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decatherms inventory capability at Jackson Prairie

decatherms withdrawal capability per day from Jackson Prairie

Decatherms inventory capability at Paiute LNG

LNG Storage

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d) OF
THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2005


Commission File	Registrant, Address of Principal Executive Offices and Telephone	I.R.S. Employer	State of
Number	Number	Identification Number	Incorporation
1-08788	SIERRA PACIFIC RESOURCES	88-0198358	Nevada
	P.O. Box 30150 (6100 Neil Road)
	Reno, Nevada 89520-3150 (89511)
	(775) 834-4011

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

0-00508	SIERRA PACIFIC POWER COMPANY	88-0044418	Nevada
	P.O. Box 10100 (6100 Neil Road)
	Reno, Nevada 89520-0024 (89511)
	(775) 834-4011


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

Securities of Sierra Pacific Resources:
Common Stock, $1.00 par value		New York Stock Exchange
7.803% Senior Notes Due 2012		New York Stock Exchange
Securities of Nevada Power Company and subsidiaries:
8.2% Cumulative Quarterly Income		New York Stock Exchange
Preferred Securities, Series A, issued by NVP Capital I
7^3/4% Cumulative Quarterly Trust Issued		New York Stock Exchange
Preferred Securities, issued by NVP Capital III
Securities registered pursuant to Section 12(g) of the Act:
Securities of Sierra Pacific Power Company:
Class A Preferred Stock, Series I, $25 stated value

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act:

Sierra Pacific Resources Yes þ No o Nevada Power Company Yes o No þ Sierra Pacific Power Company Yes o No þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No þ

Indicate by check mark whether each of the registrants (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 þ No o

Indicate by check mark if disclosure of delinquent filers pursuant to item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrants’ knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o

Indicate by check mark whether any registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. (See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act).


Sierra Pacific Resources:	Large accelerated filer þ	Accelerated filer o	Non-accelerated filer o
Nevada Power Company:	Large accelerated filer o	Accelerated filer o	Non-accelerated filer þ
Sierra Pacific Power Company:	Large accelerated filer o	Accelerated filer o	Non-accelerated filer þ

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o No þ (Response applicable to all registrants)

State the aggregate market value of Sierra Pacific Resources’ common stock held by non-affiliates. As of June 30, 2005: $ 1,458,239,815

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

Common Stock, $1.00 par value, of Sierra Pacific Resources outstanding at March 1, 2006: 200,879,752 Shares

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

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

DOCUMENTS INCORPORATED BY REFERENCE:

Portions of Sierra Pacific Resources’ definitive proxy statement to be filed in connection with the annual meeting of shareholders, to be held May 1, 2006, are incorporated by reference into Part III hereof.

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

Information contained in this document relating to Sierra Pacific Power Company is filed by Sierra Pacific Resources and separately by Sierra Pacific Power Company on its own behalf. Sierra Pacific Power Company makes no representation as to information relating to Sierra Pacific Resources or its subsidiaries, except as it may relate to Sierra Pacific Power Company.

SIERRA PACIFIC RESOURCES
NEVADA POWER COMPANY
SIERRA PACIFIC POWER COMPANY
ANNUAL REPORT ON FORM 10-K

CONTENTS


PART I
Item 1. Business			3
Sierra Pacific Resources			3
Nevada Power Company			5
Sierra Pacific Power Company			14
Other Subsidiaries of Sierra Pacific Resources			24
Item 1A. risk factors			26
Item 1B. unresolved staff comments			30
Item 2. Properties			31
Item 3. Legal proceedings			32
Item 4. Submission of Matters to a Vote of Security Holders			38
Executive Officers of Registrant			38
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities (SPR)			40
Item 6. Selected Financial Data			41
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations			44
Executive Overview			46
Sierra Pacific Resources			56
results of operations			56
analysis of cash flows			56
liquidity and capital resources (spr consolidated)			57
Energy Supply (Utilities)			63
Nevada Power Company			65
results of operations			65
analysis of cash flows			71
liquidity and capital resources			71
Sierra Pacific Power Company			76
results of operations			76
analysis of cash flows			82
liquidity and capital resources			83
Regulatory Proceedings (Utilities)			87
Item 7A. Quantitative and Qualitative Disclosures About Market Risk			96
Item 8. Financial Statements and Supplementary Data			98
Item 9. Changes in and Disagreements With Accountants On Accounting and Financial Disclosure			186
Item 9A. Controls and Procedures			186
Item 9B. Other Information			188
PART III
Item 10. Directors and Executive Officers of the Registrant			189
Item 11. Executive Compensation			192
Item 12. Security Ownership of Certain Beneficial Owners and Management			197
Item 13. Certain Relationships and Related Transactions			198
Item 14. Principal Accounting Fees and Services			200
PART IV
Item 15. Exhibits, Financial Statement Schedules			202
Signatures			203
EX-4.(A) OFFICER'S CERTIFICATE - NEVADA POWER COMPANY
EX-4.(B) FORM OF NEVADA POWER COMPANY'S 5.95% GENERAL AND REFUNDING MORTGAGE NOTES
EX-4.(C) REGISTRATION RIGHTS AGREEMENT - NEVADA POWER COMPANY
EX-10.(A) EMPLOYMENT LETTER DATED JANUARY 9, 2006
EX-10.(B) WESTERN SYSTEMS POWER POOL AGREEMENT, DATED 2/1/2005
EX-10.(C) WESTERN SYSTEMS POWER POOL AGREEMENT, DATED 9/1/2005
EX-12.(A) STATEMENT REGARDING COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES (SPR)
EX-12.(B) STATEMENT REGARDING COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES (NPC)
EX-12.(C) STATEMENT REGARDING COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES (SPPC)
EX-23.(A) CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM (SPR)
EX-31.1 ANNUAL CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER
EX-31.2 ANNUAL CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER
EX-32.1 SECTION 906 CERTIFICATION OF THE C.E.O.
EX-32.2 SECTION 906 CERTIFICATION OF THE C.F.O.

FORWARD LOOKING STATEMENTS

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

PART I

ITEM 1. BUSINESS

SIERRA PACIFIC RESOURCES

Sierra Pacific Resources (SPR) is an investor-owned holding company that was incorporated under Nevada law on December 12, 1983. The company’s stock is traded on the New York Stock Exchange under the symbol “SRP”. SPR’s mailing address is P.O. Box 30150 (6100 Neil Road), Reno, Nevada 89520-3150 (89511).

SPR has six primary, wholly-owned subsidiaries: Nevada Power Company (NPC), Sierra Pacific Power Company (SPPC), Tuscarora Gas Pipeline Company (TGPC), Sierra Pacific Communications (SPC), Sierra Pacific Energy Company (SPE), and Lands of Sierra (LOS). References to SPR refer to the consolidated entity, except where the context provides otherwise. NPC and SPPC are referred to collectively in this report as the “Utilities.”

The Utilities operate three regulated business segments, as defined by FASB Statement No. 131, Disclosure about Segments of an Enterprise and Related Information: NPC electric; SPPC electric; and SPPC natural gas service. Electric service is provided to Las Vegas and surrounding Clark County, northern Nevada and the Lake Tahoe area of California. Natural gas services are provided in the Reno-Sparks area of Nevada. The Utilities are the major contributors to SPR’s financial position and results of operations. Other subsidiaries either do not meet or are below the quantitative threshold for separate segment disclosure and are combined under “all other” in the following pages. Parenthetical references are included after each major section title to identify the specific entity or entities addressed in the section. See Note 2, Segment Information of the Notes to Financial Statements, for further discussion.

NPC and SPPC service territories are as follows:

(SIERRA PACIFIC RESOURCES SERVICES AREAS MAP)

SPR continues to focus on a “back to the basics” strategy that emphasizes the Utilities’ core business. The Utilities provide electric and natural gas services to a diverse mix of over one million residential, commercial, industrial and public sector customers. Major industries served include gaming/recreation, mining, warehousing/manufacturing, offices, health care, education, military bases and other governmental entities.

The Utilities’ revenues and operating income are subject to fluctuations during the year due to the impacts of seasonal weather, rate changes and customer usage patterns have on demand for electric energy and services. NPC is a summer peaking utility experiencing its highest retail energy sales in response to the demand for air conditioning. SPPC’s electric system peak occurs in the summer, with a slightly lower peak demand in the winter.

The Utilities do not own generating facilities sufficient to meet the peak demands and reliability needs of Nevada’s growing population and, as a result, must purchase more than half of their energy requirements in the wholesale market. For the summer 2006 summer peak, NPC and SPPC have secured approximately 95% of their respective needs, with the balance to be acquired through upcoming Requests for Proposals (RFP) or in the short-term market, depending on conditions.

The amount of power purchased by the Utilities varies from time to time depending on demand, the cost of purchased power compared with our cost of generation, and the availability of such power. In 2005, NPC and SPPC purchased approximately 61.4% and 55.4%, respectively, of total system energy needs. Some purchased power contracts are indexed to natural gas prices. Due to the relatively large seasonal gas and purchased power usage, the Utilities purchase power and hedge a portion of their total natural gas exposure as discussed further in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Energy Supply.

It is SPR’s strategy to grow the Utilities’ internal generating capacity in an effort to reduce reliance on purchased power. Consistent with this strategy, NPC acquired the 1200 MW (unit ratings are nominal ratings) gas-fired Chuck Lenzie generating station

and a 75% interest in the 560 MW, gas-fired Silverhawk plant. SPPC will be constructing a new 514 MW facility at the Tracy Generating Station. (For further details, see the following Generation sections for NPC and SPPC). Additionally, as part of the strategy to grow and invest in, and improve the performance of their regulated businesses, SPR, NPC and SPPC recently announced their intention to develop a major energy project located near Ely, Nevada (the “Ely Energy Center”). The Ely Energy Center includes two 750 MW coal-fired plants and construction of a 250-mile transmission line to interconnect NPC and SPPC. With regulatory approvals and permitting requirements, it is anticipated the first coal plant would be operational in 2011 with the second unit to follow within three years thereafter. The estimated capital expenditures for the Ely Energy Center are approximately $3 billion.

As a result of dramatic service territory growth, both Utilities have added transmission infrastructure. Discussions of new transmission lines are in NPC’s and SPPC’s discussion of Transmission which follow.

Nevada state law allows commercial customers with an average annual load of 1 MW or more, with Public Utilities Commission of Nevada’s (PUCN) approval, to choose alternate energy suppliers. In addition, some large customers may own and operate generation facilities to meet their own energy requirements. One large SPPC mining customer began operating a 118 MW generating facility in December of 2005 and another large mining customer has a 203 MW facility it is beginning to construct. These matters are discussed further under Competition for NPC and SPPC.

The Federal Energy Regulatory Commission (FERC), PUCN and California Public Utilities Commission (CPUC), in the case of SPPC, regulate portions of the Utilities’ accounting practices and electricity and natural gas rates. The FERC regulates the terms and prices of transmission services and sales of wholesale electricity. The PUCN and CPUC have authority over general and energy rates charged to retail customers, the issuance of securities, and transactions with affiliated parties.

Periodic reports on Form 10-K and Form 10-Q and current reports on Form 8-K are made available to the public, free of charge, on SPR’s, NPC’s and SPPC’s websites (www.sierrapacificresources.com, www.nevadapower.com, and www.sierrapacific.com) through links on these websites to the SEC’s website at www.sec.gov, as soon as reasonably practicable after they have been filed with the SEC. The contents of the above referenced website addresses are not part of this Form 10-K. Available on the sierrapacificresources.com website is the code of ethics for the chief executive officer, chief financial officer and controller, charters for the Audit, Compensation and Nominating and Governance Committees of SPR’s Board of Directors and our corporate governance and standards of conduct guidelines. Printed copies of these documents may be obtained free of charge by writing to SPR’s Corporate Secretary at Sierra Pacific Resources, P.O. Box 30150, Reno, NV 89520-3150.

NEVADA POWER COMPANY

NPC is a Nevada corporation organized in 1921 and, by itself and through a predecessor corporation, has been providing electric services to southern Nevada since 1906. NPC became a subsidiary of SPR in July 1999. Its mailing address is 6226 West Sahara Avenue, Las Vegas, Nevada 89146.

Nevada Electric Investment Company (NEICO) is a wholly-owned subsidiary of NPC. NEICO is a 25% member of Northwind Aladdin, LLC, which operates the central energy plant at the Aladdin Resort and Casino in Las Vegas. The other 75% is owned by Macquarie Infrastructure Company Trust.

Business and Competitive Environment

Overview

NPC is a public utility that generates, transmits and distributes electric energy in southern Nevada. At year-end 2005, NPC served approximately 774,000 customers in Las Vegas, North Las Vegas, Henderson, Searchlight, Laughlin, and adjoining areas, including Nellis Air Force Base and the Department of Energy’s Nevada Test Site in Nye County.

Electric Operations

NPC is charged with meeting the growing energy needs of the residential population and expanding business and public sectors in Southern Nevada. In addition to customer growth, demand and resulting revenues are impacted by rate changes, seasonal or atypical weather and customer use. NPC’s peak demand occurs in the summer. Therefore, NPC’s revenues and associated expenses are not incurred or generated evenly throughout the year.

To serve its growing customer base, NPC purchases power and generates electricity in accordance with an Energy Supply Plan, as discussed in more detail later in this section and in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations. It is NPC’s strategy to grow its internal generating capacity in an effort to reduce reliance on purchased power. As part of this strategy, NPC acquired the Chuck Lenzie generating station, a partially completed 1200 MW gas-fired combined cycle

plant in October 2004 and a 75% interest in the 560 MW gas-fired Silverhawk plant in January 2006, as discussed in further detail under the Generation section.

Additionally, SPR, NPC and SPPC, recently announced their intention to develop the Ely Energy Center. The Ely Energy Center, which is subject to regulatory approval and permitting requirements, includes two 750 MW coal-fired plants and construction of a 250-mile transmission line to interconnect NPC and SPPC. Assuming timely receipt of regulatory approvals and permits, it is anticipated the first coal plant would be operational in 2011 with the second unit to follow within three years thereafter.

Nevada regulations require that NPC file general rate cases every two years with the PUCN to adjust rates including cost of service and return on investment. Nevada state regulations also require annual filings to reset Base Tariff Energy Rates (BTER) and either recover or credit balances that have been deferred representing fuel and purchased power costs incurred compared with amounts collected in current retail rates. If necessary, NPC can file more than once a year to seek a change in BTER to more closely match actual prices. Rate cases are discussed in more detail in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Regulatory Proceedings, and Note 3, Regulatory Actions, of the Notes to Financial Statements.

Competition

State law allows commercial customers with an average annual load of 1 MW or more to file a letter of intent and application with the PUCN to acquire electric energy, capacity, and ancillary services from another provider. The law 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 NPC, the departure must not burden NPC 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. The PUCN adopted regulations prescribing the criteria that will be used to determine if there will be negative impacts to remaining customers or NPC. Customers wishing to choose a new supplier must provide 180-day notice to NPC. NPC would continue to provide transmission, distribution, metering, and billing services to such customers. Management believes that those customers securing energy from new energy suppliers will reduce NPC’s need to purchase power from potentially volatile wholesale energy markets.

Currently, there are no applications pending with the PUCN to exit the system in NPC’s service territory.

Revenue

NPC’s service territory continues to be among one of the fastest growing areas in the nation. In 2005, NPC set 45,261 meters and it is forecasted that NPC will set over 45,000 again in 2006. In 2005, NPC’s operating revenues were approximately $1.9 billion.

Summer peak loads are driven by air conditioning demand. Winter peak loads are low relative to the summer peak. Winter load above the base amount is driven by air handling in forced air furnaces. NPC’s peak load increased at an average annual growth rate of 5.2% over the past five years, reaching 5,563 MW on July 18, 2005. NPC’s retail total electric megawatt-hour (MWh) sales have increased at an average annual growth rate of 4.9% over the past five years.

NPC’s electric customers by class contributed the following toward 2005, 2004 and 2003 MWh sales:


	MWh Sales (Billed and Unbilled)
	2005				2004				2003
Residential		8,288,309	41.3	%		7,981,116	40.1	%		7,765,112	37.4	%
Commercial and Industrial:
Gaming/Recreation/Restaurants		4,025,982	20.0	%		3,916,681	19.7	%		4,116,561	19.8	%
All Other & Unclassified		7,140,403	35.6	%		6,709,439	33.7	%		6,076,766	29.3	%

Total Retail		19,454,694	96.9	%		18,607,236	93.5	%		17,958,439	86.5	%

Wholesale		278,527	1.4	%		870,398	4.4	%		2,377,946	11.5	%
Public Authorities		349,912	1.7	%		408,927	2.1	%		412,885	2.0	%

TOTAL		20,083,133	100.0	%		19,886,561	100.0	%		20,749,270	100.0	%

Growth in NPC’s residential class sales continues primarily as a result of new home construction in Las Vegas. New home sales in 2005 of 30,750 surpassed the previous record of 29,248 new homes that was set in 2004.

Tourism and gaming remain southern Nevada’s leading industries and comprises one of NPC’s largest class of customers (see Gaming/ Recreation /Restaurants above). In 2005, 3,863 hotel rooms were added in Las Vegas for an increase of 3% in total room capacity over the prior year.

The decrease in wholesale was due primarily to certain types of transactions that were reported in sales for 2004 and are now being netted in purchase power.

The decrease in consumption for public authorities was due to Southern Nevada Water Authority (SNWA) moving to a distribution only service (DOS) tariff. The DOS tariff allows certain customers to obtain energy from other entities but still continue to use our transmission and distribution lines for delivery.

Demand

Load and Resources Forecast

NPC’s integrated peak electric demand rose from 4,969 MW in 2004 to 5,563 MW in 2005. NPC’s peak system load and operating reserve requirements were met with 1,528 MWs of existing company owned generation and 4,795 MWs of power purchases. Variations in energy usage by NPC’s customers occur as a result of varying weather conditions and other energy usage behaviors. This necessitates a continual balancing of loads and resources, and requires both purchases and sales of energy under short and long term contracts and the prudent management and optimization of available resources.

NPC plans to meet its customers’ needs through a combination of owned-generation and purchased power. As discussed in Energy Supply — Generation, in 2006 NPC will add about 1700 MWs of new company owned generating facilities: Chuck Lenzie Units 1 & 2, Harry Allen Unit 4 and a 75% undivided interest in the Silverhawk Generating Station (the remaining 25% is owned by the SNWA and is under contract to NPC). These additional generation facilities will significantly reduce NPC’s reliance on purchased power needs. Remaining needs will be met through power purchases through RFPs or short term purchases pursuant to a PUCN approved Energy Supply Plan. NPC will be filing a new Integrated Resource Plan (IRP) with the PUCN in July 2006 that is expected to include the addition of the new coal fired generating capacity of the Ely Energy Center beginning in 2011.

Below is a table summarizing the forecasted electric capacity requirement and resource needs of NPC (assuming no curtailment of supply or load, and normal weather conditions):


			Forecasted Electric Capacity
			Requirements and Resources (MW)
	2006		2007		2008		2009		2010
Total Requirements (1)		6,141		6,388		6,661		6,947		7,192

Resources:

Company-owned existing generation		1,312		1,312		1,312		1,312		1,312
Company-owned new generation (2)		1,615		1,615		1,615		1,615		1,615
Contracts for power purchases		2,861		1,634		1,509		1,309		1,309

Total Resources		5,788		4,561		4,436		4,236		4,236


Total Additional Required (3)		353		1,827		2,225		2,711		2,956


(1)		Includes system peak load plus planning reserves.

(2)		New generation in 2006 for Lenzie 1 & 2, Harry Allen 4 and Silverhawk (75%).

(3)		Additional Required is the difference between the total required and currently committed resources. Additional required represents the amount needed to achieve the forecasted system peak plus a planning reserve margin.

NPC includes in its long term plans planning reserves in excess of required operating reserves.

Energy Supply

The energy supply function at NPC encompasses the reliable and efficient operation of NPC’s owned generation, the procurement of all fuels and purchased power, and resource optimization.

NPC faces energy supply challenges for its load control area. There is the potential for continued price volatility in NPC’s service territory, particularly during peak periods. A greater dependence on gas-fired generation in the region subjects power prices to gas price volatilities. NPC faces load obligation uncertainty due to the potential for customer switching. Some counterparties in these areas have significant credit difficulties, representing credit risk to NPC. Finally, NPC’s own credit situation can have an impact on its ability to enter into transactions.

In response to these energy supply challenges, NPC has adopted an approach to managing the energy supply function that has three primary elements. The first element is a set of management guidelines that relate to procuring and optimizing the supply portfolio that is consistent with the requirements of a load serving entity with a full requirements obligation. The second element is an energy risk management and risk control approach that ensures clear separation of roles between the day-to-day management of risks and compliance monitoring and control, and a clear distinction between policy setting (or planning) and execution. Lastly, NPC will pursue a process of ongoing regulatory involvement and acknowledgement of the resource portfolio management plans. Details of the Energy Supply function are discussed in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Energy Supply.

Total System

NPC manages a portfolio of energy supply options. The availability of alternate resources allows NPC to dispatch its electric generation system in a more cost-effective manner under varying operating and fuel market conditions while maintaining system integrity. During 2005, NPC generated 38.6% of its total electric energy requirements, purchasing the remaining 61.4% as shown below.


	2005					2004					2003
	MWh		% of Total			MWh		% of Total			MWh		% of Total
NPC Company Generation

Gas/Oil		2,465,064		11.7	%		2,557,166		12.3	%		4,292,701		19.8	%
Coal		5,629,139		26.9	%		5,913,062		28.4	%		5,734,105		26.5	%

Total Generated		8,094,203		38.6	%		8,470,228		40.7	%		10,026,806		46.3	%


Purchased Power
Hydro		409,309		2.0	%		450,086		2.2	%		470,200		2.2	%
Spot, Firm and Non-Firm		10,301,589		49.0	%		9,458,794		45.5	%		8,763,892		40.4	%
Non-Utility Purchases		2,183,484		10.4	%		2,410,381		11.6	%		2,402,978		11.1	%

Total Purchased		12,894,382		61.4	%		12,319,261		59.3	%		11,637,070		53.7	%


Total		20,988,585		100.0	%		20,789,489		100.0	%		21,663,876		100.0	%

As a supplement to its own generation, NPC purchases spot, short-term firm, intermediate-term firm, long-term firm, and non-firm energy to meet its customer demand requirements. Total energy supply includes purchases from outside the electric system due to limited control area generation and also the need to access market energy supplies. NPC’s decision to purchase this energy is based on economics, mitigation of availability risk, and system import limits. Firm block purchases are transacted as both a price hedging strategy and to ensure that needed firm capacity is available over peak load periods. Spot market energy is purchased based on the economics of purchasing “as-available” energy when it is less expensive than NPC’s own generation, again, subject to net system import limits. NPC’s 2005 company generation total of 8,094,203 MWh decreased 4.4% from NPC’s 2004 company generation total of 8,470,228 MWh. The decrease in NPC’s generation from 2004 to 2005 was primarily due to the NPC’s ability to reduce the generation from its higher heat rate gas units in favor of more economical purchase power resources. NPC’s 2005 purchased power total of 12,894,382 MWh increased 4.7% from NPC’s 2004 purchased power total of 12,319,261 MWh. See Energy Supply in Management’s Discussion and Analysis of Financial Condition and Results of Operations for additional information regarding NPC’s purchasing strategies.

Risk Management

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

Generation

NPC’s generation capacity consists of a combination of 27 gas, oil and coal generating units with a combined capacity of 3, 066 MWs as described in Item 2, Properties. In 2005, NPC generated approximately 38.6% of its total system requirements.

As described earlier, in an effort to reduce reliance on purchased power and diversify energy resources NPC acquired a partially completed generating plant (Chuck Lenzie) and a 75% ownership interest in the Silverhawk generating plant. The combination of the two plants will add approximately 1,620 MWs of capacity in 2006. Additionally, NPC is currently constructing a second unit at the Harry Allen generating plant, which is expected to provide 76 MW of capacity. The increase in capacity will be partially offset by the loss of 403 MW of -capacity due to the retirement of three steam units at the Clark Plant and the shut-down of the Mohave Plant on December 31, 2005, of which NPC is a 14% owner. See Note 14, Commitments and Contingencies, of the Notes to Financial Statements, in Item 8 for further discussion of the Mohave shut-down.

In January 2006, SPR announced NPC’s and SPPC’s intention to build the Ely Energy Center which will serve customers of both NPC and SPPC. The power complex will include two 750 megawatt units incorporating state-of-the-art, clean coal technologies, which is expected to be fully compliant with current environmental standards. The first unit is expected to become operational in 2011 and the second within three years thereafter. The plan also includes further expansion possibilities involving two 500 MW coal gasification units when the technology becomes commercially viable. This project is subject to various regulatory approval and permitting requirements.

