================================================================================
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 June 30, 2001
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM TO
Registrant, State of Incorporation, Address of
Commission File Principal Executive Offices and Telephone I.R.S. employer
Number Number Identification Number
1-8788 SIERRA PACIFIC RESOURCES 88-0198358
P.O. Box 10100
(6100 Neil Road)
Reno, Nevada 89520-0400 (89511)
(775) 834-4011
1-4698 NEVADA POWER COMPANY 88-0045330
6226 West Sahara Avenue
Las Vegas, Nevada 89146
(702) 367-5000
0-508 SIERRA PACIFIC POWER COMPANY 88-0044418
P.O. Box 10100
(6100 Neil Road)
Reno, Nevada 89520-0400 (89511)
(775) 834-4011
Indicate by check mark whether registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes [X] No [ ]
Indicate the number of shares outstanding of each of the issuer's classes of
Common Stock, as of the latest practicable date.
Class Outstanding at August 6, 2001
Common Stock, $1.00 par value 78,515,325 Shares
of Sierra Pacific Resources
Sierra Pacific Resources is the sole holder of the 1,000 shares of outstanding
Common Stock, $1.00 stated value, of Nevada Power Company.
Sierra Pacific Resources is the sole holder of the 1,000 shares of outstanding
Common Stock, $3.75 par value, of Sierra Pacific Power Company.
This combined Quarterly Report on Form 10-Q is separately filed by Sierra
Pacific Resources, Nevada Power Company and Sierra Pacific Power Company.
Information contained in this document relating to Nevada Power Company is filed
by Sierra Pacific Resources and separately by Nevada Power Company on its own
behalf. Nevada Power Company makes no representation as to information relating
to Sierra Pacific Resources or its subsidiaries, except as it may relate to
Nevada Power Company. Information contained in this document relating to Sierra
Pacific Power Company is filed by Sierra Pacific Resources and separately by
Sierra Pacific Power Company on its own behalf. Sierra Pacific Power Company
makes no representation as to information relating to Sierra Pacific Resources
or its subsidiaries, except as it may relate to Sierra Pacific Power Company.
================================================================================
SIERRA PACIFIC RESOURCES
NEVADA POWER COMPANY
SIERRA PACIFIC POWER COMPANY
QUARTERLY REPORTS ON FORM 10-Q
FOR THE QUARTER ENDED JUNE 30, 2001
CONTENTS
PART I - FINANCIAL INFORMATION
------------------------------
ITEM 1. Financial Statements
Sierra Pacific Resources -
Condensed Consolidated Balance Sheets - June 30, 2001 and December 31, 2000..................... 3
Condensed Consolidated Statements of Income - Three Months and Six Months
Ended June 30, 2001 and 2000........................................................... 4
Condensed Consolidated Statements of Cash Flows - Six Months Ended June 30, 2001 and 2000....... 5
Nevada Power Company -
Condensed Balance Sheets - June 30, 2001 and December 31, 2000.................................. 6
Condensed Statements of Income - Three Months and Six Months Ended June 30, 2001 and 2000....... 7
Condensed Statements of Cash Flows - Six Months Ended June 30, 2001 and 2000.................... 8
Sierra Pacific Power Company -
Condensed Consolidated Balance Sheets - June 30, 2001 and December 31, 2000..................... 9
Condensed Consolidated Statements of Income - Three Months and Six Months
Ended June 30, 2001 and 2000........................................................... 10
Condensed Consolidated Statements of Cash Flows - Six Months Ended June 30, 2001 and 2000....... 11
Notes to Condensed Consolidated Financial Statements.................................................... 12
ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.................. 22
Sierra Pacific Resources Results of Operations........................................ 23
Nevada Power Company Results of Operations............................................ 27
Sierra Pacific Power Company Results of Operations.................................... 31
ITEM 3. Quantitative and Qualitative Disclosures about Market Risk............................................ 38
PART II - OTHER INFORMATION
---------------------------
ITEM 1. Legal Proceedings..................................................................................... 39
ITEM 4. Submission of Matters to a Vote of Security Holders................................................... 39
ITEM 5. Other Information..................................................................................... 39
ITEM 6. Exhibits and Reports on Form 8-K...................................................................... 39
Signature Page.................................................................................................... 41
2
SIERRA PACIFIC RESOURCES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
June 30, December 31,
2001 2000
----------- -----------
ASSETS (Unaudited)
Utility Plant at Original Cost:
Plant in service $ 5,516,387 $ 5,269,724
Less: accumulated provision for depreciation 1,724,246 1,636,657
----------- -----------
3,792,141 3,633,067
Construction work-in-progress 235,968 348,067
----------- -----------
4,028,109 3,981,134
----------- -----------
Investments in subsidiaries and other property, net 128,689 135,062
----------- -----------
Current Assets:
Cash and cash equivalents 183,703 51,503
Accounts receivable less provision for uncollectible accounts:
2001-$33,336; 2000-$13,194 660,868 336,361
Materials, supplies and fuel, at average cost 91,710 75,132
Other 107,907 59,128
----------- -----------
1,044,188 522,124
----------- -----------
Deferred Charges:
Goodwill, net of amortization 316,276 320,256
Deferred energy costs 391,948 16,370
Regulatory tax asset 175,587 175,509
Other regulatory assets 111,043 105,588
Risk management assets (Note 9) 1,044,132 --
Risk management regulatory assets - net (Note 9) 657,184 --
Other 126,784 116,965
----------- -----------
2,822,954 734,688
----------- -----------
Net assets of discontinued operations (Note 7) -- 261,479
----------- -----------
$ 8,023,940 $ 5,634,487
=========== ===========
CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholders' equity $ 1,330,698 $ 1,359,712
Accumulated other comprehensive loss (3,463) --
Preferred stock 50,000 50,000
SPPC/ NPC obligated mandatorily redeemable preferred trust securities 237,372 237,372
Long-term debt 2,799,802 2,133,679
----------- -----------
4,414,409 3,780,763
----------- -----------
Current Liabilities:
Short-term borrowings 100,000 213,074
Current maturities of long-term debt 123,244 472,527
Accounts payable 722,456 312,039
Accrued interest 36,111 30,184
Dividends declared 77 20,890
Accrued salaries and benefits 23,935 28,957
Other current liabilities 11,965 17,795
----------- -----------
1,017,788 1,095,466
----------- -----------
Commitments & Contingencies (Note 10)
Deferred Credits:
Deferred federal income taxes 390,776 406,310
Deferred investment tax credit 53,759 55,252
Deferred taxes on deferred energy costs 137,182 --
Regulatory tax liability 50,685 50,994
Customer advances for construction 106,425 109,962
Accrued retirement benefits 85,549 80,027
Risk management liabilities (Note 9) 1,704,779 --
Other 62,588 55,713
----------- -----------
2,591,743 758,258
----------- -----------
$ 8,023,940 $ 5,634,487
=========== ===========
The accompanying notes are an integral part of the financial statements.
3
SIERRA PACIFIC RESOURCES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Dollars in Thousands, Except Per Share Amounts)
Three months ended Six months ended
June 30, June 30,
-------------------------- --------------------------
2001 2000 2001 2000
----------- ----------- ----------- -----------
(unaudited) (unaudited)
OPERATING REVENUES:
Electric $ 1,128,663 $ 456,210 $ 1,799,794 $ 809,862
Gas 21,729 15,755 85,894 50,591
Other 5,070 2,347 7,700 6,508
----------- ----------- ----------- -----------
1,155,462 474,312 1,893,388 866,961
----------- ----------- ----------- -----------
OPERATING EXPENSES:
Operation:
Purchased power 1,088,147 226,482 1,440,955 329,779
Fuel for power generation 187,298 99,104 405,204 166,027
Gas purchased for resale 25,171 11,470 95,714 34,321
Deferral of energy costs-net (370,204) 6,390 (370,019) 13,554
Other 62,204 65,036 166,504 126,889
Maintenance 20,154 14,016 38,458 27,906
Depreciation and amortization 40,562 38,924 79,594 77,675
Taxes: -- --
Income taxes 13,223 (12,547) (32,054) (1,672)
Other than income 10,613 10,293 21,224 20,145
----------- ----------- ----------- -----------
1,077,168 459,168 1,845,580 794,624
----------- ----------- ----------- -----------
OPERATING INCOME 78,294 15,144 47,808 72,337
----------- ----------- ----------- -----------
OTHER (EXPENSE) INCOME:
Allowance for other funds used during construction (151) 1,135 (687) 1,975
Other income - net 5,043 3,148 6,312 3,409
----------- ----------- ----------- -----------
4,892 4,283 5,625 5,384
----------- ----------- ----------- -----------
TOTAL INCOME BEFORE INTEREST CHARGES 83,186 19,427 53,433 77,721
----------- ----------- ----------- -----------
INTEREST CHARGES:
Long-term debt 43,310 29,508 83,532 53,109
Other 7,411 10,829 15,293 24,900
Allowance for borrowed funds used during construction and
capitalized interest (688) (2,493) (289) (4,726)
----------- ----------- ----------- -----------
50,033 37,844 98,536 73,283
----------- ----------- ----------- -----------
INCOME (LOSS) BEFORE SPPC/NPC OBLIGATED MANDATORILY
REDEEMABLE PREFERRED TRUST SECURITIES 33,153 (18,417) (45,103) 4,438
Preferred dividend requirements of SPPC/NPC obligated
mandatorily redeemable preferred trust securities 4,729 4,729 9,458 9,458
----------- ----------- ----------- -----------
INCOME (LOSS) BEFORE PREFERRED STOCK DIVIDENDS 28,424 (23,146) (54,561) (5,020)
Preferred stock dividend requirements of subsidiary 875 875 1,750 1,750
----------- ----------- ----------- -----------
INCOME (LOSS) FROM CONTINUING OPERATIONS 27,549 (24,021) (56,311) (6,770)
----------- ----------- ----------- -----------
DISCONTINUED OPERATIONS:
Income from operations of water business to be disposed of
(net of income taxes of $410 and $888 in 2001 and
$732 and ($128) in 2000, respectively) 641 3,830 1,022 4,757
Gain on disposal of water business
(net of income taxes of $18,237) 25,845 -- 25,845 --
----------- ----------- ----------- -----------
NET INCOME (LOSS) $ 54,035 $ (20,191) $ (29,444) $ (2,013)
=========== =========== =========== ===========
Income (Loss) per share - Basic and Diluted
Income (Loss) from continuing operations $ 0.35 $ (0.31) $ (0.72) $ (0.09)
Income from discontinued operations 0.01 0.05 0.01 0.06
Gain on disposal of water business 0.33 -- 0.33 --
----------- ----------- ----------- -----------
Net income (loss) $ 0.69 $ (0.26) $ (0.38) $ (0.03)
=========== =========== =========== ===========
Weighted Average Shares of Common Stock Outstanding (000's) 78,491 78,420 78,483 78,418
=========== =========== =========== ===========
Dividends Paid Per Share of Common Stock $ -- $ 0.250 $ 0.250 $ 0.500
=========== =========== =========== ===========
The accompanying notes are an integral part of the financial statements.
4
SIERRA PACIFIC RESOURCES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
Six Months Ended
June 30,
----------------------
2001 2000
--------- ---------
(Unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES:
(Loss) from continuing operations before preferred dividends $ (54,561) $ (5,020)
Income from discontinued operations before preferred dividends 1,222 4,957
Gain from on disposal of water business 25,845 --
Non-cash items included in income:
Depreciation and amortization 83,055 81,358
Deferred taxes and deferred investment tax credit 111,696 (3,205)
AFUDC and capitalized interest 389 (6,866)
Amortization of deferred energy costs -- 11,911
Early retirement and severance amortization 3,121 2,098
Gain on disposal of water business (44,081) --
Other non-cash (3,463) 10,260
Changes in certain assets and liabilities:
Accounts receivable (320,191) (98,839)
Materials, supplies and fuel (16,224) (7,165)
Deferred energy costs (375,578) --
Other current assets (48,903) (2,812)
Accounts payable 410,396 117,282
Other current liabilities (5,382) 2,599
Other - net 15,938 1,269
--------- ---------
Net Cash Flows (Used in) Provided by Operating Activities (216,721) 107,827
--------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to utility plant (158,652) (145,644)
AFUDC and other charges to utility plant (389) 2,023
Customer refunds for construction (3,537) 1,342
Contributions in aid of construction 16,122 5,264
--------- ---------
Net cash used for utility plant (146,456) (137,015)
Proceeds from sale of assets of water business 318,882 --
Investments in subsidiaries and other property - net (5,944) (16,699)
--------- ---------
Net Cash Provided by (Used in) Investing Activities 166,482 (153,714)
--------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Decrease in short-term borrowings (113,054) (647,516)
Proceeds from issuance of long-term debt 670,000 950,000
Retirement of long-term debt (353,160) (97,923)
Sale of common stock 433 5
Dividends paid (21,780) (41,147)
--------- ---------
Net Cash Provided by Financing Activities 182,439 163,419
--------- ---------
Net Increase in Cash and Cash Equivalents 132,200 117,532
Beginning balance in Cash and Cash Equivalents 51,503 4,789
--------- ---------
Ending balance in Cash and Cash Equivalents $ 183,703 $ 122,321
========= =========
Supplemental Disclosures of Cash Flow Information:
Cash Paid (Received) During Period For:
Interest $ 98,650 $ 71,516
Income Taxes $ (33,842) $ 12,730
The accompanying notes are an integral part of the financial statements.
5
NEVADA POWER COMPANY
CONDENSED BALANCE SHEETS
(Dollars in Thousands)
June 30, December 31,
2001 2000
---------- ----------
ASSETS (unaudited)
Utility Plant at Original Cost:
Plant in service $3,261,969 $3,089,705
Less: accumulated provision for depreciation 901,779 855,599
---------- ----------
2,360,190 2,234,106
Construction work-in-progress 142,172 228,856
---------- ----------
2,502,362 2,462,962
---------- ----------
Investments in Sierra Pacific Resources (Note 2) 439,784 471,975
Investments in subsidiaries and other property, net 12,793 13,418
---------- ----------
452,577 485,393
---------- ----------
Current Assets:
Cash and cash equivalents 80,210 43,858
Accounts receivable less provision for uncollectible accounts:
2001-$28,738; 2000-$11,605 410,223 137,097
Materials, supplies and fuel, at average cost 48,878 45,573
Other 104,510 28,933
---------- ----------
643,821 255,461
---------- ----------
Deferred Charges:
Deferred energy costs 272,777 --
Regulatory tax asset 113,647 113,647
Other regulatory assets 33,938 32,583
Risk management assets (Note 9) 746,492 --
Risk management regulatory assets - net (Note 9) 309,491
Other 27,798 25,912
---------- ----------
1,504,143 172,142
---------- ----------
$5,102,903 $3,375,958
========== ==========
CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholders' equity including $439,784 and $471,975 of equity
in Sierra Pacific Resources in 2001and 2000, respectively (Note 2) $1,327,149 $1,359,712
Accumulated other comprehensive income 1,061 --
NPC obligated mandatorily redeemable preferred trust securities 188,872 188,872
Long-term debt 1,275,368 927,784
---------- ----------
2,792,450 2,476,368
---------- ----------
Current Liabilities:
Short-term borrowings 100,000 100,000
Current maturities of long-term debt 103,628 252,910
Accounts payable 540,472 126,015
Accrued interest 18,762 16,913
Dividends declared 77 86
Accrued salaries and benefits 9,761 12,297
Other current liabilities 16,914 16,450
---------- ----------
789,614 524,671
---------- ----------
Commitments & Contingencies (Note 10)
Deferred Credits:
Deferred federal income taxes 211,769 216,753
Deferred investment tax credit 24,433 25,163
Deferred taxes on deferred energy costs 95,472 --
Regulatory tax liability 19,908 19,908
Customer advances for construction 61,849 65,588
Accrued retirement benefits 30,633 27,985
Risk management liabilities (Note 9) 1,054,922 --
Other 21,853 19,522
---------- ----------
1,520,839 374,919
---------- ----------
$5,102,903 $3,375,958
========== ==========
The accompanying notes are an integral part of the financial statements.
