================================================================================
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED September 30, 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 October 30, 2001
Common Stock, $1.00 par value 102,090,325 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 SEPTEMBER 30, 2001
CONTENTS
PART I - FINANCIAL INFORMATION
------------------------------
ITEM 1. Financial Statements
Sierra Pacific Resources -
Condensed Consolidated Balance Sheets - September 30, 2001 and December 31, 2000.................. 3
Condensed Consolidated Statements of Income (Loss) - Three Months and Nine Months
Ended September 30, 2001 and 2000............................................................. 4
Condensed Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2001 and 2000.... 5
Nevada Power Company -
Condensed Balance Sheets - September 30, 2001 and December 31, 2000................................ 6
Condensed Statements of Income (Loss) - Three Months and Nine Months
Ended September 30, 2001 and 2000............................................................. 7
Condensed Statements of Cash Flows - Nine Months Ended September 30, 2001 and 2000................. 8
Sierra Pacific Power Company -
Condensed Consolidated Balance Sheets - September 30, 2001 and December 31, 2000................... 9
Condensed Consolidated Statements of Income (Loss) - Three Months and Nine Months
Ended September 30, 2001 and 2000............................................................. 10
Condensed Consolidated Statements of Cash Flows - Nine Months Ended September 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............ 24
Sierra Pacific Resources Results of Operations................................................ 25
Nevada Power Company Results of Operations.................................................... 30
Sierra Pacific Power Company Results of Operations............................................ 34
ITEM 3. Quantitative and Qualitative Disclosures about Market Risk....................................... 42
PART II - OTHER INFORMATION
---------------------------
ITEM 1. Legal Proceedings................................................................................ 43
ITEM 4. Submission of Matters to a Vote of Security Holders.............................................. 43
ITEM 5. Other Information................................................................................ 43
ITEM 6. Exhibits and Reports on Form 8-K................................................................. 43
Signature Page............................................................................................... 45
2
SIERRA PACIFIC RESOURCES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
September 30, December 31,
2001 2000
--------------- --------------
ASSETS (Unaudited)
Utility Plant at Original Cost:
Plant in service $ 5,619,150 $ 5,269,724
Less: accumulated provision for depreciation 1,751,876 1,636,657
--------------- --------------
3,867,274 3,633,067
Construction work-in-progress 203,526 348,067
--------------- --------------
4,070,800 3,981,134
--------------- --------------
Investments in subsidiaries and other property, net 126,052 135,062
--------------- --------------
Current Assets:
Cash and cash equivalents 26,040 51,503
Accounts receivable less provision for uncollectible accounts:
2001-$42,044; 2000-$13,194 839,560 336,361
Federal income tax receivable 303,401 40,686
Materials, supplies and fuel, at average cost 95,334 75,132
Other 22,412 18,442
--------------- --------------
1,286,747 522,124
--------------- --------------
Deferred Charges:
Goodwill, net of amortization 314,210 320,256
Deferred energy costs - electric 1,105,699 -
Deferred energy costs - gas 42,308 16,370
Regulatory tax asset 175,587 175,509
Other regulatory assets 107,799 105,588
Risk management assets (Note 10) 434,380 -
Risk management regulatory assets - net (Note 10) 786,714 -
Other 126,648 116,965
--------------- --------------
3,093,345 734,688
--------------- --------------
Net assets of discontinued operations (Note 8) - 261,479
--------------- --------------
$ 8,576,944 $ 5,634,487
=============== ==============
CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholders' equity $ 1,730,841 $ 1,359,712
Accumulated other comprehensive loss (6,971) -
Preferred stock 50,000 50,000
SPPC/ NPC obligated mandatorily redeemable preferred trust securities 237,372 237,372
Long-term debt 2,946,488 2,133,679
--------------- --------------
4,957,730 3,780,763
--------------- --------------
Current Liabilities:
Short-term borrowings 269,561 213,074
Current maturities of long-term debt 23,616 472,527
Accounts payable 855,452 312,039
Accrued interest 67,610 30,184
Dividends declared 1,039 20,890
Accrued salaries and benefits 25,718 28,957
Other current liabilities 1,152 17,795
--------------- --------------
1,244,148 1,095,466
--------------- --------------
Commitments & Contingencies (Note 11)
Deferred Credits:
Deferred federal income taxes 385,919 406,310
Deferred investment tax credit 52,810 55,252
Deferred taxes on deferred energy costs 401,802 -
Regulatory tax liability 50,685 50,994
Customer advances for construction 106,743 109,962
Accrued retirement benefits 90,466 80,027
Risk management liabilities (Note 10) 1,225,412 -
Other 61,229 55,713
--------------- --------------
2,375,066 758,258
--------------- --------------
$ 8,576,944 $ 5,634,487
=============== ==============
The accompanying notes are an integral part of the financial statements
3
SIERRA PACIFIC RESOURCES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (LOSS)
(DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
Three months ended Nine months ended
September 30, September 30,
-------------------------------- -----------------------------
2001 2000 2001 2000
-------------- ------------- -------------- ------------
(unaudited) (unaudited)
OPERATING REVENUES:
Electric $ 1,947,419 $ 852,730 $ 3,747,213 $ 1,662,592
Gas 18,831 12,787 104,725 63,378
Other 5,650 2,657 13,350 9,165
-------------- ------------- -------------- ------------
1,971,900 868,174 3,865,288 1,735,135
-------------- ------------- -------------- ------------
OPERATING EXPENSES:
Operation:
Purchased power 2,195,051 581,994 3,636,006 911,773
Fuel for power generation 189,968 151,567 595,172 317,594
Gas purchased for resale 9,294 6,989 105,008 41,310
Deferral of energy costs-electric-net (737,634) 2,445 (1,080,846) 16,719
Deferral of energy costs-gas-net 3,453 (180) (23,354) (900)
Other 81,924 56,421 248,428 183,310
Maintenance 15,475 12,288 53,933 40,194
Depreciation and amortization 40,958 39,079 120,552 116,754
Taxes:
Income taxes 40,087 (12,969) 8,033 (14,641)
Other than income 11,134 11,466 32,358 31,611
-------------- ------------- -------------- ------------
1,849,710 849,100 3,695,290 1,643,724
-------------- ------------- -------------- ------------
OPERATING INCOME 122,190 19,074 169,998 91,411
-------------- ------------- -------------- ------------
OTHER (EXPENSE) INCOME:
Allowance for other funds used during construction (106) 511 (793) 2,486
Other income - net 16,007 169 22,319 3,578
-------------- ------------- -------------- ------------
15,901 680 21,526 6,064
-------------- ------------- -------------- ------------
TOTAL INCOME BEFORE INTEREST CHARGES 138,091 19,754 191,524 97,475
-------------- ------------- -------------- ------------
INTEREST CHARGES:
Long-term debt 47,623 36,228 131,155 89,337
Other 5,474 4,718 20,767 29,618
Allowance for borrowed funds used during construction and
capitalized interest (1,225) (3,053) (1,514) (7,779)
-------------- ------------- -------------- ------------
51,872 37,893 150,408 111,176
-------------- ------------- -------------- ------------
INCOME (LOSS) BEFORE SPPC/NPC OBLIGATED MANDATORILY
REDEEMABLE PREFERRED TRUST SECURITIES 86,219 (18,139) 41,116 (13,701)
Preferred dividend requirements of SPPC/NPC obligated
mandatorily redeemable preferred trust securities 4,835 4,729 14,293 14,187
-------------- ------------- -------------- ------------
INCOME (LOSS) BEFORE PREFERRED STOCK DIVIDENDS 81,384 (22,868) 26,823 (27,888)
Preferred stock dividend requirements of subsidiary 975 874 2,725 2,624
-------------- ------------- -------------- ------------
INCOME (LOSS) FROM CONTINUING OPERATIONS 80,409 (23,742) 24,098 (30,512)
-------------- ------------- -------------- ------------
DISCONTINUED OPERATIONS:
Income from operations of water business disposed of
(net of income taxes of $0 and $888 in 2001 and
$2,713 and $2,585 in 2000, respectively) - 4,194 1,022 8,951
Gain on disposal of water business
(net of income taxes of $18,237) - - 25,845 -
-------------- ------------- -------------- ------------
NET INCOME (LOSS) $ 80,409 $ (19,548) $ 50,965 $ (21,561)
============== ============= ============== ============
Income (Loss) per share - Basic and Diluted
Income (Loss) from continuing operations $ 0.89 $ (0.30) $ 0.29 $ (0.38)
Income from discontinued operations - 0.05 0.01 0.11
Gain on disposal of water business - - 0.32 -
-------------- ------------- -------------- ------------
Net income (loss) $ 0.89 $ (0.25) $ 0.62 $ (0.27)
============== ============= ============== ============
Weighted Average Shares of Common Stock Outstanding (000's) 90,303 78,446 82,423 78,428
============== ============= ============== ============
Dividends Paid Per Share of Common Stock $ 0.200 $ 0.250 $0.450 $ 0.750
============== ============= ============== ============
The accompanying notes are an integral part of the financial statements.
