NEVADA POWER CO - 10-K Annual Report

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d) OF
THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended DECEMBER 31, 2002

Registrant, State of Incorporation, Address of
Commission File Principal Executive Offices and Telephone I.R.S. employer State of
Number Number Identification Number Incorporation

1-08788 SIERRA PACIFIC RESOURCES 88-0198358 Nevada
P.O. Box 10100 (6100 Neil Road)
Reno, Nevada 89520-0400 (89511)
(775) 834-4011

2-28348 NEVADA POWER COMPANY 88-0420104 Nevada
6226 West Sahara Avenue
Las Vegas, Nevada 89146
(702) 367-5000

0-00508 SIERRA PACIFIC POWER COMPANY 88-0044418 Nevada
P.O. Box 10100 (6100 Neil Road)
Reno, Nevada 89520-0400 (89511)
(775) 834-4011

(Title of each class) (Name of exchange on which registered)
Securities registered pursuant to Section 12(b) of the Act:
Securities of Sierra Pacific Resources:

COMMON STOCK, $1.00 PAR VALUE NEW YORK STOCK EXCHANGE
COMMON STOCK PURCHASE RIGHTS NEW YORK STOCK EXCHANGE
PREMIUM INCOME EQUITY SECURITIES (PIES) NEW YORK STOCK EXCHANGE

Securities of Nevada Power Company and subsidiaries:
8.2% CUMULATIVE QUARTERLY INCOME NEW YORK STOCK EXCHANGE
PREFERRED SECURITIES, SERIES A, ISSUED BY NVP CAPITAL I

7 3/4% CUMULATIVE QUARTERLY TRUST ISSUED NEW YORK STOCK EXCHANGE
PREFERRED SECURITIES, ISSUED BY NVP CAPITAL III
Securities registered pursuant to Section 12(g) of the Act:
Securities of Sierra Pacific Power Company:

CLASS A PREFERRED STOCK, SERIES I, $25 STATED VALUE NEW YORK STOCK EXCHANGE

Indicate by check mark whether 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]

Indicate by check mark whether any registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act). Sierra Pacific Resources Yes [X] No [ ];
Nevada Power Company Yes [ ] No [X] Sierra Pacific Power Company
Yes [ ] No [X];

State the aggregate market value of the voting and non-voting stock held by
non-affiliates. As of June 28, 2002: $707,467,699

Indicate the number of shares outstanding of each of the issuer's classes of
Common Stock, as of the latest practicable date.

Common Stock, $1.00 par value, of Sierra Pacific Resources outstanding at
March 21, 2003: 117,135,012 Shares

Sierra Pacific Resources is the sole holder of the 1,000 shares of outstanding
Common Stock, $1.00 stated value, of Nevada Power Company.

Sierra Pacific Resources is the sole holder of the 1,000 shares of outstanding
Common Stock, $ 3.75 par value, of Sierra Pacific Power Company.

DOCUMENTS INCORPORATED BY REFERENCE:

Portions of Sierra Pacific Resources' definitive proxy statement to be filed in
connection with the annual meeting of shareholders, to be held May 12, 2003, are
incorporated by reference into Part III hereof.

This combined Annual Report on Form 10-K is separately filed by Sierra Pacific
Resources, Nevada Power Company and Sierra Pacific Power Company. Information
contained in this document relating to Nevada Power Company is filed by Sierra
Pacific Resources and separately by Nevada Power Company on its own behalf.
Nevada Power Company makes no representation as to information relating to
Sierra Pacific Resources or its subsidiaries, except as it may relate to Nevada
Power Company.

Information contained in this document relating to Sierra Pacific Power Company
is filed by Sierra Pacific Resources and separately by Sierra Pacific Power
Company on its own behalf. Sierra Pacific Power Company makes no representation
as to information relating to Sierra Pacific Resources or its subsidiaries,
except as it may relate to Sierra Pacific Power Company.
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SIERRA PACIFIC RESOURCES
NEVADA POWER COMPANY
SIERRA PACIFIC POWER COMPANY
ANNUAL REPORT ON FORM 10-K

CONTENTS

PART I.....................................................................................................3

ITEM 1. BUSINESS....................................................................................3
Sierra Pacific Resources.............................................................................3
Nevada Power Company.................................................................................4
Sierra Pacific Power Company........................................................................15
Other Subsidiaries Of Sierra Pacific Resources......................................................32
ITEM 2. PROPERTIES....................................................................................36
ITEM 3. LEGAL PROCEEDINGS..........................................................................36
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS........................................39

PART II...................................................................................................40

ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS (SPR).............40
ITEM 6. SELECTED FINANCIAL DATA....................................................................42
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS......44
Sierra Pacific Resources............................................................................60
Nevada Power Company................................................................................71
Sierra Pacific Power Company........................................................................84
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.............................114
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA...............................................117
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE...200

PART III.................................................................................................201

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT..........................................201
ITEM 11. EXECUTIVE COMPENSATION.................................................................207
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.........................214
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.........................................215
ITEM 14. CONTROLS AND PROCEDURES................................................................218

PART IV..................................................................................................219

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K........................219
SIGNATURES AND CERTIFICATIONS.........................................................................222

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FORWARD LOOKING STATEMENTS

The discussion of forward looking statements in Item 7, Management's
Discussion and Analysis of Financial Condition and Results of Operation, is
incorporated herein by reference.

PART I

ITEM 1. BUSINESS

SIERRA PACIFIC RESOURCES

Sierra Pacific Resources, hereafter known as SPR, was incorporated
under Nevada law on December 12, 1983. SPR's mailing address is P.O. Box 30150
(6100 Neil Road), Reno, Nevada 89520-3150 (89511).

SPR has seven primary, wholly owned subsidiaries: Nevada Power Company
(NPC), Sierra Pacific Power Company (SPPC), Tuscarora Gas Pipeline Company
(TGPC), Sierra Pacific Communications (SPC), Sierra Energy Company, dba e-three
(e-three), Sierra Pacific Energy Company (SPE), and Lands of Sierra (LOS). NPC
and SPPC are referred to together in this report as the "Utilities."

Periodic reports on Form 10-K and Form 10-Q and current reports on Form
8-K are made available to the public, free of charge, on the Sierra Pacific
Resources, Nevada Power Company and Sierra Pacific Power Company websites,
www.sierrapacificresources.com, www.nevadapower.com, and www.sierrapacific.com
and through links on these websites to the SEC's website at www.sec.gov as soon
as reasonably practicable after they have been filed with the SEC. The contents
of the above referenced website addresses are not part of this Form 10-K.

The discussion in this report has been divided wherever possible to
highlight the activities of the major subsidiaries of SPR. Parenthetical
references are included after each major section title to identify the specific
entity addressed in the section. References to SPR refer to the consolidated
entity, except for the section related to debt financing in which SPR debt is
discussed separately from that of its subsidiaries.

INDUSTRY AND REGIONAL PROBLEMS AFFECTING THE UTILITIES (NPC AND SPPC)

ELECTRIC INDUSTRY TRENDS

In the wake of volatile and unprecedented energy prices in the Western
United States in 2000 and a portion of 2001, the credit quality of a number of
utilities and power merchants deteriorated in 2002.

Like other utilities in the West, NPC and SPPC were adversely affected
by increased wholesale prices and by regulatory decisions that denied the
utilities the ability to recover in full their higher fuel and purchased power
costs. Major disallowances of power costs by the Public Utilities Commission of
Nevada (PUCN) in March and May of 2002 led to severe liquidity problems,
depressed earnings, and debt ratings downgrades for SPR and the Utilities.
Although energy price volatility has subsided, many policy, regulatory,
business, and financial issues remain, a number of which are being addressed or
litigated at state and federal levels. See Liquidity and Capital Resources, and
Regulation and Rate Proceedings, in Item 7, Management's Discussion and Analysis
of Financial Condition and Results of Operations, for additional information
regarding these issues.

Adding to liquidity concerns in the industry, a number of power
merchants had increased borrowings to purchase or build assets based on the
prospect of higher overall wholesale prices. Wholesale prices remained

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relatively steady in the latter part of 2002, causing demand projections to be
revised downward, with the result that planned investment in generation suddenly
declined and a number of highly leveraged companies were at risk of defaulting
on their obligations.

The year 2002 was also marked by a general economic downturn that left
few industries untouched. Several companies admitted to fraudulent energy
trading activities. Companies inside and outside the electric utility industry
admitted to fraudulent accounting practices. As a result, federal investigations
of corporations and energy markets were conducted and are ongoing. Investor,
consumer, and employee protection issues led to increased oversight of the
accounting profession, audit quality and independence, and to new accounting
principles and legislation. Passed in July, the Sarbanes-Oxley Act of 2002
enhances criminal penalties for certain corporate wrongdoings.

Rating agencies have also increased their scrutiny of the industry.
According to a recent release by Standard & Poors', credit rating activity in
2002 for the investor-owned power industry involved 182 downgrades compared with
only 15 upgrades during the year. The credit ratings of a number of companies,
including SPR, NPC, and SPPC, were downgraded more than once.

Transmission capacity continued to be constrained in many regions of
the country, according to the North American Electric Reliability Council. In
the second quarter of 2002, transmission congestion was almost three times the
level experienced during the same period in 1999. Investment in transmission has
been declining over the last decade.

