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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 fiscal year ended December 31, 1993 Commission file number 1-4698
NEVADA POWER COMPANY
(Exact name of Registrant as Specified in its Charter)
Nevada 88-0045330
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
6226 West Sahara Avenue 89102
Las Vegas, Nevada (Zip Code)
(Address of principal executive offices)
Registrant's telephone number, including area code: (702) 367-5000
Securities registered pursuant to Section 12(b) of the Act:
Name of Each Exchange
Title of Each Class on which Registered
------------------- ---------------------
Common Stock, $1 Par Value New York Stock Exchange
Pacific Stock Exchange
Stock Purchase Rights New York Stock Exchange
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
---
41,944,428 shares of Common Stock were outstanding as of March 24, 1994.
The aggregate market value of Common Stock, which is the only voting
stock, held by non-affiliates as of March 24, 1994, was $943,749,630.
(Computed by reference to the closing price on March 24, 1994, as reported
by the Wall Street Journal as New York Stock Exchange Composite
Transactions.)
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DOCUMENTS INCORPORATED BY REFERENCE
(1) Portions of the Registrant's Annual Report to Shareholders for the
year ended December 31, 1993 are incorporated by reference into Parts II
and IV hereof.
(2) Portions of the Registrant's definitive Proxy Statement dated
March 14, 1994 for the Company's annual meeting of shareholders on May 6,
1994, are incorporated by reference into Part III hereof.
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TABLE OF CONTENTS
Page
PART I ----
Item 1. Business ...................................... 1
Item 2. Properties .................................... 9
Item 3. Legal Proceedings ............................. 10
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 ............... 12
Item 6. Selected Financial Data ....................... 12
Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operation... 12
Item 8. Financial Statements and Supplementary Data ... 13
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure ........ 13
PART III
Item 10. Directors and Executive Officers of the
Registrant .................................... 13
Item 11. Executive Compensation ........................ 14
Item 12. Security Ownership of Certain Beneficial Owners
and Management ................................ 14
Item 13. Certain Relationships and Related Transactions. 14
PART IV
Item 14. Exhibits, Financial Statement Schedules, and
Reports on Form 8-K ........................... 15
SIGNATURES .................................................. 29
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PART I
ITEM 1. BUSINESS
THE COMPANY
Nevada Power Company (the 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 916,000 at December 31, 1993)
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:
Number Net Capacity
Plant of Units (Megawatts)
----- -------- ------------
Coal Fuel:
Reid Gardner (Steam).............. 3 330
Reid Gardner Unit No. 4 (Steam)... 1 275(1)
Mohave (Steam).................... 2 178(2)
Navajo (Steam).................... 3 255(3)
Natural Gas and Oil Fuel:
Clark (Steam)..................... 3 175
Clark (Gas Turbine).............. 1 50
Clark (Combined Cycle)............ 2 466(4)
Sunrise (Steam)................... 1 80
Sunrise (Gas Turbine)............. 1 69
-----
1,878
_________________ =====
(1) This represents 25 megawatts of base load capacity, 235 megawatts
of peaking capacity and 15 megawatts upgrade 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. The
Company is entitled to use 100% of the unit's capacity for 1,500
hours each year excepting that from 1993 through 1997, the
Company has agreed to reduce its allocation of peaking capacity
by 20 MW. The Company is entitled to 9.6% of the first 260
megawatts of capacity and associated energy and is entitled to
all the 15 megawatt upgrade accomplished in 1990. Beginning in
1998, the Company has options for the use of increasing amounts
of energy from the unit so that the Company may be entitled to
use all of the unit's output 15 years from that date. The 1998
option for 10.17 MW was not exercised by the Company and has
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.
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(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.
(4) This includes additional capacity of 87 MW expected to be
available in April 1994, due to conversion from simple cycle
combustion turbine to combined cycle operation.
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.
The peak electric demand experienced by the Company was 2,681
megawatts on August 2, 1993. This demand plus a reserve margin was served
by a combination of Company owned generation, and firm and short-term power
purchases.
For 1994, the Company has contracts to purchase power from an
independent power producer (IPP) and four qualifying facilities (QF), also
known as cogenerators, as follows:
Contract Term
--------------------- Net Capacity
From To (Megawatts)
-------- -------- ------------
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 06/01/94(1) 05/31/24 45
---
515
===
(1) Expected operation date.
The Company's total generating capacity of 2,628 megawatts, including
235 megawatts of Hoover Dam power, 210 megawatts of IPP power and 305
megawatts of QF power, for the summer of 1994 will not be sufficient to
meet the 1994 anticipated peak load demand and reserve margin needs.
Accordingly, the Company has agreements with other utilities to purchase
465 megawatts of firm capacity and associated energy and plans to enter
into agreements for an estimated additional 100 megawatts of firm capacity
and associated energy for the months of June, July and August 1994.
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 1993
and anticipated sources of fuel for generation in 1994 and 1995.
1993 1994 1995
---- ---- ----
Coal........................ 93% 93% 93%
Natural Gas................. 7 7 7
--- --- ---
100% 100% 100%
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The Company's average delivered cost per ton of coal burned was as
follows: 1991 - $32.78; 1992 - $34.54; 1993 - $34.43.
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.
The anticipated full requirements for coal at the Reid Gardner
Generating Station are covered by contracts through 1994. Partial
requirements for coal are presently under contract through the year 2007.
The Company anticipates no major difficulties in purchasing the remainder
of its coal requirements based upon current coal market conditions in the
Western United States. All coal for Reid Gardner presently comes from
underground mines in Utah and Colorado.
All of the Company's long-term coal supply contracts contain
provisions providing for adjustments in the price of coal to reflect
increases or decreases in the costs of mining operations.
The Company's natural gas supply is subject to curtailment due to
limited pipeline capacity. All the Company's plants using natural gas also
have the capability of burning oil on a sustained basis.
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, 1993
amounted to $880,969,000 and $50,047,000 respectively.
The following table sets forth the Company's actual construction
expenditures for 1993, and currently estimated construction expenditures,
including Allowance for Funds Used During Construction, for 1994 and 1995.
1993 1994 1995
-------- -------- --------
(In Thousands)
Generating Facilities............ $ 74,456 $ 65,026 $ 62,769
Transmission Facilities.......... 10,112 28,812 35,724
Distribution Facilities.......... 72,865 71,160 66,017
Other............................ 15,704 9,890 10,000
-------- -------- --------
$173,137 $174,888 $174,510
======== ======== ========
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.
To meet capital expenditure requirements through 1995, the Company
will utilize internally generated cash, the proceeds from industrial
development revenue bonds, first mortgage bonds, and common stock issues
through public offerings and the Stock Purchase and Dividend Reinvestment
Plan (SPP).
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The Company has the option of issuing new shares or using open market
purchases of its common stock to meet the requirements of the SPP. The
Company issued 1,640,326 shares of its common stock in 1993 under the SPP.
At the end of 1993, common equity represented 46.0% of total
capitalization. The Company sold 2.7 million shares of common stock for
net proceeds of $65.7 million through an underwritten public offering in
1993. The net proceeds were used to reduce short-term debt which was
incurred primarily to construct necessary plant facilities.
On January 13, 1993, the Company sold $45 million of First Mortgage
Bonds, Series Z, through a public offering. The bonds will mature in 2023
and will require interest payments due on January 1 and July 1 at the
annual rate of 8.50%. Net proceeds from the sale of the bonds were used
for the redemption of the Company's 9.375% Series S on February 15, 1993.
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, 1993 and assuming an 8 1/2 percent interest rate on
new bonds, the Company would be able to issue approximately $379 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, 1993,
this test would permit the issuance of $371 million of additional preferred
stock at a dividend rate of 8 1/2 percent.
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
5.4 percent, 4.6 percent, and 5.3 percent in 1993, 1992, and 1991,
respectively.
The peak demand for electricity by the Company's customers increased
from 2,501 megawatts in 1992 to 2,681 megawatts in 1993. The Company's
1993 energy sales reached 11,155,270 megawatthours, an increase of 5.8
percent over 1992.
Every three years Nevada law requires the Company to file with the
Public Service Commission of Nevada (PSC) a forecast of electricity demands
for the next 20 years and the Company's plans to meet those demands. On
September 16, 1991, the PSC approved the Company's 1991 Resource Plan, and
during 1992 and 1993, the PSC approved the first through fourth amendments
to the Resource Plan. The Resource Plan, as amended and approved in 1992
and 1993, includes the following major projects:
(1) two 90 megawatt (MW) combined-cycle generating units at
the Clark Generating Station, one added in 1993 and one
to be added in 1994;
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(2) the construction of two 70 (MW) combustion turbine
generating units at the Harry Allen Project site, one
unit in 1995 and one unit in 1996. The 1996 Allen
combustion turbine will be subject to a cost comparison
of purchased power resources that will be competitively
bid with the least expensive resource taken as the
Company's supply choice;
(3) a total of 305 (MW) in purchased power from four
qualifying facilities, with 175 (MW) and 85 (MW)
received beginning in 1992 and 1993, respectively, and
45 (MW) expected to be received beginning in 1994;
(4) planning costs for a 500 kilovolt (KV) transmission
system from the Harry Allen Substation, located north of
the Las Vegas Valley, to Marketplace, a future 500 KV
switching station located near the McCullough Substation
south of the Las Vegas Valley. The Company must present
final plans on this system for PSC approval. If PSC
approval is received, the transmission system could be
operational by 1998;
(5) installation of additional emissions reduction equipment
at the Navajo Generating Station;
(6) firm purchased power of 75 (MW);
(7) the construction of a 230 KV transmission line from
Arden Substation, located southwest of Las Vegas, to
Northwest Substation, located northwest of Las Vegas;
and
(8) several demand-side pilot projects.
On September 29, 1993, a fifth amendment to the Company's 20-year
Resource Plan was filed with the PSC. On February 25, 1994, the PSC
approved a stipulation among the Company, PSC Staff, Office of the Consumer
Advocate and other intervenors granting the Company's request. The
amendment calls for three purchase power contracts with Southern California
Edison, the City of Glendale and the Salt River Project totaling 160 MWs
for the years 1996 to 2000. These purchase power contracts are a result of
the Company's 1996 Request for Proposal for supply-side resources. The
stipulation also approved a 50 (MW) purchase power contract with Arizona
Public Service for the years 1995 to 1997.
The Company will file its 1994 Resource Plan on July 1, 1994. As part
of the plan, the Company anticipates a portion of the supply-side resources
and demand-side programs to be obtained through a Request For Proposal
process.
REGULATION AND RATES
The Company is subject to regulation by the PSC which has regulatory
powers with respect to rates, facilities, services, reports, issuance of
securities and other matters.
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Following is a summary of the rate increases or decreases that have
been granted the Company during the past three years.
Amount in
Effective Millions
Date Nature of Increase (Decrease) of Dollars
------------- ------------------------------ ----------
Jan. 1, 1991 Energy rate increase 24.4
March 4, 1991 Energy and resource plan
rate increase 1.0
Nov. 12, 1991 General rate increase 12.2
Energy rate increase 11.4
July 27, 1992 General rate increase 22.2
Energy and resource plan
net rate decrease (26.4)
June 28, 1993 Energy and resource plan
net rate increase 42.1
All amounts are on an annual basis.
In 1985, the Company incurred $15.8 million in increased fuel and
purchased power expenses after a ruptured steam line at the jointly owned
Mohave Generating Station resulted in a loss of the plant for six months.
The PSC allowed the Company to recover one half of the increased expenses
subject to refund. Fourth quarter 1990 earnings reflected a $12.9 million
charge to record a subsequent proposed order issued by the PSC which stated
that the Company shall not recover any of the increased costs. The Company
has fully reserved for any negative financial effect related to the
proposed order. In 1991, the PSC set aside the proposed order and ordered
the parties to participate in joint hearings before the California Public
Utilities Commission (CPUC). The CPUC hearings are now concluded, and the
PSC will prepare its own opinion based on the record created in the CPUC
hearings. In January 1994, the administrative law judge in the CPUC
proceeding issued a proposed opinion denying recovery to Southern
California Edison (SCE) of its incremental purchased power costs resulting
from the accident. SCE has filed comments with the CPUC concerning the
proposed decision.
On August 12, 1993, the Company filed a request with the PSC to
recover additional fuel and purchased power costs of $29.7 million under
the state's deferred energy accounting procedures. This request included
$9.8 million of deferred energy costs for the period of December 1, 1992,
to May 31, 1993, and $19.9 million to adjust the base energy rate. The
Company subsequently amended its request to $26.8 million. Hearings in
this matter were concluded in December 1993, and the PSC granted an
increase in rates of $23.6 million, effective February 1, 1994. The PSC
order resulted in fourth quarter 1993 charges of $2 million net of taxes
for deferred energy costs.
On November 19, 1993, the PSC Staff filed a petition with the PSC
alleging that the Company may be overearning as much as $17 million
annually because business conditions have changed substantially since the
Company received its last general rate case decision in July 1992. On
January 10, 1994, the PSC voted to open an investigation into the Company's
earnings. Management believes the Company's earnings are within the
authorized rate of return granted to the Company in July 1992. Hearings on
this proceeding are scheduled to commence in June 1994.
On February 28, 1994, the Company filed requests with the PSC to
recover additional fuel and purchased power costs of $38.5 million and
resource planning costs of $1 million. The energy rate request included
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$28.7 million of deferred energy costs for the test period ended November
30, 1993, and $9.8 million to adjust the base energy rate.
As permitted by state statute, the Company defers differences between
the current cost of fuel and purchased power, and base energy costs as
defined. Under regulations adopted by the PSC, the balance in the 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. PSC 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, however, recovery will have no effect on the
Company's earnings.
The Company is allowed to recover on an annual basis the costs of
developing its 20-year resource plan. Also, by an order of the PSC 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. Management believes environmental
expenditures will increase over time and the increased costs will also be
recovered as necessary utility expenses. A discussion of pending
environmental matters is provided below.
The Federal Clean Air Act Amendments of 1990 include provisions which
will affect the Company's existing steam generating facilities and all new
fossil fuel fired facilities. Title IV of the Amendments provides a
national cap on sulfur dioxide emissions by mandating emissions reductions
for many electric steam generating facilities. The sulfur dioxide
provisions of the Amendments will not adversely affect the Company because
the Company's steam units burn low sulfur fuels or have sulfur dioxide
control equipment. Title IV of the Amendments also provides for reduction
of emissions of oxides of nitrogen by establishing new emission limits for
coal-fired generating units. This Title 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. Other provisions of the Amendments will require the
Company to install or upgrade Continuous Emission Monitoring systems at all
steam generating units before 1995, at an expected cost of up to $3.3
million.
The United States Congress authorized $2 million for the Environmental
Protection Agency (EPA) to study the potential impact the Mohave Generating
Station (MGS) may have on visibility in the Grand Canyon. The EPA report
is expected to be finalized in late 1995, with a follow-up report from the
Grand Canyon Visibility Transport Commission in late 1996. Also, the
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Nevada Division of Environmental Protection has imposed more stringent
stack opacity limits for the MGS. This change may affect the Company's
utilization of resources, but, until more experience is gained by operating
at the new opacity levels, any effect cannot be determined. As a 14
percent owner of the MGS, the Company will be required to fund any plant
improvements that may result from the EPA study and operation at the new
opacity levels. The cost of any potential improvements cannot be estimated
at this time.
In 1991, the U.S. Environmental Protection Agency published an order
requiring the Navajo Generating Station (NGS) to install scrubbers to
remove 90 percent of sulfur dioxide beginning in 1997. As an 11.3 percent
owner of the NGS, the Company will be required to fund an estimated $46.6
million for installation of the scrubbers. In 1992, the Company received
resource planning approval from the PSC for its share of the cost of the
scrubbers up to $46.6 million.
COMPETITION
Deregulation of the electric utility industry is accelerating with the
enactment of the National Energy Policy Act of 1992 (Act). Deregulation
will lead to further competition in the industry as generators of power
obtain greater access to transmission facilities linking them to potential
new customers. Most observers believe the electric utility beneficiaries
of the Act will be twofold; those who can provide low cost generation for
sale and those who have strategically located transmission highways that
can transmit low cost power from one area to another.
Within the region the Company's residential rates are competitive.
However, large industrial customer rates may require adjustment to remain
competitive in the changing environment. In recognition of the changing
regional competitive environment, the Company is focusing on the costs of
serving various classes of customers and the appropriate rates to be
charged based on those costs of service. The Company will seek through the
PSC any rate adjustments necessary to maintain a competitive position.
An opportunity exists given the Company's strategic location in the
center of a region of price diversity. As generators arrange for sales of
electricity to customers in other areas, some of the power may need to be
transmitted through the Company's service territory. The Company would
have an opportunity to charge the generators for the transmission of energy
through its system. The Company is studying the feasibility of
constructing additional cost effective transmission facilities to maximize
the advantage of its strategic location.
In September 1993, as a part of a comprehensive organizational study,
the Company offered a voluntary early retirement package to 175 employees
who would be at least 55 years of age, and have completed at least 10 years
of service by March 31, 1994. A total of 109 employees, or approximately 6
percent of the work force, accepted the package. In October 1993, the
Company's Board of Directors unanimously approved a new organization
structure that realigns functions to improve operations and customer
service. The Company expects that the net result from the change in
organizational structure will be a leaner work force that operates more
efficiently and makes the Company more competitive in a changing electric
energy industry. At December 31, 1993, organizational study, early
retirement and severance costs of $6.7 million are included in other
deferred charges.
EMPLOYEES
The Company had 1,741 active employees at December 31, 1993.
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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 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 39-mile, 230
kilovolt lines transmit 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. In addition to the above, the Company
has 263 miles of 138 kilovolt and 483 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 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 100 percent of the 69 miles of the 345 kilovolt line from Harry
Allen Substation to the Nevada-Utah border; PacifiCorp owns 100 percent of
the 345 kilovolt line portion from the Nevada-Utah border to Red Butte
Substation.
At December 31, 1993, the Company owned 98 transmission and
distribution substations with a total installed transformer capacity of
10,186,441 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 and the Reid Gardner
Unit No. 4 Substation with installed capacity of 318,000 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, 1993, there were approximately 3,029 miles of pole
line together with approximately 5,609 cable miles of underground in the
Company's distribution system with a total installed distribution
transformer capacity of 5,160,941 kilovolt-amperes.
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ITEM 3. LEGAL PROCEEDINGS
SUSPENDED DELIVERIES UNDER MOUNTAIN COAL COMPANY CONTRACT
In December 1992, the Company suspended deliveries under a coal
contract with Mountain Coal Co. based on a pricing dispute. Mountain Coal
Co. filed a lawsuit in the federal district court for the State of Utah
seeking a determination that the Company had repudiated the coal supply
agreement. In October 1993, the court found in favor of Mountain Coal
Co.'s position. The Company appealed the court's order, however, in March
1994, the Company resolved the litigation and bought out the remaining
obligation under the contract by issuing a promissory note (bearing
interest at 10%) for a total of $25 million. The facility using the coal
under this contract is jointly owned; accordingly, the Company's portion of
this settlement is $15.25 million. The settlement and buyout have been
recorded as of December 31, 1993, with $25 million included in notes
payable, $15.25 million included in deferred energy costs and $9.75 million
included in other receivables. The settlement and buyout will result in
lower fuel costs to the Company's customers over the otherwise remaining
life of the contract; accordingly, based on similar past buyouts,
management believes that the cost of the buyout will be recovered through
Nevada's deferred energy accounting procedures.
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ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matter was submitted to a vote of security holders during the
fourth quarter of the fiscal year covered by this report, through the
solicitation of proxies or otherwise.
SUPPLEMENTAL ITEM. EXECUTIVE OFFICERS OF REGISTRANT
The Company's executive officers are as follows:
Age as of
Name December 31, 1993 Position
---- ----------------- --------
Charles A. Lenzie 56 Chairman of the Board and Chief
Executive Officer
James C. Holcombe 48 President and Chief Operating
Officer
David G. Barneby 48 Vice President, Power Delivery
Cynthia K. Gilliam 45 Vice President, Retail Customer
Operations
Richard L. Hinckley 38 Vice President, Secretary and
General Counsel
Steven W. Rigazio 39 Vice President, Finance and
Planning, Treasurer, Chief
Financial Officer
Gloria T. Banks Weddle 44 Vice President, Human Resources and
Corporate Services
Each of the executive officers has been actively engaged in the
business of the Company for more than five years.
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.
James C. Holcombe joined the Company as Executive Vice President on
March 1, 1989 and was elected President and Chief Operating Officer on May
1, 1989. Prior to joining the Company he was Vice President of Resource
Development for San Diego Gas and Electric Company.
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.
Cynthia K. Gilliam was elected Vice President - Retail Customer
Operations effective October 14, 1993. 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 l988 and
her title was changed to Vice President - Human Resources in l989. In
1992, she was elected Vice President - Customer Service.
Richard L. Hinckley was elected Vice President, Secretary and General
Counsel effective October 14, 1993. He joined the Company as Staff Counsel
in l985; was promoted to Assistant Secretary and Chief Counsel in 1989 and
elected Vice President, Chief Counsel and secretary in 1991. Prior to
11
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joining the Company, he served as Staff Attorney with the Nevada Public
Service Commission 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 l984 as a Rates Administrator and was promoted to Supervisor
of Rates and Regulations in l985, Manager of Rates and Regulatory Affairs
in l986, Director of System Planning in l990, Vice President - Planning in
1991 and Vice President and Treasurer, Chief Financial Officer in 1992.
Gloria T. Banks Weddle was elected Vice President - Human Resources
and Corporate Services effective October 14, 1993. 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.
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 1992 and 1991 are
hereby incorporated by reference from page 43 of the Company's Annual
Report to Shareholders for the year ended December 31, 1993, which is filed
herewith as Exhibit 13.
ITEM 6. SELECTED FINANCIAL DATA
The information required by Item 6 is hereby incorporated by reference
from pages 44 to 45 of the Company's Annual Report to Shareholders for the
year ended December 31, 1993, which is filed herewith as Exhibit 13.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATION
The information required by Item 7 is hereby incorporated by reference
from pages 16 to 21 of the Company's Annual Report to Shareholders for the
year ended December 31, 1993, which are filed herewith as Exhibit 13.
12
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The Company's financial statements for the years ended December 31,
1993, 1992 and 1991 together with the auditors' report thereon required by
Item 8 are incorporated by reference from the following pages of the
Company's Annual Report to Shareholders for the year ended December 31,
1993, which are filed herewith as Exhibit 13.
Annual
Report
Page
------
Statements of Income for the Years Ended
December 31, 1993, 1992 and 1991...................... 22
Statements of Retained Earnings for the Years
Ended December 31, 1993, 1992 and 1991................ 23
Balance Sheets - December 31, 1993 and 1992............ 24-25
Schedules of Capitalization -
December 31, 1993 and 1992............................ 26-27
Schedules of Long-Term Debt -
December 31, 1993 and 1992............................ 28-29
Statements of Cash Flows for the Years Ended
December 31, 1993, 1992 and 1991...................... 30
Notes to Financial Statements.......................... 31-41
Independent Auditors' Report........................... 42
Report of Management................................... 42
See Note 10 of Notes to 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.
Financial statements and supplemental schedules of the Company's
subsidiaries are omitted since their aggregate total assets, sales and
revenues, and income before income taxes are not material in relation to
the Company's total assets, sales and revenues, and income before income
taxes.
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 financial statements, December
31, 1993, 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 other
information required by Item 10 is hereby incorporated by reference from
the Company's definitive Proxy Statement dated March 14, 1994 and
heretofore filed with the Securities and Exchange Commission ("SEC"). (See
the heading therein "Election of Directors".)
13
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<PAGE>
ITEM 11. EXECUTIVE COMPENSATION
The information required by Item 11 is hereby incorporated by
reference from the Company's definitive Proxy Statement dated March 14,
1994 and heretofore filed with the SEC. (See the heading therein
"Executive Compensation".)
ITEM 12. SECURITY OWNERSHIP OF CERTAIN
BENEFICIAL OWNERS AND MANAGEMENT
The information required by Item 12 is hereby incorporated by
reference from the Company's definitive Proxy Statement dated March 14,
1994 and heretofore filed with the SEC. (See the heading therein "Security
Ownership of Management".)
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.
14
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<PAGE>
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
AND REPORTS ON FORM 8-K
The Company's financial statements for the years ended December 31,
1993, 1992 and 1991 together with the auditors' report appearing on pages
22 to 42 of Nevada Power Company's 1993 Annual Report to Shareholders are
incorporated herein by reference and filed as Exhibit 13.
FINANCIAL STATEMENT SCHEDULES FOR THE
YEARS ENDED DECEMBER 31, 1993, 1992, and 1991 PAGE
- -------------------------------------------------------------------------
Independent Auditors' Consent and Report on Schedules............. 24
Schedule V - Electric Plant....................................... 25-27
Schedule VI - Accumulated Depreciation............................ 25-27
Schedule VIII - Valuation and Qualifying Accounts................. 28
All other schedules and financial statements of subsidiaries not
consolidated are omitted because they are not applicable, not required, or
because the information is included in the financial statements or notes
thereto.
EXHIBITS FILED DESCRIPTION
- -------------- -----------
13 Pages 16 to 45 of Nevada Power Company's Annual Report to
Shareholders for the Year Ended December 31, 1993
(incorporated by reference in Parts II and IV hereof).
10.69 Long-Term Incentive Plan dated as of January 1, 1993.
10.70 Contract for Long-Term Power Purchases from Qualifying
Facilities dated May 27, 1992 between Las Vegas
Co-generation, Inc. and Nevada Power Company,
Replaces Exhibit 10.50.
10.71 Settlement Agreement and Promissory Note between Mountain
Coal Company and Atlantic Richfield Company and Nevada Power
Company dated March 9, 1994.
15
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<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:
EXHIBIT ORIGINALLY FILED
NO. DESCRIPTION AS EXHIBIT FILE NO.
- ------- ----------- ---------------- --------
3.1 Bylaws, as amended February 9, 1984 3 to Form 10-K 1-4698
Year 1983
3.2 Restated Bylaws, as amended
May 13, 1988 4.8 to Form S-3 33-33545
January 10, 1991 3.2 to Form 10-K 1-4698
Year 1990
3.3 Restated Articles of Incorporation, 2.2 to Form S-7 2-65097
filed November 7, 1978
3.4 Amendment to Restated Articles of 2.3 to Form S-16 2-67853
Incorporation, filed May 19, 1980
3.5 Amendment to Restated Articles of 3.4 to Form 10-K 1-4698
Incorporation filed May 31, 1983 Year 1983
3.6 Amendment to Restated Articles of 4.4 to Form S-3 33-4567
Incorporation, filed May 12, 1986
3.7 Amendment to Restated Articles of 4.6 to Form S-3 33-15554
Incorporation, filed May 12, 1987
3.8 Amendment to Restated Articles of 3.7 to Form 10-K 1-4698
Incorporation filed June 10, 1988 Year 1988
3.9 Restated Articles of Incorporation 3.8 to Form 10-K 1-4698
filed June 10, 1988 Year 1988
3.10 Amendment to Restated Articles of 4.7 to Form S-8 33-32372
Incorporation filed May 23, 1989.
3.11 Amendment to Restated Articles of 4.8 to Form S-3 33-55698
Incorporation filed June 8, 1992.