4
SIERRA PACIFIC RESOURCES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
Nine Months Ended
September 30,
------------------------------------
2001 2000
------------------------------------
(Unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES:
Income (Loss) from continuing operations before preferred dividends $ 26,823 $ (27,888)
Income from discontinued operations before preferred dividends 1,222 9,252
Gain from on disposal of water business 25,845 -
Non-cash items included in income:
Depreciation and amortization 124,011 122,269
Deferred taxes and deferred investment tax credit 107,795 (1,444)
AFUDC and capitalized interest (730) (10,567)
Early retirement and severance amortization 3,121 3,147
Gain on disposal of water business (44,081) -
Other non-cash 3,676 (310)
Changes in certain assets and liabilities:
Accounts receivable (498,883) (203,084)
Materials, supplies and fuel (19,849) (12,830)
Deferred energy costs - electric (1,105,698) -
Deferred energy costs - gas (25,938) 13,984
Other current assets (4,093) (45,161)
Accounts payable 543,413 134,165
Other current liabilities 18,061 15,311
Other - net 16,827 37,499
------------- ------------
Net Cash Flows (Used in) Provided by Operating Activities (828,478) 34,343
------------- ------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to utility plant (251,458) (241,221)
AFUDC and other charges to utility plant 730 3,573
Customer refunds for construction (3,219) 11,687
Contributions in aid of construction 24,259 1,985
------------- ------------
Net cash used for utility plant (229,688) (223,976)
Proceeds from sale of assets of water business 318,882 -
Investments in subsidiaries and other property - net (3,961) (26,958)
------------- ------------
Net Cash Provided by (Used in) Investing Activities 85,233 (250,934)
------------- ------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Increase (Decrease) in short-term borrowings 56,487 (553,766)
Proceeds from issuance of long-term debt 900,000 1,050,000
Retirement of long-term debt (536,103) (202,778)
Sale of common stock 340,764 37
Dividends paid (43,366) (64,950)
------------- ------------
Net Cash Provided by Financing Activities 717,782 228,543
------------- ------------
Net (Decrease) Increase in Cash and Cash Equivalents (25,463) 11,952
Beginning balance in Cash and Cash Equivalents 51,503 4,789
------------- ------------
Ending balance in Cash and Cash Equivalents $ 26,040 $ 16,741
============= ============
Supplemental Disclosures of Cash Flow Information:
Cash Paid During Period For:
Interest $ 112,982 $ 99,741
Income Taxes $ 28,424 $ 12,730
The accompanying notes are an integral part of the financial statements
5
NEVADA POWER COMPANY
CONDENSED BALANCE SHEETS
(Dollars in Thousands)
September 30, December 31,
2001 2000
-------------------- -----------------
ASSETS (unaudited)
Utility Plant at Original Cost:
Plant in service $3,328,856 $3,089,705
Less: accumulated provision for depreciation 912,256 855,599
---------------------- -----------------
2,416,600 2,234,106
Construction work-in-progress 112,539 228,856
---------------------- -----------------
2,529,139 2,462,962
---------------------- -----------------
Investment in Sierra Pacific Resources (Note 2) 424,877 471,975
Investments in subsidiaries and other property, net 12,115 13,418
---------------------- -----------------
436,992 485,393
---------------------- -----------------
Current Assets:
Cash and cash equivalents 18,259 43,858
Accounts receivable less provision for uncollectible accounts:
2001-$34,641; 2000-$11,605 548,862 137,097
Federal income tax receivable 284,525 18,728
Materials, supplies and fuel, at average cost 51,381 45,573
Other 10,930 10,205
---------------------- -----------------
913,957 255,461
---------------------- -----------------
Deferred Charges:
Deferred energy costs 928,987 -
Regulatory tax asset 113,647 113,647
Other regulatory assets 32,620 32,583
Risk management assets (Note 10) 323,451 -
Risk management regulatory assets - net (Note 10) 422,017 -
Other 27,074 25,912
---------------------- -----------------
1,847,796 172,142
---------------------- -----------------
$5,727,884 $3,375,958
====================== =================
CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholders' equity including $424,877 and $471,975 of equity
in Sierra Pacific Resources in 2001and 2000, respectively (Note 2) $1,730,993 $1,359,712
Accumulated other comprehensive income 674 -
NPC obligated mandatorily redeemable preferred trust securities 188,872 188,872
Long-term debt 1,422,584 927,784
---------------------- ----------------
3,343,123 2,476,368
---------------------- ----------------
Current Liabilities:
Short-term borrowings 230,561 100,000
Current maturities of long-term debt 3,999 252,910
Accounts payable 649,657 126,015
Accrued interest 31,223 16,913
Dividends declared 71 86
Accrued salaries and benefits 10,479 12,297
Other current liabilities 16,590 16,450
---------------------- -----------------
942,580 524,671
---------------------- -----------------
Commitments & Contingencies (Note 11)
Deferred Credits:
Deferred federal income taxes 210,572 216,753
Deferred investment tax credit 23,940 25,163
Deferred taxes on deferred energy costs 325,145 -
Regulatory tax liability 19,908 19,908
Customer advances for construction 61,534 65,588
Accrued retirement benefits 34,000 27,985
Risk management liabilities (Note 10) 743,714 -
Other 23,368 19,522
---------------------- -----------------
1,442,181 374,919
---------------------- -----------------
$5,727,884 $3,375,958
====================== =================
The accompanying notes are an integral part of the financial statements.
6
NEVADA POWER COMPANY
CONDENSED STATEMENTS OF INCOME (LOSS)
(Dollars in Thousands, Except Per Share Amounts)
Three months ended Nine months ended
September 30, September 30,
------------------------------ ------------- -----------
2001 2000 2001 2000
---------------- ------------ ------------- -----------
(unaudited) (unaudited)
OPERATING REVENUES:
Electric $ 1,395,496 $ 547,395 $2,562,949 $1,022,815
OPERATING EXPENSES:
Operation:
Purchased power 1,686,816 385,129 2,728,176 593,479
Fuel for power generation 131,023 86,140 348,633 178,809
Deferral of energy costs-net (638,571) 2,445 (908,408) 16,719
Other 45,670 33,638 130,192 97,923
Maintenance 10,331 8,126 36,789 27,210
Depreciation and amortization 23,042 21,391 67,345 64,121
Taxes:
Income taxes 36,197 (5,642) 21,979 (12,461)
Other than income 6,221 6,542 18,118 17,860
---------------- ----------- ------------- -----------
1,300,729 537,769 2,442,824 983,660
---------------- ----------- ------------- -----------
OPERATING INCOME 94,767 9,626 120,125 39,155
---------------- ----------- ------------- -----------
OTHER INCOME (EXPENSE):
Equity in earnings (losses) of Sierra Pacific Resources (Note 2) 1,658 (10,766) (5,494) (2,944)
Allowance for other funds used during construction (87) 430 (560) 2,272
Other income - net 11,021 1,307 14,189 2,014
---------------- ----------- ------------- -----------
12,592 (9,029) 8,135 1,342
---------------- ----------- ------------- -----------
TOTAL INCOME BEFORE INTEREST CHARGES 107,359 597 128,260 40,497
---------------- ----------- ------------- -----------
INTEREST CHARGES:
Long-term debt 20,545 15,980 55,504 46,132
Other 3,269 2,745 10,982 10,677
Allowance for borrowed funds used during construction and
capitalized interest (657) (2,373) (570) (6,130)
---------------- ----------- ------------- ------------
23,157 16,352 65,916 50,679
---------------- ----------- ------------- ------------
INCOME (LOSS) BEFORE NPC OBLIGATED MANDATORILY
REDEEMABLE PREFERRED TRUST SECURITIES 84,202 (15,755) 62,344 (10,182)
Preferred dividend requirements of NPC obligated
mandatorily redeemable preferred trust securities 3,793 3,793 11,379 11,379
---------------- ----------- ------------- ------------
NET INCOME (LOSS) $ 80,409 $ (19,548) $ 50,965 $ (21,561)
================ =========== ============= ============
Net Income (Loss) Per Share- Basic (Note 2) $ 0.89 $ (0.25) $ 0.62 $ (0.27)
================ =========== ============= ============
- Diluted (Note 2) $ 0.89 $ (0.25) $ 0.62 $ (0.27)
================ =========== ============= ============
Weighted Average Shares of Common
Stock Outstanding (000's) (Note 2) 90,303 78,446 82,423 78,428
================ =========== ============= ============
Dividends Paid Per Share of Common Stock (Note 2) $ 0.200 $ 0.250 $ 0.450 $ 0.750
================ =========== ============= ============
The accompanying notes are an integral part of the financial statements.
7
NEVADA POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS
(DOLLARS IN THOUSANDS)
Nine Months Ended
September 30,
-------------------------------------
2001 2000
--------------- ---------------
(Unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES:
Income (Loss) before preferred dividends $ 50,965 $ (21,561)
Non-cash items included in income:
Depreciation and amortization 67,345 64,121
Deferred taxes and deferred investment tax credit 51,944 (5,597)
AFUDC and capitalized interest (10) (8,402)
Other non-cash 2,367 (2,961)
Equity in losses of SPR (Note 2) 5,494 2,944
Changes in certain assets and liabilities, net of acquisition:
Accounts receivable (411,765) (147,917)
Materials, supplies and fuel (5,809) (876)
Deferred energy costs (928,987) 14,884
Other current assets (725) (17,265)
Accounts payable 523,642 72,215
Other current liabilities 12,632 7,311
Other - net 8,780 21,150
---------- ----------
Net Cash Flows Used in Operating Activities (624,127) (21,954)
---------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to utility plant (141,414) (138,698)
AFUDC and other charges to utility plant 10 1,349
Customer refunds for construction (4,054) (1,225)
Contributions in aid of construction 5,630 -
---------- ----------
Net cash used for utility plant (139,828) (138,574)
Investments in subsidiaries and other property - net - 250
---------- ----------
Net Cash Used in Investing Activities (139,828) (138,324)
---------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Increase (Decrease) in short-term borrowings 130,561 (58,937)
Proceeds from issuance of long-term debt 500,000 250,000
Retirement of long-term debt (254,112) (90,359)
Additional investment by parent company 394,921 128,000
Dividends paid (33,014) (64,000)
---------- ----------
Net Cash Provided by Financing Activities 738,356 164,704
---------- ----------
Net Increase (Decrease) in Cash and Cash Equivalents (25,599) 4,426
Beginning balance in Cash and Cash Equivalents 43,858 243
---------- ----------
Ending balance in Cash and Cash Equivalents $ 18,259 $ 4,669
========== ==========
Supplemental Disclosures of Cash Flow Information:
Cash Paid During Period For:
Interest $ 28,160 $ 48,303
Income Taxes $ 47,501 $ 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)
September 30, December 31,
2001 2000
------------- ------------
(Unaudited)
ASSETS
Utility Plant at Original Cost:
Plant in service $ 2,290,294 $ 2,180,019
Less: accumulated provision for depreciation 839,620 781,058
----------- -----------
1,450,674 1,398,961
Construction work-in-progress 90,986 119,210
----------- -----------
1,541,660 1,518,171
----------- -----------
Investments in subsidiaries and other property, net 57,830 60,047
----------- -----------
Current Assets:
Cash and cash equivalents 2,919 5,348
Accounts receivable less provision for uncollectible accounts:
2001 - $7,403; 2000 - $1,589 299,919 133,369
Federal income tax receivable 18,877 21,958
Materials, supplies and fuel, at average cost 41,163 29,209
Other 10,499 7,894
----------- -----------
373,377 197,778
----------- -----------
Deferred Charges:
Deferred energy costs - electric 176,712 -
Deferred energy costs - gas 42,308 16,370
Regulatory tax asset 61,940 61,862
Other regulatory assets 56,605 61,236
Risk management assets (Note 10) 110,954 -
Risk management regulatory assets - net (Note 10) 364,697 -
Other 15,517 12,036
----------- -----------
828,733 151,504
----------- -----------
Net assets of discontinued operations (Note 8) - 261,479
----------- -----------
$ 2,801,600 $ 2,188,979
=========== ===========
CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholder's equity 583,316 604,795
Accumulated other comprehensive income 321 -
Preferred stock 50,000 50,000
SPPC obligated mandatorily redeemable preferred trust securities 48,500 48,500
Long-term debt 923,836 605,816
----------- -----------
1,605,973 1,309,111
----------- -----------
Current Liabilities:
Short-term borrowings 19,000 108,962
Current maturities of long-term debt 19,616 219,616
Accounts payable 227,141 146,724
Accrued interest 22,811 6,992
Dividends declared 968 23,975
Accrued salaries and benefits 12,551 15,475
Other current liabilities 3,261 2,932
----------- -----------
305,348 524,676
----------- -----------
Commitments & Contingencies (Note 11)
Deferred Credits:
Deferred federal income taxes 164,853 179,106
Deferred investment tax credit 28,870 30,088
Deferred taxes on deferred energy costs 76,657 -
Regulatory tax liability 30,777 31,087
Accrued retirement benefits 44,741 44,374
Customer advances for construction 45,209 41,776
Risk management liabilities (Note 10) 473,733 -
Other 25,439 28,761
----------- -----------
890,279 355,192
----------- -----------
$ 2,801,600 $ 2,188,979
=========== ===========
The accompanying notes are an integral part of the financial statements.