6
NEVADA POWER COMPANY
CONDENSED STATEMENTS OF INCOME
(Dollars in Thousands, Except Per Share Amounts)
Three months ended Six months ended
June 30, June 30,
-------------------------- --------------------------
2001 2000 2001 2000
----------- ----------- ----------- -----------
(unaudited) (unaudited)
OPERATING REVENUES:
Electric $ 808,441 $ 279,390 $ 1,167,453 $ 475,420
OPERATING EXPENSES:
Operation:
Purchased power 839,538 154,533 1,041,360 208,350
Fuel for power generation 102,258 55,022 217,610 92,669
Deferral of energy costs-net (281,145) 7,486 (269,837) 14,274
Other 33,750 35,134 84,522 64,285
Maintenance 13,478 9,263 26,458 19,084
Depreciation and amortization 22,427 21,314 44,303 42,730
Taxes:
Income taxes 16,246 (10,446) (14,218) (6,819)
Other than income 5,847 5,912 11,897 11,318
----------- ----------- ----------- -----------
752,399 278,218 1,142,095 445,891
----------- ----------- ----------- -----------
OPERATING INCOME 56,042 1,172 25,358 29,529
----------- ----------- ----------- -----------
OTHER INCOME (EXPENSE):
Equity in earnings (losses) of Sierra Pacific Resources (Note 2) 20,985 (2,385) (7,152) 7,822
Allowance for other funds used during construction (122) 1,062 (473) 1,842
Other income - net 2,747 331 3,168 707
----------- ----------- ----------- -----------
23,610 (992) (4,457) 10,371
----------- ----------- ----------- -----------
TOTAL INCOME BEFORE INTEREST CHARGES 79,652 180 20,901 39,900
----------- ----------- ----------- -----------
INTEREST CHARGES:
Long-term debt 18,339 14,253 34,959 30,152
Other 3,750 4,267 7,713 7,932
Allowance for borrowed funds used during construction and
capitalized interest (265) (1,942) 87 (3,757)
----------- ----------- ----------- -----------
21,824 16,578 42,759 34,327
----------- ----------- ----------- -----------
INCOME (LOSS) BEFORE NPC OBLIGATED MANDATORILY
REDEEMABLE PREFERRED TRUST SECURITIES 57,828 (16,398) (21,858) 5,573
Preferred dividend requirements of NPC obligated
mandatorily redeemable preferred trust securities 3,793 3,793 7,586 7,586
----------- ----------- ----------- -----------
NET INCOME (LOSS) $ 54,035 $ (20,191) $ (29,444) $ (2,013)
=========== =========== =========== ===========
Net Income (Loss) Per Share- Basic $ 0.69 $ (0.26) $ (0.38) $ (0.03)
=========== =========== =========== ===========
- Diluted $ 0.69 $ (0.26) $ (0.68) $ (0.03)
=========== =========== =========== ===========
Weighted Average Shares of Common
Stock Outstanding (000's) 78,491 78,420 78,483 78,418
=========== =========== =========== ===========
Dividends Paid Per Share of Common Stock $ -- $ 0.250 $ 0.250 $ 0.500
=========== =========== =========== ===========
The accompanying notes are an integral part of the financial statements.
7
NEVADA POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
Six Months Ended
June 30,
----------------------
2001 2000
--------- ---------
(Unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES:
(Loss) before preferred dividends $ (29,444) $ (2,013)
Non-cash items included in income:
Depreciation and amortization 44,303 42,730
Deferred taxes and deferred investment tax credit 89,758 (3,810)
AFUDC and capitalized interest 560 (5,599)
Amortization of deferred energy costs -- 12,631
Other non-cash (1,670) 6,497
Equity in losses (earnings) of SPR (Note 2) 7,152 (7,822)
Changes in certain assets and liabilities, net of acquisition:
Accounts receivable (273,126) (69,170)
Materials, supplies and fuel (3,306) (1,337)
Deferred energy costs (272,777) --
Other current assets (75,578) (1,576)
Accounts payable 414,458 80,612
Other current liabilities (223) (1,593)
Other - net 4,971 4,211
--------- ---------
Net Cash Flows (Used in) Provided by Operating Activities (94,922) 53,761
--------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to utility plant (88,552) (84,315)
AFUDC and other charges to utility plant (560) 697
Customer refunds for construction (3,739) (735)
Contributions in aid of construction 3,903 --
--------- ---------
Net cash used for utility plant (88,948) (84,353)
Investments in subsidiaries and other property - net -- (388)
--------- ---------
Net Cash Used in Investing Activities (88,948) (84,741)
--------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Decrease in short-term borrowings -- (84,516)
Proceeds from issuance of long-term debt 350,000 150,000
Retirement of long-term debt (151,699) (85,003)
Additional investment by parent company 21,921 128,000
Dividends paid -- (48,000)
--------- ---------
Net Cash Provided by Financing Activities 220,222 60,481
--------- ---------
Net Increase (Decrease) in Cash and Cash Equivalents 36,352 29,501
Beginning balance in Cash and Cash Equivalents 43,858 243
--------- ---------
Ending balance in Cash and Cash Equivalents $ 80,210 $ 29,744
========= =========
Supplemental Disclosures of Cash Flow Information:
Cash Paid (Received) During Period For:
Interest $ 40,910 $ 33,550
Income Taxes $ (10,015) $ 6,500
The accompanying notes are an integral part of the financial statements.
8
SIERRA PACIFIC POWER COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
June 30, December 31,
2001 2000
---------- ----------
(Unaudited)
ASSETS
Utility Plant at Original Cost:
Plant in service $2,254,418 $2,180,019
Less: accumulated provision for depreciation 822,467 781,058
---------- ----------
1,431,951 1,398,961
Construction work-in-progress 93,795 119,210
---------- ----------
1,525,746 1,518,171
---------- ----------
Investments in subsidiaries and other property, net 58,485 60,047
---------- ----------
Current Assets:
Cash and cash equivalents 102,521 5,348
Accounts receivable less provision for uncollectible accounts:
2001 - $4,598; 2000 - $1,589 198,237 133,369
Materials, supplies and fuel, at average cost 42,553 29,209
Other 3,001 29,852
---------- ----------
346,312 197,778
---------- ----------
Deferred Charges:
Deferred energy costs 119,172 16,370
Regulatory tax asset 61,940 61,862
Other regulatory assets 60,763 61,236
Risk management assets (Note 9) 297,640 --
Risk management regulatory assets - net (Note 9) 347,693 --
Other 16,415 12,036
---------- ----------
903,623 151,504
---------- ----------
Net assets of discontinued operations (Note 7) -- 261,479
---------- ----------
$2,834,166 $2,188,979
========== ==========
CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholder's equity 571,709 604,795
Accumulated other comprehensive income 505 --
Preferred stock 50,000 50,000
SPPC obligated mandatorily redeemable preferred trust securities 48,500 48,500
Long-term debt 924,366 605,816
---------- ----------
1,595,080 1,309,111
---------- ----------
Current Liabilities:
Short-term borrowings -- 108,962
Current maturities of long-term debt 19,616 219,616
Accounts payable 145,930 146,724
Accrued interest 10,325 6,992
Dividends declared 10,000 23,975
Accrued salaries and benefits 12,040 15,475
Other current liabilities 9,060 2,932
---------- ----------
206,971 524,676
---------- ----------
Commitments & Contingencies (Note 10)
Deferred Credits:
Deferred federal income taxes 168,551 179,106
Deferred investment tax credit 29,326 30,088
Deferred taxes on deferred energy costs 41,710 --
Regulatory tax liability 30,777 31,087
Accrued retirement benefits 43,458 44,374
Customer advances for construction 44,576 41,776
Risk management liabilities (Note 9) 644,828 --
Other 28,889 28,761
---------- ----------
1,032,115 355,192
---------- ----------
$2,834,166 $2,188,979
========== ==========
The accompanying notes are an integral part of the financial statements.
9
SIERRA PACIFIC POWER COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
Three months ended Six months ended
June 30, June 30,
---------------------- ----------------------
2001 2000 2001 2000
--------- --------- --------- ---------
(unaudited) (unaudited)
OPERATING REVENUES:
Electric $ 320,222 $ 176,820 $ 632,341 $ 334,442
Gas 21,729 15,755 85,894 50,591
--------- --------- --------- ---------
341,951 192,575 718,235 385,033
--------- --------- --------- ---------
OPERATING EXPENSES:
Operation:
Purchased power 248,608 71,949 399,595 121,429
Fuel for power generation 85,041 44,082 187,594 73,358
Gas purchased for resale 25,171 11,470 95,714 34,321
Deferral of energy costs-net (89,058) (1,096) (100,182) (720)
Other 23,174 26,564 50,868 49,720
Maintenance 6,676 4,753 12,000 8,822
Depreciation and amortization 17,859 17,434 34,708 34,583
Taxes:
Income taxes 1,464 884 (656) 12,778
Other than income 4,574 4,269 8,968 8,640
--------- --------- --------- ---------
323,509 180,309 688,609 342,931
--------- --------- --------- ---------
OPERATING INCOME 18,442 12,266 29,626 42,102
--------- --------- --------- ---------
OTHER (EXPENSE) INCOME:
Allowance for other funds used during construction (30) 74 (214) 134
Other income (expense) - net 1,499 (966) 1,013 (1,239)
--------- --------- --------- ---------
1,469 (892) 799 (1,105)
--------- --------- --------- ---------
TOTAL INCOME BEFORE INTEREST CHARGES 19,911 11,374 30,425 40,997
--------- --------- --------- ---------
INTEREST CHARGES:
Long-term debt 12,529 8,379 23,099 15,908
Other 3,022 4,079 5,982 7,171
Allowance for borrowed funds used during construction and
capitalized interest (423) (551) (377) (969)
--------- --------- --------- ---------
15,128 11,907 28,704 22,110
--------- --------- --------- ---------
INCOME (LOSS) BEFORE SPPC OBLIGATED MANDATORILY
REDEEMABLE PREFERRED TRUST SECURITIES 4,783 (533) 1,721 18,887
Preferred dividend requirements of SPPC obligated
mandatorily redeemable preferred trust securities 936 936 1,872 1,872
--------- --------- --------- ---------
INCOME (LOSS) BEFORE PREFERRED STOCK DIVIDENDS 3,847 (1,469) (151) 17,015
Preferred dividend requirements 875 875 1,750 1,750
--------- --------- --------- ---------
NET INCOME (LOSS) FROM CONTINUING OPERATIONS 2,972 (2,344) (1,901) 15,265
--------- --------- --------- ---------
DISCONTINUED OPERATIONS:
Income from operations of water business disposed of
(net of income taxes of $410 and $888 in 2001 and
$732 and ($128) in 2000, respectively) 641 3,830 1,022 4,757
Gain on disposal of water business
(net of income taxes of $18,237) 25,845 -- 25,845 --
--------- --------- --------- ---------
NET INCOME $ 29,458 $ 1,486 $ 24,966 $ 20,022
========= ========= ========= =========
The accompanying notes are an integral part of the financial statements.
10
SIERRA PACIFIC POWER COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
Six Months Ended
June 30,
----------------------
2001 2000
--------- ---------
(Unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES:
(Loss) Income from continuing operations before preferred dividends $ (151) $ 17,015
Income from discontinued operations before preferred dividends 1,222 4,957
Gain on disposal of water business 25,845 --
Non-cash items included in income:
Depreciation and amortization 38,168 38,266
Deferred taxes and investment tax credits 21,932 1,093
AFUDC and capitalized interest (171) (1,268)
Early retirement and severance amortization 3,121 2,098
Gain on disposal of water business (44,081) --
Other non-cash (8,635) 3,763
Changes in certain assets and liabilities:
Accounts receivable (60,552) 11,231
Materials, supplies and fuel (12,991) (5,698)
Deferred energy costs (102,802) (720)
Other current assets 26,728 (116)
Accounts payable (814) (1,721)
Other current liabilities 5,569 9,277
Other-net 5,358 (592)
--------- ---------
Net Cash Flows (Used in) Provided by Operating Activities (102,254) 77,585
--------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to utility plant (70,101) (61,330)
AFUDC and other charges to utility plant 171 1,326
Customer (refunds) advances for construction 203 2,077
Contributions in aid of construction 12,219 5,264
--------- ---------
Net cash used for utility plant (57,508) (52,663)
Proceeds from sale of assets of water business 318,882 --
Investment in subsidiaries and other non-utility property - net 1,447 919
--------- ---------
Net Cash Provided by (Used in) Investing Activities 262,821 (51,744)
--------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Decrease in short-term borrowings (108,942) (111,813)
Proceeds from issuance of long-term debt 320,000 200,000
Retirement of long-term debt (201,450) (2,808)
Additional investment by parent company 4,948 14,000
Dividends paid (77,950) (39,941)
--------- ---------
Net Cash (Used in) Provided by Financing Activities (63,394) 59,438
--------- ---------
Net Increase in Cash and Cash Equivalents 97,173 85,279
Beginning Balance in Cash and Cash Equivalents 5,348 3,011
--------- ---------
Ending Balance in Cash and Cash Equivalents $ 102,521 $ 88,290
========= =========
Supplemental Disclosures of Cash Flow Information:
Cash Paid (Received) During Period For:
Interest $ 31,412 $ 26,252
Income Taxes $ (18,071) $ 9,644
The accompanying notes are an integral part of the financial statements.
11
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
----------------------------------------------------
NOTE 1. MANAGEMENT'S STATEMENT (SPR, NPC, SPPC)
- -------------------------------------------------
In the opinion of the management of Sierra Pacific Resources (SPR),
Nevada Power Company (NPC), and Sierra Pacific Power Company (SPPC), the
accompanying unaudited interim condensed consolidated financial statements
contain all adjustments (consisting of only normal recurring adjustments)
necessary to present fairly the condensed consolidated financial position,
condensed consolidated results of operations and condensed consolidated cash
flows for the periods shown. These condensed consolidated financial statements
do not contain the complete detail or footnote disclosure concerning accounting
policies and other matters which are included in full year financial statements
and, therefore, they should be read in conjunction with the audited financial
statements included in SPR's, NPC's, and SPPC's Combined Annual Report on Form
10-K for the year ended December 31, 2000.
The results of operations for the three months ended June 30, 2001 are
not necessarily indicative of the results to be expected for the full year.
Principles of Consolidation
---------------------------
The condensed consolidated financial statements of SPR include the
accounts of SPR and its wholly owned subsidiaries, Nevada Power Company, Sierra
Pacific Power Company, (collectively, the "Utilities"), Tuscarora Gas Pipeline
Company, Sierra Gas Holding Company (formerly Sierra Energy Company), Sierra
Energy Company dba eo 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 2001 have been
reclassified to conform to the current year's presentation. Net income and
shareholders' equity were not affected by these reclassifications.
Recent Pronouncements
---------------------
In June 2001, the Financial Accounting Standards Board ("FASB")
approved the issuance of three new pronouncements, Statement of Financial
Accounting Standards (SFAS) No. 141, "Business Combinations," SFAS No. 142,
"Goodwill and Other Intangible Assets," and SFAS No. 143, "Accounting for Asset
Retirement Obligations." SFAS No. 141 requires that the purchase method of
accounting be used for all business combinations initiated after June 30, 2001.
Management does not expect SFAS No. 141, when adopted, to have a material effect
on the financial position or results of operations of SPR, NPC, and SPPC. SFAS
No. 142, effective for fiscal years beginning after December 15, 2001, changes
the accounting for goodwill from an amortization method to one requiring at
least an annual review for impairment. Due to the regulatory treatment
anticipated for most of SPR's goodwill, Management does not expect SFAS No. 142,
when adopted, to have a material effect on the financial position or results of
operations of SPR, NPC, and SPPC. SFAS No. 143, effective for fiscal years
beginning after June 15, 2002, requires an entity to record the fair value of a
liability for an asset retirement obligation in the period in which it is
incurred. Management has not yet determined the impact, if any, of the adoption
of SFAS No. 143 on the financial position or results of operations of SPR, NPC,
and SPPC.
