NEVADA POWER CO - 10-Q Quarterly Report

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-Q
(MARK ONE)

[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2003

OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM TO

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 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]

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

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 stated value, of Sierra Pacific Power Company.

This combined Quarterly Report on Form 10-Q 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
QUARTERLY REPORTS ON FORM 10-Q
FOR THE QUARTER ENDED JUNE 30, 2003

CONTENTS

2

SIERRA PACIFIC RESOURCES

CONDENSED CONSOLIDATED BALANCE SHEETS

The accompanying notes are an integral part of the financial statements.
3

SIERRA PACIFIC RESOURCES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(DOLLARS IN THOUSANDS, EXCEPT SHARE AND PER SHARE AMOUNTS)
(UNAUDITED)

The accompanying notes are an integral part of the financial statements.
4

SIERRA PACIFIC RESOURCES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(DOLLARS IN THOUSANDS)
(UNAUDITED)

The accompanying notes are an integral part of the financial statements
5

NEVADA POWER COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS
(DOLLARS IN THOUSANDS)

The accompanying notes are an integral part of the financial statements.
7

NEVADA POWER COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(DOLLARS IN THOUSANDS)
(UNAUDITED)

The accompanying notes are an integral part of the financial statements.
8

NEVADA POWER COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(DOLLARS IN THOUSANDS)
(UNAUDITED)

The accompanying notes are an integral part of the financial statements
9

SIERRA PACIFIC POWER COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS
(DOLLARS IN THOUSANDS)

The accompanying notes are an integral part of the financial statements.

10

SIERRA PACIFIC POWER COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(DOLLARS IN THOUSANDS)
(UNAUDITED)

The accompanying notes are an integral part of the financial statements.
11

SIERRA PACIFIC POWER COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(DOLLARS IN THOUSANDS)
(UNAUDITED)

The accompanying notes are an integral part of the financial statements
12

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. MANAGEMENT'S STATEMENT (SPR, NPC, SPPC)

In the opinion of the management of Sierra Pacific Resources (SPR), Nevada
Power Company (NPC), and Sierra Pacific Power Company (SPPC), the accompanying
unaudited interim condensed consolidated financial statements contain all
adjustments (consisting of only normal recurring adjustments) necessary to
present fairly the condensed consolidated financial position, results of
operations and cash flows for the periods shown. These condensed consolidated
financial statements do not contain the complete detail or footnote disclosure
concerning accounting policies and other matters which are included in full year
financial statements; therefore, they should be read in conjunction with the
audited financial statements included in SPR's, NPC's, and SPPC's Annual Reports
on Form 10-K for the year ended December 31, 2002.

The results of operations and cash flows of SPR, NPC and SPPC for the
three-month and six-month periods ended June 30, 2003, are not necessarily
indicative of the results to be expected for the full year.

PRINCIPLES OF CONSOLIDATION

The condensed consolidated financial statements of SPR include the accounts
of SPR and its wholly-owned subsidiaries, NPC and SPPC (collectively, the
"Utilities"), Tuscarora Gas Pipeline Company (TGPC), Sierra Gas Holding Company
(SGHC), Sierra Pacific Energy Company (SPE), Lands of Sierra (LOS), Sierra
Pacific Communications (SPC), and Sierra Water Development Company (SWDC).
Sierra Energy Company dba e-three (e-three) is a discontinued operation and as
such is no longer a consolidated subsidiary of SPR and is reported separately on
the financial statements of SPR. The condensed consolidated financial statements
of NPC include the accounts of NPC and its wholly-owned subsidiaries, NEICO, NVP
Capital I (Trust) and NVP Capital III (Trust). The condensed consolidated
financial statements of SPPC include the accounts of SPPC and its wholly-owned
subsidiaries, GPSF-B, Pinon Pine Corp. (PPC), Pinon Pine Investment Co., Pinon
Pine Company, L.L.C. and Sierra Pacific Funding L.L.C. All significant
intercompany transactions and balances have been eliminated in consolidation.

SIERRA PACIFIC RESOURCES

SPR, on a stand-alone basis, had cash and cash equivalents of approximately
$19.1 million at June 30, 2003. At July 31, 2003, SPR had cash balances of
approximately $19.5 million.

Currently, SPR has a substantial amount of outstanding debt and other
obligations including, but not limited to: $300 million of its unsecured 8 3/4%
Senior Notes due 2005; $240 million of its unsecured 7.93% Senior Notes due
2007; and $300 million of its 7.25% Convertible Notes due 2010.

SPR's future liquidity and its ability to pay the principal of and interest
on its indebtedness depend on SPPC's ability to continue to pay dividends to
SPR, on NPC's financial stability and a restoration of its ability to pay
dividends to SPR, and on SPR's ability to access the capital markets or
otherwise refinance maturing and/or convertible debt. Further adverse
developments at NPC or SPPC, including a material disallowance of deferred
energy costs in future rate cases or an adverse decision in the pending lawsuit
by Enron, could make it difficult to continue to operate outside of bankruptcy.
See Note 5, Dividend Restrictions, for information regarding the dividend
restrictions applicable to NPC and SPPC, and Note 11, Commitments and
Contingencies, for additional information regarding uncertainties that could
impact SPR's liquidity and financial condition.

The provisions that currently restrict dividends payable by NPC or SPPC
have adversely affected SPR's liquidity and will continue to negatively impact
SPR's liquidity until those provisions are no longer in effect. Management is
currently in the process of seeking consent for a modification of the financial
covenant contained in NPC's first mortgage indenture. There can be no assurance
that any such consent can be obtained or that any non-consenting first mortgage
bonds could be redeemed or defeased prior to

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

their stated maturity. The regulatory limitation contained in the Public Utility
Commission of Nevada's (PUCN) Compliance Order, Docket No. 02-4037, dated June
19, 2002, expires on December 31, 2003. Prior to the expiration date of the
Compliance Order, management may seek PUCN approval for a payment of dividends
by NPC or may seek a waiver from the PUCN of the dividend restriction.

Financing Transactions. On February 14, 2003, SPR issued and sold $300
million of its 7.25% Convertible Notes due 2010. Approximately $53.4 million of
the net proceeds from the sale of the notes was used to purchase U.S. government
securities that were pledged to the trustee for the first five interest payments
on the notes payable during the first two and one-half years. A portion of the
remaining net proceeds of the notes was used to repurchase approximately $58.5
million of SPR's Floating Rate Notes due April 20, 2003. Of the remaining net
proceeds, approximately $133 million was used to repay the remainder of SPR's
Floating Rate Notes due April 20, 2003, and the remaining proceeds are available
for general corporate purposes, including the payment of interest on SPR's other
outstanding indebtedness.

The Convertible Notes are not convertible prior to August 14, 2003. At any
time on or after August 14, 2003 through the close of business February 14,
2010, holders of the Convertible Notes may convert their notes into shares of
SPR's common stock and cash. Until SPR has obtained shareholder approval to
permit the Convertible Notes to be fully convertible into shares of common
stock, holders of the Convertible Notes will be entitled to receive 76.7073
shares of common stock and an amount of cash equal to the market value of
142.4564 shares of SPR's common stock at the time of conversion, based on the
average closing price of SPR's common stock over five consecutive trading days,
for each $1,000 principal amount of notes surrendered for conversion. At an
assumed five-day average closing price of $5.00 per share (based on the last
reported sale price of SPR's common stock on August 1, 2003), the total amount
of the cash payable on conversion of the Convertible Notes would be
approximately $214 million. If SPR does not obtain shareholder approval, SPR
will be required to pay the cash portion of any Convertible Notes as to which
the holders request conversion on or after August 14, 2003. The amount of cash
payable on conversion of the Convertible Notes will increase as the average
closing price of SPR's common stock increases. Although management does not
believe it is likely that a significant amount of the Convertible Notes will be
converted in the foreseeable future, in the event that SPR does not have
available funds to pay the cash portion of the Convertible Notes upon the
requested conversion, SPR may have to issue additional debt or equity to raise
the necessary funds. There can be no assurance that SPR will be able to access
the capital markets to issue such additional debt and/or equity or that it will
be able to do so on terms favorable to SPR.

If SPR does obtain shareholder approval, it may elect to satisfy the cash
payment component of the conversion price of the Convertible Notes solely with
shares of common stock. SPR has agreed to use reasonable efforts to obtain
shareholder approval, not later than 180 days after the date of issuance of the
Convertible Notes, for approval to issue and deliver shares of SPR's common
stock in lieu of the cash payment component of the conversion price of the
Convertible Notes. SPR has called a special shareholder meeting for August 11,
2003 to comply with the terms of the Convertible Notes. For further information
regarding the terms of the Convertible Notes, see Note 4, Long-Term Debt.

Effect of Holding Company Structure. Due to its holding company structure,
SPR's right as a common shareholder to receive assets of any of its direct or
indirect subsidiaries upon a subsidiary's liquidation or reorganization is
junior to the claims against the assets of such subsidiary by its creditors.
Therefore, SPR's debt obligations are effectively subordinated to all existing
and future claims of its subsidiaries' creditors, particularly those of NPC and
SPPC, including trade creditors, debt holders, secured creditors, taxing
authorities, guarantee holders and NPC's and SPPC's preferred security holders.
As of June 30, 2003, NPC, SPPC and their subsidiaries had approximately $2.89
billion of debt and other obligations outstanding and approximately $238.9
million of outstanding preferred securities. Although the Utilities are parties
to agreements that limit the amount of additional indebtedness they may incur,
the Utilities retain the ability to incur substantial additional indebtedness
and other liabilities.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The accompanying financial statements do not include any adjustments that
might result from the outcome of the uncertainties discussed above.

NEVADA POWER COMPANY

NPC had cash and cash equivalents of approximately $21.1 million at June
30, 2003. At July 31, 2003, NPC had cash balances of approximately $35.7
million.

In addition to anticipated capital requirements for construction, NPC has
approximately $355 million of debt maturing through the end of 2003. NPC expects
to finance these requirements with internally generated funds, including the
recovery of deferred energy costs, and the issuance of debt.

NPC's liquidity would be significantly affected by an adverse decision in
the lawsuit by Enron, or by unfavorable rulings by the PUCN in future NPC or
SPPC rate cases. Standard and Poor's Rating Group, Inc. (S&P) and Moody's
Investors Service, Inc. (Moody's) have NPC's credit ratings on "negative
outlook" and "stable", respectively. Future downgrades by either S&P or Moody's
could preclude or reduce NPC's access to the capital markets. Furthermore, 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. Most of
NPC's suppliers will not sell power to NPC under traditional payment terms and
are requiring NPC to pre-pay its power requirements or to make more frequent
payments on its power purchases. If NPC does not have sufficient funds or access
to liquidity to pre-pay its power requirements or to make more frequent payments
on its power purchases, and is unable to obtain power through other means, NPC's
results of operations, financial position, and cash flows will be adversely
affected. Adverse developments with respect to any one or a combination of the
foregoing could make it difficult to continue to operate outside of bankruptcy.

NPC's General and Refunding Mortgage Indenture creates a lien on
substantially all of NPC's properties in Nevada that is junior to the lien of
the first mortgage indenture. As of June 30, 2003, $930 million of NPC's General
and Refunding Mortgage securities were outstanding. Additional securities may be
issued under the General and Refunding Mortgage Indenture on the basis of (i)
70% of net utility property additions, (ii) the principal amount of retired
General and Refunding Mortgage Bonds, and/or (iii) the principal amount of first
mortgage bonds retired after October 19, 2001. On the basis of (i), (ii) and
(iii) above, as of June 30, 2003, NPC had the capacity to issue approximately
$1.017 billion of additional General and Refunding Mortgage securities. Although
NPC has substantial capacity to issue additional General and Refunding Mortgage
securities on the basis of property additions and retired General and Refunding
Mortgage securities and first mortgage bonds, the financial covenants contained
in NPC's Series E Notes, Receivables Purchase Facility Agreements and NPC's $60
million Credit Agreement limit the amount of additional indebtedness that NPC
may issue and the reasons for which such indebtedness may be issued. NPC has
reserved $125 million of General and Refunding Mortgage bonds for issuance upon
the initial funding of NPC's receivables facility. See Note 3, Short-Term
Borrowings, for information regarding NPC's accounts receivable facility. NPC
intends to use its accounts receivable purchase facility as a back-up liquidity
facility and does not plan to activate this facility in the foreseeable future.
NPC may activate the facility within five days upon the delivery of certain
customary funding documentation and the delivery of the $125 million General and
Refunding Mortgage Bond.

The accompanying financial statements do not include any adjustments that
might result from the outcome of the uncertainties discussed above.

SIERRA PACIFIC POWER COMPANY

SPPC had cash and cash equivalents of approximately $86.5 million at June
30, 2003. At July 31, 2003, SPPC had cash balances of approximately $75.6
million.

15

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

In addition to anticipated capital requirements for construction, SPPC has
approximately $21 million of debt maturing through the end of 2003. SPPC expects
to finance these requirements with internally generated funds, including the
recovery of deferred energy costs.

SPPC's future liquidity could be significantly affected by unfavorable
rulings by the PUCN in future SPPC or NPC rate cases. S&P and Moody's have
SPPC's credit ratings on "negative outlook" and "stable", respectively. Future
downgrades by either S&P or Moody's could preclude or reduce SPPC's access to
the capital markets. Furthermore, 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. Most of SPPC's suppliers will not sell power to
SPPC under traditional payment terms and are requiring SPPC to pre-pay its power
requirements or to make more frequent payments on its power purchases. If SPPC
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 results
of operations, financial position and cash flows will be adversely affected.
Adverse developments with respect to any one or a combination of the factors and
contingencies set forth above could make it difficult to continue to operate
outside of bankruptcy.

SPPC's General and Refunding Mortgage Indenture creates a lien on
substantially all of SPPC's properties in Nevada that is junior to the lien of
the first mortgage indenture. As of June 30, 2003, approximately $499.5 million
of SPPC's General and Refunding Mortgage bonds were outstanding. On May 1, 2003,
SPPC issued its $80 million General and Refunding Mortgage Note, Series D, due
2004, to secure SPPC's payment obligations with respect to $80 million of Washoe
County, Nevada, Water Facilities Refunding Revenue Bonds (Sierra Pacific Power
Company Project), Series 2001, which were issued for SPPC's benefit. Additional
securities may be issued under the General and Refunding Mortgage Indenture on
the basis of (i) 70% of net utility property additions, (ii) the principal
amount of retired General and Refunding Mortgage bonds, and/or (iii) the
principal amount of first mortgage bonds retired after April 8, 2002. On the
basis of (i), (ii) and (iii) above, as of June 30, 2003, SPPC had the capacity
to issue approximately $364.9 million of additional General and Refunding
Mortgage securities. Although SPPC has substantial capacity to issue additional
General and Refunding Mortgage securities on the basis of property additions and
retired General and Refunding Mortgage securities and first mortgage bonds, the
financial covenants contained in SPPC's Term Loan Agreement and Receivables
Purchase Facility Agreements limit the amount of additional indebtedness that
SPPC may issue and the reasons for which such indebtedness may be issued. SPPC
has reserved $75 million of General and Refunding Mortgage Bonds for issuance
upon the initial funding of its receivables purchase facility. SPPC intends to
use its accounts receivable purchase facility as a back-up liquidity facility
and does not plan to activate this facility in the foreseeable future. SPPC may
activate the facility within five days upon the delivery of certain customary
funding documentation and the delivery of the $75 million General and Refunding
Mortgage Bond. See Note 3, Short-Term Borrowings, for information regarding
SPPC's accounts receivable facility.

The accompanying financial statements do not include any adjustments that
might result from the outcome of the uncertainties discussed above.

RECLASSIFICATIONS

Certain items previously reported have been reclassified to conform to the
current year's presentation. Net income and shareholders' equity were not
affected by these reclassifications.

NEVADA POWER COMPANY FINANCIAL STATEMENTS

The presentation of NPC's condensed consolidated statement of operations
for the three months and six months ended June 30, 2002, and NPC's condensed
consolidated statement of cash flows for the six months ended June 30, 2002 have
been revised. Specifically, the effects of the revisions were to eliminate

16

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

the line item "Equity in losses of Sierra Pacific Resources" of $(47,571) and
$(52,069) on NPC's Condensed Consolidated Statement of Operations for the three
and six months ended June 30, 2002, respectively, and to eliminate the line item
"Equity in losses of SPR" of $(52,069) on NPC's Condensed Consolidated Statement
of Cash Flows. For additional information regarding this change in presentation,
see Note 1, Summary of Significant Accounting Policies of Notes to Financial
Statements in SPR's, NPC's and SPPC's Annual Reports on Form 10-K for the year
ended December 31, 2002.

DEFERRAL OF ENERGY COSTS

NPC and SPPC implemented deferred energy accounting procedures on March 1,
2001. See Note 1, Summary of Significant Accounting Policies, of Notes to
Financial Statements in SPR's, NPC's, and SPPC's Annual Reports on Form 10-K for
the year ended December 31, 2002, for additional information regarding the
implementation of deferred energy accounting by the Utilities.

The following deferred energy costs were included in the condensed
consolidated balance sheets as of June 30, 2003 (dollars in thousands):

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(1) Credits represent over-collections, that is, the extent to which gas or fuel
and purchased power costs recovered through rates exceed actual gas or fuel
and purchased power costs.

(2) Balances adjusted from amounts presented as of December 31, 2002, reflect,
primarily, a reclassification between amounts for terminated suppliers and
balances pending PUCN approval.

(3) Amounts related to terminated suppliers are discussed in Note 17,
Commitments and Contingencies, of Notes to Financial Statements in SPR's,
NPC's, and SPPC's Annual Reports on Form 10-K for the year ended December
31, 2002.

STOCK COMPENSATION PLANS

In December 2002, the Financial Accounting Standards Board (FASB) released
Statement of Financial Accounting Standards (SFAS) No. 148, "Accounting for
Stock-Based Compensation -- Transition and Disclosure," as an amendment to SFAS
No. 123, "Accounting for Stock-Based Compensation." SPR has previously adopted
the disclosure-only provisions of SFAS No. 123, and as of December 31, 2002 has
adopted the updated disclosure requirements set forth in SFAS No. 148. At June
30, 2003, SPR had several stock-based compensation plans which are described
more fully in Note 15 "Stock Compensation Plans," of Notes to Financial
Statements in SPR's, NPC's, and SPPC's Annual Reports on Form 10-K for the year
ended December 31, 2002. SPR applies Accounting Principles Board Opinion No. 25,
"Accounting for Stock Issued to Employees," in accounting for its stock option
plans. Accordingly, no compensation cost has been recognized for nonqualified
stock options and the employee stock purchase plan. Had compensation cost for
SPR's nonqualified stock options and the employee stock purchase plan been
determined based on the fair value at the grant dates for awards under those
plans, consistent with the provisions of SFAS No. 123, SPR's loss applicable to
common stock

17

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

would have been increased to the pro forma amounts indicated below (dollars in
thousands, except loss per share):

RECENT PRONOUNCEMENTS

In November 2002, the FASB issued Interpretation No. 45, "Guarantor's
Accounting and Disclosure Requirements for Guarantees" (FIN 45), which
elaborates on the disclosures to be made in interim and annual financial
statements of a guarantor about its obligations under certain guarantees that it
has issued. It also clarifies that a guarantor is required to recognize, at the
inception of a guarantee, a liability for the fair value of the obligation
undertaken in issuing a guarantee. Initial recognition and measurement
provisions of FIN 45 are applicable on a prospective basis to guarantees issued
or modified after December 31, 2002. The disclosure requirements are effective
for financial statements of interim or annual periods ending after December 15,
2002. As of June 30, 2003, all guarantees of SPR and its subsidiaries were
intercompany, whereby the parent issued the guarantees on behalf of its
consolidated subsidiaries to a third party. Therefore, there was no impact on
the financial position, results of operation or cash flows of SPR, NPC or SPPC.

In January 2003, the FASB issued Interpretation No. 46, "Consolidation of
Variable Interest Entities" (FIN 46), which elaborates on Accounting Research
Bulletin No. 51, "Consolidated Financial Statements." Among other requirements,
FIN 46 provides that a variable interest entity be consolidated by the
enterprise that is the primary beneficiary of the variable interest entity. FIN
46 applies immediately to variable interest entities created after January 31,
2003, and to variable interest entities in which an enterprise obtains an
interest after that date. It applies in the first fiscal year or interim period
beginning after June 15, 2003, to variable interest entities in which an
enterprise holds a variable interest that it acquired before February 1, 2003.
Management is currently reviewing the effect of adopting this statement on the
financial position, results of operation or cash flows of SPR, NPC or SPPC.

On April 30, 2003, the FASB issued SFAS No. 149, which amends accounting
for derivative instruments, including certain derivative instruments embedded in
other contracts, and hedging activities under SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities." The Statement clarifies the
circumstances under which a contract with an initial net investment meets the
characteristics of a derivative as discussed in SFAS 133. In addition, SFAS 149
clarifies when a derivative contains a financing component that warrants special
reporting in the statement of cash flows. SFAS 149 is effective for contracts
entered into or modified after June 30, 2003 and for hedging relationships
designated after

18

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

June 30, 2003. Management is currently reviewing the effect of adopting this
statement on the financial position and results of operations of SPR, NPC and
SPPC.

On May 15, 2003, the FASB issued SFAS No. 150, "Accounting for Certain
Financial Instruments with Characteristics of Liabilities and Equity," which
requires that certain financial instruments with characteristics of both
liabilities and equities be classified as liabilities by their issuers. The
provisions of SFAS No. 150, which also include a number of new disclosure
requirements, are effective for (1) instruments entered into or modified after
May 31, 2003 and (2) pre-existing instruments as of the beginning of the first
interim period that commences after June 15, 2003. As a result, management
expects that NPC's obligated mandatorily redeemable preferred trust securities
will be classified as a liability once SFAS 150 goes into effect, which will be
the quarter ending September 30, 2003. Additionally, management will continue to
review the effect of adopting this statement on the financial position and
results of operations of SPR, NPC and SPPC.

NOTE 2. ASSET RETIREMENT OBLIGATIONS (AROS)

Effective January 1, 2003, the Utilities adopted the provisions of SFAS No.
143, "Accounting for Asset Retirement Obligations." SFAS No. 143 generally
applies to legal obligations associated with the retirement of long-lived assets
that result from the acquisition, construction, development and/or the normal
operation of a long-lived asset. SFAS No. 143 requires NPC to recognize an
estimated liability for the retirement of generation plant assets specified in
land leases for NPC's jointly-owned Navajo generating station because, at the
expiration of the leases, the leases require the lessees to remove the
facilities upon request of the Navajo Nation. However, the retirement obligation
and corresponding charges recognized were immaterial to the financial statements
of NPC. NPC also redesignated amounts from Accumulated Depreciation to a
regulatory liability in order to reflect the estimated costs of removal
collected through rates. NPC amortizes the amount added to Electric Plant In
Service and recognizes accretion expense in connection with the discounted
liability over the estimated remaining life of the Navajo generating station
assets. SPPC has no significant asset retirement obligations.

NPC and SPPC also collect removal costs in regulated rates for certain
assets that do not have associated legal asset retirement obligations. As of
June 30, 2003, NPC and SPPC estimate that they had approximately $133 million
and $151 million related to such removal costs recorded in Accumulated
Depreciation, respectively.

NOTE 3. SHORT-TERM BORROWINGS

NEVADA POWER COMPANY

On June 30, 2003, NPC entered into a Credit Agreement, which provides for a
$60 million revolving credit facility to provide additional liquidity to NPC for
its summer 2003 power purchases. As of July 31, 2003, NPC had borrowed $20
million under this credit facility.

NPC's Credit Agreement prohibits payments to SPR in respect of NPC's common
stock and provides that NPC's ratio of consolidated total debt to consolidated
total capitalization may not exceed .65 to 1.00. The Credit Facility, which is
secured by NPC's $60 million Series F General and Refunding Mortgage Bond, will
expire no later than September 8, 2003.

On October 29, 2002, NPC established an accounts receivable purchase
facility of up to $125 million. The accounts receivable purchase facility
expires October 28, 2003. Currently, NPC intends to negotiate an extension of
this facility. If NPC elects to activate the receivables purchase facility, NPC
will sell all of its accounts receivable generated from the sale of electricity
to customers to its newly created bankruptcy remote special purchase subsidiary.
The receivables sales will be without recourse except for breaches of customary
representations and warranties made at the time of sale. The subsidiary will, in
turn, sell these receivables to a bankruptcy remote subsidiary of SPR. SPR's
subsidiary will issue variable rate revolving

19

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

notes backed by the purchased receivables. The agreements relating to the
receivables purchase facility contain various conditions to purchase, covenants
and trigger events, termination events and other provisions customary in
receivables transactions. In connection with NPC's receivables facility, SPR has
agreed to guaranty NPC's performance of certain obligations as a seller and
servicer under the facility.

NPC has agreed to issue $125 million principal amount of its General and
Refunding Mortgage Bonds upon activation of the accounts receivables purchase
facility. The full principal amount of the Bond would secure certain of NPC's
obligations as seller and servicer, plus certain interest, fees and expenses
thereon to the extent not paid when due, regardless of the actual amounts owing
with respect to the secured obligations. As a result, in the event of an NPC
bankruptcy or liquidation, the holder of the Bond securing the receivables
facility may recover more on a pro rata basis than the holders of other General
and Refunding Mortgage securities, who could recover less on a pro rata basis
than they otherwise would recover. However, in no event will the holder of the
Bond recover more than the amount of obligations secured by the Bond.

NPC intends to use the accounts receivables purchase facility as a back-up
liquidity facility and does not plan to activate this facility in the
foreseeable future. NPC may activate the facility within five days upon the
delivery of certain customary funding documentation and the delivery of the $125
million General and Refunding Mortgage Bond. As of June 30, 2003, this facility
had not been activated.

SIERRA PACIFIC POWER COMPANY

On October 29, 2002, SPPC established an accounts receivable purchase
facility of up to $75 million. The accounts receivable purchase facility expires
October 28, 2003. Currently, SPPC intends to negotiate an extension of this
facility. If SPPC elects to activate the receivables purchase facility, SPPC
will sell all of its accounts receivable generated from the sale of electricity
and gas to customers to its newly created bankruptcy-remote special purpose
subsidiary. The receivables sales will be without recourse except for breaches
of customary representations and warranties made at the time of sale. The
subsidiary will, in turn, sell these receivables to a bankruptcy-remote
subsidiary of SPR. SPR's subsidiary will issue variable rate revolving notes
backed by the purchased receivables. The agreements relating to the receivables
purchase facility contain various conditions to purchase, covenants and trigger
events, termination events and other provisions customary in receivables
transactions. In connection with SPPC's receivables facility, SPR has agreed to
guaranty SPPC's performance of certain obligations as a seller and servicer
under the facility.

SPPC has agreed to issue $75 million principal amount of its General and
Refunding Mortgage Bonds upon activation of the accounts receivables purchase
facility. The full principal amount of the Bond would secure certain of SPPC's
obligations as seller and servicer, plus certain interest, fees and expenses
thereon to the extent not paid when due, regardless of the actual amounts owing
with respect to the secured obligations. As a result, in the event of an SPPC
bankruptcy or liquidation, the holder of the Bond securing the receivables
facility may recover more on a pro rata basis than the holders of other General
and Refunding Mortgage securities, who could recover less on a pro rata basis
than they otherwise would recover. However, in no event will the holder of the
Bond recover more than the amount of obligations secured by the Bond.

SPPC intends to use the accounts receivables purchase facility as a back-up
liquidity facility and does not plan to activate this facility in the
foreseeable future. SPPC may activate the facility within five days upon the
delivery of certain customary funding documentation and the delivery of the $75
million General and Refunding Mortgage Bond. As of June 30, 2003, this facility
had not been activated.

20

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

NOTE 4. LONG-TERM DEBT

Substantially all utility plant owned by NPC and SPPC is subject to the
liens of their respective indentures under which their First Mortgage bonds and
General and Refunding Mortgage bonds are issued.

SIERRA PACIFIC RESOURCES

In January 2003, SPR acquired $8.75 million aggregate principal amount of
its Floating Rate Notes due April 20, 2003 in exchange for approximately 1.3
million shares of its common stock, in two privately-negotiated transactions
exempt from the registration requirements of the Securities Act of 1933.

