ (19,548) $ 64,700 $ (21,561) $ 80,851
========= ========= ========== =========
Income (loss) per share - Basic
Income (loss) from continuing operations $ (0.29) $ 0.89 $ (0.35) $ 1.37
Income from discontinued operations 0.04 0.04 0.08 0.04
--------- --------- ---------- ---------
Net income (loss) $ (0.25) $ 0.93 $ (0.27) $ 1.41
========= ========= ========== =========
Income (loss) per share - Diluted
Income (loss) from continuing operations $ (0.29) $ 0.89 $ (0.35) $ 1.37
Income from discontinued operations 0.04 0.04 0.08 0.04
--------- --------- ---------- ---------
Net income (loss) $ (0.25) $ 0.93 $ (0.27) $ 1.41
========= ========= ========== =========
Weighted Average Shares of Common Stock Outstanding (000's) 78,446 69,365 78,428 57,298
========= ========= ========== =========
Dividends Paid Per Share of Common Stock $ 0.250 $ 0.250 $ 0.750 $ 0.750
========= ========= ========== =========
</TABLE>
The accompanying notes are an integral part of the financial statements.
3
<PAGE>
SIERRA PACIFIC RESOURCES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
<TABLE>
<CAPTION>
Nine Months Ended
September 30,
----------------------------
2000 1999
-------- --------
(Unaudited)
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Income before preferred dividends from continuing operations $(25,219) $ 79,214
Income before preferred dividends from discontinued operations 6,583 2,642
Non cash items included in income:
Depreciation and amortization 122,269 73,156
Deferred taxes and deferred investment tax credit (1,444) 9,885
AFUDC and capitalized interest (10,567) (6,540)
Deferred energy costs 13,984 -
Early retirement and severance amortization 3,147 699
Other non cash (310) 12,547
Changes in certain assets and liabilities, net of acquisition:
Materials, supplies and fuel (12,830) (23,239)
Accounts receivable (203,084) (47,555)
Other current assets (45,161) (11,293)
Accounts payable 134,165 12,526
Other current liabilities 15,311 34,588
Other-net 37,499 (16,504)
---------- ---------
Net Cash Flows From Operating Activities 34,343 120,126
---------- ---------
CASH FLOWS USED IN INVESTING ACTIVITIES:
Acquisition of business, net of cash acquired - (448,311)
Additions to utility plant (241,221) (195,430)
Non cash charges to utility plant 3,573 -
Contributions in aid of construction 11,687 -
Customer refunds for construction 1,985 10,424
---------- ---------
Net cash used for utility plant (223,976) (633,317)
---------- ---------
Investments in subsidiaries and other property - net (26,958) (1,036)
---------- ---------
Net Cash Used In Investing Activities (250,934) (634,353)
---------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Increase (decrease) in short-term borrowings (553,766) 411,025
Proceeds from issuance of long-term debt 1,050,000 230,303
Retirement of long-term debt and preferred stock (202,778) (53,296)
Sale of common stock 37 -
Dividends paid (64,950) (46,780)
---------- ---------
Net Cash Provided By Financing Activities 228,543 541,252
---------- ---------
Net increase in Cash and Cash Equivalents 11,952 27,025
Beginning balance in Cash and Cash Equivalents 4,789 1,770
---------- ---------
Ending balance in Cash and Cash Equivalents $ 16,741 $ 28,795
========== =========
Supplemental Disclosures of Cash Flow Information:
Cash Paid During Period For:
Interest $ 99,741 $ 65,458
Income Taxes $ 12,730 $ 17,219
</TABLE>
The accompanying notes are an integral part of the financial statements
4
<PAGE>
NEVADA POWER COMPANY
CONDENSED BALANCE SHEETS
(Dollars in Thousands)
<TABLE>
<CAPTION>
September 30, December 31,
2000 1999
------------ ------------
(Unaudited)
<S> <C> <C>
ASSETS
Utility Plant at Original Cost:
Plant in service $ 3,042,565 $ 2,928,973
Less: accumulated provision for depreciation 838,531 772,003
----------- -----------
2,204,034 2,156,970
Construction work in progress 225,767 195,671
----------- -----------
2,429,801 2,352,641
----------- -----------
Investments in Sierra Pacific Resources (Note 2) 529,934 654,156
Investments in subsidiaries and other property, net 13,939 15,644
----------- -----------
543,873 669,800
----------- -----------
Current Assets:
Cash and cash equivalents 4,669 243
Accounts receivable less provision for uncollectible accounts:
2000-$3,512; 1999-$2,826 258,872 110,955
Materials, supplies and fuel, at average cost 43,984 43,108
Deferred energy costs - 14,884
Other 20,814 3,573
----------- -----------
328,339 172,763
----------- -----------
Deferred Charges:
Regulatory tax asset 130,834 130,833
Other regulatory assets 30,818 28,190
Other 22,483 24,258
----------- -----------
184,135 183,281
----------- -----------
$ 3,486,148 $ 3,378,485
=========== ===========
CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholders' equity including $529,934-2000; $654,156-1999
of equity in Sierra Pacific Resources (Note 2) $ 1,397,982 $ 1,477,129
NVP obligated mandatorily redeemable preferred trust securities 188,872 188,872
Long-term debt 927,118 931,004
----------- -----------
2,513,972 2,597,005
----------- -----------
Current Liabilities:
Short-term borrowings 123,063 182,000
Current maturities of long-term debt 253,369 89,842
Accounts payable 147,303 75,088
Accrued interest 18,603 10,098
Dividends declared 16,086 24,126
Accrued salaries and benefits 8,733 7,025
Deferred taxes on deferred energy costs - 5,683
Other current liabilities 15,634 18,536
----------- -----------
582,791 412,398
----------- -----------
Commitments & Contingencies (Note 10)
Deferred Credits:
Deferred federal income taxes 237,319 236,139
Deferred investment tax credit 25,528 26,624
Regulatory tax liability 14,060 14,993
Customer advances for construction 68,116 69,341
Accrued retirement benefits 29,661 18,262
Other 14,701 3,723
----------- -----------
389,385 369,082
----------- -----------
$ 3,486,148 $ 3,378,485
=========== ===========
</TABLE>
The accompanying notes are an integral part of the financial statements.
5
<PAGE>
NEVADA POWER COMPANY
CONDENSED STATEMENTS OF INCOME
(Dollars in Thousands, Except Per Share Amounts)
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
--------------------------- -------------------------
2000 1999 2000 1999
--------- -------- -------- -------
(Unaudited) (Unaudited) (Unaudited) (Unaudited)
<S> <C> <C> <C> <C>
OPERATING REVENUES:
Electric $ 547,395 $ 349,878 $ 1,022,815 $ 770,248
OPERATING EXPENSES:
Operation:
Purchased power 385,129 101,070 593,479 238,711
Fuel for power generation 86,140 47,780 178,809 113,808
Deferral of energy costs-net 2,445 4,268 16,719 14,651
Other 33,638 43,952 97,923 111,243
Maintenance 8,126 11,513 27,210 40,740
Depreciation and amortization 21,391 20,613 64,121 60,144
Taxes:
Income taxes (5,642) 33,190 (12,461) 40,397
Other than income 6,542 5,626 17,860 16,815
--------- --------- ----------- ---------
537,769 268,012 983,660 636,509
--------- --------- ----------- ---------
OPERATING INCOME 9,626 81,866 39,155 133,739
--------- --------- ----------- ---------
OTHER INCOME:
Equity in earnings of Sierra Pacific Resources (Note 2) (10,766) 1,812 (2,944) 1,812
Allowance for other funds used during construction 430 1,330 2,272 5,413
Other income (expense) - net 1,307 (42) 2,014 (1,205)
--------- --------- ----------- ---------
(9,029) 3,100 1,342 6,020
--------- --------- ----------- ---------
Total Income Before Interest Charges 597 84,966 40,497 139,759
--------- --------- ----------- ---------
INTEREST CHARGES:
Long term debt 15,980 16,778 46,132 48,244
Other 2,745 1,175 10,677 4,515
Allowance for borrowed funds used during construction and
capitalized interest (2,373) (1,491) (6,130) (5,326)
--------- --------- ----------- ---------
16,352 16,462 50,679 47,433
--------- --------- ----------- ---------
INCOME (LOSS) BEFORE NVP OBLIGATED MANDATORILY
REDEEMABLE PREFERRED TRUST SECURITIES (15,755) 68,504 (10,182) 92,326
Preferred dividend requirements of NVP obligated
mandatorily redeemable preferred trust securities (3,793) (3,793) (11,379) (11,380)
--------- --------- ----------- ---------
INCOME (LOSS) BEFORE PREFERRED STOCK DIVIDENDS (19,548) 64,711 (21,561) 80,946
Preferred stock dividend requirements - (11) - (95)
--------- --------- ----------- ---------
NET INCOME (LOSS) $ (19,548) $ 64,700 $ (21,561) $ 80,851
========= ========= =========== =========
Net Income (Loss) Per Share -Basic $ (0.25) $ 0.93 $ (0.27) $ 1.41
========= ========= =========== =========
-Diluted $ (0.25) $ 0.93 $ (0.27) $ 1.41
========= ========= =========== =========
Weighted Average Shares of Common
Stock Outstanding (000's) 78,446 69,365 78,428 57,298
========= ========= =========== =========
Dividends Paid Per Share of Common Stock $ 0.250 $ 0.250 $ 0.750 $ 0.750
========= ========= =========== =========
</TABLE>
The accompanying notes are an integral part of the financial statements.
6
<PAGE>
NEVADA POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
<TABLE>
<CAPTION>
Nine Months Ended
September 30,
-----------------------------
2000 1999
--------- ---------
(Unaudited
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Income (loss) before preferred dividends $ (21,561) $ 80,946
Non cash items included in income:
Depreciation and amortization 64,121 60,143
Deferred taxes and deferred investment tax credit (5,597) 6,950
AFUDC and capitalized interest (8,402) (10,740)
Deferred energy costs 14,884 (23,239)
Other non cash (2,961) 8,080
Equity in earnings of SPR (Note 2) 2,944 (1,812)
Changes in certain assets and liabilities, net of acquisition:
Materials, supplies and fuel (876) (4,247)
Accounts receivable (147,917) (61,246)
Other current assets (17,265) (2,482)
Accounts payable 72,215 10,545
Other current liabilities 7,311 37,660
Other net 21,150 (9,252)
--------- --------
Net Cash Flows From Operating Activities (21,954) 91,306
--------- --------
CASH FLOWS USED IN INVESTING ACTIVITIES:
Additions to utility plant (138,698) (171,372)
Non cash charges to utility plant 1,349 4,918
Customer refunds for construction (1,225) 4,828
--------- --------
Net cash used for utility plant (138,574) (161,626)
--------- --------
Investments in subsidiaries and other property-net 250 (2,311)
--------- --------
Net Cash Used In Investing Activities (138,324) (163,937)
--------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Increase (decrease) in short-term borrowings (58,937) 21,930
Proceeds from issuance of long-term debt 250,000 129,900
Retirement of long-term debt (90,359) (48,533)
Change in funds held in trust - -
Retirement of preferred stock - (3,265)
Additional investment of Parent 128,000 -
Dividends paid (64,000) (25,808)
--------- --------
Net Cash Provided By Financing Activities 164,704 74,224
--------- --------
Net increase in Cash and Cash Equivalents 4,426 1,593
Beginning balance in Cash and Cash Equivalents 243 1,770
--------- --------
Ending balance in Cash and Cash Equivalents $ 4,669 $ 3,363
========= ========
Supplemental Disclosures of Cash Flow Information:
Cash Paid During Period For:
Interest $ 48,303 $ 48,187
Income Taxes $ 6,500 $ 17,219
</TABLE>
The accompanying notes are an integral part of the financial statements.
7
<PAGE>
SIERRA PACIFIC POWER COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
<TABLE>
<CAPTION>
September 30, December 31,
2000 1999
------------- -----------
(Unaudited)
<S> <C> <C>
ASSETS
Utility Plant at Original Cost:
Plant in service $ 2,147,310 $ 2,097,533
Less: accumulated provision for depreciation 769,414 718,597
----------- ------------
1,377,896 1,378,936
Construction work-in-progress 116,236 82,859
----------- ------------
1,494,132 1,461,795
----------- ------------
Investments in subsidiaries and other property, net 60,832 62,704
----------- ------------
Current Assets:
Cash and cash equivalents 6,561 3,011
Accounts receivable less provision for uncollectible accounts:
2000 - $1,259; 1999 - $3,649 110,762 111,175
Materials, supplies and fuel, at average cost 41,885 29,642
Deferred energy costs 900 -
Other 19,789 3,103
----------- ------------
179,897 146,931
----------- ------------
Deferred Charges:
Regulatory tax asset 61,852 61,852
Other regulatory assets 66,551 67,059
Other 21,257 25,512
----------- ------------
149,660 154,423
----------- ------------
Net assets of discontinued operations (Note 9) 260,384 258,574
----------- ------------
$ 2,144,905 $ 2,084,427
=========== ============
CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholder's equity $ 646,177 $ 673,738
Preferred stock 50,000 50,000
SPPC obligated mandatorily redeemable preferred trust securities 48,500 48,500
Long-term debt 623,297 625,430
----------- ------------
1,367,974 1,397,668
----------- ------------
Current Liabilities:
Short-term borrowings 82,000 109,584
Current maturities of long-term debt 202,616 102,755
Accounts payable 93,688 78,491
Accrued interest 15,007 5,110
Dividends declared 16,000 19,974
Accrued salaries and benefits 11,794 8,385
Other current liabilities 4,045 10,673
----------- ------------
425,150 334,972
----------- ------------
Commitments & Contingencies (Note 10)
Deferred Credits:
Deferred federal income taxes 167,326 161,891
Deferred investment tax credit 31,756 35,980
Regulatory tax liability 34,331 34,167
Accrued retirement benefits 42,148 49,052
Customer advances for construction 43,292 40,081
Other 32,928 30,616
----------- ------------
351,781 351,787
----------- ------------
$ 2,144,905 $ 2,084,427
=========== ============
</TABLE>
The accompanying notes are an integral part of the financial statements.
8
<PAGE>
SIERRA PACIFIC POWER COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Dollars in Thousands)
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
--------------------------- ----------------------------
2000 1999 2000 1999
--------- ---------- ---------- ----------
(Unaudited) (Unaudited) (Unaudited) (Unaudited)
<S> <C> <C> <C> <C>
OPERATING REVENUES:
Electric $ 305,334 $ 163,564 $ 639,776 $ 455,497
Gas 12,967 13,056 64,278 69,934
--------- --------- --------- ---------
318,301 176,902 704,054 525,431
--------- --------- --------- ---------
OPERATING EXPENSES:
Operation:
Purchased power 196,865 52,564 318,294 135,343
Fuel for power generation 65,427 32,560 138,785 85,397
Gas purchased for resale 6,989 9,603 41,310 46,978
Other 18,608 24,060 68,328 67,974
Maintenance 4,162 5,523 12,984 15,233
Depreciation and amortization 17,561 17,410 52,144 52,193
Taxes:
Income taxes (4,591) 5,093 6,605 25,175
Other than income 4,711 4,618 13,352 12,902
--------- --------- --------- ---------
309,732 151,431 651,802 441,195
--------- --------- --------- ---------
OPERATING INCOME 8,569 25,471 52,252 84,236
--------- --------- --------- ---------
OTHER INCOME:
Allowance for other funds used during construction 81 (2,451) 215 (2,445)
Other income (expense) - net 117 (601) (1,122) (251)
--------- --------- --------- ---------
198 (3,052) (907) (2,696)
--------- --------- --------- ---------
Total Income 8,767 22,419 51,345 81,540
--------- --------- --------- ---------
INTEREST CHARGES:
Long - term debt 10,952 7,817 26,861 23,548
Other 1,348 2,004 8,519 6,712
Allowance for borrowed funds used during construction and
capitalized interest (680) 1,723 (1,649) 1,312
--------- --------- --------- ---------
11,620 11,544 33,731 31,572
--------- --------- --------- ---------
INCOME BEFORE SPPC OBLIGATED MANDATORILY
REDEEMABLE PREFERRED TRUST SECURITIES (2,853) 10,875 17,614 49,968
Preferred dividend requirements of SPPC obligated
mandatorily redeemable preferred trust securities (935) (942) (2,807) (2,807)
--------- --------- --------- ---------
INCOME BEFORE PREFERRED DIVIDENDS (3,788) 9,933 14,807 47,161
Preferred dividend requirements (875) (1,233) (2,624) (3,674)
--------- --------- --------- ---------
INCOME (LOSS) FROM CONTINUING OPERATIONS $ (4,663) $ 8,700 $ 12,183 $ 43,487
--------- --------- --------- ---------
DISCONTINUED OPERATIONS:
Income from operations of water business to be disposed
of (net of income taxes of $3,800 and $5,254 in 2000, and
$1,790 and $2,117 in 1999, respectively) 3,106 3,750 6,282 5,597
--------- --------- --------- ---------
NET INCOME (LOSS) $ (1,557) $ 12,450 $ 18,465 $ 49,084
========= ========= ========= =========
</TABLE>
The accompanying notes are an integral part of the financial
statements.
