<PAGE>
================================================================================
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED June 30, 2000
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM TO
Commission File Number 0-508
SIERRA PACIFIC POWER COMPANY
(Exact name of registrant as specified in its charter)
NEVADA 88-0044418
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
P.O. Box 10100 (6100 Neil Road)
Reno, Nevada 89520-0400
(89511)
(Address of principal executive office) (Zip Code)
(775) 834-4011
(Registrant's telephone number, including area code)
Indicate by check mark whether registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes X No
---- ----
Indicate the number of shares outstanding of each of the issuer's classes of
Common Stock, as of the latest practicable date.
Class Outstanding at August 14, 2000
Common Stock, $3.75 par value 1,000 Shares
================================================================================
1
<PAGE>
SIERRA PACIFIC POWER COMPANY
QUARTERLY REPORT ON FORM 10-Q
FOR THE QUARTER ENDED JUNE 30, 2000
CONTENTS
PART I - FINANCIAL INFORMATION
------------------------------
<TABLE>
<CAPTION>
Page
----
<S> <C> <C>
ITEM 1. Financial Statements
Condensed Consolidated Balance Sheets - June 30, 2000 and
December 31, 1999.................................................... 3
Condensed Consolidated Statements of Income - Three Months and Six Months
Ended June 30, 2000 and 1999......................................... 4
Condensed Consolidated Statements of Cash Flows - Six Months
Ended June 30, 2000 and 1999......................................... 5
Notes to Condensed Consolidated Financial Statements...................... 6
ITEM 2. Management's Discussion and Analysis
of Financial Condition and Results
of Operations............................................................. 9
ITEM 3. Quantitative and Qualitative Disclosures about
Market Risk............................................................... 17
PART II - OTHER INFORMATION
---------------------------
ITEM 1. Legal Proceedings.............................................. 18
ITEM 5. Other Information.............................................. 18
ITEM 6. Exhibits and Reports on Form 8-K............................... 19
Signature Page.................................................................... 20
</TABLE>
2
<PAGE>
SIERRA PACIFIC POWER COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
<TABLE>
<CAPTION>
June 30, December 31,
2000 1999
--------------------------------------
(Unaudited)
<S> <C> <C>
ASSETS
Utility Plant at Original Cost:
Plant in service $2,451,060 $2,420,728
Less: accumulated provision for depreciation 836,357 799,099
--------------------------------------
1,614,703 1,621,629
Construction work-in-progress 123,001 97,561
--------------------------------------
1,737,704 1,719,190
--------------------------------------
Investments in subsidiaries and other property, net 61,604 62,704
--------------------------------------
Current Assets:
Cash and cash equivalents 88,290 3,011
Accounts receivable less provision for uncollectible accounts:
$1,491 -2000 and $3,649 -1999 102,464 113,695
Materials, supplies and fuel, at average cost 35,768 30,070
Deferred energy costs 720 -
Other 3,219 3,103
--------------------------------------
230,461 149,879
--------------------------------------
Deferred Charges:
Regulatory tax asset 65,531 65,531
Other regulatory assets 66,065 73,660
Other 17,315 25,512
--------------------------------------
148,911 164,703
--------------------------------------
$2,178,680 $2,096,476
======================================
CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholder's equity $ 669,760 $ 673,738
Preferred stock 50,000 50,000
Preferred securities subject to mandatory redemption 48,500 48,500
Long-term debt 623,718 625,430
--------------------------------------
1,391,978 1,397,668
--------------------------------------
Current Liabilities:
Short-term borrowings - 109,584
Current maturities of long-term debt 302,640 102,755
Accounts payable 76,770 78,491
Accrued interest 6,701 5,110
Dividends declared 19,982 19,974
Accrued salaries and benefits 9,482 8,385
Other current liabilities 17,262 10,673
--------------------------------------
432,837 334,972
--------------------------------------
Commitments & Contingencies (Note 4)
Deferred Credits:
Deferred federal income taxes 172,171 170,261
Deferred investment tax credit 38,087 35,980
Regulatory tax liability 37,846 37,846
Accrued retirement benefits 39,236 49,052
Customer advances for construction 42,158 40,081
Other 24,367 30,616
--------------------------------------
353,865 363,836
--------------------------------------
$2,178,680 $2,096,476
======================================
</TABLE>
The accompanying notes are an integral part of the financial statements.
3
<PAGE>
SIERRA PACIFIC POWER COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Dollars in Thousands)
<TABLE>
<CAPTION>
Three Months Ended Six Months Ended
June 30, June 30,
------------------------ --------------------------
2000 1999 2000 1999
----------- --------- --------- -----------
(Unaudited) (Unaudited) (Unaudited) (Unaudited)
<S> <C> <C> <C> <C>
OPERATING REVENUES:
Electric $176,820 $147,348 $334,442 $291,651
Gas 16,851 18,851 51,311 56,878
Water 15,335 13,619 25,584 23,900
-------- -------- -------- --------
209,006 179,818 411,337 372,429
-------- -------- -------- --------
OPERATING EXPENSES:
Operation:
Purchased power 71,949 42,111 121,429 82,779
Fuel for power generation 44,082 26,367 73,358 52,837
Gas purchased for resale 11,470 12,658 34,321 37,375
Other 31,898 30,765 59,767 54,547
Maintenance 5,228 5,164 9,757 10,660
Depreciation and amortization 19,235 19,498 38,266 38,592
Taxes:
Income taxes 1,616 8,597 12,650 20,409
Other than income 4,795 4,821 9,757 9,620
-------- -------- -------- --------
190,273 149,981 359,261 306,819
-------- -------- -------- --------
OPERATING INCOME 18,733 29,837 52,076 65,610
-------- -------- -------- --------
OTHER INCOME:
Allowance for other funds used during construction 84 - 152 -
Other income (expense)- net (1,067) 213 (1,445) 220
-------- -------- -------- --------
(983) 213 (1,293) 220
-------- -------- -------- --------
Total Income 17,750 30,050 50,783 65,830
-------- -------- -------- --------
INTEREST CHARGES:
Long-term debt 10,683 10,071 20,433 19,932
Other 4,197 2,280 7,408 4,883
Allowance for borrowed funds used during
construction and capitalized interest (634) (236) (1,116) (434)
-------- -------- -------- --------
14,246 12,115 26,725 24,381
-------- -------- -------- --------
INCOME BEFORE OBLIGATED MANDATORILY
REDEEMABLE PREFERRED SECURITIES 3,504 17,935 24,058 41,449
Preferred dividend requirements of Company-
obligated mandatorily redeemable preferred
securities (1,043) (1,043) (2,086) (2,086)
-------- -------- -------- --------
INCOME BEFORE PREFERRED DIVIDENDS 2,461 16,892 21,972 39,363
Preferred dividend requirements (975) (1,365) (1,950) (2,730)
-------- -------- -------- --------
INCOME APPLICABLE TO COMMON STOCK $ 1,486 $ 15,527 $ 20,022 $ 36,633
======== ======== ======== ========
</TABLE>
The accompanying notes are integral part of the financial statements.