REGULATION AND ELECTRIC RESTRUCTURING

The transition to retail competition continues to be highly uncertain,
driven by a changing wholesale market, the different approaches to retail
competition taken by state regulators and legislators, and the varying results
from those approaches.

Electric industry restructuring has been achieved in some states,
including Texas and a number of states in the Northeast. In the majority of
states, however, restructuring activities are either not active or they have
been suspended or eliminated. While retail competition has been halted for most
customers in Nevada, Assembly Bill 661 (AB 661), passed in 2001, allows
commercial and governmental customers with an average demand greater than one
megawatt (MW) annually to choose a new energy supplier beginning mid-2002 with
permission from the PUCN upon meeting public interest tests. To date, none have
left the system. However, 12 large customers have such applications pending with
the PUCN.

The Federal Energy Regulatory Commission (FERC) has remained committed
to regional transmission organization development and wholesale power
competition, and issued an initial standard market design (SMD) during 2002. The
SMD rule proposed to establish a single, standardized transmission service and a
single, standardized wholesale market design. In response to concerns expressed
by utility regulators in a number of states, the FERC announced it would issue a
white paper on its proposed SMD rule in April 2003.

NEVADA POWER COMPANY

NPC is a Nevada corporation organized in 1921. NPC became a wholly
owned subsidiary of SPR on July 28, 1999. Its mailing address is 6226 West
Sahara Avenue, Las Vegas, Nevada 89146.

NPC is a public utility engaged in the distribution, transmission,
generation, purchase, and sale of electric energy in Clark County in southern
Nevada. NPC provides electricity to approximately 669,000 customers in the
communities of Las Vegas, North Las Vegas, Henderson, Searchlight, Laughlin, and
adjoining

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areas, including Nellis Air Force Base. Service is also provided to the
Department of Energy's Nevada Test Site in Nye County.

During 2002, Nevada Electric Investment Company (NEICO) became a wholly
owned subsidiary of NPC. In October of 1997, NEICO and UTT Nevada, Inc., an
affiliate of Exelon Thermal Technologies, formed Northwind Las Vegas, LLC, a
Nevada limited liability company, for the purpose of evaluating district energy
projects in southern Nevada. Also, in October of 1997, NEICO and UTT Nevada,
Inc. formed Northwind Aladdin, LLC, a Nevada limited liability company, for the
purpose of owning, constructing, operating and maintaining a facility for the
production and distribution of chilled water, hot water and emergency power for
Las Vegas' Aladdin Hotel and Casino, which filed for Chapter 11 bankruptcy
protection in September 2001. The project was completed in the first quarter of
2000 and is operational.

In September 1998, NEICO and e-three formed e-three Custom Energy
Solutions, LLC, a Nevada limited liability company, for the purpose of selling
and implementing energy-related performance contracts and similar energy
services in southern Nevada. Refer to Other Subsidiaries of Sierra Pacific
Resources, e-three for a more complete discussion of these activities.

BUSINESS AND COMPETITIVE ENVIRONMENT

NPC's electric business contributed 100% of its 2002 operating revenues
of $1.9 billion. The system has an annual load factor of approximately 49%,
which is slightly lower than the industry norm of 50% to 55%.

Summer retail peak loads are driven by air conditioning demand. NPC's
peak load increased an average of 5.7% annually over the past three years,
reaching 4,617 MW on July 12, 2002. NPC's total electric megawatt-hour (MWh)
sales have increased an average of 3.9% annually over the past three years.
Winter peak loads are low relative to the summer peak. Winter load above the
base amount is driven by air handling in forced air furnaces.

NPC's service territory continues to be one of the fastest growing
areas in the nation, with residential customer growth averaging 5.3% per year
over the past 5 years. A significant part of the growth in NPC's electric sales
has resulted from new residential, industrial, and gaming customers.

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NPC's electric customers by class contributed the following toward 2002
and 2001 MWh sales:

Tourism and gaming remain southern Nevada's premier industries. Over 35
million tourists visited Las Vegas in 2002, infusing approximately $19.6 billion
into the local economy during the year. Currently, Las Vegas is the home of 17
of the world's 20 largest hotels. Las Vegas' newest casino, the 201 room
Cannery, opened on January 2, 2003 and carries a 1940s industrial theme
throughout the property. The Ritz-Carlton opened the upscale 349-room,
Mediterranean-themed MonteLago Village at Lake Las Vegas on February 11, 2003.
The Venetian Hotel plans to open its 1,013-suite second tower in June 2003.
Mandalay Resort Group has started construction on a 1,125-suite hotel tower
slated to open in November 2003. Steve Wynn's Le Reve Resort is under
construction and is scheduled for completion March 2005.

The Mandalay Resort Group opened a new 1.5 million square foot Mandalay
Bay Convention Center on January 6, 2003, becoming the nation's fifth largest
convention center. The Las Vegas Convention Center now has more than 3.2 million
square feet of total space and features approximately 2 million square feet of
net exhibit space and 380,000 square feet of net meeting room space,
accommodating 170 meeting rooms with seating capacities from 20 to 7,500. In
2002 more than 5.1 million convention and trade show delegates traveled to Las
Vegas, generating more than $5.9 billion in non-gaming revenue.

Despite the expansion of tourism and gaming properties in southern
Nevada, a number of gaming properties filed for bankruptcy during 2002 and the
industry is subject to a number of risks described later in Item 7, Management's
Discussion and Analysis.

During 2002, firm and non-firm sales to wholesale customers comprised
20.6% of total energy sales, a decrease of 58.7% from the prior year. Wholesale
customers consist of other utilities or municipalities that sell power to end
users, marketing entities and others that exchange power with NPC.

NPC's decrease in wholesale MWh sales from last year was a result of
market conditions and a change in NPC's power procurement activities. See Energy
Supply in Item 7, Management's Discussion and Analysis of Financial Condition
and Results of Operations, for a discussion of the Utilities' purchased power
procurement strategies.

6

CONSTRUCTION PROGRAM

NPC'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, the number and status of proposed independent
generation projects, the need for additional transmission capacity in southern
Nevada, adequacy of rate relief, NPC's ability to raise necessary capital, and
changes in environmental regulations. Under NPC's franchise agreements, it is
obligated to provide a safe and reliable source of energy to its customers.
NPC's service territory is one of the fastest growing areas in the nation.
Capital construction expenditures and estimates are reflective of this
obligation to serve.

Gross construction expenditures for 2002, including allowance for funds
used during construction (AFUDC) and contributions in aid of construction, were
$294.5 million, and for the period 1998 through 2002, were $1.24 billion.
Estimated construction expenditures for 2003 and the period from 2004 to 2007
are as follows (dollars in thousands):

Total construction expenditures estimated for 2003 and the 2004-2007
period consist of the following (dollars in thousands):

The Centennial Plan involves construction of the following 500 kV
lines: (1) the Harry Allen substation to Crystal substation 500 kV lines, (2)
the Harry Allen substation to Northwest substation 500 kV line, and (3) the
Harry Allen substation to Mead substation 500 kV line. Additional facilities
include a new 500 kV substation at Harry Allen, 500/230 kV transformer at Mead
and Northwest substation, phase shifting transformer at Crystal substation, and
several other sub-transmission upgrades and additions. Total estimated cost of
the Centennial project is $307.7 million. Total project costs incurred through
December 31, 2002, were $112.9 million. Estimated costs for 2003 are $58.0
million, which are expected to be financed utilizing internally generated cash.

The Centennial Plan was approved in NPC's 2001 Refiled Resource Plan.
An amendment to NPC's Refiled Resource Plan was approved by the PUCN in August
2002, which amended the in-service date for the

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Harry Allen to Mead 500 kV project from June 2003 to April 2005. Meetings have
been held with the PUCN to review the revision to the scheduled in-service date
from April 2005 to April 2006 for the Harry Allen to Mead project. See
Transmission, later, for additional information about the Centennial Plan.

FACILITIES AND OPERATIONS

TOTAL SYSTEM

NPC maintains a wide variety of resources in its generation system.
During 2002, NPC generated 44.0% of its total electric energy requirements,
purchasing the remaining 56.0% as shown below:

NPC's decision to purchase short-term and spot energy is based on the
economics of purchasing "as-available" energy when it is less expensive than its
own generation.

NPC's 2002 company generation of 10,147,053 MWh is up 2.5% from NPC's
2001 company generation of 9,899,195 MWh. NPC's 2002 purchased power of
12,907,835 MWh is down 33.0% from NPC's 2001 purchased power of 19,268,305 MWh
due to changes in NPC's purchased power procurement strategies. See Energy
Supply in Management's Discussion and Analysis for additional information
regarding NPC's purchasing strategies.

RISK MANAGEMENT

See Item 7A, Quantitative and Qualitative Disclosures About Market
Risk.

LOAD AND RESOURCES FORECAST

NPC's electric customer growth rate was 4.8% in 2002, 4.5% in 2001, and
5.1% in 2000. Annual retail electricity sales were 17.6 million MWh in 2002,
which represents an increase of 2.3% over 2001 retail electricity sales of 17.2
million MWh. Annual wholesale electricity sales reached 4.6 million MWh in 2002,
which represents a decrease of 58.6% from 2001 wholesale electricity sales of
11.1 million MWh. Overall, annual system electricity sales reached 22.2 million
MWh in 2002, which represents a decrease of 21.5% from 2001 system electricity
sales of 28.3 million MWh. The bulk of the 21.5% decrease is attributed to
wholesale sales. The peak electric demand rose from 4,412 MW in 2001 to 4,617 MW
in 2002.

