<PAGE>
FORM 10-Q
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
Quarterly Report Under Section 13 or 15(d)
of the Securities Exchange Act of 1934
For Quarter Ended June 30, 1999 Commission File No. 1-4698
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Nevada Power Company
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(Exact name of registrant as specified in its charter)
Nevada 88-0045330
- ------------------------------- -------------------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
6226 West Sahara Avenue, Las Vegas, Nevada 89146
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(Address of principal executive offices) (Zip Code)
(702) 367-5000
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(Registrant's telephone number, including area code)
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(Former name, former address and former fiscal year, if changed since last
report.)
Indicate by check mark whether the 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.
Common Stock outstanding July 27, 1999, 51,265,117 shares.
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<PAGE>
PART I. FINANCIAL INFORMATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(In Thousands, Except Per Share Amounts)
(Unaudited)
FOR THE FOR THE
THREE MONTHS SIX MONTHS
ENDED JUNE 30, ENDED JUNE 30,
-------------- --------------
1999 1998 1999 1998
-------- -------- -------- --------
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
======== ======== ======== ========
See Notes to Condensed Consolidated Financial Statements.
<PAGE>
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
(Unaudited)
June 30, December 31,
1999 1998
------------- ------------
(In Thousands)
ELECTRIC PLANT:
Original cost ..................................... $2,784,359 $2,628,934
Less accumulated depreciation ..................... 748,814 708,791
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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
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2,270,394 2,199,886
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INVESTMENTS ......................................... 26,076 24,483
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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
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243,332 208,950
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DEFERRED CHARGES .................................... 174,524 174,505
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$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
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854,533 864,036
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Cumulative preferred stock ........................ - 3,265
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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
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188,872 188,872
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Long-term debt .................................... 1,028,977 900,227
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2,072,382 1,956,400
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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
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295,163 309,946
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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
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346,781 341,478
---------- ----------
$2,714,326 $2,607,824
========== ==========
See Notes to Condensed Consolidated Financial Statements.
<PAGE>
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
FOR THE SIX MONTHS
ENDED JUNE 30,
--------------------
1999 1998
-------- --------
(In Thousands)
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 $ -
======== ========
See Notes to Condensed Consolidated Financial Statements.
<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) 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
======= ======= ======= =======
<PAGE>
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 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
<PAGE>
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 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.
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
LIQUIDITY AND CAPITAL RESOURCES
Overall net cash flows decreased during the first six months of 1999, as
compared to 1998, primarily due to less cash being provided by operating
activities, partially offset by more cash being provided by financing
activities. The decrease in cash being provided by operating activities was
primarily due to increased operations, maintenance and interest costs. The
increase in net cash provided by financing activities is primarily due to the
issuance of the $130 million 6.2% Series A senior unsecured notes, due 2004.
The Company discontinued using the deferred energy mechanism to defer the
difference between the current cost of fuel plus net purchased power and base
energy costs beginning in June 1999. In July 1999, the Company filed a deferred
energy rate increase request for $44.3 million with the PUCN. The request
includes a $30.7 million increase in residential customers' energy rates and an
increase of $13.6 million in other customer rates. If approved, the increase
would be effective September 1, 1999. See the Industry Restructuring section.
Also see Note 3 to the condensed consolidated financial statements included in
this quarterly report.
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. On July 7, 1998, Sierra Pacific Resources and the
Company issued a press release announcing the filing of a joint merger
application with the PUCN for approval of their proposed merger. Stockholders
of both companies voted to approve the proposed merger. In December 1998, the
PUCN approved the proposed merger with conditions which the companies have
accepted. On April 14, 1999, the FERC approved the joint merger application
filed by the companies. On April 16, 1999 the Department of Justice approved
the proposed merger. The comment period for the SEC expired on June 8 with only
one comment received which was later rescinded. The proposed merger is expected
to close near the end of July. (See Note 6 to the condensed consolidated
financial statements included in this quarterly report.)
