<PAGE>
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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1998 Commission file number 1-4698
NEVADA POWER COMPANY
(Exact name of registrant as specified in its charter)
<TABLE>
<S> <C>
Nevada 88-0045330
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
6226 West Sahara Avenue 89146
Las Vegas, Nevada (Zip Code)
(Address of principal executive offices)
</TABLE>
Registrant's telephone number, including area code: (702) 367-5000
Securities registered pursuant to Section 12(b) of the Act:
<TABLE>
<CAPTION>
Title of each class Name of each exchange on which registered
- ------------------- -----------------------------------------
<S> <C>
Common Stock, $1 Par Value New York Stock Exchange
Pacific Exchange
Stock Purchase Rights New York Stock Exchange
Pacific Exchange
8.2% Cumulative Quarterly Income New York Stock Exchange
Preferred Securities, Series A
</TABLE>
* issued by NVP Capital I, a Delaware Statutory Business Trust
The payment of trust distributions and payments on liquidation or
redemption are guaranteed under certain circumstances by Nevada Power
Company. Nevada Power Company is the owner of 100% of the common securities
issued by NVP Capital I.
<TABLE>
<S> <C>
7 3/4% Cumulative Quarterly Trust Issued New York Stock Exchange
Preferred Securities
</TABLE>
* issued by NVP Capital III, a Delaware Statutory Business Trust
The payment of trust distributions and payments on liquidation or
redemption are guaranteed under certain circumstances by Nevada Power
Company. Nevada Power Company is the owner of 100% of the common securities
issued by NVP Capital III.
Securities registered pursuant to Section 12(g) of the Act:
Cumulative Preferred Stock, $20 Par Value, 5.40% Series
(Title of class)
Cumulative Preferred Stock, $20 Par Value, 5.20% Series
(Title of class)
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 by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to
the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. X
---
51,265,117 shares of Common Stock were outstanding as of March 2, 1999.
The aggregate market value of Common Stock, which is the only voting stock,
held by non-affiliates as of March 2, 1999, was $1,268,811,645. (Computed by
reference to the closing price on March 2, 1999, as reported by the Wall
Street Journal as New York Stock Exchange Composite Transactions.)
DOCUMENTS INCORPORATED BY REFERENCE
(1) Portions of the Registrant's Annual Report to Shareholders for the year
ended December 31, 1998 are incorporated by reference into Parts II and IV
hereof.
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<PAGE>
TABLE OF CONTENTS
<TABLE>
<CAPTION>
Page
----
<C> <S> <C>
PART I
Item 1. Business..................................................................... 1
Item 2. Properties................................................................... 10
Item 3. Legal Proceedings............................................................ 11
Item 4. Submission of Matters to a Vote of Security Holders.......................... 11
Supplemental Item.
Executive Officers of Registrant............................................. 11
PART II
Item 5. Market for the Registrant's Common Stock and Related Security Holder Matters. 13
Item 6. Selected Financial Data...................................................... 13
Item 7. Management's Discussion and Analysis of Financial Condition and Results of
Operation.................................................................... 13
Item 7A. Quantitative and Qualitative Disclosures About Market Risk .................. 13
Item 8. Consolidated Financial Statements and Supplementary Data..................... 13
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial
Disclosure................................................................... 14
PART III
Item 10. Directors and Executive Officers of the Registrant........................... 14
Item 11. Executive Compensation....................................................... 16
Item 12. Security Ownership of Certain Beneficial Owners and Management............... 24
Item 13. Certain Relationships and Related Transactions............................... 25
PART IV
Item 14. Exhibits, Consolidated Financial Statement Schedule, and Reports on Form 8-K. 25
SIGNATURES................................................................................ 37
</TABLE>
<PAGE>
PART I
ITEM 1. BUSINESS
The Company
Nevada Power Company (Company), incorporated in 1929 under the laws of
Nevada, is an operating public utility engaged in the electric utility
business in the City of Las Vegas and vicinity in southern Nevada. Most of the
Company's operations are conducted in Clark County, Nevada (with an estimated
service area population of 1,361,700 at December 31, 1998) where the Company
furnishes electric service in the communities of Las Vegas, North Las Vegas,
Henderson, Searchlight, Laughlin and adjoining areas and to Nellis Air Force
Base (a permanent military installation northeast of Las Vegas and the USAF
Tactical Fighter Weapons Center). Electric service is also supplied to the
Department of Energy at Mercury and Jackass Flats in Nye County, where the
Nevada Test Site is located.
Sources of Electric Energy Supply
The electric energy obtained from the Company's own generating facilities
will be produced at the following plants:
<TABLE>
<CAPTION>
Number
of Net Capacity
Plant Units (Megawatts)
----- ------ ------------
<S> <C> <C>
Coal Fuel:
Reid Gardner (Steam).................................... 3 330
Reid Gardner Unit No. 4 (Steam)......................... 1 250(1)
Mohave (Steam).......................................... 2 196(2)
Navajo (Steam).......................................... 3 255(3)
Natural Gas and Oil Fuel:
Clark (Steam)........................................... 3 175
Clark (Gas Turbine)..................................... 1 50
Clark (Combined Cycle).................................. 2 462
Sunrise (Steam)......................................... 1 80
Sunrise (Gas Turbine)................................... 1 69
Harry Allen (Gas Turbine)............................... 1 72
-----
1,939
=====
</TABLE>
- --------
(1) This represents 24 megawatts of base load capacity and 226 megawatts of
peaking capacity. Reid Gardner Unit No. 4, placed in service July 25,
1983, is a coal-fired unit which is owned 32.2% by the Company and 67.8%
by the Department of Water Resources of the State of California (CDWR).
The Company is entitled to use 100% of the unit's peaking capacity for
1,500 hours each year. The Company is entitled to 9.6% of the first 250
megawatts of capacity and associated energy. The Company had options for
the use of increasing amounts of capacity and energy from the unit
beginning in 1998 so that the Company would have been entitled to use all
of the unit's output 15 years from that date. However, the 1998 through
2003 options for 10.17 MW per year were not exercised by the Company and
have expired.
(2) This represents the Company's 14% undivided interest in the Mohave
Generating Station as tenant in common without right of partition with
three other non-affiliated utilities, less operating restrictions.
(3) This represents the Company's 11.3% undivided interest in the Navajo
Generating Station as tenant in common without right of partition with
five other non-affiliated utilities.
The Company purchases Hoover Dam power pursuant to a contract with the State
of Nevada which became effective June 1, 1987 and will continue through
September 30, 2017. The Company's allocation of capacity is 235 MW.
1
<PAGE>
The peak electric demand experienced by the Company was 3,855 megawatts on
July 17, 1998. This demand plus a reserve margin was served by a combination
of Company owned generation, and firm and short-term power purchases.
For 1999, the Company has contracts to purchase power from an independent
power producer (IPP) and four qualifying facilities (QF) (also known as
cogenerators) as follows:
<TABLE>
<CAPTION>
Contract Term
----------------- Net Capacity
From To (Megawatts)
-------- -------- ------------
<S> <C> <C> <C>
Independent Power
Producer:
-----------------
Nevada Sun-Peak Limited
Partnership............ 06/08/91 05/31/16 210
Qualifying Facilities:
----------------------
Saguaro Power Company... 10/17/91 04/30/22 90
Nevada Cogeneration
Associates #1.......... 06/18/92 04/30/23 85
Nevada Cogeneration
Associates #2.......... 02/01/93 04/30/23 85
Las Vegas Cogeneration
Limited Partnership.... 05/10/94 05/31/24 45
---
515
===
</TABLE>
The Company has total generating capacity of 2,689 megawatts, including 235
megawatts of Hoover Dam power, 210 megawatts of IPP power and 305 megawatts of
QF power. This along with agreements with other suppliers to purchase 965
megawatts of firm capacity and associated energy, for the summer of 1999, will
not be sufficient to meet the 1999 anticipated peak load demand and reserve
margin needs. Accordingly, the Company is utilizing a competitive bidding
process as well as spot market purchases to obtain resources from other
suppliers for additional firm capacity and associated energy to meet the
projected peak needs for 1999. As a condition to the Public Utilities
Commission of Nevada (PUCN) approval of the merger between the Company and
Sierra Pacific Resources, the Company and Sierra Pacific Power, a wholly-owned
subsidiary of Sierra Pacific Resources, will be required to divest themselves
of their generating facilities. See Merger; Dividend Policy. At the present
time, the Company believes it will be able to generate and/or purchase
sufficient power to meet peak demands. See Merger; Dividend Policy and
Competition sections included herein.
Fuel Supplies
The fuels used to provide energy for the Company's generating facilities are
coal, natural gas and oil. Its other sources of electricity are hydroelectric
(Hoover Dam) and purchased power.
The Company's primary fuel source for generation is coal. The following
table shows the actual sources of fuel for generation for 1998 and anticipated
sources of fuel for generation in 1999 and 2000.
<TABLE>
<CAPTION>
1998 1999 2000
---- ---- ----
<S> <C> <C> <C>
Coal....................................................... 67% 68% 67%
Natural Gas................................................ 33 32 33
--- --- ---
100% 100% 100%
=== === ===
</TABLE>
The Company's average delivered cost per ton of coal burned was as follows:
1996--$29.02; 1997--$29.72; 1998--$24.92.
Coal for both the Mohave and Navajo Stations is obtained from surface mining
operations conducted by Peabody Coal Company (Peabody) on portions of the
Black Mesa in Arizona within the Navajo and Hopi Indian reservations. The
supply contracts with Peabody extend to December 31, 2005 for Mohave and to
June 1, 2011 for Navajo, each contract having an option to extend for an
additional 15 years.
Partial requirements for coal at the Reid Gardner Generating Station are
presently under contract through the year 2007. Although the Company cannot
predict how the coal market may fluctuate in the future, the Company
anticipates no major difficulties in purchasing the remainder of its coal
requirements based upon
2
<PAGE>
current coal market conditions in the Western United States. All coal for Reid
Gardner presently comes from underground mines in Utah and Colorado.
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 plants, filing of general rate cases, merger
costs and several other issues. On January 29, 1999, the PUCN clarified
portions of the order approving the proposed merger. Both companies must
submit a divestiture plan to the PUCN prior to the merger describing plans to
sell their generating units. The divestiture plan is expected to be filed in
April 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." We expect
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 proposed merger is conditioned
upon further regulatory approvals including the SEC, the Department of Justice
and the FERC. The companies filed with the FERC a joint merger application on
October 2, 1998 which was noticed on October 8, 1998. The law imposes no
deadline on the FERC to issue its decision. The entire process is expected to
be completed by mid-1999.
Construction and Financing Programs
The Company carries on a continuing program to extend and enlarge its
facilities to meet current and future loads on its system. Gross plant
additions and retirements for the five years ended December 31, 1998 amounted
to $1,107,394,000 and $100,164,000, respectively.
Excluding Allowance for Funds Used During Construction, the Company's actual
construction expenditures for 1998 were $308 million, and currently estimated
construction expenditures for 1999 and 2000 are $245 million and $225 million,
respectively.
The Company's construction program and estimated expenditures are subject to
continuing review and are revised from time to time due to various factors,
including the rate of load growth, escalation of construction costs,
availability of fuel types, changes in environmental regulations, adequacy of
rate relief and the Company's ability to raise necessary capital.
3
<PAGE>
The Company may utilize internally generated cash and the proceeds from
industrial development revenue bonds (IDBs), unsecured borrowings and
preferred securities to meet capital expenditure requirements through 1999.
Under the Stock Purchase and Dividend Reinvestment Plan (SPP) the Company
issued 799,762 shares of its common stock in 1998. Beginning in the third
quarter of 1998, the Company began using open market purchases of its common
stock to meet the requirements of the SPP. At year end, common equity
represented 44.2 percent of total capitalization.
On January 29, 1998, the Company remarketed at fixed rates $141.05 million
Clark County, Nevada (Nevada Power Company Project) variable rate revenue
bonds consisting of $76.75 million Series 1995A IDBs due 2030 at 5.6 percent,
$44 million Series 1995C IDBs due 2030 at 5.5 percent and $20.3 million Series
1995D PCRBs with $14 million due 2011 at 5.3 percent and $6.3 million due 2023
at 5.45 percent. On the same date, $13 million Coconino County, Arizona
(Nevada Power Company Project) Series 1995E PCRBs due 2022 were remarketed at
a 5.35 percent fixed rate. The Company also remarketed $85 million Series
1995B Clark County, Nevada (Nevada Power Company Project) variable rate IDBs
due 2030 at a 5.9 percent fixed rate on November 24, 1997.
The Indenture under which the Company's first mortgage bonds are issued
provides that no additional bonds may be issued unless earnings as defined
equal at least two and one-half times the interest requirements on all bonds
to be outstanding after the new issue. Based on its earnings through December
31, 1998 and assuming a 7.5 percent interest rate on new bonds, the Company
would be able to issue approximately $689 million of additional first mortgage
bonds. The Company's ability to issue additional debt is also limited by the
need to maintain a reasonable ratio of debt to equity.
The Company's ability to sell additional preferred stock is limited by the
necessity to meet required dividend coverages. At December 31, 1998, the
applicable dividend coverage test would permit the issuance of $400 million of
additional preferred stock at a dividend rate of 7.5 percent.
Under the merger agreement with Sierra Pacific Resources, the Company is
limited to $350 million in additional debt financing. A portion of the limit,
$72 million, was used when the 7 3/4% Trust Issued Preferred Securities
described below were issued in 1998. The Company ceased issuing new common
equity in September, 1998 in compliance with the merger agreement limitation
on the number of new issuances of common shares without the approval of Sierra
Pacific Resources. The limitation on financing expires upon completion of the
proposed merger or termination of the agreement. In addition to other events
of termination provided in the agreement, either party may terminate the
agreement if the merger has not been completed by October 1999 (which date is
extended to April 2000 in case of regulatory delays).
On April 2, 1997, NVP Capital I (Trust), a wholly-owned subsidiary of the
Company, issued 4,754,860 8.2% QUIPS at $25 per security. The Company owns all
of the Series A common securities, 147,058 shares issued by the Trust for $3.7
million. The QUIPS and the common securities represent undivided beneficial
ownership interests in the assets of the Trust, a statutory business trust
formed under the laws of the state of Delaware. The existence of the Trust is
for the sole purpose of issuing the QUIPS and the common securities and using
the proceeds thereof to purchase from the Company its 8.2% Junior Subordinated
Deferrable Interest Debentures (QUIDS) due March 31, 2037, extendible to March
31, 2046 under certain conditions, in a principal amount of $122.6 million.
The sole asset of the Trust is the QUIDS. Holders of the Series A QUIPS are
entitled to receive preferential cumulative cash distributions accruing from
the date of original issuance and payable quarterly in arrears on the last day
of March, June, September and December of each year. The Series A QUIPS are
subject to mandatory redemption, in whole or in part, upon repayment of the
Series A QUIDS at maturity or their earlier redemption in an amount equal to
the amount of related Series A QUIDS maturing or being redeemed. The QUIPS are
redeemable at $25 per preferred security plus accumulated and unpaid
distributions thereon to the date of redemption. The Company's obligations
under the guarantee agreement entered into in connection with the QUIPS when
taken together with the Company's obligation to make interest and other
payments on the QUIDS issued to the Trust, and the Company's obligations under
the Indenture pursuant to which the QUIDS are issued and its obligations under
the Declaration, including its liabilities to pay costs, expenses, debts and
liabilities of the Trust, provides a full and unconditional guarantee by the
Company of the
4
<PAGE>
Trust's obligations under the QUIPS. Financial statements of the Trust are
consolidated with the Company's. Separate financial statements are not filed
because the Trust is wholly-owned by the Company and essentially has no
independent operations, and the Company's guarantee of the Trust's obligations
is full and unconditional. The $118.9 million in net proceeds to the Company
was used for general corporate utility purposes and the repayment of short-
term debt incurred to redeem the Company's $38 million, 9.9% Redeemable
Cumulative Preferred Stock on April 1, 1997.
In October 1998, NVP Capital III (Trust), a wholly-owned subsidiary of the
Company, issued 2,800,000 7 3/4% Cumulative Quarterly Trust Issued Preferred
Securities at $25 per security. The Company owns all the common securities,
86,598 shares issued by the Trust for $2.2 million. The Trust Issued Preferred
Securities and the common securities represent undivided beneficial ownership
interests in the assets of the Trust, a statutory business trust formed under
the laws of the state of Delaware. The existence of the Trust is for the sole
purpose of issuing the Trust Issued Preferred Securities and the common
securities and using the proceeds thereof to purchase from the Company its 7
3/4% Junior Subordinated Deferrable Interest Debentures due September 30,
2038, extendible to September 30, 2047 under certain conditions, in a
principal amount of $72.2 million. The sole asset of the Trust is the
deferrable interest debentures. Holders of the Trust Issued Preferred
Securities are entitled to receive preferential cumulative cash distributions
accruing from the date of original issuance and payable quarterly in arrears
on the last day of March, June, September and December of each year. The Trust
Issued Preferred Securities are subject to mandatory redemption, in whole or
in part, upon repayment of the deferrable interest debentures at maturity or
their earlier redemption in an amount equal to the amount of related
deferrable interest debentures maturing or being redeemed. The Trust Issued
Preferred Securities are redeemable at $25 per preferred security plus
accumulated and unpaid distributions thereon to the date of redemption. The
Company's obligations under the guarantee agreement entered into in connection
with the Trust Issued Preferred Securities when taken together with the
Company's obligation to make interest and other payments on the deferrable
interest debentures issued to the Trust, and the Company's obligations under
the Indenture pursuant to which the deferrable interest debentures are issued
and its obligations under the Declaration, including its liabilities to pay
costs, expenses, debts and liabilities of the Trust, provides a full and
unconditional guarantee by the Company of the Trust's obligations under the
trust issued preferred securities. Financial statements of the Trust are
consolidated with the Company's. Separate financial statements are not filed
because the Trust is wholly-owned by the Company and essentially has no
independent operations, and the Company's guarantee of the Trust's obligations
is full and unconditional. The $70 million in net proceeds to the Company was
used for general corporate utility purposes including the repayment of short
term debt.
Resource Planning
The Company's rate of customer growth, especially in recent years, has been
among the highest in the nation. The annual customer growth rate was 5.9
percent, 6.4 percent, and 7.2 percent in 1998, 1997 and 1996, respectively.
The peak demand for electricity by the Company's customers increased from
3,469 megawatts in 1997 to 3,855 megawatts in 1998. The Company's 1998 energy
sales reached 14,899,500 megawatthours, an increase of 2.1 percent over 1997.
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;
5
<PAGE>
(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 Competition section. Also see
the Merger; Dividend Policy section.
Regulation and Rates
The Company is subject to regulation by the PUCN which has regulatory powers
with respect to rates, facilities, services, reports, issuance of securities
and other matters.
On January 8, 1998, the PUCN approved a $45.6 million energy rate increase
effective February 1, 1998. The Company requested the increase to recover
higher costs for natural gas and purchased power. The PUCN also decided
previously recorded revenues from the sale of sulfur dioxide emission
allowances ($2.3 million, before tax) should be reversed and credited to a
deferred liability account for a later determination.
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. On
October 6, the PUCN approved $7.4 million of the $9.9 million increase
requested in connection with the 1997 deferred energy rate case. The effective
date for $6.2 million of the increase was November 1, 1998. The remaining $1.2
million was deferred to a future general rate case.
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. Because of the October 6 decision in
the 1997 deferred energy rate case referred to in the above paragraph, this
case was refiled with the PUCN on January 20, 1999 and reduced to $43.6
million. On February 25, 1999, the PUCN approved a $35.6 million energy rate
increase effective March 1, 1999. A total of $7.5 million was deferred to a
future general rate case. The Company was ordered to write-off the carrying
charges accrued on the $7.5 million.
Following is a summary of the rate increases and decreases that have been
granted the Company during the past three years.
SUMMARY OF RATE ADJUSTMENTS 1996 THROUGH 1998
<TABLE>
<CAPTION>
Amount in
Millions
Nature of Increase of
Effective Date (Decrease) Dollars
-------------- ------------------ ---------
<C> <S> <C>
February 1, 1997 Energy rate decrease $(45.0)
February 1, 1998 Energy rate increase 45.6
November 1, 1998 Energy rate increase 6.2
</TABLE>
All amounts are on an annual basis.
As permitted by state statute, the Company defers differences between the
current cost of fuel plus net purchased power and base energy costs as
defined. Under regulations adopted by the PUCN, the balance in the
6
<PAGE>
deferred energy account at the end of twelve months should be cleared over a
subsequent period. Recovery of increased costs is permitted to the extent that
the Company has not realized its authorized overall rate of return. If the
Company has exceeded the authorized rate of return, the portion of deferred
energy costs represented in such excess is transferred to the next deferred
energy recovery period. The energy costs deferred are included as a current
item in determining taxable income for federal income tax purposes. However,
for financial statement purposes, the federal income tax effect is deferred
and amortized to income as the deferred energy account is cleared. PUCN
regulations allow the fuel base portion of the Company's general rates to be
changed at the time of a hearing to clear the balance in the deferred energy
account. This permits the recovery of fuel expenses on a deferred basis, but,
recovery will have no effect on the Company's earnings.
The Company recovers the costs of developing its 20-year resource plan in
general rates effective February 1997. In the past, the recovery of these
costs was administered under the state's deferred accounting procedures. Also,
by an order of the PUCN in June 1988, the Company is allowed to capitalize
certain costs associated with Commission approved conservation programs.
Environmental Matters
The Company is subject to regulation by federal, state and local authorities
with regard to air and water quality control and other environmental matters.
Environmental expenditures made by the Company are currently being recovered
through customer rates. The following is a discussion of pending environmental
matters:
The Federal Clean Air Act Amendments of 1990 (Amendments) include provisions
for reduction of emissions of oxides of nitrogen by establishing new emission
limits for coal-fired generating units. This will require the installation of
additional pollution-control technology at some of the Reid Gardner Station
generating units before 2000 at an estimated cost to the Company of no more
than $6 million; $4.4 million has been spent to date. Installation is
scheduled for completion by May 1999.
Also, the United States Congress authorized the Environmental Protection
Agency (EPA) to study the potential impact the Mohave Generating Station
(Mohave) may have on visibility in the Grand Canyon area. A draft report of
the study results was released for peer review in September 1998. A formal
draft and final reports are expected in the first quarter of 1999. The
majority owner has estimated that control costs, if required, could total
between $300 and $350 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 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.
Competition
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. Bills
have been introduced in the legislature that would delay the start date until
early in 2000.
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;
7
<PAGE>
(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 services provided to those customers.
Affiliate Transaction Rules
On December 18, 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.
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, basic maintenance processes,
etc.
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 first quarter of 1999.
8
<PAGE>
Compliance Plans
In April 1999, the Company will file with the PUCN a compliance filing
showing bundled and unbundled costs of service. Costs will be unbundled into
26 different categories, which are broadly characterized as potentially
competitive and noncompetitive services. Rates for unbundled noncompetitive
services, mainly distribution services, are anticipated to be submitted to the
PUCN in November 1999, or 15 days after the unbundling decision is finalized.
Rates for noncompetitive services will be effective on the day retail access
begins. The rates for noncompetitive services will 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, are a restructuring issue that will be addressed in 1999. AB366
defines the legal criteria which 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 identification of applicable tax and
accounting issues.
On February 11, 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 submission of filings to recover
past costs, which will likely be 45 days after the order from the compliance
filing is issued. The Company estimates this to be 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.
Possible Further Industry Restructuring Legislation
In March 1999, Senate Bills 222 and 226 were introduced in the Nevada state
legislature. Senate Bill 222 would strengthen utilities' ability to recover
stranded costs and Senate Bill 226 would clarify legislative authority over
PUCN restructuring rules. The Company cannot predict whether these, or other
measures related to industry restructuring, will be adopted into law.
Employees
The Company had 1,888 employees at December 31, 1998.
9
<PAGE>
ITEM 2. PROPERTIES
The Company's generating facilities are described under "Item 1. Business,
Sources of Electric Energy Supply".
The Company shares ownership in a 59-mile, 500 kilovolt line and two 15-
mile, 230 kilovolt lines that transmit power from the Mohave Generating
Station near Davis Dam on the Colorado River via Eldorado Substation to Mead
Substation located near Boulder City, Nevada. The Company has 32 miles of 230
kilovolt line from Mead Substation to Las Vegas. This line, together with two
Company-owned 10-mile 230 kilovolt lines, presently connected to the Bureau of
Reclamation lines between Mead Substation and Henderson, Nevada, transmit the
Mohave Generating Station power to the Las Vegas area. A 25-mile, 230 kilovolt
line between the Mead Substation and the Company's Winterwood Substation was
energized in 1988. This line brings the additional Hoover energy to the Las
Vegas Area and increases the Company's interconnected transmission
capabilities. The Company shares ownership in 76 miles of 500 kilovolt
transmission line from the Navajo Generating Station to the Moenkopi
Switchyard in Coconino County, Arizona (the Southern Transmission System) and
274 miles of 500 kilovolt transmission line from the Navajo Generating Station
to the McCullough Substation in Clark County, Nevada (the Western Transmission
System). Power is transmitted from the McCullough Substation to the Las Vegas
area via three 230 kilovolt lines of 23 miles, 25 miles and 32 miles in
length, respectively. The 25-mile line was energized in May 1992. Two 230
kilovolt lines transmit power from the Reid Gardner Station located near
Glendale, Nevada. One is a 39 mile line to the Pecos Substation and the other
a 25 mile line to the Harry Allen Substation. In 1994, 20 miles of a 230
kilovolt line from the Harry Allen Substation to the Pecos Substation was
energized. One 39-mile, 230 kilovolt line transmits power from the
Reid Gardner Station located near Glendale, Nevada to the Pecos Substation
near North Las Vegas. A 7 mile, 230 kilovolt line between Westside and Decatur
Substations, both located in Las Vegas, was energized in 1991. A 32 mile, 230
kilovolt line between Arden Substation and Northwest Substation, both located
in Las Vegas, was energized in 1998. In addition to the above, the Company has
328 miles of 138 kilovolt and 494 miles of 69 kilovolt transmission lines in
service.
In 1990 the Company added a new transmission interconnection consisting of a
345 kilovolt line from Harry Allen Substation in southern Nevada to the
Nevada-Utah border where it connects with a PacifiCorp line to Red Butte
Substation in Southern Utah near the City of St. George and a 230 kilovolt
line from Harry Allen Substation to Westside Substation which is located in
Las Vegas. The Company owns the 50-mile, 230 kilovolt line and the 69 miles of
the 345 kilovolt line from Harry Allen Substation to the Nevada-Utah border;
PacifiCorp owns the portion of the 345 kilovolt line from the Nevada-Utah
border to Red Butte Substation.
At December 31, 1998, the Company owned 114 transmission and distribution
substations with a total installed transformer capacity of 12,733,283
kilovolt-amperes. In addition it co-owns with others the above mentioned
Eldorado Substation with installed transformer capacity of 1,000,000 kilovolt-
amperes, the McCullough Substation with installed transformer capacity of
1,250,000 kilovolt-amperes, the Reid Gardner Unit No. 4 Substation with
installed capacity of 318,000 kilovolt-amperes and Mead Substation with
250,000 kilovolt-amperes.
At Harry Allen Substation, the Company has a 336,000 kilovolt-ampere
transformer and two 336,000 kilovolt-ampere 345 kilovolt phase shifting
transformers which are used for necessary voltage transformations and to
control flows on the interconnection.
As of December 31, 1998, there were approximately 3,162 miles of pole line
together with approximately 9,338 cable miles of underground in the Company's
distribution system with a total installed distribution transformer capacity
of 6,702,081 kilovolt-amperes.
10
<PAGE>
ITEM 3. LEGAL PROCEEDINGS
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 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
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 Environmental Matters section of this Form 10-K). 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.
Also, the United States Congress authorized the EPA to study the potential
impact Mohave may have on visibility in the Grand Canyon area. A draft report
of the study results was released for peer review in September 1998 and a
final report is expected in the first quarter of 1999. The majority owner has
estimated that control costs, if required, could total between $300 and $350
million.
The owners of Mohave, including the Company, will participate in planned
collaborative talks with groups interested in the plant's future, provided
that all stakeholders are willing to participate in a collaborative effort.
The owners' position in these talks could include a commitment to place sulfur
dioxide scrubbers and fine particulate controls on the plant between 2005 and
2008. Interest groups include the local communities, plant employees, the EPA
state jurisdictions and the plant owners. Collaborative talks could begin in
the first quarter of 1999.
The Company is involved in litigation arising in the normal course of
business. While the results of such litigation cannot be predicted with
certainty, management, based upon advice of counsel, believes that the final
outcome will not have a material adverse effect on the Company's financial
position, results of operations and net cash flow.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Both the Company and Sierra Pacific Resources held special stockholder
meetings on October 9, 1998 during which stockholders of both companies voted
to approve the proposed merger between the two companies. Of the Company's
51,264,965 outstanding shares, 35,921,103 were voted for the merger, 1,473,505
were voted against the merger, 477,213 were voted as abstentions and
13,393,144 were not voted.
SUPPLEMENTAL ITEM. EXECUTIVE OFFICERS OF REGISTRANT
The Company's executive officers are as follows:
<TABLE>
<CAPTION>
Age as of
Name December 31, 1998 Position
---- ----------------- --------
<C> <C> <S>
Charles A. Lenzie 61 Chairman of the Board and Chief
Executive Officer
Michael R. Niggli 49 President and Chief Operating
Officer
David G. Barneby 53 Vice President, Power Delivery
Sally L. Galati 37 Vice President, Distribution
Cynthia K. Gilliam 50 Vice President, Retail Customer
Services
Richard L. Hinckley 43 Vice President, Secretary and
General Counsel
Steven W. Rigazio 44 Vice President, Finance and
Planning, Treasurer, Chief
Financial Officer
Gloria T. Banks Weddle 49 Vice President, Corporate
Services
</TABLE>
11
<PAGE>
Each of the executive officers has been actively engaged in the business of
the Company for more than five years with the exception of Mr. Niggli.
Charles A. Lenzie was elected Chairman of the Board and Chief Executive
Officer on May 1, 1989. Prior to that time he was President of the Company.
Mr. Lenzie is retiring effective March 31, 1999.
Michael R. Niggli joined the Company as President and Chief Operating
Officer in February 1998. He was appointed by the Company's Board of Directors
as Chief Executive Officer effective February 23, 1999. Prior to joining the
Company, he was Senior Vice President of the Custom Accounts Market Unit for
Entergy, a New Orleans-based global energy company. At Entergy, Mr. Niggli
served as Vice President of Fuels Management, Vice President of Strategic
Planning and Vice President for Customer Service in Louisiana. He was promoted
to Senior Vice President of Marketing in 1993 and Senior Vice President of the
Custom Accounts Market Unit in 1996.