4
<PAGE>
SIERRA PACIFIC POWER COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
<TABLE>
<CAPTION>
Six Months Ended
June 30,
--------------------------------------
2000 1999
--------------------------------------
(Unaudited)
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Income before preferred dividends $ 21,972 $ 39,363
Non-cash items included in income:
Depreciation and amortization 38,266 38,592
Deferred taxes and deferred investment tax credit 1,093 2,222
AFUDC and capitalized interest (1,268) (434)
Deferred energy costs - net (720) -
Early retirement and severance amortization 2,098 2,096
Other non-cash 3,763 (158)
Changes in certain assets and liabilities:
Accounts receivable 11,231 11,874
Materials, supplies and fuel (5,698) (4,053)
Other current assets (116) 133
Accounts payable (1,721) (16,021)
Other current liabilities 9,277 (1,919)
Other - net (592) (8,034)
--------------------------------------
Net Cash Flows From Operating Activities 77,585 63,661
--------------------------------------
CASH FLOWS USED IN INVESTING ACTIVITIES:
Additions to utility plant (61,330) (55,708)
Non-cash charges to utility plant 1,326 -
Net customer refunds and contributions in aid construction 7,341 9,474
--------------------------------------
Net cash used for utility plant (52,663) (46,234)
(Investments in) disposal of subsidiaries and other property - net 919 (29,385)
--------------------------------------
Net Cash Used In Investing Activities (51,744) (75,619)
--------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Increase (decrease) in short-term borrowings (111,813) 17,731
Proceeds from issuance of long-term debt 200,000 23,696
Reduction of long-term debt (2,808) (233)
Additional investment by parent company 14,000 8,000
Dividends paid (39,941) (45,930)
--------------------------------------
Net Cash Used In Financing Activities 59,438 3,264
--------------------------------------
Net (decrease) increase in Cash and Cash Equivalents 85,279 (8,694)
Beginning balance in Cash and Cash Equivalents 3,011 15,197
--------------------------------------
Ending balance in Cash and Cash Equivalents $ 88,290 $ 6,503
======================================
Supplemental Disclosures of Cash Flow Information:
Cash Paid During Period For:
Interest $ 26,252 $ 26,138
Income Taxes $ 9,644 $ 13,522
</TABLE>
The accompanying notes are an integral part of the financial statements.
5
<PAGE>
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
----------------------------------------------------
NOTE 1. MANAGEMENT'S STATEMENT
---------------------------------
In the opinion of the management of Sierra Pacific Power Company, (the
Company or SPPC), a wholly owned subsidiary of Sierra Pacific Resources (SPR),
the accompanying unaudited interim condensed consolidated financial statements
contain all adjustments (consisting of only normal recurring adjustments)
necessary to present fairly the condensed consolidated financial position,
condensed consolidated results of operations and condensed consolidated cash
flows for the periods shown. These condensed consolidated financial statements
do not contain the complete detail or footnote disclosure concerning accounting
policies and other matters which are included in full year financial statements
and therefore, they should be read in conjunction with the Company's audited
financial statements included in the Company's Annual Report on Form 10-K for
the year ended December 31, 1999.
The results of operations for the three and six month periods ended June
30, 2000 are not necessarily indicative of the results to be expected for the
full year.
Principles of Consolidation
---------------------------
The consolidated financial statements include the accounts of the Company
and its wholly owned subsidiaries, Sierra Pacific Power Capital I, Pinon Pine
Corp., and Pinon Pine Investment Co. The Company accounts for its ownership of
GPSF-B, a Delaware corporation acquired in February 1999, using the equity
method because the Company intends to own the entity temporarily. All
significant intercompany transactions and balances have been eliminated in
consolidation.
Reclassifications
-----------------
Certain items previously reported for years prior to 2000 have been
reclassified to conform to the current year's presentation. Net income and
shareholder's equity were not affected by these reclassifications.
NOTE 2. RECENT PRONOUNCEMENTS
-------------------------------
Financial Accounting Standards Board
------------------------------------
In June 1998, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards (SFAS) 133, entitled "Accounting for
Derivative Instruments and Hedging Activities." This statement establishes
accounting and reporting standards for derivative instruments, including certain
derivative instruments embedded in other contracts (collectively referred to as
derivatives), and for hedging activities. It requires an entity to recognize
all derivatives as either assets or liabilities in the statement of financial
position, and measure those instruments at fair value. In May 1999, members of
the FASB agreed to delay the effective date of Statement 133 to fiscal years
beginning after June 15, 2000.
In June 2000, the FASB issued SFAS 138 that amended SFAS 133 in a number of
respects. Among other revisions, SFAS 138 exempted from the fair value
requirements normal purchases and normal sales (as defined by SFAS 133) that
contain settlement provisions, if it is probable that the contracts will not
settle net and will result in physical delivery. The Company is still assessing
the impact of SFAS 133 and SFAS 138 on its financial condition and results of
operations.
Securities and Exchange Commission
----------------------------------
In December 1999, the Staff of the Securities and Exchange Commission
released Staff Accounting Bulletin (SAB) No. 101, which summarizes certain of
the staff's views in applying generally accepted accounting principles to
revenue recognition in financial statements. Subsequently, SAB No. 101A and SAB
No. 101B were released delaying the implementation date of SAB No. 101 until no
later than the fourth fiscal quarter of fiscal years beginning after December
15, 1999. The Company does not believe that the SAB will have a material effect
on its financial statements.
NOTE 3. SEGMENT INFORMATION
-----------------------------
6
<PAGE>
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.
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.
Financial data for business segments is as follows (in thousands).