9
<PAGE>
SIERRA PACIFIC POWER COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
<TABLE>
<CAPTION>
Nine Months Ended
September 30,
-----------------------
2000 1999
------- -------
(Unaudited)
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Income before preferred dividends from continuing operations $ 14,807 $ 47,161
Income before preferred dividends from discontinued operations 6,583 6,017
Non cash items included in income:
Depreciation and amortization 57,659 57,927
Deferred taxes and deferred investment tax credit 4,124 6,245
AFUDC and capitalized interest (2,166) 3,665
Deferred energy costs - net (900) -
Early retirement and severance amortization 3,147 3,145
Other non cash 2,650 5,934
Changes in certain assets and liabilities:
Accounts receivable 413 3,975
Materials, supplies and fuel (12,153) (4,645)
Other current assets (16,686) (2,670)
Accounts payable 15,197 1,893
Other current liabilities 6,678 (2,762)
Other - net (5,333) (19,459)
--------- --------
Net Cash Flows From Operating Activities 74,020 106,426
--------- --------
CASH FLOWS USED IN INVESTING ACTIVITIES:
Additions to utility plant (102,523) (95,487)
Non-cash charges to utility plant 2,224 -
Net customer refunds and contributions in aid construction 14,897 16,541
--------- --------
Net cash used for utility plant (85,402) (78,946)
(Investments in) disposal of subsidiaries and other property - net 1,597 (28,394)
--------- --------
Net Cash Used In Investing Activities (83,805) (107,340)
--------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Increase (decrease) in short-term borrowings (31,434) (41,703)
Proceeds from issuance of long-term debt 200,000 124,099
Reduction of long-term debt (102,307) (31,758)
Additional investment by parent company 14,000 16,000
Dividends paid (66,924) (61,096)
--------- --------
Net Cash Used In Financing Activities 13,335 5,542
--------- --------
Net (decrease) increase in Cash and Cash Equivalents 3,550 4,628
Beginning balance in Cash and Cash Equivalents 3,011 15,197
--------- --------
Ending balance in Cash and Cash Equivalents $ 6,561 $ 19,825
========= ========
Supplemental Disclosures of Cash Flow Information:
Cash Paid During Period For:
Interest $ 33,476 $ 34,779
Income Taxes $ 9,644 $ 23,757
</TABLE>
The accompanying notes are an integral part of the financial statements.
10
<PAGE>
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
----------------------------------------------------
NOTE 1. MANAGEMENT'S STATEMENT (SPR, NVP, SPPC)
--------------------------------
In the opinion of the management of Sierra Pacific Resources (SPR), Nevada
Power Company (NVP), and Sierra Pacific Power Company (SPPC), the accompanying
unaudited interim condensed consolidated financial statements contain all
adjustments (consisting of only normal recurring adjustments) necessary to
present fairly the condensed consolidated financial position, condensed
consolidated results of operations and condensed consolidated cash flows for the
periods shown. These condensed consolidated financial statements do not contain
the complete detail or footnote disclosure concerning accounting policies and
other matters which are included in full year financial statements and
therefore, they should be read in conjunction with the audited financial
statements included in SPR's, NVP's, and SPPC's Annual Reports on Form 10-K for
the year ended December 31, 1999.
The results of operations for the nine months ended September 30, 2000 are
not necessarily indicative of the results to be expected for the full year.
Principles of Consolidation
---------------------------
The condensed consolidated financial statements of SPR include the accounts
of SPR and its wholly owned subsidiaries, Nevada Power Company, Sierra Pacific
Power Company, Tuscarora Gas Pipeline Company, Sierra Gas Holding Company
(formerly Sierra Energy Company), Sierra Energy Company dba e three, Sierra
Pacific Energy Company, Lands of Sierra, Sierra Pacific Communications, Nevada
Electric Investment Company and Sierra Water Development Company. All
significant intercompany transactions and balances have been eliminated in
consolidation.
Reclassifications
-----------------
Certain items previously reported for years prior to 2000 have been
reclassified to conform to the current year's presentation. Net income and
shareholders' equity were not affected by these reclassifications.
NOTE 2. FINANCIAL STATEMENTS OF NEVADA POWER COMPANY (NVP)
------------------------------------------------------
As described in Note 3 that follows, NVP is deemed to be the acquirer of
SPR for accounting purposes as reflected in the SPR Consolidated Financial
Statements. However, after the merger with SPR and as a result of the structure
of the transactions, NVP is a separate legal entity, which is a wholly owned
subsidiary of SPR. As a legal matter, NVP does not own any equity interest in
SPR. The audited NVP Financial Statements accommodate the presentation of
financial information of NVP on a stand-alone basis by summarizing all non-NVP
financial information into a few items on each of the Financial Statements.
These summarized items are repeated below (in 000's):
Non-NVP Financial Items on the NVP Financial Statements
<TABLE>
<CAPTION>
NVP Balance Sheet: September 30, 2000 December 31, 1999
------------------ --------------------- -------------------
<S> <C> <C> <C>
Investment in Sierra Pacific Resources $529,934 $654,156
Equity in Sierra Pacific Resources $529,934 $654,156
</TABLE>
The Investment in Sierra Pacific Resources reflects the net assets, after
deducting for all liabilities and preferred stock of Sierra Pacific Resources
not related to NVP. The Equity in Sierra Pacific Resources reflects the sum of
paid-in-capital and retained earnings of SPR, without the benefit of NVP.
These line items are required by the rules of purchase accounting and do not
represent any asset to which holders of NVP's securities may look for recovery
of their investment. These items must be disregarded for determining the ability
of NVP to satisfy its obligations or to pay dividends (preferred or common), for
calculating NVP's ratios of earnings to fixed charges and preferred stock
dividends and for all of NVP's financial covenants and earnings tests including
those under its charter and mortgage.
11
<PAGE>
<TABLE>
<CAPTION>
NVP Income Statement: Three Months Ended Three Months Ended
-------------------- -------------------- --------------------
September 30, 2000 September 30, 1999
-------------------- --------------------
<S> <C> <C>
Equity in Earnings of Sierra Pacific Resources $(10,766) $1,812
Nine Months Ended Nine Months Ended
------------------- --------------------
September 30, 2000 September 30, 1999
------------------- --------------------
Equity in Earnings of Sierra Pacific Resources $ (2,944) $1,812
</TABLE>
The Equity in Earnings of Sierra Pacific Resources reflects three and nine
months, respectively, of SPR net income, after SPPC preferred stock dividends.
This line item is required by the rules of purchase accounting and does not
represent any item of revenue or income to which holders of NVP's securities may
look for recovery of their investment. This item must be disregarded for
determining the ability of NVP to satisfy its obligations or its ability to pay
dividends (preferred or common), for calculating NVP's ratios of earnings to
fixed charges and preferred dividends and for all of NVP's financial covenants
and earnings tests including those under its charter and mortgage.
<TABLE>
<CAPTION>
NVP Statement of Cash Flow: Nine Months Ended Nine Months Ended
--------------------------- --------------------- --------------------
September 30, 2000 September 30, 1999
--------------------- --------------------
<S> <C> <C>
Equity in Earnings of Sierra Pacific Resources $2,944 $(1,812)
</TABLE>
As in the income statement, the Equity in Earnings of Sierra Pacific
Resources reflects the nine months of SPR net income, after SPPC preferred stock
dividends.
This line item is required by the rules of purchase accounting and does not
represent any item of cash flow to which holders of NVP's securities may look
for recovery of their investment. This item must be disregarded for determining
the ability of NVP to satisfy its obligations or its ability to pay dividends
(preferred or common), for calculating NVP's ratios of earnings to fixed charges
and preferred dividends and for all of NVP's financial covenants and earnings
tests including those under its charter and mortgage.
NOTE 3. SIERRA PACIFIC RESOURCES AND NEVADA POWER COMPANY MERGER (SPR, NVP)
------------------------------------------------------------------
On July 28, 1999 the merger between SPR and NVP was consummated. The merger
was accounted for as a reverse purchase under generally accepted accounting
principles, with NVP considered the acquiring entity even though SPR is the
surviving legal entity. In addition, for accounting purposes the merger was
deemed to have occurred on August 1, 1999. As a result of this reverse purchase
accounting treatment: (i) the historical financial statements of SPR for periods
prior to the date of the merger are no longer the financial statements of SPR,
and therefore, are no longer presented; (ii) the historical financial statements
of SPR for periods prior to the date of the merger are those of NVP; and (iii)
SPR's Condensed Consolidated Statements of Income for the three- and nine-month
periods ended September 30, 1999 and SPR's Condensed Consolidated Statement of
Cash Flows for the nine months ended September 30, 1999 include the financial
results of SPR and its pre-merger subsidiaries for the months of August and
September 1999. SPPC's separate Condensed Consolidated Statements of Income for
the three- and nine-month periods ended September 30, 1999 and Condensed
Consolidated Statement of Cash Flows for the nine months ended September 30,
1999 include the financial results of SPPC for the periods indicated.
Through September 30, 2000, SPR incurred a total of $56.3 million in
capitalized costs since merger work began. The capitalized merger amounts
consist of $36.0 million of transaction and transition costs and $20.3 million
of employee separation costs. For more information regarding the capitalization
of merger costs, see Note 3 of "The Notes To Financial Statements" included in
SPR's Annual Report on Form 10-K for the year ended December 31, 1999.
Employee severance, relocation, and related costs for SPR were $15.8
million, of which $.9 million remains unpaid as of September 30, 2000. Other
costs incurred in connection with employee separations included pension and
postretirement benefits net of plan gains of $4.5 million.
In accordance with the terms of the merger, each outstanding share of SPR's
common stock was converted into the right to receive either $37.55 in cash or
1.44 shares of newly issued SPR common stock. Each outstanding share of NVP
common stock was converted to the right to receive either $26.00 in cash or 1.00
share of newly issued SPR common stock. 4,037,000 shares of SPR and 11,716,611
shares of NVP common stock were exchanged for $151.6 million and $304.6 million,
respectively. The remaining shares of each company were converted to newly
issued shares of SPR common stock. SPR
12
<PAGE>
stockholders and NVP stockholders received 38,866,054 and 39,548,506 shares,
respectively, of newly issued SPR common stock, resulting in 78,414,560
outstanding shares of SPR on August 1, 1999.
The total consideration paid to SPR common stockholders was equal to cash
of $151.6 million and 38,866,054 shares of newly issued SPR common stock at a
price of $24.18 per share based on the average closing price of NVP common stock
between April 22, 1998 and May 6, 1998. The eleven-day average price of NVP
common stock used in determining the total stock consideration represents the
market price over a reasonable period of time before and after the transaction
was announced on April 29, 1998. Goodwill of $331.2 million was recorded in
connection with the merger and is being amortized over 40 years. However, the
order of the Public Utilities Commission of Nevada (PUCN) approving the merger
allowed SPR to defer merger costs (including goodwill) allocable to the
regulated utilities for a three-year period. At the end of the deferral period
SPR will propose an amortization period for goodwill and other merger costs.
Accordingly, goodwill amortization associated with the regulated utility
companies is being reclassified to a regulatory asset during the three-year
period. Also, because SPR is deferring merger costs as regulatory assets the
transaction costs included in the calculation of goodwill represent only costs
allocable to SPR's non-regulated subsidiaries.
Pro forma unaudited financial information for SPR on a consolidated basis,
giving effect to the merger as if it had occurred at the beginning of all
periods, is presented below. The pro forma information below includes the
operating results and assets of SPPC's water business, as described in Note 9
below. This pro forma information is not necessarily indicative of the results
that would have occurred, or that will occur in the future.
<TABLE>
<CAPTION>
Three Months ended Nine Months ended
(Dollars and shares in thousands September 30, September 30,
------------------------- --------------------------
except per share amounts) 2000 1999 2000 1999
---------------------------------------------- ------------ --------- ------------ ----------
<S> <C> <C> <C> <C>
Operating Revenue $ 887,093 $548,431 $1,780,358 $1,346,311
Operating Income $ 26,431 $115,749 $ 108,742 $ 236,434
Income (Loss) Applicable to Common Stock $ (19,548) $ 70,686 $ (21,561) $ 113,511
Net Income (Loss) per share - basic and diluted $ (0.25) $ 0.90 $ (0.27) $ 1.45
Weighted Average Shares of Common
Stock Outstanding (000's) 78,446 78,415 78,428 78,415
Total Assets $5,648,341 $5,648,341
</TABLE>
NOTE 4. RECENT PRONOUNCEMENTS (SPR, NVP, SPPC)
-------------------------------
FINANCIAL ACCOUNTING STANDARDS BOARD
------------------------------------
In June 1998, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards (SFAS) 133, entitled "Accounting for
Derivative Instruments and Hedging Activities." This statement establishes
accounting and reporting standards for derivative instruments, including certain
derivative instruments embedded in other contracts (collectively referred to as
derivatives), and for hedging activities. It requires an entity to recognize all
derivatives as either assets or liabilities in the statement of financial
position, and measure those instruments at fair value. In May 1999, members of
the FASB agreed to delay the effective date of Statement 133 to fiscal years
beginning after June 15, 2000.
In June 2000, the FASB issued SFAS 138 that amended SFAS 133 in a number of
respects. Among other revisions, SFAS 138 exempted from the fair value
requirements normal purchases and normal sales (as defined by SFAS 133) that
contain settlement provisions, if it is probable that the contracts will not
settle net and will result in physical delivery.
SPR has evaluated the impact of SFAS 133 and SFAS 138 and considers all
derivative transactions identified to date to be either subject to the normal
purchases and normal sales exclusion or hedges of forecasted transactions. The
change in the fair value of the hedges will be reported on the balance sheet as
other comprehensive income on January 1, 2001 and could result in a $25-$35
million loss. This amount will be reclassified into earnings in the same period
in which the hedged forecasted transaction affects earnings.
Securities and Exchange Commission
----------------------------------
In December 1999, the Staff of the Securities and Exchange Commission
released Staff Accounting Bulletin (SAB) No. 101, which summarizes certain of
the staff's views in applying generally accepted accounting principles to
revenue
13
<PAGE>
recognition in financial statements. Subsequently, SAB No. 101A and SAB No. 101B
were released delaying the implementation date of SAB No. 101 until no later
than the fourth fiscal quarter of fiscal years beginning after December 15,
1999. SPR does not believe that the SAB will have a material effect on its
financial statements.
NOTE 5. SHORT-TERM BORROWINGS (SPR, NVP, SPPC)
-------------------------------
SPR's commercial paper balance increased from $463.4 million at December
31, 1999, to approximately $493.2 million at March 31, 2000. On September 30,
2000, SPR had no commercial paper outstanding, as a result of the issuance of
long-term debt. See Note 6 - Long-Term Debt (below).
NVP's commercial paper balance increased from $82.0 million at December 31,
1999, to approximately $95.3 million at March 31, 2000. On June 30, 2000, NVP
had no commercial paper outstanding, but, as the result of the issuance of new
commercial paper in the third quarter, had approximately $123.1 million of
commercial paper outstanding at an average rate of 6.83% at September 30, 2000.
See Note 6 - Long-Term Debt (below).
SPPC's commercial paper balance decreased from $109.6 million at December
31, 1999, to approximately $101.8 million at March 31, 2000. On June 30, 2000,
SPPC had no commercial paper outstanding, but, as the result of the issuance of
new commercial paper in the third quarter, had $82.0 million of commercial paper
outstanding at an average rate of 6.83% at September 30, 2000. See Note 6 -Long-
Term Debt (below).
NOTE 6. LONG-TERM DEBT (SPR, NVP, SPPC)
------------------------
Sierra Pacific Resources
------------------------
On March 31, 2000, $10 million of SPR's Series E senior notes matured.
On April 20, 2000, SPR issued an aggregate of $300 million floating rate
notes, $200 million of which matures on April 20, 2003 and the remaining $100
million of which matures on April 20, 2002. Interest on the notes is payable
quarterly. The interest rate on the notes for each interest period is a floating
rate, subject to adjustment every three months, equal to the London InterBank
Offered Rate (LIBOR) for three-month U.S. dollar deposits plus a spread of 0.60%
for the notes maturing in 2003 and a spread of 0.65% for the notes maturing in
2002. These notes are not entitled to any sinking fund. The notes due 2002 will
be redeemable, in whole, without premium at the option of SPR beginning on April
20, 2001 and on each interest payment date thereafter. The net proceeds of the
$200 million issue were used to retire an equal amount of commercial paper of
SPR that was used as temporary funding for the cash portion of the NVP merger
consideration. The net proceeds of the $100 million issue were used to make a
capital contribution to NVP, which in turn was used to retire $85 million of
NVP's maturing First Mortgage Bonds on May 1, 2000 and the remaining proceeds
were used to pay off its commercial paper outstanding. On September 26, 2000,
SPR entered into a forward swap relating to its $200 million floating rate notes
that will mature on April 20, 2003, effectively locking in a LIBOR rate of
6.655%, which will result in an interest rate of 7.255% on the notes until their
maturity. This transaction became effective on October 20, 2000.
On April 20, 2000, upon issuance of these floating rate notes, SPR reduced
its bank credit facility to $300 million from the previous amount of $500
million in accordance with the terms of the credit agreement. On June 21, 2000,
SPR further reduced its credit facility to $150 million. The remaining $150
million credit facility was a 3-year credit facility, which has since been
terminated by SPR effective August 11, 2000.