NOTE 2. FINANCIAL STATEMENTS OF NEVADA POWER COMPANY (NPC)
- ------------------------------------------------------------
In accordance with Generally Accepted Accounting Principles, the 1999
merger between SPR and NPC was accounted for as a reverse purchase, with NPC
deemed to be the acquirer of SPR as reflected in the SPR Consolidated Financial
Statements. However, after the merger with SPR and as a result of the structure
of the transactions, NPC is a separate legal entity, which is a wholly owned
subsidiary of SPR. As a legal matter, NPC does not own any equity interest in
SPR. The audited NPC Financial Statements accommodate the presentation of
financial information of NPC on a stand-alone basis by summarizing all non-NPC
financial information into a few items on each of the Financial Statements.
These summarized items are repeated below (in 000's):
12
Non-NPC Financial Items on the NPC Financial Statements
NPC Balance Sheet: June 30, 2001 December 31, 2000
- ------------------ ------------- -----------------
Investment in Sierra Pacific Resources $439,784 $471,975
Equity in Sierra Pacific Resources $439,784 $471,975
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 NPC. The Equity in Sierra Pacific Resources reflects
the sum of paid-in-capital and retained earnings of SPR, without the benefit of
NPC.
These line items do not represent any asset to which holders of NPC's
securities may look for recovery of their investment. These items must be
disregarded for determining the ability of NPC to satisfy its obligations or to
pay dividends (preferred or common), for calculating NPC's ratios of earnings to
fixed charges and preferred stock dividends and for all of NPC's financial
covenants and earnings tests including those under its charter and mortgage.
NPC Income Statement: Three Months Ended Three Months Ended
- --------------------- ------------------ ------------------
June 30, 2001 June 30, 2000
------------- -------------
Equity in Earnings (Losses) of Sierra Pacific Resources $20,985 $(2,385)
Six Months Ended Six Months Ended
---------------- ----------------
June 30, 2001 June 30, 2000
------------- -------------
Equity in (Losses) Earnings of Sierra Pacific Resources $(7,152) $7,822
This line does not represent any item of revenue or income to which
holders of NPC's securities may look for recovery of their investment. This item
must be disregarded for determining the ability of NPC to satisfy its
obligations or its ability to pay dividends (preferred or common), for
calculating NPC's ratios of earnings to fixed charges and preferred dividends
and for all of NPC's financial covenants and earnings tests including those
under its charter and mortgage.
NPC Statement of Cash Flow: Six Months Ended Six Months Ended
- --------------------------- ---------------- ----------------
June 30, 2001 June 30, 2000
------------- -------------
Equity in (Losses) Earnings of Sierra Pacific Resources $(7,152) $7,822
As in the income statement, the Equity in Earnings of Sierra Pacific
Resources reflects the three months of SPR net income, after SPPC preferred
stock dividends.
This line item does not represent any item of cash flow to which
holders of NPC's securities may look for recovery of their investment. This item
must be disregarded for determining the ability of NPC to satisfy its
obligations or its ability to pay dividends (preferred or common), for
calculating NPC's ratios of earnings to fixed charges and preferred dividends
and for all of NPC's financial covenants and earnings tests including those
under its charter and mortgage.
NOTE 3. SHORT-TERM BORROWINGS (SPR, NPC, SPPC)
- ------------------------------------------------
As of January 16, 2001, SPR had eliminated its December 31, 2000,
commercial paper balance of $4 million. On March 9, 2001, SPR discontinued its
commercial paper program as a result of the establishment of a credit facility,
which had an outstanding balance of $50 million at March 31, 2001. That credit
facility, which had an expiration date of June 30, 2001, was paid off and
terminated on June 12, 2001.
NPC, which had no commercial paper outstanding at December 31, 2000,
issued approximately $96.2 million of commercial paper during February and March
2001. By May 25, 2001, NPC had eliminated its commercial paper balances and had
no commercial paper outstanding as of June 30, 2001.
SPPC's commercial paper balance increased from $108.9 million at
December 31, 2000, to approximately $149.1 million at March 31, 2001. By June
12, 2001, SPPC had eliminated its commercial paper balances and had no
commercial paper outstanding as of June 30, 2001. At March 31, 2001, SPPC had a
balance of $50.5 million owed to NPC, which was repaid in full on June 12, 2001.
During the quarter ended June 30, 2001, NPC and SPPC each had
short-term credit facilities in the amount of $150 million. As of June 30, 2001,
the Utilities had not drawn on these facilities. On August 1, 2001, NPC and SPPC
each
13
increased the total amount of their short-term credit facilities from $150
million to $250 million and extended the expiration date of their short-term
credit facilities from August 27, 2001 to November 30, 2001. These credit
facilities serve primarily to back up the Utilities' commercial paper programs
and to fund working capital and general corporate needs.
NOTE 4. LONG-TERM DEBT (NPC, SPPC)
- ------------------------------------
On May 24, 2001, NPC issued $350 million of 8.25% General and Refunding
Mortgage Bonds, Series A, due June 1, 2011. The bonds were issued under and
secured by a General and Refunding Mortgage Indenture dated as of May 1, 2001
that is subject to the prior lien of NPC's Indenture of Mortgage dated as of
October 1, 1953. The proceeds of the issuance were used to refinance or
discharge outstanding indebtedness including commercial paper, short-term debt,
and current maturities of long-term debt.
On June 12, 2001, $150 million of NPC's floating rate notes matured and
were paid in full.
On April 27, 2001, Washoe County, Nevada issued for SPPC's benefit $80
million of Water Facilities Refunding Revenue Bonds, Series 2001, due March 1,
2036 (the "Bonds"). The Bonds bear interest at a term rate of 5.75% per annum
from their date of issuance to April 30, 2003. Beginning May 1, 2003, the method
of determining the interest rate on the 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. The Bonds were
issued to refund $80 million of Washoe County variable rate Water Facilities
Revenue Bonds (Sierra Pacific Power Company Project) Series 1990 on April 30,
2001. SPPC's obligations in respect of the Series 1990 bonds had been supported
by a letter of credit that was terminated in connection with the redemption of
those bonds. On June 11, 2001, SPPC completed the sale of its water business
assets including the Project financed by the sale of the Bonds. (See Note 7 for
additional information on the water business sale.) Although SPPC no longer owns
the Project, SPPC will continue to bear the obligations and payments for the
Bonds under the terms of the Financing Agreement dated as of March 1, 2001,
between SPPC and Washoe County, Nevada.
On May 24, 2001, SPPC issued $320 million of its 8.00% General and
Refunding Mortgage Bonds, Series A, due June 1, 2008. The bonds were issued
under and secured by a General and Refunding Mortgage Indenture dated as of May
1, 2001 that is subject to the prior lien of SPPC's Indenture of Mortgage dated
as of December 1, 1940. The proceeds of the issuance were used to refinance or
discharge outstanding indebtedness including commercial paper, short-term debt,
and current maturities of long-term debt.
On June 12, 2001, $200 million of SPPC's floating rate notes matured
and were paid in full.
14
NOTE 5. 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.
Three Months Ended Six Months Ended
June 30, June 30,
--------------------------- ----------------------------
2001 2000 2001 2000
------------ ------------ ------------ ------------
Basic EPS
Numerator ($000)
Income (Loss) from continuing operations $ 27,549 $ (24,021) $ (56,311) $ (6,770)
Income from discontinued operations 641 3,830 1,022 4,757
Gain on disposal of water business 25,845 -- 25,845
------------ ------------ ------------ ------------
Net income (loss) $ 54,035 $ (20,191) $ (29,444) $ (2,013)
============ ============ ============ ============
Denominator
Weighted average number of shares outstanding 78,491,053 78,419,949 78,483,135 78,418,153
------------ ------------ ------------ ------------
Per-Share Amounts:
Income (Loss) from continuing operations $ 0.35 $ (0.31) $ (0.72) $ (0.09)
Income from discontinued operations 0.01 0.05 0.01 0.06
Gain on disposal of water business 0.33 -- 0.33 --
------------ ------------ ------------ ------------
Net income (loss) $ 0.69 $ (0.26) $ (0.38) $ (0.03)
============ ============ ============ ============
Diluted EPS
Numerator ($000)
Income (Loss) from continuing operations $ 27,549 $ (24,021) $ (56,311) $ (6,770)
Income from discontinued operations 641 3,830 1,022 4,757
Gain on disposal of water business 25,845 -- 25,845 --
------------ ------------ ------------ ------------
Net income (loss) $ 54,035 $ (20,191) $ (29,444) $ (2,013)
============ ============ ============ ============
Denominator
Weighted average number of shares outstanding
before dilution 78,491,053 78,419,949 78,483,135 78,418,153
Stock options/1/ 22,160 1,529 11,605 1,341
Executive long term incentive plan-performance shares/1/ 47,698 28,901 41,531 42,652
Non-Employee Director stock plan/1/ 9,355 4,532 9,355 4,532
Employee stock purchase plan/1/ 3,602 694 3,017 347
------------ ------------ ------------ ------------
78,573,868 78,455,605 78,548,643 78,467,025
------------ ------------ ------------ ------------
Per-Share Amounts/1/:
Income (Loss) from continuing operations $ 0.35 $ (0.31) $ (0.72) $ (0.09)
Income from discontinued operations 0.01 0.05 0.01 0.06
Gain on disposal of water business 0.33 -- 0.33 --
------------ ------------ ------------ ------------
Net income (loss) $ 0.69 $ (0.26) $ (0.38) $ (0.03)
============ ============ ============ ============
/1/ Because of net losses for the three months ended June 30, 2000, and the six
months ended June 30, 2001 and 2000, stock equivalents would be
anti-dilutive. Accordingly, Diluted EPS for those periods are computed
using the weighted average number of shares outstanding before dilution.
15
NOTE 6. SEGMENT INFORMATION (SPR)
- -----------------------------------
SPR operates two business segments providing regulated electric and
natural gas services. NPC provides electric service to Las Vegas and surrounding
Clark County. SPPC provides electric service in northern Nevada and the Lake
Tahoe area of California. SPPC also provides natural gas service in the
Reno-Sparks area of Nevada. Other segment information includes segments below
the quantitative threshold for separate disclosure. In September 2000, SPR and
SPPC adopted a plan to sell SPPC's water utility business. The sale of the water
utility business was completed on June 11, 2001. Accordingly, the water business
is not included in the segment information below.
Information as to the operations of the different business segments is
set forth below based on the nature of products and services offered. SPR
evaluates performance based on several factors, of which the primary financial
measure is business segment operating income. Intersegment revenues are not
material.
Financial data for business segments is as follows (in thousands):
Three Months Ended
June 30, 2001 Electric Gas Other Consolidated
------------------ ---------- ---------- ---------- ----------
Operating Revenues $1,128,663 $ 21,729 $ 5,070 $1,155,462
========== ========== ========== ==========
Operating Income $ 73,929 $ 554 $ 3,811 $ 78,294
========== ========== ========== ==========
Three Months Ended
June 30, 2000 Electric Gas Other Consolidated
------------------ ---------- ---------- ---------- ----------
Operating Revenues $ 456,210 $ 15,755 $ 2,347 $ 474,312
========== ========== ========== ==========
Operating Income $ 12,299 $ 1,139 $ 1,706 $ 15,144
========== ========== ========== ==========
Six Months Ended
June 30, 2001 Electric Gas Other Consolidated
------------------ ---------- ---------- ---------- ----------
Operating Revenues $1,799,794 $ 85,894 $ 7,700 $1,893,388
========== ========== ========== ==========
Operating Income $ 49,335 $ 5,649 $ (7,176) $ 47,808
========== ========== ========== ==========
Six Months Ended
June 30, 2000 Electric Gas Other Consolidated
------------------ ---------- ---------- ---------- ----------
Operating Revenues $ 809,862 $ 50,591 $ 6,508 $ 866,961
========== ========== ========== ==========
Operating Income $ 65,880 $ 5,751 $ 706 $ 72,337
========== ========== ========== ==========
NOTE 7. DISCONTINUED OPERATIONS (SPR, SPPC)
- ---------------------------------------------
On September 7, 2000, SPR and SPPC adopted a plan to sell SPPC's water
utility business, and on June 11, 2001, SPPC closed the sale of its water
business to the Truckee Meadows Water Authority (TMWA) for $341 million. SPPC
recorded a $25.8 million gain on the sale, net of the refund described below and
net of income taxes of $18.2 million. Included in the sale were facilities for
water storage, supply, transmission, treatment and distribution, as well as
accounts receivable and regulatory assets. Accounts receivable consisted of
amounts due from developers for distribution facilities. Regulatory assets
consisted primarily of costs incurred in connection with the Truckee River
negotiated water settlement. Transfer of hydroelectric facilities included in
the sale for an additional $8 million will require action by the California
Public Utilities Commission (CPUC). The sale agreement contemplates a second
closing for the hydroelectric facilities to accommodate the CPUC's review of the
transaction.
Pursuant to a stipulation entered into in connection with the sale and
approved by the Public Utilities Commission of Nevada ("PUCN"), SPPC is required
to refund to customers $21.5 million of the proceeds from the sale. The refund
will be credited on the electric bills of SPPC's former water customers over a
period not to exceed fifteen months after the close of the sale. Under a service
contract with TMWA, SPPC will provide, on an interim basis, customer service,
billing, and meter reading services to TMWA.
Revenues from operations of the water business were $11.8 million and
$15.3 million for the three-month periods ended June 30, 2001, and June 30,
2000, respectively. For the six-month periods ended June 30, 2001, and June 30,
2000,
16
revenues from operations of the water business were $23.2 million and $25.6
million, respectively. The net income from operations of the water business, as
shown in the Condensed Consolidated Statements of Income of SPR and SPPC,
includes preferred dividends of approximately $100,000 for each of the
three-month periods ended June 30, 2001 and 2000, and approximately $200,000 for
each of the six-month periods ended June 30, 2001 and 2000. These amounts are
not included in the revenues and income (loss) from continuing operations shown
in the accompanying income statements.
NOTE 8. REGULATORY EVENTS (SPR, NPC, SPPC)
- --------------------------------------------
On April 18, 2001, the Governor of Nevada signed into law AB369. The
provisions of AB369 include a moratorium on the sale of generation assets by
electric utilities, the repeal of electric industry restructuring, and a
reinstatement of deferred energy accounting for fuel and purchased power costs
incurred by electric utilities. The stated purposes of this emergency
legislation were, among others, to control volatility in the price of
electricity in the retail market in Nevada and to ensure that the Utilities have
the necessary financial resources to provide adequate and reliable electric
service under present market conditions. To achieve these purposes, AB369 allows
the Utilities to recover in future periods their costs for wholesale power and
fuel, which have risen dramatically over the past year. Deferred energy
accounting will have the effect of delaying additional rate increases to
consumers until early next year while, at the same time, providing a method for
the Utilities to recover their increasing costs for fuel and purchased power.
Set forth below is a summary of key provisions of AB369.
Generation Divestiture Moratorium
- ---------------------------------
AB369 prohibits all divestiture of generation assets by electric
utilities until July 2003. After January 1, 2003, NPC or SPPC may seek PUCN
permission to sell one or more generation assets with the sale to be effective
on or after July 1, 2003. The PUCN may approve the request to divest only if it
finds the transaction to be in the public interest. The PUCN may base its
approval of the request upon such terms, conditions, or modifications as it
deems appropriate.
AB369 directs the PUCN to take all steps necessary to obtain federal
approval for the prohibition on divestiture and to vacate any of its own orders
that had previously approved generation divestiture transactions.