Fuel Availability

NPC’s 2005 fuel requirements for electric generation were provided by natural gas, coal, and oil. The average costs of gas, oil, and coal for energy generation per million British thermal units (MMBtu) for the years 2001-2005, along with the percentage contribution to NPC’s total fuel requirements were as follows:

Average Consumption Cost & Percentage Contribution to Total Fuel Requirement


	Gas					Coal					Oil
	$/MMBtu		Percent			$/MMBtu		Percent			$/MMBtu		Percent
2005		6.18		32.7	%		1.59		67.1	%		13.50		0.1	%
2004		6.13		27.3	%		1.33		72.6	%		8.75		0.1	%
2003		5.70		40.9	%		1.41		59.0	%		5.28		0.1	%
2002		5.41		38.9	%		1.37		60.9	%		5.77		0.2	%
2001		8.70		41.4	%		1.31		58.5	%		7.14		0.1	%

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

Natural gas supplies are procured one season ahead of use through a competitive bidding process. The gas prices are set at an appropriate industry index during the month of current delivery. Monthly and daily gas supply adjustments are made by Gas Trading personnel based on the current energy marketplace. The addition of the Lenzie, Silverhawk and Harry Allen units in 2006 is not expected to increase NPC’s exposure to fluctuations in the market price of gas because these units are more efficient than most generating facilities supplying energy to the market in which NPC purchases energy and, consequently, will require less to produce the same amount of electric energy.

Coal delivered to the Reid Gardner Station originates from various mines in the Utah and Colorado Coal fields and is delivered to the station via the Union Pacific Railroad. NPC has five coal contracts, expiring December 31, 2006, with Canyon Fuel Company, LLC, a subsidiary of Arch Coal Company, Arch Coal Company, Oxbow Carbon & Minerals, LLC, Andalex Resources, Inc., and Valmy. Full requirements for coal supplies for 2006 are under contract. NPC is in final negotiations and plans to execute coal supply agreements with Arch Coal Sales Company and Andalex Resources, Inc. that will provide 70%, 60%, 35% and 25% of Reid Gardner’s projected coal requirements for the years 2007, 2008, 2009 and 2010, respectively.

As of December 31, 2005, Reid Gardner Station’s coal inventory level was 198,147 tons, or approximately 33 days of consumption at 100% capacity.

A transportation services contract with Union Pacific Railroad provides for deliveries from the Provo, Utah interchange as well as various mines in Utah and Colorado, to the Reid Gardner Station in Moapa, Nevada. This contract expires on December 31, 2007.

The Utah Railway contract provides for delivery of all coal not loaded by the Union Pacific in Utah to interchange with Union Pacific at Provo, Utah. Both of NPC’s rail transportation contracts contain certain tonnage requirements and railroad service criteria.

Coal for the Navajo Station is obtained from surface mining operations conducted by Peabody Coal Company (Peabody) on portions of the Black Mesa in Arizona within the Navajo and Hopi Indian Tribes (the Tribes) reservations. The Navajo supply contract expires June 1, 2011, with an option provided to NPC to extend for an additional 15 years.

Purchased Power

NPC, under the guidelines set forth in the NPC Energy Supply Plan, continues to manage a diverse portfolio of contracted and spot market supplies, as well as its own generation, with the objective of minimizing its net average system operating costs. During 2005, NPC purchased 61.4 % of its total energy requirements.

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

During 2005, NPC’s credit standing affected the terms under which NPC was able to purchase fuel and electricity in the western energy markets. NPC contracted with certain counterparties requiring modified payment terms including accelerated payments, pre-payments, and/or deposits. In the latter part of 2005, as a result of NPC’s improved credit quality, the number of counterparties requiring modified payment terms significantly declined.

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

Qualifying Facilities

Federal regulations, including the Public Utility Regulatory Policies Act of 1978 (PURPA), which were passed to promote renewable and alternative energy resources, and the Energy Policy Act of 2005 (EPA 2005), set out the requirements for utilities to purchase the output produced by Qualifying Facilities (QFs). QFs are small renewable energy power producers and co-generators, at costs determined by the appropriate state’s public utility commission. Certain QFs can qualify as renewable resources required by state law as discussed below; however, none of NPC’s current QFs qualify.

As of December 31, 2005, NPC had a total of 305 MW of contractual firm and non-firm capacity under contract with QFs. In 2005, energy purchased by NPC from the QFs constituted 17.0% of NPC’s net purchased power requirements for native load and 10.4% of NPC’s net system requirements (including generation).

Renewable Energy

Nevada law requires NPC to acquire or generate a specific percentage of its energy from renewable resources (Renewables). Renewables include biomass, geothermal, solar and wind projects. Nevada law sets forth the portfolio standard requiring providers of electric service to acquire, generate, or save a specific percentage of its energy from renewable resources or to use portfolio energy credits (portfolio credits) to comply with the portfolio standard. Pursuant to the statutory portfolio standard, NPC is required to obtain six percent of its total energy from renewable resources for 2005 and 2006. NPC will be required to meet nine percent of its total energy from renewable resources for 2007 and 2008. The portfolio standard increases to 20% by 2015. Of the total portfolio standard, not more than 25% may be based on energy efficiency measures from qualified conservation programs and not less than five percent of that amount must be from solar resources.

NPC is required to file an annual report that describes the level of compliance with Nevada’s Renewable Energy Portfolio Standard (RPS). As with the 2004 filing, NPC’s 2005 filing reported that it had not fully complied with the RPS requirements and described ongoing activities intended to gain compliance in future years.

In response to the RPS reports, the PUCN ordered NPC to develop and file a plan that would achieve the earliest possible compliance. The PUCN also approved a stipulated settlement in which the parties agreed that NPC would not be fined for non-compliance. On August 1, 2005, NPC submitted a plan to achieve compliance with the RPS. The PUCN reviewed the plan and determined that more specificity was required. On December 15, 2005, NPC filed a revised compliance plan and is awaiting action by the PUCN. In April 2006, NPC will file its annual compliance report with the PUCN for calendar year 2005. In 2005, NPC acquired sufficient portfolio energy credits to meets its portfolio requirement, but did not meet the solar requirements. NPC will request an exemption from the PUCN for the solar portion of the portfolio standard.

To assist developers of new renewable energy projects to attempt to finance their projects, resulting in a higher rate of completion for new renewable energy projects with PUCN approved contracts and allowing NPC to more quickly satisfy its renewable energy portfolio requirements, the PUCN amended its regulations to establish the Temporary Renewable Energy Development (TRED) program.

The TRED program will establish a charge to be separately collected from customers to pay renewable energy suppliers under PUCN-approved contracts. TRED program revenues will be deposited into a special purpose trust that will in turn remit payment to approved renewable energy projects that deliver renewable energy to the purchasing utility under PUCN-approved contracts. On January 6, 2005, the PUCN approved the Utilities’ application requesting approval to set up a TRED trust.

Transmission

Electric transmission systems deliver energy from electric generators to distribution systems for final delivery to customers. Transmission systems are designed to move electricity over long distances because electric generators can be located anywhere from a few miles to hundreds of miles from customers.

NPC’s electric transmission system is part of the Western Interconnection, the regional grid in the west. The Western Interconnection includes the interconnected transmission systems of fourteen western states, two Canadian provinces and the parts of Mexico that make up the Western Electric Coordinating Council (WECC). WECC is one of ten regional councils of the North American Electric Reliability Council, the entity responsible for the reliability, adequacy and security of North America’s bulk electric system.

NPC’s transmission system links generating units within the NPC control area and the Mohave and Navajo Generating Systems, located external to the NPC control area, to the NPC distribution system. NPC’s transmission system is directly interconnected with the transmission systems of Western Area Power Administration, Los Angeles Department of Water and Power, Southern California Edison, and PacifiCorp. NPC currently is not directly interconnected with SPPC; however, if regulators approve a recently proposed project, the two companies can be interconnected by 2011. The map below shows NPC’s transmission system:

As the control area operator, NPC is responsible for continuously balancing electric supply and demand by dispatching generating resources and interchange transactions so that generation internal to the control area plus net import power matches control area load. NPC also schedules power deliveries over its transmission system and maintains reliability by verifying that customers are properly using the system within its established physical bounds.

NPC plans, builds and operates a transmission system that delivered 20,988,585 MWH of electricity to customers in its control area in 2005 through 1,665 circuit miles of owned 60kV to 500kV transmission lines and an assortment of power transformers and phase shifting transformers with a maximum capacity of approximately 4,000 MW. NPC processes generation and transmission interconnection requests and requests for transmission service from a variety of customers. These requests usually involve new planning studies and the negotiation of contracts with new and existing customers in this high growth system.

In the last 7 years, due primarily to high customer growth, NPC has constructed 4 major transmission projects totaling 150 miles of high voltage transmission at a total cost of over $385 million. The projects completed include River Mountain (40 miles), Crystal (10 miles), Bighorn (60 miles), and Centennial (40 miles). NPC has another 60 miles of transmission lines at an estimated cost of over $110 million under various phases of construction. These projects have been approved by the PUCN and are currently being permitted and constructed.

Transmission Regulatory Environment

NPC’s wholesale transmission services are regulated by the FERC under cost based regulation subject to SPR’s Operating Companies Open Access Transmission Tariff (OATT). Transmission service to NPC’s bundled retail customers is subject to the jurisdiction of the PUCN. In accordance with the OATT, NPC offers several transmission services to wholesale customers:

	•		Long-term and short-term firm point-to-point transmission service (guaranteed service with fixed delivery and receipt points),

	•		Non-firm point-to-point service (“as available” service with fixed delivery and receipt points), and

	•		Network transmission service (equivalent to the service NPC provides for NPC’s bundled retail customers).

These services are all offered on a nondiscriminatory basis in that all potential customers, including NPC, have an equal opportunity to access the transmission system. NPC’s transmission business is managed and operated independently from the generating and marketing business in accordance with FERC Standards of Conduct.

NPC is participating in the development of WestConnect, a regional transmission provider in the Desert Southwest. Until 2005, NPC and SPPC both participated in the GridWest formation effort in the Pacific Northwest. In November 2005, NPC discontinued its relationship with Grid West and joined WestConnect as a member. WestConnect is a group of southwest transmission-providing utilities that have agreed to work collaboratively to assess stakeholder and market needs and to investigate, analyze and recommend to its Steering Committee implementation of cost-effective enhancements to the western wholesale electricity market.

Construction Program

NPC’s construction program and estimated expenditures are subject to continuing review, and are revised from time to time due to various factors, including the rate of load growth, construction costs, availability of fuel types, the number and status of proposed independent generation projects, the need for additional transmission capacity in southern Nevada, adequacy of rate relief, NPC’s ability to raise necessary capital, and changes in environmental regulations. Under NPC’s franchise agreements, it is obligated to provide a safe and reliable source of energy to its customers. Capital construction expenditures and estimates are reflective of NPC’s obligation to serve its growing customer base.

Gross construction expenditures for 2005, including allowance for funds used during construction (AFUDC), net salvage, and contributions in aid of construction, were $546.7 million, and for the period 2001 through 2005, were $1.8 billion. Estimated construction expenditures for 2006 and the period from 2007 to 2010 are as follows (dollars in thousands):


	2006		2007-2010		5 - Year
Electric Facilities:
Generation ⁽¹⁾	$	153,994	$	1,385,891	$	1,539,885
Distribution		171,926		742,127		914,053
Transmission		92,699		209,786		302,485
Other		116,029		223,087		339,116

Total	$	534,648	$	2,560,891	$	3,095,539

Total estimated construction and plant cash requirements related to construction projects for 2006 and the 2007 to 2010 period consist of the following (dollars in thousands)


	2006			2007-2010			Total 5 - Year
Construction Expenditures	$	482,957		$	1,308,037		$	1,790,994
Projects included in IRP but not yet approved by PUCN ⁽¹⁾		51,691			1,252,854			1,304,545

Total Construction Expenditures		534,648			2,560,891			3,095,539
AFUDC		(28,981	)		(223,513	)		(252,494	)
Net Salvage/ Cost of Removal		(657	)		(2,762	)		(3,419	)
Net Customer Advances and CIAC		(21,500	)		(90,387	)		(111,887	)

Total Cash Requirements	$	483,510		$	2,244,229		$	2,727,739


(1)		Included in this amount is a 500 MW coal fired generating station to be completed in 2010 with an estimated cost of $632 million. This project is expected to be replaced with the recently announced Ely Energy Center to be filed under NPC’s 2006 IRP with the PUCN by July of 2006. The cost for this project has not been finalized at this time and is not included in the table.

In October 2004, NPC purchased a partially constructed nominally rated 1200 megawatt (MW) natural gas-fired combined-cycle power plant from Duke Energy. The facility, re-named the Chuck Lenzie Generating Station (Lenzie), is located in the Moapa Valley, 20 miles northeast of Las Vegas. When purchased, the plant was 56% complete, and construction resumed immediately. Total cost for Lenzie as approved by the PUCN is $550 million. Based on the status of completion of the facility the cost is expected to be below this amount; however, final costs may change or be higher than anticipated in the event of unexpected delays. Costs in 2004 were approximately $218.2 million, which includes the purchase price of $182 million. Actual construction costs for 2005 were

$213.4 million. The estimated construction costs for 2006 are $53.8 million excluding AFUDC. Half of the capacity was in service in January 2006, and the remaining capacity is expected to be in service by spring 2006.

The Centennial Plan involves construction of transmission lines and substations to increase the ability to transfer power to and through the Las Vegas valley by over 3,000 MW. The final component, a 500-kV, fifty-mile line from NPC’s Harry Allen substation near Las Vegas to the Western Area Power Administration’s Mead substation is expected to be completed in January 2007.

Total estimated cost of the Centennial Plan is $309.1 million (excluding AFUDC). Total project costs incurred through December 31, 2005, were $228.7 million. Estimated costs for 2006 are $60.0 million, which are expected to be paid for utilizing internally generated cash, or external borrowings.

SIERRA PACIFIC POWER COMPANY

A Nevada corporation since 1965, SPPC was originally incorporated in Maine in 1912. SPPC became a subsidiary of SPR in 1984. Its mailing address is P. O. Box 10100 (6100 Neil Road), Reno, Nevada 89520-0024.

SPPC has two regulated business segments, SPPC electric and SPPC natural gas service, which are discussed separately in this section. SPPC has three primary, wholly owned subsidiaries: GPSF-B, Piñon Pine Corp. (PPC) and Piñon Pine Investment Co. (PPIC). GPSF-B, PPC and PPIC, collectively, own Piñon Pine Company, LLC, which was formed to utilize federal income tax credits available under Section 20 of the Internal Revenue Code associated with the alternative fuel (syngas) produced by the coal gasifier located at the Piñon Pine Facility.

SPPC Electric

Business and Competitive Environment

Overview

SPPC is a public utility that generates, transmits and distributes electric energy to approximately 353,000 customers. The service territory covers over 50,000 square miles of western, central and northeastern Nevada, including the cities of Reno, Sparks, Carson City, and Elko, and a portion of eastern California, including the Lake Tahoe area.

Electric Operations

SPPC is charged with meeting the growing energy needs of the residential population and expanding business and public sectors. In addition to customer growth, demand and resulting revenues are impacted by rate changes, seasonal or atypical weather and customer use. SPPC’s peak demand occurs in the summer with a slightly lower peak demand in the winter.

To serve its growing customer base, SPPC purchases power and generates electricity in accordance with an Energy Supply Plan, approved by the PUCN, as discussed in more detail later in this section and in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations. It is SPPC’s strategy to grow its generating capacity in an effort to reduce reliance on purchased power. As part of this strategy, SPPC recently received regulatory approval to construct a 514 MW gas-fired combined-cycle plant at Tracy, east of Reno. The plant is scheduled to be completed by the summer of 2008.

Electric loads and resulting revenues are affected by customer growth, weather, rate changes, and customer usage patterns. SPPC’s revenues and associated expenses are not incurred or generated evenly throughout the year.

Nevada regulations require that SPPC file general rate cases every two years with the PUCN to adjust rates including cost of service and return on investment. Nevada state regulations also require annual filings to reset base tariff energy rates and either recover or credit deferred energy balances that include fuel and purchased power costs above or below amounts collected in current retail rates. If necessary, SPPC can file more frequently than once a year to seek a change in base tariff energy rates to more closely match actual prices. Rate cases are discussed in more detail in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Regulatory Proceedings, and Note 3, Regulatory Actions, of the Notes to Financial Statements.

Competition

State law allows commercial customers with an average annual load of 1 MW or more to file a letter of intent and application with the PUCN to acquire electric energy, capacity, and ancillary services from another provider. The law 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 SPPC, the departure must not burden SPPC 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. The PUCN adopted regulations prescribing the criteria that will be used to determine if there will be negative impacts to remaining customers or SPPC. Customers wishing to choose a new supplier must provide 180-day notice to SPPC. SPPC would continue to provide transmission, distribution, metering, and billing services to such customers. Management believes that those customers securing energy from new energy suppliers will reduce SPPC’s need to purchase power from potentially volatile wholesale energy markets.

In February 2004, Barrick Gold (Barrick), a large SPPC mining customer, filed an application indicating its intention to construct a 118 MW generating facility to meet a majority of its electric power needs. This facility was operational as of December 2005. Barrick continues to purchase transmission and distribution services from SPPC and is selling approximately 8 MW of capacity from this new facility to SPPC. Barrick Mwh retail sales for 2005 were approximately 10.1% of total system sales for SPPC.

Newmont Mining Corporation (Newmont) is planning to construct a new 203 MW generating plant in northeastern Nevada which is anticipated to be operational in 2008. In 2004, SPPC and Newmont entered into a nonbinding Term Sheet that provides for a wholesale power sale agreement and a new form of retail service. Newmont will sell the electrical output to SPPC for at least 15 years under a long-term wholesale, purchased power agreement, and remain a retail customer of SPPC during at least that period under the terms of a retail service agreement and pursuant to a new rate schedule. SPPC and Newmont submitted a number of related filings which were approved by the PUCN on February 23, 2005. In January 2006, Newmont announced that it had completed its permitting phase and received final approval from its Board of Directors to proceed with development of the project.

Revenue

SPPC’s service territory continues to be among one of the fastest growing areas in the nation. In 2005, SPPC set approximately 11,400 meters and forecasts that it will set over 10,500 meters in 2006. In 2005, SPPC’s electric operations contributed approximately $967 million, or 84.4%, of SPPC’s total revenues.

Summer retail peak loads are primarily driven by air conditioning demand and irrigation pumping. Winter retail electric peak loads are primarily driven by increased demand for space heating, air movement (with forced air gas and oil furnaces), and ski resorts (hotels, lifts, etc.). SPPC’s peak load increased at an average annual growth rate of 2.1% over the past five years, reaching 1,740 MW on July 18, 2005. SPPC’s total retail electric MWh sales have increased at an average annual growth rate of 1.0% over the past five years.

SPPC’s electric customers by class contributed the following toward 2005, 2004 and 2003 MWh sales:


	MWH Sales (Billed and Unbilled)
	2005				2004				2003
Retail:
Residential		2,381,389	25.5	%		2,295,944	23.8	%		2,211,828	21.5	%
Commercial and Industrial:
Mining		2,716,309	29.1	%		2,686,716	27.8	%		2,609,637	25.4	%
All Other		4,136,208	44.3	%		4,160,567	43.0	%		4,079,902	39.7	%

Total Retail		9,233,906	98.9	%		9,143,227	94.6	%		8,901,367	86.6	%

Wholesale		81,856	0.9	%		505,986	5.2	%		1,366,538	13.3	%
Streetlights		15,105	0.2	%		14,932	0.2	%		13,970	0.1	%


TOTAL		9,330,867	100	%		9,664,145	100	%		10,281,875	100	%

Nevada’s precious metals mining industry continued to see positive developments as the price of gold increased in 2005. The increase in price, coupled with Nevada’s reasonable regulatory environment and favorable geology for gold deposits, offers positive opportunities for future mine development. Given the substantial amounts of both proven and probable gold reserves at existing mining operations, the industry’s strong presence in the state and its resulting high energy usage are expected to continue into the future, assuming gold prices stay high.

SPPC has long-term electric service agreements with six of its major mining customers, with yearly revenues under these agreements totaling approximately $159 million. For 2005, this represented 16.4% of SPPC’s electric operating revenues of $967 million. The terms of these agreements range from 5 to 20 years, and include requirements for customers to maintain minimum demand and load factor levels and provisions to recover all of SPPC’s customer-specific facilities investments. As discussed under “Competition” above, Barrick, a mining customer, left SPPC’s system as of December, 2005.

In 2005, Mwh sales in the wholesale segment decreased by 55.5% over sales in 2004. This decrease was a result of market conditions that resulted in fewer economic opportunities in layoffs/swap sales and purchases in 2005 compared to 2004. In addition, certain types of transactions that were reported in revenues for 2004 are now being netted in purchase power.

Demand

Load and Resources Forecast

SPPC’s integrated peak electric demand rose from 1,631 MW in 2004 to 1,740 MW in 2005. SPPC’s peak system load and operating reserve requirements were met with 1,029 MWs of existing company owned generation and 961 MWs of purchased power. Variations in energy usage by SPPC’s customers occur as a result of varying weather conditions and other energy usage behaviors. This necessitates a continual balancing of loads and resources, and requires both purchases and sales of energy under short and long term contracts and the prudent management and optimization of available resources.

SPPC plans to meets its customers needs through a combination of owned generation and purchased power. As discussed in Energy Supply — Generation, SPPC will be constructing a new 514 MW Combined Cycle facility at the existing Tracy Generating Station with a scheduled in-service date of June 2008. The addition of this facility is expected to significantly reduce SPPC’s reliance on purchased power compared to prior years. Remaining needs will be met through power purchased through RFPs or short term purchases pursuant to a PUCN approved Energy Supply Plan. SPPC will be filing an amendment to its 2004 Integrated Resource Plan with the PUCN by July 2006 that is expected to include the addition of the new coal fired generating capacity of the Ely Energy Center beginning in 2011.

Below is a table summarizing the forecasted electric capacity requirement and resource needs of SPPC (assuming no curtailment of supply or load, and normal weather conditions):


			Forecasted Electric Capacity
			Requirements and Resources (MW)
	2006		2007		2008		2009		2010
Total Requirements (1)		1,820		1,843		2,029		2,092		2,112

Resources:

Company-owned existing generation		1,029		1,029		1,029		1,029		1,029
Company-owned new generation (2)						514		514		514
Contracts for power purchases		693		467		506		441		444

Currently Committed Resources		1,722		1,496		2,049		1,984		1,987


Additional Required (3)		98		347		—		108		125


(1)		Includes system peak load plus planning reserves.

(2)		New generation in 2008 for Tracy combined cycle facility at 514 MW.

(3)		Additional Required represents the difference between the currently committed resources and the total resources needed to achieve the forecasted system peak plus a planning reserve margin.

SPPC includes in its long term plans planning reserves in excess of required operating reserves.

Energy Supply

The energy supply function at SPPC encompasses the reliable and efficient operation of SPPC’s owned generation, the procurement of all fuels and purchased power, and resource optimization (i.e., physical and economic dispatch).

SPPC faces energy supply challenges for its load control area. There is the potential for continued price volatility in SPPC’s service territory, particularly during peak periods. A greater dependence on gas-fired generation in the service territory subjects power prices to gas price volatilities. SPPC faces load obligation uncertainty due to the potential for customer switching. Some counterparties in these areas have significant credit difficulties, representing credit risk to SPPC. Finally, SPPC’s own credit situation can have an impact on its ability to enter into transactions.

In response to these energy supply challenges, SPPC has adopted an approach to managing the energy supply function that has three primary elements. The first element is a set of management guidelines to procuring and optimizing the supply portfolio that is consistent with the requirements of a load serving entity with a full requirements obligation. The second element is an energy risk management and risk control approach that ensures clear separation of roles between the day-to-day management of risks and compliance monitoring and control, and a clear distinction between policy setting (or planning) and execution. Lastly, SPPC will pursue a process of ongoing regulatory involvement and acknowledgement of the resource portfolio management plans. Details of the Energy Supply function are discussed in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Energy Supply.

Total System

SPPC manages a portfolio of energy supply options. The availability of alternate resources allows SPPC to dispatch its electric generation system in a more cost-effective manner under varying operating and fuel market conditions while maintaining system integrity. During 2005, SPPC generated 44.6% of its total electric energy requirements, purchasing the remaining 55.4% as shown below. SPPC generated 44.6% of its total requirement in 2005, which remained equal to last year’s percentage of 44.6% and higher than the 2003 percentage of 39.1%.


	2005					2004					2003
	MWh		% of Total			MWh		% of Total			MWh		% of Total
SPPC Company Generation
Gas/Oil		2,345,196		23.9	%		2,562,103		24.8	%		2,515,759		23.3	%
Coal		2,000,719		20.4	%		2,018,715		19.6	%		1,664,771		15.4	%
Hydro		33,355		0.3	%		24,090		0.2	%		46,409		0.4	%

Total Generated		4,379,270		44.6	%		4,604,908		44.6	%		4,226,939		39.1	%


Purchased Power
Spot, Firm and Non-Firm		4,778,786		48.7	%		4,845,650		46.9	%		5,848,514		54.2	%
Non-Utility Purchases		662,261		6.7	%		873,868		8.5	%		726,092		6.7	%

Total Purchased		5,441,047		55.4	%		5,719,518		55.4	%		6,574,606		60.9	%


Total		9,820,317		100.0	%		10,324,426		100.0	%		10,801,545		100.0	%

As a supplement to its own generation, SPPC purchases spot, short-term firm, intermediate-term firm, long-term firm, and non-firm energy to meet its customer demand requirements. Total energy supply includes purchases from outside the electric system due to limited control area generation and also the need to access market energy supplies. SPPC’s decision to purchase this energy is based on economics, mitigation of availability risk, and system import limits. Firm block purchases are transacted as both a price hedging strategy and to ensure that needed firm capacity is available over peak load periods. Spot market energy is purchased based on the economics of purchasing “as-available” energy when it is less expensive than SPPC’s own generation, again, subject to net system import limits. SPPC’s 2005 purchased power total of 5,441,047 MWh decreased 4.9% from SPPC’s 2004 purchased power total of 5,719,518 MWh. See Energy Supply in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, for additional information.

