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, 1998 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
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(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 .
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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 August 11, 1998, 51,279,938 shares.
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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,
------------------ ------------------
1998 1997 1998 1997
-------- -------- -------- --------
ELECTRIC REVENUES ......................$198,935 $199,970 $364,198 $355,324
OPERATING EXPENSES AND TAXES:
Fuel .............................. 30,848 34,435 57,421 55,561
Purchased and interchanged power .. 77,142 75,251 128,197 128,521
Deferred energy cost
adjustments, net ................. (10,144) (19,953) (12,420) (21,601)
-------- -------- -------- --------
Net energy costs ................. 97,846 89,733 173,198 162,481
Other production operations ....... 5,433 5,241 9,902 8,986
Other operations .................. 27,546 24,189 53,229 48,251
Maintenance and repairs ........... 15,225 17,620 27,707 27,603
Provision for depreciation ........ 17,845 16,011 35,556 32,186
General taxes ..................... 5,784 5,401 11,153 10,458
Federal income taxes .............. 4,468 9,478 7,402 13,621
-------- -------- -------- --------
174,147 167,673 318,147 303,586
-------- -------- -------- --------
OPERATING INCOME ....................... 24,788 32,297 46,051 51,738
-------- -------- -------- --------
OTHER INCOME (EXPENSES):
Allowance for other funds used
during construction .............. 2,714 2,102 4,913 4,154
Miscellaneous, net ................ (449) (726) (1,042) (1,696)
-------- -------- -------- --------
2,265 1,376 3,871 2,458
-------- -------- -------- --------
INCOME BEFORE INTEREST DEDUCTIONS ...... 27,053 33,673 49,922 54,196
-------- -------- -------- --------
INTEREST DEDUCTIONS:
Interest on long-term debt ........ 14,417 12,655 28,525 24,964
Other interest .................... 1,273 311 1,839 747
Allowance for borrowed funds used
during construction .............. (1,520) (546) (2,698) (1,339)
-------- -------- -------- --------
14,170 12,420 27,666 24,372
-------- -------- -------- --------
Distribution requirements
on company-obligated mandatorily
redeemable preferred securities
of subsidiary trust .............. 2,437 2,383 4,874 2,383
-------- -------- -------- --------
NET INCOME ............................. 10,446 18,870 17,382 27,441
DIVIDEND REQUIREMENTS ON PREFERRED
STOCK ................................. 45 47 89 1,034
-------- -------- -------- --------
EARNINGS AVAILABLE FOR COMMON STOCK ....$ 10,401 $ 18,823 $ 17,293 $ 26,407
======== ======== ======== ========
WEIGHTED AVERAGE COMMON SHARES
OUTSTANDING ........................... 50,920 49,526 50,751 49,294
======== ======== ======== ========
EARNINGS PER AVERAGE COMMON SHARE ......$ .20 $ .38 $ .34 $ .54
======== ======== ======== ========
DIVIDENDS PER COMMON SHARE .............$ .40 $ .40 $ .80 $ .80
======== ======== ======== ========
See Notes to Condensed Consolidated Financial Statements.