On February 5, 2003, SPR acquired 2.1 million of Premium Income Equity
Securities (PIES) including approximately $104.8 million of 7.93% Senior Notes
due 2007 that are a component of the PIES, in exchange for approximately 13.66
million shares of its common stock, in five privately negotiated transactions
exempt from the registration requirements of the Securities Act.

On February 14, 2003, SPR issued and sold $300 million of its 7.25%
Convertible Notes due 2010. Approximately $53.4 million of the net proceeds from
the sale of the notes was used to purchase U.S. government securities that were
pledged to the trustee for the first five interest payments on the notes payable
during the first two and one-half years. A portion of the remaining net proceeds
of the notes was used to repurchase approximately $58.5 million of SPR's
Floating Rate Notes due April 20, 2003. Of the remaining net proceeds,
approximately $133 million was used to repay SPR's Floating Rate Notes due April
20, 2003, and the remaining proceeds are available for general corporate
purposes. The Convertible Notes were issued with registration rights.

The Convertible Notes are not convertible prior to August 14, 2003. At any
time on or after August 14, 2003 through the close of business February 14,
2010, holders of the Convertible Notes may convert their notes into shares of
SPR's common stock. Until SPR has obtained shareholder approval to permit the
Convertible Notes to be fully convertible into shares of common stock, holders
of the Convertible Notes will be entitled to receive 76.7073 shares of common
stock and an amount of cash equal to the market value of 142.4564 shares of our
common stock at the time of conversion, based on the average closing price of
SPR's common stock over five consecutive trading days, for each $1,000 principal
amount of notes surrendered for conversion. At an assumed five-day average
closing price of $5.00 per share (based on the last reported sale price of SPR's
common stock August 1, 2003), the total amount of the cash payable on conversion
of the Convertible Notes would be approximately $214 million. If SPR does not
obtain shareholder approval, SPR will be required to pay the cash portion of any
Convertible Notes as to which the holders request conversion on or after August
14, 2003. The amount of cash payable on conversion of the Convertible Notes will
increase as the average closing price of SPR's common stock increases. Although
management does not believe it is likely that a significant amount of the
Convertible Notes will be converted in the foreseeable future, in the event that
SPR does not have available funds to pay the cash portion of the Convertible
Notes upon the requested conversion, SPR may have to issue additional debt or
equity to raise the necessary funds. There can be no assurance that SPR will be
able to access the capital markets to issue such additional debt and/or equity
or that it will be able to do so on terms favorable to SPR.

If SPR does obtain shareholder approval, it may elect to satisfy the cash
payment component of the conversion price of the Convertible Notes solely with
shares of common stock. SPR has agreed to use reasonable efforts to obtain
shareholder approval, not later than 180 days after the date of issuance of the
Convertible Notes, to issue and deliver shares of SPR's common stock in lieu of
the cash payment component of the conversion price of the Convertible Notes. SPR
has called a special shareholder meeting for August 11, 2003 to comply with the
terms of the Convertible Notes.

21

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

In addition, until SPR has obtained shareholder approval to permit the
Convertible Notes to be fully convertible into shares of common stock, SPR must
satisfy part of this obligation in cash. Accordingly, the portion of the
obligation relating to the amount to be settled upon conversion by issuing
shares is classified as a long-term liability and the portion to be settled with
working capital upon demand by the holder is classified as a current maturity.

The Convertible Notes provide for the payment of dividends to the holders
in an amount equal to any per share dividends on SPR common stock that would
have been payable to the holders if the holders of the notes had converted their
notes into shares of common stock at the applicable conversion rate on the
record date for such dividend.

The indenture under which the Convertible Notes were issued does not
contain any financial covenants or any restrictions on the payment of dividends,
the repurchase of SPR's securities or the incurrence of indebtedness. The
indenture does allow the holders of the Convertible Notes to require SPR to
repurchase all or a portion of the holders' Convertible Notes upon a change of
control. The indenture also provides for an event of default if SPR or any of
its significant subsidiaries, including NPC and SPPC, fails to pay any
indebtedness in excess of $10 million or has any indebtedness of $10 million or
more accelerated and declared due and payable. For further information regarding
accounting for the conversion option, see Note 10, Derivatives and Hedging
Activities.

SIERRA PACIFIC POWER COMPANY

On May 1, 2003, SPPC's $80 million Washoe County, Nevada, Water Facilities
Refunding Revenue Bonds, Series 2001, were successfully remarketed. The interest
rate on the bonds was adjusted from their prior two-year 5.75% term rate to a
7.50 % term rate for the period of May 1, 2003 to and including May 3, 2004. The
bonds will be subject to remarketing on May 3, 2004 and will continue to be
included in current maturities of long-term debt. In the event that the bonds
cannot be successfully remarketed on that date, SPPC will be required to
purchase the outstanding bonds at a price of 100% of principal amount, plus
accrued interest. From May 1, 2003 to and including May 3, 2004, SPPC's payment
and purchase obligations in respect of the bonds are secured by SPPC's $80
million General and Refunding Mortgage Note, Series D, due 2004.

As of June 30, 2003, NPC's, SPPC's and SPR's aggregate annual amount of
maturities for long-term debt (including obligations related to capital leases)
for the balance of 2003, each of the next four years and thereafter is shown
below (in thousands of dollars):

* The 2003 SPR maturities of $162,495 include $142,180 of SPR's
Convertible Notes due 2010 that are deemed current in 2003, discussed above.

22

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

NOTE 5. DIVIDEND RESTRICTIONS

Since SPR is a holding company, substantially all of its cash flow is
provided by dividends paid to SPR by NPC and SPPC on their common stock, all of
which is owned by SPR. Since NPC and SPPC are public utilities, they are subject
to regulation by state utility commissions which may impose limits on investment
returns or otherwise impact the amount of dividends that the Utilities may
declare and pay, and to federal statutory limitation on the payment of
dividends. In addition, certain agreements entered into by the Utilities set
restrictions on the amount of dividends they may declare and pay and restrict
the circumstances under which such dividends may be declared and paid. The
specific restrictions on dividends contained in agreements to which NPC and SPPC
are party, as well as specific regulatory limitations on dividends, are
summarized below.

NEVADA POWER COMPANY

First Mortgage Indenture. NPC's first mortgage indenture limits the
cumulative amount of dividends and other distributions that NPC may pay on its
capital stock to the cumulative net earnings of NPC since 1953, subject to
adjustments for the net proceeds of sales of capital stock since 1953. At the
present time, this restriction precludes NPC from making further payments of
dividends on NPC's common stock and will continue to preclude payment of
dividends until NPC, over time, generates sufficient earnings to eliminate the
deficit under this provision (which was approximately $279.3 million as of June
30, 2003), unless the restriction is waived, amended, or removed by the consent
of the first mortgage bondholders, or the first mortgage bonds are redeemed or
defeased. Management is currently in the process of seeking consent for the
modification of this restriction. There can be no assurance that any such
consent can be obtained or that any non-consenting first mortgage bonds could be
redeemed or defeased prior to their stated maturity. Under this provision, NPC
continues to have capacity to repurchase or redeem shares of its capital stock.

Series E Notes. NPC's 10 7/8% General and Refunding Mortgage Notes, Series
E, due 2009, which were issued on October 29, 2002, limit the amount of payments
in respect of common stock that NPC may pay to SPR. However, that limitation
does not apply to payments by NPC to enable SPR to pay its reasonable fees and
expenses (including, but not limited to, interest on SPR's indebtedness and
payment obligations on account of SPR's PIES) provided that:

- those payments do not exceed $60 million for any one calendar year,

- those payments comply with any regulatory restrictions then applicable to
NPC, and

- the ratio of consolidated cash flow to fixed charges for NPC's most
recently ended four full fiscal quarters immediately preceding the date
of payment is at least 1.75 to 1.

The terms of the Series E Notes also permit NPC to make payments to SPR in
an aggregate amount not to exceed $15 million from the date of the issuance of
the Series E Notes. In addition, NPC may make dividend payments to SPR in excess
of the amounts described above so long as, at the time of payment and after
giving effect to the payment:

- there are no defaults or events of default with respect to the Series E
Notes,

- NPC can meet a fixed charge coverage ratio test, and

- the total amount of such dividends is less than:

- the sum of 50% of NPC's consolidated net income measured on a quarterly
basis cumulative of all quarters from the date of issuance of the Series
E Notes, plus

- 100% of NPC's aggregate net cash proceeds from the issuance or sale of
certain equity or convertible debt securities of NPC, plus

23

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

- the lesser of cash return of capital or the initial amount of certain
restricted investments, plus

- the fair market value of NPC's investment in certain subsidiaries.

If NPC's Series E Notes are upgraded to investment grade by both Moody's
and S&P, these dividend restrictions will be suspended and will no longer be in
effect so long as the Series E Notes remain investment grade.

NPC's $60 million Credit Agreement. On June 30, 2003, NPC established a
$60 million Credit Facility, which expires no later than September 8, 2003. This
facility prohibits payments to SPR in respect of NPC's common stock.

Accounts Receivable Facility. On October 29, 2002, NPC established an
accounts receivable purchase facility, which expires on October 28, 2003. The
agreements relating to the receivables purchase facility contain various
conditions, including a limitation on the payment of dividends by NPC to SPR
that is identical to the limitation contained in NPC's General and Refunding
Mortgage Notes, Series E, described above.

Preferred Trust Securities. The terms of NPC's preferred trust securities
provide that no dividends may be paid on NPC's common stock if NPC has elected
to defer payments on the junior subordinated debentures issued in conjunction
with the preferred trust securities. At this time, NPC has not elected to defer
payments on the junior subordinated debentures.

PUCN Compliance Order. The PUCN issued a Compliance Order, Docket No.
02-4037, on June 19, 2002, relating to NPC's request for authority to issue
long-term debt. The PUCN order requires that, until such time as the order's
authorization expires (December 31, 2003), NPC must either receive the prior
approval of the PUCN or reach an equity ratio of 42% before paying any dividends
to SPR. If NPC achieves a 42% equity ratio prior to December 31, 2003, the
dividend restriction ceases to have effect. As of June 30, 2003, NPC's equity
ratio was 35.3%. Prior to the expiration date of the Compliance Order,
management may seek PUCN approval for a payment of dividends by NPC or may seek
a waiver from the PUCN of the dividend restriction.

Federal Power Act. NPC is subject to the provisions of the Federal Power
Act that state that dividends cannot be paid out of funds that are properly
included in capital accounts. Although the meaning of this provision is unclear,
it could be interpreted to impose an additional material limitation on a
utility's ability to pay dividends in the absence of retained earnings.

SIERRA PACIFIC POWER COMPANY

Term Loan Agreement. SPPC's Term Loan Agreement dated October 30, 2002, as
amended, which expires October 31, 2005, limits the amount of dividends that
SPPC may pay to SPR. However, that limitation does not apply to payments by SPPC
to enable SPR to pay its reasonable fees and expenses (including, but not
limited to, interest on SPR's indebtedness and payment obligations on account of
SPR's PIES) provided that those payments do not exceed $90 million, $80 million
and $60 million in the aggregate for the twelve month periods ending on October
30, 2003, 2004 and 2005, respectively. The Term Loan Agreement also permits SPPC
to make dividend payments to SPR in an aggregate amount not to exceed $10
million during the term of the Term Loan Agreement. In addition, SPPC may make
dividend payments to SPR in excess of the amounts described above so long as, at
the time of the payment and after giving effect to the payment, there are no
defaults or events of default under the Term Loan Agreement, and such amounts,
when aggregated with the amount of dividends paid to SPR by SPPC since the date
of execution of the Term Loan Agreement, do not exceed the sum of:

- (i) 50% of SPPC's Consolidated Net Income for the period commencing
January 1, 2003 and ending with last day of fiscal quarter most recently
completed prior to the date of the contemplated dividend payment, plus

24

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

- (ii) the aggregate amount of cash received by SPPC from SPR as equity
contributions on its common stock during such period.

Accounts Receivable Facility. On October 29, 2002, SPPC established an
accounts receivable purchase facility, which expires on October 28, 2003. The
agreements relating to the receivables purchase facility contain various
conditions, including a limitation on the payment of dividends by SPPC to SPR
that is identical to the limitation contained in SPPC's Term Loan Agreement,
described above.

Articles of Incorporation. SPPC's Articles of Incorporation contain
restrictions on the payment of dividends on SPPC's common stock in the event of
a default in the payment of dividends on SPPC's preferred stock. SPPC's Articles
also prohibit SPPC from declaring or paying any dividends on any shares of
common stock (other than dividends payable in shares of common stock), or making
any other distribution on any shares of common stock or any expenditures for the
purchase, redemption or other retirement for a consideration of shares of common
stock (other than in exchange for or from the proceeds of the sale of common
stock) except from the net income of SPPC, and its predecessor, available for
dividends on common stock accumulated subsequent to December 31, 1955, less
preferred stock dividends, plus the sum of $500,000. At the present time, SPPC
believes that these restrictions do not materially limit its ability to pay
dividends and/or to purchase or redeem shares of its common stock.

Federal Power Act. SPPC is subject to the provisions of the Federal Power
Act that state that dividends cannot be paid out of funds that are properly
included in capital accounts. Although the meaning of this provision is unclear,
it could be interpreted to impose an additional material limitation on a
utility's ability to pay dividends in the absence of retained earnings.

NOTE 6. EARNINGS PER SHARE (SPR)

The following table outlines the calculation for earnings per share (EPS).
The difference, if any, between Basic EPS and Diluted EPS is due to common stock
equivalent shares resulting from stock options, the employee stock purchase
plan, performance and restricted stock plans and the non-employee director stock
plan. However, due to net losses for the three-and six-month periods ended June
30, 2003 and 2002, these items are anti-dilutive. Accordingly, Diluted EPS for
these periods are computed using the weighted average shares outstanding before
dilution. Common stock equivalents were determined using the treasury stock
method.

25

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

- ---------------

(1) The denominator does not include anti-dilutive stock equivalents under the
Stock Option Plan and Corporate PIES due to exercise or conversion prices
being higher than market prices at June 30, 2003.

(2) Plan terminated in 2002.

(3) New plan adopted in 2003.

NOTE 7. SEGMENT INFORMATION (SPR)

SPR operates three business segments providing regulated electric and
natural gas services. NPC has one business segment that provides electric
service to Las Vegas and surrounding Clark County. SPPC has two business
segments. One business segment provides electric service in northern Nevada and
the Lake Tahoe area of California and the other segment provides natural gas
service in the Reno-Sparks area of Nevada. Other segment information includes
segments below the quantitative threshold for separate disclosure.

Information as to the operations of the different business segments is set
forth below based on the nature of products and services offered. SPR evaluates
performance based on several factors, of which the primary financial measure is
business segment operating income. Intersegment revenues are not material.

Financial data for business segments is as follows (in thousands):

26

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

NOTE 8. DISPOSAL AND IMPAIRMENT OF LONG-LIVED ASSETS

E-THREE

SPR's subsidiary, e-three, was organized in October 1996 to provide energy
and other business solutions in commercial and industrial markets. SPR's
subsidiary, e-three Custom Energy Solutions, LLC ("CES"), was formed in October
1998 for the purpose of selling and implementing energy-related performance
contracts and the construction and operation of a chilled water cooling plant in
the downtown area of Las Vegas supplying indoor air-cooling requirements for a
number of businesses in its immediate vicinity.

In keeping with management's strategy to focus on its core utility
businesses, SPR began negotiations in the second quarter of 2003 to sell e-three
and CES. Management is currently negotiating with a single buyer who is expected
to purchase both companies for approximately $2.2 million. The sale is expected
to be completed during the third quarter of 2003. Accordingly, as of June 30,
2003, e-three and CES are reported as discontinued operations and the
consolidated financial statements for all periods presented in this report have
been reclassified to report separately the assets, liabilities and operating
results of the companies to be sold. Also, the expected pre-tax loss on the
disposal of $8.9 million was recognized as of June 30, 2003. The operations of
e-three and CES are included in the "Other" business segment.

27

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Assets and liabilities for the businesses to be disposed of, which have
been adjusted as of June 30, 2003, based on the expected sales price, consist of
the following (dollars in thousands):

OTHER PROPERTY DISPOSALS

During 2002, the Utilities began pursuing the sale of several non-essential
properties. As a result, on January 15, 2003, NPC sold a parcel of land located
on Flamingo Road near the Barbary Coast Casino in Las Vegas, Nevada. NPC
received cash proceeds of approximately $18 million for the property and
retained an easement and other rights necessary to maintain aerial power lines
that cross the property. Also, it was agreed that NPC will receive an additional
$2.6 million from the sale if the power lines that cross the property are
removed and the other rights are relinquished within a five-year period from the
date of the sale. The property had been originally transferred to NPC at no
cost. The transaction resulted in a gain of $17.7 million, which will be
recognized into revenue over a period of three years consistent with the
accounting treatment directed by the PUCN.

On July 17, 2003, NPC sold a parcel of land located on Centennial Road in
North Las Vegas, Nevada. NPC received cash proceeds of approximately $5.0
million for the property. The property had a carrying value of approximately
$1.2 million. The transaction resulted in an approximate gain of $3.7 million,
which will be recognized into revenue over a period of three years consistent
with the accounting treatment directed by the PUCN.

NPC is pursuing the sale of land parcels located on Flamingo Road from
Koval Lane to Maryland Parkway, commonly known as "the Flamingo Corridor." These
properties are presently under long-term leases with restaurants, convenience
stores, gas stations, etc. On April 21, 2003 NPC provided notice to the tenants
of the Flamingo Corridor properties of its intent to sell the properties at a
public auction. Currently the auction is scheduled for mid-August 2003. The
carrying value of the properties is approximately $0.9 million.

On November 11, 2002, SPPC agreed to sell land located in Nevada County and
Sierra County, California, commonly referred to as Independence Lake. The sale
was subject to review by a third party who retained certain rights, including
water rights, after the sale is completed. Also, the sales agreement included a
due diligence review period of 180 days which allowed the buyer to review and
accept a variety

28

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

of matters agreed to by both parties. In April 2003, the buyer terminated the
agreement during the review period as provided for in the agreement. The
carrying value of the property is approximately $108,000. SPPC plans to sell the
property and is engaged in discussion with potential buyers.

SIERRA PACIFIC COMMUNICATIONS

In light of the bankruptcy of Touch America Holdings and Sierra Touch
America LLC, Sierra Pacific Communications (SPC) evaluated its business to
determine whether the bankruptcy has caused an impairment of SPC's assets. SPC
anticipates that the market for fiber optic cable and conduits will likely
become significantly over-supplied and has recognized an impairment charge of
$32.9 million during the second quarter of 2003. The asset impairment charge
consisted of $14.7 million of fiber optic cable, conduits, and other related
business equipment write-downs related to SPC's metropolitan area network
assets, and $18.2 million in fiber optic cable, conduits, and other related
business equipment write-downs of its long haul network assets.

This evaluation was conducted in conformance with the guidelines of FASB
144, and also considered factors such as the anticipated liquidation of Sierra
Touch America LLC assets, resulting significant changes in business climate and
projected discounted cash flows from the assets.

SPC evaluated its metropolitan area network assets using projected
discounted cash flows. The evaluation factored the undiscounted cash flows from
current and projected sales contracts and continued operating expenses over the
approximate 18-year remaining life of the assets and then discounted those cash
flows to the end of the current reporting period.

SPC evaluated its long haul network assets based in part on a pending sale
for a portion of the long haul network assets currently under construction and
in part by prices for similar assets adjusted for the markets factors that
resulted from the Touch America bankruptcy discussed above.

NOTE 9. REGULATORY ACTIONS

NEVADA POWER COMPANY 2002 DEFERRED ENERGY CASE

On November 14, 2002, NPC filed an application with the PUCN seeking
repayment for purchased fuel and power costs accumulated between October 1,
2001, and September 30, 2002, as required by law. The application sought to
establish a rate to collect accumulated purchased fuel and power costs of $195.7
million, together with a carrying charge, over a period of not more than three
years. The application also requested a reduction to the going-forward rate for
energy, reflecting reduced wholesale energy costs. The combined effect of these
two adjustments resulted in a request for an overall rate reduction of 6.3%.

The decision on this case was issued May 13, 2003 and authorized the
following:

- recovery of $147.6 million, with a carrying charge, and a $48.1 million
disallowance;

- a three-year amortization of the balance commencing on May 19, 2003; and

- a reduction in the Base Tariff Energy Rate (BTER) to an effective
non-residential rate of $0.04322 per kWh, and an effective residential
rate of $0.04186 per kWh.

The new rates went into effect on May 19, 2003.

NEVADA POWER COMPANY DEMAND REDUCTION PROGRAMS

On November 14, 2002, NPC filed an application with the PUCN seeking
recovery of expenses incurred in the implementation and operation of programs
for energy conservation and load management. In the filing, NPC requested a
one-year recovery of approximately $1.9 million. This would result in an average
0.12% increase in NPC's present rates. NPC asked for this increase to become
effective
29

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

simultaneously with the rate change to be ordered in its 2002 deferred energy
case discussed above. The parties to the case subsequently negotiated a
settlement agreement, which approved NPC's request for cost recovery with the
exception of a nominal disallowance. The stipulation was approved at the agenda
meeting held April 4, 2003. The rate change went into effect on May 19, 2003,
coincident with the deferred energy rate change discussed above.

SIERRA PACIFIC POWER COMPANY 2003 DEFERRED ENERGY CASE

On January 14, 2003, SPPC filed an application with the PUCN, as required
by law, seeking to clear deferred balances for purchased fuel and power costs
accumulated between December 1, 2001 and November 30, 2002. The application
sought to establish a rate to clear accumulated purchased fuel and power costs
of $15.4 million and spread the cost recovery over a period of not more than
three years. It also sought to recalculate the rate to reflect anticipated
ongoing purchased fuel and power costs. The total rate increase request amounted
to 0.01%. The interveners' testimony was received April 25, 2003, and included
proposed disallowances from $34 million to $76 million. Prior to the hearing
that was scheduled to begin on May 12, 2003, the parties negotiated a settlement
agreement. The agreement included the following provisions:

- A reduction in the current deferred energy balance of $45 million leaving
a balance payable to customers of approximately $29.6 million.

- A two-year amortization of the amount payable returning one third of the
balance in the first year (approximately $9.9 million), and two thirds of
the balance the second year (approximately $19.7 million).

- Discontinue carrying charges on deferred energy balances that SPPC is
already collecting from customers and on the $29.6 million amount payable
as a result of the agreement.

- Maintain the currently effective Base Tariff Energy Rate.

- SPPC maintains the rights to claim the cost of terminated energy
contracts in future deferred filings.

- Parties agreed that with the $45 million reduction the remaining costs
for purchasing fuel and power during the test year were prudently
incurred and are just and reasonable.

- SPPC and the Bureau of Consumer Protection agreed to file a motion to
dismiss the civil lawsuits filed in relation to the 2001 SPPC deferred
energy case.

The agreement was approved by the PUCN at the agenda meeting held on May
19, 2003, and the new rates went into effect on June 1, 2003.

SIERRA PACIFIC POWER COMPANY DEMAND REDUCTION PROGRAMS

On January 14, 2003, SPPC filed an application with the PUCN seeking
recovery of expenses incurred in the implementation and operation of programs
for energy conservation and load management. In the filing, SPPC requested a
one-year recovery of approximately $0.9 million, which would result in an
average 0.12% increase in SPPC's rates. The parties to the case subsequently
negotiated a settlement agreement, which called for complete recovery of the
$0.9 million balance. The agreement, allowing recovery of the entire balance,
was signed by all parties and approved at the PUCN's May 19, 2003 agenda
meeting. Rates went into effect June 1, 2003, coincident with the deferred
energy rate change discussed above.

30

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

NOTE 10. DERIVATIVES AND HEDGING ACTIVITIES (SPR, NPC, SPPC)

SPR, SPPC, and NPC apply SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities," as amended by SFAS No. 138 and SFAS No.
149. As amended, SFAS No. 133 requires that an entity recognize all derivatives
as either assets or liabilities in the statement of financial position, measure
those instruments at fair value, and recognize changes in the fair value of the
derivative instruments in earnings in the period of change unless the derivative
qualifies as an effective hedge.

SPR's and the Utilities' objective in using derivatives is to reduce
exposure to energy price risk and interest rate risk. Energy price risks result
from activities that include the generation, procurement and marketing of power
and the procurement and marketing of natural gas. Derivative instruments used to
manage energy price risk include forwards, options, and swaps. These contracts
allow the Utilities to reduce the risks associated with volatile electricity and
natural gas markets.

At June 30, 2003, the fair value of energy price risk related derivatives
resulted in the recording of $61 million, $41 million and $20 million in risk
management assets and $63 million, $33 million and $30 million in risk
management liabilities in the Consolidated Balance Sheets of SPR, NPC and SPPC,
respectively. Due to deferred energy accounting under which the Utilities
operate, regulatory assets and liabilities are established to the extent that
electricity and natural gas derivative gains and losses are recoverable or
payable through future rates. Accordingly, at June 30, 2003, $42 million, $17
million and $25 million in net risk management regulatory assets were recorded
in the Consolidated Balance Sheets of SPR, NPC, and SPPC, respectively. In
addition, for the six months ended June 30, 2003, the unrealized gains and
losses resulting from the change in the fair value of derivatives designated and
qualifying as cash flow hedges for SPR, NPC, and SPPC were recorded in Other
Comprehensive Income. Such amounts are reclassified into earnings when the
related transactions are settled or terminate. $1.5 million relating to SPR's
terminated interest rate swap was reclassified into earnings during the six
months ended June 30, 2003.

The effects of SFAS No. 133 on comprehensive income and the components
thereof at June 30, 2003, and 2002, are as follows (in thousands):

In connection with SPR's issuance of its Convertible Notes, on February 14,
2003 (see Note 4, Long-Term Debt), the conversion option, which is treated as a
cash-settled written-call option, was separated from the debt and accounted for
separately as a derivative instrument in accordance with FASB's Emerging Issues
Task Force Issue 90-19, "Convertible Bonds with Issuer Option to Settle for Cash
upon Conversion". Upon issuance, the fair value of the option was recorded as a
current liability in Other Current Liabilities. The change in the fair value is
recognized in earnings in the period of the change.

31

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The fair value of the option is determined using closing stock prices,
which were $5.94 as of June 30 and $3.18 as March 31, 2003, the strike price for
conversion ($4.5628), a measurement for the volatility of the stock price and
the time value of money. The option was valued at $179.7 million at June 30,
2003, resulting in an unrealized pre-tax loss of $123.5 million being recognized
in earnings for the second quarter due to the change in the fair value of the
conversion option. These unrealized pre-tax losses do not have an effect on cash
flows. The value at March 31, 2003 was $56.2 million, and resulted in an
unrealized pre-tax gain of $15.9 million during the first quarter.

In the event SPR obtains shareholder approval to permit the Convertible
Notes to be fully convertible into shares of common stock, Issue No. 00-19 of
the Emerging Issues Task Force of the FASB ("EITF"), "Accounting for Derivative
Instruments Indexed to, and Potentially Settled in, a Company's Own Stock"
provides for the recording of the fair value of the derivative in equity, if all
of the other applicable provisions of EITF Issue No. 00-19 are met. Management
believes that all such applicable provisions will be met. Accordingly, the fair
value of the derivative on the date of the shareholder vote would be
reclassified to equity. In addition, EITF Issue No. 00-19 indicates that
subsequent changes in fair value should not be recognized as long as the
derivative remains classified in equity and SPR would no longer mark this
instrument to market. This would result in no unrealized gains or losses being
recorded in earnings. The previous changes in fair value of the derivative
instrument recorded in earnings would not be reversed.

In the event SPR does not obtain shareholder approval to permit the
Convertible Notes to be fully converted into shares of its common stock, the
derivative will continue to be marked to market with the resulting unrealized
gains or losses recorded in earnings in accordance with SFAS No. 133. The fair
value of the conversion option derivative is determined using a pricing model
that incorporates information and assumptions such as SPR's stock price, time to
expiration, strike price, interest rates, and volatility. The use of different
assumptions and variables in the model could have a significant impact on the
valuation of the derivative.