On March 30, 1999, the Company issued $130 million 6.2% Series A senior
unsecured notes, due 2004. The notes were issued under rule 144A with
registration rights. Net proceeds were used to repay the indebtedness under the
Company's line of credit. The PUCN approved the issuance of these securities on
August 29, 1997.
The Company's customer growth rate during 1998 and 1997 was 5.9 and 6.4
percent, respectively. The increase in customers for the first six months of
1999 was at an annualized rate of 6.2 percent. At June 30, 1999, the Company
provided electric service to 565,734 customers.
Pursuant to Nevada law, every three years the Company is required to file
with the PUCN a forecast of electricity demands for the next 20 years and the
Company's plans to meet those demands. The Company filed its 1997 Resource Plan
on June 3, 1997. On October 20, 1997, the PUCN rendered a decision on this
plan. Among the major items in the Company's 1997 Resource Plan which were
approved by the PUCN are the following:
(1) the Company will proceed to build a 500 kV transmission project known as
the Crystal Transmission Project. The project was completed and in
service during June 1999;
(2) the Company will continue to pursue a strategy of relying on bulk
power purchases to meet near-term incremental increases in load;
(3) the Company will proceed with a joint 230 kV transmission project
with the Colorado River Commission with costs subject to prudency review
in a future rate case;
(4) the Company received limited approval to proceed with six switchyard
projects;
(5) the Company received approval for pre-development costs to build two 144
megawatt (MW) combustion turbines in 2002 and 2003 which would be
converted to a 410 MW combined cycle plant in 2004. An amendment to the
1997 Resource Plan will need to be filed by September 1999 for full
approval if the Company wants to
<PAGE>
proceed with building the turbines.
A status report to the PUCN on the above projects was filed in February of
1999. The resource plan was approved and developed before the approval of
restructuring legislation. At this time the Company does not know the impact of
the legislation on its resource plan. See the Industry Restructuring section.
Also see Note 6 to the condensed consolidated financial statements included in
this quarterly report.
The Company may utilize internally generated cash and the proceeds from
IDBs, unsecured borrowings and preferred securities to meet capital expenditure
requirements through 1999.
During the third quarter of 1998, the Company began using open market
purchases of its common stock to meet the requirements of the Stock Purchase and
Dividend Reinvestment Plan (SPP). In preparation for the merger closing and
merger exchange consideration processing, the Company suspended the SPP
effective May 4, 1999. Shareholders were notified in writing on March 31, 1999.
After May 3, 1999 no investment or sale activity under the SPP will be
conducted. No action is required by SPP participants prior to the exchange,
however, any shareholders wishing to terminate their SPP account at any time may
make a written request to have their stock certificate mailed to them. Under
the SPP the Company issued 799,762 shares of its common stock in 1998.
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.
INDUSTRY RESTRUCTURING
In July 1997, the Governor of the state of Nevada signed into law Assembly
Bill 366 (AB366) which provides for competition to be implemented in the
electric utility industry in the state no later than December 31, 1999. The
Nevada state legislature passed SB438, an amendment to AB366. SB438 contains
several changes to AB366 including changing the start date of competition to
March 1, 2000 for all customers:
SB438 allows the utility to retain its name and logo for affiliated
businesses.
The Company and Sierra Pacific will be Providers of Last Resort (PLR) for
customers until July 1, 2001 at which time the utilities will have to
establish an affiliate company to provide these services. The rates the PLR
can charge are capped for a period of three years from the beginning of
competition in Nevada until March 1, 2003. Rates charged for the
Company's customers will be the prevailing rate on July 1, 1999, as
adjusted for the deferred energy filing discussed below.
The deferred energy accounting adjustment used by utilities to recover fuel
and purchased power costs will be repealed on October 1, 1999. This allows
the Company to file a deferred energy filing this summer to recover such
costs after which the rate will be capped. The PUCN cannot initiate or
conduct any proceedings to adjust the rates, earnings, rate base or rate of
return of the PLR during the time rates are capped.