<TABLE>
<CAPTION>
Three Months
Ended June 30, 2000 Electric Gas Water Consolidated
------------------- -------------- -------------- -------------- --------------
<S> <C> <C> <C> <C>
Operating Revenues $ 176,820 $ 16,851 $ 15,335 $ 209,006
============== ============== ============== ==============
Operating Income $ 11,934 $ 1,139 $ 5,660 $ 18,773
============== ============== ============== ==============
Three Months
Ended June 30, 1999 Electric Gas Water Consolidated
------------------- -------------- -------------- -------------- --------------
Operating Revenues $ 147,348 $ 18,851 $ 13,619 $ 179,818
============== ============== ============== ==============
Operating Income $ 24,601 $ 1,189 $ 4,047 $ 29,837
============== ============== ============== ==============
Six Months
Ended June 30, 2000 Electric Gas Water Consolidated
------------------- -------------- -------------- -------------- --------------
Operating Revenues $ 334,442 $ 51,311 $ 25,584 $ 411,337
============== ============== ============== ==============
Operating Income $ 37,933 $ 5,751 $ 8,392 $ 52,076
============== ============== ============== ==============
Six Months
Ended June 30, 1999 Electric Gas Water Consolidated
------------------- -------------- -------------- -------------- --------------
Operating Revenues $ 291,651 $ 56,878 $ 23,900 $ 372,429
============== ============== ============== ==============
Operating Income $ 51,285 $ 7,479 $ 6,846 $ 65,610
============== ============== ============== ==============
</TABLE>
NOTE 4. COMMITMENTS AND CONTINGENCIES
---------------------------------------
The Company has four water wells which currently exceed the federal
drinking water standard for naturally occurring arsenic concentrations.
Production from three of these wells continues by blending water treated at the
Glendale Water Treatment Plant. The fourth well is out of service pending
treatment. The Company's water laboratory research staff is developing options
to assure that the Company is prepared to meet new arsenic standards. The new
Arsenic regulations will be promulgated in 2000 and the proposed regulation is
expected to require action on 17 of the 25 wells serving the Company's system.
Depending upon final rules from the EPA, the Company may incur between $70
million and $98 million by 2004 to meet the new standards.
In accordance with the revised Divestiture Plan stipulation approved by the
Public Utilities Commission of Nevada (PUCN) in February 2000 (see the 1999
Annual Report on Form 10-K), SPR is offering for sale generation assets with
peak capacity of approximately 2,985 megawatts (MW), with approximately 1045 MW
owned by SPPC and approximately 1,940 MW owned by Nevada Power Company (NVP).
Letters of interest were issued to potential bidders in February 2000. Upon
response from the qualified potential bidders and execution of the
confidentiality agreements, offering memoranda and materials were provided to
the bidders. First stage indicative bids were received on May 25, 2000. The
short list of qualified bidders for each of the seven bundles being offered was
completed and bidders notified by June 6, 2000. The second stage due diligence
process was started on June 6, 2000, and will continue through mid-August.
Final bids and the selection of winning bids will occur in late August and early
September 2000. Close of sale and transfer of ownership should occur between
December 2000 and mid-2001.
7
<PAGE>
NOTE 5. LONG TERM DEBT
------------------------
On June 9, 2000, the Company issued $200 million of floating rate notes
that will mature on June 12, 2001. Interest on the notes is payable quarterly
commencing on September 9, 2000. The interest rate on the notes for each
interest period will be a floating rate, subject to adjustment every three
months, equal to the London InterBank Offered Rate (LIBOR) for three-month U.S.
dollar deposits plus a spread of 0.50%. These notes will not be entitled to any
sinking fund and are non-callable. The net proceeds of the $200 million issue
were used to redeem $100 million of floating rate notes on July 14, 2000, and
the remaining proceeds were used to reduce the amount of the Company's
commercial paper outstanding.
NOTE 6. SHORT-TERM BORROWINGS
-------------------------------
The Company's commercial paper balance decreased from approximately $109.6
million at December 31, 1999, to approximately $101.8 million at March 31, 2000.
On June 30, 2000, the Company had no commercial paper outstanding, as a result
of the issuance of long-term debt in June 2000. See Note 5 - Long-Term Debt
(above).
NOTE 7. NEVADA RESTRUCTURING ACTIVITIES
-----------------------------------------
The PUCN approved stipulated agreements that resolve a federal lawsuit and
major restructuring issues including past costs. Refer to the REGULATORY
MATTERS section in ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS of this report for a discussion of these
matters. The Company has agreed to sell its generation assets and the
stipulated agreements provide for the disposition of the proceeds from the sale
of those assets.
As a result, the Company is evaluating the impact of these regulatory
actions on the value of certain Regulatory Assets currently reflected in the
Condensed Consolidated Balance Sheets. The evaluation relates to the
recoverability of Regulatory Assets, primarily related to generating activities,
given the provisions of the stipulated agreements.
NOTE 8. SUBSEQUENT EVENTS
---------------------------
On July 24, 2000 the Company received a 30-day extension of its $150
million Credit Facility to August 28, 2000, in accordance with the terms of the
credit agreement. The Company has requested a 364-day extension of this
facility which, if granted by the participating banks, would extend this
facility to August 27, 2001.
8
<PAGE>
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The information in this Form 10-Q includes forward-looking statements
within the meaning of the Private Securities Litigation Reform Act of 1995.
These forward-looking statements relate to anticipated financial performance,
management's plans and objectives for future operations, business prospects,
outcome of regulatory proceedings, market conditions and other matters. Words
such as "anticipate," "believe," "estimate," "expect," "intend," "plan" and
"objective" and other similar expressions identify those statements that are
forward-looking. These statements are based on management's beliefs and
assumptions and on information currently available to management. Actual results
could differ materially from those contemplated by the forward-looking
statements. In addition to any assumptions and other factors referred to
specifically in connection with such statements, factors that could cause Sierra
Pacific Power Company's (SPPC's) actual results to differ materially from those
contemplated in any forward-looking statement include, among others, the
following: (1) failure to receive judicial approval of the settlement agreement
recently approved by the PUCN, or other difficulties relating to the
implementation of the settlement; (2) fluctuations in electric, gas and other
commodity prices, particularly a continuation of the recent volatility in
purchased power prices in the western United States, and the ability to manage
such fluctuations successfully; (3) the pace and extent of the ongoing
restructuring of the electric and gas industries in Nevada and California; (4)
the outcome of regulatory and legislative proceedings and operational changes
related to industry restructuring; (5) the amount SPPC is allowed to recover
from customers for certain costs that prove to be uneconomic in the new
competitive market; (6) the outcome of ongoing and future regulatory
proceedings; (7) management's ability to integrate the operations of Nevada
Power Company (NVP) and SPPC, and to implement and realize anticipated cost
savings from the merger of SPR and NVP; (8) the results of the contemplated
sales by SPPC of its Nevada generating assets; (9) industrial, commercial and
residential growth in the service territory of SPPC; (10) changes in the capital
markets and interest rates affecting the ability to finance capital
requirements; (11) the loss of any significant customers; (12) the weather and
other natural phenomena; and (13) changes in the business of major customers
that may result in changes in the demand for services of SPPC. Other factors
and assumptions not identified above may also have been involved in deriving
these forward-looking statements, and the failure of those other assumptions to
be realized, as well as other factors, may also cause actual results to differ
materially from those projected. SPPC assumes no obligation to update forward-
looking statements to reflect actual results, changes in assumptions or changes
in other factors affecting forward-looking statements.