9
SIERRA PACIFIC POWER COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (LOSS)
(Dollars in Thousands)
Three months Nine months
ended ended
September 30, September 30,
------------------------- --------------------------
2001 2000 2001 2000
--------- --------- ----------- ---------
(unaudited) (unaudited)
OPERATING REVENUES:
Electric $ 551,923 $ 305,334 $ 1,184,264 $ 639,776
Gas 18,831 12,787 104,725 63,378
--------- --------- ----------- ---------
570,754 318,121 1,288,989 703,154
--------- --------- ----------- ---------
OPERATING EXPENSES:
Operation:
Purchased power 508,235 196,865 907,830 318,294
Fuel for power generation 58,946 65,427 246,540 138,785
Gas purchased for resale 9,294 6,989 105,008 41,310
Deferral of energy costs-electric-net (98,702) - (172,437) -
Deferral of energy costs-gas-net 3,093 (180) (23,354) (900)
Other 28,222 18,608 79,090 68,328
Maintenance 5,143 4,162 17,143 12,984
Depreciation and amortization 17,620 17,561 52,328 52,144
Taxes:
Income taxes 8,630 (3,504) 7,974 9,274
Other than income 4,671 4,712 13,639 13,352
--------- --------- ----------- ---------
545,152 310,640 1,233,761 653,571
--------- --------- ----------- ---------
OPERATING INCOME 25,602 7,481 55,228 49,583
--------- --------- ----------- ---------
OTHER (EXPENSE) INCOME:
Allowance for other funds used during construction (19) 81 (233) 215
Other income (expense) - net 4,309 117 5,322 (1,122)
--------- --------- ----------- ---------
4,290 198 5,089 (907)
--------- --------- ----------- ---------
TOTAL INCOME BEFORE INTEREST CHARGES 29,892 7,679 60,317 48,676
--------- --------- ----------- ---------
INTEREST CHARGES:
Long-term debt 15,380 10,953 38,479 26,861
Other 1,455 1,348 7,437 8,519
Allowance for borrowed funds used during construction and
capitalized interest (566) (680) (943) (1,649)
--------- --------- ----------- ---------
16,269 11,621 44,973 33,731
--------- --------- ----------- ---------
INCOME (LOSS) BEFORE SPPC OBLIGATED MANDATORILY
REDEEMABLE PREFERRED TRUST SECURITIES 13,623 (3,942) 15,344 14,945
Preferred dividend requirements of SPPC obligated
mandatorily redeemable preferred trust securities 1,042 935 2,914 2,807
--------- --------- ----------- ---------
INCOME (LOSS) BEFORE PREFERRED STOCK DIVIDENDS 12,581 (4,877) 12,430 12,138
Preferred dividend requirements 975 874 2,725 2,624
--------- --------- ----------- ---------
NET INCOME (LOSS) FROM CONTINUING OPERATIONS 11,606 (5,751) 9,705 9,514
--------- --------- ----------- ---------
DISCONTINUED OPERATIONS:
Income from operations of water business disposed of
(net of income taxes of $0 and $888 in 2001 and
$2,713 and $2,585 in 2000, respectively) - 4,194 1,022 8,951
Gain on disposal of water business
(net of income taxes of $18,237) - - 25,845 -
--------- --------- ----------- ---------
NET INCOME (LOSS) $ 11,606 $ (1,557) $ 36,572 $ 18,465
========= ========= =========== =========
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)
Nine Months Ended
September 30,
--------------------------------------
2001 2000
--------------- ----------------
(Unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES:
Income from continuing operations before preferred dividends $ 12,430 $ 12,138
Income from discontinued operations before preferred dividends 1,222 9,252
Gain on disposal of water business 25,845 -
Non-cash items included in income:
Depreciation and amortization 55,788 57,659
Deferred taxes and investment tax credits 55,807 4,124
AFUDC and capitalized interest (719) (2,166)
Early retirement and severance amortization 3,121 3,147
Gain on disposal of water business (44,081) -
Other non-cash (3,580) 2,650
Changes in certain assets and liabilities:
Accounts receivable (162,234) 413
Materials, supplies and fuel (11,601) (12,153)
Deferred energy costs - electric (176,712) -
Deferred energy costs - gas (25,938) (900)
Other current assets (2,728) (16,686)
Accounts payable 80,416 15,197
Other current liabilities 13,742 6,678
Other-net 1,596 (5,333)
--------------- ----------------
Net Cash Flows (Used in) Provided by Operating Activities (177,626) 74,020
--------------- ----------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to utility plant (110,043) (102,523)
AFUDC and other charges to utility plant 719 2,224
Customer (refunds) advances for construction 835 3,210
Contributions in aid of construction 18,628 11,687
--------------- ----------------
Net cash used for utility plant (89,861) (85,402)
Proceeds from sale of assets of water business 318,882 -
Investment in subsidiaries and other non-utility property - net 2,102 1,597
--------------- ----------------
Net Cash Provided by (Used in) Investing Activities 231,123 (83,805)
--------------- ----------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Decrease in short-term borrowings (89,962) (31,434)
Proceeds from issuance of long-term debt 400,000 200,000
Retirement of long-term debt (281,980) (102,307)
Additional investment by parent company 4,948 14,000
Dividends paid (88,932) (66,924)
--------------- ----------------
Net Cash (Used in) Provided by Financing Activities (55,926) 13,335
--------------- ----------------
Net (Decrease) Increase in Cash and Cash Equivalents (2,429) 3,550
Beginning Balance in Cash and Cash Equivalents 5,348 3,011
--------------- ----------------
Ending Balance in Cash and Cash Equivalents $ 2,919 $ 6,561
=============== ================
Supplemental Disclosures of Cash Flow Information:
Cash Paid (Received) During Period For:
Interest $ 29,154 $ 33,476
Income Taxes $ 22,227 $ 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 nine months ended September 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 ethree, 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 periods prior to 2001 have been
reclassified to conform to the current periods 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.
In August 2001, the FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets." This standard provides guidance
on the impairment of long-lived assets and for long-lived assets to be disposed
of. The standard supersedes the current authoritative literature on impairments
as well as disposal of a segment of a business and is effective for fiscal years
and interim periods beginning after December 15, 2001. Management has not yet
determined the impact, if any, of the adoption of this standard 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: September 30, 2001 December 31, 2000
----------------- ------------------ -----------------
Investment in Sierra Pacific Resources $424,877 $471,975
Equity in Sierra Pacific Resources $424,877 $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
-------------------- ------------------ ------------------
September 30, 2001 September 30, 2000
------------------ ------------------
Equity in Earnings (Losses) of Sierra Pacific $1,658 $(10,766)
Resources
Nine Months Ended Nine Months Ended
----------------- -----------------
September 30, 2001 September 30, 2000
------------------ ------------------
Equity in Losses of Sierra Pacific Resources $(5,494) $(2,944)
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. Also as a result of the reverse purchase accounting treatment
described above, NPC's Income Statement includes Earnings Per Share and
Dividends Paid Per Share information.
NPC Statement of Cash Flow: Nine Months Ended Nine Months Ended
-------------------------- ----------------- -----------------
September 30, 2001 September 30, 2000
------------------ ------------------
Equity in Losses of Sierra Pacific Resources $5,494 $2,944
As in the income statement, the Equity in Losses of Sierra Pacific
Resources reflects the nine months of SPR net losses, after SPPC preferred stock
dividends.
This line item does not represent any item of cash flow to which holders of
NPC's securities may look for recovery of their investment. This item must be
disregarded for determining the ability of NPC to satisfy its obligations or its
ability to pay dividends (preferred or common), for calculating NPC's ratios of
earnings to fixed charges and preferred dividends and for all of NPC's financial
covenants and earnings tests including those under its charter and 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 was paid off and terminated on June 12, 2001. On August 15, 2001, SPR
established an unsecured credit facility of $25 million that will expire on
August 14, 2002. On September 10, 2001, SPR established an additional credit
facility of $25 million that will expire on November 30, 2001. As of September
30, 2001, SPR had $20 million of outstanding borrowings under these facilities.
NPC had no commercial paper outstanding at December 31, 2000, and June 30,
2001. During the third quarter, NPC issued new commercial paper and, as of
September 30, 2001, had $130.6 million outstanding at a weighted average
interest rate of 3.68%.
SPPC's commercial paper balance was $108.9 million at December 31, 2000.
By June 12, 2001, SPPC had eliminated its commercial paper balances and had no
commercial paper outstanding as of June 30, 2001. SPPC issued $27.5 million of
commercial paper in September and had an outstanding balance of $19 million as
of September 30, 2001, at a weighted average interest rate of 3.36%.
13
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 may be used for working capital and
general corporate purposes, including commercial paper backup. SPR and the
Utilities are currently negotiating new credit facilities to take effect after
their current facilities expire on November 30, 2001. It is expected that the
Utilities' new credit facilities will require each Utility, in the event of a
decline in that Utility's senior unsecured debt ratings, to issue general and
refunding mortgage bonds to secure its new facility.
NOTE 4. LONG-TERM DEBT (NPC, SPPC)
------------------------------------
Nevada Power Company
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. NPC has agreed to exchange these
bonds for identical bonds which have been registered with the Securities and
Exchange Commission (the "SEC"). NPC expects to complete this exchange offer in
December 2001.
On June 12, 2001, $150 million of NPC's unsecured floating rate notes
matured and were paid in full.
On August 3, 2001, NPC issued $115 million 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 20, 2001, $100 million of NPC's unsecured floating rate notes
matured and were paid in full.
On September 20, 2001, NPC issued $150 million of 6% unsecured notes due
September 15, 2003. Interest on the notes is payable on March 15 and September
15 of each year. These notes are not entitled to any sinking fund and are non-
callable. The net proceeds of the $150 million issue were used to reduce
commercial paper balances that had been incurred to cover increased purchased
power and fuel costs and to pay maturing debt.