After July 1, 2001, a licensed alternative seller of electricity may submit
an offer to provide PLR service if they request 10 percent of the PLR load,
provide service to more than one customer class and provide a discount of
five percent off the PLR rate. The PUCN may conduct an auction if it
determines that doing so is in the best interests of the customers upon
receiving an offer from an alternative seller. The successful bidder will
become the PLR for the auctioned customers. The remainder of the customers
will continue with the company providing their electric service before the
auction.
Utilities will honor the terms of existing purchased power contracts
including those with qualifying facilities. Recovery of qualifying
facilities purchased power stranded costs was also clarified.
SB438 expires if the merger between Sierra Pacific and the Company is not
completed.
<PAGE>
Following are highlights of other restructuring activities:
Compliance Plans
On April 1, 1999, the Company filed Part I of a two part Compliance Plan
filing with the PUCN. This filing provided certain information to the PUCN,
including a total revenue requirement for electric service based on cost data
for the 12 months ended December 31, 1998. This bundled revenue requirement
showed a revenue deficiency of $31 million based on a proposed rate of return on
rate base of 9.27 percent and a proposed return on equity of 11.9 percent.
Additionally, the revenue requirement was unbundled, or separated, into 26
different categories, which may be broadly characterized as potentially
competitive and noncompetitive services. This filing provided information to
the PUCN in accordance with its restructuring regulations and the merger order.
The Part I filing did not include proposed rates for customer classes. Hearings
on Part I of the filing are scheduled August 4 through 12, 1999. An order on
Part I is expected shortly thereafter.
The Part II filing required the Company to submit proposed rates for
bundled services on April 30, 1999. No further action is expected on this phase
of the filing. The Company is required to provide proposed rates for unbundled
noncompetitive services (mainly distribution services) 15 days after the Part I
order is issued. Rates for noncompetitive services will be effective on the day
retail access begins and will be frozen for three years, in accordance with the
merger order.
Past Costs
Past costs, which are commonly referred to as stranded costs in other
jurisdictions, will continue to be addressed in 1999. AB366 and SB438 define
the legal criteria that must be met in order to recover past costs. The PUCN
has conducted several workshops on past costs in which various topics were
discussed, including the characteristics that define recoverable past costs,
criteria for evaluating the effectiveness of mitigation efforts, options for
cost recovery mechanisms and applicable tax and accounting issues. The Company
has not released an estimate of its past costs, since such a calculation is
dependent on a variety of issues related to restructuring which, at this time,
are not fully resolved.
On April 8, 1999, the PUCN issued a revised proposed rule that specifies
the information a utility must include in its past cost filing. On June 1, the
PUCN deferred further action on the proposed rule until the impact of SB438 on
restructuring can be fully evaluated. The PUCN indicated they may resume
discussion of the past cost rule in August, however, no date has been set for
the continuation of the hearings. The final rule is expected to include the
date for the submission of the past cost filing, which will likely be 45 days
after the order from Part I of the Compliance Plan filing is issued. The
Company estimates its application for recovery of Past Costs will be submitted
in the fourth quarter of 1999.
Independent Scheduling Administrator
The move to retail competition in various states has included the
establishment of an entity to ensure reliable operation of transmission systems
and to assure equal and non-discriminatory access to those systems by all
alternative sellers. In California, an independent system operator (ISO) was
established. An ISO was also established in the Midwest. Nevada stakeholders
are pursuing the development of an ISA to address these functions as part of the
move to retail open access in Nevada. In time, it is expected that regional
entities, either ISO's or independent transmission companies, will be
established to perform these functions. The Company therefore considers the ISA
to be an interim solution that would facilitate retail open access in Nevada
while regional solutions develop. The PUCN issued an order providing guidance
to the parties on the development of an interim ISA on October 12, 1998. The
parties, including the Company, began a consensus process to develop the ISA.
The efforts of the established working group continue. As part of the
stipulation agreement (see Note 6 to the condensed consolidated financial
statements included in this quarterly report), the Company filed a final
proposal with the PUCN and the FERC in July 1999 to establish an ISA.
