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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 March 31, 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 April 30, 1999, 51,265,117 shares.
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PART I. FINANCIAL INFORMATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(In Thousands, Except Per Share Amounts)
(Unaudited)
FOR THE
THREE MONTHS
ENDED MARCH 31,
------------------
1999 1998
-------- --------
ELECTRIC REVENUES ......................................... $182,433 $165,263
OPERATING EXPENSES AND TAXES:
Fuel ................................................. 30,603 26,573
Purchased and interchanged power ..................... 53,860 51,055
Deferred energy cost
adjustments, net .................................... 3,789 (2,276)
-------- --------
Net energy costs .................................... 88,252 75,352
Other production operations .......................... 5,501 4,469
Other operations ..................................... 26,213 25,683
Maintenance and repairs .............................. 15,011 12,482
Provision for depreciation ........................... 19,704 17,711
General taxes ........................................ 5,378 5,369
Federal income taxes ................................. 1,413 2,934
-------- --------
161,472 144,000
-------- --------
OPERATING INCOME .......................................... 20,961 21,263
-------- --------
OTHER INCOME (EXPENSES):
Allowance for other funds used
during construction ................................. 2,253 2,199
Miscellaneous, net ................................... (319) (593)
-------- --------
1,934 1,606
-------- --------
INCOME BEFORE INTEREST DEDUCTIONS ......................... 22,895 22,869
-------- --------
INTEREST DEDUCTIONS:
Interest on long-term debt ........................... 14,706 14,108
Other interest ....................................... 2,011 566
Allowance for borrowed funds used
during construction ................................. (2,098) (1,178)
-------- --------
14,619 13,496
-------- --------
Distribution requirements
on company-obligated mandatorily
redeemable preferred securities
of subsidiary trusts ................................ 3,793 2,437
-------- --------
NET INCOME ................................................ 4,483 6,936
DIVIDEND REQUIREMENTS ON PREFERRED
STOCK .................................................... 42 44
-------- --------
EARNINGS AVAILABLE FOR COMMON STOCK ....................... $ 4,441 $ 6,892
======== ========
WEIGHTED AVERAGE COMMON SHARES
OUTSTANDING .............................................. 51,265 50,579
======== ========
EARNINGS PER AVERAGE COMMON SHARE ......................... $ .09 $ .14
======== ========
DIVIDENDS PER COMMON SHARE ................................ $ .25 $ .40
======== ========
See Notes to Condensed Consolidated Financial Statements.
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CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
(Unaudited)
March 31, December 31,
1999 1998
------------- ------------
(In Thousands)
ELECTRIC PLANT:
Original cost ..................................... $2,656,239 $2,628,934
Less accumulated depreciation ..................... 728,331 708,791
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Net plant in service ............................ 1,927,908 1,920,143
Construction work in progress ..................... 231,734 213,365
Other plant, net .................................. 65,188 66,378
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2,224,830 2,199,886
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INVESTMENTS ......................................... 25,717 24,483
---------- ----------
CURRENT ASSETS:
Cash and temporary cash investments ............... 741 1,770
Customer receivables .............................. 73,103 81,288
Other receivables ................................. 10,709 16,010
Fuel stock and materials and supplies ............. 45,337 39,606
Deferred energy costs ............................. 60,571 62,489
Prepayments ....................................... 8,213 7,787
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198,674 208,950
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DEFERRED CHARGES .................................... 179,891 174,505
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$2,629,112 $2,607,824
========== ==========
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common shareholders' equity:
Common stock, 51,265,117 and 51,265,117
shares issued and outstanding, respectively .... $ 54,107 $ 54,066
Premium and unamortized expense on capital stock 682,989 683,156
Retained earnings ............................... 118,439 126,814
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855,535 864,036
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Cumulative preferred stock ........................ 3,217 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 .................................... 1,028,710 900,227
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2,076,334 1,956,400
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CURRENT LIABILITIES:
Notes Payable ..................................... 22,365 105,000
Current maturities and sinking fund requirements .. 50,291 50,380
Accounts payable .................................. 57,956 83,439
Accrued taxes ..................................... 1,168 -
Accrued interest .................................. 16,326 7,829
Deferred taxes on deferred energy costs ........... 21,200 21,871
Customers' service deposits and other ............. 39,732 41,427
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209,038 309,946
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DEFERRED CREDITS AND OTHER LIABILITIES:
Deferred investment tax credits ................... 27,719 28,083
Deferred taxes on income .......................... 233,816 231,610
Customers' advances for construction and other .... 82,205 81,785
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343,740 341,478
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$2,629,112 $2,607,824
========== ==========
See Notes to Condensed Consolidated Financial Statements.