David G. Barneby was elected Vice President, Power Delivery effective
October 14, 1993. He joined the Company in 1965 as a Student Engineer and was
made a Junior Engineer in 1967. He was promoted to Superintendent of the Reid
Gardner Generating Station in 1976; Project Manager--Reid Gardner Unit 4 in
1979 and in 1985 appointed Manager--Generation Engineering and Construction.
He was elected Vice President--Generation in 1989. His title was changed to
Vice President--Power Supply later that year.
Sally L. Galati was named Vice President, Distribution on March 13, 1997.
She first joined the Company in 1984 as an Engineer working in the Customer
Technical Services, Distribution and Transmission departments and was promoted
to Supervisor, Major Projects in 1992, Acting Manager, Builder Services in
1993, Director, Distribution System Services in 1994 and Division Director,
Distribution Operations & Construction in 1995.
Cynthia K. Gilliam was elected Vice President, Retail Customer Operations
effective October 14, 1993 and her title was changed to Vice President, Retail
Customer Services in 1997. She joined the Company in 1974 as a Rate Analyst
and was promoted to Rates Administrator in 1979 and to Manager of Financial
Planning in 1983. In 1987, she was appointed Manager of Human Resource
Planning. She was elected Vice President--Personnel in 1988 and her title was
changed to Vice President--Human Resources in 1989. In 1992, she was elected
Vice President--Customer Service.
Richard L. Hinckley was elected Vice President, Secretary and General
Counsel on May 15, 1991. He joined the Company as Staff Counsel in 1985 and
was promoted to Assistant Secretary and Chief Counsel in 1989. Prior to
joining the Company, he served as Staff Attorney with the PUCN and as
Assistant Attorney General in Utah.
Steven W. Rigazio was elected Vice President, Finance and Planning,
Treasurer, Chief Financial Officer effective October 14, 1993. He joined the
Company in 1984 as a Rates Administrator and was promoted to Supervisor of
Rates and Regulations in 1985, Manager of Rates and Regulatory Affairs in
1986, Director of System Planning in 1990, Vice President--Planning in 1991
and Vice President and Treasurer, Chief Financial Officer in 1992.
Gloria T. Banks Weddle was named Vice President, Corporate Services
effective January 1, 1996. She first joined the Company in 1973, was promoted
to Manager of Compensation and Benefits in 1988 and Director of Human
Resources in 1991. She was elected Vice President--Human Resources in 1992. On
October 14, 1993, she was elected Vice President, Human Resources and
Corporate Services. Her title was changed to Vice President--Corporate
Services in 1996.
12
<PAGE>
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK
AND RELATED SECURITY HOLDER MATTERS
Information with respect to the principal market for the Company's common
stock, securities exchange, shareholders of record, quarterly high and low
sales prices and quarterly dividend payments for 1998 and 1997 are hereby
incorporated by reference from page 59 of the Company's Annual Report to
Shareholders for the year ended December 31, 1998, which is filed herewith as
Exhibit 13.
ITEM 6. SELECTED FINANCIAL DATA
The information required by Item 6 is hereby incorporated by reference from
page 62 of the Company's Annual Report to Shareholders for the year ended
December 31, 1998, which is filed herewith as Exhibit 13.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The information required by Item 7 is hereby incorporated by reference from
pages 32 to 38 of the Company's Annual Report to Shareholders for the year
ended December 31, 1998, which are filed herewith as Exhibit 13.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES
ABOUT MARKET RISK
<TABLE>
<CAPTION>
Interest Rate Sensitivity
-----------------------------------------------------------
Fair Value
1999 2000 2001 2002 2003 Thereafter Total 12-31-98
----- ----- ---- ------ ---- ---------- ----- ----------
(Dollars in millions)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Long-term Debt,
including
Current Portion
Fixed Rate $ 45 $ 85 $- $ 15 $- $ 714 $859 $913
Average Interest Rate 6.93% 7.06% - 7.625% - 6.60%
Preferred Securities - - - - - $ 189 $189 $193
Average Interest Rate 8.03%
Notes Payable $ 105 - - - - - $105 $105
Average Interest Rate 6.83%
</TABLE>
The information required by Item 7A for qualitative disclosure is hereby
incorporated by reference from pages 32 to 38 of the Company's Annual Report to
Shareholders for the year ended December 31, 1998, which are filed herewith as
Exhibit 13.
ITEM 8. CONSOLIDATED FINANCIAL STATEMENTS
AND SUPPLEMENTARY DATA
The Company's consolidated financial statements for the years ended December
31, 1998, 1997 and 1996 together with the auditors' report thereon required by
Item 8 are incorporated by reference from the following
13
<PAGE>
pages of the Company's Annual Report to Shareholders for the year ended
December 31, 1998, which are filed herewith as Exhibit 13.
<TABLE>
<CAPTION>
Annual
Report
Page
------
<S> <C>
Consolidated Statements of Income for the Years Ended December 31,
1998, 1997 and 1996................................................. 39
Consolidated Balance Sheets--December 31, 1998 and 1997.............. 40-41
Consolidated Schedules of Capitalization--December 31, 1998 and 1997. 42
Consolidated Schedules of Long-Term Debt--December 31, 1998 and 1997. 43
Consolidated Statements of Comprehensive Income for the Years Ended
December 31, 1998, 1997 and 1996.................................... 44
Consolidated Statements of Retained Earnings for the Years Ended
December 31, 1998, 1997 and 1996.................................... 44
Consolidated Statements of Cash Flows for the Years Ended December
31, 1998, 1997 and 1996............................................. 45
Notes to Consolidated Financial Statements........................... 46-59
Independent Auditors' Report......................................... 60
Report of Management................................................. 61
</TABLE>
See Note 12 of Notes to Consolidated Financial Statements in the Company's
Annual Report to Shareholders for the unaudited selected quarterly financial
data required to be presented in this Item 8.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
There has been no Report on Form 8-K filed within the twenty-four months
prior to the date of the most recent consolidated financial statements,
December 31, 1998, reporting a change of accountants.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Information required by Item 10 with respect to the Company's executive
officers is set forth in Part I, Item 4., under the preceding heading
"Supplemental Item. Executive Officers of Registrant."
The Company's Board of Directors are as follows:
<TABLE>
<S> <C> <C>
Age as of First Became Director/
Name December 31, 1998 Term Expires
---- ----------------- ----------------------
Charles A. Lenzie 61 1983/1999
Michael R. Niggli 49 1998/2001
Mary Kaye Cashman 47 1997/1999
Mary Lee Coleman 62 1980/1999
Fred D. Gibson Jr. 71 1978/2001
John L. Goolsby 57 1991/2000
Jerry E. Herbst 61 1990/2000
John F. O'Reilly 53 1995/1999
Frank E. Scott 79 1972/2000
Arthur M. Smith 76 1959/2001
Jelindo A. Tiberti 79 1963/2000
</TABLE>
14
<PAGE>
Charles A. Lenzie is Chairman of the Board and Chief Executive Officer of
the Company. Mr. Lenzie joined the Company in 1974 as Vice President-Finance.
He was elected Senior Vice President-Finance and Accounting Services in
December 1979; President on February 1, 1983 and Chairman of the Board and
Chief Executive Officer on May 1, 1989. On August 10, 1995, Mr. Lenzie also
assumed the position of President until February 1998. Mr. Lenzie is a
graduate of the University of Illinois and a Certified Public Accountant. Mr.
Lenzie is retiring effective March 31, 1999.
Michael R. Niggli is President and Chief Operating Officer of the Company
effective February 1998. Prior to joining the Company, he was Senior Vice
President of the Custom Accounts Market Unit for Entergy, a New Orleans-based
global energy company. Since 1988, he has also served at Entergy as Senior
Vice President of Marketing and in Vice President positions for areas
including fuels, strategic planning and customer service. Mr. Niggli has a
bachelor's degree in electrical engineering from California State University
at Long Beach and a master's degree in electrical engineering from San Diego
State University. He is also a graduate of the Harvard Advanced Management
Program.
Mary Kaye Cashman is the Chief Executive Officer and Vice Chairman of the
Board of Cashman Equipment Company (one of the oldest and largest Caterpillar
dealers in North America). Mrs. Cashman has been involved with Cashman
Equipment Company since 1970, becoming a director in 1982 and CEO in 1995. She
holds a degree in nursing from the University of Nevada, Las Vegas and worked
as a registered nurse at University Medical Center from 1982-1987 and Sunrise
Hospital from 1988-1995. She serves on the boards of the Nevada Test Site
Development Corporation; Mackay School of Mines Advisory Board at the
University of Nevada, Reno; Bishop Gorman High School Endowment Foundation;
and McCaw Elementary School of Mines Foundation.
Mary Lee Coleman is the President of Coleman Enterprises (developer of
shopping centers and industrial parks). Mrs. Coleman is also a director of
First Dental Health. Mrs. Coleman is a graduate of the University of Southern
California.
Fred D. Gibson Jr. retired in 1997 as President and Chief Executive Officer
and in 1998 as Chairman but remains as a director of American Pacific
Corporation (manufacturer of chemicals and pollution abatement equipment; real
estate development) and Cashman Equipment Company. Mr. Gibson has been
affiliated with American Pacific Corporation and its predecessor, Pacific
Engineering & Production Co., since 1956. Mr. Gibson is a graduate of the
University of Nevada and holds a degree in Metallurgical Engineering.
John L. Goolsby retired in 1998 as President and Chief Executive Officer of
The Howard Hughes Corporation (real estate investment and land development
companies). Mr. Goolsby became affiliated with The Howard Hughes Corporation
in 1980 and became President in 1988. Mr. Goolsby is a director of America
West Holdings Corporation. Mr. Goolsby is a graduate of the University of
Texas at Arlington and a Certified Public Accountant.
Jerry E. Herbst is Chief Executive Officer of Terrible Herbst, Inc. (gas
station, car wash, convenience store chain) and Herbst Supply Co., Inc.
(wholesale fuel distribution), family-owned businesses for which he has worked
since 1959. Mr. Herbst is a partner of the Coast Resorts (hotel and casino
industry). Mr. Herbst is a graduate of the University of Southern California.
John F. O'Reilly is Chairman/CEO of the law firm of Keefer, O'Reilly,
Ferrario and Lubbers. Mr. O'Reilly is also Chairman and Chief Executive
Officer of the O'Reilly Gaming Group and is Chairman of the Nevada Test Site
Development Corporation. Mr. O'Reilly received his Juris Doctorate and
accounting degrees from St. Louis University and his MBA from the University
of Nevada, Las Vegas.
Frank E. Scott retired in 1988 as Chairman of the Board and Chief Executive
Officer of First Western Financial Corporation (holding company of a savings
and loan association). Mr. Scott is Chairman of the Board of Sports Media
Network and was previously Chairman of the Board of American Wollastonite
Mining
15
<PAGE>
Corporation. He was also Chairman of the Board and CEO of the Scott
Corporation, developer and operator of the Union Plaza Hotel.
Arthur M. Smith prior to his retirement in 1984 was Chairman of the Board of
First Interstate Bank of Nevada, N.A. Mr. Smith is a director of John Deere
Insurance Group and the W. M. Keck Foundation.
Jelindo A. Tiberti is Chairman of the Board of J. A. Tiberti Construction
Company, Inc. Mr. Tiberti is a Registered Professional Engineer.
ITEM 11. EXECUTIVE COMPENSATION
The following table summarizes the total compensation of the Chief Executive
Officer and the four other most highly compensated executive officers of the
Company for the year 1998, as well as the total compensation paid to each such
individual for the Company's two previous years.
Summary Compensation Table(6)
<TABLE>
<CAPTION>
Annual Compensation
---------------------------------
Name and Principal Salary Bonus Other Annual LTIP All Other
Position Year (1) (2) Compensation(3) Payouts(4) Compensation(5)
------------------ ---- -------- -------- --------------- ---------- ---------------
<S> <C> <C> <C> <C> <C> <C>
Charles A. Lenzie....... 1998 $461,145 $285,000 $9,628 $112,489 $4,800
Chairman of the Board and 1997 420,904 89,250 7,196 128,882 4,750
Chief Executive Officer, 1996 404,616 143,500 6,866 -0- 4,500
Director
Michael R. Niggli....... 1998 353,846 216,000 90,904 115,399 5,238
President and Chief
Operating Officer,
Director
Steven W. Rigazio....... 1998 219,462 67,500 14,946 29,304 4,800
Vice President, Finance 1997 202,269 30,750 13,712 36,594 4,800
and Planning, Treasurer, 1996 190,154 48,750 11,736 -0- 4,500
Chief Financial Officer
Cynthia K. Gilliam...... 1998 199,462 61,500 11,729 30,993 4,286
Vice President, Retail 1997 182,269 27,750 8,232 35,551 4,800
Customer Services 1996 181,192 43,750 14,555 -0- 4,500
David G. Barneby........ 1998 195,000 55,500 12,319 30,655 5,095
Vice President, 1997 180,908 27,750 10,831 33,063 4,800
Power Delivery 1996 180,014 42,504 11,739 -0- 4,500
</TABLE>
- --------
(1) Salaries represent base payroll compensation. Includes lump sum payment,
in 1998, of $10,000 for Mr. Barneby. Also includes lump sum payments, in
1996, of $7,000 for Mrs. Gilliam and $10,000 for Mr. Barneby.
(2) Amounts awarded under the Short-Term Incentive Plan for the respective
fiscal years.
(3) These amounts represent the personal use of Company automobiles and
reimbursement for payment of taxes thereon except for the amount for Mr.
Niggli which also includes $79,743 for relocation expenses.
(4) The amounts for 1998 and 1997 represent 50% of the LTIP target awards for
the 1996-1998 and 1995-1997 performance periods, respectively. See
Incentive Awards in the Compensation Committee Report on Executive
Compensation for a discussion of LTIP Awards.
(5) These amounts represent the Company's contribution to the Company's 401(k)
Plan.
(6) The number and value of the aggregate performance restricted shares under
the Company's Long-Term Incentive Plan as of December 31, 1998, are 15,942
shares and $414,494 for Mr. Lenzie; 15,319 shares and $398,306 for Mr.
Niggli; 4,767 shares and $123,954 for Mr. Rigazio; 4,289 shares and
$111,508 for Mrs. Gilliam; and 4,219 shares and $109,699 for Mr. Barneby,
respectively.
16
<PAGE>
Long-Term Incentive Plan--Awards in Last Fiscal Year
<TABLE>
<CAPTION>
Performance or Estimated Future Payouts under
Other Period Non-Stock Price-Based Plans
Until Maturation ---------------------------------------
Name or Payout Threshold (#) Target (#) Maximum (#)
- ---- ---------------- ------------- ------------ ------------
<S> <C> <C> <C> <C>
Charles A. Lenzie..... Three Years 3,200 shares 6,400 shares 9,600 shares
Michael R. Niggli..... Three Years 3,012 shares 6,024 shares 9,036 shares
Steven W. Rigazio..... Three Years 965 shares 1,929 shares 2,894 shares
Cynthia K. Gilliam.... Three Years 871 shares 1,741 shares 2,612 shares
David G. Barneby...... Three Years 870 shares 1,741 shares 2,612 shares
</TABLE>
The Company's Long-Term Incentive Plan (the "LTIP") gives participants the
opportunity to earn awards based on the Company's performance over a three-year
performance period. The performance period for the LTIP awards (the "Awards")
for 1998 began January 1, 1998 and ends December 31, 2000. The LTIP was
modified in 1998 for the 1998-2000 performance period and beyond. The change
was basically in the measurement criteria. The Awards of LTIP incentive
compensation units (the "Units") earned by the named executive officers will be
determined at the end of the three-year performance period based primarily on
the Company achieving targeted earnings per share. The earnings per share goal
will be cumulative over the three-year period. Earnings per share achieved in
each year will be combined to determine the cumulative earnings per share.
Total shareholder return performance will be retained as a measure which can
enhance the Award earned based on earnings per share. When earnings per share
performance is achieved at the target level or higher, the opportunity for an
enhanced Award is present. Earned Awards will be increased by 10% if earnings
per share performance is at or above target and the percentile rank of the
Company's three-year total shareholder return performance is between the 50th
and 75th percentiles in comparison to the Peer Group Companies Index (the
"Index"). Earned Awards will be increased by 20% if earnings per share
performance is at or above target and the percentile rank of the Company's
three-year total shareholder return performance is at the 75th percentile or
higher. Common stock of the Company at the rate of one share per Unit earned
will be paid to LTIP participants at the end of the performance period.
Participants would earn a percentage of the Award for the 1998-2000 performance
period based on cumulative three-year earnings per share, as follows:
<TABLE>
<CAPTION>
Cumulative Earnings Percentage of
Per Share Award Earned
------------------- -------------
<S> <C>
Less than $4.90.............................................. 0%
$4.90 through $5.53.......................................... 50%
$5.54 through $5.89 (target)................................. 100%
$5.90 or Higher.............................................. 150%
</TABLE>
The LTIP Awards earned for the 1997-1999 performance period would continue to
be based on the following measurements. The Awards of the Units earned by the
named executive officers will be determined at the end of the three-year
performance period based on the ranking of the Company's total shareholder
return (i.e., stock price appreciation plus reinvested dividends) in comparison
to the Index. Common stock of the Company at the rate of one share per Unit
earned will be paid to LTIP participants at the end of the performance period.
Participants would earn a percentage of the Award based on the percentile rank
of the Company's total shareholder return in comparison to the Index, as
follows:
<TABLE>
<CAPTION>
Percentile Rank Percentage of
of Company Award Earned
--------------- -------------
<S> <C>
Less than 40th............................................... 0%
40th..................................................... 50%
50th..................................................... 75%
60th..................................................... 90%
75th..................................................... 100%
90th..................................................... 125%
</TABLE>
17
<PAGE>
In the event of a change in control of the Company, Units previously granted
to Participants under the 1997-1999 and 1998-2000 LTIP shall automatically be
awarded to Participants without the necessity of further action by the
Committee or Company.
Retirement Benefits
The Company's Qualified Retirement Plan (the "Retirement Plan") for salaried
employees provides noncontributory benefits based upon both years of service
and the employee's highest consecutive 5-year average annual compensation.
Annual compensation includes salary and bonus amounts paid as shown in the
Summary Compensation Table. The credited years of service under the Retirement
Plan at December 31, 1998 for each of the individuals listed in the Summary
Compensation Table are as follows: Charles A. Lenzie, 23 years; Michael R.
Niggli, 26 years; Steven W. Rigazio, 13 years; Cynthia K. Gilliam, 23 years;
and David G. Barneby, 31 years. The Retirement Plan includes an early
retirement option under which a covered employee may receive a reduced benefit
upon early retirement between ages 55 and 62. Benefits payable upon retirement
after age 62 are unreduced. Benefits payable under the Retirement Plan must be
in compliance with applicable guidelines or maximums prescribed in the
Employees Retirement Income Security Act of 1974 as currently stated or as
adjusted from time to time.
The following table sets forth, by example, maximum annual benefits upon
retirement on or after age 62 from the Retirement Plan. The amounts shown
below represent the application of the Retirement Plan formula to the highest
consecutive 5-year average annual earnings and years of service shown.
<TABLE>
<CAPTION>
Maximum Annual Benefit for Specific
Years of Credited Service at Retirement
-------------------------------------------------
Highest Consecutive 20 25 30 35
5-Year Average Earnings 15 Years Years Years Years Years 40 Years
- ----------------------- -------- ------- ------- ------- ------- --------
<S> <C> <C> <C> <C> <C> <C>
$150,000...................... $38,300 $51,000 $63,800 $76,600 $89,300 $ 99,300
200,000...................... 39,400 52,500 65,600 78,700 91,800 102,000
250,000...................... 39,400 52,500 65,600 78,700 91,800 102,000
300,000...................... 39,400 52,500 65,600 78,700 91,800 102,000
350,000 and over............. 39,400 52,500 65,600 78,700 91,800 102,000
</TABLE>
The Company has adopted a Supplemental Executive Retirement Plan (the
"SERP") in addition to the Retirement Plan. Participation is limited to such
officers as the Board of Directors may select. Presently, 28 active or retired
designated officers, managers and beneficiaries including the five highest
paid officers of the Company, participate in the SERP. Each selected
participant who retires on or after age 62 with 25 years of service will
receive a SERP retirement benefit equivalent to 60% of his/her highest
consecutive 3-year average annual earnings reduced by the Retirement Plan
benefit. Annual earnings include wages, salary, bonus earned and the value of
other annual compensation amounts as shown in the Summary Compensation Table.
Reduced benefits apply to participants who retire with less than 25 years of
service or before age 62. Participants with more than 25 years of service at
retirement receive an additional benefit equal to 1.5% of their highest
consecutive 3-year average annual earnings for each year of service beyond 25
years. The credited years of service under the SERP at December 31, 1998 for
each of the individuals listed in the Summary Compensation Table are as
follows: Charles A. Lenzie, 24 years; Michael R. Niggli, 2 years; Steven W.
Rigazio, 14 years; Cynthia K. Gilliam, 24 years; and David G. Barneby, 32
years.
18
<PAGE>
The following table sets forth, by example, maximum annual benefits upon
retirement on or after age 62 under the combined regular Retirement Plan and
the SERP. The amounts shown below represent the application of the SERP
formula to the highest consecutive 3-year average annual earnings and years of
service shown. The amounts shown do not include Social Security benefits
payable upon retirement.
<TABLE>
<CAPTION>
Maximum Annual Benefit for Specific
Years of Credited Service at Retirement
-----------------------------------------------------
Highest Consecutive
3-Year Average Earnings 15 Years 20 Years 25 Years 30 Years 35 Years 40 Years
- ----------------------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C>
$150,000.................. $ 67,500 $ 78,750 $ 90,000 $101,250 $112,500 $123,750
200,000.................. 90,000 105,000 120,000 135,000 150,000 165,000
250,000.................. 112,500 131,250 150,000 168,750 187,500 206,250
300,000.................. 135,000 157,500 180,000 202,500 225,000 247,500
350,000.................. 157,500 183,750 210,000 236,250 262,500 288,750
400,000.................. 180,000 210,000 240,000 270,000 300,000 330,000
450,000.................. 202,500 236,250 270,000 303,750 337,500 371,250
500,000.................. 225,000 262,500 300,000 337,500 375,000 412,500
</TABLE>
Director Compensation
No director who receives a salary from the Company is paid any fees to serve
as a director or as a member of any committee of the Board of Directors. Those
directors not receiving salaries from the Company (the "Outside Directors")
are paid an annual fee of $20,000 plus $1,000 for each directors' meeting
attended; an annual fee of $10,000 for serving on the Executive Committee;
$1,000 per meeting attended for serving on the Audit Committee, the
Compensation Committee, the Nominating Committee, or the Pension Fund
Committee and an additional $400 per meeting for serving as Committee
Chairman. In addition, the Company provides a $20,000 term life insurance
benefit for each of the Outside Directors.
Retirement Plan for Outside Directors
The Company has established a Retirement Plan for the Outside Directors (the
"RPOD"). Outside Directors who are first elected after March 12, 1998 are not
eligible for benefits under the RPOD. The RPOD provides a maximum annual life
benefit equivalent to the annual fee being paid to the Outside Director at the
date of retirement. With respect to an Outside Director first elected after
May 11, 1990, receipt of the maximum annual life benefit under the RPOD is
subject to (a) minimum service for 5 years as an Outside Director and
(b) retirement on or before the first day of the month following such Outside
Director's 72nd birthday. The annual benefit received by an Outside Director
elected after May 11, 1990, who has met the minimum 5-year service
requirement, will be reduced by $500 for each year such Outside Director
retires after their 65th birthday but prior to their 72nd birthday.
Employment Contract
The Company entered into an employment contract with Mr. Lenzie in March
1998. The employment contract is for a three year term and provides for an
initial base salary of $475,000 per year. Mr. Lenzie will also be included in
the SERP, the LTIP, the Short-Term Incentive Plan and he will be provided an
automobile pursuant to the executive automobile policy. The employment
contract also contains a change-in-control provision which would give Mr.
Lenzie the amount equal to 3 times the annual salary in the event the Company
is sold or merged and Mr. Lenzie terminates his employment with the Company.
The Company entered into an employment contract with Mr. Niggli when he
joined Nevada Power Company as President and Chief Operating Officer. The
employment contract is for a three year term and provides for an initial base
salary of $400,000 per year. Mr. Niggli will be provided with 26 years of
credited service for the Retirement Plan, but the Company will only be
responsible for paying the difference between the
19
<PAGE>
Retirement Plan benefit and any benefits being paid by previous employers. Mr.
Niggli will also be included in the SERP, the LTIP, the Short-Term Incentive
Plan and he will also be provided an automobile pursuant to the executive
automobile policy. The employment contract also contains a change-in-control
provision which would give Mr. Niggli an amount equal to 2.99 times the annual
salary, and full vesting of his Retirement Plan and SERP benefits in the event
the Company is sold or merged and Mr. Niggli terminates his employment with
the Company.
All other remaining officers listed in the Summary Compensation Table
(Steven Rigazio, Cynthia Gilliam and David Barneby) entered into employment
contracts for three-year terms and which provide for their base salaries
($225,000, $205,000 and $185,000, respectively). Each Vice President will also
be included in the SERP, the LTIP, the Short-Term Incentive Plan and an
automobile pursuant to the executive automobile policy. These employment
contracts also contain a change-in-control provision which would give them an
amount equal to 2 times the annual salary in the event the Company is sold or
merged and if employment terminates with the Company.
Severance Allowance Plan
The Company has a Severance Allowance Plan (the "Severance Plan") for
eligible employees under which any regular full-time or part-time employee of
the Company will be eligible for severance benefits if terminated within three
years after a change in control of the Company. The following are
circumstances under which a change in control may occur: (a) the dissolution
or liquidation of the Company; (b) a reorganization, merger, or consolidation
with one or more corporations in which the Company is not the surviving
corporation; (c) the sale, exchange, or transfer of Company stock resulting in
any person or the person's affiliates owning more than 20 percent of the
outstanding shares; (d) the election to the Company's Board of Directors of
new members who were not originally nominated to the Board at the previous two
annual meetings if, as a result of this election, new members constitute a
majority of the Board, and (e) the sale of all or substantially all of the
Company's assets. These are the only business conditions under which the
Severance Plan becomes effective.
The severance benefit is payable in full at the time of the employee's
termination and equals the employee's monthly base salary, plus any bonus, in
effect during the month immediately preceding termination, times the total
number of months of severance benefits (the "severance benefit period") to
which the employee is entitled based upon the employee's years of service. The
severance benefit period for each employee shall be determined under the
following schedule:
<TABLE>
<CAPTION>
Company Seniority Severance
Except Officers Benefit Period
----------------- --------------
<S> <C>
6 Months to 5 Years........................................ 6 Months
6 Years to 10 Years........................................ 9 Months
11 Years to 20 Years........................................ 12 Months
21 Years and over........................................... 18 Months
</TABLE>
The severance benefit period for officers will be 24 months, except for the
Chief Executive Officer and Chief Operating Officer whose severance benefit
period is 36 months. In addition, each eligible employee will receive
continued medical and life insurance benefits during such severance benefit
period. No amounts paid or payable under the Severance Plan shall reduce or
offset any amounts payable under other plans maintained by the Company,
including any amounts payable under the Company's Retirement Plan or 401(k)
Plan; nor shall any amounts paid or payable under any such plans reduce or
offset any amounts payable under the Severance Plan. No payments will be made
under the Severance Plan, if combined with any other compensation from the
Company, the payments constitute what is defined as "excess parachute
payments" by the Internal Revenue Code. Excess parachute payments are defined
as those amounts over three times an individual's annualized average total
compensation at the Company for each of the five years preceding the change-
in-control.
20
<PAGE>
Compensation Committee Report On Executive Compensation
The Compensation Committee of the Board of Directors (the "Committee") is
responsible for establishing the philosophy for compensating the Company's
executives and ensuring that all aspects of the Executive Compensation Program
are administered consistent with the philosophy. During 1998, the Committee
met two times. This report describes the Committee's decisions during 1998 in
determining the compensation earned by the Chief Executive Officer (the
"CEO"), the Chief Operating Officer, (the "COO"), and all other officers as a
group.
The Omnibus Budget Reconciliation Act of 1993 contained provisions on the
deductibility of executive compensation. All compensation paid to the CEO and
other proxy-named executives for 1998 is fully deductible. It is the
Committee's intention to maintain the complete deductibility in the future;
however, we reserve the right to deviate from this policy when and if we
determine it is in the best interests of the Company and its shareholders to
do so.
The Company has retained the services of Towers Perrin, a compensation
consulting firm, to assist the Committee in connection with the performance of
its various duties. Towers Perrin has been retained in this capacity since
1990. Towers Perrin provides advice to the Committee with respect to the
reasonableness of compensation paid to the officers of the Company.
Overall Objectives
The primary objective of the Executive Compensation Program is to motivate
the officers to achieve the Company's goals of providing the Company's
shareholders with a competitive return on their investment, while at the same
time providing its customers with high quality service at a competitive price.
The compensation philosophy, therefore, bases a significant portion of each
officer's total compensation on the achievement of these goals.
Compensation Philosophy
The Executive Compensation Program is reviewed on an annual basis to ensure
its alignment with the Company's compensation philosophy. To retain and
attract an experienced results-oriented team, the Company's compensation
philosophy is to provide a total compensation opportunity between the median
and 75th percentile in comparison to both regulated and nonregulated
businesses. Each year, the Committee reviews data from the Edison Electric
Institute (the "EEI") Executive Compensation Survey of electric utilities and
Towers Perrin's annual management compensation survey. In the following
performance graph, the Company's total return to shareholders is compared to
that of the electric utilities comprising the Peer Group Companies Index and
the S&P 500 Stock Index. The Peer Group Companies Index is comprised of the
companies from the now-discontinued Salomon Electric Utilities Index adjusted
for mergers and restructurings. The overwhelming majority of the companies in
the Peer Group Companies Index participate in the EEI survey database. The
companies in the Towers Perrin survey parallel the type and mix of companies
comprising the S&P 500 Stock Index.
The Executive Compensation Program for the officers of the Company is
comprised of base salary, annual performance-related awards and a long-term
incentive plan. Annual base salary increases reflect the individual's
performance and contribution over several years. Annual incentive awards vary
directly with annual corporate performance for all officers. The long-term
incentive plan approved by the Company's shareholders in 1993 provides
officers with the opportunity to earn shares of common stock based on the
Company achieving targeted earnings per share and the Company's total return
to shareholders compared to a peer group of electric utilities.
The remainder of this report discusses the administration of the 1998
Executive Compensation Program with respect to the CEO, COO and the other
officers as a group.