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 14, 1991 4.9 to Form S-3 33-44460
Auction Series A as amended
December 12, 1991 4.1 to Form 10-K 1-4698
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
Nineteen Supplemental Indentures
as follows:
First Supplemental Indenture, 4.2 to Form S-1 2-11440
dated August 1, 1954
Second Supplemental Indenture, 4.9 to Form S-1 2-12566
dated September 1, 1956
Third Supplemental Indenture, 4.13 to Form S-1 2-14949
dated May 1, 1959
16
<PAGE>
<PAGE>
EXHIBIT ORIGINALLY FILED
NO. DESCRIPTION AS EXHIBIT FILE NO.
- ------- ----------- ---------------- --------
Fourth Supplemental Indenture, 4.5 to Form S-1 2-16968
dated October 1, 1960
Fifth Supplemental Indenture, 4.6 to Form S-16 2-74929
dated December 1, 1961
Sixth Supplemental Indenture, 4.6A to Form S-1 2-21689
dated October 1, 1963
Seventh Supplemental Indenture, 4.6B to Form S-1 2-22560
dated August 1, 1964
Eighth Supplemental Indenture, 4.6C to Form S-9 2-28348
dated April 1, 1968
Ninth Supplemental Indenture, 4.6D to Form S-1 2-34588
dated October 1, 1969
Tenth Supplemental Indenture, 4.6E to Form S-7 2-38314
dated 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 4.14 to Form S-16 2-74929
Indenture, dated October 1,
1976
Fourteenth Supplemental 4.15 to Form S-16 2-74929
Indenture, dated May 1, 1977
Fifteenth Supplemental 4.16 to Form S-16 2-74929
Indenture dated September 1,
1978
Sixteenth Supplemental Indenture, 4.17 to Form S-16 2-74929
dated December 1, 1981
Seventeenth Supplemental 4.2 to Form 10-K 1-4698
Indenture, 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 4.22 to Form S-3 33-53034
Indenture, dated June 1, 1992
Twenty-Second Supplemental 4.23 to Form S-3 33-53034
Indenture, dated June 1, 1992
Twenty-Third Supplemental 4.23 to Form S-3 33-53034
Indenture, dated October 1, 1992
Twenty-Fourth Supplemental 4.23 to Form S-3 33-53034
Indenture, dated October 1, 1992
Twenty-Fifth Supplemental 4.23 to Form S-3 33-53034
Indenture, dated January 1, 1993
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
17
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EXHIBIT ORIGINALLY FILED
NO. DESCRIPTION AS EXHIBIT FILE NO.
- ------- ----------- ---------------- --------
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
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
Southern California Edison
Company
10.7 Eldorado System Conveyance and 13.30 to Form S-9 2-28348
Co-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
18
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<PAGE>
EXHIBIT ORIGINALLY FILED
NO. DESCRIPTION AS EXHIBIT FILE NO.
- ------- ----------- ---------------- --------
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 5.37 to Form 8-K 1-4698
March 1, 1974 between Nevada Power April 1974
Company, Lessor, and Clark County,
Nevada, Lessee
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 April 1974
Power Company and Commerce
Union Bank as Trustee
10.17 Navajo Project Co-tenancy 5.31 to Form 8-K 1-4698
Agreement dated March 23, 1976 April 1974
between the 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
19
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EXHIBIT ORIGINALLY FILED
NO. DESCRIPTION AS EXHIBIT FILE NO.
- ------- ----------- ---------------- --------
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 5.37 to Form S-7 2-62509
March 1, 1980 between the
Company and Beaver Creek
Coal Company
10.24 Coal Supply Agreement dated 5.38 to Form S-7 2-62509
March 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 10.26 to Form 10-K 1-4698
August 31, 1982 between Year 1982
the Company and 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
10.30 Memorandum of Understanding 10.30 to Form 10-K 1-4698
Concerning Interconnection Year 1983
between 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 Year 1983
Nevada Power Company as Lessee,
dated January 11, 1984 for
lease of administrative
headquarters
20
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EXHIBIT ORIGINALLY FILED
NO. DESCRIPTION AS EXHIBIT FILE NO.
- ------- ----------- ---------------- --------
10.32 Participation Agreement between 10.32 to Form 10-K 1-4698
Utah Power & Light Company and Year 1985
the Company dated December 19,
1985
10.33 Sale and Purchase Agreement dated 10.33 to Form 10-K 1-4698
as of December 23, 1985 by and Year 1985
between Nevada Power Company and
CP National Corporation
10.34 Restated Coal Sales Agreement as 10.34 to Form 10-K 1-4698
of July 1, 1985 by and between Year 1985
Nevada 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 10.38 to Form 10-K 1-4698
as of December 1, 1985 between Year 1986
The Fuji 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 Year 1987
Nevada and the Company, dated
July 8, 1987
10.40 Power Sales Agreement between 10.40 to Form 10-K 1-4698
Utah Power & Light Company and Year 1987
the Company, dated August 17,
1987
10.41 Transmission Facilities Agreement 10.41 to Form 10-K 1-4698
between Utah Power & Light Year 1987
Company 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 10.43 to Form 10-K 1-4698
as of November 1, 1988 between Year 1988
The Fuji Bank, Limited and
Nevada Power Company
10.44 401(k) Savings Plan 28.1 to Form S-8 33-32372
10.45 Power Purchase Contract dated 10.45 to Form 10-K 1-4698
February 15, 1990 between Year 1989
Mission Energy Company and
Nevada Power
Company
21
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EXHIBIT ORIGINALLY FILED
NO. DESCRIPTION AS EXHIBIT FILE NO.
- ------- ----------- ---------------- --------
10.46 Contact 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
10.47 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
10.48 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
10.49 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
10.50 Contract for Long-Term Power 10.50 to Form 10-K 1-4698
Purchases from Qualified Year 1989
Facilities dated February 12,
1990 between Las Vegas
Co-generation, Inc. and Nevada
Power Company
10.51 Agreement for Transmission 10.51 to Form 10-K 1-4698
Service dated March 29, 1989 Year 1989
between Overton Power District
No. 5 , Lincoln County Power
District No. 1 and Nevada Power
Company
10.52 Contract dated June 30, 1988 10.52 to Form 10-K 1-4698
between United States Department Year 1989
of Energy Western Area Power
Administration and Nevada Power
Company
10.53 Executive Performance Incentive 10.53 to Form 10-K 1-4698
Plan dated as of January 1, 1989 Year 1989
10.54 Severance Allowance Plan 10.54 to Form 10-K 1-4698
adopted September 14, 1989 Year 1989
10.55 Power Purchase Contract dated 10.55 to Form 10-K 1-4698
July 5, 1990 between Year 1990
Mission Energy Company and
Nevada Power Company
10.56 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
10.57 Amendment dated June 15, 1989 to 10.57 to Form 10-K 1-4698
Exhibit 10.46 Year 1990
22
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EXHIBIT ORIGINALLY FILED
NO. DESCRIPTION AS EXHIBIT FILE NO.
- ------- ----------- ---------------- --------
10.58 Amendment dated August 23, 1989 10.58 to Form 10-K 1-4698
to Exhibit 10.46 Year 1990
10.59 Amendment dated April 23, 1990 10.59 to Form 10-K 1-4698
to Exhibit 10.46 Year 1990
10.60 Exhibit H dated August 13, 1990 10.60 to Form 10-K 1-4698
to Exhibit 10.46 Year 1990
10.61 Western Systems Power Pool 10.61 to Form 10-K 1-4698
Agreement (Agreement) dated Year 1990
January 2, 1991 between
thirty-nine other Western
Systems Power Pool members as
listed on pages 1 and 2 of the
Agreement and Nevada Power
Company
10.62 Financing Agreement between Clark 10.62 to Form 10-K 1-4698
County, Nevada and Nevada Power Year 1990
Company dated June 1, 1990
10.63 Restated Power Sales Agreement 10.63 to Form 10-K 1-4698
dated March 25, 1991 between Year 1991
Pacificorp and Nevada Power
Company
10.64 Amendment dated July 17, 1990 to 10.64 to Form 10-K 1-4698
Exhibit 10.55 Year 1991
10.65 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)
10.66 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)
10.67 Financing Agreement between Clark 10.67 to Form 10-K 1-4698
County, Nevada and Nevada Power Year 1992
Company dated October 1, 1992
10.68 Power Sales Agreement dated 10.68 to Form 10-K 1-4698
October 19, 1992 Between the Year 1992
Department of Water and Power
of the City of Los Angeles
and Nevada Power Company
REPORTS ON FORM 8-K
The Company filed no current report on Form 8-K during the quarter
ended December 31, 1993.
23
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INDEPENDENT AUDITORS' CONSENT AND REPORT ON SCHEDULES
We consent to the incorporation by reference in Registration Statement
No. 33-18622 on Form S-3 and in Registration Statement No. 33-15554 on Form
S-3 of Nevada Power Company of our report dated February 10, 1994 (March
11, 1994 as to the fourth paragragh of Note 7) (which expresses an
unqualified opinion and includes an explanatory paragraph relating to the
Company's change in method of accounting for income taxes to conform with
Statement of Financial Accounting Standards No. 109) incorporated by
reference in this Annual Report on Form 10-K of Nevada Power Company for
the year ended December 31, 1993.
Our audits of the financial statements referred to in our
aforementioned report also included the financial statement schedules of
Nevada Power Company, listed in Item 14. These financial statement
schedules are the responsibility of Nevada Power Company's management. Our
responsibility is to express an opinion based on our audits. In our
opinion, such financial statement schedules, when considered in relation to
the basic financial statements taken as a whole, present fairly in all
material respects the information set forth therein.
DELOITTE & TOUCHE
DELOITTE & TOUCHE
Las Vegas, Nevada
March 28, 1994
24
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NEVADA POWER COMPANY
SCHEDULE V - ELECTRIC PLANT
FOR THE YEAR ENDED DECEMBER 31, 1993
(IN THOUSANDS OF DOLLARS)
Balance at Balance at
Beginning Additions Retirements End of
of Period At Cost (1) and Other Period
---------- ----------- ----------- ----------
Production............$ 588,492 $ 93,859 $ (824) $ 681,527
Transmission.......... 263,807 13,869 (133) 277,543
Distribution.......... 536,644 61,923 (3,693) 594,874
General............... 77,402 7,927 (713) 84,616
Construction work-in-
progress............. 172,093 (4,441) -- 167,652
Property under capital
lease................ 96,753 -- (5,236) 91,517
Plant held for future
use.................. 4,442 -- (723) 3,719
---------- ----------- ----------- ----------
$1,739,633 $ 173,137 $ (11,322) $1,901,448
========== =========== =========== ==========
SCHEDULE VI - ACCUMULATED DEPRECIATION
FOR THE YEAR ENDED DECEMBER 31, 1993
(IN THOUSANDS OF DOLLARS)
Balance at Salvage, Less Balance at
Beginning Cost of End of
of Period Provisions(2) Removal Retirements Period
---------- ----------- ---------- --------- ---------
Production...$ 250,545 $ 19,919 $ (87) $ (823) $ 269,554
Transmission. 50,030 6,658 (108) (133) 56,447
Distribution. 98,355 14,817 121 (2,717) 110,576
General...... 12,755 3,104 74 (713) 15,220
Retirement work-
in-progress. (722) -- 227 -- (495)
---------- ----------- ---------- --------- ---------
$ 410,963 $ 44,498 $ 227 $ (4,386) $ 451,302
========== =========== ========== ========= =========
______________
(1) Additions include Allowance for Funds Used During Construction
capitalized in the amount of $9,880,000.
(2) Provisions include $43,341,000 charged to income and $1,157,000
charged to other accounts. The depreciation provision on the
statement of income includes additional amounts for amortization of
the electric plant acquisition adjustments in the amount of $17,000.
25
<PAGE>
<PAGE>
NEVADA POWER COMPANY
SCHEDULE V - ELECTRIC PLANT
FOR THE YEAR ENDED DECEMBER 31, 1992
(IN THOUSANDS OF DOLLARS)
Balance at Balance at
Beginning Additions Retirements End of
of Period At Cost (1) and Other Period
---------- ----------- ----------- ----------
Production............$ 577,565 $ 12,222 $ (1,295) $ 588,492
Transmission.......... 235,282 28,719 (194) 263,807
Distribution.......... 460,406 66,383 9,855 (2) 536,644
General............... 70,917 8,913 (2,428) 77,402
Construction work-in-
progress............. 112,257 62,382 (2,546)(3) 172,093
Property under capital
lease................ 96,358 -- 395 96,753
Plant held for future
use.................. 9,706 -- (5,264)(4) 4,442
---------- ----------- ----------- ----------
$1,562,491 $ 178,619 $ (1,477) $1,739,633
========== =========== =========== ==========
SCHEDULE VI - ACCUMULATED DEPRECIATION
FOR THE YEAR ENDED DECEMBER 31, 1992
(IN THOUSANDS OF DOLLARS)
Balance at Salvage, Less Balance at
Beginning Cost of End of
of Period Provisions(5) Removal Retirements Period
---------- ----------- ---------- --------- ---------
Production...$ 233,539 $ 18,190 $ 111 $ (1,295) $ 250,545
Transmission. 44,151 6,102 (40) (183) 50,030
Distribution. 86,574 14,925 266 (3,410) 98,355
General...... 12,229 2,910 44 (2,428) 12,755
Retirement work-
in-progress. (726) -- 4 -- (722)
---------- ----------- ---------- --------- ---------
$ 375,767 $ 42,127 $ 385 $ (7,316) $ 410,963
========== =========== ========== ========= =========
______________
(1) Additions include Allowance for Funds Used During Construction
capitalized in the amount of $7,544,000.
(2) Included in retirements and other is $13,567,000 for AFUDC on
Industrial Development Revenue Bond Trust Fund balances reclassified
from other deferred charges.
(3) Included in retirements and other is $2,546,000 for costs related to a
property loss at Reid Gardner Generating Station No. 4 which were
reclassified to other deferred charges.
(4) Included in retirements and other is $5,794,000 reclassified as
property under capital lease.
(5) Provisions include $39,433,000 charged to income and $2,694,000
charged to other accounts. The depreciation provision on the
statement of income includes additional amounts for amortization of
the electric plant acquisition adjustments in the amount of $18,000.
26
<PAGE>
<PAGE>
NEVADA POWER COMPANY
SCHEDULE V - ELECTRIC PLANT
FOR THE YEAR ENDED DECEMBER 31, 1991
(IN THOUSANDS OF DOLLARS)
Balance at Balance at
Beginning Additions Retirements End of
of Period At Cost (1) and Other Period
---------- ----------- ----------- ----------
Production............$ 562,858 $ 20,347 $ (5,640) $ 577,565
Transmission.......... 217,852 18,214 (784) 235,282
Distribution.......... 400,869 76,386 (16,849)(2) 460,406
General............... 63,597 8,013 (693) 70,917
Construction work-in-
progress............. 75,946 30,992 5,319 (3) 112,257
Property under capital
lease................ 18,199 83,000 (5) (4,841) 96,358
Plant held for future
use.................. 5,786 3,188 732 (4) 9,706
---------- ----------- ----------- ----------
$1,345,107 $ 240,140 $ (22,756) $1,562,491
========== =========== =========== ==========
SCHEDULE VI - ACCUMULATED DEPRECIATION
FOR THE YEAR ENDED DECEMBER 31, 1991
(IN THOUSANDS OF DOLLARS)
Balance at Salvage, Less Balance at
Beginning Cost of End of
of Period Provisions(6) Removal Retirements Period
---------- ----------- ---------- --------- ---------
Production...$ 217,606 $ 19,807 $ 1,766 $ (5,640) $ 233,539
Transmission. 39,999 5,001 (65) (784) 44,151
Distribution. 80,618 9,084 152 (3,280) 86,574
General...... 10,633 2,151 38 (593) 12,229
Retirement work-
in-progress. (634) -- (92) -- (726)
---------- ----------- ---------- --------- ---------
$ 348,222 $ 36,043 $ 1,799 $ (10,297) $ 375,767
========== =========== ========== ========= =========
______________
(1) Additions include Allowance for Funds Used During Construction
capitalized in the amount of $6,051,000.
(2) Included in retirements and other is $13,567,000 for AFUDC over-
accrued on Industrial Development Revenue Bond Trust Fund balances and
reclassified to other deferred charges to be amortized over eight
years.
(3) Included in retirements and other is $5,319,000 for costs related to
the Company's Harry Allen Generating Facility project which were
reclassified from other deferred charges.
(4) Included in retirements and other is $732,000 for amortization and
interest cost for l991 reclassified as plant held for future use.
(5) Additions include $83,000,000 for a capitalized lease which was
recorded as a result of a power purchase contract between the Company
and Mission Energy Company.
(6) Provisions include $34,663,000 charged to income and $l,380,000
charged to other accounts. The depreciation provision on the
statement of income includes additional amounts for amortization of
the electric plant acquisition adjustments in the amount of $485,000.
27
<PAGE>
<PAGE>
NEVADA POWER COMPANY
SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991
(IN THOUSANDS OF DOLLARS)
Reserve for
Doubtful
Accounts
----------
BALANCE AT DECEMBER 31, 1990............................. $ 924
Provision charged to income............................. 2,487
Amounts written off, less recoveries.................... (2,305)
-------
BALANCE AT DECEMBER 31, 1991............................. $ 1,106
Provision charged to income............................. 2,068
Amounts written off, less recoveries.................... (2,371)
-------
BALANCE AT DECEMBER 31, 1992............................. $ 803
Provision charged to income............................. 3,161
Amounts written off, less recoveries.................... (2,839)
-------
BALANCE AT DECEMBER 31, 1993............................ $ 1,125
=======
28
<PAGE>
<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.
NEVADA POWER COMPANY
-------------------------------------
(Registrant)
March 28, 1994 By CHARLES A. LENZIE
-------------------------------------
Charles A. Lenzie
Chairman of the Board and
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 28, 1994 By CHARLES A. LENZIE
-------------------------------------
Charles A. Lenzie, Chairman of
the Board, Chief Executive
Officer and Director
(Principal Executive Officer)
March 28, 1994 By STEVEN W. RIGAZIO
-------------------------------------
Steven W. Rigazio, Vice President,
Finance and Planning, Treasurer,
Chief Financial Officer
(Principal Financial and
Principal Accounting Officer)
March 28, 1994 By JAMES CASHMAN III
-------------------------------------
James Cashman III, Director
March 28, 1994 By MARY LEE COLEMAN
-------------------------------------
Mary Lee Coleman, Director
March 28, 1994 By FRED D. GIBSON JR.
-------------------------------------
Fred D. Gibson Jr., Director
March 28, 1994 By JOHN L. GOOLSBY
-------------------------------------
John L. Goolsby, Director
March 28, 1994 By JERRY HERBST
-------------------------------------
Jerry Herbst, Director
March 28, 1994 By JAMES C. HOLCOMBE
-------------------------------------
James C. Holcombe, President and
Director
March 28, 1994 By CONRAD L. RYAN
-------------------------------------
Conrad L. Ryan, Director
March 28, 1994 By FRANK E. SCOTT
-------------------------------------
Frank E. Scott, Director
March 28, 1994 By ARTHUR M. SMITH
-------------------------------------
Arthur M. Smith, Director
March 28, 1994 By JELINDO A. TIBERTI
-------------------------------------
Jelindo A. Tiberti, Director
29
<PAGE>
<PAGE>
<PAGE>
Management's Discussion and Analysis
Of Financial Condition and Results of Operations
Liquidity and Capital Resources
RESOURCE DEVELOPMENT AND CONSTRUCTION PROGRAMS
Every three years Nevada law requires the company to file with the Public
Service Commission of Nevada (PSC) a forecast of electricity demands for the
next 20 years and the company's plans to meet those demands. On September 16,
1991, the PSC approved the company's 1991 Resource Plan, and during 1992 and
1993, the PSC approved the first through fourth amendments to the Resource Plan.
The Resource Plan, as amended and approved in 1992 and 1993, includes the
following major projects:
- - two 90 megawatt (MW) combined-cycle generating units at the Clark Generating
Station, one added in 1993 and one to be added in 1994;
- - the construction of two 70 MW combustion turbine generating units at the Harry
Allen Project site, one unit in 1995 and one unit in 1996. The 1996 Allen
combustion turbine will be subject to a cost comparison of purchased power
resources that are being competitively bid with the least expensive resource
taken as the company's supply choice;
- - a total of 305 MW in purchased power from four qualifying facilities, with
175 MW and 85 MW received beginning in 1992 and 1993, respectively, and 45 MW
expected to be received beginning in 1994;
- - planning costs for a 500 kilovolt (KV) transmission system from the Harry
Allen Substation, located north of the Las Vegas Valley, to Marketplace, a
future 500 KV switching station located near the McCullough Substation south
of the Las Vegas Valley. The company must present final plans on this system
for PSC approval. If PSC approval is received, the transmission system could
be operational by 1998;
- - installation of additional emissions reduction equipment at the Navajo
Generating Station;
- - firm purchased power of 75 MW;
- - the construction of a 230 KV transmission line from Arden Substation, located
southwest of Las Vegas, to Northwest Substation, located northwest of Las
Vegas; and
- - several demand-side pilot projects.
On September 29, 1993, a fifth amendment to the company's 20-year Resource Plan
was filed with the PSC. On February 25, 1994, the PSC approved a stipulation
among the company, PSC Staff, Office of the Consumer Advocate and other
intervenors granting the company's request. The amendment calls for three
purchase power contracts with Southern California Edison, the City of Glendale
and the Salt River Project totaling 160 MWs for the years 1996 to 2000. These
purchase power contracts are a result of the company's 1996 Request for
Proposal for supply-side resources. The stipulation also approved a 50 MW
purchase power contract with Arizona Public Service for the years 1995 to 1997.
The company will file its 1994 Resource Plan on July 1, 1994. As part of
the plan, the company anticipates a portion of the supply-side resources and
demand-side programs to be obtained through a Request For Proposal process.
Budgeted construction expenditures for 1994 and 1995 are $175 million
annually including allowance for funds used during construction.
For the next five years customer growth is estimated to average 5.0
percent per year while demand for electricity is estimated to increase by an
average of 4.3 percent per year.
FINANCIAL STRATEGIES
Nevada Power Company customer growth averaged over 5.1 percent during each of
the three years ended December 31, 1993. To meet the growth forecasted for the
company's service territory for the mid 1990s, the company will continue to
rely upon the financial markets to provide a substantial portion of the funds
to build necessary company-owned facilities.
The company is committed to maintaining shareholder value throughout this
period of continuing rapid growth. To achieve this goal the company will:
- - seek appropriate and timely rate relief from regulators;
- - pursue a balanced financing approach utilizing low cost tax-exempt financing
when possible;
- - maintain ongoing cost containment efforts; and
- - seek legislative and regulatory support when necessary.
16 Nevada Power Company
<PAGE>
<PAGE>
Cost Containment - The company has and will continue to review all planned
construction and operating expenditures in an effort to reduce the level of
external financing required during this period of rapid growth. Management is
constantly reviewing expenditures in light of its commitment to provide
shareholders with returns that deliver long-term shareholder value, deliver
quality service to customers and provide a reliable supply of electricity at
reasonable prices.
CAPITALIZATION
To meet capital expenditure requirements through 1995, the company will utilize
internally generated cash, the proceeds from industrial development revenue
bonds (IDBs), first mortgage bonds (FMBs), and common stock issues through
public offerings and the Stock Purchase and Dividend Reinvestment Plan (SPP).
New Financing Capacity - Under the tests required by the company's FMBs and the
terms of its preferred stock issues, as of December 31, 1993, the company could
issue up to $379 million of additional FMBs at an assumed interest rate of 8
1/2 percent and up to $371 million of additional preferred stock at an assumed
dividend of 8 1/2 percent.
The company has received PSC approval for authority through December 31,
1994 to issue up to 2 million shares of common stock, $70 million of new
taxable debt and $195 million of fixed rate bonds for the purpose of
refinancing certain existing fixed and floating rate bonds.
Earnings to Interest and Preferred Dividends Coverage - For the year 1993, the
ratio of earnings to interest charges was 3.47 times compared to 2.42 times in
1992. The ratio of earnings to interest charges plus preferred dividends was
3.06 times in 1993 compared to 2.18 times in 1992.
Common Equity - In June 1993, the company sold by public offering 2,700,000
shares of common stock. The net proceeds of $65.7 million were used to reduce
short-term debt which was incurred primarily to construct necessary plant
facilities.
The company has the option to issue new common shares or purchase shares
on the open market to satisfy the needs of the SPP. During 1993, the company
issued $40.8 million of common stock under the SPP. (See Note (a) of "Notes to
Schedules of Capitalization.") At year end, common equity represented 46.0
percent of total capitalization.
Short-Term Debt - The company has received regulatory approval to issue short-
term debt up to $150 million for the period 1992 through 1994 and has a
committed bank line for $125 million which expires on December 31, 1994. The
bank line requires that the company obtain the bank group's approval prior to
incurring additional unsecured debt. 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, 1993, the company had no balance
outstanding on this line.
Long-Term Debt - On June 24, 1992, Clark County, Nevada issued $105 million
6.70% fixed rate 30-year IDBs (Nevada Power Company Project) Series 1992A. Net
proceeds from the sale of the IDBs were placed on deposit with a trustee and
are being used to finance the construction of certain facilities which qualify
for tax-exempt financing. At December 31, 1993, $59.1 million remained on
deposit with the trustee.
REGULATION
Adequate and timely rate relief will be an important factor in determining the
company's ability to finance the major construction program the company faces
over the next few years. Generally, the PSC allows recovery of costs on an
historical basis in setting rates charged to customers for electrical service.
Environmental expenditures made by the company are currently being
recovered through customer rates. Management believes environmental
expenditures will increase over time and the increased costs will also be
recovered as necessary utility expenses. A discussion of pending environmental
matters is contained in Note 7 of "Notes to Financial Statements."
Nevada Power Company 17
<PAGE>
<PAGE>
Management's Discussion and Analysis
Of Financial Condition and Results of Operations
Pending Rate Matters - On February 28, 1994, the company filed requests with
the PSC to recover additional fuel and purchased power costs of $38.5 million
and resource planning costs of $1 million. The energy rate request included
$28.7 million of deferred energy costs for the test period ended November 30,
1993, and $9.8 million to adjust the base energy rate.
On November 19, 1993, the PSC Staff filed a petition with the PSC alleging
that the company may be overearning as much as $17 million annually because
business conditions have changed substantially since the company received its
last general rate case decision in July 1992. On January 10, 1994, the PSC
voted to open an investigation into the company's earnings. Management believes
the company's earnings are within the authorized rate of return granted to the
company in July 1992. Hearings on this proceeding are scheduled to commence in
June 1994.
The company has fully reserved for any negative financial effect related
to a February 6, 1991, proposed order by the PSC which, if adopted, would
require the company to bear the full cost of replacement power and related
expenses resulting from a 1985 accident at the Mohave Generating Station.