Sierra Pacific Power Company
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 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 8 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. SPPC has agreed to exchange these
bonds for identical bonds which have been registered with the SEC. SPPC expects
to complete this exchange offer in December 2001.
On June 12, 2001, $200 million of SPPC's floating rate notes matured and
were paid in full.
NOTE 5. COMMON STOCK AND PREFERRED STOCK (SPR, NPC)
-----------------------------------------------------
On August 15, 2001, SPR completed a public offering of 23,575,000 shares of
its common stock, yielding net proceeds of approximately $340 million, all of
which were contributed to NPC as an additional equity investment. NPC used
these proceeds to pay maturing debt and for working capital purposes.
14
NOTE 6. 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 Nine Months Ended
September 30, September 30,
---------------------------- -----------------------------
2001 2000 2001 2000
----------- ------------ ----------- ------------
Basic EPS
Numerator ($000)
Income (Loss) from continuing operations $ 80,409 $ (23,742) $ 24,098 $ (30,512)
Income from discontinued operations - 4,194 1,022 8,951
Gain on disposal of water business - - 25,845
----------- ------------ ----------- ------------
Net income (loss) $ 80,409 $ (19,548) $ 50,965 $ (21,561)
=========== ============ =========== ============
Denominator
Weighted average number of shares
outstanding 90,302,825 78,446,264 82,423,032 78,427,523
----------- ------------ ----------- ------------
Per-Share Amounts:
Income (Loss) from continuing operations $ 0.89 $ (0.30) $ 0.29 $ (0.38)
Income from discontinued operations - 0.05 0.01 0.11
Gain on disposal of water business - - 0.32 -
----------- ------------ ----------- ------------
Net income (loss) $ 0.89 $ (0.25) $ 0.62 $ (0.27)
=========== ============ =========== ============
Diluted EPS
Numerator ($000)
Income (Loss) from continuing operations $ 80,409 $ (23,742) $ 24,098 $ (30,512)
Income from discontinued operations - 4,194 1,022 8,951
Gain on disposal of water business - - 25,845 -
----------- ------------ ----------- ------------
Net income (loss) $ 80,409 $ (19,548) $ 50,965 $ (21,561)
=========== ============ =========== ============
Denominator
Weighted average number of shares
outstanding before dilution 90,302,825 78,446,264 82,423,032 78,427,523
Stock options/1/ 31,645 3,441 18,285 2,041
Executive long term incentive plan-
performance shares/1/ 71,593 44,597 37,960 43,301
Non-Employee Director stock plan/1/ 9,355 4,532 9,355 4,532
Employee stock purchase plan/1/ 3,519 5,284 3,185 1,993
----------- ------------ ----------- ------------
90,418,937 78,504,118 82,491,817 78,479,390
----------- ------------ ----------- ------------
Per-Share Amounts/1/:
Income (Loss) from continuing operations $ 0.89 $ (0.30) $ 0.29 $ (0.38)
Income from discontinued operations - 0.05 0.01 0.11
Gain on disposal of water business - - 0.32 -
----------- ------------ ----------- ------------
Net income (loss) $ 0.89 $ (0.25) $ 0.62 $ (0.27)
=========== ============ =========== ============
/1/ Because of net losses for the three- and nine-month periods ended September
30, 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 7. SEGMENT INFORMATION (SPR, NPC, SPPC)
----------------------------------------------
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. On June 11, 2001, SPPC sold its
water utility business. Accordingly, the water business is not included in the
segment information below.
Information as to the operations of the different business segments is set
forth below based on the nature of products and services offered. SPR evaluates
performance based on several factors, of which the primary financial measure is
business segment operating income. Intersegment revenues are not material.
Financial data for business segments is as follows (in thousands):
Three Months Ended NPC SPPC Total
September 30, 2001 Electric Electric Electric Gas Other Consolidated
-------------------- -------------- -------------- -------------- -------------- -------------- --------------
Operating Revenues $ 1,395,496 $ 551,923 $ 1,947,419 $ 18,831 $ 5,650 $ 1,971,900
============== ============== ============== ============== ============== ==============
Operating Income $ 94,767 $ 25,146 $ 119,913 $ 456 $ 1,821 $ 122,190
============== ============== ============== ============== ============== ==============
Nine Months Ended NPC SPPC Total
September 30, 2001 Electric Electric Electric Gas Other Consolidated
-------------------- -------------- -------------- -------------- -------------- -------------- --------------
Operating Revenues $ 547,396 $ 305,334 $ 852,730 $ 12,787 $ 2,657 $ 868,174
============== ============== ============== ============== ============== ==============
Operating Income $ 9,626 $ 5,555 $ 15,181 $ 1,926 $ 1,967 $ 19,074
============== ============== ============== ============== ============== ==============
Nine Months Ended NPC SPPC Total
September 30, 2001 Electric Electric Electric Gas Other Consolidated
-------------------- -------------- -------------- -------------- -------------- -------------- --------------
Operating Revenues $ 2,562,949 $ 1,184,264 $ 3,747,213 $ 104,725 $ 13,350 $ 3,865,288
============== ============== ============== ============== ============== ==============
Operating Income (Loss) $ 120,125 $ 49,123 $ 169,248 $ 6,105 $ (5,355) $ 169,998
============== ============== ============== ============== ============== ==============
Three Months Ended NPC SPPC Total
September 30, 2001 Electric Electric Electric Gas Other Consolidated
-------------------- -------------- -------------- -------------- -------------- -------------- --------------
Operating Revenues $ 1,022,816 $ 639,776 $ 1,662,592 $ 63,378 $ 9,165 $ 1,735,135
============== ============== ============== ============== ============== ==============
Operating Income $ 39,155 $ 41,906 $ 81,061 $ 7,677 $ 2,673 $ 91,411
============== ============== ============== ============== ============== ==============
NOTE 8. 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 contract of 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
is being credited on the electric bills of SPPC's former water customers over a
period not to exceed fifteen months from June 11, 2001. 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 $0 and $18.7 million
for the three-month periods ended September 30, 2001, and September 30, 2000,
respectively. For the nine-month periods ended September 30, 2001, and September
30, 2000, revenues from operations of the water business were $23.2 million and
$44.3 million, respectively. The
16
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 $0 and $100,000 for the three-month periods ended September 30, 2001 and
2000, respectively, and $200,000 and $301,000 for the nine-month periods ended
September 30, 2001 and 2000, respectively. These amounts are not included in the
revenues and income (loss) from continuing operations shown in the accompanying
income statements.
NOTE 9. 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 the second quarter of 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 the 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.
17
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 Comprehensive Energy Plan (CEP) as filed by the Utilities with the PUCN on
January 29, 2001, are just and reasonable and reflect prudent business
practices.
At September 30, 2001, NPC had a balance of $929 million in its deferred
energy account, reflecting eligible fuel and purchased power costs and allowable
carrying charges incurred since March 1, 2001. At September 30, 2001, SPPC had a
balance of $219 million in its deferred energy accounts, which reflect both
eligible fuel and purchased power costs and allowable carrying charges incurred
since March 1, 2001, totaling $177 million, as well as deferrals in connection
with its natural gas business of $42 million. Future deferred energy charges
will depend greatly on a number of unpredictable factors including weather
conditions, conditions in the wholesale electricity markets in the western
United States, the effect on the wholesale markets and energy prices of price
caps imposed by the Federal Energy Regulatory Commission (FERC), and the extent
of the Utilities' revenues from sales of wholesale electricity, which offset
their respective deferred energy charges. Based upon management's continuing
monitoring of these factors, it is anticipated that NPC's deferred energy
charges (net of wholesale electric revenues) should total between $900 million
and $1 billion by the time NPC files its initial application in December 2001 to
clear its deferred energy account. Similarly, it is anticipated that SPPC's
deferred energy charges (net of wholesale electric revenues) for electricity
should total between $175 million and $225 million by the time SPPC files its
initial application in February 2002 to clear its deferred energy account.
Management cautions, however, that these expectations are subject to all of the
above uncertainties, which make it impossible at this time to predict with
certainty what the Utilities' deferred energy account balances will be at the
time that they file their initial application to clear their deferred energy
accounts.
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.
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.
18
After the initial general rate applications described above, each Utility
will be required to file future general rate applications at least every 24
months.
See "Nevada Power General Rate Case," later, for a discussion of NPC's general
rate application filed on October 1, 2001.
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,
although no customers have filed such applications as of October 31, 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 FERC adopted a price mitigation plan applicable to
spot market 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. Although the
Utilities are not able to predict at this time the long-term effect that the
FERC price mitigation plan may have on their results of operations, management
believes that, under certain market conditions, the FERC plan adversely affects
the availability of spot market power to the Utilities and reduces the price at
which the Utilities can sell power on the wholesale market. SPR 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.
19
Nevada Power General Rate Case (NPC)
On October 1, 2001, NPC filed an application with the PUCN seeking an
electric general rate increase. This application was mandated by AB 369, which
was enacted by the Nevada Legislature in April 2001. In the application, NPC
requested an increase in its general rates charged to all classes of electric
customers designed to produce an increase in annual electric revenues of $42.7
million. If the increase is granted, an average residential electric bill will
increase by approximately 8%. The application also seeks a return on common
equity ("ROE") for Nevada Power's total electric operations of 12.25% (a
reduction from NPC's last-authorized ROE for bundled electric operations of
12.50%) and an overall rate of return ("ROR") of 9.26% (a reduction from NPC's
last-authorized ROR for bundled electric operations of 10.02%). On December 1,
2001, NPC will file a deferred energy application, seeking recovery of deferred
energy balances. Final decisions on both the general rate application and
deferred energy application should occur no later than April 1, 2002, and any
rate increase approved by the PUCN would take effect after that date.
Resource Plans (SPPC, NPC)
On July 2, 2001, SPPC filed its electric resource plan for the period of
2001-2020. On July 9, 2001, NPC filed its amended electric resource plan for
the period of 2000-2019. The plans include scenarios to meet the electric needs
of customers while sustaining reliable electric systems. The integrated
resource plans evaluate resources to be used to meet forecasted loads. Resource
options considered include new transmission lines to access energy markets,
construction of generation facilities, power purchases from independent power
producers under short- and long-term agreements, and conservation programs. On
October 18, 2001, the PUCN approved NPC's amended resource plan. On August 2,
2001, a pre-hearing conference was held on SPPC's resource plan and procedural
orders were established. Public hearings on SPPC's plan were held in late
October, and on November 1 the PUCN issued an order approving and adopting
SPPC's plan.
