<PAGE>
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K/A
CURRENT REPORT
PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Date of Report (Date of Earliest Event Reported) September 15, 1999
------------------
SIERRA PACIFIC RESOURCES
------------------------
(Exact name of registrant as specified in its charter)
NEVADA 1-8788 88-0198358
- ----------------------------------- ----------- -------------------
(State or other jurisdiction of (Commission (I.R.S. Employer
incorporation or organization) File Number) Identification No.)
P.O. Box 30150 (6100 Neil Road), Reno, Nevada 89511
- --------------------------------------------- ------------------
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (775) 834-4011
---------------
None
- --------------------------------------------------------------------------------
(Former name, former address and former fiscal year, if changed since last
report)
1
<PAGE>
The undersigned registrant hereby amends the following items of its Current
Report on Form 8-K, dated July 28, 1999:
Item 7. FINANCIAL STATEMENTS AND EXHIBITS, (a) and (b) are amended by their
- -----------------------------------------
inclusion. Both items were excluded from the original filing by extension of
time allowance.
(a) Financial Statements of Businesses Acquired.
-------------------------------------------
The consolidated balance sheets of Nevada Power Company as of December 31, 1998
and 1997 (as set forth in the Nevada Power Company annual report on Form 10-K
for the fiscal year ended December 31, 1998, a copy of which is attached as
exhibit 99.2 hereto).
The consolidated statements of income and cash flows of Nevada Power Company for
each of the three years in the period ended December 31, 1998, (as set forth in
the Nevada Power Company annual report on Form 10-K for the fiscal year ended
December 31, 1998, a copy of which is attached as exhibit 99.2 hereto).
The condensed consolidated balance sheets of Nevada Power Company as of June 30,
1999 and December 31, 1998 (as set forth in the Nevada Power Company quarterly
report on Form 10-Q for the period ended June 30, 1999, a copy of which is
attached as exhibit 99.3 hereto).
The condensed consolidated statements of income and cash flows of Nevada Power
Company for the three and six month periods (six months only for cash flows)
ended June 30, 1999, 1998 ( as set forth in the Nevada Power Company quarterly
report on Form 10-Q for the period ended June 30, 1999, a copy of which is
attached as exhibit 99.3 hereto).
The consolidated balance sheets of Sierra Pacific Resources as of December 31,
1998 and 1997 (as set forth in the Sierra Pacific Resources annual report on
Form 10-K for the fiscal year ended December 31, 1998, a copy of which is
attached as exhibit 99.4 hereto).
The consolidated statements of income and cash flows of Sierra Pacific Resources
for each of the three years in the period ended December 31, 1998, (as set forth
in the Sierra Pacific Resources annual report on Form 10-K for the fiscal year
ended December 31, 1998, a copy of which is attached as exhibit 99.4 hereto).
The condensed consolidated balance sheets of Sierra Pacific Resources as of June
30, 1999 and December 31, 1998 (as set forth in the Sierra Pacific Resources
quarterly report on Form 10-Q for the period ended June 30, 1999, a copy of
which is attached as exhibit 99.5 hereto).
The condensed consolidated statements of income and cash flows of Sierra Pacific
Resources for the three and six month periods (six months only for cash flows)
ended June 30, 1999, 1998 ( as set forth in the Sierra Pacific Resources
quarterly report on Form 10-Q for the period ended June 30, 1999, a copy of
which is attached as exhibit 99.5 hereto).
The aforementioned annual reports on Form 10-K and quarterly reports on Form 10-
Q are hereby incorporated by reference.
(b) Pro Forma Financial Information
-------------------------------
The following unaudited pro forma financial information is included in this
report on Form 8-K/A:
Sierra Pacific Resources Pro Forma Combined Condensed Balance Sheet at June 30,
1999.
Sierra Pacific Resources Pro Forma Combined Condensed Statement of Income for
the six months ended June 30, 1999.
Sierra Pacific Resources Pro Forma Combined Condensed Statement of Income for
the twelve months ended December 31, 1998.
Notes to unaudited Pro Forma Combined Condensed Financial Statements.
2
<PAGE>
Unaudited Pro Forma Combined Condensed Financial Statements
- -----------------------------------------------------------
The following unaudited pro forma combined condensed financial statements
combine the historical balance sheets and statements of income of Nevada Power
Company (Nevada Power) and Sierra Pacific Resources (Sierra Pacific) for the
merger discussed in Item 2 under the purchase method of accounting and the
assumptions set forth in the notes thereto. The unaudited pro forma combined
condensed balance sheet as of June 30, 1999, is presented as if the Mergers had
occurred at the balance sheet date. The unaudited pro forma combined condensed
statements of income for the year ended December 31, 1998 and the six-months
ended June 30, 1999, assume that the Mergers occurred at the beginning of the
periods presented.
The unaudited pro forma combined condensed financial statements do not give
effect to any cost savings or other synergies anticipated as a result of the
merger. Estimated costs to achieve the merger are presented as regulatory
assets on the pro forma combined balance sheet of the merged company. The order
approving the merger by the Public Utilities Commission of Nevada (PUCN)
directed the companies to defer merger costs (including goodwill) for a three
year period. The deferral of these costs is intended to allow adequate time for
the anticipated savings from the merger to develop. At the end of the three
year period, the order instructs the merged company to propose an amortization
period for the merger costs and allows the company to recover the costs to the
extent they are offset by merger savings. See adjustments 5, 12, 13 for the
deferred merger costs.
The unaudited pro forma combined condensed financial statements have been
prepared from, and should be read in conjunction with, the historical financial
statements and related notes thereto of Nevada Power and Sierra Pacific. The
unaudited pro forma combined condensed financial statements are not necessarily
indicative of the financial position or operating results that would have
occurred had the mergers been consummated on the dates as of which, or at the
beginning of the periods for which, the Mergers are being given pro forma effect
nor is it necessarily indicative of future operating results or financial
position. In addition, due to the effect of seasonal fluctuations and other
factors on the operations of Nevada Power and Sierra Pacific, financial results
for the six-months ended June 30, 1999 are not necessarily indicative of results
for the year ending December 31, 1999.
3
<PAGE>
PRO FORMA COMBINED CONDENSED BALANCE SHEET
AT JUNE 30, 1999
(Dollars in Thousands)
(preliminary and unaudited)
<TABLE>
<CAPTION>
NEVADA SIERRA
POWER (9) PACIFIC (9) ADJUSTMENTS PROFORMA
-------------- ------------ -------------- -------------
<S> <C> <C> <C> <C>
ASSETS:
UTILITY PLANT:
Plant in service $ 2,784,359 $ 2,374,322 $ 5,158,681
Less: accumulated provision for depreciation 748,814 762,799 1,511,613
------------- ------------ -------------- --------------
2,035,545 1,611,523 - 3,647,068
Construction work-in-progress 170,864 75,141 246,005
Property under capital leases 63,985 - 63,985
------------- ------------ -------------- --------------
2,270,394 1,686,664 - 3,957,058
------------- ------------ -------------- --------------
Investments and other property, net 26,076 88,525 114,601
------------- ------------ -------------- --------------
CURRENT ASSETS:
Cash and cash equivalents 335 8,295 455,400 (1) 4,319
(151,600) (2)
(304,600) (3)
(3,511) (11)
Customer and other receivables-net of uncollectibles 138,870 103,861 242,731
Materials, supplies and fuel, at average cost 41,883 29,879 71,762
Deferred energy costs 57,897 - 57,897
Prepayments and other 4,347 2,995 7,342
------------- ------------ -------------- --------------
243,332 145,030 (4,311) 384,051
------------- ------------ -------------- --------------
DEFERRED CHARGES:
Regulatory tax asset 62,906 65,531 128,437
Goodwill 338,109 (5) 338,109
Other 46,005 83,170 5,400 (1) 194,911
32,474 (5)
17,775 (12)
(2,834) (12)
12,921 (13)
------------- ------------ -------------- --------------
108,911 148,701 403,845 661,457
------------- ------------ -------------- --------------
Total Assets $ 2,648,713 $ 2,068,920 $ 399,534 $ 5,117,167
============= ============ ============== ==============
</TABLE>
The accompanying notes to the unaudited pro forma combined condensed
balance sheet and statements of income are an integral part of this
statement.
4
<PAGE>
CAPITALIZATION:
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C>
Common stock and additional paid in capital $ 737,199 $ 489,002 (151,600) (2) $ 1,372,285
(304,600) (3)
- (4)
404,212 (5)
198,072 (14)
Retained earnings 117,334 198,166 (94) (11) 117,334
(198,072) (14)
Preferred stock-not subject to mandatory redemption - 73,115 73,115
Preferred securities-subject to mandatory redemption 188,872 48,500 237,372
Long-term debt 1,028,977 630,111 460,800 (1) 2,119,888
-------------- -------------- -------------- -------------
2,072,382 1,438,894 408,718 3,919,994
-------------- -------------- -------------- -------------
CURRENT LIABILITIES:
Short-term borrowings
93,987 123,000 216,987
Current maturities of long-term debt
and sinking fund requirements 53,416 40,597 (200) (11) 90,596
(3,217) (11)
Accounts payable 71,261 32,049 103,310
Accrued taxes 5,268 14,247 (4,974) (15) 14,541
Accrued interest 9,603 7,744 17,347
Deferred taxes on deferred energy costs 20,264 - 20,264
Other current liabilities 41,364 50,741 13,236 (12) 118,262
12,921 (13)
-------------- --------------- --------------- -------------
295,163 268,378 17,766 581,307
-------------- --------------- --------------- -------------
DEFERRED CREDITS:
Investment tax credits 27,353 36,961 64,314
Deferred income taxes 170,519 172,941 4,974 (15) 348,434
Regulatory tax liability 15,122 37,846 52,968
Customer advances for construction 65,898 36,462 102,360
Other 2,276 77,438 1,705 (12) 47,790
(33,629) (5)
-------------- --------------- --------------- -------------
281,168 361,648 (26,950) 615,866
-------------- --------------- --------------- -------------
Total Capitalization and Liabilities $ 2,648,713 $ 2,068,920 $ 399,534 $ 5,117,167
============== =============== =============== =============
</TABLE>
The accompanying notes to the unaudited pro forma combined condensed
balance sheet and statements of income are an integral part of this
statement.
5
<PAGE>
SIERRA PACIFIC RESOURCES
PRO FORMA COMBINED CONDENSED STATEMENT OF INCOME
FOR THE SIX MONTHS ENDED JUNE 30, 1999
(Thousands of dollars, except per share amounts)
(preliminary and unaudited)
<TABLE>
<CAPTION>
NEVADA SIERRA
POWER (9) PACIFIC (9) ADJUSTMENTS PRO FORMA
--------- ----------- ----------- ---------
<S> <C> <C> <C> <C>
OPERATING REVENUES $ 420,370 $ 376,943 $ 797,313
--------- ----------- ----------- ---------
OPERATING EXPENSES:
Operations 281,343 233,931 515,274
Maintenance 29,228 10,660 39,888
Depreciation and amortization 39,530 38,767 78,297
Taxes: -
Income taxes 7,206 19,513 (6,451) (7) 20,268
Other than income 11,189 9,671 20,860
--------- ----------- ----------- ---------
368,496 312,542 (6,451) 674,587
--------- ----------- ----------- ---------
OPERATING INCOME 51,874 64,401 6,451 122,726
--------- ----------- ----------- ---------
OTHER INCOME:
Allowance for other funds used during construction 4,083 0 4,083
Other income (expense) - net (1,163) 259 (904)
--------- ----------- ----------- ---------
2,920 259 - 3,179
--------- ----------- ----------- ---------
Total Income 54,794 64,660 6,451 125,905
--------- ----------- ----------- ---------
INTEREST CHARGES:
Long-term debt 31,466 20,443 18,432 (6) 70,341
Other 3,340 4,883 8,223
Allowance for borrowed funds used during construction and
capitalized interest (3,835) (434) (4,269)
--------- ----------- ----------- ---------
30,971 24,892 18,432 74,295
--------- ----------- ----------- ---------
INCOME BEFORE OBLIGATED MANDATORILY REDEEMABLE
PREFERRED SECURITIES 23,823 39,768 (11,981) 51,610
Preferred dividend requirements on company -obligated
mandatorily redeemable preferred securities 7,586 2,086 9,672
--------- ----------- ----------- ---------
INCOME BEFORE PREFERRED DIVIDENDS 16,237 37,682 (11,981) 41,938
Preferred dividend requirements 84 2,730 (84) (11) 2,730
--------- ----------- ----------- ---------
INCOME APPLICABLE TO COMMON STOCK $ 16,153 $ 34,952 (11,897) 39,208
========= =========== =========== =========
Average shares of common stock outstanding (thousands) (10) 51,265 31,015 78,398
Earnings Per Share- Basic (8) $ 0.32 $ 1.13 $ 0.50
</TABLE>
The accompanying notes to the unaudited pro forma combined condensed balance
sheet and statements of income are an integral part of this statement.
6
<PAGE>
SIERRA PACIFIC RESOURCES
PRO FORMA COMBINED CONDENSED STATEMENT OF INCOME
FOR THE TWELVE MONTHS ENDED DECEMBER 31, 1998
(Thousands in dollars, except per share amounts)
(unaudited)
<TABLE>
<CAPTION>
NEVADA SIERRA
POWER (9) PACIFIC (9) ADJUSTMENTS PRO FORMA
--------- ----------- ----------- -----------
<S> <C> <C> <C> <C>
OPERATING REVENUES $ 873,682 $ 741,841 $ 1,615,523
--------- ----------- ----------- -----------
OPERATING EXPENSES:
Operations 538,614 464,538 1,003,152
Maintenance 49,082 22,266 71,348
Depreciation and amortization 73,562 69,435 142,997
Taxes:
Income taxes 42,949 41,815 (12,902) (7) 71,862
Other than income 22,198 19,666 41,864
--------- ----------- ----------- -----------
726,405 617,720 (12,902) 1,331,223
--------- ----------- ----------- -----------
OPERATING INCOME 147,277 124,121 12,902 284,300
--------- ----------- ----------- -----------
OTHER INCOME:
Allowance for other funds used during construction 8,944 3,797 12,741
Other (expense) income - net (4,602) 674 (3,928)
--------- ----------- ----------- -----------
4,342 4,471 0 8,813
--------- ----------- ----------- -----------
Total Income 151,619 128,592 12,902 293,113
--------- ----------- ----------- -----------
INTEREST CHARGES:
Long-term debt 56,995 40,396 36,864 (6) 134,255
Other 6,018 7,659 13,677
Allowance for borrowed funds used during construction and
capitalized interest (6,080) (6,414) (12,494)
--------- ----------- ----------- -----------
56,933 41,641 36,864 135,438
--------- ----------- ----------- -----------
INCOME BEFORE OBLIGATED MANDATORILY REDEEMABLE
PREFERRED SECURITIES 94,686 86,951 (23,962) 157,675
Preferred dividend requirements on company -obligated
mandatorily redeemable preferred securities 11,013 4,171 15,184
--------- ----------- ----------- -----------
INCOME BEFORE PREFERRED DIVIDENDS 83,673 82,780 (23,962) 142,491
Preferred dividend requirements 174 5,459 (174) (11) 5,459
--------- ----------- ----------- -----------
INCOME APPLICABLE TO COMMON STOCK $ 83,499 $ 77,321 $ (23,788) 137,032
========= =========== =========== ===========
Average shares of common stock outstanding (thousands) (10) 50,993 30,955 78,040
Earnings Per Share - Basic (8) $ 1.64 $ 2.50 $ 1.76
</TABLE>
The accompanying notes to the unaudited pro forma combined condensed balance
sheet and statements of income are an integral part of this statement
7
<PAGE>
NOTES TO UNAUDITED PROFORMA COMBINED CONDENSED FINANCIAL STATEMENTS
1) Reflects the incurrence of $460,800,000 (including $5.4 million debt
issuance costs) of long-term debt the proceeds of which are to be applied
to pay the Sierra Pacific Cash Consideration and the Nevada Power Cash
Consideration.
2) Pursuant to the Merger agreement, this adjustment reflects the Sierra
Pacific cash consideration paid to Sierra Pacific shareholders who will
receive cash in lieu of common stock. The adjustment assumes a total
payment of $151,600,000 at a cash price of $37.55 per share. (see footnote
A of adjustment 10)
3) Pursuant to the Merger agreement, this adjustment reflects the Nevada Power
cash consideration paid to Nevada Power shareholders who will receive cash
in lieu of common stock. The adjustment assumes a total payment of
$304,600,000 at a cash price of $26.00 per share. (see footnote A of
adjustment 10)
4) Reflects the Nevada Power and Sierra Pacific stock consideration as
described in the Merger agreement. The adjustment recognizes the conversion
of the remaining common shares of Nevada Power and Sierra Pacific net of
the shares which were converted to cash in adjustments 2 and 3. The
adjustment is based on the number of shares outstanding as of June 30,
1999. The conversion represents the exchange of each common share of Sierra
Pacific stock into 1.44 shares of Sierra Pacific common stock and the
exchange of each common share of Nevada Power stock into 1.00 share of
Sierra Pacific common stock. The total shares exchanged and stock
consideration is based on the following calculations (share amounts in
thousands):
<TABLE>
<CAPTION>
As of June 30, 1999
SPR NVP Pro Forma
<S> <C> <C> <C>
Shares outstanding end of period 31,027 51,265
Shares redeemed for cash
(adjustments 2 and 3) (4,037) (11,715)
------- --------
Remaining shares to be exchanged 26,990 39,550
1.44 1.00
------- --------
Stock Consideration 38,866 39,550 78,416
======= ======== =======
</TABLE>
5) Reflects the recognition of goodwill equal to the excess of the purchase
price over the net assets of Sierra Pacific Resources acquired. The
adjustment assumes total purchase consideration equal to cash of
$151,600,000 and 38,866,000 shares of Sierra Pacific Resources stock at a
price of $24.18 based on the average closing price of Nevada Power common
stock between April 22, 1998 and May 6, 1998. The eleven day average price
of Nevada Power common stock used in determining the total stock
consideration represents the market price over a reasonable period of time
before and after the transaction was announced on April 29, 1998. The
calculation of goodwill for the balance sheet presented is based on the
following calculations (dollars in thousands except per share amounts):
8
<PAGE>
<TABLE>
<CAPTION>
JUNE 30, 1999
----------------------
<S> <C> <C>
Cash consideration (adjustment 2) $ 151,600
Common stock consideration:
Sierra Pacific stock converted 26,990
Conversion rate 1.44
--------------
New shares received 38,866
Nv Power stock price 4/29/98 24.18
--------------
Total stock consideration 939,780
----------------------
Total Consideration 1,091,380
Less net fair value Sierra Pacific
end of period 687,168
----------------------
Subtotal 404,212
Other assets recognized,net of tax, for
pension other postretirement benefits
($32,474 Other deferred charges,
$33,629 Other deferred credits) 66,103
----------------------
Goodwill $ 338,109
======================
</TABLE>
Sierra Pacific is primarily a regulated utility providing electric, gas and
water services at rates subject to approval of the Nevada Public Utility
Commission and the California Public Service Commission. Therefore, the value of
Sierra Pacific's assets depends on the cost of service rate treatment afforded
them in the rate-making process. The assets are included in the rate process at
book value and, therefore, the earnings potential is limited to a regulatory
return on that book value. It is therefore appropriate to equate the fair value
of Sierra Pacific's assets with their book value.
It should be noted that a portion of Sierra Pacific assets may be subject to
restructuring proceedings that require a market valuation of these assets,
absent regulatory price treatment. However, to the extent that market value of
these assets differs from book value, any gain or loss is expected to be
included in the regulatory process.
Other assets recognized for pension and other postretirement benefits
represent the excess of plan assets over the benefit obligations of all plans.
This adjustment recognizes all previously unrecognized amounts for net plan
gains and losses, prior service cost and transition obligations.
6) Reflects the recognition of interest expense related to the incurrence of
debt (adjustment 1) at an assumed annual rate of 8.00%. The interest
expense as presented in the income statements is calculated as if the
merger had occurred on the first day of each period presented. A 1/8%
increase in the interest rate would cause an increase in interest expense
for the six months ended June 30, 1999 and the year ended December 31,
1998, of $288,000 and $576,000, respectively.
7) Reflects an adjustment to reduce pro forma income taxes because of higher
interest expense (adjustment 6). The adjustment assumes an effective income
tax rate of 35%.
8) The Statement of Financial Accounting Standards No. 128, Earnings Per
Share, effective for financial periods ending after December 15, 1997,
established standards for computing and presenting earnings per share. The
statement now requires dual presentation of basic and diluted earnings per
share for entities with complex capital structures. Both Nevada Power and
Sierra Pacific adopted this pronouncement for the income statement periods
presented in these pro forma financial statements. The adoption resulted in
no effect for Nevada Power and was immaterial for both Sierra Pacific as
and the combined pro forma entity. Accordingly, only basic earnings per
share is reflected for each company.
9) For comparative purposes, certain historical amounts have been reclassified
to conform to the pro forma financial statement format.
9
<PAGE>
10) Calculation of weighted average shares outstanding (in thousands):
<TABLE>
<CAPTION>
Six Months Ended June 30, 1999 Twelve Months Ended December 31, 1998
Sierra Nevada Pro Sierra Nevada Pro
Pacific Power Forma Pacific Power Forma
----------- ---------- --------- ---------- ------------- ----------
<S> <C> <C> <C> <C> <C> <C>
Weighted Average shares
outstanding 31,015 51,265 30,955 50,993
Shares redeemed for cash (A)
(4,037) (11,715) (4,037) (11,715)
---------- --------- --------- ------------
Net shares
26,978 39,550 26,918 39,278
1.44 1.00 1.44 1.00
---------- --------- --------- ------------
Conversion
38,848 39,550 78,398 38,762 39,278 78,040
========== ========= ======== ========= ============ =========
</TABLE>
(A) Shares redeemed based on the following calculation (see footnotes (2)
and (3)):
SPR NVP
---------- ----------
Allocated cash for
redemption ($000) $151,600 $304,600
Redemption price per
share $ 37.55 $ 26.00
---------- ----------
Shares redeemed
(in thousands) 4,037 11,715
---------- ----------
11) Pursuant to the merger agreement, reflects the redemption of Nevada Power
preferred stock. The Nevada Power preferred stock is redeemable at a price
of $21 per share for the 5.20% series and the 5.40% series and at $20.25
per share for the 4.70% series at any time upon 30 day notice to the
holders. Preferred stock in the amount of $3,217,000 is included as a
current maturity on the Nevada Power balance sheet as of June 30, 1999.
This adjustment also eliminates the preferred dividend requirements on the
Pro Forma Combined Condensed Statements of Income for the six months ended
June 30, 1999 and the twelve months ended December 31, 1998. The preferred
stock redemption is based on the following schedule (dollars in thousands):
Redemption including par value and premium $ 3,511
Less:
Preferred stock at par value 3,217
Sinking fund balance 200
--------
3,417
--------
Loss on redemption $ 94
========
10
<PAGE>
12) To recognize severance, pension, postretirement and other employee benefit
costs experienced in connection with the merger. Consistent with other
merger costs, these items are being deferred as regulatory assets based on
the PUCN merger order decision. The estimated benefits are as follows
(dollars in thousands):
<TABLE>
<CAPTION>
Sierra Pacific Nevada Power Total
-------------- ------------ ----------
<S> <C> <C> <C>
Severance payments 1) $ 5,363 $ 7,873 $ 13,236
Curtailments 2) - (2,637) $ (2,637)
Other termination benefits 2) 4,446 2,730 $ 7,176
-------------- --------- ---------
Total $ 9,809 $ 7,966 $ 17,775
============== ========== =========
</TABLE>
1) Other current liablities
2) $2,834 Other deferred charges, $1,705 Other deferred credits
13) To recognize estimated merger transaction and transition costs. The PUCN
merger order also provides for deferral of these costs for a three year
period after which time the extent to which the costs will be recoverable
in rates and an appropriate amortization period will be determined. It is
anticipated that amounts deferred will be fully recoverable in rates. The
adjustment recognizes the additional estimated costs not already recorded
as of June 30, 1999 (dollars in thousands):
<TABLE>
<CAPTION>
Additional
Recorded estimated
6/30/99 Costs Total
-------- ---------- --------
<S> <C> <C> <C>
Transaction costs $ 15,847 $ 11,392 $ 27,239
Transition costs
3,601 1,529 5,130
-------- ---------- --------
Total $ 19,448 $ 12,921 $ 32,369
======== ========== ========
</TABLE>
14) Adjustment to restate retained earnings balance equal to Nevada Power
Company.
11
<PAGE>
15) Adjustment to record additional deferred income taxes for the following
temporary differences (dollars in thousands):
<TABLE>
<CAPTION>
Temporary Deferred Income
Differences Taxes
----------- ---------------
<S> <C> <C>
Liabilities for employee severance, relocation
other termination costs (see adj 12) $ 14,210 $ 4,974
</TABLE>
In accordance with SFAS 109, deferred income taxes were not recorded on goodwill
for which the amortization is not deductible for tax purposes.
12
<PAGE>
Signature
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
Sierra Pacific Resources
Date: September 15, 1999 By: /s/ Mark A. Ruelle
------------------ ----------------------------
Mark A. Ruelle
Senior Vice President,
Chief Financial Officer and
Treasurer
(Principal Financial Officer)
13
<PAGE>
Exhibits
--------
Exhibit 15
Awareness letter of independent accountants, Deloitte &Touche LLP, re
unaudited interim financial information.