NOTE 11. COMMITMENTS AND CONTINGENCIES

ENVIRONMENTAL

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.

32

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 July, NPC filed an Integrated Resource Plan with the
PUCN, which assumes that the Plant will be unavailable after December 31, 2005.

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 September 2003. New pond construction and lining
costs are estimated to cost approximately $25 million, of which, $17 million is
expected to be spent by the end of 2003.

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,
with construction expected to begin in August 2003 at an estimated cost of
$150,000.

In July 2000, NPC received a request from the EPA for information to
determine the compliance of certain generation facilities at NPC's Clark Station
with the applicable State Implementation Plan. In November 2000, NPC and 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 requires remediation, 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. However, due to
lack of financial performance the current lessee has been notified of NEICO's
intent to terminate the lease.

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
33

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 performance of the work. SPPC
has recorded a preliminary liability for the Sites of $650,000 of which
approximately $136,000 has been spent through June 30, 2003. The steering
committee is obtaining cost estimates for removal of the buildings. Once these
costs have been determined, SPPC will be in a better position to estimate and
revise, if necessary, its recorded liability for the Sites.

Lands of Sierra

LOS, a wholly owned subsidiary of SPR, owns property in North Lake Tahoe,
California, which is leased to independent condominium owners. The property has
both soil and groundwater petroleum contamination resulting from an underground
fuel tank that has been removed from the property. Additional contamination from
a third party fuel tank on the property has also been identified and is
undergoing remediation. On February 3, 2003, the Lahontan Regional Water Quality
Control Board re-opened closure of this property. By October 1, 2003, SPR
expects to have completed the evaluation of alternative remediation technologies
and their effectiveness in reducing contamination at this site. An application
for closure will be re-submitted at that time. Additional remediation costs are
expected to be approximately $100,000.

LITIGATION CONTINGENCIES

Nevada Power Company and Sierra Pacific Power Company

Enron Power Marketing (Enron) filed a complaint with the United States
Bankruptcy Court for the Southern District of New York seeking to recover
approximately $216 million and $93 million against NPC and SPPC, respectively,
for liquidated damages for power supply contracts terminated by Enron in May
2002 and for power previously delivered to the Utilities. The Utilities have
denied liability on numerous grounds, including deceit and misrepresentation in
the inducement (including, but not limited to, misrepresentation as to Enron's
ability to perform) and fraud, unfair trade practices and market manipulation.
The Utilities filed motions to dismiss for lack of jurisdiction and/or for a
stay of all proceedings pending the actions of the Utilities' proceedings under
Section 206 of the Federal Power Act at the FERC. The Utilities have also filed
proofs of claims and counterclaims against Enron, for the full amount of the
approximately $300 million claimed to be owed and additional damages, as well as
for unspecified damages to be determined during the case as a result of acts and
omissions of Enron in manipulating the power markets, wrongful termination of
its transactions with the Utilities, and fraudulent inducement to enter into
transactions with Enron, among other issues.

On December 19, 2002, the bankruptcy judge granted Enron's motion for
partial summary judgment on Enron's claim for $17.7 million and $6.7 million,
respectively, for energy delivered by Enron in April 2002, for which NPC and
SPPC did not pay. The court ordered this money to be deposited into an escrow
account not subject to claims of Enron's creditors and subject to refund
depending on the outcome of the Utilities' FERC cases on the merits. The
Utilities made the deposit as required. The bankruptcy court denied the
Utilities' motion to stay the proceeding pending the outcome of the Utilities'
Section 206 case at the FERC and denied the Utilities' motion to dismiss for
lack of jurisdiction as to Enron's claims for power previously delivered to the
Utilities. The court stated that it would rule in due course on Enron's motion
for partial summary judgment to require NPC and SPPC to post $200 million and
$87 million, respectively, pending the outcome of the case on the merits, and
for judgment on the merits on Enron's liquidated damage claim (contract price
less market price on the date of termination) relating to power it did not
deliver under contracts terminated by Enron in May 2002. The court took under
advisement the Utilities' motion to stay or dismiss Enron's claim for liquidated
damages relating to the undelivered power.
34

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

On April 3, 2003, the court heard arguments regarding Enron's motion to dismiss
the Utilities' counterclaims against Enron for unspecified damages to be
determined during the case, but did not rule on this matter nor did it indicate
when a decision on this matter can be expected.

On June 26, 2003, FERC issued three orders of consequence to this
litigation. First, FERC denied the Utilities' request to modify the contract
rates, for contracts entered into with Enron and certain other power suppliers
during the western U.S. utility crisis, to a level reflecting a just and
reasonable price in a competitive market. In doing so, however, FERC denied
Enron's request that its order in this case be deemed final and conclusive as to
any and all other challenges to the enforceability of the contracts or to the
lawful contract rate based on Enron's fraud and manipulation of the markets.
FERC indicated that it would reserve judgment on any such challenge until it
heard the evidence on the challenge. Second, FERC issued an order immediately
revoking Enron's market based rate authority based on fraud and manipulation of
the markets. Third, FERC issued an order to show cause Concerning Gaming and/or
Anomalous Market Behavior on the part of Enron and others and directing
submission of information indicating why Enron and others should not be required
to disgorge profits from January 1, 2000, forward. Based on these orders, the
Utilities filed a motion in July 2003 to amend their first amended complaint and
counterclaim to allege facts consistent with the FERC orders that Enron was not
entitled to relief on its claims against the companies but rather should be
required to pay damages against the companies for losses sustained throughout
the western energy crisis for which Enron was in part responsible. The Utilities
also filed a supplement to their opposition to Enron's motion for summary
judgment including all of the facts of fraud and manipulation of the markets as
found by FERC in its June 26, 2003, orders as well as the criminal indictments
and complaints against Enron's former chief financial officer and others engaged
in trading operations for Enron. Enron filed oppositions to the motions to amend
the amended complaint and counterclaims and an opposition to supplement the
Utilities' opposition to Enron's motion for summary judgment. On August 7, 2003,
the Bankruptcy Court heard oral arguments from the parties on the motions. The
bankruptcy judge has not indicated when a decision may be expected. The
Utilities are unable to predict the outcome of these motions. The United States
District Court for the Southern District of New York has also denied the
Utilities' motion to withdraw reference of the matter to the bankruptcy court
without prejudice.

The Bankruptcy Court currently has under submission (1) Enron's motion to
dismiss the Utilities' counterclaims, (2) Enron's motion for partial summary
judgment regarding the amounts alleged to be due for undelivered power and the
posting of collateral for undelivered power, (3) the Utilities' motion to
dismiss or stay proceeding on Enron's claims relating to delivered power and (4)
the Utilities' motion to amend their first amended complaint and counterclaim to
allege facts consistent with the FERC orders that Enron was not entitled to
relief on its claims against the companies. A decision adverse to the Utilities
on Enron's motion for partial summary judgment, or an adverse decision in the
lawsuit with respect to liability as to Enron's claims on the merits for
undelivered power, would have a material adverse effect on SPR's and the
Utilities' financial condition and liquidity, and could make it difficult for
one or more of SPR, NPC or SPPC to continue to operate outside of bankruptcy.

Nevada Power Company

In June 2003, El Paso Merchant Energy demanded mediation of its claim for a
termination payment arising out of El Paso's September 25, 2002 termination of
all executory purchase power contracts between NPC and El Paso. El Paso claims
that under the terms of the contracts, NPC owes El Paso approximately $39
million representing the difference between the contract price and the market
price for power to be delivered under all the terminated contracts and the
amount remaining unpaid under the contracts for power delivered between May 2002
and October 2002. NPC claims that El Paso owes NPC an amount up to approximately
$162 million for undelivered power representing the difference between the
replacement price or market price for power to be delivered under all the
executory contracts and the contract price for that power. The mediation was
unsuccessful, and on July 25, 2003, NPC commenced an action against El

35

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Paso Merchant Energy and several of its affiliates in the Federal District Court
for the District of Nevada for damages resulting from breach of these purchase
power contracts.

On May 3, 2002 and July 3, 2002, respectively, Reliant Resources (Reliant)
and IDACORP Energy, L.P. (Idaho) terminated their power deliveries to NPC. On
May 20, 2002 and July 30, 2002, Reliant and Idaho asserted claims for $25.6
million and $8.9 million, respectively, under the Western System Power Pool
Agreement (WSPP) for liquidated damages under energy contracts that each company
terminated before the delivery dates of the power. Such claims are subject to
mandatory mediation and, in some cases, arbitration under the contracts.
Disputes between Idaho and Reliant were both mediated to conclusion without
reaching a settlement. In May 2003, Idaho filed suit against NPC in Idaho state
court claiming damages in the approximate amount of $8.9 million dollars. NPC
has moved to dismiss the complaint on jurisdictional grounds and filed its own
action in Nevada for declaratory relief claiming that it does not owe Idaho any
money under the terminated contracts. The actions are currently in the pleading
stage. NPC continues to have discussions with Reliant on a broad range of issues
including whether any money is owed Reliant under the purchased power contracts.
Neither party has filed any action arising out of this dispute.

On September 5, 2002, Morgan Stanley Capital Group (MSCG) initiated an
arbitration pursuant to the arbitration provisions in various power supply
contracts terminated by MSCG in April 2002. In the arbitration, MSCG requested
that the arbitrator compel NPC to pay MSCG $25 million pending the outcome of
any dispute regarding the amount owed under the contracts. NPC claimed that
nothing is owed under the contracts on various grounds, including breach by MSCG
in terminating the contracts, and further, that the arbitrator does not have
jurisdiction over NPC's contract claims and defenses. In March 2003, the
arbitrator overseeing the arbitration proceedings dismissed MSCG's demand for
arbitration and agreed that the issues raised by MSCG were not calculation
issues subject to arbitration and that NPC's contract defenses were likewise not
arbitrable.

NPC has since filed a complaint for declaratory relief in the U.S. District
Court for the District of Nevada asking the Court to declare that NPC is not
liable for any damages as a result of MSCG's termination of its power supply
contracts. On April 17, 2003, MSCG answered the complaint and filed a
counterclaim against NPC at the FERC alleging non-payment of the termination
payment in the amount of $25 million. NPC filed a motion to intervene in the
FERC action commenced by MSCG. NPC is unable to predict the outcome of these
proceedings.

In connection with claims by their terminated energy suppliers, the
Utilities have established reserves, included in their Condensed Consolidated
Balance Sheets in "Contract termination reserves," of approximately $235 million
and $87 as of June 30, 2003, for NPC and SPPC, respectively. Also, pursuant to
the deferred energy accounting provisions of AB 369, NPC and SPPC added
approximately $238 million and $82 million, respectively, to their deferred
energy balances for recovery in rates in future periods associated with
terminated supplier claims.

NOTE 12. SUBSEQUENT EVENTS

See Notes 1, 3, and 8 for discussion of events occurring after June 30,
2003.

36

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS

FORWARD-LOOKING STATEMENTS AND RISK FACTORS

The information in this Form 10-Q includes forward-looking statements
within the meaning of the Private Securities Litigation Reform Act of 1995.
These forward-looking statements relate to anticipated financial performance,
management's plans and objectives for future operations, business prospects,
outcome of regulatory proceedings, market conditions and other matters. Words
such as "anticipate," "believe," "estimate," "expect," "intend," "plan" and
"objective" and other similar expressions identify those statements that are
forward-looking. These statements are based on management's beliefs and
assumptions and on information currently available to management. Actual results
could differ materially from those contemplated by the forward-looking
statements. In addition to any assumptions and other factors referred to
specifically in connection with such statements, factors that could cause the
actual results of Sierra Pacific Resources (SPR), Nevada Power Company (NPC), or
Sierra Pacific Power Company (SPPC) to differ materially from those contemplated
in any forward-looking statement include, among others, the following:

(1) unfavorable rulings in rate cases to be filed by NPC and SPPC (the
Utilities) with the Public Utilities Commission of Nevada (PUCN), including
the periodic applications to recover costs for fuel and purchased power
that have been recorded by the Utilities in their deferred energy accounts,
and deferred natural gas recorded by SPPC for its gas distribution
business;

(2) the ability of SPR, NPC, and SPPC to access the capital markets to
support their requirements for working capital, including amounts necessary
to finance deferred energy costs, construction costs, and the repayment of
maturing debt, particularly in the event of additional unfavorable rulings
by the PUCN, a further downgrade of the current debt ratings of SPR, NPC,
or SPPC, and/or adverse developments with respect to NPC's or SPPC's power
and fuel suppliers;

(3) whether NPC's ability to pay SPR dividends will be restored in the
near future, and whether SPPC will be able to continue to pay SPR dividends
under the terms of SPPC's financing agreements and/or restated articles of
incorporation;

(4) whether suppliers, such as Enron, which have terminated their
power supply contracts with NPC and/or SPPC will be successful in pursuing
their claims against the Utilities for liquidated damages under their power
supply contracts, and whether Enron will be successful in its lawsuit
against NPC and SPPC;

(5) whether the PUCN will issue favorable orders in a timely manner to
permit the Utilities to borrow money and issue additional securities to
finance the Utilities' operations and to purchase power and fuel necessary
to serve their respective customers and to repay maturing debt;

(6) whether SPR, NPC, and SPPC will be able to maintain sufficient
stability with respect to their liquidity and relationships with suppliers
to be able to continue to operate outside of bankruptcy;

(7) whether current suppliers of purchased power, natural gas, or fuel
to NPC or SPPC will continue to do business with NPC or SPPC or will
terminate their contracts and whether NPC or SPPC will have sufficient
liquidity to pay its respective power requirements if their current
suppliers continue to require the Utilities to make pre-payments or more
frequent payments on their power purchases;

(8) whether the Utilities will need to purchase additional power on
the spot market to meet unanticipated power demands (for example, due to
unseasonably hot weather) and whether suppliers will be willing to sell
such power to the Utilities in light of their weakened financial condition;

(9) whether SPPC will be successful in obtaining PUCN approval to
recover the costs of the gasifier facility at the Pinon Pine Power Project
in a future general rate case;

37

(10) whether NPC and SPPC will be successful in obtaining PUCN
approval to recover goodwill and other merger costs recorded in connection
with the 1999 merger between SPR and NPC in a future general rate case;

(11) wholesale market conditions, including availability of power on
the spot market, which affect the prices the Utilities have to pay for
power as well as the prices at which the Utilities can sell any excess
power;

(12) the final outcome of NPC's pending lawsuit in Nevada state court
seeking to reverse portions of the PUCN's 2002 order denying the recovery
of NPC's deferred energy costs;

(13) whether the Utilities will be able, either through Federal Energy
Regulatory Commission (FERC) proceedings or negotiation, to obtain lower
prices on the long-term purchased power contracts that they entered into
during 2000 and 2001 that are priced above current market prices for
electricity;

(14) the effect that any future terrorist attacks, wars, threats of
war, or epidemics may have on the tourism and gaming industries in Nevada,
particularly in Las Vegas, as well as on the economy in general;

(15) unseasonable weather and other natural phenomena which, in
addition to impacting the Utilities' customers' demand for power, can have
potentially serious impacts on the Utilities' ability to procure adequate
supplies of fuel or purchased power to serve their respective customers and
on the cost of procuring such supplies;

(16) industrial, commercial, and residential growth in the service
territories of the Utilities;

(17) the loss of any significant customers;

(18) the effect of existing or future Nevada, California, or federal
legislation or regulations affecting electric industry restructuring,
including laws or regulations which could allow additional customers to
choose new electricity suppliers or change the conditions under which they
may do so;

(19) changes in the business or power demands of the Utilities' major
customers, including those engaged in gold mining or gaming, which may
result in changes in the demand for services of the Utilities, including
the effect on the Nevada gaming industry of the opening of additional
Indian gaming establishments in California and other states;

(20) changes in environmental regulations, tax, or accounting matters
or other laws and regulations to which the Utilities are subject;

(21) future economic conditions, including inflation or deflation
rates and monetary policy;

(22) financial market conditions, including changes in availability of
capital or interest rate fluctuations;

(23) unusual or unanticipated changes in normal business operations,
including unusual maintenance or repairs; and

(24) employee workforce factors, including changes in collective
bargaining unit agreements, strikes, or work stoppages.

Other factors and assumptions not identified above may also have been
involved in deriving these forward-looking statements, and the failure of those
other assumptions to be realized, as well as other factors, may also cause
actual results to differ materially from those projected. SPR, NPC and SPPC
assume no obligation to update forward-looking statements to reflect actual
results, changes in assumptions or changes in other factors affecting
forward-looking statements.

38

CRITICAL ACCOUNTING POLICIES

The following items represent critical accounting policies that under
different conditions or using different assumptions could have a material effect
on the financial position and results of operations of SPR and the Utilities:

REGULATORY ACCOUNTING

The Utilities' rates are currently subject to the approval of the PUCN and,
in the case of SPPC, they are also subject to the approval of California Public
Utility Commission (CPUC) and are designed to recover the cost of providing
generation, transmission and distribution services. As a result, the Utilities
qualify for the application of Statement of Financial Accounting Standards
(SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation,"
issued by the Financial Accounting Standards Board (FASB). This statement
recognizes that the rate actions of a regulator can provide reasonable assurance
of the existence of an asset and requires the capitalization of incurred costs
that would otherwise be charged to expense where it is probable that future
revenue will be provided to recover these costs. SFAS No. 71 prescribes the
method to be used to record the financial transactions of a regulated entity.
The criteria for applying SFAS No. 71 include the following: (i) rates are set
by an independent third party regulator, (ii) approved rates are intended to
recover the specific costs of the regulated products or services, and (iii)
rates that are set at levels that will recover costs can be charged to and
collected from customers.

Regulatory assets represent incurred costs that have been deferred because
it is probable they will be recovered through future rates collected from
customers. Regulatory liabilities generally represent obligations to make
refunds to customers for previous collections for costs that are not likely to
be incurred. Management regularly assesses whether the regulatory assets are
probable of future recovery by considering factors such as applicable regulatory
environment changes and the status of any pending or potential deregulation
legislation. Although current rates do not include the recovery of all existing
regulatory assets as discussed further below and in Note 1 in Notes to Financial
Statements in SPR's, NPC's, and SPPC's Annual Report on Form 10-K for the year
ended December 31, 2002, management believes the existing regulatory assets are
probable of recovery. This determination reflects the current political and
regulatory climate in the state, and is subject to change in the future. If
future recovery of costs ceases to be probable, the write-off of regulatory
assets would be required to be recognized as a charge or expensed in current
period earnings.

Regulatory Accounting affects other Critical Accounting Policies, including
Deferred Energy Accounting, Accounting for Goodwill and Merger Costs, Accounting
for Generation Divestiture Costs, Impairment of Long-Lived Assets, and
Accounting for Derivatives and Hedging Activities, all of which are discussed
immediately below.

DEFERRED ENERGY ACCOUNTING

On April 18, 2001, the Governor of Nevada signed into law Assembly Bill 369
(AB 369). The provisions of AB 369 include, among others, a reinstatement of
deferred energy accounting for fuel and purchased power costs incurred by
electric utilities. In accordance with the provisions of SFAS No. 71, the
Utilities implemented deferred energy accounting on March 1, 2001, for their
respective electric operations. Under deferred energy accounting, to the extent
actual fuel and purchased power costs exceed fuel and purchased power costs
recoverable through current rates, that excess is not recorded as a current
expense on the statement of operations but rather is deferred and recorded as an
asset on the balance sheet. Conversely, a liability is recorded to the extent
fuel and purchased power costs recoverable through current rates exceed actual
fuel and purchased power costs. These excess amounts are reflected in
adjustments to rates and recorded as revenue or expense in future time periods,
subject to PUCN review. AB 369 provides that the PUCN may not allow the recovery
of any costs for purchased fuel or purchased power "that were the result of any
practice or transaction that was undertaken, managed or performed imprudently by
the electric utility." In reference to deferred energy accounting, AB 369
specifies that fuel and purchased power costs include all costs incurred to
purchase fuel, to purchase capacity, and to

39

purchase energy. The Utilities also record, and are eligible under the statute
to recover, a carrying charge on such deferred balances.

The Utilities are exposed to commodity price risk primarily related to
changes in the market price of electricity as well as changes in fuel costs
incurred to generate electricity. See Energy Supply in SPR's, NPC's, and SPPC's
Annual Report on Form 10-K for the year ended December 31, 2002, for a
discussion of the Utilities' purchased power procurement strategies, and
Commodity Price Risk in Item 7A, Quantitative and Qualitative Disclosures About
Market Risk, in SPR's, NPC's, and SPPC's Annual Reports on Form 10-K for the
year ended December 31, 2002, for a discussion of the Utilities' commodity risk
management program. As discussed above, deferred energy accounting facilitates
the recovery of costs incurred to procure fuel and purchased power for SPPC and
NPC.

As described in more detail under Regulation and Rate Proceedings, Nevada
Matters, Nevada Power Company 2001 Deferred Energy Case, in SPR's, NPC's, and
SPPC's Annual Reports on Form 10-K for the year ended December 31, 2002, on
November 30, 2001, NPC filed an application with the PUCN seeking to establish a
Deferred Energy Accounting Adjustment (DEAA) rate to clear deferred balances for
purchased fuel and power costs accumulated between March 1, 2001 and September
30, 2001. The application sought to establish a rate to clear accumulated
purchased fuel and power costs of $922 million and spread the cost recovery over
a period of not more than three years. On March 29, 2002, the PUCN issued its
decision on the deferred energy application, disallowing $434 million of
deferred purchased fuel and power costs, and allowing NPC to collect the
remaining $478 million over three years beginning April 1, 2002. As a result of
this disallowance, NPC wrote off $465 million of deferred energy costs and
related carrying charges, the two major national rating agencies immediately
downgraded the credit rating on SPR's, NPC's and SPPC's debt securities
(followed by further downgrades late in April 2002), and the market price of
SPR's common stock fell substantially.

On November 14, 2002, NPC filed an application with the PUCN seeking to
clear deferred balances of $195.7 million for purchased fuel and power costs
accumulated between October 1, 2001, and September 30, 2002, and to spread the
recovery of the deferred costs, together with a carrying charge, over a period
of not more than three years. On May 12, 2003, the PUCN issued its decision on
NPC's deferred energy application, disallowing $48.1 million of deferred
purchased fuel and power and related carrying costs, and allowing NPC to collect
the remaining $147.6 million over three years beginning May 19, 2003. As a
result of this decision, NPC wrote off $48.1 million of disallowed deferred
energy costs and related carrying charges in May 2003.

As described in more detail under Regulation and Rate Proceedings, Nevada
Matters, Sierra Pacific Power Company 2002 Deferred Energy Case, in SPR's,
NPC's, and SPPC's Annual Reports on Form 10-K for the year ended December 31,
2002, SPPC filed an application with the PUCN seeking to establish a DEAA rate
to clear its deferred balances for purchased fuel and power costs accumulated
between March 1, 2001 and November 30, 2001. The application sought to establish
a rate to clear accumulated purchased fuel and power costs of $205 million and
spread the cost recovery over a period of not more than three years. On May 28,
2002, the PUCN issued its decision on SPPC's deferred energy application,
disallowing $53 million of deferred purchased fuel and power costs, and allowing
SPPC to collect the remaining $150 million over three years beginning June 1,
2002. As a result of this decision, SPPC wrote off $58 million of disallowed
deferred energy costs and related carrying charges in the second quarter of
2002.

On January 14, 2003, SPPC filed an application with the PUCN that sought to
clear deferred balances of $15.4 million for purchased fuel and power costs
accumulated between December 1, 2001, and November 30, 2002. The application
sought to establish a DEAA rate to repay accumulated purchased fuel and power
costs of $15.4 million and spread the cost recovery over a period of not more
than three years. On May 19, 2003, the PUCN approved a stipulated agreement
between SPPC and the staff of the PUCN and others that resulted in a rate
decrease of $9.9 million beginning June 1, 2003, and a rate decrease of $19.7
million beginning June 1, 2004. As a result of the agreement, SPPC reduced its
deferred energy balance by $45 million, from a balance of approximately $15.4
million collectible from customers to

40

a balance of approximately $29.6 million payable to customers. This resulted in
a write off of $45 million in May 2003.

Both Utilities have continued to be entitled under AB 369 to utilize
deferred energy accounting for their electric operations. Because of contracts
entered into during the Western energy crisis in 2001 to assure adequate
supplies of electricity for their customers, the Utilities incurred fuel and
purchased power costs in excess of amounts they were permitted to recover in
current rates. As a result, during 2002, both Utilities continued to accumulate
amounts in their deferral of energy costs accounts.

If not for deferred energy accounting during 2003 and 2002, SPR's, NPC's
and SPPC's results of operations, financial condition, liquidity and capital
resources would have been significantly different. For example, without the
deferred energy accounting provisions of AB 369, the reported purchased power
and fuel costs of SPR, NPC, and SPPC for the three months ended June 30, 2003,
would have decreased (net of income tax) by approximately $12.1 million, $7.4
million and $4.7 million, respectively, and for the six months ended June 30,
2003, purchased power and fuel costs would have decreased by $66.9 million,
$54.8 million, and $12.1 respectively. Without deferred energy accounting the
reported interest accrued on deferred energy for the three months ended June 30,
2003, by SPR, NPC, and SPPC, would have decreased (net of income tax) by
approximately $4.3 million, $3.4 million, and $0.9 million, respectively, and
would have decreased by $9.2 million, $7.1 million and $2.1 million,
respectively, for the six months ended June 30, 2003. Similarly, without the
deferred energy accounting provisions of AB 369, the reported purchased power
and fuel costs of SPR, NPC, and SPPC for the three ended June 30, 2002, would
have increased (net of income tax) by approximately $164.8 million, $120.4
million, $44.4 million, respectively, and would have increased for the six
months ended June 30, 2002 by $174.0 million, $126.6 million, and $47.4 million,
respectively. Reported interest accrued on deferred energy costs of SPR, NPC,
and SPPC would have decreased/(increased) for the three months ended June, 30,
2002 (net of income tax) by approximately $23.6 million, $25.3 million and
$(1.7) million, respectively, and interest accrued on deferred energy costs for
the six months ended June 30, 2002, would have increased by $20.1 million, $18.1
million, and $2.1 million, respectively. The effects of AB 369 on 2003 and 2002
purchased power and fuel costs and interest accrued on deferred energy costs
discussed above exclude the write-offs during both years pursuant to PUCN
decisions discussed earlier.

ACCOUNTING FOR GOODWILL AND MERGER COSTS

The order issued by the PUCN in December 1998 approving the merger of SPR
and NPC directed both NPC and SPPC to defer three categories of merger costs to
be reviewed for recovery through future rates. That order specifically directed
both Utilities to defer merger transaction costs, transition costs and goodwill
costs for a three-year period. The deferral of these costs was intended to allow
adequate time for the anticipated savings from the merger to develop. At the end
of the three-year period, the order instructs the Utilities to propose an
amortization period for the merger costs and allows the Utilities to recover the
costs to the extent they are offset by merger savings.

Costs deferred as a result of the PUCN order were $331.2 million of
goodwill and $63.0 million in other merger costs as of June 30, 2003. The
deferred other merger costs consist of $41.1 million of transaction and
transition costs and $21.9 million of employee separation costs. Employee
separation costs were comprised of $17.4 million of employee severance,
relocation and related costs, and $4.5 million of pension and post-retirement
benefits net of plan curtailment gains.

The extent to which goodwill and merger costs will be recovered in future
revenues and the timing of those recoveries is expected to be determined in
general rate cases that will be filed in the third and fourth quarters of 2003
by NPC and SPPC, respectively. To the extent that the Utilities are not
permitted to recover any portion of goodwill in future rates, the amount not
recoverable will be reviewed for impairment and accounted for under the
provisions of Statement of Financial Accounting Standard (SFAS) No. 142,
"Goodwill and Other Intangible Assets". A significant disallowance of goodwill
or merger costs by the PUCN would have a material adverse effect on the future
financial position, results of operations and cash flows of SPR, NPC, and SPPC.