Natural Gas Rate Increase (SPPC)
On June 29, 2001, SPPC filed with the PUCN a Purchase Gas Adjustment (PGA)
seeking recovery of $41.4 million in accumulated, unrecovered purchased gas
expenses, and an increase in the going-forward rate to $.71 per therm. Public
hearings were held on October 22 and 23, 2001. On November 5, 2001, the PUCN
granted SPPC's application and approved recovery of the entire $41.4 million
accumulated deferred balance over a three-year period and an increase in the
going-forward rate to $.6648 per therm. Any under-recovery of future energy
costs will be the subject of a future PGA application.
NOTE 10. DERIVATIVES AND HEDGING ACTIVITIES (SPR, NPC, SPPC)
-------------------------------------------------------------
Effective January 1, 2001, SPR, SPPC, and NPC adopted Statement of
Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative
Instruments and Hedging Activities," as amended by SFAS No. 138, both issued by
the Financial Accounting Standards Board. As amended, SFAS No. 133 requires that
an entity recognize all derivatives as either 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.
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
20
and marketing of natural gas. Derivative instruments used to manage energy price
risk include forwards, options, and swaps. These contracts allow the Utilities
to reduce the risks associated with volatile electricity and natural gas
markets.
Derivatives used to manage interest rate risk include interest rate swaps
designed to moderate exposure to interest-rate changes and lower the overall
cost of borrowing. At September 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 September 30, 2001, the fair value of the derivatives resulted in the
recording of $434 million, $323 million and $111 million in risk management
assets and $1.225 billion, $744 million and $474 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 are established to the extent that electricity
and natural gas derivative gains and losses are recoverable or payable through
future rates. Accordingly, at September 30, 2001, $787 million, $422 million
and $365 million in net risk management regulatory assets were recorded in the
Consolidated Balance Sheets of SPR, NPC, and SPPC, respectively. In addition,
for the nine months ended September 30, 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 nine months ended September 30, 2001.
The effects of the adoption of SFAS No. 133 on comprehensive income and the
components thereof at September 30, 2001, are as follows:
Comprehensive Income (in $000's) SPR NPC SPPC
---------- ---------- ----------
Net Income for the nine months ended September 30, 2001 $ 50,965 $ 56,459 /1/ $ 36,572
Cumulative effect upon adoption of change in
accounting principle, January 1, 2001, net of taxes (1,923) 444 212
Change in market value of risk management assets and
liabilities as of September 30, 2001, net of taxes (5,048) 230 109
---------- ---------- ----------
Accumulated Other Comprehensive (Loss) Income (6,971) 674 321
---------- ---------- ----------
Total Comprehensive Income for the
nine months ended September 30, 2001 $ 43,994 $ 57,133 $ 36,893
========== ========== ==========
/1/ Does not include NPC's equity in SPR's losses of $(5,494).
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.
21
NOTE 11. 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 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, although NPC is not obligated to Mohave's other owners to
continue its Mohave operations after 2005. 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 approximately $395 million. As a 14% owner in the Mohave Station, NPC's cost
could be approximately $55 million.
Also, the United States Congress authorized the Environmental Protection
Agency (EPA) to study the potential impact Mohave may have on visibility in the
Grand Canyon area. A final report of the study results was released in March
1999. The study acknowledges that sulfur dioxide emissions from 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, the Nevada Division of Environmental Protection (NDEP) ordered
NPC to submit a plan to eliminate the discharge of Reid Gardner Station
wastewater to groundwater. The NDEP order also required a hydrological
assessment of groundwater impacts in the area. In June 1999, NDEP determined
that wastewater ponds had degraded groundwater quality. In August 1999, NDEP
issued a discharge permit to Reid Gardner Station and an order that requires all
wastewater ponds to be closed or lined with impermeable liners over the next 10
years. This order also required NPC to submit a Site Characterization Plan to
NDEP to ascertain impacts. This plan is under review by NDEP. Remediation
costs are not estimable at this time. New pond construction and lining costs
are estimated at $20 million.
In July 2000, NPC received from the United States 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. It is NEICO's intention to
sell the property.
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.
22
NOTE 12. SUBSEQUENT EVENTS (SPR, NPC)
--------------------------------------
On October 15, 2001, NPC issued an additional $60 million of 6% unsecured
notes due September 15, 2003, with the same terms and use of proceeds as the
initial $150 million issuance described above.
On October 18, 2001, NPC issued $140 million of General and Refunding
Mortgage Notes, Floating Rate, Series B, due October 15, 2003. These notes were
issued under and secured by NPC's General and Refunding Mortgage Indenture dated
as of May 1, 2001, as amended and supplemented. The lien of the General and
Refunding Mortgage is junior to the lien of NPC's Indenture of Mortgage dated as
of October 1, 1953. Interest on these notes is payable quarterly, commencing on
January 15, 2002. The interest rate on these notes is a floating rate for each
interest period, subject to adjustment every three months, equal to the London
Interbank Offering Rate (LIBOR) for three-month U.S. dollar deposits plus a
spread of 1.65%. The notes are not subject to any sinking fund and are non-
callable. The proceeds of the issuance were used to cover increased purchased
power and fuel costs and to reduce commercial paper balances.
On October 24, 2001, SPR filed a universal shelf registration statement with
the SEC to register up to $750 million of various debt and equity securities.
SPR anticipates issuing $300 million of its Premium Income Equity Securities
("PIES"). Each unit of PIES will consist of a stock purchase contract and a
senior note issued by SPR. Each stock purchase contract will obligate the
holder to purchase from SPR, no later than 2005, for a price of $50, a number of
common shares of SPR that will be set forth in the final prospectus for the
offering. The senior notes will be issued under SPR's existing senior unsecured
note indenture.
On November 6, 2001, a dividend of $975,000 ($.4875 per share) was declared
on SPPC's preferred stock. The dividend is payable on December 1, 2001, to
holders of record as of November 16, 2001.
On November 6, 2001, SPR's Board of Directors declared a dividend on common
stock of 20 cents per share, payable December 15, 2001, to shareholders of
record at the close of business on November 21, 2001.
23
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 recently filed and 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 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;
(3) 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;
(4) the extent to which volatile 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;
(5) 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;
(6) the effect that the September 11 terrorist attacks in New York and
Washington, D.C. may have on the tourism and gaming industries in Nevada,
particularly in Las Vegas, as well as on the economy in general;
(7) 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;
(8) 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;
(9) industrial, commercial and residential growth in the service territories
of the Utilities;
(10) the loss of any significant customers;
(11) 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;
(12) changes in environmental regulations, tax or accounting matters or other
laws and regulations to which the Utilities are subject;
(13) future economic conditions, including inflation rates and monetary
policy;
(14) financial market conditions, including changes in availability of capital
or interest rate fluctuations;
24
(15) unusual or unanticipated changes in normal business operations, including
unusual maintenance or repairs; and
(16) employee workforce factors, including changes in collective bargaining
unit agreements, strikes or work stoppages.
Other factors and assumptions not identified above may also have been
involved in deriving these forward-looking statements, and the failure of those
other assumptions to be realized, as well as other factors, may also cause
actual results to differ materially from those projected. SPR, NPC and SPPC
assume no obligation to update forward-looking statements to reflect actual
results, changes in assumptions or changes in other factors affecting forward-
looking statements.
SIERRA PACIFIC RESOURCES
------------------------
During the first nine months of 2001, SPR earned $26.8 million from
continuing operations before preferred stock dividend requirements. For the
three months ended September 30, 2001, SPR earned $81.4 million from continuing
operations before preferred stock dividend requirements. During the first nine
months of 2001, SPR paid $40.4 million in common stock dividends. NPC and SPPC,
SPR's principal subsidiaries, paid common stock dividends of $33 million and $76
million, respectively, to their parent, SPR. SPPC also paid $2.9 million in
dividends to holders of its preferred stock.
As discussed in the results of operations sections that follow, operating
results for the first nine 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 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, and, except as described in "Transition of Rates to
Deferred Energy Accounting" below, discontinue the Global Settlement and the
CEP. 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 the second quarter of 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.
25
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 the 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 September 30, 2001, NPC had a balance of $929 million in its deferred
energy account, reflecting eligible fuel and purchased power costs and allowable
carrying charges incurred since March 1, 2001. At September 30, 2001, SPPC had a
balance of $219 million in its deferred energy accounts, which reflect both
eligible fuel and purchased power costs and allowable carrying charges incurred
since March 1, 2001, totaling $177 million, as well as deferrals in connection
with its natural gas business of $42 million. Future deferred energy charges
will depend greatly on a number of unpredictable factors including weather
conditions, conditions in the wholesale electricity markets in the western
United States, the effect on the wholesale markets and energy prices of price
caps imposed by the FERC and the extent of the Utilities' revenues from sales of
wholesale electricity, which offset their respective deferred energy charges.
Based upon management's continuing monitoring of these factors, it is
anticipated that NPC's deferred energy charges (net of wholesale electric
revenues) should total between $900 million and $1 billion by the time NPC files
its initial application in December 2001 to clear its deferred energy account.
Similarly, it is anticipated that SPPC's deferred energy charges (net of
wholesale electric revenues) for electricity should total between $175 million
and $225 million by the time SPPC files its initial application in February 2002
to clear its deferred energy account. Management cautions, however, that these
expectations are subject to all of the above uncertainties, which make it
impossible at this time to predict with certainty what the Utilities' deferred
energy account balances will be at the time that they file their initial
application to clear their deferred energy accounts.
26
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.
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.
See "Regulatory Matters," later, for a discussion of NPC's general rate
application filed on October 1, 2001.
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.
27
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,
although no customers have filed such applications as of October 31, 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.
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. On November 6, 2001, SPR's Board of Directors declared a dividend on
common stock of 20 cents per share, payable December 15, 2001, to shareholders
of record at the close of business on November 21, 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 August 15, 2001, SPR completed a public offering of 23,575,000 shares of
its common stock, yielding net proceeds of approximately $340 million, all of
which were contributed to NPC as an additional equity investment. NPC used
these proceeds to pay maturing debt and for working capital purposes.
On October 24, 2001, SPR filed a universal shelf registration statement with
the SEC to register up to $750 million of various debt and equity securities.
SPR anticipates issuing $300 million of its Premium Income Equity Securities
("PIES"). Each unit of PIES will consist of a stock purchase contract and a
senior note issued by SPR. Each stock purchase contract will obligate the
holder to purchase from SPR, no later than 2005, for a price of $50, a number of
common shares of SPR that will be set forth in the final prospectus for the
offering. The senior notes will be issued under SPR's existing senior unsecured
note indenture.