Exhibit 23
Consent of independent accountants, Deloitte &Touche LLP
Exhibit 99.2
The consolidated balance sheets of Nevada Power Company as of December
31, 1998 and 1997 (as set forth in the Nevada Power Company annual
report on Form 10-K for the fiscal year ended December 31, 1998).
The consolidated statements of income and cash flows of Nevada Power
Company for each of the three years ended December 31, 1998, 1997, 1996
(as set forth in the Nevada Power Company annual report on Form 10-K
for the fiscal year ended December 31, 1998).
Exhibit 99.3
The condensed consolidated balance sheets of Nevada Power Company as of
June 30, 1999 and December 31, 1998 (as set forth in the Nevada Power
Company quarterly report on Form 10-Q for the period ended June 30,
1999).
The condensed consolidated statements of income and cash flows of
Nevada Power Company for the three and six months (six months only for
cash flows) ended June 30, 1999, 1998 ( as set forth in the Nevada
Power Company quarterly report on Form 10-Q for the period ended June
30, 1999).
Exhibit 99.4
The consolidated balance sheets of Sierra Pacific Resources as of
December 31, 1998 and 1997 (as set forth in the Sierra Pacific
Resources annual report on Form 10-K for the fiscal year ended December
31, 1998).
The consolidated statements of income and cash flows of Sierra Pacific
Resources for each of the three years ended December 31, 1998, 1997,
1996 (as set forth in the Sierra Pacific Resources annual report on
Form 10-K for the fiscal year ended December 31, 1998).
Exhibit 99.5
The condensed consolidated balance sheets of Sierra Pacific Resources
as of June 30, 1999 and December 31, 1998 (as set forth in the Sierra
Pacific Resources quarterly report on Form 10-Q for the period ended
June 30, 1999).
The condensed consolidated statements of income and cash flows of
Sierra Pacific Resources for the three and six months (six months only
for cash flows) ended June 30, 1999, 1998 ( as set forth in the Sierra
Pacific Resources quarterly report on Form 10-Q for the period ended
June 30, 1999).
<PAGE>
EXHIBIT 15
Sierra Pacific Resources
6100 Neil Road
Reno, Nevada 89520
We have made a review, in accordance with standards established by the American
Institute of Certified Public Accountants, of the unaudited interim financial
information of Sierra Pacific Resources and subsidiaries (the Company) for the
period ended June 30, 1999 as indicated in our report dated August 5, 1999;
because we did not perform an audit, we expressed no opinion on that
information.
We are aware that our report referred to above, which was included in your
Quarterly Report on Form 10-Q for the quarter ended June 30, 1999 and
incorporated by reference in this Current Report on Form 8-K/A is incorporated
by reference in Registration Statement No. 333-4374 of the Company on Form S-3,
Registration Statement No. 333-62895 of the Company on Form S-4, and
Registration Statement Nos. 2-92454, 333-8764 6, and 33-48152 of the Company on
Form S-8.
We also are aware that the aforementioned report, pursuant to Rule 436(c) under
the Securities Act of 1933, is not considered a part of this Amendment to the
Registration Statement prepared or certified by an accountant or a report
prepared or certified by an accountant within the meaning of Sections 7 and 11
of that Act.
September 15, 1999
DELOITTE & TOUCHE LLP
Reno, Nevada
<PAGE>
EXHIBIT 23
September 15, 1999
We consent to the incorporation by reference in Registration Statement No. 333-
4374 of Sierra Pacific Resources (the Company) on Form S-3, Registration
Statement No. 333-62895 of the Company on Form S-4, and Registration Statement
Nos. 2-92454, 333-8764 6, and 33-48152 of the Company on Form S-8 of our report
dated January 9, 1999 (February 12, 1999 as to Notes 1 and 5), appearing in the
Annual Report on Form 10-K of the Company, and our report dated March 1, 1999,
appearing in the Annual Report of Nevada Power Company which are incorporated by
reference in this Current Report on Form 8-K/A.
DELOITTE & TOUCHE LLP
Reno, Nevada
<PAGE>
EXHIBIT 99.2
NEVADA POWER COMPANY
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
December 31,
1998 1997
---------- ----------
(In Thousands)
<S> <C> <C>
ASSETS:
Electrical Plant, at original cost (Notes 1, 8, 10 and 12)
Production $ 918,804 $ 900,971
Transmission 425,632 326,917
Distribution 1,097,583 978,144
General 186,915 172,264
---------- ----------
2,628,934 2,378,296
---------- ----------
Less accumulated depreciation 708,791 647,208
---------- ----------
Net plant in service 1,920,143 1,731,088
Construction work in progress 213,365 158,029
Property under capital lease, net 64,632 69,261
Plant held for future use 1,746 2,331
---------- ----------
2,199,886 1,960,709
---------- ----------
INVESTMENTS (Note I)
Current Assets:
Cash and cash equivalents (Note I) 1,770 720
Customer receivables -
Billed 49,516 45,776
Unbilled (Note I) 34,201 28,237
Reserve for doubtful accounts (2,429) (2,291)
Other receivables 16,010 16,415
Fuel stock, at average cost 7,119 7,325
Materials and supplies, at average cost 32,487 35,045
Deferred energy asset (Note I) 62,489 30,597
Prepayments 7,787 6,711
---------- ----------
208,950 168,535
---------- ----------
Deferred Charges:
Debt expense, being amortized 34,932 30,461
Other (Note II) 139,573 166,146
---------- ----------
174,505 196,607
---------- ----------
$2,607,824 $2,339,422
========== ==========
CAPITALIZATION AND LIABILITIES:
Capitalization (See Consolidated Schedules of Capitalization and
Long-Term Debt):
Common shareholders' equity $ 864,036 $ 833,623
Cumulative preferred stock with mandatory sinking funds 3,265 3,463
Company-obligated mandatorily redeemable preferred securities 188,872 118,872
Long-term debt 900,227 895,439
---------- ----------
1,956,400 1,851,397
---------- ----------
Current liabilities:
Notes payable 105,000 -
Current maturities and sinking fund requirements (See Consolidated Schedules
of Capitalization and Long-Term Debt) 50,380 19,937
Accounts payable 83,439 64,737
Accrued taxes - 7,543
Accrued interest 7,829 7,284
Customers' service deposits 14,859 15,095
Deferred taxes on deferred energy asset (Note 3) 21,871 10,709
Other 26,568 22,554
---------- ----------
309,946 147,859
---------- ----------
Commitments and Contingencies (Note 10)
Deferred Credits and Other Liabilities:
Deferred investments tax credits (Notes 1 and 3) 28,083 29,544
Deferred taxes on income (Notes 1 and 3) 231,610 235,846
Customers' advances for construction 64,113 55,772
Other (Note II) 17,672 19,004
---------- ----------
341,478 340,166
---------- ----------
TOTAL CAPITALIZATION AND LIABILITIES $2,607,824 $2,339,422
========== ==========
</TABLE>
1
<PAGE>
NEVADA POWER COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(In Thousands, Except Per Share Amounts)
<TABLE>
<CAPTION>
For The Years Ended
December 31,
1998 1997 1996
--------- --------- ---------
<S> <C> <C> <C>
ELECTRIC REVENUES (Note I) $ 873,682 $ 799,148 $ 805,374
OPERATING EXPENSES AND TAXES:
Fuel 149,804 138,956 112,321
Purchased and interchanged power 283,838 277,644 264,143
Deferred energy cost adjustments, net (Note I) (29,680) (60,400) 8,817
--------- --------- ---------
Net energy costs 403,962 356,200 385,281
Other production operations 21,153 21,214 17,834
Other operations 113,499 101,597 99,266
Maintenance and repairs 49,082 52,126 44,464
Provision for depreciation (Note I) 73,562 66,273 61,771
General taxes 22,198 21,064 19,558
Federal income taxes (Notes I and 3) 42,949 43,478 44,970
--------- --------- ---------
726,405 661,952 673,144
--------- --------- ---------
OPERATING INCOME 147,277 137,196 132,230
--------- --------- ---------
OTHER INCOME (EXPENSES):
Allowance for other funds used during
construction (Note I) 8,944 8,760 6,240
Other miscellaneous, net (4,602) (5,741) (10,116)
--------- --------- ---------
4,342 3,019 (3,876)
--------- --------- ---------
INCOME BEFORE INTEREST DEDUCTIONS 151,619 140,215 128,354
INTEREST DEDUCTIONS:
Interest on long-term debt 56,995 50,791 47,792
Other interest 6,018 1,531 2,584
Allowance for borrowed funds used
during construction (Note I) (6,080) (2,579) (890)
--------- --------- ---------
56,933 49,743 49,486
Distribution requirements
on company-obligated mandatorily
redeemable preferred securities
of subsidiary trusts (Note 7) 11,013 7,256 -
NET INCOME 83,673 83,216 78,868
DIVIDEND REQUIREMENTS ON PREFERRED STOCK 174 1,125 3,956
--------- --------- ---------
EARNINGS AVAILABLE FOR COMMON STOCK $ 83,499 $ 82,091 $ 74,912
========= ========= =========
WEIGHTED AVERAGE COMMON SHARES
OUTSTANDING 50,993 49,691 47,976
========= ========= =========
EARNINGS PER AVERAGE COMMON SHARE $ 1.64 $ 1.65 $ 1.56
========= ========= =========
</TABLE>
2
<PAGE>
NEVADA POWER COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In Thousands)
<TABLE>
<CAPTION>
For The Years Ended
December 31,
1998 1997 1996
--------- --------- ---------
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income $ 83,673 $ 83,216 $ 78,868
Adjustments to reconcile net income to net
cash provided by operating activities -
Depreciation and amortization 87,458 78,274 69,876
Deferred income taxes and investment
tax credits 23,640 21,599 5,679
Allowance for other funds used
during construction (8,944) (8,760) (6,240)
Changes in -
Receivables (9,034) (15,407) (1,754)
Fuel stock and materials and supplies 2,764 163 2,105
Accounts payable and other current liabilities 22,788 8,306 (6,257)
Deferred energy costs (33,819) (59,543) 12,093
Accrued taxes and interest (9,433) 2,416 (13,105)
Other assets and liabilities (4,714) 108 13,725
Net cash provided by operating activities 154,379 110,372 154,990
CASH FLOWS FROM INVESTING ACTIVITIES:
Construction expenditures and gross additions (314,366) (213,550) (180,871)
Investment in subsidiaries and other (2,780) (463) 70
Net cash used in investing activities (317,146) (214,013) (180,801)
CASH FLOWS FROM FINANCING ACTIVITIES:
Issuance of capital stock 20,746 32,473 37,395
Issuance of company-obligated mandatorily
redeemable preferred securities 70,000 118,872 -
Issuance of long-term debt - 72,285 20,000
Deposit of funds held in trust (1,884) (74,672) (22,814)
Withdrawal of funds held in trust 54,822 74,424 47,581
Retirement of long-term debt (19,603) (5,334) (5,418)
Retirement of preferred stock (200) (38,200) (200)
Increase (decrease) in short-term borrowing 105,000 - -
Cash dividends (73,962) (81,216) (80,370)
Other financing activities 8,898 3,185 6,674
Net cash provided by financing activities 163,817 101,817 2,848
CASH AND CASH EQUIVALENTS (Note 1):
Net increase (decrease) during the year 1,050 (1,824) (22,963)
Beginning of year 720 2,544 25,507
End of year $ 1,770 $ 720 $ 2,544
CASH PAID DURING THE YEAR FOR:
Interest, net of amounts capitalized $ 75,487 $ 64,692 $ 59,521
Income taxes $ 27,110 $ 19,545 $ 51,282
</TABLE>
See Notes to Consolidated Financial Statements
3
<PAGE>
<TABLE>
<CAPTION>
CONSOLIDATED SCHEDULES OF CAPITALIZATION
- --------------------------------------------------------------------------------
(Dollars in thousands)
December 31, 1998 1997
- ------------------------------------------------------------------------------
<S> <C> <C>
COMMON SHAREHOLDERS' EQUITY (Note 6):
Common stock, $1 par value, authorized
70,000,000 shares; issued and
outstanding 51,265,117 and 50,399,746
shares at December 31, 1998 and 1997;
stated at $ 54,066 $ 53,604
Premium on capital stock 687,537 667,203
Unamortized capital stock expense (2,986) (2,872)
Accumulated other comprehensive income (1,395) (1,344)
Retained earnings 126,814 117,032
- ------------------------------------------------------------------------------
Total common shareholders' equity 864,036 44.2% 833,623 45.0%
- ------------------------------------------------------------------------------
CUMULATIVE PREFERRED STOCK WITH MANDATORY
SINKING FUNDS (Note 6):
Outstanding at December 31, 1998 and 1997:
5.40% Series, 36,669 and 38,669
shares 733 773
5.20% Series, 34,570 and 36,507
shares 692 730
4.70% Series, 102,006 and 108,006
shares 2,040 2,160
- ------------------------------------------------------------------------------
3,465 3,663
Current sinking fund requirement (200) (200)
- ------------------------------------------------------------------------------
Total preferred stock 3,265 .2 3,463 .2
- ------------------------------------------------------------------------------
COMPANY-OBLIGATED MANDATORILY REDEEMABLE
PREFERRED SECURITIES OF THE COMPANY'S
SUBSIDIARY TRUST, NVP CAPITAL I,
HOLDING SOLELY $122.6 MILLION
PRINCIPAL AMOUNT OF 8.2% JUNIOR
SUBORDINATED DEBENTURES OF THE
COMPANY, DUE 2037 (Note 7) 118,872 118,872
COMPANY-OBLIGATED MANDATORILY REDEEMABLE
PREFERRED SECURITIES OF THE COMPANY'S
SUBSIDIARY TRUST, NVP CAPITAL III,
HOLDING SOLELY $72.2 MILLION
PRINCIPAL AMOUNT OF 7 3/4% JUNIOR
SUBORDINATED DEBENTURES OF THE
COMPANY, DUE 2038 (Note 7) 70,000 -
- ------------------------------------------------------------------------------
Total preferred securities 188,872 9.6 118,872 6.4
- ------------------------------------------------------------------------------
LONG-TERM DEBT
(See Consolidated Schedules of Long-Term
Debt) 900,227 46.0 895,439 48.4
- ------------------------------------------------------------------------------
Total capitalization $1,956,400 100.0% $1,851,397 100.0%
- --------------------------------------------==================================
</TABLE>
See Notes to Consolidated Financial Statements.
- ------------------------------------------------------------------------------
4
<PAGE>
<TABLE>
<CAPTION>
NEVADA POWER COMPANY
CONSOLIDATED SCHEDULES OF LONG-TERM DEBT
- ------------------------------------------------------------------------------
(In thousands)
December 31, 1998 1997
- ------------------------------------------------------------------------------
<S> <C> <C>
LONG-TERM DEBT (Notes 8, 9 and 10):
First mortgage bonds:
7 1/8% Series I due 1998 $ - $ 15,000
7 5/8% Series L due 2002 15,000 15,000
7.80% Series T due 2009 15,000 15,000
6.70% Series V due 2022 105,000 105,000
6.60% Series W due 2019 39,500 39,500
7.20% Series X due 2022 78,000 78,000
6.93% Series Y due 1999 45,000 45,000
8.50% Series Z due 2023 45,000 45,000
7.06% Series AA due 2000 85,000 85,000
- ------------------------------------------------------------------------------
427,500 442,500
Industrial development revenue bonds:
7.80% due 2020 100,000 100,000
5.90% Series 1997A due 2032 52,285 52,285
5.90% Series 1995B due 2030 85,000 85,000
5.60% Series 1995A due 2030 76,750 -
5.50% Series 1995C due 2030 44,000 -
Variable rate -
Series 1995A due 2030 (4.33%*) - 76,750
Series 1995C due 2030 (4.23%*) - 44,000
Pollution control revenue bonds:
6 3/8% due 2036 20,000 20,000
5.80% Series 1997B due 2032 20,000 20,000
5.30% Series 1995D due 2011 14,000 -
5.45% Series 1995D due 2023 6,300 -
5.35% Series 1995E due 2022 13,000 -
Variable rate -
Series 1995D due 2011 (4.19%*) - 14,000
Series 1995D due 2023 (4.19%*) - 6,300
Series 1995E due 2022 (4.19%*) - 13,000
Less funds held in trust (10) (52,948)
Other notes 327 300
Obligations under capital leases 91,249 93,985
- ------------------------------------------------------------------------------
950,401 915,172
Debt premium and discount, being amortized 6 4
Current maturities and sinking fund requirements (50,180) (19,737)
- ------------------------------------------------------------------------------
Total long-term debt $900,227 $895,439
- ---------------------------------------------------------=====================
*Average interest rate during 1997
See Notes to Consolidated Financial Statements.
- ------------------------------------------------------------------------------
</TABLE>
5
<PAGE>
NEVADA POWER COMPANY 1998 ANNUAL REPORT
<TABLE>
<CAPTION>
NEVADA POWER COMPANY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
- ------------------------------------------------------------------------------
(In thousands)
For the Years Ended December 31, 1998 1997 1996
- ------------------------------------------------------------------------------
<S> <C> <C> <C>
Net Income $ 83,673 $ 83,216 $ 78,868
- -----------------------------------------------------------------------------
Minimum pension liability adjustment (77) (1,487) 722
Tax effect 27 521 (252)
- -----------------------------------------------------------------------------
Minimum pension liability adjustment, net of
tax (50) (966) 470
- -----------------------------------------------------------------------------
Comprehensive income $ 83,623 $ 82,250 $ 79,338
- -----------------------------------------------==============================
</TABLE>
See Notes to Consolidated Financial Statements.
<TABLE>
<CAPTION>
NEVADA POWER COMPANY
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
- -----------------------------------------------------------------------------
(In thousands)
For the Years Ended December 31, 1998 1997 1996
- -----------------------------------------------------------------------------
<S> <C> <C> <C>
BALANCE AT BEGINNING OF YEAR $117,032 $117,360 $118,860
Add - Net Income 83,673 83,216 78,868
- -----------------------------------------------------------------------------
200,705 200,576 197,728
- -----------------------------------------------------------------------------
Deduct:
Dividends paid in cash:
Cumulative preferred stock -
5.40%, 5.20% and 4.70% Series 174 184 194
9.90% Series (Notes 6 and 7) - 941 3,762
Common stock 73,717 79,176 76,412
- -----------------------------------------------------------------------------
73,891 80,301 80,368
Redemption of preferred stock
(Notes 6 and 7) - 3,243 -
- -----------------------------------------------------------------------------
73,891 83,544 80,368
- -----------------------------------------------------------------------------
BALANCE AT END OF YEAR $126,814 $117,032 $117,360
- -----------------------------------------------==============================
</TABLE>
See Notes to Consolidated Financial Statements.
6
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- --------------------------------------------------------------------------------
1 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
- --------------------------------------------------------------------------------
For ratemaking and other purposes, the Company is subject to the
jurisdiction of the PUCN and the FERC. The accounting records of the Company are
maintained in accordance with the uniform system of accounts prescribed by the
FERC and adopted by the PUCN.
The Company is subject to the provisions of Statement of Financial
Accounting Standards No. 71, Accounting for the Effects of Certain Types of
Regulation, which require the Company to record certain regulatory assets and
liabilities.
CONTINUING APPLICABILITY OF FASB 71
The Company's rates are currently subject to approval by the PUCN and
are designed to recover the Company's costs of providing services to its
customers. A primary difference between a rate regulated entity and an
unregulated entity is the timing of recognizing certain assets and expenses for
financial reporting purposes. The Statement of Financial Accounting Standards
No. 71, "Accounting for the Effects of Certain Types of Regulation" (FAS 71),
prescribes the method to be used to record the financial transactions of a
regulated entity. The criteria for applying FAS 71 include the following: (i)
rates are set by an independent third party regulator, (ii) approved rates are
intended to recover the specific costs of the regulated products or services and
(iii) rates are set at levels that will recover costs, can be charged to and
collected from customers. If the Company determines as a result of competitive
changes in Nevada, PUCN orders or otherwise that its business, or a portion of
its business, fails to meet any of these three criteria of FAS 71, it may have
to eliminate from its Consolidated Financial Statements the related transactions
prescribed by the regulators that would not have been recognized if it had been
a non-regulated company, which could result in an impairment of or write-off of
utility assets. The Company believes, however, that it continues to meet the
criteria for operating as a rate regulated entity, as prescribed by FAS 71.
In July 1997, the Emerging Issues Task Force (EITF) of the Financial
Accounting Standards Board reached a consensus on several issues which have
arisen due to deregulation of the electric utility industry and the continuing
applicability of FAS 71. The EITF reached a consensus that a company should stop
applying FAS 71 to a separable portion of its business when deregulatory
legislation or a rate order which results in deregulation gives enough detail
for the company to reasonably determine how the transition plan to deregulation
will effect that separable portion. Once FAS 71 is no longer applied to that
separable portion of the business it should be disclosed separately in the
company's financial statements. Any regulatory assets and liabilities that
originated in that separable portion of the company should be evaluated on the
basis of which portion of the business the regulated cash flows to settle them
will come from and will not be eliminated until they are recovered, individually
impaired or eliminated by the regulator or the portion of the business where the
regulated cash flows come from can no longer apply FAS 71. Any new regulatory
assets and liabilities are recognized within the portion of the company where
the regulated cash flows for their recovery or settlement are derived and are
eliminated in the same manner as existing regulatory assets and liabilities as
described above. After considering the EITF, the Company believes that it
continues to meet the criteria for operating as a rate regulated entity, as
prescribed by FAS 71.
7
<PAGE>
PRINCIPLES OF CONSOLIDATION
The consolidated financial statements include the accounts of the
Company and its wholly-owned subsidiaries, NVP Capital I and III. All
significant intercompany transactions and balances have been eliminated in
consolidation.
USE OF ESTIMATES
The preparation of consolidated financial statements in conformity with
generally accepted accounting principles requires management to make estimates
and assumptions that affect the reported amounts of assets and liabilities at
the date of the consolidated financial statements and the reported amounts of
revenues and expenses during the reporting period. Actual results could differ
from those estimates.
ELECTRIC REVENUES
The Company bills its customers monthly on a cycle basis and recognizes
the estimated
- --------------------------------------------------------------------------------
NEVADA POWER COMPANY 1998 ANNUAL REPORT
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- --------------------------------------------------------------------------------
amount of revenue applicable to kilowatthours of energy sold but not yet billed
at the end of an accounting period.
DEFERRED ENERGY COST ADJUSTMENTS
As permitted by state statute, the Company defers differences between
the current cost of fuel plus net purchased power and base energy costs as
defined. Any over or under recoveries are deferred in the balance sheet as a
current asset or current liability. Under regulations adopted by the PUCN,
deferred energy rates are revised at least every 12 months to clear the
accumulated deferred balance over a future period.
ELECTRIC PLANT
The costs of betterments and additions to electric plant and
replacements of retirement units of property are capitalized. Such costs include
labor, payroll taxes, material, transportation, an allowance for funds used
during construction and, where applicable, property taxes. Maintenance is
charged with the cost of repairs and minor replacements. Accumulated
depreciation is charged for the cost of plant retired, less net salvage.
Depreciation has been provided for financial statement purposes on a
straight-line basis at rates based upon the estimated useful lives of the
various classes of plant. The provisions for depreciation during 1998, 1997 and
1996 were equivalent to an annual rate of approximately 2.9 percent of the
average gross investment in depreciable plant.
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION
The allowance for funds used during construction (AFUDC) represents the
estimated costs of borrowed and equity funds applicable to electric plant
construction.
The FERC has prescribed a specific computational method for determining
the AFUDC rate. The PUCN has authorized the AFUDC rate to be the lesser of the
rate determined under the FERC computational method or the rate equivalent to
the overall rate of return authorized by the PUCN. The overall rate of return
authorized by the PUCN was 9.66 percent beginning July 1994. The Company's
actual AFUDC rate averaged 9.66 percent for 1998, 1997 and 1996.
8
<PAGE>
RECENTLY ISSUED ACCOUNTING STANDARDS
The Financial Accounting Standards Board recently issued Statement of
Financial Accounting Standards No. 133 (FAS 133), Accounting for Derivative
Instruments and Hedging Activities, which is effective for financial statements
for all fiscal quarters of all fiscal years beginning after June 15, 1999. FAS
133 establishes accounting and reporting standards for derivative instruments,
including certain derivative instruments embedded in other contracts and for
hedging activities. It requires that an entity recognize all derivatives as
either assets or liabilities in the statement of financial position and measure
those instruments at fair value. The Company is currently evaluating the effect
of the adoption of FAS 133 on the Company's consolidated financial statements
and disclosures.
FEDERAL INCOME TAXES
The Company accounts for income taxes in accordance with Statement of
Financial Accounting Standards No. 109 (FAS 109), Accounting for Income Taxes.
FAS 109 requires recognition of deferred tax liabilities and assets for the
future tax consequences of events that have been included in the consolidated
financial statements or tax returns. Under this method, deferred tax liabilities
and assets are determined based on the difference between the financial
statement and tax bases of assets and liabilities using enacted tax rates in
effect for the year in which the differences are expected to reverse. The
Company's December 31, 1998 consolidated balance sheet contains a net regulatory
asset of $48 million related to federal income taxes. (See Note 11 of "Notes to
Consolidated Financial Statements.")