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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
FOR THE THREE MONTHS
ENDED MARCH 31,
--------------------
1999 1998
-------- --------
(In Thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income .......................................... $ 4,483 $ 6,936
Adjustments to reconcile net income to net cash
provided-
Depreciation and amortization ...................... 23,376 20,537
Deferred income taxes and investment tax credits ... (1,630) 3,340
Allowance for other funds used during construction . (2,253) (2,199)
Changes in-
Receivables ........................................ 13,483 6,427
Fuel stock and materials and supplies .............. (5,731) (1,961)
Accounts payable and other current liabilities ..... (27,319) (11,545)
Deferred energy costs .............................. 1,918 (2,923)
Accrued taxes and interest ......................... 12,100 7,933
Other assets and liabilities ........................ (7,519) (7,313)
-------- --------
Net cash provided by operating activities ......... 10,908 19,232
-------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Construction expenditures and gross additions ....... (43,421) (38,196)
Investment in subsidiaries and other ................ (1,766) (227)
-------- --------
Net cash used in investing activities ............. (45,187) (38,423)
-------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Issuance of capital stock ........................... - 7,575
Issuance of long-term debt .......................... 130,000 -
Deposit of funds held in trust ...................... - (532)
Withdrawal of funds held in trust ................... 10 -
Retirement of long-term debt ........................ (1,612) (16,081)
Retirement of preferred stock ....................... (49) (80)
Change in short-term borrowing ...................... (82,635) 47,155
Cash dividends ...................................... (12,894) (20,221)
Other financing activities .......................... 430 701
-------- --------
Net cash provided by financing activities ......... 33,250 18,517
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CASH AND TEMPORARY CASH INVESTMENTS:
Net decrease during the period ...................... (1,029) (674)
Beginning of period ................................. 1,770 720
-------- --------
End of period ....................................... $ 741 $ 46
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CASH PAID DURING THE PERIOD FOR:
Interest, net of amounts capitalized ................ $ 12,334 $ 11,303
======== ========
Income taxes ........................................ $ - $ -
======== ========
See Notes to Condensed Consolidated Financial Statements.
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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, 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, 1999. FAS
133 establishes accounting and reporting standards for derivative instruments,
including certain derivative instruments embedded in other contracts and for
hedging activities. It requires that an entity recognize all derivatives as
either assets or liabilities in the statement of financial position and measure
those instruments at fair value. The Company is currently evaluating the effect
of the adoption of FAS 133 on the Company's consolidated financial statements
and disclosures.
(3) 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
ENDED MARCH 31,
----------------
1999 1998
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(In Thousands)
Federal income tax at statutory rate ...................... $ 2,451 $ 3,771
Investment tax credit amortization ........................ (365) (365)
Other ..................................................... 433 433
------- -------
Recorded federal income taxes ............................. $ 2,519 $ 3,839
======= =======
Federal income taxes included in-
Operating expenses ...................................... $ 1,413 $ 2,934
Other income, net ....................................... 1,106 905
------- -------
Recorded federal income taxes ............................. $ 2,519 $ 3,839
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(4) 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
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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. The Court recently held oral argument
on the appeal and the Company is awaiting a decision.