RESULTS OF OPERATIONS
---------------------
As discussed in the results of operations discussion that follows,
operating results for the second quarter of 2000 were negatively affected by
higher fuel and purchased power costs during the same period. These costs were
reflective of significantly higher and extremely volatile prices for purchased
power that developed in May in the western United States and have continued
since. The Company cannot predict how long these unprecedented market
conditions will persist or how such a continuation could affect the Company's
future earnings. However, in order to mitigate the effect of higher fuel and
purchased power costs the Company entered into a stipulation permitting it to
file monthly fuel and purchased power adjustment cases to commence not later
than November 1, 2000. Customer price increases that result from higher fuel
and purchased power costs are to be capped at incrementally increased or
decreased rates over six-month periods. Comparative fuel and purchased power
cost information is included in the results of operations discussion that
follows. See "Regulatory Matters" below.
The components of gross margin are set forth below (dollars in thousands):
9
<PAGE>
<TABLE>
<CAPTION>
Three Months Six Months
Ended June 30, Ended June 30,
------------- -------------
Change from Change from
2000 1999 Prior Year % 2000 1999 Prior Year %
---------- ---------- -------------- ---------- ---------- ---------------
<S> <C> <C> <C> <C> <C> <C>
Operating Revenues:
Electric $ 176,820 $ 147,348 20.0% $ 334,442 $ 291,651 14.7%
Gas 16,851 18,851 -10.6% 51,311 56,878 -9.8%
Water 15,335 13,619 12.6% 25,584 23,900 7.0%
--------- --------- ---------- --------- --------- ---------
Total Revenues 209,006 179,818 16.2% 411,337 372,429 10.4%
Energy Costs:
Electric 116,031 68,478 69.4% 194,787 135,616 43.6%
Gas 11,470 12,658 -9.4% 34,321 37,375 -8.2%
---------- --------- ---------- --------- --------- ---------
Total Energy Costs 127,501 81,136 57.1% 229,108 172,991 32.4%
---------- --------- --------- --------- --------- ---------
Gross Margin 81,505 98,682 -17.4% 182,229 199,438 -8.6%
========== ========= ========= ========= ========= =========
Gross Margin by Segment:
Electric 60,789 78,870 -22.9% 139,655 156,035 -10.5%
Gas 5,381 6,193 -13.1% 16,990 19,503 -12.9%
Water 15,335 13,619 12.6% 25,584 23,900 7.0%
---------- --------- ---------- --------- --------- --------
Total $ 81,505 $ 98,682 -17.4% $ 182,229 $ 199,438 -8.6%
========== ========= ========== ========= ========= ========
</TABLE>
The causes for significant changes in specific lines comprising the results
of operations are as follows (dollars in thousands):
<TABLE>
<CAPTION>
Three Months Six Months
Ended June 30, Ended June 30,
------------- -------------
<S> <C> <C> <C> <C> <C> <C>
Change from Change from
2000 1999 Prior Year % 2000 1999 Prior Year %
---------- ---------- -------------- ---------- ---------- ---------------
Electric Operating Revenues:
Residential $ 38,279 $ 38,486 -0.5% $ 86,190 $ 86,011 0.2%
Commercial 48,627 46,294 5.0% 93,426 89,699 4.2%
Industrial 48,900 46,548 5.1% 94,014 91,915 2.3%
--------- --------- ---------- --------- ---------- -----------
Retail revenues 135,806 131,328 3.4% 273,630 267,625 2.2%
Other 41,014 16,020 156.0% 60,812 24,026 153.1%
--------- --------- ---------- --------- ---------- -----------
Total Revenues $ 176,820 $ 147,348 20.0% $ 334,442 $ 291,651 14.7%
========= ========= ========== ========== ========== ===========
Retail sales in thousands of
megawatt-hours (MWH) 2,131 2,046 4.2% 4,248 4,140 2.6%
--------- --------- ---------- --------- ---------- -----------
Average retail revenue
per MWH $ 63.73 $ 64.19 -0.7% $ 64.41 $ 64.64 -0.4%
</TABLE>
Residential revenues decreased slightly for the three months ended June 30,
2000 and increased slightly for the six months ended June 30, 2000. These
changes were due to increases in total customers over the prior periods largely
being offset by lower use per customer as a result of milder weather in 2000
compared to the same periods in 1999.
Commercial revenues increased for both the three months and six months
ended June 30, 2000. This was due primarily to increases of 3.3% and 3.4%,
respectively, in customers and, to a lesser extent, usage at higher billing
rates within the class.
10
<PAGE>
Industrial revenues also increased for both the three months and six months
ended June 30, 2000. This was due to a change in classification of one customer
to the commercial class offset by increases in the number of smaller industrial
customers and to higher usage by the remaining large industrial customers.
Other electric revenues were higher in the second quarter of 2000 compared
to the prior year primarily due to a $24.9 million increase in wholesale
electric revenues that resulted from more wholesale opportunities offset by a
refund reserve reflecting an agreement with the PUCN. Similarly, other electric
revenues were higher for the six months ended June 30, 2000, due to a $32.8
million increase in wholesale electric sales. The increase for the six months
ended June 30, 2000, was also due in part to the 1999 reclassification of a $4.3
million reserve to revenues from operating expense, that was made in order to
reflect a refund resulting from an agreement with the PUCN to refund a share of
earnings.