Risk Management

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

Generation

SPPC’s generation capacity consists of a combination of 27 gas, steam, combined cycle and diesel generating units with a combined capacity of 1,045 MW as described in Item 2, Properties. In 2005, SPPC generated approximately 44.6% of its total system requirements.

As described earlier, in an effort to reduce reliance on purchased power and diversify energy resources, SPPC plans to construct a 514 MW gas fired combined cycle generator at the Tracy station. The unit is expected to be operable by June 2008.

In January 2006, SPR announced NPC’s and SPPC’s intention to build the Ely Energy Center, a coal-fired power complex which will serve customers of both NPC and SPPC. The power complex will include two 750 megawatt units incorporating state-of-the-art, clean coal technologies, which is expected to be fully compliant with current environmental standards. The first unit is expected to become operational in 2011 and the second within three years thereafter. The plan also includes further expansion possibilities involving two 500 MW coal gasification units when the technology becomes commercially viable. This project is subject to various regulatory approval and permitting requirements.

Fuel Availability

SPPC’s 2005 fuel requirements for electric generation were provided by natural gas, coal, and oil. The average costs of gas, coal and oil for energy generation per MMBtu for the years 2001-2005, along with the percentage contribution to SPPC’s total fuel requirements, were as follows:

Average Consumption Cost & Percentage Contribution to Total Fuel


	Gas					Coal					Oil
	$/MMBtu		Percent			$/MMBtu		Percent			$/MMBtu		Percent
2005		7.87		56.81	%		1.67		43.08	%		7.37		.11	%
2004		7.32		53.11	%		1.39		44.93	%		6.14		1.96	%
2003		6.68		59.11	%		1.60		40.79	%		6.92		.10	%
2002		4.42		41.10	%		1.68		58.70	%		5.69		.20	%
2001		5.63		45.30	%		1.55		32.40	%		6.49		22.30	%

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

SPPC has long-term coal contracts with Arch Coal Sales Company and Black Butte Coal Company that provide for deliveries through December 31, 2009. These contracts represent 100% of Valmy’s projected coal requirements in 2007, and 75% of Valmy’s projected coal requirements for 2008 and 2009.

Union Pacific Rail Road originates and delivers coal to the Valmy Station. A transportation services contract is in place that expires December 31, 2007.

As of December 31, 2005, Valmy’s coal inventory level was 325,064 tons or approximately 57 days of consumption at 100% capacity.

SPPC meets its needs for residual oil and diesel for generation through purchases on the spot market. SPPC attempts to maintain an actual residual oil inventory target level of about 325,000 barrels, which is equal to a 14-day supply at full load operation.

Purchased Power

SPPC, under the guidelines set forth in the SPPC Energy Supply Plan, continues to manage a diverse portfolio of contracted and spot market supplies, as well as its own generation, with the objective of minimizing its net average system operating costs. During 2005, SPPC purchased 55.4% of its total energy requirement.

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

During 2005, SPPC’s credit standing affected the terms under which SPPC was able to purchase fuel and electricity in the western energy markets. SPPC contracted with certain counterparties requiring modified payment terms including accelerated payments, pre-payments, and/or provide deposits. In the latter part of 2005, as a result of SPPC’s improved credit quality, the number of counterparties requiring modified payment terms significantly declined.

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

Qualifying Facilities

As of December 31, 2005, SPPC had a total of 126 MW of contractual firm and non-firm capacity under contract with QFs. In 2005, energy purchased by SPPC from the QFs constituted 13.9 % of SPPC’s net purchased power requirements for native load and 7.7% of SPPC’s net system requirements (including generation).

Renewable Energy

Nevada law requires SPPC to acquire or generate a specific percentage of its energy from renewable resources (Renewables). Renewables include biomass, geothermal, solar and wind projects. State law sets forth the portfolio standard requiring providers of electric service to acquire, generate, or save a specific percentage of its energy from renewable resources or to use portfolio energy credits (portfolio credits) to comply with the portfolio standard. Pursuant to the statutory portfolio standard, SPPC is required to obtain six percent of its total energy from renewable resources for 2005 and 2006. SPPC will be required to meet nine percent of its total energy from renewable resources for 2007 and 2008. The portfolio standard increases to 20% by 2015. Of the total portfolio standard, not more than 25% may be based on energy efficiency measures from qualified conservation programs and not less than five percent of that amount must be from solar resources.

SPPC is required to file an annual report that describes the level of compliance with Nevada’s Renewable Energy Portfolio Standard (RPS). As with the 2004 filing, SPPC’s 2005 filing reported that it had not fully complied with the RPS requirements and described ongoing activities intended to gain compliance in future years.

In response to the RPS reports, the PUCN ordered SPPC to develop and file a plan that would achieve the earliest possible compliance. The PUCN also approved a stipulated settlement in which the parties agreed that SPPC would not be fined for non-compliance. On August 1, 2005, SPPC submitted a plan to achieve compliance with the RPS. The PUCN reviewed the plan and determined that more specificity was required. On December 15, 2005, SPPC filed a revised compliance plan and is awaiting action by the PUCN. In April 2006, SPPC will file its annual compliance report with the PUCN for calendar year 2005. In 2005, SPPC acquired or generated approximately 7.7% of its total energy from Renewables, but did not meet the solar requirements. SPPC will request an exemption from the PUCN for the solar portion of the portfolio standard.

To assist developers of new renewable energy projects to attempt to finance their projects, resulting in a higher rate of completion for new renewable energy projects with PUCN approved contracts and allowing SPPC to more quickly satisfy its renewable energy portfolio requirements, the PUCN amended its regulations to establish the Temporary Renewable Energy Development (TRED) program.

Transmission

SPPC’s electric transmission system is part of the Western Interconnection, the regional grid in the west. The Western Interconnection includes the interconnected transmission systems of fourteen western states, two Canadian provinces and the parts of Mexico that make up the Western Electric Coordinating Council (WECC). WECC is one of ten regional councils of the North American Electric Reliability Council, the entity responsible for the reliability, adequacy and security of North America’s bulk electric system.

SPPC’s transmission system links generating units within the SPPC control area to the SPPC distribution system. SPPC’s transmission system is directly interconnected with the transmission systems of Idaho Power, Los Angeles Department of Water and Power, Southern California Edison, PacifiCorp, Bonneville Power Administration, and Pacific Gas & Electric. SPPC currently is not directly interconnected with NPC; however, if regulators approve a recently proposed project, the two companies can be interconnected by 2011. SPPC delivers power to SPPC’s retail customers and to wholesale customers. The map below shows SPPC’s transmission system:

As the control area operator, SPPC is responsible for continuously balancing electric supply and demand by dispatching generating resources and interchange transactions so that generation internal to the control area plus net import power matches control area load. SPPC also schedules power deliveries over its transmission system and maintains reliability by verifying that customers are properly using the system within its established physical bounds.

SPPC plans, builds and operates a transmission system that delivered 9,820,317 MWH of electricity to customers in its control area in 2005 through 2,165 circuit miles of owned 60kV to 500kV transmission lines and an assortment of power transformers and phase shifting transformers with a maximum capacity of approximately 2,000 MW. SPPC processes generation and transmission

interconnection requests and requests for transmission service from a variety of customers. These requests usually involve new planning studies and the negotiation of contracts with new and existing customers in this high growth system.

In the last 7 years, due primarily to high customer growth, SPPC has constructed 2 major transmission projects totaling 347 miles of high voltage transmission at a total cost of over $254 million. The projects completed include Alturas (167 miles), and Falcon – Gonder (180 miles). SPPC has another 52 miles of transmission lines at an estimated cost of over $46 million under various phases of construction. These projects have been approved by the PUCN and are currently being permitted and constructed.

Transmission Regulatory Environment

SPPC’s wholesale transmission services are regulated by the FERC under cost based regulation subject to SPR’s Operating Companies Open Access Transmission Tariff (OATT). Transmission service to SPPC’s bundled retail customers is subject to the jurisdiction of the PUCN. In accordance with the OATT, SPPC offers several transmission services to customers:

	•		Long-term and short-term firm point-to-point transmission service (guaranteed service with fixed delivery and receipt points),

	•		Non-firm point-to-point service (“as available” service with fixed delivery and receipt points), and

	•		Network transmission service (equivalent to the service SPPC provides for SPPC’s bundled retail customers).

These services are all offered on a nondiscriminatory basis in that all potential customers, including SPPC, have an equal opportunity to access the transmission system. SPPC’s transmission business is managed and operated independently from the generating and marketing business in accordance with FERC Standards of Conduct.

SPPC is participating in the development of GridWest, a regional transmission provider in the Pacific Northwest.

SPPC Gas

Business and Competitive Environment

Overview

SPPC provides natural gas service to approximately 140,000 customers in an area of about 600 square miles in Nevada’s Reno/Sparks area. SPPC also procures natural gas for electric power generation at the Tracy and Fort Churchill plants east of Reno.

Gas Operations

SPPC is charged with meeting the growing energy needs of the residential population and expanding business and public sectors. In addition to customer growth and demand, resulting revenues are impacted by rate changes, seasonal or atypical weather and customer use. Gas demand and revenues are very seasonal for SPPC Gas. Average daily temperatures range from 72 to 33 degrees and the average high temperature to low temperature range from 91 to 19 degrees. This wide temperature swing causes gas send-out to vary substantially from a warm summer day to a cold winter day.

In recent years, natural gas prices have trended upward and fluctuated widely, depending on such factors as weather, supply, demand, and the cost of competing fuels. Natural gas supply and demand fundamentals indicate immediate continued volatility. Relatively cheap sources of fuel have been somewhat depleted and new supply is expensive to bring on-line. Additionally, gas demand has steadily increased, particularly due to an increase in gas-fired electric generation on a national level. Much of SPPC’s electric generation resources use natural gas as their primary fuel source.

To serve its growing customer base, SPPC purchases all of its natural gas supply. SPPC is well connected with several major gas producing regions and the gas transport system into Northern Nevada is robust. SPPC’s gas distribution system receives gas supplies from two interstate natural gas pipelines: Paiute Pipeline Company and Tuscarora Gas Transmission. In addition, SPPC has contracted for natural gas storage services to supplement firm and spot market purchases.

Nevada state regulations require annual filings to reset base purchased gas rates and recover deferred balances that include purchased gas costs above or below amounts collected in current rates. The regulations also require a Gas Supply Plan to be filed annually. Natural gas commodity costs are passed directly through to customers on a dollar for dollar basis. SPPC does not profit from increased natural gas prices. SPPC may also file general rate cases to adjust gas division rates including cost of service and return on investment. SPPC filed a general rate case for its gas distribution business in October of 2005. Rate cases are discussed in

more detail in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Regulatory Proceedings, and Note 3, Regulatory Actions, of the Notes to Financial Statements.

Competition

SPPC’s natural gas local distribution company (LDC) business is subject to competition from other suppliers and other forms of energy available to its customers. Large gas customers using 12,000 therms per month and that have fuel switching capability are allowed to compare natural gas prices on an interruptible basis to alternative energy source prices. Additionally, customers using greater than 1,000 therms per day have the ability to secure their own gas supplies. As of January 1, 2006, there were 16 large customers securing their own supplies. These customers have a combined firm distribution load of approximately 5,022 Decatherms (Dth) per day. Transportation customers continue to pay firm and interruptible distribution charges. These customers are responsible for procuring and paying for their own gas supply, which reduces SPPC’s purchases, but does not have an impact on net income.

Revenue

SPPC’s natural gas business accounted for $178 million in 2005 operating revenues or 16% of SPPC’s total revenues from continuing operations. SPPC expects to install approximately 5,000 meters in 2006.

Demand

Growth in all sectors is expected to continue as a result of new real estate developments under construction and planned for the near future in SPPC’s distribution service area. Projected peak demand, which will only occur when the temperature drops to negative 16 degrees, is estimated to be 187,000 Dth for the winter of 2005/2006, up from 181,000 Dth for the previous winter.

To secure gas supplies for power generation and the LDC, SPPC contracted for firm winter, summer, and annual gas supplies with over two dozen Canadian and domestic suppliers. Seasonal and monthly gas supply contracts averaged approximately 116,000 Dth per day with the winter period contracts averaging approximately 134,000 Dth per day, and the summer period contracts averaging approximately 103,000 Dth per day.

SPPC’s firm natural gas supply is supplemented with natural gas storage services and supplies from a Northwest Pipeline Co. facility located at Jackson Prairie in southern Washington. The Jackson Prairie facility contributed a total of 12,687 Dth per day of peaking supplies

Following is a summary of SPPC’s transportation and storage portfolio (as of December 31, 2005):

Firm Transportation Capacity


Northwest	68,664	decatherms per day firm	(Annual)
Paiute	68,696	decatherms per day firm	(November through March)
Paiute	61,044	decatherms per day firm	(April through October)
Paiute	23,000	decatherms per day firm	(LNG tank to Reno/Sparks)
Nova	130,217	decatherms per day firm	(Annual)
ANG	128,932	decatherms per day firm	(Annual)
National Energy Gas Transmission	130,169	decatherms per day firm	(November through April)
National Energy Gas Transmission	69,899	decatherms per day firm	(May through October)
Tuscarora	132,823	decatherms per day firm	(Annual)

Storage Capacity

Total LDC Dth supply requirements in 2004 and 2005 were 16.1 million Dth and 17.1 million Dth, respectively. Electric generating fuel requirements for 2004 and 2005 were 25.3 million Dth and 24.3 million Dth, respectively.

Gas Distribution

As of December 31, 2005, SPPC owned and operated 1,906 miles of three-inch equivalent natural gas distribution piping, 56 miles of which were added in 2005. There were several significant projects completed in 2005. A recently constructed City Gate off the Tuscarora Pipeline came on line and SPPC constructed over 20,000 feet of 12” steel gas main in various parts of the system (as a part of a multi-year project to serve our customers north of Reno, for new construction in the TRI Center Industrial Park and due to a

relocation at the Tracy Power Plant). SPPC also continued to increase its ongoing main and service replacement projects by replacing approximately 9,300 feet of various sized sections of main and approximately 75 services in 2005.

SPPC Electric and Gas

Construction Program

SPPC’s construction program and estimated expenditures are subject to continuing review and are revised from time to time due to various factors, including the rate of load growth, escalation of construction costs, availability of fuel types, the number and status of proposed independent generation projects, the need for additional transmission capacity in northern Nevada, adequacy of rate relief, SPPC’s ability to raise necessary capital, SPPC’s other cash needs and changes in environmental regulation. Under SPPC’s franchise agreements, it is obligated to provide a safe and reliable source of energy to its customers. Capital construction expenditures and estimates are reflective of SPPC’s obligation to serve its growing customer base.

SPPC’s gross construction expenditures for 2005, including AFUDC and contributions in aid of construction, were $139.6 million, and for the period 2001 through 2005, were $661.6 million. Estimated construction expenditures for 2006 and the period 2007-2010 are as follows (dollars in thousands):


	2006		2007-2010		5 - Year
Electric Facilities:
Generation ⁽¹⁾	$	174,050	$	1,370,329	$	1,544,379
Distribution		69,568		291,341		360,909
Transmission		30,173		46,803		76,976
Other		21,890		64,423		86,313

Total		295,681		1,772,896		2,068,577


Gas Facilities:
Distribution		14,160		64,834		78,994
Other		78		330		408

Total		14,238		65,164		79,402


Common Facilities		13,337		61,045		74,382


TOTAL	$	323,256	$	1,899,105	$	2,222,361

Total estimated construction and plant cash requirements for 2006 and the 2007-2010 periods consist of the following (dollars in thousands):


	2006			2007-2010			Total 5 - Year
Construction Expenditures	$	306,118		$	970,697		$	1,276,815

Projects included in IRP but not yet approved by PUCN ⁽¹⁾		17,138			928,408			945,546


Total Construction Expenditures		323,256			1,899,105			2,222,361

AFUDC		(8,108	)		(218,391	)		(226,499	)
Net Salvage/ Cost of Removal		(201	)		(845	)		(1,046	)
Net Customer Advances and CIAC		(19,076	)		(80,196	)		(99,272	)


Total Cash Requirements	$	295,871		$	1,599,673		$	1,895,544


(1)		Included in this amount is a 500 MW coal fired generating station to be completed in 2010 with an estimated cost of $812 million. This project is expected to be replaced with the recently announced Ely Energy Center to be filed under SPPC’s amendment to its 2004 IRP with the PUCN by July of 2006. The cost for this project has not been finalized at this time and is not included in the table.

SPPC is planning to construct an additional combined cycle generator at the Tracy Plant. On December 14, 2005, the PUCN approved the construction of a new 514 MW gas-fired combined cycle plant at the Tracy Generating Station. Estimated construction cost is approximately $421 million with completion expected in 2008. Total project costs incurred through December 31, 2005, were $3.8 million.

OTHER SUBSIDIARIES OF SIERRA PACIFIC RESOURCES

Tuscarora Gas Pipeline Company

Tuscarora Gas Pipeline Company (TGPC) was formed in 1993 as a wholly owned subsidiary of SPR for the purpose of entering into a partnership with a wholly owned subsidiary of TransCanada PipeLines, Ltd., headquartered in Calgary, Alberta, Canada. The partnership, Tuscarora Gas Transmission Company (Tuscarora) owned 50% by TGPC was formed for the purpose of constructing and operating an interstate natural gas pipeline from Malin, Oregon to Reno, Nevada to serve an expanding natural gas market in northern Nevada and northeastern California. In late 1995, Tuscarora completed the construction of its 229-mile pipeline system and began commercial operations on December 1, 1995. Tuscarora has since continued to expand its system with the addition of compression and added pipeline to meet the growing demand for natural gas in the region and particularly in the northern Nevada. As an interstate natural gas pipeline, Tuscarora takes custody of its customers’ volumes of natural gas near Malin, Oregon and transports that gas to various delivery points along the Tuscarora system, as prescribed by those customers. At Malin, Oregon the Tuscarora pipeline interconnects with Gas Transmission Northwest Corporation (GTN), the pipeline located immediately upstream of Tuscarora. GTN is a major interstate natural gas pipeline system extending from the U.S./Canadian border, at a point near Bonners Ferry, Idaho to the Oregon/California border near Malin, Oregon. The GTN system provides Tuscarora customers access to Canadian natural gas reserves located in the Western Canadian Sedimentary basin, one of the largest natural gas reserve basins in North America.

As an interstate natural gas pipeline, Tuscarora provides only transportation service to its customers. SPPC was the only customer at the start of commercial operations in 1995 and while Tuscarora serves many other customers today, SPPC continues to be Tuscarora’s largest customer contributing 72% of gross revenues in 2005.

Sierra Pacific Communications

Sierra Pacific Communications (SPC) was formed as a Nevada corporation in 1999 to identify and develop business opportunities in telecommunications services and infrastructure. SPC entered 2004 with two distinct business areas. The first involved a fiber optic system extending between Salt Lake City, Utah and Sacramento, California (the Long Haul System) and the second was the Metro Area Network (MAN) business in Las Vegas and Reno, Nevada.

In 2004, SPC disposed of their MAN assets and certain portions of their long haul system. SPC retains possession of one duct and associated occupancy rights in the Long Haul System allowing SPC to complete the transfer and sale of this duct, which was negotiated under a 2002 contract with Qwest Communications (Qwest) for $20 million. In accordance with Statement of Financial Accounting Standards 144, Accounting for the Disposition or Impairment of Long-Lived Assets, SPR has reported the remaining Long Haul System as discontinued operations.

Due to certain legal issues, SPR has been delayed in consummating the sale of the Long Haul System to Qwest. In October 2005, the assets were presented to Qwest, however, Qwest rejected SPC’s request to tender alleging primarily that SPC failed to deliver a timely completion notice. SPC denies these claims and believes Qwest remains obligated to perform under the contract terms. SPC has initiated mandatory arbitration with Qwest.

Lands of Sierra

Lands of Sierra (LOS) was organized in 1964 to develop and manage SPPC’s non-utility property in Nevada and California. These properties previously included retail, industrial, office and residential sites, timberland, and other properties. In keeping with SPR’s strategy to focus on its core energy business, LOS continues to sell its remaining properties, which are located in Nevada and are of minimal book value. LOS does not materially contribute to the results of operations of SPR.

For a discussion of other subsidiaries’ results of operations, refer to Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations.

ENVIRONMENTAL (SPR, NPC AND SPPC)

As with other utilities, NPC and SPPC are subject to federal, state and local regulations governing air, water quality, hazardous and solid waste, land use and other environmental considerations. Nevada’s Utility Environmental Protection Act requires approval of the PUCN prior to construction of major utility, generation or transmission facilities. The United States Environmental Protection Agency (EPA), Nevada Division of Environmental Protection (NDEP), and Clark County Health District (CCHD) administer regulations involving air quality, water pollution, solid, and hazardous and toxic waste. See Note 14, Commitments and Contingencies, Environmental of the Notes to Financial Statements, for further discussion.

Federal Legislative and Regulatory Initiatives

Congress has from time to time considered legislation that would amend the Clean Air Act to target specific emissions from electric utility generating plants. If enacted, this legislation would require reductions in emissions of nitrogen oxides, sulfur dioxide and mercury. There is significant uncertainty at this time as to whether such legislation will be passed by Congress and, if passed, the timing and extent of any required reductions.

In addition, in 2005 EPA issued its Clean Air Mercury Rule (CAMR) and Clean Air Visibility Rule (CAVR), both of which are the subject of litigation by various parties. Should it be upheld, the CAMR provides for management of mercury emissions based on the quantity of mercury allowances it would allocate to individual coal-fired generating units. If the NDEP adopts regulations consistent with the CAMR’s proposed mercury allowance allocation, based on emission test data currently available, the Utilities’ coal-fired units would have sufficient mercury allowances until the second phase of the CAMR, which would take effect some time after 2015, subject to outcome of the rule challenges noted above. If the CAVR withstands legal challenges, it would require utility generating units and other industrial sources, which may ultimately be shown through air quality modeling to contribute to reduced visibility in designated Class I areas (for the most part National Parks), to install Best Available Retrofit Technology to reduce emissions, in approximately 2015-2017. Because of the uncertainty relating to the proposed legislation and regulations, management is not able at this time to predict the requirements that may ultimately take effect, the timing of such requirements, and the potential impact of these initiatives on SPR or the Utilities.

The United Nations-sponsored Kyoto Protocol contains specific greenhouse gas emission reduction targets for developed countries as a response to concerns over global warming and climate change. In 2001, President Bush announced that the U. S. would not ratify the Kyoto Protocol. Instead, the administration’s greenhouse gas policy currently favors voluntary actions, continued research and technology development. Although several bills have been introduced in Congress that would require carbon dioxide emission reductions by electric utilities and other industries, none has been enacted, and there are presently no federal mandatory greenhouse gas reduction requirements. SPR may be affected by future federal or state legislation or regulations mandating a reduction in greenhouse gas emissions. Because of the high level of uncertainty regarding whether any legislation or regulations will be adopted in this area, management is unable at this time to evaluate the potential impact of any such measures on SPR or the Utilities.

GENERAL — EMPLOYEES (ALL)

SPR and its subsidiaries had 3,158 employees as of February 1, 2006, of which 1,767 were employed by NPC and 1,281 were employed by SPPC.

NPC’s current contract with the International Brotherhood of Electrical Workers (IBEW) Local No. 396, which covers approximately 58% of NPC’s workforce, was renegotiated and ratified April 7^,, 2005. The new contract is in effect until February 1, 2008. The three-year contract provided for a 4% general wage increase for bargaining unit employees effective February 2, 2005, with 3.75% increases in 2006 and 2007. In addition, the agreement includes modifications to holiday schedules, health care cost sharing, retirement benefits and other operational productivity improvements.

SPPC’s current contract with the IBEW Local No. 1245, which represents approximately 64% of SPPC’s workforce, was set to expire on December 31, 2005. Both SPPC and IBEW 1245 are currently in negotiations for a new contract which has not been reached as of March 6, 2006. Current contract language allows for the extension of the contract while negotiations on a new labor contract continue. All terms of the current collective bargaining agreement (CBA) will continue during the negotiating process and until a new contract is ratified by IBEW membership. If either party wishes to terminate the contract they must provide the other party 30 days’ written notice.

GENERAL — FRANCHISES (NPC AND SPPC)

The Utilities have nonexclusive local franchises or revocable permits to carry on their business in the localities in which their respective operations are conducted in Nevada and California. The franchise and other governmental requirements of some of the cities and counties in which the Utilities operate provide for payments based on gross revenues. Public utilities are required by law to collect from their customers a universal energy charge (UEC) based on consumption. The UEC is designed to help those customers who need assistance in paying their utility bills or need help in paying for ways to reduce energy consumption. During 2005, the Utilities collected $87.6 million in franchise or other fees based on gross revenues. They collected $9.6 million in UEC based on consumption. They also paid and recorded as expense $900 thousand of fees based on net profits.

The Utilities will apply for renewal of franchises in a timely manner prior to their respective expiration dates.