Deferred Energy Accounting
- --------------------------
AB369 requires both Utilities to use deferred energy accounting for
their respective electric operations beginning on March 1, 2001. The intent of
deferred energy accounting is to ease the effect of fluctuations in the cost of
purchased power and fuel. Under deferred energy accounting, to the extent actual
fuel and purchased power costs exceed fuel and purchased power costs recoverable
through current rates, that excess is not recorded as a current expense on the
income statement but rather is deferred and recorded as an asset on the balance
sheet. Conversely, a liability is recorded to the extent fuel and purchased
power costs recoverable through current rates exceed actual fuel and purchased
power costs. These excess amounts are reflected in adjustments to rates and
recorded as revenue or expense in future time periods, subject to PUCN review.
AB369 provides that the PUCN may not allow the recovery of any costs for
purchased fuel or purchased power "that were the result of any practice or
transaction that was undertaken, managed or performed imprudently by the
electric utility." In reference to deferred energy accounting, AB369 specifies
that fuel and purchased power costs include all costs incurred to purchase fuel,
to purchase capacity and to purchase energy. The Utilities also record, and are
eligible to recover, a carrying charge on such deferred balances.
AB369 requires that each Utility file an application to clear its
deferred energy account balances after the end of each 12-month period, but
allows the balances from each 12-month period to be recovered over an adjustment
period of up to three years in order to reduce the volatility of rate changes.
In addition, after the initial deferred energy case, each Utility is allowed to
file an application to clear its deferred energy account balances after the end
of a six-month period if the proposed net increase or decrease in fuel and
purchased power revenues for the six-month period is more than 5%. If a Utility
using deferred energy accounting realizes a rate of return greater than the rate
authorized by the PUCN, the portion that exceeds the authorized rate of return
will be transferred to the next deferred energy adjustment period.
Before an electric utility may clear its deferred accounts, AB 369
requires the PUCN to determine whether the costs for purchased fuel and
purchased power that the electric utility recorded in its deferred accounts are
recoverable and whether the revenues that the electric utility collected from
customers in Nevada for purchased fuel and purchased power are properly recorded
and credited in its deferred accounts. AB 369 prohibits the PUCN from allowing
an electric utility to recover any costs for purchased fuel and purchased power
that were the result of any practice or transaction that was undertaken, managed
or performed imprudently by the electric utility.
In addition, as discussed under "Required Filings" below, the PUCN must
determine whether the rates that went into effect on March 1, 2001, pursuant to
the CEP (as defined below) are just and reasonable and reflect prudent business
practices.
17
At June 30, 2001, NPC had a balance of $272.8 million in its deferred
energy account, reflecting eligible fuel and purchased power costs incurred
since March 1, 2001. At June 30, 2001, SPPC had a balance of $119.2 million in
its deferred energy account, which reflects both deferrals in connection with
its natural gas business as well as eligible fuel and purchased power costs
incurred since March 1, 2001. Management expects these balances to increase
significantly during the summer of 2001, particularly at NPC, although the
amount of such increases will depend on a number of unpredictable factors such
as weather conditions and conditions in the wholesale electricity and gas
markets in the western United States.
Transition of Rates to Deferred Energy Accounting
- -------------------------------------------------
All rates in effect on April 1, 2001, including the cumulative
increases under the Global Settlement and the Comprehensive Energy Plan ("CEP")
Riders, remain in effect until the PUCN issues final orders on future general
and initial deferred energy rate applications. (See "Required Filings," below).
No further applications can be made for the Fuel and Purchased Power (F&PP)
riders that were part of the July 2000 Global Settlement described in SPR's
Annual Report on Form 10-K for the year ended December 31, 2000.
The Utilities will not be permitted to recover any shortfall incurred
before March 1, 2001, resulting from the difference between actual fuel and
purchased power costs and the rates permitted by the Global Settlement. Although
the F&PP riders were in effect during this period, the riders were based on
trailing 12-month average costs and were subject to caps and therefore did not
allow the Utilities full recovery for fuel and purchased power costs due to the
rapid rise in energy prices.
AB369 prohibits the PUCN from taking any further action on the CEP
described in SPR's Annual Report on Form 10-K for the year ended December 31,
2000, and provides that, except for the CEP Rider rate increases put in effect
on April 1, 2001, the CEP will be deemed to have been withdrawn by the
Utilities. Additionally, approximately $20 million of revenue collected by the
Utilities based on the CEP before April 1, 2001, was credited to the deferred
energy accounts, which caused the accounts to start in an over-collected
position.
Required Filings
- ----------------
NPC and SPPC are each required to file a general rate application and a
deferred energy application on or before the dates listed below:
General Rate Case Deferred Energy Filing
----------------- ----------------------
File Date Effective Date File Date Effective Date
--------- -------------- --------- --------------
Nevada Power Company Oct. 1, 2001 April 1, 2002 Dec. 1, 2001 April 1, 2002
Sierra Pacific Power Company Dec. 1, 2001 June 1, 2002 Feb. 1, 2002 June 1, 2002
In connection with clearing the Utilities' deferred energy accounts,
the PUCN must investigate and determine whether the Utilities' rates that went
into effect on March 1, 2001, pursuant to the CEP, are just and reasonable and
reflect prudent business practices. The rates in effect on April 1, 2001, remain
in effect until the PUCN issues final orders on the general and initial deferred
energy rate applications referred to above. The PUCN is prohibited from
adjusting rates during this time period unless an adjustment is absolutely
necessary to avoid a finding that the rates are confiscatory and therefore in
violation of the United States or Nevada Constitutions. If adjustments are
necessary, they may only be made to the extent necessary to avoid an
unconstitutional result.
After the initial general rate applications described above, each
Utility will be required to file future general rate applications at least every
24 months.
Restrictions on Mergers and Acquisitions
- ----------------------------------------
AB369 imposes certain restrictions on mergers and acquisitions
involving Nevada electric utilities. In particular, the PUCN may not approve a
merger or acquisition involving an electric utility unless the utility complies
with the generation divestiture provisions of AB369.
In addition, AB369 includes provisions that would have significantly
affected the required regulatory approvals for the proposed acquisition of
Portland General Electric Company (PGE) from Enron Corp. On April 26, 2001,
Enron Corp. and SPR terminated, by mutual agreement, the proposed purchase and
sale of PGE.
18
Repeal of Electric Industry Restructuring
- -----------------------------------------
AB369 repeals all statutes authorizing retail competition in Nevada's
electric utility industry and voids any license issued to an alternative seller
in connection with retail electric competition.
Other Legislation
- -----------------
Senate Bill 372 ("SB372"), which increased renewable energy portfolio
requirements, was enacted in the 2001 Nevada legislative session. Renewable
resources include biomass, wind, solar and geothermal projects. In 2003, both
SPPC and NPC will be required to purchase five percent of their energy from
renewable resources. These requirements increase to 15% by 2013. Prior law
capped renewable energy requirements at one percent. Currently SPPC obtains
approximately nine percent of its energy from renewable resources while NPC
obtains less than one percent from renewables. SB372 requires the PUCN to
establish standards for renewable energy contracts including prices and other
terms and conditions. If sufficient renewable energy contracts that meet PUCN
standards are not available, the Utilities will not be required to meet the
portfolio requirements. All renewable energy contracts meeting PUCN standards
will be recoverable in the deferred energy accounts.
The 2001 Nevada Legislature passed another key piece of legislation for
the energy industry, Assembly Bill 661 ("AB661"). AB661 allows commercial and
governmental customers with an average demand greater than 1 megawatt (MW) to
select new energy suppliers. The Utilities would continue to provide
transmission, distribution, metering and billing services to such customers.
AB661 requires customers wishing to choose a new supplier to receive the
approval of the PUCN and meet public interest standards. In particular,
departing customers must secure new energy resources that are not under contract
to the Utilities, remaining customers cannot be negatively impacted by the
departure, and the departing customers must pay any deferred energy fuel
balances. Certain limits are placed upon the departure of NPC customers until
2003; most significantly, the amount of load departing is limited to
approximately 1100 MW in peak conditions. AB661 permits customers to file
applications with the PUCN beginning in the fourth quarter of 2001. Customers
must provide 180-day notice to the Utilities and could begin to receive service
from new suppliers in mid-2002.
AB661 also contains new electric and gas energy surcharges for
low-income assistance and weatherization programs. These surcharges are
recoverable directly from customers as separate line items on their bills with
the Utilities remitting collected surcharges to the PUCN. Various state agencies
will administer the disposition of the funds.
FERC Price Cap
- --------------
On June 19, 2001, the Federal Energy Regulatory Commission ("FERC")
adopted a price mitigation plan applicable to wholesale power sales in
California and throughout the western United States during the period June 20,
2001 through September 30, 2002. The price mitigation plan establishes a
mechanism with which to determine the maximum amount that may be charged for
power sold during this period. The intent of the mitigation plan is to simulate
the price that might be charged for electricity sold under competitive market
conditions. Sellers that do not wish to establish rates on the basis of this
price mitigation plan may propose cost-of-service rates covering all of their
generating units in the Western Systems Coordinating Council for the duration of
the mitigation plan. Management is not able to predict at this time the extent
to which the FERC price mitigation plan may affect SPR's results of operations.
It is possible, however, under certain market conditions, that the FERC plan may
adversely affect the availability of spot market power to the Utilities and may
reduce the price at which the Utilities can sell power on the wholesale market.
SPR recently joined with two utilities in Washington and Oregon to seek changes
to the FERC plan on the basis that the price caps are unfair to electric
customers who reside outside of California.
NOTE 9. DERIVATIVES AND HEDGING ACTIVITIES (SPR, NPC, SPPC)
- ------------------------------------------------------------
Effective January 1, 2001, SPR, SPPC, and NPC adopted the Statement of
Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative
Instruments and Hedging Activities," as amended by SFAS No. 138, both issued by
the Financial Accounting Standards Board. As amended, SFAS No. 133 requires that
an entity recognize all derivatives as either assets or liabilities in the
statement of financial position, measure those instruments at fair value, and
recognize changes in the fair value of the derivative instruments in earnings in
the period of change unless the derivative qualifies as an effective hedge.
The adoption of this standard did not have a material impact on the
earnings of SPR or the Utilities. SPR and the Utilities did, however, recognize
all derivatives as assets or liabilities in the condensed consolidated balance
sheets upon adoption and measured those instruments at fair value. This resulted
in SPR, NPC, and SPPC recording $981 million, $678 million, and $303 million of
risk management assets, respectively, and $822 million, $722 million, and $97
million of risk management liabilities, respectively, at January 1, 2001.
19
On April 18, 2001, AB 369 was signed into law in Nevada. AB 369
reinstated deferred energy accounting by the Utilities effective March 1, 2001.
(See Note 8 - Regulatory Events, above.) As a result, fuel and purchased power
expenses, including gains and losses on derivative instruments, are recoverable
or payable through future rates. In accordance with SFAS No. 71, "Accounting for
the Effects of Certain Types of Regulation," regulatory assets and liabilities
are established to the extent that such derivative gains and losses are
recoverable or payable through future rates. Because of this accounting
treatment, the Utilities will not apply hedge accounting to their electricity
and natural gas derivatives. However, SPR and the Utilities have adopted cash
flow hedge accounting for other derivative instruments not subject to regulatory
treatment. The transition adjustments resulting from adoption of SFAS No. 133
related to the other derivative instruments not subject to regulatory treatment
was reported as the cumulative effect of a change in accounting principle in
Other Comprehensive Income of SPR and the Utilities.
SPR's and the Utilities' objective in using derivatives is to reduce
exposure to energy price risk and interest rate risk. Energy price risks result
from activities that include the generation, procurement and marketing of power
and the procurement and marketing of natural gas. Derivative instruments used to
manage energy price risk include forwards and swaps. These contracts allow the
Utilities to reduce the risks associated with volatile electricity and natural
gas markets.
Derivatives used to manage interest rate risk include interest rate
swaps designed to moderate exposure to interest-rate changes and lower the
overall cost of borrowing. At June 30, 2001, SPR had one interest rate swap
related to $200 million of SPR floating rate notes maturing April 20, 2003. This
interest rate swap is considered a completely effective cash flow hedge.
At June 30, 2001, the fair value of the derivatives resulted in the
recording of $1.044 billion, $746 million and $298 million in risk management
assets and $1.705 billion, $1.055 billion and $645 million in risk management
liabilities in the Consolidated Balance Sheets of SPR, NPC and SPPC,
respectively. Due to the regulatory environment in which the Utilities operate,
regulatory assets and liabilities were established to the extent that
electricity and natural gas derivative gains and losses are recoverable or
payable through future rates. Accordingly, at June 30 2001, $657 million, $309
million and $348 million in net risk management regulatory assets were recorded
in the Consolidated Balance Sheets of SPR, NPC, and SPPC, respectively. In
addition, for the six months ended June 30, 2001, the unrealized gains and
losses resulting from the change in the fair value of derivatives designated and
qualifying as cash flow hedges for SPR, NPC, and SPPC were recorded in Other
Comprehensive Income. Such amounts will be reclassified into earnings when the
related transactions are settled or terminate. No amounts were reclassified into
earnings during the six months ended June 30, 2001.
The effects of the adoption of SFAS No. 133 on comprehensive income and
the components thereof at June 30, 2001, are as follows:
Comprehensive Income (in $000's) SPR NPC SPPC
-------- -------- --------
Net (Loss) Income for the six months ended June 30, 2001 $(29,444) $(29,444) $ 24,966
Cumulative effect upon adoption of change in
accounting principle, January 1, 2001, net of taxes (1,923) 444 212
Change in market value of risk management assets and
liabilities as of June 30, 2001, net of taxes (1,540) 617 293
-------- -------- --------
Accumulated Other Comprehensive (Loss) Income (3,463) 1,061 505
-------- -------- --------
Total Comprehensive (Loss) Income for the
six months ended June 30, 2001 $(32,907) $(28,383) $ 25,471
======== ======== ========
Management has evaluated the impact of Derivatives Implementation Group
Issues C10 and C15 with respect to option contracts and optionality features. In
Management's opinion, the implementation of these interpretations will not
result in any changes to the initial application of SFAS No. 133 nor have a
significant impact on the financial position or results of operations of SPR or
the Utilities.
NOTE 10. COMMITMENTS AND CONTINGENCIES (SPR, NPC)
- --------------------------------------------------
Nevada Power Company
- --------------------
The Grand Canyon Trust and Sierra Club filed a lawsuit in the U.S.
District Court, District of Nevada, in February 1998, against the owners
(including NPC) of the Mohave Generation Station ("Mohave"), alleging violations
of the Clean Air
20
Act regarding emissions of sulfur dioxide and particulates. An additional
plaintiff, National Parks and Conservation Association later joined the suit.
The plant owners and plaintiffs have had numerous settlement discussions and
filed a proposed settlement with the court in October 1999. The consent decree,
approved by the court in November 1999, established emission limits for sulfur
dioxide and opacity and required installation of air pollution controls for
sulfur dioxide, nitrogen oxides and particulate matter. The new emission limits
must be met by January 1, 2006 and April 1, 2006, for the first and second units
respectively. However, if the owners sell their entire ownership interest with a
closing date prior to December 30, 2002, the new emission limits become
effective 36 months and 39 months from the date of last closing for the two
respective units. The estimated cost of new controls is $300 million. As a 14%
owner in the Mohave Station, NPC's cost could be $42 million.
Also, the United States Congress authorized the 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 Mohave 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. Mohave's owners
believe that settlement of the suit discussed above is acceptable to the EPA.
Provisions that are agreed to in a settlement are expected to be reflected in a
State Implementation Plan for Nevada and resolve any concerns of the EPA
regarding visibility impairment.
In May 1997, NDEP ordered NPC to submit a plan to eliminate the
discharge of Reid Gardner Station wastewater to groundwater. The NDEP order also
required a hydrological assessment of groundwater impacts in the area. In June
1999, NDEP determined that wastewater ponds had degraded groundwater quality. In
August 1999, NDEP issued a discharge permit to Reid Gardner Station and an order
that requires all wastewater ponds to be closed or lined with impermeable liners
over the next 10 years. This order also required NPC to submit a Site
Characterization Plan to NDEP to ascertain impacts. This plan is under review by
NDEP. After approval, an estimate of remediation costs will be determined by
NPC. New pond construction and lining costs are estimated at $20 million.