<TABLE>
<CAPTION>
Three Months Six Months
Ended June 30, Ended June 30,
-------------- --------------
Change from Change from
2000 1999 Prior Year % 2000 1999 Prior Year %
------------ ------------ ----------- ------------ ----------- -----------
<S> <C> <C> <C> <C> <C> <C>
Gas Operating Revenues ($000):
Residential $ 6,212 $ 8,273 -24.9% $ 22,938 $ 25,216 -9.0%
Commercial 3,292 4,311 -23.6% 11,716 13,149 -10.9%
Industrial 2,111 2,391 -11.7% 5,457 6,118 -10.8%
Deferred Energy 1,096 - - 720 - -
Miscellaneous 595 412 44.4% 1,008 943 6.9%
------------ ------------ ----------- ------------ ----------- ---------
Total retail revenue 13,306 15,387 -13.5% 41,839 45,426 -7.9%
Wholesale revenue 3,545 3,464 2.3% 9,472 11,452 -17.3%
------------ ------------ ----------- ------------ ----------- ---------
Total Revenues $ 16,851 18,851 -10.6% 51,311 56,878 -9.8%
============ ============ =========== ============ =========== =========
Sales Decatherms (Dth):
Retail 1,937,604 2,621,342 -26.1% 7,066,300 8,021,177 -11.9%
Wholesale 1,160,969 1,797,396 -35.4% 3,542,176 5,548,332 -36.2%
------------ ------------ ----------- ------------ ----------- ---------
Total 3,098,573 4,418,738 -29.9% 10,608,476 13,569,509 -21.8%
------------ ------------ ----------- ------------ ----------- ---------
Average revenues per Dth
Retail $ 6.87 $ 5.87 17.0% $ 5.92 $ 5.66 4.5%
Wholesale $ 3.05 $ 1.93 58.4% $ 2.67 $ 2.06 29.6%
</TABLE>
The three months ended June 30, 2000, continued to show decreased gas
revenues among residential, commercial and industrial customers, the result of
significantly lower usage per customer due to mild weather conditions. The
quarter's reduced usage exceeded the continued increases in residential and
commercial customers of 4.4% and 2.6%, respectively. Similarly, the six-month
period ended June 30, 2000, reflected significant reductions in usage by all
classes of retail customers, in spite of increases in residential and commercial
customers of 4.9% and 2.9%, respectively.
A small increase in wholesale gas revenues for the second quarter of 2000
over the same period in 1999 somewhat reduced the wholesale revenue shortfall in
the first quarter of 2000, which had resulted primarily from the expiration of
three short-term gas contracts that were included in 1999 revenues.
<TABLE>
<CAPTION>
Three Months Six Months
Ended June 30, Ended June 30,
-------------- --------------
Change from Change from
2000 1999 Prior Year % 2000 1999 Prior Year%
------------ ------------ ------------ ------------ ----------- -----------
<S> <C> <C> <C> <C> <C> <C>
Water Operating Revenues ($000) $ 15,335 $ 13,619 12.6% $ 25,584 $ 23,900 7.0%
============ ============ =========== ============ =========== =========
</TABLE>
11
<PAGE>
Water revenues were higher for the second quarter of 2000 due to a 7.4%
increase in the number of customers and increased use per customer, primarily by
the Company's irrigation customers. Water revenues for the six months ended
June 30, 2000, also increased compared to the prior year due to increases in the
numbers of customers and increased use per customer.
<TABLE>
<CAPTION>
Three Months Six Months
Ended June 30, Ended June 30,
-------------- --------------
Change from Change from
2000 1999 Prior Year % 2000 1999 Prior Year%
------------ ------------ ------------ ------------ ------------ -----------
<S> <C> <C> <C> <C> <C> <C>
Purchased Power ($000) $ 71,949 $ 42,111 70.9% $ 121,429 $ 82,779 46.7%
Purchased Power in thousands
of MWHs 1,706 1,703 0.2% 3,299 3,023 9.1%
Average cost per MWH
of Purchased Power $ 42.17 $ 24.73 70.6% $ 36.81 $ 27.38 34.4%
</TABLE>
Purchased power costs were higher for the three and six months ended June
30, 2000 because the Company fulfilled more of its total energy requirements
with more expensive economy energy purchased power, which significantly
increased in cost from the prior period.
<TABLE>
<CAPTION>
Three Months Six Months
Ended June 30, Ended June 30,
-------------- --------------
Change from Change from
2000 1999 Prior Year % 2000 1999 Prior Year%
------------ ------------ ------------ ------------ ----------- -----------
<S> <C> <C> <C> <C> <C> <C>
Fuel for Power Generation ($000) $ 44,082 $ 26,367 67.2% $ 73,358 $ 52,837 38.8%
Thousands of MWHs generated 1,343 1,146 17.2% 2,543 2,319 9.7%
Average cost per MWH
of Generated Power $ 32.82 $ 23.01 42.7% $ 28.85 $ 22.78 26.6%
</TABLE>
Fuel for generation costs for the both the three month and six month periods
ended June 30, 2000, were significantly higher than the same periods of the
prior year as gas prices increased significantly and volumes were higher to
accommodate greater system load.
<TABLE>
<CAPTION>
Three Months Six Months
Ended June 30, Ended June 30,
-------------- --------------
Change from Change from
2000 1999 Prior Year % 2000 1999 Prior Year%
------------ ------------ ------------ ------------ ----------- -----------
<S> <C> <C> <C> <C> <C> <C>
Gas Purchased for Resale ($000)
Retail $ 7,760 $ 9,444 -17.8% $ 24,898 $ 27,005 -7.8%
Wholesale 3,710 3,214 15.4% 9,423 3,023 -9.1%
------------ ------------ ------------ ------------ ----------- -----------
Total 11,470 12,658 -9.4% 34,321 37,375 -8.2%
============ ============ ============ ============ =========== ==========
Gas Purchased for Resale
(thousands of decatherms)
Retail $ 1,945 $ 2,621 -25.8% $ 6,585 $ 8,025 -17.9%
Wholesale 1,162 1,797 -35.3% 3,543 5,548 -36.1%
------------ ------------ ------------ ------------ ----------- ----------
Total 3,107 4,418 -29.7% 10,128 13,573 -25.4%
============ ============ ============ ============ =========== ==========
Average cost per decatherm)
Retail $ 3.99 $ 3.60 10.8% $ 3.78 $ 3.37 12.2%
Wholesale $ 3.19 $ 1.79 78.2% $ 2.66 $ 1.87 42.2%
</TABLE>
12
<PAGE>
The cost of retail gas purchased for resale decreased for the three and six
months ended June 30, 2000 as reduced demand due to milder weather more than
offset increases in gas unit prices.