41

ACCOUNTING FOR GENERATION DIVESTITURE COSTS

As a condition to its approval of the merger between SPR and NPC, the
Utilities filed, and in February 2000 the PUCN approved, a revised Divestiture
Plan stipulation for the sale of the Utilities' generation assets. 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. 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 exemption to AB 6, which had prevented
private utilities from selling any power plants that provide energy to
California customers until 2006. The exemption allows SPPC to complete the sale
of the hydroelectric units to TMWA subject to review and approval of the sale by
the CPUC.

The sales agreements for the six bundles provided that they would terminate
eighteen months after their execution, and all of the agreements have now
terminated in accordance with their respective provisions. As of June 30, 2003,
NPC and SPPC had incurred costs, including carrying charges, of approximately
$21.0 million and $12.7 million, respectively, in order to prepare for the sale
of generation assets. In the fourth quarter of 2001, each Utility requested
recovery of its respective costs in its application for a general rate increase
filed with the PUCN. In 2002, the PUCN delayed recovery of divestiture costs to
future rate case requests but did grant a carrying charge on the costs until
such time as recovery is allowed. To the extent that the Utilities are not
permitted to recover any portion of these costs in future rates, the disallowed
costs and related carrying charges would be required to be written off in
current period earnings.

DISPOSAL OF AND IMPAIRMENT OF LONG-LIVED ASSETS

SPR and the Utilities evaluate their Utility Plant and definite-lived
tangible assets for impairment whenever indicators of impairment exist.
Accounting standards require that if the sum of the undiscounted expected future
cash flows from a company's asset (without interest charges that will be
recognized as expenses when incurred) is less than the carrying value of the
asset, an asset impairment must be recognized in the financial statements. The
amount of impairment recognized is calculated by subtracting the fair value of
the asset from the carrying value of the asset.

SIERRA PACIFIC COMMUNICATIONS

As discussed in Note 8 -- Disposal and Impairment of Long-Lived Assets,
Sierra Pacific Communication (SPC) operates its telecommunication business in
two segments, Metropolitan Area Network and Long Haul Fiber Network. SPC
evaluated the assets of its business as of June 30, 2003 as a result of market
conditions created by the bankruptcy of Touch America. This event substantially
deteriorated the telecommunications market in the areas where SPC operates it
long haul fiber assets and SPC anticipates the market for fiber optic cable and
conduits will likely become significantly over-supplied and has caused Sierra
Pacific Communications to test for and as result recognize an impairment charge.
Estimates underlying the asset impairment are significant in determining the
impairment charge. The assumptions underlying the calculation of the
undiscounted future cash flows used to evaluate the impairment, including
projected revenues and expenses and the discount rate used to present value
future cash flows materially effect the amount of the impairment charge. In
estimating undiscounted future cash flows for its long haul fiber assets SPC
used prices for similar assets sales adjusted for the markets factors that
resulted from the Touch America bankruptcy discussed above. To estimate the
undiscounted cash

42

flows from the metropolitan area network assets, SPC used revenues from current
and projected sales contracts and continued operating expenses over the
approximate 18-year remaining life of the assets. Any difference from the
assumptions used could materially change the results of the asset impairment
charge as recognized in the current period.

PINON PINE

As discussed in more detail in Note 21, Pinon Pine, of Notes to Financial
Statements in SPR's, NPC's, and SPPC's Annual Reports on Form 10-K for the year
ended December 31, 2002, SPPC owns a combined cycle generation facility, a
post-gasification facility, and, through its wholly owned subsidiaries, owns a
gasifier that are collectively referred to as the Pinon Pine Power Project
(Pinon Pine). Construction of Pinon Pine was completed in June 1998. Included in
the Condensed Consolidated Balance Sheets of SPR and SPPC is the net book value
of the gasifier and related assets, which is approximately $98 million as of
June 30, 2003.

To date, SPPC has not been successful in obtaining sustained operation of
the gasifier. In 2001 SPPC retained an independent engineering consulting firm
to complete a comprehensive study of the Pinon Pine gasification plant. After
evaluating the options presented in the draft report, SPPC decided not to pursue
modifications intended to make the facility operational and intends to seek
recovery, net of salvage, through regulated rates in its next general rate case
based, in part, on the PUCN's approval of Pinon Pine as a demonstration project
in an earlier resource plan. However, if SPPC is unsuccessful in obtaining
recovery, there could be a material adverse effect on SPPC's and SPR's financial
position, results of operations and cash flows.

MOHAVE

As discussed in more detail in Note 11, Commitments and Contingencies,
Environmental, NPC owns a 14% interest in the Mohave Generating Station located
in Laughlin, Nevada. Included in the Condensed Consolidated Balance Sheets of
SPR and NPC is the net book value of NPC's share of the Mohave facility, which
is approximately $36.1 million as of June 30, 2003.

Due to a lack of progress in negotiations with the parties to resolve
several coal and water supply issues, Southern California Edison's (SCE), the
operating partner, filed an application with the California Public Utility
Commission (CPUC) to determine whether it is in the public interest to continue
operation of the Mohave facility beyond 2005. Also, 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 due to the uncertainty over the coal supply and water issues.

NPC is currently evaluating and analyzing all of its options with regard to
the Mohave coal and water supply issues and the compliance with the
environmental consent decree approved in November 1999. NPC intends to seek
recovery, net of salvage, through regulated rates in its next general rate case.
However, if NPC is unsuccessful in obtaining recovery, there could be an adverse
effect on NPC's and SPR's financial position, results of operations and cash
flows.

E-THREE AND E-THREE CUSTOM ENERGY SOLUTIONS

SPR's subsidiary, e-three, was organized in October 1996 to provide energy
and other business solutions in commercial and industrial markets. SPR's
subsidiary, e-three Custom Energy Solutions, LLC (CES), was formed in October
1998 for the purpose of selling and implementing energy-related performance
contracts and the construction and operation of a chilled water cooling plant in
the downtown area of Las Vegas supplying indoor air-cooling requirements for a
number of businesses in its immediate vicinity.

In keeping with management's strategy to focus on its core utility
businesses, SPR began negotiations in the second quarter of 2003 to sell e-three
and CES. Management is currently negotiating with a single buyer who is expected
to purchase both companies for approximately $2.2 million. The sale is expected
to

43

be completed during the third quarter of 2003. Accordingly, as of June 30, 2003,
e-three and CES are reported as discontinued operations and the consolidated
financial statements for all periods presented in this report have been
reclassified to report separately the assets, liabilities and operating results
of the companies. Based on the expected selling price, a pre-tax loss on the
disposal of $8.9 million was recognized as of June 30, 2003. To the extent the
final sales price differs from $2.2 million, the loss on disposal will be
adjusted accordingly.

ACCOUNTING FOR DERIVATIVES AND HEDGING ACTIVITIES

SPR, SPPC, and NPC apply SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities," as amended. SFAS No. 133 requires that an
entity recognize all derivatives as either assets or liabilities in the
statement of financial position and measure those instruments at fair value.

FUEL AND PURCHASED POWER CONTRACTS

In order to manage loads, resources and energy price risk, the Utilities
buy fuel and power under forward contracts. In addition to forward fuel and
power purchase contracts, the Utilities also use options and swaps to manage
price risk. All of these instruments are considered to be derivatives under SFAS
No. 133. The risk management assets and liabilities recorded in the balance
sheets of the Utilities and SPR are primarily comprised of the fair value of
these forward fuel and power purchase contracts and other energy related
derivative instruments.

Fuel and purchased power costs are subject to deferred energy accounting.
Accordingly, the energy related risk management assets and liabilities and the
corresponding unrealized gains and losses (changes in fair value) are offset
with a regulatory asset or liability rather than recognized in the statements of
operations and comprehensive income. Upon settlement of a derivative instrument,
actual fuel and purchased power costs are recognized if they are currently
recoverable or deferred if they are recoverable or payable through future rates.

The fair values of the forward contracts and swaps are determined based on
quotes obtained from independent brokers and exchanges. The fair values of
options are determined using a pricing model that incorporates assumptions such
as the underlying commodity's forward price curve, time to expiration, strike
price, interest rates, and volatility. The use of different assumptions and
variables in the model could have a significant impact on the valuation of the
instruments.

DEBT CONVERSION OPTION

In connection with SPR's issuance of its Convertible Notes (see Note 4,
Long-Term Debt), the conversion option, which is treated as a cash-settled
written call option, was separated from the debt and accounted for separately as
a derivative instrument.

Until SPR has obtained shareholder approval to permit the Convertible Notes
to be fully convertible into shares of common stock, holders of the Convertible
Notes will be entitled to receive 76.7073 shares of common stock and a remaining
portion in cash, based on the average closing price of SPR's common stock over
five consecutive trading days, for each $1,000 principal amount of notes
surrendered for conversion. Because the conversion of the option presently
cannot be entirely settled with shares of common stock, the fair market value of
the derivative is recorded as a liability with changes in the fair value of the
derivative reported in earnings in the period of the change. SPR has scheduled a
special meeting of the stockholders to be held on August 11, 2003.

In the event SPR obtains shareholder approval to permit the Convertible
Notes to be fully converted into shares of common stock, Issue No. 00-19 of the
Emerging Issues Task Force of the FASB (EITF), "Accounting for Derivative
Instruments Indexed to, and Potentially Settled in, a Company's Own Stock"
provides for the recording of the fair value of the derivative in equity, if all
of the other applicable provisions of EITF Issue No. 00-19 are met. Management
believes that all such applicable provisions will be met. Accordingly, the fair
value of the derivative on the date of the shareholder vote would be

44

reclassified to equity. In addition, EITF Issue No. 00-19 indicates that
subsequent changes in fair value should not be recognized as long as the
derivative remains classified in equity and SPR would no longer mark this
instrument to market. This would result in no unrealized gains or losses being
recorded in earnings. The previous changes in fair value of the derivative
instrument recorded in earnings would not be reversed.

In the event SPR does not obtain shareholder approval to permit the
Convertible Notes to be fully converted into shares of its common stock, the
derivative will continue to be marked to market with the resulting unrealized
gains or losses recorded in earnings in accordance with SFAS No. 133. The fair
value of the conversion option derivative is determined using a pricing model
that incorporates information and assumptions such as SPR's stock price, time to
expiration, strike price, interest rates, and volatility. The use of different
assumptions and variables in the model could have a significant impact on the
valuation of the derivative.

Based on the closing price of SPR's common stock at June 30, 2003 of $5.94,
the fair value of the conversion option was determined to be approximately $180
million at June 30, 2003 and as a result, SPR recorded unrealized losses in
earnings of approximately $123.5 million and $107.5 million for three and six
month periods ended June 30, 2003, respectively. Assuming no change in the other
variables, a $1.00 change in the closing price of SPR's stock to $4.94 or $6.94
would have resulted in a fair value of approximately $128 million and $234
million, respectively, and unrealized losses for the three months ended June 30,
2003 of approximately $72 million and $178 million, respectively, and unrealized
losses for the six months ended June 30, 2003 of approximately $56 million and
$161 million, respectively.

Similarly, changes in the market price of SPR's common stock can have a
significant impact on the amount of cash payable upon conversion of the
Convertible Notes. At an assumed five-day average closing price of $5.94 per
share (based on the last reported sale price of SPR's common stock on July 30,
2003), the total amount of the cash payable on conversion of the Convertible
Notes would be approximately $254 million. The amount of cash payable on
conversion of the Convertible Notes would increase or decrease approximately $43
million to $297 million and $211 million, respectively based on a $1.00 change
in the average closing price of SPR's common stock.

OTHER DERIVATIVES

SPR and the Utilities have other non-energy related derivative instruments.
The changes in fair values of these non-energy related derivatives are reported
in Other comprehensive income until the related transactions are settled or
terminate, at which time the amounts are reclassified into earnings.

ENVIRONMENTAL CONTINGENCIES

SPR and its subsidiaries are subject to federal, state and local
regulations governing air and 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 and
water quality, solid, hazardous and toxic waste.

SPR and its subsidiaries are subject to rising costs that result from a
steady increase in the number of federal, state and local laws and regulations
designed to protect the environment. These laws and regulations can result in
increased capital, operating, and other costs as a result of compliance,
remediation, containment and monitoring obligations, particularly with laws
relating to power plant emissions. In addition, SPR or its subsidiaries may be a
responsible party for environmental clean up at a site identified by a
regulatory body. The management of SPR and its subsidiaries cannot predict with
certainty the amount and timing of all future expenditures related to
environmental matters because of the difficulty of estimating clean up costs and
compliance and the possibility that changes will be made to the current
environmental laws and regulations. There is also uncertainty in quantifying
liabilities under environmental laws that impose joint and several liability on
all potentially responsible parties. SPR and its
45

subsidiaries accrue for environmental costs only when they can conclude that it
is probable that they have an obligation for such costs and can reasonably
determine the amount of such costs.

Note 11, Commitments and Contingencies, of Notes to Condensed Consolidated
Financial Statements discusses the environmental matters of SPR and its
subsidiaries that have been identified, and the estimated financial effect of
those matters. To the extent that (1) actual results differ from the estimated
financial effects, (2) there are environmental matters not yet identified for
which SPR or its subsidiaries are determined to be responsible, or (3) the
Utilities are unable to recover through future rates the costs to remediate such
environmental matters, there could be a material adverse effect on the financial
condition and future liquidity and results of operations of SPR and its
subsidiaries.

LITIGATION CONTINGENCIES

Note 11, Commitments and Contingencies, of Notes to Condensed Consolidated
Financial Statements discusses the significant legal matters of SPR and its
subsidiaries. As described in Note 11, NPC and SPPC established reserves,
included in their Condensed Consolidated Balance Sheets as "Contract termination
reserves," for amounts claimed for liquidated damages for terminated power
supply contracts and for power previously delivered to the Utilities by Enron
and other suppliers. Correspondingly, pursuant to the deferred energy accounting
provisions of AB 369, NPC and SPPC added as of June 30, 2003, approximately $238
million and $82 million, respectively, to their deferred energy balances for
recovery in rates in future periods associated with these terminated supplier
claims. If NPC and SPPC receive unfavorable rulings with respect to the
terminated supplier claims and as a result are required to pay part or all of
the amounts reserved, the Utilities will pursue recovery of the amounts through
future deferred energy filings. To the extent that the Utilities are not
permitted to recover any portion of these costs through a deferred energy
filing, the amounts not permitted would be charged as a current operating
expense. A significant disallowance of these costs by the PUCN could have a
material adverse effect on the future financial position, results of operations
and cash flows of SPR, NPC, and SPPC.

SPR and its subsidiaries, through the course of their normal business
operations, are currently involved in a number of other legal actions, none of
which has had or, in the opinion of management, is expected to have, a
significant impact on its financial position or results of operations.

DEFINED BENEFIT PLANS AND OTHER POSTRETIREMENT PLANS

As further explained in Note 14, Retirement Plan and Post-Retirement
Benefits, of Notes to Financial Statements in SPR's, NPC's, and SPPC's Annual
Reports on Form 10-K for the year ended December 31, 2002, SPR maintains a
pension plan as well as other postretirement benefit plans that provide health
and life insurance for retired employees. All employees are eligible for these
benefits if they reach retirement age while still working for SPR or its
subsidiaries. These costs are determined in accordance with the provisions of
SFAS No. 87, "Employers' Accounting for Pensions," and SFAS No. 106, "Employers'
Accounting for Postretirement Benefits Other Than Pensions," and ultimately
collected in rates billed to customers. The amounts funded are then used to meet
benefit payments to plan participants. In the first six months of 2003, SPR has
contributed approximately $25.6 million and $0.1 million to the pension and
other postretirement plans, respectively. For the year ended December 31, 2002,
SPR contributed $41.1 million to its pension plan, and $0.2 million to the other
postretirement benefits plan. Due to the sharp decline in United States equity
markets since the third quarter of 2000, the value of a significant portion of
the assets held in the plans' trusts to satisfy the obligations of the plans
decreased significantly. As a result, additional contributions were required and
may be required in the future to meet the requirements of the plan to pay
benefits to plan participants.

PENSION PLANS

SPR's reported costs of providing non-contributory defined pension benefits
(described in Note 14, Retirement Plan and Post-Retirement Benefits, of Notes to
Financial Statements in SPR's, NPC's, and

46

SPPC's Annual Reports on Form 10-K for the year ended December 31, 2002) are
dependent upon numerous factors resulting from actual plan experience and
assumptions of future experience.

For example, pension costs are impacted by actual employee demographics
(including age and employment periods), the level of contributions SPR makes to
the plan, and earnings on plan assets. Changes made to the provisions of the
plan may also impact current and future pension costs. Pension costs may also be
significantly affected by changes in key actuarial assumptions, including
anticipated rates of return on plan assets and the discount rates used in
determining the projected benefit obligation and pension costs.

SPR has made no changes to pension plan provisions in 2002 or 2003 that
have had any significant impact on recorded pension amounts. SPR reduced the
discount rate used in determining pension expense for the calendar year 2003
from 7.5% to 6.75%. This change will not have a significant impact on reported
pension costs for 2003.

SPR's pension plan assets are primarily made up of equity and fixed income
investments. Fluctuations in actual equity market returns as well as changes in
general interest rates may result in increased or decreased pension costs in
future periods. Likewise, changes in assumptions regarding current discount
rates and expected rates of return on plan assets could also increase or
decrease recorded pension costs.

In selecting an assumed rate of return on plan assets, SPR considers past
performance and economic forecasts for the types of investments held by the
plan. The market value of SPR's plan assets has been affected by sharp declines
in equity markets since the third quarter of 2000.

Pension cost and cash funding requirements could increase in future years
without a substantial recovery in the equity markets.

OTHER POSTRETIREMENT BENEFITS

SPR's reported costs of providing other postretirement benefits (described
in Note 14, Retirement Plan and Post-Retirement Benefits, of Notes to Financial
Statements in SPR's, NPC's, and SPPC's Annual Reports on Form 10-K for the year
ended December 31, 2002) are dependent upon numerous factors resulting from
actual plan experience and assumptions of future experience.

For example, other postretirement benefit costs are impacted by actual
employee demographics (including age and employment periods), the level of
contributions made to the plan, earnings on plan assets, and health care cost
trends. Changes made to the provisions of the plan may also impact current and
future other postretirement benefit costs. Other postretirement benefit costs
may also be significantly affected by changes in key actuarial assumptions,
including anticipated rates of return on plan assets and the discount rates used
in determining the postretirement benefit obligation and postretirement costs.

SPR has made no changes to other postretirement benefit plan provisions in
2002 or 2003 that have had any significant impact on recorded benefit plan
amounts. SPR reduced the discount rate used in determining other postretirement
expense for the calendar year 2003 from 7.5% to 6.75%. This change will not have
a significant impact on reported other postretirement benefit costs for 2003.
However, in determining the other postretirement benefit obligation and related
cost, these assumptions can change from period to period, and such changes could
result in material changes to such amounts.

SPR's other postretirement benefit plan assets are primarily made up of
equity and fixed income investments. Fluctuations in actual equity market
returns as well as changes in general interest rates may result in increased or
decreased other postretirement benefit costs in future periods. Likewise,
changes in assumptions regarding current discount rates and expected rates of
return on plan assets could also increase or decrease recorded other
postretirement benefit costs.

In selecting an assumed rate of return on plan assets, SPR considers past
performance and economic forecasts for the types of investments held by the
plan. The market value of the SPR's plan assets has been affected by sharp
declines in equity markets since the third quarter of 2000. Also, other

47

postretirement benefit cost and cash funding requirements could increase in
future years without a substantial recovery in the equity markets.

COST CAPITALIZATION POLICIES

The Utilities continue to devote substantial resources in 2003 on the
Centennial Transmission project at NPC and the Falcon to Gonder Transmission
project at SPPC. In addition, certain operating units of the Utilities are
charged with maintaining, repairing and replacing components of generation,
transmission and distribution systems both on a scheduled basis and on an
as-needed basis. As described in Note 1, Summary of Significant Accounting
Policies, of Notes to Financial Statements in SPR's, NPC's, and SPPC's Annual
Reports on Form 10-K for the year ended December 31, 2002, the cost of
additions, including betterments and replacements of units of property, is
charged to utility plant. When units of property are replaced, renewed or
retired, their cost, plus removal or disposal costs less salvage, is charged to
accumulated depreciation. Certain direct and indirect costs are capitalized,
including the cost of debt and equity capital associated with construction and
retirement activity as prescribed by Generally Accepted Accounting Principles
(GAAP) and the FERC's Uniform System of Accounts.

The indirect construction overhead costs capitalized are based upon the
following cost components: the cost of time spent by administrative employees in
planning and directing construction; property taxes; employee benefits including
such costs as pensions, postretirement and post employment benefits, vacations
and payroll taxes; and an allowance for funds used during construction (AFUDC).
The level of indirect construction overhead costs capitalized by the Utilities
is based upon real-time construction activity. Accordingly, payroll and other
costs capitalized will fluctuate based upon seasonal construction activities and
the deployment of resources to those efforts. During periods of higher
maintenance levels, these payroll and other costs will not be capitalized. As
such, operating income could be impacted by the manner in which payroll and
related costs are deployed. However, the total cash flow of the Utilities is not
impacted by the allocation of these costs to various construction or maintenance
activities.

During the three and six months ended June 30, 2003, NPC and SPPC
capitalized approximately $1.0 million, $1.2 million, $3.2 million and $2.5
million, respectively, of AFUDC as a result of construction activity. Similarly,
during the three and six months ended June 30, 2002, NPC and SPPC capitalized
approximately $1.0 million, $146,000, $2.5 million and $773,000, respectively,
of AFUDC. These amounts are non-cash components reflected in the Consolidated
Statements of Operations. Recognition of AFUDC as a cost of utility plant is in
accordance with established regulatory ratemaking practices. Such practices
permit the Utility to earn a return on, and recover in rates, all capital costs
charged for Utility services.

DEPRECIATION EXPENSE

The Utilities have a significant investment in electric plant. SPPC also
has an investment in gas distribution plant. Depreciable assets of generation,
transmission and distribution operations represent approximately 93% of the
Utilities' investment in utility plant. As described in Note 1, Summary of
Significant Accounting Policies, of Notes to Financial Statements in SPR's,
NPC's, and SPPC's Annual Report on Form 10-K for the year ended December 31,
2002, the Utilities depreciate these assets utilizing a composite rate, which
currently includes a component for net negative salvage. These assets are
depreciated on a straight-line basis over the remaining useful life of the
related assets, which approximates the anticipated physical lives of these
assets in most cases. The Nevada Administrative Code requires the Utilities to
provide a depreciation study every four years in order to substantiate the
remaining physical lives of their investment in utility plant. Adjustments to
the estimated depreciable lives of the Utilities' plant are recorded on a
prospective basis, as prescribed by Generally Accepted Accounting Principals
(GAAP) and the Federal Energy Regulatory Commission's (FERC) Uniform System of
Accounts.

Substantially all of the Utilities' plant is subject to the ratemaking
jurisdiction of the PUCN or the FERC and, in the case of SPPC's California
operations, the CPUC, which also approves any changes SPPC may make to
depreciation rates utilized for this property. Because the Utilities' periodic

48

depreciation expense is included as a component of the revenue requirement
utilized in the development of the Utilities' tariff rates, revenue reflects
collection of the recognized depreciation expense. Accordingly, the impact of
depreciation on net income is not significant. However, operating cash flows are
positively affected by the amount of depreciation collected in rates, since
depreciation expense is not a current cash outlay for the Utilities.

ASSET RETIREMENT OBLIGATIONS

In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations." SFAS No. 143 provides accounting requirements for the
recognition and measurement of liabilities associated with the retirement of
tangible long-lived assets. Under the standard, these liabilities will be
recognized at fair value as incurred and capitalized as part of the cost of the
related tangible long-lived assets. Accretion of the liabilities due to the
passage of time will be an operating expense. Retirement obligations associated
with long-lived assets included within the scope of SFAS No. 143 are those for
which a legal obligation exists under enacted laws, statutes written or oral
contracts, including obligations arising under the doctrine of promissory
estoppel. The Utilities adopted SFAS No. 143 on January 1, 2003.

Prior to adopting SFAS 143, costs for removal of most utility assets were
accrued as an additional component of depreciation expense. Under SFAS 143, only
the costs to remove an asset with legally binding retirement obligations will be
accrued over time through accretion of the asset retirement obligation and
depreciation of the capitalized asset retirement cost.

Management's methodology to assess its legal obligation included an
inventory of assets by system and components, and a review of right of ways and
easements, regulatory orders, leases and federal, state, and local environmental
laws. Management assumed in determining its Asset Retirement Obligations that
transmission, distribution and communications systems will be operated in
perpetuity and would continue to be used or sold without land remediation; and
mass asset properties that are replaced or retired frequently would be
considered normal maintenance.

Management has identified a legal obligation to retire generation plant
assets specified in land leases for NPC's jointly-owned Navajo generating
station. The land on which the Navajo generating station resides is leased from
the Navajo Nation. The provisions of the leases require the lessees to remove
the facilities upon request of the Navajo Nation at the expiration of the
leases. Although the related retirement obligation and corresponding charges
recognized were immaterial to the financial statements of NPC, those amounts
were based on certain estimates and assumptions. The estimated liability is
based on two levels of decommissioning, minimal and full, and two possible
retirement dates. The liability is escalated using average historical Consumer
Price Index inflation factors equal to the estimated retirement dates. The
liability is discounted using credit-adjusted risk-free rates of return for the
respective retirement dates. Changes to future statements of financial position
and results of operations will occur to the extent that actual results differ
from the estimates and assumptions used, including changes in decommissioning
costs, timing or changes in NPC's credit rating. SPPC has no significant asset
retirement obligations.

The Utilities have various transmission and distribution lines as well as
substations that operate under various rights of way that contain end dates and
restorative clauses. Management operates the transmission and distribution
system as though they will be operated in perpetuity and will continue to be
used or sold without land remediation. As a result, the Utilities have not
recorded any costs associated with the removal of the transmission and
distribution systems.

STOCK COMPENSATION PLANS

In December 2002, the FASB released SFAS No. 148, "Accounting for
Stock-Based Compensation -- Transition and Disclosure," as an amendment to SFAS
No. 123, "Accounting for Stock-Based Compensation." SPR has previously adopted
the disclosure-only provisions of SFAS No. 123, and as of December 31, 2002 has
adopted the updated disclosure requirements set forth in SFAS No. 148. Pursuant
to those updated disclosure requirements, SPR has included the following
discussion on the stock
49

compensation plans. For additional information on SPR's stock compensation
plans, see Note 1, Summary of Significant Accounting Policies, and Note 15,
Stock Compensation Plans, of Notes to Financial Statements in SPR's, NPC's, and
SPPC's Annual Reports on Form 10-K for the year ended December 31, 2002.

At June 30, 2003, SPR had several stock-based compensation plans. SPR
applies Accounting Principles Board Opinion No. 25, Accounting for Stock Issued
to Employees, in accounting for its stock option plans. Accordingly, no
compensation cost has been recognized for nonqualified stock options and the
employee stock purchase plan. SPR has adopted the disclosure-only provisions of
SFAS No. 123, Accounting for Stock Based Compensation, and its related
amendment(s).

UNBILLED RECEIVABLES

Revenues related to the sale of energy are recorded based on meter reads,
which occur on a systematic basis throughout a month, rather than when the
service is rendered or energy is delivered. At the end of each month, the energy
delivered to the customers from the date of their last meter read to the end of
the month is estimated and the corresponding unbilled revenues are calculated.
These estimates of unbilled sales and revenues are based on the ratio of
billable days versus unbilled days, amount of energy procured and generated
during that month, historical customer class usage patterns and the Utilities'
current tariffs. Customer accounts receivable as of June 30, 2003, include
unbilled receivables of $89 million and $51 million for NPC and SPPC,
respectively. Customer accounts receivable as of June 30, 2002, include unbilled
receivables of $101 million and $43 million for NPC and SPPC, respectively.

PROVISION FOR UNCOLLECTIBLE ACCOUNTS

The Utilities reserve for doubtful accounts based on past experience
writing off uncollectible customer accounts. The adequacy of these reserves will
vary to the extent that future collections differ from past experience.

FINANCIAL CONDITION AND MATERIAL CHANGES IN RESULTS OF OPERATIONS

SIERRA PACIFIC RESOURCES

The operating results of SPR primarily reflect those of NPC and SPPC,
discussed later.