In July 2000, NPC received from the United States Environmental
Protection Agency (EPA) a request for information to determine the compliance of
certain generation facilities at the Clark Station with the applicable State
Implementation Plan. In November 2000, NPC and the Clark County Health District
entered into a Corrective Action Order requiring, among other steps, capital
expenditures at the Clark Station totaling approximately $3 million. In March
2001, the EPA issued an additional request for information that could result in
remediation beyond that specified in the November 2000 Corrective Action Order.
If the EPA prevails, capital expenditures and temporary outages of four of Clark
Station's generation units could be required. Additionally, depending on the
time of year that the compliance activity and corresponding generation outage
would occur, the incremental cost to purchase replacement energy could be
substantial.
Other Subsidiaries of SPR
- -------------------------
Nevada Electric Investment Company (NEICO), a wholly owned subsidiary
of SPR, owns property in Wellington, Utah, which was the site of a coal washing
and load out facility. The site now has a reclamation estimate supported by a
bond of $4 million with the Utah Division of Oil and Gas Mining. The property
was under contract for sale and the contract required the purchaser to provide
$1.3 million in escrow towards reclamation. However, the sales contract was
terminated and NEICO took title to the escrow funds. In September 2000, NEICO
leased the property together with an option to purchase it. It is NEICO's
intention to sell the property.
NOTE 11. SUBSEQUENT EVENTS (SPR, SPPC)
- ---------------------------------------
On July 20, 2001, SPR's Board of Directors declared a dividend on
common stock of 20 cents per share, payable September 15, 2001, to shareholders
of record at the close of business on August 24, 2001.
On July 24, 2001, SPR filed with the Securities and Exchange Commission
an amended registration statement relating to an offering of 21,850,000 shares
of common stock. SPR intends to use the net proceeds to contribute capital to
NPC and SPPC to reduce short-term debt obligations and for general corporate
purposes, which may include repayment of long-term debt.
On August 3, 2001, NPC issued $115 million principal amount of its
First Mortgage Bonds, Series BB and Series CC, to AMBAC Assurance Corporation
("AMBAC") in satisfaction of a covenant contained in insurance agreements
entered into with AMBAC in June and July 2000, in connection with the issuance
by Clark County, Nevada of tax-exempt bonds for the benefit of NPC. These First
Mortgage Bonds secure NPC's reimbursement obligations under the insurance
agreements with AMBAC.
On August 7, 2001, SPPC declared $975,000 ($0.4875 per share) in
dividends to holders of its preferred stock. The dividend is payable on
September 1, 2001, to holders of record as of August 10, 2001.
On August 7, 2001, NPC declared a $33 million dividend on its common
stock, all of which is held by SPR.
21
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, pending or future Nevada, California or
federal legislation, 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 Nevada Power Company (NPC), Sierra Pacific Power Company
(SPPC) (collectively, the "Utilities"), or Sierra Pacific Resources (SPR), to
differ materially from those contemplated in any forward-looking statement
include, among others, the following:
(1) the outcome and timing of rate cases to be filed by NPC and SPPC with
the Public Utilities Commission of Nevada (PUCN), including the
periodic applications authorized by recent Nevada legislation to
permit the Utilities to recover costs for fuel and purchased power
which have been recorded by the Utilities in their deferred energy
accounts and deferred natural gas recorded by SPPC for its gas
distribution business;
(2) the extent to which high energy prices and the financial difficulties
of electric utilities and power exchanges in the western United States
cause any counterparties to NPC's or SPPC's purchased power contacts
to default on their obligations, thus requiring the Utilities to seek
to replace the power on the spot market;
(3) the effect of price controls promulgated in June 2001 by the Federal
Energy Regulatory Commission (FERC) on the availability and price of
wholesale power purchases and sales in the western United States;
(4) the ability of SPR, NPC and SPPC to access the capital markets to
support their requirements for working capital, construction costs and
the repayment of maturing debt;
(5) whether the PUCN will issue favorable orders in a timely manner to
permit the Utilities to borrow money and issue additional securities
to finance the Utilities' operations and to purchase power and fuel
necessary to serve their respective customers;
(6) the effect of current or future Nevada, California or federal
legislation or regulations affecting electric industry restructuring,
including laws or regulations which could allow certain customers to
chose new electricity suppliers;
(7) unseasonable weather and other natural phenomena, which can have
potentially serious impacts on the Utilities' ability to procure
adequate supplies of fuel or purchased power to serve their respective
customers and on the cost of procuring such supplies;
(8) industrial, commercial and residential growth in the service
territories of the Utilities;
(9) the loss of any significant customers;
(10) changes in the business of major customers, including those engaged in
gold mining or gaming, which may result in changes in the demand for
services of NPC or SPPC;
(11) changes in environmental regulations, tax or accounting matters or
other laws and regulations to which the Utilities are subject;
(12) future economic conditions, including inflation rates and monetary
policy;
(13) financial market conditions, including changes in availability of
capital or interest rate fluctuations;
(14) unusual or unanticipated changes in normal business operations,
including unusual maintenance or repairs; and
(15) employee workforce factors, including changes in collective bargaining
unit agreements, strikes or work stoppages.
22
Other factors and assumptions not identified above may also have been
involved in deriving these forward-looking statements, and the failure of those
other assumptions to be realized, as well as other factors, may also cause
actual results to differ materially from those projected. SPR, NPC and SPPC
assume no obligation to update forward-looking statements to reflect actual
results, changes in assumptions or changes in other factors affecting
forward-looking statements.
SIERRA PACIFIC RESOURCES
- ------------------------
During the first six months of 2001, SPR incurred a loss of $54.6
million from continuing operations before preferred stock dividend requirements.
However, for the three months ended June 30, 2001, SPR earned $28.4 million from
continuing operations before preferred stock dividend requirements. During the
first six months of 2001, SPR paid $19.8 million in common stock dividends. NPC
and SPPC, SPR's principal subsidiaries, paid common stock dividends of $0 and
$76 million, respectively, to their parent, SPR. SPPC also paid $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 first six months of 2001 were negatively affected by
the significantly higher and extremely volatile fuel and purchased power costs
that developed in the western United States in May 2000 and have continued
since.
In an effort to mitigate the effects of higher fuel and purchased power
costs, during 2000 NPC and SPPC (collectively, the "Utilities") entered into the
Global Settlement, which established a mechanism that initiated incremental rate
increases for each Utility. However, because the mechanism for adjusting rates
lagged changes in actual energy costs and was subject to certain caps, increases
were insufficient to cover fuel and purchased power costs. Cumulative electric
rate increases under the Global Settlement for NPC and SPPC, respectively, are
$127 million and $65 million per year.
Because the rate adjustment mechanism of the Global Settlement could
not keep pace with the continued escalation of fuel and purchased power prices,
on January 29, 2001, the Utilities filed a Comprehensive Energy Plan (CEP) with
the PUCN. The CEP included a request for emergency rate increases (CEP Riders).
On March 1, 2001, the PUCN permitted the requested CEP Riders to go into effect
subject to later review. The CEP Riders provided further rate increases of $210
million and $104 million per year, respectively, for NPC and SPPC.
Notwithstanding the increases under the Global Settlement and the CEP
Riders, the Utilities' revenues for fuel and purchased power recovery continued
to be less than the related expenses. Accordingly, the Utilities sought
additional relief pursuant to legislation. As described in more detail below, in
April 2001 the Nevada Legislature enacted AB369, the provisions of which include
the reinstatement of deferred energy accounting by the Utilities beginning March
1, 2001. Deferred energy accounting allows the Utilities to recover in future
periods that portion of their costs for fuel and purchased power not covered by
current rates and defers to future periods the expense associated with the
amounts by which fuel and purchased power costs exceed the costs to be recovered
in current rates.
NEVADA ENERGY LEGISLATION
-------------------------
On April 18, 2001, the Governor of Nevada signed into law AB369. The
provisions of AB369 include a moratorium on the sale of generation assets by
electric utilities, the repeal of electric industry restructuring, and a
reinstatement of deferred energy accounting for fuel and purchased power costs
incurred by electric utilities. The stated purposes of this emergency
legislation were, among others, to control volatility in the price of
electricity in the retail market in Nevada and to ensure that the Utilities have
the necessary financial resources to provide adequate and reliable electric
service under present market conditions. To achieve these purposes, AB369 allows
the Utilities to recover in future periods their costs for wholesale power and
fuel, which have risen dramatically over the past year. Deferred energy
accounting will have the effect of delaying additional rate increases to
consumers until early next year while, at the same time, providing a method for
the Utilities to recover their increasing costs for fuel and purchased power.
Set forth below is a summary of key provisions of AB369.
Generation Divestiture Moratorium
- ---------------------------------
AB369 prohibits all divestiture of generation assets by electric
utilities until July 2003. After January 1, 2003, NPC or SPPC may seek PUCN
permission to sell one or more generation assets with the sale to be effective
on or after July 1, 2003. The PUCN may approve the request to divest only if it
finds the transaction to be in the public interest. The PUCN may base its
approval of the request upon such terms, conditions, or modifications as it
deems appropriate.
AB369 directs the PUCN to take all steps necessary to obtain federal
approval for the prohibition on divestiture and to vacate any of its own orders
that had previously approved generation divestiture transactions.
23
Deferred Energy Accounting
- --------------------------
AB369 requires both Utilities to use deferred energy accounting for
their respective electric operations beginning on March 1, 2001. The intent of
deferred energy accounting is to ease the effect of fluctuations in the cost of
purchased power and fuel. Under deferred energy accounting, to the extent actual
fuel and purchased power costs exceed fuel and purchased power costs recoverable
through current rates, that excess is not recorded as a current expense on the
income statement but rather is deferred and recorded as an asset on the balance
sheet. Conversely, a liability is recorded to the extent fuel and purchased
power costs recoverable through current rates exceed actual fuel and purchased
power costs. These excess amounts are reflected in adjustments to rates and
recorded as revenue or expense in future time periods, subject to PUCN review.
AB369 provides that the PUCN may not allow the recovery of any costs for
purchased fuel or purchased power "that were the result of any practice or
transaction that was undertaken, managed or performed imprudently by the
electric utility." In reference to deferred energy accounting, AB369 specifies
that fuel and purchased power costs include all costs incurred to purchase fuel,
to purchase capacity and to purchase energy. The Utilities also record, and are
eligible to recover, a carrying charge on such deferred balances.
AB369 requires that each Utility file an application to clear its
deferred energy account balances after the end of each 12-month period, but
allows the balances from each 12-month period to be recovered over an adjustment
period of up to three years in order to reduce the volatility of rate changes.
In addition, after the initial deferred energy case, each Utility is allowed to
file an application to clear its deferred energy account balances after the end
of a six-month period if the proposed net increase or decrease in fuel and
purchased power revenues for the six-month period is more than 5%. If a Utility
using deferred energy accounting realizes a rate of return greater than the rate
authorized by the PUCN, the portion that exceeds the authorized rate of return
will be transferred to the next deferred energy adjustment period.
Before an electric utility may clear its deferred accounts, AB 369
requires the PUCN to determine whether the costs for purchased fuel and
purchased power that the electric utility recorded in its deferred accounts are
recoverable and whether the revenues that the electric utility collected from
customers in Nevada for purchased fuel and purchased power are properly recorded
and credited in its deferred accounts. AB 369 prohibits the PUCN from allowing
an electric utility to recover any costs for purchased fuel and purchased power
that were the result of any practice or transaction that was undertaken, managed
or performed imprudently by the electric utility.
In addition, as discussed under "Required Filings" below, the PUCN must
determine whether the rates that went into effect on March 1, 2001, pursuant to
the CEP are just and reasonable and reflect prudent business practices.
At June 30, 2001, NPC had a balance of $272.8 million in its deferred
energy account, reflecting eligible fuel and purchased power costs incurred
since March 1, 2001. At June 30, 2001, SPPC had a balance of $119.2 million in
its deferred energy account, which reflects both deferrals in connection with
its natural gas business as well as eligible fuel and purchased power costs
incurred since March 1, 2001. Management expects these balances to increase
significantly during the summer of 2001, particularly at NPC, although the
amount of such increases will depend on a number of unpredictable factors such
as weather conditions and conditions in the wholesale electricity and gas
markets in the western United States.
Transition of Rates to Deferred Energy Accounting
- -------------------------------------------------
All rates in effect on April 1, 2001, including the cumulative
increases under the Global Settlement and the CEP Riders, remain in effect until
the PUCN issues final orders on future general and initial deferred energy rate
applications. (See "Required Filings," below). No further applications can be
made for the Fuel and Purchased Power (F&PP) riders that were part of the July
2000 Global Settlement described in SPR's Annual Report on Form 10-K for the
year ended December 31, 2000.
The Utilities will not be permitted to recover any shortfall incurred
before March 1, 2001, resulting from the difference between actual fuel and
purchased power costs and the rates permitted by the Global Settlement. Although
the F&PP riders were in effect during this period, the riders were based on
trailing 12-month average costs and were subject to caps and, therefore, did not
allow the Utilities full recovery for fuel and purchased power costs due to the
rapid rise in energy prices.
AB369 prohibits the PUCN from taking any further action on the CEP
described in SPR's Annual Report on Form 10-K for the year ended December 31,
2000, and provides that, except for the CEP Rider rate increases put in effect
on April 1, 2001, the CEP will be deemed to have been withdrawn by the
Utilities. Additionally, approximately $20 million of revenue collected by the
Utilities based on the CEP before April 1, 2001, was credited to the deferred
energy accounts, which caused the accounts to start in an over-collected
position.
24
Required Filings
- ----------------
NPC and SPPC are each required to file a general rate application and a
deferred energy application on or before the dates listed below:
General Rate Case Deferred Energy Filing
----------------- ----------------------
File Date Effective Date File Date Effective Date
--------- -------------- --------- --------------
Nevada Power Company Oct. 1, 2001 April 1, 2002 Dec. 1, 2001 April 1, 2002
Sierra Pacific Power Company Dec. 1, 2001 June 1, 2002 Feb. 1, 2002 June 1, 2002
In connection with clearing the Utilities' deferred energy accounts,
the PUCN must investigate and determine whether the Utilities' rates that went
into effect on March 1, 2001, pursuant to the CEP, are just and reasonable and
reflect prudent business practices. The rates in effect on April 1, 2001, remain
in effect until the PUCN issues final orders on the general and initial deferred
energy rate applications referred to above. The PUCN is prohibited from
adjusting rates during this time period unless an adjustment is absolutely
necessary to avoid a finding that the rates are confiscatory and, therefore, in
violation of the United States or Nevada Constitutions. If adjustments are
necessary, they may only be made to the extent necessary to avoid an
unconstitutional result.
After the initial general rate applications described above, each
Utility will be required to file future general rate applications at least every
24 months.
Restrictions on Mergers and Acquisitions
- ----------------------------------------
AB369 imposes certain restrictions on mergers and acquisitions
involving Nevada electric utilities. In particular, the PUCN may not approve a
merger or acquisition involving an electric utility unless the utility complies
with the generation divestiture provisions of AB369.
In addition, AB369 includes provisions that would have significantly
affected the required regulatory approvals for the proposed acquisition of
Portland General Electric Company (PGE) from Enron Corp. On April 26, 2001,
Enron Corp. and SPR terminated, by mutual agreement, the proposed purchase and
sale of PGE.
Repeal of Electric Industry Restructuring
- -----------------------------------------
AB369 repeals all statutes authorizing retail competition in Nevada's
electric utility industry and voids any license issued to an alternative seller
in connection with retail electric competition.