21
<PAGE>
1998 Base Salary
The CEO received a salary increase of 11.8% in 1998. All other officers
received increases of between 5.4% and 10.8%. For 1998, the CEO's salary and
salaries for all other officers as a group were at the 75th percentile of
salaries for comparable positions within the electric utility industry.
1998 Incentive Awards
Awards under the Company's Short-Term Incentive Plan for 1998 were based on
two corporate performance goals weighted as follows--corporate earnings, 60%;
and customer satisfaction, 40%. Specific corporate performance goals were
established at the beginning of the year. Achievement of the corporate
performance goals were evaluated and taken into consideration in determining
1998 annual incentive awards for all officers.
The 1998 incentive award earned by the CEO was 60% of salary while the COO
earned 54% of salary. The incentive awards for all other officers were 30% of
salary. These awards reflected the Company surpassing both the targeted
earnings goal and targeted levels of customer satisfaction.
Under the Company's LTIP for the 1996-1998 performance period, the Company's
total shareholder return for the period, in comparison to the Peer Group
Companies Index, was at the 48th percentile. This ranking relates to a 50%
payout of the awards granted to all officers in 1996.
Under the provisions of the Company's LTIP, the officers of the Company were
granted a total number of 22,541 stock units for the 1998-2000 period. The
CEO's grant of 6,400 stock units and the grant to all other officers as a
group was based on the Company's philosophy of providing the opportunity to
earn total compensation between the 50th and 75th percentile of regulated and
nonregulated businesses. The actual number of stock units earned by the CEO
and all officers as a group will be determined in 2001 based on the Company's
earning per share goals and total shareholders return as compared to a peer
group of electric utilities for the period 1998-2000 or such other measure as
the Committee deems appropriate.
Both the Short-Term Incentive Plan and the Long-Term Incentive Plan contain
provisions whereby, in the event of a change of control, any performance
cycles in process will be paid out on a prorata basis at target.
COMPENSATION COMMITTEE
Arthur M. Smith
John L. Goolsby
Jerry E. Herbst
Frank E. Scott
Jelindo A. Tiberti
22
<PAGE>
PERFORMANCE GRAPH
The following graph shows a five-year comparison of cumulative total returns
for the Company's common stock, the S&P 500 Stock Index, and the Peer Group
Companies Index. The companies that make up the Peer Group Companies Index are
listed below.
Comparison of Five-Year Cumulative Total Return Among
Nevada Power Company Common Stock (NPC), S&P 500 Stock Index (S&P 500)
and Peer Group Companies Index (Peer)
Value of Investment ($)
COMPARISON OF FIVE-YEAR CUMULATIVE TOTAL RETURN
AMONG NEVADA POWER, S&P 500 INDEX AND PEER GROUP
PERFORMANCE GRAPH APPEARS HERE
<TABLE>
<CAPTION>
Measurement Period NEVADA S&P
(Fiscal Year Covered) POWER 500 INDEX Peer Group
- ------------------- ---------- --------- ----------
<S> <C> <C> <C>
Measurement Pt- 12/31/93 $100 $100 $100
FYE 12/31/94 $ 91 $101 $ 88
FYE 12/31/95 $107 $139 $116
FYE 12/31/96 $107 $171 $118
FYE 12/31/97 $149 $229 $150
FYE 12/31/98 $155 $294 $172
</TABLE>
Assumes $100 invested on December 31, 1993 in Nevada Power Company common
stock, S&P 500 Stock Index and Peer Group Companies Index with dividend
reinvestment over the period.
The Companies included in the Peer Group Companies Index are the following.
<TABLE>
<S> <C>
ALLEGHENY ENERGY INC AMEREN CORP
AMERICAN ELECTRIC POWER ATLANTIC ENERGY INC
BALTIMORE GAS & ELECTRIC BOSTON EDISON CO
CAROLINA POWER & LIGHT CENTERIOR ENERGY CORP
CENTRAL & SOUTHWEST CORP CINERGY CORP
CIPSCO INC CMS ENERGY CORP
CONSOLIDATED EDISON OF NY DELMARVA POWER & LIGHT
DOMINION RESOURCES INC DPL INC
DQE INC DTE ENERGY CO
DUKE ENERGY CORP EASTERN UTILITIES ASSOC
EDISON INTERNATIONAL ENOVA CORP
ENTERGY CORP FIRSTENERGY CORP
FLORIDA PROGRESS CORP FPL GROUP INC
</TABLE>
23
<PAGE>
<TABLE>
<S> <C>
GPU INC HOUSTON INDUSTRIES INC
IDAHO POWER CO ILLINOVA CORP
IPALCO ENTERPRISES INC KANSAS CITY POWER & LIGHT
KU ENERGY CORP LG&E ENERGY CORP
LONG ISLAND LIGHTING MONTANA POWER CO
NEW CENTURY ENERGIES INC NEW ENGLAND ELECTRIC SYSTEM
NEW YORK STATE ELEC & GAS NIAGARA MOHAWK POWER
NIPSCO INDUSTRIES INC NORTHEAST UTILITIES
NORTHERN STATES POWER/MIN OGE ENERGY CORP
PACIFICORP PECO ENERGY CO
PG&E CORP PINNACLE WEST CAPITAL
PORTLAND GENERAL CORP POTOMAC ELECTRIC POWER
PP&L RESOURCES INC PUBLIC SERVICE CO OF NEW MEXICO
PUBLIC SERVICE ENTRP PUGET SOUND ENERGY INC
ROCHESTER GAS & ELECTRIC SCANA CORP
SIERRA PACIFIC RES SOUTHERN CO
TECO ENERGY INC TEXAS UTILITES CO
UNICOM CORP WESTERN RESOURCES INC
WISCONSIN ENERGY CORP
</TABLE>
ITEM 12. SECURITY OWNERSHIP OF CERTAIN
BENEFICIAL OWNERS AND MANAGEMENT
The following table presents certain information regarding the Company's
Common Stock beneficially owned by each director, the Chief Executive Officer
and the four other most highly compensated executive officers of the Company
for the year 1998, and all directors and executive officers of the Company as
a group as of December 31, 1998:
<TABLE>
<CAPTION>
Amount and Nature Percent of
Name of Beneficial Owner of Beneficial Ownership Class
------------------------ ----------------------- ----------
<S> <C> <C>
Mary Kaye Cashman...................... 8,118(1) .016%
Mary Lee Coleman....................... 299,157(2) .584%
Fred D. Gibson, Jr..................... 7,593(3) .015%
John L. Goolsby........................ 5,440(4) .011%
Jerry E. Herbst........................ 5,100(5) .010%
Charles A. Lenzie...................... 18,926(6)(14) .037%
Michael R. Niggli...................... 4,261(5)(14) .008%
John F. O'Reilly....................... 2,000(7) .004%
Frank E. Scott......................... 4,146(5) .008%
Arthur M. Smith........................ 1,200(8) .002%
Jelindo A. Tiberti..................... 2,000(9) .004%
David G. Barneby....................... 6,374(10)(14) .012%
Cynthia K. Gilliam..................... 4,740(11)(14) .009%
Steven W. Rigazio...................... 7,317(12)(14) .014%
All Directors & Executive Officers as a
Group
(17 individuals)(15).................. 385,657(13)(14) .752%
</TABLE>
- --------
(1) 6,300 shares held in street name; balance held in shareholder's name.
(2) 158,696 shares held in shareholder's name; balance held in family trust.
(3) 4,600 shares held in street name; balance held in shareholder's name.
(4) 5,000 shares held in street name; balance held in shareholder's name.
(5) Held in shareholder's name.
(6) 7,930 shares held in street name; balance held in shareholder's name.
24
<PAGE>
(7) Held in street name.
(8) 1,000 shares held in street name; balance held in family trust.
(9) 1,250 shares held in street name; balance held in name of controlled
corporation.
(10) 1,136 shares held in street name; 2,392 shares held in shareholder's
name; balance held in trust.
(11) 1,478 shares held in street name; balance held in shareholder's name.
(12) 3,485 shares held in shareholder's name; balance held in family trust.
(13) Includes 750 shares held in the name of controlled corporation; 30,694
shares held in street name; 150,601 shares held in trust and 203,612
shares held in shareholders' names.
(14) Of the shares shown, 3,127 shares beneficially owned by Mr. Lenzie, 216
shares beneficially owned by Mr. Niggli, 2,392 shares beneficially owned
by Mr. Barneby, 2,283 shares beneficially owned by Mrs. Gilliam, 2,057
shares beneficially owned by Mr. Rigazio, and 14,888 of the shares
beneficially owned by all directors and executive officers as a group are
held in the Company's 401(k) Plan for the benefit of such shareholders.
These shares are fully vested. All shares of Company Common Stock held in
the Company's 401(k) Plan are subject to shared voting power with the
trustee of the 401(k) Plan.
(15) None of the directors or executive officers own any of the Company's
outstanding Cumulative Preferred Stock or Preference Stock.
The management of the Company does not know of any shareholder holding more
than 5% of the Company's common stock.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The Management of the Company has no knowledge of any transaction,
relationship or indebtedness which is required to be disclosed by Item 13.
PART IV
ITEM 14. EXHIBITS, CONSOLIDATED FINANCIAL STATEMENT SCHEDULE
AND REPORTS ON FORM 8-K
The Company's consolidated financial statements for the years ended December
31, 1998, 1997 and 1996 together with the auditors' report appearing on pages
39 to 60 of Nevada Power Company's 1998 Annual Report to Shareholders are
incorporated herein by reference and filed as Exhibit 13.
<TABLE>
<CAPTION>
Consolidated Financial Statement Schedule for the
Years Ended December 31, 1998, 1997 and 1996 Page
------------------------------------------------- ----
<S> <C>
Independent Auditors' Consent and Report on Schedule.................. 35
Schedule II--Valuation and Qualifying Accounts........................ 36
</TABLE>
All other schedules are omitted because they are not applicable, not
required, or because the information is included in the consolidated financial
statements or notes thereto.
<TABLE>
<CAPTION>
Exhibits
Filed Description
-------- -----------
<C> <S>
10.86 Amendment dated April 30, 1998 to Exhibit 10.55
10.87 Amendment dated April 30, 1998 to Exhibit 10.48
12 Computation of Ratios--December 31, 1998
13 Pages 32 to 62 of Nevada Power Company's Annual Report to
Shareholders for the Year Ended December 31, 1998 (incorporated by
reference in Parts II and IV hereof)
23 Independent Auditors' Consent and Report on Schedule
27 Financial Data Schedule--December 31, 1998
</TABLE>
25
<PAGE>
In addition to those Exhibits shown above, the Company hereby incorporates
the following Exhibits pursuant to Exchange Act Rule 12B-32 and Regulation
#201.24 by reference to the filings set forth below:
<TABLE>
<CAPTION>
Exhibit Originally Filed
No. Description as Exhibit File No.
------- ----------- ---------------- --------
<C> <S> <C> <C>
2.1 Agreement and Plan of Merger, April 2.1 to Form 8-K 1-4698
29, 1998 by Nevada Power Company, Year 1998
Sierra Pacific Resources, LAKE
Merger Sub, Inc. and DESERT Merger
Sub, Inc.
3.1 Restated Articles of Incorporation 3.8 to Form 10-K 1-4698
filed June 10, 1988 Year 1988
3.2 Amendment to Restated Articles of 4.7 to Form S-8 33-32372
Incorporation filed May 23, 1989
3.3 Amendment to Restated Articles of 4.8 to Form S-3 33-55698
Incorporation filed June 8, 1992
3.4 Restated Bylaws, as amended March 9, 3.4 to Form 10-K 1-4698
1995 Year 1995
4.1 Certificate of Designation of
Cumulative Preferred Stock as
follows:
5.40% Series 2.1 to Form S-1 2-16968
5.20% Series 2.1 to Form S-1 2-20618
4.70% Series 3.2 to Form 8-K 1-4698
July 1965
8% Series 2.1 to Form S-7 2-44513
8.70% Series 2.1 to Form S-7 2-49622
11.50% Series 2.1 to Form S-7 2-52238
9.75% Series 2.1 to Form S-7 2-56788
Auction Series A 4.6 to Form S-3 33-15554
Auction Series A as amended November 4.9 to Form S-3 33-44460
14, 1991
Auction Series A as amended December 4.1 to Form 10-K 1-4698
12, 1991 Year 1992
9.90% Series 4.1 to Form 10-K 1-4698
Year 1992
4.2 Indenture of Mortgage and Deed of 4.2 to Form S-1 2-10932
Trust Providing for First Mortgage
Bonds, dated October 1, 1953 and
Twenty-Six Supplemental Indentures
as follows:
First Supplemental Indenture, dated 4.2 to Form S-1 2-11440
August 1, 1954
Second Supplemental Indenture, dated 4.9 to Form S-1 2-12566
September 1, 1956
Third Supplemental Indenture, dated 4.13 to Form S-1 2-14949
May 1, 1959
Fourth Supplemental Indenture, dated 4.5 to Form S-1 2-16968
October 1, 1960
</TABLE>
26
<PAGE>
<TABLE>
<CAPTION>
Exhibit Originally Filed
No. Description as Exhibit File No.
------- ----------- ---------------- --------
<C> <S> <C> <C>
Fifth Supplemental Indenture, dated 4.6 to Form S-16 2-74929
December 1, 1961
Sixth Supplemental Indenture, dated 4.6A to Form S-1 2-21689
October 1, 1963
Seventh Supplemental Indenture, 4.6B to Form S-1 2-22560
dated August 1, 1964
Eighth Supplemental Indenture, dated 4.6C to Form S-9 2-28348
April 1, 1968
Ninth Supplemental Indenture, dated 4.6D to Form S-1 2-34588
October 1, 1969
Tenth Supplemental Indenture, dated 4.6E to Form S-7 2-38314
October 1, 1970
Eleventh Supplemental Indenture, 2.12 to Form S-7 2-45728
dated November 1, 1972
Twelfth Supplemental Indenture, 2.13 to Form S-7 2-52350
dated December 1, 1974
Thirteenth Supplemental Indenture, 4.14 to Form S-16 2-74929
dated October 1, 1976
Fourteenth Supplemental Indenture, 4.15 to Form S-16 2-74929
dated May 1, 1977
Fifteenth Supplemental Indenture, 4.16 to Form S-16 2-74929
dated September 1, 1978
Sixteenth Supplemental Indenture, 4.17 to Form S-16 2-74929
dated December 1, 1981
Seventeenth Supplemental Indenture, 4.2 to Form 10-K 1-4698
dated August 1, 1982 Year 1982
Eighteenth Supplemental Indenture, 4.6 to Form S-3 33-9537
dated November 1, 1986
Nineteenth Supplemental Indenture, 4.2 to Form 10-K 1-4698
dated October 1, 1989 Year 1989
Twentieth Supplemental Indenture, 4.21 to Form S-3 33-53034
dated May 1, 1992
Twenty-First Supplemental Indenture, 4.22 to Form S-3 33-53034
dated June 1, 1992
Twenty-Second Supplemental 4.23 to Form S-3 33-53034
Indenture, dated June 1, 1992
Twenty-Third Supplemental Indenture, 4.23 to Form S-3 33-53034
dated October 1, 1992
Twenty-Fourth Supplemental 4.23 to Form S-3 33-53034
Indenture, dated October 1, 1992
Twenty-Fifth Supplemental Indenture, 4.23 to Form S-3 33-53034
dated January 1, 1993
Twenty-Sixth Supplemental Indenture, 4.2 to Form 10-K 1-4698
dated May 1, 1995 Year 1995
4.3 Instrument of Further Assurance 4.8 to Form S-1 2-12566
dated April 1, 1956 to Indenture of
Mortgage and Deed of Trust dated
October 1, 1953
4.4 Rights Agreement dated October 15, 4.1 to Form 8-A 1-4698
1990 between Manufacturers Hanover Year 1990
Trust Company and Nevada Power
Company
</TABLE>
27
<PAGE>
<TABLE>
<CAPTION>
Exhibit Originally Filed
No. Description as Exhibit File No.
------- ----------- ---------------- --------
<C> <S> <C> <C>
4.5 Junior Subordinated Indenture 4.01 to Form S-3 333-21091
between Nevada Power and IBJ
Schroder Bank & Trust Company,
as Debenture Trustee dated March
1, 1997
4.6 Trust Agreement of NVP Capital I 4.03 to Form S-3 333-21091
dated March 1, 1997
4.7 Form of Amended and Restated 4.10 to Form S-3 333-21091
Trust Agreement dated March 1,
1997
4.8 Form of Preferred Security 4.11 to Form S-3 333-21091
Certificate for NVP Capital I
and NVP Capital II dated March
1, 1997
4.9 Form of Guarantee Agreement dated 4.12 to Form S-3 333-21091
March 1, 1997
4.10 Form of Supplemental Indenture 4.13 to Form S-3 333-21091
between Nevada Power and IBJ
Schroder Bank & Trust Company,
as Debenture Trustee dated March
1, 1997
4.11 Form of Agreement as to Expenses 4.14 to Form S-3 333-21091
and Liabilities between Nevada
Power and NVP Capital I dated
March 1, 1997
4.12 Form of Indenture between Nevada 4.1 to Form S-3 333-63613
Power and IBJ Schroder Bank & and
Trust Company, as Trustee dated 333-63613-01
October 1, 1998
4.13 Certificate of Trust of NVP 4.2 to Form S-3 333-63613
Capital III dated October 1, and
1998 333-63613-01
4.14 Trust Agreement for NVP Capital 4.3 to Form S-3 333-63613
III dated October 1, 1998 and
333-63613-01
4.15 Form of Amended and Restated 4.4 to Form S-3 333-63613
Declaration of Trust dated and
October 1, 1998 333-63613-01
4.16 Form of Preferred Security 4.5 to Form S-3 333-63613
Certificate for NVP Capital III and
dated October 1, 1998 333-63613-01
4.17 Form of Preferred Securities 4.7 to Form S-3 333-63613
Guarantee Agreement dated and
October 1, 1998 333-63613-01
4.18 Form of Junior Subordinated 4.9 to Form S-3 333-63613
Deferrable Interest Debenture and
dated October 1, 1998 333-63613-01
4.19 Amendment dated April 29, 1998 to 10.1 to Form 8-K 1-4698
Rights Agreement Exhibit 4.4 Year 1998
10.1 Contract for Sale of Electrical 13.9A to Form S-1 2-10932
Energy between State of Nevada
and the Company, dated October
10, 1941
10.2 Amendment dated June 30, 1953 to 13.9A to Form S-1 2-10932
Exhibit 10.1
10.3 Contract for Sale of Electrical 13.10 to Form S-1 2-10932
Energy between State of Nevada
and the Company, dated June 1,
1951
</TABLE>
28
<PAGE>
<TABLE>
<CAPTION>
Exhibit Originally Filed
No. Description as Exhibit File No.
------- ----------- ---------------- --------
<C> <S> <C> <C>
10.4 Agreement dated November 10, 1948 13.18 to Form S-1 2-12697
between the Company and Lincoln
County Power District No. 1 and
Overton Power District No. 5
10.5 Agreement dated October 21, 1949 13.19 to Form S-9 2-12697
between the Company and Lincoln
County Power District No. 1 and
Overton Power District No. 5
10.6 Mohave Project Plant Site 13.27 to Form S-9 2-28348
Conveyance and Co-tenancy
Agreement dated May 29, 1967
between the Company and Salt River
Project Agricultural Improvement
and Power District and Southern
California Edison Company
10.7 Eldorado System Conveyance and Co- 13.30 to Form S-9 2-28348
tenancy Agreement dated December
20, 1967 between the Company and
Salt River Project Agricultural
Improvement and Power District and
Southern California Edison Company
10.8 Mohave Operating Agreement dated 13.26F to Form S-1 2-38314
July 6, 1970 between the Company,
Salt River Project Agricultural
Improvement and Power District,
Southern California Edison Company
and Department of Water and Power
of the City of Los Angeles
10.9 Navajo Project Participation 13.27A to Form S-1 2-38314
Agreement dated September 30, 1969
between the Company, the United
States of America, Arizona Public
Service Company, Department of
Water and Power of the City of Los
Angeles, Salt River Project
Agricultural Improvement and Power
District and Tucson Gas & Electric
Company
10.10 Navajo Project Coal Supply 13.27B to Form S-1 2-38314
Agreement dated June 1, 1970
between the Company, the United
States of America, Arizona Public
Service Company, Department of
Water and Power of the City of Los
Angeles, Salt River Project
Agricultural District, Tucson Gas
& Electric Company and the Peabody
Coal Company
10.11 Contract dated January 1, 1968 13.32 to Form S-1 2-34588
between the Company and United
States Bureau of Reclamation for
interconnections at Mead Station
10.12 Note Agreement dated December 11, 5.35 to Form S-7 2-49622
1973 relating to $25,000,000 8
1/2% Promissory Notes due 1998
10.13 Reclaimed Wastewater Purchase 5.36 to Form S-7 2-52238
Agreement dated June 21, 1974
among City of Las Vegas, Nevada,
Clark County Sanitation District
No. 1, County of Clark, Nevada and
Nevada Power Company
10.14 Equipment Lease dated as of March 5.37 to Form 8-K 1-4698
1, 1974 between Nevada Power April 1974
Company, Lessor, and Clark County,
Nevada, Lessee
</TABLE>
29
<PAGE>
<TABLE>
<CAPTION>
Exhibit Originally Filed
No. Description as Exhibit File No.
------- ----------- ---------------- --------
<C> <S> <C> <C>
10.15 Sublease Agreement dated as of 5.38 to Form 8-K 1-4698
March 1, 1974 between Clark April 1974
County, Nevada, Sublessor, and
Nevada Power Company, Sublessee
10.16 Guaranty Agreement dated as of 5.39 to Form 8-K 1-4698
March 1, 1974 between Nevada Power April 1974
Company and Commerce Union Bank as
Trustee
10.17 Navajo Project Co-tenancy Agreement 5.31 to Form 8-K 1-4698
dated March 23, 1976 between the April 1974
Company, Arizona Public Service
Company, Department of Water and
Power of the City of Los Angeles,
Salt River Project Agricultural
Improvement and Power District,
Tucson Gas & Electric Company and
the United States of America
10.18 Amended Mohave Project Coal Supply 5.35 to Form S-7 2-56356
Agreement dated May 26, 1976
between the Company and Southern
California Edison Company,
Department of Water and Power of
the City of Los Angeles, Salt
River Project Agricultural
Improvement and Power District and
the Peabody Coal Company
10.19 Amended Mohave Project Coal Slurry 5.36 to Form S-7 2-56356
Pipeline Agreement dated May 26,
1976 between Peabody Coal Company
and Black Mesa Pipeline, Inc.
(Exhibit B to Exhibit 10.18)
10.20 Coal Supply Agreement dated October 5.38 to Form S-7 2-56356
15, 1975 between the Company and
United States Fuel Company
10.21 Amendment dated November 19, 1976 5.30 to Form S-7 2-62105
to Exhibit 10.20
10.22 Participation Agreement Reid 5.34 to Form S-7 2-65097
Gardner Unit No. 4 dated July 11,
1979 between the Company and
California Department of Water
Resources
10.23 Coal Supply Agreement dated March 5.37 to Form S-7 2-62509
1, 1980 between the Company and
Beaver Creek Coal Company
10.24 Coal Supply Agreement dated March 5.38 to Form S-7 2-62509
1, 1980 between the Company and
Trail Mountain Coal Company
10.25 Coal Supply Agreement dated 10.26 to Form 10-K 1-4698
December 8, 1980 between the Year 1981
Company and Plateau Mining Company
10.26 Coal Supply Agreement dated August 10.26 to Form 10-K 1-4698
31, 1982 between the Company and Year 1982
CO-OP Mining Company
10.27 Coal Supply Agreement dated 10.27 to Form 10-K 1-4698
September 8, 1982 between the Year 1982
Company and Getty Mining Company
10.28 Coal Supply Agreement dated 10.28 to Form 10-K 1-4698
September 8, 1982 between the Year 1982
Company and Tower Resources, Inc.
10.29 Coal Supply Agreement dated 10.29 to Form 10-K 1-4698
September 22, 1982 between the Year 1982
Company and Beaver Creek Coal
Company
</TABLE>
30
<PAGE>
<TABLE>
<CAPTION>
Exhibit Originally Filed
No. Description as Exhibit File No.
------- ----------- ---------------- --------
<C> <S> <C> <C>
10.30 Memorandum of Understanding 10.30 to Form 10-K 1-4698
Concerning Interconnection between Year 1983
Utah Power & Light Company and
Nevada Power Company dated February
2, 1984
10.31 Sublease Agreement between Powveg 10.31 to Form 10-K 1-4698
Leasing Corp., as Lessor and Nevada Year 1983
Power Company as Lessee, dated
January 11, 1984 for lease of
administrative headquarters
10.32 Participation Agreement between Utah 10.32 to Form 10-K 1-4698
Power & Light Company and the Year 1985
Company dated December 19, 1985
10.33 Sale and Purchase Agreement dated as 10.33 to Form 10-K 1-4698
of December 23, 1985 by and between Year 1985
Nevada Power Company and CP
National Corporation
10.34 Restated Coal Sales Agreement as of 10.34 to Form 10-K 1-4698
July 1, 1985 by and between Nevada Year 1985
Power Company and Trail Mountain
Coal Company
10.35 Summary of Supplemental Executive 10.35 to Form 10-K 1-4698
Retirement Plan as approved Year 1985
November 14, 1985
10.36 Financing Agreement dated as of 10.36 to Form 10-K 1-4698
February 1, 1983 between Clark Year 1985
County, Nevada and Nevada Power
Company
10.37 Financing Agreement between Clark 10.37 to Form 10-K 1-4698
County, Nevada and Nevada Power Year 1985
Company dated as of December 1,
1985
10.38 Reimbursement Agreement dated as of 10.38 to Form 10-K 1-4698
December 1, 1985 between The Fuji Year 1986
Bank, Limited and Nevada Power
Company
10.39 Contract for Sale of Electrical 10.39 to Form 10-K 1-4698
Energy between the State of Nevada Year 1987
and the Company, dated July 8, 1987
10.40 Power Sales Agreement between Utah 10.40 to Form 10-K 1-4698
Power & Light Company and the Year 1987
Company, dated August 17, 1987
10.41 Transmission Facilities Agreement 10.41 to Form 10-K 1-4698
between Utah Power & Light Company Year 1987
and the Company, dated August 17,
1987
10.42 Financing Agreement between Clark 10.42 to Form 10-K 1-4698
County, Nevada and Nevada Power Year 1988
Company dated as of November 1,
1988
10.43 Reimbursement Agreement dated as of 10.43 to Form 10-K 1-4698
November 1, 1988 between The Fuji Year 1988
Bank, Limited and Nevada Power
Company
10.44 Power Purchase Contract dated 10.45 to Form 10-K 1-4698
February 15, 1990 between Mission Year 1989
Energy Company and Nevada Power
Company
10.45 Contract for Long-Term Power 10.46 to Form 10-K 1-4698
Purchases from Qualifying Year 1989
Facilities dated May 1, 1989
between Oxford Energy of Nevada and
Nevada Power Company
</TABLE>
31
<PAGE>
<TABLE>
<CAPTION>
Exhibit Originally Filed
No. Description as Exhibit File No.
------- ----------- ---------------- --------
<C> <S> <C> <C>
10.46 Contract A for Long-Term Power 10.47 to Form 10-K 1-4698
Purchases from Qualifying Year 1989
Facilities dated May 2, 1989
between Bonneville Nevada
Corporation and Nevada Power
Company
10.47 Contract for Long-Term Power 10.48 to Form 10-K 1-4698
Purchases from Qualifying Year 1989
Facilities dated April 10, 1989
between Magna Energy Systems,
Eastern Sierra Energy Company and
Nevada Power Company
10.48 Contract B for Long-Term Power 10.49 to Form 10-K 1-4698
Purchases from a Qualifying Year 1989
Facility dated October 27, 1989
between Bonneville Nevada
Corporation and Nevada Power
Company
10.49 Contract for Long-Term Power 10.50 to Form 10-K 1-4698
Purchases from Qualified Facilities Year 1989
dated February 12, 1990 between Las
Vegas Co-generation, Inc. and
Nevada Power Company
10.50 Agreement for Transmission Service 10.51 to Form 10-K 1-4698
dated March 29, 1989 between Year 1989
Overton Power District No. 5 ,
Lincoln County Power District No. 1
and Nevada Power Company
10.51 Contract dated June 30, 1988 between 10.52 to Form 10-K 1-4698
United States Department of Energy Year 1989
Western Area Power Administration
and Nevada Power Company
10.52 Executive Performance Incentive Plan 10.53 to Form 10-K 1-4698
dated as of January 1, 1989 Year 1989
10.53 Severance Allowance Plan adopted 10.54 to Form 10-K 1-4698
September 14, 1989 Year 1989
10.54 Power Purchase Contract dated July 10.55 to Form 10-K 1-4698
5, 1990 between Mission Energy Year 1990
Company and Nevada Power Company
10.55 Contract B for Long-Term Power 10.56 to Form 10-K 1-4698
Purchases from a Qualifying Year 1990
Facility dated May 24, 1990 between
Bonneville Nevada Corporation and
Nevada Power Company
10.56 Amendment dated June 15, 1989 to 10.57 to Form 10-K 1-4698
Exhibit 10.45 Year 1990
10.57 Amendment dated August 23, 1989 to 10.58 to Form 10-K 1-4698
Exhibit 10.45 Year 1990
10.58 Amendment dated April 23, 1990 to 10.59 to Form 10-K 1-4698
Exhibit 10.45 Year 1990
10.59 Exhibit H dated August 13, 1990 to 10.60 to Form 10-K 1-4698
Exhibit 10.45 Year 1990
10.60 Western Systems Power Pool Agreement 10.61 to Form 10-K 1-4698
(Agreement) dated January 2, 1991 Year 1990
between thirty-nine other Western
Systems Power Pool members as
listed on pages 1 and 2 of the
Agreement and Nevada Power Company
</TABLE>
32
<PAGE>
<TABLE>
<CAPTION>
Exhibit Originally Filed
No. Description as Exhibit File No.