During the three months ended June 30, 2003, SPR incurred a net loss of
$172.4 million compared to a $40.9 million net loss for the same period during
2002. Operating results for the three months ended June 30, 2003, were
negatively affected by the following items (before income taxes):

- an unrealized loss of $123.5 million on the derivative instrument
associated with the issuance of $300 million of convertible debt (see
Critical Accounting Policies -- Accounting for Derivatives and Hedging
Activities -- Debt Conversion Option above). This unrealized loss has no
effect on cash flows;

- the write-off of disallowed deferred energy costs (excluding carrying
charges) of approximately $46 million and $45 million by NPC and SPPC,
respectively;

- losses by SPR subsidiaries due to the recognition of asset impairments
and business disposals of $32.9 million and $8.9 million by SPC and
e-three, respectively; and

- higher interest costs at SPR, NPC and SPPC.

SPR operating results during the same three-month period in 2002 were
negatively affected by a write-off of $53.1 million of SPPC's disallowed
deferred energy costs.

During the first six months of 2003, SPR incurred a net loss of $188.0
million compared to a $345.4 million net loss for the same period during 2002.
Similar to the items affecting the three-month

50

operating results, SPR operating results for the six months ended June 30, 2003,
were negatively affected by the following items (before income taxes):

- an unrealized loss of $107.6 million on the derivative instrument
associated with the issuance of $300 million of convertible debt. This
unrealized loss has no effect on cash flows;

- the write-off of disallowed deferred energy costs (excluding carrying
charges) of approximately $46 million and $45 million by NPC and SPPC,
respectively;

- losses by SPR subsidiaries due to the recognition of asset impairments
and business disposals of $32.9 million and $8.9 million by SPC and
e-three, respectively; and

- higher interest costs at SPR, NPC and SPPC.

SPR operating results for the same six-month period during 2002 were
negatively affected by write-offs of $434.1 million and $53.1 million of
disallowed deferred energy costs by NPC and SPPC, respectively.

SPR did not pay or declare a common dividend in the first six months of
2003, nor did NPC and SPPC declare or pay common stock dividends to their
parent, SPR, during the same period. SPPC paid $1.95 million in dividends to
holders of its preferred stock during the first six months of 2003.

LIQUIDITY AND CAPITAL RESOURCES (SPR CONSOLIDATED)

SPR, on a stand-alone basis, had cash and cash equivalents of approximately
$19.1 million at June 30, 2003. At July 31, 2003, SPR had cash balances of
approximately $19.5 million.

SPR's future liquidity and its ability to pay the principal of and interest
on its indebtedness depend on SPPC's ability to continue to pay dividends to
SPR, on NPC's financial stability and the restoration of its ability to pay
dividends to SPR, and on SPR's ability to access the capital markets or
otherwise refinance maturing and/or convertible debt. Further adverse
developments at NPC or SPPC, including a material disallowance of deferred
energy costs in future rate cases or an adverse decision in the pending lawsuit
by Enron, could make it difficult for SPR to operate outside of bankruptcy.

DIVIDENDS FROM SUBSIDIARIES

Since SPR is a holding company, substantially all of its cash flow is
provided by dividends paid to SPR by NPC and SPPC on their common stock, all of
which is owned by SPR. Since NPC and SPPC are public utilities, they are subject
to regulation by state utility commissions, which may impose limits on
investment returns or otherwise impact the amount of dividends that the
Utilities may declare and pay, and to federal statutory limitation on the
payment of dividends. In addition, certain agreements entered into by the
Utilities set restrictions on the amount of dividends they may declare and pay
and restrict the circumstances under which such dividends may be declared and
paid. The specific restrictions on dividends contained in agreements to which
NPC and SPPC are party, as well as specific regulatory limitations on dividends,
are summarized below.

- NPC's first mortgage indenture limits the cumulative amount of dividends
and other distributions that NPC may pay on its capital stock to the
cumulative net earnings of NPC since 1953, subject to adjustments for the
net proceeds of sales of capital stock since 1953. At the present time,
this restriction precludes NPC from making further payments of dividends
on NPC's common stock and will continue to bar dividends until NPC, over
time, generates sufficient earnings to eliminate the deficit under this
provision (which was approximately $279.3 million as of June 30, 2003),
unless the restriction is earlier waived, amended, or removed by the
consent of the first mortgage bondholders, or the first mortgage bonds
are redeemed or defeased. Management is currently in the process of
seeking consent for the modification of this restriction. There can be no
assurance that any such consent can be obtained or that any
non-consenting first mortgage bonds could be redeemed or defeased prior
to their stated maturity. Under this provision, NPC continues to have

51

capacity to repurchase or redeem shares of its capital stock, although
other restrictions set forth below would limit the amount of any such
repurchases or redemptions.

- NPC's 10 7/8% General and Refunding Mortgage Notes, Series E, due 2009,
which were issued on October 29, 2002, limit the amount of payments in
respect of common stock that NPC may pay to SPR. However, that limitation
does not apply to payments by NPC to enable SPR to pay its reasonable
fees and expenses (including, but not limited to, interest on SPR's
indebtedness and payment obligations on account of SPR's Premium Income
Equity Securities (PIES)) provided that:

- those payments do not exceed $60 million for any one calendar year,

- those payments comply with any regulatory restrictions then applicable
to NPC, and

- the ratio of consolidated cash flow to fixed charges for NPC's most
recently ended four full fiscal quarters immediately preceding the date
of payment is at least 1.75 to 1.

The terms of the Series E Notes also permit NPC to make payments to SPR in
an aggregate amount not to exceed $15 million from the date of the
issuance of the Series E Notes. In addition, NPC may make payments to SPR
in excess of the amounts described above so long as, at the time of
payment and after giving effect to the payment:

- there are no defaults or events of default with respect to the Series E
Notes,

- NPC has a ratio of consolidated cash flow to fixed charges for NPC's
most recently ended four full fiscal quarters immediately preceding the
payment date of at least 2.0 to 1, and

- the total amount of such dividends is less than:

- the sum of 50% of NPC's consolidated net income measured on a
quarterly basis cumulative of all quarters from the date of issuance
of the Series E Notes, plus

- 100% of NPC's aggregate net cash proceeds from contributions to its
common equity capital or the issuance or sale of certain equity or
convertible debt securities of NPC, plus

- the lesser of cash return of capital or the initial amount of certain
restricted investments, plus

- the fair market value of NPC's investment in certain subsidiaries.

If NPC's Series E Notes are upgraded to investment grade by both Moody's
Investors Service, Inc. (Moody's) and Standard & Poor's Rating Group, Inc.
(S&P), these restrictions will be suspended and will no longer be in
effect so long as the Series E Notes remain investment grade.

- On October 29, 2002, NPC established an accounts receivables purchase
facility, which expires on October 28, 2003. The agreements relating to
the receivables purchase facility contain various covenants, including a
limitation on payments in respect of common stock by NPC to SPR that is
identical to the limitation contained in NPC's General and Refunding
Mortgage Notes, Series E, described above.

- NPC's $60 million Credit Agreement dated June 30, 2003, which expires no
later than September 8, 2003, prohibits payments to SPR in respect of
NPC's common stock.

- The PUCN issued a Compliance Order, Docket No. 02-4037, on June 19, 2002,
relating to NPC's request for authority to issue long-term debt. The PUCN
order requires that, until such time as the order's authorization expires
(December 31, 2003), NPC must either receive the prior approval of the
PUCN or reach an equity ratio of 42% before paying any dividends to SPR.
If NPC achieves a 42% equity ratio prior to December 31, 2003, the
dividend restriction ceases to have effect. As of June 30, 2003, NPC's
equity ratio was 35.3%. Prior to the expiration date of the Compliance
Order, management may seek PUCN approval for a payment of dividends by
NPC or may seek a waiver from the PUCN of the dividend restriction.

52

- The terms of NPC's preferred trust securities provide that no dividends
may be paid on NPC's common stock if NPC has elected to defer payments on
the junior subordinated debentures issued in conjunction with the
preferred trust securities. At this time, NPC has not elected to defer
payments on the junior subordinated debentures.

- SPPC's Term Loan Agreement dated October 30, 2002, as amended, which
expires October 31, 2005, limits the amount of payments that SPPC may pay
to SPR. However, that limitation does not apply to payments by SPPC to
enable SPR to pay its reasonable fees and expenses (including, but not
limited to, interest on SPR's indebtedness and payment obligations on
account of SPR's PIES) provided that those payments do not exceed $90
million, $80 million and $60 million in the aggregate for the twelve
month periods ending on October 30, 2003, 2004 and 2005, respectively.
The Term Loan Agreement also permits SPPC to make payments to SPR in an
aggregate amount not to exceed $10 million during the term of the Term
Loan Agreement. In addition, SPPC may make payments to SPR in excess of
the amounts described above so long as, at the time of the payment and
after giving effect to the payment, there are no defaults or events of
default under the Term Loan Agreement, and such amounts, when aggregated
with the amount of payments to SPR by SPPC since the date of execution of
the Term Loan Agreement, do not exceed the sum of:

- 50% of SPPC's Consolidated Net Income for the period commencing January
1, 2003 and ending with last day of fiscal quarter most recently
completed prior to the date of the contemplated dividend payment, plus

- the aggregate amount of cash received by SPPC from SPR as equity
contributions on its common stock during such period.

- On October 29, 2002, SPPC established an accounts receivables purchase
facility, which expires on October 28, 2003. The agreements relating to
the receivables purchase facility contain various covenants, including a
limitation on the payment of dividends by SPPC to SPR that is identical
to the limitation contained in SPPC's Term Loan Agreement, described
above.

- SPPC's Articles of Incorporation contain restrictions on the payment of
dividends on SPPC's common stock in the event of a default in the payment
of dividends on SPPC's preferred stock. SPPC's Articles also prohibit
SPPC from declaring or paying any dividends on any shares of common stock
(other than dividends payable in shares of common stock), or making any
other distribution on any shares of common stock or any expenditures for
the purchase, redemption or other retirement for a consideration of
shares of common stock (other than in exchange for or from the proceeds
of the sale of common stock) except from the net income of SPPC, and its
predecessor, available for dividends on common stock accumulated
subsequent to December 31, 1955, less preferred stock dividends, plus the
sum of $500,000. At the present time, SPPC believes that these
restrictions do not materially limit its ability to pay dividends and/or
to purchase or redeem shares of its common stock.

- The Utilities are subject to the provision of the Federal Power Act that
states that dividends cannot be paid out of funds that are properly
included in capital accounts. Although the meaning of this provision is
unclear, it could be interpreted to impose an additional material
limitation on a utility's ability to pay dividends in the absence of
retained earnings.

EFFECTS OF 2002 RATE CASE DECISIONS

On March 29 and April 1, 2002, S&P and Moody's lowered the unsecured debt
ratings of SPR, NPC and SPPC to below investment grade in response to the
decision of the PUCN with respect to NPC's rate cases. On April 23 and 24, 2002,
the unsecured debt ratings of SPR and the Utilities were further downgraded by
both rating agencies, and the Utilities' secured debt ratings were downgraded to
below investment grade. The downgrades affected SPR's, NPC's and SPPC's
liquidity primarily in two principal areas: (1) their respective financing
arrangements, and (2) NPC's and SPPC's contracts for fuel, for purchase and sale
of electricity and for transportation of natural gas.

53

For more detailed discussion of these effects, please see SPR's, NPC's and
SPPC's Annual Reports on Form 10-K for the year ended December 31, 2002.

ACCOUNTS RECEIVABLE FACILITIES

On October 29, 2002, NPC and SPPC established accounts receivable purchase
facilities of up to $125 million and $75 million, respectively, which expire on
October 28, 2003. Currently, NPC and SPPC intend to negotiate extensions of
their respective receivables purchase facilities. If NPC and/or SPPC elect to
activate their receivables purchase facilities, they will sell all of their
accounts receivable generated from the sale of electricity and natural gas to
customers to their newly created bankruptcy-remote special purpose subsidiaries.
The receivables sales will be without recourse except for breaches of customary
representations and warranties made at the time of sale. The subsidiaries will,
in turn, sell these receivables to a bankruptcy-remote subsidiary of SPR. SPR's
subsidiary will issue variable rate revolving notes backed by the purchased
receivables.

The agreements relating to the receivables purchase facilities contain
various conditions to purchase, covenants and trigger events, and other
provisions customary in receivables transactions. In addition to customary
termination and mandatory repurchase events, each Utilities' receivables
purchase facility may terminate in the event that the Utility or SPR defaults
(i) on the payment of indebtedness, or (ii) on the payment of amounts due under
a swap agreement, and such defaults aggregate to greater than $10 million and $5
million for the Utility and SPR, respectively. Under the terms of the agreements
relating to the receivables purchase facility, each Utility's facility may not
be activated or, if activated, will be terminated in the event of a material
adverse change in the condition, operations or business prospects of the
Utility. SPR has agreed to guaranty the performance by NPC and SPPC of certain
obligations as sellers and servicers under the receivables purchase facilities.
NPC and SPPC intend to use their accounts receivables purchase facilities as
back-up liquidity facilities and do not plan to activate these facilities in the
foreseeable future.

CROSS DEFAULT PROVISIONS

Certain financing agreements of SPR and the Utilities contain cross-default
provisions that would result in an event of default under such financing
agreements if there is a failure under other financing agreements of SPR and the
Utilities to meet payment terms or to observe other covenants that would result
in an acceleration of payments due. Most of these default provisions (other than
ones relating to a failure to pay other indebtedness) provide for a cure period
of 30-60 days from the occurrence of a specified event, during which time SPR or
the Utilities may rectify or correct the situation before it becomes an event of
default. The primary cross-default provisions in SPR's and the Utilities'
various financing agreements are briefly summarized below:

- The indenture pursuant to which SPR issued its 7.25% Convertible Notes
due 2010 provides for an event of default if SPR or any of its
significant subsidiaries (NPC and SPPC) fails to pay indebtedness in
excess of $10 million or has any indebtedness of $10 million or more
accelerated and declared due and payable;

- NPC's General and Refunding Mortgage Indenture, under which NPC has $930
million of securities outstanding as of June 30, 2003, provides for an
event of default if a matured event of default under NPC's First Mortgage
Indenture occurs;

- The terms of NPC's Series E Notes provide that a default with respect to
the payment of principal, interest or premium beyond the applicable grace
period under any mortgage, indenture or other security instrument, by NPC
or any of its restricted subsidiaries, relating to debt in excess of $15
million, triggers a right of the holders of the Series E Notes to require
NPC to redeem the Series E Notes at a price equal to 100% of the
aggregate principal amount plus accrued and unpaid interest and
liquidated damages, if any, upon notice given by at least 25% of the
outstanding Series E Notes holders;

54

- NPC's receivables purchase facility may terminate in the event that
either NPC or SPR defaults (i) in the payment of indebtedness, or (ii) in
the payment of amounts due under hedge agreements, and such defaults
aggregate to greater than $10 million and $5 million for NPC and SPR,
respectively;

- NPC's $60 million Credit Agreement provides for an event of default if
(i) NPC or any of its subsidiaries default (a) in the payment of
indebtedness, or (b) in the payment of amounts due under hedge
agreements, and such defaults aggregate to greater than $20 million, or
(ii) NPC's General and Refunding Mortgage Indenture ceases to be
enforceable;

- SPPC's General and Refunding Mortgage Indenture, under which SPPC has
$499.5 million of securities outstanding as of June 30, 2003, provides
for an event of default if a matured event of default under SPPC's First
Mortgage Indenture occurs;

- SPPC's Term Loan Agreement provides for an event of default if (a) SPPC
or any of its subsidiaries default (i) in the payment of indebtedness, or
(ii) in the payment of amounts due under hedge agreements, and such
defaults aggregate to greater than $10 million, or (b) SPPC's General and
Refunding Mortgage Indenture ceases to be enforceable; and

- SPPC's receivables purchase facility may terminate in the event that
either SPPC or SPR defaults (i) in the payment of indebtedness, or (ii)
in the payment of amounts due under hedge agreements, and such defaults
aggregate to greater than $10 million and $5 million for SPPC and SPR,
respectively.

FINANCING TRANSACTIONS

In January 2003, SPR acquired $8.75 million aggregate principal amount of
its Floating Rate Notes due April 20, 2003 in exchange for approximately 1.3
million shares of its common stock, in two privately-negotiated transactions
exempt from the registration requirements of the Securities Act of 1933.

On February 5, 2003, SPR issued approximately 13.66 million shares of
common stock in exchange for a total of 2.1 million of its PIES in five
privately-negotiated transactions exempt from the registration requirements of
the Securities Act of 1933.

On February 14, 2003, SPR issued and sold $300 million of its 7.25%
Convertible Notes due 2010. Approximately $53.4 million of the net proceeds from
the sale of the notes were used to purchase U.S. government securities that were
pledged to the trustee for the first five interest payments on the notes payable
during the first two and one-half years. A portion of the remaining net proceeds
of the notes were used to repurchase approximately $58.5 million of SPR's
Floating Rate Notes due April 20, 2003. Of the remaining net proceeds,
approximately $133 million were used to repay SPR's Floating Rate Notes due
April 20, 2003, and the remaining proceeds are available for general corporate
purposes. The Convertible Notes were issued with registration rights.

The Convertible Notes will not be convertible prior to August 14, 2003. At
any time on or after August 14, 2003 through the close of business February 14,
2010, holders of the Convertible Notes may convert their notes into shares of
SPR's common stock. Until SPR has obtained shareholder approval to permit the
Convertible Notes to be fully convertible into shares of common stock, holders
of the Convertible Notes will be entitled to receive 76.7073 shares of common
stock and an amount of cash equal to the market value of 142.4564 shares of
common stock at the time of conversion, based on the average closing price of
SPR's common stock over five consecutive trading days, for each $1,000 principal
amount of notes surrendered for conversion. At an assumed five-day average
closing price of $5.00 per share (based on the last reported sale price of SPR's
common stock on August 1, 2003), the total amount of the cash payable on
conversion of the Convertible Notes would be approximately $214 million. If SPR
does not obtain shareholder approval, SPR will be required to pay the cash
portion of any Convertible Notes as to which the holders request conversion on
or after August 14, 2003. The amount of cash payable on conversion of the
Convertible Notes will increase as the average closing price of SPR's common
stock increases. Although management does not believe it is likely that a
significant amount of the Convertible
55

Notes will be converted in the foreseeable future, in the event that SPR does
not have available funds to pay the cash portion of the Convertible Notes upon
the requested conversion, SPR may have to issue additional debt or equity to
raise the necessary funds. There can be no assurance that SPR will be able to
access the capital markets to issue such additional debt and/or equity or that
it will be able to do so on terms favorable to SPR.

If SPR does obtain shareholder approval, it may elect to satisfy the cash
payment component of the conversion price of the Convertible Notes solely with
shares of common stock. SPR has agreed to use reasonable efforts to obtain
shareholder approval, not later than 180 days after the date of issuance of the
Convertible Notes, to issue and deliver shares of SPR's common stock in lieu of
the cash payment component of the conversion price of the Convertible Notes. SPR
has called a special shareholder meeting for August 11, 2003 to comply with the
terms of the Convertible Notes. For further information regarding the terms of
the Convertible Notes, see Note 4, Long-Term Debt.

The indenture under which the Convertible Notes were issued does not
contain any financial covenants or any restrictions on the payment of dividends,
the repurchase of SPR's securities or the incurrence of indebtedness. The
indenture does allow the holders of the Convertible Notes to require SPR to
repurchase all or a portion of the holders' Convertible Notes upon a change of
control. The indenture also provides for an event of default if SPR or any of
its significant subsidiaries, including NPC and SPPC, fails to pay any
indebtedness in excess of $10 million or has any indebtedness of $10 million or
more accelerated and declared due and payable.

EFFECT OF HOLDING COMPANY STRUCTURE

Currently, SPR (on a stand-alone basis) has a substantial amount of
outstanding debt and other obligations including, but not limited to: $300
million of its unsecured 8 3/4% Senior Notes due 2005; $240 million of its
unsecured 7.93% Senior Notes due 2007; and $300 million of its 7.25% Convertible
Notes due 2010.

Due to the holding company structure, SPR's right as a common shareholder
to receive assets of any of its direct or indirect subsidiaries upon a
subsidiary's liquidation or reorganization is junior to the claims against the
assets of such subsidiary by its creditors and preferred stockholders.
Therefore, SPR's debt obligations are effectively subordinated to all existing
and future claims of its subsidiaries' creditors, particularly those of NPC and
SPPC, including trade creditors, debt holders, secured creditors, taxing
authorities, guarantee holders, NPC's preferred trust security holders and
SPPC's preferred stockholders. As of June 30, 2003, NPC, SPPC and their
subsidiaries had approximately $2.89 billion of debt and other obligations
outstanding and approximately $238.9 million of outstanding preferred
securities. Although the Utilities are parties to agreements that limit the
amount of additional indebtedness they may incur, the Utilities retain the
ability to incur substantial additional indebtedness and other liabilities.

NEVADA POWER COMPANY

During the three and six months ended June 30, 2003, NPC incurred net
losses of $22.2 million and $37.4 million, respectively, and did not pay or
declare a common stock dividend to its parent, SPR. Operating results during
both periods were negatively affected by the write-off of $46 million in May
2003

56

of disallowed deferred energy costs, described below. The causes for significant
changes in specific lines comprising the results of operations for NPC are as
follows:

ELECTRIC OPERATING REVENUE

NPC retail electric revenues for the three and six months ended June 30,
2003, were slightly lower than the same periods in 2002 primarily due to lower
average retail rates in 2003. The lower rates in 2003 were due to a rate
decrease effective May 19, 2003, which was the result of NPC's Deferred Energy
Case (see Regulatory Matters -- Nevada Power Company 2002 Deferred Energy Case,
later) and higher revenues recognized in June 2002 from a one-time rate increase
of $.01 per kilowatt-hour, which allowed NPC to accelerate the recovery of its
deferred energy balance. This decrease in revenues was partially offset by an
increase in revenues due to an increase in the number of residential, commercial
and industrial customers of 7.9%, 8.6% and 10.3%, respectively.

NPC's Electric Operating Revenues - Other decreased for the three and six
months ended June 30, 2003, compared to the same periods in 2002, due to a
decrease in the volumes of wholesale electric power sold to other utilities. See
NPC's Annual Report on Form 10-K for the year ended December 31, 2002, Item 7,
Management's Discussion and Analysis of Financial Condition and Results of
Operation -- Energy Supply, for a discussion of NPC's purchased power
procurement strategies.

PURCHASED POWER

- ---------------

(1) 2002 average costs do not include contract termination costs, discussed
below

Purchased power costs were lower for the three months and six months ended
June 30, 2003, than the same period in the prior year primarily as a result of a
$229 million provision recorded in the second quarter of 2002 for terminated
purchased power contracts. See Part II, Item I -- Legal Proceedings in this

57

report and SPR's, NPC's and SPPC's Annual Reports on Form 10-K for the year
ended December 31, 2003 for a discussion of the terminated purchased power
contracts. Additionally, the decrease resulted from lower volumes purchased and
a decrease in the price of Short-Term Firm energy purchases. Finally, purchases
associated with risk management activities, which are included in Short-Term
Firm energy, decreased in 2003. Risk management activities include transactions
entered into to minimize purchased power costs. See SPR's, NPC's and SPPC's
Annual Reports on Form 10-K for the year ended December 31, 2002, Item 7,
Management's Discussion and Analysis of Financial Condition and Results of
Operation -- Energy Supply, for a discussion of NPC's purchased power
procurement.

FUEL FOR POWER GENERATION

Fuel for generation costs for the three months ended June 30, 2003 were
comparable with the same period in 2002 as decreases in the volumes generated
were substantially offset by increases in the price of coal and gas during the
second quarter of 2003. Fuel for generation costs for the six months ended June
30, 2003, were lower than the prior year due to a decrease in volumes generated
and lower fuel prices during 2003. Also, during the second quarter of 2003, Reid
Gardner generating units were down for scheduled maintenance, and Clark Stations
and Sunrise generating units were not utilized at all times because it was more
economical to purchase power than generate.

DEFERRED ENERGY COSTS

Deferred energy costs disallowed for the three and six months ended June
30, 2003, reflects the PUCN disallowance of approximately $46 million in May
2003, of deferred energy costs incurred during the twelve months ended November
2002. Deferred energy costs disallowed for the six months ended June 30, 2002,
reflects the write-off of $434 million of deferred energy costs incurred during
the seven months ended September 30, 2001, that were disallowed by the PUCN in
NPC's 2001 deferred energy rate case.

Deferred energy costs -- net increased for the three and six months ended
June 30, 2003, as a result of the amortization of prior deferred costs, pursuant
to the PUCN decisions in NPC's 2001 and 2002 deferred energy rate cases that
both resulted in increased rates. The increase for the six months ended June 30,
2003, also reflects deferrals, to the extent fuel and purchased power costs
recovered through current rates exceeded actual fuel and purchased power costs.
However, during the three months ended June 30, 2003, the increase due to
amortization of prior costs was partially offset by deferrals due to fuel and
purchase power costs exceeding the recovery of those costs through current
rates. Deferred energy costs -- net for the three and six months ended June 30,
2002, reflect the deferral in the second quarter of 2002 of approximately $229
million for contract termination costs and additional deferrals of electric
energy costs, both partially offset by the amortization of prior deferred energy
costs resulting from an increase in rates in April 2002.

58

ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFUDC)

NPC's total allowance for funds used during construction was higher for the
three-month and six-month periods ended June 30, 2003 than the comparable
periods in 2002, as a result of an increase in construction work in progress
including capital expenditures for the Centennial Project and an increase in the
AFUDC equity rate. This increase was offset in part by a decrease in the AFUDC
debt rate.

OTHER (INCOME) AND EXPENSES

Other operating expense for the three and six month periods ending June 30,
2003, was greater than the same periods during the prior year, due primarily to
increased reserves for uncollectible accounts, costs associated with increased
billing and collection efforts, higher operating costs at the Navajo and Mohave
generating facilities and the reversal of $2.7 million in costs for NPC's
short-term incentive plan in June 2002.

Maintenance costs for the three- and six-month periods ending June 30,
2003, were higher than the same periods last year due to the timing of scheduled
plant maintenance.

Depreciation and amortization was higher for the three-month period ended
June 30, 2003, compared to the same period in 2002 as a result of both an
adjustment that reduced depreciation in May 2002 and depreciation on software
placed in service in 2003. Depreciation and amortization was higher for the six-
month period ended June 30, 2003 compared to the same period in 2002 as a result
of an increase in depreciable assets, including the Centennial Project, and the
addition of new software in 2003.

NPC's income tax benefit for the three months ended June 30, 2003,
increased compared to the same period in 2002, due to a corresponding increase
in second quarter 2003 pre-tax losses. Pre-taxes losses

59

increased in the second quarter of 2003 over the same period in 2002
significantly as a result of higher operating, maintenance, depreciation and
interest expense.

NPC's income tax benefit for the six months ended June 30, 2003 decreased
compared to the same period in 2002 due to a corresponding decrease in 2003
pre-tax losses. Pre-tax losses in 2003 decreased largely as a result of the
write-off of disallowed deferred energy costs recognized in 2002. The decrease
in 2003 pre-tax losses was partially offset by the recognition of lower revenues
and higher operating, maintenance, depreciation and interest expense.

NPC's taxes other than income taxes for the three and six months ended June
30, 2003 were comparable to amounts the same periods during 2002.

Interest charges on long-term debt for the three and six-month periods
ending June 30, 2003, increased over the same period in 2002 due primarily to
the issuance in October 2002 of $250 million additional debt at an interest rate
of 10.875%. The redemption, in October 2002, of $15 million of debt slightly
offset the increase in interest during 2003 over 2002.

Interest charges -- other for the three and six-month periods ending June
30, 2003, increased over the prior year due to interest on delayed/terminated
contracts, charges related to fees associated with NPC's credit facilities and
receivables conduit and to the amortization of increased debt discount charges
related to the issuance in October 2002 of $250 million of additional debt.