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The projections shown below are forecasts of the load to be provided to
all of NPC's current and forecasted customers. No adjustments have been made at
this time to incorporate possible changes to NPC loads due to the passage of AB
661 and Senate Bill 211 (SB 211). SB 211 allows the Colorado River Commission to
sell electricity to its purveyors of water. AB661 allows commercial and
governmental customers with an average demand greater than 1 MW to select other
energy suppliers. See Regulation and Rate Proceedings, Nevada Matters, Customers
File Under AB661 in Item 7, Management's Discussion and Analysis of Financial
Condition and Results of Operations. The forecast takes into account many
sources of information. The peak load forecast uses the economic forecast
produced by the University of Nevada Las Vegas' Center for Business and Economic
Research. The population forecast is used to develop a customer forecast for
NPC. Other major assumptions are normal weather (based on 20-year averages), and
the addition of hotel rooms will continue as expected. Other uncertainties
include abnormal temperatures, the price levels NPC will be allowed to charge,
and the timing of rules allowing customers to leave NPC under AB 661 and SB 211.
Also, bundled retail price levels, as well as availability of power in the West,
could have great effects on consumption by customers of NPC. NPC's total system
capability and peak loads for 2002, and the forecast for summer peak demand for
2003 and 2004 (assuming no curtailment of supply or load, and normal weather
conditions), are indicated below:

(1) Existing Generation Capacity includes Clark, Reid Gardner, Sunrise,
Harry Allen Generating Stations, and NPC's share of Mohave and Navajo
Generating Stations.

(2) NPC and its partners in the Mohave Generating Station have not been
able to install extensive pollution control equipment necessary to have
Mohave's operations extended past 2005 due to coal supply and water
issues. The Mohave plant represents 196 MW of capacity. See Note 17 of
Notes to Financial Statements, Commitments and Contingencies,
Environment for further discussion.

(3) Long-Term Purchases include NPC's allotment of hydroelectric power from
Hoover Dam. Values are net of line losses.

(4) Non-Utility Generation Capacity includes SunPeak units and the
Qualifying Facilities.

(5) Amount represents on peak wholesale to Silver State Power Pool. Silver
State Power Pool, a wholesale customer, is not included in the system
peak value of 4,617 MW for 2002. Therefore, NPC resources (generation
and purchases) are reduced by the amount of load serving Silver State
to show NPC's resources left available to meet the system peak.

(6) Additional Required represents the additional, uncommitted capacity
needed in order to maintain an adequate reserve margin consistent with
the Western Electricity Coordinating Council planning reserve criteria.
These additional reserves will be met, if needed, with short-term
purchases.

(7) The system peak shown for 2002 of 4,617 MW occurred on July 12, 2002 at
4:00 p.m.

NPC plans its system capacity needs in accordance with the Western
Electricity Coordinating Council (WECC) reliability criteria, which recommends
planning reserves in excess of required operating reserves.

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GENERATION

The following is a list of NPC's share of generation plants (except
Reid Gardner No. 4, see note (2) below), including the MW summer net capacity,
the type and fuel used for generation, and the year(s) that the unit(s) was
(were) installed.

(1) The combined cycles at Clark Station each consist of one steam turbine
and two combustion turbines for a total of six generating units.

(2) Reid Gardner Units 1 through 3 are owned by NPC. Reid Gardner Unit No.
4 is jointly owned by the California Department of Water Resources
(CDWR) (67.8%) and NPC (32.2%). NPC is the operating agent.
Contractually, NPC is entitled to receive 24 MW of base load capacity
from Reid Gardner Unit No. 4 and 226 MW of peaking capacity from Reid
Gardner Unit No. 4 for a total base load capacity of 354 MW and peaking
capacity of 605 MW for all Reid Gardner Units. NPC is entitled to use
100% of the unit's peaking capacity for 1,500 hours each year and is
entitled to 9.6% of the first 250 MW of capacity and associated energy.

(3) This represents NPC'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 represents NPC's 14% undivided interest in the Mohave Generating
Station as tenant in common without right of partition with three other
non-affiliated utilities, less operating restrictions.

(5) Due to coal supply and water issues, the Mohave plant will not be able
to operate after December 31, 2005. See Note 17 of Notes to Financial
Statements, Commitments and Contingencies, Environment for further
discussion.

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PURCHASED POWER

NPC continues to manage a diverse portfolio of contracted and spot
market supplies, as well as its own generation, with the objective of minimizing
its net average system operating costs. During 2002, NPC experienced favorable
market energy prices when compared with the previous four years. The decrease in
market energy prices is reflective of FERC price cap regulation, plus the price
of gas and power volatility in general, which decreased electricity costs
throughout the western United States.

During 2002, NPC experienced difficulty maintaining liquidity in
western energy markets due to counterparties' credit concerns with NPC when its
credit rating dropped below investment grade. With only a handful of
counterparties willing to transact, NPC found it necessary to 1) contract with
energy marketers to transact on NPC's behalf, and 2) negotiate special payment
arrangements to satisfy credit concerns. These two actions remedied the
liquidity limitation.

If NPC continues to experience financial difficulty or if its credit
ratings are further downgraded, NPC may experience considerable difficulty
entering into new power supply contracts, particularly under traditional payment
terms. If suppliers will not sell power to NPC under traditional payment terms,
NPC may have to pre-pay its power requirements. If it does not have sufficient
funds or access to liquidity to pre-pay its power requirements, particularly at
the onset of the summer months, and is unable to obtain power through other
means, NPC's business, operations and financial condition would be materially
adversely affected and could make it difficult to provide reliable service to
its customers and/or to continue to operate outside of bankruptcy.

NPC is a member of the Western Systems Power Pool and the Southwest
Reserve Sharing Group (SRSG). NPC's membership in the SRSG has allowed it to
network with other utilities in an effort to use its resources more efficiently
in the sharing of responsibilities for reserves.

NPC purchases both forward firm energy (typically in blocks) and spot
market energy based on economics, operating reserve margins and unit
availability. NPC seeks to manage its growing loads efficiently by utilizing its
generation resources in conjunction with buying and selling opportunities in the
market.

NPC 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. NPC's allocation of hydroelectric capacity is 235 MW annually.

NPC has a contract to purchase 222 MW annually from Nevada Sunpeak
Limited Partnership, an independent power producer. The contract became
effective June 8, 1991 and will continue through May 31, 2016.

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According to regulations issued pursuant to the Public Utility
Regulatory Policies Act (PURPA), NPC is obligated, under certain conditions, to
purchase the output produced by small power producers and co-generation
facilities at costs determined by the appropriate state utility commission.
Generation facilities that meet the specifications of the regulations are known
as qualifying facilities (QFs). As of December 31, 2002, NPC had a total of 305
MW of contractual firm capacity under contract with four QFs. All QF contracts
currently delivering power to NPC at long-term rates have been approved by the
PUCN and have QF status as approved by the FERC. The QFs are as follows:

Energy purchased by NPC from the QFs constituted 25.7% of the net
purchased power requirements (excluding wholesale purchases) and 12.4% of the
net system requirements during 2002. All of the QFs are co-generators providing
steam for various products and businesses.

In November 2002, NPC executed and filed with the PUCN four long term
power purchase agreements (PPAs) with geothermal developers in northern Nevada
for a total of 97 MW or an estimated 841,000 MWh per year, and two PPAs with
wind developers, one in each of northern and southern Nevada for a total of 130
MW or an estimated 405,000 MWh per year. The combined total estimated non-solar
supply is 1,246,000 MWh annually. The contract term for all but one geothermal
PPA is for twenty years. The term for the remaining geothermal PPA is ten years,
with an option for either party to extend the PPA by an additional ten years.

NPC also executed five power purchase agreements related to the
purchase of renewable energy under the terms of which NPC sells the power
associated with the renewable energy contracts located in northern Nevada to
SPPC ("Related PPAs"). For these five non-solar PPAs involving suppliers in
SPPC's service territory, NPC will receive "Product" (Product is a defined term
in the PPA that includes all Renewable Energy Credits "RECs" and energy supplied
by the developer) from the renewable supplier at a delivery point on SPPC's
transmission system and then NPC will immediately resell the energy to SPPC
under the terms and conditions of a "Related PPA" (defined term in the original
PPA). NPC will retain the RECs to comply with the requirements of SB 372,
Nevada's renewable portfolio law.

NPC has also executed a solar renewable energy PPA with Duke Solar for
a 50 MW facility located near Boulder City in Clark County, Nevada in NPC's
service territory. NPC expects to purchase approximately 70 GWh of energy that
includes Renewable Energy Credits "RECs" annually.

SPPC entered into a solar PPA with Duke Solar from the same facility
located in NPC's service territory. NPC executed an additional Related PPA for
this facility. For SPPC's solar PPA, SPPC will receive Product from the
renewable supplier at a delivery point on NPC's transmission system and then
SPPC will immediately resell the energy to NPC under the terms and conditions of
the Related PPA. SPPC will retain the RECs to comply with SB 372. NPC expects to
purchase 32 GWh of energy under the terms of the Related PPA. The terms for both
SPPC and NPC's solar PPAs are 20 years.