On May 9, 2000, SPR issued $300 million of notes under its universal shelf
registration. These notes bear interest at an annual rate of 8.75% and will
mature on May 15, 2005. Interest on the notes is payable semi-annually. The
notes are not subject to any sinking fund and are redeemable in whole or in part
at any time upon payment of the principal amount of the notes being redeemed,
plus accrued interest and a make-whole premium. The net proceeds from the
issuance of these notes were used to retire an equal amount of commercial paper
of SPR.
14
<PAGE>
Nevada Power Company
--------------------
On June 9, 2000, NVP issued $150 million of floating rate notes that will
mature on June 12, 2001. Interest on the notes is payable quarterly. The
interest rate on the notes for each interest period is a floating rate, subject
to adjustment every three months, equal to the London InterBank Offered Rate
(LIBOR) for three-month U.S. dollar deposits plus a spread of 0.55%. These notes
are not entitled to any sinking fund and are non-callable. The net proceeds of
the $150 million issue were used to redeem $100 million of floating rate notes
on July 14, 2000, and the remaining proceeds were used to reduce NVP's
commercial paper outstanding.
On June 22, 2000, Clark County, Nevada issued for NVP's benefit $100
million Industrial Development Refunding Revenue Bonds, Series 2000A, due June
1, 2020. The interest rate is currently being determined by a Dutch Auction
based on an auction period of seven days. The Series A bonds were issued to
refund $100 million of Clark County's 7.80% Industrial Development Revenue Bonds
Series 1990 on June 30, 2000.
On July 28, 2000, Clark County, Nevada issued for NVP's benefit $15 million
Pollution Control Refunding Revenue Bonds, Series 2000B, due October 1, 2009.
The interest rate is currently being determined by a Dutch Auction based on an
auction period of seven days. The Series B bonds were issued to refund a like
principal amount of Clark County's 7.80% Pollution Control Revenue Bonds Series
1989 on October 2, 2000.
The method of determining the interest rate on the Series A and Series B
Bonds may be converted from time to time in accordance with the related
Indenture so that such bonds would, thereafter, bear interest at a daily,
weekly, flexible, term or auction rate. Both Series A and Series B Bonds are
insured by AMBAC Assurance Corporation.
On July 24, 2000, NVP received a 30-day extension on its $150 million
Credit Facility to August 28, 2000, in accordance with the terms of the credit
agreement. On August 28, 2000, NVP received a 364-day extension of this facility
to August 27, 2001.
On August 18, 2000, NVP issued $100 million of floating rate notes that
will mature on August 20, 2001. Interest on the notes is payable quarterly
commencing on November 18, 2000. The interest rate on the notes for each
interest period is a floating rate, subject to adjustment every three months,
equal to the London InterBank Offered Rate (LIBOR) for three-month U.S. dollar
deposits plus a spread of 0.58%. These notes are not entitled to any sinking
fund. The notes are redeemable at the option of NVP in whole or in part from
time to time, without premium, beginning on February 18, 2001. The net proceeds
of the $100 million issue were used to reduce NVP's commercial paper
outstanding.
Sierra Pacific Power Company
----------------------------
On June 9, 2000, SPPC issued $200 million of floating rate notes that will
mature on June 12, 2001. Interest on the notes is payable quarterly. The
interest rate on the notes for each interest period is a floating rate, subject
to adjustment every three months, equal to the London InterBank Offered Rate
(LIBOR) for three-month U.S. dollar deposits plus a spread of 0.50%. These notes
are not entitled to any sinking fund and are non-callable. The net proceeds of
the $200 million issue were used to redeem $100 million of floating rate notes
on July 14, 2000, and the remaining proceeds were used to reduce the amount of
SPPC's commercial paper outstanding.
On July 24, 2000, SPPC received a 30-day extension of its $150 million
Credit Facility to August 28, 2000, in accordance with the terms of the credit
agreement. On August 28, 2000, SPPC received a 364-day extension of this
facility to August 27, 2001.
15
<PAGE>
NOTE 7. EARNINGS PER SHARE (SPR)
------- ------------------
SPR follows SFAS No. 128, "Earnings Per Share". The difference between
Basic EPS and Diluted EPS is due to common stock equivalent shares resulting
from stock options, employee stock purchase plan, performance shares and a non-
employee director stock plan. Common stock equivalents were determined using the
treasury stock method.
The following provides a reconciliation of Basic EPS and Diluted EPS.
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
--------------------------- ---------------------------
2000 1999 2000 1999
----------- ----------- ----------- -----------
<S> <C> <C> <C> <C>
Basic Eps
Numerator
Income (loss) from continuing operations ($000) $ (22,654) $ 62,146 $ (27,843) $ 78,297
Income from discontinued operations ($000) 3,106 2,554 6,282 2,554
----------- ----------- ----------- -----------
Net income (loss) ($000) $ (19,548) $ 64,700 $ (21,561) $ 80,851
=========== =========== =========== ===========
Denominator
Weighted average number of shares outstanding 78,446,264 69,364,746 78,427,523 57,298,327
----------- ----------- ----------- -----------
Per-Share Amounts:
Income (loss) from continuing operations $ (0.29) $ 0.89 $ (0.35) $ 1.37
Income from discontinued operations 0.04 0.04 0.08 0.04
----------- ----------- ----------- -----------
Net income (loss) $ (0.25) $ 0.93 $ (0.27) $ 1.41
=========== =========== =========== ===========
Diluted Eps
Numerator
Income (loss) from continuing operations ($000) $ (22,654) $ 62,146 $ (27,843) $ 78,297
Income from discontinued operations ($000) 3,106 2,554 6,282 2,554
----------- ----------- ----------- -----------
Net income (loss) ($000) $ (19,548) $ 64,700 $ (21,561) $ 80,851
=========== =========== =========== ===========
Denominator
Weighted average number of shares outstanding
before dilution 78,446,264 69,364,746 78,427,523 57,298,327
Stock options 3,441 19,641 2,041 23,153
Executive long term incentive plan 44,597 25,124 43,301 21,898
Non-Employee stock plan 4,532 4,532 4,532 4,532
Employee stock purchase plan 5,284 1,380 1,993 860
----------- ----------- ----------- -----------
78,504,118 69,415,423 78,479,390 57,348,770
----------- ----------- ----------- -----------
Per-Share Amounts:
Income (loss) from continuing operations $ (0.29) $ 0.89 $ (0.35) $ 1.37
Income from discontinued operations 0.04 0.04 0.08 0.04
----------- ----------- ----------- -----------
Net income (loss) $ (0.25) $ 0.93 $ (0.27) $ 1.41
=========== =========== =========== ===========
</TABLE>
16
<PAGE>
NOTE 8. SEGMENT INFORMATION (SPR)
------- -------------------
SPR operates two business segments providing regulated electric and natural
gas services. Electric service is provided to Las Vegas and surrounding Clark
County, northern Nevada and the Lake Tahoe area of California. Natural gas
service is provided in the Reno-Sparks area of Nevada. Other segment information
includes segments below the quantitative threshold for separate disclosure. In
September 2000, SPR and SPPC adopted a plan to sell SPPC's water utility
business. Accordingly, the water business is not included in the segment
information below.
Information as to the operations of the different business segments is set
forth below based on the nature of products and services offered. SPR evaluates
performance based on several factors, of which the primary financial measure is
business segment operating income. Intersegment revenues are not material.
Financial data for business segments is as follows (in thousands). Segment
information for 1999 includes the operating results of SPR and its pre-merger
subsidiaries only for the months of August and September 1999.
Three Months Ended
September 30, 2000 Electric Gas Other Consolidated
-------------------- ---------- ------- ------ ------------
Operating Revenues $ 852,730 $12,967 $2,657 $ 868,354
========== ======= ====== ============
Operating Income $ 16,268 $ 1,927 $1,967 $ 20,162
========== ======= ====== ============
Three Months Ended
September 30, 1999 Electric Gas Other Consolidated
-------------------- ---------- ------- ------ ------------
Operating Revenues $ 455,617 $ 8,716 $2,713 $ 467,046
========== ======= ====== ============
Operating Income $ 96,423 $ 198 $1,290 $ 97,911
========== ======= ====== ============
Nine Months Ended
September 30, 2000 Electric Gas Other Consolidated
-------------------- ---------- ------- ------ ------------
Operating Revenues $1,662,592 $64,278 $9,165 $ 1,736,035
========== ======= ====== ============
Operating Income $ 83,731 $ 7,677 $2,672 $ 94,080
========== ======= ====== ============
Nine Months Ended
September 30, 1999 Electric Gas Other Consolidated
-------------------- ---------- ------- ------ ------------
Operating Revenues $ 875,987 $ 8,716 $2,713 $ 887,416
========== ======= ====== ============
Operating Income $ 148,296 $ 198 $1,290 $ 149,784
========== ======= ====== ============
NOTE 9. DISCONTINUED OPERATIONS (SPR, SPPC)
------- -----------------------
On September 7, 2000, SPR and SPPC adopted a plan to sell SPPC's water
utility business. Accordingly, the water business is reported as a discontinued
operation as of September 30, 2000, and the consolidated financial statements
have been reclassified to report separately the net assets and operating results
of the water business. SPR's and SPPC's prior year operating results have been
restated to reflect continuing operations.
Water revenues for the three- and nine-month periods ended September 30,
2000, were $18.7 million and $44.3 million, respectively; and $17.9 million and
$41.8 million, respectively, for the same periods in 1999. Net income from
operations of the water business for the month of September 2000 was
approximately $1.0 million. These amounts are not included in the revenues and
income (loss) from continuing operations shown in the accompanying income
statements.
The income from operations of the water business to be disposed of, as
shown in the Condensed Consolidated Statements of Income of SPR, includes (in
thousands) preferred dividends of $100 and $88 for the three months ended
September 30, 2000 and 1999, respectively, and $301 and $88 for the nine months
ended September 30, 2000 and 1999, respectively. The income from operations of
the water business to be disposed of, as shown in the Condensed Consolidated
Statements of Income of SPPC, includes (in thousands) preferred dividends of
$100 and $132 for the three months ended September 30, 2000 and 1999,
respectively, and $301 and $420 for the nine months ended September 30, 2000 and
1999, respectively.
17
<PAGE>
The transaction is expected to close in the first half of 2001, after a
buyer is selected and the necessary regulatory approvals are received. It is
anticipated that the sales price will exceed the book value of the net assets to
be sold. Management anticipates using the proceeds from the sale to reduce debt
and other corporate purposes. Included in the sale will be water storage and
supply, transmission, treatment and distribution facilities. Also included in
the sale will be four hydroelectric generation plants on the Truckee River.
Accounts receivable consist of amounts due from developers for distribution
facilities. Regulatory assets included for sale consist primarily of costs
incurred in connection with the Truckee River negotiated water settlement. SPPC
has received favorable regulatory treatment that allows these costs to be
recovered through its water rates. Other unallocated regulatory assets, that
may be in part included in the sale, are not reflected in the table of net
assets that follows. Assets and liabilities that have been identified for sale
consist of the following:
<TABLE>
<CAPTION>
Amounts in thousands September 30, 2000 December 31, 1999
------------------ -----------------
<S> <C> <C>
Plant in service $329,998 $323,195
Less: Accumulated provision for depreciation 86,545 80,502
Construction work-in-progress 15,286 14,702
Accounts receivable 2,520 2,520
Materials 338 428
Regulatory tax asset 3,679 3,679
Other regulatory assets 6,985 6,601
-------- --------
Total Assets $272,261 $270,623
-------- --------
Deferred federal income taxes 8,198 8,370
Regulatory tax liability 3,679 3,679
-------- --------
Net assets to be sold $260,384 $258,574
======== ========
</TABLE>
NOTE 10. COMMITMENTS AND CONTINGENCIES (SPR, NVP, SPPC)
---------------------------------------
The Grand Canyon Trust and Sierra Club filed a lawsuit in the U.S. District
Court, District of Nevada, in February 1998, against the owners (including NVP)
of the Mohave Generation Station (Mohave), alleging violations of the Clean Air
Act regarding emissions of sulfur dioxide and particulates. An additional
plaintiff, National Parks and Conservation Association, later joined the suit.
The plant owners and plaintiffs have had numerous settlement discussions and
filed a proposed settlement with the court on October 6, 1999. The consent
decree, approved by the court in November 1999, established emission limits for
sulfur dioxide and opacity and required installation of air pollution controls
for sulfur dioxide, nitrogen oxides and particulate matter. The new emission
limits must be met by January 1, 2006 and April 1, 2006, for the first and
second units, respectively. However, if the owners sell their entire ownership
interest, with a closing date prior to December 30, 2002, then the new emission
limits become effective 36 months and 39 months, respectively, from the date of
last closing for the two units. The estimated cost of new controls is $300
million. As a 14% owner in the Mohave Station, NVP's costs could be $42
million. As discussed below, NVP is selling its 14% ownership to AES
Corporation
Also, the United States Congress authorized the Environmental Protection
Agency (EPA) to study the potential impact Mohave may have on visibility in the
Grand Canyon area. A final report of the study results was released in March
1999. The study acknowledges that sulfur dioxide emissions from Mojave are
transported to the Grand Canyon. EPA has solicited information to determine
whether visibility impairment in the Grand Canyon can be reasonably attributed
to Mohave. If EPA determines that significant visibility impairment is
reasonably attributable to the station, EPA could initiate a review for Best
Available Retrofit Technology. Based upon indications from EPA and the National
Park Service, the Plant owners believe that terms of the settlement of the suit
discussed above are expected to be reflected in a State Implementation Plan for
Nevada and resolve any concerns of EPA regarding visibility impairment.
18
<PAGE>
In May 1997, the Nevada Division of Environmental Protection (NDEP) issued
an Order requiring NVP to submit a plan to eliminate the discharge of Reid
Gardner Station wastewater to groundwater. The Order also required a
hydrological assessment of groundwater impacts in the area. In June 1999, NDEP
determined that wastewater ponds have degraded groundwater quality. In August
1999, NDEP issued a discharge permit to Reid Gardner Station and an Order that
requires all wastewater ponds to be closed or lined with impermeable liners over
the next 10 years. This Order also required NVP to submit a Site
Characterization Plan to NDEP to ascertain impacts. This plan will be submitted
in November 2000. Technical information from the Plan will be used to develop a
corrective action plan and allow NVP to determine an estimate of remediation
costs for cleanup. New pond construction and lining costs are estimated at $20
million.
Additionally, SPPC has four water wells which currently exceed the federal
drinking water standard for naturally occurring arsenic concentrations.
Production from three of these wells continues by blending treated water. The
fourth well is out of service pending treatment. SPPC's water laboratory
research staff is developing options to assure that SPPC is prepared to meet new
arsenic standards. The new arsenic regulations will be promulgated in 2000 and
the proposed regulation is expected to require action on 17 of the 25 wells
serving SPPC's system. Depending upon final rules from the EPA, SPPC may incur
between $70 million and $98 million by 2004 to meet the new standards.
As part of the Generation Divestiture Process described below, Phase I
and/or Phase II and Phase III Environmental Assessments were conducted at NVP's
Harry Allen, Clark, Sunrise and Reid Gardner facilities. These were completed
in July, 2000 and submitted to NDEP for their review and any subsequent
remediation.
Nevada Electric Investment Company (NEICO), a subsidiary of NVP in 1999,
owns property in Wellington, Utah, which was the site of a coal washing and load
out facility. The site now has a reclamation estimate supported by a bond of
$4.9 million with the Utah Division of Oil and Gas Mining. The property was
under contract for sale and the contract required the purchaser to provide $1.3
million in escrow towards reclamation. However, the sales contract was recently
terminated and NEICO has taken title to the escrow funds. It is NEICO's
intention to sell the property. In June 2000 an adjacent property owner filed
suit in Utah District Court claiming impacts from coal dust. The coal dust was
stabilized with an acrylic polymer to control impacts. NEICO intends to defend
itself against the suit, no discovery has been conducted, and no trial date has
been set. At this time, management cannot express an opinion on the extent of
possible damages or liability related to this matter.
In accordance with the revised Divestiture Plan stipulation approved by the
PUCN in February 2000 (see the 1999 Annual Report on Form 10-K), SPR's wholly
owned utilities are offering for sale generation assets with peak capacity of
approximately 2,985 megawatts (MW), with approximately 1045 MW owned by SPPC and
approximately 1,940 MW owned by NVP. Letters of interest were issued to
potential bidders in February 2000. Upon response from the qualified potential
bidders and execution of the confidentiality agreements, offering memoranda and
materials were provided to the bidders. First stage indicative bids were
received on May 25, 2000. The short list of qualified bidders for each of the
seven bundles being offered was completed and bidders notified by June 6, 2000.
The second stage due diligence process was started on June 6, 2000, and will
continue through mid-November. Final bids and the selection of winning bids
will occur in the fourth quarter of 2000. See Note 12 - Subsequent Events.
Close of sale and transfer of ownership is expected to occur by mid-2001.