On August 15, 2001, SPR established an unsecured credit facility of $25
million that will expire on August 14, 2002. On September 10, 2001 SPR
established an additional credit facility of $25 million that will expire on
November 30, 2001. As of September 30, 2001, SPR had $20 million of outstanding
borrowings under 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 may be used for working capital and
general corporate purposes, including commercial paper backup. SPR and the
Utilities are currently negotiating new credit facilities to take effect after
their current facilities expire on November 30, 2001. It is expected that the
Utilities' new credit facilities will require each Utility, in the event of a
decline in that Utility's senior unsecured debt ratings, to issue general and
refunding mortgage bonds to secure its new facility.
Set forth below is a schedule showing the current maturities of debt during
the remainder of 2001 (in $000's):
28
SPPC NPC
----------- -----------
December 1, 2001 $ 19,616
December 17, 2001 $ 100,000
----------- -----------
$ 19,616 $ 100,000
=========== ===========
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
continue to be significant as a result of the restoration of deferred energy
accounting and the resulting delay in recovering higher fuel and purchased power
costs. To the extent that the energy cost component in current revenues is less
than current expenses for fuel and purchased power, 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.
29
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 Nine Months
Ended September 30, Ended September 30,
---------------------------------------- ----------------------------------------
Change from Change from
2001 2000 Prior Year % 2001 2000 Prior Year %
------------- ------------- ------------ ------------- ------------- ------------
Electric Operating Revenues ($000):
Residential $ 253,631 $ 184,290 37.6% $ 529,330 $ 393,402 34.6%
Commercial 94,262 68,680 37.2% 233,391 174,387 33.8%
Industrial 159,041 120,227 32.3% 349,866 252,675 38.5%
------------- ------------- ------------- -------------
Retail revenues 506,934 373,197 35.8% 1,112,587 820,464 35.6%
Other 888,562 174,198 410.1% 1,450,362 202,351 616.8%
------------- ------------- ------------- -------------
Total Revenues $ 1,395,496 $ 547,395 154.9% $ 2,562,949 $ 1,022,815 150.6%
============= ============= ============= =============
Retail sales in thousands
of megawatt-hours (MWH) 5,540 5,385 2.9% 13,296 12,846 3.5%
Average retail revenue per MWH $ 91.50 $ 69.30 32.0% $ 83.68 $ 63.87 31.0%
Residential electric revenues increased for the three and nine months ended
September 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 nine month periods ended September 30, 2001, the number of residential
customers increased by 4.7% and 4.9%, respectively, over the same periods in
2000.
Commercial and industrial electric revenues also increased for the three and
nine months ended September 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 businesses 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 nine month periods ended September 30, 2001, the number of
commercial customers increased by 4.4% over the same periods of 2000. For the
three and nine month periods ended September 30, 2001, the number of industrial
customers increased by 5.6% and 7.2%, respectively, over the same periods in
2000.
The large increases in other electric revenues for the three and nine-month
periods ended September 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 purchases and sales have taken place in prior years.
Three Months Nine Months
Ended September 30, Ended September 30,
---------------------------------------- ----------------------------------------
Change from Change from
2001 2000 Prior Year % 2001 2000 Prior Year %
------------- ------------- ------------ ------------- ------------- ------------
Purchased Power ($000) $ 1,686,816 $ 385,129 338.0% $ 2,728,176 $ 593,479 359.7%
Purchased Power in thousands
of MWHs 8,330 4,711 76.8% 16,015 8,426 90.1%
Average cost per MWH of
Purchased Power $ 202.50 $ 81.75 147.7% $ 170.35 $ 70.43 141.9%
30
Purchased power costs were significantly higher for both the three and nine
months ended September 30, 2001, than for the same periods of the prior year, as
Short-Term Firm energy prices and volumes purchased increased substantially.
Purchases associated with the risk management activities and wholesale power
sales discussed above are included in the purchased power amounts. Also, 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.
Three Months Nine Months
Ended September 30, Ended September 30,
---------------------------------------- ----------------------------------------
Change from Change from
2001 2000 Prior Year % 2001 2000 Prior Year %
------------- ------------- ------------ ------------- ------------- ------------
Fuel for Power Generation ($000) $ 131,023 $ 86,140 52.1% $ 348,633 $ 178,809 95.0%
Thousands of MWHs generated 2,436 3,052 -20.2% 7,510 7,769 -3.3%
Average cost per MWH of
Generated Power $ 53.79 $ 28.22 90.6% $ 46.42 $ 23.02 101.7%
Fuel for generation costs for both the three and nine months ended September
30, 2001, were significantly higher than the prior year due to substantial
increases in natural gas prices. The price increases substantially offset a
reduction in volumes generated, as more of system load was accommodated through
purchased power.
Three Months Nine Months
Ended September 30, Ended September 30,
---------------------------------------- ----------------------------------------
Change from Change from
2001 2000 Prior Year % 2001 2000 Prior Year %
------------- ------------- ------------ ------------- ------------- ------------
Deferral of energy costs-net ($000) $ (638,571) $ 2,445 -26217.4% $ (908,408) $ 16,719 -5533.4%
Deferral of energy costs-net decreased significantly for both the three and
nine months ended September 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 nine-month periods ended
September 30, 2000, as a result of deferred energy rate increases granted in
1999.
Three Months Nine Months
Ended September 30, Ended September 30,
---------------------------------------- ----------------------------------------
Change from Change from
2001 2000 Prior Year % 2001 2000 Prior Year %
------------- ------------- ------------ ------------- ------------- ------------
Allowance for other funds
used during construction ($000) $ (87) $ 430 -120.2% $ (560) $ 2,272 -124.6%
Allowance for borrowed funds
used during construction ($000) 657 2,373 -72.3% 570 6,130 -90.7%
------------- ------------- ------------- -------------
$ 570 $ 2,803 -79.7% $ 10 $ 8,402 -99.9%
============= ============= ============= =============
31
The totals of allowance for funds used during construction (AFUDC) for both
the three and nine months ended September 30, 2001, reflect adjustments to
refine amounts assigned to specific components of facilities that were completed
in different periods.
Three Months Nine Months
Ended September 30, Ended September 30,
---------------------------------------- ----------------------------------------
Change from Change from
($000) 2001 2000 Prior Year % 2001 2000 Prior Year %
------------- ------------- ------------ ------------- ------------- ------------
Other operating expense $ 45,670 $ 33,638 35.8% $ 130,192 $ 97,923 33.0%
Maintenance expense 10,331 8,126 27.1% 36,789 27,210 35.2%
Depreciation and amortization 23,042 21,391 7.7% 67,345 64,121 5.0%
Income taxes 36,197 (5,642) N/A 21,979 (12,461) N/A
Interest charges on long-term debt 20,545 15,980 28.6% 55,504 46,132 20.3%
Interest charges-other 3,269 2,745 19.1% 10,982 10,677 2.9%
Other income (expense) - net 11,021 1,307 743.2% 14,189 2,014 604.5%
Other operating expense for the three-month period ending September 30,
2001, increased compared with the prior year, primarily due to an increase in
the provision for uncollectible accounts of approximately $10 million, as well
as increased costs related to corporate insurance, the mill tax, and operating
costs associated with the Clark Station. Other operating expense for the nine-
month period ending September 30, 2001, increased compared to the same period in
2000 primarily due to a $12.6 million increase in the provision for
uncollectible accounts related to the California Power Exchange ("PX"), the $10
million increase in the provision for uncollectible accounts in the third
quarter of 2001, and a $3 million reserve provision established as a result of
the conclusion of electric industry restructuring in Nevada.
Maintenance costs for the three- and nine-month periods ending September 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
nine-month periods ended September 30, 2001, compared to the same periods in
2000, reflect an increase in plant-in-service over the prior year.
For the three- and nine-month periods ending September 30, 2001, income tax
expense is reflected compared to income tax benefits in the same periods of
2000, as NPC recorded pre-tax income for the current year periods compared with
a pre-tax losses for the year-earlier periods.
Interest charges on long-term debt increased for the three-month period
ending September 30, 2001, compared with the prior year due to the issuance of
$250 million of long-term debt in excess of retirements during the period May
2001 through September 2001. The increase for the nine months ending September
30, 2001, compared to the same period in 2000 as a result of the issuance of a
total of $250 million in floating rate notes in June and August of 2000, and the
net increase in long-term debt for the May 2001 through September 2001 period.
The increase in Interest charges-other for the three-month period ending
September 30, 2001, compared to the same period of 2000 results from greater
reliance on commercial paper in the third quarter of 2001 than 2000.
The increase in Other income (expense) - net for the three- and nine-month
periods ending September 30, 2001, compared to the same periods of 2000 is due
primarily to the recognition in the current year of carrying charges on deferred
fuel and purchased power balances pursuant to AB369.
Financial Condition, Liquidity and Capital Resources
During the first nine months of 2001, NPC earned approximately $56.4 million
(excluding NPC's equity in the losses of its parent, SPR), and paid $33 million
in dividends on its common stock, all of which is held by SPR. For the three
months ended September 30, 2001, NPC earned approximately $78.8 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.
During the nine months ended September 30, 2001, net cash flows decreased by
$25.6 million compared to a small increase in net cash flows in the same period
in 2000. A large increase in cash flows used in operating activities was
offset, in
32
part, by an increase in cash provided by financing activities. The increase in
cash flows used in operating activities resulted from a large deferral of
electric energy costs pursuant to AB369 and an increase in accounts receivable,
due in part to increased risk management activities. These uses of cash flows
were partially offset by an increase in accounts payable. Cash flows from
financing activities increased significantly in 2001 compared to 2000 due to an
increase in funding from NPC's parent, SPR, a current year increase in short-
term borrowings compared to a decrease in 2000, and a greater net increase in
long-term debt in 2001, as discussed in Note 4 to the Financial Statements,
compared to 2000.
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), $139.8
million (79.9%) was spent as of September 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 for the remainder of 2001.