CONTINUING APPLICABILITY OF FAS 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
<PAGE>
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 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 that 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.
YEAR 2000
The Company has made Year 2000 readiness a top priority for all of its
departments. With the oversight of several officers, the Company has virtually
completed its review of all of its computers, software programs and electrical
systems to verify that appropriate actions are being taken in order to be Year
2000 ready, including the ability to process, calculate, compare and sequence
date data into the next century, and to make all necessary leap year
corrections.
A plan is in place and has been implemented to identify and correct
problems related to the Year 2000 issue and to test remediated systems,
including verification of the level of Year 2000 readiness of business partners
and suppliers. The responses of business partners and suppliers are evaluated
individually and responded to as appropriate. A centralized data base is used
to identify and track the progress of Year 2000 readiness activities Company-
wide. A centralized control over incoming correspondence and inquiries relating
to Year 2000 and external communication efforts is being maintained. The
Company's general purchasing policy requires that all newly purchased products
be Year 2000 ready or designed to allow the Company to determine whether such
products present Year 2000 issues.
The Company's Year 2000 readiness activities are tracked and reported
monthly to the North American Electric Reliability Council (NERC), an
association of all segments of the electric industry - investor-owned, federal,
rural electric cooperatives, state/municipal and provincial utilities,
independent power producers, and power marketers, with the general mission to
promote the reliability of the electricity supply for North America.
Overall status for the Company as of June 30, 1999 shows identification and
assessment of potential problems at 100% complete and remediation/testing at 99%
complete. The Company filed its' monthly report to the North American Electric
Reliability Council (NERC) on June 30, 1999 and has certified its' "Year 2000
Readiness With Limited Exceptions" status, based on NERC guidelines. All
generation units have been successfully tested to date, with the exception of
one generation unit that will be remediated and
<PAGE>
tested in October of 1999 coinciding with its annual scheduled maintenance
outage. The unit is similar to others in the Company's system that have been
remediated and tested and is not critical to the ability of the Company to
provide reliable service to customers during the rollover. No material
difficulties have been identified to date and none are anticipated.
Even though the Company is confident that its critical systems will be
fully remediated, the Company has initiated a corporate-wide process of Year
2000 contingency planning. Contingency planning has been influenced by the
responses received from business partners and suppliers received in upcoming
months, as well as the Company's determination of its reasonably worst case
scenario. The contingency plan is scheduled to be finalized by the second
quarter of 1999. The Company is also working with utility and non-utility
suppliers, generation and transmission operators and regional governmental
organizations to develop external contingency plans, where appropriate. The
reasonably worst case scenario anticipated would be loss of standard means of
communication. This has been addressed in contingency planning. Nevada Power
Company is confident that the steps taken to deal with this scenario, which
include several alternative means of communication such as two-way radio and
internal microwave and fiber optic systems, will provide sufficient backup in
the unlikely event of the loss of standard communication. As a summer peaking
utility, the Company's electrical loads in mid-winter are comparatively low.
Although contingency planning is by its nature speculative, the Year 2000
contingency plan will reduce the risk of material impacts on the Company's
operations due to Year 2000 problems. If the Company or its significant
business partners or suppliers were to fail to achieve Year 2000 readiness with
respect to critical systems, there could be a materially adverse impact on the
utility's financial position, results of operations and cash flows.
During 1998, the estimated total cumulative cost to the Company of
addressing Year 2000 readiness was determined to be in the range of $4 to $7
million, including operating and capital expenditures. Through June 1999,
approximately $2.6 million in operating expenses and approximately $1.3 million
in capital additions have been incurred. While additional expenditures and
capital additions will be incurred during 1999, the rate of expenditures and
capital additions is below original estimates. The estimated total cumulative
cost is reviewed and revised periodically.