On May 10, 2000, AES Corporation announced that it was the successful
bidder for the purchase of a controlling interest in the 1,580 MW Mohave
Generating Station in Laughlin, Nevada for approximately $667 million. NVP owns
a 14% undivided interest in the facility. Mohave Generating Station is a 2-
unit, coal-fired power plant located on 2,500 acres along the Colorado River,
approximately 80 miles south of Las Vegas. AES executed Asset Sale Agreements
with the sellers, NVP (14%) and Southern California Edison Company (56%), for a
70% undivided interest in the facility. The acquisition is subject to approval
by the Federal Energy Regulatory Commission (FERC) and the California Public
Utilities Commission, and review by the PUCN and is expected to close in 2001.
NOTE 11. NEVADA RESTRUCTURING ACTIVITIES (SPR, NVP, SPPC)
-----------------------------------------
Competition in the Nevada electricity market was originally scheduled to
start on March 1, 2000. However, in February 2000 the Governor of Nevada
delayed the start date of competition indefinitely. Generally, restructuring
regulations and PUCN decisions during the first and second quarters of 2000
proceeded slowly. Numerous hearings and workshops have been held by the Public
Utilities Commission of Nevada (PUCN) regarding two important regulations,
"provider of last resort" and "past costs" regulations.
On March 28, 2000, SPR, NVP and SPPC filed a federal lawsuit challenging
Nevada's laws providing for competition in the electric utility industry and the
PUCN's implementation of competition. See SPR's and NVP's Form 8-K, filed on
April 17, 2000.
On July 20, 2000, the PUCN approved stipulated agreements that resolved
pending state and federal lawsuits and major restructuring issues including past
costs. See the Form 8-K filed July 26, 2000. On August 3, 2000, the PUCN
approved
19
<PAGE>
revisions to the stipulated agreements. The stipulations paved the way for open
access to occur in a phased manner beginning in November 2000 for large
commercial customers and continuing until September 2001 for residential
customers.
On October 4, 2000, the Governor announced that he had decided to delay the
opening of the electricity market in order to allow the state to develop a
comprehensive energy policy. The Governor also appointed a bipartisan panel to
develop a long-term strategy and report its findings by January 15, 2001, prior
to the start of the 2001 legislative session. Management believes it is
probable that changes will be made to restructuring legislation and/or PUCN
restructuring rules.
In accordance with SFAS 71, "Accounting for the Effects of Certain Types of
Regulation," SPPC's and NVP's financial statements reflect the effects of rate
regulation and decisions by regulatory commissions. For example, expenses may
be deferred as regulatory assets on the balance sheet and subsequently be
amortized to the income statement when they are recovered from customers in
future periods. Similarly, certain items may be deferred as regulatory
liabilities, which are also eventually amortized to the income statement.
Management periodically assesses whether the requirements for application of
SFAS 71 are satisfied.
In 1997, the Emerging Issues Task Force of the FASB concluded that once
sufficiently detailed deregulation guidance is issued, an entity should
discontinue applying SFAS 71 to the separable potion of their business whose
pricing is being deregulated. However, an entity may continue to recognize
regulatory assets previously associated with that separable portion of their
business provided that the transition plan provides for their recovery through
the regulatory process.
Given the uncertainty related to the current restructuring legislation and
PUCN restructuring rules that would ultimately enable retail competition in
Nevada, SPPC and NVP continue to apply regulatory accounting to the generation,
transmission and distribution portions of their businesses.
NOTE 12. SUBSEQUENT EVENTS (SPR, SPPC)
---------------------------
On October 19, 2000, SPR and SPPC announced an agreement to sell SPPC's 50%
interest in the Valmy Power Station to NRG Energy of Minneapolis, Minnesota.
Under the agreement, SPPC will have the right to buy energy and ancillary
services from the Valmy Power Station for agreed upon prices subject to a
collar, through early 2003. The sale price of the asset bundle, which includes
the Battle Mountain Diesel Plant and the Winnemucca Gas Plant, is $273.3
million, net of a payment from SPPC to NRG for the power purchase agreement,
subject to taxes and other adjustments. The Valmy Power Station sells
electricity in northern Nevada and surrounding markets. SPPC's net capacity
interest in the Valmy Power Station totals 286 MW. Located forty miles from
Winnemucca, Nevada, the Valmy Power Station consists of two similar coal-fired
units and is owned jointly by SPPC and Idaho Power Co. SPPC owns 50% of the
station and operates the plant. The sale of the Valmy Power Station bundle,
which is subject to approval and review by various regulatory agencies, is
expected to close in mid-2001.
On October 27, 2000, SPR and SPPC announced an agreement to sell SPPC's
Tracy/Pinon Power Station to WPS Power Development, Inc., a wholly owned
subsidiary of WPS Resources Corporation of Green Bay, Wisconsin. Under the
agreement, SPPC will have the right to buy energy and ancillary services from
WPS Power Development for agreed upon prices subject to a collar from closing of
the agreement through February 2003. The sale price of the asset bundle, which
includes the Tracy Plant, Pinon Pine, and the Brunswick, Gabbs and Valley Road
diesel generators, is $249.8 million, subject to taxes and other adjustments at
closing. In conjunction with the purchase, SPPC negotiated the right to buy
energy and ancillary services from WPS Power Development for agreed upon prices,
subject to a collar, from closing up until March 1, 2003, at a cost ranging from
$80 million to $150 million, based on time of closing. The Tracy/Pinon Power
Station sells electricity in northern Nevada and surrounding markets. Tracy is
also the site of the Pinon Pine Integrated Coal Gasification Combined Cycle
project co-funded by the U.S. Department of Energy as part of the Clean Coal
Technology Program. SPPC's average capacity in the Tracy/Pinon Power Station
totals 525 megawatts. Located approximately 20 miles from Reno, Nevada, the
Tracy/Pinon Power Station consists of three similar gas- and oil-fired units,
four gas turbines, and the Pinon Pine facility (a combined cycle unit). The
sale of the Tracy/Pinon Power Station, which is subject to approval and review
by various regulatory agencies, is expected to close no later than June 2001.
20
<PAGE>
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The information in this Form 10-Q includes forward-looking statements
within the meaning of the Private Securities Litigation Reform Act of 1995.
These forward-looking statements relate to anticipated financial performance,
management's plans and objectives for future operations, business prospects,
outcome of regulatory proceedings, market conditions and other matters. Words
such as "anticipate," "believe," "estimate," "expect," "intend," "plan" and
"objective" and other similar expressions identify those statements that are
forward-looking. These statements are based on management's beliefs and
assumptions and on information currently available to management. Actual results
could differ materially from those contemplated by the forward-looking
statements. In addition to any assumptions and other factors referred to
specifically in connection with such statements, factors that could cause the
actual results of Sierra Pacific Resources (SPR), Nevada Power Company (NVP), or
Sierra Pacific Power Company (SPPC) to differ materially from those contemplated
in any forward-looking statement include, among others, the following: (1) a
continuation of the lag in recovery of increased purchased power and fuel costs
resulting from the historical test year mechanism of measuring such costs as
provided in the settlement agreement approved by the PUCN in July 2000; (2)
fluctuations in electric, gas and other commodity prices, particularly a
continuation of the extremely high and volatile purchased power prices in the
western United States, and the ability of NVP and SPPC to manage such
fluctuations successfully; (3) the pace and extent of the ongoing restructuring
of the electric and gas industries in Nevada and California; (4) the outcome of
regulatory and legislative proceedings and operational changes related to
industry restructuring; (5) the amount NVP and SPPC are allowed to recover from
customers for certain costs that prove to be uneconomic in the new competitive
market; (6) regulatory delays or conditions imposed by regulatory bodies in
approving the acquisition of Portland General Electric; (7) the outcome of
ongoing and future regulatory proceedings; (8) management's ability to integrate
the operations of SPR, NVP, SPPC, and Portland General Electric and to implement
and realize anticipated cost savings from the merger of SPR and NVP and the
acquisition of Portland General Electric; (9) the results of the contemplated
sales by NVP and SPPC of their Nevada generating assets; (10) industrial,
commercial and residential growth in the service territories of NVP and SPPC;
(11) changes in the capital markets and interest rates affecting the ability to
finance capital requirements; (12) the loss of any significant customers; (13)
the potentially serious impact on the utilities' costs and earnings which can
result from unseasonable weather and other natural phenomena; and (14) changes
in the business of major customers which may result in changes in the demand for
services of NVP or SPPC. Other factors and assumptions not identified above may
also have been involved in deriving these forward-looking statements, and the
failure of those other assumptions to be realized, as well as other factors, may
also cause actual results to differ materially from those projected. SPR, NVP
and SPPC assume no obligation to update forward-looking statements to reflect
actual results, changes in assumptions or changes in other factors affecting
forward-looking statements.
21
<PAGE>
RESULTS OF OPERATIONS
---------------------
SIERRA PACIFIC RESOURCES CONSOLIDATING STATEMENTS OF INCOME
(Dollars in Thousands)
<TABLE>
<CAPTION>
Three Months Ended September 30, 2000 Three Months Ended September 30, 1999
----------------------------------------------- -----------------------------------------------
Sierra Sierra
Nevada Pacific Nevada Pacific
Power Power Other Total Power Power Other Total
----------- ----------- ----------- ----------- ----------- ----------- ---------- ------------
(Unaudited) (Unaudited) (Unaudited) (Unaudited) (Unaudited) (Unaudited) (Unaudited) (Unaudited)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
OPERATING REVENUES:
Electric $ 547,395 $ 305,334 $ 1 852,730 $ 349,878 $ 105,739 $ - $ 455,617
Gas 12,967 - 12,967 - 8,716 - 8,716
Other - - 2,657 2,657 - - 2,713 2,713
---------- ----------- --------- ---------- ---------- ----------- ----------- ----------
547,395 318,301 2,658 868,354 349,878 114,455 2,713 467,046
---------- ----------- --------- ---------- ---------- ----------- ----------- ----------
OPERATING EXPENSES:
Operation:
Purchased power 385,129 196,865 - 581,994 101,070 35,418 - 136,488
Fuel for power generation 86,140 65,427 - 151,567 47,780 21,917 - 69,697
Gas purchased for resale - 6,989 - 6,989 - 6,114 - 6,114
Deferral of energy costs-net 2,445 - - 2,445 4,268 - - 4,268
Other 33,638 18,608 4,175 56,421 43,952 16,191 3,162 63,305
Maintenance 8,126 4,162 - 12,288 11,513 3,416 - 14,929
Depreciation and amortization 21,391 17,561 127 39,079 20,613 11,618 109 32,340
Taxes:
Income taxes (5,642) (4,591) (3,823) (14,056) 33,190 1,906 (1,884) 33,212
Other than income 6,542 4,711 212 11,465 5,626 3,120 36 8,782
---------- ----------- --------- ---------- ---------- ----------- ----------- ----------
537,769 309,732 691 848,192 268,012 99,700 1,423 369,135
---------- ----------- --------- ---------- ---------- ----------- ----------- ----------
OPERATING INCOME 9,626 8,569 1,967 20,162 81,866 14,755 1,290 97,911
---------- ----------- --------- ---------- ---------- ----------- ----------- ----------
OTHER INCOME:
Allowance for other funds used
during construction 430 81 - 511 1,330 (2,449) - (1,119)
Other income - net 1,307 117 (1,255) 169 (42) (432) 309 (165)
---------- ----------- --------- ---------- ---------- ----------- ----------- ----------
1,737 198 (1,255) 680 1,288 (2,881) 309 (1,284)
---------- ----------- --------- ---------- ---------- ----------- ----------- ----------
Total Income 11,363 8,767 712 20,842 83,154 11,874 1,599 96,627
---------- ----------- --------- ---------- ---------- ----------- ----------- ----------
INTEREST CHARGES:
Long-term debt 15,980 10,952 9,295 36,227 16,778 5,139 116 22,033
Other 2,745 1,348 625 4,718 1,175 1,311 4,391 6,877
Allowance for borrowed funds
used during construction
and capitalized interest (2,373) (680) - (3,053) (1,491) 1,808 - 317
---------- ----------- --------- ---------- ---------- ----------- ----------- ----------
16,352 11,620 9,920 37,892 16,462 8,258 4,507 29,227
---------- ----------- --------- ---------- ---------- ----------- ----------- ----------
INCOME (LOSS) BEFORE SPPC/NVP 66,692 3,616 (2,908) 67,400
OBLIGATED MANDATORILY REDEEMABLE
PREFERRED TRUST SECURITIES (4,989) (2,853) (9,208) (17,050)
Preferred dividend requirements
of mandatorily redeemable
preferred trust securities (3,793) (935) (1) (4,729) (3,793) (628) - (4,421)
---------- ----------- --------- ---------- ---------- ----------- ----------- ----------
INCOME (LOSS) BEFORE PREFERRED
STOCK DIVIDENDS (8,782) (3,788) (9,209) (21,779) 62,899 2,988 (2,908) 62,979
Preferred stock dividend
requirements - (875) - (875) (11) (822) - (833)
---------- ----------- --------- ---------- ---------- ----------- ----------- ----------
INCOME (LOSS) APPLICABLE
TO COMMON STOCK (8,782) (4,663) (9,209) (22,654) 62,888 2,166 (2,908) 62,146
---------- ----------- --------- ---------- ------------ ----------- ----------- ----------
INCOME FROM DISCONTINUED OPERATIONS - 3,106 - 3,106 - 2,554 - 2,554
---------- ----------- --------- ---------- ------------ ----------- ----------- ----------
NET INCOME (LOSS) $ (8,782) $ (1,557) $ (9,209) $(19,548) $ 62,888 $ 4,720 $ (2,908) $ 64,700
========== =========== ========= ========== ============ =========== =========== ==========
</TABLE>
22
<PAGE>
SIERRA PACIFIC RESOURCES CONSOLIDATING STATEMENTS OF INCOME
(Dollars in Thousands)
<TABLE>
<CAPTION>
Nine Months Ended September 30, 2000 Nine Months Ended September 30, 1999
----------------------------------------------- -----------------------------------------------
Sierra Sierra
Nevada Pacific Nevada Pacific
Power Power Other Total Power Power Other Total
---------- ---------- ---------- ---------- ---------- ---------- ---------- -----------
(Unaudited) (Unaudited) (Unaudited) (Unaudited) (Unaudited) (Unaudited) (Unaudited) (Unaudited)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
OPERATING REVENUES:
Electric $1,022,816 $ 639,776 $ - 1,662,592 $ 770,248 $ 105,739 $ - 875,987
Gas - 64,278 - 64,278 - 8,716 - 8,716
Other - - 9,165 9,165 - - 2,713 2,713
---------- ---------- -------- --------- ---------- --------- -------- ---------
1,022,816 704,054 9,165 1,736,035 770,248 114,455 2,713 887,416
---------- ---------- -------- --------- ---------- --------- -------- ---------
OPERATING EXPENSES:
Operation:
Purchased power 593,479 318,294 - 911,773 238,711 35,418 - 274,129
Fuel for power generation 178,809 138,785 - 317,594 113,808 21,917 - 135,725
Gas purchased for resale - 41,310 - 41,310 - 6,114 - 6,114
Deferral of energy costs-net 16,719 - - 16,719 14,651 - - 14,651
Other 97,923 68,328 17,059 183,310 111,243 16,191 3,162 130,596
Maintenance 27,210 12,984 - 40,194 40,740 3,416 - 44,156
Depreciation and amortization 64,121 52,144 489 116,754 60,144 11,618 109 71,871
Taxes:
Income taxes (12,461) 6,605 (11,454) (17,310) 40,397 1,906 (1,884) 40,419
Other than income 17,860 13,352 399 31,611 16,815 3,120 36 19,971
---------- ---------- -------- --------- ---------- --------- -------- ---------
983,660 651,802 6,493 1,641,955 636,509 99,700 1,423 737,632
---------- ---------- -------- --------- ---------- --------- -------- ---------
OPERATING INCOME 39,156 52,252 2,672 94,080 133,739 14,755 1,290 149,784
---------- ---------- -------- --------- ---------- --------- -------- ---------
INCOME:
Allowance for other funds used
during construction 2,271 215 - 2,486 5,413 (2,449) - 2,964
Other income - net 2,014 (1,122) 2,686 3,578 (1,205) (432) 309 (1,328)
---------- ---------- -------- --------- ---------- --------- -------- ---------
4,285 (907) 2,686 6,064 4,208 (2,881) 309 1,636
---------- ---------- -------- --------- ---------- --------- -------- ---------
Total Income 43,441 51,345 5,358 100,144 137,947 11,874 1,599 151,420
---------- ---------- -------- --------- ---------- --------- -------- ---------
INTEREST CHARGES:
Long-term debt 46,132 26,861 16,344 89,337 48,244 5,139 116 53,499
Other 10,677 8,519 10,422 29,618 4,515 1,311 4,391 10,217
Allowance for borrowed funds
used during construction
and capitalized interest (6,130) (1,649) - (7,779) (5,326) 1,808 - (3,518)
---------- ---------- -------- --------- ---------- --------- -------- ---------
50,679 33,731 26,766 111,176 47,433 8,258 4,507 60,198
---------- ---------- -------- --------- ---------- --------- -------- ---------
INCOME (LOSS) BEFORE SPPC/NVP
OBLIGATED
MANDATORILY REDEEMABLE PREFERRED
TRUST SECURITIES (7,238) 17,614 (21,408) (11,032) 90,514 3,616 (2,908) 91,222
Preferred dividend requirements
of mandatorily redeemable
preferred trust securities (11,379) (2,807) (1) (14,187) (11,380) (628) - (12,008)
---------- ---------- -------- --------- ---------- --------- -------- ---------
INCOME (LOSS) BEFORE PREFERRED STOCK
DIVIDENDS (18,617) 14,807 (21,409) (25,219) 79,134 2,988 (2,908) 79,214
Preferred stock dividend
requirements - (2,624) - (2,624) (95) (822) - (917)
---------- ---------- -------- --------- ---------- --------- -------- ---------
INCOME (LOSS) FROM CONTINUING
OPERATIONS (18,617) 12,183 (21,409) (27,843) 79,039 2,166 (2,908) 78,297
---------- ---------- -------- --------- ---------- --------- -------- ---------
INCOME FROM DISCONTINUED OPERATIONS - 6,282 - 6,282 - 2,554 - 2,554
---------- ---------- -------- --------- ---------- --------- -------- ---------
NET INCOME (LOSS) $ (18,617) $ 18,465 $(21,409) $ (21,561) $ 79,039 $ 4,720 $(2,908) $ 80,851
========== ========== ======== ========= ========== ========= ======== =========
</TABLE>
23
<PAGE>
Sierra Pacific Resources
------------------------
Financial Condition, Liquidity And Capital Resources
During the first nine months of 2000, SPR incurred a loss of $25.2 million
from continuing operations before preferred stock dividend requirements and
declared $59.0 million in common stock dividends. NVP and SPPC, SPR's principal
subsidiaries, declared common stock dividends to their parent, SPR, of $64
million and $61 million, respectively. SPPC also declared $1.95 million in
dividends to holders of its preferred stock.