Interest accrued on deferred energy costs decreased during the three months
ended June 30, 2003, compared to the same period in 2002, following lower
deferred fuel and purchased power balances during 2003. For the six months ended
June 30, 2003, the increase over the same period in 2002 compared favorably due
to the first quarter 2002 write-off of approximately $20.1 million of carrying
charges, net of taxes, on deferred energy costs that were disallowed by the PUCN
in its March 29, 2002 decision on NPC's deferred energy rate case. The 2002
write-off was partially offset by the recording of carrying charges on deferred
energy costs incurred.

Other income for the three months ended June 30, 2003, increased over the
same period in 2002 due, primarily, to an increase in gains from the disposition
of non-utility property during 2003 and income generated as a result of the
relocation of electricity lines for Clark County. Additionally, Other Income
increased for the six months ended June 30, 2003, compared to the same period in
2002, due to the recognition of income from the disposition of SO2 allowances in
2003, an increase in gains from the disposition of non-utility property in 2003
and the recognition of carrying charges related to divestiture costs, ordered by
the PUCN.

Other expense increased during the three months ended June 30, 2003,
compared to the same period in 2002 as a result of increased expenditures
related to low-income energy assistance programs, lobbying and ballot initiative
charges, and charges related to depreciation on non-utility property. Other
expense decreased during the six months ended June 30, 2003, compared to the
same period in 2002 due, primarily to the 2002 write-off of $5.0 million
relating to the disposition of SO2 allowances as ordered by the PUCN. The
decrease in expense relating to the SO2 allowances was offset partially by
increases in charges related to low-income energy assistance programs, lobbying
and ballot initiative charges, and depreciation on non-utility property.

NPC's income taxes -- other income and expense for the three months ended
June 30, 2003, decreased compared to the same period in 2002, due to a
corresponding decrease in second quarter pre-tax losses on other income.

NPC's income taxes -- other income and expense changed from a tax benefit
for the six months ended June 30, 2002, to a tax expense for the same period in
2003. This change was primarily a result of the write-off of disallowed interest
charges on deferred energy costs in 2002.

60

ANALYSIS OF CASH FLOWS

NPC's cash flows were less during the six-months ended June 30, 2003,
compared to the same period in 2002, resulting primarily from decreases in cash
flows from operating and financing activities. The decrease in cash from
operating activities was substantially as a result of the prepayment of fuel and
power purchases during 2003 and the receipt of an income tax refund in 2002
both, partially offset, by the collection in 2003 of previously deferred energy
costs as a result of a rate increase that began April 1, 2002. The decrease
operating cash flow was partially offset by the collection of previously
deferred energy costs due to the PUCN decision in NPC's 2001 deferred energy
rate case, that resulted in increased rates beginning April 1, 2002. Cash flows
from financing activities were lower in 2003 because of cash provided by
short-term borrowings during 2002. NPC also utilized additional cash for
financing activities in 2003 for the Centennial Plan and other construction
projects.

LIQUIDITY AND CAPITAL RESOURCES

NPC had cash and cash equivalents of approximately $21.1 million at June
30, 2003. At July 31, 2003, NPC had cash balances of approximately $35.7
million.

Due to NPC's weakened financial condition and, in certain instances, the
weakened financial condition of NPC's power suppliers, NPC has been required to
pre-pay its power purchases or make more frequent payments on its power
deliveries. As a result of unseasonably cool weather during the spring of 2003
and its prepayment and more frequent payment obligations for its summer 2003
power requirements, NPC's liquidity was significantly constrained during the
early summer months of 2003. If NPC does not have sufficient liquidity to meet
its power requirements, particularly at the onset of future summer seasons, NPC
may be required to issue or incur additional indebtedness. If NPC is unable to
issue or incur such indebtedness, whether due to lack of access to the capital
markets, lack of regulatory authority to issue or incur such debt, or
restrictive covenants in certain of its financing agreements (see below), its
ability to provide power and its financial condition will be adversely affected.

NPC's liquidity would be significantly affected by an adverse decision in
the lawsuit by Enron, or by unfavorable rulings by the PUCN in future NPC rate
cases. S&P and Moody's have NPC's credit ratings on "negative outlook" and
"stable," respectively. Future downgrades by either S&P or Moody's could
preclude or reduce NPC's access to the capital markets, and could adversely
affect NPC's ability to continue to purchase power and fuel. Adverse
developments with respect to any one or a combination of the foregoing could
have a material adverse effect on NPC's financial condition and liquidity, and
could make it difficult for NPC to continue to operate outside of bankruptcy.

EFFECT OF 2002 RATE CASE DECISIONS

On March 29 and April 1, 2002, following the decision by the PUCN in NPC's
deferred energy rate case, S&P and Moody's lowered NPC's unsecured debt ratings
to below investment grade. On April 23 and 24, 2002, NPC's unsecured debt
ratings were further downgraded and its secured debt ratings were downgraded to
below investment grade. As a result of these downgrades, NPC's ability to access
the capital markets to raise funds was severely limited. Since SPR's credit
ratings were similarly downgraded, SPR's ability to make capital contributions
to NPC also became severely limited.

For more detailed discussion of these effects, please see SPR's, NPC's and
SPPC's Annual Reports on Form 10-K for the year ended December 31, 2002.

CREDIT FACILITY

On June 30, 2003, NPC entered into a $60 million revolving Credit Agreement
to provide additional liquidity to NPC for its summer 2003 power purchases. As
of July 31, 2003, NPC had borrowed $20 million under the credit facility.

NPC's Credit Agreement prohibits payments to SPR in respect of NPC's common
stock and provides that NPC's ratio of consolidated total debt to consolidated
total capitalization may not exceed .65 to 1.00.
61

The Credit Facility, which is secured by NPC's $60 million Series F General and
Refunding Mortgage Bond, will expire no later than September 8, 2003.

ACCOUNTS RECEIVABLE FACILITY

On October 29, 2002, NPC established an accounts receivable purchase
facility of up to $125 million. The receivables purchase facility expires on
October 28, 2003. Currently, NPC intends to negotiate an extension of this
facility. If NPC elects to activate the receivables purchase facility, NPC will
sell all of its accounts receivable generated from the sale of electricity to
customers to its newly created bankruptcy remote special purpose subsidiary. The
receivables sales will be without recourse except for breaches of customary
representations and warranties made at the time of sale. The subsidiary will, in
turn, sell these receivables to a bankruptcy-remote subsidiary of SPR. SPR's
subsidiary will issue variable rate revolving notes backed by the purchased
receivables.

The agreements relating to the receivables purchase facility contain
various conditions to purchase, covenants and trigger events, and other
provisions customary in receivables transactions. In addition to customary
termination and mandatory repurchase events, the receivables purchase facility
may terminate in the event that either NPC or SPR defaults (i) in the payment of
indebtedness, or (ii) in the payment of amounts due under a swap agreement, and
such defaults aggregate to greater than $10 million and $5 million for NPC and
SPR, respectively. Under the terms of the agreements relating to the receivables
purchase facility, NPC's facility may not be activated or, if activated, will be
terminated in the event of a material adverse change in the condition,
operations or business prospects of NPC. In addition, the agreements contain a
limitation on the payment of dividends by NPC to SPR that is identical to the
limitation contained in NPC's General and Refunding Mortgage Notes, Series E,
described below. SPR has agreed to guaranty NPC's performance of certain
obligations as a seller and servicer under the receivables purchase facility.

NPC has agreed to issue $125 million principal amount of its General and
Refunding Mortgage Bonds upon activation of the receivables purchase facility.
The full principal amount of the bond would secure certain of NPC's obligations
as seller and servicer, plus certain interest, fees and expenses thereon to the
extent not paid when due, regardless of the actual amounts owing with respect to
the secured obligations. As a result, in the event of an NPC bankruptcy or
liquidation, the holder of the bond securing the receivables purchase facility
may recover more on a pro rata basis than the holders of other General and
Refunding Mortgage securities, who could recover less on a pro rata basis than
they otherwise would recover. However, in no event will the holder of the bond
recover more than the amount of obligations secured by the bond.

NPC intends to use the accounts receivable purchase facility as a back-up
liquidity facility and does not plan to activate this facility in the
foreseeable future. NPC may activate the facility within five days upon the
delivery of certain customary funding documentation and the delivery of the $125
million General and Refunding Mortgage Bond.

MORTGAGE INDENTURES

NPC's first mortgage indenture creates a first priority lien on
substantially all of NPC's properties. As of June 30, 2003, $372.5 million of
NPC's first mortgage bonds were outstanding. NPC agreed in connection with its
Series E Notes that it would not issue any more first mortgage bonds.

NPC's General and Refunding Mortgage Indenture creates a lien on
substantially all of NPC's properties in Nevada that is junior to the lien of
the first mortgage indenture. As of June 30, 2003, $930 million of NPC's General
and Refunding Mortgage securities were outstanding. Additional securities may be
issued under the General and Refunding Mortgage Indenture on the basis of (i)
70% of net utility property additions, (ii) the principal amount of retired
General and Refunding Mortgage Bonds, and/or (iii) the principal amount of first
mortgage bonds retired after October 19, 2001. On the basis of (i), (ii) and
(iii) above, as of June 30, 2003, NPC had the capacity to issue approximately
$1.017 billion of additional General and Refunding Mortgage securities. Although
NPC has substantial capacity to issue
62

additional General and Refunding securities on the basis of property additions
and retired securities, the financial covenants contained in the Series E Notes,
Receivables Purchase Facility Agreements and NPC's $60 million Credit Agreement
limit the amount of additional indebtedness that NPC may issue and the reasons
for which such indebtedness may be issued. NPC has reserved $125 million of
General and Refunding Mortgage bonds for issuance upon the initial funding of
NPC's receivables facility.

NPC also has the ability to release property from the liens of the two
mortgage indentures on the basis of net property additions, cash and/or retired
bonds. To the extent NPC releases property from the lien of its General and
Refunding Mortgage Indenture, it will reduce the amount of bonds issuable under
that indenture.

CROSS DEFAULT PROVISIONS

Certain financing agreements of NPC contain cross-default provisions that
would result in an event of default under such financing agreements if there is
a failure under other financing agreements of NPC and SPR to meet payment terms
or to observe other covenants that would result in an acceleration of payments
due. Most of these default provisions (other than ones relating to a failure to
pay other indebtedness) provide for a cure period of 30-60 days from the
occurrence of a specified event during which time, NPC or SPR may rectify or
correct the situation before it becomes an event of default. The primary
cross-default provisions in NPC's various financing agreements are briefly
summarized below:

- NPC's General and Refunding Mortgage Indenture, under which NPC has $930
million of securities outstanding as of June 30, 2003, provides for an
event of default if a matured event of default under NPC's First Mortgage
Indenture occurs;

- The terms of NPC's Series E Notes provide that a default with respect to
the payment of principal, interest or premium beyond the applicable grace
period under any mortgage, indenture or other security instrument, by NPC
or any of its restricted subsidiaries, relating to debt in excess of $15
million, triggers a right of the holders of the Series E Notes to require
NPC to redeem the Series E Notes at a price equal to 100% of the
aggregate principal amount plus accrued and unpaid interest and
liquidated damages, if any, upon notice given by at least 25% of the
outstanding Series E Notes holders;

- NPC's receivables purchase facility may terminate in the event that
either NPC or SPR defaults (i) in the payment of indebtedness, or (ii) in
the payment of amounts due under hedge agreements, and such defaults
aggregate to greater than $10 million and $5 million for NPC and SPR,
respectively; and

- NPC's $60 million Credit Agreement provides for an event of default if
(i) NPC or any of its subsidiaries default (a) in the payment of
indebtedness, or (b) in the payment of amounts due under hedge
agreements, and such defaults aggregate to greater than $20 million, or
(ii) NPC's General and Refunding Mortgage Indenture ceases to be
enforceable.

LIMITATIONS ON INDEBTEDNESS

The terms of NPC's Series E Notes, which mature in 2009, restrict NPC from
incurring any additional indebtedness unless (i) at the time the debt is
incurred, the ratio of consolidated cash flow to fixed charges for NPC's most
recently ended four quarter period on a pro forma basis is at least 2 to 1, or
(ii) the debt incurred is specifically permitted, which includes limited amounts
of debt with respect to certain credit facility or letter of credit
indebtedness, obligations incurred to finance property construction or
improvement, indebtedness incurred to refinance existing indebtedness
(including, but not limited to, NPC's $210 million unsecured 6% Notes due
September 15, 2003 and $140 million General and Refunding Mortgage Notes,
Floating Rate, due October 15, 2003), certain intercompany indebtedness, hedging
obligations, indebtedness incurred to support bid, performance or surety bonds,
and certain letters of credit issued to support NPC's obligations with respect
to energy suppliers. At June 30, 2003, NPC met the fixed charge ratio test set
forth in (i) above. If NPC's Series E Notes are upgraded to investment

63

grade by both Moody's and S&P, certain restrictions on indebtedness applicable
to the Series E Notes will be suspended and will no longer be in effect so long
as the Series E Notes remain investment grade.

The terms of NPC's $60 million Credit Facility, which expires no later than
September 8, 2003, restrict NPC from issuing additional indebtedness unless the
debt issued is specifically permitted, which includes limited amounts of debt
with respect to certain letter of credit indebtedness, indebtedness incurred to
refinance existing indebtedness (including NPC's $210 million unsecured 6% Notes
due September 15, 2003 and $140 million General and Refunding Mortgage Notes,
Floating Rate, due October 15, 2003), certain intercompany indebtedness and
certain letters of credit issued to support NPC's obligations with respect to
energy suppliers.

If NPC is unable to access the capital markets to issue additional
indebtedness to support its operations, including the purchase of fuel and
power, and to refinance its existing indebtedness, whether due to lack of access
to the capital markets, lack of regulatory authority, or restrictive covenants
in its financing agreements, its ability to provide power and its financial
condition will be adversely affected. In addition, if NPC's proposed 2003
Resource Plan is approved by the PUCN, NPC may need to expend up to
approximately $500 million prior to the summer of 2007 for the construction
and/or acquisition of generation facilities. If NPC is unable to provide this
amount with internally generated funds, it may need to access the capital
markets to do so. There can be no assurances that NPC could access the capital
markets to issue additional indebtedness to finance the construction and/or
acquisition of generation facilities or that NPC will have capacity under the
debt covenants of its financing agreements to issue such additional
indebtedness.

SIERRA PACIFIC POWER COMPANY

During the three months and six months ended June 30, 2003, SPPC incurred
net losses of $28.9 million and $25.9 million, respectively. Operating results
during both periods were negatively affected by a write-off of $45 million in
June 2003 of disallowed deferred energy costs (see later discussion). During the
same period, SPPC paid $1.95 million in dividends to holders of its preferred
stock, but did not declare nor pay dividends on its common stock, all of which
is held by its parent, SPR.

The components of SPPC's gross margin are set forth below (dollars in
thousands):

64

The causes for significant changes in specific lines comprising the results
of operations for SPPC are as follows:

ELECTRIC OPERATING REVENUES

SPPC's retail electric revenues for the three- and six-month periods ended
June 30, 2003, were higher than the same periods in the prior year. This
increase was primarily due to a rate increase effective June 1, 2002.

Other electric operating revenues decreased for the three- and six-month
periods ended June 30, 2003, compared to the same periods in 2002 due to a
decrease in wholesale sales to other utilities. See SPPC's Annual Report on Form
10-K for the year ended December 31, 2002, Item 7, Management's Discussion and
Analysis of Financial Condition and Results of Operation, Energy Supply, for a
discussion of SPPC's purchased power procurement strategies.

GAS OPERATING REVENUES

65

Residential gas revenues for the three-months and six-months ended June 30,
2003 were slightly higher and approximately the same, respectively, when
compared to the same periods in 2002, due to cooler than normal weather in April
2003 than in April 2002. Revenues during both the three- and six-months ended
June 30, 2003, were also affected by a rate decrease effective December 26,
2002, which was the result of the outcome of the Company's purchased gas
adjustment clause case.

Commercial gas revenues for the three-months ended June 30, 2003, were
higher than the same period in 2002 because the 2002 revenues reflect a timing
difference associated with the revenues billed in the first quarter of 2002.

Industrial revenues for both the three and six-months ended June 30, 2003,
were lower than the same periods in 2002 because some of SPPC's industrial
customers switched to SPPC's gas transportation tariff which gave those
customers the ability to procure their gas commodity from a source other than
SPPC.

Wholesale revenues for both periods in 2003 were higher than the same
periods in 2002 primarily due to the utilization of idle gas transportation
capacity to move gas from Canada to California for resale.

PURCHASED POWER

- ---------------

(1) 2002 average cost does not include contract termination costs, discussed
below

Purchased power costs were lower for the three months and six-months ended
June 30, 2003, than the prior year primarily as a result of an $86.8 million
provision recorded in the second quarter of 2002 for terminated purchased power
contracts. See Part II, Item I -- Legal Proceedings in this report and SPR's,
NPC's and SPPC's Annual Reports on Form 10-K for the year ended December 31,
2003 for a discussion of the terminated purchased power contracts. In addition,
the majority of SPPC's total energy requirements were satisfied by Short-Term
Firm power purchases for which costs have decreased as compared to a year ago.
In addition, volumes of and prices for SPPC's risk management activities have
decreased. Risk management activities include transactions entered into to
minimize purchased power costs. See SPPC's Annual Report on Form 10-K for the
year ended December 31, 2002, Item 7, Management's Discussion and Analysis of
Financial Condition and Results of Operation, Energy Supply, for a discussion of
SPPC's purchased power procurement strategies.

FUEL FOR POWER GENERATION

Fuel for power generation costs for the three and six month periods ended
June 30, 2003 were higher than the same periods in the prior year as natural gas
prices increased significantly. Partially offsetting this increase was a
reduction in volume. The volume reductions are primarily attributed to the Valmy

66

Generating Units being down due to both scheduled and unscheduled maintenances
in 2003, which necessitated additional power purchases.

GAS PURCHASED FOR RESALE

Gas purchased for resale increased significantly for the three and six
month periods ended June 30, 2003, due to an increase in wholesale activity,
which more than offset decreases in gas prices experienced during the six months
ended June 30, 2003. Gas price decreases for the six months ended June 30, 2003,
were primarily as a result of credits received on terminated gas contracts
during the first quarter of 2003.

DEFERRED ENERGY COSTS

Deferred energy costs disallowed for the three and six months ended June
30, 2003, reflects a disallowance, effective June 1, 2003, of $45 million
pursuant to a stipulation approved by the PUCN. Deferral of energy costs -- net
for the three- and six-month periods ended June 30, 2002, reflects the write-off
of $53 million of electric deferred energy costs incurred in the nine months
ended November 30, 2001, and were disallowed by the PUCN in their May 28, 2002,
decision.

The increase in Deferred energy costs -- electric -- net for the three and
six month periods ended June 30, 2003, reflects the amortization of prior
deferred costs pursuant to the PUCN decisions in SPPC's 2001 deferred energy
rate case, which resulted in increased rates beginning June 1, 2002. The
increase for both the three and six month periods, is offset partially by
current year deferrals of electric energy costs, to the extent fuel and
purchased power costs exceeded the recovery of those costs through current rates
during those periods. Deferral of energy costs -- net for the three- and
six-month periods ended June 30, 2002, reflected the deferral in the second
quarter of 2002 of approximately $82 million for contract termination costs. For
the three months ended June 30, 2002, this deferral of contract termination
costs was offset, in part, by the recording of additional energy expense.
Pursuant to the PUCN's decision on SPPC's deferred energy rate case, rates were
increased beginning June 1, 2002, resulting in the amortization of prior
deferred costs. For the six months ended June 30, 2002, SPPC recorded deferrals
of electric energy costs, reflecting the extent to which actual fuel and
purchased power costs exceeded the fuel and purchased power costs recovered
through current rates.

SPPC's Deferred energy costs -- gas -- net, for the three and six months
ended June 30, 2003, reflects the amortization of prior deferred costs due to
the PUCN authorized recovery of those costs. The increase in 2003 for the six
months also includes additional expense to the extent natural gas costs
recovered through current rates exceeded actual natural gas costs.

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ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFUDC)

Total allowance for funds used during construction increased for the
three-month and six-month periods ended June 30, 2003, compared to the same
periods in the prior year due to increases in construction work in progress and
an increase in the AFUDC Rate.

OTHER (INCOME) AND EXPENSES

Other operating expense for the three and six month periods ending June 30,
2003, were greater than the prior year periods due to the absence in 2003 of
credits associated with the discontinuation of billing services for Truckee
Meadows Water Authority, costs associated with increased billing and collection
efforts, higher employee labor overhead costs and the reversal of a $2.6 million
accrual for SPPC's short-term incentive plan in June 2002.

Maintenance costs for the three- and six-month periods ending June 30, 2003
were higher than the same period last year due to additional maintenance costs
at Valmy generating facilities.

Depreciation and amortization decreased for the three-month period ended
June 30, 2003, compared to the same period in 2002 as a result of a PUCN order
in 2002 that increased depreciation rates through May 2002. This decrease was
offset, in part, by an increase in depreciable assets in 2003. Depreciation and
amortization increased for the six-month period ended June 30, 2003, compared to
the same period in 2002 as a result of an increase in depreciable assets in
2003.

SPPC's income tax benefit for the three and six months ended June 30, 2003
were comparable to the amounts recognized during the same periods in 2002. The
changes result from changes in pretax book losses.

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Taxes other than income taxes for the three and six months ended June 30,
2003, were comparable to the amounts recognized during the same periods in 2002.

Interest charges on long-term debt for the three and six-month periods
ending June 30, 2003, increased over the comparable periods in 2002 due,
primarily, to the issuance in October 2002 of $100 million of additional debt at
an interest rate of 10.5%.

Interest charges -- other for the three months ended June 30, 2003
decreased, compared to the same period, 2002, due to the absence of associated
short-term debt during the current period, compared to the same period, 2002.
During the six-month period ending June 30, 2003, other interest charges
increased over the prior year period due to interest on delayed/terminated
contracts, charges related to fees associated with SPPC's credit facilities and
receivables conduit, and to the increase of amortization resulting from
increased debt discount charges related to the issuance, in October 2002 of $100
million of additional debt.

Interest accrued on deferred energy costs increased for the three-month
period ending June 30, 2003, compared to the same period, 2002, due to the
write-off, during the comparable period in 2002, of approximately $2 million of
carrying charges, net of taxes, that were disallowed by the PUCN in its May 28,
2002 decision on SPPC's deferred energy rate case. For the six months ended June
30, 2003, compared to the same period, 2002, the decrease in these charges
resulted from lower deferred fuel and purchased power balances during 2003.

Other income for the three and six months ended June 30, 2003, decreased
compared to the same periods in the prior year due primarily to a decrease in
interest income and subsidiary earnings, partially offset by increases in lease
revenues and miscellaneous non-operating income.

Other expense for the three and six months ended June 30, 2003, decreased
compared to the prior year periods due primarily to the recognition in 2002 of
miscellaneous charges related to SPPC's sale of its water division. The decrease
in 2003 was partially offset by higher charges related to corporate advertising
during 2003.

Income taxes -- other income and expense changed from an income tax benefit
in the second quarter of 2002 to an income tax expense in the second quarter of
2003. This change is due to SPPC's pretax loss on other income for the quarter
ended June 30, 2002 and pretax income on other income for the quarter ended June
30, 2003. Income taxes -- other income and expense for the six months ended June
30, 2003 decreased over the prior year proportionate to the decrease experienced
in the pretax other income.

ANALYSIS OF CASH FLOWS

SPPC's cash flows were less during the six-months ended June 30, 2003,
compared to the same period in 2002, resulting primarily from decreases in cash
flows from financing and investing activities, minimally offset by a slight
increase in cash flows from operating activities. Cash flows from financing
activities were lower primarily as a result of the cash provided in 2002 from
short-term borrowings, offset partially by no common dividend payments to SPR
during 2003. Cash flows from investing activities decreased in 2003 because of
additional cash requirements for construction activity during 2003. Cash flows
from operating activities increased slightly over 2002 as the collection of
previously deferred energy costs during 2003 that was substantially offset by
the prepayment of fuel and energy purchases during 2003 and the receipt of an
income tax refund in 2002.

LIQUIDITY AND CAPITAL RESOURCES

SPPC had cash and cash equivalents of approximately $86.5 million at June
30, 2003. At July 31, 2003, SPPC had cash balances of approximately $75.6
million.

Due to SPPC's weakened financial condition and, in certain instances, the
weakened financial condition of SPPC's power suppliers, SPPC has been required
to pre-pay its power purchases or make more frequent payments on its power
deliveries. If SPPC does not have sufficient liquidity to meet its

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power requirements, SPPC may be required to issue additional indebtedness. If
SPPC is unable to issue such indebtedness, whether due to lack of access to the
capital markets, lack of regulatory authority to issue such debt, or restrictive
covenants in its Term Loan Agreement (see below), its ability to provide power
and its financial condition will be adversely affected.

SPPC's future liquidity could be significantly affected by unfavorable
rulings by the PUCN in future SPPC or NPC rate cases. S&P and Moody's have
SPPC's credit ratings on "negative outlook" and "stable", respectively. Future
downgrades by either S&P or Moody's could preclude or reduce SPPC's access to
the capital markets and could adversely affect SPPC's ability to continue
purchasing power and fuel. Adverse developments with respect to any one or a
combination of the factors and contingencies set forth above could have a
material adverse effect on SPPC's financial condition and liquidity, and could
make it difficult to continue to operate outside of bankruptcy.

EFFECT OF 2002 RATE CASE DECISIONS

On March 29 and April 1, 2002, following the decision by the PUCN in NPC's
deferred energy rate case, S&P and Moody's lowered SPPC's unsecured debt ratings
to below investment grade. On April 23 and 24, 2002, SPPC's unsecured debt
ratings were further downgraded and its secured debt ratings were downgraded to
below investment grade. The decision of the PUCN on May 29, 2002, on SPPC's
deferred energy application to disallow $53 million of deferred purchased fuel
and power costs accumulated between March 1, 2001 and November 30, 2001, did not
result in any further downgrades of SPPC's securities. As a result of the
downgrades, SPPC's ability to access the capital markets to raise funds is
severely limited. Since SPR's credit ratings were similarly downgraded, SPR's
ability to make capital contributions to SPPC also became severely limited.

For more detailed discussion of these effects please see SPR's, NPC's and
SPPC's Annual Reports on Form 10-K for the year ended December 31, 2002.

ACCOUNTS RECEIVABLE FACILITY

On October 29, 2002, SPPC established an accounts receivable purchase
facility of up to $75 million. The receivables purchase facility expires on
October 28, 2003. Currently, SPPC intends to negotiate an extension of this
facility. If SPPC elects to activate the receivables purchase facility, SPPC
will sell all of its accounts receivable generated from the sale of electricity
and natural gas to customers to its newly created bankruptcy remote special
purpose subsidiary. The receivables sales will be without recourse except for
breaches of customary representations and warranties made at the time of sale.
The subsidiary will, in turn, sell these receivables to a bankruptcy-remote
subsidiary of SPR. SPR's subsidiary will issue variable rate revolving notes
backed by the purchased receivables.

The agreements relating to the receivables purchase facility contain
various conditions to purchase, covenants and trigger events, and other
provisions customary in receivables transactions. In additional to customary
termination and mandatory repurchase events, the receivables purchase facility
may terminate in the event that either SPPC or SPR defaults (1) on the payment
of indebtedness, or (2) on the payment of amounts due under a swap agreement,
and such defaults aggregate to greater than $10 million and $5 million for SPPC
and SPR, respectively. Under the terms of the agreements relating to the
receivables purchase facility, SPPC's facility may not be activated or, if
activated, will be terminated in the event of a material adverse change in the
condition, operations or business prospects of SPPC. In addition, the agreements
contain a limitation on the payment of dividends by SPPC to SPR that is
identical to the limitation contained in SPPC's Term Loan Agreement, described
below. SPR has agreed to guaranty SPPC's performance of certain obligations as a
seller and servicer under the receivables purchase facility.