------- ----------- ---------------- --------
<C> <S> <C> <C>
10.61 Financing Agreement between Clark 10.62 to Form 10-K 1-4698
County, Nevada and Nevada Power Year 1990
Company dated June 1, 1990
10.62 Restated Power Sales Agreement dated 10.63 to Form 10-K 1-4698
March 25, 1991 between Pacificorp Year 1991
and Nevada Power Company
10.63 Amendment dated July 17, 1990 to 10.64 to Form 10-K 1-4698
Exhibit 10.54 Year 1991
10.64 Financing Agreement between Clark 10.65 to Form 10-K 1-4698
County, Nevada and Nevada Power Year 1992
Company dated June 1, 1992 (Series
1992A)
10.65 Financing Agreement between Clark 10.66 to Form 10-K 1-4698
County, Nevada and Nevada Power Year 1992
Company dated June 1, 1992 (Series
1992B)
10.66 Financing Agreement between Clark 10.67 to Form 10-K 1-4698
County, Nevada and Nevada Power Year 1992
Company dated October 1, 1992
10.67 Power Sales Agreement dated October 10.68 to Form 10-K 1-4698
19, 1992 between the Department of Year 1992
Water and Power of the City of Los
Angeles and Nevada Power Company
10.68 Long-Term Incentive Plan dated as of 10.69 to Form 10-K 1-4698
January 1, 1993 Year 1993
10.69 Contract for Long-Term Power 10.70 to Form 10-K 1-4698
Purchases from Qualifying Year 1993
Facilities dated May 27, 1992
between Las Vegas Co-generation,
Inc. and Nevada Power Company
Replaces Exhibit 10.49
10.70 Settlement Agreement and Promissory 10.71 to Form 10-K 1-4698
Note between Mountain Coal Company Year 1993
and Atlantic Richfield Company and
Nevada Power Company dated March 9,
1994
10.71 401(k) Savings Plan, as amended and 99.1 to Form S-8 33-50809
restated January 1, 1990
10.72 Amendment dated January 1, 1991 to 99.2 to Form S-8 33-50809
Exhibit 10.71
10.73 Letter of Credit and Reimbursement 10.72 to Form 10-K 1-4698
Agreement dated as of April 12, Year 1994
1994 between Nevada Power Company
and Societe Generale, Los Angeles
Branch and Amendment No. 1 thereto
dated as of May 3, 1994
10.74 Loan Agreement dated as of November 10.73 to Form 10-K 1-4698
21, 1994 between Nevada Power Year 1994
Company, certain banks, and First
Interstate Bank of Nevada, N.A. as
the Administrative Agent
10.75 Financing Agreement between Clark 10.75 to Form 10-K 1-4698
County, Nevada and Nevada Power Year 1995
Company dated October 1, 1995
(Series 1995A)
</TABLE>
33
<PAGE>
<TABLE>
<CAPTION>
Exhibit Originally Filed
No. Description as Exhibit File No.
------- ----------- ---------------- --------
<C> <S> <C> <C>
10.76 Financing Agreement between Clark 10.76 to Form 10-K 1-4698
County, Nevada and Nevada Power Year 1995
Company dated October 1, 1995
(Series 1995B)
10.77 Financing Agreement between Clark 10.77 to Form 10-K 1-4698
County, Nevada and Nevada Power Year 1995
Company dated October 1, 1995
(Series 1995C)
10.78 Financing Agreement between Clark 10.78 to Form 10-K 1-4698
County, Nevada and Nevada Power Year 1995
Company dated October 1, 1995
(Series 1995D)
10.79 Financing Agreement between Coconino 10.79 to Form 10-K 1-4698
County, Arizona Pollution Control Year 1995
Corporation and Nevada Power
Company dated October 1, 1995
(Series 1995E)
10.80 Letter of Credit and Reimbursement 10.80 to Form 10-K 1-4698
Agreement dated as of October 1, Year 1995
1995 among Nevada Power Company,
The Banks Named Herein, and Societe
Generale, Los Angeles Branch
10.81 Letter of Credit and Reimbursement 10.81 to Form 10-K 1-4698
Agreement dated as of October 1, Year 1995
1995 among Nevada Power Company,
The Banks Named Herein, and
Barclays Bank PLC, New York Branch
10.82 Financing Agreement between Coconino 10.82 to Form 10-K 1-4698
County, Arizona Pollution Control Year 1996
Corporation and Nevada Power
Company dated October 1, 1996
10.83 Financing Agreement between Clark 10.83 to Form 10-K 1-4698
County, Nevada and Nevada Power Year 1997
Company dated November 1, 1997
10.84 Financing Agreement between Coconino 10.84 to Form 10-K 1-4698
County, Arizona Pollution Control Year 1997
Corporation and Nevada Power
Company dated November 1, 1997
10.85 Loan Agreement dated as of November 10.85 to Form 10-K 1-4698
21, 1997 between Nevada Power Year 1997
Company, certain banks, Nationsbank
of Texas, N.A. as Documentation
Agent and Wells Fargo Bank,
National Association as Arranger
and Administrative Agent
</TABLE>
Reports on Form 8-K
The Company filed no current report on Form 8-K during the quarter ended
December 31, 1998.
34
<PAGE>
INDEPENDENT AUDITORS' CONSENT AND REPORT ON SCHEDULE
We consent to the incorporation by reference in Registration Statements No.
333-46567 on Form S-3 and No. 33-34011 on Form S-8 of Nevada Power Company of
our report dated March 1, 1999 incorporated by reference in this Annual Report
on Form 10-K of Nevada Power Company for the year ended December 31, 1998.
Our audits of the consolidated financial statements referred to in our
aforementioned report also included the consolidated financial statement
schedule of Nevada Power Company, listed in Item 14. This consolidated
financial statement schedule is the responsibility of Nevada Power Company's
management. Our responsibility is to express an opinion based on our audits.
In our opinion, such consolidated financial statement schedule, when
considered in relation to the basic consolidated financial statements taken as
a whole, presents fairly in all material respects the information set forth
therein.
DELOITTE & TOUCHE LLP
Las Vegas, Nevada
March 15, 1999
35
<PAGE>
NEVADA POWER COMPANY
SCHEDULE II--VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
(In Thousands of Dollars)
<TABLE>
<CAPTION>
Reserve for
Doubtful
Accounts
-----------
<S> <C>
BALANCE AT JANUARY 1, 1996.......................................... $ 1,327
Provision charged to income....................................... 3,829
Amounts written off, less recoveries.............................. (2,264)
-------
BALANCE AT DECEMBER 31, 1996........................................ 2,892
Provision charged to income....................................... 2,737
Amounts written off, less recoveries.............................. (3,338)
-------
BALANCE AT DECEMBER 31, 1997........................................ 2,291
Provision charged to income....................................... 3,697
Amounts written off, less recoveries.............................. (3,559)
-------
BALANCE AT DECEMBER 31, 1998........................................ $ 2,429
=======
</TABLE>
36
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) 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.
<TABLE>
<S> <C> <C>
NEVADA POWER COMPANY
________________________________________
(Registrant)
March 19, 1999 By MICHAEL R. NIGGLI
________________________________________
Michael R. Niggli
Chief Executive Officer
Pursuant to the requirements of the Securities Act of 1934, this report has
been signed below by the following persons on behalf of the registrant and in
the capacities and on the dates indicated.
March 19, 1999 By MICHAEL R. NIGGLI
________________________________________
Michael R. Niggli, Chief Executive
Officer and Director
(Principal Executive Officer)
March 19, 1999 By STEVEN W. RIGAZIO
________________________________________
Steven W. Rigazio, Vice President,
Finance and Planning, Treasurer,
Chief Financial Officer
(Principal Financial and
Principal Accounting Officer)
March 19, 1999 By MARY KAYE CASHMAN
________________________________________
Mary Kaye Cashman, Director
March 19, 1999 By MARY LEE COLEMAN
________________________________________
Mary Lee Coleman, Director
March 19, 1999 By FRED D. GIBSON JR.
________________________________________
Fred D. Gibson Jr., Director
March 19, 1999 By JOHN L. GOOLSBY
________________________________________
John L. Goolsby, Director
March 19, 1999 By JERRY E. HERBST
________________________________________
Jerry E. Herbst, Director
March 19, 1999 By CHARLES A. LENZIE
________________________________________
Charles A. Lenzie, Director
March 19, 1999 By JOHN F. O'REILLY
________________________________________
John F. O'Reilly, Director
March 19, 1999 By FRANK E. SCOTT
________________________________________
Frank E. Scott, Director
March 19, 1999 By ARTHUR M. SMITH
________________________________________
Arthur M. Smith, Director
March 19, 1999 By JELINDO A. TIBERTI
________________________________________
Jelindo A. Tiberti, Director
</TABLE>
37
<PAGE>
RESTATED FIRST AMENDMENT TO POWER PURCHASE AGREEMENT
This Restated First Amendment to Power Purchase Agreement (this "Amendment") is
made and entered into this 30 day of April, 1998 by and between Nevada
Cogeneration Associates #2, a Utah general partnership ("Seller") and Nevada
Power Company, a Nevada corporation ("Nevada"). Seller and Nevada are sometimes
referred to herein collectively as the "Parties" and individually as a "Party".
RECITALS
A. Bonneville Nevada Corporation ("Bonneville") and Nevada executed that certain
Bonneville Nevada Contract B with Nevada Power Company for Long Term Power
Purchases from Qualifying Facilities (the "Contract") dated July 19, 1990
which was assigned to Seller effective as of January 29, 1991.
B. Seller and Nevada executed that certain First Amendment to Power Purchase
Agreement dated October 3, 1997 (the "First Amendment") under the following
basis:
i. Seller and Nevada have had a continuing dispute concerning the second
paragraph of Section 4.6.3 of the Contract and the right thereunder of
Nevada to curtail potential purchases of capacity and energy from
Seller's Generating Facility.
ii. Seller and Nevada wish to resolve their dispute and to make other
changes to the Contract which will provide greater operating flexibility
for Nevada and create mutually beneficial opportunities for Seller,
Nevada, and Nevada's customers in connection with the purchase and sale
of energy and capacity from Seller's Generating Facility.
iii. To effect such resolution and changes, the Parties wish:
a. To amend Section 4.6.3 of the Contract.
b. To revise the payment provisions set forth in the Contract.
c. To provide a mechanism by which Nevada, upon mutual agreement of the
Parties (reached at each Party's sole discretion), may reduce its take
of the output from Seller's Generating Facility that would otherwise be
delivered by Seller to Nevada under the Contract.
d. To provide a mechanism by which Seller, upon mutual agreement of the
Parties (reached at each Party's sole discretion), may sell to other
parties the capacity or energy from Seller's Generating Facility that
would otherwise be dedicated by Seller to Nevada under the Contract.
e. To allow payment for Excess Energy and Excess Capacity by Nevada to
Seller on the basis of a negotiated market rate rather than Nevada's
Tariff Schedule QF-Short Term Energy and Capacity rates.
Page 1
<PAGE>
C. Pursuant to Section 20 of the First Amendment, Nevada filed a Petition with
the Public Utilities Commission of Nevada ("Commission") seeking approval of
the First Amendment as executed and approval of a regulatory accounting
treatment with respect to the First Amendment, assigned Docket No. 97-11004.
D. The Parties to Docket No. 97-11004 have filed a stipulation to amend the
First Amendment and describe a regulatory accounting treatment acceptable to
Nevada. The Parties have asked the Commission to approve such stipulation.
E. The Parties entered into an Agreement to Extend Cancellation Date of First
Amendment to Power Purchase date March 26, 1998, for 90 days to allow time
for approval of the stipulation.
F. The terms of the First Amendment must be revised pursuant to the terms of the
stipulation.
NOW, THEREFORE, in consideration of the mutual promises and obligations
stated herein and the mutual benefits to be derived therefrom, Seller and Nevada
hereby agree to this Restated First Amendment to the Contract as follows:
1. This Amendment shall amend and supersede the First Amendment and any
amendments thereto in their entirety.
2. Section 1.9.3 of the Contract is hereby amended to read as follows:
Nevada shall, in accordance with a Purchase Schedule, purchase and pay Seller
for Excess Capacity and Released Capacity made available to Nevada by Seller
only under rates, terms and conditions which are mutually agreed to by Nevada
and Seller.
3. Section 1.10.3 of the Contract is hereby amended to read as follows:
Nevada shall, in accordance with a Purchase Schedule, purchase and pay Seller
for Excess Energy and Released Energy delivered to Nevada by Seller only
under rates, terms and conditions which are mutually agreed to by Nevada and
Seller.
4. All capitalized terms shall have the meaning stated in Section 2 of the
Agreement, except as expressly amended by this Amendment.
5. The following definitions are hereby added to Section 2 of the Contract:
5.1. Derate Amount: The Contract Capacity and associated Energy less the
-------------------
amount of capacity and energy Seller is able to produce and deliver to
Nevada during any time that Seller experiences a Derating.
Page 2
<PAGE>
5.2. Derating: The Seller's inability to deliver the full Contract Capacity
--------------
and associated Energy due to a physical partial or complete outage of
either Seller's Generating Facility or the associated transmission
line.
5.3. First Amendment Effective Date: The date the Commission issues an order
------------------------------------
approving the First Amendment as amended by this Amendment.
5.4. Purchase Schedule: A document setting forth the mutual agreement of
-----------------------
the Parties regarding the sale by Seller and the purchase by Nevada of
Excess Energy, Excess Capacity, Released Energy, and/or Released
Capacity. The Purchase Schedule shall be substantially in the form
attached hereto as Exhibit 2. The Purchase Schedule may be changed upon
the express consent of the Parties.
5.5. Recall Time: The period of time within which Seller must become capable
-----------------
of delivering Released Energy to Nevada following the request of
Nevada.
5.6. Release: Release, in accordance with the terms of a mutually agreed
-------------
upon Release Schedule, of a Party's obligation to purchase, dedicate,
or sell capacity and energy in accordance with Section 4A hereunder,
that would otherwise be dedicated and/or delivered by Seller to Nevada
under the Contract.
5.7. Release Period: That period or those periods of time during which
--------------------
Release will occur.
5.8. Release Rate: The payment rate for the Release.
------------------
5.9. Release Schedule: A document setting forth the mutual agreement of the
----------------------
Parties regarding the Release Period, the Released Energy and Released
Capacity, the Release Rate, Recall Time, an other terms and conditions
pertaining thereto. The Release Schedule shall be substantially in the
form attached hereto as Exhibit 1A or Exhibit 1B, as applicable. The
Release Schedule may be changed upon the express consent of the
Parties.
5.10. Released Capacity: The amount of capacity, associated with Released
-----------------------
Energy, that is Released.
5.11. Released Energy: The amount of energy that is Released.
---------------------
6. The following sections of the Contract shall be amended to read as follows:
6.1. Section 2.11 - Excess Capacity: Capacity in excess of Contract Capacity
---------------
or as designated by the Parties during a Release Period in accordance
with a Purchase Schedule. The amount of Excess Capacity shall be
determined on a kWh basis hour by hour.
Page 3
<PAGE>
6.2. Section 2.12 - Excess Energy: Energy associated with Capacity in excess
--------------
of Contract Capacity or as designated by the Parties during a Release
Period in accordance with a Purchase Schedule. The amount of Excess
Energy shall be determined on a kWh basis hour by hour.
7. Section 4.6.3 of the Contract is hereby amended to read as follows:
The Parties agree that the provisions of 18 C.F.R. Sec. 292.304(f) pertaining
to curtailment and reduction of output from qualifying facilities shall not
apply to Seller's Generating Facility or the obligations of Seller and Nevada
under this Contract.
Nevada shall have the right to require Seller to reduce the output of
Seller's Generating Facility or to isolate any of Seller's Facilities from
Nevada's electric system if, in Nevada's reasonable judgment, such actions
are required to facilitate the maintenance of any of Nevada's facilities or
to maintain Nevada's Electric System Integrity. Nevada shall, within a
reasonable period of time and to the extent possible, endeavor to correct the
condition that necessitated the reduction or isolation. The duration of such
reduction or isolation shall be limited to the period of time that the
condition existed plus a reasonable period of time for the restoration of
Nevada's electric system to an operating condition that allows Nevada to
resume the discharge of its obligations in accordance with the provisions of
this Contract.
If Nevada has required Seller to reduce the output of Seller's Generating
Facility or to isolate any of Seller's Facilities from Nevada's electric
system, Seller shall neither increase the output nor reconnect the isolated
facilities without the prior approval of Nevada's Operating Representative.
Provisions for obtaining such approval have been set forth in Exhibit C.
8. A new Section 4A, "Release", is hereby added to the Contract to read as
follows:
4A.1 Nevada may request of Seller, and Seller may permit Nevada, at
Seller's sole discretion, to be Released of its obligation to purchase
all of the Contract Capacity and associated Energy output of Seller's
Generating Facility for any reason pursuant to the terms and
conditions of a Release Schedule.
Seller may request of Nevada, and Nevada may permit Seller, at
Nevada's sole discretion, to be Released of its obligation to dedicate
all of the capacity and associated energy output of Seller's
Generating Facility to Nevada for any reason pursuant to the terms and
conditions of a Release Schedule.
Neither Seller nor Nevada is under an obligation to accept a Release
Schedule proposed by the other Party.
Page 4
<PAGE>
4A.2 If Nevada is Released, Nevada shall pay Seller for the Release at the
Release Rate set forth in the applicable Release Schedule. If Nevada
is Released, payment for the Release shall be due only to the extent
that the Seller's Generating Facility is able to produce the Released
Energy and such Released Energy could be delivered to Nevada within
the stated Recall Time. The ability of Seller's Generating Facility
to produce and the availability for delivery of such Released Energy
to Nevada shall be subject to reasonable review and verification by
Nevada. Seller shall not take a Scheduled Outage during any Release
Period.
If Seller is Released, Seller shall pay Nevada for the Release at the
Release Rate set forth in the applicable Release Schedule.
Payment shall be made on a per kWh basis, unless otherwise agreed by
the Parties, as if the Released Energy had been delivered.
4A.3 If, for any reason during any Release Period, Seller experiences a
Derating, then, for the duration of the Derating within the Release
Period, Seller shall not deliver to Nevada capacity and energy in
excess of Contract Capacity and associated Energy less Released
Capacity and Released Energy less the Derate Amount. Examples of
payments during a Derating, should it occur during a Release Period,
in accordance with the Contract and the appropriate Release Schedule,
are given in Exhibit 3.
4A.4. Except as specifically provided in this Section 4A, payment for
Release hereunder shall be made in the same manner and under the same
conditions set forth in Section 13 hereof.
9. Section 10.1.1. of the Contract is hereby amended to read as follows:
Summer Season: For the purposes of this section, a summer season shall
-------------
include May, June, July, August, and September. During a summer season, total
Energy produced and delivered to Nevada during the On-peak hours of that
season must meet or exceed the product of (Contract Capacity multiplied by
the number of On-peak hours during that season less the total Released Energy
during that season's On-peak hours) and 90%.
10.Section 10.1.2. of the Contract is hereby amended to read as follows:
Winter Season: For the purposes of this section, a winter season shall
include the months of December, January, and February. During a winter
season, total Energy produced and delivered to Nevada during the On-peak
hours of that season must meet or exceed the product of (Contract Capacity
multiplied by the number of On-peak hours during that season less the total
Released Energy during that season's On-peak hours) and 90%.
Page 5
<PAGE>
11.Exhibit A of the Contract, entitled "Power Purchase Contract Payment
Provisions", shall be replaced in its entirety with the following:
Exhibit A
Power Purchase Contract
Payment Provisions
For the purposes of this exhibit, a summer season shall include the months
of May, June, July, August, and September. The associated On-Peak hours shall
be the twelve (12) hours from 10:00 am to 10:00 p.m. each day of the summer
period; all other hours shall be Off-Peak hours.
For the purposes of this exhibit, a winter season shall include the months
of January, February, March, April, October, November, and December. The
associated On-Peak hours shall be the five (5) hours from 5:00 am to 10:00 am
and the eight (8) hours from 4:00 p.m. to midnight each day of the winter
period; all other hours shall be Off-Peak hours.
Maintenance months shall include the months of March, April, October, and
November.
Except as otherwise provided, the rates ($/kWh) applicable to this Contract
shall be:
<TABLE>
<CAPTION>
Summer Summer Winter Winter
On-Peak Off-Peak On-Peak Off-Peak
-------------------------------------------------------------
<S> <C> <C> <C> <C>
Capacity 0.05410 0.02060 0.03170 0.02060
Energy 0.02310 0.02120 0.02120 0.02120
------ ------- ------- ------- -------
Total 0.07720 0.04180 0.05290 0.04180
</TABLE>
The above cited rates shall be effective from January 1, 1990 through April
30, 1991.
The above cited Capacity rates shall be adjusted by zero (0) percent per
annum, on May 1 of each year beginning with the annual adjustment date of May 1,
1991 and ending with the annual adjustment date of May 1, 1998. The above cited
Capacity rates shall be adjusted by two and one-half (2.5) percent per annum
beginning with the annual adjustment date of May 1, 1999, and ending with the
annual adjustment date of May 1, 2007. On the annual adjustment date of May 1,
2008, the Capacity rates shall be reduced to the following levels:
<TABLE>
<CAPTION>
Summer Summer Winter Winter
On-Peak Off-Peak On-Peak Off- Peak
-------------------------------------------------------------
<S> <C> <C> <C> <C>
Capacity 0.04100 0.01480 0.02250 0.01480
</TABLE>
Page 6
<PAGE>
The above cited Capacity rates shall be adjusted by two (2) percent per annum,
beginning with the annual adjustment date of May 1, 2009, and ending with the
annual adjustment date of May 1, 2022.
On May 1 of each year beginning with the annual adjustment date of May 1,
1991, and ending with the annual adjustment date of May 1, 2022, the above cited
Energy rates shall be adjusted by one hundred twenty percent (120%) of the
change in the Consumer Price Index for All Urban Consumers during the preceding
year; the base index shall be the index for January of 1990. The Energy rates
shall then be reduced by the amounts set forth in Table A below:
Table A
$/kWh
-----
- ------------------------------------------------------------------------
For the period beginning the November 1, 1997 until
April 30, 1998
- ------------------------------------------------------------------------
- ------------------------------------------------------------------------
For the annual Period beginning May 1 of the year:
- --------------------------------------------------
- ------------------------------------------------------------------------
1998
- ------------------------------------------------------------------------
1999
- ------------------------------------------------------------------------
2000
- ------------------------------------------------------------------------
2001
- ------------------------------------------------------------------------
2002
- ------------------------------------------------------------------------
2003
- ------------------------------------------------------------------------
2004
- ------------------------------------------------------------------------
2005
- ------------------------------------------------------------------------
2006
- ------------------------------------------------------------------------
2007
- ------------------------------------------------------------------------
2008
- ------------------------------------------------------------------------
2009
- ------------------------------------------------------------------------
2010
- ------------------------------------------------------------------------
2011
- ------------------------------------------------------------------------
2012
- ------------------------------------------------------------------------
2013
- ------------------------------------------------------------------------
2014
- ------------------------------------------------------------------------
2015
- ------------------------------------------------------------------------
2016
- ------------------------------------------------------------------------
2017
- ------------------------------------------------------------------------
2018
- ------------------------------------------------------------------------
2019
- ------------------------------------------------------------------------
2020
- ------------------------------------------------------------------------
2021
- ------------------------------------------------------------------------
2022
- ------------------------------------------------------------------------
Page 7
<PAGE>
- ------------------------------------------------------------------------
2023
- ------------------------------------------------------------------------
12. Except as expressly amended by this Amendment, the provisions of the
Contract shall remain unchanged.
13. The governing law for this Amendment shall be determined in accordance with
Section 26 of the Contract.
14. Any amendment to this Amendment shall be in accordance with Section 19 of
the Contract.
15. The non-waiver provisions of Section 21 of the Contract shall also apply to
this Amendment.
16. If any paragraph, sentence, term or provision hereof shall be held to be
invalid or unenforceable, such invalidity or unenforceability shall not
affect the validity or enforceability of any other paragraph, sentence, term
or provision of this Amendment.
17. This Amendment is the result of negotiation and each Party's respective
counsel has reviewed this Amendment. Accordingly, the normal rules of
construction to the effect that any ambiguity shall be resolved against the
drafting Party shall not be employed in the interpretation of this
Amendment.
18. This Amendment constitutes the entire agreement of the Parties with respect
to this Amendment and supersedes any and all prior negotiations,
correspondence, understandings, and agreements between the Parties
concerning the subject matter of this Amendment.
19. The Parties agree to cooperate fully and to take all additional steps which
may be necessary or appropriate to give full force and effect to the terms
and intent of this Amendment. This Amendment shall become effective on the
First Amendment Effective Date.
In the event that the First Amendment Effective Date does not occur within
270 calendar days of the execution of the First Amendment, this Amendment
shall become null and void.
IN WITNESS WHEREOF, the Parties have caused this Amendment to be executed by
their duly authorized representatives.
Page 8
<PAGE>
NEVADA COGENERATION NEVADA POWER COMPANY
ASSOCIATES #2
By: /s/ J.R. Gilmer By: /s/ Steven W. Rigazio
-------------------------------- ---------------------------------
J.R. Gilmer Steven W. Rigazio
Executive Director Vice President, Finance & Planning
Treasurer and Chief Financial Officer
Date: May 1, 1998 Date: _______________________________
------------------------------
Page 9
<PAGE>
EXHIBIT 1A
RELEASE SCHEDULE
Nevada hereby Releases Seller from the obligation to have the following capacity
and energy dedicated to Nevada:
<TABLE>
<CAPTION>
Contract Excess
-------- ------
<S> <C> <C>
Released Capacity (MW): __________________________ ____________________________
Released Energy (kWh): __________________________ ____________________________
</TABLE>
Under the following terms:
Release Period (day, month,...): _______________________________________________
Release Period (hours of the day): _____________________________________________
Release Rate ($/kWh):___________________________________________________________
Recall Time (10 min, 1 hour, or as specified): _________________________________
Other terms:____________________________________________________________________
<TABLE>
<CAPTION>
NEVADA COGENERATION ASSOCIATES #2 NEVADA POWER COMPANY
<S> <C>
By: ______________________________________ By: _________________________________________
Date:_____________________________________ Date:________________________________________
</TABLE>
10
<PAGE>
EXHIBIT 1B
RELEASE SCHEDULE
Seller hereby Releases Nevada from the obligation to purchase the following:
<TABLE>
<CAPTION>
Contract
--------
<S> <C>
Released Capacity (MW): _____________________________
Released Energy (kWh): _____________________________
</TABLE>
Under the following terms:
Release Period (day, month,...): _______________________________________
Release Period (hours of the day): _____________________________________
Release Rate ($/kWh):___________________________________________________
Recall Time (10 min, 1 hour, or as specified): _________________________
Other terms: ___________________________________________________________
NEVADA COGENERATION ASSOCIATES #2 NEVADA POWER COMPANY
By: _______________________________ By: ________________________________
Date: _____________________________ Date: ______________________________
11
<PAGE>
EXHIBIT 2
PURCHASE SCHEDULE
Nevada hereby agrees to purchase from Seller and Seller agrees to sell to Nevada
the following capacity and energy:
Released Excess
-------- ------
Capacity (MW): __________________________ ____________________________
Energy (kWh): __________________________ ____________________________
Under the following terms:
Term of Purchase (day, month,...): _________________________________________
Purchase Period (hours of the day): ________________________________________
Purchase Rate ($/kWh): _____________________________________________________
WSPP Schedule: _____________________________________________________________
Other terms: _______________________________________________________________
NEVADA COGENERATION ASSOCIATES #2 NEVADA POWER COMPANY
By: _______________________________ By: _______________________________
Date:______________________________ Date:______________________________
12
<PAGE>
EXHIBIT 3
Table 1/1/
-------
Prior to Derating:
(1) Seller has the ability to deliver full 85MW Contract Capacity and
associated Energy; and
(2) 20MW released.
Result of Derating of 20MW:
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------------------
Prior to Derating Result of Derating
- ------------------------------------------------------------------------------------------------------------
<S> <C> <C>
Released Capacity and Released Energy paid for at 20MW 20MW
Release Rate/10/
- ------------------------------------------------------------------------------------------------------------
Capacity and Energy purchased at Exhibit A rates 65MW/2/ (20MW derating)
45MW/3/
- ------------------------------------------------------------------------------------------------------------
Excess Capacity and Excess Energy purchased at 0MW 0MW
negotiated rate/4,10/
- ------------------------------------------------------------------------------------------------------------
Released Capacity and Released Energy repurchased at 0MW 0MW
negotiated rate/6,10/
- ------------------------------------------------------------------------------------------------------------
Actual Output 65MW 45MW
- ------------------------------------------------------------------------------------------------------------
</TABLE>
Table 2/1/
-------
Prior to Derating:
(1) Seller has the ability to deliver full 85MW Contract Capacity and
associated Energy; and
(2) Seller has the ability to deliver 5MW of Excess Energy and Excess Capacity;
and
(3) 20MW released.
Result of Derating of 10MW:
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------------------
Prior to Derating Result of Derating
- ------------------------------------------------------------------------------------------------------------
<S> <C> <C>
Released Capacity and Released Energy paid for at 20MW 20MW
Release Rate/10/
- ------------------------------------------------------------------------------------------------------------
Capacity and Energy purchased at Exhibit A rates 65MW/2/ (5MW derating)
60MW
- ------------------------------------------------------------------------------------------------------------
Excess Capacity and Excess Energy purchased at 5MW (5MW derating)
negotiated rate/4,10/ 0MW5
- ------------------------------------------------------------------------------------------------------------
Released Capacity and Released Energy repurchased at 0MW 0MW
negotiated rate/6,10/
- ------------------------------------------------------------------------------------------------------------
Actual Output 70MW 60MW
- ------------------------------------------------------------------------------------------------------------
</TABLE>
13
<PAGE>
Table 3/1/
-------
Prior to Derating:
(1) Seller has the ability to deliver full 85MW Contract Capacity and
associated Energy; and
(2) Seller has the ability to deliver 5MW of Excess Energy and Excess Capacity;
and
(3) 20MW released; and
(4) Nevada agrees to repurchase 20MW of Released Capacity and Released Energy.
Result of Derating of 15MW:
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------------------
Prior to Derating Result of Derating
- ------------------------------------------------------------------------------------------------------------
<S> <C> <C>
Released Capacity and Released Energy paid for at 20MW 20MW
Release Rate/10/
- ------------------------------------------------------------------------------------------------------------
Capacity and Energy purchased at Exhibit A rates 65MW/2/ (10MW derating)
55MW
- ------------------------------------------------------------------------------------------------------------
Excess Capacity and Excess Energy purchased at 5MW (5MW derating)
negotiated rate/4,10/ 0MW/5/
- ------------------------------------------------------------------------------------------------------------
Released Capacity and Released Energy repurchased at 20MW 20MW
negotiated rate/6,10/
- ------------------------------------------------------------------------------------------------------------
Actual Output 90MW 75MW
- ------------------------------------------------------------------------------------------------------------
</TABLE>
Table 4/1/
-------
Prior to Derating:
(1) Seller has the ability to deliver full 85MW Contract Capacity and
associated Energy; and
(2) Seller has the ability to deliver 5MW of Excess Energy and Excess Capacity;
and
(3) 30MW released; and
(4) Nevada agrees to repurchase 30MW of Released Capacity and Released Energy.