<TABLE>
<CAPTION>
Three Months Six Months
Ended June 30, Ended June 30,
(in $000's) (in $000's)
-------------- --------------
Change from Change from
2000 1999 Prior Year % 2000 1999 Prior Year%
------------ ------------ ------------ ------------ ----------- -----------
<S> <C> <C> <C> <C> <C> <C>
Allowance for other funds
used during construction $ 84 $ - - $ 152 $ - -
Allowance for borrowed funds
used during construction 634 236 168.6% 1,116 434 157.1%
------------ ------------ ------------ ------------ ----------- -----------
Total 718 236 204.2% 1,268 434 192.2%
============ ============ ============ ============ =========== ===========
</TABLE>
Total allowance for funds used during construction (AFUDC) is higher for the
three and six months ended June 30, 2000, as compared to the same periods in
1999 because of higher construction work in progress balances in 2000.
<TABLE>
<CAPTION>
Three Months Six Months
Ended June 30, Ended June 30,
(in $000's) (in $000's)
-------------- --------------
Change from Change from
2000 1999 Prior Year % 2000 1999 Prior Year%
------------ ------------ ------------ ------------ ----------- -----------
<S> <C> <C> <C> <C> <C> <C>
Other operating expense $ 31,898 $ 30,765 3.7% $ 59,767 $ 54,547 9.6%
Maintenance expense 5,228 5,164 1.2% 9,713 10,660 -8.9%
Income taxes 1,616 8,597 -81.2% 12,650 20,409 -38.0%
Interest charges-other 4,197 2,280 84.1% 7,408 4,883 51.7%
</TABLE>
Other operating expense was higher for the second quarter of 2000 due to
increased legal fees over the same period in 1999. Other operating expense for
the six months ended June 30, 2000 also increased as compared to the same period
in 1999 due to increased legal fees in the current year and a first quarter 1999
reclassification of a reserve to revenues of $4.3 million from operating expense
that was made in order to reflect a refund resulting from an agreement with the
PUCN to refund a share of earnings.
Maintenance costs for the three months ended June 30, 2000 were comparable
to the same period in 1999, and were lower for the six months ended June 30,
2000 due to slightly lower plant maintenance expenses in the first quarter of
2000 than in the same period in 1999.
Income taxes decreased for both the three and six months periods ended June
30, 2000, due to comparable reductions in pre-tax income in 2000 as compared to
the same periods in 1999.
Interest charges-other were higher for the three and six months ended June
30, 2000, due to significantly higher commercial paper balances during those
periods as compared to the same periods in 1999, and due to interest on the $200
million of floating rate notes issued in early June 2000.
FINANCIAL CONDITION, LIQUIDITY AND CAPITAL RESOURCES
----------------------------------------------------
13
<PAGE>
During the first six months of 2000, the Company earned approximately $22.0
million in income before preferred stock dividends. It declared $1.95 million
in dividends to holders of its preferred stock and declared $38.0 million in
common stock dividends to its parent, Sierra Pacific Resources.
Cash flows during the six months ended June 30, 2000 increased compared to
the same period in 1999. Cash flows were greater due to an increase in cash
provided by financing activities, a decrease in cash used for investing
activities, and, to a lesser extent, an increase in cash flows from operating
activities. The increase in cash flows from financing activities is primarily
the result of a significant increase in long-term debt in excess of the decrease
in short-term borrowings. The decrease in cash used for investing activities
was due to the Company's 1999 acquisition of General Electric Capital
Corporation's interest in Pinon Pine Company L.L.C.
Construction Expenditures and Financing
---------------------------------------
The Company's construction program and capital requirements for the period
2000-2004 were originally discussed in the Company's 1999 Annual Report on Form
10-K. Of the amount projected for 2000 ($137.7 million), $52.7 million (38.3%)
had been spent as of June 30, 2000. Internally generated funds provided 71.5%
of construction expenditures.
Financing
---------
On June 9, 2000, the Company issued $200 million of floating rate notes,
that will mature on June 12, 2001. Interest on the notes is payable quarterly
commencing on September 9, 2000. The interest rate on the notes for each
interest period will be a floating rate, subject to adjustment every three
months, equal to the London InterBank Offered Rate (LIBOR) for three-month U.S.
dollar deposits plus a spread of 0.50%. These notes will not be entitled to any
sinking fund and are non-callable. The net proceeds of the $200 million issue
were used to redeem $100 million of floating rate notes on July 14, 2000, and
the remaining proceeds were used to reduce the amount of the Company's
commercial paper outstanding.
On July 24, 2000 the Company received a 30-day extension of its $150
million Credit Facility to August 28, 2000, in accordance with the terms of the
credit agreement. The Company has requested a 364-day extension of this
facility which, if granted by the participating banks, would extend this
facility to August 27, 2001.
Generation Divestiture
----------------------
In accordance with the revised Divestiture Plan stipulation approved by the
PUCN in February 2000 (see the 1999 Annual Report on Form 10-K), SPR is offering
for sale generation assets with peak capacity of approximately 2,985 megawatts
(MW), with approximately 1045 MW owned by SPPC and approximately 1,940 MW owned
by NVP. Letters of interest were issued to potential bidders in February 2000.
Upon response from the qualified potential bidders and execution of the
confidentiality agreements, offering memoranda and materials were provided to
the bidders. First stage indicative bids were received on May 25, 2000. The
short list of qualified bidders for each of the seven bundles being offered was
completed and bidders notified by June 6, 2000. The second stage due diligence
process was started on June 6, 2000, and will continue through mid-August.
Final bids and the selection of winning bids will occur in late August and early
September 2000. Close of sale and transfer of ownership should occur between
December 2000 and mid-2001.
REGULATORY MATTERS
------------------
Nevada Electric Restructuring Activities
----------------------------------------
Competition was originally scheduled to start on March 1, 2000. However,
in February 2000 the Governor of Nevada delayed the start date of competition
indefinitely. Generally, restructuring regulations and PUCN decisions during
the first and second quarters of 2000 proceeded slowly. Numerous hearings and
workshops have been held by the Public Utilities Commission of Nevada (PUCN)
regarding two important regulations, Provider of Last Resort and Past Costs.
On March 28, 2000, the Company and its parent, Sierra Pacific Resources,
together with Nevada Power Company, filed a federal lawsuit challenging Nevada's
laws providing for competition in the electric utility industry and the PUCN's
implementation of competition. See SPR's Form 8-K, filed on April 17, 2000.