Earnings for the fourth quarter of 1990 included an after-tax charge of $12.9
million for this proposed order. On June 17, 1991, the PSC issued another order
setting aside the proposed order and ordered the parties to participate in
joint hearings before the California Public Utilities Commission (CPUC). The
CPUC hearings are now concluded, and the PSC will prepare its own opinion based
on the record created in the CPUC hearings. In January 1994, the administrative
law judge in the CPUC proceeding issued a proposed opinion denying recovery to
Southern California Edison (SCE) of its incremental purchased power costs
resulting from the accident. SCE has filed comments with the CPUC concerning
the proposed decision.
Concluded Rate Matters - Effective February 1, 1994, the PSC granted the
company a $23.6 million increase in the energy portion of customer rates. (See
Note 7 of "Notes to Financial Statements.")
The table below summarizes the rate adjustments that have been granted to
the company during the past three years.
Summary of Rate Adjustments 1991 through 1993
Effective Date Nature of Increase (Decrease) Amount (In millions)
____________________________________________________________________________
Jan. 1, 1991 Energy rate increase $24.4
March 4, 1991 Energy and resource plan rate increase 1.0
Nov. 12, 1991 General rate increase 12.2
Energy rate increase 11.4
July 27, 1992 General rate increase 22.2
Energy and resource plan net rate decrease (26.4)
June 28, 1993 Energy and resource plan net rate increase 42.1
____________________________________________________________________________
DEREGULATION AND COMPETITION
Deregulation of the electric utility industry is accelerating with the
enactment of the National Energy Policy Act of 1992 (Act). Deregulation will
lead to further competition in the industry as generators of power obtain
greater access to transmission facilities linking them to potential new
customers. Most observers believe the electric utility beneficiaries of the Act
will be twofold; those who can provide low cost generation for sale and those
who have strategically located transmission highways that can transmit low cost
power from one area to another.
18 Nevada Power Company
<PAGE>
<PAGE>
Within the region the company's residential rates are competitive. However,
large industrial customer rates may require adjustment to remain competitive in
the changing environment. In recognition of the changing regional competitive
environment, the company is focusing on the costs of serving various classes of
customers and the appropriate rates to be charged based on those costs of
service. The company will seek through the PSC any rate adjustments necessary
to maintain a competitive position.
An opportunity exists given the company's strategic location in the center
of a region of price diversity. As generators arrange for sales of electricity
to customers in other areas, much of the power may need to be transmitted
through the company's service territory. The company would have an opportunity
to charge generators for the transmission of energy through its system. The
company is studying the feasibility of constructing additional cost effective
transmission facilities to maximize the advantage of its strategic location.
OTHER
In September 1993, as a part of a comprehensive organizational study, the
company offered a voluntary early retirement package to 175 employees who would
be at least 55 years of age, and have completed at least 10 years of service by
March 31, 1994. A total of 109 employees, or approximately 6 percent of the
work force, accepted the package. In October 1993, the company's Board of
Directors unanimously approved a new organization structure that realigns
functions to improve operations and customer service. The company expects that
the net result from the change in organizational structure will be a leaner
work force that operates more efficiently and makes the company more
competitive in a changing electric energy industry. At December 31, 1993,
organizational study, early retirement and severance costs of $6.7 million are
included in other deferred charges. (See Note 8 of "Notes to Financial
Statements.")
The company and the International Brotherhood of Electrical Workers Local
396 signed new Collective Bargaining Agreements for the company's plant and
clerical employees in January and February 1994, respectively. The four-year
plant and clerical agreements, effective February 1 and May 1, 1994,
respectively, each provide for base wage increases of 4% in 1994, 3.5% in 1995,
3.25% in 1996 and a 4% lump sum increase in 1997.
The company has adopted Statement of Financial Accounting Standards No.
106 (FAS 106), Employers' Accounting for Postretirement Benefits Other Than
Pensions (See Note 3 of "Notes to Financial Statements") and No. 109 (FAS 109),
Accounting for Income Taxes (See Note 2 of "Notes to Financial Statements")
effective January 1, 1993. The increase in 1993 of other deferred charges and
other deferred credits primarily reflects adjustments related to the adoption
of FAS 106 and FAS 109. (See Note 8 of "Notes to Financial Statements.")
In March 1994, the company resolved certain litigation and bought out the
remaining obligation under a coal purchase contract. The company's portion of
the settlement and buyout is $15.25 million. Management believes the cost of
the buyout will be recovered through Nevada's deferred energy accounting
procedures. (See Note 7 of "Notes to Financial Statements.")
Results of Operations
GENERAL
In 1993, earnings increased, as compared to 1992, due primarily to higher
revenues resulting from an increase in general rates effective July 1992 and an
increase in kilowatthour sales. In 1992, earnings increased, as compared to
1991, due primarily to higher revenues resulting from two increases in general
rates effective November 1991 and July 1992.
Average shares of common stock outstanding for 1993 increased by 3.8
million shares compared to 1992, as a result of public offerings of 2.7 million
shares in June of 1993 and 2.99 million shares in April 1992.
REVENUES
Revenues during 1993, 1992 and 1991 were $652 million, $601 million and $546
million, respectively. The 8.5 percent increase in 1993, as compared to 1992,
was a result of a 5.8 percent increase in kilowatthour sales and an increase in
energy rates effective June of 1993.
The 10 percent increase in 1992, as compared to 1991, was a result of a
7.2 percent increase in kilowatthour sales and increases in general and energy
rates effective November 1991.
Nevada Power Company 19
<PAGE>
<PAGE>
Management's Discussion and Analysis
Of Financial Condition and Results of Operations
Increase (Decrease) in Revenue From Prior Year
Nature of Increase (Decrease) (In millions) 1993 1992 1991
_______________________________________________________________________________
Kilowatthour sales $28.2 $37.7 $19.1
General rate changes 12.3 20.5 (0.3)
Deferred energy adjustments (13.3) (5.3) 5.4
Fuel cost base rate changes 22.4 0.4 26.9
Resource plan cost changes and other 1.3 1.2 3.0
-------------------------
Total increase $50.9 $54.5 $54.1
=========================
_______________________________________________________________________________
FUEL AND PURCHASED POWER
In 1993, as compared to 1992, and in 1992, as compared to 1991, purchased power
expense increased 21.1 percent and 51.6 percent, respectively, due to increased
purchases from qualifying facilities.
Effective June 28, 1993, the PSC granted the company a $44.2 million
increase in the energy portion of customer rates, and effective July 27, 1992,
the PSC granted the company a $28.3 million decrease in energy rates.
During 1993, the company deferred $48.5 million of increased energy costs
for collection in a later period and collected $17 million of energy cost
increases which had previously been deferred. During 1992, the company deferred
$39.5 million of increased energy costs for collection in a later period and
collected $26.6 million of energy cost increases which had previously been
deferred. Recovery of fuel expenses is administered under the state's deferred
energy cost accounting procedures. (See Note 1 of "Notes to 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.
The following tables summarize the source of kilowatthours sold, the
percentage of company generated kilowatthours by fuel source and fuel costs per
kilowatthour.
1993 1992 1991
_______________________________________________________________________________
Source of Kilowatthours Sold
Company generation 49% 49% 55%
Hoover Dam hydroelectric 4 4 5
Purchased power 47 47 40
---------------------------------
100% 100% 100%
=================================
Company Generated Kilowatthours
By Fuel Source
Coal 93% 94% 94%
Natural Gas 7 5 5
Oil - 1 1
---------------------------------
100% 100% 100%
=================================
Fuel Costs Per Kilowatthour
Coal 1.61 cents 1.63 cents 1.56 cents
Natural Gas 2.98 3.83 3.53
Oil 4.21 4.74 6.42
_______________________________________________________________________________
20 Nevada Power Company
<PAGE>
<PAGE>
OTHER OPERATING EXPENSES AND TAXES
Other operations expense increased by $5.5 million in 1993, as compared with
1992, primarily due to an increase in administrative and general expenses
resulting mainly from increased labor costs, computer system conversion costs
and an increase in the provision for uncollectible accounts.
The $7.2 million increase in other operations expense for 1992 was due
mainly to an increase in employee medical benefit costs, employee pension
expenses and an increase in resource planning 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. During 1993, these expenses decreased by $2.5 million due primarily
to lower maintenance costs at the Reid Gardner and Navajo Generating Stations.
During 1992, as compared to 1991, these expenses decreased by $10 million due
to major maintenance expenses at the Reid Gardner and Mohave Generating
Stations in 1991.
Depreciation expense increased $3.9 million in 1993 and $4.3 million in
1992 primarily because of a growing electric plant asset base. In addition, the
average annual depreciation rate increased from approximately 2.8 percent to
2.9 percent effective November 1991.
General taxes increased by $2.3 million in 1993 primarily due to higher
assessed property values and rates for property tax purposes.
OTHER INCOME AND EXPENSES
Other miscellaneous, net includes a charge of $3.2 million net of tax in the
fourth quarter of 1993 for a write-off of costs related to environmental and
engineering studies for the cancelled coal-fired White Pine Power Project. A
rate decision by the PSC on January 24, 1994, resulted in a write-off of $2
million net of tax in the fourth quarter of 1993 for previously deferred energy
costs. (See Note 7 of "Notes to Financial Statements.")
Other miscellaneous, net includes a charge of $2.6 million net of tax in
the fourth quarter of 1992 for a write-off of costs related to the property
loss on a faulty cooling tower at the company's Reid Gardner Generating Station
unit 4 and associated legal fees. On August 4, 1992, the PSC issued an order
resulting in a write-off of $2.4 million net of tax for previously deferred
energy costs.
On November 26, 1991, the PSC issued an order associated with requests by
the company for a general rate increase and an increase to recover certain fuel
and purchased power costs. The PSC order resulted in write-offs during the
fourth quarter of 1991 to other miscellaneous, net which included a charge of
$1.9 million net of tax applicable to a cancelled coal-fired generating station
as well as a charge of $2.3 million net of tax for deferred energy costs.
FINANCING EXPENSES
Interest on long-term debt increased $2.0 million in 1992, as compared to 1991,
primarily as a result of interest on IDBs issued in June 1992, offset partially
by lower interest costs on several issues of long-term debt refinanced at lower
interest rates and interest income on IDB proceeds held in trust.
Other interest expenses decreased by $1.3 million during 1992, as compared
to 1991, because of less short-term borrowing.
Nevada Power Company 21
<PAGE>
<PAGE>
Statements of Income
For the Years Ended Dec. 31,
(In thousands, except per share amounts) 1993 1992 1991
______________________________________________________________________________
Electric Revenues (Notes 1 and 7) $651,772 $600,915 $546,411
----------------------------
Operating Expenses and Taxes:
Fuel 98,701 96,563 98,084
Purchased and interchanged power 242,803 200,344 132,117
Deferred energy cost adjustments,
net (Note 1) (31,490) (12,834) 38,533
----------------------------
Net energy costs 310,014 284,073 268,734
Other production operations 17,715 17,594 17,795
Other operations 83,158 77,697 70,454
Maintenance and repairs 35,379 37,911 47,928
Provision for depreciation (Note 1) 43,358 39,450 35,148
General taxes (Note 2) 16,401 14,093 12,727
Federal income taxes (Notes 1 and 2) 37,278 29,975 16,198
----------------------------
543,303 500,793 468,984
----------------------------
Operating Income 108,469 100,122 77,427
----------------------------
Other Income (Expenses):
Allowance for other funds used
during construction (Note 1) 9,880 8,251 4,172
Other miscellaneous, net (Note 7) (5,496) (10,127) (6,285)
----------------------------
4,384 (1,876) (2,113)
----------------------------
Income Before Interest Deductions 112,853 98,246 75,314
----------------------------
Interest Deductions:
Interest on long-term debt 43,173 43,500 41,518
Other interest 1,931 2,185 3,468
Allowance for borrowed funds used
during construction (Note 1) (5,799) (4,219) (4,848)
----------------------------
39,305 41,466 40,138
----------------------------
Net Income 73,548 56,780 35,176
Dividend Requirements
on Preferred Stock 3,986 4,262 2,880
----------------------------
Earnings Available for
Common Stock $ 69,562 $ 52,518 $ 32,296
============================
Weighted Average Common
Shares Outstanding 39,482 35,652 30,855
============================
Earnings per Average Common Share $ 1.76 $ 1.47 $ 1.05
============================
See Notes to Financial Statements.
______________________________________________________________________________
22 Nevada Power Company
<PAGE>
<PAGE>
Statements of Retained Earnings
For the Years Ended Dec. 31, (In thousands) 1993 1992 1991
_______________________________________________________________________________
Balance at Beginning of Period $102,493 $107,516 $123,963
Add - Net Income 73,548 56,780 35,176
--------------------------------
176,041 164,296 159,139
--------------------------------
Deduct:
Dividends paid in cash:
Cumulative preferred stock -
5.40%, 5.20% and 4.70% Series 224 233 243
9.90% Series (Note 6) 3,762 4,572 2,264
Common stock 62,696 56,998 49,116
--------------------------------
66,682 61,803 51,623
--------------------------------
Balance at End of Period $109,359 $102,493 $107,516
================================
See Notes to Financial Statements.
_______________________________________________________________________________
Nevada Power Company 23
<PAGE>
<PAGE>
Balance Sheets
December 31, (In thousands) 1993 1992
_____________________________________________________________________________
Assets
Electrical Plant, at Original Cost (Notes 1, 7 and 9):
Production $ 681,527 $ 588,493
Transmission 277,543 263,807
Distribution 594,874 536,644
General 84,616 77,402
-----------------------
1,638,560 1,466,346
Less accumulated depreciation 451,302 410,963
-----------------------
Net plant in service 1,187,258 1,055,383
Construction work in progress 167,652 172,092
Property under capital leases 91,517 96,753
Plant held for future use 3,719 4,442
-----------------------
1,450,146 1,328,670
-----------------------
Investments (Notes 1 and 7) 21,822 19,339
-----------------------
Current Assets:
Cash and temporary cash investments 145 160
Customer receivables -
Billed 37,270 33,988
Unbilled (Note 1) 13,000 9,945
Reserve for doubtful accounts (1,125) (803)
Other receivables (Note 7) 15,465 7,139
Fuel stock, at average cost 16,613 21,717
Materials and supplies, at average cost (Note 8) 23,714 24,099
Deferred energy costs (Notes 1 and 7) 74,033 24,708
Prepayments 8,313 9,151
-----------------------
187,428 130,104
-----------------------
Deferred Charges:
Debt expense, being amortized 28,645 25,503
Accumulated deferred taxes on proposed refund of
recovered energy costs - Mohave accident (Note 7) 5,417 6,055
Other (Note 8) 115,879 47,369
-----------------------
149,941 78,927
-----------------------
$1,809,337 $1,557,040
=======================
See Notes to Financial Statements.
_____________________________________________________________________________
24 Nevada Power Company
<PAGE>
<PAGE>
December 31, (In thousands) 1993 1992
______________________________________________________________________________
Capitalization and Liabilities
Capitalization
(See Schedules of Capitalization
and Long-Term Debt):
Common shareholders' equity $ 645,924 $ 532,473
Redeemable cumulative preferred stock 38,000 38,000
Cumulative preferred stock with
mandatory sinking funds 4,264 4,464
Long-term debt 716,589 715,451
-------------------------
1,404,777 1,290,388
-------------------------
Current Liabilities:
Notes payable (Note 7) 25,000 -
Current maturities and sinking fund requirements
(See Schedules of Capitalization
and Long-Term Debt) 7,496 15,345
Accounts payable, including salaries and wages 70,098 46,357
Accrued taxes (1,131) 1,375
Accrued interest 6,212 7,178
Customers' service deposits 12,069 11,816
Accumulated deferred taxes on deferred energy costs 20,574 7,264
Other (Note 8) 19,372 6,716
-------------------------
159,690 96,051
-------------------------
Commitments and Contingencies (Note 7)
Deferred Credits and Other Liabilities:
Accumulated deferred investment tax credits (Note 1) 35,384 36,687
Accumulated deferred taxes on income (Note 2) 126,133 84,097
Customers' advances for construction 28,455 26,803
Proposed refund of recovered energy
costs - Mohave accident (Note 7) 16,698 15,113
Other (Note 8) 38,200 7,901
-------------------------
244,870 170,601
-------------------------
$1,809,337 $1,557,040
=========================
See Notes to Financial Statements.
______________________________________________________________________________
Nevada Power Company 25
<PAGE>
<PAGE>
Schedules of Capitalization
December 31, (Dollars in thousands) 1993 1992
_____________________________________________________________________________
Common Shareholders' Equity (a,c):
Common stock, $1 par value, authorized
70,000,000 shares; issued 41,505,195
and 37,132,817 shares at December 31,
1993 and 1992; stated at $ 44,709 $ 40,337
Premium on capital stock 496,367 393,401
Unamortized capital stock expense (4,511) (3,758)
Retained earnings 109,359 102,493
-----------------------------------
Total common shareholders' equity 645,924 46.0% 532,473 41.3%
-----------------------------------
Redeemable Cumulative Preferred Stock (b):
$20 par value, authorized 4,500,000 shares
for all series; Outstanding at December
31, 1993 and 1992: 9.90% Series,
1,900,000 shares 38,000 38,000
-----------------------------------
Total 38,000 2.7 38,000 3.0
-----------------------------------
Cumulative Preferred Stock with
Mandatory Sinking Funds (b):
Outstanding at December 31, 1993 and 1992:
5.40% Series, 46,669 and 48,669 shares 934 974
5.20% Series, 44,507 and 46,507 shares 890 930
4.70% Series, 132,000 and 138,000 shares 2,640 2,760
-----------------------------------
4,464 4,664
Current sinking fund requirement (200) (200)
-----------------------------------
Total 4,264 0.3 4,464 0.3
-----------------------------------
Long-Term Debt (See Schedules of
See Schedules of Long-Term Debt) 716,589 51.0 715,451 55.4
-----------------------------------
Total capitalization $1,404,777 100.0% $1,290,388 100.0%
===================================
_____________________________________________________________________________
26 Nevada Power Company
<PAGE>
<PAGE>
Notes to Schedules of Capitalization
(a) The changes in common stock shares for 1991, 1992 and 1993 are as
follows:
Shares
________________________________________________________________________________
Outstanding, December 31, 1990 28,912,228
Issued through public offering 3,000,000
Issued under 401(k) Savings Plan 30,870
Issued under Stock Purchase and
Dividend Reinvestment Plan 1,032,369
----------
Outstanding, December 31, 1991 32,975,467
Issued through public offering 2,990,000
Issued under 401(k) Savings Plan 27,644
Issued under Stock Purchase and
Dividend Reinvestment Plan 1,139,706
----------
Outstanding, December 31, 1992 37,132,817
Issued through public offering 2,700,000
Issued under 401(k) Savings Plan 32,052
Issued under Stock Purchase and
Dividend Reinvestment Plan 1,640,326
----------
Outstanding, December 31, 1993 41,505,195
==========
_______________________________________________________________________________
Premium on capital stock increased $103 million, $73.9 million and $66.8
million during 1993, 1992 and 1991, respectively, due to issue of common
stock.
Cash dividends paid per share on common stock were $1.60 each year during
1993, 1992 and 1991.
(b) The Redeemable Cumulative Preferred Stock, 9.90% Series is redeemable at
the option of the company, as a whole or in part, on April 1, 1997, and
is subject to mandatory redemption in its entirety on April 1, 2002.
(See Note 6 of "Notes to Financial Statements.")
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.
(c) In October 1990, the company adopted a Stockholder Rights Plan and
declared a dividend of one stock purchase right for each outstanding
share of common stock. (See Note 6 of "Notes to Financial Statements.")
Nevada Power Company 27
<PAGE>
<PAGE>
Schedules of Long-Term Debt
December 31, (In thousands) 1993 1992
_________________________________________________________________________
Long-Term Debt (a)
(Note 5 to Financial Statements):
First mortgage bonds (b):
7 1/8% Series I due 1998 $ 15,000 $ 15,000
7 5/8% Series L due 2002 15,000 15,000
7 1/8% Series N due 2006 13,000 13,000
6 3/4% Series O due 2007 7,100 7,500
8 3/4% Series P due 1995 423 445
9 3/8% Series S due 2016 - 52,000
7.80% Series T due 2009 15,000 15,000
6.92% Series U due 1995 50,000 50,000
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 -
--------------------------
428,023 435,445
Industrial development revenue bonds (c):
7.80% due 2020 100,000 100,000
Floating rate weekly demand -
Due 2015 44,000 44,000
Due 2018 25,000 25,000
Due 2019 60,000 60,000
Less funds held in trust (59,051) (65,285)
6 3/8% pollution control revenue bonds
due 2004 (d) 16,000 17,000
Obligations under capital leases 109,968 114,501
--------------------------
723,940 730,661
Debt premium and discount, being amortized (55) (65)
Current maturities and sinking fund
requirements (7,296) (15,145)
--------------------------
Total long-term debt $716,589 $715,451
==========================
_________________________________________________________________________
28 Nevada Power Company
<PAGE>
<PAGE>
Notes to Schedules of Long-Term Debt
(a) The amounts of long-term debt maturities, including sinking fund
requirements, are $7.3 million in 1994, $57.3 million in 1995, $8
million in 1996, $7.9 million in 1997 and $7.3 million in 1998,
including $5.6 million, $5.2 million, $5.3 million, $5.2 million
and $4.5 million for obligations under capital leases, respectively.
None of the long-term debt is held by or for the account of the
company.
(b) Generally, electric plant is subject to the first mortgage lien.
It is the company's intention to meet the sinking fund requirement
for its series I and L first mortgage bonds by pledging property
additions in lieu of cash payments.
The N, O and P series first mortgage bonds provide for annual payments
sufficient to ratably retire the respective series by their final due
dates. Payments on the N series do not commence until 1996.
The series N, O, T, V, W and X first mortgage bonds correspond with
respect to their terms to four series of collateralized pollution control
revenue bonds and two series of industrial development revenue bonds
issued by various municipal authorities.
(c) The fixed rate industrial development bonds and floating rate
industrial development bonds were issued by Clark County, Nevada and
are guaranteed as to payment of principal and interest by the company.
(d) The indenture for the 6 3/8% pollution control revenue bonds due 2004
provides for annual sinking fund payments of $1 million to and including
March 1, 2003 and a final payment of $6 million on March 1, 2004.
Nevada Power Company 29
<PAGE>
<PAGE>
Statements of Cash Flows
For the Years Ended Dec. 31,
(In thousands) 1993 1992 1991
__________________________________________________________________________
Cash Flows from Operating Activities:
Net income $ 73,548 $ 56,780 $ 35,176
Adjustments to reconcile net
income to net cash provided -
Depreciation and amortization 55,139 47,356 44,686
Deferred income taxes and
investment tax credits 16,504 12,030 (9,536)
Allowance for other funds
used during construction (9,880) (8,251) (4,172)
Changes in -
Receivables (4,591) (2,635) (339)
Fuel stock and materials and supplies 5,490 5,928 (8,104)
Accounts payable and other
current liabilities 27,290 17,296 676
Deferred energy costs (37,766) (8,916) 40,466
Accrued taxes and interest 1,868 (14,683) 439
Other assets and liabilities 3,343 2,473 1,013
---------------------------------
Net cash provided by operating
activities 130,945 107,378 100,305
---------------------------------
Cash Flows from Investing Activities:
Construction expenditures and
gross additions (163,257) (171,074) (151,089)
Investment in subsidiaries and other (2,828) (4,531) (2,851)
Salvage net of removal cost 227 405 1,798
---------------------------------
Net cash used in investing
activites (165,858) (175,200) (152,142)
---------------------------------
Cash Flows from Financing Activities:
Sale of capital stock 107,329 78,066 70,814
Sale of long-term debt 45,000 317,500 -
Change in funds held in trust 6,234 (21,135) 6,612
Retirement of preferred stock
and long-term debt (59,405) (175,745) (9,043)
Increase (decrease) in short-term
borrowing - (71,000) 34,110
Cash dividends (66,883) (60,596) (51,532)
Other financing activities 2,623 738 845
---------------------------------
Net cash provided by financing
activities 34,898 67,828 51,806
---------------------------------
Cash and Temporary Cash Investments(Note 1):
Net increase (decrease) during the period (15) 6 (31)
Beginning of period 160 154 185
--------------------------------
End of period $ 145 $ 160 $ 154
================================
Cash Paid During the Period for:
Interest, net of amounts capitalized $ 57,140 $ 55,926 $ 48,919
================================
Income taxes $ 18,001 $ 13,793 $ 22,771
================================
See Notes to Financial Statements.
__________________________________________________________________________
30 Nevada Power Company
<PAGE>
<PAGE>
Notes to Financial Statements
Note 1 - Summary of Significant Accounting Policies
For ratemaking and other purposes, the company is subject to the
jurisdiction of the PSC and the Federal Energy Regulatory Commission (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 PSC.
Electric Revenues - The company bills its customers monthly on a cycle basis
and recognizes the estimated 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 PSC, 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 the first
ten months of 1991 were equivalent to an annual rate of approximately 2.8
percent of the average gross investment in depreciable plant. Effective
November 1991, as authorized by the PSC, the annual depreciation rate was
increased to approximately 2.9 percent.
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 PSC 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 PSC. Through December 31, 1992,
the company used a rate of 10.02 percent to calculate AFUDC on construction
work in progress as authorized by the PSC, effective July 1992. In January
1993, the company began using an AFUDC rate as calculated under the FERC
computational method which averaged 9.88 percent for 1993.
Recently Issued Accounting Standards - In November 1992, the Financial
Accounting Standards Board issued Statement of Financial Accounting Standards
No. 112 (FAS 112), Employers' Accounting for Postemployment Benefits which is
effective for years beginning after December 15, 1993. FAS 112 established
accounting standards for employers who provide benefits to former or inactive
employees after employment but before retirement (postemployment benefits).
The company is currently analyzing the provisions of FAS 112 and believes that
application of the new standard will not have a material impact on the
company's results of operations or financial position.
Federal Income Taxes - Effective January 1, 1993, the company adopted
the provisions of 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 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 cumulative effect of the
change in accounting for income taxes is not material to net income.
In November 1991, the PSC 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 $38
million of income taxes will be allowed in future rates.
Nevada Power Company 31
<PAGE>
<PAGE>
Notes to Financial Statements
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, which generally are convertible to
cash at par on short notice and mature three months or less from the date of
acquisition, are reported as temporary cash investments.
The company had no material non-cash investing or financing transactions
during 1993 or 1992. During 1991, a capital lease obligation of $83 million
was incurred when the company entered into a power purchase contract with
Mission Energy Company.
Other Accounting Policies - The company uses the equity method of accounting
to report immaterial investments in subsidiaries.
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, 1993 and 1992, the provisions
of FAS 107 apply only to the company's long-term debt and redeemable
cumulative preferred stock. (See Notes 5 and 6 of "Notes to Financial
Statements.")
In 1993, the company adopted the provisions of FAS 106, Employers'
Accounting for Postretirement Benefits Other Than Pensions, which requires
accrual of postretirement benefits during the years an employee provides
services. (See Notes 3 and 8 of "Notes to Financial Statements.")
Certain amounts in prior periods have been reclassified to conform to
the financial statement presentation for December 31, 1993.