Result of Derating of 70MW:
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------------------
Prior to Derating Result of Derating
- ------------------------------------------------------------------------------------------------------------
<S> <C> <C>
Released Capacity and Released Energy paid for at 30MW (10MW derating)
Release Rate/10/ 20MW8
- ------------------------------------------------------------------------------------------------------------
Capacity and Energy purchased at Exhibit A rates 55MW/2/ (55MW derating)
0MW/6/
- ------------------------------------------------------------------------------------------------------------
Excess Capacity and Excess Energy purchased at 5MW (5MW derating)
negotiated rate/4,10/ 0MW/5/
- ------------------------------------------------------------------------------------------------------------
Released Capacity and Released Energy repurchased at 30MW 20MW/9/
negotiated rate/6, 10/
- ------------------------------------------------------------------------------------------------------------
Actual Output 90MW 20MW
- ------------------------------------------------------------------------------------------------------------
</TABLE>
14
<PAGE>
Footnotes:
/1)/ In order to simplify the example, amounts are shown in MW. Payments would
be in MWH for the MW's delivered over the duration of the conditions specified.
/2)/ Amount of Capacity and Energy purchased at Exhibit A rates is reduced by
the amount of Released Capacity and Released Energy. Thus:
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------
Amount of Capacity and = Contract Capacity and - Released Capacity and
Energy purchased at Energy Delivered Released Energy
Exhibit A rates.
- --------------------------------------------------------------------------------
<S> <C> <C>
Table 1-3 65MW = 85MW - 20MW
- --------------------------------------------------------------------------------
Table 4 55MW = 85MW - 30MW
- --------------------------------------------------------------------------------
</TABLE>
/3)/ The amount of Capacity and Energy purchased at Exhibit A rates is reduced
by the amount of Released Capacity and Released Energy and the Derate Amount.
Thus:
<TABLE>
<CAPTION>
Amount of Capacity and = Contract Capacity - Derate - Released Capacity and
Energy purchased at and Energy Delivered Amount Released Energy
Exhibit A rates.
- ----------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
45MW = 85MW - 20MW - 20MW
- ----------------------------------------------------------------------------------------------------------------
</TABLE>
/4)/ Though the party purchasing the Excess Capacity and Excess Energy is not
material to the result shown, for simplicity, these examples assume that Nevada
is purchasing the specified amount of Excess Capacity and Excess Energy.
/5)/ Excess is reduced to zero first because there is no output in excess of
Contract Capacity, in accordance with the definition of Excess (amount of output
in excess of Contract Capacity).
/6)/ Though the party purchasing the Released Capacity and Released Energy is
not material to the result shown, for simplicity, these examples assume that
Nevada is purchasing the specified amount of Released Capacity and Released
Energy.
/7)/ The amount of Capacity and Energy purchased at Exhibit A rates is reduced
to zero because Seller is unable to deliver capacity and energy over the amount
of the Released Capacity and Released Energy. Any remaining Derate Amount is
deducted from the Released Amount and any Release repurchase.
/8)/ The amount of Released Capacity and Released Energy to be paid for by
Nevada is reduced because of Seller's inability to deliver the full Released
Amount in accordance with Section 4A.2.
/9)/ The amount of the repurchased Released Capacity and Released Energy is
limited by the Seller's ability to deliver.
/10)/ If more than one schedule is in effect at the time of Derating then the
weighted average of the rates, for the applicable type of schedule, prior to
Derating shall be applied to the result of Derating. Weighted average shall be
determined as the [sum of (kWh amount multiplied by rate) divided by total kWh
amount] for the applicable type of schedule.
15
<PAGE>
NEVADA POWER EXHIBIT 10.87
10-K
RESTATED FIRST AMENDMENT TO POWER PURCHASE AGREEMENT
This Restated First Amendment to Power Purchase Agreement (this "Amendment") is
made and entered into this 30 day of April, 1998 by and between Nevada
Cogeneration Associates #1, a Utah general partnership ("Seller") and Nevada
Power Company, a Nevada corporation ("Nevada"). Seller and Nevada are sometimes
referred to herein collectively as the "Parties" and individually as a "Party".
RECITALS
A. Bonneville Nevada Corporation ("Bonneville") and Nevada executed that certain
Bonneville Nevada Contract A with Nevada Power Company for Long Term Power
Purchases from Qualifying Facilities (the "Contract") dated May 2, 1989 which
was assigned to Seller effective as of January 29, 1991.
B. Seller and Nevada executed that certain First Amendment to Power Purchase
Agreement dated October 3, 1997 (the "First Amendment") under the following
basis:
i. Seller and Nevada have had a continuing dispute concerning the second
paragraph of Section 4.6.3 of the Contract and the right thereunder of
Nevada to curtail potential purchases of capacity and energy from
Seller's Generating Facility.
ii. Seller and Nevada wish to resolve their dispute and to make other
changes to the Contract which will provide greater operating flexibility
for Nevada and create mutually beneficial opportunities for Seller,
Nevada, and Nevada's customers in connection with the purchase and sale
of energy and capacity from Seller's Generating Facility.
iii. To effect such resolution and changes, the Parties wish:
a. To amend Section 4.6.3 of the Contract.
b. To revise the payment provisions set forth in the Contract.
c. To provide a mechanism by which Nevada, upon mutual agreement of the
Parties (reached at each Party's sole discretion), may reduce its
take of the output from Seller's Generating Facility that would
otherwise be delivered by Seller to Nevada under the Contract.
d. To provide a mechanism by which Seller, upon mutual agreement of the
Parties (reached at each Party's sole discretion), may sell to other
parties the capacity or energy from Seller's Generating Facility that
would otherwise be dedicated by Seller to Nevada under the Contract.
e. To allow payment for Excess Energy and Excess Capacity by Nevada to
Seller on the basis of a negotiated market rate rather than Nevada's
Tariff Schedule QF-Short Term Energy and Capacity rates.
Page 1
<PAGE>
C. Pursuant to Section 20 of the First Amendment, Nevada filed a Petition with
the Public Utilities Commission of Nevada ("Commission") seeking approval of
the First Amendment as executed and approval of a regulatory accounting
treatment with respect to the First Amendment, assigned Docket No. 97-11004.
D. The Parties to Docket No. 97-11004 have filed a stipulation to amend the
First Amendment and describe a regulatory accounting treatment acceptable to
Nevada. The Parties have asked the Commission to approve such stipulation.
E. The Parties entered into an Agreement to Extend Cancellation Date of First
Amendment to Power Purchase dated March 26, 1998, for 90 days to allow time
for approval of the stipulation.
F. The terms of the First Amendment must be revised pursuant to the terms of the
stipulation.
NOW, THEREFORE, in consideration of the mutual promises and obligations
stated herein and the mutual benefits to be derived therefrom, Seller and Nevada
hereby agree to this Restated First Amendment to the Contract as follows:
1. This Amendment shall amend and supersede the First Amendment and any
amendments thereto in their entirety.
2. Section 1.8.3 of the Contract is hereby amended to read as follows:
Nevada shall, in accordance with a Purchase Schedule, purchase and pay Seller
for Excess Capacity and Released Capacity made available to Nevada by Seller
only under rates, terms and conditions which are mutually agreed to by Nevada
and Seller.
3. Section 1.9.3 of the Contract is hereby amended to read as follows:
Nevada shall, in accordance with a Purchase Schedule, purchase and pay Seller
for Excess Energy and Released Energy delivered to Nevada by Seller only
under rates, terms and conditions which are mutually agreed to by Nevada and
Seller.
4. All capitalized terms shall have the meaning stated in Section 2 of the
Agreement, except as expressly amended by this Amendment.
5. The following definitions are hereby added to Section 2 of the Contract:
5.1. Derate Amount: The Contract Capacity and associated Energy less the
-------------------
amount of capacity and energy Seller is able to produce and deliver to
Nevada during any time that Seller experiences a Derating.
Page 2
<PAGE>
5.2. Derating: The Seller's inability to deliver the full Contract
--------------
Capacity and associated Energy due to a physical partial or complete
outage of either Seller's Generating Facility or the associated
transmission line.
5.3. First Amendment Effective Date: The date the Commission issues an
------------------------------------
order approving the First Amendment as amended by this Amendment.
5.4. Purchase Schedule: A document setting forth the mutual agreement of
-----------------------
the Parties regarding the sale by Seller and the purchase by Nevada of
Excess Energy, Excess Capacity, Released Energy, and/or Released
Capacity. The Purchase Schedule shall be substantially in the form
attached hereto as Exhibit 2. The Purchase Schedule may be changed upon
the express consent of the Parties.
5.5. Recall Time: The period of time within which Seller must become
-----------------
capable of delivering Released Energy to Nevada following the
request of Nevada.
5.6. Release: Release, in accordance with the terms of a mutually agreed
-------------
upon Release Schedule, of a Party's obligation to purchase, dedicate,
or sell capacity and energy in accordance with Section 4A hereunder,
that would otherwise be dedicated and/or delivered by Seller to Nevada
under the Contract.
5.7. Release Period: That period or those periods of time during which
--------------------
Release will occur.
5.8. Release Rate: The payment rate for the Release.
------------------
5.9. Release Schedule: A document setting forth the mutual agreement of
----------------------
the Parties regarding the Release Period, the Released Energy and
Released Capacity, the Release Rate, Recall Time, an other terms and
conditions pertaining thereto. The Release Schedule shall be
substantially in the form attached hereto as Exhibit 1A or Exhibit 1B,
as applicable. The Release Schedule may be changed upon the express
consent of the Parties.
5.10. Released Capacity: The amount of capacity, associated with Released
-----------------------
Energy, that is Released.
5.11. Released Energy: The amount of energy that is Released.
---------------------
6. The following sections of the Contract shall be amended to read as
follows:
6.1. Section 2.11 - Excess Capacity: Capacity in excess of Contract
---------------
Capacity or as designated by the Parties during a Release Period in
accordance with a Purchase Schedule. The amount of Excess Capacity
shall be determined on a kWh basis hour by hour.
Page 3
<PAGE>
6.2. Section 2.12 - Excess Energy: Energy associated with Capacity in
-------------
excess of Contract Capacity or as designated by the Parties during a
Release Period in accordance with a Purchase Schedule. The amount of
Excess Energy shall be determined on a kWh basis hour by hour.
7. Section 4.6.3 of the Contract is hereby amended to read as follows:
The Parties agree that the provisions of 18 C.F.R. Sec. 292.304(f)
pertaining to curtailment and reduction of output from qualifying
facilities shall not apply to Seller's Generating Facility or the
obligations of Seller and Nevada under this Contract.
Nevada shall have the right to require Seller to reduce the output of
Seller's Generating Facility or to isolate any of Seller's Facilities from
Nevada's electric system if, in Nevada's reasonable judgment, such actions
are required to facilitate the maintenance of any of Nevada's facilities
or to maintain Nevada's Electric System Integrity. Nevada shall, within a
reasonable period of time and to the extent possible, endeavor to correct
the condition that necessitated the reduction or isolation. The duration
of such reduction or isolation shall be limited to the period of time that
the condition existed plus a reasonable period of time for the restoration
of Nevada's electric system to an operating condition that allows Nevada
to resume the discharge of its obligations in accordance with the
provisions of this Contract.
If Nevada has required Seller to reduce the output of Seller's Generating
Facility or to isolate any of Seller's Facilities from Nevada's electric
system, Seller shall neither increase the output nor reconnect the
isolated facilities without the prior approval of Nevada's Operating
Representative. Provisions for obtaining such approval have been set forth
in Exhibit C.
8. A new Section 4A, "Release", is hereby added to the Contract to read as
follows:
4A.1 Nevada may request of Seller, and Seller may permit Nevada, at
Seller's sole discretion, to be Released of its obligation to
purchase all of the Contract Capacity and associated Energy output
of Seller's Generating Facility for any reason pursuant to the terms
and conditions of a Release Schedule.
Seller may request of Nevada, and Nevada may permit Seller, at
Nevada's sole discretion, to be Released of its obligation to
dedicate all of the capacity and associated energy output of
Seller's Generating Facility to Nevada for any reason pursuant to
the terms and conditions of a Release Schedule.
Neither Seller nor Nevada is under an obligation to accept a Release
Schedule proposed by the other Party.
Page 4
<PAGE>
4A.2 If Nevada is Released, Nevada shall pay Seller for the Release at
the Release Rate set forth in the applicable Release Schedule. If
Nevada is Released, payment for the Release shall be due only to the
extent that the Seller's Generating Facility is able to produce the
Released Energy and such Released Energy could be delivered to
Nevada within the stated Recall Time. The ability of Seller's
Generating Facility to produce and the availability for delivery of
such Released Energy to Nevada shall be subject to reasonable review
and verification by Nevada. Seller shall not take a Scheduled Outage
during any Release Period.
If Seller is Released, Seller shall pay Nevada for the Release at
the Release Rate set forth in the applicable Release Schedule.
Payment shall be made on a per kWh basis, unless otherwise agreed by
the Parties, as if the Released Energy had been delivered.
4A.3 If, for any reason during any Release Period, Seller experiences a
Derating, then, for the duration of the Derating within the Release
Period, Seller shall not deliver to Nevada capacity and energy in
excess of Contract Capacity and associated Energy less Released
Capacity and Released Energy less the Derate Amount. Examples of
payments during a Derating, should it occur during a Release Period,
in accordance with the Contract and the appropriate Release
Schedule, are given in Exhibit 3.
4A.4. Except as specifically provided in this Section 4A, payment for
Release hereunder shall be made in the same manner and under the
same conditions set forth in Section 13 hereof.
9. Section 10.1.1 of the Contract is hereby amended to read as follows:
Summer Season: For the purposes of this section, a summer season shall
-------------
include May, June, July, August, and September. During a summer season,
total Energy produced and delivered to Nevada during the On-peak hours of
that season must meet or exceed the product of (Contract Capacity
multiplied by the number of On-peak hours during that season less the
total Released Energy during that season's On-peak hours) and 90%.
10. Section 10.1.2 of the Contract is hereby amended to read as follows:
Winter Season: For the purposes of this section, a winter season shall
-------------
include the months of December, January, and February. During a winter
season, total Energy produced and delivered to Nevada during the On-peak
hours of that season must meet or exceed the product of (Contract Capacity
multiplied by the number of On-peak hours during that season less the
total Released Energy during that season's On-peak hours) and 90%.
Page 5
<PAGE>
11. Exhibit A of the Contract, entitled "Power Purchase Contract Payment
Provisions", shall be replaced in its entirety with the following:
Exhibit A
Power Purchase Contract
Payment Provisions
For the purposes of this exhibit, a summer season shall include the months
of May, June, July, August, and September. The associated On-Peak hours shall
be the twelve (12) hours from 10:00 am to 10:00 p.m. during each day of the
summer period; all other hours shall be Off-Peak hours.
For the purposes of this exhibit, a winter season shall include the months
of January, February, March, April, October, November, and December. The
associated On-Peak hours shall be the five (5) hours from 5:00 am to 10:00 am
and the eight (8) hours from 4:00 p.m. to midnight during each day of the winter
period; all other hours shall be Off-Peak hours.
Maintenance months shall include the months of March, April, October, and
November.
Except as otherwise provided, the rates ($/kWh) applicable to this
Contract shall be:
<TABLE>
<CAPTION>
Summer Summer Winter Winter
On-Peak Off-Peak On-Peak Off-Peak
<S> <C> <C> <C> <C>
Capacity 0.05430 0.02084 0.03180 0.02084
Energy 0.02070 0.02070 0.02070 0.02070
------ ------- ------- ------- -------
Total 0.07500 0.04154 0.05250 0.04154
</TABLE>
The above cited rates shall be effective from January 1, 1990 through April
30, 1991.
The above cited Capacity rates shall be adjusted annually, on May 1 of each
year beginning with the annual adjustment date of May 1, 1991 and ending with
the annual adjustment date of May 1, 2022, by two (2) percent per annum.
The above cited Energy rates shall be adjusted annually, on May 1 of each
year beginning with the annual adjustment date of May 1, 1991 and ending with
the annual adjustment date of May 1, 2022, by one hundred twenty percent (120%)
of the change in the Consumer Price Index for All Urban Consumers experienced
during the preceding year; the base index shall be the index for
Page 6
<PAGE>
January of 1990. The Energy Rate shall then be reduced by the amounts set forth
in Table A below:
Table A
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------
$/kWh
-----
- ------------------------------------------------------------------------
<S> <C>
For the period beginning the November 1, 1997 until April 30,
1998
- ------------------------------------------------------------------------
- ------------------------------------------------------------------------
For the annual Period beginning May 1 of the year:
- --------------------------------------------------
- ------------------------------------------------------------------------
1998
- ------------------------------------------------------------------------
1999
- ------------------------------------------------------------------------
2000
- ------------------------------------------------------------------------
2001
- ------------------------------------------------------------------------
2002
- ------------------------------------------------------------------------
2003
- ------------------------------------------------------------------------
2004
- ------------------------------------------------------------------------
2005
- ------------------------------------------------------------------------
2006
- ------------------------------------------------------------------------
2007
- ------------------------------------------------------------------------
2008
- ------------------------------------------------------------------------
2009
- ------------------------------------------------------------------------
2010
- ------------------------------------------------------------------------
2011
- ------------------------------------------------------------------------
2012
- ------------------------------------------------------------------------
2013
- ------------------------------------------------------------------------
2014
- ------------------------------------------------------------------------
2015
- ------------------------------------------------------------------------
2016
- ------------------------------------------------------------------------
2017
- ------------------------------------------------------------------------
2018
- ------------------------------------------------------------------------
2019
- ------------------------------------------------------------------------
2020
- ------------------------------------------------------------------------
2021
- ------------------------------------------------------------------------
2022
- ------------------------------------------------------------------------
2023
- ------------------------------------------------------------------------
</TABLE>
Except as expressly amended by this Amendment, the provisions of the Contract
shall remain unchanged.
13. The governing law for this Amendment shall be determined in accordance with
Section 25 of the Contract.
Page 7
<PAGE>
14. Any amendment to this Amendment shall be in accordance with Section 19 of
the Contract.
15. The non-waiver provisions of Section 21 of the Contract shall also apply to
this Amendment.
16. If any paragraph, sentence, term or provision hereof shall be held to be
invalid or unenforceable, such invalidity or unenforceability shall not
affect the validity or enforceability of any other paragraph, sentence, term
or provision of this Amendment.
17. This Amendment is the result of negotiation and each Party and each Party's
respective counsel has reviewed this Amendment. Accordingly, the normal
rules of construction to the effect that any ambiguity shall be resolved
against the drafting Party shall not be employed in the interpretation of
this Amendment.
18. This Amendment constitutes the entire agreement of the Parties with respect
to this Amendment and supersedes any and all prior negotiations,
correspondence, understandings, and agreements between the Parties
concerning the subject matter of this Amendment.
19. The Parties agree to cooperate fully and to take all additional steps which
may be necessary or appropriate to give full force and effect to the terms
and intent of this Amendment. This Amendment shall become effective on the
First Amendment Effective Date.
In the event that the First Amendment Effective Date does not occur within
270 calendar days of the execution of the First Amendment, this Amendment
shall become null and void.
IN WITNESS WHEREOF, the Parties have caused this Amendment to be executed by
their duly authorized representatives.
NEVADA COGENERATION NEVADA POWER COMPANY
ASSOCIATES #2
By: /s/ J.R. Gilmer By: /s/ Steven W. Rigazio
------------------------- ----------------------------
J.R. Gilmer Steven W. Rigazio
Executive Director Vice President, Finance
& Planning, Treasurer
and Chief Financial Officer
Date: May 1, 1998 Date:
------------------------ ---------------------------
Page 8
<PAGE>
EXHIBIT 1A
RELEASE SCHEDULE
Nevada hereby Releases Seller from the obligation to have the following capacity
and energy dedicated to Nevada:
Contract Excess
-------- ------
Released Capacity (MW):
------------------ ----------------
Released Energy (kWh):
------------------ ----------------
Under the following terms:)
------------------------------------------
Release Period (day, month,...):
-------------------------------------
Release Period (hours of the day):
-----------------------------------
Release Rate ($/kWh):
------------------------------------------------
Recall Time (10 min, 1 hour, or as specified):
-----------------------
Other terms:
---------------------------------------------------------
NEVADA COGENERATION NEVADA POWER COMPANY
ASSOCIATES #1
By: By:
------------------------------- ----------------------------
Date: Date:
------------------------------ --------------------------
Page 9
<PAGE>
EXHIBIT 1B
RELEASE SCHEDULE
Seller hereby Releases Nevada from the obligation to purchase the following:
Contract
--------
Released Capacity (MW):
------------------
Released Energy (kWh):
------------------
Under the following terms:
Release Period (day, month,...):
-----------------------------------
Release Period (hours of the day):
---------------------------------
Release Rate ($/kWh):
----------------------------------------------
Recall Time (10 min, 1 hour, or as specified):
---------------------
Other terms:
-------------------------------------------------------
NEVADA COGENERATION NEVADA POWER COMPANY
ASSOCIATES #1
By: By:
--------------------------- ----------------------
Date: Date:
--------------------------- ----------------------
Page 10
<PAGE>
EXHIBIT 2
PURCHASE SCHEDULE
Nevada hereby agrees to purchase from Seller and Seller agrees to sell to Nevada
the following capacity and energy:
Released Excess
-------- ------
Capacity (MW):
-------------- -------------
Energy (kWh):
-------------- -------------
Under the following terms:
Term of Purchase (day, month,...):
------------------------------
Purchase Period (hours of the day):
-----------------------------
Purchase Rate ($/kWh):
------------------------------------------
WSPP Schedule:
--------------------------------------------------
Other terms:
----------------------------------------------------
NEVADA COGENERATION NEVADA POWER COMPANY
ASSOCIATES #1
By: By:
------------------------- ----------------------
Date: Date:
----------------------- -------------------
Page 11
<PAGE>
EXHIBIT 3
Table 1/1/
-------
Prior to Derating:
(1) Seller has the ability to deliver full 85MW Contract Capacity and
associated Energy; and
(2) 20MW released.
Result of Derating of 20MW:
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------------------
Prior to Derating Result of Derating
- ------------------------------------------------------------------------------------------------------------
<S> <C> <C>
Released Capacity and Released Energy paid for at 20MW 20MW
Release Rate/10/
- ------------------------------------------------------------------------------------------------------------
Capacity and Energy purchased at Exhibit A rates 65MW/2/ (20MW derating)
45MW/3/
- ------------------------------------------------------------------------------------------------------------
Excess Capacity and Excess Energy purchased at 0MW 0MW
negotiated rate/4/,/10/
- ------------------------------------------------------------------------------------------------------------
Released Capacity and Released Energy repurchased at 0MW 0MW
negotiated rate/6/,/10/
- ------------------------------------------------------------------------------------------------------------
Actual Output 65MW 45MW
- ------------------------------------------------------------------------------------------------------------
</TABLE>
Table 2/1/
-------
Prior to Derating:
(1) Seller has the ability to deliver full 85MW Contract Capacity and associated
Energy; and
(2) Seller has the ability to deliver 5MW of Excess Energy and Excess Capacity;
and
(3) 20MW released.
Result of Derating of 10MW:
<TABLE>
<CAPTION>
Prior to Derating Result of Derating
- ------------------------------------------------------------------------------------------------------------
<S> <C> <C>
Released Capacity and Released Energy paid for at 20MW 20MW
Release Rate/10/
- ------------------------------------------------------------------------------------------------------------
Capacity and Energy purchased at Exhibit A rates 65MW2 (5MW derating)
60MW
- ------------------------------------------------------------------------------------------------------------
Excess Capacity and Excess Energy purchased at 5MW (5MW derating)
negotiated rate/4/,/10/ 0MW/5/
- ------------------------------------------------------------------------------------------------------------
Released Capacity and Released Energy repurchased at 0MW 0MW
negotiated rate/6/,/10/
- ------------------------------------------------------------------------------------------------------------
Actual Output 70MW 60MW
- ------------------------------------------------------------------------------------------------------------
</TABLE>
Page 12
<PAGE>
Table 3/1/
-------
Prior to Derating:
(1) Seller has the ability to deliver full 85MW Contract Capacity and associated
Energy; and
(2) Seller has the ability to deliver 5MW of Excess Energy and Excess Capacity;
and
(3) 20MW released; and
(4) Nevada agrees to repurchase 20MW of Released Capacity and Released Energy.
Result of Derating of 15MW:
<TABLE>
<CAPTION>
Prior to Derating Result of Derating
- ------------------------------------------------------------------------------------------------------------
<S> <C> <C>
Released Capacity and Released Energy paid for at 20MW 20MW
Release Rate/10/
- ------------------------------------------------------------------------------------------------------------
Capacity and Energy purchased at Exhibit A rates 65MW2 (10MW derating)
55MW
- ------------------------------------------------------------------------------------------------------------
Excess Capacity and Excess Energy purchased at 5MW (5MW derating)
negotiated rate/4/,/10/ 0MW/5/
- ------------------------------------------------------------------------------------------------------------
Released Capacity and Released Energy repurchased at 20MW 20MW
negotiated rate/6/,/10/
- ------------------------------------------------------------------------------------------------------------
Actual Output 90MW 75MW
- ------------------------------------------------------------------------------------------------------------
</TABLE>
Table 4/1/
-------
Prior to Derating:
(1) Seller has the ability to deliver full 85MW Contract Capacity and associated
Energy; and
(2) Seller has the ability to deliver 5MW of Excess Energy and Excess Capacity;
and
(3) 30MW released; and
(4) Nevada agrees to repurchase 30MW of Released Capacity and Released Energy.
Result of Derating of 70MW:
<TABLE>
<CAPTION>
Prior to Derating Result of Derating
- ------------------------------------------------------------------------------------------------------------
<S> <C> <C>
Released Capacity and Released Energy paid for at 30MW (10MW derating)
Release Rate/10/ 20MW/8/
- ------------------------------------------------------------------------------------------------------------
Capacity and Energy purchased at Exhibit A rates 55MW/2/ (55MW derating)
0MW/6/
- ------------------------------------------------------------------------------------------------------------
Excess Capacity and Excess Energy purchased at 5MW (5MW derating)
negotiated rate/4/,/10/ 0MW/5/
- ------------------------------------------------------------------------------------------------------------
Released Capacity and Released Energy repurchased at 30MW 20MW/9/
negotiated rate/6/, /10/
- ------------------------------------------------------------------------------------------------------------
Actual Output 90MW 20MW
- ------------------------------------------------------------------------------------------------------------
</TABLE>
Page 13
<PAGE>
Footnotes:
1) In order to simplify the example, amounts are shown in MW. Payments would be
in MWH for the MW's delivered over the duration of the conditions specified.
2) Amount of Capacity and Energy purchased at Exhibit A rates is reduced by the
amount of Released Capacity and Released Energy. Thus:
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
Amount of Capacity and Energy = Contract Capacity and Energy - Released Capacity and Released
purchased at Exhibit A rates. Delivered Energy
- --------------------------------------------------------------------------------------------------------------------
Table 1-3 65MW = 85MW - 20MW
- --------------------------------------------------------------------------------------------------------------------
Table 4 55MW = 85MW - 30MW
- --------------------------------------------------------------------------------------------------------------------
</TABLE>
3) The amount of Capacity and Energy purchased at Exhibit A rates is reduced by
the amount of Released Capacity and Released Energy and the Derate Amount.
Thus:
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Amount of Capacity and = Contract Capacity and - Derate - Released Capacity and Released
Energy purchased at Energy Delivered Amount Energy
Exhibit A rates.
- -----------------------------------------------------------------------------------------------------------------------
45MW = 85MW - 20MW - 20MW
- -----------------------------------------------------------------------------------------------------------------------
</TABLE>
4) Though the party purchasing the Excess Capacity and Excess Energy is not
material to the result shown, for simplicity, these examples assume that Nevada
is purchasing the specified amount of Excess Capacity and Excess Energy.
5) Excess is reduced to zero first because there is no output in excess of
Contract Capacity, in accordance with the definition of Excess (amount of output
in excess of Contract Capacity).
6) Though the party purchasing the Released Capacity and Released Energy is not
material to the result shown, for simplicity, these examples assume that Nevada
is purchasing the specified amount of Released Capacity and Released Energy.
7) The amount of Capacity and Energy purchased at Exhibit A rates is reduced to
zero because Seller is unable to deliver capacity and energy over the amount of
the Released Capacity and Released Energy. Any remaining Derate Amount is
deducted from the Released Amount and any Release repurchase.
8) The amount of Released Capacity and Released Energy to be paid for by Nevada
is reduced because of Seller's inability to deliver the full Released Amount in
accordance with Section 4A.2.
9) The amount of the repurchased Released Capacity and Released Energy is
limited by the Seller's ability to deliver.
10) If more than one schedule is in effect at the time of Derating then the
weighted average of the rates, for the applicable type of schedule, prior to
Derating shall be applied to the result of Derating. Weighted average shall be
determined as the [sum of (kWh amount multiplied by rate) divided by total kWh
amount] for the applicable type of schedule.
Page 14
<PAGE>
EXHIBIT 12
EXHIBIT 12
NEVADA POWER COMPANY
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
AND PREFERRED STOCK DIVIDENDS
<TABLE>
<CAPTION>
1994 1995 1996 1997 1998
-------- -------- -------- -------- -------
<S> <C> <C> <C> <C> <C>
Fixed Charges:
Interest:
Long-Term Debt $ 56,537 $ 59,900 $ 60,964 $ 70,267 $ 79,787
Other Interest 2,572 1,566 2,584 1,531 6,018
One-third Rentals 1,203 807 961 982 1,132
-------- -------- -------- -------- --------
Total Fixed
Charges 60,312 62,273 64,509 72,780 86,937
-------- -------- -------- -------- --------
Preferred Dividends
Requirements 3,976 3,966 3,956 1,125 174
Ratio of Income Before
Tax to Net Income 1.55 1.49 1.54 1.54 1.54
-------- -------- -------- -------- --------
Total 6,163 5,909 6,092 1,732 268
-------- -------- -------- -------- --------
Total Fixed Charges
and Preferred
Dividends $ 66,475 $ 68,182 $ 70,601 $ 74,512 $ 87,205
======== ======== ======== ======== ========
Earnings:
Net Income (before
preferred dividend
requirements) $ 81,870 $ 76,971 $ 78,868 $ 83,216 $ 83,673
Add:
Fixed Charges
(from above) 60,312 62,273 64,509 72,780 86,937
Taxes on Income 44,716 37,791 42,884 45,225 45,471
-------- -------- -------- -------- --------
Total Earnings for
Purpose of Ratio $186,898 $177,035 $186,261 $201,221 $216,081
======== ======== ======== ======== ========
Ratio of Earnings
to Fixed Charges and
Preferred Dividends 2.81 2.60 2.64 2.70 2.48
======== ======== ======== ======== ========
</TABLE>
<PAGE>
MANAGEMENT'S DISCUSSION & ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
- -------------------------------------------------------------------------------
| RESULTS OF OPERATIONS
- -------------------------------------------------------------------------------
GENERAL
In 1998, earnings per share decreased as compared to 1997, due to increased
average shares of common stock outstanding. Earnings for 1998 increased as
compared to 1997 due to higher kilowatthour sales from customer growth.