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
(Unaudited)
June 30, December 31,
1998 1997
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(In Thousands)
ELECTRIC PLANT:
Original cost ..................................... $2,468,051 $2,378,296
Less accumulated depreciation ..................... 679,683 647,208
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Net plant in service ............................ 1,788,368 1,731,088
Construction work in progress ..................... 184,018 158,029
Other plant, net .................................. 69,334 71,592
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2,041,720 1,960,709
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INVESTMENTS ......................................... 20,589 13,571
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CURRENT ASSETS:
Cash and temporary cash investments ............... 575 720
Customer receivables .............................. 95,466 71,722
Other receivables ................................. 15,333 16,415
Fuel stock and materials and supplies ............. 38,787 42,370
Deferred energy costs ............................. 43,495 30,597
Prepayments ....................................... 4,663 6,711
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198,319 168,535
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DEFERRED CHARGES .................................... 206,018 196,607
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$2,466,646 $2,339,422
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CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common shareholders' equity:
Common stock, 51,050,838 and 50,399,746
shares issued and outstanding, respectively .... $ 54,256 $ 53,604
Premium and unamortized expense on capital stock 678,394 662,987
Retained earnings ............................... 93,855 117,032
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826,505 833,623
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Cumulative preferred stock ........................ 3,385 3,463
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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
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Long-term debt .................................... 892,858 895,439
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1,841,620 1,851,397
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CURRENT LIABILITIES:
Notes payable ..................................... 125,298 -
Current maturities and sinking fund requirements .. 5,148 19,937
Accounts payable .................................. 68,943 64,737
Accrued taxes ..................................... 7,016 7,543
Accrued interest .................................. 8,833 7,284
Deferred taxes on deferred energy costs ........... 15,223 10,709
Customers' service deposits and other ............. 40,374 37,649
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270,835 147,859
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DEFERRED CREDITS AND OTHER LIABILITIES:
Deferred investment tax credits ................... 28,813 29,544
Deferred taxes on income .......................... 248,608 235,846
Customers' advances for construction and other .... 76,770 74,776
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354,191 340,166
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$2,466,646 $2,339,422
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See Notes to Condensed Consolidated Financial Statements.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
FOR THE SIX MONTHS
ENDED JUNE 30,
--------------------
1998 1997
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(In Thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income .......................................... $ 17,382 $ 27,441
Adjustments to reconcile net income to net cash
provided by operating activities-
Depreciation and amortization ...................... 41,984 36,213
Deferred income taxes and investment tax credits ... 7,040 8,135
Allowance for other funds used during construction . (4,913) (4,154)
Changes in-
Receivables ........................................ (22,661) (29,838)
Fuel stock and materials and supplies .............. 2,835 (1,119)
Accounts payable and other current liabilities ..... 6,768 4,574
Deferred energy costs .............................. (13,873) (20,224)
Accrued taxes and interest ......................... 1,022 1,318
Other assets and liabilities ........................ (4,027) 1,701
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Net cash provided by operating activities ......... 31,557 24,047
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CASH FLOWS FROM INVESTING ACTIVITIES:
Construction expenditures and gross additions ....... (114,834) (97,320)
Investment in subsidiaries and other ................ (1,611) (403)
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Net cash used in investing activities ............. (116,445) (97,723)
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CASH FLOWS FROM FINANCING ACTIVITIES:
Issuance of capital stock ........................... 16,058 17,908
Issuance of company-obligated mandatorily
redeemable preferred securities ................... - 118,872
Deposit of funds held in trust ...................... (1,049) (1,063)
Retirement of long-term debt ........................ (17,189) (2,546)
Retirement of preferred stock ....................... (80) (38,080)
Change in short-term borrowing ...................... 125,298 18,000
Cash dividends ...................................... (40,563) (41,257)
Other financing activities .......................... 2,268 (39)
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Net cash provided by financing activities ......... 84,743 71,795
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CASH AND TEMPORARY CASH INVESTMENTS:
Net decrease during the period ...................... (145) (1,881)
Beginning of period ................................. 720 2,544
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End of period ....................................... $ 575 $ 663
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CASH PAID DURING THE PERIOD FOR:
Interest, net of amounts capitalized ................ $ 36,500 $ 31,328
======== ========
Income taxes ........................................ $ - $ 3,010
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See Notes to Condensed Consolidated Financial Statements.
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 with the current period presentation.
(1) CONSOLIDATION POLICY:
The condensed consolidated financial statements include the accounts of
Nevada Power Company (Company) and its wholly-owned subsidiary, NVP Capital I.
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. 131 (FASB 131), Disclosures about Segments
of an Enterprise and Related Information, which is effective for annual
financial statements for periods beginning after December 15, 1997. FASB 131
establishes standards for the way that public business enterprises report
information about operating segments in annual financial statements and
requires that those enterprises report selected information about operating
segments in interim financial reports issued to shareholders. It also
establishes standards for related disclosures about products and services,
geographic areas and major customers. Due to recent legislation enacted in
Nevada for restructuring the electric utility industry, the Company cannot
predict the effect adoption of FASB 131 will have on disclosures in its
condensed consolidated financial statements.