In November 1991, the PUCN issued an order which allows the Company to
recover the previously flowed through tax benefits ratably over the estimated
remaining book life of the plant. Calculated at current rates, approximately $31
million of income taxes will be allowed in future rates.
Investment tax credits earned have been deferred and are being
amortized to income ratably over the estimated service lives of the related
property.
CASH FLOW INFORMATION
Cash equivalents are generally convertible to cash at par on short
notice and mature three months or less from the date of acquisition.
The Company had no material noncash investing or financing transactions
during 1998, 1997 or 1996.
- --------------------------------------------------------------------------------
NEVADA POWER COMPANY 1998 ANNUAL REPORT
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- --------------------------------------------------------------------------------
OTHER ACCOUNTING POLICIES
Certain amounts in prior periods have been reclassified to conform to
the consolidated financial statement presentation for December 31, 1998.
2 MERGER; DIVIDEND POLICY
On April 30, 1998, the Company and Sierra Pacific Resources announced
that their boards of directors unanimously approved an agreement providing for a
proposed merger of equals combination with stock and cash consideration. In
conjunction with the proposed merger, the Company's Board of Directors stated
that, beginning with the November 1998 dividend, it intended to adopt the
expected combined company initial annual dividend rate. This would result in an
indicated annual dividend rate of $1.00 per share for periods following the
August 1998 dividend payment. For further information regarding the proposed
merger please refer to the Company's Form 8-K filed with the SEC on April 30,
1998.
9
<PAGE>
Both the Company and Sierra Pacific Resources held special stockholder
meetings in October 1998 during which stockholders of both companies voted to
approve the proposed merger. On December 31, 1998, the PUCN approved the
proposed merger subject to conditions regarding the divestiture of the two
companies' generating plants, filing of general rate cases, merger costs and
several other issues. On January 29, 1999, the PUCN clarified portions of the
order approving the proposed merger. Both companies must sell their generating
units. Upon selling the generating units, both companies can determine how they
will use the proceeds of the sales, up to the book value of the plants. Any
after-tax gains above book value will be used to offset stranded costs, as
determined by the PUCN. Any remaining gains can be used to offset goodwill.
After-tax gains may not be sufficient to cover generation-related goodwill.
However, if the company demonstrates that the divestiture "resulted in a market
for generation services that produced market prices that are lower than what
could have been achieved otherwise, the company may include in the general rate
case a request to recover goodwill." Both companies are required to file a
general rate case in 1999 that would update rates to current costs and
"unbundle" rates, i.e. break them into generation, transmission and distribution
components. The merged company would again file a general rate case three years
after the start of retail competition in the state of Nevada that would give the
company the opportunity to recover costs of the merger, provided the company can
demonstrate that merger savings exceed merger costs. Merger costs are to be
split among the non-competitive, potentially competitive and unregulated
services or businesses. An opportunity to recover the non-competitive portion of
the merger costs will be addressed in the rate case that follows the start of
competition in Nevada. The burden is on the company to prove that merger savings
exceed merger costs. The company will also have the opportunity to recover
goodwill in the same proceeding. The proposed merger is conditioned upon further
regulatory approvals including the SEC, the Department of Justice and the FERC.
The companies filed with the FERC a joint merger application on October 2, 1998
which was noticed on October 8, 1998. The law imposes no deadline on the FERC to
issue its decision. The entire process is expected to be completed by mid-1999.
- --------------------------------------------------------------------------------
NEVADA POWER COMPANY 1998 ANNUAL REPORT
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- --------------------------------------------------------------------------------
10
<PAGE>
3 FEDERAL INCOME AND OTHER TAXES
- -------------------------------------------------------------------------------
The total federal income tax expense as set forth in the accompanying
Consolidated Statements of Income results in an effective federal income tax
rate different from the statutory federal income tax rate for the following
reasons:
For the Years Ended December 31,
(Dollars in thousands) 1998 1997 1996
- ------------------------------------------------------------------------------
Federal income tax at statutory
rate $45,200 35.0% $44,954 35.0% $42,613 35.0%
Adjustments:
Investment tax credit
amortization (1,460) (1.1) (1,460) (1.1) (1,460) (1.2)
Other items 1,731 1.3 1,731 1.3 1,731 1.4
- ------------------------------------------------------------------------------
Total recorded federal income tax $45,471 35.2% $45,225 35.2% $42,884 35.2%
- -----------------------------------===========================================
Federal income taxes included in:
Operating expenses $42,949 $43,478 $44,970
Other miscellaneous, net 2,522 1,747 (2,086)
- ------------------------------------------------------------------------------
$45,471 $45,225 $42,884
- -----------------------------------===========================================
The current and deferred components of federal income taxes included in
operating expenses are as follows:
For the Years Ended December 31, (In thousands) 1998 1997 1996
- -------------------------------------------------------------------------------
Current federal income taxes $19,329 $21,899 $ 39,312
- -------------------------------------------------------------------------------
Deferred federal income taxes:
Depreciation differences 24,111 13,669 16,427
Deferred energy costs 11,162 20,848 (3,544)
Contributions in aid of
construction (13,211) (6,302) (7,720)
Allowance for borrowed funds used during
construction 6,463 (2,406) (281)
Coal contract buyout (697) (787) 1,752
Other - net (2,748) (1,983) 484
- -------------------------------------------------------------------------------
25,080 23,039 7,118
- -------------------------------------------------------------------------------
Investment tax credit amortization (1,460) (1,460) (1,460)
- -------------------------------------------------------------------------------
Total $42,949 $43,478 $ 44,970
- ------------------------------------------------===============================
The regulatory asset for temporary differences related to liberalized
depreciation will continue to be amortized using the average rate assumption
method required by the Tax Reform Act of 1986. The regulatory liability for
temporary differences caused by investment tax credits will be amortized ratably
in the same fashion as the deferred investment tax credit under former Internal
Revenue Code Section 46(f)(2).
- --------------------------------------------------------------------------------
11
<PAGE>
- --------------------------------------------------------------------------------
NEVADA POWER COMPANY 1998 ANNUAL REPORT
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- --------------------------------------------------------------------------------
The net deferred federal income tax liability consists of deferred
federal income tax liabilities less deferred federal income tax assets related
to:
December 31, (In thousands) 1998 1997
- -------------------------------------------------------------------------------
DEFERRED FEDERAL INCOME TAX
LIABILITIES:
Temporary basis differences - plant $ (62,906) $ (95,077)
Investment tax credits (28,083) (29,544)
Excess of tax depreciation over book
depreciation (163,658) (133,084)
Coal contract buyout (441) (1,138)
Accrued taxes (3,120) (3,298)
Debt reacquisition costs (2,177) (2,420)
Deferred energy (21,871) (10,709)
Other (626) (116)
- -------------------------------------------------------------------------------
Total (282,882) (275,386)
- -------------------------------------------------------------------------------
DEFERRED FEDERAL INCOME TAX
ASSETS:
Unamortized investment tax credits 15,122 15,908
Refundable customer advances 21,837 18,920
Nonrefundable contributions in aid of
construction 25,312 15,017
Capitalized expenses 83 (27)
Demand-side program costs 1,319 (712)
Supplemental executive retirement plan 2,549 2,249
Other 1,082 681
- -------------------------------------------------------------------------------
Total 67,304 52,036
- -------------------------------------------------------------------------------
Net deferred tax liability $(215,578) $(223,350)
- ----------------------------------------------------===========================
4 EMPLOYEE BENEFITS
- -------------------------------------------------------------------------------
DEFINED CONTRIBUTION RETIREMENT PLAN - The Company maintains an employee
investment plan (401(k) Plan) which was established January 1, 1990, under
Section 401(k) of the Internal Revenue Code. Employees who are at least 21 years
old and have completed one month of service may become "participants" in the
401(k) Plan. The Company matches 60 percent of a participant's contributions to
the 401(k) Plan not to exceed 4.2 percent of the participant's annual
compensation. All Company contributions are invested in common stock of the
Company. The amounts expensed for Company matching contributions to the 401(k)
Plan were $2,419,000 for 1998, $2,074,000 for 1997 and $1,821,000 for 1996.
DEFINED BENEFIT RETIREMENT PLAN - The Company has a non-contributory defined
benefit retirement plan (PLAN) designed to meet the provisions of the Employee
Retirement Income Security Act of 1974. All employees age 21 and over who have
completed one year of service with at least 1,000 hours worked participate in
the PLAN. Benefits under the PLAN are dependent upon each participant's salary
for the highest consecutive 60 months of service and length of service.
The Company also has a Supplemental Executive Retirement Plan (SERP) in
addition to the regular PLAN. Participation is limited to such officers as the
Board of Directors may select. Presently, 28 active or retired designated
officers and employees participate in the SERP. The SERP will be funded as
benefits are disbursed.
12
<PAGE>
The following table sets forth the funded status and amounts recognized
in the Company's consolidated financial statements at December 31, 1998, 1997
and 1996 for both the PLAN and SERP.
The discount rate and rate of increase in future compensation levels
used in determining the actuarial present value of the projected benefit
obligations for both the PLAN and SERP were 6.75 percent and 4.5 percent in
1998, 7.5 percent and 4.5 percent in 1997, and 8 percent and 4.5 percent in
1996, respectively. The expected rate of return on PLAN assets was 8.5 percent
in 1998, 1997 and 1996. PLAN assets are primarily invested in listed securities
(domestic and international), fixed income securities and federal agencies
securities. The accumulated benefit obligation for the SERP was $8,264,000 at
December 31, 1998 and $7,452,000 at December 31, 1997.
- --------------------------------------------------------------------------------
13
<PAGE>
NEVADA POWER COMPANY 1998 ANNUAL REPORT
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- --------------------------------------------------------------------------------
RECONCILIATION OF FUNDED STATUS
<TABLE>
<CAPTION>
PLAN SERP
---------------------------------------------------------------------
For the Years Ended
December 31, 1998 1997 1996 1998 1997 1996
(In thousands)
- --------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Change in benefit
obligation:
Net benefit
obligation at
beginning of year $110,503 $ 96,592 $103,973 $ 9,030 $ 6,662 $ 7,063
Service cost 5,159 4,303 4,843 226 103 102
Interest cost 8,598 7,893 7,642 687 544 517
Plan amendments 2,063 - - 178 117 -
Actuarial (gain) loss 17,989 6,473 (16,003) 11 2,041 (553)
Benefits paid (4,979) (4,758) (3,863) (434) (437) (467)
- --------------------------------------------------------------------------------------------------------
Net benefit obligation
at end of year 139,333 110,503 96,592 9,698 9,030 6,662
- --------------------------------------------------------------------------------------------------------
Change in plan assets:
Fair value of plan
assets at beginning
of year 100,899 81,564 74,628 - - -
Actual return on plan
assets 9,545 16,493 4,003 - - -
Employer contributions 5,696 7,600 6,797 434 437 467
Benefits paid (4,980) (4,758) (3,864) (434) (437) (467)
- --------------------------------------------------------------------------------------------------------
Fair value of plan
assets at end of year 111,160 100,899 81,564 - - -
- --------------------------------------------------------------------------------------------------------
Plan assets less than
projected benefit
obligation (28,173) (9,604) (15,028) (9,698) (9,030) (6,662)
Unrecognized prior
service costs 7,207 5,809 6,386 577 515 495
Unrecognized actuarial
(gain) loss 15,850 (292) 2,712 3,470 3,646 1,692
4th quarter contri-
butions/benefits 3,500 1,196 800 109 109 110
- --------------------------------------------------------------------------------------------------------
Pension liability $ (1,616) $ (2,891) $ (5,130) $ (5,542) $ (4,760) $ (4,365)
- -----------------------------------=====================================================================
Net pension expense
comprised the
following:
Service cost $ 5,159 $ 4,303 $ 4,843 $ 226 $ 103 $ 102
Interest cost on
projected benefit
obligation 8,598 7,893 7,642 687 544 517
Expected return on
plan assets (7,698) (7,015) (6,184) - - -
Amortization of:
Prior service cost 665 577 227 115 98 98
Actuarial loss - - - 188 86 137
- --------------------------------------------------------------------------------------------------------
Net periodic pension
cost $ 6,724 $ 5,758 $ 6,528 $ 1,216 $ 831 $ 854
- -----------------------------------=====================================================================
</TABLE>
14
<PAGE>
<TABLE>
<CAPTION>
PLAN SERP
---------------------------------------------
For the Years Ended
December 31, 1998 1997 1998 1997
(In thousands)
- --------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Amounts recognized in
the balance sheet
consist of:
Accrued benefit
liability $ (1,616) $ (2,891) $(5,542) $(4,760)
Additional minimum
liability - - (2,723) (2,584)
Intangible asset - - 577 515
Accumulated other
comprehensive
income - - 2,146 2,069
- --------------------------------------------------------------------------------
Net amount recognized $ (1,616) $ (2,891) $(5,542) $(4,760)
- -----------------------------------=============================================
</TABLE>
- --------------------------------------------------------------------------------
NEVADA POWER COMPANY 1998 ANNUAL REPORT
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- --------------------------------------------------------------------------------
POSTRETIREMENT BENEFITS OTHER THAN PENSIONS - The Company accounts for
postretirement benefits other than pensions in accordance with Statement of
Financial Accounting Standards No. 106 (FAS 106), Employers' Accounting for
Postretirement Benefits Other Than Pensions. The Company has elected to amortize
its transition obligation at January 1, 1993 over a period of 20 years.
The Company currently provides postretirement medical, dental and vision
benefits to employees who have retired. The postretirement health care plan is
contributory, and retirees' contributions can be adjusted annually for increases
in the cost of providing the benefits. The postretirement health care plan is
being funded in amounts not to exceed the lesser of amounts collected from
customers through rates or amounts allowable under the Internal Revenue Code as
amended from time to time.
Net periodic postretirement benefit cost for the years ended December 31,
1998, 1997 and 1996 included the following components:
(In thousands) 1998 1997 1996
- ----------------------------------------------------------------------
Service cost $ 432 $ 370 $ 406
Interest cost on projected benefit
obligation 1,155 1,270 1,223
Expected return on assets (771) (627) (486)
Amortization of:
Transition obligation 969 968 968
Actuarial gain (505) (399) (312)
- ----------------------------------------------------------------------
Net periodic postretirement
benefit cost $1,280 $1,582 $1,799
- ----------------------------------------==============================
15
<PAGE>
A reconciliation of the funded status of the plan to the amounts recognized in
the Consolidated Balance Sheets as of December 31, 1998 and 1997 is as follows:
(In thousands) 1998 1997
- -----------------------------------------------------------------
Change in benefit obligation:
Net benefit
obligation at beginning of year $(15,496) $(16,065)
Service cost (432) (370)
Interest cost (1,155) (1,270)
Plan participants' contributions 252 252
Actuarial gain (loss) (551) 816
Benefits paid 1,001 1,141
- -----------------------------------------------------------------
Net benefit
obligation at end of year (16,381) (15,496)
- -----------------------------------------------------------------
Change in fair value of assets:
Fair value of assets at beginning of year 8,665 7,075
Actual return on assets 1,463 725
Employer contribution 1,759 2,006
Plan participants' contributions 252 -
Benefits paid (1,001) (1,141)
- -----------------------------------------------------------------
Fair value of assets at end of year 11,138 8,665
- -----------------------------------------------------------------
Accumulated postretirement benefit
obligation in excess of assets (5,243) (6,831)
Unrecognized net transition obligation 13,561 14,530
Unrecognized net actuarial gain (11,506) (11,576)
4th quarter contributions 1,908 1,267
- -----------------------------------------------------------------
Accrued postretirement benefit liability $ (1,280) $ (2,610)
- ---------------------------------------------====================
Amounts recognized in
the balance sheet
consist of:
Accrued benefit cost $ (1,280) $ (2,610)
Additional minimum
liability - -
Intangible asset - -
Accumulated other
comprehensive
income - -
- -----------------------------------------------------------------
Net amount recognized $ (1,280) $ (2,610)
- ---------------------------------------------====================
- --------------------------------------------------------------------------------
16
<PAGE>
NEVADA POWER COMPANY 1998 ANNUAL REPORT
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- --------------------------------------------------------------------------------
The medical cost trend rate assumed for 1999 was 6.25 percent, grading
down to 4.75 percent in 2001 and remaining at that level thereafter. The health
care cost trend rate has a significant effect on the accumulated postretirement
benefit obligation and net periodic cost. A one-percentage-point increase in the
assumed health care cost trend rate would increase the accumulated
postretirement benefit obligation at December 31, 1998 by $769,000 and would
increase the aggregate of the service and interest cost components of net
periodic postretirement benefit cost for 1998 by $229,000. A
one-percentage-point decrease in the assumed health care cost trend rate would
decrease the accumulated postretirement benefit obligation at December 31, 1998
by $689,000 and would decrease the aggregate of the service and interest cost
components of net periodic postretirement benefit cost for 1998 by $214,000. The
weighted-average discount rate used in determining the accumulated
postretirement benefit obligation at December 31, 1998 was 6.75 percent. The
expected rate of return on assets was 8.5 percent in 1998. Assets are primarily
invested in listed stocks, fixed income securities and federal agencies
securities.
5 SHORT-TERM BORROWINGS
- --------------------------------------------------------------------------------
The Company has a $125 million bank revolving credit facility which
expires on November 21, 2002, and pays a facility fee based on the Company's
senior unsecured debt rating. Borrowing rates under the bank line are determined
by both current market rates and the Company's senior unsecured debt rating.
There were $105 million in short-term borrowings outstanding at a weighted
average rate of 6.8% on the $125 million bank line at December 31, 1998 and none
at December 31, 1997.
In April 1998, the Company obtained an additional $50 million bank
revolving credit facility which expires on April 16, 1999 and pays a facility
fee based on the Company's senior unsecured debt rating. Borrowing rates under
the bank line are determined by both current market rates and the Company's
senior unsecured debt rating. There were no short-term borrowings outstanding on
the $50 million bank line at December 31, 1998.
6 CAPITAL STOCK
- -------------------------------------------------------------------------------
The changes in common stock shares for 1996, 1997 and 1998 are as follows:
Shares
- -------------------------------------------------------------------------------
Outstanding, January 1, 1996 47,038,193
Issued under 401(k) Savings Plan 87,889
Issued under Stock Purchase and Dividend Reinvestment Plan 1,659,764
- -------------------------------------------------------------------------------
Outstanding, December 31, 1996 48,785,846
Issued under 401(k) Savings Plan 98,184
Issued under Stock Purchase and Dividend Reinvestment Plan 1,515,716
- -------------------------------------------------------------------------------
Outstanding, December 31, 1997 50,399,746
Issued under 401(k) Savings Plan 65,609
Issued under Stock Purchase and Dividend Reinvestment Plan 799,762
- -------------------------------------------------------------------------------
Outstanding, December 31, 1998 51,265,117
- -------------------------------------------------------------------============
Premium on capital stock increased $20.3 million, $31.8 million and
$35.2 million during 1998, 1997 and 1996, respectively, due to issuances of
common stock. Cash dividends paid per share on common stock were $1.45 during
1998 and $1.60 during 1997 and 1996.
17
<PAGE>
Under the provisions of the 4.70%, 5.20% and 5.40% series cumulative
preferred stock with mandatory sinking funds, the Company is obligated to use
its best efforts to purchase, each year, up to an aggregate of 6,000, 2,000 and
2,000 shares, respectively, at prices not in excess of $20.00 per share. The
obligations are not cumulative. The 5.20% series and 5.40% series are presently
redeemable at the option of the Company at $21.00 per share and the 4.70% series
at $20.25 per share. Completion of the proposed merger requires that all of the
cumulative preferred stock be redeemed.
In October 1990, the Company adopted a Stockholder Rights Plan and
issued through dividend to its common shareholders one stock purchase right for
each outstanding share of common stock. The rights expire in October 2000. The
rights to purchase junior preference shares, common
- --------------------------------------------------------------------------------
NEVADA POWER COMPANY 1998 ANNUAL REPORT
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- --------------------------------------------------------------------------------
shares or shares of a successor corporation are not exercisable unless certain
events occur and are intended to assure fair shareholder treatment in any
takeover of the Company and to guard against abusive takeover tactics. The
current proposed merger with Sierra Pacific Resources will not trigger the
Stockholder Rights Plan.
7 PREFERRED SECURITIES
- -------------------------------------------------------------------------------
On April 2, 1997, NVP Capital I (Trust), a wholly-owned subsidiary of
the Company, issued 4,754,860 8.2% QUIPS at $25 per security. The Company owns
all of the Series A common securities, 147,058 shares issued by the Trust for
$3.7 million. The QUIPS and the common securities represent undivided beneficial
ownership interests in the assets of the Trust, a statutory business trust
formed under the laws of the state of Delaware. The existence of the Trust is
for the sole purpose of issuing the QUIPS and the common securities and using
the proceeds thereof to purchase from the Company its 8.2% Junior Subordinated
Deferrable Interest Debentures (QUIDS) due March 31, 2037, extendible to March
31, 2046 under certain conditions, in a principal amount of $122.6 million. The
sole asset of the Trust is the QUIDS. Holders of the Series A QUIPS are entitled
to receive preferential cumulative cash distributions accruing from the date of
original issuance and payable quarterly in arrears on the last day of March,
June, September and December of each year. The Series A QUIPS are subject to
mandatory redemption, in whole or in part, upon repayment of the Series A QUIDS
at maturity or their earlier redemption in an amount equal to the amount of
related Series A QUIDS maturing or being redeemed. The QUIPS are redeemable at
$25 per preferred security plus accumulated and unpaid distributions thereon to
the date of redemption. The Company's obligations under the guarantee agreement
entered into in connection with the QUIPS when taken together with the Company's
obligation to make interest and other payments on the QUIDS issued to the Trust,
and the Company's obligations under the Indenture pursuant to which the QUIDS
are issued and its obligations under the Declaration, including its liabilities
to pay costs, expenses, debts and liabilities of the Trust, provides a full and
unconditional guarantee by the Company of the Trust's obligations under the
QUIPS. Financial statements of the Trust are consolidated with the Company's.
Separate financial statements are not filed because the Trust is wholly-owned by
the Company and essentially has no independent operations, and the Company's
guarantee of the Trust's obligations is full and unconditional. The $118.9
million in net proceeds to the Company was used for general corporate utility
purposes and the repayment of short-term debt incurred to redeem the Company's
$38 million, 9.9% Redeemable Cumulative Preferred Stock on April 1, 1997.
18
<PAGE>
In October 1998, NVP Capital III (Trust), a wholly-owned subsidiary of
the Company, issued 2,800,000 7 3/4% Cumulative Quarterly Trust Issued Preferred
Securities at $25 per security. The Company owns all the common securities,
86,598 shares issued by the Trust for $2.2 million. The Trust Issued Preferred
Securities and the common securities represent undivided beneficial ownership
interests in the assets of the Trust, a statutory business trust formed under
the laws of the state of Delaware. The existence of the Trust is for the sole
purpose of issuing the Trust Issued Preferred Securities and the common
securities and using the proceeds thereof to purchase from the Company its 7
3/4% Junior Subordinated Deferrable Interest Debentures due September 30, 2038,
extendible to September 30, 2047 under certain conditions, in a principal amount
of $72.2 million. The sole asset of the Trust is the deferrable interest
debentures. Holders of the Trust Issued Preferred Securities are entitled to
receive preferential cumulative cash distributions accruing from the date of
original issuance and payable quarterly in arrears on the last day of March,
June, September and December of each year. The Trust Issued Preferred Securities
are subject to mandatory redemption, in whole or in part, upon repayment of the
deferrable interest debentures at maturity or their earlier redemption in an
amount equal to the amount of related deferrable interest debentures maturing or
being redeemed. The Trust Issued Preferred Securities are redeemable at $25 per
preferred security plus accumulated and unpaid distributions thereon to the date
of redemption. The Company's obligations under the guarantee agreement entered
into in connection with the Trust Issued Preferred Securities when taken
together with the Company's obligation to make interest
- --------------------------------------------------------------------------------
NEVADA POWER COMPANY 1998 ANNUAL REPORT
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- --------------------------------------------------------------------------------
and other payments on the deferrable interest debentures issued to the Trust,
and the Company's obligations under the Indenture pursuant to which the
deferrable interest debentures are issued and its obligations under the
Declaration, including its liabilities to pay costs, expenses, debts and
liabilities of the Trust, provides a full and unconditional guarantee by the
Company of the Trust's obligations under the Trust Issued Preferred Securities.
Financial statements of the Trust are consolidated with the Company's. Separate
financial statements are not filed because the Trust is wholly-owned by the
Company and essentially has no independent operations, and the Company's
guarantee of the Trust's obligations is full and unconditional. The $70 million
in net proceeds to the Company was used for general corporate utility purposes
including the repayment of short term debt.
8 LONG-TERM DEBT
- -------------------------------------------------------------------------------
None of the long-term debt is held by or for the account of the
Company.
The amounts of long-term debt maturities, including sinking fund
requirements, are $50.2 million in 1999, $90.5 million in 2000, $3.6 million in
2001, $20.1 million in 2002 and $4.7 million in 2003, including $4.9 million,
$5.2 million, $3.5 million, $5.0 million and $4.7 million for obligations under
capital leases, respectively.