As discussed in the results of operations sections that follow, operating
results for the second and third quarters of 2000 were negatively affected by
higher fuel and purchased power costs during the same periods. These costs were
reflective of significantly higher and extremely volatile prices for purchased
power and fuel that developed in May 2000 in the western United States and have
continued since. SPR, NVP, and SPPC cannot predict how long these unprecedented
market conditions will persist. If such market conditions persist, they could
have a material adverse effect on the future earnings of SPR, NVP and SPPC.
In order to mitigate the effect of these higher fuel and purchased power
costs, NVP and SPPC entered into stipulations permitting each of them to
increase electric rates. With respect to NVP, the stipulation established a Fuel
and Purchase Power (F&PP) Rider beginning September 1, 2000. This rider is based
on the incremental increase in F&PP costs between two historic 12-month periods,
subject to certain caps. The first filing by NVP under this mechanism was based
on comparing NVP's F&PP costs for the 12 months ended May 2000 with those costs
for the 12 months ended April 2000. The second filing was based on comparing
those costs for the 12 months ended June 2000 with the 12 months ended May 2000.
Future filings will follow the same pattern of comparison. The stipulation
requires that filings be made by NVP each month, with the last filing to be made
December 15, 2002, for rates effective February 1, 2003.
The stipulation also imposed caps on the amount of increase or decrease
permitted to NVP pursuant to each filing. For NVP's first six monthly filings,
the cap is 0.95 mills per kilowatt-hour (kWh), for the second six monthly
filings the cap is 1.15 mills/kWh, for the third six monthly filings the cap is
1.35 mills/kWh, for the fourth six monthly filings the cap is 1.55 mills/kWh,
and for the remaining monthly filings the cap is 1.75 mills/kWh. After each
sixth filing, the amount of increases or decreases not recognized as a result of
the caps will be calculated. In the next filing thereafter, 50% of the
unrecognized amount will be added to the incremental increase or decrease in
F&PP costs for that filing, up to the cap for that filing. Any of the 50% of
unrecognized increases or decreases not reflected in that filing because of the
cap can be added to the next filing.
As a result of the stipulation, in addition to a net rate increase of $48
million that became effective as of August 1, 2000, the following monthly
filings have been made to date for NVP:
Increase Allowed Annual
Filing Filed Effective Mills/kWh Mills/kWh (in millions)
------ ----- --------- --------- --------- -------------
1 Aug-1 Sep-1 1.1 0.95 15.1
2 Aug-15 Oct-1 2.56 0.95 15.3
3 Sep-15 Nov-1 2.97 0.95 15.6
4 Oct-15 Dec-1 2.91 0.95 15.8
To date, the PUCN has approved and NVP has implemented the first three of
the above rate increases.
In each monthly filing, the NVP must include a calculation of its Fixed
Charge Coverage Ratio for the 12-month period (May 2000 for the first filing).
If the Fixed Charge Coverage Ratio is at or above 2.5, then no increase in the
rider is allowed for that filing. In addition, every six months an audit of fuel
and purchase power practices will be conducted Any findings by the PUCN of
imprudence are to be reflected in future F&PP rider filings.
SPPC also entered into a stipulation permitting it to file monthly fuel and
purchased power adjustment cases. Beginning November 1, 2000, a F&PP Rider was
established for SPPC. As with NVP, the rider is based on the incremental
increase in F&PP costs between two 12-month periods, subject to certain caps.
The first such filing for SPPC was based on comparing SPPC's F&PP costs for the
12 months ended July 2000 with SPPC's Base Tariff Energy Rate (BTER). The second
filing was based on comparing F&PP costs for the 12 months ended August 2000
with those costs for the 12 months ended July 2000, with future filings
following the pattern of comparison. The stipulation requires SPPC to make a
filing each month, with the last filing to be made December 15, 2002, for rates
effective February 1, 2003.
24
<PAGE>
As with NVP, the stipulation imposes caps on the amount of increase or
decrease permitted under each filing by SPPC. For SPPC's first filing, the cap
is 4.5 mills/kWh. For subsequent filings the caps are the same as for NVP's
F&PP rider (i.e. 0.95 mills for the next six months, 1.15 mills for following
six months, 1.35 for the following six months, 1.55 mills for the following six
months, and 1.75 mills for each month thereafter). The treatment for
unrecognized amounts due to the cap is the same as for NVP.
As a result of the stipulation, SPPC has filed with the PUCN for approval
of the following electric rate increases:
Increase Allowed Annual
Filing Filed Effective Mills/kWh Mills/kWh $Millions
------ ----- --------- --------- --------- -------------
1 Sept. 15 Nov. 1 3.2 3.2 25.7
2 Oct. 15 Dec 1 1.5 0.95 7.7
To date, the PUCN has approved and SPPC has implemented the first of the
above rate increases.
The Fixed Charge Coverage Ratio and audit provisions are the same for SPPC
as for NVP.
Although both utilities are increasing electric rates to recover higher
fuel and purchased power costs, the mechanism described above for adjusting
rates lags changes in actual energy costs. Consequently, high fuel and
purchased power costs are likely to continue affecting earnings negatively until
these costs stabilize and/or electric rates reflect the higher costs.
In addition to the above rate filings, on November 1, SPPC filed with the
PUCN to recover $26.8 million in additional costs to its natural gas
distribution segment, to account for the higher cost of natural gas that SPPC
pays to its suppliers. The earliest that all or a portion of this increase
could go into effect would be December 1, 2000. Comparative fuel and purchased
power cost information is included in each utility's results of operations
discussion that follows. Also see "Regulatory Matters" below.
SPR's cash flows during the nine months ended September 30, 2000 decreased
slightly compared to the same period in 1999. Decreases in cash flows from
operating activities and financing activities were largely offset by a decrease
in cash flows used in investing activities. Cash flows from operating
activities were less in 2000 than in 1999 due primarily to a decrease in
operating income and an increase in accounts receivable, offset, in part, by
increases in accounts payable and depreciation and amortization. The decrease
in cash flows used in investing activities resulted mainly from 1999 including
the cash used for the merger of SPR and NVP. Cash flows from financing
activities decreased in 2000 as compared to 1999 due to most of 2000's net
increase in long-term debt being used to retire short-term borrowings, while the
nine months ended September 30, 1999, included net increases in both long-term
debt and short-term borrowings.
FINANCING
On April 20, 2000, SPR issued an aggregate of $300 million floating rate
notes, $200 million of which matures on April 20, 2003 and the remaining $100
million of which matures on April 20, 2002. Interest on the notes is payable
quarterly. The interest rate on the notes for each interest period is a floating
rate, subject to adjustment every three months, equal to the London InterBank
Offered Rate (LIBOR) for three-month U.S. dollar deposits plus a spread of 0.60%
for the notes maturing in 2003 and a spread of 0.65% for the notes maturing in
2002. These notes are not entitled to any sinking fund. The notes due 2002 will
be redeemable, in whole, without premium at the option of SPR beginning on April
20, 2001 and on each interest payment date thereafter. The net proceeds of the
$200 million issue were used to retire an equal amount of commercial paper of
SPR that was used as temporary funding for the cash portion of the NVP merger
consideration. The net proceeds of the $100 million issue were used to make a
capital contribution to NVP, which in turn was used to retire $85 million of
NVP's maturing First Mortgage Bonds on May 1, 2000 and the remaining proceeds
were used to pay off its commercial paper outstanding. On September 26, 2000,
SPR entered into a forward swap relating to its $200 million floating rate notes
that will mature on April 20, 2003, effectively locking in a LIBOR rate of
6.655%, which will result in an interest rate of 7.255% on the notes until their
maturity. This transaction became effective on October 20, 2000.
On April 20, 2000, upon issuance of these floating rate notes, SPR also
reduced its bank credit facility to $300 million from the previous amount of
$500 million in accordance with the terms of the credit agreement. On June 21,
2000, SPR further reduced its credit facility to $150 million. The remaining
$150 million credit facility was a 3-year credit facility, which has since been
terminated by SPR effective August 11, 2000.
On May 9, 2000, SPR issued $300 million of notes under its universal shelf
registration. These notes bear interest at an annual rate of 8.75% and will
mature on May 15, 2005. Interest on the notes is payable semi-annually. The
notes are not subject to any sinking fund and are redeemable in whole or in part
at any time upon payment of the principal amount of the
25
<PAGE>
notes being redeemed, plus accrued interest and a make-whole premium. The net
proceeds from the issuance of these notes were used to retire an equal amount of
commercial paper of SPR.
Also see Portland General Electric Acquisition, below.
26
<PAGE>
Nevada Power Company
---------------------
The causes for significant changes in specific lines comprising the results
of operations for NVP are as follows (dollars in thousands):
<TABLE>
<CAPTION>
Three Months Nine Months
Ended September 30, Ended September 30,
------------------- -------------------
Change from Change from
2000 1999 Prior Year% 2000 1999 Prior Year%
-------- -------- ----------- ---------- -------- -----------
<S> <C> <C> <C> <C> <C> <C>
Electric Operating Revenues ($000):
Residential $184,290 $159,022 15.9% $ 393,402 $334,789 17.5%
Commercial 68,680 60,461 13.6% 174,387 154,152 13.1%
Industrial 120,227 104,397 15.2% 252,675 227,459 11.1%
-------- -------- ---------- ---------- -------- ----------
Retail revenues 373,197 323,880 15.2% 820,464 716,400 14.5%
Other 174,198 25,998 570.0% 202,351 53,848 275.8%
-------- -------- ---------- ---------- -------- ----------
Total Revenues $547,395 $349,878 56.5% $1,022,815 $770,248 32.8%
======== ======== ========== ========== ======== ==========
Total retail sales in thousands
of megawatt-hours (MWH) 5,385 4,858 10.8% 12,846 11,380 12.9%
Average retail revenue per MWH $ 69.30 $ 66.67 4.0% $ 63.87 $ 62.95 1.5%
</TABLE>
Residential electric revenues increased for the three and nine months ended
September 30, 2000, due to increases in the number of customers and above-normal
temperatures. For the three and nine month periods ended September 30, 2000,
the number of residential customers increased by 5.5% and 5.7%, respectively,
over the same periods of 1999. Hotter than normal weather also increased
revenues in both the three and nine month periods ended September 30, 2000, over
the same periods the previous year. Residential revenues were also affected by
rate increases effective March 1, 1999, August 1, 2000, and September 1, 2000.
Both commercial and industrial electric revenues increased for the three
and nine months ended September 30, 2000, due, in part, to increases in the
number of customers. For the three and nine month periods ended September 30,
2000, the number of commercial customers increased by 4.6% and 4.8%,
respectively, over the same periods of 1999. For the three and nine month
periods ended September 30, 2000, the number of industrial customers increased
by 9.2% and 7.1%, respectively, over the same periods of 1999. The opening of
several new schools and large casinos along with new business and energy rate
increases effective August 1, 2000, and September 1, 2000, contributed to
increased 2000 revenues despite an overall rate decrease associated with
deferred energy effective May 1, 2000. The May 1, 2000 deferred energy rate
change that ended August 1, 2000, resulted in an increase in residential rates
and a decrease in rates to all other customers.
The increase in other electric revenues for the three and nine month
periods ended September 30, 2000, over the same periods in 1999 was mainly due
to large increases in wholesale power sales at much higher prices. NVP's
wholesale power revenues have increased in response to its hedging program. NVP
purchases fixed cost energy at a delivery point where the energy can either be
delivered to its control area or traded, should NVP not require the energy. The
energy is also traded if replacement energy can be obtained less expensively
than transporting the energy to the control area. Historically, less of these
trades have taken place. NVP neither purchases nor sells energy on a
speculative basis.
Also included in other electric revenues for these periods is $7.2 million
from the sale of sulfur dioxide allowances from the Navajo Generation Station.
The sale of these allowances occurred at this time to take advantage of
beneficial market conditions and trends.
27
<PAGE>
<TABLE>
<CAPTION>
Three Months Nine Months
Ended September 30, Ended September 30,
------------------ ------------------
Change from Change from
2000 1999 Prior Year % 2000 1999 Prior Year %
-------- -------- ------------ -------- -------- ------------
<S> <C> <C> <C> <C> <C> <C>
Purchased Power ($000) $385,129 $101,070 281.1% $593,479 $238,711 148.6%
Purchased Power in thousands
of MWHs 4,711 2,836 66.1% 8,426 6,387 31.9%
Average cost per MWH of
Purchased Power $ 81.75 $ 35.64 129.4% $ 70.43 $ 37.37 88.5%
</TABLE>
Purchased power costs were significantly higher for the three and nine
months ended September 30, 2000 as Short-Term Firm and Economy Energy prices
increased substantially. In addition, volumes purchased increased to accommodate
system load and increased wholesale sales.
<TABLE>
<CAPTION>
Three Months Nine Months
Ended September 30, Ended September 30,
------------------- -------------------
Change from Change from
2000 1999 Prior Year % 2000 1999 Prior Year %
-------- --------- ------------ -------- -------- ------------
<S> <C> <C> <C> <C> <C> <C>
FUEL FOR POWER GENERATION $ 86,140 $ 47,780 80.3% $178,809 $113,808 57.1%
($000)
Thousands of MWHs generated 3,052 2,811 8.6% 7,769 6,823 13.9%
Average cost per MWH of
Generated Power $ 28.22 $ 17.00 66.0% $ 23.02 $ 16.68 38.0%
</TABLE>
Fuel for generation costs for the three and nine months ended September 30,
2000, were significantly higher than the prior year as volumes generated were
higher to accommodate system load. Furthermore, natural gas prices have
increased over 50% from the prior year.
<TABLE>
<CAPTION>
Three Months Nine Months
Ended September 30, Ended September 30,
------------------- -------------------
Change From Change From
2000 1999 Prior Year % 2000 1999 Prior Year %
------ ------- ------------ ------- ------- -----------
<S> <C> <C> <C> <C> <C> <C>
Deferral of energy costs-net ($000) $2,445 $4,268 -42.7% $16,719 $14,651 14.1%
====== ====== =========== ======= ======= ===========
</TABLE>
Deferral of energy costs-net decreased for the three months ended September
30, 2000, because NVP discontinued deferred energy cost recognition in September
2000 pursuant to the July 2000 settlement with the PUCN. (See "Regulatory
Matters" below.) Deferral of energy costs-net for the nine months ended
September 30, 2000 increased as a result of deferred energy rate increases
granted in 1999 to reflect the increased cost of fuel and purchased power.
28
<PAGE>
<TABLE>
<CAPTION>
Three Months Nine Months
Ended September 30, Ended September 30,
(in $000's) (in $000's)
---------- -----------
Change from Change from
2000 1999 Prior Year % 2000 1999 Prior Year %
------ ------ ------------ ------ -------- -------------
<S> <C> <C> <C> <C> <C> <C>
Allowance for other funds
used during construction $ 430 $1,330 -67.7% $2,272 $ 5,413 -58.0%
Allowance for borrowed funds
used during construction $2,373 $1,491 59.2% 6,130 5,326 15.1%
------ ------ ----------- ------ ------- -----------
$2,803 $2,821 -0.6% $8,402 $10,739 -21.8%
====== ====== =========== ====== ======= ===========
</TABLE>
Total allowance for funds used during construction (AFUDC) for the nine-
month period ending September 30, 2000, is lower compared to 1999 because of
reductions in construction-work-in-progress resulting primarily from the
completion of the Crystal Transmission Project in May 1999 and because of a
reduction in the overall AFUDC rate. Total AFUDC was comparable for the three-
month periods ending September 30, 1999 and 2000.