In 1997, earnings increased, as compared to 1996, due primarily to the $5.5
million, net of tax, write-off recorded in the fourth quarter of 1996 resulting
from the Public Utilities Commission of Nevada (PUCN) (previously the Public
Service Commission of Nevada) order in the 1995 deferred energy case.
Average shares of common stock outstanding for 1998 increased by 1.3
million shares compared to 1997 and by 1.7 million shares for 1997 compared to
1996, as a result of the sale of shares through the Stock Purchase and Dividend
Reinvestment Plan (SPP). Beginning in the third quarter of 1998, the Company
began using open market purchases of its common stock to meet the requirements
of the SPP.
REVENUES
Revenues during 1998, 1997 and 1996 were $874 million, $799 million and
$805 million, respectively.
The 9.3 percent increase in 1998 as compared to 1997 was primarily a result
of an energy rate increase effective February 1, 1998 and higher kilowatthour
sales.
The .8 percent decrease in 1997 as compared to 1996 was primarily a result
of an energy rate decrease effective February 1, 1997.
INCREASE (DECREASE) IN REVENUE FROM PRIOR YEAR
<TABLE>
<CAPTION>
Nature of Increase (Decrease) (In millions) 1998 1997 1996
- -----------------------------------------------------------------------------
<S> <C> <C> <C>
Kilowatthour sales $36.4 $ 44.1 $ 86.2
General rate changes - 111.7 -
Deferred energy adjustments 30.0 (25.8) (27.1)
Fuel cost base rate changes - (137.3) (4.5)
Other 8.1 1.1 .8
- -----------------------------------------------------------------------------
Total increase (decrease) $74.5 $ (6.2) $ 55.4
=============================================================================
</TABLE>
FUEL AND PURCHASED POWER
Fuel expense increased $10.8 million in 1998, as compared with 1997,
primarily due to increased generation.
In 1998, as compared to 1997, purchased power expense increased 2.2 percent
due to higher average purchased power prices.
Fuel expense increased $26.6 million in 1997, as compared with 1996,
primarily due to higher average fuel prices and increased generation.
In 1997, as compared to 1996, purchased power expense increased 5.1 percent
due to higher average purchased power prices.
Effective February 1, 1998 the PUCN granted Nevada Power Company (Company)
an energy rate increase of $45.6 million. Effective February 1, 1997, the PUCN
granted the Company a decrease of $45.0 million in energy rates.
In 1998, the Company deferred $27.0 million of increased energy costs for
collection in a later period and refunded $2.7 million of energy cost decreases
which had been previously deferred. In 1997, the Company deferred $27.8 million
of increased energy costs for collection in a later period and refunded $32.6
million of energy cost decreases which had been previously deferred. In 1996,
the Company deferred $14.5 million of decreased energy costs for refund in a
later period and refunded $5.7 million of energy cost decreases which had been
previously deferred. Recovery of fuel expenses is administered under the state's
deferred energy cost accounting procedures. (See Note 1 of "Notes to
Consolidated Financial Statements.") Under the deferred energy procedure,
changes in the costs of fuel and purchased power are reflected in customer rates
through annual rate adjustments and do not affect earnings.
<TABLE>
<CAPTION>
The following tables summarize kilowatthour data.
1998 1997 1996
- -----------------------------------------------------------------------------
<S> <C> <C> <C>
SOURCE OF KILOWATTHOURS SOLD
Company generation 56% 54% 50%
Hoover Dam hydroelectric 5 4 4
Purchased power 39 42 46
- -----------------------------------------------------------------------------
100% 100% 100%
=============================================================================
COMPANY GENERATED KILOWATTHOURS BY FUEL SOURCE
Coal 67% 67% 76%
Natural Gas 33 33 24
- -----------------------------------------------------------------------------
100% 100% 100%
=============================================================================
</TABLE>
32
- -----------------------------------------------------------------------------
NEVADA POWER COMPANY 1998 ANNUAL REPORT
<PAGE>
MANAGEMENT'S DISCUSSION & ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------
1998 1997 1996
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
FUEL COSTS PER KILOWATTHOUR
Coal 1.15 cents 1.39 cents 1.39 cents
Natural Gas 2.35 2.25 1.95
- --------------------------------------------------------------------------------
</TABLE>
OTHER OPERATING EXPENSES AND TAXES
Other operations expense increased $11.9 million in 1998 primarily due to
increased costs for outside services, computer software and maintenance,
administrative and general salaries and pension costs.
The level of maintenance and repair expenses depends primarily upon the
scheduling, magnitude and number of unit overhauls at the Company's generating
stations. In 1998, these expenses decreased by $3.0 million due primarily to
decreased maintenance expense at the Reid Gardner Generating Station. In 1997,
these expenses increased by $7.7 million due primarily to increased maintenance
expense at the Reid Gardner and Clark Generating Stations.
Depreciation expense increased $7.3 million in 1998 and $4.5 million in
1997 because of a growing electric plant asset base.
OTHER INCOME AND EXPENSES
Other miscellaneous, net expense decreased by $4.4 million in 1997 due
primarily to the $5.5 million, net of tax, write-off recorded in the fourth
quarter of 1996 resulting from the PUCN order in the 1995 deferred energy case.
INTEREST DEDUCTIONS
Interest on long-term debt increased by $6.2 million in 1998 primarily due
to the issuance in November 1997 of the new Series 1997A $52.3 million
Industrial Development Revenue Bonds (IDBs) and Series 1997B $20 million
Pollution Control Revenue Bonds (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.
Other interest expense increased by $4.5 million in 1998 primarily due to
increased short-term borrowing.
DISTRIBUTION REQUIREMENTS ON COMPANY-OBLIGATED PREFERRED SECURITIES
Distribution requirements on company-obligated preferred securities of a
subsidiary trust increased by $3.8 million due to the issuance in April 1997 of
the 8.2% Quarterly Income Preferred Securities (QUIPS) and the issuance in
October 1998 of the 7 3/4% Trust Issued Preferred Securities (see Note 7 of
"Notes to Consolidated Financial Statements").
| LIQUIDITY AND CAPITAL RESOURCES
- -------------------------------------------------------------------------------
CASH FLOWS
Overall net cash flows increased during 1998, as compared to 1997,
primarily due to more cash being provided by operating and financing activities
partially offset by more cash being used in investing activities. The increase
in cash being provided by operating activities was mainly 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 mainly due to
increased short-term borrowing.
Overall net cash flows increased during 1997, as compared to 1996, as a
result of more cash being provided by financing activities partially offset by
less cash being provided by operating activities and more cash being used in
investing activities. The energy rate decrease effective February 1, 1997 was
the primary cause of the decrease in cash being provided by operating activities
partially offset by timing differences in federal income tax payments. The
increase in cash used in investing activities was due to increased construction
expenditures. The increase in cash being provided by financing activities was a
result of the issuance of the Series A, 8.2% QUIPS by the Company's subsidiary
Trust, NVP Capital I (see Note 7 of "Consolidated Financial Statements") and the
issuance of the Series 1997B $20 million PCRBs.
MERGER
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. Further regulatory approvals are required including the Securities
and Exchange Commission (SEC), the Federal Energy Regulatory Commission (FERC)
and the Department of Justice. (See Note 2 of "Notes to Consolidated Financial
Statements.")
RESOURCE DEVELOPMENT AND CONSTRUCTION PROGRAMS
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
33
- --------------------------------------------------------------------------------
NEVADA POWER COMPANY 1998 ANNUAL REPORT
<PAGE>
MANAGEMENT'S DISCUSSION & ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
- --------------------------------------------------------------------------------
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. See the Industry Restructuring section. (Also see
Note 2 of "Notes to Consolidated Financial Statements.")
Budgeted construction expenditures for 1999 and 2000 are $245 million and
$225 million, respectively, excluding allowance for funds used during
construction.
For the next five years customer growth is estimated to average 4.6 percent
per year while demand for electricity is estimated to increase by an average of
5.2 percent per year.
In order to assemble the resource plan and budget construction expenditures
and also estimate customer growth and demand for electricity, the Company is
required to make assumptions. The assumptions include but are not limited to
economic, competitive, governmental and technological factors affecting the
Company's operations, markets, products, services and prices, and other factors.
If actual events differ from any of these assumptions, the resource plan and
predictions of future expenditures, growth and demand may change.
FINANCIAL STRATEGIES
Rapid growth continues to be forecasted for the Company's service territory
for 1999 and into the next century. As in the past, the Company will rely upon
the financial markets to provide a substantial portion of the funds to build
necessary Company-owned facilities. Customer growth averaged 6.5 percent
annually during the three years ended December 31, 1998.
During this period of continued rapid growth, the Company is committed to
maintaining shareholder value by utilizing a balanced and flexible financing
approach using low cost financing whenever possible, reducing costs and seeking
legislative and regulatory support as needed.
CAPITALIZATION
The Company may utilize internally generated cash and the proceeds from
IDBs, unsecured borrowings and preferred securities to meet capital expenditure
requirements through 2000.
NEW FINANCING CAPACITY
Under the tests required by the Company's FMBs and the terms of its
preferred stock issues, as of December 31, 1998, the Company could issue up to
$689 million of additional FMBs at an assumed interest rate of 7.5 percent and
up to $400 million of additional preferred stock at an assumed dividend of 7.5
percent.
Under the terms of the merger agreement with Sierra Pacific Resources, the
Company is limited to $350 million in additional debt financing. A portion of
the limit, $72 million, was used when the 7 3/4% Trust Issued Preferred
Securities were issued in 1998. The Company ceased issuing new common equity in
September 1998 in compliance with the merger agreement limitation on the number
of common shares outstanding. The limitation on financing expires upon
completion of the proposed merger or October 1999, whichever happens first.
On August 21, 1997, the Company received approval from the PUCN to issue
and sell up to $213 million of preferred stock, tax advantaged preferred stock
and/or common stock through public or private offerings, the Company's SPP, the
Company's 401(k) plan or any other method deemed appropriate. Approval was also
received to issue and sell $487 million of tax-exempt, taxable, tax advantaged
and/or any other type of debt the Company determines to be appropriate at the
time. The Company
34
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NEVADA POWER COMPANY 1998 ANNUAL REPORT
<PAGE>
MANAGEMENT'S DISCUSSION & ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
- -------------------------------------------------------------------------------
also received approval to secure any of the debt through the issuance and pledge
of first mortgage bonds only if it cannot, at the time of issuance, economically
and effectively issue investment grade unsecured debt. The financing approval
expires on December 31, 1999.
EARNINGS TO INTEREST AND PREFERRED DIVIDENDS COVERAGE
For the year 1998, the ratio of earnings to interest charges was 2.49 times
compared to 2.76 times in 1997. The ratio of earnings to interest charges plus
preferred dividends was 2.48 times in 1998 compared to 2.70 times in 1997.
COMMON EQUITY
Under the SPP, the Company issued $19.7 million of its common stock in
1998. Beginning in the third quarter of 1998, the Company began using open
market purchases of its common stock to meet the requirements of the SPP.(See
Note 5 of "Notes to Consolidated Financial Statements.") At year end, common
equity represented 44.2 percent of total capitalization.
CUMULATIVE QUARTERLY INCOME PREFERRED SECURITIES
In October 1998, NVP Capital III (Trust), a wholly-owned subsidiary of
the Company, issued 2,800,000 7 3/4% Cumulative Quarterly Trust Issued
Preferred Securities at $25 per security. The Company owns all the common
securities, 86,598 shares issued by the Trust for $2.2 million. The $70 million
in net proceeds to the Company were used for general corporate utility purposes
including the repayment of short-term debt. (See Note 7 of "Notes to
Consolidated Financial Statements.")
SHORT-TERM DEBT
The Company has PUCN approval for authority to issue short-term unsecured
promissory notes not to exceed $225 million with such authorization to expire on
December 31, 1999 and has a committed bank line for $125 million which expires
on November 21, 2002. The short-term financing is expected to be utilized to
fund some of the Company's construction expenditures until long-term financing
is secured. At December 31, 1998, the Company had $105 million outstanding on
this line with a weighted average interest rate of 6.8%.
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. At December 31, 1998, the Company had no balance
outstanding on this line.
LONG-TERM DEBT
On January 29, 1998, the Company remarketed at fixed rates $141.05 million
Clark County, Nevada (Nevada Power Company Project) variable rate revenue bonds
consisting of $76.75 million Series 1995A IDBs due 2030 at 5.6 percent, $44
million Series 1995C IDBs due 2030 at 5.5 percent and $20.3 million Series 1995D
PCRBs with $14 million due 2011 at 5.3 percent and $6.3 million due 2023 at 5.45
percent. On the same date, $13 million Coconino County, Arizona (Nevada Power
Company Project) Series 1995E PCRBs due 2022 were remarketed at a 5.35 percent
fixed rate. The Company also remarketed $85 million Series 1995B Clark County,
Nevada (Nevada Power Company Project) variable rate IDBs due 2030 at a 5.9
percent fixed rate on November 24, 1997.
A discussion of long-term debt maturities, including sinking fund
requirements, is contained in Note 8 of "Notes to Consolidated Financial
Statements."
REGULATION
The PUCN allows recovery of costs on an historical test year in setting
rates charged to customers for electrical service. (See Industry Restructuring
section.)
Environmental expenditures made by the Company are currently being
recovered through customer rates. A discussion of pending environmental matters
is contained in Note 10 of "Notes to Consolidated Financial Statements."
PENDING AND CONCLUDED RATE MATTERS
On January 8, 1998, the PUCN approved a $45.6 million energy rate increase
effective February 1, 1998. The Company requested the increase to recover
higher costs for natural gas and purchased power.
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. On October 6, the
PUCN approved $7.4 million of the $9.9 million increase requested in connection
with the 1997 deferred energy rate case. The effective date for $6.2 million of
the increase was November 1, 1998. The remaining $1.2 million was deferred to a
future general rate case.
35
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NEVADA POWER COMPANY 1998 ANNUAL REPORT
<PAGE>
MANAGEMENT'S DISCUSSION & ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
- -------------------------------------------------------------------------------
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. Because of the October 6 decision in the
1997 deferred energy rate case referred to in the preceding paragraph, this case
was refiled with the PUCN on January 20, 1999 and reduced to $43.6 million. On
February 25, 1999, the PUCN approved a $35.6 million energy rate increase
effective March 1, 1999. A total of $7.5 million was deferred to a future
general rate case. The Company was ordered to write-off the carrying charges
accrued on the $7.5 million.
The table below summarizes the rate adjustments that have been granted to
the Company during the past three years.
<TABLE>
<CAPTION>
SUMMARY OF RATE ADJUSTMENTS 1996 THROUGH 1998
Effective Date Nature of Increase (Decrease) Amount (In millions)
- --------------------------------------------------------------------------
<S> <C> <C>
February 1, 1997 Energy rate decrease $(45.0)
February 1, 1998 Energy rate increase 45.6
November 1, 1998 Energy rate increase 6.2
- --------------------------------------------------------------------------
</TABLE>
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. (See
Note 1 of "Notes to Consolidated Financial Statements.")
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 did not provide
the legislature with a recommendation for a new start date. 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;
(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 utility to provide billing and
customer service to its customers (i.e. alternative sellers) for any services
provided to those customers.
36
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NEVADA POWER COMPANY 1998 ANNUAL REPORT
<PAGE>
MANAGEMENT'S DISCUSSION & ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
- -------------------------------------------------------------------------------
Affiliate Transaction Rules
On December 18, 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.
Distribution Non-price Terms and Conditions
The PUCN issued an order adopting final regulations for non-price terms and
conditions of distribution services on January 7, 1999. In this order, the PUCN
delineated the roles and responsibilities of the electric distribution utility
and the alternative sellers for various processes and procedures including new
service connections, change orders, basic maintenance processes, etc.
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 sometime in the first quarter of 1999.
Compliance Plans
The Company will prepare a compliance filing showing bundled and unbundled
costs of service in April 1999. Costs will be unbundled into 26 different
categories, which are broadly characterized as potentially competitive and
noncompetitive services. Rates for unbundled noncompetitive services, mainly
distribution services, are anticipated to be submitted to the PUCN in November
1999, or 15 days after the unbundling decision is finalized. Rates for
noncompetitive services will be effective on the day retail access begins. The
rates for noncompetitive services will 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, are a restructuring issue that will be addressed in 1999. AB366
defines the legal criteria which 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 identification of applicable tax and accounting
issues.
On February 11, 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 submission of filings to recover past
costs, which will likely be 45 days after the order from the compliance filing
is issued. The Company estimates this to be 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.
The deregulation of the electric utility industry has caused a reevaluation
of current accounting guidelines for electric utilities. A discussion of this
subject is included in Note 1 of "Notes to Consolidated Financial Statements."
37
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NEVADA POWER COMPANY 1998 ANNUAL REPORT
<PAGE>
MANAGEMENT'S DISCUSSION & ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
- -------------------------------------------------------------------------------
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.
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. No
material difficulties are anticipated at that time.
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 January 1999,
approximately $1.9 million in operating expenses and approximately $612,000 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.
38
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NEVADA POWER COMPANY 1998 ANNUAL REPORT
<PAGE>
CONSOLIDATED STATEMENTS OF INCOME
- --------------------------------------------------------------------------------
(In thousands, except per share amounts)
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------
For the Years Ended December 31,
1998 1997 1996
- ----------------------------------------------------------------------------------------
<S> <C> <C> <C>
ELECTRIC REVENUES (Note 1) | $873,682 $799,148 $805,374
- ------------------------------------------------------|---------------------------------
OPERATING EXPENSES AND TAXES: |
Fuel | 149,804 138,956 112,321
Purchased and interchanged power | 283,838 277,644 264,143
Deferred energy cost adjustments, net |
(Note 1) | (29,680) (60,400) 8,817
- ------------------------------------------------------|---------------------------------
Net energy costs | 403,962 356,200 385,281
Other production operations | 21,153 21,214 17,834
Other operations | 113,499 101,597 99,266
Maintenance and repairs | 49,082 52,126 44,464
Provision for depreciation (Note 1) | 73,562 66,273 61,771
General taxes | 22,198 21,064 19,558
Federal income taxes (Notes 1 and 3) | 42,949 43,478 44,970
- ------------------------------------------------------|---------------------------------
| 726,405 661,952 673,144
- ------------------------------------------------------|---------------------------------
OPERATING INCOME | 147,277 137,196 132,230
- ------------------------------------------------------|---------------------------------
OTHER INCOME (EXPENSES): |
Allowance for other funds used |
during construction (Note 1) | 8,944 8,760 6,240
Other miscellaneous, net | (4,602) (5,741) (10,116)
- ------------------------------------------------------|---------------------------------
| 4,342 3,019 (3,876)
- ------------------------------------------------------|---------------------------------
INCOME BEFORE INTEREST DEDUCTIONS | 151,619 140,215 128,354
- ------------------------------------------------------|---------------------------------
INTEREST DEDUCTIONS: |
Interest on long-term debt | 56,995 50,791 47,792
Other interest | 6,018 1,531 2,584
Allowance for borrowed funds |
used during construction (Note 1) | (6,080) (2,579) (890)
- ------------------------------------------------------|---------------------------------
| 56,933 49,743 49,486
- ------------------------------------------------------|---------------------------------
DISTRIBUTION REQUIREMENTS ON COMPANY- |
OBLIGATED MANDATORILY REDEEMABLE PREFERRED |
SECURITIES OF SUBSIDIARY TRUSTS (Note 7) | 11,013 7,256 -
- ------------------------------------------------------|---------------------------------
NET INCOME | 83,673 83,216 78,868
DIVIDEND REQUIREMENTS ON PREFERRED STOCK | 174 1,125 3,956
- ------------------------------------------------------|---------------------------------
EARNINGS AVAILABLE FOR COMMON STOCK | $ 83,499 $ 82,091 $ 74,912
- ------------------------------------------------------|=================================
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING | 50,993 49,691 47,976
- ------------------------------------------------------|=================================
EARNINGS PER AVERAGE COMMON SHARE | $ 1.64 $ 1.65 $ 1.56
- ------------------------------------------------------|=================================
</TABLE>
See Notes to Consolidated Financial Statements.
39
- --------------------------------------------------------------------------------
NEVADA POWER COMPANY 1998 ANNUAL REPORT
<PAGE>
CONSOLIDATED BALANCE SHEETS
- ----------------------------------------------------------------------------
(In thousands)
<TABLE>
<CAPTION>
December 31, 1998 1997
- ------------------------------------------------------------------------------------
<S> <C> <C>
ASSETS |
Electrical Plant, at original cost |
(Notes 1, 8, 10 and 12): |
Production | $ 918,804 $ 900,971
Transmission | 425,632 326,917
Distribution | 1,097,583 978,144
General | 186,915 172,264
- ------------------------------------------------------|-----------------------------
| 2,628,934 2,378,296
Less accumulated depreciation | 708,791 647,208
- ------------------------------------------------------|-----------------------------
Net plant in service | 1,920,143 1,731,088
Construction work in progress | 213,365 158,029
Property under capital leases, net | 64,632 69,261
Plant held for future use | 1,746 2,331
- ------------------------------------------------------|-----------------------------
| 2,199,886 1,960,709
- ------------------------------------------------------|-----------------------------
Investments (Note 1) | 24,483 13,571
- ------------------------------------------------------|-----------------------------
Current Assets: |
Cash and cash equivalents (Note 1) | 1,770 720
Customer receivables - |
Billed | 49,516 45,776
Unbilled (Note 1) | 34,201 28,237
Reserve for doubtful accounts | (2,429) (2,291)
Other receivables | 16,010 16,415
Fuel stock, at average cost | 7,119 7,325
Materials and supplies, at average cost | 32,487 35,045
Deferred energy asset (Note 1) | 62,489 30,597
Prepayments | 7,787 6,711
- ------------------------------------------------------|-----------------------------
| 208,950 168,535
- ------------------------------------------------------|-----------------------------
Deferred Charges: |
Debt expense, being amortized | 34,932 30,461
Other (Note 11) | 139,573 166,146
- ------------------------------------------------------|-----------------------------
| 174,505 196,607
- ------------------------------------------------------|-----------------------------
TOTAL ASSETS | $2,607,824 $2,339,422
- -------------------------------------------------------=============================
</TABLE>
See Notes to Consolidated Financial Statements.
40
- ----------------------------------------------------------------------------
NEVADA POWER COMPANY 1998 ANNUAL REPORT
<PAGE>
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------
(IN THOUSANDS)
December 31, 1998 1997
- --------------------------------------------------------------------------------------
<S> | <C> <C>
CAPITALIZATION AND LIABILITIES |
Capitalization (See Consolidated Schedules of |
Capitalization and Long-Term Debt): |
|
Common shareholders' equity | $ 864,036 $ 833,623
Cumulative preferred stock with |
mandatory sinking funds | 3,265 3,463
Company-obligated mandatorily redeemable |
preferred securities | 188,872 118,872
Long-term debt | 900,227 895,439
- ------------------------------------------------------|-------------------------------
| 1,956,400 1,851,397
- ------------------------------------------------------|-------------------------------
Current Liabilities: |
Notes payable | 105,000 -
Current maturities and sinking fund |
requirements (See Consolidated Schedules |
of Capitalization and Long-Term Debt) | 50,380 19,937
Accounts payable | 83,439 64,737
Accrued taxes | - 7,543
Accrued interest | 7,829 7,284
Customers' service deposits | 14,859 15,095
Deferred taxes on deferred energy asset |
(Note 3) | 21,871 10,709
Other | 26,568 22,554
- ------------------------------------------------------|-------------------------------
| 309,946 147,859
- ------------------------------------------------------|-------------------------------
Commitments and Contingencies (Note 10) |
|
Deferred Credits and Other Liabilities: |
Deferred investment tax credits |
(Notes 1 and 3) | 28,083 29,544
Deferred taxes on income (Notes 1 and 3) | 231,610 235,846
Customers' advances for construction | 64,113 55,772
Other (Note 11) | 17,672 19,004
- ------------------------------------------------------|-------------------------------
| 341,478 340,166
- ------------------------------------------------------|-------------------------------
TOTAL CAPITALIZATION AND LIABILITIES | $2,607,824 $2,339,422
- -------------------------------------------------------===============================
</TABLE>
See Notes to Consolidated Financial Statements.
41
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NEVADA POWER COMPANY 1998 ANNUAL REPORT
<PAGE>
CONSOLIDATED SCHEDULES OF CAPITALIZATION
- --------------------------------------------------------------------------------
(Dollars in thousands)
<TABLE>
<CAPTION>
December 31, 1998 1997
- ------------------------------------------------------------------------------------------------
<S> | <C> <C> <C> <C>
COMMON SHAREHOLDERS' EQUITY (Note 6): |
Common stock, $1 par value, authorized |
70,000,000 shares; issued and |
outstanding 51,265,117 and 50,399,746 |
shares at December 31, 1998 and 1997; |
stated at |$ 54,066 $ 53,604
Premium on capital stock | 687,537 667,203
Unamortized capital stock expense | (2,986) (2,872)
Accumulated other comprehensive income | (1,395) (1,344)
Retained earnings | 126,814 117,032
- ------------------------------------------------------|-----------------------------------------
Total common shareholders' equity | 864,036 44.2% 833,623 45.0%
- ------------------------------------------------------|-----------------------------------------
CUMULATIVE PREFERRED STOCK WITH MANDATORY |
SINKING FUNDS (Note 6): |
Outstanding at December 31, 1998 and 1997: |
5.40% Series, 36,669 and 38,669 |
shares | 733 773
5.20% Series, 34,570 and 36,507 |
shares | 692 730
4.70% Series, 102,006 and 108,006 |
shares | 2,040 2,160
- ------------------------------------------------------|-----------------------------------------
| 3,465 3,663
Current sinking fund requirement | (200) (200)
- ------------------------------------------------------|-----------------------------------------
Total preferred stock | 3,265 .2 3,463 .2
- ------------------------------------------------------|-----------------------------------------
COMPANY-OBLIGATED MANDATORILY REDEEMABLE |
PREFERRED SECURITIES OF THE COMPANY'S |
SUBSIDIARY TRUST, NVP CAPITAL I, |
HOLDING SOLELY $122.6 MILLION |
PRINCIPAL AMOUNT OF 8.2% JUNIOR |
SUBORDINATED DEBENTURES OF THE |
COMPANY, DUE 2037 (Note 7) | 118,872 118,872
COMPANY-OBLIGATED MANDATORILY REDEEMABLE |
PREFERRED SECURITIES OF THE COMPANY'S |
SUBSIDIARY TRUST, NVP CAPITAL III, |
HOLDING SOLELY $72.2 MILLION |
PRINCIPAL AMOUNT OF 7 3/4% JUNIOR |
SUBORDINATED DEBENTURES OF THE |
COMPANY, DUE 2038 (Note 7) | 70,000 -
- ------------------------------------------------------|-----------------------------------------
Total preferred securities | 188,872 9.6 118,872 6.4
- ------------------------------------------------------|-----------------------------------------
LONG-TERM DEBT |
(See Consolidated Schedules of Long-Term |
Debt) | 900,227 46.0 895,439 48.4
- ------------------------------------------------------|-----------------------------------------
Total capitalization |$1,956,400 100.0% $1,851,397 100.0%
- -------------------------------------------------------=========================================
</TABLE>
See Notes to Consolidated Financial Statements.
42
- --------------------------------------------------------------------------------
NEVADA POWER COMPANY 1998 ANNUAL REPORT
<PAGE>
CONSOLIDATED SCHEDULES OF LONG-TERM DEBT
- --------------------------------------------------------------------------------
(In thousands)
<TABLE>
<CAPTION>
December 31, 1998 1997
- --------------------------------------------------------------------------------------------------------------------
<S> | <C> <C>
LONG-TERM DEBT (Notes 8, 9 and 10): |
First mortgage bonds: |
7 1/8% Series I due 1998 |$ - $ 15,000
7 5/8% Series L due 2002 | 15,000 15,000
7.80% Series T due 2009 | 15,000 15,000
6.70% Series V due 2022 | 105,000 105,000
6.60% Series W due 2019 | 39,500 39,500
7.20% Series X due 2022 | 78,000 78,000
6.93% Series Y due 1999 | 45,000 45,000
8.50% Series Z due 2023 | 45,000 45,000
7.06% Series AA due 2000 | 85,000 85,000
- -------------------------------------------------------------------------------------|------------------------------
| 427,500 442,500
|
Industrial development revenue bonds: |
7.80% due 2020 | 100,000 100,000
5.90% Series 1997A due 2032 | 52,285 52,285
5.90% Series 1995B due 2030 | 85,000 85,000
5.60% Series 1995A due 2030 | 76,750 -
5.50% Series 1995C due 2030 | 44,000 -
Variable rate - |
Series 1995A due 2030 (4.33%*) | - 76,750
Series 1995C due 2030 (4.23%*) | - 44,000
Pollution control revenue bonds: |
6 3/8% due 2036 | 20,000 20,000
5.80% Series 1997B due 2032 | 20,000 20,000
5.30% Series 1995D due 2011 | 14,000 -
5.45% Series 1995D due 2023 | 6,300 -
5.35% Series 1995E due 2022 | 13,000 -
Variable rate - |
Series 1995D due 2011 (4.19%*) | - 14,000
Series 1995D due 2023 (4.19%*) | - 6,300
Series 1995E due 2022 (4.19%*) | - 13,000
Less funds held in trust | (10) (52,948)
Other notes | 327 300
Obligations under capital leases | 91,249 93,985
- -------------------------------------------------------------------------------------|------------------------------
| 950,401 915,172
|
Debt premium and discount, being amortized | 6 4
Current maturities and sinking fund requirements | (50,180) (19,737)
- -------------------------------------------------------------------------------------|------------------------------
Total long-term debt |$900,227 $895,439
- --------------------------------------------------------------------------------------==============================
</TABLE>
* Average interest rate during 1997. See Notes to Consolidated Financial
Statements.