Generally, electric plant is subject to the first mortgage lien. It is
the Company's intention to meet the sinking fund requirements for its series L
first mortgage bonds by pledging property additions in lieu of cash payments.
The series T, V, W and X first mortgage bonds correspond with respect to their
terms to two series of collateralized pollution control revenue bonds and two
series of industrial development revenue bonds issued by Clark County, Nevada.
19
<PAGE>
The industrial development revenue bonds and pollution control revenue
bonds were issued by various municipal authorities and are guaranteed as to
payment of principal and interest by the Company.
On January 29, 1998, the Company remarketed at fixed rates $141.05
million Clark County, Nevada (Nevada Power Company Project) variable rate
revenue bonds consisting of $76.75 million Series 1995A IDBs due 2030 at 5.6
percent, $44 million Series 1995C IDBs due 2030 at 5.5 percent and $20.3 million
Series 1995D PCRBs with $14 million due 2011 at 5.3 percent and $6.3 million due
2023 at 5.45 percent. On the same date, $13 million Coconino County, Arizona
(Nevada Power Company Project) Series 1995E PCRBs due 2022 were remarketed at a
5.35 percent fixed rate. The Company also remarketed $85 million Series 1995B
Clark County, Nevada (Nevada Power Company Project) variable rate IDBs due 2030
at a 5.9 percent fixed rate on November 24, 1997.
9 FAIR VALUE OF FINANCIAL INSTRUMENTS
- -------------------------------------------------------------------------------
Disclosure by the Company of the estimated fair value of financial
instruments is made in accordance with the requirements of Statement of
Financial Accounting Standards No. 107 (FAS 107), Disclosures about Fair Value
of Financial Instruments. At December 31, 1998 and 1997, the provisions of FAS
107 applies to the Company's long-term debt, QUIPS and 7 3/4% Trust Issued
Preferred Securities.
In accordance with FAS 107, the Company estimates the fair value of its
long-term debt, QUIPS and Trust Issued Preferred Securities based on quoted
market prices for the same or similar issues or on current interest rates
available to the Company for debt with similar terms and maturity. The book
value and estimated fair value of the Company's long-term debt, including
current maturities and sinking fund requirements and excluding obligations under
capital leases, were $859 million and $913 million at December 31, 1998, and
$821 million and $857 million at December 31, 1997, respectively. The book value
and estimated fair value of the QUIPS were $119 million and $122 million at
December 31, 1998, and $119 million and $125 million at December 31, 1997,
respectively. The book value and estimated fair value of the 7 3/4 % Trust
Issued Preferred Securities were $70 million and $71 million at December 31,
1998, respectively. The estimates presented herein are not necessarily
indicative of the amounts that the Company could realize in a current market
exchange. The use of different market assumptions and/or estimation
methodologies may have an effect on the estimated fair value amounts.
- --------------------------------------------------------------------------------
NEVADA POWER COMPANY 1998 ANNUAL REPORT
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- --------------------------------------------------------------------------------
10 COMMITMENTS AND CONTINGENCIES
- --------------------------------------------------------------------------------
LEGAL MATTERS
The Company is involved in litigation arising in the normal course of
business. While the results of such litigation cannot be predicted with
certainty, management, based upon advice of counsel, believes that the final
outcome will not have a material adverse effect on the Company's financial
position, results of operations and net cash flow.
20
<PAGE>
On February 6, 1997, the PUCN issued its opinion and order in the last
phase of the 1995 deferred energy case concerning the prudency of the Company's
fuel and purchased power expenditures during the period June 1993 to May 1995, a
buyout of a coal supply agreement and a credit to customers related to the use
of coal reserves in an unregulated subsidiary company. The PUCN order resulted
in a fourth quarter 1996 charge of $5.5 million, net of tax, for amounts
disallowed by the PUCN. On May 7, 1997, the Company filed a Petition for
Judicial Review in the First District Court in Carson City, Nevada challenging
the PUCN's findings which resulted in disallowances. The Court recently held
oral argument on the appeal and the Company is awaiting a decision.
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 of the
Mohave Generating Station (Mohave) alleging violations of the Clean Air Act
regarding emissions of sulfur dioxide and particulates. The owners believe the
emission limits referenced in the suit are not applicable to Mohave. The owners
previously partnered with the Environmental Protection Agency (EPA) and the
National Park Service on a multi-year study to determine the impacts, if any, of
Mohave emissions on visibility in the Grand Canyon (see Environmental Matters).
The environmental groups want the owners to install pollution control equipment
at an estimated cost of $300 to $350 million. The Company owns a 14 percent
interest in Mohave. The outcome of this action cannot be determined at this
time.
The owners of Mohave, including the Company, will participate in
collaborative talks with groups interested in the plant's future (see
Environmental Matters).
ENVIRONMENTAL MATTERS
The Federal Clean Air Act Amendments of 1990 (Amendments) include
provisions for reduction of emissions of oxides of nitrogen by establishing new
emission limits for coal-fired generating units. This will require the
installation of additional pollution-control technology at some of the Reid
Gardner Station generating units before 2000 at an estimated cost to the Company
of no more than $6 million; $4.4 million has been spent to date. Installation is
scheduled for completion by May 1999.
Also, the United States Congress authorized the EPA to study the
potential impact Mohave may have on visibility in the Grand Canyon area. A draft
report of the study results was released for peer review in September 1998 and a
final report is expected in the first quarter of 1999. The majority owner has
estimated that control costs, if required, could total between $300 and $350
million.
The owners of Mohave, including the Company, will participate in
planned collaborative talks with groups interested in the plant's future,
provided that all stakeholders are willing to participate in a collaborative
effort. The owners' position in these talks could include a commitment to place
sulfur dioxide scrubbers and fine particulate controls on the plant between 2005
and 2008. Interest groups include the local communities, plant employees, the
EPA state jurisdictions and the plant owners. Collaborative talks could begin in
the first quarter of 1999.
21
<PAGE>
In 1991, the EPA published an order requiring the Navajo Generating
Station (Navajo) to install scrubbers to remove 90 percent of sulfur dioxide
emissions beginning in 1997. As an 11.3 percent owner of Navajo, the Company
will be required to fund an estimated $50.9 million for installation of the
scrubbers. The first of three scrubber units was placed in commercial operation
in November 1997, the second scrubber in September 1998, with the last scrubber
unit scheduled to be operational by August 1999. Currently, the project is
approaching 98 percent completion. The Company has spent approximately $45.6
million through December 1998 on the scrubbers' construction. In 1992, the
Company received resource planning approval from the PUCN for its share of the
cost of the scrubbers.
- --------------------------------------------------------------------------------
NEVADA POWER COMPANY 1998 ANNUAL REPORT
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- --------------------------------------------------------------------------------
LEASES
In 1984, the Company sold its administrative headquarters facility,
less furniture and fixtures, for $27 million and entered into a 30-year capital
lease of that facility with five-year renewal options beginning in year 31. The
fixed rental obligation for the first 30 years is $5.1 million per year. Future
cash rental payments as of December 31, 1998, are as follows:
(In thousands)
- ----------------------------------------------------
1999 $ 4,880
2000 6,156
2001 6,156
2002 6,156
2003 6,156
Thereafter 80,433
- ----------------------------------------------------
$109,937
- --------------------------------------------========
The amount of imputed interest necessary to reduce the future cash
rental payments to present value is $60.5 million as of December 31, 1998.
Total interest expense on the lease obligation was $5.6 million and
total amortization of the leased facility was $(194,000) for the year ended
December 31, 1998. The total accumulated amortization of the leased facility on
December 31, 1998, was $9.7 million.
At December 31, 1998, the Company has certain long-term noncancelable
operating lease agreements for which the future minimum lease payments are
immaterial.
FUEL AND PURCHASED POWER OBLIGATIONS
The Company has seven long-term contracts for the purchase of electric
energy and/or capacity. The contracts expire in years ranging from 1999 to 2016.
Total payments under these contracts were $46.3 million, $41.9 million
and $39.7 million in 1998, 1997 and 1996, respectively. The cost of power
obtained under these contracts is included in purchased and interchanged power
expense in the Consolidated Statements of Income.
22
<PAGE>
At December 31, 1998, the estimated future payments for capacity and
energy that the Company is obligated to purchase under these contracts, subject
in part to certain conditions, are as follows:
Accounted for
as Long-Term Accounted for
Executory as Long-Term
(In thousands) Contracts Capital Lease
- ---------------------------------------------------------------------
1999 $ 20,736 $ 11,844
2000 11,338 11,315
2001 - 10,786
2002 - 10,282
2003 - 9,752
Thereafter - 91,652
- ---------------------------------------------------------------------
Total minimum payment $ 32,074 145,631
- -------------------------------------------========
Less amount representing estimated
executory costs included in total
minimum payment (82,544)
- ---------------------------------------------------------------------
Net minimum payments 63,087
Less amount representing interest (21,260)
- ---------------------------------------------------------------------
Present value of net minimum payments $ 41,827
- -------------------------------------------------------------========
One purchase power obligation is accounted for as a capital lease
according to Financial Accounting Standards No. 13 Accounting for Leases. Total
interest expense on the capital lease was $4.2 million, $4.6 million and $5.1
million in 1998, 1997 and 1996, respectively. Total amortization on the capital
lease was $4.5 million, $5.2 million and $5.3 million in 1998, 1997 and 1996,
respectively. Total accumulated amortization was $41.2 million as of December
31, 1998.
The Company has contracted with various coal suppliers to provide coal
to the Reid Gardner Generating Station. The contracts expire in years ranging
from 1999 to 2007.
Costs of approximately $32.1 million, $18.1 million and $25.9 million
were incurred under the long-term coal contracts in 1998, 1997 and 1996,
respectively.
In addition, the Company has long-term transportation arrangements with
railway companies to transport coal to the Reid Gardner Generating Station and a
coal railcar lease. The contracts expire in 1999, 2000 and 2011.
- --------------------------------------------------------------------------------
23
<PAGE>
NEVADA POWER COMPANY 1998 ANNUAL REPORT
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- --------------------------------------------------------------------------------
Costs of approximately $18.3 million, $15.0 million and $18.5 million
were incurred under the coal transportation contracts in 1998, 1997 and 1996,
respectively.
At December 31, 1998 the estimated future payments for purchase and
transportation of coal that the Company is obligated to purchase under these
contracts are as follows:
(In thousands) Coal Transportation Coal Use
- ---------------------------------------------------------------------
1999 $13,278 $ 18,465
2000 12,111 15,956
2001 1,012 16,222
2002 1,012 15,823
2003 1,012 11,360
Thereafter 8,014 40,270
- ---------------------------------------------------------------------
$36,439 $118,096
- -------------------------------------------==========================
CONSTRUCTION
Certain commitments have been incurred at December 31, 1998, in
connection with the 1999 construction budget. Construction expenditures are
estimated at $245 million, excluding AFUDC, for 1999.
11 OTHER DEFERRED CHARGES AND CREDITS
- -------------------------------------------------------------------------------
OTHER DEFERRED CHARGES
At December 31, 1998, other deferred charges include a regulatory asset
of $62.9 million and a deferred tax asset of $15.1. The regulatory asset
represents future revenue to be received from customers due to the flow-through
of tax benefits of temporary differences in prior years and the deferred tax
asset is from temporary differences caused by investment tax credits.
At December 31, 1998, organizational study, early retirement and
severance costs of $3 million are included in other deferred charges as a
regulatory asset and are being amortized over an eight-year period effective
February 1994 as approved in an order issued by the PUCN in 1994. These costs
are a result of the completion of a comprehensive organizational study started
in 1993.
Other deferred charges as of December 31, 1998, also include $47.1
million for deferred federal income taxes on customer advances for construction.
OTHER DEFERRED CREDITS
Other deferred credits as of December 31, 1998, include a regulatory
liability of $15.1 million representing amounts to be refunded to customers in
the future as a result of the Company adopting FAS 109.
24
<PAGE>
12 INTERESTS IN JOINTLY OWNED ELECTRIC UTILITY FACILITIES
- --------------------------------------------------------------------------------
At December 31, 1998, the Company owned the following undivided interests in
jointly owned electric utility facilities:
Company's Share of
- -------------------------------------------------------------------------------
Construction
Percent Owned Plant Accumulated Net Plant Work In
by Company In Service Depreciation In Service Progress
(In thousands)
- -------------------------------------------------------------------------------
FACILITY
Navajo Generating
Station 11.3 $186,483 $ 79,356 $107,127 $13,078
Mohave Generating
Station 14.0 77,950 30,105 47,845 2,171
Reid Gardner Unit
No. 4 Generating
Station 32.2 125,719 43,525 82,194 352
- -------------------------------------------------------------------------------
Total $390,152 $152,986 $237,166 $15,601
- -------------------------------================================================
The amounts above for Navajo and Mohave include the Company's share of
transmission systems and general plant equipment and, in the case of Navajo, the
Company's share of the jointly owned railroad which delivers coal to the plant.
Each participant provides its own financing for all of these jointly owned
facilities. The Company's share of operating expenses for these facilities is
included in the corresponding operating expenses in the Consolidated Statements
of Income.
- --------------------------------------------------------------------------------
NEVADA POWER COMPANY 1998 ANNUAL REPORT
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- --------------------------------------------------------------------------------
13 QUARTERLY FINANCIAL DATA (UNAUDITED)
- --------------------------------------------------------------------------------
(In thousands, except per share amounts)
<TABLE>
<CAPTION>
March 31 June 30 September 30 December 31
- ---------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
1998:
Electric Revenues $165,263 $198,935 $327,776 $181,708
Operating Income 21,263 24,788 76,919 24,307
Net Income 6,936 10,446 61,987 4,304
Earnings Available
for Common Stock 6,892 10,401 61,945 4,261
Earnings per Average
Common Share .14 .20 1.21 .08
Dividends per Common Share .40 .40 .40 .25
Common Stock Price per Share:
High 26 3/4 26 15/16 26 15/16 26 13/16
Low 24 3/8 22 3/16 23 1/16 23 3/16
</TABLE>
- --------------------------------------------------------------------------------
25
<PAGE>
<TABLE>
<CAPTION>
1997:
<S> <C> <C> <C> <C>
Electric Revenues $155,355 $199,970 $284,994 $158,829
Operating Income 19,441 32,297 66,483 18,975
Net Income 8,570 18,870 52,747 3,029
Earnings Available
for Common Stock 7,583 18,823 52,701 2,984
Earnings per Average
Common Share .15 .38 1.06 .06
Dividends per Common Share .40 .40 .40 .40
Common Stock Price per Share:
High 20 25/32 21 1/2 22 3/16 27 5/8
Low 19 3/4 19 3/8 20 5/8 20 5/8
</TABLE>
- --------------------------------------------------------------------------------
The business of the Company is seasonal in nature and it is
management's opinion that comparisons of earnings for the quarters do not give a
true indication of overall trends and changes in the Company's operations.
High and low common stock prices shown are as reported by the Wall
Street Journal as New York Stock Exchange Composite Transactions. The common
stock is also listed on the Pacific Exchange.
Holders of common stock are entitled to dividends as declared by the
Board of Directors, subject to the rights of the cumulative preferred stock and
the preference stock of the Company to quarterly cumulative dividends as
declared by the Board of Directors. The Company has paid quarterly dividends on
its common stock since August 1954.
The Company had 46,693 shareholders of record of common stock at
December 31, 1998.
- --------------------------------------------------------------------------------
NEVADA POWER COMPANY 1998 ANNUAL REPORT
REPORT OF INDEPENDENT AUDITORS
To the Board of Directors and Shareholders of Nevada Power Company:
We have audited the consolidated balance sheets and schedules of
capitalization and long-term debt of Nevada Power Company and its subsidiaries
as of December 31, 1998 and 1997, and the related consolidated statements of
income, comprehensive income, retained earnings and cash flows for each of the
three years in the period ended December 31, 1998. These consolidated financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these consolidated financial
statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly,
in all material respects, the financial position of Nevada Power Company and its
subsidiaries at December 31, 1998 and 1997, and the results of their operations
26
<PAGE>
and their cash flows for each of the three years in the period ended December
31, 1998 in conformity with generally accepted accounting principles.
DELOITTE & TOUCHE LLP
Deloitte & Touche LLP
Las Vegas, Nevada
March 1, 1999
27
<PAGE>
EXHIBIT 99.3
NEVADA POWER COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(In Thousands, Except Per Share Amounts)
(Unaudited)
<TABLE>
<CAPTION>
FOR THE FOR THE
THREE MONTHS SIX MONTHS
ENDED JUNE 30, ENDED JUNE 30,
----------------- ------------------
1999 1998 1999 1998
-------- -------- -------- --------
<S> <C> <C> <C> <C>
ELECTRIC REVENUES .................... $237,937 $198,935 $420,370 $364,198
OPERATING EXPENSES AND TAXES:
Fuel ............................ 35,425 30,848 66,028 57,421
Purchased and interchanged power. 83,781 77,142 137,641 128,197
Deferred energy cost
adjustments, net ............... 6,594 (10,144) 10,383 (12,420)
-------- -------- -------- --------
Net energy costs ............... 125,800 97,846 214,052 173,198
Other production operations ..... 5,180 5,433 10,681 9,902
Other operations ................ 30,397 27,546 56,610 53,229
Maintenance and repairs ......... 14,216 15,225 29,228 27,707
Provision for depreciation ...... 19,827 17,845 39,530 35,556
General taxes ................... 5,811 5,784 11,189 11,153
Federal income taxes ............ 5,793 4,468 7,206 7,402
-------- -------- -------- --------
207,024 174,147 368,496 318,147
-------- -------- -------- --------
OPERATING INCOME ..................... 30,913 24,788 51,874 46,051
-------- -------- -------- --------
OTHER INCOME (EXPENSES):
Allowance for other funds used
during construction ............ 1,830 2,714 4,083 4,913
Miscellaneous, net .............. (844) (449) (1,163) (1,042)
-------- -------- -------- --------
986 2,265 2,920 3,871
-------- -------- -------- --------
INCOME BEFORE INTEREST DEDUCTIONS .... 31,899 27,053 54,794 49,922
-------- -------- -------- --------
INTEREST DEDUCTIONS:
Interest on long-term debt ...... 16,761 14,417 31,466 28,525
Other interest .................. 1,329 1,273 3,340 1,839
Allowance for borrowed funds used
during construction ............ (1,738) (1,520) (3,835) (2,698)
-------- -------- -------- --------
16,352 14,170 30,971 27,666
-------- -------- -------- --------
Distribution requirements
on company-obligated mandatorily
redeemable preferred securities
of subsidiary trust ............ 3,793 2,437 7,586 4,874
-------- -------- -------- --------
NET INCOME ........................... 11,754 10,446 16,237 17,382
DIVIDEND REQUIREMENTS ON PREFERRED
STOCK ............................... 42 45 84 89
-------- -------- -------- --------
EARNINGS AVAILABLE FOR COMMON STOCK .. $ 11,712 $ 10,401 $ 16,153 $ 17,293
======== ======== ======== ========
WEIGHTED AVERAGE COMMON SHARES
OUTSTANDING ......................... 51,265 50,920 51,265 50,751
======== ======== ======== ========
EARNINGS PER AVERAGE COMMON SHARE .... $ .23 $ .20 $ .32 $ .34
======== ======== ======== ========
DIVIDENDS PER COMMON SHARE ........... $ .25 $ .40 $ .50 $ .80
======== ======== ======== ========
</TABLE>
See Notes to Condensed Consolidated Financial Statements.
1
<PAGE>
NEVADA POWER COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
(Unaudited)
<TABLE>
<CAPTION>
June 30, December 31,
1999 1998
(In Thousands)
--------------------------
<S> <C> <C>
ELECTRIC PLANT:
Original cost ..................................... $2,784,359 $2,628,934
Less accumulated depreciation ..................... 748,814 708,791
---------- ----------
Net plant in service ............................ 2,035,545 1,920,143
Construction work in progress ..................... 170,864 213,365
Other plant, net .................................. 63,985 66,378
---------- ----------
2,270,394 2,199,886
---------- ----------
INVESTMENTS ......................................... 26,076 24,483
---------- ----------
CURRENT ASSETS:
Cash and temporary cash investments ............... 335 1,770
Customer receivables .............................. 123,051 81,288
Other receivables ................................. 15,819 16,010
Fuel stock and materials and supplies ............. 41,883 39,606
Deferred energy costs ............................. 57,897 62,489
Prepayments ....................................... 4,347 7,787
---------- ----------
243,332 208,950
---------- ----------
DEFERRED CHARGES .................................... 174,524 174,505
---------- ----------
$2,714,326 $2,607,824
========== ==========
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common shareholders' equity:
Common stock, 51,265,117 and 51,265,117
shares issued and outstanding, respectively .... $ 54,182 $ 54,066
Premium and unamortized expense on capital stock 683,017 683,156
Retained earnings ............................... 117,334 126,814
---------- ----------
854,533 864,036
---------- ----------
Cumulative preferred stock ........................ - 3,265
---------- ----------
Company-obligated mandatorily redeemable preferred
securities of the Company's subsidiary trust,
NVP Capital I, holding solely
$122.6 million principal amount of 8.2% junior
subordinated debentures of
the Company, due 2037 ............................ 118,872 118,872
Company-obligated mandatorily redeemable preferred
securities of the Company's subsidiary trust, NVP
Capital III, holding solely $72.2 million principal
amount of 7 3/4% junior subordinated debentures of
the Company, due 2038 ............................ 70,000 70,000
---------- ----------
188,872 188,872
---------- ----------
Long-term debt .................................... 1,028,977 900,227
---------- ----------
2,072,382 1,956,400
---------- ----------
CURRENT LIABILITIES:
Notes Payable ..................................... 93,987 105,000
Current maturities and sinking fund requirements .. 53,416 50,380
Accounts payable .................................. 71,261 83,439
Accrued taxes ..................................... 5,268 -
Accrued interest .................................. 9,603 7,829
Deferred taxes on deferred energy costs ........... 20,264 21,871
Customers' service deposits and other ............. 41,364 41,427
---------- ----------
295,163 309,946
---------- ----------
DEFERRED CREDITS AND OTHER LIABILITIES:
Deferred investment tax credits ................... 27,353 28,083
Deferred taxes on income .......................... 236,132 231,610
Customers' advances for construction and other .... 83,296 81,785
---------- ----------
346,781 341,478
---------- ----------
$2,714,326 $2,607,824
========== ==========
</TABLE>
See Notes to Condensed Consolidated Financial Statements.
2
<PAGE>
NEVADA POWER COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
<TABLE>
<CAPTION>
FOR THE SIX MONTHS
ENDED JUNE 30,
--------------------
1999 1998
-------- --------
(In Thousands)
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income .......................................... $ 16,237 $ 17,382
Adjustments to reconcile net income to net cash
provided by operating activities-
Depreciation and amortization ...................... 46,870 41,984
Deferred income taxes and investment tax credits ... (2,206) 7,040
Allowance for other funds used during construction . (4,083) (4,913)
Changes in-
Receivables ........................................ (41,577) (22,661)
Fuel stock and materials and supplies .............. (2,278) 2,835
Accounts payable and other current liabilities ..... (12,549) 6,768
Deferred energy costs .............................. 4,783 (13,873)
Accrued taxes and interest ......................... 9,476 1,022
Other assets and liabilities ........................ 2,094 (4,027)
-------- --------
Net cash provided by operating activities ......... 16,767 31,557
-------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Construction expenditures and gross additions ....... (108,840) (114,834)
Investment in subsidiaries and other ................ (1,945) (1,611)
-------- --------
Net cash used in investing activities ............. (110,785) (116,445)
-------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Issuance of capital stock ........................... - 16,058
Issuance of long-term debt .......................... 130,000 -
Deposit of funds held in trust ...................... - (1,049)
Withdrawal of funds held in trust ................... 10 -
Retirement of long-term debt ........................ (2,402) (17,189)
Retirement of preferred stock ....................... (49) (80)
Change in short-term borrowing ...................... (11,012) 125,298
Cash dividends ...................................... (25,725) (40,563)
Other financing activities .......................... 1,761 2,268
-------- --------
Net cash provided by financing activities ......... 92,583 84,743
-------- --------
CASH AND TEMPORARY CASH INVESTMENTS:
Net decrease during the period ...................... (1,435) (145)
Beginning of period ................................. 1,770 720
-------- --------
End of period ....................................... $ 335 $ 575
======== ========
CASH PAID DURING THE PERIOD FOR:
Interest, net of amounts capitalized ................ $ 39,521 $ 36,500
======== ========
Income taxes ........................................ $ 1,000 $ -
======== ========
</TABLE>
See Notes to Condensed Consolidated Financial Statements.
3
<PAGE>
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The condensed consolidated financial statements included herein have
been prepared by the registrant, pursuant to the rules and regulations of the
Securities and Exchange Commission (SEC), and reflect all adjustments which, in
the opinion of management are necessary for a fair presentation and are of a
normally recurring nature. Certain information and footnote disclosures have
been condensed in accordance with generally accepted accounting principles and
pursuant to such rules and regulations. The registrant believes that the
disclosures are adequate to make the information presented not misleading. It is
suggested that these condensed consolidated financial statements and notes
thereto be read in conjunction with the financial statements and the notes
thereto included in the registrant's latest annual report. Certain prior period
amounts have been reclassified, with no effect on income or common shareholders'
equity, to conform to the current period presentation.