<TABLE>
<CAPTION>
Three Months Nine Months
Ended September 30, Ended September 30,
------------------- -------------------
Change From Change From
2000 1999 Prior Year % 2000 1999 Prior Year %
------- ------- ------------ ------- -------- ------------
<S> <C> <C> <C> <C> <C> <C>
Other operating expense $33,638 $43,952 -23.5% $97,923 $111,243 -12.0%
Maintenance expense $ 8,126 $11,513 -29.4% 27,210 40,740 -33.2%
Depreciation and amortization $21,391 $20,613 3.8% 64,121 60,144 6.6%
Income taxes $(5,642) $33,190 -117.0% (12,461) 40,397 -130.8%
Taxes other than income taxes $ 6,542 $ 5,626 16.3% 17,860 16,815 6.2%
Interest charges- Long-term debt $15,980 $16,778 -4.8% 46,132 48,244 -4.4%
Interest charges-other $ 2,745 $ 1,175 133.6% 10,677 4,515 136.5%
</TABLE>
Other operating expense for the three- and nine-month periods ending
September 30, 2000 decreased compared to the same periods in 1999 primarily due
to reduced labor and benefit costs in 2000 as a result of merger efficiencies
and unfilled vacancies.
Maintenance costs for the three- and nine-month periods ending September
30, 2000, decreased from the prior year primarily as a result of fewer planned
plant maintenance activities at NVP's coal generation facilities. In addition,
crews have been performing required activities of a capital nature, thereby
reducing the amount of maintenance expense. Finally, in 1999 maintenance
expenses were higher than normal.
Depreciation and amortization expense increased for the three- and nine-
month periods ending September 30, 2000, due to an increase in electric plant-
in-service over the prior year.
Income taxes decreased for both the three- and nine-month periods ending
September 30, 2000, due to net pre-tax losses in the third quarter and lower
pre-tax income for the nine months ended September 30, 2000 versus periods of
higher net pre-tax income in 1999.
Taxes other than income taxes increased for both the three- and nine-month
periods ending September 30, 2000 compared to the same periods in 1999
reflecting increases in both revenues and electric plant-in-service.
Interest charges-Long-term debt decreased for the three and nine months
ended September 30, 2000 due to lower average long-term debt balances compared
to 1999. Although floating rate notes are classified as long-term debt on the
balance sheet, the associated interest costs are included in Interest charges-
other.
Interest charges-other increased for the both three- and nine-month periods
ending September 30, 2000, because of interest incurred on $100 million of
floating rate notes issued in October 1999, interest on $150 million of floating
rate notes
29
<PAGE>
issued in June 2000, $150 million of floating rate notes issued in August 2000,
and due to the utilization of commercial paper in 2000.
Financial Condition, Liquidity And Capital Resources
During the first nine months of 2000, NVP incurred a loss of approximately
$21.6 million and declared $64.0 million in dividends on its common stock, all
of which is held by its parent, Sierra Pacific Resources.
Cash flows during the nine months ended September 30, 2000 increased
slightly compared to the same period in 1999. A reduction in cash flows from
operating activities, mainly due to a decrease in operating income, was offset
by a decrease in cash used for investing activities and an increase in cash
flows from financing activities. A reduction in cash used for utility plant was
the main cause of the decrease in cash used for investing activities. The
increase in cash flows from financing activities was due to funding received
from SPR offset, in part, by an increase in dividends paid.
Construction Expenditures And Financing
NVP's construction program and capital requirements for the period 2000-
2004 were originally discussed in the combined SPR/NVP Annual Report on Form 10-
K for the year ending December 31, 1999. Of NVP's amount projected for 2000
($190.5 million), $138.6 million (72.8%) was spent as of September 30, 2000.
Construction expenditures were funded from sources other than internally
generated funds.
NVP may utilize internally generated cash and the proceeds from secured and
unsecured borrowings and preferred securities to meet capital expenditure
requirements through 2000.
Financing
On April 20, 2000, SPR issued an aggregate of $300 million floating rate
notes, $200 million of which matures on April 20, 2003 and the remaining $100
million of which matures on April 20, 2002. Interest on the notes is payable
quarterly. The net proceeds of the $100 million issue were used to make a
capital contribution to NVP, which in turn was used to retire $85 million of
NVP's maturing First Mortgage Bonds on May 1, 2000 and the remaining proceeds
were used to pay off its commercial paper outstanding.
On June 9, 2000, NVP issued $150 million of floating rate notes that will
mature on June 12, 2001. Interest on the notes is payable quarterly. The
interest rate on the notes for each interest period is a floating rate, subject
to adjustment every three months, equal to the London InterBank Offered Rate
(LIBOR) for three-month U.S. dollar deposits plus a spread of 0.55%. These
notes are not entitled to any sinking fund and are non-callable. The net
proceeds of the $150 million issue were used to redeem $100 million of floating
rate notes on July 14, 2000, and the remaining proceeds were used to reduce
NVP's commercial paper outstanding.
On June 22, 2000, Clark County, Nevada issued for NVP's benefit $100
million Industrial Development Refunding Revenue Bonds, Series 2000A, due June
1, 2020. The interest rate is currently being determined by a Dutch Auction
based on an auction period of seven days. The Series A bonds were issued to
refund $100 million of Clark County's 7.80% Industrial Development Revenue Bonds
Series 1990 on June 30, 2000.
On July 28, 2000, Clark County, Nevada issued for NVP's benefit $15 million
Pollution Control Refunding Revenue Bonds, Series 2000B, due October 1, 2009.
The interest rate is currently being determined by a Dutch Auction based on an
auction period of seven days. The Series B bonds were issued to refund a like
principal amount of Clark County's 7.80% Pollution Control Revenue Bonds Series
1989 on October 2, 2000.
The method of determining the interest rate on the Series A and Series B
Bonds may be converted from time to time in accordance with the related
Indenture so that such bonds would, thereafter, bear interest at a daily,
weekly, flexible, term or auction rate. Both Series A and Series B Bonds are
insured by AMBAC Assurance Corporation.
On July 24, 2000, NVP received a 30-day extension on its $150 million
Credit Facility to August 28, 2000, in accordance with the terms of the credit
agreement. On August 28, 2000, NVP received a 364-day extension of this
facility to August 27, 2001.
On August 18, 2000, NVP issued $100 million of floating rate notes that
will mature on August 20, 2001. Interest on the notes is payable quarterly
commencing on November 18, 2000. The interest rate on the notes for each
interest period is a floating rate, subject to adjustment every three months,
equal to the London InterBank Offered Rate (LIBOR) for three-month U.S. dollar
deposits plus a spread of 0.58%. These notes are not entitled to any sinking
fund. The notes are redeemable at the
30
<PAGE>
option of NVP in whole or in part from time to time, without premium, beginning
on February 18, 2001. The net proceeds of the $100 million issue were used to
reduce NVP's commercial paper outstanding.
31
<PAGE>
SIERRA PACIFIC POWER COMPANY
----------------------------
The components of gross margin are set forth below (dollars in thousands):
<TABLE>
<CAPTION>
Three Months Nine Months
Ended September 30, Ended September 30,
------------------- -------------------
Change from Change from
2000 1999 Prior Year % 2000 1999 Prior Year %
-------- -------- ------------ -------- -------- ------------
<S> <C> <C> <C> <C> <C> <C>
Operating Revenues:
Electric $305,334 $163,846 86.4% $639,776 $455,497 40.5%
Gas 12,967 13,056 -0.7% 64,278 69,934 -8.1%
-------- -------- -------- --------
Total Revenues 318,301 176,902 79.9% 704,054 525,431 34.0%
-------- -------- -------- --------
Energy Costs:
Electric 262,292 85,124 208.1% 457,079 220,740 107.1%
Gas 6,989 9,603 -27.2% 41,310 46,978 -12.1%
-------- -------- -------- --------
Total Energy Costs 269,281 94,727 184.3% 498,389 267,718 86.2%
-------- -------- -------- --------
Gross Margin 49,020 82,175 -40.3% 205,665 257,713 -20.2%
======== ======== ======== ========
Gross Margin by Segment:
Electric 43,042 78,722 -45.3% 182,697 234,757 -22.2%
Gas 5,978 3,453 73.1% 22,968 22,956 0.1%
-------- -------- -------- --------
Total $ 49,020 $ 82,175 -40.3% $205,665 $257,713 -20.2%
======== ======== ======== ========
</TABLE>
The causes for significant changes in specific lines comprising the
results of operations for SPPC are as follows (dollars in thousands):
<TABLE>
<CAPTION>
Three Months Nine Months
Ended September 30, Ended September 30,
------------------- -------------------
Change from Change from
2000 1999 Prior Year % 2000 1999 Prior Year %
-------- -------- ------------ ------- -------- ------------
<S> <C> <C> <C> <C> <C> <C>
Electric Operating Revenues:
Residential $ 45,114 $ 41,892 7.7% $131,304 $127,903 2.7%
Commercial 54,327 52,175 4.1% 147,753 141,874 4.1%
Industrial 49,670 47,878 3.7% 143,684 139,793 2.8%
-------- -------- ---------- -------- -------- --------
Retail revenues 149,111 141,945 5.0% 422,741 409,570 3.2%
Other 156,223 21,901 613.3% 217,035 45,927 372.6%
-------- -------- ---------- -------- -------- --------
Total Revenues $305,334 $163,846 86.4% $639,776 $455,497 40.5%
======== ======== ========== ======== ======== ========
Retail sales in thousands of
megawatt-hours (MWH) 2,336 2,193 6.5% 6,584 6,333 4.0%
-------- -------- ---------- -------- -------- --------
Average retail revenue per MWH $ 63.83 $ 64.73 -1.4% $ 64.21 $ 64.67 -0.7%
</TABLE>
Residential revenues increased for both the three- and nine-month periods
ended September 30, 2000. These changes were due to growth in total customers
and increases in cooling degree-days over the three- and nine-month periods in
1999.
Commercial revenues also were higher for both the three months and nine
months ended September 30, 2000. This was due primarily to 3.1% increases in
total customers and, to a lesser extent, the increases in cooling degree-days
mentioned above.
Industrial revenues also increased for both the three months and nine
months ended September 30, 2000. This was due to significant increases in usage
per customer, primarily by mining customers, more than offsetting the migration
of some customers to the commercial class.
32
<PAGE>
Other electric revenues were higher in the three and nine-month periods
ended September 30, 2000, compared to the prior year primarily due to $124
million and $157 million increases, respectively, in wholesale electric
revenues. SPPC's wholesale power revenues have increased in response to its
hedging program. SPPC purchases fixed cost energy at a delivery point where the
energy can either be delivered to its control area or traded, should SPPC not
require the energy. The energy is also traded if replacement energy can be
obtained less expensively than transporting the energy to the control area.
Historically, less of these trades have taken place. SPPC neither purchases nor
sells energy on a speculative basis. The increase for the nine months ended
September 30, 2000, was also due in part to the 1999 reclassification of a $4.3
million reserve to revenues from operating expense, that was made in order to
reflect a refund resulting from an agreement with the PUCN to refund a share of
earnings.
<TABLE>
<CAPTION>
Three Months Nine Months
Ended September 30, Ended September 30,
------------------- -------------------
Change From Change From
2000 1999 Prior Year % 2000 1999 Prior Year%
------------ ---------- ------------ ---------- ----------- ------------
<S> <C> <C> <C> <C> <C>
Gas Operating Revenues ($000):
Residential $ 4,316 $ 3,813 13.2% $ 27,254 $ 29,029 -6.1%
Commercial 2,382 2,189 8.8% 14,098 15,338 -8.1%
Industrial 1,852 1,781 4.0% 7,309 7,899 -7.5%
Deferred Energy 180 - - 900 - -
Miscellaneous 216 (194) -211.3% 1,224 749 63.4%
---------- ---------- ---------- ------------ ----------- --------
Total retail revenue 8,946 7,589 17.9% 50,785 53,015 -4.2%
Wholesale revenue 4,021 5,467 -26.4% 13,493 16,919 -20.2%
---------- ---------- ---------- ------------ ----------- --------
Total Revenues $ 12,967 $ 13,056 -0.7% $ 64,278 $ 69,934 -8.1%
========== ========== ========== ============ =========== ========
Sales Decatherms (Dth):
Retail 1,348,000 1,248,372 8.0% 8,414,300 9,269,549 -9.2%
Wholesale 1,110,459 2,440,570 -54.5% 4,652,635 7,988,902 -41.8%
---------- ---------- ---------- ------------ ----------- --------
Total 2,458,459 3,688,942 -33.4% 13,066,935 17,258,451 -24.3%
---------- ---------- ---------- ------------ ----------- --------
Average revenues per Dth
Retail $ 6.64 $ 6.08 9.2% $ 6.04 $ 5.72 5.5%
Wholesale $ 3.62 $ 2.24 61.6% $ 2.90 $ 2.12 36.9%
</TABLE>
The three months ended September 30, 2000, reflected increased gas revenues
among residential and commercial customers, primarily the result of higher usage
per customer as well as increases in residential and commercial customers of
4.9% and 2.5%, respectively. However, the nine-month period ended September 30,
2000, reflected reductions in usage by all classes of retail customers largely
due to a 12% decrease in the number of heating degree-days, offset, in part, by
increases in residential and commercial customers of 4.9% and 2.8%,
respectively.
Wholesale gas revenues declined for both the third quarter and the nine-
month period ended September 30, 2000 over the same periods in 1999 as a result
of less gas available for wholesale sales because of significant increases in
the usage of gas supplies for electricity generation offset, in part, by much
higher unit prices.
<TABLE>
<CAPTION>
Three Months Nine Months
Ended September 30, Ended September 30,
------------------- -------------------
Change From Change From
2000 1999 Prior Year % 2000 1999 Prior Year%
------------ ---------- ------------ ---------- ----------- ------------
<S> <C> <C> <C> <C> <C>
Purchased Power ($000) $ 196,865 $ 52,564 274.5% $318,294 $135,343 135.2%
Purchased Power in
thousands
of MWHs 2,511 1,543 62.7% 5,810 4,566 27.2%
Average cost per MWH of
Purchased Power $ 78.40 $ 34.07 130.1% $ 54.78 $ 29.64 84.8%
</TABLE>
Purchased power costs were higher for the three and nine months ended
September 30, 2000 because total purchased power requirements were higher than
in the same periods in 1999, and SPPC fulfilled more of its total energy
requirements
33
<PAGE>
with more expensive economy energy purchased power. SPPC also took advantage of
additional hedging opportunities and the price was substantially higher.
<TABLE>
<CAPTION>
Three Months Nine Months
Ended September 30, Ended September 30,
-------------------- ---------------------
Change from Change from
2000 1999 Prior Year % 2000 1999 Prior Year
-------- -------- ------------- --------- ---------- ------------
<S> <C> <C> <C> <C> <C> <C>
Fuel for Power Generation ($000) $65,427 $32,560 100.9% $138,785 $85,397 62.5%
Thousands of MWHs generated $ 1,612 $ 1,382 16.6% 4,155 3,701 12.3%
Average cost per MWH
of Generated Power $ 40.59 $ 23.56 72.3% $ 33.40 $ 23.07 44.8%
</TABLE>
Fuel for generation costs for the both the three month and nine month
periods ended September 30, 2000, were significantly higher than the same
periods of the prior year as gas prices increased significantly and volumes were
higher to accommodate greater system load.
<TABLE>
<CAPTION>
Three Months Nine Months
Ended September 30, Ended September 30,
------------------- -------------------
Change from Change from
2000 1999 Prior Year % 2000 1999 Prior Year
------- ------- ------------ -------- -------- ----------
<S> <C> <C> <C> <C> <C> <C>
Gas Purchased for Resale ($000)
Retail $ 2,740 $ 5,043 -45.7% $ 27,638 $ 32,048 -13.8%
Wholesale 4,249 4,560 -6.8% 13,672 14,930 -8.4%
------- ------- -------- --------
Total 6,989 9,603 -27.2% 41,310 46,978 -12.1%
======= ======= ======== ========
Gas Purchased for Resale
(thousands of decatherms)
Retail 1,391 1,248 11.5% 7,976 9,273 -14.0%
Wholesale 1,110 2,441 -54.5% 4,653 7,989 -41.8%
------- ------- -------- --------
Total 2,501 3,689 -32.2% 12,629 17,262 -26.8%
======= ======= ======== ========
Average cost per decatherm
Retail $ 1.97 $ 4.04 -51.2% $ 3.47 $ 3.46 0.3%
Wholesale $ 3.83 $ 1.87 104.8% $ 2.94 $ 1.87 57.2%
</TABLE>
The quantity of retail gas purchased for resale increased for the three
months and decreased for the nine months ended September 30, 2000, corresponding
to the increased and decreased retail demand, respectively, for the same
periods. The cost of retail gas purchased for resale for the three and nine
months ended September 30, 2000, has been reduced by an adjustment of $3.0
million made in August 2000. The adjustment represented a historical
reclassification of gas costs that SPPC determined were properly allocable as
fuel for power generation costs. Excluding the adjustment, the average retail
cost per decatherm for the three and nine months ended September 30, 2000, would
have been $4.14 and $3.84, respectively, reflecting higher gas costs in 2000.