The Financial Accounting Standards Board recently issued Statement of
Financial Accounting Standards No. 132 (FASB 132), Employers' Disclosures about
Pensions and Other Postretirement Benefits - an amendment of FASB Statements
No. 87, 88 and 106, which is effective for financial statements for fiscal
years beginning after December 15, 1997. FASB 132 revises employer's
disclosures about pension and other postretirement benefit plans but does not
change the measurement or recognition of those plans. It standardizes the
disclosure requirements for pensions and other postretirement benefits to the
extent practicable, requires additional information on changes in the benefit
obligations and fair values of plan assets that will facilitate financial
analysis and eliminates certain disclosures that are no longer as useful as
they were when the above mentioned FASB statements were originally issued. The
adoption resulted in no material effect on the disclosures in the Company's
condensed consolidated financial statements.
The Financial Accounting Standards Board recently issued Statement of
Financial Accounting Standards No. 133 (FASB 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. FASB
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 adoption of FASB 133 will have no
material effect on the disclosures in the Company's condensed consolidated
financial statements.
(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 which created this difference.
THREE MONTHS SIX MONTHS
ENDED JUNE 30, ENDED JUNE 30,
---------------- ----------------
1998 1997 1998 1997
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(In Thousands) (In Thousands)
Federal income tax at statutory rate .$ 5,661 $10,197 $ 9,432 $14,848
Investment tax credit amortization ... (365) (365) (730) (730)
Other ................................ 433 433 865 866
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Recorded federal income taxes ........$ 5,729 $10,265 $ 9,567 $14,984
======= ======= ======= =======
Federal income taxes included in-
Operating expenses .................$ 4,468 $ 9,478 $ 7,402 $13,621
Other income, net .................. 1,261 787 2,165 1,363
------- ------- ------- -------
Recorded federal income taxes ........$ 5,729 $10,265 $ 9,567 $14,984
======= ======= ======= =======
(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 a fourth quarter 1996 charge of
$5.5 million, net of tax, for amounts disallowed by the PUCN. On May 7, 1997,
the Company filed a Petition for Judicial Review in the First District Court in
Carson City, Nevada challenging the PUCN's findings which resulted in
disallowances.
The 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, and filed
a motion to dismiss the lawsuit in April 1998. Also, the owners previously
partnered with the Environmental Protection Agency (EPA) and the National Park
Service on a multi-year study to determine the impacts, if any, of Mohave
emissions on visibility in the Grand Canyon (see the following paragraph). The
environmental groups want the owners to install pollution control equipment at
an estimated cost of $200 to $300 million. The Company owns a 14 percent
interest in Mohave. The outcome of this action cannot be determined at this
time.
The United States Congress authorized the EPA to study the potential
impact Mohave may have on visibility in the Grand Canyon area. Results of this
study are expected in 1998.
The Federal Clean Air Act Amendments of 1990 (Amendments) include
provisions for reduction of emissions of oxides of nitrogen by establishing new
emission limits for coal-fired generating units. This will require the
installation of additional pollution-control technology at two of the Reid
Gardner Station generating units before 2000 at an estimated cost to the
Company of no more than $4 million; $1.4 million has been spent to date.
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 entered start-up April 6, 1998
and will be in commercial operation by November 1998, with the last scrubber
unit operational by August 1999. Currently, the project is approaching 92
percent complete. The Company has spent approximately $42.9 million through
April 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) SHORT-TERM BORROWING:
In April 1998, the Company obtained an additional $50 million bank
revolving credit facility which expires on April 16, 1999 and pays a facility
fee based on the Company's
senior unsecured debt rating. Borrowing rates under the bank line are
determined by both current market rates and the Company's senior unsecured debt
rating.