(1) CONSOLIDATION POLICY:
The condensed consolidated financial statements include the accounts of
Nevada Power Company (Company) and its wholly-owned subsidiaries, NVP Capital I
and III. All significant intercompany transactions and balances have been
eliminated in consolidation.
(2) RECENTLY ISSUED ACCOUNTING STANDARDS:
The Financial Accounting Standards Board recently issued Statement of
Financial Accounting Standards No. 133 (FAS 133), Accounting for Derivative
Instruments and Hedging Activities, which is effective for financial statements
for all fiscal quarters of all fiscal years beginning after June 15, 2000. FAS
133 establishes accounting and reporting standards for derivative instruments,
including certain derivative instruments embedded in other contracts and for
hedging activities. It requires that an entity recognize all derivatives as
either assets or liabilities in the statement of financial position and measure
those instruments at fair value. The Company is currently evaluating the effect
of the adoption of FAS 133 on the Company's consolidated financial statements
and disclosures.
(3) DEFERRED ENERGY COST ADJUSTMENT:
The deferred energy accounting adjustment used by the Company to
recover fuel and purchased power costs will be repealed on October 1, 1999 in
accordance with Senate Bill 438 (SB438) which was signed into Nevada law in June
1999. SB438 allows the Company to make a final deferred energy filing prior to
October 1, 1999, after which the rate will be capped for a period of three years
from the beginning of competition in Nevada until March 1, 2003. The Company
discontinued using the deferred energy mechanism, which defers the difference
between the current cost of fuel plus net purchased power and base energy costs
beginning in June 1999 and filed a $44.3 million deferred energy filing in July
1999.
4
<PAGE>
(4) FEDERAL INCOME TAXES:
For interim financial reporting purposes, the Company reflects in the
computation of the federal income tax provision liberalized depreciation based
upon the expected annual percentage relationship of book and tax depreciation
and reflects the allowance for funds used during construction on an actual
basis. The total federal income tax expense as set forth in the accompanying
consolidated statements of income results in an effective federal income tax
rate different than the statutory federal income tax rate. The table below shows
the effects of those transactions that created this difference.
THREE MONTHS SIX MONTHS
ENDED JUNE 30, ENDED JUNE 30,
---------------- ----------------
1999 1998 1999 1998
------- ------- ------- -------
(In Thousands) (In Thousands)
Federal income tax at statutory rate .$ 6,349 $ 5,661 $ 8,800 $ 9,432
Investment tax credit amortization ... (365) (365) (730) (730)
Other ................................ 403 433 836 865
------- ------- ------- -------
Recorded federal income taxes ........$ 6,387 $ 5,729 $ 8,906 $ 9,567
======= ======= ======= =======
Federal income taxes included in-
Operating expenses .................$ 5,793 $ 4,468 $ 7,206 $ 7,402
Other income, net .................. 594 1,261 1,700 2,165
------- ------- ------- -------
Recorded federal income taxes ........$ 6,387 $ 5,729 $ 8,906 $ 9,567
======= ======= ======= =======
(5) COMMITMENTS AND CONTINGENCIES:
On February 6, 1997, the Public Utilities Commission of Nevada (PUCN)
issued its opinion and order in the last phase of the 1995 deferred energy case
concerning the prudency of the Company's fuel and purchased power expenditures
during the period June 1993 to May 1995, a buyout of a coal supply agreement and
a credit to customers related to the use of coal reserves in an unregulated
subsidiary company. The PUCN order resulted in a fourth quarter 1996 charge of
$5.5 million, net of tax, for amounts disallowed by the PUCN. On May 7, 1997,
the Company filed a Petition for Judicial Review in the First District Court in
Carson City, Nevada, challenging the PUCN's findings that resulted in
disallowances. In May 1999, the First District Court issued a decision which
determined the PUCN's finding was erroneous and remanded the matter to the PUCN
to reconsider its ruling consistent with the court's determination. In June
1999, the PUCN filed an additional motion with the court arguing that the error
was irrelevant. The court denied the PUCN's motion. The Company cannot determine
the outcome of this matter at this time.
The Grand Canyon Trust and Sierra Club filed suit in the U.S. District
Court of Nevada in February 1998, against the owners of the Mohave Generating
Station (Mohave). The Company owns a 14 percent interest in Mohave. The lawsuit
alleges that Mohave has violated the Clean Air Act and Nevada regulations
regarding emissions of sulfur dioxide and particulate matter. Later in 1998, an
additional plaintiff, National Parks and Conservation Association, was added to
the proceedings.
Mohave's owners and the plaintiffs have been discussing settlement of
the suit. If settled, a consent decree could be signed during the third quarter
of 1999. The consent decree could address the installation of additional
pollution controls.
The Clean Air Act Amendments of 1990 directed the Environmental
Protection Agency (EPA) to determine the impact of Mohave's air emissions on
visibility in the Grand Canyon National Park. The study report, released in
March 1999, acknowledges that Mohave's emissions are transported to the Grand
Canyon. On June 17,1999, EPA published an Advance Notice of Proposed Rulemaking
(ANPR) which presents a summary of the visibility study results. The ANPR also
asks for additional information that should be considered in
5
<PAGE>
determining whether visibility impairment at the Grand Canyon can be reasonably
attributed to Mohave, and if so, what, if any, pollution controls should be
required. The Company believes the outcome of the ANPR will be greatly
influenced by the outcome of the lawsuit described above. The final rulemaking
could be consistent with a lawsuit settlement.
The Clean Air Act also included provisions for reduction of emissions
of oxides of nitrogen by establishing new emission limits for coal-fired
electric generating units. Installation of additional pollution controls was
required on some of the Reid Gardner Station generating units prior to January
1, 2000. Installation was completed during the second quarter of 1999. The total
costs were $8.9 million.
In May 1997, the Nevada Division of Environmental Protection (NDEP)
ordered the Company to submit a plan to eliminate the discharge of Reid Gardner
Station wastewater to ground water. The Order also required a hydrological
assessment of groundwater impacts in the area. In June 1999, NDEP determined
that all wastewater ponds have degraded groundwater quality. NDEP has published
a notice to issue a discharge permit to Reid Gardner Station. The Company
expects the permit to require all wastewater ponds be closed or lined with
impermeable liners over the next 10 years. The preliminary cost is estimated to
be $19 million.
In 1991, the EPA published an order requiring the Navajo Generating
Station (Navajo) to install scrubbers to remove 90 percent of sulfur dioxide
emissions beginning in 1997. As an 11.3 percent owner of Navajo, the Company
will be required to fund $48 million for installation of the scrubbers. The
first of three scrubber units was placed in commercial operation in November
1997, the second scrubber in September 1998, with the last scrubber unit
scheduled to be operational by August 1999. Currently, the project is
approaching 100 percent completion. The Company has spent approximately $46.3
million through May 1999 on the scrubbers' construction. In 1992, the Company
received resource planning approval from the PUCN for its share of the cost of
the scrubbers.
(6) MERGER; DIVIDEND POLICY:
On April 30, 1998, the Company and Sierra Pacific Resources announced
that their boards of directors unanimously approved an agreement providing for a
proposed merger of equals combination with stock and cash consideration. In
conjunction with the proposed merger and as indicated at the time of the public
announcement of the proposed merger, beginning with the November 1998 dividend,
the Company's Board of Directors has adopted the expected combined company
initial annual dividend rate of $1.00 per share. For further information
regarding the proposed merger please refer to the Company's Form 8-K filed with
the SEC on April 30, 1998.
At special stockholder meetings held in October 1998, stockholders of
both companies voted to approve the proposed merger. On December 31, 1998, the
PUCN approved the proposed merger subject to conditions regarding the
divestiture of the two companies' generating plants, filing of general rate
cases, merger costs and several other issues. On January 29, 1999, the PUCN
clarified portions of the order approving the proposed merger. On April 12,
1999, the PUCN issued an order to appear and show cause to determine if the
companies are in compliance with their January 4, 1999 compliance order Docket
No. 98-7023 requiring, among other things, the companies to file a divestiture
plan. The show cause hearings occurred during May and June 1999. Both companies
submitted a joint divestiture plan to the PUCN on April 15, 1999 describing
plans to sell the companies' generating units. On June 11, 1999, the PUCN
unanimously approved a stipulation between the companies, the PUCN staff and the
Utility Consumer Advocate which clears the way for completion of the proposed
merger. As part of the stipulation, the companies must re-file the divestiture
plan and file the final Independent System Administrator (ISA) proposal with the
PUCN and the Federal Energy Regulatory Commission (FERC). These filings took
place in June 1999. Upon
6
<PAGE>
selling the generating units, both companies can determine how they will use the
proceeds of the sales, up to the book value of the plants. Any after-tax gains
above book value will be used to offset stranded costs, as determined by the
PUCN. Any remaining gains can be used to offset goodwill. After-tax gains may
not be sufficient to cover generation-related goodwill. However, if the combined
company demonstrates that the divestiture "resulted in a market for generation
services that produced market prices that are lower than what could have been
achieved otherwise, the combined company may include in the general rate case a
request to recover goodwill." The Company expects that the generation sales will
be completed by late-2000. Jointly-owned generation sales should be completed by
late-2001. Both companies are required to file a compliance plan filing in 1999
that would provide certain information to the PUCN including bundled revenue
requirement based on current costs and "unbundle" rates, i.e. break them into
generation, transmission and distribution components. The merged company would
also be required to file a general rate case three years after the start of
retail competition in the state of Nevada that would give the merged company the
opportunity to recover costs of the merger, provided the merged company can
demonstrate that merger savings are sufficient to cover merger costs. Merger
costs are to be split among the non-competitive, potentially competitive and
unregulated services or businesses. An opportunity to recover the non-
competitive portion of the merger costs will be addressed in the rate case that
follows the start of competition in Nevada. The burden is on the merged company
to prove that merger savings are sufficient to cover merger costs. The merged
company will also have the opportunity to recover goodwill in the same
proceeding. The companies filed with the FERC a joint merger application on
October 2, 1998 that was approved on April 14, 1999. The Department of Justice
approved the proposed merger on April 16, 1999. The SEC comment period expired
on June 8, 1999 with only one comment received which was later rescinded. On
June 26, 1999, election forms were mailed to shareholders asking them to
indicate their preference to hold or sell their shares. The election period
ended on Wednesday, July 21, 1999. The proposed merger is expected to be
completed by the end of July 1999.
(7) REDEMPTION OF PREFERRED STOCK:
The Company redeemed the 4.7%, 5.2% and 5.4% Series Redeemable
Cumulative Preferred Stock on July 23, 1999. The total par value and premium was
$3.5 million and was paid in accordance with the merger agreement with Sierra
Pacific Resources.
7
<PAGE>
EXHIBIT 99.4
INDEPENDENT AUDITORS' REPORT
To the Board of Directors and Stockholders of
Sierra Pacific Resources
Reno, Nevada
We have audited the accompanying consolidated balance sheets and consolidated
statements of capitalization of Sierra Pacific Resources and subsidiaries as of
December 31, 1998 and 1997, and the related consolidated statements of income,
retained earnings, and cash flows for each of the three years in the period
ended December 31, 1998. These financial statements are the responsibility of
the Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all
material respects, the financial position of the Company as of December 31, 1998
and 1997, and the results of its operations and its cash flows for each of the
three years in the period ended December 31, 1998 in conformity with generally
accepted accounting principles.
DELOITTE & TOUCHE LLP
Reno, Nevada
January 29, 1999
(February 12, 1999 as to Notes 1 and 5)
1
<PAGE>
SIERRA PACIFIC RESOURCES
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
<TABLE>
<CAPTION>
December 31,
ASSETS 1998 1997
------ ---- ----
<S> <C> <C>
Utility Plant, at Original Cost:
Plant in service $2,348,996 $2,063,269
Less accumulated provision for depreciation 727,624 664,490
---------- ----------
1,621,372 1,398,779
Construction work in progress 55,670 202,036
---------- ----------
1,677,042 1,600,815
---------- ----------
Investments in subsidiaries and other property, net 59,258 49,614
---------- ----------
Current Assets:
Cash and cash equivalents 17,674 8,901
Accounts receivable less provision for
uncollectible accounts: 1998-$3,461; 1997-$1,704 114,870 103,356
Materials, supplies and fuel, at average cost 25,776 25,255
Other 3,048 2,885
---------- ----------
161,368 140,397
---------- ----------
Deferred Charges:
Regulatory tax asset 65,619 66,563
Other regulatory assets 61,675 63,476
Other 16,434 15,015
---------- ----------
143,728 145,054
---------- ----------
$2,041,396 $1,935,880
========== ==========
CAPITALIZATION AND LIABILITIES
------------------------------
Capitalization:
Common shareholders' equity $673,432 $633,394
Preferred stock 73,115 73,115
Preferred stock subject to mandatory redemption:
SPPC-obligated mandatorily redeemable preferred securities
of SPPC's subsidiary trust, Sierra Pacific Power Capital I, holding
solely $50 million principal amount of 8.6% junior
subordinated debentures of the SPPC, due 2036 48,500 48,500
Long-term debt 616,754 627,224
---------- ----------
1,411,801 1,382,233
---------- ----------
Current Liabilities:
Short-term borrowings 105,000 75,000
Current maturities of long-term debt 40,585 10,566
Accounts payable 60,128 62,105
Accrued interest 7,885 6,910
Dividends declared 11,465 10,941
Accrued salaries and benefits 12,131 14,978
Other current liabilities 28,059 19,382
---------- ----------
265,253 199,882
---------- ----------
Deferred Credits:
Accumulated deferred federal income taxes 168,602 165,076
Accumulated deferred investment tax credits 37,944 39,873
Regulatory tax liability 38,939 40,767
Customer advances for construction 34,961 38,478
Accrued retirement benefits 42,560 37,456
Other 41,336 32,115
---------- ----------
364,342 353,765
---------- ----------
Commitments and Contingencies (Note 2 and 16) $2,041,396 $1,935,880
========== ==========
</TABLE>
The accompanying notes are an integral part of the financial statements.
2
<PAGE>
SIERRA PACIFIC RESOURCES
CONSOLIDATED STATEMENTS OF INCOME
(Dollars in Thousands, Except Per Share Amounts)
<TABLE>
<CAPTION>
Year Ended December 31,
1998 1997 1996
---- ---- ----
<S> <C> <C> <C>
Operating Revenues:
Electric $585,657 $540,346 $507,004
Gas 99,532 70,675 67,376
Water 49,143 46,519 45,344
Other 7,509 5,703 7,987
-------- -------- --------
741,841 663,243 627,711
-------- -------- --------
Operating Expenses:
Operation:
Purchased power 156,970 130,612 122,272
Fuel for power generation 114,803 100,861 102,601
Gas purchased for resale 65,430 38,127 33,899
Deferral of energy costs-net - 8 (1,736)
Other 127,335 129,493 128,430
Maintenance 22,266 23,387 20,672
Depreciation and Amortization 69,435 64,117 58,118
Taxes:
Income taxes 41,815 38,667 35,626
Other than income 19,666 19,344 18,951
-------- -------- --------
617,720 544,616 518,833
-------- -------- --------
Operating Income 124,121 118,627 108,878
-------- -------- --------
Other Income:
Allowance for other funds used during construction 3,797 5,723 5,231
Other income -net 674 1,261 1,289
-------- -------- --------
4,471 6,984 6,520
-------- -------- --------
Total Income Before Interest Charges 128,592 125,611 115,398
-------- -------- --------
Interest Charges:
Long-term debt 40,396 41,738 39,770
Other 7,659 4,583 4,624
Allowance for borrowed funds used during
construction and Capitalized interest (6,414) (4,785) (3,924)
-------- -------- --------
41,641 41,536 40,470
-------- -------- --------
Income before obligated mandatorily redeemable
preferred securities 86,951 84,075 74,928
Preferred dividend requirements of SPPC-obligated
mandatorily redeemable preferred securities (4,171) (4,171) (1,749)
-------- -------- --------
Income before preferred dividend requirements of subsidiary 82,780 79,904 73,179
Preferred dividend requirements of subsidiary (5,459) (5,459) (6,300)
-------- -------- --------
Net Income $77,321 $74,445 $66,879
======== ======== ========
Net Income Per Share - Basic $ 2.50 $ 2.41 $ 2.19
- Diluted $ 2.49 $ 2.40 $ 2.19
Weighted Average Shares of Common Stock Outstanding 30,955,154 30,879,696 30,495,224
Annual Dividends Paid Per Share of Common Stock $ 1.285 $ 1.225 $ 1.165
</TABLE>
The accompanying notes are an integral part of the financial statements.
3
<PAGE>
SIERRA PACIFIC RESOURCES
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(Dollars in Thousands)
<TABLE>
<CAPTION>
Year Ended December 31,
1998 1997 1996
---- ---- ----
<S> <C> <C> <C>
Retained Earnings at Beginning of Year $147,871 $111,741 $80,845
Income Before Preferred Dividends 82,780 79,904 73,179
Stock Issuance Costs - (7) (268)
Dividends Declared:
Preferred stock of subsidiary (5,459) (5,459) (5,879)
Common stock (40,285) (38,308) (36,136)
-------- -------- --------
Retained Earnings at End of Year $184,907 $147,871 $111,741
======== ======== ========
</TABLE>
The accompanying notes are an integral part of the financial statements.
4
<PAGE>
SIERRA PACIFIC RESOURCES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
<TABLE>
<CAPTION>
Year Ended December 31,
1998 1997 1996
---- ---- ----
<S> <C> <C> <C>
Cash Flows From Operating Activities:
------------------------------------
Income before preferred dividends $82,780 $79,904 $73,179
Non-cash items included in income:
Depreciation and amortization 69,435 64,117 58,118
Deferred taxes and investment tax credits 713 (2,083) 2,983
AFUDC and capitalized interest (10,211) (10,508) (9,155)
Deferred energy costs - 8 (1,736)
Early Retirement and severance Amortization 4,177 4,551 7,877
Merger Costs - (50) 1,909
Other non-cash 2,400 (2,110) 2,803
Changes in certain assets and liabilities:
Accounts receivable (15,897) (8,620) (2,559)
Materials, supplies and fuel (521) 2,331 2,869
Other current assets (163) 1,587 (1,934)
Accounts payable (1,977) 8,301 (38,081)
Other current liabilities 6,805 1,282 11,373
Other - net 7,599 8,315 2,802
------- ------- -------
Net Cash Flows From Operating Activities 145,140 147,025 110,448
------- ------- -------
Cash Flows From Investing Activities:
------------------------------------
Additions to utility plant (183,384) (147,801) (203,109)
Non-cash charges to utility plant 10,587 10,814 9,474
Customer refunds for construction (3,517) (951) (739)
Contributions in aid of construction 37,216 26,321 15,272
------- ------- -------
Net cash used for utility plant (139,098) (111,617) (179,102)
Proceeds from sale of other assets - - 4
(Investments in) disposal of subsidiaries and
other property - net (5,200) (5,637) 1,261
------- ------- -------
Net Cash Used in Investing Activities (144,298) (117,254) (177,837)
------- ------- -------
Cash Flows From Financing Activities:
------------------------------------
Increase (Decrease) in short-term borrowings 30,646 40,583 (16,059)
Proceeds from issuance of long-term debt 35,000 - 80,041
Retirement of long-term debt (15,568) (25,529) (10,539)
Decrease in funds held in trust - - 9,175
Proceeds from SPPC-obligated mandatorily
redeemable preferred securities - - 48,500
Retirement of preferred stock - - (20,400)
Sale of common stock 3,074 2,405 19,414
Expenses of external financing - - (5)
Dividends paid (45,221) (43,278) (42,032)
------- ------- -------
Net Cash From (Used in) Financing Activities 7,931 (25,819) 68,095
------- ------- -------
Net Increase in Cash and
Cash Equivalents 8,773 3,952 706
Beginning Balance in Cash and Cash Equivalents 8,901 4,949 4,243
------- ------- -------
Ending Balance in Cash and Cash Equivalents $17,674 $ 8,901 $4,949
======= ======= =======
Supplemental Disclosures of Cash Flow Information:
-------------------------------------------------
Cash Paid During Year For:
Interest $49,922 $49,108 $44,106
Income taxes $43,165 $39,472 $39,234
</TABLE>
The accompanying notes are an integral part of the financial statements.
5
<PAGE>
CONSOLIDATED STATEMENTS OF CAPITALIZATION
(Dollars in Thousands)
<TABLE>
<CAPTION>
December 31,
1998 1997
---- ----
Common Shareholders' Equity:
- ---------------------------
<S> <C> <C>
Common stock, $1.00 par value, authorized 90 million;
issued and outstanding 1998, 31,009,364 shares; 1997, 30,915,402 shares $ 31,009 $ 30,915
Additional paid-in capital 457,516 454,608
Retained earnings 184,907 147,871
---------- ----------
Total Common Shareholders' Equity 673,432 633,394
---------- ----------
Preferred Stock of Subsidiary:
- ------------------------------
Not subject to mandatory redemption:
$50 par value:
Series A; $2.44 dividend 4,025 4,025
Series B; $2.36 dividend 4,100 4,100
Series C; $3.90 dividend 14,990 14,990
$25 stated value:
Class A Series 1; $1.95 dividend 50,000 50,000
---------- ----------
Subtotal 73,115 73,115
SPPC-obligated mandatorily redeemable preferred securities of SPPC's subsidiary
trust, Sierra Pacific Power Capital I, holding solely $50 million
principal amount of 8.60% junior subordinated debentures of the SPPC, due 2036 48,500 48,500
---------- ----------
Total preferred stock 121,615 121,615
---------- ----------
Long-Term Debt:
- --------------
First Mortgage Bonds:
Unamortized bond premium and discount, net (831) (867)
Debt Secured by First Mortgage Bonds:
2.00% Series Z due 2004 93 114
2.00% Series O due 2011 1,497 1,618
6.35% Series FF due 2012 1,000 1,000
6.55% Series AA due 2013 39,500 39,500
6.30% Series DD due 2014 45,000 45,000
6.65% Series HH due 2017 75,000 75,000
6.65% Series BB due 2017 17,500 17,500
6.55% Series GG due 2020 20,000 20,000
6.30% Series EE due 2022 10,250 10,250
6.95% to 8.61% Series A MTN due 2022 110,000 115,000
7.10% and 7.14% Series B MTN due 2023 58,000 58,000
6.83% and 6.86% Series C MTN due 1999 - 30,000
6.62% to 6.83% Series C MTN due 2006 50,000 50,000
5.90% Series JJ due 2023 9,800 9,800
5.90% Series KK due 2023 30,000 30,000
5.00% Series Y due 2024 3,207 3,275
6.70% Series II due 2032 21,200 21,200
5.47% Series D MTN due 2001 17,000 -
5.50% Series D MTN due 2003 5,000 -
5.59% Series D MTN due 2003 13,000 -
---------- ---------
Subtotal, excluding current portion 527,047 527,257
Variable Rate Note:
Water Facilities Note maturing 2020 80,000 80,000
Senior Notes 10,000 20,000
Other, excluding current portion 538 834
Total Long-Term Debt 616,754 627,224
---------- ----------
TOTAL CAPITALIZATION $1,411,801 $1,382,233
========== ==========
</TABLE>
The accompanying notes are an integral part of the financial statements.
6
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
------------------------------------------
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
- ---------------------------------------------------
The significant accounting policies for both utility and non-utility
operations are as follows:
General
- -------
The consolidated financial statements include the accounts of Sierra
Pacific Resources (SPR) and its wholly-owned subsidiaries, Sierra Pacific Power
Company (SPPC), Tuscarora Gas Pipeline Company (TGPC), Lands of Sierra, Inc.
(LOS), Sierra Gas Holding Company (SGHC, formerly Sierra Energy Company), Sierra
Energy Company dba ethree (eothree), Sierra Pacific Energy Company (SPE), Sierra
Water Development Company (SWDC) and SPR Media Group (SMG). All significant
intercompany balances and intercompany transactions have been eliminated in
consolidation.
SPPC, SPR's principal subsidiary, is a regulated public utility engaged
principally in the generation, purchase, transmission, distribution, and sale of
electric energy. It provides electricity to approximately 294,000 customers in a
50,000 square mile territory including western, central, and northeastern
Nevada, including the cities of Reno, Sparks, Carson City and Elko, and a
portion of eastern California, including the Lake Tahoe area. SPPC also provides
water and gas service in the cities of Reno and Sparks, Nevada, and environs. In
1995, SPPC formed two subsidiaries for the specific purpose of forming a
partnership to operate the Pinon Pine gasifier facility. These subsidiaries are
Pinon Pine Corporation and Pinon Pine Investment Company. In February 1999, SPPC
purchased GPSF-B, which owns the portion of the gasifier facility which was not
already owned by SPPC. They are consolidated into the financial statements of
SPPC, with all significant intercompany transactions eliminated. On July 29,
1996, SPPC formed a wholly owned subsidiary, Sierra Pacific Power Capital I
(Trust), for the purpose of completing a public offering of trust originated
preferred securities. Refer to Note 7 of SPR's consolidated financial statements
for the stock issuance and Note 5 for the Pinon Pine Power Project.