43
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NEVADA POWER COMPANY 1998 ANNUAL REPORT
<PAGE>
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
- --------------------------------------------------------------------------------
(In thousands)
<TABLE>
<CAPTION>
For the Years Ended December 31, 1998 1997 1996
- -------------------------------------------------------------------------------
<S> <C> <C> <C>
Net Income |$ 83,673 $83,216 $78,868
- -----------------------------------------------|-------------------------------
Minimum pension liability adjustment | (77) (1,487) 722
Tax effect | 27 521 (252)
- -----------------------------------------------|-------------------------------
Minimum pension liability adjustment, net of |
tax | (50) (966) 470
- -----------------------------------------------|-------------------------------
Comprehensive income |$ 83,623 $82,250 $79,338
- -----------------------------------------------|===============================
</TABLE>
See Notes to Consolidated Financial Statements.
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
- --------------------------------------------------------------------------------
(In thousands)
<TABLE>
<CAPTION>
For the Years Ended December 31, 1998 1997 1996
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
BALANCE AT BEGINNING OF YEAR |$117,032 $117,360 $118,860
Add - Net Income | 83,673 83,216 78,868
- -----------------------------------------------|--------------------------------
| 200,705 200,576 197,728
- -----------------------------------------------|--------------------------------
Deduct: |
Dividends paid in cash: |
Cumulative preferred stock - |
5.40%, 5.20% and 4.70% Series | 174 184 194
9.90% Series (Notes 6 and 7) | - 941 3,762
Common stock | 73,717 79,176 76,412
- -----------------------------------------------|------------------------------
| 73,891 80,301 80,368
Redemption of preferred stock |
(Notes 6 and 7) | - 3,243 -
- -----------------------------------------------|------------------------------
| 73,891 83,544 80,368
- -----------------------------------------------|------------------------------
BALANCE AT END OF YEAR |$126,814 $117,032 $117,360
- -----------------------------------------------===============================
</TABLE>
See Notes to Consolidated Financial Statements.
44
- --------------------------------------------------------------------------------
NEVADA POWER COMPANY 1998 ANNUAL REPORT
<PAGE>
- --------------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF CASH FLOWS
- --------------------------------------------------------------------------------
(In thousands)
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------
For the Years Ended December 31, 1998 1997 1996
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
|
CASH FLOWS FROM OPERATING ACTIVITIES: |
Net income |$ 83,673 $ 83,216 $ 78,868
Adjustments to reconcile net income to net |
cash provided by operating activities - |
Depreciation and amortization | 87,458 78,274 69,876
Deferred income taxes and investment |
tax credits | 23,640 21,599 5,679
Allowance for other funds used |
during construction | (8,944) (8,760) (6,240)
Changes in - |
Receivables | (9,034) (15,407) (1,754)
Fuel stock and materials and supplies| 2,764 163 2,105
Accounts payable and other current |
liabilities | 22,788 8,306 (6,257)
Deferred energy costs | (33,819) (59,543) 12,093
Accrued taxes and interest | (9,433) 2,416 (13,105)
Other assets and liabilities | (4,714) 108 13,725
- ---------------------------------------------|----------------------------------
Net cash provided by operating |
activities | 154,379 110,372 154,990
- ---------------------------------------------|----------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES: |
Construction expenditures and gross additions|(314,366) (213,550) (180,871)
Investment in subsidiaries and other | (2,780) (463) 70
- ---------------------------------------------|----------------------------------
Net cash used in investing activities|(317,146) (214,013) (180,801)
- ---------------------------------------------|----------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES: |
Issuance of capital stock | 20,746 32,473 37,395
Issuance of company-obligated mandatorily |
redeemable preferred securities | 70,000 118,872 -
Issuance of long-term debt | - 72,285 20,000
Deposit of funds held in trust | (1,884) (74,672) (22,814)
Withdrawal of funds held in trust | 54,822 74,424 47,581
Retirement of long-term debt | (19,603) (5,334) (5,418)
Retirement of preferred stock | (200) (38,200) (200)
Increase (decrease) in short-term borrowing | 105,000 - -
Cash dividends | (73,962) (81,216) (80,370)
Other financing activities | 8,898 3,185 6,674
- ---------------------------------------------|----------------------------------
Net cash provided by financing |
activities | 163,817 101,817 2,848
- ---------------------------------------------|----------------------------------
CASH AND CASH EQUIVALENTS (Note 1): |
Net increase (decrease) during the year | 1,050 (1,824) (22,963)
Beginning of year | 720 2,544 25,507
- ---------------------------------------------|----------------------------------
End of year |$ 1,770 $ 720 $ 2,544
- ---------------------------------------------|==================================
CASH PAID DURING THE YEAR FOR: |
Interest, net of amounts capitalized |$ 75,487 $ 64,692 $ 59,521
- ---------------------------------------------|==================================
Income taxes |$ 27,110 $ 19,545 $ 51,282
- ----------------------------------------------==================================
</TABLE>
See Notes to Consolidated Financial Statements.
45
- --------------------------------------------------------------------------------
NEVADA POWER COMPANY 1998 ANNUAL REPORT
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- --------------------------------------------------------------------------------
1 | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
- -------------------------------------------------------------------------------
For ratemaking and other purposes, the Company is subject to the
jurisdiction of the PUCN and the FERC. The accounting records of the Company are
maintained in accordance with the uniform system of accounts prescribed by the
FERC and adopted by the PUCN.
The Company is subject to the provisions of Statement of Financial
Accounting Standards No. 71, Accounting for the Effects of Certain Types of
Regulation, which require the Company to record certain regulatory assets and
liabilities.
CONTINUING APPLICABILITY OF FASB 71
The Company's rates are currently subject to approval by the PUCN and are
designed to recover the Company's costs of providing services to its customers.
A primary difference between a rate regulated entity and an unregulated entity
is the timing of recognizing certain assets and expenses for financial reporting
purposes. The Statement of Financial Accounting Standards No. 71, "Accounting
for the Effects of Certain Types of Regulation" (FAS 71), prescribes the method
to be used to record the financial transactions of a regulated entity. The
criteria for applying FAS 71 include the following: (i) rates are set by an
independent third party regulator, (ii) approved rates are intended to recover
the specific costs of the regulated products or services and (iii) rates are set
at levels that will recover costs, can be charged to and collected from
customers. If the Company determines as a result of competitive changes in
Nevada, PUCN orders or otherwise that its business, or a portion of its
business, fails to meet any of these three criteria of FAS 71, it may have to
eliminate from its Consolidated Financial Statements the related transactions
prescribed by the regulators that would not have been recognized if it had been
a non-regulated company, which could result in an impairment of or write-off of
utility assets. The Company believes, however, that it continues to meet the
criteria for operating as a rate regulated entity, as prescribed by FAS 71.
In July 1997, the Emerging Issues Task Force (EITF) of the Financial
Accounting Standards Board reached a consensus on several issues which have
arisen due to deregulation of the electric utility industry and the continuing
applicability of FAS 71. The EITF reached a consensus that a company should stop
applying FAS 71 to a separable portion of its business when deregulatory
legislation or a rate order which results in deregulation gives enough detail
for the company to reasonably determine how the transition plan to deregulation
will effect that separable portion. Once FAS 71 is no longer applied to that
separable portion of the business it should be disclosed separately in the
company's financial statements. Any regulatory assets and liabilities that
originated in that separable portion of the company should be evaluated on the
basis of which portion of the business the regulated cash flows to settle them
will come from and will not be eliminated until they are recovered, individually
impaired or eliminated by the regulator or the portion of the business where the
regulated cash flows come from can no longer apply FAS 71. Any new regulatory
assets and liabilities are recognized within the portion of the company where
the regulated cash flows for their recovery or settlement are derived and are
eliminated in the same manner as existing regulatory assets and liabilities as
described above. After considering the EITF, the Company believes that it
continues to meet the criteria for operating as a rate regulated entity, as
prescribed by FAS 71.
PRINCIPLES OF CONSOLIDATION
The consolidated financial statements include the accounts of the Company
and its wholly-owned subsidiaries, NVP Capital I and III. All significant
intercompany transactions and balances have been eliminated in consolidation.
USE OF ESTIMATES
The preparation of consolidated financial statements in conformity with
generally accepted accounting principles requires management to make estimates
and assumptions that affect the reported amounts of assets and liabilities at
the date of the consolidated financial statements and the reported amounts of
revenues and expenses during the reporting period. Actual results could differ
from those estimates.
ELECTRIC REVENUES
The Company bills its customers monthly on a cycle basis and recognizes the
estimated
46
- --------------------------------------------------------------------------------
NEVADA POWER COMPANY 1998 ANNUAL REPORT
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- --------------------------------------------------------------------------------
amount of revenue applicable to kilowatthours of energy sold but not yet billed
at the end of an accounting period.
DEFERRED ENERGY COST ADJUSTMENTS
As permitted by state statute, the Company defers differences between the
current cost of fuel plus net purchased power and base energy costs as defined.
Any over or under recoveries are deferred in the balance sheet as a current
asset or current liability. Under regulations adopted by the PUCN, deferred
energy rates are revised at least every 12 months to clear the accumulated
deferred balance over a future period.
ELECTRIC PLANT
The costs of betterments and additions to electric plant and replacements
of retirement units of property are capitalized. Such costs include labor,
payroll taxes, material, transportation, an allowance for funds used during
construction and, where applicable, property taxes. Maintenance is charged with
the cost of repairs and minor replacements. Accumulated depreciation is charged
for the cost of plant retired, less net salvage.
Depreciation has been provided for financial statement purposes on a
straight-line basis at rates based upon the estimated useful lives of the
various classes of plant. The provisions for depreciation during 1998, 1997 and
1996 were equivalent to an annual rate of approximately 2.9 percent of the
average gross investment in depreciable plant.
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION
The allowance for funds used during construction (AFUDC) represents the
estimated costs of borrowed and equity funds applicable to electric plant
construction.
The FERC has prescribed a specific computational method for determining the
AFUDC rate. The PUCN has authorized the AFUDC rate to be the lesser of the rate
determined under the FERC computational method or the rate equivalent to the
overall rate of return authorized by the PUCN. The overall rate of return
authorized by the PUCN was 9.66 percent beginning July 1994. The Company's
actual AFUDC rate averaged 9.66 percent for 1998, 1997 and 1996.
RECENTLY ISSUED ACCOUNTING STANDARDS
The Financial Accounting Standards Board recently issued Statement of
Financial Accounting Standards No. 133 (FAS 133), Accounting for Derivative
Instruments and Hedging Activities, which is effective for financial statements
for all fiscal quarters of all fiscal years beginning after June 15, 1999. FAS
133 establishes accounting and reporting standards for derivative instruments,
including certain derivative instruments embedded in other contracts and for
hedging activities. It requires that an entity recognize all derivatives as
either assets or liabilities in the statement of financial position and measure
those instruments at fair value. The Company is currently evaluating the effect
of the adoption of FAS 133 on the Company's consolidated financial statements
and disclosures.
FEDERAL INCOME TAXES
The Company accounts for income taxes in accordance with Statement of
Financial Accounting Standards No. 109 (FAS 109), Accounting for Income Taxes.
FAS 109 requires recognition of deferred tax liabilities and assets for the
future tax consequences of events that have been included in the consolidated
financial statements or tax returns. Under this method, deferred tax liabilities
and assets are determined based on the difference between the financial
statement and tax bases of assets and liabilities using enacted tax rates in
effect for the year in which the differences are expected to reverse. The
Company's December 31, 1998 consolidated balance sheet contains a net regulatory
asset of $48 million related to federal income taxes. (See Note 11 of "Notes to
Consolidated Financial Statements.")
In November 1991, the PUCN issued an order which allows the Company to
recover the previously flowed through tax benefits ratably over the estimated
remaining book life of the plant. Calculated at current rates, approximately $31
million of income taxes will be allowed in future rates.
Investment tax credits earned have been deferred and are being amortized to
income ratably over the estimated service lives of the related property.
CASH FLOW INFORMATION
Cash equivalents are generally convertible to cash at par on short notice
and mature three months or less from the date of acquisition.
The Company had no material noncash investing or financing transactions
during 1998, 1997 or 1996.
47
- --------------------------------------------------------------------------------
NEVADA POWER COMPANY 1998 ANNUAL REPORT
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- --------------------------------------------------------------------------------
OTHER ACCOUNTING POLICIES
Certain amounts in prior periods have been reclassified to conform to the
consolidated financial statement presentation for December 31, 1998.
2 | MERGER; DIVIDEND POLICY
On April 30, 1998, the Company and Sierra Pacific Resources announced that
their boards of directors unanimously approved an agreement providing for a
proposed merger of equals combination with stock and cash consideration. In
conjunction with the proposed merger, the Company's Board of Directors stated
that, beginning with the November 1998 dividend, it intended to adopt the
expected combined company initial annual dividend rate. This would result in an
indicated annual dividend rate of $1.00 per share for periods following the
August 1998 dividend payment. For further information regarding the proposed
merger please refer to the Company's Form 8-K filed with the SEC on April 30,
1998.
Both the Company and Sierra Pacific Resources held special stockholder
meetings in October 1998 during which stockholders of both companies voted to
approve the proposed merger. On December 31, 1998, the PUCN approved the
proposed merger subject to conditions regarding the divestiture of the two
companies' generating plants, filing of general rate cases, merger costs and
several other issues. On January 29, 1999, the PUCN clarified portions of the
order approving the proposed merger. Both companies must sell their generating
units. Upon selling the generating units, both companies can determine how they
will use the proceeds of the sales, up to the book value of the plants. Any
after-tax gains above book value will be used to offset stranded costs, as
determined by the PUCN. Any remaining gains can be used to offset goodwill.
After-tax gains may not be sufficient to cover generation-related goodwill.
However, if the company demonstrates that the divestiture "resulted in a market
for generation services that produced market prices that are lower than what
could have been achieved otherwise, the company may include in the general rate
case a request to recover goodwill." Both companies are required to file a
general rate case in 1999 that would update rates to current costs and
"unbundle" rates, i.e. break them into generation, transmission and distribution
components. The merged company would again file a general rate case three years
after the start of retail competition in the state of Nevada that would give the
company the opportunity to recover costs of the merger, provided the company can
demonstrate that merger savings exceed merger costs. Merger costs are to be
split among the non-competitive, potentially competitive and unregulated
services or businesses. An opportunity to recover the non-competitive portion
of the merger costs will be addressed in the rate case that follows the start of
competition in Nevada. The burden is on the company to prove that merger
savings exceed merger costs. The company will also have the opportunity to
recover goodwill in the same proceeding. The proposed merger is conditioned upon
further regulatory approvals including the SEC, the Department of Justice and
the FERC. The companies filed with the FERC a joint merger application on
October 2, 1998 which was noticed on October 8, 1998. The law imposes no
deadline on the FERC to issue its decision. The entire process is expected to
be completed by mid-1999.
48
- --------------------------------------------------------------------------------
NEVADA POWER COMPANY 1998 ANNUAL REPORT
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- --------------------------------------------------------------------------------
3 | FEDERAL INCOME AND OTHER TAXES
- -------------------------------------------------------------------------------
The total federal income tax expense as set forth in the accompanying
Consolidated Statements of Income results in an effective federal income tax
rate different from the statutory federal income tax rate for the following
reasons:
<TABLE>
<CAPTION>
For the Years Ended December 31,
(Dollars in thousands) 1998 1997 1996
- ----------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Federal income tax at statutory |
rate | $45,200 35.0% $44,954 35.0% $42,613 35.0%
Adjustments: |
Investment tax credit |
amortization | (1,460) (1.1) (1,460) (1.1) (1,460) (1.2)
Other items | 1,731 1.3 1,731 1.3 1,731 1.4
- ----------------------------------|-----------------------------------------------------------------------
Total recorded federal income tax | $45,471 35.2% $45,225 35.2% $42,884 35.2%
|
- ----------------------------------|=======================================================================
Federal income taxes included in: |
Operating expenses | $42,949 $43,478 $44,970
Other miscellaneous, net | 2,522 1,747 (2,086)
- ----------------------------------|-----------------------------------------------------------------------
| $45,471 $45,225 $42,884
- -----------------------------------=======================================================================
The current and deferred components of federal income taxes included in operating expenses are as follows:
For the Years Ended December 31, (In thousands) 1998 1997 1996
- ------------------------------------------------------------------------------------------------------------
Current federal income taxes | $19,329 $21,899 $ 39,312
- -----------------------------------------------|------------------------------------------------------------
Deferred federal income taxes: |
Depreciation differences | 24,111 13,669 16,427
Deferred energy costs | 11,162 20,848 (3,544)
Contributions in aid of |
construction | (13,211) (6,302) (7,720)
Allowance for borrowed funds used during |
construction | 6,463 (2,406) (281)
Coal contract buyout | (697) (787) 1,752
Other - net | (2,748) (1,983) 484
- -----------------------------------------------|------------------------------------------------------------
| 25,080 23,039 7,118
- -----------------------------------------------|------------------------------------------------------------
Investment tax credit amortization | (1,460) (1,460) (1,460)
- -----------------------------------------------|------------------------------------------------------------
Total | $42,949 $43,478 $44,970
- ------------------------------------------------============================================================
</TABLE>
The regulatory asset for temporary differences related to liberalized
depreciation will continue to be amortized using the average rate assumption
method required by the Tax Reform Act of 1986. The regulatory liability for
temporary differences caused by investment tax credits will be amortized ratably
in the same fashion as the deferred investment tax credit under former Internal
Revenue Code Section 46(f)(2).
49
- --------------------------------------------------------------------------------
NEVADA POWER COMPANY 1998 ANNUAL REPORT
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- --------------------------------------------------------------------------------
The net deferred federal income tax liability consists of deferred federal
income tax liabilities less deferred federal income tax assets related to:
<TABLE>
<CAPTION>
December 31, (In thousands) 1998 1997
- -----------------------------------------------------------------------------
<S> <C> <C>
DEFERRED FEDERAL INCOME TAX |
LIABILITIES: |
Temporary basis differences - plant | $ (62,906) $(95,077)
Investment tax credits | (28,083) (29,544)
Excess of tax depreciation over book |
depreciation | (163,658) (133,084)
Coal contract buyout | (441) (1,138)
Accrued taxes | (3,120) (3,298)
Debt reacquisition costs | (2,177) (2,420)
Deferred energy | (21,871) (10,709)
Other | (626) (116)
- ----------------------------------------------|-------------------------------
Total | (282,882) (275,386)
- ----------------------------------------------|-------------------------------
DEFERRED FEDERAL INCOME TAX |
ASSETS: |
Unamortized investment tax credits | 15,122 15,908
Refundable customer advances | 21,837 18,920
Nonrefundable contributions in aid of |
construction | 25,312 15,017
Capitalized expenses | 83 (27)
Demand-side program costs | 1,319 (712)
Supplemental executive retirement plan | 2,549 2,249
Other | 1,082 681
- ----------------------------------------------|------------------------------
Total | 67,304 52,036
- ----------------------------------------------|------------------------------
Net deferred tax liability | $(215,578) $(223,350)
- -----------------------------------------------===============================
</TABLE>
4 | EMPLOYEE BENEFITS
- -------------------------------------------------------------------------------
DEFINED CONTRIBUTION RETIREMENT PLAN - The Company maintains an employee
investment plan (401(k) Plan) which was established January 1, 1990, under
Section 401(k) of the Internal Revenue Code. Employees who are at least 21 years
old and have completed one month of service may become "participants" in the
401(k) Plan. The Company matches 60 percent of a participant's contributions to
the 401(k) Plan not to exceed 4.2 percent of the participant's annual
compensation. All Company contributions are invested in common stock of the
Company. The amounts expensed for Company matching contributions to the 401(k)
Plan were $2,419,000 for 1998, $2,074,000 for 1997 and $1,821,000 for 1996.
DEFINED BENEFIT RETIREMENT PLAN - The Company has a non-contributory defined
benefit retirement plan (PLAN) designed to meet the provisions of the Employee
Retirement Income Security Act of 1974. All employees age 21 and over who have
completed one year of service with at least 1,000 hours worked participate in
the PLAN. Benefits under the PLAN are dependent upon each participant's salary
for the highest consecutive 60 months of service and length of service.
The Company also has a Supplemental Executive Retirement Plan (SERP) in
addition to the regular PLAN. Participation is limited to such officers as the
Board of Directors may select. Presently, 28 active or retired designated
officers and employees participate in the SERP. The SERP will be funded as
benefits are disbursed.
The following table sets forth the funded status and amounts recognized in
the Company's consolidated financial statements at December 31, 1998, 1997 and
1996 for both the PLAN and SERP.
The discount rate and rate of increase in future compensation levels used
in determining the actuarial present value of the projected benefit obligations
for both the PLAN and SERP were 6.75 percent and 4.5 percent in 1998, 7.5
percent and 4.5 percent in 1997, and 8 percent and 4.5 percent in 1996,
respectively. The expected rate of return on PLAN assets was 8.5 percent in
1998, 1997 and 1996. PLAN assets are primarily invested in listed securities
(domestic and international), fixed income securities and federal agencies
securities. The accumulated benefit obligation for the SERP was $8,264,000 at
December 31, 1998 and $7,452,000 at December 31, 1997.
50
- --------------------------------------------------------------------------------
NEVADA POWER COMPANY 1998 ANNUAL REPORT
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------------------------------------------
RECONCILIATION OF FUNDED STATUS
PLAN SERP
---------------------------------------------------------------------------
For the Years Ended | | |
December 31, | 1998 1997 1996 | 1998 1997 1996 |
(In thousands) | | |
- ----------------------|-------------------------------------|---------------------------------- |
<S> | <C> <C> <C> | <C> <C> <C> |
Change in benefit | | |
obligation: | | |
Net benefit | | |
obligation at | | |
beginning of year | $110,503 $ 96,592 $103,973 | $ 9,030 $ 6,662 $ 7,063 |
Service cost | 5,159 4,303 4,843 | 226 103 102 |
Interest cost | 8,598 7,893 7,642 | 687 544 517 |
Plan amendments | 2,063 - - | 178 117 - |
Actuarial (gain) loss | 17,989 6,473 (16,003) | 11 2,041 (553) |
Benefits paid | (4,979) (4,758) (3,863) | (434) (437) (467) |
- ----------------------|-------------------------------------|---------------------------------- |
Net benefit obligation| 139,333 110,503 96,592 | 9,698 9,030 6,662 |
at end of year | | |
- ----------------------|-------------------------------------|---------------------------------- |
Change in plan assets:| | |
Fair value of plan | | |
assets at beginning | | |
of year | 100,899 81,564 74,628 | - - - |
Actual return on plan | | |
assets 9,545 16,493 4,003 | - - - |
Employer contributions| 5,696 7,600 6,797 | 434 437 467 |
Benefits paid | (4,980) (4,758) (3,864) | (434) (437) (467) |
- ----------------------|-------------------------------------|---------------------------------- |
Fair value of plan | | |
assets at end of year| 111,160 100,899 81,564 | - - - |
- ----------------------|-------------------------------------|---------------------------------- |
Plan assets less than | | |
projected benefit | | |
obligation | (28,173) (9,604) (15,028) | (9,698) (9,030) (6,662) |
Unrecognized prior | | |
service costs | 7,207 5,809 6,386 | 577 515 495 |
Unrecognized actuarial| | |
(gain) loss | 15,850 (292) 2,712 | 3,470 3,646 1,692 |
4th quarter contri- | | |
butions/benefits | 3,500 1,196 800 | 109 109 110 |
- ----------------------|-------------------------------------|---------------------------------- |
Pension liability | $ (1,616) $ (2,891) $ (5,130) | $(5,542) $(4,760) $(4,365) |
- ----------------------|=====================================|================================== |
Net pension expense | | |
comprised the | | |
following: | | |
Service cost | $ 5,159 $ 4,303 $ 4,843 | $ 226 103 $ 102 |
Interest cost on | | |
projected benefit | | |
obligation | 8,598 7,893 7,642 | 687 544 517 |
Expected return on | | |
plan assets | (7,698) (7,015) (6,184) | - - - |
Amortization of: | | |
Prior service cost | 665 577 227 | 115 98 98 |
Actuarial loss | - - - | 188 86 137 |
- ----------------------|-------------------------------------|---------------------------------- |
Net periodic pension| | |
cost | $ 6,724 $ 5,758 $ 6,528 | $ 1,216 $ 831 $ 854 |
- ----------------------|=====================================|================================== |
</TABLE>
<TABLE>
<CAPTION>
PLAN SERP
----------------------------------------------------------|
For the Years Ended | | |
December 31, | 1998 1997 | 1998 1997 |
(In thousands) | | |
- ----------------------|--------------------------|------------------------------|
<S> | <C> <C> | <C> <C> |
Amounts recognized in | | |
the balance sheet | | |
consist of: | | |
Accrued benefit | | |
liability | $ (1,616) $ (2,891) | $(5,542) $ (4,760) |
Additional minimum | | |
liability | - - | (2,723) (2,584) |
Intangible asset | - - | 577 515 |
Accumulated other | | |
comprehensive | | |
income | - - | 2,146 2,069 |
| | |
- ----------------------|--------------------------|------------------------------|
Net amount recognized | $ (1,616) $ (2,891) | $(5,542) $(4,760) |
- ----------------------|==========================|==============================|
51
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NEVADA POWER COMPANY 1998 ANNUAL REPORT
</TABLE>
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- --------------------------------------------------------------------------------
POSTRETIREMENT BENEFITS OTHER THAN PENSIONS - The Company accounts for
postretirement benefits other than pensions in accordance with Statement of
Financial Accounting Standards No. 106 (FAS 106), Employers' Accounting for
Postretirement Benefits Other Than Pensions. The Company has elected to
amortize its transition obligation at January 1, 1993 over a period of 20 years.
The Company currently provides postretirement medical, dental and vision
benefits to employees who have retired. The postretirement health care plan is
contributory, and retirees' contributions can be adjusted annually for increases
in the cost of providing the benefits. The postretirement health care plan is
being funded in amounts not to exceed the lesser of amounts collected from
customers through rates or amounts allowable under the Internal Revenue Code as
amended from time to time.
Net periodic postretirement benefit cost for the years ended December 31,
1998, 1997 and 1996 included the following components:
<TABLE>
<CAPTION>
(In thousands) 1998 1997 1996
- ---------------------------------------------------------------------------
<S> <C> <C> <C>
Service cost | $ 432 $ 370 $ 406
Interest cost on projected benefit |
obligation | 1,155 1,270 1,223
Expected return on assets | (771) (627) (486)
Amortization of: |
Transition obligation | 969 968 968
Actuarial gain | (505) (399) (312)
- ---------------------------------------|----------------------------------
Net periodic postretirement |
benefit cost | $1,280 $1,582 $1,799
- ----------------------------------------==================================
</TABLE>
A reconciliation of the funded status of the plan to the amounts recognized in
the Consolidated Balance Sheets as of December 31, 1998 and 1997 is as follows:
<TABLE>
<CAPTION>
(In thousands) 1998 1997
- ---------------------------------------------------------------------
<S> <C> <C>
Change in benefit obligation: |
Net benefit |
obligation at beginning of year |$(15,496) $(16,065)
Service cost | (432) (370)
Interest cost | (1,155) (1,270)
Plan participants' contributions | 252 252
Actuarial gain (loss) | (551) 816
Benefits paid | 1,001 1,141
- -----------------------------------------------|---------------------
Net benefit |
obligation at end of year | (16,381) (15,496)
- -----------------------------------------------|---------------------
Change in fair value of assets: |
Fair value of assets at beginning of year | 8,665 7,075
Actual return on assets | 1,463 725
Employer contribution | 1,759 2,006
Plan participants' contributions | 252 -
Benefits paid | (1,001) (1,141)
- -----------------------------------------------|---------------------
Fair value of assets at end of year | 11,138 8,665
- -----------------------------------------------|---------------------
Accumulated postretirement benefit |
obligation in excess of assets | (5,243) (6,831)
Unrecognized net transition obligation | 13,561 14,530
Unrecognized net actuarial gain | (11,506) (11,576)
4th quarter contributions | 1,908 1,267
- -----------------------------------------------|---------------------
Accrued postretirement benefit liability |$ (1,280) $ (2,610)
- ------------------------------------------------=====================
Amounts recognized in |
the balance sheet |
consist of: |
Accrued benefit cost |$ (1,280) $ (2,610)
Additional minimum |
liability | - -
Intangible asset | - -
Accumulated other |
comprehensive |
income | - -
- -----------------------------------------------|---------------------
Net amount recognized |$ (1,280) $ (2,610)
- -----------------------------------------------|=====================
</TABLE>
52
- ------------------------------------------------------------------------------
NEVADA POWER COMPANY 1998 ANNUAL REPORT
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- --------------------------------------------------------------------------------
The medical cost trend rate assumed for 1999 was 6.25 percent, grading down
to 4.75 percent in 2001 and remaining at that level thereafter. The health care
cost trend rate has a significant effect on the accumulated postretirement
benefit obligation and net periodic cost. A one-percentage-point increase in
the assumed health care cost trend rate would increase the accumulated
postretirement benefit obligation at December 31, 1998 by $769,000 and would
increase the aggregate of the service and interest cost components of net
periodic postretirement benefit cost for 1998 by $229,000. A one-percentage-
point decrease in the assumed health care cost trend rate would decrease the
accumulated postretirement benefit obligation at December 31, 1998 by $689,000
and would decrease the aggregate of the service and interest cost components of
net periodic postretirement benefit cost for 1998 by $214,000. The weighted-
average discount rate used in determining the accumulated postretirement benefit
obligation at December 31, 1998 was 6.75 percent. The expected rate of return on
assets was 8.5 percent in 1998. Assets are primarily invested in listed stocks,
fixed income securities and federal agencies securities.
5 | SHORT-TERM BORROWINGS
- -------------------------------------------------------------------------------
The Company has a $125 million bank revolving credit facility which expires
on November 21, 2002, and pays a facility fee based on the Company's senior
unsecured debt rating. Borrowing rates under the bank line are determined by
both current market rates and the Company's senior unsecured debt rating. There
were $105 million in short-term borrowings outstanding at a weighted average
rate of 6.8% on the $125 million bank line at December 31, 1998 and none at
December 31, 1997.
In April 1998, the Company obtained an additional $50 million bank
revolving credit facility which expires on April 16, 1999 and pays a facility
fee based on the Company's senior unsecured debt rating. Borrowing rates under
the bank line are determined by both current market rates and the Company's
senior unsecured debt rating. There were no short-term borrowings outstanding on
the $50 million bank line at December 31, 1998.