Note 2 - Federal Income and Other Taxes
The total federal income tax expense as set forth in the accompanying
Statements of Income results in an effective federal income tax rate
different than the statutory federal income tax rate for the following
reasons:
Years Ended Dec. 31,
(Dollars in thousands) 1993 1992 1991
______________________________________________________________________________
Federal income tax
at statutory rate $39,625 35.0% $29,241 34.0% $17,057 34.0%
Adjustments:
Investment tax credit
amortization (1,303) (1.2) (1,618) (1.9) (1,618) (3.2)
Other items 1,344 1.2 1,600 1.9 (446) (0.9)
--------------------------------------------------
Total recorded federal
income tax $39,666 35.0% $29,223 34.0% $14,993 29.9%
==================================================
Federal income taxes
included in:
Operating expenses $37,278 $29,975 $16,198
Other income, net 2,388 (752) (1,205)
--------------------------------------------------
$39,666 $29,223 $14,993
==================================================
______________________________________________________________________________
32 Nevada Power Company
<PAGE>
<PAGE>
The current and deferred components of federal income taxes included
in operating expenses are as follows:
Years Ended Dec. 31, (In thousands) 1993 1992 1991
_________________________________________________________________________
Current federal income taxes $20,680 $18,213 $25,753
-----------------------------------
Deferred federal income taxes:
Depreciation differences 8,899 13,823 8,127
Deferred energy costs 11,765 (434) (12,601)
Contributions in aid of
construction (1,732) (1,437) (806)
Coal contract buyout (945) (1,009) (1,009)
Other - net (86) 2,437 (1,648)
-----------------------------------
17,901 13,380 (7,937)
-----------------------------------
Investment tax credit amortization (1,303) (1,618) (1,618)
-----------------------------------
Total $37,278 $29,975 $16,198
===================================
_________________________________________________________________________
General taxes charged to operating expenses are as follows:
Years Ended Dec. 31, (In thousands) 1993 1992 1991
_________________________________________________________________________
Real estate and personal property $11,338 $ 9,408 $ 8,185
Payroll 4,748 4,285 4,083
Other 315 400 459
-----------------------------------
Total $16,401 $14,093 $12,727
===================================
_________________________________________________________________________
The company adopted FAS 109, Accounting for Income Taxes, effective January 1,
1993. As a result, the company's December 31, 1993 balance sheet contains a net
regulatory asset of $14 million. (See Note 8 of "Notes to Financial
Statements.")
The regulatory liability 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 accumulated deferred investment credit under
former Internal Revenue Code Section 46(f)(2).
Nevada Power Company 33
<PAGE>
<PAGE>
Notes to Financial Statements
The net accumulated deferred federal income tax liability consists of
accumulated deferred federal income tax liabilities less accumulated deferred
federal income tax assets related to:
Years ended Dec. 31, (In thousands) 1993 1992
________________________________________________________________________
Accumulated deferred federal income tax
liabilities:
Temporary basis differences - plant $ (33,058) $ -
Investment tax credits (35,384) (36,687)
Excess of tax depreciation over
book depreciation (83,309) (75,214)
Coal contract buyout (2,251) (3,196)
Accrued taxes (1,985) (2,418)
Deferred energy (20,574) (7,264)
Demand-side program costs (3,686) (1,072)
Other (1,844) (2,197)
------------------------
Total (182,091) (128,048)
------------------------
Accumulated deferred federal income tax
assets:
Unamortized investment tax credits 19,053 -
Refundable customer advances 9,867 8,800
Purchased power 5,417 6,055
Nonrefundable contributions in aid
of construction 2,510 3,497
Capitalized expenses 1,439 1,556
Other 1,949 1,916
-----------------------
Total 40,235 21,824
-----------------------
Net accumulated deferred tax liability $(141,856) $(106,224)
=======================
________________________________________________________________________
Note 3 - Employee Benefits
Employee Welfare Benefit Plans - The company provides certain health, dental,
vision care and long-term disability benefits to employees through plans
administered under a Voluntary Employee's Beneficiary Association (VEBA)
Trust. Currently, substantially all of the costs of the benefit programs for
employees are borne by the company. Effective August 1, 1994, current
employees will begin paying 10% of the cost of providing health, dental and
vision benefits.
The cost of the benefit plans was approximately $10.3 million, $9.3
million and $8.2 million, during 1993, 1992 and 1991, respectively. The
programs also provide benefits to retired employees who elect to continue
coverage by paying the applicable premiums. (See "Postretirement Benefits
Other Than Pensions" below.)
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 who have completed one year of eligibility service may become
"participants" in the 401(k) Plan. The company matched 50 percent in 1993,
1992 and 1991 of any Management, Professional, Administrative and Technical
participant's contributions to the 401(k) Plan not to exceed 3 percent of the
participant's annual compensation. In 1993, 1992 and 1991, the company matched
25 percent of any union-represented participant's contributions to the 401(k)
Plan not to exceed 1.5 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 $921,000
for 1993, $629,000 for 1992 and $581,000 for 1991.
34 Nevada Power Company
<PAGE>
<PAGE>
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 full-time employees age
21 and over with one year of service are covered by 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, 27 active or retired designated
officers and employees participate in the SERP. The SERP will be funded as
benefits are disbursed.
The table below sets forth the funded status and amounts recognized in
the company's financial statements at December 31, 1993, 1992 and 1991 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 7.25 percent and 4.50 percent in 1993, and 8.25
percent and 5 percent in 1992 and 1991, respectively. The expected rate of
return on PLAN assets was 8.5 percent in 1993, 1992 and 1991. PLAN assets are
primarily invested in listed stocks, fixed income securities and federal
agencies securities.
Reconciliation of Funded Status
PLAN SERP
___________________________ ____________________________
Years Ended Dec. 31,
(In thousands) 1993 1992 1991 1993 1992 1991
______________________________________________________________________________
Actuarial present
value of:
Vested benefit
obligation $54,434 $40,592 $32,458 $ 3,854 $ 2,814 $ 2,174
Nonvested benefit
obligation 3,875 4,217 3,312 514 375 345
----------------------------------------------------------
Accumulated benefit
obligation $58,309 $44,809 $35,770 $ 4,368 $ 3,189 $ 2,519
==========================================================
Projected benefit
obligation $80,575 $63,121 $56,032 $ 4,837 $ 3,452 $ 2,569
Plan assets
at fair value 60,236 54,575 49,494 - - -
----------------------------------------------------------
Plan assets
less than projected
benefit obligation (20,339) (8,546) (6,538) (4,837) (3,452) (2,569)
Unrecognized net
transition
obligation amortized
over approximately
nine years - - - 129 303 478
Unrecognized prior
service costs 5,577 6,005 6,433 412 166 (300)
Unrecognized net
(gain) loss 8,949 2,925 (822) 1,267 209 84
----------------------------------------------------------
Pension asset
(liability) $(5,813) $ 384 $ (927) $(3,029) $(2,774) $(2,307)
==========================================================
Net pension expense was
comprised of the following:
Service cost $ 3,284 $ 3,147 $ 2,884 $ 67 $ 76 $ 29
Interest cost on
projected benefit
obligation 5,243 4,900 4,334 297 278 211
Return on plan
assets (5,371) (1,739) (8,301) - - -
Net amortization
and deferral 1,021 (2,117) 2,862 197 331 268
----------------------------------------------------------
Net periodic
pension cost $ 4,177 $ 4,191 $ 1,779 $ 561 $ 685 $ 508
==========================================================
______________________________________________________________________________
Nevada Power Company 35
<PAGE>
<PAGE>
Notes to Financial Statements
Postretirement Benefits Other Than Pensions - The company adopted FAS 106,
Employers' Accounting for Postretirement Benefits Other Than Pensions,
effective January 1, 1993. The costs of these benefits have been expensed on
a pay-as-you-go basis prior to the company adopting FAS 106. In July 1992,
the PSC authorized the company to continue recognizing these benefit costs
on a pay-as-you-go basis after adopting FAS 106 and to record any difference
in costs resulting from the implementation of FAS 106 as a deferred asset.
The company has elected to amortize its transition obligation at January 1, 1993
over a period of 20 years.
The company provides postretirement medical, dental and vision benefits to
employees who have retired or will retire and are eligible for an immediate
pension benefit. The postretirement health care plan is contributory, and
retirees' contributions can be adjusted annually for increases in the cost of
providing the benefits.
Net periodic postretirement benefit cost for the year ended December 31,
1993 included the following components:
(In thousands) 1993
_______________________________________________________________________
Service cost benefit earned during the year $ 614
Interest cost on projected benefit obligation 1,881
Amortization of transition obligation 1,166
------
Net periodic postretirement benefit cost $3,661
======
_______________________________________________________________________
A reconciliation of the funded status of the plan to the amounts recognized
in the Balance Sheet as of December 31, 1993 is as follows:
(In thousands) 1993
_______________________________________________________________________
Retirees $(10,270)
Fully eligible active employees (8,749)
Other active employees (6,777)
--------
Accumulated postretirement benefit obligation (25,796)
Unrecognized transition obligation 22,149
Unrecognized loss 542
--------
Accrued postretirement benefit cost liability $ (3,105)
========
_______________________________________________________________________
The medical cost trend rate assumed for 1994 was 10.25 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 postretire-
ment 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, 1993 by $1.9
million and would increase the aggregate of the service and interest cost
components of net periodic postretirement benefit cost for 1993 by $149,000.
The weighted-average discount rate used in determining the accumulated
postretirement benefit obligation at December 31, 1993 was 7.25 percent.
Note 4 -Short-Term Borrowings
The company has a $125 million bank revolving credit facility which expires
on December 31, 1994, and pays commitment fees based on both the unused amount
of the facility and the company's first mortgage bond ratings. Borrowing rates
under the bank line are determined by both current market rates and the
company's first mortgage bond ratings.
During 1993, the maximum amounts of short-term borrowings outstanding
were $74 million, average short-term borrowings were $16.1 million and
weighted average interest costs were 5.34%. There were no short-term
borrowings outstanding at December 31, 1993.
36 Nevada Power Company
<PAGE>
<PAGE>
During 1992, the maximum amounts of short-term borrowings outstanding
were $71 million, average short-term borrowings were $18.6 million and
weighted average interest costs were 6.01%. There were no short-term
borrowings outstanding at December 31, 1992.
During 1991, the maximum amounts of short-term borrowings outstanding
were $71 million, average short-term borrowings were $36.2 million and
weighted average interest costs were 6.91%. The weighted average interest
rate for short-term borrowings outstanding at December 31, 1991, was 5.33%.
Note 5 - Long-Term Debt
In accordance with FAS 107, the company estimates the fair value of its long-
term debt 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 $614 million and $665
million at December 31, 1993, and $616 million and $626 million at December
31, 1992, respectively. The estimate presented herein is not necessarily
indicative of the amount 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 amount.
The indentures under which the company's first mortgage bonds were
issued provide for an immaterial restriction as to distributions to
shareholders at December 31, 1993.
Note 6 - Capital Stock
In October 1990, the company issued through dividend to its common share-
holders certain stock rights which expire in October 2000. The rights to
purchase junior preference shares, common 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.
On April 30, 1992, the company issued shares of Redeemable Cumulative
Preferred Stock, 9.90% Series consisting of the previously issued shares of
Auction Preferred Stock. The company elected to establish a 10-year dividend
period for this preferred stock, with mandatory redemption April 1, 2002. The
dividend rate on the shares of Redeemable Cumulative Preferred Stock, 9.90%
Series was determined at an auction held on April 23, 1992. Dividends on the
shares are cumulative from April 30, 1992, and will be payable when, as and if
declared, quarterly on January 1, April 1, July 1 and October 1 of each year
commencing July 1, 1992.
In accordance with FAS 107, the company estimates the fair value of its
redeemable cumulative preferred stock based on the per share closing price
times the number of shares outstanding. The book value and estimated fair
value of the redeemable cumulative preferred stock were $38 million and $43.6
million at December 31, 1993 and $38 million and $42 million at December 31,
1992, respectively. The estimate presented herein is not necessarily indicative
of the amount 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 amount.
Note 7 - Commitments and Contingencies
Rate Matters - In 1985 the company incurred $15.8 million in increased fuel and
purchased power expenses after a ruptured steam line at the jointly owned
Mohave Generating Station resulted in a loss of the plant for six months. The
PSC allowed the company to recover one half of the increased expenses subject
to refund. Fourth quarter 1990 earnings reflected a $12.9 million charge to
record a subsequent proposed order issued by the PSC which stated that the
company shall not recover any of the increased costs. The company has fully
reserved for any negative financial effect related to the proposed order. In
1991, the PSC set aside the proposed order and ordered the parties to
participate in joint hearings before the CPUC. The CPUC hearings are now
concluded, and the PSC will prepare its own opinion based on the record
created in the CPUC hearings. In January 1994, the administrative law judge
in the CPUC proceeding issued a proposed opinion denying recovery to SCE of
its incremental purchased power costs resulting from the accident. SCE has
filed comments with the CPUC concerning the proposed decision.
On August 12, 1993, the company filed a request with the PSC to recover
additional fuel and purchased power costs of $29.7 million under the state's
deferred energy accounting procedures. This request included $9.8 million of
deferred energy costs for the period of December 1, 1992, to May 31, 1993, and
$19.9 million to adjust the base energy rate. The company subsequently amended
its request to $26.8 million. Hearings in this
Nevada Power Company 37
<PAGE>
<PAGE>
Notes to Financial Statements
matter were concluded in December 1993, and the PSC granted an increase in rates
of $23.6 million, effective February 1, 1994. The PSC order resulted in fourth
quarter 1993 charges of $2 million net of taxes for deferred energy costs.
On July 11, 1991, Nevada Electric Investment Co. (NEICO), the company's
unregulated subsidiary, entered into an agreement to sell a 50 percent
undivided ownership interest in certain coal mining assets to the
Intermountain Power Agency (IPA). NEICO and IPA will continue the coal
mining operations as joint venturers under the name of the Crandall Canyon
Project. Additionally, IPA has executed a continuing coal purchase agreement.
This transaction has been inquired into by the PSC, and no gain on the
transaction has been recorded pending regulatory review which is expected in
1994.
Legal Matters - In December 1992, the company suspended deliveries under a
coal contract with Mountain Coal Co. based on a pricing dispute. Mountain
Coal Co. filed a lawsuit in the federal district court for the State of Utah
seeking a determination that the company had repudiated the coal supply
agreement. In October 1993, the court found in favor of Mountain Coal Co.'s
position. The company appealed the court's order, however, in March 1994,
the company resolved the litigation and bought out the remaining obligation
under the contract by issuing a promissory note (bearing interest at 10%) for
a total of $25 million. The facility using the coal under this contract is
jointly owned; accordingly the company's portion of this settlement is $15.25
million. The settlement and buyout have been recorded as of December 31, 1993,
with $25 million included in notes payable, $15.25 million included in
deferred energy costs and $9.75 million included in other receivables. The
settlement and buyout will result in lower fuel costs to the company's
customers over the otherwise remaining life of the contract; accordingly,
based on similar past buyouts, management believes that the cost of the
buyout will be recovered through Nevada's deferred energy accounting
procedures.
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 and results of operations.
Environmental Matters - The Federal Clean Air Act Amendments of 1990 include
provisions which will affect the company's existing steam generating
facilities and all new fossil fuel fired facilities. Title IV of the
Amendments provides a national cap on sulfur dioxide emissions by mandating
emissions reductions for many electric steam generating facilities. The
sulfur dioxide provisions of the Amendments will not adversely affect the
company because the company's steam units burn low sulfur fuels or have
sulfur dioxide control equipment. Title IV of the Amendments also provides
for reduction of emissions of oxides of nitrogen by establishing new
emission limits for coal-fired generating units. This Title 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. Other provisions of the Amendments will
require the company to install or upgrade Continuous Emission Monitoring
systems at all steam generating units before 1995 at an expected cost of up
to $3.3 million.
The United States Congress authorized $2 million for the Environmental
Protection Agency (EPA) to study the potential impact the Mohave Generating
Station (MGS) may have on visibility in the Grand Canyon. The EPA report is
expected to be finalized in late 1995, with a follow-up report from the Grand
Canyon Visibility Transport Commission in late 1996. Also, the Nevada Division
of Environmental Protection has imposed more stringent stack opacity limits
for the MGS. This change may affect the company's utilization of resources,
but, until more experience is gained by operating at the new opacity levels,
any effect cannot be determined. As a 14 percent owner of the MGS, the company
will be required to fund any plant improvements that may result from the EPA
study and operation at the new opacity levels. The cost of any potential
improvements cannot be estimated at this time.
In 1991, the U.S. Environmental Protection Agency published an order
requiring the Navajo Generating Station (NGS) to install scrubbers to remove
90 percent of sulfur dioxide beginning in 1997. As an 11.3 percent owner of
the NGS, the company will be required to fund an estimated $46.6 million for
installation of the scrubbers. In 1992, the company received resource
planning approval from the PSC for its share of the cost of the scrubbers up
to $46.6 million.
38 Nevada Power Company
<PAGE>
<PAGE>
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, 1993, are as follows:
(In thousands)
___________________________________________________________________________
1994 $ 3,605
1995 3,604
1996 3,605
1997 3,604
1998 3,605
Thereafter 109,937
--------
$127,960
========
___________________________________________________________________________
The amount of imputed interest necessary to reduce the future cash rental
payments to present value is $85.7 million as of December 31, 1993.
Total interest expense on the lease obligation was $4 million and total
amortization of the leased facility was $402,000 for the year ended December
31, 1993. The total accumulated amortization of the leased facility on
December 31, 1993, was $9 million.
At December 31, 1993, the company has certain long-term noncancellable
operating lease agreements for which the future minimum lease payments are
immaterial.
Fuel and Purchased Power Obligations - The company has five long-term
contracts for the purchase of electric energy and/or capacity. The contracts
expire in years ranging from 1995 to 2016.
Total payments under these contracts were $55.9 million, $51.4 million
and $42.6 million in 1993, 1992 and 1991, respectively. The cost of power
obtained under these contracts is included in purchased power expense in the
statements of income.
At December 31, 1993, 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:
Accounted for Accounted for
as Long-term as Long-term
(In thousands) Executory Contracts Capital Lease
___________________________________________________________________________
1994 $ 35,600 $ 14,591
1995 36,150 13,986
1996 27,600 13,432
1997 28,600 12,902
1998 18,450 12,373
Thereafter 1,800 145,631
----------------------------------
Total minimum payment $148,200 212,915
========
Less amount representing estimated
executory costs included in total
minimum payment (98,232)
--------
Net minimum payments 114,683
Less amount representing interest (47,022)
--------
Present value of net minimum payments $ 67,661
========
___________________________________________________________________________
Nevada Power Company 39
<PAGE>
<PAGE>
Notes to Financial Statements
Total interest expense on the purchase power obligation accounted for as a
capital lease was $6.7 million and total amortization was $5.5 million in
1993. Total accumulated amortization was $15.3 million for the year ended
December 31, 1993.
The company has contracted with various coal suppliers to provide coal
to the Reid Gardner Generating Station. The contracts expire in years ranging
from 1994 to 2007.
The costs of approximately $33.9 million, $38.2 million and $44.6
million were incurred under the long-term coal contracts in 1993, 1992 and
1991, respectively.
At December 31, 1993, the estimated future payments for coal that the
company is obligated to purchase under these contracts are as follows:
(In thousands)
__________________________________________________________________________
1994 $ 29,128
1995 19,776
1996 17,258
1997 17,775
1998 18,308
Thereafter 182,258
--------
$284,503
========
__________________________________________________________________________
Construction - Certain commitments have been incurred at December 31, 1993, in
connection with the 1994 construction budget. Construction expenditures are
estimated at $175 million, including AFUDC, for 1994.
Note 8 - Other Deferred Charges and Credits
Other Deferred Charges - At December 31, 1993, as a result of the company
adopting FAS 109 effective January 1, 1993, other deferred charges include a
regulatory asset of $46 million and a deferred tax asset of $19.1 million.
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.
As a result of the company adopting FAS 106 effective January 1, 1993, a
regulatory asset and a postretirement benefit liability of $3.1 million are
included in other deferred charges and other current liabilities,
respectively, at December 31, 1993. The regulatory asset and benefit
liability represent the difference between the postretirement benefit costs
expensed by the company on a pay-as-you-go basis as authorized by the PSC and
the costs resulting from the implementation of FAS 106.
At December 31, 1993, organizational study, early retirement and
severance costs of $6.7 million are included in other deferred charges to be
amortized over three years beginning February 1994. Of such costs, $5.5
million are related to the company's defined benefit retirement plan and are
included in other current liabilities as a part of the pension liability of
$5.8 million at December 31, 1993.
In May 1988, after securing PSC approval, the company paid United States
Fuel Company $23.5 million to terminate an existing coal supply agreement.
The amount paid plus carrying charges is being amortized over eight years and
the amounts included in other deferred charges and deferred energy costs as of
December 31, 1993, were $6.4 million and $2.3 million,respectively.
Other deferred charges as of December 31, 1993, also include $12.4
million for deferred federal income taxes on customer advances for
construction and $8.9 million for conservation programs.
Other Deferred Credits - As of December 31, 1993, a credit of $4.7 million
for generating station spare parts is included in other deferred credits.
Effective January 1992, this credit is being amortized over a six-year
period.
Other deferred credits as of December 31, 1993, also include a
regulatory liability of $32 million representing amounts to be refunded
to customers in the future as a result of the company adopting FAS 109.
40 Nevada Power Company
<PAGE>
<PAGE>
Note 9 -Interests in Jointly Owned Electric Utility Facilities
At December 31, 1993, the company owned the following undivided interests in
jointly owned electric utility facilities:
Company's Share of
_________________________________________________
Percent Construction
Owned by Plant Accumulated Net Plant Work in
(In thousands) Company In Service Depreciation In Service Progress
______________________________________________________________________________
Facility
Navajo Project 11.3 $132,370 $ 59,999 $ 72,371 $ 6,016
Mohave Project 14.0 67,479 27,559 39,920 4,888
Reid Gardner
Plant
Unit No. 4 32.2 133,528 30,516 103,012 869
---------------------------------------------
Total $333,377 $118,074 $215,303 $11,773
=============================================
______________________________________________________________________________
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
Statements of Income.
Note 10 - Quarterly Financial Data (unaudited)
Earnings Earnings
(In thousands, Available per Average
except per share Electric Operating Net for Common Common
amounts) Revenues Income Income Stock Share
___________________________________________________________________________
1993: First $132,814 $16,621 $ 8,379 $ 7,382 $0.20
Second 142,318 23,022 15,238 14,241 0.37
Third 232,263 54,957 47,113 46,117 1.13
Fourth 144,377 13,869 2,818 1,822 0.04
1992: First 122,902 12,035 2,022 820 0.02
Second 140,913 20,774 10,245 9,181 0.26
Third 206,868 51,198 42,982 41,984 1.15
Fourth 130,232 16,115 1,531 533 0.01
___________________________________________________________________________
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.
The fourth quarter of 1993 reflects write-offs of $5.6 million net of tax
or 14 cents per average common share for certain deferred amounts including
costs related to preliminary studies for the coal-fired White Pine Power Project
and for deferred energy.
The fourth quarter of 1992 reflects write-offs of $4.5 million net of tax
or 13 cents per average common share for certain deferred amounts including
costs related to a property loss at Reid Gardner Generating Station No. 4.
Nevada Power Company 41
<PAGE>
<PAGE>
Independent Auditors' Report
To the Board of Directors and Shareholders of Nevada Power Company:
We have audited the balance sheets of Nevada Power Company as of December 31,
1993 and 1992, and the related statements of income, retained earnings and
cash flows for each of the three years in the period ended December 31, 1993.
These financial statements are the responsibility of the company's management.
Our responsibility is to express an opinion on these 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 financial statements present fairly, in all material
respects, the financial position of the company at December 31, 1993 and 1992,
and the results of its operations and its cash flows for each of the three
years in the period ended December 31, 1993 in conformity with generally
accepted accounting principles.
As discussed in Notes 1 and 2 to the financial statements, the company
changed its method of accounting for income taxes effective January 1, 1993 to
conform with Statement of Financial Accounting Standards No. 109.
Deloitte & Touche
Deloitte & Touche
Las Vegas, Nevada
February 10, 1994
(March 11, 1994 as to the fourth paragraph of Note 7)
Report of Management
The management of Nevada Power Company is responsible for the financial
statements presented in this report. Management prepared the 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 Service Commission of Nevada
and the Federal Energy Regulatory Commission. In preparing the financial
statements, management made informed judgements 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 financial statements have been audited by Deloitte & Touche,
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 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 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 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
and the internal audit staff have complete and free access to the Audit
Committee.
42 Nevada Power Company
<PAGE>
<PAGE>
Stock Prices on New York Stock Exchange
and Dividends Per Share
1993 Quarters 1992 Quarters
_________________________________ __________________________________
First Second Third Fourth First Second Third Fourth
______________________________________________________________________________
Common
High $25 $25 3/4 $26 3/4 $26 1/4 $19 5/8 $19 1/8 $22 5/8 $24
Low 22 5/8 24 24 5/8 22 1/2 18 5/8 18 18 1/2 21 3/4
Dividend
paid .40 .40 .40 .40 .40 .40 .40 .40
______________________________________________________________________________
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 Stock Exchange.
Holders of common stock are entitled to dividends as are 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. See Note 5 of "Notes to Financial
Statements" for restriction on the company's ability to pay dividends.
The company had 47,239 shareholders of record of common stock at
December 31, 1993.
Nevada Power Company 43
<PAGE>
<PAGE>
<TABLE>
Statistical Summary 1993-1989
<CAPTION>
1993 1992 1991 1990 1989
___________________________________________________________________________________________________________________
<S> <C> <C> <C> <C> <C>
Summary of Operations
(In thousands, except per share amounts):
Electric Revenues:
Residential $ 267,941 $ 245,160 $ 216,784 $ 194,911 $ 179,333
Commercial and industrial 326,006 305,707 287,407 256,310 210,167
Other electric sales 48,504 42,011 34,459 35,057 27,767
Miscellaneous 9,321 8,037 7,761 6,043 5,635
----------------------------------------------------------------------
651,772 600,915 546,411 492,321 422,902
----------------------------------------------------------------------
Net Income (a) 73,548 56,780 35,176 24,992 51,467
Dividend Requirements on Preferred Stock 3,986 4,262 2,880 2,917 3,058
Earnings Available for Common Stock (a) $ 69,562 $ 52,518 $ 32,296 $ 22,075 $ 48,409
Weighted Average Number of Common
Shares Outstanding 39,482 35,652 30,855 28,330 26,693
Earnings Per Average Common Share (a) $ 1.76 $ 1.47 $ 1.05 $ .78 $ 1.81
Dividends Per Common Share $ 1.60 $ 1.60 $ 1.60 $ 1.58 $ 1.54
Capitalization
(In thousands, except per share amounts):
Long-Term Debt $ 716,589 $ 715,451 $ 578,540 $ 521,340 $ 460,366
Cumulative Preferred Stock 38,000 38,000 38,000 38,000 38,000
Cumulative Preferred Stock with
Mandatory Sinking Funds 4,264 4,464 4,664 4,864 5,067
Common Shareholders' Equity 645,924 532,473 460,307 406,291 383,150
Book Value Per Common Share $ 15.56 $ 14.34 $ 13.96 $ 14.05 $ 14.27
Return on Common Shareholders' Equity 10.77% 9.86% 7.02% 5.43% 12.63%
Electric Plant Investment (In thousands):
Gross $1,901,448 $1,739,633 $1,562,921 $1,345,107 $1,187,612
Depreciated 1,450,146 1,328,670 1,187,154 996,885 865,834
Total Assets (In thousands) $1,809,337 $1,557,040 $1,410,022 $1,236,210 $1,099,741
Construction Expenditures Excluding
AFUDC (In thousands) $ 157,458 $ 167,233 $ 145,271 $ 152,583 $ 120,134
Operating and Sales Data:
Generating Capacity and Firm
Purchases (Megawatts) 3,488 2,989 2,719 2,534 2,333
Peak Load (Megawatts) 2,681 2,501 2,373 2,248 2,092
Electric Sales (Megawatthours) 11,155,270 10,541,204 9,834,952 9,619,723 8,715,442
Number of Customers (Year End) 403,875 383,036 366,325 347,969 318,036
Average Annual Kilowatthour Sales
Per Residential Customer 13,008 13,343 13,213 13,331 13,624
Number of Employees (Year End) 1,741 1,734 1,689 1,639 1,543
___________________________________________________________________________________________________________________
</TABLE>
(a) Amount for 1990 includes a provision for a proposed regulatory
disallowance and other adjustments.