Other Legislation
- -----------------
SB372, which increased renewable energy portfolio requirements, was
enacted in the 2001 Nevada legislative session. Renewable resources include
biomass, wind, solar and geothermal projects. In 2003, both SPPC and NPC will be
required to purchase five percent of their energy from renewable resources.
These requirements increase to 15% by 2013. Prior law capped renewable energy
requirements at one percent. Currently SPPC obtains approximately nine percent
of its energy from renewable resources while NPC obtains less than one percent
from renewables. SB372 requires the PUCN to establish standards for renewable
energy contracts including prices and other terms and conditions. If sufficient
renewable energy contracts that meet PUCN standards are not available, the
Utilities will not be required to meet the portfolio requirements. All renewable
energy contracts meeting PUCN standards will be recoverable in the deferred
energy accounts.
The 2001 Nevada Legislature passed another key piece of legislation for
the energy industry, AB661. AB661 allows commercial and governmental customers
with an average demand greater than 1 megawatt (MW) to select new energy
suppliers. The Utilities would continue to provide transmission, distribution,
metering and billing services to such customers. AB661 requires customers
wishing to choose a new supplier to receive the approval of the PUCN and meet
public interest standards. In particular, departing customers must secure new
energy resources that are not under contract to the Utilities, remaining
customers cannot be negatively impacted by the departure, and the departing
customers must pay any deferred energy fuel balances. Certain limits are placed
upon the departure of NPC customers until 2003; most significantly, the amount
of load departing is limited to approximately 1100 MW in peak conditions. AB661
permits customers to file applications with the PUCN beginning in the fourth
quarter of 2001. Customers must provide 180-day notice to the Utilities and
could begin to receive service from new suppliers in mid-2002.
25
AB661 also contains new electric and gas energy surcharges for
low-income assistance and weatherization programs. These surcharges are
recoverable directly from customers as separate line items on their bills with
the Utilities remitting collected surcharges to the PUCN. Various state agencies
will administer the disposition of the funds.
FINANCIAL CONDITION, LIQUIDITY AND CAPITAL RESOURCES
----------------------------------------------------
On April 13, 2001, SPR announced that it would not be paying the
dividend on its common stock historically paid on May 1st. On July 20, 2001,
SPR's Board of Directors declared a dividend on common stock of 20 cents per
share, payable September 15, 2001, to shareholders of record at the close of
business on August 24, 2001. Payment of future dividends will be determined by
SPR's Board of Directors and will be subject to factors that ordinarily affect
dividend policy, such as earnings, cash flow, estimates of future earnings and
cash flow, business conditions, regulatory factors, financial condition, and
other matters.
On July 24, 2001, SPR filed with the Securities and Exchange Commission
an amended registration statement relating to an offering of 21,850,000 shares
of common stock. SPR intends to use the net proceeds to contribute capital to
NPC and SPPC to reduce short-term debt obligations and for general corporate
purposes, which may include repayment of long-term debt.
During the quarter ended June 30, 2001, NPC and SPPC each had
short-term credit facilities in the amount of $150 million. As of June 30, 2001,
the Utilities had not drawn on these facilities. On August 1, 2001, NPC and SPPC
each increased the total amount of their short-term credit facilities from $150
million to $250 million and extended the expiration date of their short-term
credit facilities from August 27, 2001 to November 30, 2001. These credit
facilities serve primarily to back up the Utilities' commercial paper programs
and to fund working capital and general corporate needs.
Set forth below is a schedule showing the current maturities of debt
during the remainder of 2001 (in $000's):
SPPC NPC
--------- ---------
August 20, 2001 100,000
December 1, 2001 19,616
December 17, 2001 100,000
--------- ---------
$ 19,616 $ 200,000
========= =========
The Utilities expect to pay the principal amounts of these maturing
debt obligations, to pay their current obligations and to finance the
anticipated deferred energy regulatory assets with a combination of ongoing cash
flows from operations and the proceeds from borrowings and the sale of
additional securities.
The Utilities expect that their working capital financing needs will
grow with the restoration of deferred energy accounting. To the extent that
current revenues are less than current expenses, the recovery of those costs
will be delayed until the completion of the next deferred rate cases.
It is Management's objective to achieve a ratio of common equity to
total capitalization of 30% to 35% over the long term. Accordingly, Management
believes that SPR may be required to issue additional securities in the future
in order to achieve this objective, although the exact amounts and timing cannot
be predicted at this time.
26
NEVADA POWER COMPANY
- --------------------
The causes for significant changes in specific lines comprising the
results of operations for NPC are discussed below (in $000's):
Three Months Six Months
Ended June 30, Ended June 30,
-------------------------------------- --------------------------------------
Change from Change from
2001 2000 Prior Year % 2001 2000 Prior Year %
--------- --------- ------------ ---------- --------- ------------
Electric Operating Revenues ($000):
Residential $ 172,520 $ 125,539 37.4% $ 275,699 $ 209,112 31.8%
Commercial 83,573 58,973 41.7% 139,129 105,707 31.6%
Industrial 118,603 77,327 53.4% 190,825 132,448 44.1%
--------- --------- ---------- ---------
Retail revenues 374,696 261,839 43.1% 605,653 447,267 35.4%
Other 433,745 17,551 2371.3% 561,800 28,153 1895.5%
--------- --------- ---------- ---------
Total Revenues $ 808,441 $ 279,390 189.4% $1,167,453 $ 475,420 145.6%
========= ========= ========== =========
Retail sales in thousands
of megawatt-hours (MWH) 4,440 4,313 2.9% 7,756 7,461 4.0%
Average retail revenue per MWH $ 84.39 $ 60.71 39.0% $ 78.09 $ 59.95 30.3%
Residential electric revenues increased for the three and six months
ended June 30, 2001, over the same periods in 2000 due to increases in both
electric rates and the number of customers. Higher rates resulted from
cumulative monthly rate increases pursuant to the 2000 Global Settlement and an
increase in rates effective March 1, 2001, pursuant to the CEP. For the three
and six month periods ended June 30, 2001, the number of residential customers
increased by 4.9% and 5.0%, respectively, over the same periods in 2000.
Commercial and industrial electric revenues also increased for the
three and six months ended June 30, 2001, over the same periods in 2000 due to
increases in both electric rates and the number of customers. Commercial and
industrial rate increases corresponded to those experienced by residential
customers. The opening of several new schools and large casinos contributed to
the increases in commercial and industrial revenues, diminishing the effect of
voluntary energy curtailment practices among these customer classes. For both
the three and six month periods ended June 30, 2001, the number of commercial
customers increased by 4.4% over the same periods of 2000. For the three and six
month periods ended June 30, 2001, the number of industrial customers increased
by 7.7% and 8.0%, respectively, over the same periods in 2000.
The large increases in other electric revenues for the three and
six-month periods ended June 30, 2001, over the same periods in 2000 were mainly
due to significant increases in risk management activities and wholesale power
sales at much higher prices. NPC seeks neither to purchase nor sell energy on a
speculative basis. NPC purchases fixed cost energy at a delivery point where the
energy can either be delivered to its control area or sold, should NPC not
require the energy. The energy is also sold if replacement energy can be
obtained less expensively than transporting the energy to the control area.
Fewer of these sales have taken place in prior years.
Three Months Six Months
Ended June 30, Ended June 30,
------------------------------------------- -------------------------------------------
Change from Change from
2001 2000 Prior Year % 2001 2000 Prior Year %
--------- --------- ------------ ---------- --------- ------------
Purchased Power ($000) $ 839,538 $ 154,533 443.3% $1,041,360 $ 208,350 399.8%
Purchased Power in thousands
of MWHs 5,217 2,472 111.0% 7,685 3,715 106.9%
Average cost per MWH of
Purchased Power $ 160.92 $ 62.51 157.4% $ 135.51 $ 56.08 141.6%
27
Purchased power costs were significantly higher for both the three and
six months ended June 30, 2001, than for the same periods of the prior year, as
Short-Term Firm and spot market prices, as well as volumes purchased, increased
substantially. NPC acquired a portfolio of energy supply contracts sufficient to
meet the projected needs of its retail customers in advance of the peak summer
period. From time to time and dependent, in part, upon the weather, NPC may sell
purchased or generated power on the wholesale market to the extent that supplies
exceed the actual energy demands of its retail customers. The benefit of such
sales is passed to NPC's retail customers through reduced costs per MWH.
Three Months Six Months
Ended June 30, Ended June 30,
------------------------------------------- -------------------------------------------
Change from Change from
2001 2000 Prior Year % 2001 2000 Prior Year %
--------- --------- ------------ ---------- --------- ------------
Fuel for Power Generation ($000) $ 102,258 $ 55,022 85.8% $ 217,610 $ 92,669 134.8%
Thousands of MWHs generated 2,573 2,453 4.9% 5,074 4,717 7.6%
Average cost per MWH of
Generated Power $ 39.74 $ 22.43 77.2% $ 42.89 $ 19.65 118.3%
Fuel for generation costs for both the three and six months ended June
30, 2001, were significantly higher than the prior year due to substantial
increases in natural gas prices. In addition, volumes generated were higher to
accommodate system load.
Three Months Six Months
Ended June 30, Ended June 30,
------------------------------------------- -------------------------------------------
Change from Change from
2001 2000 Prior Year % 2001 2000 Prior Year %
--------- --------- ------------ ---------- --------- ------------
Deferral of energy costs-net ($000) $(281,145) $ 7,486 -3855.6% $(269,837) $ 14,274 -1990.4%
Deferral of energy costs-net decreased significantly for both the three
and six months ended June 30, 2001, due to the implementation of deferred energy
accounting beginning March 1, 2001. The current year amounts reflect the extent
to which actual fuel and purchased power costs exceeded the fuel and purchased
power costs recovered through current rates. Deferral of energy costs-net for
2000 represents energy costs that had been deferred in prior periods and were
then recovered in the three and six month periods ended June 30, 2000, as a
result of deferred energy rate increases granted in 1999.
Three Months Six Months
Ended June 30, Ended June 30,
------------------------------------------- -------------------------------------------
Change from Change from
2001 2000 Prior Year % 2001 2000 Prior Year %
--------- --------- ------------ ---------- --------- ------------
Allowance for other funds
used during construction ($000) $ (122) $ 1,062 -111.5% $ (473) $ 1,842 -125.7%
Allowance for borrowed funds
used during construction ($000) $ 265 $ 1,942 -86.4% $ (87) $ 3,757 -102.3%
--------- --------- ---------- ---------
$ 143 $ 3,004 -95.2% $ (560) $ 5,599 -110.0%
========= ========= ========== =========
28
The totals of allowance for funds used during construction (AFUDC) for
both the three and six months ended June 30, 2001, reflect adjustments to refine
amounts assigned to specific components of facilities that were completed in
different periods.
Three Months Six Months
Ended June 30, Ended June 30,
------------------------------------------- -------------------------------------------
Change from Change from
2001 2000 Prior Year % 2001 2000 Prior Year %
($000) --------- --------- ------------ ---------- --------- ------------
Other operating expense $ 33,750 $ 35,134 -3.9% $ 84,522 $ 64,285 31.5%
Maintenance expense 13,478 9,263 45.5% 26,458 19,084 38.6%
Depreciation and amortization 22,427 21,314 5.2% 44,303 42,730 3.7%
Income taxes 16,246 (10,446) N/A (14,218) (6,819) 108.5%
Interest charges on long-term debt 18,339 14,253 28.7% 34,959 30,152 15.9%
Interest charges-other 3,750 4,267 -12.1% 7,713 7,932 -2.8%
Other income (expense) - net 2,747 331 729.9% 3,168 707 348.1%
Other operating expense for the three-month period ending June 30,
2001, decreased compared with the prior year, as the 2000 amount included
nonrecurring executive severance expenses and timing differences in employee
benefit expenses. The decrease was offset in part by a current year increase in
costs associated with the Clark Station. Other operating expense for the
six-month period ending June 30, 2001, increased compared to the same period in
2000 primarily due to a $16.1 million increase in the provision for
uncollectible accounts related to the California Power Exchange and a $3 million
reserve provision established as a result of AB369.
Maintenance costs for the three- and six-month periods ending June 30,
2001, increased from the prior year as a result of additional outages at the
Reid-Gardner, Mohave, and Clark stations and unplanned maintenance expenses. A
shift from generation divestiture activities in 2000 to maintenance activities
in 2001 also contributed to the increase.
The increases in depreciation and amortization expense for the three
and six-month periods ended June 30, 2001, compared to the same periods in 2000,
reflect an increase in plant-in-service over the prior year.
For the three-month period ending June 30, 2001, income tax expense
replaced an income tax benefit in the same period of 2000 as NPC recorded
pre-tax income for the current year period compared with a pre-tax loss for the
year-earlier period. However, for the six-months ended June 30, 2001, the income
tax benefit increased over the prior year as a result of a larger pre-tax loss
in the current year than in 2000.
Interest charges on long-term debt increased for the three- and
six-month periods ending June 30, 2001, compared to the same periods of 2000 due
primarily to the issuance of a total of $250 million in floating rate notes in
June and August of 2000, and the issuance of $350 million in mortgage bonds in
May 2001.
Interest charges-other decreased for the three- and six-month periods
ending June 30, 2001, compared to the same periods of 2000 due to reduced
reliance on commercial paper in 2001.
The increase in Other income (expense) - net for the three- and
six-month periods ending June 30, 2001, compared to the same periods of 2000 is
due primarily to the recognition in the current year of the carrying charge on
deferred fuel and purchased power balances pursuant to AB369.
Financial Condition, Liquidity and Capital Resources
During the first six months of 2001, NPC incurred a loss of
approximately $22.3 million (excluding NPC's equity in the losses of its parent,
SPR), and declared no dividends on its common stock, all of which is held by
SPR. However, for the three months ended June 30, 2001, NPC earned $33.0 million
(excluding NPC's equity in the earnings of its parent, SPR). In June 2001 NPC
received a $21.9 million capital contribution from SPR.
Net cash flows during the six months ended June 30, 2001, were
comparable to the same period in 2000. However, net cash flows from operating
activities, decreased significantly. This was the result of the combination of a
larger loss before preferred dividends and large increases in accounts
receivable and deferred energy costs due to increased risk management activities
and implementation of AB369, respectively, being only partially offset by an
increase in accounts payable. Cash
29
flows from financing activities increased significantly in 2001 compared to 2000
due to a greater net increase in long-term debt in 2001, a decrease in
short-term borrowings in 2000, and no common dividend payment in 2001. These
increases were offset in part by a decrease in funding from NPC's parent, SPR,
from $128 million in 2000 to $21.9 million in 2001.
Construction Expenditures and Financing
NPC's construction program and capital requirements for the period
2001-2005 were originally discussed in its Annual Report on Form 10-K for the
year ended December 31, 2000. Of NPC's amount projected for 2001 ($175 million),
$88.9 million (50.8%) was spent as of June 30, 2001. Construction expenditures
were funded from sources other than internally generated funds.
NPC may utilize internally generated cash, the proceeds from secured
and unsecured borrowings and preferred securities, and capital contributions
from SPR to meet capital expenditure requirements through 2001.