The Grand Canyon Trust and Sierra Club filed a lawsuit in the U.S. District
Court, District of Nevada, in February 1998 against the owners of the Mohave
Generating Station (Mohave) alleging violations of the Clean Air Act regarding
emissions of sulfur dioxide and particulates. The owners believe the emission
limits referenced in the suit are not applicable to Mohave. The owners
previously partnered with the Environmental Protection Agency (EPA) and the
National Park Service on a multi-year study to determine the impacts, if any, of
Mohave emissions on visibility in the Grand Canyon. The environmental groups
want the owners to install pollution control equipment at an estimated cost of
$300 to $350 million. The Company owns a 14 percent interest in Mohave. The
outcome of this action cannot be determined at this time.
The Federal Clean Air Act Amendments of 1990 include provisions for
reduction of emissions of oxides of nitrogen by establishing new emission limits
for coal-fired generating units. This will require the installation of
additional pollution-control technology at some of the Reid Gardner Station
generating units before 2000 at an estimated cost to the Company of no more than
$6 million; $4.4 million has been spent to date. Installation is scheduled for
completion by May 1999.
Also, the United States Congress authorized the EPA to study the potential
impact Mohave emissions may have on visibility in the Grand Canyon. A final
report of this study was released in March 1999. The study acknowledges that
Mohave's emissions are transported to the Grand Canyon. However, at this time,
EPA has not determined the magnitude and frequency of visibility impairment that
is attributable to emissions from Mohave. The majority owner has estimated that
control costs, if required by EPA, could total between $300 and $350 million.
The owners of Mohave, including the Company, desire collaborative talks
with groups interested in the plant's future, provided that all stakeholders are
willing to participate. The owners' position in these talks could include a
commitment to install sulfur dioxide scrubbers and additional fine particulate
controls on the plant between 2005 and 2008. The reality of this collaboration
is dependent on participation of environmental groups who have brought suit
against Mohave. The Mohave owners have entered into settlement discussions with
the environmental groups. If settlement is reached, the collaboration effort
will be unnecessary.
In 1991, the EPA published an order requiring the Navajo Generating Station
(Navajo) to install scrubbers to remove 90 percent of sulfur dioxide emissions
beginning in 1997. As an 11.3 percent owner of Navajo, the Company will be
required to fund an estimated $50.9 million for installation of the scrubbers.
The first of three scrubber units was placed in commercial operation in November
1997, the second scrubber in September 1998, with the last scrubber unit
scheduled to be operational by August 1999. Currently, the project is
approaching 98 percent completion. The Company has spent approximately $45.6
million through December 1998 on the scrubbers' construction. In 1992, the
Company received resource planning approval from the PUCN for its share of the
cost of the scrubbers.
(5) 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 Securities and Exchange Commission (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
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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 hearing is scheduled for May 10,
1999. Both companies submitted a joint divestiture plan to the PUCN on April
15, 1999 describing plans to sell the companies' generating units. Upon selling
the generating units, both companies can determine how they will use the
proceeds of the sales, up to the book value of the plants. Any after-tax gains
above book value will be used to offset stranded costs, as determined by the
PUCN. Any remaining gains can be used to offset goodwill. After-tax gains may
not be sufficient to cover generation-related goodwill. However, if the
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. Both companies are required to
file a general rate case in 1999 that would update rates to current costs and
"unbundle" rates, i.e. break them into generation, transmission and distribution
components. The merged company would 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 company the opportunity to recover costs of the merger,
provided the company can demonstrate that merger savings exceed merger costs.
Merger costs are to be split among the non-competitive, potentially competitive
and unregulated services or businesses. An opportunity to recover the non-
competitive portion of the merger costs will be addressed in the rate case that
follows the start of competition in Nevada. The burden is on the merged company
to prove that merger savings exceed merger costs. The company will also have
the opportunity to recover goodwill in the same proceeding. The companies filed
with the Federal Energy Regulatory Commission (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 proposed merger is
conditioned upon further regulatory approval from the SEC. The entire process is
expected to be completed by mid-1999.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
LIQUIDITY AND CAPITAL RESOURCES
Overall net cash flows decreased during the first three months of 1999, as
compared to 1998, primarily due to more cash being used in investing activities
and 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 maintenance and
interest costs. The increase in cash being used in investing activities was
primarily due to increased construction expenditures. 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.