(6) MERGER; DIVIDEND POLICY:
On April 30, 1998, Nevada Power 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. Based upon then current market prices and expected financing
requirements, the combination would create a company with a total market
capitalization of approximately $4.0 billion ($2.3 billion in equity, $1.5
billion in debt and $240 million in preferred stock). In conjunction with the
Company's approval of the proposed merger, the Company's Board of Directors
stated that, beginning with the November 1998 dividend, it intends to adopt the
expected combined company initial annual dividend rate. This would result in
an indicated annual dividend rate of $1.00 per share for periods following the
August 1998 dividend payment. For further information regarding the proposed
merger please refer to the Company's Form 8-K filed with the SEC on April 30,
1998.
On July 7, 1998 Sierra Pacific Resources and Nevada Power Company issued a
press release announcing the filing of a joint merger application with the PUCN
for approval of their proposed merger. In the filing, Sierra Pacific Resources
and Nevada Power Company propose selling their generating plants if the merger
is completed and a long-term freeze in prices for regulated utility services
(transmission and distribution). Capital raised by the sale of generating
plants will be reinvested primarily in new transmission and distribution
facilities. An incentive mechanism through which net merger and other benefits
are shared by customers and investors has also been proposed. Among other
issues addressed in the PUCN merger application are: the impact of the merger
on competition and electricity prices; operation of the electric transmission
system to ensure competing energy suppliers have equal access to customers;
and benefits of the merger to employees and stockholders. For further
information regarding this filing please refer to the Company's SEC Form 8-K
filed with the SEC on July 8, 1998.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
LIQUIDITY AND CAPITAL RESOURCES
Overall net cash flows increased during the first six months of 1998, as
compared to 1997, primarily due to more cash being provided by operating
activities and more cash being provided by financing activities partially
offset by more cash being used in investing activities. The increase in cash
being provided by operating activities was primarily due to an energy rate
increase effective February 1, 1998. The increase in cash used in investing
activities was primarily due to increased construction expenditures. The
increase in net cash provided by financing activities was primarily due to
increased short-term borrowing.
On April 30, 1998, Nevada Power 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 Nevada Power Company issued a press release announcing the filing
of a joint merger application with the PUCN for approval of their proposed
merger. (See Note 6 to the condensed consolidated financial statements
included in this quarterly report.)
In April 1998, the Company filed a request with the PUCN for authorization
to increase energy rates under the state's deferred energy accounting
procedures by approximately $43 million for increased energy costs and $9.9
million for remaining issues from the 1997 deferred energy rate case. If the
$9.9 million energy rate case is approved, residential customers' rates will
increase $4.3 million and all other customers' rates $5.6 million.
The $43 million energy rate increase request was dismissed by the PUCN on
July 15, 1998. After the dismissal, the Company immediately filed a request
with the PUCN for authorization to increase energy rates by approximately $49
million using a different test period. If approved by the PUCN, residential
customers' rates will increase by $13 million and commercial customers' rates
will increase by $36 million. The Company has requested the new rates be
effective September 1, 1998, however, the PUCN has 180 days to
render a final decision. The Company is requesting the increase in energy
rates to recover higher costs for natural gas and purchased power.
The Company's customer growth rate during 1997 and 1996 was 6.4 and 7.2
percent, respectively. The increase in customers for the first six months of
1998 was at an annualized rate of 6.0 percent. At June 30, 1998, the Company
provided electric service to 533,842 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, 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.
To meet capital expenditure requirements through 1998, the Company plans
to utilize internally generated cash, the proceeds from industrial development
revenue bonds (IDBs), FMBs, unsecured borrowings, preferred securities and
common stock issues through public offerings.
The Company uses open market purchases of its common stock to meet the
requirements of the Stock Purchase and Dividend Reinvestment Plan (SPP). Under
the SPP the Company issued 1,515,716 and 605,643 shares, respectively, of its
common stock in 1997 and the first six months of 1998.