ITEM 1A. RISK FACTORS

For the purposes of this section, the terms “we,” “us” and “our” refer to SPR on a consolidated basis (including NPC and SPPC). The risks and uncertainties described below are not the only ones we face. Additional risks and uncertainties that are not presently known or that we currently believe to be less significant may also adversely affect us.

The Utilities may not be able to mitigate fuel and wholesale electricity pricing risks which could result in unanticipated liabilities or increased volatility in our earnings.

The Utilities’ business and operations are subject to changes in purchased power prices and fuel costs that may cause increases in the amounts they must pay for power supplies on the wholesale market and the cost of producing power in their generation plants. As evidenced by the western utility crisis that began in 2000, prices for electricity, fuel and natural gas may fluctuate substantially over relatively short periods of time and expose the Utilities to significant commodity price risks. Among the factors that could affect market prices for electricity and fuel are:

	•		prevailing market prices for coal, oil, natural gas and other fuels used in generation plants, including associated transportation costs, and supplies of such commodities;

	•		changes in the regulatory framework for the commodities markets that they rely on for purchased power and fuel;

	•		liquidity in the general wholesale electricity market;

	•		the actions of external parties, such as the FERC or independent system operators, that may impose price limitations and other mechanisms to address some of the volatility in the western energy markets;

	•		weather conditions impacting demand for electricity or availability of hydroelectric power or fuel supplies;

	•		union and labor relations;

	•		natural disasters, wars, embargoes and other catastrophic events; and

	•		changes in federal and state energy and environmental laws and regulations.

As a part of the Utilities’ risk management strategy, they focus on executing contracts for power deliveries to the Utilities’ physical points of delivery to mitigate the commodity-related risks listed above. To the extent that open positions exist, fluctuating commodity prices could have a material adverse effect on their cash flows and their ability to operate and, consequently, on our financial condition.

Increasing energy commodity prices, particularly with respect to natural gas, have a significant effect on our short-term liquidity. Although the Utilities are entitled to recover their prudently incurred power, natural gas and fuel costs through deferred energy rate case filings with the PUCN, if current commodity prices hold or increase, the Utilities’ deferred energy balances will increase, which will negatively affect our cash flow and liquidity until such costs are recovered from customers.

The Utilities are also subject to credit risk for losses that they incur as a result of non-performance by counterparties of their contractual obligations to deliver fuel, purchased power or settlement payments. The Utilities often extend credit to counterparties and customers and they are exposed to the risk that they may not be able to collect amounts owed to them. Credit risk includes the risk that a counterparty may default due to circumstances relating directly to it, and also the risk that a counterparty may default due to circumstances that relate to other market participants that have a direct or indirect relationship with such counterparty. Should a counterparty, customer or supplier fail to perform, the Utilities may be required to replace existing contracts with contracts at then-current market prices or to honor the underlying commitment.

The Utilities are also subject to liquidity risk resulting from the exposure that their counterparties perceive with respect to the possible non-performance by the Utilities of their physical and financial obligations under their energy and fuel contracts. These counterparties may under certain circumstances, pursuant to the Utilities agreements with them, seek assurances of performance from the Utilities in the form of letters of credit, prepayment or cash deposits. In periods of price volatility, the Utilities’ exposure levels can change significantly, which could have a significant negative impact on our liquidity and earnings.

As of February 24, 2006 NPC had approximately $170.4 million available under its $500 million revolving credit facility and SPPC has approximately $216 million available under its $250 million revolving credit facility. The combined effects of higher natural gas prices, significant deferred energy balances and ongoing under-recovery of fuel, energy and natural gas costs may have a negative effect on our short-term liquidity.

If NPC and/or SPPC do not receive favorable rulings in the deferred energy applications that they file with the PUCN and they are unable to recover their deferred purchased power, gas and fuel costs, we will experience an adverse impact on cash flow and earnings. Any significant disallowance of deferred energy charges in the future could materially adversely affect our cash flow, financial condition and liquidity.

The rates that the Utilities charge their customers and certain aspects of their operations are subject to the regulation of the PUCN, which significantly influences the Utilities’ operating environment and affects their ability to recover costs from their customers. Under Nevada law, purchased power, gas and fuel costs in excess of those included in base rates are deferred as an asset on their balance sheets and are not shown as an expense until recovered from their retail customers. The Utilities are required to file deferred energy applications with the PUCN at least once every twelve months so that the PUCN may verify the prudence of the energy costs and allow them to clear their deferred energy accounts. Nevada law also requires the PUCN to act on these cases within a specified time period. Any of these costs determined by the PUCN to have been imprudently incurred cannot be recovered from the Utilities’ customers. Past disallowances in the Utilities’ deferred energy cases have been significant.

On January 17, 2006, NPC filed its annual deferred energy rate case seeking to recover past costs of $171.5 million and to increase going-forward rates by $138 million. The filing, if approved by the PUCN, would result in an overall 9% increase to recover costs already incurred and a 8% increase to account for current and anticipated future costs. On December 1, 2005, SPPC filed its annual deferred energy rate case seeking to recover past costs of $46.7 million and to increase going forward rates by $53 million. Decisions on NPC’s and SPPC’s deferred energy rate cases are expected in the second quarter of 2006. As of December 31, 2005, NPC’s and SPPC’s unapproved deferred energy costs, including claims for terminated energy supply contracts, were $282 million and $69.1 million, respectively, and SPPC’s unapproved gas deferred energy costs were $2.1 million.

Material disallowances of deferred energy costs, gas costs or inadequate base tariff energy rates would have a significant adverse effect on the Utilities’ financial condition and future results of operations, could cause downgrades of SPR’s and the Utilities’ securities by the rating agencies and would make it more difficult to finance operations and buy fuel and purchased power from third parties.

If NPC and/or SPPC do not receive favorable rulings in their future general rate cases, it will have a significant adverse effect on our financial condition, cash flows and future results of operations.

The Utilities’ revenues and earnings are subject to changes in regulatory proceedings known as general rate cases, which the Utilities file with the PUCN approximately every two years. In the Utilities’ general rate cases, the PUCN establishes, among other things, their recoverable rate base, their return on common equity, overall rate of return, depreciation rates and their cost of capital.

On October 3, 2005, SPPC filed a gas and electric general rate case requesting a $27 million increase in its electric rates, for an overall increase of 3.4%, and a $8.3 million increase in its natural gas rates, for an overall increase of 5.4%. On January 23, 2006,

SPPC reduced the amount requested in its electric filing to $3.2 million, for an overall increase of 0.4% in electric rates. A decision on SPPC’s gas and electric general rate case is expected early in the second quarter of 2006. NPC’s next general rate case will be filed in the fourth quarter of 2006.

We cannot predict what the PUCN will direct in their orders on the Utilities’ pending or future general rate cases. Inadequate base energy rates would have a significant adverse effect on the Utilities’ financial condition and future results of operations and could cause additional downgrades of their securities by the rating agencies and make it significantly more difficult to finance operations and to buy fuel and purchased power from third parties.

Past regulatory decisions significantly adversely affected our liquidity. Adverse regulatory decisions could cause downgrades of our credit ratings which, in turn, could limit our access to the capital markets and make it difficult for the Utilities to obtain power necessary for their operations.

On March 29, 2002, the PUCN issued a decision in NPC’s deferred energy rate case disallowing $434 million of its request to recover deferred purchased power and fuel costs through rate increases to its customers. Following this decision by the PUCN, each of Standard & Poor’s Rating Services (“S&P”) and Moody’s Investor Service, Inc. (“Moody’s”) lowered our unsecured debt ratings to below investment grade. As a result of these downgrades, our ability to access the capital markets to raise funds to service our debt obligations and refinance our maturing debt became limited. Since that time, SPR and the Utilities have completed a series of financings that have extended the debt maturities, reduced interest costs, improved their capital structure, increased liquidity and enhanced the credit of SPR and the Utilities. As a result, Moody’s improved the credit ratings of SPR and the Utilities, S&P changed our credit outlook to “positive” from “negative,” and Fitch Ratings Ltd. (“Fitch”) commenced credit coverage at the equivalent ratings as Moody’s. Currently, S&P, Moody’s and Fitch have our credit ratings on “stable” outlook. SPR and the Utilities will continue to look for opportunities to improve their financial strength and improve their credit quality. However, any future downgrades would increase our cost of capital and limit our access to the capital markets.

Historically, the Utilities have purchased a significant portion of the power that they sell to their customers from power suppliers. If their credit ratings are downgraded, they may experience difficulty entering into new power supply contracts, and to the extent that they must rely on the spot market, they may experience difficulty obtaining such power from suppliers in the spot market in light of their financial condition. In addition, if the Utilities experience unexpected failures or outages in their generation facilities, they may need to purchase a greater portion of the power they provide to their customers. If they do not have sufficient funds or access to liquidity to obtain their power requirements, particularly for NPC at the onset of the summer months, and are unable to obtain power through other means, their business, operations and financial condition will be materially adversely affected.

The Utilities plan to make significant capital expenditures to construct new transmission and generating facilities. If we are unable to finance such construction or limit the amount of capital expenditures associated therewith to forecasted levels, our financial condition and results of operation could be adversely affected.

Our long term business objectives include plans to construct new generating and transmission facilities. Such construction will require significant capital expenditures that the Utilities may finance through significant additional borrowings under the Utilities’ respective credit facilities, through additional debt financings in private or public offerings or through debt or equity financings by SPR. We cannot be sure that we will be able to obtain financing for such capital expenditures on favorable terms, or at all. Neither can we be sure that we will be successful in limiting capital expenditures to planned amounts. Failure to obtain favorable financing arrangements for our planned capital expenditures and to be able to limit such capital expenditures to forecasted amounts would adversely affect our financial condition and results of operation.

The Utilities’ ability to access the capital markets is dependent on their ability to obtain regulatory approval to do so.

The Utilities must obtain regulatory approval in Nevada in order to borrow money or to issue securities and will therefore be dependent on the PUCN to issue favorable orders in a timely manner to permit them to finance their operations, construction and acquisition costs and to purchase power and fuel necessary to serve their customers. We cannot assure you that the PUCN will issue such orders or that such orders will be issued on a timely basis.

SPR and the Utilities have substantial indebtedness that they may be required to refinance. The failure to refinance indebtedness would have an adverse effect on us.

SPR and the Utilities have indebtedness that must be repaid, purchased, remarketed or refinanced. If the Utilities do not have sufficient funds from operations and/or SPR does not have sufficient funds from dividends to repay such indebtedness at maturity, we will have to refinance the indebtedness through additional financings in private or public offerings. If, at the time of any financing or refinancing, prevailing interest rates or other factors result in higher interest rates on the refinanced debt, the increase in interest expense associated with the refinancing could adversely affect our cash flow, and, consequently, the cash available for payments on

our other indebtedness. If the Utilities are unable to refinance or extend outstanding borrowings on commercially reasonable terms, or at all, they may have to:

	•		reduce or delay capital expenditures planned for replacements, improvements and expansions; and/or

	•		dispose of assets on disadvantageous terms, potentially resulting in losses and adverse effects on cash flow from their operating activities.

We cannot assure you that the Utilities could effect or implement any of these alternatives on satisfactory terms, if at all. If SPR or the Utilities are unable to refinance indebtedness as it matures, our cash flow, financial conditions and liquidity could be materially adversely affected.

If SPR is precluded from receiving dividends from the Utilities, its financial condition and ability to meet its debt service obligations will be materially adversely affected.

SPR is a holding company with no significant operations of its own. Its cash flows are substantially derived from dividends paid to it by the Utilities, which are typically utilized to service SPR’s debt and pay dividends on SPR’s common stock, with the balance, if any, reinvested in our subsidiaries as contributions to capital. The Utilities are subject to restrictions on their ability to pay dividends to SPR under the terms of certain of their respective financing agreements and, in the case of SPPC, under the terms of its restated articles of incorporation. In addition, certain provisions of the Federal Power Act could, depending on the interpretation thereof, limit or prohibit the payment of dividends to SPR.

Assuming that the Utilities meet the requirements to pay dividends under the Federal Power Act, the most restrictive of the dividend restrictions applicable to the Utilities individually can be found, for NPC, in NPC’s Series E Notes and, for SPPC, in SPPC’s Series H Notes. Under their material dividend restrictions, each of the Utilities may pay dividends to SPR if each such Utility can meet a 2 to 1 fixed charge coverage ratio test. If that condition is met, the amount of dividends that can be paid is less than 50% of such Utilities’ consolidated net income plus the amount of capital contributions made to such Utility by SPR for the period from the date of issuance of the respective series of Notes to the end of the most recently ended fiscal quarter. If they do not meet these conditions, in order for either of the Utilities to pay dividends to SPR, other than to pay SPR’s reasonable fees and expenses, the Utility must have a cash flow to fixed charge coverage ratio of at least 1.75:1 over the prior four fiscal quarters as a condition to their payment of dividends. In addition, under the most restrictive of their dividend restrictions, NPC and SPPC are limited to paying no more than $15 million and $25 million, respectively, to SPR, from the date of issuance of the applicable debt securities. Although each Utility currently meets the conditions described above, a significant loss by either Utility could cause that Utility to be precluded from paying dividends to SPR until such time as that Utility again meets the coverage test. In 2005, SPR received approximately $59.2 million in dividends from the Utilities to meet its debt service obligations.

SPR’s indebtedness is effectively subordinated to the liabilities of its subsidiaries, particularly NPC and SPPC. SPR and the Utilities have the ability to issue a significant amount of additional indebtedness under the terms of their various financing agreements.

Because SPR is a holding company, its indebtedness is effectively subordinated to the Utilities’ existing and future liabilities. SPR conducts substantially all of its operations through its subsidiaries, and thus SPR’s ability to meet its obligations under its indebtedness will be dependent on the earnings and cash flows of those subsidiaries and the ability of those subsidiaries to pay dividends or to advance or repay funds to SPR. Holders of SPR’s indebtedness will generally have a junior position to claims of SPR’s subsidiaries creditors of, including trade creditors, debt holders, secured creditors, taxing authorities, guarantee holders and preferred stockholders. As of January 31, 2006, the Utilities had approximately $3.6 billion of debt outstanding and SPPC had approximately $50 million stated value of preferred stock outstanding. The terms of SPR’s indebtedness restrict the amount of additional indebtedness that SPR and the Utilities may issue. Based on SPR’s December 31, 2005 financial statements, assuming an interest rate of 6.0%, SPR’s indebtedness restrictions would allow SPR and the Utilities to issue up to approximately $482 million of additional indebtedness in the aggregate, unless the indebtedness being issued is specifically permitted under the terms of SPR’s indebtedness. In addition, NPC and SPPC are subject to restrictions under the terms of their various financing agreements on their ability to issue additional indebtedness.

The Utilities are subject to numerous environmental laws and regulations that may increase our cost of operations, impact or limit our business plans, or expose us to environmental liabilities.

The Utilities are subject to extensive federal, state and local statutes, rules and regulations relating to environmental protection. These laws and regulations can result in increased capital, operating, and other costs, particularly with regard to enforcement efforts focused on power plant emissions obligations. These laws and regulations generally require us to obtain and comply with a wide variety of environmental licenses, permits, inspections and other approvals, and may be enforced by both public

officials and private individuals. We cannot predict the outcome or effect of any action or litigation that may arise from applicable environmental regulations.

In addition, either of the Utilities may be required to be a responsible party for environmental clean up at sites identified by environmental agencies or regulatory bodies. We cannot predict with certainty the amount or timing of future expenditures related to environmental matters because of the difficulty of estimating clean up costs. There is also uncertainty in quantifying liabilities under environmental laws that impose joint and several liability on all potentially responsible parties. Environmental regulations may also require us to install pollution control equipment at, or perform environmental remediation on, our facilities.

Existing environmental regulations may be revised or new regulations may be adopted or become applicable to us. Revised or additional regulations, which result in increased compliance costs or additional operating restrictions, could have a material adverse effect on our financial condition and results of operations particularly if those costs are not fully recoverable from our customers.

Furthermore, we may not be able to obtain or maintain all environmental regulatory approvals necessary to our business. If there is a delay in obtaining any required environmental regulatory approval or if we fail to obtain, maintain or comply with any such approval, operations at our affected facilities could be halted or subjected to additional costs. Further, at some of our older facilities the cost of installing the necessary equipment may cause us to shut down those generation units.

Our operating results will likely fluctuate on a seasonal and quarterly basis.

Electric power generation is generally a seasonal business. In many parts of the country, including our service areas, demand for power peaks during the hot summer months, with market prices also peaking at that time. As a result, our operating results in the future will likely fluctuate substantially on a seasonal basis. In addition, we have historically sold less power, and consequently earned less income, when weather conditions in our service areas are milder. Unusually mild weather in the future could diminish our results of operations and harm our financial condition.

War and the threat of terrorism or epidemics may harm our future growth and operating results.

The growth of our business depends in part on continued customer growth and tourism demand in the Las Vegas portion of our service area. Changes in consumer preferences or discretionary consumer spending in the Las Vegas portion of our service area could harm our business. The terrorist attacks of September 11, 2001 had a negative impact on travel and leisure expenditures, including lodging, gaming and tourism. Although activity levels in the Las Vegas area have recovered significantly since then, we cannot predict the extent to which future terrorist and war activities, or epidemics, in the United States and elsewhere may affect us, directly or indirectly. An extended period of reduced discretionary spending and/or disruptions or declines in airline travel and business conventions could significantly harm the businesses in and the continued growth of the Las Vegas portion of our service area, which could harm our business and results of operations. In addition, instability in the financial markets as a result of war, terrorism or epidemics may affect our ability to raise capital.

A continued military presence in Iraq or any other military strikes may affect our operations in unpredictable ways, such as increased security measures and disruptions of fuel supplies and markets, particularly oil. Uncertainty surrounding retaliatory military strikes or a sustained military campaign may affect our business in unpredictable ways, including disruptions of fuel supplies and markets, and the possibility that our infrastructure facilities (which include our pipelines, production facilities, and transmission and distribution facilities) could be direct targets or indirect casualties of an act of terror. War and the possibility of a prolonged military presence in Iraq may have an adverse effect on the economy in general, which could adversely affect our business, operations and financial condition.

ITEM 1B. UNRESOLVED STAFF COMMENTS

SPR, NPC and SPPC have received no written comments regarding their periodic or current reports from the SEC staff that were issued 180 days or more preceding the end of their 2005 fiscal year and that remain unresolved.

ITEM 2. PROPERTIES

Substantially all of NPC’s utility plant assets are subject to the lien of the Indenture of Mortgage, dated October 1, 1953, among NPC and Deutsche Bank Trust Company Americas, as trustee, securing NPC’s outstanding first mortgage bonds.

Additionally, all of NPC’s property in Nevada is subject to the lien of the General and Refunding Mortgage Indenture dated as of May 1, 2001 between NPC and The Bank of New York, as trustee, which lien is junior, subject and subordinate to the prior lien of the Indenture of Mortgage mentioned above.

Substantially all of SPPC’s utility plant assets are subject to the lien of the Indenture of Mortgage, dated December 1, 1940, between SPPC and U.S. Bank National Association, and Gerald R. Wheeler, as trustees, securing SPPC’s outstanding first mortgage bonds.

Additionally, all of SPPC’s property in Nevada is subject to the lien of the General and Refunding Mortgage Indenture dated as of May 1, 2001 between SPPC and The Bank of New York, as trustee, which lien is junior, subject and subordinate to the prior lien of SPPC’s Indenture of Mortgage mentioned above.

The following is a list of NPC’s share of generation plants including the type and fuel used to generate, the capacity (MW), and the years that the units were installed.


							Commercial Operation
Plant Name	Type	Fuel	No. of Units		MW Capacity		Year
Clark (1) (2)	Combined Cycle	Gas/Oil		6		500	1979, 1979, 1980, 1982, 1993, 1994

	Gas	Gas/Oil		1		59	1973

Sunrise	Steam	Gas		1		80	1964

	Gas	Gas/Oil		1		76	1974

Harry Allen (3)	Gas	Gas/Oil		2		152	1995, 2006

Chuck Lenzie (4)	Combined Cycle	Gas		6	1, 200		2006

Silverhawk (5)	Combined Cycle	Gas		3		420	2004

Mohave (6)	Steam	Coal		—		—	1971, 1971

Navajo (7)	Steam	Coal		3		255	1974, 1975, 1976

Reid Gardner (8)	Steam	Coal		4		324	1965, 1968, 1976, 1983


Total				27		3,066


1)		The two combined cycles at Clark each consist of two gas turbines, two Heat Recovery Steam Generators (HRSG), and one steam turbine. In 1993 and 1994, the original four gas turbines (1979-1982) were combined with four new HRSGs and two new steam turbines to form the combined cycles.

2)		Three of Clark steam units were retired in 2005, per stipulation approved by PUCN on September 23, 2005. The associated units are not included in the table above.

3)		The second Harry Allen unit, which does not have dual fuel capability, will be available for the 2006 summer season.

4)		The two combined cycles at Lenzie each consist of two gas turbines, two HRSGs and one steam turbine. The partially completed plant was purchased from Duke Energy in 2004. Unit 1 was placed in service in January 2006. Unit 2 is expected to be available for the 2006 summer peak.

5)		NPC acquired a 75% ownership interest in the 560 MW Silverhawk power station from Pinnacle West in January 2006. The Southern Nevada Water Authority will continue to hold a 25% ownership interest in the plant. The plant will be available for the 2006 summer peak. The combined cycle plant consists of two gas turbines, two HRSGs and one steam turbine.

6)		Mohave has been temporarily shut-down as of December 31, 2005. The associated units are not included in the table above. Prior to the shut-down, the total capacity of NPC’s 14% share in the generating station was approximately 222 MWs. See Note 14, Commitments and Contingencies, Environment of the Notes to Financial Statements for further discussion.

7)		NPC has an 11.3% interest in the Navajo Generating Station. The total capacity of the Station is 2,250 MW. Salt River Project is the operator (21.7% interest). There are four other partners: U.S. Bureau of Reclamation (24.3% interest), Los Angeles Dept. of Water & Power (21.2% interest), Arizona Public Service Co (14% interest), and Tucson Electric Power (7.5% interest).

8)		Reid Gardner Unit No. 4 is co-owned by the California Department of Water Resources (CDWR) (67.8%) and NPC (32.2%); NPC is the operating agent. NPC is entitled to 25 MW of base load capacity and 235 MW of peaking capacity from that Unit, subject to the following limitations: 1,500 hours/year, 300 hours/month, and 8 hours/day. There was a 15 MW upgrade to the Unit in 1990, which is now under CDWR’s control; the total summer net capacity of the Unit, subject to heat input limitation, is 257 MW. Reid Gardner Units 1, 2, and 3, subject to heat input limitations, are 100 MW each; the total capacity of the Station is 557 MW.

The following is a list of SPPC’s share of generation plants including the type and fuel used to generate, the capacity (MW), and the years that the units became operational.


					MW		Commercial Operation
Plant Name	Type	Fuel	Number of Units		Capacity		Year
Ft. Churchill	Steam	Gas/Oil		2		226	1968, 1971

Tracy	Steam	Gas/Oil		3		244	1963, 1965, 1974

Tracy 4&5 (1)	Combined Cycle	Gas		2		108	1996, 1996

Clark Mtn. CT’s	Gas	Gas/Oil		2		144	1994, 1994

Valmy (2)	Steam	Coal		2		261	1981, 1985

Other (3)	Gas, Diesels	Propane, Oil		16		62	1960 — 1970


Grand Total				27		1,045


1)		Tracy 4&5 were part of the Piñon Pine Integrated Coal Gasification Combined Cycle power plant located at Tracy Station. This project was part of the Department of Energy’s Clean Coal Demonstration Program. Although the coal gasification portion of the facility has never proven operational, the combined cycle unit has been operating on natural gas since 1996. The combined cycle consists of one combustion turbine, one HRSG, and one steam turbine.

2)		Valmy is co-owned by Idaho Power Company (50%) and SPPC (50%); SPPC is the operator. The Plant has a total capacity of 522 MW.

3)		The number of diesel units available was reduced by six units compared to 2004 due to a combination of obsolescence and/or emissions restrictions.

ITEM 3. LEGAL PROCEEDINGS

Nevada Power Company and Sierra Pacific Power Company

Enron Litigation

Settlement Agreement

On February 1, 2006, the Utilities completed the settlement of long-term, ongoing litigation involving Enron’s market manipulation during the Western United States energy crisis and Enron’s claims with respect to terminated purchase power contracts between Enron Power Marketing Inc. (“Enron”) and the Utilities in accordance with the terms of the Settlement Agreement, entered into as of November 15, 2005 among the Utilities, Enron, and other related Enron affiliates (the “Settlement Agreement”). The Settlement Agreement provided for the settlement and release of the on-going litigation, regulatory proceedings, appellate proceedings, proofs of claim and other claims between Enron and the Utilities related to these matters, before the U.S. Bankruptcy Court for the Southern District Court of New York (the “Enron Bankruptcy Court”), the U.S. District Court for the Southern District of New York (the “District Court”), the FERC, the U.S. Court of Appeals for the Ninth Circuit (the “Ninth Circuit”) and the U.S. Court of Appeals for the District of Columbia (the “DC Court of Appeals”).