6 | CAPITAL STOCK
- -------------------------------------------------------------------------------
The changes in common stock shares for 1996, 1997 and 1998 are as follows:
<TABLE>
<CAPTION>
Shares
- --------------------------------------------------------------------------------------------------
<S> | <C>
Outstanding, January 1, 1996 | 47,038,193
Issued under 401(k) Savings Plan | 87,889
Issued under Stock Purchase and Dividend Reinvestment Plan | 1,659,764
- -------------------------------------------------------------------------------------|------------
Outstanding, December 31, 1996 | 48,785,846
Issued under 401(k) Savings Plan | 98,184
Issued under Stock Purchase and Dividend Reinvestment Plan | 1,515,716
- -------------------------------------------------------------------------------------|------------
Outstanding, December 31, 1997 | 50,399,746
Issued under 401(k) Savings Plan | 65,609
Issued under Stock Purchase and Dividend Reinvestment Plan | 799,762
- -------------------------------------------------------------------------------------|------------
Outstanding, December 31, 1998 | 51,265,117
- --------------------------------------------------------------------------------------============
</TABLE>
Premium on capital stock increased $20.3 million, $31.8 million and $35.2
million during 1998, 1997 and 1996, respectively, due to issuances of common
stock. Cash dividends paid per share on common stock were $1.45 during 1998 and
$1.60 during 1997 and 1996.
Under the provisions of the 4.70%, 5.20% and 5.40% series cumulative
preferred stock with mandatory sinking funds, the Company is obligated to use
its best efforts to purchase, each year, up to an aggregate of 6,000, 2,000 and
2,000 shares, respectively, at prices not in excess of $20.00 per share. The
obligations are not cumulative. The 5.20% series and 5.40% series are presently
redeemable at the option of the Company at $21.00 per share and the 4.70% series
at $20.25 per share. Completion of the proposed merger requires that all of the
cumulative preferred stock be redeemed.
In October 1990, the Company adopted a Stockholder Rights Plan and issued
through dividend to its common shareholders one stock purchase right for each
outstanding share of common stock. The rights expire in October 2000. The rights
to purchase junior preference shares, common
53
- --------------------------------------------------------------------------------
NEVADA POWER COMPANY 1998 ANNUAL REPORT
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- --------------------------------------------------------------------------------
shares or shares of a successor corporation are not exercisable unless certain
events occur and are intended to assure fair shareholder treatment in any
takeover of the Company and to guard against abusive takeover tactics. The
current proposed merger with Sierra Pacific Resources will not trigger the
Stockholder Rights Plan.
7 | PREFERRED SECURITIES
- -------------------------------------------------------------------------------
On April 2, 1997, NVP Capital I (Trust), a wholly-owned subsidiary of the
Company, issued 4,754,860 8.2% QUIPS at $25 per security. The Company owns all
of the Series A common securities, 147,058 shares issued by the Trust for $3.7
million. The QUIPS and the common securities represent undivided beneficial
ownership interests in the assets of the Trust, a statutory business trust
formed under the laws of the state of Delaware. The existence of the Trust is
for the sole purpose of issuing the QUIPS and the common securities and using
the proceeds thereof to purchase from the Company its 8.2% Junior Subordinated
Deferrable Interest Debentures (QUIDS) due March 31, 2037, extendible to March
31, 2046 under certain conditions, in a principal amount of $122.6 million. The
sole asset of the Trust is the QUIDS. Holders of the Series A QUIPS are
entitled to receive preferential cumulative cash distributions accruing from the
date of original issuance and payable quarterly in arrears on the last day of
March, June, September and December of each year. The Series A QUIPS are
subject to mandatory redemption, in whole or in part, upon repayment of the
Series A QUIDS at maturity or their earlier redemption in an amount equal to the
amount of related Series A QUIDS maturing or being redeemed. The QUIPS are
redeemable at $25 per preferred security plus accumulated and unpaid
distributions thereon to the date of redemption. The Company's obligations
under the guarantee agreement entered into in connection with the QUIPS when
taken together with the Company's obligation to make interest and other payments
on the QUIDS issued to the Trust, and the Company's obligations under the
Indenture pursuant to which the QUIDS are issued and its obligations under the
Declaration, including its liabilities to pay costs, expenses, debts and
liabilities of the Trust, provides a full and unconditional guarantee by the
Company of the Trust's obligations under the QUIPS. Financial statements of the
Trust are consolidated with the Company's. Separate financial statements are
not filed because the Trust is wholly-owned by the Company and essentially has
no independent operations, and the Company's guarantee of the Trust's
obligations is full and unconditional. The $118.9 million in net proceeds to
the Company was used for general corporate utility purposes and the repayment of
short-term debt incurred to redeem the Company's $38 million, 9.9% Redeemable
Cumulative Preferred Stock on April 1, 1997.
In October 1998, NVP Capital III (Trust), a wholly-owned subsidiary of
the Company, issued 2,800,000 7 3/4% Cumulative Quarterly Trust Issued
Preferred Securities at $25 per security. The Company owns all the common
securities, 86,598 shares issued by the Trust for $2.2 million. The Trust
Issued Preferred Securities and the common securities represent undivided
beneficial ownership interests in the assets of the Trust, a statutory business
trust formed under the laws of the state of Delaware. The existence of the
Trust is for the sole purpose of issuing the Trust Issued Preferred Securities
and the common securities and using the proceeds thereof to purchase from the
Company its 7 3/4% Junior Subordinated Deferrable Interest Debentures due
September 30, 2038, extendible to September 30, 2047 under certain conditions,
in a principal amount of $72.2 million. The sole asset of the Trust is the
deferrable interest debentures. Holders of the Trust Issued Preferred Securities
are entitled to receive preferential cumulative cash distributions accruing from
the date of original issuance and payable quarterly in arrears on the last day
of March, June, September and December of each year. The Trust Issued Preferred
Securities are subject to mandatory redemption, in whole or in part, upon
repayment of the deferrable interest debentures at maturity or their earlier
redemption in an amount equal to the amount of related deferrable interest
debentures maturing or being redeemed. The Trust Issued Preferred Securities
are redeemable at $25 per preferred security plus accumulated and unpaid
distributions thereon to the date of redemption. The Company's obligations
under the guarantee agreement entered into in connection with the Trust Issued
Preferred Securities when taken together with the Company's obligation to make
interest
54
- --------------------------------------------------------------------------------
NEVADA POWER COMPANY 1998 ANNUAL REPORT
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- --------------------------------------------------------------------------------
and other payments on the deferrable interest debentures issued to the Trust,
and the Company's obligations under the Indenture pursuant to which the
deferrable interest debentures are issued and its obligations under the
Declaration, including its liabilities to pay costs, expenses, debts and
liabilities of the Trust, provides a full and unconditional guarantee by the
Company of the Trust's obligations under the Trust Issued Preferred Securities.
Financial statements of the Trust are consolidated with the Company's. Separate
financial statements are not filed because the Trust is wholly-owned by the
Company and essentially has no independent operations, and the Company's
guarantee of the Trust's obligations is full and unconditional. The $70 million
in net proceeds to the Company was used for general corporate utility purposes
including the repayment of short term debt.
8 | LONG-TERM DEBT
- -------------------------------------------------------------------------------
None of the long-term debt is held by or for the account of the Company.
The amounts of long-term debt maturities, including sinking fund
requirements, are $50.2 million in 1999, $90.5 million in 2000, $3.6 million in
2001, $20.1 million in 2002 and $4.7 million in 2003, including $4.9 million,
$5.2 million, $3.5 million, $5.0 million and $4.7 million for obligations under
capital leases, respectively.
Generally, electric plant is subject to the first mortgage lien. It is the
Company's intention to meet the sinking fund requirements for its series L first
mortgage bonds by pledging property additions in lieu of cash payments. The
series T, V, W and X first mortgage bonds correspond with respect to their terms
to two series of collateralized pollution control revenue bonds and two series
of industrial development revenue bonds issued by Clark County, Nevada.
The industrial development revenue bonds and pollution control revenue
bonds were issued by various municipal authorities and are guaranteed as to
payment of principal and interest by the Company.
On January 29, 1998, the Company remarketed at fixed rates $141.05 million
Clark County, Nevada (Nevada Power Company Project) variable rate revenue bonds
consisting of $76.75 million Series 1995A IDBs due 2030 at 5.6 percent, $44
million Series 1995C IDBs due 2030 at 5.5 percent and $20.3 million Series 1995D
PCRBs with $14 million due 2011 at 5.3 percent and $6.3 million due 2023 at 5.45
percent. On the same date, $13 million Coconino County, Arizona (Nevada Power
Company Project) Series 1995E PCRBs due 2022 were remarketed at a 5.35 percent
fixed rate. The Company also remarketed $85 million Series 1995B Clark County,
Nevada (Nevada Power Company Project) variable rate IDBs due 2030 at a 5.9
percent fixed rate on November 24, 1997.
9 | FAIR VALUE OF FINANCIAL INSTRUMENTS
- -------------------------------------------------------------------------------
Disclosure by the Company of the estimated fair value of financial
instruments is made in accordance with the requirements of Statement of
Financial Accounting Standards No. 107 (FAS 107), Disclosures about Fair Value
of Financial Instruments. At December 31, 1998 and 1997, the provisions of FAS
107 applies to the Company's long-term debt, QUIPS and 7 3/4% Trust Issued
Preferred Securities.
In accordance with FAS 107, the Company estimates the fair value of its
long-term debt, QUIPS and Trust Issued Preferred Securities based on quoted
market prices for the same or similar issues or on current interest rates
available to the Company for debt with similar terms and maturity. The book
value and estimated fair value of the Company's long-term debt, including
current maturities and sinking fund requirements and excluding obligations under
capital leases, were $859 million and $913 million at December 31, 1998, and
$821 million and $857 million at December 31, 1997, respectively. The book value
and estimated fair value of the QUIPS were $119 million and $122 million at
December 31, 1998, and $119 million and $125 million at December 31, 1997,
respectively. The book value and estimated fair value of the 7 3/4 % Trust
Issued Preferred Securities were $70 million and $71 million at December 31,
1998, respectively. The estimates presented herein are not necessarily
indicative of the amounts that the Company could realize in a current market
exchange. The use of different market assumptions and/or estimation
methodologies may have an effect on the estimated fair value amounts.
55
- --------------------------------------------------------------------------------
NEVADA POWER COMPANY 1998 ANNUAL REPORT
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- --------------------------------------------------------------------------------
10| COMMITMENTS AND CONTINGENCIES
- --------------------------------------------------------------------------------
LEGAL MATTERS
The Company is involved in litigation arising in the normal course of
business. While the results of such litigation cannot be predicted with
certainty, management, based upon advice of counsel, believes that the final
outcome will not have a material adverse effect on the Company's financial
position, results of operations and net cash flow.
On February 6, 1997, the PUCN issued its opinion and order in the last
phase of the 1995 deferred energy case concerning the prudency of the Company's
fuel and purchased power expenditures during the period June 1993 to May 1995, a
buyout of a coal supply agreement and a credit to customers related to the use
of coal reserves in an unregulated subsidiary company. The PUCN order resulted
in a fourth quarter 1996 charge of $5.5 million, net of tax, for amounts
disallowed by the PUCN. On May 7, 1997, the Company filed a Petition for
Judicial Review in the First District Court in Carson City, Nevada challenging
the PUCN's findings which resulted in disallowances. The Court recently held
oral argument on the appeal and the Company is awaiting a decision.
The Grand Canyon Trust and Sierra Club filed a lawsuit in the U.S. District
Court, District of Nevada, in February 1998 against the owners of the Mohave
Generating Station (Mohave) alleging violations of the Clean Air Act regarding
emissions of sulfur dioxide and particulates. The owners believe the emission
limits referenced in the suit are not applicable to Mohave. The owners
previously partnered with the Environmental Protection Agency (EPA) and the
National Park Service on a multi-year study to determine the impacts, if any, of
Mohave emissions on visibility in the Grand Canyon (see Environmental Matters).
The environmental groups want the owners to install pollution control equipment
at an estimated cost of $300 to $350 million. The Company owns a 14 percent
interest in Mohave. The outcome of this action cannot be determined at this
time.
The owners of Mohave, including the Company, will participate in
collaborative talks with groups interested in the plant's future (see
Environmental Matters).
ENVIRONMENTAL MATTERS
The Federal Clean Air Act Amendments of 1990 (Amendments) include
provisions for reduction of emissions of oxides of nitrogen by establishing new
emission limits for coal-fired generating units. This will require the
installation of additional pollution-control technology at some of the Reid
Gardner Station generating units before 2000 at an estimated cost to the Company
of no more than $6 million; $4.4 million has been spent to date. Installation
is scheduled for completion by May 1999.
Also, the United States Congress authorized the EPA to study the potential
impact Mohave may have on visibility in the Grand Canyon area. A draft report of
the study results was released for peer review in September 1998 and a final
report is expected in the first quarter of 1999. The majority owner has
estimated that control costs, if required, could total between $300 and $350
million.
The owners of Mohave, including the Company, will participate in planned
collaborative talks with groups interested in the plant's future, provided that
all stakeholders are willing to participate in a collaborative effort. The
owners' position in these talks could include a commitment to place sulfur
dioxide scrubbers and fine particulate controls on the plant between 2005 and
2008. Interest groups include the local communities, plant employees, the EPA
state jurisdictions and the plant owners. Collaborative talks could begin in the
first quarter of 1999.
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.
56
- --------------------------------------------------------------------------------
NEVADA POWER COMPANY 1998 ANNUAL REPORT
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- --------------------------------------------------------------------------------
LEASES
In 1984, the Company sold its administrative headquarters facility, less
furniture and fixtures, for $27 million and entered into a 30-year capital lease
of that facility with five-year renewal options beginning in year 31. The fixed
rental obligation for the first 30 years is $5.1 million per year. Future cash
rental payments as of December 31, 1998, are as follows:
<TABLE>
<CAPTION>
(In thousands)
- ----------------------------------------------------
<S> <C>
1999 |$ 4,880
2000 | 6,156
2001 | 6,156
2002 | 6,156
2003 | 6,156
Thereafter | 80,433
- -------------------------------------------|--------
|$109,937
- --------------------------------------------========
</TABLE>
The amount of imputed interest necessary to reduce the future cash rental
payments to present value is $60.5 million as of December 31, 1998.
Total interest expense on the lease obligation was $5.6 million and total
amortization of the leased facility was $(194,000) for the year ended December
31, 1998. The total accumulated amortization of the leased facility on December
31, 1998, was $9.7 million.
At December 31, 1998, the Company has certain long-term noncancelable
operating lease agreements for which the future minimum lease payments are
immaterial.
FUEL AND PURCHASED POWER OBLIGATIONS
The Company has seven long-term contracts for the purchase of electric
energy and/or capacity. The contracts expire in years ranging from 1999 to 2016.
Total payments under these contracts were $46.3 million, $41.9 million and
$39.7 million in 1998, 1997 and 1996, respectively. The cost of power obtained
under these contracts is included in purchased and interchanged power expense in
the Consolidated Statements of Income.
At December 31, 1998, the estimated future payments for capacity and energy
that the Company is obligated to purchase under these contracts, subject in part
to certain conditions, are as follows:
<TABLE>
<CAPTION>
Accounted for
as Long-Term Accounted for
Executory as Long-Term
(In thousands) Contracts Capital Lease
- ----------------------------------------------------------------------------
<S> <C> <C>
1999 |$ 20,736 $ 11,844
2000 | 11,338 11,315
2001 | - 10,786
2002 | - 10,282
2003 | - 9,752
Thereafter | - 91,652
- ------------------------------------------|---------------------------------
Total minimum payment |$ 32,074 145,631
- ------------------------------------------|========
Less amount representing estimated |
executory costs included in total |
minimum payment | (82,544)
- ------------------------------------------|---------------------------------
Net minimum payments | 63,087
Less amount representing interest | (21,260)
- ------------------------------------------|---------------------------------
Present value of net minimum payments | $ 41,827
- ------------------------------------------------------------------==========
</TABLE>
One purchase power obligation is accounted for as a capital lease according
to Financial Accounting Standards No. 13 Accounting for Leases. Total interest
expense on the capital lease was $4.2 million, $4.6 million and $5.1 million in
1998, 1997 and 1996, respectively. Total amortization on the capital lease was
$4.5 million, $5.2 million and $5.3 million in 1998, 1997 and 1996,
respectively. Total accumulated amortization was $41.2 million as of December
31, 1998.
The Company has contracted with various coal suppliers to provide coal to
the Reid Gardner Generating Station. The contracts expire in years ranging from
1999 to 2007.
Costs of approximately $32.1 million, $18.1 million and $25.9 million were
incurred under the long-term coal contracts in 1998, 1997 and 1996,
respectively.
In addition, the Company has long-term transportation arrangements with
railway companies to transport coal to the Reid Gardner Generating Station and a
coal railcar lease. The contracts expire in 1999, 2000 and 2011.
57
- --------------------------------------------------------------------------------
NEVADA POWER COMPANY 1998 ANNUAL REPORT
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- --------------------------------------------------------------------------------
Costs of approximately $18.3 million, $15.0 million and $18.5 million were
incurred under the coal transportation contracts in 1998, 1997 and 1996,
respectively.
At December 31, 1998 the estimated future payments for purchase and
transportation of coal that the Company is obligated to purchase under these
contracts are as follows:
<TABLE>
<CAPTION>
(In thousands) Coal Transportation Coal Use
- ----------------------------------------------------------------
<S> <C> <C>
1999 $13,278 $18,465
2000 12,111 15,956
2001 1,012 16,222
2002 1,012 15,823
2003 1,012 11,360
Thereafter 8,014 40,270
- -----------------------------------------------------------------
$36,439 $118,096
- -----------------------------------==============================
</TABLE>
CONSTRUCTION
Certain commitments have been incurred at December 31, 1998, in connection
with the 1999 construction budget. Construction expenditures are estimated at
$245 million, excluding AFUDC, for 1999.
11 | OTHER DEFERRED CHARGES AND CREDITS
- -------------------------------------------------------------------------------
OTHER DEFERRED CHARGES
At December 31, 1998, other deferred charges include a regulatory asset of
$62.9 million and a deferred tax asset of $15.1. The regulatory asset represents
future revenue to be received from customers due to the flow-through of tax
benefits of temporary differences in prior years and the deferred tax asset is
from temporary differences caused by investment tax credits.
At December 31, 1998, organizational study, early retirement and severance
costs of $3 million are included in other deferred charges as a regulatory asset
and are being amortized over an eight-year period effective February 1994 as
approved in an order issued by the PUCN in 1994. These costs are a result of the
completion of a comprehensive organizational study started in 1993.
Other deferred charges as of December 31, 1998, also include $47.1 million
for deferred federal income taxes on customer advances for construction.
OTHER DEFERRED CREDITS
Other deferred credits as of December 31, 1998, include a regulatory
liability of $15.1 million representing amounts to be refunded to customers in
the future as a result of the Company adopting FAS 109.
12 | INTERESTS IN JOINTLY OWNED ELECTRIC UTILITY FACILITIES
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------
At December 31, 1998, the Company owned the following undivided interests in
jointly owned electric utility facilities:
Company's Share of
- -------------------------------------------------------------------------------
| Construction
Percent Owned |Plant Accumulated Net Plant Work In
by Company |In Service Depreciation In Service Progress
(In thousands) |
- -------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
FACILITY |
Navajo Generating |
Station 11.3 | $186,483 $ 79,356 $107,127 $13,078
Mohave Generating |
Station 14.0 | 77,950 30,105 47,845 2,171
Reid Gardner Unit |
No. 4 Generating |
Station 32.2 | 125,719 43,525 82,194 352
- -------------------------------------------------------------------------------
Total $390,152 $152,986 $237,166 $15,601
- ----------------------------===================================================
</TABLE>
The amounts above for Navajo and Mohave include the Company's share of
transmission systems and general plant equipment and, in the case of Navajo, the
Company's share of the jointly owned railroad which delivers coal to the plant.
Each participant provides its own financing for all of these jointly owned
facilities. The Company's share of operating expenses for these facilities is
included in the corresponding operating expenses in the Consolidated Statements
of Income.
58
- --------------------------------------------------------------------------------
NEVADA POWER COMPANY 1998 ANNUAL REPORT
<PAGE>
<TABLE>
<CAPTION>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- --------------------------------------------------------------------------------
13| QUARTERLY FINANCIAL DATA (UNAUDITED)
- -------------------------------------------------------------------------------
(In thousands, except per share amounts)
March 31 June 30 September 30 December 31
- -------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
1998: |
Electric Revenues | $165,263 $198,935 $327,776 $181,708
Operating Income | 21,263 24,788 76,919 24,307
Net Income | 6,936 10,446 61,987 4,304
Earnings Available |
for Common Stock | 6,892 10,401 61,945 4,261
Earnings per Average |
Common Share | .14 .20 1.21 .08
Dividends per Common Share | .40 .40 .40 .25
Common Stock Price per Share: |
High | 26 3/4 26 15/16 26 15/16 26 13/16
Low | 24 3/8 22 3/16 23 1/16 23 3/16
- --------------------------------|-----------------------------------------------
1997: |
Electric Revenues | $155,355 $199,970 $284,994 $158,829
Operating Income | 19,441 32,297 66,483 18,975
Net Income | 8,570 18,870 52,747 3,029
Earnings Available |
for Common Stock | 7,583 18,823 52,701 2,984
Earnings per Average |
Common Share | .15 .38 1.06 .06
Dividends per Common Share | .40 .40 .40 .40
Common Stock Price per Share: |
High | 20 25/32 21 1/2 22 3/16 27 5/8
Low | 19 3/4 19 3/8 20 5/8 20 5/8
- --------------------------------|-----------------------------------------------
</TABLE>
The business of the Company is seasonal in nature and it is management's
opinion that comparisons of earnings for the quarters do not give a true
indication of overall trends and changes in the Company's operations.
High and low common stock prices shown are as reported by the Wall Street
Journal as New York Stock Exchange Composite Transactions. The common stock is
also listed on the Pacific Exchange.
Holders of common stock are entitled to dividends as declared by the Board
of Directors, subject to the rights of the cumulative preferred stock and the
preference stock of the Company to quarterly cumulative dividends as declared by
the Board of Directors. The Company has paid quarterly dividends on its common
stock since August 1954.
The Company had 46,693 shareholders of record of common stock at December
31, 1998.
59
- --------------------------------------------------------------------------------
NEVADA POWER COMPANY 1998 ANNUAL REPORT
<PAGE>
REPORT OF INDEPENDENT AUDITORS
To the Board of Directors and Shareholders of Nevada Power Company:
We have audited the consolidated balance sheets and schedules of
capitalization and long-term debt of Nevada Power Company and its subsidiaries
as of December 31, 1998 and 1997, and the related consolidated statements of
income, comprehensive income, retained earnings and cash flows for each of the
three years in the period ended December 31, 1998. These consolidated financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these consolidated financial
statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in
all material respects, the financial position of Nevada Power Company and its
subsidiaries at December 31, 1998 and 1997, and the results of their operations
and their cash flows for each of the three years in the period ended December
31, 1998 in conformity with generally accepted accounting principles.
DELOITTE & TOUCHE LLP
Deloitte & Touche LLP
Las Vegas, Nevada
March 1, 1999
60
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NEVADA POWER COMPANY 1998 ANNUAL REPORT
<PAGE>
REPORT OF MANAGEMENT
The management of Nevada Power Company is responsible for the consolidated
financial statements presented in this report. Management prepared the
consolidated financial statements in conformity with generally accepted
accounting principles applicable to public utilities which are consistent in all
material respects with the accounting prescribed by the Public Utilities
Commission of Nevada and the Federal Energy Regulatory Commission. In preparing
the consolidated financial statements, management made informed judgments and
estimates relating to events and transactions being reported.
The Company has a system of internal accounting and financial controls and
procedures in place to insure that the financial records reflect the
transactions of the Company and that assets are safeguarded. This system is
examined by management on a continuing basis for effectiveness and efficiency
and is reviewed on a regular basis by an internal audit staff that reports
directly to the Audit Committee of the Board of Directors.
The consolidated financial statements have been audited by Deloitte &
Touche LLP, independent auditors. The auditors provide an objective, independent
review as to management's discharge of its responsibilities as they relate to
the fairness of reported operating results and financial condition. Their audit
includes procedures which provide them reasonable assurance that the
consolidated financial statements are not misleading and includes a review of
the Company's system of internal accounting and financial controls and a test of
transactions.
The Board of Directors has oversight responsibility for determining that
management has fulfilled its obligation in the preparation of consolidated
financial statements and the ongoing examination of the Company's system of
internal accounting controls. The Audit Committee, which is composed solely of
outside directors, meets regularly with management, Deloitte & Touche LLP and
the internal audit staff to discuss accounting, auditing and financial reporting
matters. The Audit Committee reviews the program of audit work performed by the
internal audit staff. To insure auditor independence, both Deloitte & Touche LLP
and the internal audit staff have complete and free access to the Audit
Committee.
61
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NEVADA POWER COMPANY 1998 ANNUAL REPORT
<PAGE>
<TABLE>
<CAPTION>
STATISTICAL SUMMARY 1998-1994
- ----------------------------------------------------------------------------------------------------------------
1998 1997 1996 1995 1994
- ----------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
SUMMARY OF OPERATIONS |
(In thousands, except per share amounts) |
Electric Revenues: |
Residential | $ 380,299 $ 358,921 $ 354,883 $ 319,373 $ 331,671
Commercial and industrial | 425,150 380,531 394,743 383,080 380,223
Other electric sales | 49,123 48,749 45,683 38,700 43,732
Miscellaneous | 19,110 10,947 10,065 8,828 8,532
- -------------------------------------------|--------------------------------------------------------------------
| 873,682 799,148 805,374 749,981 764,158
- -------------------------------------------|--------------------------------------------------------------------
|
Net Income (a) | 83,673 83,216 78,868 76,971 81,870
Dividend Requirements on Preferred Stock | 174 1,125 3,956 3,966 3,976
Earnings Available for Common Stock (a) | $ 83,499 $ 82,091 $ 74,912 $ 73,005 $ 77,894
Weighted Average Number of Common |
Shares Outstanding | 50,993 49,691 47,976 46,288 42,784
Earnings per Average Common Share (a) | $ 1.64 $ 1.65 $ 1.56 $ 1.58 $ 1.82
Dividends per Common Share | $ 1.45 $ 1.60 $ 1.60 $ 1.60 $ 1.60
|
CAPITALIZATION |
(In thousands, except per share amounts) |
Long-Term Debt | $ 900,227 $ 895,439 $ 841,364 $ 799,999 $ 712,571
Company-obligated Mandatorily Redeemable |
Preferred Securities of the Company's |
Subsidiary Trusts, NVP Capital I and III | 188,872 118,872 - - -
Cumulative Preferred Stock | - - 38,000 38,000 38,000
Cumulative Preferred Stock with |
Mandatory Sinking Funds | 3,265 3,463 3,663 3,863 4,064
Common Shareholders' Equity | 864,036 833,623 800,154 764,361 731,749
Book Value per Common Share | $ 16.85 $ 16.54 $ 16.40 $ 16.25 $ 16.12
|
RETURN ON COMMON SHAREHOLDERS' EQUITY | 9.66% 9.85% 9.36% 9.55% 10.64%
|
ELECTRIC PLANT INVESTMENT (In thousands) |
Gross | $2,908,677 $2,607,917 $2,411,901 $2,247,923 $2,079,694
Depreciated | 2,199,886 1,960,709 1,819,330 1,701,120 1,584,003
|
TOTAL ASSETS (In thousands) | $2,607,824 $2,339,422 $2,163,224 $2,073,050 $1,907,389
|
CONSTRUCTION EXPENDITURES EXCLUDING |
AFUDC (In thousands) | $ 308,286 $ 210,971 $ 179,981 $ 176,395 $ 179,674
|
OPERATING AND SALES DATA: |
Generating Capacity and Firm |
Purchases (Megawatts) | 3,901 3,621 3,858 3,525 3,462
Peak Load (Megawatts) | 3,855 3,469 3,332 3,066 2,920
Electric Sales (Megawatthours) | 14,899,500 14,596,228 13,697,059 12,109,355 11,942,724
Number of Customers (Year-End) | 548,796 518,391 487,064 454,166 428,286
Average Annual Kilowatthour Sales |
per Residential Customer | 12,182 12,757 13,199 12,367 13,605
|
NUMBER OF EMPLOYEES (Year-End) | 1,888 1,909 1,792 1,761 1,759
- -----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
(a) Amount for 1994 includes other income from the resolution of a regulatory
investigation of replacement power costs resulting from a 1985 generating
station accident. Amount for 1996 includes a write-off resulting from the PUCN
order in the 1995 deferred energy case.
62
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NEVADA POWER COMPANY 1998 ANNUAL REPORT
<TABLE> <S> <C>
<PAGE>
<ARTICLE> UT
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
CONSOLIDATED BALANCE SHEET OF NEVADA POWER COMPANY AS OF DECEMBER 31, 1998 AND
THE RELATED CONSOLIDATED STATEMENTS OF INCOME, CASH FLOWS AND RETAINED EARNINGS
FOR THE YEAR ENDED DECEMBER 31, 1998 AND IS QUALIFIED IN ITS ENTIRETY BY
REFERENCE TO SUCH CONSOLIDATED FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-END> DEC-31-1998
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 2,199,886
<OTHER-PROPERTY-AND-INVEST> 24,483
<TOTAL-CURRENT-ASSETS> 208,950
<TOTAL-DEFERRED-CHARGES> 174,505
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 2,607,824
<COMMON> 54,066
<CAPITAL-SURPLUS-PAID-IN> 683,156
<RETAINED-EARNINGS> 126,814
<TOTAL-COMMON-STOCKHOLDERS-EQ> 864,036
188,872
3,265
<LONG-TERM-DEBT-NET> 813,899
<SHORT-TERM-NOTES> 105,000
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 45,259
200
<CAPITAL-LEASE-OBLIGATIONS> 86,328
<LEASES-CURRENT> 4,921
<OTHER-ITEMS-CAPITAL-AND-LIAB> 496,044
<TOT-CAPITALIZATION-AND-LIAB> 2,607,824
<GROSS-OPERATING-REVENUE> 873,682
<INCOME-TAX-EXPENSE> 42,949
<OTHER-OPERATING-EXPENSES> 683,456
<TOTAL-OPERATING-EXPENSES> 726,405
<OPERATING-INCOME-LOSS> 147,277
<OTHER-INCOME-NET> 4,342
<INCOME-BEFORE-INTEREST-EXPEN> 151,619
<TOTAL-INTEREST-EXPENSE> 67,946
<NET-INCOME> 83,673
174
<EARNINGS-AVAILABLE-FOR-COMM> 83,499
<COMMON-STOCK-DIVIDENDS> 73,717
<TOTAL-INTEREST-ON-BONDS> 56,995
<CASH-FLOW-OPERATIONS> 154,379
<EPS-PRIMARY> 1.64
<EPS-DILUTED> 0<F1>
<FN>
<F1>INAPPLICABLE
</FN>
</TABLE>