SPPC has agreed to issue $75 million principal amount of its General and
Refunding Mortgage Bonds upon activation of the receivables purchase facility.
The full principal amount of the bond would secure certain of SPPC's obligations
as seller and servicer, plus certain interest, fees and expenses thereon to the
extent not paid when due, regardless of the actual amounts owing with respect to
the secured obligations.
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As a result, in the event of a SPPC bankruptcy or liquidation, the holder of the
bond securing the receivables purchase facility may recover more on a pro rata
basis than the holders of other General and Refunding Mortgage securities, who
could recover less on a pro rata basis than they otherwise would recover.
However, in no event will the holder of the bond recover more than the amount of
obligations secured by the bond.

SPPC intends to use the accounts receivable purchase facility as a back-up
liquidity facility and does not plan to activate this facility in the
foreseeable future. SPPC may activate the facility within five days upon the
delivery of certain customary funding documentation and the delivery of the $75
million General and Refunding Mortgage Bond.

MORTGAGE INDENTURES

SPPC's First Mortgage Indenture creates a first priority lien on
substantially all of SPPC's properties in Nevada and California. As of June 30,
2003, $505.3 million of SPPC's first mortgage bonds were outstanding. SPPC
agreed in its General and Refunding Mortgage Indenture that it would not issue
any additional first mortgage bonds.

SPPC's General and Refunding Mortgage Indenture creates a lien on
substantially all of SPPC's properties in Nevada that is junior to the lien of
the first mortgage indenture. As of June 30, 2003, $499.5 million of SPPC's
General and Refunding Mortgage bonds were outstanding. Additional securities may
be issued under the General and Refunding Mortgage Indenture on the basis of (i)
70% of net utility property additions, (ii) the principal amount of retired
General and Refunding Mortgage bonds, and/or (iii) the principal amount of first
mortgage bonds retired after April 8, 2002. On the basis of (i), (ii) and (iii)
above, as of June 30, 2003, SPPC had the capacity to issue approximately $364.9
million of additional General and Refunding Mortgage securities. Although SPPC
has substantial capacity to issue additional General and Refunding Mortgage
securities on the basis of property additions and retired securities, the
financial covenants contained in SPPC's Term Loan Agreement and Receivable
Purchase Facility Agreements limit the amount of additional indebtedness that
SPPC may issue and the reasons for which such indebtedness may be issued. SPPC
has reserved $75 million of General and Refunding Mortgage Bonds for issuance
upon the initial funding of its receivables purchase facility.

SPPC also has the ability to release property from the liens of the two
mortgage indentures on the basis of net property additions, cash and/or retired
bonds. To the extent SPPC releases property from the lien of its General and
Refunding Mortgage Indenture, it will reduce the amount of bonds issuable under
that indenture.

FINANCING TRANSACTIONS AND COVENANTS

On May 1, 2003, SPPC's $80 million Washoe County, Nevada, Water Facilities
Refunding Revenue Bonds, Series 2001, were successfully remarketed. The interest
rate on the bonds was adjusted from their prior two-year 5.75% term rate to a
7.50% term rate for the period of May 1, 2003 to and including May 3, 2004. The
bonds will be subject to remarketing on May 3, 2004. In the event that the bonds
cannot be successfully remarketed on that date, SPPC will be required to
purchase the outstanding bonds at a price of 100% of principal amount, plus
accrued interest. From May 1, 2003 to and including May 3, 2004, SPPC's payment
and purchase obligations in respect of the bonds are secured by SPPC's $80
million General and Refunding Mortgage Note, Series D, due 2004.

SPPC's $100 million Term Loan Agreement, entered into on October 30, 2002,
as amended on June 27, 2003, contains two financial maintenance covenants. The
first requires that SPPC maintain a ratio of consolidated total debt to
consolidated total capitalization at all times during each of the following
quarters in an amount not to exceed (i) .650 to 1.0 for the fiscal quarters
ended December 31, 2002 through December 31, 2003, (ii) .625 to 1.0 for the
fiscal quarters ended March 31, 2004 through December 31, 2004, and (iii) .600
to 1.0 for the fiscal quarter ended March 31, 2005 and for each fiscal quarter
thereafter. The second covenant requires that SPPC maintain a consolidated
interest coverage ratio for the four consecutive fiscal quarters ending with
each of the following fiscal quarters of not less than
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(i) 1.75 to 1.00 for the fiscal quarters ended December 31, 2002, March 31, 2003
and June 30, 2003, (ii) 1.85 to 1.0 for the fiscal quarter ended September 30,
2003, (iii) 2.00 to 1.0 for the fiscal quarter ended December 30, 2003, (iv)
2.25 to 1.0 for the fiscal quarter ended March 31, 2004, (v) 2.40 to 1.0 for the
fiscal quarter ended June 30, 2004, (vi) 2.70 to 1.0 for the fiscal quarter
ended September 30, 2004, and (vii) 3.00 to 1.0 for the fiscal quarter ended
December 31, 2004 and for each fiscal quarter thereafter. As of June 30, 2003,
SPPC was in compliance with these financial covenants. The Term Loan Facility,
which is secured by SPPC's $100 million Series C General and Refunding Mortgage
Bond, will expire October 31, 2005.

CROSS DEFAULT PROVISIONS

Certain financing agreements of SPPC contain cross-default provisions that
would result in an event of default under such financing agreements if there is
a failure under other financing agreements of SPPC and SPR to meet payment terms
or to observe other covenants that would result in an acceleration of payments
due. Most of these default provisions (other than ones relating to a failure to
pay other indebtedness) provide for a cure period of 30-60 days from the
occurrence of a specified event during which time, SPPC or SPR may rectify or
correct the situation before it becomes an event of default. The primary
cross-default provisions in SPPC's various financing agreements are briefly
summarized below:

- SPPC's General and Refunding Mortgage Indenture, under which SPPC has
$499.5 million of securities outstanding as of June 30, 2003, provides
for an event of default if a matured event of default under SPPC's First
Mortgage Indenture occurs;

- SPPC's Term Loan Agreement provides for an event of default if (a) SPPC
or any of its subsidiaries default (i) in the payment of indebtedness, or
(ii) in the payment of amounts due under hedge agreements, and such
defaults aggregate to greater than $10 million, or (b) SPPC's General and
Refunding Mortgage Indenture ceases to be enforceable; and

- SPPC's receivables purchase facility may terminate in the event that
either SPPC or SPR defaults (i) in the payment of indebtedness, or (ii)
in the payment of amounts due under hedge agreements, and such defaults
aggregate to greater than $10 million and $5 million for SPPC and SPR,
respectively.

LIMITATIONS ON INDEBTEDNESS

The terms of SPPC's $100 million Credit Facility, which expires October
2005, restrict SPPC from issuing additional indebtedness unless the debt issued
is specifically permitted, which includes certain letter of credit indebtedness,
certain capital lease obligations, indebtedness incurred to refinance existing
indebtedness, certain intercompany indebtedness, certain letters of credit
issued to support SPPC's obligations with respect to energy suppliers and a
limited amount of general indebtedness.

If SPPC is unable to access the capital markets to issue additional
indebtedness to support its operations, including the purchase of fuel and
power, and to refinance its existing indebtedness, whether due to lack of access
to the capital markets, lack of regulatory authority, or restrictive covenants
in its Term Loan Agreement, its ability to provide power and its financial
condition will be adversely affected.

SIERRA PACIFIC RESOURCES (HOLDING COMPANY)

The Condensed Consolidated Statements of Operations of SPR for the
six-months ended June 30, 2003, include the operating results of the holding
company. The holding company recognized an unrealized loss of $107.6 million on
the derivative instrument associated with the issuance of $300 million of
convertible notes and higher interest costs, $40.1 million in 2003 compared to
$36.7 million in 2002, also due to the issuance of $300 million of convertible
notes in February 2003.

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TUSCARORA GAS PIPELINE COMPANY

The Condensed Consolidated Statements of Income of Sierra Pacific Resources
include the operating results of Tuscarora Gas Pipeline Company (TGPC), a wholly
owned subsidiary of SPR. For the three-and six-month periods ended June 30,
2003, TGPC contributed $0.9 million and $1.8 million, respectively, in net
income. For the three-and six-month periods ended June 30, 2002, TGPC
contributed $0.7 million and $1.6 million, respectively, in net income.

E-THREE

SPR began negotiations in the second quarter of 2003 to sell two of its
subsidiaries, e-three and e-three Customer Energy Solutions, LLC (CES).
Management is currently negotiating with a single buyer who is expected to
purchase both companies for approximately $2.2 million. Accordingly, as of June
30, 2003, e-three and CES are reported as discontinued operations and the
consolidated financial statements for all periods presented in this report have
been reclassified to report separately the assets, liabilities and operating
results of the companies. See Note 8 of Notes to Condensed Consolidated
Financial Statements for additional information.

SIERRA PACIFIC COMMUNICATIONS

The Condensed Consolidated Statements of Income of Sierra Pacific Resources
include the operating results of Sierra Pacific Communications (SPC), a wholly
owned subsidiary of SPR. For the three- and six-month periods ended June 30,
2003, SPC incurred net losses of $22.2 million and $23.1 million, respectively.
SPC incurred net losses of $0.6 million and $.1.3 million, respectively, for the
three- and six-month periods ended June 30, 2002. Included in 2003 net losses
for the three- and six-month periods is a pre-tax asset impairment charge of
$32.9 million. See Note 8 of the Notes to Consolidated Financial Statements for
discussion of the asset impairment charge.

REGULATORY MATTERS

The Utilities are subject to the jurisdiction of the PUCN and, in the case
of SPPC, the California Public Utility Commission (CPUC) with respect to rates,
standards of service, siting of and necessity for, generation and certain
transmission facilities, accounting, issuance of securities and other matters
with respect to electric distribution and transmission operations. NPC and SPPC
submit integrated resource plans to the PUCN for approval.

Under federal law, the Utilities and Tuscarora Gas Pipeline Company (TGPC)
are subject to certain jurisdictional regulation, primarily by the FERC. The
FERC has jurisdiction under the Federal Power Act with respect to rates,
service, interconnection, accounting, and other matters in connection with the
Utilities' sale of electricity for resale and interstate transmission. The FERC
also has jurisdiction over the natural gas pipeline companies from which the
Utilities take service.

As a result of regulation, many of the fundamental business decisions of
the Utilities, as well as the rate of return they are permitted to earn on their
utility assets, are subject to the approval of governmental agencies.

NEVADA MATTERS

NEVADA POWER COMPANY 2001 DEFERRED ENERGY CASE

On November 30, 2001, NPC filed an application with the PUCN seeking
repayment for purchased fuel and power costs accumulated between March 1, 2001,
and September 30, 2001, as required by law. The application sought to establish
a rate to repay accumulated purchased fuel and power costs of $922 million and
spread the recovery of the deferred costs, together with a carrying charge, over
a period of not more than three years.

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On March 29, 2002, the PUCN issued its decision on the deferred energy
application, allowing NPC to recover $478 million over a three-year period, but
disallowing $434 million of deferred purchased fuel and power costs and $30.9
million in carrying charges consisting of $10.1 million in carrying charges
accrued through September 2001 and $20.8 million in carrying charges accrued
from October 2001 through February 2002. The order stated that the disallowance
was based on alleged imprudence in incurring the disallowed costs.

On April 11, 2002, NPC filed a lawsuit in the First District Court of
Nevada seeking to reverse portions of the PUCN's decision. NPC's lawsuit
requested that the District Court reverse portions of the PUCN's order and
remand the matter to the PUCN with direction that the PUCN authorize NPC to
immediately establish rates that would allow NPC to recover its entire deferred
energy balance of $922 million, with a carrying charge, over three years. The
Bureau of Consumer Protection (BCP) of the Nevada Attorney General's Office
filed a petition in the case seeking additional disallowances.

Various interveners in NPC's deferred energy case before the PUCN filed
petitions with the PUCN for reconsideration of the PUCN's order, seeking
additional disallowances of between $12.8 million and $488 million. On May 24,
2002, the PUCN issued an order denying any further disallowances and granted NPC
the authority to increase the deferred energy cost recovery charge for the month
of June 2002 by one cent per kilowatt-hour. This increase accelerated the
recovery of the deferred balance by approximately $16 million for the month of
June 2002 only.

On April 28, 2003, the District Court issued its decision denying NPC's and
BCP's requests and affirming the PUCN's order and also denied the BCP's
petition. The BCP and NPC have both appealed the Nevada Supreme Court to
overturn the District Court's decision. The Nevada Supreme Court has ordered the
parties to submit to a settlement conference. A typical Supreme Court appeal
takes 18 to 24 months.

NEVADA POWER COMPANY 2002 DEFERRED ENERGY CASE

On November 14, 2002, NPC filed an application with the PUCN seeking
repayment for purchased fuel and power costs accumulated between October 1,
2001, and September 30, 2002, as required by law. The application sought to
establish a rate to collect accumulated purchased fuel and power costs of $195.7
million, together with a carrying charge, over a period of not more than three
years. The application also requested a reduction to the going-forward rate for
energy, reflecting reduced wholesale energy costs. The combined effect of these
two adjustments resulted in a request for an overall rate reduction of 6.3%.

The decision on this case was issued May 13, 2003 and authorized the
following:

- recovery of $147.6 million, with a carrying charge, and a $48.1 million
disallowance;

- a three-year amortization of the balance commencing on May 19, 2003;

- a reduction in the Base Tariff Energy Rate (BTER) to an effective
non-residential rate of $0.04322 per kWh, and an effective residential
rate of $0.04186 per kWh.

The new rates went into effect on May 19, 2003.

NEVADA POWER COMPANY DEMAND REDUCTION PROGRAMS

On November 14, 2002, NPC filed an application with the PUCN seeking
recovery of expenses incurred in the implementation and operation of programs
for energy conservation and load management. In the filing, NPC requested a
one-year recovery of approximately $1.9 million. This would result in an average
0.12% increase in NPC's present rates. NPC asked for this increase to become
effective simultaneously with the rate change to be ordered in its 2002 deferred
energy case discussed above. The parties to the case subsequently negotiated a
settlement agreement, which approved NPC's request for cost recovery with the
exception of a nominal disallowance. The stipulation was approved at the agenda

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meeting held April 4, 2003. The rate change went into effect on May 19, 2003,
coincident with the deferred energy rate change discussed above.

NEVADA POWER COMPANY 2003 RESOURCE PLAN

On July 1, 2003, NPC filed its 2003 Resource Plan with the PUCN. The
Resource Plan was prepared in compliance with Nevada laws and regulations. The
Resource Plan was prepared for the 20-year period from 2003 through 2022. The
three-year action plan covers calendar years 2004, 2005, and 2006. The 2003
Resource Plan develops a comprehensive, integrated plan that considers customer
energy requirements and proposes the resources to meet that requirement in a
manner that is consistent with prevailing market fundamentals. The ultimate goal
of the plan is to balance the objectives of minimizing costs and reducing
volatility while reliably meeting the electric needs of NPC's customers.

The 2003 Resource Plan is consistent with Governor Guinn's 2001 Nevada
Energy Protection Plan calling for the increased development of internal power
generation to reduce dependence on volatile energy sources outside Nevada. The
plan begins the process of taking control of energy supply and demand and
reducing the dependence on others in order to provide price stability and
electric reliability for customers.

As a step towards achieving this objective, NPC proposed building an 80
mega-watt (MW) combustion turbine at the Harry Allen power plant site with an
in-service date prior to the 2006 summer peak and a 520 MW combined cycle
generating turbine, also at the Harry Allen power plant site, with a 2007
in-service date. Delivery of the energy from this new generation to NPC's
customers will require a reservation on the Harry Allen-to-Mead 500 kilovolt
(kV) transmission line. The construction of this transmission project is
required to fulfill existing wholesale transmission contractual obligations to
Independent Power Producers located within NPC's control area.

The three-year Action Plan describes the actions, specific projects, and
budgets that NPC is proposing to implement during calendar years 2004, 2005 and
2006. NPC is seeking approval by the PUCN for the demand and supply side
projects described in the plan. This three-year strategy is based on analyses of
prevailing market dynamics and supply and demand fundamentals within the energy
sector. NPC is therefore seeking PUCN approval of a number of action items,
including the following:

- Approval of NPC's electric load forecast as being a fair representation
of expected loads during the 20-year period spanning 2003 through 2022.

- Approval of NPC's fuels price forecasts as being a fair representation of
expected range of prices during the same 2003 through 2022 period.

- Approval of NPC's plan to reserve up to 650 MW of additional native load
transmission rights on the Centennial Transmission Project following the
construction of the Harry Allen-to-Mead 500 kV transmission line, the
third phase of the project.

- Approval for re-conductoring the 230 kV Mead system that would increase
system import by 450 MW at an estimated cost of $24 million.

- Approval to construct a combustion turbine generating plant at the Harry
Allen power plant site prior to the summer peak of 2006 at an estimated
cost of $44.1 million,

- Approval to construct a combined cycle generating plant including duct
burners rated at 520 MW. The unit is planned for the Harry Allen power
plant site with an in-service date prior to the 2007 summer peak, at a
cost of $414.7 million

- NPC will submit long-term transmission service requests to other
transmission owners for capacity from the Palo Verde region to Mead.
Long-term transmission capacity has been unavailable from the Palo Verde
region to Mead. These requests will likely result in system impact and
facility studies by these transmission owners. NPC is requesting PUCN
approval of the estimated $100,000 for the aforementioned studies.

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- Approval to spend $9.2 million, $9.3 million, and $9.3 million for
calendar years 2004, 2005, and 2006 respectively, devoted to demand-side
programs. The programs were developed in a collaborative effort, based
upon input from various interested parties.

- Approval of the recommended natural gas hedging strategy for 2004.

- Exemption from the avoided cost filing requirements set forth in Nevada
Administrative Code section 704.8783 based upon the use of a competitive
bidding process to fill mega-watts available to Qualifying Facilities as
a result of the renewable energy request for proposal (RFP) and long-term
purchase obligation RFP for up to 2,500 MW.

- Approval for a plant life assessment of NPC's existing power plants, at a
cost of $500,000 per each year of the Three-Year Action Plan.

In addition, the Action Plan includes the following action items:

- Issue an RFP for long-term purchase power contracts to fill a substantial
portion of remaining capacity requirements expected for 2004-2006. The
results of the RFP and any executed contracts will be filed with the PUCN
for approval.

- Issue an RFP to meet the Renewable Energy Portfolio Standard through 2007
as adopted and passed into law by the Nevada State Legislature. NPC
proposes to execute the agreements and bring the signed agreements to the
PUCN for approval as a compliance item to this plan.

The PUCN is expected to begin hearings on NPC's Resource Plan October 14,
2003, and issue a decision on November 13, 2003. If NPC's proposed 2003 Resource
Plan is approved by the PUCN, NPC may need to expend up to approximately $500
million prior to the summer of 2007 for the construction and/or acquisition of
generation facilities. If NPC is unable to provide this amount with internally
generated funds, it may need to access the capital markets to do so. There can
be no assurances that NPC will be able to issue such indebtedness. See NPC's
Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Liquidity and Capital Resources for a discussion of NPC's
financial condition and limitations on NPC's ability to issue additional
indebtedness.

SIERRA PACIFIC POWER COMPANY 2003 DEFERRED ENERGY CASE

On January 14, 2003, SPPC filed an application with the PUCN, as required
by law, seeking to clear deferred balances for purchased fuel and power costs
accumulated between December 1, 2001 and November 30, 2002. The application
sought to establish a rate to clear accumulated purchased fuel and power costs
of $15.4 million and spread the cost recovery over a period of not more than
three years. It also sought to recalculate the rate to reflect anticipated
ongoing purchased fuel and power costs. The total rate increase request amounted
to 0.01%. The interveners' testimony was received April 25, 2003, and included
proposed disallowances from $34 million to $76 million. Prior to the hearing
that was scheduled to begin on May 12, 2003, the parties negotiated a settlement
agreement. The agreement included the following provisions:

- A reduction in the current deferred energy balance of $45 million leaving
a balance payable to customers of approximately $29.6 million.

- A two-year amortization of the amount payable returning one third of the
balance in the first year (approximately $9.9 million), and two thirds of
the balance the second year (approximately $19.7 million).

- Discontinue carrying charges on deferred energy balances that SPPC is
already collecting from customers and on the $29.6 million amount payable
as a result of the agreement.

- Maintain the currently effective Base Tariff Energy Rate.

- SPPC maintains the rights to claim the cost of terminated energy
contracts in future deferred filings.

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- Parties agreed that with the $45 million reduction the remaining costs
for purchasing fuel and power during the test year were prudently
incurred and are just and reasonable.

- SPPC and the Bureau of Consumer Protection agreed to file a motion to
dismiss the civil lawsuits filed in relation to the 2001 SPPC deferred
energy case.

The agreement was approved by the PUCN at the agenda meeting held on May
19, 2003 and the new rates went into effect on June 1, 2003.

SIERRA PACIFIC POWER COMPANY DEMAND REDUCTION PROGRAMS

On January 14, 2003, SPPC filed an application with the PUCN seeking
recovery of expenses incurred in the implementation and operation of programs
for energy conservation and load management. In the filing, SPPC requested a
one-year recovery of approximately $0.9 million, which would result in an
average 0.12% increase in SPPC's rates. The parties to the case subsequently
negotiated a settlement agreement that is expected to be approved by the PUCN
coincident with its 2003 deferred energy ruling. The agreement called for
complete recovery of the $0.9 million balance. The agreement, allowing recovery
of the entire balance, was signed by all parties and approved at the PUCN's May
19, 2003 agenda meeting. Rates went into effect June 1, 2003, coincident with
the deferred energy rate change discussed above.

CUSTOMERS FILE TO BE SERVED BY NEW PROVIDERS UNDER NRS 704B (AB 661)

AB 661, passed by the Nevada legislature in 2001 and incorporated into
Nevada Revised Statutes as NRS 704B, allows commercial and governmental
customers with an average demand greater than 1 MW to select new energy
suppliers. The Utilities would continue to provide transmission, distribution,
metering and billing services to such customers. NRS 704B requires customers
wishing to choose a new supplier to receive the approval of the PUCN and meet
public interest standards. In particular, departing customers must secure new
energy resources that are not under contract to the Utilities, the departure
must not burden the Utilities with increased costs or cause any remaining
customers to pay increased costs, and the departing customers must pay their
portion of any deferred energy balances. Management believes that those
customers securing from new energy suppliers may help alleviate the Utilities'
need to access energy from potentially volatile wholesale energy markets. The
PUCN adopted regulations prescribing the criteria that will be used to determine
if there will be negative impacts to remaining customers or the Utility.
Customers wishing to choose a new supplier must provide 180-day notice to the
Utilities.

Thirteen NPC customers have filed applications for departure. These
applications total approximately 350 MW of peak load. In twelve of these
applications, stipulations have been reached that addressed all issues except
treatment of Base Tariff General Rate (BTGR) revenue impacts arising from
departure. The PUCN has issued a compliance order for these twelve applications
that will allow the customers to depart upon completion of items in the
compliance order. The remaining application is pending with a decision
anticipated in fourth quarter of 2003.

NPC continues to pursue resolution of the BTGR revenue impact issue. The
most recent departure orders allow NPC to establish a regulatory asset to
recover the BTGR revenue impact. According to the PUCN's order, the BTGR revenue
impact will be offset by load growth from new customers. NPC will present its
load growth calculation and request recovery of the regulatory asset in a
subsequent general rate case.

Currently, four customers have made their required compliance filings and
are requesting departure in the fourth quarter of 2003. Seven customers elected
not to make compliance filings and will remain full requirements customers of
NPC; these applications will lapse. However, many of these customers have filed
notice of their intent to file new applications. The compliance date for the
remaining approved application has not yet occurred.

The four customers who are proceeding with departure applications total 175
MW or approximately 4% of NPC's peak load. These customers are also proceeding
with the implementation of metering and
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communications equipment. Until the customers receive a final order accepting
their compliance items from the PUCN, none of the customers will provide formal
written notice of their intent to proceed with departure from NPC. NPC is
obligated to plan for and secure energy supplies for these customers until
official departure notice is received. The written departure notice must provide
a minimum of 60 days notice.

CALIFORNIA MATTERS (SPPC)

RATE STABILIZATION PLAN

SPPC serves approximately 44,500 customers in California. On June 29, 2001,
SPPC filed with the California Public Utilities Commission (CPUC) a Rate
Stabilization Plan, which included two phases. Phase One, which was also filed
June 29, 2001, was an emergency electric rate increase of $10.2 million annually
or 26%. The increase was applicable to all customers except those eligible for
low-income and medical-needs rates and went into effect July 18, 2002.

Phase Two of the Rate Stabilization Plan was filed with the CPUC on April
1, 2002, and includes a general rate case and requests the CPUC to reinstate the
Energy Cost Adjustment Clause, which would allow SPPC to file for periodic rate
adjustments to reflect its actual costs for wholesale energy supplies. Phase Two
also includes a proposal to terminate the 10% rate reduction mandated by AB
1890, but does not include a performance-based rate-making proposal. This
request was for an additional overall increase in revenues of 17.1%, or $8.9
million annually.

On December 19, 2002, SPPC filed an amendment to the Phase Two application
reducing the requested increase by $4.1 million to $4.8 million or 9.2%
annually. SPPC agreed to make certain changes to the application and file the
amendment following discussions with the CPUC Office of Ratepayer Advocates. In
February 2003, the Office of the Ratepayer Advocates (ORA) filed testimony on
cost of service proposing to reduce SPPC's request by $3.2 million resulting in
a $1.6 million increase or 3.3%. On March 14, 2003, SPPC filed rebuttal
testimony. On March 10, 2003, the ORA filed testimony on revenue allocation and
rate design and on April 2, 2003, SPPC and the California Ski Areas Association
filed rebuttal testimony. Hearings were held on April 9, 2003. Opening and reply
briefs were filed on May 21, 2003 and June 6, 2003, respectively. Also on June
6, 2003, a settlement agreement was filed resolving all issues except rate
design, reflecting an increase of $3.02 million or 5.8%. A decision by the CPUC
regarding the Energy Cost Adjustment Clause is expected in September 2003 and a
decision on the settlement and rate design is expected in late 2003.

CALIFORNIA ASSEMBLY BILL 1235

On September 24, 2002, the Governor of California signed into law Assembly
Bill 1235 (AB 1235), which allows the transfer of hydroelectric plants along the
Truckee River from SPPC to the Truckee Meadows Water Authority (TMWA). AB 1235
effectively amends previous California legislation (AB 6) that prevented private
utilities from selling any power plants that provide energy to California
customers until 2006. AB 1235 provides an exemption for the four
"run-of-the-river" hydroelectric plants that SPPC sold to TMWA as part of the
sale of its water business in June 2001.

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 to this proceeding
and SPPC must supplement the application with a certified environmental
document. SPPC has begun informal discussions with the CPUC on the environmental
issues and cannot yet predict the outcome of this proceeding. On April 17, 2003,
the CPUC issued a ruling dismissing the application without prejudice. The
decision allows SPPC to re-file the application including an environmental
assessment. SPPC plans to file a new application by the end of 2003.

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FERC MATTERS (SPPC, NPC)

In December 2001, the Utilities filed ten wholesale-purchased power
complaints with the FERC under Section 206 of the Federal Power Act seeking to
reduce prices of certain forward power purchase contracts that the Utilities
entered into prior to the price caps established by the FERC during the western
United States utility crisis. The Utilities believe the prices under these
purchased power contracts are unjust and unreasonable. The Utilities negotiated
a settlement with Duke Energy Trading and Marketing, but were unable to reach
agreement in bilateral settlement discussions with other respondents.

The Utilities have already paid the full contact price for all power
actually delivered by these suppliers, but are contesting claims made for
terminated power suppliers, including those terminated by Enron.

The Administrative Law Judge (ALJ) overseeing the Utilities' complaints and
proceedings under Section 206 of the Federal Power Act issued an initial
decision on December 19, 2002 which stated that the Utilities' complaints did
not meet the public interest standard of proof, which the ALJ believed applied
to the reformation of their contracts. NPC, SPPC and other parties to these
proceedings filed Briefs on Exceptions to the ALJ's initial order with the FERC.