14
<PAGE>
On July 20, 2000, the PUCN approved stipulated agreements that resolve the
federal lawsuit and major restructuring issues including past costs. See SPR's
Form 8-K, filed on July 26, 2000. On August 3, 2000, the PUCN approved
revisions to the stipulated agreements. The stipulations pave the way for open
access to occur in a phased manner beginning in November for large commercial
customers and continuing until September 2001 for residential customers. The
following are highlights of the stipulations:
Opening Dates
Retail access choice will be phased in based upon customer size. Customers
will be able to choose a new supplier for energy, metering, billing or customer
service according to the following schedule:
November 1, 2000 - Large commercial customers including large resorts
and mines
April 1, 2001 - Medium commercial customers
June 1, 2001 - Small commercial customers
September 1, 2001 - December 1, 2001 - residential customers
Incentives for Company to Meet Open Access Dates
Provided that open access procedures, including billing and settlement, are
in place by the open access dates, the Company will be allowed to retain up to
$9 million from any gain on the divestiture of generation assets.
Transmission Access
The Company has filed a modified Open Access Tariff with FERC to facilitate
retail open access. The Company also continues to pursue compliance with FERC
Order 2000 and the formation of a regional transmission organization (RTO).
Also see FERC Matters, below.
Past Costs
Major past cost issues are resolved by the stipulations. The Company has
waived its rights to the collection of any past costs other than those provided
for in the stipulations. The parties have agreed that the stipulations
eliminate the need for a past cost regulation.
Generation
The gain on the sale of generation facilities will be calculated based upon
recorded book values as of the date of sale and includes costs of sale, less
applicable taxes. Common and general plant allocable to generation will be
recoverable from the gain. Additional gain, if any, up to $9 million will be
applied to the allowed incentives to the Company for meeting retail open access
dates, as described above. Any remaining gain will be set aside in an escrow
account to be utilized to pay down costs associated with above-market purchased
power contracts.
Purchased Power Contracts
The Company will auction its purchased power contracts on an annual basis
in the wholesale markets. If the auction does not yield sufficient proceeds to
pay for the purchased power contracts, the Company will collect the difference
from all customers through a non-bypassable wires charge. This Purchased Power
Annual Auction Mechanism (PPAAM) charge will be in place on November 1, 2000
when the market opens.
To the extent that there are tax or market advantages, the Company will
pursue a competitive permanent auction of purchased power contracts. Such an
auction would be funded by an amount not to exceed the principal and interest in
the escrow account that was funded by the gain on the sale of generation assets.
If the permanent auction does not proceed or if such auction does not
exhaust the generation escrow account, the PPAAM charge will be reduced by an
annuity calculated on any remaining amount in the generation escrow account.
Metering
15
<PAGE>
Customers will have the opportunity to purchase metering equipment directly
from SPPC or through an alternative seller. Such assets will be sold at net
book value.
Transition Costs
The ability of the Company to recover costs it expects to spend to open the
market, referred to as transition costs, was not resolved by the stipulations.
The Company expects to petition the PUCN in the near future to request recovery
of its transition costs.
Earnings Sharing
The stipulated agreements discussed earlier set the shared earnings refund
to customers at a total of $9.3 million, for which the Company has recorded
appropriate reserves.
In other matters related to restructuring, the PUCN has continued
rulemaking and discussion related to a number of topics including:
Independent Scheduling Administrator (ISA)
On March 21, 2000, the PUCN issued a Notice of Workshop on retail
transmission issues including funding for the Mountain West Independent
Scheduling Administrator (MWISA). In a workshop held April 12, various parties
advocated that the utilities provide funding and that the PUCN should provide
cost recovery for the utilities. The PUCN and the parties will continue to
explore this issue in the future workshops.
During the second quarter of 2000 the MWISA option has not been given a
means of funding its operation. Though this option is still available, the
Company is planning and proposing utility transmission open access tariffs until
an RTO can be put in place. See FERC Matters, below, for a further discussion
of transmission access issues.
Unbundling of Utility Services
On May 4, 2000, the PUCN issued a final order (the "Order") that was
consistent with its September 1999 interim order. See the Company's 1999 Annual
Report on Form 10-K for additional information on the interim order. The Order
reduces the Company's revenue requirement and return on equity for distribution
service for those customers who choose to leave the Company upon the start of
retail competition. The Company filed a Petition for Reconsideration with the
PUCN on May 19. The Petition for Reconsideration was granted on July 12 by the
PUCN.
Provider of Last Resort (PLR)
The PLR will provide electric service to customers who do not select an
electricity provider and to customers who are not able to obtain service from an
alternative seller after the date competition begins. Nevada Senate Bill 438
provides for the electric distribution utility (EDU) to provide PLR services
from the start of competition until July 1, 2001. The Company is seeking to
modify the PLR regulation. If the Company does not provide PLR services, the
May 4, 2000 Order referred to above could result in a reduction of revenues.
On May 3, 2000, the PUCN reissued the PLR regulation for comment. The
current draft regulation continues to contain various provisions that could have
negative financial ramifications for the Company. See the Company's 1999 Annual
Report on Form 10-K.
The PUCN is nearing completion of this regulation. Certain legal issues
surrounding the EDU or PLR ability to provide unbundled metering services are
not resolved. In addition, the proposed regulation continues to contain a
strict standard of conduct to govern the relationship between EDU and PLR
functions. Implementation of these provisions could have negative financial
ramifications.
California Matters
------------------
Generation Divestiture
16
<PAGE>
On March 2, 2000, the Company filed a new application requesting exemption
from California Public Utility Commission (CPUC) approval of the Nevada-based
generation divestiture transaction. The Company cited several reasons for the
exemption including that the PUCN and FERC oversight of the generation
divestiture will assure reliability and market power mitigation as required by
California's electric restructuring legislation.
Distribution Performance-Based Rate-making (PBR)
On May 4, 2000, the CPUC dismissed without prejudice the Company's January
3, 2000 distribution PBR proposal (see the Company's 1999 Annual Report on Form
10-K). The order accepted the application as meeting the compliance requirement
but directed the Company to re-file it when the cost of capital and cost of
service studies are available. On May 8, 2000, the Company filed its 2001 Cost
of Capital application. On July 3, 2000, the Company re-submitted the PBR
proposal along with the Cost of Service Study.