The Settlement Agreement was conditioned upon receipt of approvals from the Enron Bankruptcy Court and the FERC. The Settlement Agreement received approval from the Enron Bankruptcy Court on December 15, 2005. The FERC’s approval of the Settlement Agreement was received on January 25, 2006, which triggered the mutual releases and discharges of all past, existing and future claims between the parties. Although the Settlement Agreement did not require the approval of the PUCN, the Utilities expect to seek recovery of the net amounts paid under the Settlement Agreement in future rate case filings with the PUCN.

As part of the settlement, the Utilities were granted general unsecured claims (the “Unsecured Claims”) in Class Six of Enron’s Plan of Reorganization in the aggregate amount of $126.5 million (allocated $80.7 million to NPC and $45.8 million to SPPC). The Utilities paid Enron an aggregate amount of $129.0 million in connection with the terminated purchase power contracts (allocated $89.8 million from NPC and $39.2 million from SPPC). The Utilities funded the termination payment amounts through available cash resources. Approximately $63.6 million held in escrow pursuant to the terms of a stipulation between Enron and the Utilities has been returned to the Utilities. The Utilities’ escrowed general and refunding bonds, in the outstanding principal amount of approximately $185.7 million for NPC and $92.3 million for SPPC, have been cancelled and returned to the Utilities and may be used to support future issuances of general and refunding securities by the Utilities.

rate cases. To the extent the Utilities are not permitted to recover these costs through rate filings, the amounts not permitted would be charged as a current operating expense.

The Enron Bankruptcy Court restrictions that the Utilities could not transfer any funds or assets other than to unaffiliated third parties for ordinary course of business operating and capital expenses and could not pay dividends to SPR other than for SPR’s current operating expenses and debt payment obligations were lifted in connection with the settlement.

Enron Litigation before FERC

FERC Early Termination Case

On October 6, 2003, the Utilities filed a Complaint with FERC raising three principal issues: (a) whether Enron exercised reasonable discretion in terminating its purchased power contracts with the Utilities; (b) whether FERC should exercise its authority to find that Enron is not entitled to collect termination payment profits; and (c) whether Enron should be otherwise denied the authority to collect such payments because to do so would be contrary to public interest. In accordance with the terms of the Settlement Agreement, the FERC Early Termination Proceeding was dismissed with prejudice.

FERC Revocation Show Cause Proceeding

In March 2003, FERC instituted a “Show Cause” proceeding on whether Enron’s market-based rate authority should be revoked in light of Enron’s engagement in illicit trading activities. The Utilities intervened in the FERC’s proceeding against Enron. In accordance with the terms of the Settlement Agreement, the Utilities withdrew from further participation in the Revocation Show Cause Proceeding (including any associated appeals).

Western United States Energy Crisis Proceedings before the FERC

FERC Gaming and Partnership Show Cause Proceeding

On June 25, 2003, FERC issued orders in two separate cases involving Enron, and the potential gaming of power markets. The first is referred to as the “Gaming Show Cause Proceeding” and the second as the “Partnership Show Cause Proceeding.” Both FERC proceedings focus on Enron’s illicit trading activity in California with various counterparties, including the People of the State of California, California state entities, California utilities and other non-Californian entities (including NPC and SPPC). In 2004, FERC consolidated the proceedings, expanded the scope of its inquiry, revisited its decision not to revoke Enron’s market-based rate authority and announced that “Enron potentially could be required to disgorge profits for all of its wholesale power sales in the Western Interconnect for the period January 16, 1997 to June 15, 2003.” Enron challenged the expanded scope of the proceeding. The Utilities, in joint coalition with other Western Parties sought clarification on available remedies, other than disgorgement. On March 11, 2005, FERC clarified that Enron’s profits under the terminated power contracts fell within the scope of that proceeding.

On July 20, 2005, FERC suspended its trial schedule, pending FERC review of a settlement agreement between the California parties and Enron. FERC also ordered Enron not to take any action to move forward the Enron Bankruptcy Court proceeding, and ordered it to join in any request for postponement of any filing or action in the Enron Bankruptcy Court proceeding. In addition, FERC ordered the remaining parties, including NPC and SPPC, to participate in settlement negotiations.

On August 8, 2005, President Bush signed the Domenici Barton Energy Policy Act into law (the “Energy Bill”), which, in part, addressed termination payment disputes concerning forward power purchase contracts terminated by Enron in 2002. The Energy Bill grants FERC exclusive jurisdiction to determine whether any such payments are unjust, unreasonable or contrary to the public interest.

In accordance with the terms of the Settlement Agreement, the Utilities withdrew from further participation in the Gaming and Partnership Show Cause Proceeding (including any associated appeals) as against Enron. The Utilities retained, however, all rights to participate in any allocation phase that may follow.

FERC 206 complaints

In December 2001, the Utilities filed ten complaints with the FERC against various power suppliers, including Enron, under Section 206 of the Federal Power Act seeking price reduction of forward wholesale power purchase contracts entered into prior to the FERC mandated price caps imposed in June 2001 in reaction to the Western United States energy crisis. The Utilities contested the amounts paid for power actually delivered as well as termination claims for undelivered power against terminating suppliers.

On June 26, 2003, the FERC dismissed the Utilities’ Section 206 complaints, stating that the Utilities had failed to satisfy their burden of proof under the strict public interest standard. On July 28, 2003, the Utilities filed a petition for rehearing, but the FERC reaffirmed its June 26, 2003 decision. The Utilities appealed this decision to the Ninth Circuit. Oral argument was held on December 8, 2004. A decision remains pending. The Utilities are unable to predict the outcome of this appeal at this time.

The Utilities have negotiated settlements with Duke Energy Trading and Marketing, Reliant Energy Services, Inc., Morgan Stanley Capital Group, El Paso Merchant Energy (EPME), now known as El Paso Marketing L.P. and Enron, but have been unable to reach agreement in bilateral settlement discussions with other respondents. In accordance with the Enron Settlement Agreement, the Utilities withdrew from further participation in the FERC 206 Complaints (including any associated appeals) as against Enron.

Reliant and Duke Antitrust Litigation

The People of the State of California, City and County of San Francisco, City of Oakland and County of Santa Clara had sued Duke and Reliant for alleged fraud, misrepresentation, and anticompetitive conduct in manipulating the California energy markets. Reliant and Duke had filed cross-complaints against any and all energy suppliers selling in California, including NPC, SPPC and SPR, on the basis that liability, if any, should be spread among any such suppliers. In November 2005, NPC, SPPC and SPR were dismissed, with prejudice, as parties in the consolidated Wholesale Electricity Antitrust Cases commenced in April 2002 against Reliant Energy Services, Inc. (“Reliant”) and Duke Energy Trading and Marketing, LLC (“Duke”).

Nevada Power Company

Morgan Stanley Proceedings

On November 29, 2005, SPR and NPC entered into a settlement agreement with Morgan Stanley Capital Group, Inc. (MSCG) resolving the litigation in the United States District Court, District of Nevada concerning various power supply contracts between NPC and MSCG that had been terminated by MSCG in April 2002 and the FERC 206 Complaint against MSCG and the related appeal described above. Under the terms of the settlement agreement, NPC paid $17.5 million to MSCG and that the parties will dismiss the litigation concerning terminated power contracts between them, and the FERC 206 proceedings as they relate to MSCG.

Three years earlier, on September 5, 2002, MSCG had first initiated arbitration seeking $25 million in termination payments pursuant to arbitration provisions in the power supply contracts with NPC. In March 2003, the arbitrator dismissed MSCG’s demand for arbitration, agreeing that the issues were not arbitrable. NPC subsequently filed a complaint in the U.S. District Court, District of Nevada for declaratory relief that it was not liable for any damages resulting from MSCG’s termination. In April, 2003, MSCG filed a counterclaim seeking $25.3 million in termination payments. In addition, MSCG filed a complaint against NPC at the FERC seeking termination payments from NPC pending resolution of the civil case. In the third quarter of 2005, the Court ordered that NPC pay MSCG for the approximately $1.8 million (plus interest) for power delivered prior to the termination. With the resolution of the termination disputes for undelivered power on November 29, 2005, all termination claims between NPC and MSCG, including those for power undelivered, have now been resolved.

El Paso Merchant Energy

On January 19, 2006, NPC and EPME entered into a Settlement Agreement in resolution of their termination claims and counterclaims under the WSPPA in the Federal District Court, District of Nevada. Parties further agreed to withdraw, as to EPME, the appeal currently pending in the Ninth Circuit (FERC 206 Appeal) and to dismiss, as to EPME, any complaints made at FERC related to such appeal. NPC agreed to pay EPME $19 million. NPC and EPME executed a final written settlement agreement implementing the terms of this settlement on February 13, 2006.

Three and a half years prior, on September 25, 2002, EPME had terminated all its forward energy contracts with NPC for alleged defaults under the WSPPA. Specifically, EPME alleged NPC failed to pay full contract price under NPC’s “delayed” payment program, which extended from May 1 to September 15, 2002. In October 2002, EPME asserted a claim against NPC for $29 million in damages, representing $19 million unpaid for power delivered from May 15 to September 15, 2002, and approximately $10 million in alleged mark to market damages for future undelivered power. After an unsuccessful mediation in June 2003, NPC commenced an action against EPME and several affiliates in the Federal District Court, District of Nevada for damages and declaratory relief resulting from breach of these purchase power contracts. With the resolution of the termination disputes on January 19, 2006, all termination claims between NPC and El Paso, including those for power undelivered, have now been resolved. Other claims between the Utilities and EPME, not covered by the parties’ settlement, remain pending in the Ninth Circuit as described below under the heading “Sierra Pacific Resources and Nevada Power Company Lawsuit Against Natural Gas Providers.” The outcome of that matter cannot be predicted.

Nevada Power Company 2001 Deferred Energy Case

On November 30, 2001, NPC made a deferred energy filing 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 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.

On March 29, 2002, the PUCN issued its Order on the 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. NPC and the Bureau of Consumer Protection (BCP) both sought individual review of the PUCN Order in the First District Court of Nevada. The District Court affirmed the PUCN’s decision. Both NPC and the BCP filed Notices of Appeal with the Nevada Supreme Court.

Supreme Court rules mandate settlement talks before a matter is set for briefing and argument. As a result of that mandatory process, NPC filed a motion with the Nevada Supreme Court seeking remand of the matter back to the PUCN to consider new evidence uncovered after the PUCN’s final decision, but on November 2, 2004, the Nevada Supreme Court denied such motion for remand.

Oral argument was heard on February 23, 2006. A decision is not expected for several months thereafter. At this time NPC is unable to predict either the outcome or timing of a decision in this matter.

Sierra Pacific Power Company

Piñon Pine

In its 2003 General Rate Case, SPPC sought recovery of its unreimbursed costs associated with the Piñon Pine Coal Gasification Demonstration Project (the “Project”). The Project represented experimental technology tested pursuant to a Department of Energy (DOE) Clean Coal Technology initiative. Under the terms of the Project agreement, SPPC and DOE agreed to each fund 50% of construction costs of the Piñon Pine unit. SPPC’s participation in the Project had received PUCN approval as part of SPPC’s 1993 integrated electric resource plan. While the conventional portion of the plant, a gas-fired combined cycle unit, was installed and performed as planned, the coal gasification unit never became fully operational. After numerous attempts to re-engineer the coal gasifier, the technology was determined to be unworkable. In its order of May 25, 2004, the PUCN disallowed $43 million of unreimbursed costs associated with the Project. SPPC filed a Petition for Judicial Review with the Second Judicial District Court of Nevada (District Court) in June 2004 (CV04-01434). On January 25, 2006, the District Court vacated the PUCN’s disallowance in SPPC’s 2003 General Rate Case and remanded the case back to the PUCN for further review as to whether the costs were justly and reasonably incurred (Order). On March 1, 2006, the PUCN voted to appeal the Order to the Nevada Supreme Court and file a motion to stay the Order pending the appeal to the Supreme Court.

Sierra Pacific Resources and Nevada Power Company

Merrill Lynch/Allegheny Lawsuit

In May 2003, SPR and NPC filed suit against Merrill Lynch & Co., Inc. and Merrill Lynch Capital Services, Inc. (collectively, “Merrill Lynch”) and Allegheny Energy, Inc. and Allegheny Energy Supply Co., LLC (collectively, “Allegheny”) in the United States District Court, District of Nevada, for compensatory and punitive damages of $850 million for causing the PUCN to disallow a $180 million rate adjustment for NPC in its 2001 deferred energy case (as discussed in Part II of this report under Nevada Power Company 2001 Deferred Energy Case). The PUCN held that NPC acted imprudently when it refused to enter into an electricity supply contract with Merrill Lynch and subsequently paid too much for electricity from another source. SPR and NPC allege that Merrill Lynch and Allegheny’s fraudulent testimony and wrongful conduct caused the PUCN disallowance. The case is currently stayed pending resolution of NPC’s appeal of the 2001 deferred energy case currently pending before the Nevada Supreme Court.

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 several natural gas providers and traders. On July 3, 2003, SPR and NPC filed a First Amended Complaint. A Second Amended Complaint was filed on June 4, 2004, which named three different groups of defendants: (1) El Paso Corporation, El Paso Natural Gas Company, El Paso Merchant Energy, L.P., El Paso Merchant Energy Company, El Paso Tennessee Pipeline Company, El Paso Merchant Energy-

Gas Company; (2) Dynegy Marketing and Trade; and (3) Sempra Energy, Sempra Energy Trading Corporation, Southern California Gas Company, and San Diego Gas and Electric. The defendants filed motions to dismiss, which were granted by the District Court. SPR and NPC appealed the decision to the Ninth Circuit Court of Appeals. Briefing has been completed. Oral argument has not been scheduled. At this time, management cannot predict the timing or outcome of a decision on this matter.

Investment Banker Complaint

On November 19, 2004, SPR and NPC had filed suit in United States District Court, District of Nevada, against Citigroup, Inc., Solomon Smith Barney, Inc., J.P. Morgan Chase Bank and other banks seeking damages in excess of $500 million, asserting defendants, in concert with Enron, had falsely portrayed Enron’s financial condition and induced reliance on Enron’s financial statements and financial health in the 1990s and early 2000 time period. Effective January 10, 2005, the suit had been transferred to MDL-1446, In re Enron Corp. Securities, Derivative and Erisa Litigation, pending in the United States District Court in Houston, Texas before Judge Melinda Harmon.

On November 28, 2005, the District Court in Houston granted NPC and SPR’s Motion for Voluntary Dismissal, with prejudice, submitted in accordance with the Settlement Agreement. The voluntary dismissal fully resolves the Investment Banker matter.

Other Legal Matters

SPR and it 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 their financial positions or results of operations.

Environmental Matters

Nevada Power Company

Mohave Generation Station

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. Pursuant to the decree, Mohave Units 1 and 2 have ceased operations as of January 1, 2006 as the new emission limits are not met. The estimated cost of new pollution controls to meet the limits, and other capital investments is $1.2 billion. Should such investments be undertaken in the future, as a 14% owner in Mohave, NPC’s cost would be $168 million.

When operating, 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.

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. On October 20, 2004, the CPUC issued a proposed decision which, among other things, directed SCE to continue negotiations with the Tribes regarding post-2005 coal and water supply, and directed SCE to conduct a study of potential alternatives to Mohave.

Because coal and water supplies necessary for long-term operation of Mohave have yet to be secured, SCE and the other Mohave co-owners (the “Owners”) have been prevented from commencing the installation of extensive pollution control equipment that must be put in place to meet the emission limits contained in the decree. Due to the lack of resolution regarding continual availability of the coal and water supply with the Tribes, the Owners did not proceed with the installation of required pollution control equipment. Thus the Owners suspended operation of the plant on December 31, 2005, pending resolution of these issues. It is the Owners’ intent to preserve their ability to restart the plant at a later date should these issues be resolved, and economic analysis at that time support such a decision. NPC’s ownership interest in Mohave comprised approximately 10% of NPC’s peak generation capacity. See further discussion of issues related to Mohave in Note 14, Commitments and Contingencies of the Notes to Financial Statements.

Reid Gardner Station

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 reviewed and approved by NDEP. In collaboration with NDEP, NPC has evaluated remediation requirements. In May 2004, NPC submitted a schedule of remediation actions to NDEP which included proposed dates for corrective action plans and/or suggested additional assessment plans for each specified area. Pond construction and lining costs to satisfy the NDEP order expended to date are approximately $25 million. Expenditures for 2006 through 2010 are projected to be approximately $21 million.

In August 2004, NDEP conducted a Facility Air Quality Operating Permit (Title V permit) inspection at the Reid Gardner Station. NDEP requested monitoring, recordkeeping and reporting items and information pertaining to the sources identified in the Title V permit. NPC complied with the request and any subsequent requests that followed. In September and October 2004, NPC met with NDEP to review the results of NDEP’s inspection. NDEP informed NPC of possible non-compliance with some elements of its Title V permit, and on December 2, 2004 issued Notices of Alleged Violation (NOAVs) relating to record-keeping, monitoring and other alleged administrative infractions. Discussions between NPC and NDEP ensued. On July 20, 2005, NDEP issued new Notices of Alleged Violations (NOAVs). In part, these NOAVs represent reissuance of the previously issued NOAVs dated December 2, 2004 and address additional monitoring and reporting issues for the period September 2002 through December 2004. Additional NOAVs were issued concerning intermittent opacity emissions and the monitoring, record-keeping and reporting of such emissions. All NOAVs are subject to an administrative hearing before the Nevada State Environmental Commission and then to judicial review. On July 26, 2005 NPC received a letter from the EPA requiring submittal of information relating to compliance of Reid Gardner Station with opacity emission limits and reporting requirements. NPC has responded to the EPA information request.

NPC is engaged in an ongoing dialogue and settlement discussions with NDEP and the EPA and DOJ regarding the NOAVs. Management has booked a minimum liability with respect to these matters; however, because management cannot predict at this time whether a final settlement will be reached, it cannot accurately predict the cost of additional environmental controls and equipment changes, environmental benefit projects, monetary penalties, and/or other measures that may be required to achieve a settlement of the alleged violations.

Clark Station

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 the Clark County Health District entered into a Corrective Action Order requiring, among other steps, capital expenditures at the Clark Station totaling approximately $3 million. In March 2001, the EPA issued an additional request for information that could result in remediation beyond that specified in the November 2000 Corrective Action Order. On October 31, 2003, the EPA issued a violation regarding turbine blade upgrades, which occurred in July 1993. A conference between the EPA and NPC occurred in December 2003. NPC presented evidence on the nature and finding of the alleged violations. In March 2004, the EPA issued another request for information regarding the turbine blade upgrades, and NPC provided information responsive to this request in April and May 2004. NPC’s position is that a violation did not occur. Monetary penalties and retrofit control cost, if any, cannot be reasonably estimated at this time.

NEICO

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 has a reclamation estimate supported by a bond of approximately $5 million with the Utah Division of Oil and Gas Mining, which management believes is sufficient to cover reclamation costs. Management is continuing to evaluate various options including reclamation and sale.

Sierra Pacific Power Company

PCB Treatment, Inc.

material was not disposed of, but remained on-site. A number of the largest PRP’s formed a steering committee, which has completed site investigations and along with the EPA has determined that the Sites should be remediated by removing the buildings to the appropriate landfills. SPPC is a member of this steering committee. The EPA issued an administrative order on consent requiring the steering committee to oversee the performance of the work. One of the two buildings has been dismantled and the work has commenced on the other site. While the final cost to complete the work is not yet definite, SPPC’s share of the cost is not expected to be material.

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

None.

EXECUTIVE OFFICERS OF THE REGISTRANT

The following are current executive officers of the companies indicated and their ages as of December 31, 2005. There are no family relationships among them. Officers serve a term which extends to and expires at the annual meeting of the Board of Directors or until a successor has been elected and qualified:

Walter M. Higgins, 61, Chairman, President and Chief Executive Officer, SPR

Chairman, President and Chief Executive Officer of SPR and Director and Chief Executive Officer of NPC and SPPC since August 2000. Mr. Higgins served as Chairman, President and Chief Executive Officer of AGL Resources, Inc., from February 1998 to August 2000. He is also a director of AEGIS Insurance Services, the American Gas Association, Edison Electric Institute, Western Energy Institute and several not-for-profit organizations.

Michael W. Yackira, 54, Corporate Executive Vice President and Chief Financial Officer, SPR

Mr. Yackira was elected to his position in October 2004 and holds the same position at NPC and SPPC. From December 2003 to October 2004 he held the position of Executive Vice President and CFO, at both NPC and SPPC. Mr. Yackira was previously Executive Vice President, Strategy and Policy, from January to December 2003. Previously he was the Vice President and CFO of Mars, Inc. from 2001 to 2002. Prior to that, he was with Florida-based FPL Group, Inc. from 1989 to 2000. Mr. Yackira is a certified public accountant.

Donald L. “Pat” Shalmy, 65, Corporate Senior Vice President, Policy & External Affairs, SPR; President, NPC

Mr. Shalmy was elected to his present position in November 2004. From July 2002 to October 2004 he held the position of President, NPC. He was previously Senior Vice President, NPC since May 2002. Formerly he held the position of Director, Government and Community Relations at Kummer, Kaempfer, Bonner & Renshaw Ltd. Prior to that, Mr. Shalmy was County Manager of Clark County for 12 ¹/2 years and President of the Las Vegas Chamber of Commerce for four years. He is also a director of the Las Vegas Monorail Company.

Jeffrey L. Ceccarelli, 51, Corporate Senior Vice President, Service Delivery & Operations; President, SPPC

Mr. Ceccarelli was elected to his present position in October 2004. From June 2000 to October 2004 he held the position of President, SPPC. He previously held the position of Vice President, Distribution Services, New Business, in July 1999 for SPPC and NPC. A civil engineer, Mr. Ceccarelli has been with SPPC since 1972.

Paul L. Kaleta, 50, Corporate Senior Vice President, General Counsel and Corporate Secretary, SPR.

Mr. Kaleta was elected to his present position in February 2006, and holds the same position at NPC and SPPC. Previously he was General Counsel for Koch Industries, Inc. and various Koch subsidiaries from 1998 to 2005. Prior to that, he was Vice President and General Counsel of Niagara Mohawk Power Company for 10 years.

Roberto R. Denis, 56, Corporate Senior Vice President, Generation & Energy Supply, SPR, NPC and SPPC

Mr. Denis was elected to his present position in October 2004. From August 2003 to October 2004 he held the position of Vice President, Energy Supply, for NPC and SPPC. From 2001 to 2003, he held the position of Vice President, Market & Regulatory Affairs, at FPL Energy, LLC. From 1999 to 2001, he held the position of Vice President of Market Services.

Stephen R. Wood, 62, Corporate Senior Vice President, Administration, SPR

Mr. Wood was elected to his present position in July 2004 and holds the same position at NPC and SPPC. He was previously President, Centaur Energy Development LLC, from 2000 to 2004. From 1997 to 2000 he served as President of Louisville Gas and Electric Company and President, Distribution Services, LG&E Energy Corp. concurrently. He was Executive Vice President and Chief Administrative Officer, LG&E Energy Corp. from 1994 to 1997. He is also a director of Martin Engineering, Inc.

John E. Brown, 55, Controller, SPR

Mr. Brown was elected to his current position in May 2001, and holds the same position at SPPC and NPC. Previously he held the position of Director, Corporate and Tax Accounting, and Director, Internal Audit. Mr. Brown has been with SPR since 1981.

William D. Rogers, 45, Corporate Treasurer, SPR

Mr. Rogers was elected to his current position on June 8, 2005. Before joining SPR, he served as managing director of debt capital markets for Merrill Lynch & Co. in New York from 2000 to 2005. Prior to that, he served as managing director of debt capital markets with JP Morgan Chase in New York from 1992 until 2000.

Mary O. Simmons, 50, Vice President, External Affairs, SPPC

Ms. Simmons was elected to her current position in November 2004. From May 2001 to October 2004, she held the position of Vice President, Rates and Regulatory Affairs, for NPC and SPPC. Previously she held the position of Controller for SPR and SPPC since 1997 and held the same position with NPC beginning in 1999. Ms. Simmons is a certified public accountant and has been with SPR since 1985.

PART II


ITEM 5.		MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES (SPR)

SPR’s Common Stock is traded on the New York Stock Exchange (symbol SRP). The high and low sale prices of the Common Stock in the consolidated transaction reporting system in “The Dow Jones News Retrieval Service” for 2005 and 2004 are as follows:


	2005				2004
	High		Low		High		Low
First Quarter	$	11.30	$	9.00	$	8.53	$	7.19
Second Quarter		13.05		10.11		7.90		6.57
Third Quarter		15.36		12.05		9.00		7.55
Fourth Quarter		15.20		12.34		10.54		8.93

Number of Security Holders:


Title of Class		Number of Record Holders
Common Stock: $1.00 Par Value		As of February 23, 2006: 18,849

The Board last declared a dividend on SPR’s Common Stock on February 6, 2002. Since that time, the Board has determined not to pay a dividend on SPR’s Common Stock. Dividends are considered periodically by SPR’s Board of Directors and are subject to factors that ordinarily affect dividend policy, such as current and prospective earnings, current and prospective business conditions, regulatory factors, SPR’s financial conditions and other matters within the discretion of the Board, as well as dividend restrictions set forth in SPR’s 8 5/8% Senior Notes due 2014, 7.803% Senior Notes due 2012 and 6.75% Senior Notes due 2017. The Board will continue to review the factors described above on a periodic basis to determine if and when it would be prudent to declare a dividend on SPR’s Common Stock. There is no guarantee that dividends will be paid in the future, or that, if paid, the dividends will be paid at the same amount or with the same frequency as in the past. See Note 9, Debt Covenant Restrictions of the Notes to Financial Statements, for a description of the restrictions on NPC’s and SPPC’s ability to pay dividends to SPR and on SPR’s ability to pay dividends on its common stock.