SPPC maintains its accounts for electric and gas operations in
accordance with the Uniform System of Accounts prescribed by the Federal Energy
Regulatory Commission (FERC) and for water operations in accordance with the
Uniform System of Accounts prescribed by the National Association of Regulatory
Utility Commissioners.
TGPC is a partner in a joint venture, which developed, constructed, and
operates a natural gas pipeline serving the expanding gas market in the Reno
area and certain northeastern California markets. TGPC accounts for its interest
in Tuscarora Gas Transmission Company (TGTC) under the equity method. Organized
in October 1996, ethree provides comprehensive energy services in commercial and
industrial markets on a regional basis. LOS is primarily engaged in real estate
management. In 1997, SPR formed SPE, which operates under the brand name of
Simple Choice and markets a package of products and services.
In November 1996, the SPR board of directors approved an investment, as
a limited partner, in an energy technology venture capital partnership to gain
access to new technologies that could affect SPR and its subsidiaries. This
partnership will invest in energy companies offering technologies of strategic
advantage to its partners. SPR's initial $250,000 payment on this investment was
made in November 1996. Additional investments of $750,000 and $1,250,000 were
made in 1997 and 1998, respectively. The remaining balance of SPR's commitment,
$4 million, will be drawn as funds are needed by the partnership over the next
three years. The term of this partnership is ten years with two extensions of up
to two years each. Gains and losses will be allocated 79% to the limited
partners and 21% to the general partner. Gains and losses will be allocated
among the limited partners based on their contributions. SPR, as a limited
partner, is entitled to 10.4%. This investment is accounted for on the cost
basis.
The preparation of consolidated financial statements in conformity with
generally accepted accounting principles requires management to make estimates
and assumptions that affect the reported amounts of certain assets and
liabilities. These estimates and assumptions also affect the disclosure of
contingent assets and liabilities at the date of the financial statements and
the reported amounts of certain revenues and expenses during the reporting
period. Actual results could differ from these estimates.
Certain reclassifications have been made for comparative purposes but
have not affected previously reported net income or common shareholders' equity.
SPPC Utility Plant
- ------------------
In addition to direct labor and material costs, SPPC also charges to
the construction of utility plant: the cost of time spent by administrative
employees in planning and directing construction work; property taxes; employee
benefits (including such costs as pensions, postretirement and postemployment
benefits, vacations and payroll taxes); and an allowance for funds used during
construction.
7
<PAGE>
The original cost of plant retired or otherwise disposed of and the
cost of removal less salvage is generally charged to the accumulated provision
for depreciation. The cost of current repairs and minor replacements is charged
to operating expenses when incurred. The cost of renewals and betterments is
capitalized.
Allowance For Funds Used During Construction and Capitalized Interest
- ---------------------------------------------------------------------
SPPC capitalizes, as part of construction costs on utility plant, an
allowance for funds used during construction (AFUDC). AFUDC represents the cost
of borrowed funds and, where appropriate, the cost of equity funds used for
construction purposes in accordance with rules prescribed by the FERC and the
Public Utilities Commission of Nevada (PUCN). AFUDC is capitalized in the same
manner as construction labor and material costs, with an offsetting credit to
"other income" for the portion representing the cost of equity funds and as a
reduction of interest charges for the portion representing borrowed funds.
Recognition of this item as a cost of utility plant is in accordance with
established regulatory ratemaking practices. Such practices permit the utility
to earn a fair return on, and recover in rates charged for utility services, all
capital costs. This is accomplished by including such costs in rate base and in
the provision for depreciation.
The AFUDC rates used during 1998, 1997 and 1996 were 7.69%, 8.30% and
8.91%, respectively. As specified by the PUCN, certain projects were assigned a
lower AFUDC rate due to specific low-interest-rate financings directly
associated with those projects.
Depreciation
- ------------
Depreciation is calculated using the straight-line composite method
over the estimated remaining service lives of the related properties. The
provision, as authorized by the PUCN, for 1998, 1997 and 1996, stated as a
percentage of the original cost of depreciable property, was 3.31%, 3.16% and
3.18%, respectively.
Cash and Cash Equivalents
- -------------------------
Cash is comprised of cash on hand and working funds. Cash equivalents
consist of high quality investments in money market funds. Short-term
investments in money market funds were $13.0 million and $5.2 million for
December 31, 1998 and 1997, respectively.
SPPC engages in short-term investment activity whenever it is deemed
beneficial. As of December 31, 1998 and 1997, SPPC's investments in money market
funds were $12.4 million and $4.7 million, respectively.
Regulatory Accounting and Other Regulatory Assets
- -------------------------------------------------
SPPC's rates are currently subject to the approval of the PUCN and are
designed to recover the cost of providing generation, transmission and
distribution services. As a result, SPPC qualifies for the application of SFAS
No. 71, "Accounting for the Effects of Certain Types of Regulation". This
statement recognizes that the rate actions of a regulator can provide reasonable
assurance of the existence of an asset and requires the capitalization of
incurred costs that would otherwise be charged to expense where it is probable
that future revenue will be provided to recover these costs. SFAS No. 101,
"Regulated Enterprises-Accounting for the Discontinuation of Application of FASB
Statement No. 71" requires that an enterprise whose operations cease to meet the
qualifying criteria of SFAS 71 discontinue the application of that statement by
eliminating the effects of any actions of regulators that had been previously
recognized.
In 1997, the Emerging Issues Task Force (EITF) released Issue 97-4. In
doing so, it reached a consensus that a utility subject to a deregulation plan
for its generation business should stop applying SFAS No. 71 to the generating
portion of its business no later than the date when a plan with sufficient
detail of the effect of the plan is known. EITF 97-4 also reached a consensus
that regulatory assets and liabilities that originated in a portion of the
business which is discontinuing its application of SFAS No. 71 should be
evaluated on the basis of where (that is, the portion of the business in which)
the regulated cash flows to realize and settle them will be derived. The result
of the consensus is that there is no elimination of regulatory assets which the
deregulatory legislation or rate order specifies collection of, if they are
recoverable through a portion of the business which remains subject to SFAS No.
71.
8
<PAGE>
In conformity with SFAS No. 71, the accounting for SPPC conforms with
generally accepted accounting principles as applied to regulated public
utilities and as prescribed by agencies and the commissions of the jurisdictions
in which it operates. In accordance with these principles, certain costs that
would otherwise be charged to expense or capitalized as plant costs are deferred
as regulatory assets based on expected recovery from customers in future rates.
Management's expected recovery of deferred costs is based upon specific
ratemaking decisions or precedent for each item. The following other regulatory
assets were included in the consolidated balance sheets as of December 31
(dollars in thousands):
<TABLE>
<CAPTION>
DESCRIPTION 1998 1997 AMORTIZATION
----------- ---- ---- ------------
PERIODS
-------
<S> <C> <C> <C>
Early Retirement and Severance Offers $20,468 $24,644 Various through 2005
Loss on Reacquired Debt 17,918 18,354 Various through 2023
Plant Assets 7,978 8,869 Various through 2031
Conservation and Demand Side Programs 3,787 6,146 Various through 2006
Other Costs 11,524 5,463 Various
------- -------
Total $61,675 $63,476
======= =======
</TABLE>
Currently, the electric utility industry is predominately regulated on
a basis designed to recover the cost of providing electric power to its retail
and wholesale customers. If cost-based regulation were to be discontinued in the
industry for any reason, including competitive pressure on the cost-based prices
of electricity, profits could be reduced, and utilities might be required to
reduce their asset balances to reflect a market basis less than cost.
Discontinuance of cost-based regulation would also require affected utilities to
write off their associated regulatory assets. Management cannot predict the
potential impact, if any, of these competitive forces on SPPC's future financial
position and results of operations.
Deferral Of Energy Costs
- ------------------------
SPPC has suspended deferred energy accounting in its Nevada (except for
liquid propane gas) and California jurisdictions. Prior to May 1995 (Nevada) and
June 1996 (California), SPPC employed deferred energy accounting procedures in
its electric and gas operations, as provided by statutes. The intent of these
procedures was to capture fluctuations in the cost of purchased gas, fuel and
purchased power. Deferred energy accounting required SPPC to record the
difference between actual fuel expense and fuel revenues as deferred energy
costs.
In Nevada, deferred energy remains suspended until January 1, 2000. At
that time, there is a possibility of SPPC returning to deferred energy
accounting.
Federal Income Taxes And Investment Tax Credits
- -----------------------------------------------
SPR and its subsidiaries file a consolidated federal income tax return.
Current income taxes are allocated based on SPR and each subsidiary's respective
taxable income or loss and investment tax credits as if each subsidiary filed a
separate return. Deferred taxes are provided on temporary differences at the
statutory income tax rate in effect as of the most recent balance sheet date.
For regulatory purposes, SPPC is authorized to provide for deferred
taxes on the difference between straight-line and accelerated tax depreciation
on post-1969 utility plant expansion property, deferred energy, and certain
other differences between financial reporting and taxable income, including
those added by the Tax Reform Act of 1986 (TRA). In 1981, SPPC began providing
for deferred taxes on the benefits of using the Accelerated Cost Recovery System
for all post-1980 property. In 1987, the TRA required SPPC to begin providing
deferred taxes on the benefits derived from using the Modified Accelerated Cost
Recovery System.
Investment tax credits are no longer available to SPPC. The deferred
investment tax credit balance is being amortized over the estimated service
lives of the related properties.
Revenues
- --------
SPPC accrues unbilled utility revenues earned from the dates customers
were last billed to the end of the accounting period. These amounts are included
in accounts receivable.
Recent Pronouncements of The FASB
- ---------------------------------
In June 1998, the FASB issued SFAS 133, entitled "Accounting for Derivative
Instruments and Hedging Activities". This statement establishes accounting and
reporting standards for derivative instruments, including certain derivative
instruments embedded in other contracts, (collectively referred to as
derivatives) and for hedging activities. It requires that an entity recognize
all derivatives as either assets or liabilities in the statement of financial
position and measure those instruments at fair value. This
9
<PAGE>
statement is effective for all fiscal quarters of all fiscal years beginning
after June 15, 1999. The Company is assessing the impact of SFAS 133 on its
financial condition and results of operations.
NOTE 2. REGULATORY ACTIONS
- ----------------------------
Nevada Proceedings
- ------------------
As a result of the 1997 rate plan, SPPC made its first earnings sharing
filing on April 29, 1998. For its electric customers, SPPC filed to refund $7.3
million based upon calendar year 1997 results. SPPC also proposed a refund of
$1.7 million to its gas division customers for results of the same period. In
December 1998, a pre-hearing conference was held which set hearings for early
1999. An order is expected before mid-year. SPPC has recognized contingent
liabilities to provide for its estimate of the outcome of this proceeding.
On April 2, 1998, the PUCN issued its order with respect to SPPC's
application for an increase in its water division's general rates. The
application was filed in September 1997. The PUCN's decision authorized SPPC to
increase its water rates by approximately $4.3 million annually (or 9.4%),
effective April 29, 1998.
On February 27, 1998, SPPC requested permission from the PUCN to continue
to serve customers in the Truckee-Carson Irrigation District (TCID) leasehold
area upon expiration of the leasehold agreement. On September 29, 1998, the PUCN
determined that SPPC was fit, willing, and able to serve the leasehold area. The
PUCN also determined that TCID's application was deficient. However, the PUCN
will allow the TCID to reapply for a certificate sometime in the future if it
satisfies numerous conditions including obtaining a judicial determination that
it owns facilities in the area. SPPC continues to provide service while
negotiations continue.
California Proceedings
- ----------------------
On January 1, 1998, as a result of the California Public Utilities
Commission's (CPUC) December 16, 1997 Transition Plan order, SPPC implemented a
10%, or a $2.9 million annual rate reduction for its residential and small
commercial customers using less than 20 kw of demand monthly.
In June 1998, SPPC filed for rate reduction bonds in order to recover the
cost of the 10% rate reduction. SPPC requested approval to issue up to $25
million in rate reduction bonds. At the suggestion of the CPUC, after the defeat
of Proposition 9, SPPC filed a Petition for Modification of the Transition Plan
Order and requested balancing account treatment in lieu of rate reduction bonds
in September. On December 17, 1998 the CPUC denied SPPC's Petition for
Modification of the Transition Plan Order. SPPC anticipates issuing rate
reduction bonds during the second quarter of 1999.
FERC Proceedings
- ----------------
On January 21, 1998, SPPC made a filing in compliance with the FERC's Order
in Docket No. ER98-12 (Retail Access Transmission Service). This filing
contained changes to the Open Access Transmission Tariff necessary to
accommodate retail access in SPPC's California retail jurisdiction. On April 17,
1998, a settlement was filed resolving all outstanding issues. The settlement
was certified on May 20, 1998 and approved on November 2, 1998.
On May 22, 1998, SPPC and several other parties filed a "Petition for
Review" with the D.C. Court of Appeals requesting review of the FERC's decisions
in the Pacific Gas Transmission (PGT) case, another of SPPC's natural gas
transportation providers. The FERC had previously denied SPPC's protest of a
settlement in PGT's last rate case and SPPC's request for rehearing.
On June 4, 1998, SPPC filed a settlement with all parties in Docket No.
ER97-3593-000 et al. The settlement resolves all issues in these cases and
upholds the current import limit and the allocation of limited import capacity
until the Alturas Intertie is in service. As of December 22, 1998, when the
Alturas Intertie became commercially operational and until February 28, 2001,
Truckee Donner Public Utility District will receive 30 MW of import capability.
After February 28, 2001, allocation of import capacity will be determined by the
FERC based on the results of SPPC's 1998 resource plan and a subsequent filing
with FERC in 1999. On July 9, 1998, the settlement was certified and is pending
FERC approval.
On November 30, 1998, the FERC issued an order accepting the Alturas
Interconnection and O&M agreement between the Company, Bonneville Power
Administration (BPA) and Pacificorp. The order requires SPPC to work with the
Western States Coordinating Council members to establish operating procedures to
avoid impacting the reliability of other systems. On December 22, 1998, SPPC
filed the draft Alturas Operating Agreement between SPPC, BPA and Pacificorp.
10
<PAGE>
On September 21, 1998, Tuscarora Gas Transmission Company, a subsidiary of
TGPC, received a rate order from FERC. The FERC order found that TGTC had
justified it existing rates and could continue charging customers based on those
rates.
NOTE 3. EARNINGS PER SHARE
- ----------------------------
The Company follows SFAS No. 128, "Earnings Per Share". The following
provides the calculation for Diluted EPS. The difference between Basic EPS and
Diluted EPS is due to common stock equivalent shares resulting from stock
options, the employee stock purchase plan, performance shares and a non-employee
director stock plan. Common stock equivalents were determined using the treasury
stock method.
<TABLE>
<CAPTION>
1998 1997 1996
--------------- ---------------- ----------------
<S> <C> <C> <C>
Basic EPS
Numerator
---------
Income available to common
stockholders ($000) $ 77,321 $ 74,445 $ 66,879
--------------- ---------------- ----------------
Denominator
-----------
Weighted average number of shares
outstanding 30,955,154 30,879,696 30,495,224
Per-Share Amount $ 2.50 $ 2.41 $ 2.19
---------------- =============== ================ ================
Diluted EPS
Numerator
---------
Income available to common
stockholders ($000) $ 77,321 $ 74,445 $ 66,879
--------------- ---------------- ----------------
Denominator
-----------
Weighted average number of shares
outstanding before dilution 30,955,154 30,879,696 30,495,224
Stock options 52,510 38,058 18,245
Executive long term incentive plan
- performance shares 18,215 36,696 13,911
Non-employee stock plan 8,655 5,573 4,176
Employee stock purchase plan 1,123 3,341 2,019
--------------- ---------------- ----------------
31,035,657 30,963,364 30,533,575
--------------- ---------------- ----------------
Per-Share Amount $ 2.49 $ 2.40 $ 2.19
---------------- =============== ================ ================
</TABLE>
11
<PAGE>
NOTE 4. OTHER PROPERTY
- ------------------------
Other property consisted of (dollars in thousands):
December 31,
1998 1997
----------- -----------
Investment in TGTC $ 17,751 $ 16,737
Investment in Pinon
Pine Gasifier 32,679 24,863
Real Estate - net 2,590 2,560
Other 6,238 5,454
----------- -----------
$ 59,258 $ 49,614
=========== ===========
NOTE 5. JOINTLY-OWNED FACILITIES
- ----------------------------------
Valmy
- -----
SPPC and Idaho Power Company each own an undivided 50% interest in the
Valmy Generating Station, with each company being responsible for financing its
share of capital and operating costs. SPPC is the operator of the plant for both
parties.
SPPC's share of direct operation and maintenance expenses for Valmy is
included in the accompanying consolidated statements of income.
The following schedule reflects SPPC's 50% ownership interest in jointly-
owned electric utility plant at December 31, 1998 (dollars in thousands):
<TABLE>
<CAPTION>
Electric Accumulated Construction
MW Plant Provision For Work In
Plant Capacity In Service Depreciation Progress
----- -------- ---------- ------------ --------
<S> <C> <C> <C> <C>
Valmy #1 129 $127,642 $53,152 $469
Valmy #2 137 $153,684 $52,916 $735
</TABLE>
Pinon Pine
- ----------
Pinon Pine Corp. and Pinon Pine Investment Co., subsidiaries of SPPC, own
25% and 75% of a 38% interest in Pinon Pine Company, L.L.C. GPSF-B, a Delaware
corporation formerly owned by General Electric Capital Corporation (GECC) and
now owned by SPPC, owns the remaining 62% as of February 1999. The LLC was
formed to take advantage of federal income tax credits associated with the
alternative fuel (syngas) produced by the coal gasifier available under ss. 29
of the Internal Revenue Code. The entire project, which includes an LLC-owned
gasifier and an SPPC-owned power island and post-gasification facility to
partially cool and clean the syngas, is referred to collectively as the Pinon
Pine Power Project.
SPPC has a funding arrangement with the Department of Energy (DOE). Under
the agreement, the DOE will provide funding towards the construction of the
project, and towards the operating and maintenance costs of the facility. The
DOE has committed $168 million of funding for Pinon construction and operation
costs. The DOE provided funding for approximately 43% of the estimated
construction cost and half of the operating and fuel expenses and will provide
funding until the commitment is expended. A dispute has arisen with the DOE
regarding the historical and future funding of natural gas costs. In February
1999, the DOE informed the Company it will not fund the remaining $14 million
under the cooperative agreement until the dispute is resolved. Estimated
construction start-up and commissioning costs for Pinon, including the DOE's
portion are approximately $301.5 million, which includes permitting taxes,
start-up commissioning, operator training and Allowance for Funds Used During
Construction. DOE funding for construction through December 1998 is $132.4
million.
Construction began on the project in February 1995, following resource plan
approval and the receipt of all permits and other approvals. The natural gas
portion (combined cycle combustion turbine) was satisfactorily completed and
placed in service December 1, 1996. The balance of the plant was completed in
June 1998. The construction of the gasifier portion of the project overran the
fixed contract price by approximately 12% or $12.6 million. The overrun is
primarily due to redesign issues, resolving technical issues relative to start
up and other costs due to a later than anticipated completion date. To date,
SPPC has not been successful in obtaining sustained operation of the gasifier
but work continues to identify problem areas and redesign solutions which will
likely require additional capital expenditures. Due to the problems noted above,
SPPC and Foster Wheeler settled on a portion of the cost overrun and have
entered into an alternative dispute resolution.
12
<PAGE>
SPPC had to satisfy certain performance requirements as part of the
construction agreement with the LLC. The initial performance warranty required
that the gasifier attain an average capacity factor of 30% during 1997,
regardless of delays in the in-service date. Since the gasifier was not in
service in 1997, the certain performance warranties required by the contract
were not met. Consequently, SPPC paid GECC $2.8 million as satisfaction of the
performance obligation.
NOTE 6. COMMON STOCK AND ADDITIONAL PAID-IN CAPITAL
- -----------------------------------------------------
As of December 31, 1998, 1,870,630 shares of common stock were reserved for
issuance under the Common Stock Investment Plan (CSIP), Employees' Stock
Purchase Plan (ESPP), Non-Employee Director Stock Plan and Executive Long-term
Incentive Plan (ELTIP). The ELTIP for key management employees allows for the
issuance of SPR common shares to key employees of SPPC through December 30,
2003. This Plan permits the following types of grants, separately or in
combination: nonqualified and qualified stock options; stock appreciation
rights; restricted stock; performance units; performance shares and bonus stock.
SPPC also provides an ESPP to all of its employees meeting minimum service
requirements. Employees can choose twice each year to have up to 15% of their
base earnings withheld to purchase SPR common stock. The purchase price of the
stock is 90% of the market value on the offering date or 100% of the market
price on the execution date, if less. The Non-employee Director Stock Plan
provides that a portion of SPR's outside directors annual retainer be paid in
SPR common stock. SPR records the costs of these plans in accordance with
Accounting Principles Board Opinion Number 25.
A Stock Rights Plan was placed into effect by declaring a dividend
distribution of one right for each outstanding share of common stock of SPR, par
value $1.00 per share, to stockholders of record at the close of business on
October 31, 1989, and by authorizing the issuance of one right for each share of
common stock issued between the October 31, 1989, record date and the earliest
of the distribution date, the redemption date and the October 31, 1999
expiration date. With certain exceptions and under certain conditions, each
right, when exercisable under the terms of the plan, entitles the registered
holder (except acquiring persons as defined by the plan) to purchase common
stock of an acquiring or surviving corporation (including SPR stock if any
remains after the transaction) having a value of $140 for $70, subject to
adjustment. The purpose of the plan is to help ensure that SPR's shareholders
receive fair and equal treatment in the event of any proposed hostile takeover
of SPR.
The changes in common stock and additional paid-in capital for 1998, 1997,
and 1996 are as follows (dollars in thousands):
<TABLE>
<CAPTION>
Shares Issued Amount
1998 1997 1996 1998 1997 1996
------- ------- ------- ------- ------- --------
<S> <C> <C> <C> <C> <C> <C>
Public Sale 38,758 - 517,900 $ 1,092 $ - $12,870
CSIP/DRP 400 50,633 238,403 21 1,419 5,985
ESPP, ESOP,
and Other 54,804 48,833 25,120 1,889 986 558
------- ------- ------- ------- ------- -------
93,962 99,466 781,423 $ 3,002 $ 2,405 $19,413
======= ======= ======= ======= ======= =======
</TABLE>
Merger
- ------
Under the terms of the Merger Agreement between SPR and Nevada Power
Company, each outstanding share of SPR's common stock, $1.00 par value per
share, together with associated purchase rights (the "Company Common Stock"),
other than shares owned by SPR or any subsidiary of SPR, will be converted into
the right to receive either $37.55 in cash (the "Company Cash Consideration") or
1.44 shares of SPR Common Stock (the "Company Stock Consideration" and, together
with the Company Cash Consideration, the "Company Merger Consideration"). Each
holder of shares of SPR Common Stock may elect to receive either the Company
Cash Consideration or the Company Stock Consideration. Holders who (i) own less
than 100 shares of SPR Common Stock or (ii) elect to receive the Company Stock
Consideration in respect of less than 100 shares of SPR Common Stock (all such
shares, the "De Minimis Shares"), will be deemed to have elected to receive the
Company Cash Consideration, except where the value of the Company Stock
Consideration exceeds 120% of the value of the Company Cash Consideration at the
time of the election deadline. In this case, such holders of De Minimis Shares
may, at the election of SPR, receive Company Stock Consideration in lieu of all
or part of the cash they would have received.
NOTE 7. PREFERRED STOCK
- -------------------------
All issues of SPPC preferred stock are superior to SPR's common stock with
respect to dividend payments (which are cumulative) and liquidation rights.
SPPC's Restated Articles of Incorporation, as amended on August 19, 1992,
authorize an aggregate total of 11,780,500 shares of preferred stock at any
given time.
The following table indicates the number of shares outstanding and the
dollar amount thereof at December 31 of each year. The difference between total
shares authorized and the amount outstanding represents undesignated shares
authorized but not issued.
Shares Outstanding Amount
------------------ ------
13
<PAGE>
<TABLE>
<CAPTION>
1998 1997 1996 1998 1997 1996
--------- --------- --------- ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
(dollars in thousands)
Not subject to mandatory
Redemption:
Series A 80,500 80,500 80,500 $ 4,025 $ 4,025 $ 4,025
Series B 82,000 82,000 82,000 4,100 4,100 4,100
Series C 299,800 299,800 299,800 14,990 14,990 14,990
Class A Series I 2,000,000 2,000,000 2,000,000 50,000 50,000 50,000
--------- --------- --------- -------- -------- --------
Subtotal 2,462,300 2,462,300 2,462,300 73,115 73,115 73,115
Subject to mandatory
Redemption:
Preferred securities of
Sierra Pacific Power
Capital I 1,940,000 1,940,000 1,940,000 48,500 48,500 48,500
--------- --------- --------- -------- -------- --------
Total 4,402,300 4,402,300 4,202,300 $121,615 $121,615 $121,615
========= ========= ========= ======== ======== ========
</TABLE>
SPPC redeemed 408,000 shares of Series G, 8.24% Preferred Stock, at par
value, for $20.4 million on June 3, 1996 using the proceeds from the following
issuance of Preferred Securities.