On June 26, 2003, FERC dismissed the Utilities' Section 206 complaints on a
two-to-one vote essentially finding that the strict public interest standard
applied to the case and that the company had failed to satisfy the burden of
proof required by that standard. In that order, FERC also determined that it
would not deem the order final and conclusive as to any of the Utilities'
liability to Enron for purchase power contracts terminated by Enron. FERC
indicated that any challenges to those contracts on the basis of market
manipulation or fraud would be based on the evidence presented in that
proceeding. On July 28, 2003, the Utilities filed a petition for rehearing at
the FERC requesting that the FERC either reconsider or rehear the case. The
petition cited several grounds for rehearing, including that the public interest
standard did not apply but that the Utilities had satisfied it as well as the
less onerous just and reasonable standard which does apply to the case. The
Utilities cannot predict the outcome of the petition but intend to pursue it
vigorously as well as take all available appeals. Also, on June 26, 2003, FERC
issued two other orders of interest to the company. First, FERC revoked Enron's
market based authority. Second, FERC ordered Enron and several other power
marketers with whom the Utilities had power contracts subject to the 206
proceeding to show cause why they should not be found to have manipulated the
power markets through certain anomalous market behaviors and to disgorge any
profits from January 2000 to June 2001. The Utilities intend to intervene in
these cases to protect their rights as well as initiate a new Section 206 case
against Enron based on the market fraud and manipulation identified by FERC in
its June 26, 2003, orders.

Additionally, the Staff recommended that certain market participants
identified in the Cal ISO Report released January 6, 2003, including SPPC, be
directed to show cause why their behavior did not constitute gaming in violation
of the Cal ISO and Cal PX tariffs. In its report, the Cal ISO indicated that it
was unclear as to the reason SPPC received certain revenues in the amount of
approximately $6 thousand. The total revenues for all companies for which the
Staff recommended show cause orders are approximately $2.8 million. SPPC was one
of the over 30 market participants included in the Staff's recommendation. On
April 7, 2003, SPR submitted documentation to the FERC demonstrating that SPPC
did not engage in gaming in violation of the Cal ISO or Cal PX tariffs, nor in
the manipulation of the Western energy market. The Cal ISO revised its report,
removing SPPC's name altogether, but other California parties' testimony
included SPPC's name for the same transactions. On June 25, 2003, the FERC
issued a show cause order allowing SPPC to justify its actions on these same
transactions. SPPC is actively pursuing the issue to clear its name in this
proceeding.

For more information regarding the Section 206 proceedings, please see Item
7, Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Regulation and Rate Proceedings -- FERC Matters -- FERC 206
Complaints in SPR's, NPC's and SPPC's Annual Reports on Form 10-K for the year
ended December 31, 2002.

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OPEN ACCESS TRANSMISSION TARIFF

On September 27, 2002, the Utilities filed with the FERC a revised Open
Access Transmission Tariff. The purpose of the filing was to implement changes
that are required to implement retail open access in Nevada. The Utilities
requested the changes to become effective November 1, 2002; the date retail
access was scheduled to commence in Nevada in accordance with provisions of AB
661, passed in the 2001 session of the Nevada Legislature.

On October 11, 2002, the Utilities filed with the FERC, revised rates,
terms, and conditions for ancillary services offered in the OATT designated
Docket No. ER03-37-000. On November 25, 2002, the FERC suspended the rates in
Docket No. ER03-37-000 for a nominal period and made them effective subject to
refund on January 1, 2003, as requested by the Utilities.

On November 21, 2002, the FERC suspended the revised OATT in Docket No.
ER02-2607-000 for a nominal period, made it effective subject to refund, set
certain issues for hearing, and directed the Utilities to make a compliance
filing. The compliance filing was submitted on December 23, 2002. This order
additionally established hearing procedures and consolidated the two dockets for
hearing. On March 11, 2003, all parties to these dockets reached a settlement in
principle regarding all issues. A settlement agreement was filed with the FERC
on May 12, 2003 and was certified to the PUCN on May 22, 2003. The settlement
was adopted by letter order issued on July 1, 2003.

On May 1, 2003, the Utilities filed with the FERC a revision to the Open
Access Transmission Tariff that established the distribution loss factors to be
applied to settlements for retail open access service. The filing designated
Docket No. ER03-806-000 was accepted by letter order issued July 1, 2003.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market risk is the risk of loss arising from adverse changes in market
rates and prices, such as interest rates, and commodity prices. Our primary
exposures to market risk are interest rate risk associated with long-term debt,
commodity price risk associated with fuel and purchased power contracts,
forwards and options held by the Utilities, the credit risk associated with
energy and financial service company counterparties from which the Utilities
procure fuel and purchase power, and equity price risk associated with SPR's
Convertible Notes.

INTEREST RATE RISK

SPR has evaluated its risk related to financial instruments whose values
are subject to market sensitivity, such as fixed and variable rate debt and
preferred trust securities obligations. As shown in SPR's Form 10-K for the year
ended December 31, 2002, the fair market value of SPR's consolidated long-term
debt and preferred trust securities was $3.372 billion, as of December 31, 2002.
As of June 30, 2003, the fair market value of SPR's market-sensitive financial
instruments had increased approximately 7.7% to $3.632 billion. Fair market
value is determined using quoted market price for the same or similar issues or
on the current rates offered for debt or preferred obligations of the same
remaining maturities.

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Long-term debt as of June 30, 2003 (dollars in thousands):

- ---------------

(1) Weighted average daily rate for month ended June 30, 2003.

(2) The 2003 SPR Fixed Rate amount of $162,495 includes $142,180 of SPR's
convertible debt current in 2003.

EQUITY PRICE RISK

In connection with SPR's issuance of its Convertible Notes, the conversion
option, which is treated as a cash-settled written call option, was separated
from the debt and accounted for separately as a derivative instrument in
accordance with SFAS No. 133, "Accounting for Derivative Instruments and Hedging
Activities," as amended. The fair market value of the derivative is recorded as
a liability in SPR's financial statements with changes in the fair value of the
derivative reported in earnings in the period of the change.

The fair value of the conversion option derivative is determined using a
pricing model that incorporates information and assumptions such as SPR's stock
price, time to expiration, strike price, interest rates, and volatility. The use
of different assumptions and variables in the model could have a significant
impact on the valuation of the derivative.

Based on the closing price of SPR's common stock at June 30, 2003 of $5.94,
the fair value of the conversion option was determined to be approximately $180
million at June 30, 2003, and as a result, SPR recorded unrealized losses of
approximately $123.5 million and $107.5 million for three and six month periods
ended June 30, 2003, respectively. Assuming no change in the other variables, a
$1.00 change in the closing price of SPR's stock to $4.94 or $6.94 would have
resulted in a fair value of approximately $128 million and $234 million,
respectively, and unrealized losses for the three months ended June 30,

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2003 of approximately $72 million and $178 million, respectively, and unrealized
losses for the six months ended June 30, 2003 of approximately $56 million and
$161 million, respectively.

Similarly, changes in the market price of SPR's common stock could have a
significant impact on the amount of cash payable upon conversion of the
Convertible Notes. At an assumed five-day average closing price of $5.94 per
share (based on the last reported sale price of SPR's common stock July 30,
2003), the total amount of the cash payable on conversion of the Convertible
Notes would be approximately $254 million. Based on a $1.00 change in the
average closing price of SPR's common stock, the amount of cash payable on
conversion of the Convertible Notes would increase or decrease by approximately
$43 million to $297 million if the stock price increases or to $211 million if
the stock price decreases.

COMMODITY PRICE RISK

See the Annual Reports on Form 10-K of SPR, NPC, and SPPC for the year
ended December 31, 2002, Item 7A, Quantitative And Qualitative Disclosures About
Market Risk, Commodity Price Risk for a discussion of Commodity Price Risk.

CREDIT RISK

The Utilities monitor and manage credit risk with their trading
counterparties. As of June 30, 2003, the Utilities had outstanding transactions
with over 40 energy and financial services companies. The Utilities' credit risk
associated with these transactions was approximately $16.7 million as of June
30, 2003. This credit risk represents the difference between the contract price
of energy that the Utilities have secured with energy and financial services
companies and the higher market prices as of June 30, 2003. In the event that
the energy providers were unable to deliver under the contracts, it would be
necessary for the Utilities to purchase alternative energy at the higher market
price.

ITEM 4. CONTROLS AND PROCEDURES

SPR, NPC, and SPPC maintain disclosure controls and procedures as defined
in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as
amended (the Exchange Act), designed to ensure that they are able to collect the
information required to be disclosed in the reports they file with the
Securities and Exchange Commission (SEC), and to process, summarize and disclose
this information accurately and within the time periods specified in the rules
of the SEC. The chief executive officer and chief financial officer of each of
SPR, NPC, and SPPC have reviewed and evaluated SPR's, NPC's and SPPC's
disclosure controls and procedures as of June 30, 2003 (the Evaluation Date).
Based on such evaluation, such officers have concluded that, as of the
Evaluation Date, the disclosure controls and procedures of SPR, NPC, and SPPC
are effective in bringing to their attention on a timely basis material
information relating to SPR, NPC, and SPPC required to be included in periodic
filings under the Exchange Act.

There have not been any significant changes in the internal controls over
financial reporting of SPR, NPC, and SPPC that occurred during the quarter ended
June 30, 2003 that materially affected, or were reasonably likely to materially
affect SPR's, NPC's and SPPC's internal controls over financial reporting.

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PART II

ITEM 1. LEGAL PROCEEDINGS

Refer to Item 3 of SPR's, NPC's and SPPC's Annual Reports on Form 10-K for
the year ended December 31, 2002, and Note 18 to SPR's consolidated financial
statements contained in that report and Note 11 to SPR's condensed consolidated
financial statements contained in this report for a description of pending legal
proceedings. Except as set forth below, there are no additional material legal
proceedings or material developments with respect to previously reported
proceedings involving SPR, NPC or SPPC.

SIERRA PACIFIC RESOURCES AND NEVADA POWER COMPANY

LAWSUIT AGAINST MERRILL LYNCH AND ALLEGHENY ENERGY, INC.

On April 2, 2003, SPR and NPC filed a complaint in the U.S. District Court
for the District of Nevada against Merrill Lynch & Co., Inc. and Merrill Lynch
Capital Services, Inc. (collectively, Merrill Lynch) and Allegheny Energy, Inc.,
and Allegheny Energy Supply Company, LLC (collectively, Allegheny) seeking
actual and punitive damages in excess of $850 million and demanding a jury trial
for all claims triable by jury. The complaint alleges that the Merrill Lynch
defendants engaged in misrepresentation, suppression and concealment, breach of
fiduciary duty, wrongful hiring and supervision of Daniel Gordon, and breach of
contract and alleges that both Merrill Lynch and Allegheny engaged in
intentional interference with contractual and prospective advantage, conspiracy
and racketeering (in violation of Nevada Revised Statutes Section 207.470). The
complaint also alleges that the improper behavior of Merrill Lynch and Allegheny
was the direct and proximate cause of the March 2002 decision by the PUCN to
disallow $180 million of rate adjustments in NPC's 2001 deferred energy
accounting adjustment rate application.

LAWSUIT AGAINST NATURAL GAS PROVIDERS

On April 21, 2003, SPR and NPC filed a complaint in the U.S. District Court
for the District of Nevada against natural gas providers El Paso Corporation, El
Paso Natural Gas Company, El Paso Merchant Energy Company, El Paso Tennessee
Pipeline Company, El Paso Merchant Energy-Gas Company, Sempra Energy, Southern
California Gas Company, San Diego Gas and Electric Company, Dynegy Holdings,
Inc., Dynegy Energy Services, Inc., and Does 1-100, seeking $600 million in
total damages. The complaint alleges, among other things, that as a result of
the defendants' conspiracies and fraudulent behavior, SPR and NPC were forced to
enter into natural gas purchase contracts "at artificially high,
supracompetitive prices." The complaint further states that between 1996 and
2001, certain of the defendants and their subsidiaries conspired, in secret
meetings, to decrease competition by restricting the amount of pipeline capacity
and fuel available to NPC while other defendants decreased natural gas supplies
and drove up prices by illegally withholding pipeline capacity, maintained
control over output and prices by manipulating natural gas price indexes, and
harmed market competition and the plaintiffs by driving up prices and increasing
the volatility of natural gas supplies. SPR and NPC assert that the defendants
conspired to prevent the construction of new gas transportation capacity to
deliver gas to the southern Nevada area by preventing the planned expansion of
the Kern River Pipeline upon which NPC relies for its primary supply of natural
gas for its generation facilities. The complaint also alleges that certain of
the defendants "systematically misrepresented the price and volume of their
trades" to key trade publications, creating the appearance of supply volatility
and escalating prices starting in 2000 and continuing through the beginning of
2002. SPR and NPC assert claims for fraud, violation of Nevada's RICO Act and
conspiracy to violate Nevada's RICO Act, compensatory damages, treble damages,
punitive damages, legal fees, interest and other such relief deemed just and
proper by the court.

DISPUTES WITH PURCHASED POWER PROVIDERS

In June 2003, El Paso Merchant Energy demanded mediation of its claim for a
termination payment arising out of El Paso's September 25, 2002 termination of
all executory purchase power contracts

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between NPC and El Paso. El Paso claims that under the terms of the contracts,
NPC owes El Paso approximately $39 million representing the difference between
the contract price and the market price for power to be delivered under all the
terminated contracts and the amount remaining unpaid under the contracts for
power delivered between May 2002 and October 2002. NPC claims that El Paso owes
NPC an amount up to approximately $162 million for undelivered power
representing the difference between the replacement price or market price for
power to be delivered under all the executory contracts and the contract price
for that power. The mediation was unsuccessful, and on July 25, 2003, NPC
commenced an action against El Paso Merchant Energy and several of its
affiliates in the Federal District Court for the District of Nevada for damages
resulting from breach of these purchase power contracts.

In June 2003, Reliant Energy submitted a comprehensive settlement proposal
to NPC proposing a settlement of NPC's termination payment obligation arising
out of Reliant's May 2002 termination of its purchase power contracts with NPC.
NPC denies that it owes Reliant any money under these contracts. Mediation of
this claim occurred in 2002 and was not successful. Neither party has requested
arbitration nor commenced litigation over this dispute, and the parties are
continuing discussions. See Note 11 to SPR's condensed consolidated financial
statements contained in this report for additional information regarding
Reliant's claims.

NEVADA POWER COMPANY AND SIERRA PACIFIC POWER COMPANY

ENRON LITIGATION

Enron Power Marketing (Enron) filed a complaint with the United States
Bankruptcy Court for the Southern District of New York seeking to recover
approximately $216 million and $93 million against NPC and SPPC, respectively,
for liquidated damages for power supply contracts terminated by Enron in May
2002 and for power previously delivered to the Utilities. The Utilities have
denied liability on numerous grounds, including deceit and misrepresentation in
the inducement (including, but not limited to, misrepresentation as to Enron's
ability to perform) and fraud, unfair trade practices and market manipulation.
The Utilities filed motions to dismiss for lack of jurisdiction and/or for a
stay of all proceedings pending the actions of the Utilities' proceedings under
Section 206 of the Federal Power Act at the FERC. The Utilities have also filed
proofs of claims and counterclaims against Enron, for the full amount of the
approximately $300 million claimed to be owed and additional damages, as well as
for unspecified damages to be determined during the case as a result of acts and
omissions of Enron in manipulating the power markets, wrongful termination of
its transactions with the Utilities, and fraudulent inducement to enter into
transactions with Enron, among other issues.

On December 19, 2002, the bankruptcy judge granted Enron's motion for
partial summary judgment on Enron's claim for $17.7 million and $6.7 million,
respectively, for energy delivered by Enron in April 2002, for which NPC and
SPPC did not pay. The court ordered this money to be deposited into an escrow
account not subject to claims of Enron's creditors and subject to refund
depending on the outcome of the Utilities' FERC cases on the merits. The
Utilities made the deposit as required. The bankruptcy court denied the
Utilities' motion to stay the proceeding pending the outcome of the Utilities'
Section 206 case at the FERC and denied the Utilities' motion to dismiss for
lack of jurisdiction as to Enron's claims for power previously delivered to the
Utilities. The court stated that it would rule in due course on Enron's motion
for partial summary judgment to require NPC and SPPC to post $200 million and
$87 million, respectively, pending the outcome of the case on the merits, and
for judgment on the merits on Enron's liquidated damage claim (contract price
less market price on the date of termination) relating to power it did not
deliver under contracts terminated by Enron in May 2002. The court took under
advisement the Utilities' motion to stay or dismiss Enron's claim for liquidated
damages relating to the undelivered power. On April 3, 2003, the court heard
arguments regarding Enron's motion to dismiss the Utilities' counterclaims
against Enron for unspecified damages to be determined during the case, but did
not rule on this matter nor did it indicate when a decision on this matter can
be expected.

On June 26, 2003, FERC issued three orders of consequence to this
litigation. First, FERC denied the Utilities' request to modify the contract
rates, for contracts entered into with Enron and certain other

84

power suppliers during the western U.S. utility crisis, to a level reflecting a
just and reasonable price in a competitive market. In doing so, however, FERC
denied Enron's request that its order in this case be deemed final and
conclusive as to any and all other challenges to the enforceability of the
contracts or to the lawful contract rate based on Enron's fraud and manipulation
of the markets. FERC indicated that it would reserve judgment on any such
challenge until it heard the evidence on the challenge. Second, FERC issued an
order immediately revoking Enron's market based rate authority based on fraud
and manipulation of the markets. Third, FERC issued an order to show cause
Concerning Gaming and/or Anomalous Market Behavior on the part of Enron and
others and directing submission of information indicating why Enron and others
should not be required to disgorge profits from January 1, 2000, forward. Based
on these orders, the Utilities filed a motion in July 2003 to amend their first
amended complaint and counterclaim to allege facts consistent with the FERC
orders that Enron was not entitled to relief on its claims against the companies
but rather should be required to pay damages against the companies for losses
sustained throughout the western energy crisis for which Enron was in part
responsible. The Utilities also filed a supplement to their opposition to
Enron's motion for summary judgment including all of the facts of fraud and
manipulation of the markets as found by FERC in its June 26, 2003, orders as
well as the criminal indictments and complaints against Enron's former chief
financial officer and others engaged in trading operations for Enron. Enron
filed oppositions to the motions to amend the amended complaint and
counterclaims and an opposition to supplement the Utilities' opposition to
Enron's motion for summary judgment. On August 7, 2003, the Bankruptcy Court
heard oral arguments from the parties on the motions. The bankruptcy judge has
not indicated when a decision may be expected. The Utilities are unable to
predict the outcome of these motions. The United States District Court for the
Southern District of New York has also denied the Utilities' motion to withdraw
reference of the matter to the bankruptcy court without prejudice.

The Bankruptcy Court currently has under submission (1) Enron's motion to
dismiss the Utilities' counterclaims, (2) Enron's motion for partial summary
judgment regarding the amounts alleged to be due for undelivered power and the
posting of collateral for undelivered power, (3) the Utilities' motion to
dismiss or stay proceeding on Enron's claims relating to delivered power and (4)
the Utilities' motion to amend their first amended complaint and counterclaim to
allege facts consistent with the FERC orders that Enron was not entitled to
relief on its claims against the companies. A decision adverse to the Utilities
on Enron's motion for partial summary judgment, or an adverse decision in the
lawsuit with respect to liability as to Enron's claims on the merits for
undelivered power, would have a material adverse effect on SPR's and the
Utilities' financial condition and liquidity, and could make it difficult for
one or more of SPR, NPC or SPPC to continue to operate outside of bankruptcy.

NEVADA POWER COMPANY

MORGAN STANLEY PROCEEDINGS

In March 2003, the arbitrator overseeing the arbitration proceedings
initiated by Morgan Stanley Capital Group (MSCG) regarding various power supply
contracts terminated by MSCG in April 2002 dismissed MSCG's demand for
arbitration and agreed that the issues raised by MSCG were not calculation
issues subject to arbitration and that NPC's contract defenses were likewise not
arbitrable. For more information regarding the MSCG arbitration proceedings,
please see Note 11 to SPR's condensed consolidated financial statements
contained in this report and Item 3 -- Legal Proceedings in SPR's and NPC's
Annual Reports on Form 10-K for the year ended December 31, 2002. NPC has since
filed a complaint for declaratory relief in the U.S. District Court for the
District of Nevada asking the Court to declare that NPC is not liable for any
damages as a result of MSCG's termination of its power supply contracts. On
April 17, 2003, MSCG answered the complaint and filed a counterclaim against NPC
at the FERC alleging non-payment of the termination payment in the amount of $25
million. NPC filed a motion to intervene in the FERC action commenced by MSCG.
To date, FERC has not placed the matter on its agenda for adjudication or for
hearing. NPC is unable to predict the outcome of these proceedings.

85

OTHER LITIGATION

On October 21, 2002, Bonneville Square and Union Plaza filed a complaint
seeking class certification in the Eighth Judicial District Court for Clark
County, Nevada, against NPC for fraud and misrepresentation for allegedly
overcharging a certain class of customers for energy delivered over the past
several years. Plaintiffs allege that NPC fraudulently placed its meters and
measured energy delivered at a point prior to passing through transformers
during which process a certain amount of energy is dissipated as heat, instead
of placing the meters after they pass through the transformer. NPC denies that
the placement of the meters was fraudulent and alleges that placement of the
meters was mandated by either or both customers request or applicable tariff.
NPC's motion to dismiss on jurisdictional grounds was denied. NPC filed a writ
of prohibition with the state supreme court alleging that the district court did
not have jurisdiction over this dispute and that the PUCN had exclusive
jurisdiction over the matter. The state supreme court granted an alternative
writ and ordered the district court through the plaintiff real party in interest
to show cause why the action should not be dismissed on jurisdictional grounds.
The PUCN intervened in the matter and is supporting the NPC's position. The
court has established a briefing schedule and it is anticipated that a decision
will be issued in the third quarter of 2003. Although management cannot predict
the outcome of this lawsuit, management does not believe that it will result in
a material liability for NPC.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

The 2003 Annual Meeting of the Stockholders of Sierra Pacific Resources was
held at 10:00 a.m., Pacific Daylight Time, on Monday, May 12, 2003, at the
Orleans Hotel and Casino, 4500 West Tropicana Avenue, Las Vegas, Nevada.

The meeting involved the election of three members of the Board of
Directors to serve until the Annual Meeting in 2006, or until their successors
are elected, and the approval of the 2003 Non-Employee Director Stock Plan. The
directors elected at the Annual Meeting were Mary Lee Coleman, T.J. Day, and
Jerry E. Herbst.

The voting are shown below:

- ---------------

(1) 6,378,439 shares that were originally voted for election of each of the
nominees for director (and were so included in the preliminary voting
results announced at the Annual Meeting) were changed to withhold authority
for all nominees. Although the Inspector of Election did not receive
notification of this change of vote until after the Annual Meeting
concluded, he determined that all action necessary to change the vote with
respect to these shares had been taken prior to the Annual Meeting.
Accordingly, those (which did not alter the Directors' ultimate re-election)
shares are reflected above as having voted to withhold authority for each of
the nominees.

ITEM 5. OTHER INFORMATION

None

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

(a) Exhibits filed with this Form 10-Q:

86

NEVADA POWER COMPANY

Exhibit 10.1 $60,000,000 Credit Agreement among Nevada Power Company, the
several lenders from time to time parties to the Agreement,
and Merrill Lynch Capital Corporation, as administrative
agent.

SIERRA PACIFIC POWER COMPANY

Exhibit 10.2 First Amendment, dated as of June 27, 2003, to the Term Loan
Agreement, dated as of October 30, 2002.

SIERRA PACIFIC RESOURCES, NEVADA POWER COMPANY AND SIERRA PACIFIC POWER COMPANY

Exhibit 31.1 Certification Pursuant to Section 302 of the Sarbanes-Oxley
Act of 2002.

Exhibit 31.2 Certification Pursuant to Section 302 of the Sarbanes-Oxley
Act of 2002.

Exhibit 32.1 Certification Pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

(b) Reports on Form 8-K:

FORM 8-K DATED APRIL 2, 2003, FILED BY SPR, NPC -- ITEM 5, OTHER EVENTS

Disclosed, and included as an exhibit, the Complaint and Jury Demand by SPR
and NPC in the United States District Court for the District of Nevada against
Merrill Lynch & Co., Merrill Lynch Capital Services, Inc., Allegheny Energy,
Inc., and Allegheny Energy Supply Company, LLC for actions that caused the
Public Utilities Commission of Nevada to disallow $180,000,000 of rate
adjustment in Nevada Power's deferred energy account adjustment rate
application.

FORM 8-K DATED APRIL 21, 2003, FILED BY SPR, NPC -- ITEM 5, OTHER EVENTS

Disclosed, and included as an exhibit, SPR's press release, dated April 21,
2003, announcing NPC's filed suit in federal court against El Paso Corp., Sempra
Energy, Dynegy Holdings and others for alleged restraint of trade, fraud,
violation of Nevada's RICO Act and civil conspiracy. Also included as an exhibit
the Complaint and Jury Demand in support of the allegations.

FORM 8-K, DATED APRIL 28, 2003, FILED BY SPR, NPC AND SPPC -- ITEM 5, OTHER
EVENTS

Disclosed the First District Court of Nevada (Court) decision on Nevada
Power Company's appeal of the March 29, 2002 decision of the PUCN denying
recovery of $437 million of deferred energy costs incurred by NPC. In its
decision, the Court denied the requests and affirmed the PUCN's order.

FORM 8-K DATED MAY 12, 2003, FILED BY SPR, SPPC -- ITEM 5, OTHER EVENTS

Disclosed, and included as an exhibit, SPR's press release dated May 12,
2003, announcing that electric ratepayers served by the Company in northern
Nevada would realize a rate decrease of $9.8 million beginning June 1, 2003 and
a rate decrease of $19.8 million beginning June 1, 2004, subject to PUCN
approval.

FORM 8-K DATED MAY 12, 2003, FILED BY SPR, NPC, SPPC -- ITEM 5, OTHER EVENTS

Disclosed, and included as an exhibit, SPR's press release dated May 13,
2003, announcing that the PUCN finalized an order allowing the Company to
recover $148 million of $195 million in deferred energy costs incurred by the
Company. The order established a reduction to the base tariff energy rate of
6.3% for a typical electric residential customer. The new rate became effective
on May 19, 2003.

In addition, the Company disclosed the filed Motion to Reconsider, Alter or
Amend (Motion) the Order of the First Judicial District Court of Nevada (Court),
denying the Company's appeal of the
87

March 29, 2002 decision of the PUCN disallowing the recovery of $437 million of
deferred energy costs. The Motion requests the Court reconsider its Order with
respect to the Merrill Lynch disallowances.

FORM 8-K DATED MAY 19, 2003, FILED BY SPR, SPPC -- ITEM 5, OTHER EVENTS

Disclosed, and included as an exhibit, SPR's press release dated May 19,
2003, announcing PUCN approval of the stipulated agreement relating to the filed
deferred energy costs incurred by SPPC. The stipulation gives northern Nevada
electric ratepayers a rate decrease of $9.8 million, beginning June 1, 2003.

88

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrants have duly caused this report to be signed on their behalf by the
undersigned thereunto duly authorized.

SIERRA PACIFIC RESOURCES
(Registrant)

Date: August 8, 2003 By: /s/ RICHARD K. ATKINSON
---------------------------------------------
Richard K. Atkinson
Vice President
Chief Financial Officer
(Principal Financial Officer)

Date: August 8, 2003 By: /s/ JOHN E. BROWN
---------------------------------------------
John E. Brown
Vice President
Controller
(Principal Accounting Officer)

NEVADA POWER COMPANY
(Registrant)

Date: August 8, 2003 By: /s/ RICHARD K. ATKINSON
---------------------------------------------
Richard K. Atkinson
Vice President
Chief Financial Officer
(Principal Financial Officer)

Date: August 8, 2003 By: /s/ JOHN E. BROWN
---------------------------------------------
John E. Brown
Vice President
Controller
(Principal Accounting Officer)

89

SIERRA PACIFIC POWER COMPANY
(Registrant)

Date: August 8, 2003 By: /s/ RICHARD K. ATKINSON
---------------------------------------------
Richard K. Atkinson
Vice President
Chief Financial Officer
(Principal Financial Officer)

Date: August 8, 2003 By: /s/ JOHN E. BROWN
---------------------------------------------
John E. Brown
Vice President
Controller
(Principal Accounting Officer)