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NPC also executed a long term PPA with MNS Wind on the Nevada Test Site
for an 85 MW wind project in February 2002.

TRANSMISSION

NPC's existing transmission lines are primarily located within Clark
County, Nevada. Six 230 kV transmission lines and two 230/69 kV transformers
connect NPC to the Western Area Power Administration's transmission facilities
at Henderson and Mead substations. Three 230 kV lines connect NPC to the Los
Angeles Department of Water and Power's transmission facilities at McCullough
Substation. Two 500/69 kV transformers connect NPC to the Southern California
Edison system at the Mohave Generating station. A 345 kV line connects NPC to
PacifiCorp at the Utah-Nevada state line. Also, NPC has two 500/230 kV
transformers that connect NPC to the Navajo Transmission System at the Crystal
Substation. Finally, NPC has ownership rights in two 500 kV transmission lines
that allow for the transmittal of NPC's share of power from its interests in the
Mohave and Navajo Generating Stations to the NPC control area. If the Mohave
Generating station is shut down in 2005, NPC intends to continue to utilize the
Eldorado Transmission System that is connected to the Mohave Generating station
to supply NPC load and to meet other transmission service obligations currently
in place. The transmission and generation are governed under separate contracts.

NPC received approval from the PUCN to construct two transmission line
projects and four switchyards proposed in NPC's 2001 Refiled Resource Plan. The
Arden-Tolson 230 kV line upgrade, was completed in June 2002 to meet Independent
Power Producers (IPP's) transmission service requests at a cost of $475,000. The
Faulkner-Tolson 230 kV transmission line will be completed in 2003 at a cost of
$9.65 million and will increase NPC's import capability by 300 MW. The
Equestrian switchyard was placed in service in 2001. The McDonald switchyard is
planned to be completed in 2006. The Avera 230/138 kV switching station and the
Beltway 230/138 switching station upgrade projects are all internal NPC
reinforcements with 2003 and 2004 in-service dates, respectively. The Avera and
Beltway projects are needed for system reliability, increased import capability,
and to provide a path for Centennial IPP energy to be delivered into or through
NPC's transmission system. The Avera project costs are estimated at $5.3 million
and the Beltway project costs are approximately $8.25 million.

As a result of the supply shortage in the western United States
experienced during 2000 and 2001, several IPPs proposed the construction of new
generating plants in southern Nevada and requested transmission service from
NPC. NPC proposed the Centennial Plan to address transmission service requests
from these IPPs. The Centennial Plan was approved in NPC's 2001 Refiled Resource
Plan. This plan, consistent with its tariff and the FERC pricing policies,
involves the following lines (1) the Harry Allen substation to Crystal
substation 500 kV line, (2) the Harry Allen substation to Northwest substation
500 kV line, (3) the Harry Allen substation to Mead substation 500 kV line and
(4) two Bighorn to Arden 230 kV lines. Additional facilities include a new 500
kV substation at Harry Allen, 500/230 kV transformers at Mead, McCullough and
Northwest substations, two phase shifting transformers at Crystal substation,
and several other sub-transmission upgrades and additions. The Harry Allen
- -Crystal 500 kV line and the Harry Allen 500 kV substation were energized in
June 2002. The Arden- Bighorn 230 kV #1 and #2 lines were completed in July
2002. The Harry Allen - Northwest 500 kV line, the Northwest 500/230 kV
transformer and the Northwest 500 kV substation were completed in mid-March
2003. The Crystal 500 kV phase shifting transformers will be installed in
February 2004. The scheduled in-service date for the Harry Allen-Mead 500 kV
line, the Mead 500/230 kV transformer and the McCullough 500/230 kV transformer
is April 2006.

See Regulation and Rate Proceedings, FERC Matters in Item 7,
Management's Discussion and Analysis of Financial Condition and Results of
Operations for a discussion of regional transmission issues.

13

FUEL AVAILABILITY

NPC's 2002 fuel requirements for electric generation were provided by
natural gas, coal and oil. The average costs of coal, gas and oil for energy
generation per million British thermal units (MMBtu) for the years 1998 - 2002,
along with the percentage contribution to total fuel requirements were as
follows:

Average Consumption Cost & Percentage Contribution to Total Fuel Requirements

* Oil was less than .1% of consumption

For a discussion of the change in fuel costs, see Results of Operations
in Item 7, Management's Discussion and Analysis of Financial Condition and
Results of Operations.

Coal delivered to the Reid Gardner Station originates from various
mines in the Utah coalfields and is delivered to the station via the Union
Pacific Railroad. Partial requirements for coal supplies are under contract for
various terms up to 2007, with the remainder of 2002's requirements purchased
from the spot market under four one-year contracts. NPC's long-term coal supply
agreement with RAG Coal Sales of America, Inc. is supplied from its Willow Creek
Mine in Carbon County, Utah, which experienced an explosion and fire on July 31,
2000. No deliveries under this agreement were scheduled for 2002 and NPC
replaced these volumes with spot market purchases. The mine remains sealed and
NPC does not anticipate that deliveries will resume before the contract
terminates. The contract remains in a force majeure status. The contract was due
to expire in 2007 and has been replaced by short-term purchases.

The Union Pacific Rail Transportation contract provides for deliveries
from the Provo, Utah interchange as well as various mines in the Price, Utah
area, to the Reid Gardner Station in Moapa, Nevada. This contract was effective
January 1, 1996 and has been extended through December 31, 2004. The Utah
Railway contract provides for the remainder of NPC's Price, Utah area supplies.
This contract has been extended through December 31, 2003 and will be
renegotiated year to year as needed. All of NPC's rail transportation contracts
contain certain tonnage requirements and railroad service criteria.

Coal for both the Mohave and Navajo Stations is obtained from surface
mining operations conducted by Peabody Coal Company on portions of the Black
Mesa in Arizona within the Navajo and Hopi Indian Tribes reservations. The
supply contracts with Peabody extend to December 31, 2005, for Mohave and to
June 1, 2011, for Navajo, with each contract having an option to extend for an
additional 15 years. The Mohave coal is delivered from the mine to Mohave by
means of a coal slurry pipeline, which requires water that is obtained from
groundwater wells located on lands of the Tribes in the mine vicinity.

Due to the lack of progress in negotiations with the Tribes and other
parties to resolve several coal and water supply issues, Southern California
Edison's (SCE's) application with the California Public Utility Commission
(CPUC) to determine whether it is in the public interest to continue operation
of the Mohave facility states that it probably will not be possible for SCE, the
operating partner, to extend Mohave's operations beyond 2005. Due to the
uncertainty over a post-2005 coal supply, SCE and the other Mohave co-owners
have been prevented from commencing the installation of extensive pollution
control equipment that must be put in place if Mohave's operations are extended
past 2005.

14

NPC purchases natural gas on a firm, fixed and indexed price basis from
the Rocky Mountain Basin.

Natural gas is transported to the Clark, Sunrise and Harry Allen
stations via Kern River Gas Transmission Company from the Rocky Mountain Basin.
NPC has entered into a summer seasonal transportation contract for 50,000
decatherms (Dth)/day and an annual contract for 75,000 Dth/day of Kern River
Pipeline capacity. This service is scheduled for delivery in May 2003 and will
run for a period of 15 years. NPC also responded to an open season for shorter
term service in the Kern River California Emergency Expansion and was awarded
29,600 Dth/day for the period July 2001 to April 2002, and 5,600 Dth/day for the
period May 2002 to April 2003. The Kern River California Emergency Expansion
service does not carry any renewal rights.

Local natural gas transportation service to Clark and Sunrise Stations
is provided under a 32-year transportation services contract with Southwest Gas
Company signed in 1995. This contact provides firm service and contains certain
operating and nominating provisions. The Harry Allen Station is directly
connected to Kern River Pipeline.

Oil provides a secondary fuel for Clark, Sunrise and Harry Allen
Stations and is used in the igniters at Reid Gardner.

REGULATION AND RATE PROCEEDINGS

See Regulation and Rate Proceedings in Item 7, Management's Discussion
and Analysis of Financial Condition and Results of Operations.

OTHER

On July 7, 2002, the Board of County Commissioners of Clark County,
Nevada, added an Electric Utility Advisory Question to its November 5, 2002,
general election ballot which asked voters in a non-binding initiative whether
"the Nevada Legislature should take appropriate action to enable the electrical
energy provider for southern Nevada to be a locally controlled, not for profit
public utility." The Company and various private entities and public interest
groups strongly opposed the measure. Although passing by a 57% majority, this
was substantially below the level of support indicated in early polls. No bills
related to this issue were introduced in the 2003 Nevada legislative session.

On August 22, 2002, SPR received a letter from the Southern Nevada
Water Authority ("SNWA") stating that it was prepared to enter into good faith
negotiations of definitive agreements to acquire NPC in some undetermined way
(stock purchase or all or some of its assets) and to assume some unspecified
amount of indebtedness, at a purchase price subject to adjustment at SNWA's
discretion at the conclusion of negotiations and due diligence. On September 12,
2002, SPR responded with a letter stating that it did not view the SNWA's letter
as an offer and expressing concerns with the SNWA's financing plans, certain
significant legal issues with the proposal, SNWA's lack of utility management
experience, and ambiguity in the proposal. SPR was served with a complaint by a
shareholder seeking class action status to require SPR to enter into
negotiations. See Legal Proceedings for further details.