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. Further regulatory approval is required from the SEC.
(See Note 5 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 three months of
1999 was at an annualized rate of 6.1 percent. At March 31, 1999, the Company
provided electric service to 557,220 customers.
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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, with an in-service date of June 1,
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 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 5 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, Nevada Power Company will suspend 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.
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. However,
in early February 1999, the PUCN recommended to the state legislature that the
start date for competition be delayed to allow more time for consideration of
issues as a result of restructuring. The PUCN has not yet provided the
legislature with a recommendation for a new start date. On April 19, 1999, the
Nevada state senate passed SB438 which is an amendment to AB366. SB438 contains
several changes to AB366 including changing the start date of competition to
March 1, 2000 for all customers. The bill allows the utility to retain its name
and logo for affiliated businesses. The bill does not allow the PUCN to assign
to a provider of last resort customers who do not choose. SB438 now moves to
the Nevada State assembly. The Company cannot predict whether this, or other
measures related to industry restructuring, will be adopted into law.
In August 1997, the PUCN opened an investigatory docket of the following
issues to be considered as a result of restructuring of the electric industry.
(1) Identification of all cost components in utility service and
establishment of allocation methods necessary for later pricing of
noncompetitive services;
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(2) Designation of services as potentially competitive or
noncompetitive;
(3) Determination of rate design and non-price terms and conditions for
noncompetitive services;
(4) Establishment of licensing requirements for alternative sellers of
potentially competitive services;
(5) Past (stranded) costs;
(6) Criteria and standards by which the PUCN will apply the legislative
requirements concerning affiliate relations;
(7) Criteria and process by which the PUCN will appoint providers of
bundled electric service;
(8) Consumer protection;
(9) Anti-competitive behavior codes of conduct and enforcement;
(10) Price regulation for potentially competitive services in immature
markets;
(11) Compliance plans in accordance with regulation;
(12) Options for complying with legislative mandates for integrated
resource planning and portfolio standards;
(13) Innovative pricing for noncompetitive services.
The following are highlights of restructuring activity:
Designation of Services as Potentially Competitive or Noncompetitive
On August 20, 1998 the PUCN issued a final order designating certain
services as potentially competitive or noncompetitive. The PUCN deemed that
generation and aggregation had already been designated potentially competitive
as a result of AB366. Additionally, the PUCN deemed customer services,
metering, and billing as potentially competitive services. However, the PUCN
also authorized the regulated electric distribution utilities to provide billing
and customer service to their customers (i.e. alternative sellers) for any
noncompetitive services provided to those customers.
Affiliate Transaction Rules
On December 30, 1998, the PUCN issued a final rule dealing with business
transactions between regulated electric and gas distribution companies and
affiliates providing potentially competitive services. The rule includes a
prohibition on the use of the corporate utility name and logo by affiliates.
Any statement of affiliation to the regulated distribution company used by an
affiliate must include a lengthy and no less prominently displayed disclaimer.
The rule also prohibits the sharing of corporate services without prior PUCN
approval.
Nevada Power and Sierra Pacific Power Company filed, on March 30, 1999, a
lawsuit in Washoe County District Court, contesting the enforceability of the
affiliate transaction rules. The suit contests the prohibition on the use of
name and logo as a violation of the utilities' free speech. The suit also
argues that several provisions of the rule violate the constitutional guarantee
of equal protection, and that the rule was adopted without compliance with
several procedural requirements under state law.
Distribution Non-price Terms and Conditions
The PUCN issued an order on January 7, 1999 adopting final regulations for
non-price terms and conditions of distribution services. In this order, the
PUCN delineated the roles and responsibilities of the electric distribution
utilities and the alternative sellers for various processes and procedures
including new service connections, change orders and basic maintenance
processes.
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Provider of Last Resort
The provider of last resort (PLR) will provide electric service to
customers who choose not to choose and to customers who are not able to obtain
service from an alternative seller. There have been several workshops and
hearings held on the PLR issue and more discussion of the issue is anticipated.
A final order is expected in the second quarter of 1999.
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.