On November 20, 1997, Clark County, Nevada issued $52.3 million Series
1997A IDBs (Nevada Power Company Project) due 2032 and Coconino County, Arizona
Pollution Control Corporation issued $20 million 5.8% Pollution Control Revenue
Bonds (PCRBs) Series 1997B (Nevada Power Company Project) due 2032. Net
proceeds from the sale of the IDBs were placed on deposit with a trustee and
are being used to finance the construction of certain facilities which qualify
for tax-exempt financing. Net proceeds from the sale of the PCRBs were placed
on deposit with a trustee and are being used to finance the construction of the
Navajo scrubber facilities which qualify for tax-exempt financing. At June 30,
1998, $54.0 million remained on deposit with the trustee.
In April 1998, the Company obtained an additional committed bank line for
$50 million which expires on April 16, 1999. The short-term financing is
expected to be utilized to fund some of the Company's construction expenditures
until long-term financing is secured.
In April 1998, the plant workers of the International Brotherhood of
Electrical Workers Union (IBEW) Local 396 ratified a new contract presented by
Company management. Clerical and plant workers of the IBEW have been working
without contracts since February 1998. The contract for the clerical workers
has not been scheduled for a vote at this time.
INDUSTRY RESTRUCTURING
In July 1997, the Governor of the state of Nevada signed into law Assembly
Bill 366 (AB 366) which provides for competition to be implemented in the
electric utility industry in the state no later than December 31, 1999. In
August 1997, the PUCN opened an investigatory docket of the issues to be
considered as a result of restructuring of the electric industry. For a
detailed discussion of AB 366 and the investigatory docket please see the
Company's 1997 Annual Report to Shareholders.
In its Order dated November 4, 1997, the PUCN designated unbundled
services in eight major categories with twenty-six unbundled services in total.
The major categories include Generation Capacity and Energy Supply, Generation
Services Necessary to Support Transmission Service, Arranging for Power
Supplies, Power Delivery, End-Use Metering, Customer Accounting, Marketing and
Sales, and Public Good Services. The PUCN evaluated the cost unbundling
methodologies for the unbundled services set forth in its Order and, after
hearings, issued an Interim Order describing the process the parties should
follow to complete developing cost unbundling methodologies and to work toward
consensus on that issue. Subsequently, the PUCN stated in an Interim Order
dated March 5, 1998 that the majority of the conclusions of the Cost Unbundling
Consensus Report should be adopted. Additionally, on March 19, 1998, a second
Cost Unbundling Consensus Report on resolution of most of the final issues was
filed with the PUCN. Informal workshops involving only the interested parties
were held in April, May, June and July to discuss final issues regarding
transmission and distribution demarcation. A hearing was held late in July
1998.
The PUCN has the authority to classify a service as a potentially
competitive service if it finds the service meets specific requirements. As
requested by the PUCN, comments were filed on the Classification of Electric
Service as Potentially Competitive Services and workshops were held. The
services which were discussed as potentially competitive were billing, customer
service, metering, demand management services and physical connection. On June
8, 1998, the PUCN issued an Order Identifying Potentially Competitive Services.
Based on PUCN findings, metering, billing and customer service are classified
as potentially competitive services. On June 23, 1998, the Company filed a
Motion for Reconsideration and Rehearing of this Order. The Company is
concerned that the validity of the Order could be challenged because a public
hearing creating an evidentiary record was not held. The PUCN granted the
petition on July 15. The Company is ordered to file an application for
designation of any components of electric service as potentially competitive by
August 26. Any person seeking a designation of an unbundled service as
potentially competitive can file an application with the PUCN. A proposed rule
was issued to set standards for the contents of this application and a hearing
was held. On May 14, 1998, the PUCN voted on and issued a revised proposed
rule. A public hearing is scheduled for August 19 to discuss the comments to
be filed on August 13 by all interested parties.
Comments were filed with the PUCN on Non-Price Terms and Conditions for
Distribution Tariffs and a workshop was held. The main topics of discussion
were physical distribution facilities and services, eligibility to obtain
distribution service, packaging of services, processing requests and denial of
service, informational interaction, safety and reliability. On June 4, 1998,
the PUCN voted on and issued a proposed rule. A public hearing is scheduled
for September 14 to discuss the comments to be filed on September 3 by all
interested parties.