Amount for 1991 includes write-offs for deferred energy and environmental
study costs.
Amount for 1993 includes write-offs for deferred energy costs and
preliminary study costs for a cancelled coal-fired generating station
project.
44 Nevada Power Company 45
<PAGE>
<PAGE>
<PAGE>
NEVADA POWER COMPANY
1993 LONG-TERM INCENTIVE PLAN
ARTICLE I
PURPOSES
The purposes of this Plan are to motivate and reward corporate officers and
certain other key managerial employees of Nevada Power Company (the "Company")
to achieve the Company's long term objective of providing the Company
shareholders with an above average return on the shareholders' investment and to
retain in its employ and reward those persons who by their position, ability and
diligence are able to make important contributions to the Company's success.
ARTICLE II
DEFINITIONS
The terms used in this Plan shall have the following meanings:
(a) "Award" means the right to receive Incentive Compensation Units
following the adjustment, if any, by the Committee to previously granted Units
at the end of the Performance Period.
(b) "Board of Directors" means the Board of Directors of the Company.
(c) "Committee" means the Compensation Committee of the Board of
Directors of the Company.
(d) "Company" means Nevada Power Company.
(e) "Employee" means any person who is employed on a permanent basis
by and receives a regular salary from the Company.
(f) "Fair Market Value" means the average closing market price of the
common shares of the Company on the New York Stock Exchange for the 15 trading
days immediately preceding the date in question.
(g) "Grant" means a conditional right to receive Incentive
Compensation Units, subject to adjustment or rescission by the Committee
pursuant to the terms of the Plan.
(h) "Incentive Compensation Units" means the units granted or awarded
to Participants pursuant to the provisions of the Plan. Each Incentive
Compensation Unit awarded under the Plan represents the right to receive one
common share of the Company.
(i) "Participant" means any Employee who is granted Incentive
Compensation benefits hereunder.
(j) "Performance Period" means the time period beginning on the date
of the grant of Incentive Compensation Units (as defined below) pursuant to this
Plan, and ending on the third anniversary of the date of the grant.
(k) "Total Common Shareholder Return" means the dividends paid with
respect to the common shares of a company and the increase in the Fair Market
Value of the common shares of a company.
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ARTICLE III
ADMINISTRATION
(a) The complete and sole administration of the Plan is the responsibility
of the Compensation Committee (sometimes hereinafter called the "Committee"),
appointed by the Board of Directors. No member of the Committee shall be
eligible for any grant under the Plan for any period during which he served as a
member of the Committee. No member of the Committee shall be liable for any act
done or determination made in good faith.
(b) The construction and interpretation by the Committee of any provision
of this Plan shall be final and conclusive. The Committee shall determine, from
time to time, subject to the provisions of this Plan, the Employees who shall
participate in the Plan (sometimes hereinafter called "Participants"), and the
number of Incentive Compensation Units (sometimes hereinafter called "Units") to
be granted and awarded to each Participant under this Plan.
(c) The Committee's determinations under the Plan, including without
limitation, determinations as to the persons to receive grants or awards of
Units, the terms and provisions of such grants or awards and the agreements
evidencing the same, need not be uniform and may be made by it selectively among
persons who receive or are eligible to receive grants or awards under the Plan,
whether or not such persons are similarly situated.
ARTICLE IV
MAXIMUM NUMBER OF UNITS
The maximum number of Units outstanding according to the Incentive
Compensation Ledger to the credit of the Participants at any one time shall not
exceed 200,000 Units. Each Unit awarded under the Plan will represent the right
to receive one common share of the Company.
ARTICLE V
INCENTIVE COMPENSATION UNITS
(a) Incentive Compensation Units may be granted to persons who at the time
of the grant are full time Employees of the Company. While all such Employees
are eligible to be considered for the receipt of Incentive Compensation Units,
it is contemplated that only those Employees who perform services of special
importance to the Company in the management, operation, and development of the
business will be selected to receive Incentive Compensation Units. Subject to
the terms, provisions, and conditions of this Plan, the Committee is hereby
authorized to (a) select the Employees to be granted Incentive Compensation
Units (it being understood that more than one grant may be made to the same
person), (b) determine the number of Incentive Compensation Units covered by
each grant, and (c) prescribe the form, which shall be consistent with this
Plan, of the instruments evidencing any Incentive Compensation Units granted
under this Plan.
(b) The amount of the individual grant of Incentive Compensation Units to
the Employees will be determined by the Committee by giving consideration to the
functions and responsibilities of the Employee, the Employee's contribution to
the achievement of the Company's objectives, and such other factors as the
Committee deems relevant.
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ARTICLE VI
ADJUSTMENTS TO ACCOUNTS OF PARTICIPANTS
(a) At the end of each Performance Period, the Committee may adjust the
number of Incentive Compensation Units previously granted to the Participants
based upon the Total Common Shareholder Return of the Company as compared with
the Total Common Shareholder Return of companies included in the Merrill Lynch
Electric Utility Index during the Performance Period, or such other measures of
performance as the Committee deems appropriate.
(b) Except as otherwise provided herein, in making adjustments to the
number of Units granted to Participants pursuant to this Paragraph, the
Committee shall have the discretion to rescind the Incentive Compensation Units
previously granted to the Participants.
(c) Except as otherwise provided herein, in the event of any share
dividend on the common shares of the Company, any split-up or combination of the
common shares, any distribution other than in cash, the issuance of rights to
subscribe to additional common shares of the Company, or any material change in
the capitalization or business structure of the Company, appropriate adjustment
shall be made by the Committee subject to approval of the Board of Directors, in
the aggregate number of Units which may be granted and awarded under this Plan
and in the number of Units granted to each Participant under this Plan. In the
event of the reclassification of common shares of the Company into shares of any
other class, the Committee, subject to approval of the Board of Directors, is
authorized to make such adjustment in the terms of the Plan as the Committee may
deem equitable.
(d) Notwithstanding the foregoing, previously granted Units which have
been awarded to a Participant pursuant to the provisions of the Plan will not be
subject to adjustment or rescission.
ARTICLE VII
TERMINATION OF EMPLOYMENT
(a) A Participant whose employment with the Company is terminated by
voluntary resignation (other than retirement) or by termination for cause during
a Performance Period will not be entitled to an award of any of the Incentive
Compensation Units granted to him (nor to any upward adjustments to such grant),
except as provided in Paragraph (b) of Article VIII, unless the Committee in its
absolute discretion determines the circumstances exceptional and not contrary to
the interest of the Company.
(b) A Participant whose employment with the Company is terminated without
cause due to retirement or death during a Performance Period will be entitled to
a prorated portion of a grant based upon the proportion of full time employment
during the Performance Period, counting the year of retirement as a full year,
after adjustment to the Units granted pursuant to Article VI.
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ARTICLE VIII
PAYMENT OF AWARDS
(a) At the end of a Performance Period, or upon the termination of any
Participant's employment with the Company, and after the adjustment provided for
by Article VI, there shall be awarded to the Participant, or in the event of the
Participant's death to his Beneficiary or Beneficiaries designated under
Paragraph (d) of this Article VIII, the Incentive Compensation Units previously
granted to the Participant.
(b) Notwithstanding anything herein to the contrary, in the event of a
change in control of the Company, Units previously granted to Participants under
the Plan shall automatically be awarded to Participants without the necessity of
further action by the Committee or Company and shall be paid to Participants
pursuant to this Article VIII. The occurrence of any of the following events
shall constitute a change in control of the Company: (1) the dissolution or
liquidation of the Company; (2) the reorganization, merger, or consolidation
with one or more corporations in which the Company is not the surviving
corporation; (3) 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; (4) 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 (5) the sale of all or substantially all of the
Company's assets.
(c) Awards shall be made by payment to the Participant of one common share
of the Company for each Incentive Compensation Unit awarded to the Participant.
(d) Each person within 30 days of becoming a Participant under this Plan
shall file with the Secretary of the Company a notice in writing designating one
or more Beneficiaries to whom payments otherwise due the Participant shall be
made in the event of his death while in the employ of the Company or after
severance therefrom. The benefits of a deceased Participant who has not
completed a beneficiary designation shall be paid to the Participant's spouse,
or if none, to the Participant's estate.
(e) Notwithstanding the foregoing, and except as provided in Paragraph (b)
of this Article VIII, previously granted Incentive Compensation Units will not
be awarded at the end of a Performance Period if dividends on the common shares
of the Company have been reduced during the Performance Period, and any Units
granted at the beginning of the Performance Period will be held until such time
as the Committee determines that the grant shall be either awarded or rescinded.
ARTICLE IX
NONALIENATION OF BENEFITS
No right or benefit or payment under this Plan shall be subject to
transfer, anticipation, sale, assignment, pledge, encumbrance, or charge, and
any attempt to anticipate, sell, assign, pledge, encumber, or charge the same
shall be void. No right or benefit or payment hereunder shall in any manner be
liable for or subject to the debts, contracts, liabilities, or torts of the
person entitled to such benefits. If any Participant or Beneficiary hereunder
should become bankrupt or attempt to transfer, anticipate, alienate, sell,
assign, pledge, encumber, or charge any right or benefit or payment hereunder,
then such right or benefit or payment shall, in the sole discretion of the
Committee, terminate.
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ARTICLE X
AMENDMENT OR TERMINATION OF PLAN
(a) The Board of Directors may amend or terminate this Plan at any time,
except that Units awarded to a Participant (and the corresponding right to
receive common shares of Company stock) pursuant to the Plan may not be subject
to reduction or rescission, and except that without approval by vote of holders
of the outstanding common shares of the Company, the maximum number of Plan
Units which may be granted to all Participants may not be increased and this
Article X may not be amended.
(b) Unless sooner terminated pursuant to the provisions herein, the Plan
shall terminate on January 1, 2006. No grants of Incentive Compensation Units
shall be made under this Plan after December 31, 2002, and no awards of
Incentive Compensation Units shall be made under this Plan after December 31,
2005.
ARTICLE XI
MISCELLANEOUS PROVISIONS
(a) No Employee or other person shall have any claim or right to receive
Units under the Plan until an award is approved by the Committee, except as
provided in Paragraph (b) of Article VIII. Neither the Plan nor any action taken
hereunder shall be construed as giving any Employee any right to be retained in
the employ of the Company.
(b) The Plan shall at all times be entirely unfunded and no provision
shall at any time be made with respect to segregating assets of the Company for
the payment of any benefits hereunder. No Participant or other person shall have
any interest in any particular asset of the Company by reason of the right to
receive a benefit under the Plan and any such Participant or other person shall
have only the right of a general unsecured creditor of the Company with respect
to any rights under the Plan.
(c) The Company shall have the right to deduct from all amounts paid
pursuant to the Plan any taxes required by law to be withheld with respect to
such award.
(d) No Employee shall have any right as a shareholder under this Plan
unless and until certificates for shares of common shares are transferred to
Employee in payment of an award hereunder.
(e) For purposes of paying benefits to the Participants pursuant to the
Plan, the Committee may purchase common shares, may use common shares held in
the Company's treasury, or may issue authorized but unissued common shares,
subject to appropriate regulatory approval.
(f) The obligation of the Company to sell and deliver common shares under
the Plan shall be subject to all applicable laws, regulations, rules and
approvals, including, but not by way of limitation, the effectiveness of a
registration statement under the Securities Act of 1933 if deemed necessary or
appropriate by the Company. Certificates for shares of common shares issued
hereunder may be legended as the Board shall deem appropriate.
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ARTICLE XII
EFFECTIVE DATE OF PLAN
This Plan shall become operative and in effect on such date as shall be
fixed by the Board of Directors of the Company in its sole discretion following
approval by vote of the holders of the outstanding common shares of the Company.
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LAS VEGAS COGENERATION LIMITED PARTNERSHIP CONTRACT
WITH
NEVADA POWER COMPANY
FOR
LONG TERM POWER PURCHASES
FROM A
QUALIFYING FACILITY
<PAGE>
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TABLE OF CONTENTS
SECTION PAGE
1. INTRODUCTION AND AGREEMENT.......................... 1
2. DEFINITIONS......................................... 2
3. CONTRACT TERMINATION AND MILESTONES................. 5
4. CAPACITY AND ENERGY PAYMENT PROVISIONS.............. 7
5. CAPACITY REQUIREMENTS............................... 9
6. CAPACITY AND ENERGY METERING........................ 11
7. SELLER'S FACILITIES................................. 13
8. NEVADA'S FACILITIES................................. 21
9. INTERCONNECTION FACILITIES AGREEMENT................ 23
10.OPERATIONS COORDINATION AGREEMENT................... 23
11.IMPROVEMENTS AGREEMENTS............................. 23
12.ESCROW PROVISIONS................................... 23
13.BILLING PROVISIONS.................................. 24
14.ASSIGNMENT AND DELEGATION........................... 24
15.TAXES............................................... 25
16.LIABILITY........................................... 25
17.INSURANCE........................................... 26
18.UNCONTROLLABLE FORCES............................... 26
19.NON-DEDICATION OF FACILITIES........................ 27
20.AMENDMENTS.......................................... 27
21.PREVIOUS COMMUNICATIONS............................. 27
22.NON-WAIVER.......................................... 27
23.DISPUTES............................................ 27
24.REMEDIES............................................ 28
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25.GOVERNING LAW....................................... 28
26.NATURE OF OBLIGATIONS............................... 28
27.COMMISSION APPROVAL................................. 28
28.SIGNATURES.......................................... 29
EXHIBIT A
Payment Provisions..................................... A-1
EXHIBIT B
Interconnection Facilities Agreement................... B-1
EXHIBIT C
Operations Coordination Agreement...................... C-1
EXHIBIT D
Project Improvement Agreement.......................... D-1
EXHIBIT E
Procedure for Establishing Firm Operation.............. E-1
EXHIBIT F
Form of Insured Endorsement............................ F-1
EXHIBIT G
Standby Service Agreement.............................. G-1
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1. INTRODUCTION AND AGREEMENT:
This Contract and its Exhibits, entered into between NEVADA
POWER COMPANY (Nevada) and LAS VEGAS COGENERATION LIMITED
PARTNERSHIP (Seller), constitutes the entire agreement
between the Parties for the sale of electric capacity and
energy to Nevada from a Qualifying Facility owned and operated
by Seller.
1.1 Seller shall own, operate, and maintain a Qualifying
Facility providing electric capacity and energy which
Nevada agrees to purchase under the terms and conditions
of this Contract.
1.1.1 Operating Option: During On-Peak hours, the entire
electric capacity and energy output of Seller's
Generating Facility net of station usage shall be
dedicated to Nevada. During all other hours, Nevada
shall have first right of refusal to purchase the
entire electric capacity and energy output of
Seller's Generating Facility net of station usage.
1.2 Notices to Seller:
1.2.1 Written notices and correspondence shall be sent to
Seller at the following address:
Las Vegas Cogeneration Limited Partnership
c/o United Cogen
Glenway Avenue
P.O. Box 1280
Bristol, VA 24203
1.2.2 Seller's Operating Representative shall be: J.
Thomas Fowlkes.
1.2.3 Oral notices shall be conveyed to Seller via
telephone at: (703) 466-3322.
1.2.4 Notices to Seller shall be effective upon receipt
by Seller.
1.3 Notices to Nevada:
1.3.1 Written notices and correspondence shall be sent to
Nevada at the following address:
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Nevada Power Company
Attention: Secretary
P. O. Box 230
Las Vegas, Nevada 89151
with a copy to Nevada's Operating Representative at
the same address.
1.3.2 Nevada's Operating Representative shall be the
Manager of Power Systems Operations; the Supervisor
of Interchange Scheduling shall be Nevada's
Alternate Operating Representative.
1.3.3 Oral notices shall be conveyed to Nevada's
Operating Representative via telephone at:(702) 367-
5390.
1.3.4 Notices to Nevada shall be effective upon
receipt by Nevada.
1.4 Seller's Qualifying Facility:
1.4.1 Prior to Firm Operation, Seller shall obtain
Qualifying Facility status for Seller's Generating
Facility and shall maintain qualification as
required by the Federal Energy Regulatory Commission
throughout the Contract Term.
1.4.2 Location: S.E. Corner of Alexander and Bruce
North Las Vegas, Nevada
1.4.3 Contract Capacity: 45 MW.
1.4.4 Estimated Annual Energy Delivery: 208,000 MWH.
1.4.5 Fuel Type: Gas.
1.4.6 The expected date of Firm Operation for
Seller's Facilities is June 1, 1994. Nevada's
Facilities shall be completely constructed and
capable of energization not later than February 1,
1994.
2. DEFINITIONS: Common electric utility industry terms shall
have the meaning ascribed to them in the Edison Electric
Institute "Glossary of Electric Utility Terms" (Pub. No. 04-
84-06). The following terms, whether used in the singular or
plural, and when initially capitalized, shall have the
indicated meanings:
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2.1 Applicable Laws: Any effective law, rule, regulation,
ordinance, order, code, judgment, decree, injunction, or
decision of any federal, state, or local government,
authority, agency, court, or other governmental body
having jurisdiction over the matter in question.
2.2 Applicable Permits: Any action, approval, consent,
waiver, exemption, variance, franchise, order,
authorization, right, or license required in connection
with Seller's Facilities.
2.3 Capacity: The kilowatts produced by Seller's Generating
Facility and purchased by Nevada.
2.4 Commission: The Public Service Commission of Nevada.
2.5 Contract: This document and its attached exhibits, as
amended.
2.6 Contract Capacity: The electric power producing
capability of Seller's Generating Facility that is
dedicated to Nevada and more specifically described in
Section 1.4.3.
2.7 Contract Term: The period during which Nevada shall
purchase Capacity or Energy, or both, from Seller and
ending on the date set forth in Section 3.1.
2.8 Electric System Integrity: The state of operation of an
electric system that maximizes the health, welfare, and
safety of personnel and the general public; minimizes the
risk of injury to personnel and the general public;
minimizes the risk of damage to property; and maximizes
the system's ability to provide electric service to
customers in accordance with electric utility standards.
2.9 Emergency: Any condition that, in Nevada's judgment,
adversely affects Nevada's Electric System Integrity.
2.10 Energy: The kilowatt-hours produced by Seller's
Generating Facility that are purchased by Nevada.
2.11 Excess Capacity: Capacity that exceeds Contract
Capacity.
2.12 Excess Energy: Energy associated with Excess Capacity.
2.13 Firm Operation: The date agreed upon by the Parties on
which Seller complied with the requirements of Exhibit E.
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2.14 Forced Outage: Any outage, other than a Scheduled
Outage, that fully or partially curtails the production
or delivery of Energy to Nevada.
2.15 Generating Facility: A plant containing prime movers,
electric generators, and auxiliary equipment required to
produce electric energy.
2.16 Interconnection Facilities: The facilities that shall be
required to connect a Generating Facility to an electric
system, and the incremental facilities that shall be
required to transmit the output of a Generating Facility
to distribution points on that electric system.
2.17 Interconnection Point: The point designated in Exhibit B
where the transfer of electric energy between Nevada and
Seller will take place.
2.18 Lender: The entities that have provided financing for
Seller's Facilities.
2.19 Maintenance Months: As designated in Exhibit A, the
months of March, April, October, and November.
2.20 Nevada: Nevada Power Company, its directors, officers,
employees, and agents with authority to act on its
behalf.
2.21 Off-Peak Hours: The hours designated in Exhibit A.
2.22 On-Peak Hours: The hours designated in Exhibit A.
2.23 Operating Communications: Any transmittals between the
Parties of information required to ensure Nevada's
Electric System Integrity. Provisions for Operating
Communications are contained in Exhibit C.
2.24 Operating Representative: The individuals appointed by
each Party to ensure effective communication,
coordination, and cooperation between the Parties.
Either Party may change its Operating Representative by
providing written notice of the change to the other
Party. Such changes shall not be considered amendments
to this Contract.
2.25 Party: Nevada or Seller.
2.26 Qualifying Facility: A cogeneration or small power
production facility that meets the criteria defined in
Title 18, Code of Federal Regulations, Sections 292.201
through 292.207.
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2.27 Scheduled Outage: Any outage, other than a Forced
Outage, that shall fully or partially curtail the
production and delivery of Seller's electric energy to
Nevada and has been noticed in accordance with the
requirements of this Contract.
2.28 Seller: The entity designated in Section 1, its
directors, officers, employees, and agents with authority
to act on its behalf.
2.29 Tariff: The rate schedules and service rules that have
been promulgated by Nevada and approved by the
Commission, as amended from time to time. Nevada's
Tariffs shall be on file with the Commission.
2.30 Uncontrollable Force: Any occurrence beyond the
reasonable control of a Party that renders a Party
incapable of performing its obligations. Uncontrollable
Forces shall include, but not be limited to floods,
droughts, earthquakes, storms, fires, pestilence,
lightning or other natural catastrophes; epidemics; wars;
riots, civil disturbance, or other civil disobedience;
strikes or other labor disputes; action or inaction of
legislative, judicial, regulatory, or other governmental
bodies that may render or may have rendered actions
illegal in accordance with this Contract; and failure,
threat of failure, or sabotage of facilities that have
been operated and maintained in accordance with the
requirements of this Contract.
3. CONTRACT TERMINATION AND MILESTONES:
3.1 This Contract shall become effective upon execution by
the Parties and shall terminate on May 31, 2024 unless
the Commission does not approve this Contract within
ninety (90) days of receipt from Nevada; in that case,
this Contract shall terminate ninety (90) days after
Commission receipt. If, however, the docket assigned to
this Contract is scheduled for hearing within ninety (90)
days of receipt of this Contract by the Commission, then
the Contract shall terminate six (6) months after the
Commission's receipt if it has not been approved by the
Commission according to Section 27. Any amendments to
this Contract shall also be subject to the approval
process described in this Section 3.1.
3.2 Seller has established the following milestones to
demonstrate to Nevada diligent development of Seller's
Facilities.
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3.2.1 Not later than May 1, 1993, Seller shall
provide Nevada a copy of Seller's Agreement with
Seller's steam host. Confidential and proprietary
information may be deleted from the submittal.
3.2.2 Not later than May 1, 1993, Seller shall obtain
a firm, fifteen (15) year primary and secondary
fuel supply and related transportation. Seller
shall provide Nevada copies of signed agreements
indicating accomplishment of this project
development task. Confidential and proprietary
information may be deleted from the submittals.
3.2.3 Not later than May 1, 1993, Seller shall
provide Nevada a copy of Seller's water service
agreement; zoning permits; Clark County Health
District/Environmental Protection Agency Permit to
Construct; and, Utility Environmental Protection Act
(UEPA) Permit to construct as described in NRS
704.820 to 704.900, inclusive.
3.2.4 Not later than July 1, 1993, Lender shall
provide Nevada a letter written on Lender's
corporate letterhead stationery certifying that it
is providing full project financing for Seller
through Firm Operation.
3.2.5 Not later than April 1, 1993, Seller shall
provide Nevada a copy of its Engineering,
Procurement, and Construction (EPC) Contract
evidencing consummation of a turnkey agreement for
project construction. Confidential and proprietary
information may be deleted from the submittal.
3.2.6 Not later than February 1, 1994, Seller shall
start construction, i.e., pour first structural
concrete, of Seller's Facilities. Commencing with
start of construction, Seller shall provide Nevada
copies of monthly construction progress reports.
3.2.7 Not later than May 1, 1994, Seller shall
provide Nevada a copy of the Federal Energy
Regulatory Commission (FERC) Order granting
Application for Certification as a Qualifying
Facility for Seller's Facilities.
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3.2.8 Not later than January 1, 1995, Seller shall
achieve Firm Operation of Seller's Facilities.
If Seller does not achieve Firm Operation by June 1,
1994, for any reason, and Nevada must purchase
replacement power between June 1, 1994 and January
1, 1995 at a cost higher than the contract rate,
Seller agrees to reimburse Nevada the difference
between Nevada's replacement power cost and the cost
Nevada would have paid Seller for the same increment
of power.
3.3 This contract shall be terminated thirty (30) days after
Seller's failure to meet any milestone specified in
Section 3.2, unless such failure has been caused by
Nevada, or unless such failure has been cured by Seller
or Lender within thirty (30) days of Seller's failure to
meet the specified milestone.
3.3.1 The milestones of Section 3.2 shall be
appropriately adjusted to reflect any delays caused
by Nevada.
3.4 Termination of this Contract shall not excuse either
Party from any obligations, other than Seller's
obligation to deliver additional Capacity and Energy to
Nevada, incurred by either Party prior to termination of
this Contract. This Contract shall remain effective
until both Parties have discharged their obligations and
have exercised their rights and remedies in accordance
with the provisions of this Contract.
4. CAPACITY AND ENERGY PAYMENT PROVISIONS:
4.1 Capacity Rates:
4.1.1 Starting with Firm Operation and continuing
through the Contract Term, Seller shall be paid for
Capacity at the rates agreed upon by the Parties and
set forth in Exhibit A.
4.1.2 Prior to Firm Operation, Seller shall not be
paid for capacity unless Nevada, because of
operating conditions, experiences a capacity
requirement that may be met by Seller, in which case
Seller shall be paid for Capacity at Nevada's Tariff
Schedule QF-Short Term Capacity rates effective at
the time of delivery.
4.1.3 Seller shall not be paid for Excess Capacity
unless Nevada, because of operating conditions,
experiences a capacity requirement that may be met
by Seller's Excess Capacity, in which case Seller
shall be paid for Excess Capacity at Nevada's Tariff
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Schedule QF-Short Term Capacity rates effective at
the time of delivery.
4.1.4 If Seller obtains Qualifying Facility status
prior to Firm Operation and subsequent to Firm
Operation loses such status for reasons beyond
Seller's reasonable control, Seller shall be paid
for Capacity delivered to Nevada during the periods
that Seller does not have Qualifying Facility status
at rates equal to eighty (80) percent of the
Capacity rates otherwise agreed upon by the Parties.
4.2 Energy Rates:
4.2.1 Starting with Firm Operation and continuing
through the Contract Term, Seller shall be paid for
Energy at the rates agreed upon by the Parties and
set forth in Exhibit A.