30
SIERRA PACIFIC POWER COMPANY
- ----------------------------
The components of gross margin (net of deferral of energy costs) are
set forth below (dollars in thousands):
Three Months Six Months
Ended June 30, Ended June 30,
------------------------------------------- -------------------------------------------
Change from Change from
2001 2000 Prior Year % 2001 2000 Prior Year %
--------- --------- ------------ ---------- --------- ------------
Operating Revenues:
Electric $ 320,222 $ 176,820 81.1% $ 632,341 $ 334,442 89.1%
Gas 21,729 15,755 37.9% 85,894 50,591 69.8%
--------- --------- ---------- ---------
Total Revenues 341,951 192,575 77.6% 718,235 385,033 86.5%
--------- --------- ---------- ---------
Energy Costs:
Electric 252,894 116,031 118.0% 513,454 194,787 163.6%
Gas 16,868 10,374 62.6% 69,267 33,601 106.1%
--------- --------- ---------- ---------
Total Energy Costs 269,762 126,405 113.4% 582,721 228,388 155.1%
--------- --------- ---------- ---------
Gross Margin $ 72,189 $ 66,170 9.1% $ 135,514 $ 156,645 -13.5%
========= ========= ========== =========
Gross Margin by Segment:
Electric $ 67,328 $ 60,789 10.8% $ 118,887 $ 139,655 -14.9%
Gas 4,861 5,381 -9.7% 16,627 16,990 -2.1%
--------- --------- ---------- ---------
Total $ 72,189 $ 66,170 9.1% $ 135,514 $ 156,645 -13.5%
========= ========= ========== =========
The causes for significant changes in specific lines comprising the
results of operations for SPPC are discussed below:
Three Months Six Months
Ended June 30, Ended June 30,
------------------------------------------- -------------------------------------------
Change from Change from
2001 2000 Prior Year % 2001 2000 Prior Year %
--------- --------- ------------ ---------- --------- ------------
Electric Operating Revenues ($000):
Residential $ 46,965 $ 38,279 22.7% $ 98,474 $ 86,190 14.3%
Commercial 60,120 48,627 23.6% 111,294 93,426 19.1%
Industrial 65,323 48,900 33.6% 119,908 94,014 27.5%
--------- --------- ---------- ---------
Retail revenues 172,408 135,806 27.0% 329,676 273,630 20.5%
Other 147,814 41,014 260.4% 302,665 60,812 397.7%
--------- --------- ---------- ---------
Total Revenues $ 320,222 $ 176,820 81.1% $ 632,341 $ 334,442 89.1%
========= ========= ========== =========
Retail sales in thousands of
megawatt-hours (MWH) 2,096 2,131 -1.6% 4,229 4,248 -0.4%
Average retail revenue per MWH $ 82.26 $ 63.73 29.1% $ 77.96 $ 64.41 21.0%
Retail electric revenues increased for both the three and six-month
periods ended June 30, 2001, over the same periods in 2000 due to increases in
rates offsetting small reductions in demand. Higher rates resulted from
cumulative monthly rate increases pursuant to the 2000 Global Settlement and an
increase in rates effective March 1, 2001, pursuant to the CEP. Demand by
commercial and industrial customers decreased in part from voluntary curtailment
programs, which were offset by continued growth in the number of customers.
Demand by residential customers increased due to 10% increases in both heating
degree-days and cooling degree-days.
The large increases in other electric revenues for the three and
six-month periods ended June 30, 2001, over the same periods in 2000 were mainly
due to significant increases in risk management activities and wholesale power
sales at much higher prices. SPPC seeks neither to purchase nor sell energy on a
speculative basis. SPPC purchases fixed cost energy at a
31
delivery point where the energy can either be delivered to its control area or
sold, should SPPC not require the energy. The energy is also sold if replacement
energy can be obtained less expensively than transporting the energy to the
control area. Fewer of these sales have taken place in prior years.
Three Months Six Months
Ended June 30, Ended June 30,
------------------------------------------- -------------------------------------------
Change from Change from
2001 2000 Prior Year % 2001 2000 Prior Year %
--------- --------- ------------ ---------- --------- ------------
Gas Operating Revenues ($000):
Residential $ 10,130 $ 6,212 63.1% $ 31,754 $ 22,938 38.4%
Commercial 5,423 3,292 64.7% 16,064 11,716 37.1%
Industrial 1,998 2,111 -5.4% 6,629 5,457 21.5%
Miscellaneous 111 595 -81.3% 628 1,008 -37.7%
--------- --------- ---------- ---------
Total retail revenue 17,662 12,210 44.7% 55,075 41,119 33.9%
Wholesale revenue 4,067 3,545 14.7% 30,819 9,472 225.4%
--------- --------- ---------- ---------
Total Revenues $ 21,729 $ 15,755 37.9% $ 85,894 $ 50,591 69.8%
========= ========= ========== =========
Retail sales in thousands
of decatherms 2,190 1,938 13.0% 7,483 7,066 5.9%
Average retail revenues per
decatherms $ 8.06 $ 6.30 28.0% $ 7.36 $ 5.82 26.5%
The three months ended June 30, 2001, reflected increased gas revenues
from residential and commercial customers compared to the prior year, primarily
as a result of the rate increase approved by the PUCN that took effect February
1, 2001. The increase in retail revenues was due, to a lesser extent, to an
increase in heating-degree days.
SPPC's wholesale gas revenues increased significantly for the six
months ended June 30, 2001, and increased approximately 15% for the second
quarter, over the same periods in 2000 in response to risk management
activities. SPPC seeks neither to purchase nor sell gas on a speculative basis.
Three Months Six Months
Ended June 30, Ended June 30,
------------------------------------------- -------------------------------------------
Change from Change from
2001 2000 Prior Year % 2001 2000 Prior Year %
--------- --------- ------------ ---------- --------- ------------
Purchased Power ($000): $ 248,608 $ 71,949 245.5% $ 399,595 $ 121,429 229.1%
Purchased Power in thousands
of MWHs 1,703 1,706 -0.2% 3,150 3,299 -4.5%
Average cost per MWH of
Purchased Power $ 145.98 $ 42.17 246.1% $ 126.86 $ 36.81 244.6%
Purchased power costs were higher for both the three and six-month
periods ended June 30, 2001, than the prior year because SPPC fulfilled more of
its total energy requirements with more expensive Short-Term Firm purchased
power. SPPC also engaged in additional risk management activities at prices that
were substantially higher.
32
Three Months Six Months
Ended June 30, Ended June 30,
------------------------------------------- -------------------------------------------
Change from Change from
2001 2000 Prior Year % 2001 2000 Prior Year %
--------- --------- ------------ ---------- --------- ------------
Fuel for Power Generation ($000) $ 85,041 $ 44,082 92.9% $ 187,594 $ 73,358 155.7%
Thousands of MWHs generated 1,492 1,343 11.1% 3,075 2,543 20.9%
Average fuel cost per MWH
of Generated Power $ 57.00 $ 32.82 73.6% $ 61.01 $ 28.85 111.5%
Fuel for generation costs for the three and six-month periods ended
June 30, 2001, were substantially higher than for the prior year as natural gas
prices increased significantly and volumes generated were higher to accommodate
system load when generation was less expensive than purchased power.
Three Months Six Months
Ended June 30, Ended June 30,
------------------------------------------- -------------------------------------------
Change from Change from
2001 2000 Prior Year % 2001 2000 Prior Year %
--------- --------- ------------ ---------- --------- ------------
Gas Purchased for Resale ($000)
Retail $ 18,158 $ 7,760 134.0% $ 69,843 $ 24,898 180.5%
Wholesale 7,013 3,710 89.0% 25,871 9,423 174.6%
--------- --------- ---------- ---------
Total $ 25,171 $ 11,470 119.5% $ 95,714 $ 34,321 178.9%
========= ========= ========== =========
Gas Purchased for Resale - retail
(thousands of decatherms) 2,314 1,945 19.0% 8,030 6,585 21.9%
Average cost per retail decatherm $ 7.85 $ 3.99 96.7% $ 8.70 $ 3.78 130.0%
The cost of retail gas purchased for resale increased for the three and
six-month periods ended June 30, 2001, compared to the prior year due to
substantially higher gas prices. The increase in the cost of wholesale gas
purchased over the prior year reflects higher prices as well as costs associated
with risk management activities.
Three Months Six Months
Ended June 30, Ended June 30,
--------------------------------------- ---------------------------------------
Change from Change from
2001 2000 Prior Year % 2001 2000 Prior Year %
--------- --------- ------------ ---------- --------- ------------
Deferral of energy costs-net ($000)
Purchased Power and Fuel for Power
Generation (80,755) -- N/A (73,735) -- N/A
Gas Purchased for Resale (8,303) (1,096) 657.6% (26,447) (720) 3573.2%
--------- --------- ---------- ---------
Total $ (89,058) $ (1,096) 8025.7% $ (100,182) $ (720) 13814.2%
========= ========= ========== =========
For both the three and six months ended June 30, 2001, SPPC recorded
significant Deferral of energy costs-net for purchased power and fuel for
generation due to the implementation of deferred energy accounting beginning
March 1, 2001. The current year amounts reflect the extent to which actual fuel
and purchased power costs exceeded the fuel and purchased power costs recovered
through current rates. SPPC did not utilize deferred energy accounting for its
electric operations in 2000.
Deferral of energy costs-net for gas purchased for resale increased
substantially for both the three and six month periods ended June 30, 2001, over
the prior year because SPPC is recording higher undercollections of such costs
than in 2000. Revenue received from the base purchased gas rates did not cover
the increased cost of natural gas experienced by SPPC.
33
Three Months Six Months
Ended June 30, Ended June 30,
------------------------------------------- -------------------------------------------
Change from Change from
2001 2000 Prior Year % 2001 2000 Prior Year %
--------- --------- ------------ ---------- --------- ------------
Allowance for other funds used
during construction ($000) $ (30) $ 74 -140.5% $ (214) $ 134 -259.7%
Allowance for borrowed funds used
during construction ($000) 423 551 -23.2% 377 969 -61.1%
--------- --------- --------- ----------
$ 393 $ 625 -37.1% $ 163 $ 1,103 -85.2%
========= ========= ========= ==========
The totals of allowance for funds used during construction (AFUDC) for
both the three and six months ended June 30, 2001, reflect adjustments to refine
amounts assigned to specific components of facilities that were completed in
different periods.
Three Months Six Months
Ended June 30, Ended June 30,
------------------------------------------- -------------------------------------------
Change from Change from
2001 2000 Prior Year % 2001 2000 Prior Year %
(In 000's) --------- --------- ------------ ---------- --------- ------------
Other operating expense $ 23,174 $ 26,564 -12.8% $ 50,868 $ 49,720 2.3%
Maintenance expense 6,676 4,753 40.5% 12,000 8,822 36.0%
Income taxes 1,464 884 65.6% (656) 12,778 -105.1%
Interest charges on long-term debt 12,529 8,379 49.5% 23,099 15,908 45.2%
Interest charges - other 3,022 4,079 -25.9% 5,982 7,171 -16.6%
Other income (expense) - net 1,499 (966) -255.2% 1,013 (1,239) -181.8%
Other operating expense for the three-month period ending June 30,
2001, decreased compared with the prior year, as the 2000 amount included
nonrecurring executive severance expenses and timing differences in employee
benefit expenses. Other operating expense for the six-month period ending June
30, 2001, increased compared to the same period in 2000 primarily due to a $3.5
million increase in the provision for uncollectible accounts related to the
California Power Exchange and a $2.7 million reserve provision established as a
result of AB369. The increase was offset, in part, by reductions in labor costs,
and consulting and legal fees.
Maintenance costs for the three and six-month periods ended June 30,
2001 were higher compared to the same periods in 2000 primarily due to increased
expenses related to the combustion turbines at the Winnemucca and Clark Mountain
generation facilities.
Income taxes were higher for the three-month period ending June 30,
2001, compared to the prior year reflecting an increase in pre-tax income from
continuing operations. However, for the six-months ended June 30, 2001, an
income tax benefit replaced income tax expense in the same period of 2000 as
SPPC recorded a pre-tax loss from continuing operations for the current year
period compared with pre-tax income from continuing operations for the
year-earlier period.
Interest charges on long-term debt increased for the three- and
six-month periods ending June 30, 2001, compared to the same periods of 2000 due
primarily to the issuance of $200 million in floating rate notes in June of
2000, and the issuance of $320 million in mortgage bonds in May 2001.
Interest charges-other decreased for the three- and six-month periods
ending June 30, 2001, compared to the same periods of 2000 due to reduced
reliance on commercial paper in 2001.
The change in Other income (expense) - net from net expense to net
income for the three- and six-month periods ending June 30, 2001, compared to
the same periods of 2000 is due primarily to the recognition in the current year
of the carrying charge on deferred fuel and purchased power balances pursuant to
AB369.
34
Financial Condition, Liquidity and Capital Resources
During the first six months of 2001, SPPC incurred a loss of $151,000
from continuing operations before preferred stock dividends. However, for the
three months ended June 30, 2001, SPPC earned $3.8 million from continuing
operations before preferred stock dividends. During the first six months of
2001, SPPC paid $1.95 million in dividends to holders of its preferred stock and
paid $76 million in dividends on its common stock, all of which is held by its
parent, SPR. In June 2001 SPPC received a $4.9 million capital contribution from
SPR.
Net cash flows during the six months ended June 30, 2001, were
comparable to the same period in 2000 as a result of an increase in net cash
flows from investing activities offsetting decreases in net cash flows from both
operating activities and financing activities. The increase in net cash flows
from investing activities resulted from the sale of the assets of SPPC's water
business. The decrease in net cash flows from operating activities in 2001
compared to 2000 was primarily the result of increases in accounts receivable
and deferred energy costs due to increased risk management activities and
implementation of AB369, respectively. The decrease in cash flows from financing
activities was mainly due to a decrease in net long-term debt issued and an
increase in common dividends paid in 2001.
Construction Expenditures and Financing
SPPC's construction program and capital requirements for the period
2001-2005 were originally discussed in its Annual Report on Form 10-K for the
year ended December 31, 2000. Of SPPC's amount projected for 2001 ($125
million), $57.5 million (46.0%) was spent as of June 30, 2001. Construction
expenditures were funded from sources other than internally generated funds.
SPPC may utilize internally generated cash, the proceeds from secured
and unsecured borrowings and preferred securities, and capital contributions
from SPR to meet capital expenditure requirements through 2001.
Sierra Pacific Resources (Holding Company)
- ------------------------------------------
The Condensed Consolidated Statements of Income of Sierra Pacific
Resources include the operating results of the holding company. The holding
company operating results included a charge of approximately $22 million
recognized as a result of the termination of the PGE acquisition. The holding
company also recognized higher interest costs, $27.8 million in 2001 and $17.2
million in 2000, due to the issuance of a total of $600 million in debt in April
and May of 2000.
Tuscarora Gas Pipeline Company
- ------------------------------
The Condensed Consolidated Statements of Income of Sierra Pacific
Resources include the operating results of Tuscarora Gas Pipeline Company
(TGPC), a wholly owned subsidiary of SPR. For the three-and six-month periods
ended June 30, 2001, TGPC contributed $.6 million and $1.3 million,
respectively, in net income. For the three-and six-month periods ended June 30,
2000, TGPC contributed $.5 million and $1.1 million, respectively, in net
income.
e-three
- --------
The Condensed Consolidated Statements of Income of Sierra Pacific
Resources include the operating results of e-three, a wholly owned subsidiary
of SPR. For the three months ended June 30, 2001, e-three contributed $.2
million in net income; e-three incurred a net loss of $.1 million for the six
months ended June 30, 2001. For the three-and six-month periods ended June 30,
2000, e-three contributed $.1 million and $.3 million, respectively, in net
income.
Sierra Pacific Energy Company
- -----------------------------
The Condensed Consolidated Statements of Income of Sierra Pacific
Resources include the operating results of Sierra Pacific Energy Company (SPE),
a wholly owned subsidiary of SPR. For the three- and six-month periods ended
June 30, 2001, SPE incurred net losses of $71,000 and $158,000, respectively.
SPE incurred net losses of $.5 million and $3.8 million, respectively, for the
three- and six-month periods ended June 30, 2000. The losses are the result of
costs incurred to exit the retail energy-sales business.
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. For the three- and six-month periods ended
June 30, 2001,
35
SPC incurred net losses of $396,000 and $769,000, respectively. SPC incurred net
losses of $14,000 and $75,000, respectively, for the three- and six-month
periods ended June 30, 2000.
PORTLAND GENERAL ELECTRIC ACQUISITION
-------------------------------------
On April 26, 2001, SPR and Enron Corp. announced that they had mutually
agreed to terminate their agreement for SPR's purchase of Enron's wholly owned
subsidiary, Portland General Electric (PGE). In negotiating the mutual
termination, SPR agreed to share certain expenses which Enron Corp and PGE had
incurred for the proposed transaction. The Condensed Consolidated Statement of
Income of SPR for the six months ended June 30, 2001, reflects a charge in
connection with the planned purchase of PGE of $22 million, including
approximately $7.5 million representing a termination payment for shared
expenses.