Comments on Licensing of Alternative Sellers and Consumer Protection were
filed and workshops held. During the Licensing portion of the workshops, the
primary issues discussed were types of licenses, by services offered and
customers served, and financial viability. The main topics of discussion
during the Consumer Protection workshop were standardized disclosure, uniform
contracts, allocation of partial payments, labeling and the Consumer Bill of
Rights. On June 26, 1998, the PUCN voted on and issued proposed rules on the
Alternative Sellers' Licensing and Consumer Protection Requirements. A public
hearing is scheduled for September 14 to discuss the comments to be filed on
September 3 by all interested parties.
On March 4, 1998 the PUCN issued a Notice of Request for Comments on
proposed regulation intended to address the competitive provision of services
by the utility distribution company and its affiliates. Comments were filed
and workshops were held where several of the major issues discussed were the
use of the corporate family name and logo, shared corporate support functions,
consistent application of the rule, cross subsidization of costs, violations
and sanctions. A revised proposed regulation was
subsequently issued by the PUCN. A hearing was held on June 30 and was
continued on July 20 and 21. Another revised proposed regulation will be
issued by the PUCN as a result of those hearings.
On April 23, 1998, the PUCN issued an Order to solicit comments in
response to questions and issues related to Load Pockets, Treatment of
Transition Costs (costs which include the difference between the market value
and book value of an asset or obligation; and the incremental costs required to
bring about a competitive market that would not have been incurred but for
competition), and Provider of Last Resort Service. Comments were filed and
PUCN workshops were held on these issues.
The PUCN requested additional information on Provider of Last Resort
Service issues, which were filed on June 30. The Provider of Last Resort shall
be designated by the PUCN. This entity will provide electric service to
customers who are unable to obtain electric service from an alternative seller
or who fail to select an alternative seller.
Informal workshops involving only the interested parties were held in
June, July and August on Load Pockets and issues related to the administration
of the transmission system. A load pocket is defined to exist when the Nevada
Power Company's control area can not be completely served by firm purchase
power due to transmission line capacity limitations. Under these conditions
some internal generation "must run" to meet the system requirements. In
response to Procedural Order Number Four issued by the PUCN on July 15, a
consensus report is due on August 14 regarding the formation of an Independent
Scheduling Administrator. A formal workshop is scheduled for August 24 if full
consensus is not reached. No later than September 1, 1998, the parties are
required to submit a report outlining the proposal for a generation aggregation
tariff with a workshop to follow on September 9.
CONTINUING APPLICABILITY OF FASB 71
The Company's rates are currently subject to approval by the PUCN and are
designed to recover the Company's costs of providing services to its customers.
A primary difference between a rate regulated entity and an unregulated entity
is the timing of recognizing certain assets and expenses for financial
reporting purposes. The Statement of Financial Accounting Standards No. 71,
"Accounting for the Effects of Certain Types of Regulation" (FASB 71),
prescribes the method to be used to record the financial transactions of a
regulated entity. The criteria for applying FASB 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, (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 FASB 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 FASB 71.
In July 1997, the Emerging Issues Task Force (EITF) of the Financial
Accounting Standards Board reached a consensus on several issues which have
arisen due to deregulation of the electric utility industry and the continuing
applicability of FASB 71. The EITF reached a consensus that a company should
stop applying FASB 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 FASB 71 is no longer applied to that
separable portion of the business, it will 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 FASB 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.