34
<PAGE>
<TABLE>
<CAPTION>
Three Months Nine Months
Ended September 30, Ended September 30,
(in $000's) (in $000's)
------------------ -------------------
Change from Change from
2000 1999 Prior Year % 2000 1999 Prior Year
------- --------- ------------ ------- --------- -----------
<S> <C> <C> <C> <C> <C> <C>
Allowance for other funds
used during construction $ 81 $ (2,451) N/A $ 215 $ (2,445) N/A
Allowance for borrowed funds
used during construction 680 (1,723) N/A 1,649 (1,312) N/A
------- --------- ------- ---------
$ 761 $ (4,174) N/A $1,864 $ (3,757) N/A
======= ========= ======= =========
</TABLE>
Total allowance for funds used during construction (AFUDC) is higher for
the three and nine months ended September 30, 2000, as compared to the same
periods in 1999 because of higher construction-work-in-progress balances in 2000
and due to a September 1999 adjustment reducing AFUDC for the Pinon Pine
project.
<TABLE>
<CAPTION>
Three Months Nine Months
Ended September 30, Ended September 30,
(in $000's) (in $000's)
------------------ -------------------
Change from Change from
2000 1999 Prior Year % 2000 1999 Prior Year
------- --------- ------------ ------- --------- -----------
<S> <C> <C> <C> <C> <C> <C>
Other operating expense $18,608 $24,060 -22.7% $68,328 $67,974 0.5%
Maintenance expense 4,162 5,523 -24.6% 12,984 15,233 -14.8%
Income taxes (4,591) 5,093 -190.1% 6,605 25,175 -73.8%
Interest charges- Long-term debt 10,952 7,817 40.1% 26,861 23,548 14.1%
Interest charges-other 1,348 2,004 -32.7% 8,519 6,712 26.9%
</TABLE>
Other operating expense was lower for the third quarter of 2000 due to
reduced labor and benefit costs in 2000 as a result of merger efficiencies and
other unfilled vacancies, and due to higher fire-related claims reserves in
1999. Other operating expense for the nine months ended September 30, 2000 was
comparable to the same period in 1999.
Maintenance costs for the three-and nine-month periods ended September 30,
2000 were decreased compared to the same periods in 1999, due to fewer outages
and lower plant maintenance expenses.
Income taxes decreased for both the three and nine months periods ended
September 30, 2000, due to comparable reductions in pre-tax income in 2000 as
compared to the same periods in 1999.
Interest charges-Long-term debt increased for the three and nine months
ended September 30, 2000 due to higher average long-term debt balances compared
to 1999.
Interest charges-other decreased for the three months ended September 30,
2000 due to lower average commercial paper balances compared to 1999. However,
commercial paper balances were higher for the nine months ended September 30,
2000, which accounted for most of the increase in Interest charges-other for the
nine-month period.
Financial Condition, Liquidity And Capital Resources
During the first nine months of 2000, SPPC earned approximately $14.8
million in income from continuing operations before preferred stock dividends.
SPPC declared $1.95 million in dividends to holders of its preferred stock and
declared $61.0 million in dividends on its common stock, all of which is held by
its parent, Sierra Pacific Resources.
35
<PAGE>
Cash flows during the nine months ended September 30, 2000, were comparable
to the same period in 1999. A reduction in cash flows from operating
activities, mainly due to a decrease in operating income, was largely offset by
a decrease in cash used for investing activities. The decrease in cash used for
investing activities was primarily due to SPPC's 1999 acquisition of General
Electric Capital Corporation's interest in Pinon Pine Company L.L.C. Cash flows
from financing activities increased slightly compared to the prior year due to
an increase in net long-term debt issued and a decrease in the reduction in
short-term borrowings.
Construction Expenditures and Financing
SPPC's construction program and capital requirements for the period 2000-
2004 were originally discussed in SPPC's 1999 Annual Report on Form 10-K. Of
the amount projected for 2000 ($137.7 million), $85.4 million (62.0%) had been
spent as of September 30, 2000. Internally generated funds provided 8.3% of
construction expenditures.
SPPC may utilize internally generated cash and the proceeds from secured
and unsecured borrowings and preferred securities to meet capital expenditure
requirements through 2000.
Financing
On June 9, 2000, SPPC issued $200 million of floating rate notes that will
mature on June 12, 2001. Interest on the notes is payable quarterly. The
interest rate on the notes for each interest period is a floating rate, subject
to adjustment every three months, equal to the London InterBank Offered Rate
(LIBOR) for three-month U.S. dollar deposits plus a spread of 0.50%. These
notes are not entitled to any sinking fund and are non-callable. The net
proceeds of the $200 million issue were used to redeem $100 million of floating
rate notes on July 14, 2000, and the remaining proceeds were used to reduce the
amount of SPPC's commercial paper outstanding.
On July 24, 2000, SPPC received a 30-day extension of its $150 million
Credit Facility to August 28, 2000, in accordance with the terms of the credit
agreement. On August 28, 2000, SPPC received a 364-day extension of this
facility to August 27, 2001.
Sierra Pacific Resources (Holding Company)
------------------------------------------
The Condensed Consolidated Statements of Income of Sierra Pacific Resources
for the three and nine months ended September 30, 2000 include the operating
results of the holding company. The holding company operating results included
approximately $14.0 million and $27.0 million, respectively, of interest costs
for the three- and nine-month periods ended September 30, 2000, primarily as a
result of financing the merger between SPR and NVP. For additional merger
information, see Note 3 to the Condensed Consolidated Financial Statements
included in this report. SPR's Condensed Consolidated Statements of Income for
the three- and nine-month periods ended September 30, 1999, include only two
months' operating results of SPR and its pre-merger subsidiaries.
Tuscarora Gas Pipeline Company
------------------------------
The Condensed Consolidated Statements of Income of Sierra Pacific Resources
for the three and nine months ended September 30, 2000 include the operating
results of Tuscarora Gas Pipeline Company (TGPC), a wholly owned subsidiary of
SPR. TGPC contributed $.5 million and $1.6 million, respectively, in net income
for the three- and nine-month periods ended September 30, 2000. Although not
fully reflected in the Condensed Consolidated Statements of Income of SPR for
the three- and nine-month periods ended September 30, 1999 included in this
report, TGPC contributed $.5 million and $1.4 million, respectively, in net
income for those periods.
e.three
-------
The Condensed Consolidated Statements of Income of Sierra Pacific Resources
for the three and nine months ended September 30, 2000 include the operating
results of e.three, a wholly owned subsidiary of SPR. e.three incurred a loss
of $56,000 for the three-months ended September 30, 2000 and contributed
$235,000 in net income for the nine-month period ended September 30, 2000.
Although not fully reflected in the Condensed Consolidated Statements of Income
of SPR for the three- and nine-month periods ended September 30, 1999 included
in this report, e.three incurred net losses of $16,000 and $1.2 million,
respectively, for those periods due to start-up activities.
36
<PAGE>
Sierra Pacific Energy Company
-----------------------------
The Condensed Consolidated Statements of Income of Sierra Pacific Resources
for the three and nine months ended September 30, 2000 include the operating
results of Sierra Pacific Energy Company (SPE), a wholly owned subsidiary of
SPR. SPE incurred net losses of $.5 million and $4.3 million, respectively, for
the three- and nine-month periods ended September 30, 2000. The losses are the
result of costs incurred to exit the retail energy-sales business. Although not
fully reflected in the Condensed Consolidated Statements of Income of SPR for
the three- and nine-month periods ended September 30, 1999 included in this
report, SPE incurred net losses of $1.4 million and $2.2 million, respectively,
for those periods.
Sierra Pacific Communications
-----------------------------
The Condensed Consolidated Statements of Income of Sierra Pacific Resources
include the operating results of Sierra Pacific Communications (SPC), a wholly
owned subsidiary of SPR. SPC incurred net losses of $305,000 and $380,000,
respectively, for the three- and nine-month periods ended September 30, 2000.
SPC began operations in the third quarter of 1999.
In the first quarter of 2000, SPC finalized a partnership, called Sierra
Touch America LLC, with Touch America, a subsidiary of Montana Power Company.
The partnership was formed to construct and operate a fiber optic connection
between Salt Lake City, Utah and Sacramento, CA. The route is being constructed
for AT&T, PF Net Corporation, and Sierra Touch America. SPC's share is
approximately $25 million of a total estimated construction cost of $120
million. Right-of-way and permitting is in progress. Construction activity
between Sacramento and Reno commenced in July and completion is expected in the
fourth quarter of 2000.
PORTLAND GENERAL ELECTRIC ACQUISITION
-------------------------------------
On November 8, 1999, SPR and Enron Corporation (Enron) announced they had
entered into a purchase and sale agreement for Enron's wholly owned electric
utility subsidiary, Portland General Electric Company (PGE). PGE is an electric
utility serving more than 700,000 retail customers in northwest Oregon. PGE
will become a wholly owned subsidiary of SPR. Under terms of the agreement,
Enron will sell PGE to SPR for $2.02 billion to $2.1 billion, depending upon the
level of liabilities assumed at the time of close. In addition, $1.0 billion in
PGE debt and preferred stock will be reflected in SPR's consolidated financial
statements.
In addition to other regulatory approvals discussed below, the PGE
acquisition is subject to the approval of the Securities and Exchange Commission
(the "SEC") under the Public Utility Holding Company Act ("PUHCA"), and SPR has
applied to the SEC to become a registered public utility holding company under
PUHCA. In connection with that application, SPR has made certain
representations to the SEC regarding the methods of financing the PGE
acquisition and regarding the capital structure of SPR following the
acquisition. According to those representations, SPR expects to finance the
transaction initially primarily through a bank loan or other form of debt.
Ultimately, the transaction is expected to be financed through proceeds from the
sale of generation assets of NVP and SPPC and the issuance by SPR of debt and
equity securities. Immediately after the acquisition of PGE, SPR expects that
its consolidated common equity will be approximately 23 percent of total
consolidated capitalization. During the two years following the acquisition,
however, SPR has indicated that it intends to increase consolidated common
equity to approximately 29 percent by paying down a portion of the acquisition
debt with proceeds from the sale of the electric generation assets of NVP and
SPPC, the sale of non-strategic assets, the sale of additional common stock, and
increased retained earnings from the combined operations of the three utility
subsidiaries. SPR's ability to increase its common equity will depend upon,
among other things, market conditions and the results of operations of these
subsidiaries.
The proposed transaction is subject to closing conditions, including,
without limitation, the receipt of all necessary governmental approvals,
including the Federal Energy Regulatory Commission (FERC), the Federal Trade
Commission/Department of Justice (FTC/DOJ), the Securities and Exchange
Commission (SEC), the Oregon Public Utility Commission (OPUC), and the Nuclear
Regulatory Commission (NRC). SPR's filings have been made and the federal and
state regulatory processes continue. As of May 3, 2000, the FTC/DOJ
investigation concluded and the waiting period under Hart-Scott-Rodino expired
with no action taken. On July 27, 2000, the NRC approved PGE's transfer
application filed in January. On August 25, SPR filed additional market power
and pricing information requested by the FERC in its late July draft order. On
October 30, 2000, the OPUC approved SPR's application to acquire PGE. The OPUC
approved a September 1 settlement agreement that calls for a six-year price
freeze for PGE customers and a $95 million credit for Oregon consumers. The
"acquisition credit" will be shown on monthly power bills as soon as the
transaction is complete and will continue through September 30, 2007. PGE will
retain its ability to adjust rates to reflect changes in the prices for
wholesale electricity and fuel
37
<PAGE>
purchased to operate its power plants. It is anticipated that remaining
approvals will be received in the fourth quarter of 2000 or in 2001.
GENERATION DIVESTITURE
----------------------
In accordance with the revised Divestiture Plan stipulation approved by the
PUCN in February 2000 (see the 1999 Annual Report on Form 10-K), SPR is offering
for sale generation assets with peak capacity of approximately 2,985 megawatts
(MW), with approximately 1,045 MW owned by SPPC and approximately 1,940 MW owned
by NVP. Letters of interest were issued to potential bidders in February 2000.
Upon response from the qualified potential bidders and execution of the
confidentiality agreements, offering memoranda and materials were provided to
the bidders. First stage indicative bids were received on May 25, 2000. The
short list of qualified bidders for each of the seven bundles being offered was
completed and bidders notified by June 6, 2000. The second stage due diligence
process was started on June 6, 2000, and will continue through mid-November.
Final bids and the selection of winning bids will occur in the Fourth Quarter of
2000. The sale and transfer of ownership is expected to close by mid-2001.
Each sale will include an executed Transitional Purchase Power Agreement (TPPA)
between the utility and the new owner of the divested generation. The TPPAs
will provide price protection by enabling the utilities to buy back energy and
ancillary services from the divested plants at prices not to exceed 1998 costs.
The term of the TPPAs will begin at closing and end at a date no later than
March 1, 2003.
On May 10, 2000, AES Corporation announced that it was the successful
bidder for the purchase of a controlling interest in the 1,580 MW Mohave
Generating Station in Laughlin, Nevada for approximately $667 million. NVP owns
a 14% undivided interest in the facility. Mohave Generating Station is a 2-
unit, coal-fired power plant located on 2,500 acres along the Colorado River,
approximately 80 miles south of Las Vegas. AES executed Asset Sale Agreements
with the sellers, NVP (14%) and Southern California Edison Company (56%), for a
70% undivided interest in the facility. The acquisition is subject to approval
by the FERC and the California Public Utilities Commission and review by the
PUCN, and is expected to close in 2001.
On October 19, 2000, SPR and SPPC announced an agreement to sell SPPC's 50%
interest in the Valmy Power Station to NRG Energy of Minneapolis, Minnesota.
Under the agreement, SPPC will have the right to buy energy and ancillary
services from the Valmy Power Station for agreed upon prices subject to a
collar, through early 2003. The sale price of the asset bundle, which includes
the Battle Mountain Diesel Plant and the Winnemucca Gas Plant, is $273.3
million, net of a payment from SPPC to NRG for the power purchase agreement,
subject to taxes and other adjustments. The Valmy Power Station sells
electricity in northern Nevada and surrounding markets. SPPC's net capacity
interest in the Valmy Power Station totals 286 MW. Located forty miles from
Winnemucca, Nevada, the Valmy Power Station consists of two similar coal-fired
units and is owned jointly by SPPC and Idaho Power Co. SPPC owns 50% of the
station and operates the plant. The sale of the Valmy Power Station bundle,
which is subject to approval and review by various regulatory agencies, is
expected to close in mid-2001.
On October 27, 2000, SPR and SPPC announced an agreement to sell SPPC's
Tracy/Pinon Power Station to WPS Power Development, Inc., a wholly owned
subsidiary of WPS Resources Corporation of Green Bay, Wisconsin. Under the
agreement, SPPC will have the right to buy energy and ancillary services from
WPS Power Development for agreed upon prices subject to a collar from closing of
the agreement through February 2003. The sale price of the asset bundle, which
includes the Tracy Plant, Pinon Pine, and the Brunswick, Gabbs and Valley Road
diesel generators, is $249.8 million, subject to taxes and other adjustments at
closing. In conjunction with the purchase, SPPC negotiated the right to buy
energy and ancillary services from WPS Power Development for agreed upon prices,
subject to a collar, from closing up until March 1, 2003, at a cost ranging from
$80 million to $150 million, based on time of closing. The Tracy/Pinon Power
Station sells electricity in northern Nevada and surrounding markets. Tracy is
also the site of the Pinon Pine Integrated Coal Gasification Combined Cycle
project co-funded by the U.S. Department of Energy as part of the Clean Coal
Technology Program. SPPC's average capacity in the Tracy/Pinon Power Station
totals 525 megawatts. Located approximately 20 miles from Reno, Nevada, the
Tracy/Pinon Power Station consists of three similar gas- and oil-fired units,
four gas turbines, and the Pinon Pine facility (a combined cycle unit). The
sale of the Tracy/Pinon Power Station, which is subject to approval and review
by various regulatory agencies, is expected to close no later than June 2001.
SALE OF WATER BUSINESS
----------------------
On September 7, 2000, SPR and SPPC announced their intention to sell SPPC's
water utility business as part of a strategy to concentrate on SPR's core
electric, gas and telecommunications businesses. SPPC expects to exit the
entire water business. Expected to be included in the sale is water storage and
supply, treatment facilities, and transmission and distribution facilities.
Also included in the sale will be four hydroelectric generation plants on the
Truckee River, totaling approximately nine MW of installed (name plate)
generation capacity. The transaction is expected to close in the first half of
2001, after a buyer is selected and the necessary regulatory approvals are
received.
38
<PAGE>
The water utility business currently employs approximately 87 direct
employees. As of December 31, 1999, total assets were approximately $268
million and net utility plant was about $257 million. For the nine months
ended September 30, 2000, revenues were $44.3 million. The water business
serves approximately 71,000 customers in the Reno/Sparks area.
REGULATORY MATTERS
------------------
Substantially all of the utility operations of both NVP and SPPC
(collectively the "utilities") are conducted in Nevada. As a result both
companies are subject to utility regulation within Nevada and therefore deal
with many of the same regulatory issues.