On July 29, 1996, Sierra Pacific Power Capital I (the Trust), a wholly-
owned subsidiary of SPPC, issued $48.5 million (1,940,000 shares) 8.60% Trust
Originated Preferred Securities (the Preferred Securities). SPPC owns all the
common securities of the Trust; 60,000 shares totaling $1.5 million (Common
Securities). The Preferred Securities and the Common Securities (the Trust
Securities) represent undivided beneficial ownership interests in the assets of
the Trust. The existence of the Trust is for the sole purpose of issuing the
Trust Securities and using the proceeds thereof to purchase from SPPC its 8.60%
Junior Subordinated Debentures due July 30, 2036, in a principal amount of $50
million. The sole asset of the Trust is SPPC's junior subordinated debentures.
SPPC's obligations under the guarantee agreement entered into in connection with
the Preferred Securities, when taken together with SPPC's obligation to make
interest and other payments on the Junior Subordinated Debentures issued to the
Trust, and SPPC's obligations under its indenture pursuant to which the Junior
Subordinated Debentures; are issued and its obligations under the declaration,
including its liabilities to pay costs, expenses, debts and liabilities of the
Trust, provides a full and unconditional guarantee by SPPC of the Trust's
obligations under the Preferred Securities. In addition to retiring the Series G
Preferred Stock, proceeds were used to reduce short-term borrowings.
The Preferred Securities of Sierra Pacific Power Capital I are redeemable
only in conjunction with the redemption of the related 8.60% Junior Subordinated
Debentures. The Junior Subordinated Debentures will mature on July 30, 2036, and
may be redeemed, in whole or in part, at any time on or after July 30, 2001, or
at any time in certain circumstances upon the occurrence of a tax event. A tax
event occurs if an opinion has been received from tax counsel that there is more
than an insubstantial risk that: the Trust is, or will be subject to United
States federal income tax with respect to interest accrued or received on the
Junior Subordinated Debentures; the Trust is, or will be subject to more than a
de minimis amount of other taxes, duties or other governmental charges; interest
payable by SPPC to the Trust on the Junior Subordinated Debentures is not, or
will not be, deductible, in whole or in part by SPPC for federal income tax
purposes.
Upon the redemption of the Junior Subordinated Debentures, payment will
simultaneously be applied to redeem preferred securities having an aggregate
liquidation amount equal to the aggregate principal amount of the Junior
Subordinated Debentures. The preferred securities are redeemable at $25 per
preferred security plus accrued dividends.
NOTE 8. LONG-TERM DEBT
- ------------------------
Substantially all utility plant is subject to the lien of the SPPC
indenture under which the first mortgage bonds are issued.
On June 30, 1997, SPPC redeemed $15 million 6.5% First Mortgage Bonds which
had been included in the current liability portion of the consolidated balance
sheet.
On June 17, 1998, SPPC redeemed $ 5 million 8.65% First Mortgage Bonds
before the due date in 2022.
In December 1998, SPPC issued $35 million principal amount of
collateralized Medium-Term Notes, Series D, consisting of three year non-
callable notes, due in 2001, with interest rates of 5.47% and five year non-
callable notes, due in 2003, with interest rates ranging from 5.50% to 5.59%.
For all notes, interest is payable in semi-annual payments. The proceeds to SPPC
from the sale of the notes is to be used for general corporate purposes
including but not limited to: the acquisition of property; the construction,
completion, extension or improvement of facilities; or discharge or refunding of
obligations, including short-term borrowings.
14
<PAGE>
On April 1, 1998, SPR redeemed $10 million of senior notes Series C leaving
a remaining balance of $20 million, of which $10 million has been included in
the current liability portion of long term debt on the consolidated balance
sheets. These senior notes, Series D and E, are due in 1999 and 2000.
SPR's aggregate annual amount of maturities for long-term debt for the next
five years is shown below (dollars in thousands):
1999 $ 40,600
2000 10,400
2001 17,500
2002 200
2003 18,100
NOTE 9. TAXES
- ---------------
The following reflects the composition of taxes on income (in thousands of
dollars):
<TABLE>
<CAPTION>
1998 1997 1996
----------------------------------------------
<S> <C> <C> <C>
Federal:
Taxes estimated to be currently payable $44,441 $38,854 $28,986
Deferred taxes related to:
Excess of tax depreciation over book depreciation 4,100 3,997 5,217
Deferral of energy costs deducted currently for tax purposes net - (3) (307)
Contributions in aid of construction and customer advances (2,963) (3,966) (2,917)
Avoided interest capitalized (875) (1,578) (3,124)
Costs of abandoned merger - 301 4,359
Net amortization of investment tax credit (1,930) (1,962) (1,961)
Other-net (2,075) 711 3,382
State (California) 925 801 754
----------------------------------------------
Total $41,623 $37,155 $34,389
==============================================
As Reflected in Statement of Income:
Federal income taxes $40,890 $37,866 $34,872
State income taxes 925 801 754
----------------------------------------------
Operating Income 41,815 38,667 35,626
Other income-net (192) (1,512) (1,237)
==============================================
Total $41,623 $37,155 $34,389
==============================================
</TABLE>
15
<PAGE>
The total income tax provisions differ from amounts computed by applying
the federal statutory tax rate to income before income taxes for the following
reasons (in thousands of dollars):
<TABLE>
<CAPTION>
1998 1997 1996
----------------------------------------------
<S> <C> <C> <C>
Income before preferred dividend requirements $ 82,780 $ 79,904 $ 73,179
Total income tax expense 41,623 37,155 34,389
----------------------------------------------
124,403 117,059 107,568
Statutory tax rate 35% 35% 35%
----------------------------------------------
Expected income tax expense 43,541 40,971 37,649
Depreciation related to difference in cost basis for tax purposes 1,383 1,591 2,456
Allowance for funds used during construction - equity (1,334) (1,912) (1,831)
Tax benefit from the disposition of assets 63 (569) (1,130)
ITC amortization (1,930) (1,962) (1,961)
California franchise taxes (net of federal benefit) 601 521 490
Other-net (701) (1,485) (1,284)
----------------------------------------------
$41,623 $37,155 $34,389
==============================================
Effective tax rate 33.5% 31.7% 32.0%
==============================================
</TABLE>
The net accumulated deferred federal income tax liability consists of
accumulated deferred federal income tax liabilities less related accumulated
deferred federal income tax assets, as shown (in thousands of dollars):
<TABLE>
<CAPTION>
1998 1997 1996
----------------------------------------------
<S> <C> <C> <C>
Accumulated Deferred Federal Income Tax Liabilities:
AFUDC $ 8,378 $ 7,174 $ 5,745
Bond redemptions 5,865 6,423 6,690
Excess of tax depreciation over book depreciation 157,906 154,240 142,447
Repairs & maintenance 6,180 4,355 3,047
Tax benefits flowed through to customers 65,619 66,563 67,667
Other 10,201 5,025 7,073
----------------------------------------------
Total 254,149 243,780 232,669
----------------------------------------------
Accumulated Deferred Federal Income Tax Assets:
Avoided interest capitalized 14,694 13,819 12,241
Employee benefit plans 3,049 1,783 1,132
Contributions in aid of construction and customer advances 33,925 30,697 25,980
Gross-ups received on contributions in aid of construction
and customer advances 4,512 4,197 3,529
Unamortized investment tax credit 20,432 21,471 22,527
Other 8,935 6,737 3,061
----------------------------------------------
Total 85,547 78,704 68,470
----------------------------------------------
Accumulated Deferred Federal Income Taxes $168,602 $165,076 $164,199
==============================================
</TABLE>
The company's balance sheets contain a net regulatory tax asset of $26.7
million at year-end 1998 and $25.8 million at year-end 1997. The net regulatory
asset consists of future revenue to be received from customers (a regulatory tax
asset) of $65.6 million at year-end 1998 and $66.6 million at year-end 1997, due
to flow-through of the tax benefits of temporary differences. Offset against
these amounts are future revenues to be refunded to customers (a regulatory tax
liability), consisting of $18.5 million at year-end 1998 and $19.3 million at
year-end 1997, due to temporary differences for liberalized depreciation at
rates in excess of current tax rates, and $20.4 million at year-end 1998 and
$21.5 million at year-end 1997 due to temporary differences caused by the
investment tax credit. The regulatory tax liability for temporary differences
related to liberalized depreciation will continue to be amortized using the
average rate assumption method required by the Tax Reform Act of 1986. The
regulatory tax liability for temporary differences caused by the investment tax
credit will be amortized ratably in the same fashion as the accumulated deferred
investment credit.
16
<PAGE>
NOTE 10. FAIR VALUE OF FINANCIAL INSTRUMENTS
- ---------------------------------------------
The December 31, 1998 carrying amount for cash, cash equivalents, current
assets, accounts payable, and current liabilities approximates fair value due to
the short-term nature of these instruments.
The total fair value of SPR's consolidated long-term debt at December 31,
1998, is estimated to be $652.1 million (excluding current portion) based on
quoted market prices for the same or similar issues or on the current rates
offered to SPPC for debt of the same remaining maturities. The total fair value
(excluding current portion) was estimated to be $660.6 million at December 31,
1997.
NOTE 11. SHORT-TERM BORROWINGS
- -------------------------------
SPR has a $10 million revolving credit facility with First Union National
Bank. This facility replaced the prior $10 million facility with Barclay's Bank.
There is currently no outstanding balance.
SPPC revised its credit facilities on January 29, 1998 resulting in a $150
million 364-day credit facility for the Alturas project, and a $50 million
revolving credit facility to support commercial paper activity. The $150 million
Alturas credit facility was used primarily to finance the construction of the
Alturas Intertie. This facility expired on January 29, 1999. The Company
utilized $105 million of the facility during 1998. Facility fees for 1998 were
approximately $120,000 for the Alturas Credit Facility, and $60,000 for the
revolving credit facility. Facility fees for 1997 were approximately $110,000.
On January 29, 1999 SPPC established a new $150 million unsecured credit
facility for general corporate purposes. This credit facility will expire on
December 31, 1999. SPPC pays the lender a facility fee on the commitment
quarterly, in arrears.
At December 31, 1998, SPPC's short-term debt was $105.0 million drawn from
the Alturas Credit Facility at an average interest rate of 5.41%. At December
31, 1997, SPPC had a balance of $75 million in short-term borrowings comprised
entirely of commercial paper at an average interest rate of 6.12%.
The other subsidiaries of SPR had no outstanding short-term borrowings at
December 31, 1998.
NOTE 12. DIVIDEND RESTRICTIONS
- -------------------------------
SPR's primary source of funds for the payment of dividends to its
stockholders is dividends paid by SPPC on its common stock, all of which is
owned by SPR. Accordingly, SPR's ability to pay dividends is dependent upon the
ability of SPPC to pay dividends on its common stock. The Restated Articles of
Incorporation of SPPC and the indentures relating to the various series of its
First Mortgage Bonds contain restrictions as to the payment of dividends on its
common stock and as to the purchase or retirement of its capital stock. Under
the most restrictive of these provisions, approximately $84 million of SPPC's
retained earnings was available at December 31, 1998, for the payment of cash
dividends to SPR. As of December 31, 1998, SPR had consolidated retained
earnings of approximately $184.9 million available for the payment of cash
dividends on SPR's common stock.
NOTE 13. RETIREMENT PLAN AND POST RETIREMENT BENEFITS
- ------------------------------------------------------
SPPC sponsors a noncontributory defined benefit retirement plan covering
all employees who satisfy the service requirement and a defined benefit post-
retirement plan that covers administrative employees and those covered under
collective bargaining agreements. The plan provides medical, dental and life
insurance benefits for retirees.
The retirement plan provides benefits based on each covered employee's
years of service, highest five-year average compensation, and a step rate
benefit formula indirectly integrating the plan with Social Security.
Beginning in 1998, retirement plan provisions applicable to employees
covered by the collective bargaining agreement were amended to recognize
additional compensation as pensionable pay and to reduce the penalty for
retirement before age 62.
SPPC's funding policy for the retirement plan is to contribute an annual
amount to an irrevocable trust that is not less than the minimum funding
requirement under the Employee Retirement Income Security Act of 1974, and not
in excess of the amount that can be deducted for federal income tax purposes.
The plan's assets are invested primarily in common stocks, marketable bonds, and
other fixed-income securities. The remainder is held in cash and cash
equivalents. None of the plan assets are invested in SPR common or SPPC
preferred stock.
In April 1995, SPPC offered an early retirement plan to non-bargaining unit
employees age 50 or older with at least 15 years of credited service as of
January 1, 1996 and whose age and credited years of service equaled at least 70.
The present value of termination costs relating to the 112 employees who
accepted the offering was originally recorded in 1995 at $16.8 million, but
17
<PAGE>
was revalued at $12.8 million during 1996 due to a revision in the measurement
date. These termination costs were fully deferred, as a regulatory asset, as of
December 31, 1995. During 1996, SPPC began amortizing the termination costs by
recognizing expense for both 1995 and 1996. SPPC is using a ten-year
amortization period for these costs, consistent with the treatment of previous
early retirement programs.
For management, professional and administrative employees, the post-
retirement plan is contributory for individuals retiring after January 1, 1993,
with retiree contributions tied to each retiree's length of service.
Additionally, the plan requires employees retiring after January 1, 1993 to
participate in Medicare Part "B". Life insurance benefits remain noncontributory
for retirees. However, the amount of life insurance provided for retirees is
significantly less than that provided to active employees. Also, dental coverage
is discontinued for all employees at age 65.
Beginning in 1998, post-retirement plan provisions applicable to employees
covered by the collective bargaining agreement were amended. Retiree
contributions were increased to a minimum of 10% plus an additional amount for
each year of service fewer than 20. Also, the plan introduced a managed care
option for future retirees.
SPPC's funding policy for its post-retirement benefit obligation takes
advantage of federal income tax deductions. Contributions are being made to two
voluntary employee's beneficiary associations and in IRC (S).401(h) account.
Plan assets are invested primarily in common stocks, marketable bonds and other
fixed income securities. The remainder is held in cash and cash equivalents.
None of the plan assets are invested in SPR common or SPPC preferred stock.
Post-retirement health care costs for key executives continue to be paid from
SPPC's general assets.
The following table sets forth a reconciliation of the funded status of the
plans with amounts included in SPPC's consolidated balance sheets for 1998, 1997
and 1996 (dollars in thousands).
<TABLE>
<CAPTION>
Pension Benefits Post-Retirement Benefits
1998 1997 1996 1998 1997 1996
----------- ---------- ----------- ---------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C>
Change in benefit obligation
Benefit obligation at beginning
of year $ 186,612 $ 157,660 $ 165,877 $ 65,483 $ 73,526 $ 73,821
Service cost 7,047 5,825 6,652 2,162 2,440 2,587
Interest cost 13,702 11,920 11,778 4,817 5,597 5,269
Plan participant's contributions - - - 67 54 41
Amendments - 5,204 - - (3,520) 415
Actuarial gain 8,310 14,500 (18,540) 6,661 (10,278) (6,277)
Benefits paid (8,563) (8,497) (8,107) (2,764) (2,336) (2,330)
----------- ---------- ----------- ---------- ----------- -----------
Benefit obligation at end of year 207,108 186,612 157,660 76,426 65,483 73,526
----------- ---------- ----------- ---------- ----------- -----------
Change in plan assets
Fair value of plan assets at
beginning of year 190,535 167,416 148,300 39,326 32,944 24,620
Actual return on plan assets 23,160 32,534 19,954 7,069 5,202 1,942
Employer contribution - - 8,087 4,143 3,668 8,877
Plan participant's contributions - - - 67 54 41
Expenses paid (1,275) (917) (818) (252) (206) (206)
Benefits paid (8,563) (8,498) (8,107) (2,764) (2,336) (2,330)
----------- ---------- ----------- ---------- ----------- -----------
Fair value of plan assets at end
of year 203,857 190,535 167,416 47,589 39,326 32,944
----------- ---------- ----------- ---------- ----------- -----------
Funded status 3,251 (3,923) (9,756) 28,837 26,157 40,582
Unrecognized net actuarial gain 26,519 29,352 26,661 16,716 20,837 8,562
Unrecognized prior service cost (8,404) (9,083) (4,251) - - (415)
Unrecognized transition obligation - - - (31,563) (33,818) (39,419)
=========== ========== =========== ========== =========== ===========
Accrued benefit cost $21,366 $ 16,346 $ 12,654 $ 13,990 $ 13,176 $ 9,310
=========== ========== =========== ========== =========== ===========
</TABLE>
18
<PAGE>
In the preceding table, unrecognized net gain represents the net gain
attributable to changes in actuarial assumptions and differences between actual
experience and actuarial assumptions. Also, service cost represents the benefits
earned during the year while interest cost represents the increase in the
accumulated benefit obligation due to the passage of time.
<TABLE>
<CAPTION>
Pension Benefits Post-Retirement Benefits
1998 1997 1996 1998 1997 1996
----------- ---------- ----------- ---------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C>
Weighted-average assumptions
as of December 31
Discount rate 6.75% 7.25% 7.50% 6.75% 7.25% 7.50%
Expected return on plan assets 8.50% 8.50% 8.50% 8.50% 8.50% 8.50%
Rate of compensation increase 4.50% 5.00% 5.00% 4.50% 5.00% 5.00%
</TABLE>
For 1996, SPPC used a graduated medical trend rate assumption with an
initial rate of 11.25%. This medical trend rate declined by 0.50% over the next
ten years to an ultimate rate of 5.75% in 2007, remaining at that level
thereafter. Beginning in 1997, the obligation valuation changed to a flat trend
rate of 6.00% for each year. In 1997, SPPC also adopted the 1994 Group Annuity
Generational Mortality Table.
<TABLE>
<CAPTION>
Pension Benefits Post-Retirement Benefits
1998 1997 1996 1998 1997 1996
----------- ---------- ----------- ---------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C>
Components of net periodic
benefit cost
Service cost $ 7,047 $ 5,825 $ 6,652 $ 2,162 $ 2,440 $ 2,587
Interest cost 13,702 11,920 11,778 4,817 5,597 5,269
Expected return on plan assets (15,800) (13,844) (12,590) (3,495) (2,937) (2,036)
Amortization of prior service cost 679 372 372 - 33 -
Amortization of transition - - 2,255 2,464 2,464
obligation -
Recognized net actuarial gain (609) (581) - (783) (62) -
----------- ---------- ----------- ---------- ----------- -----------
Net periodic benefit cost:
SFAS No. 132 5,019 3,692 6,212 4,956 7,535 8,284
Amount expensed :
SFAS No. 71 - Net 2,599 2,599 3,882 805 805 2,044
=========== ========== =========== ========== =========== ===========
Total net periodic benefit cost $ 7,618 $ 6,291 $ 10,094 $ 5,761 $ 8,340 $ 10,328
=========== ========== =========== ========== =========== ===========
</TABLE>
The amount expensed under SFAS No. 71 for the retirement plan represents
the SFAS No. 88 costs arising from the 1989, 1992 and 1995 early retirement
programs. Pursuant to PUCN directive and prior precedent, costs for the 1989,
1992, and 1995 programs are being amortized over 10 years.
Assumed health care cost trend rates have a significant effect on the
amounts reported for Post-Retirement Benefit plans. A one-percentage-point
change in the assumed health care cost trend would have the following effects:
1-Percentage- 1-Percentage-
Point Increase Point Decrease
Effect on total of service and interest
cost components $1.8 million ($1.4 million)
Effect on post-retirement
Benefit obligation $14.0 million ($11.0 million)
In addition to the employee retirement plan covering all employees, SPPC
has a Supplemental Executive Retirement Plan which is a non-qualified defined
benefit plan under which SPPC will pay out of general assets supplemental
pension benefits to key executives. SPPC also has a non-qualified supplemental
pension plan covering certain employees. This plan provides for incremental
pension payments from SPPC's funds so that total pension payments equal amounts
that would have been payable from SPPC's principal pension plan if it were not
for limitations imposed by income tax regulations. The unfunded liability under
these plans as of December 31, 1998, 1997 and 1996 was $5.6 million, $5.2
million and $4.9 million, respectively.
19
<PAGE>
NOTE 14. STOCK COMPENSATION PLANS
- ----------------------------------
At December 31, 1998, SPPC had several stock-based compensation plans which
are described below. SPPC applies Accounting Principles Board Opinion No. 25 and
related Interpretations in accounting for its plans. Accordingly, no
compensation cost has been recognized for nonqualified stock options and the
employee stock purchase plan. The total compensation cost that has been charged
against income for the performance shares, dividend equivalents and the non-
employee director stock plans was $.5 million, $1.4 million and $.9 million for
1998, 1997 and 1996, respectively. Had compensation cost for SPPC's nonqualified
stock options and the employee stock purchase plan been determined based on the
fair value at the grant dates for awards under those plans consistent with the
method of Statement of SFAS No. 123, SPR's net income and earnings per share
would have been decreased to the pro forma amounts indicated below (in thousands
of dollars except for per share amounts):
<TABLE>
<CAPTION>
1998 1997 1996
---- ---- ----
<S> <C> <C> <C>
Net Income As Reported $ 77,321 $ 74,445 $ 66,879
Pro Forma $ 76,977 $ 74,277 $ 66,812
Basic Earnings Per Share As Reported $ 2.50 $ 2.41 $ 2.19
Pro Forma $ 2.49 $ 2.41 $ 2.19
Diluted Earnings Per Share As Reported $ 2.49 $ 2.40 $ 2.19
Pro Forma $ 2.48 $ 2.40 $ 2.19
</TABLE>
SPPC's executive long-term incentive plan for key management employees,
which was approved by shareholders on May 16, 1994, provides for the issuance of
up to 750,000 of SPR's common shares to key employees through December 31, 2003.
The plan permits the following types of grants, separately or in combination:
nonqualified and qualified stock options; stock appreciation rights; restricted
stock; performance units; performance shares; and bonus stock. During 1998, 1997
and 1996, SPPC issued only nonqualified stock options and performance shares
under the plan.
Nonqualified stock options granted during 1998, 1997 and 1996 were granted
at an option price not less than market value at the date of the grant (January
1, 1998, January 1, 1997 and January 1, 1996, respectively). The 1998 and 1997
options vest to the participants 33 1/3% per year over a three year period from
the grant date and may be exercised for a period not exceeding ten years from
the date of the grant. The 1996 options vest to the participants 20% per year
over a five year period from the grant date and may be exercised for a period
not exceeding ten years from the date of the grant. The options may be exercised
using either cash or previously acquired shares, valued at the current market
price, or a combination of both.
The fair value of each nonqualified option has been estimated on the date
of grant using the Black-Scholes option-pricing model with the following
assumptions used for grants in 1998, 1997 and 1996, respectively: dividend yield
of 4.71%, 5.30% and 5.50%; expected volatility of 13.16%, 11.42% and 11.57%;
risk-free rates of return of 5.81%, 6.68% and 5.75%; and an expected life of 10
years for all grants.
20
<PAGE>
A summary of the status of SPPC's nonqualified stock option plan as of
December 31, 1998, 1997 and 1996, and changes during those years is presented
below:
<TABLE>
<CAPTION>
1998 1997 1996
---- ---- ----
Weighted-Average Weighted-Average Weighted-Average
Shares Exercise Shares Exercise Shares Exercise
Nonqualified Stock Options (000) Price (000) Price (000) Price
---------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Outstanding at beginning of year 158 $ 25.51 89 $ 20.73 70 $ 19.59
Granted 125 $ 35.90 98 $ 28.75 28 $ 23.38
Exercised (31) $ 24.24 (15) $ 20.28 (1) $ 19.83
Forfeited (44) $ 27.12 (14) $ 23.17 (8) $ 20.04
Outstanding at end of year 208 $ 31.62 158 $ 25.51 89 $ 20.73
Options exercisable at year-end 38 $ 24.54 25 $ 20.32 18 $ 19.83
Weighted-average fair value of
options granted during the year $ 4.79 $ 3.51 $ 2.13
</TABLE>
The following table summarizes information about nonqualified stock options
outstanding at December 31, 1998:
<TABLE>
<CAPTION>
Options Outstanding Options Exercisable
---------------------------- ----------------------------
Number Remaining Number
Outstanding Contractual Exercisable
Exercise Price at 12/31/98 Life Exercise Price at 12/31/98
---------------------------------------------- ----------------------------
<S> <C> <C> <C> <C>
$ 20.500 9,088 5 years $ 20.500 7,270
$ 18.750 12,544 6 years $ 18.750 7,526
$ 23.375 11,180 7 years $ 23.375 4,472
$ 28.750 55,598 8 years $ 28.750 18,570
$ 35.900 120,000 9 years $ 35.900 -
</TABLE>
During 1998, 1997 and 1996, SPPC granted performance shares in the
following numbers and initial values, respectively: 12,700, 14,090 and 8,973
shares; and $35.90, $28.75 and $23.375 per share. The actual number of shares
earned is dependent upon SPR achieving certain financial goals over three-year
performance periods. The value of performance shares, if earned, will be equal
to the market value of SPR's common shares as of the end of the performance
periods. SPPC, at its sole discretion, may pay earned performance shares in the
form of cash or in shares (or a combination thereof).
Simultaneous with the grant of both the nonqualified options and
performance shares above, each participant was granted dividend equivalents.