FERC Matters
------------
Independent Transmission Company
On April 26, 2000, the Company, together with Nevada Power Company,
Portland General Electric Company, Avista Corporation, The Montana Power
Company, and Puget Sound Energy, Inc. agreed to study the formation of a for-
profit Independent Transmission Company (ITC). The ITC is continuing to review
its options as the Regional Transmission Organization (RTO) process continues
toward the October 15, 2000 filing deadline.
Transmission Rate Case
In March 1999, the Company filed an application with the FERC to increase
its Open Access Transmission rates. See the Company's 1999 Annual Report on
Form 10-K. On March 30, 2000, the Company filed a Loss Study that the Company
agreed to provide in the partial settlement that was approved in January 2000.
On April 27, 2000, a pre-hearing conference was held to set a procedural
schedule for remaining issues. A settlement has been reached on the loss study
that will be submitted to the FERC for approval.
Generation Tariffs and Transitional Purchase Power Agreements
On March 31, 2000, the Company filed for approval of generation tariffs
that contain the rates, terms and conditions under which the new owners of
divested generation would operate after divestiture. Included in the filing are
the Transitional Purchase Power Agreements (TPPAs) between the Company and the
new owners.
On May 31, 2000, the FERC accepted the tariffs and the TPPAs. The FERC
required one change to the TPPAs. The FERC also set for hearing the level of
rates for ancillary services in the tariffs and the rates in the TPPAs. A
procedural schedule has been established for the hearing on rates. On June 29,
2000, the Company filed the revised TPPAs in compliance with the May 31 order.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES
ABOUT MARKET RISK
See "Results of Operations" above for a discussion of recent increased
prices and volatility in the markets for purchased power and fuel, which have
had a negative effect on the financial performance of SPPC.
17
<PAGE>
PART II
-------
ITEM 1. LEGAL PROCEEDINGS
On March 28, 2000, SPR, NVP, and SPPC filed a lawsuit in Federal District
Court in Nevada asking the court to declare unconstitutional certain aspects of
the Nevada laws that created the framework for a deregulated electric market in
Nevada.
On July 20, 2000, the PUCN approved a stipulation (the "Settlement")
entered into among the parties to state and federal lawsuits permitting NVP to
increase its rates effective August 1, 2000, by approximately $48 million
annually to recover increased costs of fuel and purchased power, and to update
its going-forward costs of fuel and purchased power thereafter with monthly fuel
and purchased power filings up to March 2003. Increases and/or decreases are
capped at incrementally increased or decreased rates over successive six-month
periods at .95 mils for the first six months, 1.15 mils for the second six
months, 1.25 mils for the third six months, 1.55 mils for the next six months,
and 1.75 mils for the remaining period. The Settlement also permits SPPC to
commence filing monthly fuel and purchased power adjustment cases on the same
basis to commence not later than November 1, 2000. SPPC fuel and purchased
power increases and/or decreases are also capped at incrementally increased or
decreased rates over successive six-month periods starting October 1, 2000 at
4.5 mils for the first six-month period followed by .95, 1.15, 1.35, 1.55, and
1.75 mils for each successive six-month period.
The Settlement also resolves numerous other issues relating to the
restructuring of the electric industry in Nevada, including phased-in access to
competitive markets by customer class, recovery of stranded costs, auctioning
out-of-market qualified facility and other purchased power contracts, imposition
of a wires charge to recover any balance, and filing of new proceedings to
address metering costs and transition costs. The Settlement was contingent on
stipulations entered into with third parties with respect to several other
pending dockets. On July 28, 2000, the parties revised the Settlement to remove
the contingencies. The revisions were approved by the PUCN on August 3, 2000,
but still remain subject to judicial approval as well as future regulatory
proceedings relating to the filing of monthly fuel and purchased power cases,
recovery of stranded costs, and divestiture of generation proceeds. The outcome
of the dockets and proceedings cannot be predicted at this time; however,
unfavorable treatment of any of these proceedings would have a negative effect
on the economic value of the Settlement.
See the Form 8-K filed July 26, 2000 and Regulatory Matters, above, for
additional details.
Although the Company is involved in other ongoing litigation on a variety
of matters, it is management's opinion that none individually or collectively
are material to the Company's financial position.
ITEM 5. OTHER INFORMATION
On July 12, 2000, SPR issued a press release announcing that fuel and
purchased power costs would negatively impact earnings for the second quarter
and the remainder of 2000. For additional details, see the Form 8-K filed July
14, 2000.
On July 20, 2000, SPR issued a press release announcing that SPR, its
utility subsidiaries, SPPC and Nevada Power Company (NVP), Nevada regulators and
several other parties took steps toward a settlement of issues involving
restructuring the electric utility industry in the state, setting new electric
rates for NVP's and SPPC's customers and resolving other issues involved in
state and federal court cases filed by NVP and SPPC. For additional details,
see the Form 8-K filed July 26, 2000.
On July 21, 2000, SPR issued a press release announcing the resignation of
Michael R. Niggli, Chairman and Chief Executive Officer of Sierra Pacific
Resources. For additional details, see the Form 8-K filed July 26, 2000.
On August 9, 2000, the Board of Directors of Sierra Pacific Resources
announced that Walter M. Higgins had been named chairman, president and chief
executive officer. Mr. Higgins returns to SPR, where he served from 1994 to
18
<PAGE>
1998 as chairman of the board, president and chief executive officer. Since
January 1998, he has served as chairman and chief executive officer of Atlanta,
Georgia-based AGL Resources, Inc., the holding company of Atlanta Gas Light
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits filed with this Form 10-Q.
(27) The Financial Data Schedule containing summary financial
information extracted from the condensed consolidated financial
statements filed on Form 10-Q for the six month period ended June
30, 2000, for Sierra Pacific Power Company and is qualified in
its entirety by reference to such financial statements.
(b) Reports on Form 8-K
Form 8-K filed on April 21, 2000 - Item 5, Other Events
Described, and included as an exhibit, SPR's press release dated April 18,
2000, announcing the resignation of Malyn K. Malquist, President and Chief
Operating Officer of SPR, and President of SPPC.
19
<PAGE>
SIGNATURES
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 Power Company
---------------------------------
(Registrant)
Date: August 14, 2000 By /s/ Mark A. Ruelle
----------------------------- -------------------
Mark A. Ruelle
Senior Vice President and
Chief Financial Officer
(Principal Financial Officer)
Date: August 14, 2000 By /s/ Mary O. Simmons
------------------------------ --------------------
Mary O. Simmons
Controller
(Principal Accounting Officer)
20