SIERRA PACIFIC POWER COMPANY

SPPC is a Nevada corporation organized in 1965 as a successor to a
Maine corporation organized in 1912. SPPC became a wholly owned subsidiary of
Sierra Pacific Resources on May 31, 1984. Its mailing address is Post Office Box
10100 (6100 Neil Road), Reno, Nevada 89520-0024.

15

SPPC is a public utility primarily engaged in the distribution,
transmission, generation, purchase, and sale of electric energy. It provides
electricity to more than 318,000 customers in an approximately 50,000 square
mile service area in western, central and northeastern Nevada, including the
cities of Reno, Sparks, Carson City, and Elko, and a portion of eastern
California, including the Lake Tahoe area. In 2002, electric revenues were 86.1%
of SPPC's revenue.

SPPC also provides natural gas service in Nevada to approximately
123,500 customers in an area of about 600 square miles in Reno/Sparks and
environs. In 2002, natural gas revenues were 13.9% of SPPC's revenues.

In June 2001, SPPC completed the sale of its water business to the
Truckee Meadows Water Authority (TMWA) for $341 million. SPPC recorded a $25.8
million gain on the sale, net of income taxes of $18.2 million. The sale
agreement contemplates a second closing for the transfer of hydroelectric
facilities included in the contract of sale for an additional $8 million to
accommodate review of the transaction by the CPUC. See Sale of Water Business,
later, for further discussion.

SPPC has three primary, wholly owned subsidiaries: GPSF-B, Pinon Pine
Corp. (PPC) and Pinon Pine Investment Co. (PPIC). GPSF-B, PPC and PPIC,
collectively, own Pinon Pine Company, L.L.C., which was formed to take advantage
of federal income tax credits available under Section 29 of the Internal Revenue
Code associated with the alternative fuel (syngas) produced by the coal gasifier
located at the Pinon Pine facility. See Note 21 of Notes to Financial
Statements, Pinon Pine.

BUSINESS AND COMPETITIVE ENVIRONMENT

In 2002, SPPC's electric business contributed $931 million (86.1%) in
revenues from continuing operations. The electric system peak typically occurs
in the summer, while the winter peak is nearly as high. The system has an annual
load factor of approximately 74.98%, which is higher than the industry norm of
50% to 55%.

Winter retail peak loads are primarily driven by increased demand for
space heating, demand for air movement (with forced air gas and oil furnaces),
and ski resort demands (hotels, lifts, etc.). Summer retail peak loads are
primarily driven by cooling equipment demand (including air conditioning demand)
and irrigation pumping. SPPC's peak load increased an average of 2.7% annually
over the past three years, reaching 1,590 MW on July 10, 2002. SPPC's total
retail electric MWh sales have increased an average of 1.1% annually over the
past three years.

16

SPPC's electric customers by class contributed the following toward
2002 and 2001 MWh sales:

According to the Nevada Division of Minerals, gold is Nevada's most
important mineral commodity in terms of economic impact on the state and on
communities located near mining operations. The state's gold production has
remained near 8 million ounces per year over the past 5 years, enabling Nevada
to maintain its position as the leading gold producing state in the U.S. While
gold mining in past years has been challenged by a relatively low commodity
price, individual mines have focused on improving efficiency at their
operations, reducing overhead costs, and closing down less efficient and
uneconomic properties. While these actions led to a small decrease in total MWh
sales by SPPC to the mining industry during 2002, they also enabled mines to
lower production costs so they could operate economically during the period of
low gold prices and improve their competitive position. With projections that
recent increases in gold prices will be sustained at or above current levels for
a number of years, individual companies are expected to maintain their
production activities and resulting energy use at current levels for the
foreseeable future.

SPPC has long-term electric service agreements with eight of its major
mining customers. The terms range from 5 to 15 years from the effective dates of
these agreements with the longest term contract expiring in 2011. SPPC had sales
in 2002 of approximately $148 million in annual revenues, which is 16.0% of 2002
electric operating revenues under these agreements. The agreements require that
customers maintain minimum demand and load factor levels, and include
termination charge provisions to recover all of SPPC's customer-specific
facilities investment and secures approximately $6 million in annual revenues
through electric facilities charges.

The offices/schools/government and healthcare customer segment
continues to grow with the addition of new schools, government facilities and
healthcare facilities. At the same time that growth is occurring, customers'
implementation of energy conservation and efficiency programs has led to a 4.85%
decrease in energy sales to the overall sector. In healthcare, increasing
demands for new long term and acute care facilities is expected to double the
number of facilities by 2006. In the education sector, one new high school will
open in 2003, a middle school in 2004, and on average, two new schools will be
added each year between 2005 and 2007.

The resorts and recreation customer segment, consisting of hotels,
casinos and ski resorts, account for 7.3% of the total electric system retail
MWh sales. MWh sales were down 8% in 2002 compared to 2001 primarily as a result
of customers' continued efforts to implement energy conservation measures. In
the ski

17

resort segment, energy consumption was reduced in response to heavy natural
precipitation and snow early in the 2002-2003 ski season that enabled resorts to
decrease their use of artificial snowmaking equipment.

In 2002, tourism and gaming were negatively impacted by a reduction in
flight schedules to northern Nevada and a continuing increase in competition
from gaming on Indian reservations in California. In response, the industry and
the community continued to work together to strengthen the region's competitive
position in the tourism, gaming and leisure markets. These efforts included the
opening of a major new hotel casino in Reno, the completion of a $105 million,
500,000 square foot renovation and expansion of the Reno-Sparks Convention
Center, and the repositioning of the state's tourism advertising to promote its
natural resources and its diversified entertainment and recreation
opportunities.

The manufacturing and warehousing customer segment overall continued to
decline for a second straight year. Many manufacturing customers have suffered
large order reductions and production losses due to the economic slowdown.
However, manufacturing orders are beginning to recover from their all time low
point in 2002. At the same time, there has been an increase in the number of
customers in the sector as the result of small manufacturers relocating out of
the California market. Northern Nevada continues to develop as a destination for
relocating high-technology companies, which could result in an increase in sales
to the manufacturing and warehousing customer segment. In 2002 SPPC continued to
solidify working relationships within the business community by assisting in the
recruitment of industries in targeted sectors such as plastic manufacturers and
high-technology companies.

The 2001 session of the Nevada State Legislature enacted AB 661. One
provision of this bill allows commercial customers with an average annual load
of 1 MW or more to file a letter of intent and application with the PUCN to
acquire electric energy, capacity, and ancillary services from another provider
beginning in mid-2002. This provision was part of a package of legislation
passed by the 2001 Legislature to ensure the continued creditworthiness of the
Utilities, protect consumers from unexpected rate hikes, and attract new energy
suppliers to Nevada. During 2002, one qualifying customer filed a notice of
intent with the PUCN indicating their desire to procure energy services from a
new provider. This customer has not yet filed a formal application with the PUCN
but could do so at any time. Under the law, the earliest departure date would be
180 days after the application is filed.

SPPC's MWh sales to wholesale customers have decreased 36.8% over the
past year. During 2002 firm and non-firm sales to wholesale customers comprised
23.0% of total energy sales. Wholesale customers consist of other utilities or
municipalities that sell power to end users, marketing entities and others that
exchange power with SPPC.

SPPC's decrease in wholesale MWh sales from last year was a result of
market conditions and SPPC's power procurement activities. See Energy Supply in
Item 7, Management's Discussion and Analysis of Financial Condition and Results
of Operations, for a discussion of the Utilities' purchased power procurement
strategies.

CONSTRUCTION PROGRAM

SPPC'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

18

costs, availability of fuel types, the number and status of proposed independent
generation projects, the need for additional transmission capacity in northern
Nevada, adequacy of rate relief, SPPC's ability to raise necessary capital and
changes in environmental regulation. Under SPPC's franchise agreements, it is
obligated to provide a safe and reliable source of energy to its customers.
SPPC's service territory continues to experience steady growth. Capital
construction expenditures and estimates are reflective of this obligation to
serve.

Gross construction expenditures for 2002, including AFUDC and
contributions in aid of construction, were $105.3 million, and for the period
1998 through 2002, were $719.4 million. Estimated construction expenditures for
2003 and the period 2004-2007 are as follows (dollars in thousands):

19

Total construction expenditures estimated for 2003 and the 2004-2007
period, for each segment of SPPC's business, consist of the following (dollars
in thousands):

The Falcon to Gonder Transmission Project is a 345kV transmission line
within northern Nevada with a planned in-service date of May 2004. Total project
costs incurred through December 31, 2002, were $32.8 million. Actual costs
incurred in 2002 were $21.0 million. Estimated costs for 2003 are $46.5 million.