Each dividend equivalent entitles the participant to receive a contingent right
to be paid an amount equal to dividends declared on shares originally granted
from the date of grant through the exercise date, or, in the case of performance
shares, throughout the performance period. Additionally, in order for dividend
equivalents to be paid on the performance shares, certain financial targets must
be met. Dividend equivalents will be forfeited if options expire unexercised.
Under SPPC's employee stock purchase plan, SPR is authorized to issue up to
400,162 shares of common stock to all of its employees with minimum service
requirements. Under the terms of the plan, employees can choose twice each year
to have up to 15% of their base earnings withheld to purchase the Company's
common stock. The purchase price of the stock is 90% of the market value on the
offering commencement date. Employees can withdraw from the plan at any time
prior to the exercise date. Under the plan, SPR sold 15,282, 17,822 and 15,602
shares to employees in 1998, 1997 and 1996, respectively. Compensation cost has
been estimated for the employees' purchase rights on the date of grant using the
Black-Scholes option-pricing model with the following assumptions used for 1998,
1997 and 1996, respectively: average dividend yield of 4.17%, 4.87% and 5.38%;
average expected volatility of 14.16%, 11.57% and 11.51%; and average risk-free
interest rates of 4.96%, 5.59% and 5.45%. The weighted average fair value of
those purchase rights in 1998, 1997 and 1996 was $4.94, $4.14 and $3.26,
respectively.
SPR's non-employee director stock plan provides that a portion of the
outside directors' annual retainer be paid in SPR stock. Effective May 20, 1996,
the annual retainer for non-employee directors was increased from $14,000 to
$30,000. The minimum amount to be paid in SPR stock was also increased from
$4,000 to $20,000 per director, over the prior year. During
21
<PAGE>
1998, 1997 and 1996, SPR granted the following total shares and related
compensation to directors in SPR stock, respectively: 6,391, 8,208 and 9,212
shares; and $233,250, $230,833 and $160,417.
NOTE 15. POSTEMPLOYMENT BENEFITS
- ---------------------------------
During 1995, SPPC offered a severance program to non-bargaining-unit
employees which provided both severance pay and medical benefits continuation
totaling $7.0 million and $0.5 million, respectively. These costs were deferred
as a regulatory asset as of December 31, 1995. SPPC began amortization of these
costs during 1996 over a ten-year period consistent with the period used for
pension and post-retirement benefits. There was no remaining liability for
unpaid severance and benefits at December 31, 1998, 1997 or 1996.
NOTE 16. COMMITMENTS AND CONTINGENCIES
- ---------------------------------------
SPPC's estimated cash construction expenditures for the year 1999 and the
five-year period 1999-2003 are $112.7 million and $639.8 million, respectively.
Several of SPR's and SPPC's purchased power, gas supply and pipeline
capacity, and coal supply contracts contain minimum volume provisions, which SPR
and SPPC is either meeting or exceeding. SPR and SPPC anticipate continuing to
meet or exceed them in the future. Estimated future commitments under non-
cancelable agreements with initial terms of one year or more at December 31,
1998 were as follows (dollars in thousands):
1999 $ 192,600
2000 117,000
2001 91,800
2002 88,900
2003 71,500
After 2003 to 2015 465,100
SPPC has an operating lease for its corporate headquarters building, a
334,000 square foot, five-floor, multi-purpose building located in southeast
Reno, Nevada. The primary term of the lease is 25 years, ending in 2010. The
current annual rental is $5.4 million, which amount remains constant until the
end of the primary term. The lease has renewal options for an additional 50
years. SPPC subleases building space to various tenants. The subleases vary from
year to year and are shown at net of total lease.
The total rental expense under all leases (net) was approximately $7.5
million in 1998, $7.4 million in 1997 and $8.2 million in 1996.
Estimated future minimum lease commitments (net of the corporate
headquarters building subleases described above) under non-cancelable operating
leases with initial terms of one year or more at December 31, 1998 were as
follows (dollars in thousands):
1999 $ 8,700
2000 6,600
2001 6,300
2002 6,200
2003 7,000
After 2003 to 2018 41,800
----------
Total $ 76,600
==========
SPR and SPPC have no material capital lease commitments.
See Notes 1, 5, 7 and 13 of SPR's consolidated financial statements for
additional commitments and contingencies.
SPR, through the course of its normal business operations, is currently
involved in a number of legal actions, none of which has had or, in the opinion
of management, is expected to have a significant impact on its financial
position or results of operations.
22
<PAGE>
NOTE 17. SEGMENT INFORMATION
- -----------------------------
SPR adopted FASB statement No. 131, Disclosure about Segments of an
Enterprise and Related Information, for its annual reports as of December 31,
1998. SPR operates three primary business segments providing regulated electric,
natural gas and water service. Electric service is provided to northern Nevada
and the Lake Tahoe area of California. Natural gas and water services are
provided in the Reno-Sparks area of Nevada. The All Other segment includes other
segments below the quantitative threshold for separate disclosure.
Information as to the operations of the different business segments is set
forth below based on the nature of products and services offered. SPR evaluates
performance based on several factors, of which the primary financial measure is
business segment operating income. The accounting policies of the business
segments are the same as those described in the summary of significant
accounting policies (Note 1). Intersegment revenues are not material.
Financial data for business segments is as follows ($000):
<TABLE>
<CAPTION>
Reconciling
December 31, 1998 Electric Gas Water All Other Eliminations Consolidated
- ------------------------- ------------ ------------ ------------ ------------ ------------ ------------
<S> <C> <C> <C> <C> <C> <C>
Operating revenues $ 585,657 $ 99,532 $ 49,143 $ 7,509 $ 741,841
============ ============ ============ ============ ============ ============
Operating income $ 103,728 $ 10,534 $ 11,932 $ (2,073) $ 124,121
============ ============ ============ ============ ============ ============
Operating income taxes $ 34,611 $ 5,142 $ 3,797 $ (1,735) $ 41,815
============ ============ ============ ============ ============ ============
Depreciation and amortization $ 57,180 $ 4,810 $ 7,445 $ - $ 69,435
============ ============ ============ ============ ============ ============
Interest expense on long term debt $ 28,277 $ 4,001 $ 10,911 $ 1,506 $ (4,299) $ 40,396
============ ============ ============ ============ ============ ============
Assets $ 1,558,322 $ 139,398 $ 274,124 $ 29,576 $ 39,976 $ 2,041,396
============ ============ ============ ============ ============ ============
Capital expenditures $ 144,080 $ 11,124 $ 28,180 $ 668 $ 184,052
============ ============ ============ ============ ============ ============
<CAPTION>
Reconciling
December 31, 1997 Electric Gas Water All Other Eliminations Consolidated
- ------------------------- ------------ ------------ ------------ ------------ ------------ ------------
<S> <C> <C> <C> <C> <C> <C>
Operating revenues $ 540,346 $ 70,675 $ 46,519 $ 5,703 $ 663,243
============ ============ ============ ============ ============ ============
Operating income $ 99,671 $ 10,057 $ 10,444 $ (1,545) $ 118,627
============ ============ ============ ============ ============ ============
Operating income taxes $ 33,742 $ 4,223 $ 2,422 $ (1,720) $ 38,667
============ ============ ============ ============ ============ ============
Depreciation and amortization $ 52,239 $ 4,531 $ 7,347 $ - $ 64,117
============ ============ ============ ============ ============ ============
Interest expense on long term debt $ 31,098 $ 3,653 $ 9,158 $ 2,129 $ (4,300) $ 41,738
============ ============ ============ ============ ============ ============
Assets $ 1,463,969 $ 130,392 $ 282,524 $ 23,638 $ 35,357 $ 1,935,880
============ ============ ============ ============ ============ ============
Capital expenditures $ 105,531 $ 12,191 $ 30,079 $ - $ 147,801
============ ============ ============ ============ ============ ============
<CAPTION>
Reconciling
December 31, 1996 Electric Gas Water All Other Eliminations Consolidated
- ------------------------- ------------ ------------ ------------ ------------ ------------ ------------
<S> <C> <C> <C> <C> <C> <C>
Operating revenues $ 507,004 $ 67,376 $ 45,344 $ 7,987 $ 627,711
============ ============ ============ ============ ============ ============
Operating income $ 86,428 $ 11,035 $ 9,545 $ 1,870 $ 108,878
============ ============ ============ ============ ============ ============
Operating income taxes $ 27,743 $ 4,872 $ 3,626 $ (615) $ 35,626
============ ============ ============ ============ ============ ============
Depreciation and amortization $ 47,797 $ 4,223 $ 6,098 $ - $ 58,118
============ ============ ============ ============ ============ ============
Interest expense on long term debt $ 27,856 $ 3,480 $ 7,519 $ 2,719 $ (1,804) $ 39,770
============ ============ ============ ============ ============ ============
Assets $ 1,407,927 $ 122,137 $ 276,954 $ 26,726 $ 35,610 $ 1,869,354
============ ============ ============ ============ ============ ============
Capital expenditures $ 158,482 $ 10,798 $ 33,829 $ - $ 203,109
============ ============ ============ ============ ============ ============
</TABLE>
The reconciliation of segment information to consolidated totals in the
preceding table includes an adjustment for intersegment interest expense
eliminated from the consolidated totals. The reconciliation of segment assets
to the consolidated total includes the following unallocated amounts.
23
<PAGE>
1998 1997 1996
------------ ------------ ------------
Other property $ 1,342 $ 1,928 $ 1,043
Cash 15,197 6,920 890
Current assets- other 2,692 2,572 3,948
Other regulatory assets 21,031 23,876 29,426
Deferred charges- other (286) 61 303
=========== =========== ===========
$ 39,976 $ 35,357 $ 35,610
=========== =========== ===========
NOTE 18. QUARTERLY FINANCIAL DATA (unaudited)
The following figures are unaudited and include all adjustments necessary
in the opinion of management for a fair presentation of the results of interim
periods (dollars in thousands except per share amounts):
<TABLE>
<CAPTION>
Quarter Ended
-------------
Mar. 31, 1998 June 30, 1998 Sept 30, 1998 Dec. 31, 1998
------------- ------------- ------------- -------------
<S> <C> <C> <C> <C>
Operating Revenues $184,482 $171,632 $188,549 $197,178
======== ======== ======== ========
Operating Income $ 32,972 $ 26,842 $ 32,706 $ 31,601
======== ======== ======== ========
Net Income $ 21,286 $ 15,570 $ 21,167 $ 19,298
======== ======== ======== ========
Net Income per share - Basic $ .69 $ .50 $ .68 $ .63
======== ======== ======== ========
- Diluted $ .69 $ .50 $ .68 $ .62
======== ======== ======== ========
</TABLE>
<TABLE>
<CAPTION>
Quarter Ended
-------------
Mar. 31, 1997 June 30, 1997 Sept 30, 1997 Dec. 31, 1997
------------- ------------- ------------- -------------
<S> <C> <C> <C> <C>
Operating Revenues $173,313 $156,720 $160,875 $172,335
======== ======== ======== ========
Operating Income $ 30,917 $ 27,245 $ 29,033 $ 31,432
======== ======== ======== ========
Net Income $ 20,833 $ 15,484 $ 18,158 $ 19,970
======== ======== ======== ========
Net Income per share - Basic $ .68 $ .50 $ 59 $ .64
======== ======== ======== ========
- Diluted $ .67 $ .50 $ .59 $ .64
======== ======== ======== ========
</TABLE>
24
<PAGE>
EXHIBIT 99.5
SIERRA PACIFIC RESOURCES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
<TABLE>
<CAPTION>
June 30, December 31,
1999 1998
-------------------- ----------------
(Unaudited)
<S> <C> <C>
ASSETS
Utility Plant at Original Cost:
Plant in service $ 2,374,322 $ 2,348,996
Less: accumulated provision for depreciation 762,799 727,624
-------------------- -----------------
1,611,523 1,621,372
Construction work-in-progress 75,141 55,670
-------------------- -----------------
1,686,664 1,677,042
-------------------- -----------------
Investments in subsidiaries and other property, net 88,525 59,258
-------------------- -----------------
Current Assets:
Cash and cash equivalents 8,295 17,674
Accounts receivable less provision for uncollectible accounts
1999-$4,313; 1998-$3,461 103,861 114,870
Materials, supplies and fuel, at average cost 29,879 25,776
Other 2,995 3,048
-------------------- -----------------
145,030 161,368
-------------------- -----------------
Deferred Charges:
Regulatory tax asset 65,531 65,619
Other regulatory assets 61,888 61,675
Other 21,282 16,434
-------------------- -----------------
148,701 143,728
-------------------- -----------------
$ 2,068,920 $ 2,041,396
==================== =================
CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholder's equity $ 687,168 $ 673,432
Preferred stock 73,115 73,115
Preferred stock subject to mandatory redemption:
SPPC-obligated mandatorily redeemable preferred securities of
SPPC's subsidiary Sierra Pacific Power Capital I, holding
solely $50 million principal amount of 8.6% junior
subordinated debentures of SPPC, due 2036 48,500 48,500
Long-term debt 630,111 616,754
-------------------- -----------------
1,438,894 1,411,801
-------------------- -----------------
Current Liabilities:
Short-term borrowings 123,000 105,000
Current maturities of long-term debt 40,597 40,585
Accounts payable 46,296 60,128
Accrued interest 7,744 7,885
Dividends declared 12,536 11,465
Accrued salaries and benefits 13,154 12,131
Other current liabilities 25,051 28,059
-------------------- -----------------
268,378 265,253
-------------------- -----------------
Deferred Credits:
Accumulated deferred federal income taxes 172,941 168,602
Accumulated deferred investment tax credit 36,961 37,944
Regulatory tax liability 37,846 38,939
Customer advances for construction 36,462 34,961
Accrued retirement benefits 45,977 42,560
Other 31,461 41,336
-------------------- -----------------
361,648 364,342
-------------------- -----------------
$ 2,068,920 $ 2,041,396
==================== =================
</TABLE>
The accompanying notes are an integral part of the financial statements
1
<PAGE>
SIERRA PACIFIC RESOURCES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Dollars in Thousands, Except Per Share Amounts)
<TABLE>
<CAPTION>
Three-Months Ended Six-Months Ended
June 30, June 30,
---------------------------- -----------------------------
1999 1998 1999 1998
----------- ----------- ----------- -----------
(Unaudited) (Unaudited) (Unaudited) (Unaudited)
<S> <C> <C> <C> <C>
OPERATING REVENUES:
Electric $ 147,348 $ 135,169 $ 291,651 $ 277,308
Gas 18,851 22,112 56,878 53,478
Water 13,619 11,862 23,900 21,079
Other 2,339 2,489 4,514 4,249
----------- ----------- ----------- -----------
182,157 171,632 376,943 356,114
----------- ----------- ------------ -----------
OPERATING EXPENSES:
Operation:
Purchased power 42,111 35,377 82,779 73,752
Fuel for power generation 26,367 27,447 52,837 51,327
Gas purchased for resale 12,658 13,510 37,375 32,841
Other 33,853 32,463 60,940 63,479
Maintenance 5,164 6,007 10,660 10,703
Depreciation and amortization 19,624 16,672 38,767 33,593
Taxes:
Income taxes 8,228 8,313 19,513 20,699
Other than income 4,849 5,001 9,671 9,906
----------- ----------- ----------- -----------
152,854 144,790 312,542 296,300
----------- ----------- ----------- -----------
OPERATING INCOME 29,303 26,842 64,401 59,814
----------- ----------- ----------- -----------
OTHER INCOME:
Allowance for other funds used during construction - 1,155 - 2,126
Other income - net 221 (242) 259 (2)
----------- ----------- ----------- -----------
221 913 259 2,124
----------- ----------- ----------- -----------
Total Income 29,524 27,755 64,660 61,938
----------- ----------- ----------- -----------
INTEREST CHARGES:
Long-term debt 10,245 10,057 20,443 20,320
Other 2,280 1,759 4,883 3,667
Allowance for borrowed funds used during
construction and capitalized interest (236) (2,039) (434) (3,721)
----------- ----------- ----------- -----------
12,289 9,777 24,892 20,266
----------- ----------- ----------- -----------
INCOME BEFORE OBLIGATED MANDATORILY
REDEEMABLE PREFERRED SECURITIES 17,235 17,978 39,768 41,672
Preferred dividend requirements of SPPC-obligated
mandatorily redeemable preferred securities (1,043) (1,043) (2,086) (2,086)
----------- ----------- ----------- -----------
INCOME BEFORE PREFERRED DIVIDENDS 16,192 16,935 37,682 39,586
Preferred dividend requirements (1,365) (1,365) (2,730) (2,730)
----------- ----------- ----------- -----------
INCOME APPLICABLE TO COMMON STOCK $ 14,827 $ 15,570 $ 34,952 $ 36,856
=========== =========== =========== ===========
Net Income Per Share - Basic $ 0.48 $ 0.50 $ 1.13 $ 1.19
Net Income Per Share - Diluted $ 0.48 $ 0.50 $ 1.12 $ 1.19
Weighted Average Shares of Common
Stock Outstanding 31,019,641 30,945,868 31,015,010 30,938,332
Dividends Paid Per Share of Common Stock $ 0.340 $ 0.325 $ 0.665 $ 0.635
</TABLE>
The accompanying notes are an integral part of the financial statements.
2
<PAGE>
PAGE>
SIERRA PACIFIC RESOURCES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
<TABLE>
<CAPTION>
Six-Months Ended
June 30,
------------------------------------
1999 1998
------------- -------------
(Unaudited)
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Income before preferred dividends $ 37,682 $ 39,586
Non-cash items included in income:
Depreciation and amortization 38,767 33,593
Deferred taxes and deferred investments tax credit 2,322 (718)
AFUDC and capitalized interest (434) (5,846)
Early retirement and severance amortization 2,096 2,109
Other (158) 1,427
Changes in certain assets and liabilities:
Accounts receivable 11,009 14,710
Materials, supplies and fuel (4,103) (871)
Other current assets 53 (1,480)
Accounts payable (13,832) (4,963)
Other current liabilities (2,126) 3,724
Other - net (13,216 (763)
------------- -------------
Net Cash Flows From Operating Activities 58,060 80,508
------------- -------------
CASH FLOWS USED IN INVESTING ACTIVITIES:
Additions to utility plant (55,708) (66,454)
Net customer refunds and contributions in aid construction 9,474 10,319
------------- -------------
Net cash used for utility plant (46,234) (56,135)
------------- -------------
Investments in subsidiaries and other property - net (29,412) (1,676)
------------- -------------
Net Cash Used In Investing Activities (75,646) (57,811)
------------- -------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Increase in short-term borrowings 17,731 14,037
Proceeds from issuance of long-term debt 23,696 -
Reduction of long-term debt (10,345) (15,300)
Sale of common stock 476 1,535
Dividends paid (23,351) (22,322)
------------- -------------
Net Cash Used In Financing Activities 8,207 (22,050)
------------- -------------
Net (decrease) increase in Cash and Cash Equivalents (9,379) 647
Beginning balance in Cash and Cash Equivalents 17,674 8,901
------------- -------------
Ending balance in Cash and Cash Equivalents $ 8,295 $ 9,548
============= =============
Supplemental Disclosures of Cash Flow Information:
Cash Paid During Period For:
Interest $ 26,837 $ 26,189
Income Taxes $ 12,524 $ 34,350
</TABLE>
The accompanying notes are an integral part of the financial statements.
3
<PAGE>
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
----------------------------------------------------
NOTE 1. MANAGEMENT'S STATEMENT
- ---------------------------------
In the opinion of the management of Sierra Pacific Resources, hereafter
known as the Company, 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
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
Company's audited financial statements included in the Company's Annual Report
on Form 10-K for the year ended December 31, 1998. Deloitte & Touche LLP, the
Company's independent accountants, have performed a review of the unaudited
condensed consolidated financial statements, and their report has been included
in this report.
The results of operations for the three-month and six-month period ended
June 30, 1999 are not necessarily indicative of the results to be expected for
the full year.
Principles of Consolidation
---------------------------
The condensed consolidated financial statements include the accounts of the
Company and its wholly-owned subsidiaries, Sierra Pacific Power Company (SPPC),
Tuscarora Gas Pipeline Company (TGPC), Sierra Gas Holding Company (formerly
Sierra Energy Company), Sierra Energy Company dba eo three (eo three), Sierra
Pacific Energy Company (SPE), Lands of Sierra (LOS), and Sierra Water
Development Company (SWDC). All significant intercompany transactions and
balances have been eliminated in consolidation.
Reclassifications
-----------------
Certain items previously reported for years prior to 1998 have been
reclassified to conform with the current year's presentation. Net income and
shareholder's equity were not affected by these reclassifications.
NOTE 2. RECENT PRONOUNCEMENTS OF THE FASB
- ------------------------------------------
In June 1998, the Financial Accounting Standards Board issued SFAS 133,
entitled "Accounting for Derivative Instruments and Hedging Activities". This
statement establishes accounting and reporting standards for derivative
instruments, including certain derivative instruments embedded in other
contracts (collectively referred to as derivatives), and for hedging activities.
It requires an entity to recognize all derivatives as either assets or
liabilities in the statement of financial position, and measure those
instruments at fair value. In May 1999, members of the Financial Accounting
Standards agreed to delay the effective date of Statement 133 to fiscal years
beginning after June 15, 2000. The Company is still assessing the impact of SFAS
133 on its financial condition and results of operations.
4
<PAGE>
NOTE 3. EARNINGS PER SHARE
- ---------------------------
The Company follows SFAS No. 128, "Earnings Per Share". The difference
between Basic EPS and Diluted EPS is due to common stock equivalent shares
resulting from stock options, employee stock purchase plan, performance shares
and a non-employee director stock plan. Common stock equivalents were determined
using the treasury stock method.
The following provides a reconciliation of Basic EPS and Diluted EPS.
<TABLE>
<CAPTION>
Three Months Ended Six Months Ended
June 30, June 30,
------------------------ ----------------------------
1999 1998 1999 1998
----------- ---------- ----------- ------------
<S> <C> <C> <C> <C>
Basic EPS
Numerator
Income available to common stockholders ($000) 14,827 15,570 34,952 36,856
----------- ---------- ----------- ------------
Denominator
Weighted average number of shares outstanding 31,019,641 30,945,868 31,015,010 30,938,332
----------- ---------- ----------- ------------
Per-Share Amount $ 0.48 $ 0.50 $ 1.13 $ 1.19
=========== ========== =========== ============
Diluted EPS
Numerator
Income available to common stockholders ($000) 14,827 15,570 34,952 36,856
----------- ---------- ----------- ------------
Denominator
Weighted average number of shares outstanding 31,019,641 30,945,868 31,015,010 30,938,332
before dilution
Stock options 26,206 62,508 24,909 47,346
Executive long term incentive plan - performance shares 21,947 18,387 20,285 16,807
Non-Employee stock plan 9,666 7,114 9,666 7,114
Employee stock purchase plan 679 1,002 618 1,158
----------- ---------- ---------- ------------
31,078,139 31,034,879 31,070,488 31,010,757
----------- ---------- ---------- ------------
Per-Share Amount $ 0.48 $ 0.50 $ 1.12 $ 1.19
=========== ========== ========== ============
</TABLE>
5
<PAGE>
NOTE 4. SEGMENT INFORMATION
- ----------------------------
The Company operates three business segments providing regulated electric,
natural gas and water service. Electric service is provided to northern Nevada
and the Lake Tahoe area of California. Natural gas and water services are
provided in the Reno-Sparks area of Nevada. Other segment information includes
segments below the quantitative threshold for separate disclosure.
Information as to the operations of the different business segments is set
forth below based on the nature of products and services offered. The Company
evaluates performance based on several factors, of which the primary financial
measure is business segment operating income. Intersegment revenues are not
material.
<TABLE>
<CAPTION>
Three Months
Ended June 30, 1999 Electric Gas Water Other Consolidated
- ------------------- ------------- ------------- ------------- ------------- -------------
<S> <C> <C> <C> <C> <C>
Operating Revenues $ 147,348 $ 18,851 $ 13,619 $ 2,339 $ 182,157
============= ============= ============= ============= =============
Operating income $ 24,601 $ 1,189 $ 4,047 $ (534) $ 29,303
============= ============= ============= ============= =============
Three Months
Ended June 30, 1998 Electric Gas Water Other Consolidated
- ------------------- ------------- ------------- ------------- ------------- ------------
Operating revenues $ 135,169 $ 22,112 $ 11,862 $ 2,489 $ 171,632
============= ============= ============= ============= =============
Operating income $ 21,546 $ 2,947 $ 2,815 $ (466) $ 26,842
============= ============= ============= ============= =============
Six Months
Ended June 30, 1999 Electric Gas Water Other Consolidated
- --------------------- ------------- ------------- ------------- -------------- -------------
Operating Revenues $ 291,651 $ 56,878 $ 23,900 $ 4,514 $ 376,943
============= ============= ============= ============== =============
Operating income $ 51,285 $ 7,479 $ 6,846 $(1,209) $ 64,401
============= ============= ============= ============== =============
Six Months
Ended June 30, 1998 Electric Gas Water Other Consolidated
- --------------------- ------------- ------------- ------------- -------------- -------------
Operating revenues $ 277,308 $ 53,478 $ 21,079 $ 4,249 $ 356,114
============= ============= ============= ============== =============
Operating income $ 47,962 $ 8,110 $ 4,374 $ (632) $ 59,814
============= ============= ============= ============== =============
</TABLE>
6