33
SIERRA PACIFIC POWER COMPANY
----------------------------
The components of gross margin (net of deferral of energy costs) are set
forth below (dollars in thousands):
Three Months Nine Months
Ended September 30, Ended September 30,
---------------------------------------- ----------------------------------------
Change from Change from
2001 2000 Prior Year % 2001 2000 Prior Year %
------------- ------------- ------------ ------------- ------------- ------------
Operating Revenues:
Electric $ 551,923 $ 305,334 80.8% $ 1,184,264 $ 639,776 85.1%
Gas 18,831 12,787 47.3% 104,725 63,378 65.2%
------------- ------------- ------------- -------------
Total Revenues 570,754 318,121 79.4% 1,288,989 703,154 83.3%
------------- ------------- ------------- -------------
Energy Costs:
Electric 468,479 262,292 78.6% 981,933 457,079 114.8%
Gas 12,387 6,809 81.9% 81,654 40,410 102.1%
------------- ------------- ------------- -------------
Total Energy Costs 480,866 269,101 78.7% 1,063,587 497,489 113.8%
------------- ------------- ------------- -------------
Gross Margin $ 89,888 $ 49,020 83.4% $ 225,402 $ 205,665 9.6%
============= ============= ============= =============
Gross Margin by Segment:
Electric $ 83,444 $ 43,042 93.9% $ 202,331 $ 182,697 10.7%
Gas 6,444 5,978 7.8% 23,071 22,968 0.4%
------------- ------------- ------------- -------------
Total $ 89,888 $ 49,020 83.4% $ 225,402 $ 205,665 9.6%
============= ============= ============= =============
The causes for significant changes in specific lines comprising the results of
operations for SPPC are discussed below:
Three Months Nine Months
Ended September 30, Ended September 30,
---------------------------------------- ----------------------------------------
Change from Change from
2001 2000 Prior Year % 2001 2000 Prior Year %
------------- ------------- ------------ ------------- ------------- ------------
Electric Operating Revenues ($000):
Residential $ 58,670 $ 45,114 30.0% $ 157,144 $ 131,304 19.7%
Commercial 71,387 54,327 31.4% 182,681 147,753 23.6%
Industrial 67,590 49,670 36.1% 187,498 143,684 30.5%
------------- ------------- ------------- -------------
Retail revenues 197,647 149,111 32.6% 527,323 422,741 24.7%
Other 354,276 156,223 126.8% 656,941 217,035 202.7%
------------- ------------- ------------- -------------
Total Revenues $ 551,923 $ 305,334 80.8% $ 1,184,264 $ 639,776 85.1%
============= ============= ============= =============
Retail sales in thousands of
megawatt-hours (MWH) 2,309 2,336 -1.2% 6,538 6,584 -0.7%
Average retail revenue per MWH $ 85.60 $ 63.83 34.1% $ 80.66 $ 64.21 25.6%
Retail electric revenues increased for both the three and nine-month periods
ended September 30, 2001, over the same periods in 2000 due to increases in
rates and customer growth. 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 residential customers
increased due to increases in both heating degree-days and cooling degree-days.
The large increases in other electric revenues for the three and nine-month
periods ended September 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 delivery point where
the energy can either be delivered to its control area or sold, should SPPC not
require the energy. The
34
energy is also sold if replacement energy can be obtained less expensively than
transporting the energy to the control area. Fewer of these purchases and sales
have taken place in prior years.
Three Months Nine Months
Ended September 30, Ended September 30,
---------------------------------------- ----------------------------------------
Change from Change from
2001 2000 Prior Year % 2001 2000 Prior Year %
------------- ------------- ------------ ------------- ------------- ------------
Gas Operating Revenues ($000):
Residential $ 7,861 $ 4,316 82.1% $ 39,615 $ 27,254 45.4%
Commercial 4,267 2,382 79.1% 20,331 14,098 44.2%
Industrial 6,333 1,852 242.0% 12,962 7,309 77.3%
Miscellaneous (542) 216 -350.9% 86 1,224 -93.0%
------------- ------------- ------------- -------------
Total retail revenue 17,919 8,766 104.4% 72,994 49,885 46.3%
Wholesale revenue 912 4,021 -77.3% 31,731 13,493 135.2%
------------- ------------- ------------- -------------
Total Revenues $ 18,831 $ 12,787 47.3% $ 104,725 $ 63,378 65.2%
============= ============= ============= =============
Retail sales in thousands
of decatherms 1,336 1,348 -0.9% 8,819 8,414 4.8%
Average retail revenues per
decatherms $ 13.41 $ 6.50 106.3% $ 8.28 $ 5.93 39.6%
The three months ended September 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 nine months
ended September 30, 2001, and decreased for the third quarter, compared to 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 Nine Months
Ended September 30, Ended September 30,
---------------------------------------- ----------------------------------------
Change from Change from
2001 2000 Prior Year % 2001 2000 Prior Year %
------------- ------------- ------------ ------------- ------------- ------------
Purchased Power ($000): $ 508,235 $ 196,865 158.2% $ 907,830 $ 318,294 185.2%
Purchased Power in thousands
of MWHs 2,688 2,511 7.0% 5,838 5,810 0.5%
Average cost per MWH of
Purchased Power $ 189.08 $ 78.40 141.2% $ 155.50 $ 54.78 183.8%
Purchased power costs were higher for both the three- and nine-month periods
ended September 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. Purchases associated with the risk management activities
and wholesale power sales discussed above are included in the purchased power
amounts.
35
Three Months Nine Months
Ended September 30, Ended September 30,
---------------------------------------- ----------------------------------------
Change from Change from
2001 2000 Prior Year % 2001 2000 Prior Year %
------------- ------------- ------------ ------------- ------------- ------------
Fuel for Power Generation ($000) $ 58,946 $ 65,427 -9.9% $ 246,540 $ 138,785 77.6%
Thousands of MWHs generated 1,593 1,612 -1.2% 4,668 4,155 12.3%
Average fuel cost per MWH
of Generated Power $ 37.00 $ 40.59 -8.8% $ 52.81 $ 33.40 58.1%
For the three months ended September 30, 2001, Fuel for Power Generation
costs were lower than the same period of 2000 due to the substitution of less
expensive fuel oil for natural gas. Fuel for generation costs for the nine-
month period ended September 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 Nine Months
Ended September 30, Ended September 30,
---------------------------------------- ----------------------------------------
Change from Change from
2001 2000 Prior Year % 2001 2000 Prior Year %
------------- ------------- ------------ ------------- ------------- ------------
Gas Purchased for Resale ($000)
Retail $ 6,879 $ 2,740 151.1% $ 76,722 $ 27,638 177.6%
Wholesale 2,415 4,249 -43.2% 28,286 13,672 106.9%
------------- ------------- ------------- -------------
Total $ 9,294 $ 6,989 33.0% $ 105,008 $ 41,310 154.2%
============= ============= ============= =============
Gas Purchased for Resale - retail
(thousands of decatherms) 1,411 1,391 1.4% 9,441 7,976 18.4%
Average cost per retail decatherm $ 4.88 $ 1.97 147.5% $ 8.13 $ 3.47 134.5%
The cost of retail gas purchased for resale increased for the three and
nine-month periods ended September 30, 2001, compared to the prior year due to
substantially higher gas prices. The increase in the cost of wholesale gas
purchased for the nine months ended September 30, 2001, over the prior year
reflects higher prices as well as costs associated with risk management
activities. The decrease in the cost of wholesale gas purchased for the three
months ended September 30, 2001, compared to the prior year reflects a reduction
in costs associated with risk management activities.
Three Months Nine Months
Ended September 30, Ended September 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 (98,702) - N/A (172,437) - N/A
Gas Purchased for Resale 3,093 (180) N/A (23,354) (900) 2494.9%
------------- ------------- ------------- -------------
Total $ (95,609) $ (180) 53016.1% $ (195,791) $ (900) 21654.6%
============= ============= ============= =============
For both the three and nine months ended September 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.
36
Deferral of energy costs-net for gas purchased for resale increased
substantially for the nine months ended September 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. The undercollections of gas purchased
for resale that SPPC continued to experience in the three-month period ended
September 30, 2001, was more than offset by a third quarter true-up of year-to-
date energy revenues for natural gas.
Three Months Nine Months
Ended September 30, Ended September 30,
---------------------------------------- ----------------------------------------
Change from Change from
2001 2000 Prior Year % 2001 2000 Prior Year %
------------- ------------- ------------ ------------- ------------- ------------
Allowance for other funds used
during construction ($000) $ (19) $ 81 -123.5% $ (233) $ 215 -208.4%
Allowance for borrowed funds used
during construction ($000) 566 680 -16.8% 943 1,649 -42.8%
------------- ------------- ------------- -------------
$ 547 $ 761 -28.1% $ 710 $ 1,864 -61.9%
============= ============= ============= =============
The totals of allowance for funds used during construction (AFUDC) for both
the three and nine months ended September 30, 2001, reflect adjustments to
refine amounts assigned to specific components of facilities that were completed
in different periods.
Three Months Nine Months
Ended September 30, Ended September 30,
---------------------------------------- ----------------------------------------
Change from Change from
(In 000's) 2001 2000 Prior Year % 2001 2000 Prior Year %
------------- ------------- ------------ ------------- ------------- ------------
Other operating expense $ 28,222 $ 18,608 51.7% $ 79,090 $ 68,328 15.8%
Maintenance expense 5,143 4,162 23.6% 17,143 12,984 32.0%
Income taxes 8,630 (3,504) N/A 7,974 9,274 -14.0%
Interest charges on long-term debt 15,380 10,953 40.4% 38,479 26,861 43.3%
Interest charges - other 1,455 1,348 7.9% 7,437 8,519 -12.7%
Other income (expense) - net 4,309 117 3582.9% 5,322 (1,122) N/A
Other operating expense for the three-month period ending September 30,
2001, increased compared with the prior year, primarily due to an increase in
the provision for uncollectible accounts of approximately $4 million, as well as
increased costs related to corporate insurance and the start-up of the gasifier
at Tracy. Other operating expense for the nine-month period ending September
30, 2001, increased compared to the same period in 2000 primarily due to a $3.5
million reserve provision established as a result of the conclusion of electric
industry restructuring in Nevada, the $4 million increase in the provision for
uncollectible accounts in the third quarter of 2001, and a $1.2 million increase
in the provision for uncollectible accounts related to the California PX.
Maintenance costs for the three- and nine-month periods ended September 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 as well as unplanned maintenance on diesel generators.
For the three months ended September 30, 2001, income tax expense is
reflected compared to an income tax benefit in the same period of 2000, as SPPC
recorded pre-tax income from continuing operations for the current year period
compared with a pre-tax loss from continuing operations for the year-earlier
period. Income taxes were lower for the nine-month period ending September 30,
2001, compared to the prior year reflecting a decrease in pre-tax income from
continuing operations.
37
Interest charges on long-term debt increased for the three- and nine-month
periods ending September 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.
The decrease in Interest charges-other for the nine-month period ending
September 30, 2001, compared to the same periods of 2000 is due to reduced
reliance on commercial paper in 2001 as compared to 2000.
The increase in Other income (expense) - net for the three months ended
September 30, 2001, and the change from net expense to net income for the nine-
month period ending September 30, 2001, compared to the same periods of 2000 are
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 nine months of 2001, SPPC earned approximately $12.4
million from continuing operations before preferred stock dividends. For the
three months ended September 30, 2001, SPPC earned approximately $12.6 million
before preferred stock dividends. During the first nine months of 2001, SPPC
paid $2.9 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 nine months ended September 30, 2001, were
comparable to the same period in 2000. An increase in net cash flows from
investing activities substantially offset 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. Operating activities in 2001 used $178 million of cash and cash
equivalents, compared to a provision of $74 million in 2000. This resulted from
a large deferral of electric energy costs pursuant toAB369 and larger deferrals
of resale natural gas costs, as well as an increase in accounts receivable, due
in part to increased risk management activities. These uses of cash flows were
partially offset by increases in accounts payable and deferred taxes. The
decrease in cash flows from financing activities was mainly due to reduced
reliance on commercial paper in 2001 compared to 2000.