20

FACILITIES AND OPERATIONS

TOTAL SYSTEM

SPPC maintains a wide variety of resources in its generation system.
The availability of alternate resources allows SPPC to dispatch its electric
generation system in a more cost-effective manner under varying operating and
fuel market conditions while maintaining system integrity. SPPC also supplies
its customers' electric power needs using a combination of firm and
interruptible resources to maximize operating flexibility and reliability while
minimizing cost. During 2002, SPPC generated 39.5% of its total electric energy
requirements in its own plants, purchasing the remaining 60.5% as shown below:

As a supplement to its own generation, SPPC purchases both firm and
non-firm energy to meet its customer demand requirements. Total energy supply
includes purchases from outside the electric system due to limited control area
generation and also the need to access market energy supplies. SPPC's decision
to purchase this energy is based on economics, mitigation of availability risk,
and system import limits. Firm block purchases are transacted as both a price
hedging strategy and to ensure that needed firm capacity is available over peak
load periods. Spot market energy is purchased based on the economics of
purchasing "as-available" energy when it is less expensive than SPPC's own
generation, again, subject to net system import limits. In 2002, most of SPPC's
non-utility generation came from QFs. See Energy Supply in Item 7, Management's
Discussion and Analysis of Financial Condition and Results of Operations, for
additional information.

RISK MANAGEMENT

See Item 7A, Quantitative and Qualitative Disclosures About Market
Risk.

21

LOAD AND RESOURCES FORECAST

SPPC's electric customer growth rate was 2.3% in 2002, 1.9% in 2001,
and 2.6% in 2000. Annual retail electricity sales were 8.7 million MWh in 2002
and 2001. Annual wholesale electricity sales reached 2.6 million MWh in 2002,
which represents a decrease of 36.8% from 2001 wholesale electricity sales of
4.1 million MWh. Overall, annual system electricity sales reached 11.3 million
MWh in 2002, which represents a decrease of 12.0% from 2001 system electricity
sales of 12.8 million MWh. The 2002 peak electric demand was 1,590 MW. The 2001
peak demand was 1,529 MW.

The projections shown below are forecasts of the load to be provided to
all of SPPC's current and forecasted customers. No adjustments have been made at
this time to incorporate possible changes to SPPC loads due to the passage of AB
661 by the 2001 Nevada Legislature which allows commercial and governmental
customers with an average demand greater than one MW to select other energy
supplies. See Regulation and Rate Proceedings, Nevada Matters, Customers File
Under AB 661 in Item 7, Management's Discussion and Analysis of Financial
Condition and Results of Operation. The forecast includes an assumption that
normal weather (based on 20-year averages) will occur. Other uncertainties to
the forecast include abnormal weather, failure of the local economy to recover,
and customer losses due to AB 661. SPPC continues to provide energy through
generation and purchased power to meet both summer and winter peak loads. SPPC's
total system capability and peak loads for 2002, and the forecast for summer
peak demand through 2004 (assuming no curtailment of supply or load and normal
weather conditions), are indicated below:

(1) Value is net of losses and includes committed short-term firm
block purchases. Values shown represent purchases within
existing transmission system limits. No economy (non-firm)
energy purchases occurred during the 2002 peak, only firm
power purchases.

(2) The system peak shown for 2002 occurred on July 10, 2002, at
5:00 p.m.

SPPC plans its system capacity needs in accordance with the WECC
reliability criteria, which recommends planning reserves in excess of required
operating reserves. The "Additional Required" represents the additional,
uncommitted capacity needed in order to maintain adequate reserve margin
consistent with the WECC planning reserve criteria. These additional reserves
will be met, if needed, with short-term purchases through 2004 to the extent
available.

22

GENERATION

The following is a list of SPPC's share of generation plants including
the MW summer net capacity, the type and fuel used to generate, and the year(s)
that the unit(s) was (were) installed.

(1) SPPC is the operator and owns an undivided 50% interest in the Valmy
plant. Idaho Power Company owns the remainder. SPPC owns 100% of all of
its remaining electric generation plants.

(2) Pinon is part of the Pinon Pine Integrated Coal Gasification Combined
Cycle power plant. This project was part of the Department of Energy's
Clean Coal Demonstration Program. Although the coal gasification
portion of the facility is inactive, the combined cycle units have been
operating on natural gas since 1996. See Note 21, Pinon Pine, to the
Notes to Financial Statements.

(3) The combined cycle at Pinon consists of one combustion turbine and one
steam turbine. Pinon is located at the Tracy Generating Station.

(4) The four hydroelectric generating units, with a total capacity of 8.7
MW, were to be included in the sale of SPPC's water business in June
2001. The California Legislature has passed a law exempting the hydro
plants from the prohibition against generation divestiture. On November
9, 2002, SPPC filed an application with the CPUC for authority to sell
the four hydroelectric plants. On January 13, 2003, the CPUC issued a
ruling that the California Environmental Quality Act applies and SPPC
must supplement the application with a certified environmental
document.

PURCHASED POWER

SPPC continues to manage a diverse portfolio of contracted and spot
market supplies, as well as its own generation, with the objective of minimizing
its net average system operating costs. During 2002, SPPC experienced favorable
market energy prices when compared with the previous four years. The decrease is
reflective of FERC price cap regulation, which decreased electricity costs
throughout the western United States.

During 2002, SPPC experienced difficulty purchasing power in western
energy markets due to counterparties' credit concerns with SPPC when its credit
rating dropped below investment grade. With only a handful of counterparties
willing to enter into agreements, SPPC found it necessary to 1) contract with
energy marketers to transact on SPPC's behalf, and 2) negotiate special payment
arrangements to satisfy credit concerns.

If SPPC continues to experience financial difficulty or if its credit
ratings are further downgraded, SPPC may experience considerable difficulty
entering into new power supply contracts, particularly under traditional payment
terms. If suppliers will not sell power to SPPC under traditional payment terms,
SPPC may have to pre-pay its power requirements. If it does not have sufficient
funds or access to liquidity to pre-pay its power requirements and is unable to
obtain power through other means, SPPC's business, operations and financial
condition would be materially adversely affected and could make it difficult for
SPPC to continue to provide reliable service to its customers or to operate
outside of bankruptcy.

23

SPPC is a member of the Northwest Power Pool and Western Systems Power
Pool. These pools have provided SPPC further access to reserves and spot market
power, respectively, in the Pacific Northwest and Southwest. In turn, SPPC's
generation facilities provide a backup source for other pool members who rely
heavily on hydroelectric systems.

SPPC purchases hydroelectric and thermal generation spot market energy,
by the hour, based upon economics and system import limits. Also purchased
during peak load periods is firm energy as required to supply load and maintain
adequate operating reserve margins. As off-system energy costs increase, SPPC
supplies a higher percentage of its native load utilizing its fossil fuel
generation.

Currently, SPPC has contracted for a total of 75 MW of long-term firm
purchased power from PacifiCorp. SPPC's firm purchase power contract is from
June 1989 to February 28, 2009 and contains a 70% minimum purchase obligation.

According to PURPA, SPPC is obligated under certain conditions to
purchase the output produced by small power producers and co-generation
facilities at costs determined by the appropriate state utility commission. As
of December 31, 2002, SPPC had a total of 109 MW of maximum contractual firm
capacity under 15 contracts with QFs. SPPC had contracts with three of the 15
projects at variable short-term avoided cost rates. All QF contracts currently
delivering power to SPPC at long-term rates have been approved by either the
PUCN or the CPUC, and have QF status as approved by the FERC. One long-term QF
contract terminates in 2006, one terminates in 2039, and the remaining terminate
between 2014 and 2022.

Energy purchased by SPPC from QF contracts continues to provide useful
diversity for SPPC in meeting its peak load. All the QFs from which SPPC makes
firm purchases are either geothermal, hydroelectric or biomass.

The actual QF firm capacity output under contract was 62 MW during the
summer of 2002. The actual QF output for all non-utility generator deliveries
during the summer 2002 peak was 263 MW.

NPC also executed five power purchase agreements related to the
purchase of renewable energy under the terms of which NPC sells the power
associated with the renewable energy contracts located in northern Nevada to
SPPC ("Related PPAs"). For these five non-solar PPAs involving suppliers in
SPPC's service

24

territory, NPC will receive "Product" (Product is a defined term in the PPA that
includes all Renewable Energy Credits "RECs" and energy supplied by the
developer) from the renewable supplier at a delivery point on SPPC's
transmission system and then NPC will immediately resell the energy to SPPC
under the terms and conditions of a "Related PPA" (defined term in the original
PPA). NPC will retain the RECs to comply with the requirements of SB 372,
Nevada's renewable portfolio law.

SPPC entered into a solar PPA with Duke Solar from the same facility
located in NPC's service territory. NPC executed an additional Related PPA for
this facility. For SPPC's solar PPA, SPPC will receive Product from the
renewable supplier at a delivery point on NPC's transmission system and then
SPPC will immediately resell the energy to NPC under the terms and conditions of
the Related PPA. SPPC will retain the RECs to comply with SB 372. NPC expects to
purchase 32 GWh of energy under the terms of the Related PPA.

The terms for both SPPC and NPC's solar PPAs are 20 years.

TRANSMISSION

SPPC's existing transmission lines extend some 300 miles from the crest
of the Sierra Nevada in eastern California, northeast to the Nevada-Idaho border
at Jackpot, Nevada, about 160 miles from Reno northwest to Alturas, California,
and 250 miles from the Reno area south to Tonopah, Nevada. A 230 kV transmission
line connects SPPC to facilities near the Utah-Nevada state line, which in turn
interconnects SPPC to Utah Power facilities. A 345 kV transmission line connects
SPPC to Idaho Power facilities at the Idaho-Nevada state line. A 345 kV line
connects SPPC to the Bonneville Power Administration's facilities near Alturas,
California.