<PAGE>
OPERATING RESULTS OF THE SECOND QUARTER OF 1999
COMPARED TO SECOND QUARTER OF 1998
Earnings per average common share were 23 cents for the second quarter of
1999, compared to 20 cents for the same period in 1998. The increase in
revenues and earnings available for common stock was due primarily to warmer
weather and customer growth. Revenues also increased due to an energy rate
increase effective March 1, 1999. The average number of customers increased 6.0
percent and kilowatthour sales, excluding sales for resale, were up 15.86
percent, as compared to the second quarter of 1998.
Fuel expense increased $4.6 million due primarily to increased generation.
Purchased power increased $6.6 million due primarily to increased power
purchases. The Company discontinued using the deferred energy mechanism to defer
the difference between the current cost of fuel plus net purchased power and
base energy costs beginning in June 1999. See the Liquidity and Capital
Resources section of Management's Discussion and Analysis of Financial Condition
included in this quarterly report. Other operations expense increased $2.9
million due primarily to charges for firm transmission service and increased
group insurance costs. Depreciation expense increased $2.0 million because of a
growing asset base. Interest on long-term debt increased by $2.3 million
primarily due to the issuance of the $130 million, 6.2% Series A senior
unsecured notes. Distribution requirements on Company-obligated preferred
securities of a subsidiary trust increased by $1.4 million due to the issuance
of the 7 3/4% trust issued preferred securities.
OPERATING RESULTS OF THE FIRST SIX MONTHS OF 1999
COMPARED TO FIRST SIX MONTHS OF 1998
Earnings per average common share were 32 cents for the first six months of
1999, compared to 34 cents for the same period in 1998. The decrease in
earnings available for common stock was primarily due to increased operations
and maintenance expense and increases in interest and depreciation expense due
to infrastructure requirements associated with customer growth. Revenues
increased primarily due to energy rate increases effective February 1, 1998 and
March 1, 1999. The average number of customers increased 5.97 percent and
kilowatthour sales, excluding sales for resale, were up 11.51 percent, as
compared to the first six months of 1998.
Fuel expense increased $8.6 million due primarily to increased generation.
Purchased power increased $9.4 million due primarily to increased power
purchases. The Company discontinued using the deferred energy mechanism to defer
the difference between the current cost of fuel plus net purchased power and
base energy costs beginning in June 1999. See the Liquidity and Capital
Resources section of Management's Discussion and Analysis of Financial Condition
included in this quarterly report. Other operations expense increased $3.4
million due primarily to charges for firm transmission service and increased
group insurance costs. Maintenance and repairs increased $1.5 million due
mainly to increased maintenance expense at the Reid Gardner Generating Station.
Depreciation expense increased $4.0 million because of a growing asset base.
Interest on long-term debt increased by $2.9 million primarily due to the
issuance of the $130 million, 6.2% Series A senior unsecured notes. Other
interest increased by $1.5 million primarily due to increased short-term
borrowing. Distribution requirements on Company-obligated preferred securities
of a subsidiary trust increased by $2.7 million due to the issuance of the 7
3/4% trust issued preferred securities.
<PAGE>
PART II. OTHER INFORMATION
Items 1 through 5. None.
Item 6. Exhibits and Reports on Form 8-K.
a. Exhibits.
Exhibits Filed Description
-------------- -----------
27 Financial Data Schedule
b. Reports on Form 8-K.
None.
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.
Nevada Power Company
--------------------
(Registrant)
STEVEN W. RIGAZIO
--------------------------------------
(Signature)
Date: July 27, 1999 Steven W. Rigazio
--------------
Vice President, Finance and Planning,
Treasurer, Chief Financial Officer
<TABLE> <S> <C>
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<LEGEND>
THE SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE CONDENSED
CONSOLIDATED BALANCE SHEET OF NEVADA POWER COMPANY AS OF JUNE 30, 1999 AND THE
RELATED CONDENSED CONSOLIDATED STATEMENTS OF INCOME AND CASH FLOWS FOR THE SIX
MONTHS ENDED JUNE 30, 1999 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH
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