For information on the equity compensation plans, see Item 12.

ITEM 6. SELECTED FINANCIAL DATA

See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, for a discussion of factors that may affect the future financial condition and results of operations of SPR, NPC and SPPC.

SIERRA PACIFIC RESOURCES


	Year ended December 31,
	(dollars in thousands; except per share amounts)
	2005⁽⁵⁾		2004⁽⁴⁾		2003⁽³⁾			2002⁽²⁾			2001⁽¹⁾
Operating Revenues	$	3,030,219	$	2,823,839	$	2,787,543		$	2,984,604		$	4,574,987


Operating Income (Loss)	$	358,781	$	338,785	$	271,464		$	(27,508	)	$	224,641


Net Income (Loss) from Continuing Operations	$	86,240	$	35,635	$	(104,160	)	$	(294,979	)	$	35,818


Income (Loss) from Continuing Operations Per Average Common Share — Basic	$	0.46	$	0.19	$	(0.90	)	$	(2.89	)	$	0.41


Income (Loss) from Continuing Operations Per Average Common Share — Diluted	$	0.46	$	0.19	$	(0.90	)	$	(2.89	)	$	0.41


Total Assets	$	7,870,546	$	7,528,467	$	7,063,758		$	7,110,639		$	8,132,727


Long-Term Debt	$	3,817,122	$	4,081,281	$	3,579,674		$	3,226,281		$	3,570,750


Dividends Declared Per Common Share	$	—	$	—	$	—		$	0.20		$	0.40


(1)		In 2001, the Utilities implemented deferred energy accounting for fuel and purchased power costs. Under deferred energy accounting, to the extent actual fuel and purchased power costs exceed fuel and purchased power costs recoverable through current rates, the 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. For the year ended 2001, fuel and purchase power costs were higher than normal due to the Western Energy Crisis. Additionally, Operating Revenues were significantly higher in 2001 compared to other years due to volumes of wholesale electric power to other utilities and hedging activity.

(2)		Loss from Continuing Operations and Total Assets for the year ended 2002 was severely affected by the write-off of deferred energy costs and related carrying charges of $523 million as a result of the PUCN decision in NPC’s and SPPC’s deferred energy cases disallowing $434 million and $53 million, respectively, of deferred purchased fuel and power costs.

(3)		Loss from Continuing Operations for the year ended 2003 was negatively affected by an unrealized net loss of $46.1 million on the derivative instrument associated with the issuance of SPR’s $300 million Convertible Notes, $91 million write-off of deferred energy costs by NPC and SPPC and approximately $52 million of interest charges related to the Enron Litigation.

(4)		Income from Continuing Operations for the year ended 2004 includes the reversal of $39.8 million in interest expense due to the decision on the appeal of the Enron bankruptcy judgment, and the write-off of $47.1 million in disallowed plant costs at SPPC.

(5)		Income from Continuing Operations for the year ended 2005, includes a charge of $54 million for the inducement for debt conversion and the reversal of $20.9 million in interest charges as a result of settlements with terminated suppliers.

NEVADA POWER COMPANY


	Year ended December 31,
	(dollars in thousands)
	2005⁽⁵⁾		2004⁽⁴⁾		2003⁽³⁾		2002⁽²⁾			2001⁽¹⁾
Operating Revenues	$	1,883,267	$	1,784,092	$	1,756,146	$	1,901,034		$	3,025,103


Operating Income (Loss)	$	228,827	$	216,490	$	183,733	$	(104,003	)	$	144,364


Net Income (Loss)	$	132,734	$	104,312	$	19,277	$	(235,070	)	$	63,405


Total Assets	$	5,173,921	$	4,883,540	$	4,210,759	$	4,166,988		$	4,791,261


Long-Term Debt	$	2,214,063	$	2,275,690	$	1,899,709	$	1,683,310		$	1,802,680


Dividends Declared — Common Stock	$	35,258	$	45,373	$	—	$	10,000		$	33,000


(1)		In 2001, NPC implemented deferred energy accounting for fuel and purchased power costs. Under deferred energy accounting, to the extent actual fuel and purchased power costs exceed fuel and purchased power costs recoverable through current rates, the 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. For the year ended 2001, fuel and purchase power costs were higher than normal due to the Western Energy Crisis, as a result. Additionally, Operating Revenues were significantly higher in 2001 compared to other years due to volumes of wholesale electric power to other utilities and hedging activity.

(2)		Net Loss and Total Assets for the year ended 2002 was severely affected by the write-off of $465 million of deferred purchased fuel and power costs and related carrying charges.

(3)		Net Income for the year ended 2003 included a $46 million write-off of deferred energy costs and $36 million of interest charges related to the Enron litigation.

(4)		Net Income for the year ended 2004 included the reversal of $27.5 million in interest expense due to the decision on the appeal of the Enron Bankruptcy judgment.

(5)		For the year ended 2005, Income from Continuing Operations included the reversal in the fourth quarter of $17.7 million in interest charges as a result of settlements with terminated suppliers.

SIERRA PACIFIC POWER COMPANY


	Year ended December 31,
	(dollars in thousands)
	2005⁽⁵⁾		2004⁽⁴⁾		2003⁽³⁾			2002⁽²⁾			2001⁽¹⁾
Operating Revenues	$	1,145,697	$	1,035,660	$	1,029,866		$	1,081,034		$	1,547,430


Operating Income	$	116,304	$	111,245	$	68,566		$	55,292		$	78,968


Net Income (Loss) from Continuing Operations	$	52,074	$	18,577	$	(23,275	)	$	(13,968	)	$	22,743


Total Assets	$	2,546,301	$	2,524,320	$	2,362,469		$	2,457,516		$	2,760,770


Preferred Stock	$	50,000	$	50,000	$	50,000		$	50,000		$	50,000


Long-Term Debt	$	941,804	$	994,309	$	912,800		$	914,788		$	923,070


Dividends Declared — Common Stock	$	23,933	$	—	$	18,530		$	44,900		$	63,000


Dividends Declared — Preferred Stock	$	3,900	$	3,900	$	3,900		$	3,900		$	3,700


(1)		In 2001, SPPC implemented deferred energy accounting for fuel and purchased power costs. Under deferred energy accounting, to the extent actual fuel and purchased power costs exceed fuel and purchased power costs recoverable through current rates, the 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. For the year ended 2001, fuel and purchase power costs were higher than normal due to the Western Energy Crisis. Additionally, Operating Revenues were significantly higher in 2001 compared to other years due to volumes of wholesale electric power to other utilities and hedging activity.

(2)		Loss from Continuing Operations for the year ended 2002 was severely affected by the write-off of $58 million of deferred purchased fuel and power costs and related carrying charges.

(3)		Loss from Continuing Operations for the year ended 2003 was affected by the write-off of $45 million in June 2003 of disallowed deferred energy costs and interest charges of $16 million related to the Enron litigation.

(4)		Net Income from Continuing Operations for the year ended 2004 was affected by the write-off of $47.1 million in disallowed plant costs and the reversal of interest expense of $12.3 million due to the decision on the appeal of the Enron Bankruptcy judgment and a reduction to income tax expense of $3.3 million as a result of a flow-through adjustment for pension funding.

(5)		For the year ended 2005, Income from Continuing Operations includes the reversal in the fourth quarter of $3.2 million in interest expense related to settlements with terminated suppliers.


ITEM 7.		MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Forward-Looking Statements

The information in this Form 10-K 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)		wholesale market conditions, including availability of power on the spot market, which affect the prices NPC and SPPC (the Utilities) have to pay for power as well as the prices at which the Utilities can sell any excess power;

	(2)		whether the Utilities will be able to continue to obtain fuel, power and natural gas from their suppliers on favorable payment terms and favorable prices, particularly in the event of unanticipated power demands, sharp increases in the prices for fuel, power and/or natural gas, or a ratings downgrade;

	(3)		the ability of SPR, NPC and SPPC to maintain access to the capital markets to support their requirements for working capital, including amounts necessary to finance deferred energy costs, as well as for construction and acquisition costs and other capital expenditures, particularly in the event of unfavorable rulings by the Public Utilities Commission of Nevada (PUCN), a downgrade of the current debt ratings of SPR, NPC, or SPPC and/or adverse developments with respect to the Utilities’ power and fuel suppliers;

	(4)		unfavorable or untimely rulings in rate cases filed and to be filed by the Utilities with the 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;

	(5)		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;

	(6)		whether the Utilities will be successful in obtaining the PUCN approval to recover the outstanding balance of their other regulatory assets and other merger costs recorded in connection with the 1999 merger between SPR and NPC in a future general rate case;

	(7)		whether the Utilities will be able to continue to pay SPR dividends under the terms of their respective financing and credit agreements, limitations imposed by the Federal Power Act and, in the case of SPPC, under the terms of SPPC’s restated articles of incorporation;

	(8)		the final outcome of SPPC’s pending lawsuit in Nevada state court seeking to reverse the PUCN’s 2004 decision on SPPC’s 2003 General Rate case disallowing the recovery of a portion of SPPC’s costs, expenses and investment in the Piñon Pine Project;

	(9)		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;

	(10)		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;

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

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

	(13)		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;

	(14)		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;

	(15)		the financial decline of any significant customers;

	(16)		changes in environmental laws or regulations, including the imposition of significant new limits on mercury and other emissions from coal-fired power plants;

	(17)		changes in tax or accounting matters or other laws and regulations to which SPR or the Utilities are subject;

	(18)		future economic conditions, including inflation rates and monetary policy;

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

	(20)		unusual or unanticipated changes in normal business operations, including unusual maintenance or repairs.

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.

EXECUTIVE OVERVIEW

Management’s Discussion and Analysis of Financial Condition and Results of Operations explains the general financial condition and the results of operations for Sierra Pacific Resources (SPR) and its two primary subsidiaries, Nevada Power Company (NPC) and Sierra Pacific Power Company (SPPC), collectively referred to as the “Utilities” (references to “we,” “us” and “our” refer to SPR and the Utilities collectively), and includes the following:

•

Critical Accounting Policies and Estimates

•

Recent Pronouncements

•

For each of SPR, NPC and SPPC:

	•		Results of Operations

	•		Analysis of Cash Flows

	•		Liquidity and Capital Resources

	•		Energy Supply (Utilities)

	•		Regulatory Proceedings (Utilities)

SPR’s Utilities operate three regulated business segments which are NPC electric, SPPC electric and SPPC natural gas service. The Utilities are public utilities engaged in the distribution, transmission, generation and sale of electricity and in the case of SPPC, sale of natural gas. Other segment operations consist mainly of unregulated operations and the holding company operations. The Utilities are the principal operating subsidiaries of SPR and account for substantially all of SPR’s assets and revenues. SPR, NPC and SPPC are separate filers for SEC reporting purposes and as such this discussion has been divided to reflect the individual filers (SPR, NPC and SPPC), except for discussions that relate to all three entities or the Utilities.

The Utilities are regulated by the PUCN and for the California service territory of SPPC, the California Public Utilities Commission (CPUC), with respect to rates, standards of service, setting of and necessity for generation and certain transmission facilities, accounting, issuance of securities and other matters with respect to generation, distribution and transmission operations. 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.

Overview of Major Factors Affecting Results of Operations

During 2005, SPR’s earnings applicable to common stock was $82.2 million compared to $28.6 million in 2004. The change in earnings was primarily due to the following items (after income taxes):

	•		increases in operating income primarily resulting from general rate cases decided in 2004 as well as continued customer growth;

	•		increases in Allowance for Other Funds used During Construction and Allowance for Borrowed Funds used During Construction, for a total of approximately $29.3 million, primarily due to the construction of the Chuck Lenzie Generating Station;

	•		lower interest expenses due to refinancing activities;

	•		reversal of interest for energy suppliers on settled disputes of approximately $13.6 million.

Partially offsetting these increases in earnings applicable to common stock were the following items (after income taxes)

	•		early conversion fees of the Convertible Notes of approximately $35.1 million after taxes and unamortized debt issuance costs and legal fees associated with the various financing transactions of approximately $6.3 million after taxes.

	•		legal fees of approximately $7.4 million.

During 2004, earnings applicable to common stock were lower primarily due to the following charges (after income taxes):

	•		a non-cash goodwill impairment charge of approximately $7.6 million during 2004 (See Note 19, Goodwill and Other Merger Costs of the Notes to Financial Statements, for further discussion);

	•		a non-cash charge in 2004 to write-off disallowed merger costs of approximately $3.8 million;

	•		charges of approximately $15.4 million during 2004 of tender fees, interest costs and unamortized debt issuance costs associated with the early extinguishment of SPR’s 8³/4% Senior Unsecured Notes due 2005 (see Note 7, Long-Term Debt of the Notes to Financial Statements, for further discussion); and

	•		a charge of approximately $30.6 million (after taxes) as a result of the PUCN’s decision to disallow recovery of a portion of SPPC’s costs associated with Piñon Pine (see Regulatory Proceedings (Utilities)).

Offsetting these charges was interest charges of approximately $26 million (after income taxes) recognized in September 2003 in connection with the Enron judgment, that was reversed in 2004 based on the U.S. District Court decision, as discussed in Note 14, Commitments and Contingencies of the Notes to Financial Statements.

Overview of Key Business Issues

This review summarizes key business issues faced by SPR and the Utilities during 2005 and issues management will focus on in 2006. It is not intended to be an exhaustive discussion, nor to suggest that other issues may not arise during 2006 or thereafter. Details relating to the discussion below can be found in the Notes to the Financial Statements and elsewhere within this Management’s Discussion and Analysis of Financial Condition and Results of Operations.

SPR and the Utilities were faced with several significant business issues at the onset of 2005, including, improving debt profile, the ongoing litigation with Enron and other energy suppliers, regulatory approvals, managing of energy risk and pursuing strategic initiatives to reduce reliance on external power supplies.

Management addressed these significant business issues as follows:

Improved Debt Profile

Management has sought and continues to seek opportunities to increase liquidity, refinance existing debt at lower interest rates and to extend the maturity dates of certain indebtedness in order to obtain interest cost savings and to better manage SPR’s and the Utilities’ indebtedness profiles.

Major financing transactions completed in 2005 included, but are not limited to:

	•		remarketing of SPR’s $240 million Senior Notes associated with the Premium Income Equity Securities (PIES)

	•		SPR’s Private Placement of $225 million 6.75% Senior Notes due 2017

	•		NPC redemption of $87.5 million aggregate principal amount of its 10 7/8% General and Refunding Mortgage Notes, Series E, due 2009, and $122.5 million aggregate principal amount of its 9% General and Refunding Mortgage Notes, Series G, due 2013, in accordance with the redemption provisions of these securities. These redemptions constituted 35% of the principal amounts outstanding of each of the Series E and Series G Notes.

	•		conversion of SPR’s $300 million 7.25% Convertible Notes due 2010, to SPR common stock, plus an inducement payment of $54 million

	•		issuance of SPR Common Stock as settlement of the PIES

	•		improved liquidity through increased revolving lines of credit through 2010, at lower rates

These financing transactions are expected to lead toward investment grade credit ratings of the Utilities’ senior secured debt. These transactions are described in more detail in Note 7, Long-Term Debt, of the Notes to Financial Statements.

Enron Settlement

On November 15, 2005, the Utilities entered into an agreement (Settlement Agreement) with Enron Power Marketing, Inc. (Enron) that resolved the litigation that commenced in 2001 and 2002 involving Enron’s claim for more than $300 million in termination payments for terminated purchase power contracts between Enron and the Utilities and Enron’s market manipulation during the Western United States energy crisis. The Settlement Agreement provided for the settlement and release of the ongoing litigation, regulatory proceedings, appellate proceedings, proofs of claim and other claims between Enron and the Utilities related to these matters before the U.S. Bankruptcy Court for the Southern District Court of New York (the Enron Bankruptcy Court), the U.S. District Court for the Southern District of New York (the District Court), the FERC, the U.S. Court of Appeals for the Ninth Circuit (the Ninth Circuit) and the U.S. Court of Appeals for the District of Columbia (the DC Court of Appeals).

On January 26, 2006, upon final approval of the settlement with Enron, the Utilities paid Enron approximately $129 million from available cash resources. On January 27, 2006, the approximate $60 million cash held in escrow, plus interest, and NPC’s General and Refunding Series H Bond of approximately $185.7 million and SPPC’s General and Refunding Series E Bond of approximately $92.3 million were returned to the Utilities. The bonds were cancelled and may be used to support future issuances of general and refunding securities by the Utilities. As part of the settlement, NPC and SPPC were granted general unsecured claims (the “Unsecured Claims”) in Class Six of Enron’s Plan of Reorganization in the amount of $80.7 million and $45.8 million, respectively. On October 24, 2005, the Utilities purchased a put option from a major international banking institution that, if exercised, obligated that institution to purchase the Unsecured Claims (contingent upon allowance of the Unsecured Claims by the Bankruptcy Court), which ensured that the Utilities’ net cash outlay to settle Enron’s claim would be no higher than $89.9 million. On February 16, 2006, the Unsecured Claims were sold to a separate third party resulting in a final net cash outlay which did not materially differ from the anticipated cash outlay.

The Utilities intend to seek recovery of the amounts paid in connection with the Settlement Agreement, net of the proceeds from the sale of the Unsecured Claims, in future rate case filings with the PUCN. The Utilities cannot predict, whether, to what extent or upon what conditions the PUCN will approve recovery of these amounts in future rate cases. To the extent the Utilities are not permitted to recover these costs through rate filings, the amounts not permitted would be charged as a current operating expense.

Details of the Enron Litigation can be found in Note 14, Commitments and Contingencies of the Notes to Financial Statements.

Other Terminated Contract Disputes

As of January 31, 2006, all proceedings against SPR and the Utilities with respect to terminated purchased power contracts have been settled. Pursuant to deferred energy accounting provisions, included in NPC and SPPC deferred energy balances as of December 31, 2005, were approximately $83.9 million and $21.1 million of terminated contract costs, respectively, for recovery in rates in future periods. The Utilities will pursue recovery of the payments through future regulatory filings. To the extent that the Utilities are not permitted to recover any portion of these costs, 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 effect on the future financial position, results of operations, and cash flows of SPR, NPC, and SPPC. The various contract termination lawsuits are discussed in detail in Note 14, Commitments and Contingencies of the Notes to Financial Statements.

Regulatory Approvals

Decisions by the PUCN to allow full recovery of deferred energy costs over shorter amortization periods than had been experienced in prior rate cases resulted in additional cash flows for the Utilities. The PUCN approved Base Tariff Energy rates that more closely matched market costs and test periods. The PUCN also approved the construction of the Tracy combined cycle power plant for SPPC with an incentive of 1.5% above SPPC’s allowed return on equity (ROE), and also approved NPC’s acquisition and associated financing for the 75% ownership of the Silverhawk generating facility.

Execution of Generation Strategy

In 2003, NPC and SPPC embarked on a strategy to build electric power plants to reduce their exposure to the energy markets, reduce the overall price and volatility for its customers, and to increase the earnings of SPR. In line with this strategy, in October 2004, upon PUCN approval, NPC purchased a partially constructed nominally rated 1,200 MW natural gas-fired high efficiency combined cycle power plant from Duke Energy, (“Lenzie”). The PUCN further granted NPC’s request for a critical facility designation and allowed a 2% enhancement above NPC’s authorized ROE to be applied to the rate base associated with the Lenzie construction costs expended after acquisition. The order allows for up to an additional 1% enhanced ROE if the two Lenzie generator units are brought on line on or before dates specified in the order. In January 2006, NPC announced commercial operation of the first Lenzie generation unit, well ahead of the PUCN-prescribed in service date to qualify for the additional incentive. NPC expects the second unit to be commercially operable in the spring of 2006, also ahead of date necessary to qualify for the added incentive. Total construction costs are expected to be below the amount approved by the PUCN.

On June 21, 2005, NPC announced that it signed an agreement to acquire from Pinnacle West Capital Corporation (“Pinnacle West”), Pinnacle West Energy Corporation (PWEC), a wholly-owned subsidiary of Pinnacle West, and GenWest, LLC (“GenWest”), a 75 percent ownership interest in the Silverhawk Power Plant (“Silverhawk”). Silverhawk is a 560-megawatt, natural gas-fueled, combined-cycle electric generating facility located 20 miles northeast of Las Vegas. In January 2006, NPC completed the $208 million purchase of Silverhawk.

On December 14, 2005, the PUCN issued an order granting approval for SPPC to construct a 514 MW gas fired high efficiency combined cycle generator at the Tracy Plant. The PUCN also allowed SPPC to include construction work in progress balances in the rate base of any interim general rate cases and granted a 1.5% enhanced ROE for the estimated $421 million investment. In January 2006, SPPC announced it had signed contracts for construction of the unit with construction scheduled to commence in April 2006 and an in service date by June 2008. The unit will provide needed generation within the Utilities’ control area to reliably serve the growing needs of Northern Nevada.

Future Business Issues

SPR continues to focus on a “back to the basics” strategy that emphasizes the Utilities’ core business. As mentioned above, SPR’s and the Utilities’ strategies are aimed at owning more generating facilities, reducing dependence on purchased power and diversifying fuel mix while the Utilities’ service areas continue to grow. NPC and SPPC will continue to be subject to markets that over recent years have been volatile, for energy necessary to serve the Utilities’ customers that are in excess of owned generation, as well as, natural gas. With the significant amounts of construction costs in the Utilities’ future, SPR and the Utilities will need to raise substantial amounts of capital to fund the expenditures. As a result, access to capital markets at favorable investment grade ratings is a significant business focus for SPR and the Utilities in 2006.

Management of Energy Risk

The Utilities buy coal, natural gas, and oil to operate generating plants as well as buy wholesale power to meet the energy requirements of their customers. The Utilities also have invested in and maintain extensive transmission systems that allow the Utilities to move energy to meet customers’ needs. The Utilities’ significant need to tap energy markets is necessary because the Utilities’ ownership and contractual call on power generating assets is insufficient to meet our customers’ energy needs. This situation exposes the Utilities to energy risk and uncertainty as to the Utilities’ cash flow requirements for fuel and wholesale power, the expense the Utilities will incur as a result of their energy procurement efforts, and the rates the Utilities need to recover those costs. Energy risk also encompasses reliability risk — the prospect that energy supplies will not be sufficient to fulfill customer requirements.

The Utilities systematically manage and control each of the energy-related risks through three primary vehicles — organization and governance, energy risk management programs, and energy risk control practices.

The Utilities, through the purchases and sale of specified financial instruments and physical products, maintain an energy risk management program that limits energy risk to levels consistent with an approved energy supply plan. The energy risk management program provides for the systematic identification, quantification, evaluation, and management of the energy risk inherent in the Utilities’ operations.

The Utilities follow PUCN-approved energy supply plans that encompasses the reliable and efficient operation of the Utilities’ owned generation, the procurement of all fuels and purchased power and resource optimization. The process includes assessments of projected loads and resources, assessments of expected market prices, evaluations of relevant supply portfolio options available to the Utilities, and evaluations of the risk attributable to those supply portfolio options. Financial instruments for economic hedging in conjunction with energy purchases and sales are also used to mitigate these risks.

Continued Execution of Generation Strategy

In January 2006, SPR, NPC and SPPC, announced their intention to develop a major energy project located near Ely, Nevada, (the “Ely Energy Center”). The project includes two 750 MW coal-fired units utilizing the latest, state-of-the-art, fully-environmental compliant, clean pulverized coal technologies, as well as the construction of a 250-mile transmission line to interconnect NPC and SPPC. With regulatory approvals and permitting requirements, it is anticipated the first coal plant would be operational in 2011 with the second unit to follow within three years thereafter. The total estimated capital expenditures associated with the two coal plants and the transmission line is approximately $3 billion.

Liquidity and Access to Capital Markets

With rising energy costs and substantial commitments to construction, SPR and the Utilities’ liquidity needs and access to capital markets will be a significant business issue in 2006. As such, management plans to continue to evaluate opportunities to refinance high yield debt at lower interest rates. Management will be focused on returning the Utilities’ senior secured debt to investment grade credit quality. Significant amounts of capital may be necessary to fund the construction costs of new power plants and, as such, management may issue new debt as necessary. If energy costs continue to rise at a rapid rate, and the Utilities do not recover, in a timely manner, the cost of fuel and purchased power, the Utilities’ may need to issue more debt to support their operating costs.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

SPR prepared its consolidated financial statements in accordance with accounting principles generally accepted in the United States of America. In doing so, certain estimates were made that were critical in nature to the results of operations. The following discusses those significant estimates that may have a material impact on the financial results of SPR and the Utilities and are subject to the greatest amount of subjectivity. Senior management has discussed the development and selection of these critical accounting policies with the Audit Committee of SPR’s Board of Directors. The following items represent critical accounting estimates that under different conditions or using different assumptions could have a material effect on the financial condition, results of operation, cash flows, liquidity and capital resources of SPR and the Utilities:

Regulatory Accounting

The Utilities’ retail rates are currently subject to the approval of the PUCN and, in the case of SPPC, they are also subject to the 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. Under federal law, wholesale rates charged by 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.