4.2.2 Prior to Firm Operation, Seller shall be paid
for Energy at Nevada's Tariff Schedule QF-Short Term
Energy rates effective at the time of delivery.
4.2.3 Seller shall be paid for Excess Energy at
Nevada's Tariff Schedule QF-Short Term Energy rates
effective at the time of delivery.
4.2.4 If Seller obtains Qualifying Facility status
prior to Firm Operation and subsequent to Firm
Operation loses such status for reasons beyond
Seller's reasonable control, Seller shall be paid
for Energy delivered to Nevada during the periods
that Seller does not have Qualifying Facility status
at Energy rates equal to eighty (80) percent of the
Energy rates otherwise agreed upon by the Parties.
4.3 Payment Procedures:
4.3.1 Not later than thirty (30) days after the end
of each monthly payment period, Nevada shall send
Seller a statement showing the Capacity and Energy
received by Nevada during the payment period and
Nevada's check in payment of the amount due Seller.
If two or more rates are applicable to any payment
period, Nevada's payment shall be based upon the
amount of Capacity and Energy received by Nevada
during the period each rate was applicable, or, if
such information is unavailable, Nevada's payment
shall be based upon the number of hours each rate
was applicable.
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4.3.2 Seller shall have the right of access to
Nevada's records that are reasonably required to
confirm the accuracy of Nevada's statement. Within
thirty (30) days of Seller's receipt of Nevada's
statement, Seller shall notify Nevada in writing of
any error in Nevada's statement. If Seller fails to
provide such notice, Seller shall waive all rights
to an adjusted payment for the subject payment
period.
If Seller notifies Nevada of an error in Nevada's
statement, or if Nevada discovers an error in its
statement within thirty (30) days of issuing the
statement, Nevada shall provide an adjusted
statement to Seller. If Nevada's error results in
an additional payment to Seller, Nevada's check in
payment of the amount due Seller shall accompany the
adjusted statement. If Nevada's error results in a
refund to Nevada, Nevada's bill for the amount due
Nevada shall accompany the adjusted statement.
5. CAPACITY REQUIREMENTS: Unless otherwise provided within this
section, Uncontrollable Forces shall not excuse Seller from
the performance requirements of this section.
5.1 Performance Requirements: Unless otherwise instructed by
Nevada, Seller shall make Contract Capacity available to
Nevada during On-Peak hours during the Contract Term.
Seller shall be considered to have met that obligation
whenever Seller meets or exceeds the performance
requirements of this Section 5.
5.1.1 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
equal or exceed the product of Contract Capacity,
the number of On-Peak hours during that season, and
0.90.
5.1.2 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
equal or exceed the product of Contract Capacity,
the number of On-Peak hours during that season, and
0.90.
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5.1.3 For the purposes of this section, On-Peak hours
shall be those hours designated in Exhibit A for the
summer and winter seasons less any coincidental
operating hours lost because of the occurrence of
the events expressly listed in Sections 5.2.1 and
5.3.1.
5.2 Summer Probation:
5.2.1 If, for reasons other than limitations imposed
by Nevada, or natural catastrophes, epidemics, wars,
civil disobedience, or sabotage of facilities,
Seller fails to meet the performance requirements of
Section 5.1.1 during any summer season, Seller shall
be placed on summer probation for a period not to
exceed twelve (12) months.
5.2.2 If, for reasons other than limitations imposed
by Nevada, Seller fails to produce and deliver
Energy to Nevada that equals or exceeds the product
of Contract Capacity, the number of On-Peak hours in
the month, and 0.90 during any month of a summer
season within a summer probationary period, Nevada
shall have the right to extend the summer
probationary period for an additional twelve (12)
months or to reduce Contract Capacity to a level not
less than the average capacity level achieved by
Seller during the On-Peak hours of the preceding
summer season.
5.2.3 If Seller meets the performance requirements of
this Contract during each month of a summer season
within a summer probationary period, Seller shall be
taken off summer probation. Seller shall also be
taken off summer probation if Seller demonstrates,
to Nevada's reasonable satisfaction that the
problems which caused Seller to be placed on summer
probation have been rectified, and Seller is able to
produce and deliver Contract Capacity to Nevada in
accordance with the requirements of this Contract.
5.3 Winter Probation:
5.3.1 If, for reasons other than limitations imposed
by Nevada, or natural catastrophes, epidemics, wars,
civil disobedience, or sabotage of facilities,
Seller fails to meet the performance requirements of
Section 5.1.2 during any winter season, Seller shall
be placed on winter probation for a period not to
exceed twelve (12) months.
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5.3.2 If, for reasons other than limitations imposed
by Nevada, Seller fails to produce and deliver
Energy to Nevada that equals or exceeds the product
of Contract Capacity, the number of On-Peak hours in
the month, and 0.90 during any month of a winter
season within a winter probationary period, Nevada
shall have the right to extend the winter
probationary period for an additional twelve (12)
months or to reduce Contract Capacity to a level not
less than the average capacity level achieved by
Seller during the On-Peak hours of the preceding
winter season.
5.3.3 If Seller meets the performance requirements of
this Contract during each month of a winter season
within a winter probationary period, Seller shall be
taken off winter probation. Seller shall also be
taken off winter probation if Seller demonstrates,
to Nevada's reasonable satisfaction, that the
problems which caused Seller to be placed on winter
probation have been rectified, and that Seller is
able to provide Contract Capacity in accordance with
the requirements of this Contract.
5.4 Contract Capacity Changes: If Contract Capacity is
reduced for any reason the requirements and provisions of
this Contract shall remain applicable in their entirety
to the reduced capacity. If contract Capacity is reduced
for any reason, Seller shall, upon receipt of Nevada's
bill, refund to Nevada with interest at the rate
established by the Commission for Nevada's overall rate
of return, all payments to Seller in excess of the amount
that would have been paid if Contract Capacity reduction
had been in effect for the time periods shown in the
following table.
Contract Capacity In
Reduction Effect
0 to 1,000 kW 1 year
1,001 to 70,000 kW 3 years
6. CAPACITY AND ENERGY METERING:
6.1 Unless otherwise agreed upon by the Parties and set forth
in Exhibit B, meters and metering equipment to measure
Capacity and Energy shall be provided, owned, operated,
and maintained by Nevada as Nevada's Facilities.
6.2 Meters and metering equipment shall be installed in
locations designated by Nevada in Exhibit B. If the
meters and metering equipment are installed at locations
other than the Interconnection Point, Nevada shall have
the right to install loss compensation equipment to
reflect the losses that would have been recorded by the
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meters if the meters and metering equipment had been
installed at the Interconnection Point.
6.3 Seller shall not undertake any action that may interfere
with the operation of Nevada's meters and metering
equipment. If Seller fails to comply with the
requirements of this section, Nevada shall have the
right, without liability, to isolate Seller's Facilities
from Nevada's electric system until Nevada's meters and
metering equipment are reinstalled in a location that is
inaccessible to Seller.
6.4 Nevada's meters and metering equipment shall be tested
and calibrated upon installation and thereafter at
intervals not to exceed two (2) years in accordance with
the provisions of the American National Standard
Institute Code for Electricity Metering (ANSI C12.1,
latest revision). Nevada shall provide fifteen (15) days
prior written notice of meter testing to Seller. Seller
shall have the right to monitor Nevada's meter testing.
Seller shall also have the right to request additional
testing and calibration of Nevada's meters and metering
equipment. If so requested in writing, Nevada shall test
and calibrate Nevada's meters and metering equipment
within thirty (30) days of receipt of Seller's request.
If the accuracy of Nevada's meters and metering equipment
is within the limits established in ANSI C12.1, Seller
shall bear the cost of such additional tests. Billing
for such costs shall be in accordance with the
requirements of Section 13 or Exhibit B, whichever is
applicable. If the accuracy of Nevada's meters and
metering equipment is outside the limits established in
ANSI C12.1, Nevada shall bear the cost of such additional
tests.
6.5 If the accuracy of Nevada's meters and metering equipment
is outside the limits established in ANSI C12.1, Nevada
shall repair and recalibrate or replace Nevada's meters
and metering equipment, and Nevada shall adjust payments
to Seller for Capacity and Energy delivered to Nevada
during the period in which the inaccuracy existed. If
the period in which the inaccuracy existed cannot be
determined, adjustments shall be made for a period equal
to one-half of the elapsed time since the last test and
calibration of Nevada's meters and metering equipment;
however, the adjustment period shall not exceed six (6)
months. If adjustments are required, Nevada shall render
a statement describing the adjustments to Seller within
thirty (30) days of the date on which the inaccuracy was
rectified. Additional payments to Seller, or Nevada's
bill for refunds due Nevada, as applicable, shall
accompany Nevada's statement.
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6.6 If Nevada's meters fail to register, Nevada shall make
payments to Seller that are based upon Nevada's estimate
of the best available alternative information. Nevada's
estimated payments shall have the same meaning as actual
payments.
7. SELLER'S FACILITIES: Seller's Facilities shall mean Seller's
Generating Facility and Seller's Interconnection Facilities.
Seller's Interconnection Facilities are described in Exhibit
B.
7.1 Ownership: Seller's Facilities may be leased or owned,
and shall be designed, constructed, operated, maintained,
and improved by Seller. All costs associated with
Seller's Facilities, whether incurred by Nevada or by
Seller, shall be borne by Seller.
7.2 General:
7.2.1 Nevada shall have the right, without liability,
to either isolate Seller's Facilities from Nevada's
electric system or to refuse to connect Seller's
Facilities to Nevada's electric system if Seller
fails to comply with any of the requirements of this
Contract and adversely affects Nevada's Electric
System Integrity.
Nevada shall also have the right, without liability,
to either isolate Seller's Facilities from Nevada's
electric system or to refuse to connect Seller's
Facilities to Nevada's electric system if failure to
do so would render Nevada's conduct unlawful.
7.2.2 Seller shall neither solicit nor accept advice
from any Nevada representative except Nevada's
Operating Representative. If requested by Seller,
Nevada's Operating Representative shall provide, to
the extent possible, advice to Seller relative to
the design, construction, operation, maintenance,
and improvement of Seller's Facilities. Such advice
shall be provided as a courtesy. Seller shall save
harmless and indemnify Nevada from any direct or
indirect loss or liability, including attorney's
fees and other costs of litigation, resulting from
Seller's implementation of Nevada's advice.
7.2.3 Seller shall design, construct, operate,
maintain, and improve Seller's Facilities in
accordance with prudent engineering, construction,
operation, and maintenance practices. Seller shall
comply with all Applicable Laws even if compliance
necessitates improvements to Seller's Facilities or
interferes with the operation of Seller's
Facilities. In addition, Seller shall operate
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Seller's Facilities so as to ensure, to a reasonable
extent, the production and delivery of electric
energy to Nevada consistent with Nevada's
requirements. If Seller fails to comply with the
requirements of this section, Seller shall save
harmless and indemnify Nevada from any direct or
indirect loss or liability, including attorney's
fees and other costs of litigation, resulting from
Seller's failure to comply with these requirements.
7.2.4 Nevada shall have the right, without liability,
to monitor and make recommendations to Seller
regarding any aspect of the construction, operation,
maintenance, and improvement of Seller's Facilities
provided that such recommendations, if implemented,
do not unreasonably interfere with the construction,
operation, maintenance, or improvement of Seller's
Facilities and, provided further, that such
recommendations are required, in Nevada's reasonable
judgment, to maintain Nevada's Electric System
Integrity or to ensure compliance with the
requirements of this Contract. Nevada's
recommendations shall be made as a courtesy. Seller
shall save harmless and indemnify Nevada from any
direct or indirect loss or liability, including
attorney's fees and other costs of litigation,
resulting from Seller's implementation of Nevada's
recommendations.
7.2.5 Seller shall acquire and maintain all
Applicable Permits for Seller's Facilities.
7.2.6 Seller shall acquire and maintain all
easements, rights-of-way, and land rights required
for Seller's Facilities.
7.2.7 Seller shall complete all environmental impact
studies required for Seller's Facilities.
7.2.8 Seller shall complete all feasibility studies
required for Seller's Facilities.
7.3 Design:
7.3.1 Seller shall design Seller's Facilities so that
those facilities do not impose any voltage or
current upon Nevada's system that could interfere
with Nevada's operations, lower the quality of
service to Nevada's customers, or interfere with the
operation of any communications facilities.
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7.3.2 Seller shall design Seller's Facilities so that
those facilities are protected from damage that
could result from disturbances on Nevada's electric
system or the electric systems to which Nevada is
interconnected.
7.3.3 Seller shall design Seller's Facilities so that
those facilities incorporate reactive power
equipment capable of maintaining a power factor
ranging from 0.90 lagging to 0.90 leading at the
Interconnection Point whenever Capacity is being
delivered to Nevada at that point.
7.3.4 Seller shall design Seller's Facilities so that
they incorporate two separate, independent fuel
supplies and transportation systems throughout the
term of the Contract. The design should assure that
Seller's Generating Facility will be available
during periods when fuel supply curtailments might
otherwise limit the delivery of Contract Capacity
and Energy to Nevada. Proof of compliance with this
Section 7.3.4 will be submitted to the Commission
following approval of the Contract.
7.3.5 Seller shall provide those drawings and
specifications reasonably required by Nevada to
accomplish its design review. Nevada shall review
and specify modifications to the design of Seller's
Facilities if necessary to maintain Nevada's
Electric System Integrity and to ensure compliance
with the requirements of this Contract. In
conjunction with Nevada's design review, Nevada
shall designate the minimum set of protective
devices that shall be required to protect Nevada's
electric system whenever any of Seller's Facilities
are connected to Nevada's electric system. Nevada
shall not unreasonably withhold or delay its review
of any design related drawing or specification that
has been submitted to Nevada for review and
approval.
7.3.6 Seller shall modify Seller's design as
reasonably required by Nevada and shall provide
revised drawings and specifications that are
required by Nevada to confirm compliance with
Nevada's requirements.
7.4 Construction:
7.4.1 Prior to the start of Seller's construction,
Seller shall furnish Nevada a construction schedule
for Seller's Facilities. Upon receipt of pertinent
information, Seller shall notify Nevada of any
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changes in that construction schedule that may
affect or may have affected Firm Operation.
7.4.2 Seller shall construct Seller's Facilities in
accordance with Seller's design as modified to
reflect the changes, if any, that are reasonably
required by Nevada. Seller shall furnish and
install all equipment that may be reasonably
required by Nevada to maintain Nevada's Electric
System Integrity and to ensure compliance with the
requirements of this Contract.
7.4.3 Seller shall provide to Nevada, as reasonably
required by Nevada, "as built" drawings and
specifications for Seller's Facilities.
7.5 Initial Operation:
7.5.1 Seller shall not connect any of Seller's
Facilities to Nevada's electric system or operate
any of Seller's generators in parallel with Nevada's
electric system, without the prior written approval
of Nevada's Operating Representative and without
properly calibrated, tested, and fully operational
protective devices in service, as designated by
Nevada. Nevada's approval shall not be unreasonably
withheld or delayed. If Nevada's approval is
withheld, Nevada shall provide Seller a written
explanation including a list of required remedial
actions within fifteen (15) days of the date Nevada
withheld its approval.
7.5.2 Seller shall notify Nevada's Operating
Representative at least fifteen (15) days prior to
initial energization of any of Seller's
Interconnection Facilities. Nevada shall then
inspect Seller's Interconnection Facilities and
approve initial energization if, in Nevada's
reasonable judgment, Seller's Facilities can be
energized without adversely affecting Nevada's
Electric System Integrity. Nevada's approval shall
be in writing.
7.5.3 Seller shall notify Nevada's Operating
Representative at least fifteen (15) days prior to
initial testing and calibration of Seller's
protective devices. Nevada shall inspect and
approve Seller's protective devices after that
initial testing and calibration if Seller has
demonstrated, to Nevada's reasonable satisfaction,
the correct calibration and operation of Seller's
protective devices. Nevada's approval shall be in
writing.
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7.5.4 Seller shall notify Nevada's Operating
Representative at least fifteen (15) days prior to
initial operation of any of Seller's generators in
parallel with Nevada's electric system. Nevada
shall inspect and approve Seller's generators prior
to initial operation of those generators in parallel
with Nevada's electric system if Seller has
demonstrated, to Nevada's reasonable satisfaction,
the ability to synchronize Seller's generators with
Nevada's electric system, and to operate Seller's
generators in parallel with Nevada's electric system
without adversely affecting Nevada's Electric System
Integrity. Nevada's approval shall be in writing.
7.5.5 Prior to Firm Operation, Seller shall
demonstrate, to Nevada's reasonable satisfaction,
the ability to produce and deliver Contract Capacity
to Nevada. Seller's demonstration shall be
according to the procedures set forth in Exhibit E.
If Seller fails to demonstrate the ability to
produce and deliver Contract Capacity to Nevada,
Nevada shall have the right, without liability, to
reduce Contract Capacity to the level Seller is able
to produce and deliver.
7.6 Operation and Maintenance:
7.6.1 To the extent set forth in Exhibit C, Seller shall
maintain Operating Communications with Nevada.
7.6.2 Seller shall neither connect any of Seller's
Facilities to Nevada's electric system nor operate
a generator in parallel with Nevada's electric
system without the prior approval of Nevada's
Operating Representative. Procedures for obtaining
such approval are set forth in Exhibit C.
7.6.3 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 exists 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 requirements of this Contract.
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In accordance with 18 CFR Section 292.304(f),
Nevada shall also have the right to require Seller
to reduce the delivery of electric energy to Nevada
during Off-Peak or light-load hours when, due to
operational circumstances other than economic
dispatch, purchases from Seller will result in
costs greater than those that Nevada may otherwise
incur if Nevada generates or purchases an
equivalent amount of energy. Nevada shall provide
one (1) hour's oral notice of such reduction to
Seller. The exercise of Nevada's right shall be
subject to a calendar year energy limitation equal
to the product of Contract Capacity and one
thousand (1,000) hours. The amount of energy
curtailed shall be determined by multiplying the
hours of curtailment by the magnitude of the
reduction below Seller's average rate of delivery
(KW) to Nevada during the hour immediately
preceding the start of curtailment.
If Nevada requires 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 are set
forth in Exhibit C.
7.6.4 Seller shall avoid the imposition of any voltage or
current upon Nevada's electric system that
interferes with Nevada's operations, distorts the
electric service provided to Nevada's customers, or
interferes with the operation of any communications
facilities. If Seller imposes such a voltage or
current upon Nevada's electric system, Seller
shall, immediately upon learning of such condition,
pursue and implement remedial measures.
7.6.5 Except as otherwise agreed upon by the Parties'
Operating Representatives, Seller shall have all of
Seller's protective devices, as designated by
Nevada, in service whenever Seller's Facilities are
connected to Nevada's electric system.
7.6.6 Seller shall provide Seller's reactive power
requirements. Seller shall also provide reactive
power reasonably required by Nevada to maintain
Nevada's Electric System Integrity, provided that
such requirements are consistent with the
capabilities of Seller's Facilities and do not
adversely affect Seller's ability to provide
Capacity and Energy to Nevada in accordance with
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the requirements of this Contract. Seller shall
not deliver excess reactive power to Nevada without
the prior approval of Nevada's Operating
Representative. Procedures for obtaining such
approval are set forth in Exhibit C.
7.6.7 Seller shall maintain operation and maintenance
logs for Seller's Facilities that contain such data
as are set forth in Exhibit C. Nevada shall have
the right to inspect or request a copy of Seller's
operation and maintenance logs. If so requested,
Seller shall provide the copy within five (5) days
of Seller's receipt of Nevada's request.
7.6.8 Seller shall notify Nevada's Operating
Representative of any condition that may have
affected Seller's ability to produce and deliver
Contract Capacity to Nevada. Procedures for such
notice are set forth in Exhibit C.
7.6.9 If Nevada, as a result of participation in a power
pool or coordinating council, is required to
routinely demonstrate the capacity of its
generating facilities, Seller shall routinely
demonstrate, to Nevada's reasonable satisfaction,
the ability to produce and deliver Contract
Capacity to Nevada. Seller's demonstrations shall
be in accordance with the procedures established by
the power pool or coordinating council.
7.6.10 If Nevada, as a result of participation in a
power pool or coordinating council, is required to
comply with the operating criteria of that power
pool or coordinating council, Seller shall also
comply with those operating criteria. The criteria
which Seller shall comply with are set forth in
Exhibit C.
7.6.11 Seller shall notify Nevada's Operating
Representative in advance of all Scheduled Outages.
Unless the Parties' Operating Representatives agree
otherwise, the minimum required advance notice
shall be two (2) days if the expected outage
duration is less than one (1) day; five (5) days if
the expected outage duration is between one (1) and
five (5) days; and, fifteen (15) days if the
expected outage duration is longer than five (5)
days. Procedures for Seller's notices are set
forth in Exhibit C.
Unless operating conditions dictate otherwise,
Seller shall schedule all outages of expected
duration of less than five (5) days for completion
during the period designated by Nevada's Operating
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Representative. Unless operating conditions
dictate otherwise, Seller shall schedule all
outages of expected duration of greater than five
(5) days for completion during Maintenance Months
as designated by Nevada's Operating Representative.
7.6.12 If requested by Nevada's Operating
Representative, Seller shall, at no additional cost
to Nevada, make every reasonable effort to produce
Contract Capacity in case of an Emergency during
On-Peak hours. If Seller has scheduled an outage
when the Emergency occurs, Seller shall make every
reasonable effort to reschedule the outage. Nevada
waives the minimum notice requirements of Section
7.6.11 if Seller, at Nevada's request, does not
take a properly scheduled outage and subsequently
seeks to reschedule that outage.
7.6.13 Seller shall test and calibrate Seller's
protective devices at intervals agreed upon by the
Parties' Operating Representatives, but not more
than every four (4) years. Seller shall notify
Nevada's Operating Representative at least thirty
(30) days prior to such testing and calibration.
Procedures for Seller's notices are set forth in
Exhibit C.
If Nevada, because of an analysis of operating
conditions, or the addition of facilities to
Nevada's electric system, or the modification of
facilities on Nevada's electric system, has reason
to doubt the effectiveness of Seller's protective
devices, Nevada shall have the right, without
liability, to require Seller to retest and
recalibrate those devices and to demonstrate, to
Nevada's reasonable satisfaction and at no
additional cost to Nevada, the proper calibration
and operation of those devices. If operating
conditions allow, Nevada shall also have the right,
without liability, to retest and recalibrate those
devices and to bill Seller for the associated costs
in accordance with the provisions of Section 13 or
Exhibit B, whichever is applicable.
7.7 Nevada's Review: Any review of the design, construction,
operation, maintenance, or improvement of Seller's
Facilities by Nevada is solely for Nevada. Nevada makes
no representation as to the economic or technical
feasibility or suitability of any of Seller's Facilities
for any purpose. Seller shall not represent to any third
party that Nevada's review constitutes such a
representation.
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8. NEVADA'S FACILITIES: Nevada shall, as agreed upon by the
Parties and set forth in Exhibit B, provide facilities
required to implement the requirements of this Contract.
Nevada's Facilities shall be those facilities designated in
Exhibit B.
8.1 Ownership: Nevada's Facilities shall be owned, designed,
constructed, operated, maintained, and improved by
Nevada. Unless otherwise agreed upon by the Parties and
set forth in Exhibit B, all costs associated with
Nevada's Facilities, whether incurred by Nevada or by
Seller, shall be borne by Seller.
8.2 Construction Cost and Deposits:
8.2.1 The estimated cost of Nevada's Facilities for
which Seller shall have cost responsibility shall be
determined according to procedures set forth in
Exhibit B1.
8.2.2 Within thirty (30) days of Commission approval
of this Contract, Seller shall deposit the estimated
cost of Nevada's Facilities with Nevada. Failure to
do so shall be cause for immediate cancellation of
this Contract by Nevada. Seller's cost for the
design and construction of that portion of Nevada's
Facilities for which Seller has deposited the
estimated cost with Nevada shall be adjusted to
Nevada's actual cost after the facilities are
complete. If Seller's construction deposits exceed
Nevada's actual cost, Nevada shall refund the excess
to Seller within sixty (60) days of completing those
facilities. If Nevada's actual cost exceeds
Seller's construction deposits, Nevada shall bill
Seller for the excess cost. Seller shall have sixty
(60) days to remit payment to Nevada for Nevada's
excess construction costs. Failure to do so shall
be cause for immediate cancellation of this Contract
by Nevada.
8.2.3 If any portion of Nevada's Facilities which
Seller has paid for is used for the sale of electric
energy to Seller and related parties as defined in
Internal Revenue Service Advance Notice 88-129, and
if the electric energy that is sold to Seller and
related parties is projected to exceed five (5)
percent of the electric energy sold to Nevada by
Seller under the provisions of this Contract, the
estimated cost of such facilities shall be increased
by 30.185 percent to cover the income tax liability
attributable to such facilities.
8.2.4 If any portion of Nevada's Facilities which
Seller has paid for is deemed "nontaxable" for the
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purposes of Section 8.2.3, and if those facilities
subsequently become taxable, Nevada shall bill
Seller for the income tax liability attributable to
such facilities because of the sales to Seller and
related parties.
8.3 Construction: Prior to the start of construction, Nevada
shall furnish a construction schedule for Nevada's
Facilities to Seller. Nevada shall notify Seller of any
changes in that schedule that may affect or may have
affected Firm Operation.
Seller shall release Nevada from any direct or indirect
loss and liability, including attorney's fees and other
costs of litigation, resulting from any delay in
completing Nevada's Facilities that is caused by Seller
or by circumstances beyond Nevada's reasonable control.
8.4 Project Abandonment: If this Contract is terminated
prior to Firm Operation, Seller shall bear all costs
associated with Nevada's Facilities that were incurred by
Nevada prior to Contract termination plus all removal and
abandonment costs incurred by Nevada subsequent to
contract termination. Seller's cost for the design,
construction, and removal and abandonment of Nevada's
Facilities shall be adjusted to Nevada's actual cost net
of salvage value after Nevada's removal and abandonment
activities are complete.
8.5 Operation and Maintenance:
8.5.1 Nevada shall operate and maintain Nevada's
Facilities in accordance with Nevada's methods of
operation and maintenance.
8.5.2 Nevada shall notify Seller's Operating
Representative of any condition that may affect or
may have affected Seller's ability to produce and
deliver Contract Capacity to Nevada.
8.5.3 Unless otherwise agreed upon by the Parties and
set forth in Exhibit B, Nevada shall render monthly
bills to Seller for direct and indirect operation
and maintenance costs associated with Nevada's
Facilities that were incurred by Nevada during the
billing period. Indirect costs shall include, but
not be limited to, labor loadings for administrative
and general, FICA, bodily injury insurance, property
damage insurance, group insurance, industrial
insurance, holiday pay, sick leave, vacation pay,
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pension plans, supervision, tools, transportation,
and unemployment taxes.
9. INTERCONNECTION FACILITIES AGREEMENT: Upon execution of this
Contract, the Parties shall execute an Interconnection
Facilities Agreement which shall be attached to this Contract
as Exhibit B.
10. OPERATIONS COORDINATION AGREEMENT: Upon execution of this
Contract, the Parties shall execute an Operations Coordination
Agreement which shall be attached to this Contract as Exhibit
C.