The Part II filing requires the Company to submit proposed rates for
bundled services on April 30, 1999. Additionally, the Company will provide
proposed rates for unbundled noncompetitive services (mainly distribution
services) in the filing. A final decision concerning unbundled rates is
expected from the PUCN in the fourth quarter, and final rates will be filed 15
days thereafter. Rates for noncompetitive services will be effective on the day
retail access begins. The rates for noncompetitive services will then be frozen
for three years, in accordance with the terms of 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 defines 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.
On April 8, 1999, the PUCN issued a revised proposed rule that specifies
the information a utility must include in its request for recovery of past
costs. This version of the proposed rule may be changed again before being
adopted as final based on comments from the parties and additional hearings.
The final rule is expected to include the date for the submission of filings to
recover past costs, which will likely be 45 days after the order from the
Compliance Plan filing is issued. The Company estimates its application for
recovery of Past Costs will be submitted mid-November 1999.
The Company has not completed an estimate of its past costs, since such a
calculation is dependent on a variety of issues related to restructuring which
are not fully resolved at this time.
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. Similar to a proposal
being developed in Arizona, Nevada stakeholders are pursuing the development of
an independent scheduling administrator (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. The Company expects to
file a proposal with the FERC by the second quarter of 1999 to establish an ISA.
10
<PAGE>
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 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 is committed
to reviewing 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 largely 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.
11
<PAGE>
Overall status for the Company as of January 29, 1999 shows identification
and assessment of potential problems at 95% complete and remediation/testing at
75% complete. This status is within the NERC guidelines and the Company's Year
2000 Project Schedule which calls for the Company to achieve Year 2000 readiness
by the end of June 1999. Significant progress has been made in addressing Year
2000 readiness needs within the Company's data center, its Energy Management
System (EMS), its generation plants and other facilities. Seven generation
units have been successfully tested to date, with the remaining units scheduled
for remediation and testing in the coming months. One generation unit will be
remediated and tested in September of 1999 to conform with its annual scheduled
maintenance outage, however, this unit is similar to others in the Company's
system which will have been remediated and tested by the end of June 1999 and it
is not critical to the ability of the Company to provide 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 by July 1999, the Company has initiated a corporate-wide
process of Year 2000 contingency planning. Contingency planning will likely be
partially affected by the responses received from business partners and
suppliers received in upcoming months, as well as the Company's determination of
the 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 organizations to develop external contingency plans, where appropriate.
Due to the need to assess the readiness of business partners, suppliers and
interconnected operators, the risk factors which will form the basis for the
Company's contingency plan are not fully known at this time and the reasonably
worst case scenario has not been determined, at this time. 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 February 1999,
approximately $2.5 million in operating expenses and approximately $2.3 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.
12
<PAGE>
OPERATING RESULTS OF THE FIRST QUARTER OF 1999
COMPARED TO FIRST QUARTER OF 1998
Earnings per average common share were nine cents for the first quarter of
1999, compared to fourteen cents for the same period in 1998. The decrease in
earnings available for common stock was due primarily to mild weather 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 5.95 percent and kilowatthour sales,
excluding sales for resale, were up 6.67 percent, as compared to the first
quarter of 1998.
Fuel expense increased $4 million due primarily to increased generation.
Purchased power increased $2.8 million due primarily to increased purchased
power costs. Maintenance and repairs increased $2.5 million due mainly to
increased maintenance expense at the Reid Gardner Generating Station.
Depreciation expense increased $2.0 million because of a growing asset base.
Other interest increased by $1.4 million primarily due to increased short-term
borrowing. 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.
Average common shares increased because of the sale of additional common
shares through the SPP to partially provide funds for the construction of
facilities necessary to meet increased customer demand for electricity.
13
<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: April 30, 1999 Steven W. Rigazio
---------------
Vice President, Finance and Planning,
Treasurer, Chief Financial Officer
14
<PAGE>
<PAGE>
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THE SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE CONDENSED
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THE RELATED CONDENSED CONSOLIDATED STATEMENTS OF INCOME AND CASH FLOWS FOR THE
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