Nevada Electric Restructuring Activities
----------------------------------------
Competition was originally scheduled to start on March 1, 2000. However,
in February 2000 the Governor of Nevada delayed the start date of competition
indefinitely. Generally, restructuring regulations and PUCN decisions during
the first and second quarters of 2000 proceeded slowly. Numerous hearings and
workshops have been held by the Public Utilities Commission of Nevada (PUCN)
regarding two important regulations, Provider of Last Resort and Past Costs
regulations.
On March 28, 2000, SPR, NVP and SPPC filed a federal lawsuit challenging
Nevada's laws providing for competition in the electric utility industry and the
PUCN's implementation of competition. See SPR's and NVP's Form 8-K, filed on
April 17, 2000.
On July 20, 2000, the PUCN approved stipulated agreements that resolved
pending state and federal lawsuits and major restructuring issues including past
costs. See the Form 8-K filed July 26, 2000. On August 3, 2000, the PUCN
approved revisions to the stipulated agreements. The stipulations paved the way
for open access to occur in a phased manner beginning in November 2000 for large
commercial customers and continuing until September 2001 for residential
customers.
On October 4, 2000, the Governor announced that he had decided to delay the
opening of the electricity market in order to allow the state to develop a
comprehensive energy policy. The Governor also appointed a bipartisan panel to
develop a long-term strategy and report its findings by January 15, 2001, prior
to the start of the 2001 legislative session. Management believes it is
probable that changes will be made to restructuring legislation and / or PUCN
restructuring rules.
The following are highlights of the stipulations:
Incentives for Utilities to Meet Open Access Dates
Provided that open access procedures including billing and settlement are
in place by the open access dates, NVP and SPPC will be allowed to retain up to
$16 million and $9 million, respectively, from any gain on the divestiture of
generation assets.
Past Costs
Major past cost issues are resolved by the stipulations. The utilities
have waived their rights to the collection of any past costs other than those
provided for in the stipulations. The parties have agreed that the stipulations
eliminate the need for a past cost regulation.
Generation
The gain on the sale of generation facilities for regulatory purposes will
be calculated based upon recorded book values as of the date of sale and
includes costs of sale, less applicable taxes and amounts related to the
Transitional Purchase Power Agreements (See Generation Divestiture, above).
Common and general plant allocable to generation will be recoverable from the
gain.
NVP is to receive the first $15 million dollars in settlement for certain
deferred energy costs. Additional gain, if any, from the sale of NVP's
generation facilities will be applied to the allowed incentive to NVP for
meeting retail open access dates, as described above.
Additional gain, if any, up to $9 million, from the sale of SPPC's
generation facilities will be applied to the allowed incentives to SPPC for
meeting retail open access dates, as described above.
Any remaining gains will be set aside in escrow accounts to be utilized to
pay down costs associated with above-market purchased power contracts.
39
<PAGE>
Purchased Power Contracts
The utilities will auction their purchased power contracts on an annual
basis in the wholesale markets. If the auction does not yield sufficient
proceeds to pay for the purchased power contracts, the utilities will collect
the difference from all customers through a non-bypassable wires charge. This
Purchased Power Agreement Adjustment Mechanism (PPAAM) charge will be in place
when the market opens. NVP and SPPC each filed its first PPAAM with the PUCN on
October 2, 2000.
To the extent that there are tax or market advantages, the utilities will
pursue a competitive permanent auction of purchased power contracts. Such an
auction would be funded by an amount not to exceed the principal and interest in
the escrow accounts that were funded by the gain on the sale of generation
assets.
If the permanent auction does not proceed or if such auction does not
exhaust the generation escrow accounts, the PPAAM charge will be reduced by an
annuity calculated on any remaining amount in the generation escrow account.
Metering
Customers will have the opportunity to purchase metering equipment directly
from the utilities or through an alternative seller. Such assets will be sold
at net book value.
Transition Costs
The ability of the utilities to recover costs they expect to spend to open
the market, referred to as transition costs, was not resolved by the
stipulations. The utilities expect to petition the PUCN in the near future to
request recovery of their transition costs.
In other matters related to restructuring, the PUCN has continued
rulemaking and discussion related to a number of topics including:
Transmission Access for Retail Competition
On July 19, 2000, the utilities filed with the FERC a modified Open Access
Tariff that would govern transmission access for retail competition in Nevada
until a Regional Transmission Organization (RTO) becomes operational. The
modified Open Access Tariff was approved by FERC on October 25, 2000, to become
effective when retail competition begins in Nevada. The utilities also continue
to pursue compliance with FERC Order 2000, which calls for utilities to form
RTO's. Also see FERC Matters, below.
Unbundling of Utility Services
In May 2000, the PUCN issued final orders (the "Orders") that were
consistent with its September 1999 interim order. See the utilities' 1999
Annual Reports on Form 10-K for additional information on the interim order.
The Orders reduce the utilities' revenue requirements and returns on equity for
distribution service for those customers who choose to leave the utilities upon
the start of retail competition. NVP and SPPC filed Petitions for
Reconsideration with the PUCN. The petitions were granted by the PUCN in the
first half of July 2000. As part of the July 20, 2000 Settlement, the utilities
withdrew their Petitions for Reconsideration of all issues arising out of the
Commission's Interim and Compliance Orders with the exception of two issues
related to plant depreciation rates and treatment of merger costs and savings.
Provider Of Last Resort (PLR)
The PLR will provide electric service to customers who do not select an
electricity provider and to customers who are not able to obtain service from an
alternative seller after the date competition begins
The PUCN has conducted several hearings on the PLR regulation and is
nearing completion of this regulation. Some of the negative provisions of the
regulation have been modified including language that restricted the PLR's
ability to finance costs. However the proposed regulation continues to contain
a strict standard of conduct to govern the relationship between electric
distribution utility (EDU) and PLR functions. Implementation of these
provisions could have negative financial ramifications.
40
<PAGE>
Ferc Matters
------------
Regional Transmission Organization (RTO)
On May 1, 2000, NVP, SPPC, and Avista Corporation, Bonneville Power
Administration (BPA), Idaho Power Company, The Montana Power Company,
PacifiCorp, Portland General Electric, and Puget Sound Energy, Inc. formed RTO
West and filed articles of incorporation in the State of Washington. RTO West
will be a non-profit independent system operator governed by an independent
board of directors with a stakeholder advisory board. RTO West would be the
single provider of transmission services, and controller of transmission
operations in an eight-state region.
RTO West submitted a compliance filing on October 16, 2000 with FERC.
Supplemental material, which provided details of the formation of RTO West, was
submitted on October 23. The creation of RTO West is subject to regulatory
approvals from FERC and the states served by the investor-owned utilities. The
organization will begin operations after all approvals are obtained. FERC's
goal is for all RTO's to be operational by December 15, 2001. The proposed
operational date in the RTO West filing is approximately one year later.
Independent Transmission Company
On October 16, 2000, NVP, SPPC, and Portland General Electric Company,
Avista Corporation, The Montana Power Company, and Puget Sound Energy filed
jointly with FERC to form TransConnect, a for-profit Independent Transmission
Company. The creation of TransConnect is subject to regulatory approvals from
FERC, state regulators, and the board of directors of each company.
TransConnect would own or lease the transmission facilities of the six utilities
in Oregon, Washington, Nevada and Montana and parts of Idaho and California.
Those facilities are within the proposed territory for RTO West. RTO West would
deal with TransConnect, instead of the six utilities. TransConnect expects to
begin operations by December 15, 2001.
Open Access Transmission Rates
In May 1999, NVP filed an application with the FERC to increase its Open
Access Transmission rates. On March 30, 2000, the FERC approved the settlement
filed on February 8, 2000 with rates becoming effective on March 1, 2000. Also
on March 30, 2000, NVP filed a Loss Study that NVP agreed to provide in the
settlement. On May 23, 2000, the FERC accepted NVP's Loss Study and the docket
was completed.
In March 1999, SPPC filed an application with the FERC to increase its Open
Access Transmission rates. See the SPPC's 1999 Annual Report on Form 10-K. On
March 30, 2000, SPPC filed a Loss Study that SPPC agreed to provide in the
partial settlement that was approved in January 2000.
On April 26, 2000, a settlement was filed by SPPC on issues raised by the
City of Fallon and on August 1, 2000, the FERC approved the settlement.
On July 18, 2000 a settlement was filed by SPPC on issues raised by the
Mines which provides that the issues not be resolved in this case, but at a
later date. On September 18, 2000, the FERC approved the settlement
On July 7, 2000, a settlement was filed by SPPC resolving all Loss Study
issues in the case and on September 18, 2000, the FERC approved the settlement.
Revised Generation Tariffs And Transitional Purchase Power Agreements
On March 31, 2000, the utilities filed for approval of Generation Tariffs
that contain the rates, terms and conditions under which the new owners of
divested generation facilities could sell energy and ancillary services. The
filing also included pro-forma Transitional Purchase Power Agreements (TPPAs)
between the utilities and the new owners of the divested generation facilities.
Final signed versions of the TPPAs will be submitted to the FERC as part of the
Asset Sale Agreements between the utilities and the new owners of the divested
generation.
On May 31, 2000, the FERC accepted for filing the Generation Tariff and the
TPPAs. The FERC required one modification to the TPPAs in that the utilities
were required to notify the new owners day-ahead of real-time of their intended
use of the generation or release the capacity to the new owners. The FERC also
set for hearing the rates in the generation tariff and in the TPPAs. The
utilities have reached a settlement with the FERC Staff, PUCN and the Bureau of
Consumer Protection regarding the rates in the Generation Tariff and TPPAs. The
settlement has not yet been submitted to the FERC for approval.
41
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California Matters (SPPC)
-------------------------
Generation Divestiture
On March 2, 2000, SPPC filed a new application requesting exemption from
California Public Utility Commission (CPUC) approval of the Nevada-based
generation divestiture transaction. SPPC cited several reasons for the
exemption including that the PUCN and FERC oversight of the generation
divestiture will assure reliability and market power mitigation as required by
California's electric restructuring legislation.
On September 18, 2000, a proposed settlement agreement was filed with the
CPUC.
Distribution Performance-based Rate-making (PBR)
On May 4, 2000, the CPUC dismissed without prejudice SPPC's January 3, 2000
distribution PBR proposal (see the SPPC's 1999 Annual Report on Form 10-K). The
order accepted the application as meeting the compliance requirement but
directed SPPC to re-file it when the cost of capital and cost of service studies
are available. On May 8, 2000, SPPC filed its 2001 Cost of Capital application.
On July 3, 2000, SPPC re-submitted the PBR proposal along with the Cost of
Service Study.
In September 2000, hearings were held on SPPC's Cost of Capital filing. On
September 20, 2000 a pre-hearing conference was held on SPPC's Cost of Service
and Distribution PBR filing which established the procedural schedule.
Litigation Regarding California Power Market.
In response to complaints and requests for relief filed by California
utilities and their customers, the FERC issued an order on August 23, 2000
initiating hearing proceedings under section 206 of the Federal Power Act
("FPA") to address matters affecting bulk power markets and wholesale energy
prices (including price volatility) in California. On November 1, 2000, the
FERC proposed specific remedies to address problems that it found in
California's wholesale bulk power markets and to ensure just and reasonable
wholesale power rates by public utility sellers in California. This ongoing
proceeding, together with proceedings currently pending before the CPUC, may
result in significant changes to the California power markets. Some parties to
these proceedings have requested refunds from sellers of electrical power for
past market transactions. The FERC denied this request for sales prior to
October 2, 2000. However, the FERC held that sales made after October 2, 2000
are subject to refund, with the level and extent of any refund to be determined
in future orders. Although a relatively small portion of SPPC's electricity
customers are in the California, SPR, SPPC and NVP are monitoring the
developments in California and at the FERC to determine what effect, if any,
those developments may have on SPPC's California operations, on bulk sales of
power by either utility and on general market prices for wholesale energy in the
western United States.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES
ABOUT MARKET RISK
See "Results of Operations" above for a discussion of recent increased
prices and volatility in the markets for purchased power and fuel, which have
had a negative effect on the financial performance of NVP, SPPC, and SPR.
42
<PAGE>
PART II
ITEM 1. LEGAL PROCEEDINGS
On March 28, 2000, SPR, NVP, and SPPC filed a lawsuit in Federal District
Court in Nevada asking the court to declare unconstitutional certain aspects of
the Nevada laws that created the framework for a deregulated electric market in
Nevada.
In response to the certain PUCN decisions described in SPR's Annual Report
on Form 10-K for the period ending December 31, 1999 and in SPR's Quarterly
Report on Form 10-Q for the period ending March 31, 2000, NVP filed a lawsuit
against the PUCN on March 30, 2000 in the First Judicial District of Nevada in
Carson City.
On July 20, 2000, the PUCN approved a stipulation (the "Settlement")
entered into among the parties to the state and federal lawsuits permitting NVP
to increase its rates effective August 1, 2000, by approximately $48 million
annually to recover increased costs of fuel and purchased power, and to update
its going-forward costs of fuel and purchased power thereafter with monthly fuel
and purchased power filings up to March 2003. Increases and/or decreases are
capped at incrementally increased or decreased rates over successive six-month
periods at .95 mils for the first six months, 1.15 mils for the second six
months, 1.25 mils for the third six months, 1.55 mils for the next six months,
and 1.75 mils for the remaining period. The Settlement also permits SPPC to
commence filing monthly fuel and purchased power adjustment cases on the same
basis to commence not later than November 1, 2000. SPPC fuel and purchased
power increases and/or decreases are also capped at incrementally increased or
decreased rates over successive six-month periods starting October 1, 2000 at
4.5 mils for the first six-month period followed by .95, 1.15, 1.35, 1.55, and
1.75 mils for each successive six-month period.
The Settlement also resolved numerous other issues relating to the
restructuring of the electric industry in Nevada, including phased-in access to
competitive markets by customer class, recovery of stranded costs, auctioning
out-of-market qualified facility and other purchased power contracts, imposition
of a wires charge to recover any balance, and filing of new proceedings to
address metering costs and transition costs. Recovery is still subject to
future regulatory proceedings relating to the filing of monthly fuel and
purchased power cases, recovery of stranded costs, and divestiture of generation
proceeds. The outcome of the dockets and proceedings cannot be predicted at
this time; however, unfavorable treatment of any of these proceedings would have
a negative effect on the economic value of the Settlement.
See the Form 8-K filed July 26, 2000 and Regulatory Matters, above, for
additional details.
Although SPR is involved in other ongoing litigation on a variety of
matters, it is management's opinion that none individually or collectively are
material to SPR's financial position.
43
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ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None
ITEM 5. OTHER INFORMATION
None
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits filed with this Form 10-Q:
(10.A) Stipulation and Agreement To Compromise and Settle - Federal
(10.B) Stipulation and Agreement To Compromise and Settle - State
(27) The Financial Data Schedule containing summary financial information
extracted from the condensed consolidated financial statements on
Form 10-Q for the nine month period ended September 30, 2000, for
Sierra Pacific Resources, and is qualified in its entirety by
reference to such financial statements.
(b) Reports on Form 8-K:
Form 8-K filed on July 14, 2000 by SPR, NVP, and SPPC- Item 5, Other Events
Described, and included as an exhibit, SPR's press release dated July 12,
2000, announcing that fuel and purchased power costs would negatively impact
earnings for the second quarter and the remainder of 2000.
Form 8-K filed on July 26, 2000 by SPR, NVP, and SPPC - Item 5, Other Events
Described, and included as an exhibit, SPR's press release dated July 20,
2000, announcing that the Company, Nevada regulators and several other parties
took steps toward a settlement of issues involving restructuring the electric
utility industry in the state, setting new electric rates for NVP's and SPPC's
customers and resolving other issues involved in state and federal court cases
filed by NVP and SPPC.
Form 8-K filed on September 12, 2000 by SPR and SPPC - Item 5, Other Events
Described, and included as an exhibit, SPR's press release dated September
7, 2000, announcing that its SPPC subsidiary intends to sell its water business.
44
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrants have duly caused this report to be signed on their behalf by the
undersigned thereunto duly authorized.
Sierra Pacific Resources
------------------------
(Registrant)
Date: November 14, 2000 By: /s/ Mark A. Ruelle
----------------- -----------------------------
Mark A. Ruelle
Senior Vice President
Treasurer
Chief Financial Officer
(Principal Financial Officer)
Date: November 14, 2000 By: /s/ Mary O. Simmons
-----------------------------
Mary O. Simmons
Controller
(Principal Accounting Officer)
Nevada Power Company
--------------------
(Registrant)
Date: November 14, 2000 By: /s/ Mark A. Ruelle
----------------- -----------------------------
Mark A. Ruelle
Senior Vice President
Treasurer
Chief Financial Officer
(Principal Financial Officer)
Date: November 14, 2000 By: /s/ Mary O. Simmons
-----------------------------
Mary O. Simmons
Controller
(Principal Accounting Officer)
SIERRA PACIFIC POWER COMPANY
----------------------------
(Registrant)
Date: November 14, 2000 By: /s/ Mark A. Ruelle
----------------- -----------------------------
Mark A. Ruelle
Senior Vice President
Treasurer
Chief Financial Officer
(Principal Financial Officer)
Date: November 14, 2000 By: /s/ Mary O. Simmons
-----------------------------
Mary O. Simmons
Controller
(Principal Accounting Officer)
45