11. IMPROVEMENTS AGREEMENTS: If improvements are required, the
Parties shall execute Improvements Agreements which shall be
attached to this Contract as Exhibit D. Improvements shall
include any modifications and additions to Seller's
Interconnection Facilities or Nevada's Facilities that are
required to maintain Nevada's Electric System Integrity or to
comply with the directive of any governmental body.
The execution of Improvements Agreements shall not obligate
Nevada to increase the rates set forth in Exhibit A or to
otherwise compensate Seller for costs incurred by Seller as a
result of implementing the Improvements Agreements.
12. ESCROW PROVISIONS: Upon execution of this Contract, Seller
shall deposit with Nevada an amount equal to $5.00 per
kilowatt of Contract Capacity. Within thirty (30) days of
Commission approval of this Contract, Seller shall deposit
with Nevada an additional amount equal to $20.00 per kilowatt
of Contract Capacity. Seller's deposits shall be in addition
to any other deposits required under this Contract. Seller's
deposits shall be placed in escrow and shall accrue interest
at the rate set by the Commission for interest paid on
customer deposits.
12.1 If this Contract is not approved by the Commission,
Seller's escrow deposit and accrued interest shall be
refunded to Seller within sixty (60) days of the
Commission's failure to approve this Contract.
12.2 If Seller achieves Firm Operation at the level of
capacity specified in Section 1.4.3, Seller's escrow
deposits and accrued interest shall be refunded to Seller
within sixty (60) days of Firm Operation.
12.3 If Seller achieves Firm Operation at a capacity level
less than the level specified in Section 1.4.3, the
refund of Seller's escrow deposits and accrued interest
shall be prorated on the basis of actual performance.
That portion of Seller's escrow deposits and accrued
interest attributed to Seller's actual performance shall
be refunded to Seller; the balance shall be totally
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forfeited to Nevada. Seller's refund shall be sent to
Seller within sixty (60) days of Firm Operation.
12.4 If Seller fails to achieve Firm Operation at any level,
Seller's escrow deposits and accrued interest shall be
totally forfeited to Nevada.
12.5 Instead of cash deposits, Seller may substitute
irrevocable letters of credit or surety bonds in the
amounts of the escrow deposits. Such irrevocable letters
of credit or surety bonds shall be in a form acceptable
to Nevada.
13. BILLING PROVISIONS: Nevada's bills rendered in accordance
with the requirements of this Contract shall be due upon
receipt by Seller and payable within twenty (20) days of
receipt by Seller. Seller shall make every reasonable effort
to pay Nevada's bills promptly. If Seller fails to make
timely payment of any of Nevada's bills, Nevada shall have the
right, without liability, to withhold the amount due Nevada
from payments due Seller for Capacity and Energy. Also, if
Seller fails to make timely payment of any of Nevada's bills,
Nevada shall have the right to exercise any other rights and
remedies available to Nevada under the provisions of this
Contract.
14. ASSIGNMENT AND DELEGATION: Neither Party shall assign any
right nor delegate any duty under this Contract without the
written consent of the other Party. Consent for assignment or
delegation shall not be unreasonably withheld or delayed.
Nevada hereby gives Seller the right to assign Seller's rights
under this Contract as collateral in conjunction with project
financing. However, Seller shall notify Nevada in writing
within ten (10) working days following such assignment as
collateral for project financing. Failure of Seller to
accordingly notify Nevada shall nullify Nevada's consent for
such assignment.
If Seller assigns Seller's rights under this Contract as
collateral in conjunction with project financing, and if
Seller fails to perform in accordance with the terms and
conditions of this Contract, then upon receipt of Nevada's
written notice to Seller and Lender of such failure, Lender
shall have the right to appoint, subject to Nevada's prior
written approval, operating agents who shall assume
responsibility for the construction, operation, and
maintenance of Seller's Facilities. Nevada's approval shall
not be unreasonably withheld or delayed. If Lender's
operating agents fail to cure, or fail to commence action with
all due diligence to cure, Seller's default within thirty (30)
days of receipt of Nevada's written notification of such
default, Nevada shall have the right without liability to
terminate this Contract.
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Nevada shall also have the right to assume responsibility for
the operation and maintenance of Seller's Facilities if Seller
fails to perform in accordance with the terms and conditions
of this Contract, and Lender fails to appoint operating agents
to assume responsibility for the operation and maintenance of
Seller's Facilities. However, if Nevada does not assume
responsibility for the operation and maintenance of Seller's
Facility, Nevada's failure to assume such responsibility in
accordance with the provisions of this Contract shall not be
deemed a waiver of any right or remedy Nevada may have under
this Contract.
15. TAXES:
15.1 Seller and Nevada shall each pay ad valorem and other
taxes properly attributed to their respective facilities.
15.2 Seller and Nevada shall provide information concerning
either Party's Facilities to any tax authority.
15.3 Nevada shall pay franchise and other taxes properly
attributed to Nevada's resale of Capacity and Energy.
16. LIABILITY:
16.1 Neither Party shall be saved harmless and indemnified
from any loss and liability resulting from that Party's
negligence or willful misconduct.
16.2 Each Party shall release the other Party from any direct
or indirect loss and liability, including attorney's fees
and other costs of litigation, resulting from damages to
property of the releasing Party arising out of the other
Party's efforts to perform its obligations under this
Contract, if such damages were not caused by negligence
or willful misconduct of the indemnified Party.
16.3 Each Party shall be solely responsible for the costs and
liability of all claims brought by its employees or
contractors, and shall save harmless and indemnify the
other Party from all such costs and liability. Costs
arising out of worker's compensation laws shall be
considered employee related claims for the purposes of
this section.
16.4 Each Party shall save harmless and indemnify the other
Party from any direct or indirect loss and liability,
including attorney's fees and other costs of litigation,
resulting from the injury or death of any person and
damage to any property of a third party arising out of
the indemnifying Party's performance of obligations under
this Contract if such injury, death, or damage was not
25
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caused by negligence or willful misconduct of the
indemnified Party.
16.5 If the Commission does not approve this Contract in
accordance with Section 27 of the Contract, Seller shall
release Nevada from any direct or indirect loss and
liability, including attorney's fees and other costs of
litigation, resulting from the actions of both Parties
prior to the Commission's failure to approve the
Contract.
17. INSURANCE: Until this Contract has been terminated, Seller
shall maintain comprehensive general liability coverage with a
minimum combined single limit per occurrence of five million
dollars ($5,000,000.00). Seller's insurance policy shall be
subject to Nevada's approval. Seller shall deliver a copy of
Seller's insurance policy to Nevada prior to the date Seller's
Interconnection Facilities are first energized. Seller's
insurance policy shall provide for thirty (30) days written
notice to Nevada of alteration or termination. Seller shall
also provide an insured endorsement to Nevada in the form set
forth in Exhibit F.
If Seller fails to comply with the provisions of this section,
Seller shall save harmless and indemnify Nevada from any
direct or indirect loss and liability, including attorney's
fees and other cost of litigation, resulting from the injury
or death of any person or damage to any property if Nevada
would have been protected had Seller complied with these
requirements. If Seller fails to comply with the requirements
of this section, Nevada shall have the right, without
liability, to either refuse to connect Seller's Facilities to
Nevada's system or to isolate Seller's Facilities from
Nevada's system. Once isolated, Seller's Facilities shall
remain isolated until Seller is in compliance with these
requirements.
18. UNCONTROLLABLE FORCES: Except as otherwise provided in
Section 5, if Uncontrollable Forces renders a Party wholly or
partially unable to perform any obligations under this
Contract, the non-performing Party shall be excused from such
performance if that Party delivers a written description of
the problem to the other Party within two weeks of the
occurrence. Statements should be included that the suspension
of performance was no greater in magnitude and no longer in
duration than was dictated by the problem; that the non-
performing Party made every reasonable effort to alleviate the
problem; and that the non-performing Party notified the other
Party in writing as soon as the non-performing Party was able
to resume full performance of its obligations under this
Contract. Neither Party shall be required to settle any labor
dispute on terms it considers are contrary to its best
interests.
26
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19. NON-DEDICATION OF FACILITIES: By this Contract, neither Party
dedicates any part of its facilities to the public or to the
service provided under this Contract. Such service shall
cease upon termination of this Contract.
20. AMENDMENTS: Unless otherwise specified herein, all
modifications to this Contract shall require Contract
amendments. Amendments shall be in writing and shall be
executed by both Parties, and shall be filed with the
Commission for approval.
21. PREVIOUS COMMUNICATIONS: This Contract contains the entire
agreement and understanding between the Parties thereby
merging and superseding all prior agreements and
representations by the Parties.
22. NON-WAIVER: Any waiver of the requirements or provisions of
this Contract shall be in writing. The failure of either
Party to insist upon strict performance of Contract
requirements or provisions or to exercise any Contract right
shall not be construed as a waiver of such Contract
requirement or provision or a relinquishment of such Contract
right.
23. DISPUTES: The Parties shall negotiate in good faith and
attempt to resolve any dispute arising between the Parties and
requiring an interpretation of the provisions of this
Contract. However, if the Parties are unable to resolve any
such dispute, either Party shall have the right to submit a
demand to the other Party that such dispute be arbitrated. If
such a demand is submitted, the dispute shall be resolved by
arbitration conducted in accordance with the rules of the
American Arbitration Association (AAA). The demanding Party
shall file a request with the AAA for the selection, pursuant
to the AAA rules, of a member of the AAA in good standing who
shall serve as the sole arbitrator. After the arbitrator has
been selected, the arbitration shall be held in Las Vegas,
Nevada. The Parties shall proceed with the arbitration
expeditiously and shall conclude all proceedings thereunder so
that a decision may be rendered within one hundred twenty
(120) days of the submittal of the demand for arbitration.
Pending resolution of a dispute, the Parties shall proceed
diligently with the performance of their obligations under
this Contract. The award of the arbitrator shall be final and
binding on both Parties and shall be enforceable by any court
having jurisdiction over the Party against whom enforcement is
sought. Each Party shall bear its own costs associated with
resolution of the dispute except that all costs associated
with the arbitration shall be apportioned in the award of the
arbitrator based upon the respective merit of the claims of
the Parties.
24. REMEDIES: Except as otherwise set forth in this Contract,
each Party, upon the other Party's failure to perform in
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accordance with the requirements of this Contract, shall have
the right to exercise any right or remedy that Party may have
at law or in equity including but not limited to compensation
for monetary damages such as the cost of removal or
abandonment of Nevada's Facilities and the incremental cost of
replacement power plus the incremental installed cost of
replacement generation and transmission facilities, injunctive
relief, and specific performance. Neither Party shall be
liable for any indirect, consequential, incidental, punitive,
or exemplary damages. If applicable, forfeited escrow
deposits and refunded Capacity and Energy payments shall be
subtracted from monetary damages due Nevada in accordance with
the requirements of this section.
25. GOVERNING LAW: This Contract shall be interpreted under the
laws of the State of Nevada as if executed and performed
wholly within that state.
26. NATURE OF OBLIGATIONS: Unless otherwise agreed upon by the
Parties and set forth herein, the duties, obligations, and
liabilities of the Parties shall be several, not joint or
collective. The requirements and provisions of this Contract
shall not be construed as creating an association, trust,
partnership, or joint venture, or as imposing a trust or
partnership duty, obligation, or liability on either Party, or
as creating any relationship between the Parties other than
that of independent contractors for the sale and purchase of
electric capacity and energy. Nothing in this Contract nor
any action taken hereunder shall be construed as creating any
duty, liability or standard of care to any person not a Party
to this Contract.
27. COMMISSION APPROVAL: Within thirty (30) days of the
Commission's acceptance of the stipulation entered into by the
Parties in the Commission's Docket 91-10047, Nevada shall
submit this Contract to the Commission for review and
approval. This Contract shall be void if not approved by the
Commission as executed.
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28. SIGNATURES:
IN WITNESS WHEREOF, the Parties hereto have executed this
Contract this 27th day of May, 1992.
NEVADA POWER COMPANY: LAS VEGAS COGENERATION
LIMITED PARTNERSHIP:
By: Steven W. Rigazio By: J. Thomas Fowlkes
Name: Steven W. Rigazio Name: J. Thomas Fowlkes
Title: Vice President Title: President
Treas. & CFO United Cogen Corporation
APPROVED AS TO FORM:
Gloria Moore
29
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<PAGE>
EXHIBIT A
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 pm 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
pm 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:
Summer Summer Winter Winter
On-Peak Off-Peak On-Peak Off-Peak
Capacity 0.04781 0.00000 0.02282 0.00000
Energy 0.02273 0.01986 0.02273 0.01986
Total 0.07054 0.01986 0.04555 0.01986
The above cited rates shall be effective from January 1, 1991
through April 30, 1992.
The above cited rates shall be adjusted annually, on May 1 of
each year beginning with the annual adjustment date of May 1,
1992 and ending with the annual adjustment date May 1, 2023, by
eighty (80) percent of the changes in the Consumer Price Index
for all Urban Consumers; the base index shall be the index for
January of 1991 (134.6).
A-1
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EXHIBIT B
Interconnection Facilities Agreement
WHEREAS, Nevada Power Company (Nevada) and Las Vegas Cogeneration
Limited Partnership (Seller) entered into a Contract for a Long
Term Power Purchase from Seller's Facilities located at North Las
Vegas, Nevada on the 27th day of May,1992, and
WHEREAS, the Parties agreed to execute an Interconnection
Facilities Agreement (Exhibit B) as a condition of that Contract.
NOW, THEREFORE, Nevada and Seller agree to own, design,
construct, operate, maintain, and improve the facilities required
to implement the provisions of that Contract in accordance with
the terms and conditions of that Contract and the additional
terms and conditions set forth herein.
1. Purpose:
1.1 This Exhibit B generally describes the facilities
that shall be required to implement the
requirements and provisions of the Contract and to
designate those facilities as either Seller's
Facilities or Nevada's Facilities. Since
interconnection studies require data for Seller's
Facilities that may have been unavailable upon
execution of this Exhibit B, Nevada shall have the
right to complete those studies in phases linked
to the availability of such data and to modify
this Exhibit B accordingly.
1.2 Nothing in the Contract or this Exhibit B shall be
construed, by virtue of the absence of a specific
reference, as relieving either Party of the
responsibility for all labor, equipment, and
materials incidental to the construction of
facilities designated herein as being the
responsibility of that Party. Upon completion of
construction, the facilities constructed per this
Exhibit B should be fully capable of completing
the interconnection between Nevada and Seller in
accordance with the terms and conditions of the
Contract and this Exhibit B.
B-1
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2. Attachment of Documents:
2.1 If necessary to accomplish the purposes of this
Exhibit B, documents shall be attached and shall
be a part of the Contract to the same extent as
set forth herein.
2.2 Preliminary documents shall be replaced with final
documents as they become available.
2.3 The following designated documents shall be
attached to this Exhibit B.
X Exhibit B1: "Procedures For Determining QF
Interconnection Facility Cost Responsibilities."
X Exhibit B2: A "List of Drawings" and the
referenced drawings,
X Exhibit B3: a "List of Major Components",
__ Exhibit B4: a "List of Specifications" and the
referenced specifications,
__ Exhibit B5: a "List of Standards" and the
referenced standards, and
X Exhibit B6: a "List of Miscellaneous Attachments"
and the referenced attachments.
3. Interconnection Point: The Interconnection Point
shall be that point designated on Drawing No. 2.3.
4. Seller's Facilities:
4.1 Seller's Facilities shall be those facilities
designated on the attached drawings and List of
Major Components.
4.2 If set forth in the documents attached to this
Exhibit B, Seller's Facilities shall conform to
the specifications and standards attached hereto.
5. Nevada's Facilities:
5.1 Nevada's Facilities shall be those facilities
designated on the attached drawings and List of
Major Components.
5.2 If set forth in the documents attached to this
Exhibit B, Nevada's Facilities shall conform to
the specifications and standards attached hereto.
B-2
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5.3 The estimated cost of Nevada's Facilities which
Seller shall be required to place construction
deposits with Nevada is $1,100,000.
5.4 Following receipt of Seller's authorization to
proceed and Seller's deposit of the estimated cost
of Nevada's Facilities, Nevada shall use its best
efforts to complete the construction of Nevada's
Facilities no later than February 1, 1994.
5.5 The special provisions for Seller's construction
deposits associated with Nevada's Facilities, as
set forth in Miscellaneous Attachment No. 3, shall
be applicable to the Contract.
6. Capacity and Energy: Meters and metering equipment
shall be installed inside Nevada's relay and control
building which shall be located within Nevada's
Switchyard.
7. Protective Devices: The minimum set of protective
devices required to protect Nevada's electric system
whenever Seller's Facilities are connected to or
operated in parallel with Nevada's electric system
shall be the protective devices designated on a drawing
to be agreed upon by the Parties and attached to this
Exhibit B.
B-3
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8. Signatures:
IN WITNESS WHEREOF, the Parties hereto have executed
this Exhibit B this 27th day of May, 1992.
NEVADA POWER COMPANY: LAS VEGAS COGENERATION
LIMITED PARTNERSHIP:
By: Steven W. Rigazio By: J. Thomas Fowlkes
Name: Steven W. Rigazio Name: J. Thomas Fowlkes
Title: Vice President Title: President
Treas. & CFO United Cogen
Corporation
APPROVED AS TO FORM:
Gloria Moore
B-4
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EXHIBIT B1
PROCEDURES FOR DETERMINING
QF INTERCONNECTION FACILITY COST
RESPONSIBILITIES
1. Nevada Power Company (NPC) shall determine the
interconnection facilities which will be built between NPC's
system and a Qualified Facility (QF) based on the following
requirements:
a. Such facilities shall be adequate to maintain a minimum
transfer capability which will allow the QF to sell the
desired amount of power to NPC; and
b. Such facilities shall maximize the efficient
development of NPC's system for existing or future
benefits.
2. The QF shall be responsible for the proportionate share of
costs of the interconnection facilities which is adequate to
transfer the amount of capacity and energy to be sold by the
QF to NPC with the following exceptions.
a. If such facilities are determined by NPC to not be
needed to serve NPC's customers within five years of
the in-service date, then QF shall be responsible for
all costs. However, if NPC subsequently determines,
within 10 years of the in-service date, that such
facilities are needed to serve load, NPC shall refund,
without interest, the cost of such interconnection
facilities less the QF's proportionate share.
b. If such facilities involve the rebuilding of a portion
of NPC's system, the QF shall also be responsible for
the portion of the interconnection costs plus income
taxes, if applicable, for capacity NPC had available
prior to the rebuilding.
3. NPC shall be responsible for those costs of the
interconnection facilities not covered in No. 2 above.
4. Definitions:
Interconnection Facilities: Those facilities constructed
between the QF interconnection point and a point on NPC's
system adequate to receive power from the QF. Such
facilities shall include, but not be limited to, new or
rebuilt transmission lines, substation modification,
metering, relaying, and communication equipment.
Interconnection facilities shall not include any
B-5
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modification of facilities beyond the point of receipt
within NPC's system.
Transfer Capability: The normal rating of the transmission
line based on NPC's standard rating of conductors, unless
otherwise limited as determined by NPC.
Example: 138 kV transmission line using 954 MCM ACSR
conductor shall have a capability of (138kV) (837
amperes)(1.732) = 200 MW
Proportionate Share: The ratio of the QF capacity amount to
be sold to NPC relative to the transfer capability of the
interconnection facilities.
Example: an 85 MW QF sale to NPC on a 200 MW
transmission line shall produce a proportionate share
of (85/200)(100%) =42.5%
B-6
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EXHIBIT B2
List of Drawings
Drawing Number Description
2.1 Transmission Requirement to Interconnect -
dated 5/22/89
2.2 Interconnection with Pecos and Craig
Substations -
dated 5/22/89
2.3 Interconnection Detail - dated 5/22/89
B-7
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LVCOGEN
PRELIMINARY INTERCONNECTION FACILITIES
DWG. 2.1
Area map bordered by Bruce Street, Gowan Road, Losee Road and Craig
Road showing the relative location of the LVCOGEN 138 KV Substation
and the Craig 138/12 KV Substation as well as existing 138 KV
transmission line, new conductor on existing 138 KV double circuit
structures, and new 138 KV double circuit structures.
B-8
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LVCOGEN
PRELIMINARY INTERCONNECTION FACILITIES
DWG. 2.2
Drawing showing existing 138 KV PCBs at the Pecos and Craig
Substations and a new 138 KV PCB at LVCOGEN with the existing and new
transmission lines connecting these PCBs.
B-9
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LVCOGEN
PRELIMINARY INTERCONNECTION FACILITIES
DWG. 2.3
Drawing showing interconnection detail at LVCOGEN.
B-10
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EXHIBIT B3
List of Major Components
Constr.
Deposit
Description Quantity Owner Required Taxable
138 kV Termination 1 Nevada Yes No
(Craig Sub)
138 kV Transmission Line 1.6 miles Nevada Yes No
(LV Cogen - Craig)
Provisions for future 138 kV as req'd Nevada No
No
Breaker Bay
138 kV Breaker Bay 1 Nevada Yes No
(LV Cogen Sub)
138 kV Power Circuit Breaker 1 Nevada Yes
No
(LV Cogen Sub)
138 kV Disconnects 2 Nevada Yes No
(LV Cogen Sub)
138/13.8 kV Transformer as req'd Seller No No
(LV Cogen Sub)
13.8 kV Switchgear as req'd Seller No No
(LV Cogen Sub)
Protective Devices
for Craig 138 kV PCB as req'd Nevada Yes No
for LV Cogen 138 kV PCB as req'd Nevada Yes No
for 138 kV Switchgear as req'd Seller No No
Metering Equipment (138 kV) as req'd Nevada Yes
No
Remote Terminal Unit 1 Nevada Yes No
Automatic Synchronizing
Equipment as req'd Seller No No
B-11
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EXHIBIT B6
List of Miscellaneous Attachments
Number Description
1 Temporary Easement
2 Protective Equipment
3 Special Provisions
B-12
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Miscellaneous Attachment No. 1
Temporary Easement
1. To facilitate the preparation of easements required by
Nevada to implement the requirements of this Contract,
Seller shall provide the following documents to Nevada:
a. A map or maps showing the location of Seller's
Facilities and the ownership of all parcels which
Nevada must traverse to gain access to the site of
Seller's Facilities;
b. A copy of the deed or deeds of ownership for all
parcels which Nevada must traverse to gain access to
the site of Seller's Facilities; and
c. A letter, executed by the owners of all parcels which
Nevada must traverse to gain access to the site of
Seller's Facilities, granting Nevada the right of
ingress and egress to implement the requirements of
this Contract until such time as permanent easements,
rights-of-way, and land rights have been obtained.
2. The above cited documents shall be delivered to Nevada
coincident with Seller's deposit for Nevada's Facilities.
B-13
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Miscellaneous Attachment No. 2
Protective Equipment
Nevada has established minimum requirements essential for
the safe and reliable operation of Qualifying Facilities
operating in parallel with Nevada's system. Those
requirements provide for control and protective equipment
which is required to:
1. Protect Nevada's personnel and the general public;
2. Sense and properly react to disturbances on
Nevada's system;
3. Assist Nevada's efforts to maintain its system
integrity.
The following list presents the various devices and features
generally required by Nevada as a prerequisite to operation
of a Qualifying Facility in parallel with Nevada's electric
system.
1. A dedicated transformer;
2. An interconnection disconnect;
3. A generator circuit breaker;
4. Under/over-voltage protection;
5. Under/over-frequency protection;
6. Ground fault protection;
7. Overcurrent relays with voltage restraint;
8. Automatic synchronizing;
9. Voltage and power factor regulation; and
10. No automatic line restoration equipment.
B-14
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Miscellaneous Attachment No. 3
Special Provisions
1. Deposits for Nevada's Facilities for which Seller has been
required to place construction deposits with Nevada: Seller
shall have the option of establishing an escrow account to
pay for Nevada's Facilities which Seller has been required
to fund. Such escrow account shall be located at a Las
Vegas area financial institution that has been approved by
Nevada. Nevada's approval shall not be unreasonably delayed
or withheld.
Seller shall deposit the full estimated cost of Nevada's
Facilities in the escrow account within thirty (30) days of
Commission approval of the Contract. Nevada shall have the
right to make withdrawals from the escrow account as
required to pay materials and labor costs associated with
construction of Nevada's Facilities.
Seller shall not make withdrawals from the escrow account
without Nevada's written approval. Seller's escrow account
shall be established in a manner that precludes withdrawals
without such approval.
If the balance in Seller's escrow account is less than
Nevada's actual cost for that portion of Nevada's Facilities
for which Seller has been required to place a construction
deposit with Nevada, Seller shall be billed for Nevada's
excess cost in accordance with the provisions of Section 13
of the Contract.
If the balance of Seller's escrow account exceeds Nevada's
actual cost for that portion of Nevada's Facilities for
which Seller has been required to place a construction
deposit with Nevada, Nevada shall provide Seller with
written authorization for Seller to withdraw such excess
funds within sixty (60) days of completion of Nevada's
Facilities.
2. The Parties agree to collectively put forth their best
efforts to achieve Firm Operation of The Las Vegas
Cogeneration Project at Contract Capacity of 45 megawatts
not later than June 1, 1994.
B-15
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EXHIBIT C
Operations Coordination Agreement
WHEREAS, Nevada Power Company (Nevada) and Las Vegas Cogeneration
Limited Partnership (Seller) entered into a Contract for a Long
Term Power Purchase from Seller's Facilities located at North Las
Vegas, Nevada on the 27th day of May, 1992, and
WHEREAS, the Parties agreed to execute an Operations Coordination
Agreement (Exhibit C) as a condition of that Contract,
NOW THEREFORE, Nevada and Seller agree to coordinate the
operations of their respective facilities in accordance with the
requirements and provisions of that Contract and the additional
terms and conditions set forth herein.
1. Purpose:
1.1 This Exhibit C generally describes the procedures
that shall be required to implement the
requirements and provisions of the Contract.
1.2 Nothing in the Contract or this Exhibit C shall be
construed, by virtue of the absence of a specific
reference, as relieving either Party of the
responsibility for communicating with the other
Party in a manner that will allow both Parties to
operate their facilities in a safe manner
consistent with the best interests of the Parties
and the general public.
2. Communications:
2.1 Seller shall maintain telephone service to
Seller's Generating Facility.
2.2 The following points of contact have been
designated for Operating Communications.
C-1
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2.2.1 Communications to Seller:
Seller's Operator (____) ____ - _______
2.22 Communications to Nevada:
Nevada's System Dispatcher (702) 451-2026
Nevada's Program Coordinator (702) 731-3382
Each Party shall notify the other Party in
writing prior to changing any of the above
cited points of contact.
2.3 Unless otherwise specified herein, Nevada's System
Dispatcher shall be the point of contact for
Operating Communications with Nevada.
3. Jurisdiction: When any of Seller's Facilities are
connected to Nevada's electric system, those facilities
shall be under the jurisdiction of Nevada's System
Dispatcher. Seller's Operator shall comply with all of
the instructions provided by Nevada's System Dispatcher
at the time designated in the instructions. In the
course of operating or maintaining Seller's Facilities,
Seller's Operator shall not undertake any action that
may have an adverse impact on Nevada's electric system
integrity without contacting Nevada's System Dispatcher
and receiving prior authorization. Such activities
shall include, but not be limited to, energization or
deenergization of Seller's Interconnection Facilities,
connection of Seller's generators to Nevada's electric
system, isolation of Seller's generators from Nevada's
electric system, and adjustment of the amount of real
or reactive power being delivered to Nevada's electric
system.