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, Summary of Significant Accounting Policies of the Notes to Financial Statements, management believes the existing regulatory assets are probable of recovery. Management’s judgment 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 and expensed in current period earnings.

Regulatory Accounting affects other Critical Accounting Policies, including Deferred Energy Accounting, Accounting for Goodwill and Merger Costs, and Accounting for Derivatives and Hedging Activities, all of which are discussed immediately below.

Deferred Energy Accounting

Under deferred energy accounting, to the extent actual fuel and purchased power costs exceed fuel and purchased power costs recoverable through current rates, the 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 approval. Pursuant to AB 369, Nevada law 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, Nevada law specifies that fuel and purchased power costs include all costs incurred to purchase fuel, to purchase capacity, and to purchase energy. Both Utilities are entitled under statute to utilize deferred energy accounting for their electric operations and both Utilities accumulate amounts in their deferral of energy costs accounts. The Utilities also record, and are eligible under the statute to recover, a carrying charge on such deferred balances, recognized as interest income in the current period.

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 Item 7A, Quantitative and Qualitative Disclosures About Market Risk, for a discussion of the Utilities’ purchased power procurement strategies, and commodity price risk and commodity risk management program. Currently, commodity price increases are recoverable through the deferred energy accounting mechanism, with no anticipated effect on earnings. However, the Utilities are subject to regulatory risk related to commodity price changes due to the fact that the PUCN may disallow recovery for any of these costs that it considers imprudently incurred.

See Note 3, Regulatory Actions of the Notes to Financial Statements, for additional discussion of the regulatory process to recover these deferred costs and description of the PUCN’s disallowance of significant amounts in NPC’s 2001 and SPPC’s 2002 deferred energy cases.

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 related costs for a three year period, to be reviewed for recovery through future rates: merger transaction costs, transition costs and goodwill costs. 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 instructed the Utilities to propose an amortization period for the merger related costs and allowed 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 $325.1 million of goodwill and $62.8 million in other merger costs as of January 1, 2004. The deferred other merger costs consisted of $41.5 million of transaction and transition costs and $21.3 million of employee separation costs. Employee separation costs were comprised of $16.8 million of employee severance, relocation and related costs, and $4.5 million of pension and post-retirement benefits net of plan curtailment gains.

On March 26, 2004, the PUCN issued a decision on NPC’s general rate case that included the recovery of goodwill and other merger costs allocated to NPC resulting from the merger of SPR and NPC in 1999. In its decision, the PUCN affirmed that NPC demonstrated merger savings and permitted NPC to recover approximately $4 million per year for two years beginning April 1, 2004, based on a forty-year amortization of NPC’s total goodwill. The amount to be recovered over the next two years reflects a reduction of 20% from the amounts sought by NPC, or approximately $1 million per year, due to customer satisfaction survey results that the PUCN determined required improvement. The decision requires NPC to again demonstrate in its next general rate application that merger savings continue during the test period in that case. Management expects that it will be able to demonstrate continued savings as a result of the merger as well as satisfactory customer survey results. As a result of the PUCN decision, goodwill of approximately $198 million was reclassified as a regulatory asset and then transferred from the financial statements of SPR to the financial statements of NPC as of March 31, 2004.

On May 27, 2004, the PUCN approved a settlement agreement, previously entered into by SPPC, the Staff of the PUCN and other interveners in connection with SPPC’s 2003 general rate case that permits SPPC recovery of goodwill and other merger costs assigned to SPPC’s electric business. SPPC is permitted to recover approximately $2.4 million per year for two years beginning June 1, 2004, based on a forty-year amortization of goodwill costs. Similar to the decision reached in NPC’s rate case described above, in order to continue to recover goodwill costs SPPC is required to again demonstrate in its next general rate application filed October 3, 2005, that merger savings continue during the test period in that case. Management expects that it will be able to demonstrate continued savings resulting from the merger. As a result of the PUCN decision, goodwill of approximately $96 million was reclassified to a regulatory asset and transferred from the financial statements of SPR to the financial statements of SPPC as of June 30, 2004. See Note 3, Regulatory Actions for more information regarding the NPC and SPPC general rate decisions.

In addition to amounts discussed above, SPR’s Consolidated Balance Sheet as of December 31, 2005, includes approximately $4 million of goodwill assigned to SPR’s unregulated operations and $19 million assigned to SPPC’s regulated gas business. SPPC believes it has demonstrated in its general rate case filed on October 3, 2005 for the gas distribution business that savings from the merger allocable to the gas business exceed goodwill and other merger costs and, as a result, expects to recover goodwill and merger costs through future gas rates. Accordingly, management has not reviewed goodwill assigned to the gas business for impairment. However, the approximate $12 million of goodwill assigned to NPC’s and SPPC’s electric businesses that are not recoverable through future rates and approximately $4 million of goodwill assigned to SPR’s unregulated operations are subject to impairment review under the provisions of SFAS No. 142.

As part of the impairment testing analysis, management revised certain underlying assumptions utilized in previously performed preliminary analyses, that included, revised cash flow forecasts, an increase in the discount rate applied to future cash flows and other assumptions related to the outcomes of NPC’s and SPPC’s general rate cases. As a result of this impairment testing, SPR recorded a goodwill impairment charge related to NPC’s and SPPC’s electric reporting units of approximately $2 million and $10 million as a charge to other operating expenses in SPR’s, NPC’s and SPPC’s Consolidated Statements of Operations for the quarter ended March 31, 2004. Goodwill assigned to SPR’s unregulated businesses was determined not to be impaired.

We believe that the accounting estimate related to determining the fair value of goodwill, and thus any impairment, is a “critical accounting estimate” because (1) it is highly susceptible to change from period to period because it requires SPR management to make cash flow assumptions about future revenues, operating costs, and regulatory and legal contingencies; and (2) the impact that recognizing an impairment would have on the assets reported on our balance sheet as well as our net loss would be material. Management’s assumptions about future revenues, operating costs, and regulatory and legal contingencies require significant judgment because actual operating results, regulatory and legal contingencies are undeterminable.

Accounting for Derivatives and Hedging Activities

SPR, NPC, and SPPC 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 to manage price risk. All of these instruments are considered to be derivatives under SFAS No. 133 and are marked to market in the statement of financial position unless the contract qualifies for the normal purchases or sales exemption per the criteria in 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 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.

Accounting for Income Taxes

As of December 31, 2005, net operating losses (NOLs) were $246.2 million. The NOLs may be utilized in future periods to reduce taxes payable to the extent that SPR and the Utilities recognize taxable income.

The following table summarizes the tax NOL and credit carry-forwards and associated carry-forward periods, and a valuation allowance for amounts which SPR has determined that realization is uncertain (dollars in thousands):


							Expiration
	Deferred Tax Asset		Valuation Allowance		Net Deferred Tax Asset		Period

Federal NOL	$	241,295	$	—	$	241,295		2020-2023

State NOL		1,433		—		1,433		2006-2013

Alternative minimum tax credit		3,159				3,159	indefinite

Arizona state coal credits		1,248		984		264		2006-2010


Total	$	247,135	$	984	$	246,151

At December 31, 2005, the Utilities had gross federal and state NOL carry-forwards of $689.4 million and $17.7 million, respectively.

Considering all positive and negative evidence regarding the utilization of the Utilities’ deferred tax assets, it has been determined that the Utilities are more likely than not to realize all recorded deferred tax assets, except for the Arizona coal credits. As such, these Arizona coal credits represent the only valuation allowance that has been recorded as of December 31, 2005.

Litigation Contingencies

Note 14, Commitments and Contingencies of the Notes to Financial Statements discusses the significant legal matters of SPR and its subsidiaries. As described in Note 14, NPC and SPPC established accrued liabilities, included in their Consolidated Balance Sheets as of December 31, 2005, as “Contract termination liabilities,” of approximately $89.8 million and $39.2 million, respectively, 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, NPC and SPPC included approximately $84 million and $21.1 million, respectively, of charges associated with the terminated power supply contracts, deferred for recovery in rates in future periods. The Utilities will pursue recovery of these balances through future regulatory filings. To the extent

that the Utilities are not permitted to recover any portion of these costs, the disallowed amounts would be charged to current operating expense.

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 have had or, in the opinion of management, are expected to have, a significant impact on its financial position or results of operations.

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, and 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 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 14, Commitments and Contingencies of the Notes to 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.

Defined Benefit Plans and Other Postretirement Plans

As further explained in Note 12, Retirement Plan and Post-Retirement Benefits of the Notes to Financial Statements, SPR maintains a qualified pension plan, a non-qualified supplemental executive retirement and restoration plan (SERP), as well as an other postretirement benefit (OPEB) plan that provide health and life insurance for retired employees. All employees are eligible for these benefits if they terminate with certain age and service requirements from the qualified and restoration plans, or if they reach retirement age and meet certain service requirements under the SERP and OPEB plans 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 are ultimately collected in rates billed to customers. Amounts are funded to trusts maintained for the plans. The amounts funded are then used to meet benefit payments to plan participants. SPR contributed $17 million and $51.8 million to its pension plan, in 2005 and 2004, respectively, and $14.9 million and $0.2 million to the other postretirement benefits plan in 2005 and 2004, respectively. Due to the sharp decline in United States equity markets from 2000 to 2002, the value of a significant portion of the assets held in the plans’ trusts to satisfy the obligations of the plans had decreased significantly. This decrease has been funded in the Retirement Plan as noted above in 2003. At the present time it is not expected that any additional funding will be required in 2005 or 2006 to meet the minimum funding levels defined by ERISA. SPR currently expects to contribute approximately $15 million to the retirement plan and $14.7 million to the other postretirement plan in 2006; however, the amounts to be contributed may change, subject to market conditions.

Pension Plans

SPR’s reported costs of providing non-contributory defined pension benefits (described in Note 12, Retirement Plan and Post-Retirement Benefits of the Notes to Financial Statements) 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, the discount rates and mortality assumptions used in determining the projected benefit obligation and pension costs.

In accordance with SFAS No. 87, changes in pension obligations associated with these factors may not be immediately recognized as pension costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. As such, significant portions of pension costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants. For the year ended December 31, 2005, 2004, and 2003, SPR recorded pension expense of approximately $22.7 million, $28.3 million, and $35.5 million, respectively, in accordance with the provisions of SFAS No. 87. Actual payments of benefits made to retirees and terminated vested employees for the twelve months ended September 30, 2005, 2004 and 2003 were $20.3 million, $17.5 million and $17.7 million respectively.

SPR has not made changes to pension plan provisions in 2005, 2004, and 2003 that had significant impacts on recorded pension expense for these years. As further described in Note 12, Retirement Plan and Post-Retirement Benefits of the Notes to Financial Statements, SPR increased the discount rate used in determining pension expense for the calendar year 2005 from 6.00% in 2004 to 6.10%. For determining the expense to be recorded in 2006, SPR moved to a 5.75% discount rate to determine FAS 87 cost. SPR also moved to a more up-to-date mortality table (RP2000 with 15 year projections using scale AA phasing to zero) to determine the liabilities at December 31, 2005. Pension costs for 2006 are expected to increase, primarily as a result of changes in assumptions.

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 such as current discount rates, mortality assumption and/or expected rates of return on plan assets could also increase or decrease recorded pension costs.

The following chart reflects the sensitivities associated with a change in certain actuarial assumptions by the indicated percentage. While the chart below reflects an increase in the percentage for each assumption, SPR and its actuaries expect that a decrease would impact the projected benefit obligation (PBO) and the reported annual pension cost (PC) by a similar amount in the opposite direction. Each sensitivity below reflects an evaluation of the change based solely on a change in that assumption only.


	Change in	Impact on	Impact on
Actuarial Assumption	Assumption	PBO	PC
(dollars in millions)	Incr/(Decr)	Incr/(Decr)	Incr/(Decr)
Discount Rate	1%	$(74.5)	$(9.9)
Rate of Return on Plan Assets	1%	N/A	$(4.4)

In selecting an assumed discount rate for fiscal years 2004 and 2005 disclosures, and for fiscal years 2005 and 2006 pension cost, SPR’s projected benefit payments were matched to the yield curve derived from a portfolio of over 500 high quality Aa bonds with yields within the 40th to 90th percentiles of these bond yields.

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. Investment returns on plan assets in the retirement plan gained approximately $55.7 million in 2005 and $41.5 million in 2004 as a result of continued improvement in market conditions. These returns in conjunction with SPR’s contributions have improved the funded status compared to prior years.

As a result of SPR’s plan asset returns and funding through September 30, 2005, SPR recognized an increase in the additional minimum liability in the amount of $4.5 million, as prescribed by SFAS No. 87. The asset was recorded as an increase to common equity through Accumulated Other Comprehensive Income, and did not affect net income for 2005. The remaining charge to Accumulated Other Comprehensive Income will be adjusted each year to reflect assets and liabilities.

Other Postretirement Benefits

SPR’s reported costs of providing other postretirement benefits (described in Note 12, Retirement Plan and Post-Retirement Benefits of the Notes to Financial Statements) 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.

For the year ended December 31, 2005, 2004, and 2003, SPR recorded other postretirement benefit expense of approximately $14.1 million, $13.4 million, and $11.4 million, respectively, in accordance with the provisions of SFAS No. 106. Actual payments of benefits made to retirees for the twelve months ended September 30, 2005, 2004, and 2003 were $8.2 million, $8.0 million, and $7.1 million respectively.

SPR has not made changes to other postretirement benefit plan provisions in 2005, 2004, and 2003 that have had any significant impact on recorded benefit plan amounts. As further described in Note 12, Retirement Plan and Post-Retirement Benefits of the Notes to Financial Statements, SPR has revised the discount rate in 2005, as compared to 2004, from 6.00% to 6.10%. For determining the expense to be recorded in 2006, SPR moved to a 5.75% discount rate as well as a more up-to-date mortality table, namely, RP2000 white collar with 15 year projection using Scale AA phasing to zero. 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.

The following chart reflects the sensitivities associated with a change in certain actuarial assumptions by the indicated percentage. While the chart below reflects an increase in the percentage for each assumption, SPR and its actuaries expect that a decrease would impact the projected accumulated other postretirement benefit obligation (APBO) and the reported annual other postretirement benefit cost (PBC) on the income statement by a similar amount in the opposite direction. Each sensitivity below reflects an evaluation of the change based solely on a change in that assumption only.


	Change in	Impact on	Impact on
Actuarial Assumption	Assumption	APBO	PBC
(dollars in millions)	Incr/(Decr)	Incr/(Decr)	Incr/(Decr)
Discount Rate	1%	$(20.9)	$(2.0)
Health Care Cost Trend Rate	1%	$23.5	$3.4
Rate of Return on Plan Assets	1%	N/A	$(0.5)

In selecting an assumed discount rate for fiscal year 2005 pension cost and disclosures, and for fiscal year 2006 pension cost, SPR’s projected benefit payments were matched to the yield curve derived from a portfolio of over 500 high quality Aa bonds with yields within the 40th to 90th percentiles of these bond yields.

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 December 31, 2005,include unbilled receivables of $80 million and $77 million for NPC and SPPC, respectively. Customer accounts receivable as of December 31, 2004 include unbilled receivables of $83 million and $67 million for NPC and SPPC, respectively.

RECENT PRONOUNCEMENTS

See Note 1, Summary of Significant Accounting Policies of the Notes to Financial Statements, for discussion of accounting policies and recent pronouncements.

SIERRA PACIFIC RESOURCES

RESULTS OF OPERATIONS

Sierra Pacific Resources (Holding Company) and Other Subsidiaries

SPR (Holding Company)

The Holding Company’s (stand alone) operating results included approximately $74.3 million, $88.3 million, and $75.3 million of long-term debt interest costs for the years ended December 31, 2005, 2004, and 2003 respectively. The holding company’s operating results for 2005 were negatively affected by early conversion fees of the Convertible Notes of approximately $35 million after taxes and unamortized debt issuance costs and legal fees associated with the Convertible Notes of approximately $4.7 million after taxes. See Note 7, Long-Term Debt of the Notes to Financial Statements, for further discussion on the conversion of the Convertible Notes. The Holding Company’s operating results for 2004 were negatively affected by an impairment of goodwill of approximately $11.7 million and higher interest costs. The Holding Company recognized charges of approximately $23.7 million during 2004 for tender fees, interest costs and unamortized debt issuance costs associated with the early extinguishment of SPR’s 8³/4% Senior Unsecured Notes due 2005. The Holding Company’s operating results for 2003, were negatively affected by an unrealized net loss of $46.1 million on the derivative instrument associated with the convertible note debt. This unrealized loss had no effect on cash flows. See Note 7, Long-Term Debt of the Notes to Financial Statements, for further discussion on the Convertible Notes.

Tuscarora Gas Pipeline Company

TGPC, a wholly-owned subsidiary of SPR, contributed $5.1 million in net income for the year ended December 31, 2005, $5.2 million in net income for the year ended December 31, 2004 and $3.9 million in net income for the year ended December 31, 2003.

Sierra Pacific Communications

SPC, a wholly-owned subsidiary of SPR, which is reported as discontinued operations, incurred a net loss of $103 thousand for the year ended December 31, 2005, a net loss of $3.2 million for the year ended December 31, 2004, and a net loss of $25.2 million for the year ended December 31, 2003. SPC’s loss in 2004 was primarily due to the settlement with Sierra Touch America, see Note 18, Discontinued Operations and Disposal and Impairment of Long-Lived Assets of the Notes to Financial Statements, for further discussion. SPC’s loss for the year ended December 31, 2003 was due to the impairment charge of $32.9 million recognized in the second quarter of 2003.

Other Subsidiaries

Other Subsidiaries of SPR did not contribute materially to the consolidated results of operations of SPR.

Sierra Pacific Resources (Consolidated)

See Executive Overview, Results of Operations for SPR Consolidated.

ANALYSIS OF CASH FLOWS

SPR’s consolidated net cash flows decreased for the year ended December 31, 2005 compared to the same period in 2004, as a result of decreases in cash from operating and financing activities and an increase in cash used by investing activities. Cash flows for operating activities are lower in 2005 due to energy costs being higher than amounts recovered in rates in 2005. Offsetting the decrease in cash from operating activities was the $60 million escrow payment for Enron in 2004, a reduction in prepayments and deposits for energy in 2005 due to the establishment of the revolving credit facilities and an increase in general rates in the second quarter of 2004. The increase in cash used by investing activities was mainly due to construction at NPC for the Chuck Lenzie project. The decrease in cash from financing activities in 2005, when compared to 2004, was primarily due to the reduction of debt issued in 2005.

SPR’s consolidated net cash flows increased during 2004, when compared to 2003, due mainly to almost $300 million in additional debt, and rate increases to recover deferred energy balances and operating costs. A major portion of the new debt was for the purchase of the partially constructed Lenzie project from Duke Energy. This purchase is reflected in the increase in net cash used by investing activities, which was offset by cash received upon the disposal of property belonging to SPR’s unregulated subsidiaries, SPC and Lands of Sierra (LOS). Cash flows from operating activities were higher during 2004 as a result of rate increases that went

into effect in the second quarter of 2004, offset by higher interest payments, pension plan funding and the payment of $61 million to the Enron escrow account ordered by the judge overseeing the bankruptcy proceedings of Enron.

LIQUIDITY AND CAPITAL RESOURCES (SPR CONSOLIDATED)

Overall Liquidity

SPR’s consolidated operating cash flows are primarily derived from the operations of NPC and SPPC. The primary source of operating cash flows for the Utilities is revenues (including the recovery of previously deferred energy and natural gas costs) from sales of electricity and natural gas. Significant uses of cash flows from operations include the purchase of electricity and natural gas, other operating expenses and interest. SPR, on a stand-alone basis, had cash and cash equivalents of approximately $35.1 million at December 31, 2005. SPR has approximately $51.8 million payable of debt service obligations for 2006, which it intends to pay through dividends from subsidiaries. See “Factors Affecting Liquidity—Dividends from Subsidiaries” below.

SPR and the Utilities anticipate that they will be able to meet operating costs such as fuel and purchased power costs with internally generated funds, including the recovery of deferred energy. However, in order to fund capital requirements, as discussed below, SPR and the Utilities may meet such financial obligations with a combination of internally generated funds, the use of the Utilities’ revolving credit facilities and if necessary, the issuance of long term debt.

SPR’s overall liquidity continued to improve in 2005. The increases in the Utilities’ general, electric and gas rates, as discussed further in Regulatory Proceedings, improved debt profile, the settlement of various litigation, as discussed in Note 14, Commitments and Contingencies of the Notes to Financial Statements, and management of energy risk are allowing SPR to continue to improve its overall liquidity. SPR’s debt profile improved in 2005, as a result of several financing transactions, including the early conversion of SPR’s 7.25% Convertible Notes, the conversion of SPR’s Corporate Premium Interest Equity Securities (PIES) to common stock, and the redemption of $210 million of high coupon debt at NPC. These financing transactions are expected to reduce future interest expense.

SPR designs operating and capital budgets to control operating costs and capital expenditures. In addition to operating expenses, SPR has continuing commitments for capital expenditures for construction, improvement and maintenance of facilities.

Detailed below are SPR’s Capital Structure, Capital Requirements, recently completed financing transactions and factors affecting our ability to obtain debt on favorable terms, including the effect of our holding company structure and limitation on dividends from the Utilities.

Capital Structure (SPR Consolidated)

SPR’s actual capital structure on a consolidated basis was as follows at December 31 (dollars in thousands):


	2005					2004

Short-Term Debt (1)	$	58,909	1.0	%	$	8,491	0.2	%
Long-Term Debt		3,817,122	63.8	%		4,081,281	72.4	%
Preferred Stock		50,000	0.8	%		50,000	0.9	%
Common Equity		2,060,154	34.4	%		1,498,616	26.5	%

Total	$	5,986,185	100	%	$	5,638,388	100	%

(1)

Includes current maturities of long-term debt and capital lease obligations.

Capital Requirements

Construction Expenditures

SPR’s annual consolidated cash construction expenditures have increased since 2003 and are expected to continue to increase due to programs designed to meet electric load growth and reliability needs. Cash construction expenditures for the years ended 2005, 2004 and 2003 were approximately $590 million, $557 million, and $334 million, respectively. SPR’s consolidated cash construction expenditures for 2006 are projected to be $779.3 million. SPR’s consolidated cash construction expenditures for 2006-2010 are projected to be $4.6 billion and are expected to be funded by external financing, internally generated funds, which included recovery of the Utilities’ deferred energy balances and the Utilities’ existing credit facilities. The timing and extent of the estimated capital expenditures may change if the utilities receive approval for the Ely Energy Center. If this project is approved by the PUCN, each Utility’s steadily improving financial condition, as evidenced by the upgrade in credit ratings in 2005 and recent financing transactions, should allow it to successfully raise the necessary funds in the capital markets to finance construction costs.

Contractual Obligations (SPR Consolidated)

The table below provides SPR’s contractual obligations on a consolidated basis (except as otherwise indicated), not including estimated construction expenditures described above, or Pension funding requirements as discussed in Note 12, Retirement Plan and Post-Retirement Benefits of the Notes to Financial Statements, as of December 31, 2005, that SPR expects to satisfy through a combination of internally generated cash and, as necessary, through the issuance of short-term and long-term debt (dollars in thousands):


	Payment Due by Period
	2006		2007		2008		2009		2010		Thereafter		Total
NPC/SPPC Long-Term Debt Maturities (1)	$	58,909	$	8,350	$	329,466	$	185,058	$	157,843	$	2,480,758	$	3,220,384
NPC/SPPC Long-Term Debt Interest Payments (1)		216,397		213,011		197,923		184,006		168,904		1,557,535		2,537,776
SPR Long-Term Debt Maturities		—		—		—		—		—		659,142		659,142
SPR Long-Term Debt Interest Payments		51,817		51,817		51,817		51,817		51,817		204,600		463,685
Purchase Power		526,100		345,874		336,530		287,406		287,238		3,544,035		5,327,183
Coal and Natural Gas		871,631		138,278		101,362		92,562		75,596		478,308		1,757,737
Long -Term Service Agreements (2)		3,023		3,023		3,023		3,023		3,023		24,738		39,853
Capital Purchase Commitment(3)		208,000		—		—		—		—		—		208,000
Operating Leases		13,448		7,856		7,602		7,565		7,157		38,173		81,801

Total Contractual Cash Obligations	$	1,949,325	$	768,209	$	1,027,723	$	811,437	$	751,578	$	8,987,289	$	14,295,561

(1)

Does not include principal and interest associated with NPC’s January 2006 issuance of $210 million in General and Refunding Mortgage Notes, Series M, due March 2016.

(2)

Amount does not include variable or unplanned maintenance fees related to the Chuck Lenzie service contract, of which the total contract is estimated to be approximately $150 million. The amount also does not include the January 2006 long-term service contract totaling $328 million for equipment and construction services associated with the new generation plant at the Tracy facility.

(3)

Does not include various closing adjustments related to the Silverhawk purchase.

Pension Plan Matters

SPR has a qualified pension plan that covers substantially all employees of SPR, NPC and SPPC. The annual net benefit cost for the plan is expected to increase in 2006 by approximately $7.9 million compared to the 2005 cost of $22.7 million. As of September 30, 2005, the measurement date, the plan was fully funded on a FAS 87 ABO basis (fair value of assets exceeded ABO). During 2005, SPR contributed a total of $15 million to meet its funding obligations under the plan. At the present time it is not expected that any additional funding will be required in 2006 to meet the minimum funding level requirements defined by the Pension Benefit Guaranty Corporation and ERISA. SPR and the Utilities currently expect to contribute approximately $15 million to the plan in 2006; however, the amounts to be contributed may change, subject to market conditions.