SPPC also has two 120 kV lines and one 60 kV line that interconnect
with Pacific Gas & Electric on the west side of SPPC's system at Donner Summit,
California. Two 60 kV transmission ties allow wheeling of up to 14 MW of power
from the Beowawe Geothermal Project, which is located within SPPC's service
area, to Southern California Edison. These two minor interties are available for
use during emergency conditions affecting either party. The transmission
intertie system provides access to regional energy sources.

The Falcon to Gonder Project is a 180-mile 345 kV line connecting
SPPC's Falcon Substation to Mt. Wheeler Power's Gonder Substation. The Falcon to
Gonder Project improves system import and export capabilities and enables SPPC
to provide transmission service between Idaho, Utah, and the northwest. The
Final Environmental Impact Statement was released in December 2001. Federal
permitting was completed in July 2002. Construction started March 3, 2003 with
an expected in-service date of May 2004. Total project costs incurred through
December 31, 2002, were $32.8 million. Actual costs incurred in 2002 were $21.0
million. Estimated costs for 2003 are $46.5 million.

See Regulation and Rate Proceedings, FERC Matters in Item 7,
Management's Discussion and Analysis of Financial Condition and Results of
Operations for a discussion of regional transmission issues.

25

FUEL AVAILABILITY

SPPC's 2002 fuel requirements for electric generation were provided by
natural gas, coal, and oil. The average costs of coal, gas and oil for energy
generation per MMBtu for the years 1998-2002, along with the percentage
contribution to total fuel requirements, are as follows:

For a discussion of the change in fuel costs, see Results of Operations
in Item 7, Management's Discussion and Analysis of Financial Condition and
Results of Operations.

SPPC fully satisfied all volume requirements under a long-term contract
with Black Butte Coal Company for coal shipments to Valmy, which terminated in
February 2002.

SPPC's long-term coal contract with Canyon Fuel Company, LLC (Canyon),
which provides coal for Valmy from Canyon's SUFCO mine in Central Utah, expires
on June 30, 2003. The coal supply agreement for Valmy has been replaced with a
new contract from Arch Coal for deliveries through December 31, 2006. The
current owner of the SUFCO mine is Arch Coal, Inc., which acquired ARCO Coal
(the previous owner of the Canyon properties, including SUFCO) on June 1, 1998.

During 2002, two short-term agreements for the purchase of spot market
coal were in place. The source of this coal is the Uinta Basin of Utah. These
spot market purchases supplement base volume requirements under SPPC's long-term
coal contracts at a cost approximately one-half that of contract coal.

As of December 31, 2002, Valmy's coal inventory level was 257,740 tons,
or approximately 45 days of consumption at 100% capacity. Inventory levels were
increased to allow for economically priced supplies under contract to be
delivered prior to the expiration of those supply arrangements.

During 2002, transportation of coal to Valmy was provided by the Union
Pacific Railroad (UP) under a contract that will expire December 31, 2004.

During 2002, SPPC operated the Pinon Pine facility exclusively on
natural gas. No coal was purchased in 2002 for synthetic gas production in the
plant's coal gasification facility.

SPPC meets its needs for residual oil for generation through purchases
on the spot market. The actual residual oil inventory level was 325,334 barrels
as of December 31, 2002, which is equal to a 14-day supply at full load
operation.

NATURAL GAS BUSINESS

SPPC's natural gas business consists of operating the local
distribution company (LDC) for the Reno/Sparks metropolitan area and procuring
gas for electrical power generation at the Tracy and Ft. Churchill

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plants. The LDC accounted for $149.8 million in 2002 operating revenues or 13.9%
of SPPC's revenues from continuing operations. Growth in SPPC's LDC service
territory continues to be strong. Customer meter count growth during 2002 was
approximately 3.7%. SPPC's total customer gas meter count increased by 4,520 to
126,382 meters by the end of 2002.

Growth in all sectors is expected to continue due to the fact that new
real estate developments in SPPC's distribution service area are under
construction and planned for the near future. SPPC's forecast for growth in the
number of LDC customers in 2003 is 4,800 meters.

SPPC's natural gas LDC business is subject to competition from other
suppliers and other forms of energy available to its customers. Large customers
with fuel switching capability compare natural gas prices on an interruptible
basis to alternative energy source prices. Additionally, large customers have
the ability to secure their own gas supplies. As of March 13, 2003, there are 11
large customers securing their own supplies. These customers have a combined
firm distribution load of 3,665 Dth per day. Three additional customers have
announced intentions to begin securing their own supplies in mid 2003.
Transportation customers continue to pay firm and interruptible distribution
charges. These customers are responsible for procuring and paying for their own
supply.

To secure gas supplies for power generation and the LDC, SPPC
contracted for firm winter, summer, and annual gas supplies with over a dozen
Canadian and domestic suppliers to meet the firm requirements of its LDC and
electric operations. Annual contracts totaled approximately 65,000 Dth per day.
The winter period contracts totaled approximately 50,000 Dth per day, and the
summer period contracts totaled approximately 9,000 Dth per day.

SPPC's firm natural gas supply is supplemented with natural gas storage
services and supplies from a Northwest Pipeline Co. facility located at Jackson
Prairie in southern Washington and liquefied natural gas (LNG) storage from a
facility located near Lovelock, Nevada. The contract for LNG facility operated
by Paiute Pipeline Company terminated on February 28, 2003. The Jackson Prairie
facility contributed a total of 12,687 Dth per day of peaking supplies. A
peaking transaction to Southwest Gas terminated on the same date.

In November 1996 SPPC entered an agreement to sell winter seasonal
peaking capacity supplies to another company over a seven-year period. The
contract provides for the payment to SPPC of a monthly reservation charge,
reimbursement of pipeline capacity charges during the winter, and a volumetric
commodity charge based on the market price for natural gas. SPPC was able to
enter into this agreement due to the ability of its power plants to utilize
alternative fuels and its power importation option. The obligation to provide
peaking supply terminated on February 28, 2003 coincident with the termination
of the LNG contract and therefore no additional resources are required to meet
Sierra load obligations.

Following is a summary of SPPC's transportation and storage portfolio
(as of December 31, 2002). Firm transportation capacity on the Northwest/Paiute
system exists to serve primarily the LDC. Firm transportation capacity on the
Pacific Gas & Electric Gas Transmission Northwest (PGT)/Tuscarora system exists
primarily to serve SPPC's electric generating plants. Storage capacity is
generally used for the peaking requirements of the LDC.

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Transportation Capacity

Northwest: 68,696 decatherms per day firm (annual)
Paiute: 103,774 decatherms per day firm (November through March)
61,044 decatherms per day firm (April through October
NOVA: 124,777 decatherms per day firm
ANG: 128,105 decatherms per day firm
PGT: 69,099 decatherms per day firm (annual)
60,270 decatherms per day firm (November through April)
24,500 decatherms per day firm (KG to Stanfield)
Tuscarora: 127,601 decatherms per day firm (annual)

Storage Capacity

Williams: 281,242 decatherms inventory capability at Jackson Prairie
12,687 decatherms withdrawal capability per day from Jackson Prairie
Paiute: 463,034 decatherms Inventory capability from LNG
35,078 decatherms withdrawal capability per day from LNG

Total LDC Dth supply requirements in 2001 and 2002 were 14.26 million
Dth and 14.57 million Dth, respectively. Electric generating fuel requirements
for 2001 and 2002 were 28.9 million Dth and 23.7 million Dth, respectively.

In December 2002, the PUCN released its order regarding SPPC's Purchase
Gas Adjustment filing made on July 1, 2002 and the new rates became effective
January 1, 2003. An average residential customer received a decrease in their
rates of approximately 3%.

As of December 31, 2002, SPPC owned and operated 1,693 miles of
three-inch equivalent natural gas distribution piping, 91 miles of which were
added in 2002. Two significant projects were completed to improve distribution
system's capacity in two high growth areas in south Reno where 5,600 feet of 18
inch main was installed and in northern Sparks where 4,531 feet of 8 inch main
was installed.

SALE OF WATER BUSINESS

In June 2001, SPPC closed the sale of its water business to the TMWA
for $341 million. SPPC recorded a $25.8 million gain on the sale, net of income
taxes of $18.2 million. Pursuant to a stipulation entered into in connection
with the sale and approved by the PUCN, SPPC was required to refund to customers
$21.5 million of the proceeds from the sale. The refund was credited on the
electric bills of SPPC's former water customers over a fifteen-month period
ended November 2002.

Under a service contract with TMWA, SPPC provided customer service and
billing services to TMWA until August 2002. SPPC continues to provide
meter-reading services under a one-year service contract renewable in one-year
increments by TMWA through 2008. On September 24, 2002, California Assembly Bill
1235 was approved which amended previous California legislation that prevented
until 2006 private utilities from selling any power plants that provide energy
to California customers. Transfer of the four hydroelectric facilities included
in the contract of sale for an additional $8 million will require action by the
CPUC. On November 9, 2002, SPPC filed an application with the CPUC for authority
to sell the four hydroelectric plants. Not included in the sale were certain
properties along the Truckee River related to the hydroelectric facilities and
in California at Independence Lake. SPPC continues to own these properties with
the intent of possible future sale. For further discussion of this item, see
Generation Divestiture below.