Only authorized representatives of Nevada shall be
allowed to connect Seller's Interconnection Facilities
to Nevada's electric system or to isolate Seller's
Interconnection Facilities from Nevada's electric
system. This restriction shall not be applicable to
the operation of power circuit breakers and other
protective devices that have been designed to react to
abnormal conditions.
C-2
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4. Operating Criteria:
4.1 Power pool or coordinating council operating
criteria applicable to Seller's Facilities shall
be attached to this exhibit as Exhibit C1.
Exhibit C1 shall be made a part hereof to the same
extent as set forth herein.
4.2 Nevada shall have the right to modify Exhibit C1
so that the criteria set forth therein are
consistent with the criteria which Nevada must
comply with as a result of Nevada's participation
in a power pool or coordinating council. Nevada's
modifications shall be written.
5. Seller's Generators: The following procedures shall be
used to connect Seller's generators to Nevada's
electric system (connection), to disconnect Seller's
generators from Nevada's electric system (isolation),
and to adjust the output of Seller's Generating
Facility.
5.1 Connection Under Normal Conditions:
5.1.1 Seller's Operator shall notify Nevada's
Program Coordinator at least seventy-two (72)
hours prior to connection of any of Seller's
generators.
5.1.2 Nevada's Program Coordinator shall
advise Seller's Operator of any conditions
that may preclude connection of Seller's
generator at the time requested by Seller's
Operator. If necessary, Seller's Operator
shall adjust Seller's startup schedule to
accommodate the changes requested by Nevada's
Program Coordinator.
5.1.3 At lease two (2) hours prior to
connection of any Seller's generators,
Seller's Operator shall contact Nevada's
System Dispatcher and provide the following
information.
A. The time when Seller's Operator expects
Seller's turbine to start;
B. The time when Seller's Operator expects
to connect Seller's generator to
Nevada's electric system; and
C. The ramping rate that Seller's Operator
expects to use while loading Seller's
generator.
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5.1.4 Unless otherwise instructed by Nevada's
System Dispatcher, Seller's Operator shall
maintain communications with Nevada's System
Dispatcher prior to and during
synchronization of Seller's generator with
Nevada's electric system.
5.1.5 The scheduling requirements of this
section may be waived by Nevada's System
Dispatcher if connection is requested after a
Forced Outage or if Nevada's System
Dispatcher deems it otherwise prudent to do
so.
5.2 Isolation Under Normal Conditions:
5.2.1 Seller's Operator shall notify Nevada's
Program Coordinator at least seventy-two (72)
hours prior to isolation of Seller's
generator.
5.2.2 Nevada's Program Coordinator shall
advise Seller's Operator of any conditions
that may preclude isolation of Seller's
generators at the time requested by Seller's
Operator. If necessary, Seller's Operator
shall adjust Seller's shutdown schedule to
accommodate the changes requested by Nevada's
Program Coordinator.
5.2.3 At least two (2) hours prior to
isolation of any of Seller's generators,
Seller's Operator shall contact Nevada's
System Dispatcher and provide the following
information:
A. The ramping rate that Seller's Operator
expects to use to unload Seller's
generator;
B. The time when Seller's Operator expects
to isolate Seller's generator from
Nevada's electric system; and
C. The time when Seller's Operator expects
to shut down Seller's turbine.
5.2.4 Unless otherwise instructed by Nevada's
System Dispatcher, Seller's Operator shall
maintain communications with Nevada's System
Dispatcher prior to and during isolation of
Seller's generator from Nevada's electric
system.
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5.2.5 The scheduling requirements of this
section may be waived by Nevada's System
Dispatcher if isolation is required by a
Forced Outage or if Nevada's System
Dispatcher deems it otherwise prudent to do
so.
5.3 Output Adjustment Initiated By Seller:
5.3.1 If abnormal conditions require an
adjustment in the output of Seller's
Generating Facility that is being delivered
to Nevada, Seller's Operator shall contact
Nevada's System Dispatcher and provide the
following information to Nevada's System
Dispatcher.
A. The reason why Capacity and Energy being
delivered to Nevada must be adjusted;
B. The amount and the expected duration of
the adjustment;
C. The time when Seller's Operator expects
to begin adjusting the output of
Seller's generator;
D. The ramping rate that Seller's Operator
expects to use while adjusting the
output of Seller's generator; and
E. The level of deliveries of Capacity and
Energy to Nevada that Seller expects to
maintain after the output of Seller's
generator has been adjusted to the
prescribed level.
5.3.2 After the abnormal condition has been
alleviated, Seller's Operator shall comply
with the applicable provisions of Section 5.1
or Section 5.2 of this exhibit while
restoring the output of Seller's generator to
the normal level.
6. Curtailments: Consistent with the provisions of the
Contract, Nevada's System Dispatcher shall have the
right to either order reductions in the output of
Seller's Generating Facility or the isolation of any of
Seller's Facilities from Nevada's electric system. To
the extent possible, Nevada shall attempt to notify
Seller's Operator in advance of such reductions and
isolations. Regardless of the notice provided, the
following procedure shall be applicable.
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6.1 Nevada's System Dispatcher shall contact Seller's
Operator and instruct Seller's Operator to reduce
the output of Seller's Generating Facility to the
prescribed level over the specified period of
time.
6.2 Seller's Operator shall reduce the output of
Seller's Generating Facility to the prescribed
level in accordance with the instructions from
Nevada's System Dispatcher. If Nevada's System
Dispatcher is unable to contact Seller's Operator
or if Seller's Operator fails to comply with the
instructions from Nevada's System Dispatcher,
Nevada's System Dispatcher shall isolate Seller's
Facilities from Nevada's electric system.
6.3 Unless Nevada's System Dispatcher has established
an alternative procedure, Seller's Operator shall
notify Nevada's System Dispatcher after the output
of Seller's Generating Facility has been reduced
to the prescribed level. Once reduced, Seller's
Operator shall not increase the output of Seller's
Generating Facility until instructed to do so by
Nevada's System Dispatcher.
6.4 After the condition dictating the reduction has
passed or Nevada's electric system has been
adjusted to accommodate increased deliveries from
Seller's Facilities, Nevada's System Dispatcher
shall instruct Seller's Operator to return
Seller's Generating Facility to its normal
operating status.
7. Reactive Power:
7.1 Seller shall provide the reactive power required
to maintain voltage at Seller's 138 kV bus in the
range from 138,000 volts to 144,900 volts: or,
Seller shall provide the reactive power required
to maintain power factor at the 138 kV bus in the
range from ninety (90) percent lagging to one
hundred (100) percent, whichever has been
designated by Nevada's System Dispatcher.
7.2 If Seller's Operator is unable to maintain the
specified voltage or power factor, whichever is
applicable, within the prescribed range, Seller's
Operator shall immediately contact Nevada's System
Dispatcher and describe the nature of the problem
that precludes maintaining the specified voltage
or power factor.
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7.3 Nevada's System Dispatcher shall then describe any
remedial actions to be taken by Seller's Operator.
7.4 Seller's Operator shall implement the instructions
provided by Nevada's System Dispatcher for
alleviation of the abnormal conditions.
8. Operation and Maintenance Logs: Seller's operation and
maintenance logs shall contain the following minimum
information:
8.1 The gross real and reactive power output of
Seller's Generating Facility and Seller's real and
reactive power consumption, both on an hourly
basis, or the real and reactive power delivered to
Nevada by Seller, on an hourly basis.
8.2 The date and time at which any of Seller's
generators are connected to or isolated from
Nevada's electric system.
8.3 The date and time of any unscheduled operations of
Seller's power circuit breakers and a list of
relay targets from the protective devices that may
have caused those circuit breakers to operate.
8.4 The beginning and ending dates and times for all
periods during which Seller's Generating Facility
is operated at less than full output and a
description of the reasons for the reduced output.
8.5 A description of any other unusual events.
8.6 The date and time of all telephone calls placed to
Nevada's System Dispatcher or Nevada's Program
Coordinator and a summary of the information that
was exchanged during the telephone conversation.
8.7 Any other information that may be reasonably
required by Nevada's System Dispatcher.
9. Abnormal Conditions: Seller shall immediately notify
Nevada's System Dispatcher of any abnormal conditions.
Abnormal conditions shall always include the following:
9.1 Conditions that may result or may have resulted in
injury to Nevada's or Seller's personnel or the
general public.
9.2 Conditions that may result or may have resulted in
damage to Nevada's or Seller's property or the
property of the general public.
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9.3 Conditions that may adversely affect or may have
adversely affected Nevada's ability to provide
electric service to Nevada's customers.
9.4 Conditions that may adversely affect or may have
adversely affected Seller's ability to produce and
deliver Capacity and Energy to Nevada.
9.5 Conditions that may cause or may have caused an
unscheduled reduction in the rate of delivery of
electric energy to Nevada.
9.6 Conditions that may cause or may have caused an
unscheduled isolation of any of Seller's
Facilities from Nevada's electric system.
10. Scheduled Outages: Seller shall make every reasonable
effort to schedule all outages in accordance with
Nevada's electric system requirements.
10.1 On or before January 1, and July 1 of each year,
Seller shall provide a written schedule of outages
to Nevada for Seller's Facilities. Seller's
schedule shall cover the following twenty-four
(24) month period beginning with the date on which
the schedule is provided to Nevada. Seller's
schedule shall be mailed to Nevada's Program
Coordinator at Mail Station 58, Nevada Power
Company, P. O. Box 230, Las Vegas, NV 89151.
10.2 Nevada's Program Coordinator shall advise Seller's
Operator of any changes to Seller's outage
schedule that may be required to maintain Nevada's
electric system integrity.
10.3 If necessary, Seller's Operator shall reschedule
Seller's outages in accordance with the changes
that are described by Nevada's Program
Coordinator.
10.4 Unless conditions dictate otherwise, Seller's
Operator shall accomplish outages in accordance
with Seller's schedule as modified by Nevada's
Program Coordinator.
10.5 If Seller's outage schedule must be adjusted for
reasons beyond Seller's reasonable control,
Seller's Operator shall contact Nevada's Program
Coordinator who shall adjust Seller's outage
schedule as necessary.
10.6 If unforeseen circumstances require Seller's
Operator to schedule outages that were not
addressed on Seller's outage schedule, Seller's
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Operator shall contact Nevada's Program
Coordinator and advise Nevada's Program
Coordinator of Seller's requirements. Nevada's
Program Coordinator shall make every reasonable
effort to adjust Seller's outage schedule as
requested by Seller's Operator.
11. Relay Calibration: Seller shall make every reasonable
effort to schedule testing and calibration of Seller's
protective devices in accordance with Nevada's
requirements.
11.1 Seller's Operator shall notify Nevada's Program
Coordinator at least thirty (30) days prior to any
scheduled testing or calibration of Seller's
protective devices. Seller's notice shall include
Seller's proposed schedule for testing or
calibration of individual protective devices.
11.2 Nevada's Program Coordinator shall advise Seller's
Operator of any potential conflicts that may
preclude testing or calibration of Seller's
protective devices. Seller's Operator shall
adjust Seller's schedule as requested by Nevada's
Program Coordinator.
11.3 Prior to removing any of Seller's protective
devices from operation, Seller's Operator shall
advise Nevada's System Dispatcher of Seller's
intent. Nevada's System Dispatcher shall withhold
authorization for removal of Seller's protective
devices from service if such removal will
adversely affect Nevada's Electric System
Integrity. Seller shall not remove any protective
devices from operation without authorization from
Nevada's System Dispatcher.
11.4 After any of Seller's protective devices have been
returned to normal operation, Seller's Operator
shall advise Nevada's System Dispatcher
accordingly.
11.5 After any of Seller's protective devices have been
tested or calibrated, Seller shall provide a copy
of the Seller's test reports to Nevada. Such
reports shall be mailed to Nevada's Program
Coordinator or provided to Nevada's representative
if Nevada monitors Seller's testing or
calibration.
12. Maintenance Authorization:
12.1 Seller shall not perform any maintenance on
Seller's energized Facilities without prior
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authorization from Nevada. Normally, such
authorization shall only be provided for the
maintenance of control equipment and protective
devices if the equipment and devices cannot be
deenergized during the maintenance.
12.2 Seller shall not perform any maintenance on
Seller's energized Facilities without a clearance
from Nevada's System Dispatcher. Seller's
Operator shall use the following procedure to
obtain a clearance.
12.2.1 To arrange for the clearance, Seller's
Operator shall contact Nevada's Program
Coordinator at lease seventy-two (72) hours
prior to a requested outage, unless an
emergency exists. Nevada's Program
Coordinator shall make every reasonable
effort to schedule the outage in accordance
with Seller's request.
12.2.2 Nevada's Program Coordinator shall advise
Seller of any conditions that may preclude
isolation of Seller's Facilities. The
schedule for Seller's outage shall be
adjusted accordingly.
12.2.3 Switching to isolate Seller's Facilities
from Nevada's electric system shall be
completed by Nevada's authorized
representative who shall be acting in
accordance with an approved switching
program and under the direction of Nevada's
System Dispatcher. After the switching to
isolate Seller's Facilities has been
completed, Nevada's System Dispatcher shall
issue a clearance to Seller's Operator
releasing the isolated facilities to
Seller's Operator for the prescribed
maintenance. Under no circumstances shall
Seller physically contact any of Seller's
Facilities that are normally energized
until those facilities have been released
to Seller's Operator.
12.2.4 Isolation of Seller's Interconnection
Facilities from Nevada's electric system
shall be accomplished at a lockable
disconnect. Seller shall not attempt to
operate the disconnect, attempt to remove
the lock from the disconnect, or attempt to
remove any safety tags that accompany the
lock.
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12.2.5 Seller shall complete maintenance in
accordance with prudent maintenance
practices. Seller shall take all necessary
steps to ensure that maintenance will be
conducted in a manner that does not
endanger the safety of persons or
equipment. Nevada assumes no
responsibility for the safety and well
being of Seller's personnel or contractors.
Nevada assumes no responsibility for
Seller's equipment.
12.2.6 After Seller has completed the prescribed
maintenance on Seller's Interconnection
Facilities, removed all protective grounds,
and returned those facilities to the normal
operating condition, Seller's Operator
shall contact Nevada's System Dispatcher
and release the previously issued
clearance.
12.2.7 After Seller's Operator has released the
previously issued clearance and Seller's
Facilities have been inspected to the
extent deemed necessary by Nevada's System
Dispatcher to protect Nevada's Electric
System Integrity, Nevada's authorized
representative, acting in accordance with
an approved switching program and under the
direction of Nevada's System Dispatcher,
shall energize Seller's Interconnection
Facilities. Nevada's inspection shall be
solely for Nevada. Nevada assumes no
responsibility for the safety and well
being of Seller's personnel, the personnel
of Seller's contractors, or the general
public. Nevada assumes no responsibility
for Seller's equipment or the property of
the general public.
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13. Signatures:
IN WITNESS WHEREOF, the Parties hereto have executed
this Exhbit C this 27th day of May, 1992.
NEVADA POWER COMPANY: LAS VEGAS COGENERATION
LIMITED PARTNERSHIP:
By: Steven W. Rigazio By: J. Thomas Fowlkes
Name: Steven W. Rigazio Name: J. Thomas Fowlkes
Title: Vice President Title: President
Treas. & CFO United Cogen
Corporation
APPROVED AS TO FORM:
Gloria Moore
C-12
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EXHIBIT D
Project Improvement Agreement
[Intentionally left blank, pending the need for such
agreement pursuant to Section 11 of the Contract.]
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EXHIBIT E
Procedure For Establishing Firm Operation
1. Tests for establishing Firm Operation shall be conducted
over a period of not more than one hundred (100) continuous
hours. A separate test shall be performed for each
generator or group of generators.
2. Seller shall notify Nevada's Operating Representative at
least fifteen (15) days prior to the start of each of
Seller's proposed test periods.
3. Nevada shall have the right to monitor Seller's tests.
4. Firm Operation testing shall not be permitted during the
months of July, August, and September.
5. If Seller's test is conducted during the months of October
through April, inclusive, Seller's actual performance (KW)
shall equal Seller's actual energy (KWH) produced and
delivered to Nevada during the test period divided by one
hundred and ten (110) hours.
6. If Seller's test is conducted during the months of May
through June, inclusive, Seller's actual performance (KW)
shall equal Seller's actual energy (KWH) produced and
delivered to Nevada during the test period divided by one
hundred (100) hours.
7. Seller shall notify Nevada's Operating Representative in
writing of the results of Seller's tests. Seller's notices
shall contain sufficient information to allow Nevada to
confirm Seller's actual performance. Seller shall be
considered to have attained Firm Operation at Seller's
actual performance or Contract Capacity, whichever is lower,
upon Nevada's receipt of Seller's notices that Seller
complied with the provisions of this exhibit and that Seller
does not elect retesting.
8. If Seller elects retesting, the procedure set forth herein
shall be applicable in its entirety.
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EXHIBIT F
Form of Insured Endorsement
Seller shall provide an insured endorsement in substantially the
following form: "In consideration of the premium charged, Nevada
Power Company (Nevada) is named as additional insured with
respect to all liabilities arising out of Seller's ownership and
use of Seller's Facilities. The inclusion of more than one
insured under this policy shall not operate to impair the rights
of one insured against another insured and the coverages offered
by this policy shall apply as though separate policies had been
issued to each insured. The inclusion of more than one insured
under this policy shall not, however, operate to increase the
limit of the carrier's liability. Nevada shall not, by reason of
its inclusion under this policy, incur any liability to the
insurance carrier for payment of any premium for this policy.
Any other insurance carried by Nevada that may be applicable
shall be excess insurance and Seller's insurance shall be primary
for all purposes despite any conflicting provisions in Seller's
policy."
F-1
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EXHIBIT G
Standby Service Agreement
WHEREAS, Nevada Power Company (Nevada) and Las Vegas Cogeneration
Limited Partnership (Seller) entered into a Contract for a Long
Term Power Purchase from Seller's Facilities located in North Las
Vegas, Nevada on the 27th day of May, 1992, and
WHEREAS, Seller wants Standby Service from Nevada,
NOW THEREFORE, Nevada, in exchange for the compensation
referenced herein, hereby agrees to provide Standby Service to
Seller pursuant to the terms and conditions of that Contract and
the additional terms and conditions set forth herein.
1. General:
1.1 Standby Capacity: 1000 KW.
1.2 Expected Annual Standby Energy Requirement:
500,000 KWH.
1.3 Standby Term: Coincident with the Contract Term.
2. Definitions: When used in this Contract and initially
capitalized the following terms shall have the
indicated meaning:
2.1 Standby Capacity: Seller's capacity requirement
that Nevada is obligated to serve whenever
Seller's Generating Facility experiences a Forced
or Scheduled Outage.
2.2 Standby Term: The period during which Nevada
shall provide Standby Service.
3. Termination: Unless otherwise provided within this
Exhibit G, this Exhibit G shall become effective upon
execution by the Parties and shall be terminated upon
expiration of the Standby Term set forth in Section
1.3.
4. Standby Metering: Meters and metering equipment
required to measure Standby Service shall be installed
in accordance with Nevada's Tariff. Meters so
installed shall be equipped with detents to preclude
reversal. If Nevada's meters fail to register, Nevada
shall render bills to Seller based upon Nevada's
estimate of Seller's Standby Service requirements.
Estimated bills shall have the same force and effect as
actual bills.
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5. Capacity Provisions: Standby Capacity shall not exceed
five (5) percent of Contract Capacity.
5.1 Standby Capacity Reduction: After Seller has
attained Firm Operation, Seller shall have the
right to reduce Standby Capacity by providing six
(6) months prior written notice of Seller's
intent. The provisions of this Exhibit G shall be
applicable to the reduced Standby Capacity.
5.2 Standby Capacity Increase: After Seller has
attained Firm Operation, Seller shall have the
right to increase Standby Capacity by providing
six (6) months prior written notice of Seller's
intent. The provisions of this Exhibit G shall be
applicable to the increased Standby Capacity.
6. Attachment of Documents:
6.1 If necessary to accomplish the requirements of
this Exhibit G, documents shall be attached hereto
and made a part hereof to the same extent as set
forth herein.
6.2 Preliminary documents shall be replaced with final
documents as final documents become available.
6.3 Standby meters and metering equipment shall be
installed in the location designated on Drawing
No. 2.3, Exhibit B2.
7. Billing Provisions: Seller shall pay for Standby
Service at Nevada's Tariff Schedule SS rates effective
when such Standby Service is provided. Nevada shall
render monthly bills to Seller for Standby Service.
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8. Signatures:
IN WITNESS WHEREOF, the Parties hereto have executed
this Exhibit G this 27 th day of May, 1992.
NEVADA POWER COMPANY: LAS VEGAS COGENERATION
LIMITED PARTNERSHIP:
By: Steven W. Rigazio By: J. Thomas Fowlkes
Name: Steven W. Rigazio Name: J. Thomas Fowlkes
Title: Vice President Title: President
Treas. & CFO United Cogen
Corporation
APPROVED AS TO FORM:
Gloria Moore
G-3
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APPENDIX A
LIST OF GRAPHIC AND IMAGE MATERIAL
1. Drawing of transmission requirement to interconnect. See
page B-8 of Exhibit B1 to the contact for a description of
the drawing.
2. Drawing of interconnection with Pecos and Craig Substations.
See page B-9 of Exhibit B1 to the contact for a description
of the drawing.
3. Drawing of interconnection detail. See page B-10 of Exhibit
B1 to the contact for a description of the drawing.
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SETTLEMENT AGREEMENT
--------------------
THIS SETTLEMENT AGREEMENT is made as of the 9th day of March, 1994, between
Mountain Coal Company and Atlantic Richfield Company ("Plaintiffs") and Nevada
Power Company ("Defendant").
RECITALS
--------
1. The parties are engaged in litigation before the United States
District Court for the District of Utah (Civil No. 92-C-522-S)
concerning three coal supply agreements (the "1980 Agreement,
"the "1982 Agreement," and the "1985 Agreement") and one
agreement for loading services ("Loading Agreement") (the "Utah
Action");
2. The parties have agreed to compromise and settle their pending
disputes upon the terms set out below.
NOW, THEREFORE, Plaintiffs and Defendant agree in compromise and settlement
of their claims as follows:
1. Defendant shall pay Plaintiff ARCO $25,000,000 for coal not sold
under the 1985 Agreement from December 31, 1992, through the
expiration of the term of the 1985 Agreement, and for loading
services not performed under the Loading Agreement, according to
the terms of a promissory note annexed hereto as Exhibit A, which
note shall be executed by Defendant concurrently with execution
by Defendant of this Settlement Agreement.
2. Defendant shall pay Plaintiff ARCO $310,552 in satisfaction of
certain price adjustments for past deliveries under the 1985
Agreement, made over the period 1987-1991, which sum is included
in the annexed Promissory Note.
3. The parties shall cause their legal counsel to do the
following(except as may be required to preserve the pricing
approach approved by the court in Civil No. 92-C-522-S as
contained in paragraph 9 of its July 30, 1993, Order) within
ten (10) days of the date of this Agreement:
a. Defendant shall dismiss with prejudice its appeal pending
before the United States Court of Appeals for the Tenth
Circuit, Case No. 93-4165;
b. Defendant shall dismiss with prejudice all claims pending
against Plaintiffs in the Utah Action;
c. Plaintiffs shall dismiss with prejudice all claims pending
by Plaintiffs against Defendant in the Utah Action;
d. All parties shall dismiss the Utah action.
4. The parties specifically exclude from this Settlement Agreement
the retroactive adjustment amounts on the 1980 and 1982
Agreements as detailed in ARCO's letter of January 6, 1994, which
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amounts are subject to ongoing audit and possible adjustment.
The parties further understand that performance under these
Agreements is ongoing and that NPC has not completed its audits
for deliveries under these agreements for the years 1991 to date.
These audits will be completed in the ordinary course, using West
Elk actual costs as approved by the Court in Civil No. 92-C-522-S
in paragraph 9 of its July 30, 1993, Order.
5. The parties acknowledge and agree that the 1985 Agreement and
Loading Agreement are at an end as of midnight, December 31,
1992. The parties confirm and agree that the 1980 and 1982
Agreements are in full force and effect and that, apart from
price adjustments, including without limitation any applicable
retroactive adjustments as may be required thereunder: (1) no
party has any claim against the other under either the 1980 or
1982 Agreements, (2) no party is in default thereunder as of the
date hereof, and (3) except for possible retroactive adjustments
as described in paragraph 4 above, each party hereby releases any
and all claims, known or unknown, which each may have against the
other party based upon any action or inaction occurring prior to
the date of this Agreement arising out of or in consequence of
any of the three Coal Supply agreements or the Loading Services
Agreement.
6. Each party shall bear its own costs and attorneys' fees for or in
connection with this litigation.
7. This Settlement Agreement contains the entire agreement between
the parties respecting settlement of the disputes between them
and there exists no other covenant, representation or agreement
respecting the subject matter hereof between the parties.
NEVADA POWER COMPANY MOUNTAIN COAL COMPANY
By: David G. Barneby By: Anthony G. Fernandes
An Authorized Representative An Authorized Representative
Title: Vice President - Power Delivery Title: Chairman
Dated: March 11, 1994 Dated: March 9, 1994
ATLANTIC RICHFIELD COMPANY
By: Anthony G. Fernandes
An Authorized Representative
Title: Senior Vice President
Dated: March 9, 1994
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EXHIBIT A
PROMISSORY NOTE
Pursuant to a Settlement Agreement of even date herewith, Nevada Power
Company, a Nevada corporation ("Nevada Power"), for value received, hereby
promised to pay to the order of ATLANTIC RICHFIELD COMPANY, a Delaware
corporation ("ARCO"), or ARCO's assigns, the sum of Twenty-five Million three
Hundred Ten Thousand, Five Hundred Fifty-two Dollars ($25,310,552.00) in
immediately available funds on or before June 11, 1994, at 555 Seventeenth
Street, Suite 2100, Denver, Colorado 80202.
Payment shall be made without interest if made on or before the close of
business on the thirtieth day after execution of the Settlement Agreement by
Plaintiffs. If payment is made after the thirtieth day, interest shall be paid
at a rate of ten percent (10%) annually ($6,934.40 per day), calculated from
April 13, 1994.
If unpaid, in whole or in part, on June 11, 1994, Nevada Power agrees to
confess judgment in any court of competent jurisdiction which ARCO may choose,
in favor of ARCO and against Nevada Power with interest accruing on said sum as
from April 13, 1994, at the rate of Ten Percent (10%) per annum. Nevada Power
hereby consents to jurisdiction and venue in any such court.
Nevada Power hereby waives presentment for payment, demand, notice of
dishonor and protest of this promissory note.
This instrument shall be governed in all respects by the law of the State
of Utah.
Any expense incurred by ARCO in the collection of this note by suit or
otherwise, including, but not limited to, attorneys' fees and court costs, shall
be borne by Nevada Power.
NEVADA POWER COMPANY
By: David G. Barneby
An Authorized Representative
Dated: March 9, 1994
<PAGE>