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),
$89.9 million (71.9%) was spent as of September 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 for the remainder of 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, $40.3 million in 2001 and $27.1 million in
2000, due to the issuance of a total of $600 million in debt in April and May of
2000, and increased reliance on short-term borrowings in 2001.
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 nine-month periods ended September
30, 2001, TGPC contributed $.6 million and $1.9 million, respectively, in net
income. For the three-and nine-month periods ended September 30, 2000, TGPC
contributed $.5 million and $1.6 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-and nine-month periods ended September 30, 2001, e.three contributed
$334,000 and $202,000, respectively, in net income. For the three months ended
September 30, 2000, e.three incurred a net loss of $56,000; e.three contributed
$235,000 in net income for the nine months ended September 30, 2000.
38
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 nine-month periods ended September
30, 2001, SPE incurred net losses of $89,000 and $247,000, respectively. SPE
incurred net losses of $.5 million and $4.3 million, respectively, for the
three- and nine-month periods ended September 30, 2000. The losses are the
result of costs incurred to exit the retail energy-sales business.
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 nine-month periods ended September
30, 2001, SPC incurred net losses of $1.7 million and $2.4 million,
respectively. SPC incurred net losses of $305,000 and $380,000, respectively,
for the three- and nine-month periods ended September 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 nine months ended September 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 September 30, 2001, NPC and SPPC had
incurred costs of approximately $11 million and $14.9 million, respectively, in
order to prepare for the sale of generation assets. NPC has requested recovery
of these costs, and SPPC plans to do so.
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 is being credited on the electric bills of SPPC's former water
customers over a period not to exceed fifteen months from June 11, 2001. 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 contract of 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 were certain properties 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.
39
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
spot market 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. Although the
Utilities are not able to predict at this time the long-term effect that the
FERC price mitigation plan may have on their results of operations, management
believes that, under certain market conditions, the FERC plan adversely affects
the availability of spot market power to the Utilities and reduces the price at
which the Utilities can sell power on the wholesale market. SPR 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 the utility groups that are forming 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
--------------
Nevada Power General Rate Case (NPC)
On October 1, 2001, NPC filed an application with the PUCN seeking an
electric general rate increase. This application was mandated by AB 369, which
was enacted by the Nevada Legislature in April 2001. In the application, NPC
requested an increase in its general rates charged to all classes of electric
customers designed to produce an increase in annual electric revenues of $42.7
million. If the increase is granted, an average residential electric bill will
increase by approximately 8%. The application also seeks a return on common
equity ("ROE") for Nevada Power's total electric operations of 12.25% (a
reduction from NPC's last-authorized ROE for bundled electric operations of
12.50%) and an overall rate of return ("ROR") of 9.26% (a reduction from NPC's
last-authorized ROR for bundled electric operations of 10.02%). On December 1,
2001, NPC will file a deferred energy application, seeking recovery of deferred
energy balances. Final decisions on both the general rate application and
deferred energy application should occur no later than April 1, 2002, and any
rate increase approved by the PUCN would take effect after that date.
Resource Plans (SPPC, NPC)
On July 2, 2001, SPPC filed its electric resource plan for the period of
2001-2020. On July 9, 2001, NPC filed its amended electric resource plan for
the period of 2000-2019. The plans include scenarios to meet the electric needs
of customers while sustaining reliable electric systems. The integrated
resource plans evaluate resources to be used to meet forecasted loads. Resource
options considered include new transmission lines to access energy markets,
construction of generation facilities, power purchases from independent power
producers under short- and long-term agreements, and conservation programs. On
October 18, 2001, the PUCN approved NPC's amended resource plan. On August 2,
2001, a pre-hearing conference was held on SPPC's resource plan and procedural
orders were established. Public hearings on SPPC's plan were held in late
October, and on November 1 the PUCN issued an order approving and adopting
SPPC's plan.
40
PUCN Rulemaking for Assembly Bill 661 (SPPC, NPC)
The PUCN opened an investigatory and rulemaking docket to implement the
provisions of AB661. Beginning on October 16, 2001, the PUCN has scheduled a
workshop to receive comments regarding proposed regulations. These regulations
concern eligible customers purchasing new electric resources from suppliers
other than SPPC or NPC. A public hearing regarding the regulation was held on
October 30, 2001, and PUCN is approval is expected in November.
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. On August 3, 2001, the PUCN approved the revisions.
Finance Authority (NPC, SPPC)
On September 20, 2001, the PUCN approved the June 19, 2001, applications by
NPC and SPPC for authority to issue long or short-term debt on either a secured
or unsecured basis in an aggregate amount not to exceed $200 million for NPC and
$100 million for SPPC through the end of 2002. On September 20, 2001, the PUCN
also approved the Utilities' 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 applications, the Utilities 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.
On October 1, 2001, NPC and SPPC each filed an application with the PUCN
requesting authority to issue secured or unsecured promissory notes in aggregate
amounts not to exceed $250 million through the end of 2004.
Natural Gas Rate Increase (SPPC)
On June 29, 2001, SPPC filed with the PUCN a Purchase Gas Adjustment (PGA)
seeking recovery of $41.4 million in accumulated, unrecovered purchased gas
expenses, and an increase in the going-forward rate to $.71 per therm. Public
hearings were held on October 22 and 23, 2001. On November 5, 2001, the PUCN
granted SPPC's application and approved recovery of the entire $41.4 million
accumulated deferred balance over a three-year period and an increase in the
going-forward rate to $.6648 per therm. Any under-recovery of future energy
costs will be the subject of a future PGA application.
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. On August 14, 2001, a pre-hearing
conference was held, and a procedural order was established. On September 27,
the Administrative Law Judge issued an order stating that no interim or
emergency relief could be granted until the end of the "rate freeze" period
mandated by the California restructuring law for recovery of stranded costs. In
accordance with the judge's request, on October 26 SPPC filed an amendment to
its application declaring the rate freeze period to be over. Public hearings
have been scheduled for late November with a proposed draft decision expected by
January 31, 2002. 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 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.
41
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.
The Utilities also monitor and manage credit risk with their trading
counterparties. As of September 30, 2001, the Utilities have outstanding
transactions with over 30 energy and financial services companies. Due to
changes in the energy market, the credit risk associated with these transactions
has decreased from $1.6 billion at December 31, 2000, to approximately $3
million as of September 30, 2001.
42
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
None
ITEM 5. OTHER INFORMATION
None
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits filed with this Form 10-Q:
Nevada Power Company
Exhibit 4.1 - Fiscal and Paying Agency Agreement, dated as of September
19, 2001, between Nevada Power Company and Bankers Trust
Company, relating to the issuance and sale of Nevada Power
Company's 6% Notes due 2003
Exhibit 4.2 - Form of Global Note due September 15, 2003, in connection
with the issuance and sale of Nevada Power Company's 6%
Notes due 2003
Sierra Pacific Resources
Exhibit 10.1 - 364-Day Credit Agreement, dated as of August 15, 2001,
between Sierra Pacific Resources and The Bank of New York,
relating to $25,000,000 credit facility
Exhibit 10.2 - Credit Agreement, dated as of September 10, 2001, between
Sierra Pacific Resources and Wells Fargo Bank, National
Association, relating to $25,000,000 credit facility
Nevada Power Company
Exhibit 10.3 - Amendment Agreement, dated as of August 1, 2001, among
Nevada Power Company, Mellon Bank, N.A., First Union
National Bank, Wells Fargo Bank, N.A., and the other parties
thereto, relating to $120,000,000 credit facility
Exhibit 10.4 - Credit Agreement, dated as of August 1, 2001, among Nevada
Power Company, Mellon Bank, N.A., as Administrative Agent,
BNP Paribas, First Union National Bank and Wells Fargo Bank,
N.A., as Syndication Agents, and the Lenders party thereto,
relating to $130,000,000 credit facility
43
Sierra Pacific Power Company
Exhibit 10.5 - Amendment Agreement, dated as of August 1, 2001, among
Sierra Pacific Power Company, Mellon Bank, N.A., First
Union National Bank, Wells Fargo Bank, N.A., and the other
parties thereto, relating to $120,000,000 credit facility
Exhibit 10.6 - Credit Agreement, dated as of August 1, 2001, among Sierra
Pacific Power Company, Mellon Bank, N.A., as Administrative
Agent, BNP Paribas, First Union National Bank and Wells
Fargo Bank, N.A., as Syndication Agents, and the Lenders
party thereto, relating to $130,000,000 credit facility
(b) Reports on Form 8-K:
Form 8-K filed on August 3, 2001, by SPR, NPC, and SPPC - Item 5, Other Events
Disclosed, and included as an exhibit, SPR's press release dated August 3,
2001, announcing SPR's earnings for the second quarter of 2001.
Form 8-K filed on September 19, 2001, by SPR and NPC - Item 5, Other Events
Updated disclosures regarding NPC's deferred energy balances through July
31, 2001, and Management's expectations regarding such deferred energy balances
for the remainder of 2001.
44
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrants have duly caused this report to be signed on their behalf by the
undersigned thereunto duly authorized.
Sierra Pacific Resources
------------------------
(Registrant)
Date: November 7, 2001 By: /s/ Dennis D. Schiffel
---------------- ----------------------------
Dennis D. Schiffel
Senior Vice President
Chief Financial Officer
(Principal Financial Officer)
Date: November 7, 2001 By: /s/ John E. Brown
---------------- ----------------------------
John E. Brown
Controller
(Principal Accounting Officer)
Nevada Power Company
--------------------
(Registrant)
Date: November 7, 2001 By: /s/ Dennis D. Schiffel
---------------- ----------------------------
Dennis D. Schiffel
Senior Vice President
Chief Financial Officer
(Principal Financial Officer)
Date: November 7, 2001 By: /s/ John E. Brown
---------------- ----------------------------
John E. Brown
Controller
(Principal Accounting Officer)
Sierra Pacific Power Company
----------------------------
(Registrant)
Date: November 7, 2001 By: /s/ Dennis D. Schiffel
---------------- ----------------------------
Dennis D. Schiffel
Senior Vice President
Chief Financial Officer
(Principal Financial Officer)
Date: November 7, 2001 By: /s/ John E. Brown
---------------- ----------------------------
John E. Brown
Controller
(Principal Accounting Officer)
45