YEAR 2000
The Company has made Year 2000 readiness a top priority for all of its
departments. With officer oversight, 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
progress to identify, correct and test problems related to the year 2000 issue,
including verification of the level of Year 2000 readiness of business partners
and suppliers. A data base will be used to identify and track the progress of
work on each phase. The Company has also engaged in contingency planning and
is working cooperatively with utility and non-utility suppliers, generation and
transmission operators, and regional organizations such as the Western States
Coordinating Council to develop external contingency plans. The Company's Year
2000 readiness activities are well under way currently and are scheduled to
achieve readiness by the third quarter of 1999 to allow time to address any
unforeseen contingencies. The estimated total cost to the Company of
addressing Year 2000 readiness is in the range of $7 to $15 million, including
capital expenditures and operating expenses. The risk of a materially
incomplete or untimely resolution of the Year 2000 problems by the Company, its
major suppliers or its major customers would be the Company's inability to
reliably supply electricity to customers as a result of the failure of the
generation, transmission or distribution systems. The PUCN has opened an
investigatory proceeding to review Year 2000 issues for natural gas, electric
and water utilities in Nevada.
OPERATING RESULTS OF THE SECOND QUARTER OF 1998
COMPARED TO SECOND QUARTER OF 1997
Earnings per average common share were 20 cents for the first quarter of
1998, compared to 38 cents for the same period in 1997. The decrease in
earnings available for common stock was primarily due to reduced revenues and
increased interest expense. Revenues decreased primarily due to extremely mild
weather in 1998 partially offset by an energy rate increase effective February
1, 1998. The average number of customers increased 6.33 percent, however,
kilowatthour sales, excluding sales for resale, were down 7.81 percent, as
compared to the second quarter of 1997.
Fuel expense decreased $3.6 million due to decreased generation.
Purchased power increased $1.9 million due to higher average purchased power
costs. Other operations expense increased $3.4 million primarily due to
increased administrative and general expense. Maintenance and repairs expense
decreased $2.4 million due to higher maintenance expense in 1997 for Reid
Gardner Generating Station. Depreciation expense increased $1.8 million
because of a growing asset base. Interest on long term debt increased by $1.8
million primarily due to the issuance in November 1997 of the new Series 1997A
$52.3 million IDBs and Series 1997B $20 million PCRBs and the remarketing at
fixed rates in January 1998 of variable rate revenue bonds $76.75 million
Series 1995A, $44 million Series 1995C, $20.3 million Series 1995D and $13
million Series 1995E.
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.
OPERATING RESULTS OF THE FIRST SIX MONTHS OF 1998
COMPARED TO FIRST SIX MONTHS OF 1997
Earnings per average common share were 34 cents for the first six months
of 1998, compared to 54 cents for the same period in 1997. The decrease in
earnings available for common stock was primarily due to decreased kilowatthour
sales and increased other operations expense, interest expense and the
distribution requirements on the Quarterly Income Preferred Securities (QUIPS).
Revenues increased primarily due to an energy rate increase effective February
1, 1998 which was partially offset by extremely mild weather during 1998. Even
though the average number of customers increased 6.41 percent, kilowatthour
sales, excluding sales for resale, were down 1.5 percent, as compared to the
first six months of 1997.
Fuel expense increased $1.9 million due to increased generation. Other
operations expense increased $5.0 million primarily due to increased
administrative and general expense. Depreciation expense increased $3.4
million because of a growing asset base. Interest on long term debt increased
by $3.6 million primarily due to the issuance in November 1997 of the new
Series 1997A $52.3 million IDBs and Series 1997B $20 million PCRBs and the
remarketing at fixed rates in January 1998 of variable rate revenue bonds
$76.75 million Series 1995A, $44 million Series 1995C, $20.3 million Series
1995D and $13 million Series 1995E. Distribution requirements on company-
obligated preferred securities of a subsidiary trust increased by $2.5 million
due to the issuance in April 1997 of the QUIPS.
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.
PART II. OTHER INFORMATION
Items 1 through 5. None.
Item 6. Exhibits and Reports on Form 8-K.
a. Exhibits.
Exhibits Filed Description
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27 Financial Data Schedule
b. Reports on Form 8-K.
Form 8-K filed on April 30, 1998.
Form 8-K filed on July 8, 1998.
Signatures
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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
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(Registrant)
STEVEN W. RIGAZIO
--------------------------------------
(Signature)
Date: August 13, 1998 Steven W. Rigazio
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Vice President, Finance and Planning,
Treasurer, Chief Financial Officer