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REGULATION AND RATE PROCEEDINGS

See Regulation and Rate Proceedings in Item 7, Management's Discussion
and Analysis of Financial Condition and Results of Operations.

GENERATION DIVESTITURE (NPC AND SPPC)

As a condition to its approval of the merger between SPR and NPC, the
PUCN required the Utilities to file a Divestiture Plan for the sale of their
electric generation assets. The PUCN approved a revised Divestiture Plan
stipulation in February 2000. In May 2000, an agreement was announced for the
sale of NPC's 14% undivided interest in the Mohave Generating Station
("Mohave"). In the fourth quarter of 2000, the Utilities announced agreements to
sell six additional bundles of generation assets described in the approved
Divestiture Plan. The sales were subject to approval and review by various
regulatory agencies.

AB 369, which was signed into law on April 18, 2001, prohibits until
July 2003 the sale of generation assets and directs the PUCN to vacate any of
its orders that had previously approved generation divestiture transactions. In
January 2001, California enacted a law that prohibits until 2006 any further
divestiture of generation properties by California utilities, including SPPC,
and could also affect any sale of NPC's interest in Mohave after July 2003 since
the majority owner of that project is Southern California Edison.

In addition, SPPC's request for an exemption from the requirements of a
separate California law requiring approval of the CPUC to divest its plants was
denied. In September 2002, the California Legislature approved an amendment, AB
1235, to AB 6 that would allow SPPC to complete the sale of the four
hydroelectric units to TMWA. Section 851 of the Public Utilities Code requires
review and approval of the sale by the CPUC. The sale of the Farad Hydroelectric
Unit is conditioned on the completion of the reconstruction of the Farad dam and
flume or assignment of SPPC insurance claim for reconstruction of the dam. The
Farad Reconstruction Project is currently in the permitting phase with permits
expected by mid-2003.

The sales agreements for the six bundles provided that they terminate
eighteen months after their execution unless the parties agreed to an earlier
termination. The parties could have extended the termination another six months
to obtain additional regulatory approvals. As a result of the legislative and
regulatory developments which rendered the contracts impossible to perform, the
Utilities engaged in discussions with the buyers of the generation assets
regarding the formal termination of the sales agreements and the related energy
buyback contracts and interconnection agreements. Those discussions ended
without agreement to mutually terminate; however, all the contracts have now
terminated in accordance with the contract provisions. As of December 31, 2002,
the Utilities had incurred costs of approximately $20.1 million at NPC and $12.2
million at SPPC in order to prepare for the sale of generation assets. The
Utilities requested recovery of these costs in each Utility's respective general
rate case filings with the PUCN. The PUCN delayed recovery of the divestiture
costs to a future rate case request but did grant a carrying charge on the costs
until such time as recovery is allowed. A further discussion of the Regulation
and Rate Proceedings is included in Item 7, Management's Discussion and Analysis
of Financial Condition and Results of Operation.

ENVIRONMENT (SPR, NPC AND SPPC)

As with other utilities, NPC and SPPC are subject to federal, state and
local regulations governing air, water quality, hazardous and solid waste, land
use and other environmental considerations. Nevada's Utility Environmental
Protection Act requires approval of the PUCN prior to construction of major
utility, generation or transmission facilities. The United States Environmental
Protection Agency (EPA), Nevada Division of Environmental Protection (NDEP), and
Clark County Health District (CCHD) administer regulations involving air
quality, water pollution, solid, and hazardous and toxic waste. SPR's Board of
Directors has a

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comprehensive environmental policy and a separate board committee that oversees
NPC's, SPPC's, and SPR's corporate performance and achievements related to the
environment.

NEVADA POWER COMPANY

The Grand Canyon Trust and Sierra Club filed a lawsuit in the U.S.
District Court, District of Nevada in February 1998 against the owners
(including NPC) of the Mohave Generation Station ("Mohave"), alleging violations
of the Clean Air Act regarding emissions of sulfur dioxide and particulates. An
additional plaintiff, National Parks and Conservation Association, later joined
the suit. The plant owners and plaintiffs have had numerous settlement
discussions and filed a proposed settlement with the court in October 1999. The
consent decree, approved by the court in November 1999, established emission
limits for sulfur dioxide and opacity and required installation of air pollution
controls for sulfur dioxide, nitrogen oxides and particulate matter. The new
emission limits must be met by January 1, 2006 and April 1, 2006 for the first
and second units respectively. The estimated cost of new controls is
$1.1 billion. As a 14% owner in Mohave, NPC's cost could be $154 million.

NPC's ownership interest in Mohave comprises approximately 10% of NPC's
peak generation capacity. Southern California Edison (SCE) is the operating
partner of Mohave. On May 17, 2002, SCE filed with the CPUC an application to
address the future disposition of SCE's share of Mohave. Mohave obtains all of
its coal supply from a mine in northeast Arizona on lands of the Navajo Nation
and the Hopi Tribe (the Tribes). This coal is delivered from the mine to Mohave
by means of a coal slurry pipeline which requires water that is obtained from
groundwater wells located on lands of the Tribes in the mine vicinity.

Due to the lack of progress in negotiations with the Tribes and other
parties to resolve several coal and water supply issues, SCE's application
states that it appears that it probably will not be possible for SCE to extend
Mohave's operations beyond 2005. Due to the uncertainty over a post-2005 coal
supply, SCE and the other Mohave co-owners have been prevented from commencing
the installation of extensive pollution control equipment that must be put in
place if Mohave's operations are extended past 2005.

NPC is currently evaluating and analyzing all of its options with
regard to the Mohave project.

In May 1997, the Nevada Division of Environmental Protection (NDEP)
ordered NPC to submit a plan to eliminate the discharge of Reid Gardner Station
wastewater to groundwater. The NDEP order also required a hydrological
assessment of groundwater impacts in the area. In June 1999, NDEP determined
that wastewater ponds had degraded groundwater quality. In August 1999, NDEP
issued a discharge permit to Reid Gardner Station and an order that requires all
wastewater ponds to be closed or lined with impermeable liners over the next 10
years. This order also required NPC to submit a Site Characterization Plan to
NDEP to ascertain impacts. This plan has been approved by NDEP. NDEP is expected
to identify remediation requirements of contaminated groundwater resulting from
these evaporation ponds by July 2003. New pond construction and lining costs are
estimated at $15 million.

At the Reid Gardner Station, the NDEP has determined that there is
additional groundwater contamination that resulted from oil spills at the
facility. NDEP has required NPC to submit a corrective action plan. The extent
of contamination has been determined and remediation is occurring at a modest
rate. A hydro-geologic evaluation of the current remediation was completed, and
a dual phase extraction remediation system, which has been approved by NDEP,
will be constructed beginning in April 2003 at an estimated cost of $150,000.

In May 1999, NDEP issued an order to eliminate the discharge of NPC's
Clark Station wastewater to groundwater. The order also required a hydrological
assessment of groundwater impacts in the area. This assessment, submitted to
NDEP in February 2001, warranted a Corrective Action Plan, which was approved in

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June 2002. Remediation costs are expected to be approximately $100,000. In
addition to remediation, NPC will spend $789,000 to line existing ponds. This
project was started in 2002 and is expected to be completed in the first quarter
2003.

In July 2000, NPC received a request from the EPA for information to
determine the compliance of certain generation facilities at the Clark Station
with the applicable State Implementation Plan. In November 2000 NPC and the
Clark County Health District entered into a Corrective Action Order requiring,
among other steps, capital expenditures at the Clark Station totaling
approximately $3 million. In March 2001, the EPA issued an additional request
for information that could result in remediation beyond that specified in the
November 2000 Corrective Action Order. If the EPA prevails, capital expenditures
and temporary outages of four of Clark Station's generation units could be
required. Additionally, depending on the time of year that the compliance
activity and corresponding generation outage would occur, the incremental cost
to purchase replacement energy could be substantial. To date, EPA has not issued
additional requests for further information.

NEICO, a wholly owned subsidiary of NPC, owns property in Wellington,
Utah, which was the site of a coal washing and load out facility. The site now
has a reclamation estimate supported by a bond of $4.8 million with the Utah
Division of Oil and Gas Mining. The property was under contract for sale and the
contract required the purchaser to provide $1.3 million in escrow towards
reclamation. However, the sales contract was terminated and NEICO took title to
the escrow funds. The property is currently leased with the intention to reclaim
coal fines with subsequent revenues and reduction to the reclamation bond.

SIERRA PACIFIC POWER COMPANY

In September 1994 Region VII of the EPA notified SPPC that it was being
named as a potentially responsible party (PRP) regarding the past improper
handling of Polychlorinated Biphenyls (PCB's) by PCB Treatment, Inc., in two
buildings, one located in Kansas City, Kansas and the other in Kansas City,
Missouri (the Sites). Prior to 1994, SPPC sent PCB contaminated material to PCB
Treatment, Inc. for disposal. Certificates of disposal were issued to SPPC by
PCB Treatment, Inc. however; the contaminated material was not disposed of, but
remained on-site. A number of the largest PRP's formed a steering committee,
which is chaired by SPPC. The steering committee has completed its site
investigations and the EPA has determined that the Sites should be remediated by
removing the buildings to the appropriate landfills. The EPA has issued an
administrative order on consent requiring the steering committee to oversee the<