GENERATION DIVESTITURE
----------------------
As a condition to its approval of the merger between SPR and NPC, the
PUCN required the Utilities to file a Divestiture Plan for the sale of their
electric generation assets. The PUCN approved a revised Divestiture Plan
stipulation in February 2000. In May 2000 an agreement was announced for the
sale of NPC's 14% undivided interest in the Mohave Generating Station
("Mohave"). In the fourth quarter of 2000 the Utilities announced agreements to
sell six additional bundles of generation assets described in the approved
Divestiture Plan. The sales were subject to approval and review by various
regulatory agencies. For additional information, see the Annual Report on Form
10-K for the year ended December 31, 2000.
As described above, AB369, which was signed into law on April 18, 2001,
prohibits until July 2003 the sale of generation assets and directs the PUCN to
vacate any of its orders that had previously approved generation divestiture
transactions. In January 2001, California enacted a law that prohibits until
2006 any further divestiture of generation properties by California utilities,
including SPPC, and could also affect any sale of NPC's interest in Mohave after
July 2003 since the majority owner of that project is Southern California
Edison. In addition SPPC's request for an exemption from the requirements of a
separate California law requiring approval of the California Public Utilities
Commission (CPUC) to divest its plants was denied, subject to future refiling.
As a result of these legislative and regulatory developments, the
Utilities are engaged in discussions with the buyers of the generation assets
regarding the termination of the sales agreements and the related energy buyback
contracts and interconnection agreements. As of June 30, 2001, NPC and SPPC
incurred costs of approximately $9.5 million and $13.8 million, respectively, in
order to prepare for the sale of generation assets. NPC and SPPC plan to request
recovery of these costs.
SALE OF WATER BUSINESS
----------------------
On June 11, 2001, SPPC closed the sale of its water business to the
Truckee Meadows Water Authority (TMWA) for $341 million. SPPC recorded a $25.8
million gain on the sale, net of income taxes of $18.2 million. Pursuant to a
stipulation entered into in connection with the sale and approved by the PUCN,
SPPC is required to refund to customers $21.5 million of the proceeds from the
sale. The refund will be credited on the electric bills of SPPC's former water
customers over a period not to exceed fifteen months after the close of the
sale. Under a service contract with TMWA, SPPC will provide, on an interim
basis, customer service, billing, and meter reading services to TMWA. Transfer
of the hydroelectric facilities included in the sale for an additional $8
million will require action by the CPUC. The sale agreement contemplates a
second closing for the hydroelectric facilities to accommodate the CPUC's review
of the transaction. Not included in the sale was certain property along the
Truckee River related to the hydroelectric facilities and in California at
Independence Lake. SPPC will continue to own this property with the intent of a
possible future sale.
REGULATORY MATTERS
------------------
Substantially all of the utility operations of both 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.
FERC Matters (NPC, SPPC)
- ------------------------
Price Mitigation Plan
On June 19, 2001, the FERC adopted a price mitigation plan applicable
to wholesale power sales in California and throughout the western United States
during the period June 20, 2001 through September 30, 2002. The price mitigation
plan establishes a mechanism with which to determine the maximum amount that may
be charged for power sold during this period. The intent of the mitigation plan
is to simulate the price that might be charged for electricity sold under
competitive market conditions. Sellers that do not wish to establish rates on
the basis of this price mitigation plan may propose cost-of-service rates
covering all of their generating units in the Western Systems Coordinating
Council for the duration of the mitigation plan.
36
The Utilities are not able to predict at this time the extent to which the FERC
price mitigation plan may affect their results of operations. It is possible,
however, under certain market conditions, that the FERC plan may adversely
affect the availability of spot market power to the Utilities and may reduce the
price at which the Utilities can sell power on the wholesale market. SPR
recently joined with two utilities in Washington and Oregon to seek changes to
the FERC plan on the basis that the price caps are unfair to electric customers
who reside outside of California.
Regional Transmission Organization and Independent Transmission Company
NPC and SPPC are members of a proposed regional transmission
organization (RTO West) and a proposed independent transmission company
(TransConnect). On April 25, 2001, FERC gave preliminary approval for both RTO
West and TransConnect. Both organizations remain subject to approvals from state
regulators and the board of directors of each member company. See the Utilities'
Annual Report on Form 10-K for the year ended December 31, 2000, for additional
information about RTO West and TransConnect.
Wholesale Sales Tariffs
On March 13, 2001, SPPC and NPC each filed an application for an order
approving market-based rates. The market-based authority would apply to sales of
electric energy and capacity outside of the Utilities' control areas.
Nevada Matters
- --------------
Optional Conservation Service (NPC, SPPC)
On April 19, 2001, the PUCN approved new NPC and SPPC electric rates
for Optional Conservation Service (Schedule OC). Schedule OC allows the
Utilities to request customers with demand greater than 1 MW to voluntarily
curtail their load when there is an economic or system need for capacity and
energy. Customers who curtail load will receive a billing credit.
Parallel Generation Tariffs (NPC, SPPC)
On May 11, 2001, NPC and SPPC filed with the PUCN revisions to existing
tariffs that will allow customers to interconnect standby generators in parallel
with the Utilities facilities. These changes will allow customers meeting
specific requirements to utilize their standby generators in support of the
Optional Conservation Service tariffs during times of power shortages or higher
prices.
Finance Authority (NPC, SPPC)
On June 19, 2001, NPC and SPPC filed with the PUCN asking for approval
to issue long or short-term debt on either a secured or unsecured basis in an
aggregate amount not to exceed $200 million and $100 million, respectively,
through the end of 2002. The Utilities also filed on June 19, 2001, applications
to amend an order issued by the PUCN allowing each of the Utilities to issue
unsecured short-term promissory notes in an amount not to exceed $250 million
through the period ending December 31, 2001. In the application the Utilities
have requested that the PUCN amend its previous order to provide the Utilities
with the flexibility to issue secured promissory notes in addition to, or in
lieu of, the authorized unsecured promissory notes.
Natural Gas Rate Increase (SPPC)
On June 29, 2001, SPPC filed with the PUCN a request seeking a natural
gas rate increase. The Purchase Gas Adjustment (PGA) filing was made requesting
an increase in gas rates of $63 million annually. If the increase is granted, an
average residential customer's monthly bill will increase by approximately 55%
or $27.43.
California Matters (SPPC)
- -------------------------
Rate Stabilization Plan
SPPC serves approximately 44,500 customers in California. On June 29,
2001, SPPC filed with the CPUC a Rate Stabilization Plan, which includes two
phases. Phase One, which was also filed June 29, 2001, is an emergency electric
rate increase of $10.2 million annually or 26%. If granted, the typical
residential monthly electric bill for a customer using 650 kilowatt-hours would
increase from approximately $47.12 to $60.12. SPPC has asked that the rate
become effective August 1, 2001. Phase Two, which is scheduled to be filed with
the CPUC in January 2002, will be a general rate case to recover costs for
expenses other than fuel and purchased power. SPPC will also ask the CPUC to
reinstate the Energy Cost Adjustment
37
Clause, which would allow SPPC to file for periodic rate adjustments to reflect
its actual costs for wholesale energy supplies. Phase Two will also include a
proposal pertaining to the termination of the 10% rate reduction mandated by AB
1890, and a modification of the distribution performance ratemaking mechanism
(PBR) previously agreed to by all parties.
Distribution Performance-based Rate-making (PBR)
Hearings on SPPC's distribution PBR proposal were held on April 2,
2001. An outline of the settlement reached by SPPC, the CPUC Office of Ratepayer
Advocates, and The Utility Reform Network resolving all issues was presented
during the hearing. On May 11, 2001, a formal joint settlement was submitted to
the Administrative Law Judge. To date there has been no formal action on the
filed joint settlement.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES
ABOUT MARKET RISK
See SPR's Annual Report on Form 10-K for the year ended December 31,
2000, for quantitative and qualitative disclosures about market risk. There have
been no material changes to the information previously disclosed in that report,
except as described in the following discussion.
The Utilities described in their Annual Report on Form 10-K for the
year ended December 31, 2000, that they were primarily exposed to commodity
price risk for changes in the market price of electricity as well as changes in
fuel costs incurred to generate electricity. However, on April 18, 2001, the
Governor of Nevada signed into law AB369, which provides, among other
requirements, a reinstatement of deferred energy accounting for electric
utilities. AB369 requires both Utilities to utilize deferred energy accounting
for their respective electric operations beginning on March 1, 2001. The intent
of deferred energy accounting is to ease the effect of fluctuations in the cost
of purchased power and fuel. To the extent actual fuel and purchased power costs
exceed amounts collected through rates, deferred energy accounting provides a
mechanism to collect the excess amounts through adjustments to rates in future
time periods, subject to PUCN review of prudency and other matters. The
Utilities are also permitted to record a carrying charge on uncollected deferred
balances. Deferred energy accounting significantly affects the commodity price
risk associated with the Utilities' purchased power and fuel costs. See "Nevada
Energy Legislation" in Item 2, Management's Discussion And Analysis Of Financial
Condition And Results Of Operations, above, for more information regarding
deferred energy accounting and AB369.
Also See Item 2, Management's Discussion And Analysis Of Financial
Condition And Results Of Operations, above, for a discussion of rate increases
permitted under the Global Settlement and the CEP, and the estimated future
revenues that will be provided by those increases.
38
PART II
ITEM 1. LEGAL PROCEEDINGS
As discussed in SPR's Annual Report on Form 10-K for the year ending
December 31, 2000, Sierra Touch America LLC ("STA"), is a partnership between
SPR's wholly owned subsidiary, Sierra Pacific Communications ("SPC"), and Touch
America, a subsidiary of Montana Power Company. STA is constructing and will
operate a fiber optic line between Salt Lake City, Utah and Sacramento, CA.
SPC's share is approximately $25 million of a total estimated construction cost
of $130 million. Williams Communications, LLC ("Williams") has filed a complaint
in United States District Court alleging that STA has failed to make timely
payment on invoices totaling $23.4 million in connection with a construction
agreement between Williams and STA whereby Williams is to construct a fiber
optic telecommunications route. STA has not approved certain payments because of
questions about invoicing and the quality of work performed by Williams.
Although SPC's ultimate liability, if any, in this matter is presently difficult
to estimate, Management believes that the final outcome is not likely to have a
material adverse effect on SPR's financial position.
Although SPR, NPC, and SPPC are involved in other ongoing litigation on
a variety of matters, in management's opinion none individually or collectively
are material to SPR's, NPC's, or SPPC's financial position.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
The 2001 Annual Meeting of the Shareholders of Sierra Pacific Resources
was held on May 21, 2001. SPR solicited proxies pursuant to Regulation 14 under
the Securities and Exchange Act of 1934. There was no solicitation in opposition
to the nominees for Director listed in the proxy statement, and all such
nominees were elected to the classes indicated in the proxy statement pursuant
to the vote of shareholders as follows.
Reelected to SPR's Board of Directors to serve until the Annual Meeting
in 2004, or until their successors are elected, were:
James R. Donnelley
Votes For: 65,348,624
Votes Against or Withheld: 1,928,013
Walter M. Higgins
Votes For: 64,799,411
Votes Against or Withheld: 2,477,226
John F. O'Reilly
Votes For: 65,365,329
Votes Against or Withheld: 1,911,308
ITEM 5. OTHER INFORMATION
None
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits filed with this Form 10-Q:
Nevada Power Company
4.1 (a) General and Refunding Mortgage Indenture, dated as of May 1,
2001, between Nevada Power Company and The Bank of New York,
as Trustee.
(b) First Supplemental Indenture, dated as of May 1, 2001,
establishing Nevada Power Company's 8.25% General and
Refunding Mortgage Bonds, Series A, due June 1, 2011.
(c) Officer's Certificate establishing the terms of Nevada Power
Company's 8.25% General and Refunding Mortgage Bonds, Series
A, due June 1, 2011.
39
(d) Form of Nevada Power Company's 8.25% General and Refunding
Mortgage Bonds, Series A, due June 1, 2011.
Sierra Pacific Power Company
4.2 (a) General and Refunding Mortgage Indenture, dated as of May 1,
2001, between Sierra Pacific Power Company and The Bank of New
York, as Trustee.
(b) First Supplemental Indenture, dated as of May 1, 2001,
establishing Sierra Pacific Power Company's 8% General and
Refunding Mortgage Bonds, Series A, due June 1, 2008.
(c) Officer's Certificate establishing the terms of Sierra Pacific
Power Company's 8% General and Refunding Mortgage Bonds,
Series A, due June 1, 2008.
(d) Form of Sierra Pacific Power Company's 8% General and
Refunding Mortgage Bonds, Series A, due June 1, 2008.
(b) Reports on Form 8-K:
Form 8-K filed on April 16, 2001, by SPR - Item 5, Other Events
Disclosed, and included as an exhibit, SPR's press release dated April
13, 2001, announcing that SPR would not be paying the dividend historically paid
on May 1st.
Form 8-K filed on April 17, 2001, by SPPC - Item 5, Other Events
Disclosed that the Nevada Legislature was considering various bills
including Assembly Bill 369 (AB369) that, if enacted, could have a material
effect on SPPC. See below for additional information on AB369.
Item 7, Financial Statements and Exhibits
Presented the unaudited pro forma financial statements of SPPC showing
the effect of the proposed sale of SPPC's water business.
Form 8-K filed on April 20, 2001, by SPR, NPC, and SPPC - Item 5, Other Events
Disclosed, and included as an exhibit, SPR's press release dated April
18, 2001, announcing that Assembly Bill 369 (AB369) was passed by the Nevada
Legislature, signed by the governor, and effective immediately.
Form 8-K filed on April 27, 2001, by SPR, NPC, and SPPC - Item 5, Other Events
Disclosed, and included as an exhibit, SPR's press release dated April
26, 2001, announcing that SPR and Enron Corp mutually agreed to terminate their
purchase and sale agreement for Enron's wholly owned electric utility
subsidiary, Portland General Electric.
Form 8-K filed on May 18, 2001, by SPPC - Item 7, Financial Statements and
Exhibits
Presented updated unaudited pro forma financial statements of SPPC
showing the effect of the proposed sale of SPPC's water business.
Form 8-K filed on June 25, 2001, by SPPC - Item 2, Acquisition or Disposition of
Assets
Disclosed that on June 11, 2001, SPPC completed the sale of its water
business assets (excluding hydroelectric generation assets) to the Truckee
Meadows Water Authority.
40
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: August 9, 2001 By: /s/ DENNIS D. SCHIFFEL
-------------- ----------------------------------
Dennis D. Schiffel
Senior Vice President
Chief Financial Officer
(Principal Financial Officer)
Date: August 9, 2001 By: /s/ JOHN E. BROWN
-------------- ----------------------------------
John E. Brown
Controller
(Principal Accounting Officer)
Nevada Power Company
--------------------
(Registrant)
Date: August 9, 2001 By: /s/ DENNIS D. SCHIFFEL
-------------- ----------------------------------
Dennis D. Schiffel
Senior Vice President
Chief Financial Officer
(Principal Financial Officer)
Date: August 9, 2001 By: /s/ JOHN E. BROWN
-------------- ----------------------------------
John E. Brown
Controller
(Principal Accounting Officer)
Sierra Pacific Power Company
----------------------------
(Registrant)
Date: August 9, 2001 By: /s/ DENNIS D. SCHIFFEL
-------------- ----------------------------------
Dennis D. Schiffel
Senior Vice President
Chief Financial Officer
(Principal Financial Officer)
Date: August 9, 2001 By: /s/ JOHN E. BROWN
-------------- ----------------------------------
John E. Brown
Controller
(Principal Accounting Officer)
41