Financing Transactions (SPR — Holding Company)

Convertible Notes

On August 3, 2005, SPR announced an offer to pay a cash premium to induce holders of its $300 million outstanding ($248 million carrying value) 7.25% Convertible Notes, due 2010 to convert their Convertible Notes to shares of SPR common stock. The conversion offer, which was extended to September 2, 2005, was accepted by 100% of the holders of the Convertible Notes. Under the terms of the offer, for each $1,000 in liquidation amount of Convertible Notes tendered, holders received cash conversion consideration and 219.1637 shares of common stock. The cash consideration offered was an amount equal to $180 per $1,000 principal amount of Convertible Notes validly surrendered for conversion plus an amount equivalent to the interest that would have accrued thereon from and after August 14, 2005 (which was the last interest payment date on the Convertible Notes prior to the expiration of the offer). On September 8, 2005, 65,749,096 shares of common stock, plus cash in lieu of fractional shares, were issued and an aggregate of $54 million in cash consideration was paid to the holders in exchange for the Convertible Notes. In accordance with SFAS No. 84, “Induced Conversion of Convertible Debt,” the $54 million cash payment was expensed during the third quarter of 2005. For further details on the Convertible Notes, see Note 7, Long-Term Debt of the Notes to Financial Statements.

Private Placement

On August 12, 2005, SPR conducted a private placement of $225 million 6.75% Senior Notes due 2017. The proceeds were used to repurchase approximately $141 million 7.93% Senior Notes associated with the Old PIES, pay approximately $54 million in premiums associated with the conversion of the 7.25% Notes and fund the associated fees and expenses and provide additional liquidity to SPR.

Premium Income Equity Securities (PIES) Transactions

On April 15, 2005, SPR commenced an offer to exchange its previously-existing PIES (“Old PIES”) for newly-issued PIES (“New PIES”) plus an exchange fee of $0.125 in cash for each Old PIES tendered. On May 24, 2005, the tender offer was completed with 1,982,822 or about 41% of the 4,804,350 Old PIES outstanding tendered for exchange. The remaining 2,821,528 Old PIES remained outstanding. The New PIES were similar to the Old PIES except that the New PIES: (i) allowed for the remarketing of the senior notes that are associated with the New PIES prior to the earliest remarketing date for the Old PIES, (ii) provided for more flexible remarketing terms, and (iii) allowed certain terms of the senior notes to be modified upon their remarketing, including the maturity date of the senior notes, the redemption provisions, the interest payment dates and the addition of covenants applicable to the senior notes.

On May 24, 2005, as a component of the New PIES, SPR issued $99,142,000 aggregate principal amount of 7.93% Senior Notes, due 2007. These senior notes replaced the notes associated with the Old PIES. SPR successfully remarketed these notes on June 14, 2005. In connection with the remarketing, the interest rate of the senior notes issued in connection with the New PIES was reset to 7.803% per annum, effective on and after June 14, 2005. The remarketed senior notes will mature on June 15, 2012. The proceeds of the remarketing of the senior notes were used to purchase U.S. treasury securities and to pay the fee of the remarketing agents. The U.S. treasury securities served as substitute collateral for the senior notes component of the New PIES to secure holders’ obligations under the related forward purchase contracts. The proceeds of the U.S. treasury securities were used at maturity to fulfill holders’ payment obligations under the related forward purchase contracts on November 15, 2005, and to pay the aggregate amount of remaining interest payments to the holders of the New PIES through November 15, 2005.

On August 10, 2005, the remaining $141,076,000 aggregate principal amount of SPR’s 7.93% Senior Notes associated with the Old PIES were remarketed. On August 15, 2005, SPR used a portion of the proceeds from the $225 million 6.75% Senior Notes (described above under the heading “Private Placement”) to purchase all of the 7.93% Senior Notes that were remarketed. As with the May 2005 remarketing of the 7.93% Senior Notes, the proceeds of this remarketing were used to purchase U.S. treasury securities and to pay the fee of the remarketing agents. The U.S. treasury securities served as substitute collateral for the senior notes component of the Old PIES to secure holders’ obligations under the related forward purchase contracts. The proceeds of the U.S treasury securities were used at maturity to fulfill holders’ payment obligations under the related forward purchase contracts on November 15, 2005, and to pay the aggregate amount of remaining interest payments to the holders of the Old PIES through November 15, 2005.

On November 15, 2005, the Purchase Contract Settlement Date for the Old PIES and the New PIES, 3.6101 shares per forward purchase contract were exchanged for a total of 17,344,183 shares of common stock issued to the holders of the Old PIES and the New PIES.

Short —Term Borrowings

On June 20, 2005, SPR issued and sold $140,860,000 of its Series A Floating Rate Senior Notes, due November 16, 2005, and $99,140,000 of its Series B Floating Rate Senior Notes, due November 16, 2005 (collectively, the “Floating Rate Notes”). The Series A Floating Rate Notes initially bore interest at a rate equal to 3-month LIBOR plus 2.00%, and the Series B Floating Rate Notes bear interest at a rate equal to 3-month LIBOR plus 1.00%. On August 15, 2005, the interest rate on the Series A Floating Rate Notes was reduced to a rate equal to 3-month LIBOR plus 1.00%. Of the proceeds from this issuance, $230.5 million was used to make an equity contribution to NPC and the balance was used for general corporate purposes. NPC used the equity contribution to redeem approximately $210 million of General and Refunding Mortgage Notes.

On November 16, 2005, the Series A and Series B Floating Rate Senior Notes were repaid with the $240 million in proceeds received from the settlement of the common stock purchase contracts associated with the PIES.

Factors Affecting Liquidity

Effect of Holding Company Structure

As of December 31, 2005, SPR (stand-alone) has outstanding debt and other obligations including, but not limited to: $99 million of its unsecured 7.803% Senior Notes due 2012; $225 million of its 6.75% Senior Notes due 2017; and $335 million of its unsecured 8⅝% Senior Notes due 2014.

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 the creditors of NPC and SPPC and its other subsidiaries, including trade creditors, debt holders, secured creditors, taxing authorities, guarantee holders, NPC’s preferred trust security holders, and SPPC’s preferred stockholders.

As of December 31, 2005, SPR, NPC, SPPC, and their subsidiaries had approximately $3.9 billion of debt and other obligations outstanding, consisting of approximately $2.2 billion of debt at NPC, approximately $1 billion of debt at SPPC and approximately $660 million of debt at the holding company and other subsidiaries. Additionally, SPPC had $50 million of outstanding preferred stock. 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.

Dividends from Subsidiaries

Since SPR is a holding company, substantially all of its cash flow is provided by dividends paid to it 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 impose limits on investment returns or otherwise impact the amount of dividends that the Utilities may declare and pay, and to a 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 agreements entered into by the Utilities, restrictions on dividends contained in agreements to which NPC and SPPC are party, are detailed in Note 9, Debt Covenant Restrictions of the Notes to Financial Statements.

In addition to the restrictions imposed by specific agreements, the Federal Power Act prohibits the payment of dividends from “capital accounts”. Although the meaning of this provision is unclear, the Utilities believe that the Federal Power Act restriction, as applied to their particular circumstances, would not be construed or applied by the FERC to prohibit the payment of dividends for lawful and legitimate business purposes from current year earnings, or in the absence of current year earnings, from other/additional paid-in capital accounts. If, however, the FERC were to interpret this provision differently, the ability of the Utilities to pay dividends to SPR could be jeopardized.

Assuming that NPC and SPPC meet the requirements to pay dividends under the Federal Power Act, the most restrictive of the dividend restrictions applicable to the Utilities individually can be found for NPC, in NPC’s Series E Notes and, for SPPC, in SPPC’s Series H Notes. Under their material dividend restrictions, each of the Utilities may pay dividends to SPR if each such Utility can meet a 2 to 1 fixed charge coverage ratio test. If that condition is met, the amount of dividends that can be paid is less than 50% of such Utilities’ consolidated net income plus the amount of capital contributions made to such Utility by SPR for the period from the date of issuance of the respective series of Notes to the end of the most recently ended fiscal quarter. If they do not meet these conditions, in order for either of the Utilities to pay dividends to SPR, other than to pay SPR’s reasonable fees and expenses, the

Utility must have a cash flow to fixed charge coverage ratio of at least 1.75:1 over the prior four fiscal quarters as a condition to their payment of dividends. In addition, under the most restrictive of their dividend restrictions, NPC and SPPC are limited to paying no more than $15 million and $25 million, respectively, to SPR, from the date of issuance of the applicable debt securities. Although each Utility currently meets these tests, a significant loss by either Utility could cause that Utility to be precluded from paying dividends to SPR until such time as that Utility again meets the coverage test. In 2004, SPR received approximately $45 million in dividends from the Utilities to meet its debt service obligations. In 2005, NPC and SPPC had paid $35.3 million and $23.9 million in dividends, respectively, to SPR.

Credit Ratings

Fitch initiated ratings on all three companies on September 29, 2005, assigning a rating outlook of “Stable.” On September 27, 2005, Moody’s upgraded the senior unsecured debt rating of SPR and the senior secured ratings of NPC and SPPC. Prior to this, on August 9, 2005, Standard & Poor’s announced it had revised the outlook to positive from negative on its ratings for SPR, NPC and SPPC and revised the business profile score on all three companies from “Weak” to “Satisfactory.” The secured debt ratings for both Utilities remain below investment grade, which affects 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.

A security rating is not a recommendation to buy, sell or hold securities. Security ratings are subject to revision and withdrawal at any time by the assigning rating organization, and each rating should be evaluated independently of any other rating.

Energy Supplier Issues

With respect to NPC’s and SPPC’s contracts for purchased power, NPC and SPPC purchase and sell electricity with counterparties under the Western Systems Power Pool (WSPP) agreement, an industry standard contract that NPC and SPPC are required to use as members of the WSPP. The WSPP contract is posted on the WSPP website.

These contracts provide that a material adverse change may give rise to request adequate financial assurance, which, if not provided within three business days, could cause a default. A default must be declared within 30 days of the event, giving rise to the default becoming known. A default will result in a termination payment equal to the present value of the net gains and losses for the entire remaining term of all contracts between the parties aggregated to a single liquidated amount due within three business days following the date the notice of termination is received. The mark-to-market value, which is substantially based on quoted market prices, can be used to roughly approximate the termination payment and benefit at any point in time. The net mark-to-market value as of December 31, 2005 for all suppliers continuing to provide power under a WSPP agreement would approximate a $7 million payment by NPC and an approximate $18.5 million payment by SPPC.

Gas Supplier Issues

With respect to the purchase and sale of natural gas, NPC and SPPC use several types of standard industry contracts. The natural gas contract terms and conditions are more varied than the electric contracts. Consequently, some of the contracts contain language similar to that found in the WSPP agreement and other agreements have unique provisions dealing with material adverse changes. Because of creditworthiness concerns, most contracts and confirmations for natural gas purchases have been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery. At the present time, some natural gas purchase transactions require payment in advance of delivery.

Gas transmission service is secured under FERC Tariffs or custom agreements. These service contracts and Tariffs require the user establish and maintain creditworthiness to obtain service or otherwise post cash or a letter of credit to be able to receive service. Service contracts are subject to FERC approved tariffs, which, under certain circumstances, require the Utilities to provide collateral to continue receiving service.

Financial Covenants

Nevada Power Company and Sierra Pacific Power Company

Each of NPC’s $500 million Second Amended and Restated Revolving Credit Agreement and SPPC’s $250 million Amended and Restated Revolving Credit Agreement, dated November 4, 2005, contains two financial maintenance covenants. The first requires that the Utility maintain a ratio of consolidated indebtedness to consolidated capital, determined as of the last day of each fiscal quarter, not to exceed 0.68 to 1. The second requires that the Utility maintain a ratio of consolidated cash flow to consolidated interest expense, determined as of the last day of each fiscal quarter for the period of four consecutive fiscal quarters, not to be less than 2.0 to 1. As of December 31, 2005, both companies were in compliance with these covenants.

Limitations on Indebtedness

Sierra Pacific Resources

The terms of SPR’s $335 million 8 5/8% Senior Unsecured Notes due 2014, its $99.1 million 7.803% Senior Notes due 2012, and its 6.75% Senior Notes due 2017 restrict SPR and any of its Restricted Subsidiaries (NPC and SPPC) from incurring any additional indebtedness unless:

1. at the time the debt is incurred, the ratio of consolidated cash flow to fixed charges for SPR’s most recently ended four quarter period on a pro forma basis is at least 2 to 1, or

2. the debt incurred is specifically permitted under the terms of the applicable series of notes, which permit the incurrence of certain credit facility or letter of credit indebtedness, obligations incurred to finance property construction or improvement, indebtedness incurred to refinance existing indebtedness, certain intercompany indebtedness, hedging obligations, indebtedness incurred to support bid, performance or surety bonds, and certain letters of credit supporting SPR’s or any Restricted Subsidiary’s obligations to energy suppliers, or

3. the indebtedness is incurred to finance capital expenditures pursuant to NPC’s 2003 Integrated Resource Plan and SPPC’s 2004 Integrated Resource Plan.

If the applicable series of notes are upgraded to investment grade by both Moody’s and S&P, these restrictions will be suspended and will no longer be in effect so long as the applicable series of notes remain investment grade. As of December 31, 2005 SPR, NPC and SPPC would have been able to issue approximately $482 million of additional indebtedness on a consolidated basis, assuming an interest rate of 6.00%, per the requirement stated in number 1 above.

Nevada Power Company

The terms of NPC’s 10⅞% General and Refunding Mortgage Notes, Series E, due 2009, 9% General and Refunding Mortgage Notes, Series G, due 2013, 6.5% General and Refunding Mortgage Notes, Series I, 5⅞% General and Refunding Mortgage Notes, Series L, and NPC’s $500 million Revolving Credit Agreement restrict NPC from incurring any additional indebtedness unless:

1. 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

2. 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, certain intercompany indebtedness, hedging obligations, indebtedness incurred to support bid, performance or surety bonds, certain letters of credit issued to support NPC’s obligations with respect to energy suppliers, and for the Series G Notes, Series I Notes, Series L Notes and the Revolving Credit Facility, indebtedness to finance capital expenditures incurred pursuant to NPC’s 2003 Resource Plan.

If NPC’s Series E Notes, Series G Notes, Series I Notes, or Series L Notes are upgraded to investment grade by both Moody’s and S&P, these restrictions will be suspended and will no longer be in effect so long as the applicable series of securities remains investment grade. For additional details, reference Note 9, Debt Covenant Restrictions of the Notes to the Financial Statements.

Sierra Pacific Power Company

The terms of SPPC’s 6¹/4% General and Refunding Mortgage Notes, Series H, due 2012, and $250 million Revolving Credit Agreement restrict SPPC from issuing additional indebtedness unless:

1. at the time the debt is incurred, the ratio of consolidated cash flow to fixed charges for SPPC’s most recently ended four quarter period on a pro forma basis is at least 2 to 1, or

2. the debt incurred is specifically permitted under the terms of the Series H Notes and the Revolving Credit Agreement, which includes certain credit facility or letter of credit indebtedness, obligations incurred to finance property construction or improvement, indebtedness incurred to refinance existing indebtedness, certain intercompany indebtedness,

hedging obligations, indebtedness incurred to support bid, performance or surety bonds, and certain letters of credit issued to support SPPC’s obligations with respect to energy suppliers, or

indebtedness incurred to finance capital expenditures pursuant to SPPC’s 2004 Resource Plan.

Cross Default Provisions

SPR’s and the Utilities’ financing agreements do not contain cross-default provisions that would result in an event of default for the respective entity upon an event of default by either of the other entities under any of their financing agreements. Certain financing agreements of each of SPR and the Utilities provide for an event of default if there is a failure under other financing agreements of that entity 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.

ENERGY SUPPLY (UTILITIES)

The energy supply function at the Utilities encompasses the reliable and efficient operation of the Utilities’ owned generation, the procurement of all fuels and purchased power and resource optimization (i.e., physical and economic dispatch).

The Utilities face energy supply challenges for their respective load control areas. There is the potential for continued price volatility in each Utility’s service territory, particularly during peak periods. A greater dependence on gas-fired generation in the service territory subjects power prices to gas price volatilities. Both Utilities face load obligation uncertainty due to the potential for customer switching. Some counterparties in these areas have significant credit difficulties, representing credit risk to the Utilities. Finally, each Utility’s own credit situation can have an impact on its ability to enter into transactions.

In response to these energy supply challenges, the Utilities have adopted an approach to managing the energy supply function that has three primary elements. The first element is a set of management guidelines to procuring and optimizing the supply portfolio that is consistent with the requirements of a load serving entity with a full requirements obligation. The second element is an energy risk management and risk control approach that ensures clear separation of roles between the day-to-day management of risks and compliance monitoring and control; and ensures clear distinction between policy setting (or planning) and execution. Lastly, the Utilities will pursue a process of ongoing regulatory involvement and acknowledgement of the resource portfolio management plans.

Energy Supply Planning

Within the energy supply planning process, there are three key components covering different time frames:

(1)

the PUCN-approved long-term IRP has a twenty-year planning horizon;

(2)

the energy supply plan, which is an intermediate term resource procurement and risk management plan that establishes the supply portfolio parameters within which intermediate term resource requirements will be met, has a one to three year planning horizon; and

(3)

tactical execution activities with a one-month to twelve-month focus.

The energy supply plan operates in conjunction with the PUCN-approved twenty-year IRP. It serves as a guide for near-term execution and fulfillment of energy needs. When the energy supply plan calls for executing contracts with a duration of more than three years, the IRP regulations require PUCN approval as part of the integrated resource planning process.

In developing energy supply plans and implementing on those plans, management guidelines followed by the Utilities include:

•

Maintaining an energy supply plan that balances costs, risks, price volatility (retail price stability), reliability and predictability of supply.

•

Investigating feasible commercial options to implement against the energy supply plan.

•

Applying quantitative techniques and diligence commensurate with risk to evaluate and execute each transaction.

•

Implementing the approved energy supply plan in a manner that manages ratepayer risk in terms of reliability, volatility and cost.

•

Monitoring the portfolio against evolving market conditions and managing the resource optimization options.

•

Ensuring simple, transparent and well-documented decisions and execution processes.

Energy Risk Management and Control

The Utilities’ efforts to manage energy commodity (electricity, natural gas, coal and oil) price risk are governed by a Board of Directors’ revised and approved Enterprise Risk Management and Control Policy. That policy created the Enterprise Risk Oversight Committee (EROC) and made that committee responsible for the overall policy direction of the Utilities’ risk management and control efforts. That policy further instructed the EROC to oversee the development of appropriate risk management and control policies including the Energy Supply Risk Management and Control Policy.

The Utilities’ commodity risk management program establishes a control framework based on existing commercial practices. The program creates predefined risk limits and delineates management responsibilities and organizational relationships. The program requires that transaction accounting systems and procedures be maintained for systematically identifying, measuring, evaluating and responding to the variety of risks inherent in the Utilities’ commercial activities. The program’s control framework consists of a disclosure and reporting mechanism designed to keep management fully informed of the operation’s compliance with portfolio and credit limits.

The Utilities, through the purchase and sale of financial instruments and physical products, maintain an energy risk management program that limits energy risk to levels consistent with energy supply plans approved by the Chief Executive Officer and the EROC.

Regulatory Issues

The Utilities’ long-term IRPs are filed with the PUCN for approval every three years. Nevada law provides that resource additions approved by the PUCN in the resource planning process are deemed prudent for ratemaking purposes. NPC’s IRP was filed in July 2003 and received approval in November 2003. SPPC’s IRP was filed in July 2004 and approved on November 2004. Between IRP filings, the Utilities are required to seek PUCN approval for modifications to their resource plans and for power purchases with terms of three years or greater by filing amendments to prior IRP filings.

The Utilities also seek regulatory input and acknowledgement of intermediate term energy supply plans. The Utilities feel this is necessary to ensure that the appropriate levels of risks are being mitigated at reasonable costs, the appropriate levels of risks are being retained in the portfolio, and decisions to manage risks with best available information at the point in time when decisions are made are subject to reasonable mechanisms for recovery in rates

Intermediate Term Energy Supply Plans

The Utilities update their intermediate term energy supply plans on an annual basis. On September 1, 2005, the Utilities filed updates to their respective energy supply plans with the PUCN. Those plans covered the years 2006 through 2007 for SPPC and 2006 for NPC. The plans were approved by the EROC and the CEO prior to submission to the PUCN. The energy supply plans operate within the framework of the PUCN-approved twenty-year IRPs. They serve as a guide for near-term execution and fulfillment of energy needs. When the energy supply plans call for the execution of contracts of duration of more than three years, an amended IRP is prepared and submitted for PUCN approval. The energy supply plans filed in September 2005 were found to be reasonable and prudent by the PUCN in January 2006.

The Utilities have reduced the extent of their intermediate-term needs from those in prior years. NPC will be adding a significant amount of new, efficient, generating capacity to its system in 2006 (Lenzie 1 and 2, Silverhawk and Harry Allen 4). Both Utilities also have executed forward contracts for their peak resource needs through the summer of 2006. The portfolio mix consists of owned generating resources, forward contracts for power and peaking and seasonal capacity, or synthetic tolling based contracts (i.e., power prices indexed to gas prices), to meet the following requirements:

	•		Optimize the tradeoff between overall fuel and purchase power cost and market price and supply risk.

	•		Pursue in-region capacity to enhance long-term regional reliability.

	•		Represent the set of transactions/products available in the market.

	•		Reduce credit risk—in a market with some counter-parties in weak financial conditions.

	•		Procure to match the difficult load profile, to the extent possible.

	•		Hedge the gas price risk exposure in the fuel portfolio through the purchase of a set of risk management options.

	•		Manage energy price risk through ongoing intermediate and short-term optimization activities (e.g., optimizing the dispatch of NPC generation and/or buying directly from the market).

Both of the energy supply plans reflect the Utilities’ strategies, embedded in amendments to their filed IRPs, to minimize supply and price risk through acquisition or construction of highly efficient company owned generating resources in the intermediate term, forward contracts to meet capacity needs in the shorter term, and pursuit of fuel diversity options such as coal and renewables in the longer term. NPC will file a new IRP with the PUCN in July 2006, and SPPC will update its energy supply plan by September 2006 for the remaining year of its energy supply plan period (2007).

Long Term Purchase Power Activities

The Utilities update their long-term energy supply plans on an annual basis in concert with the preparation of their respective energy supply plans, which are described in the preceding section. As noted above, the energy supply plans serve as a guide for near-term execution and fulfillment of energy needs. When the energy supply plans call for contracts of duration more than three years, requests for proposals are issued, bids are evaluated, and contracts are executed with the successful bidders. Those contracts are submitted to the PUCN for approval through an amended IRP.

As noted in the preceding section, the Utilities have reduced their longer-term needs for power from those in prior years. The Utilities have not entered into a long-term purchase agreement for conventional power since 2003. During January of that year, NPC entered into long-term purchase agreements with three companies – Panda Gila River LP, Calpine Energy Services and Mirant Americas Energy Marketing LP. Those agreements were approved by the PUCN on April 14, 2003, and the suppliers have performed or are performing in accordance with expectations. During December of 2003, NPC entered into a long-term purchase power agreement with the Las Vegas Cogeneration II facility owned by Black Hills Power and Light and located in North Las Vegas. The agreement was approved by the PUCN on March 15, 2004.

The Utilities also entered into long term contracts with renewable energy providers.

Short-Term Resource Optimization Strategy

The Utilities’ short-term resource optimization strategy involves both day-ahead (next day through the end of the current month) and real-time (next hour through the end of the current day) activities that require buying, selling and scheduling power resources to determine the most economical way to produce or procure the power resources needed to meet the retail customer load and operating reserve requirement. The Utilities commit and dispatch generating units based on the comparative economics of generation versus spot-market purchase opportunities. Any amount of excess capacity or energy is sold on the wholesale market, while any deficient capacity or energy position is filled by either buying on the spot market or utilizing available generating capacity.

The day-ahead resource optimization begins with an analysis of projected hourly loads, existing resources, and operating reserve requirements. Firm forward take-or-pay contracts are scheduled and counted towards meeting the capacity needs of the day being pre-scheduled. The day-of resource optimization involves minimizing system production costs each hour by lowering or raising generating unit output or buying power and/or selling excess power in the wholesale market all in order to meet the system load requirement and operating reserve requirement. Any sale of excess power priced above the incremental cost of producing such power reduces the net production cost of operating the electrical system and thereby benefits the end use customer. The Utilities endeavor to reduce the electrical systems’ net production cost by selling available excess energy when it exists.

Real-time resource optimization requires an hourly determination of whether to increase or decrease the loading of on-line generating units, commit previously off-line generating units, un-commit on-line generating units, sell excess power, or purchase power in the real-time market to meet the companies’ resource needs. In order to achieve the lowest production cost, the projected incremental or decremental cost of the next available generation resource options is compared to determine the lowest cost option.

NEVADA POWER COMPANY

RESULTS OF OPERATIONS

NPC recognized net income of $132.7 million in 2005 compared to net income of $104.3 million in 2004 and $19.3 million in 2003. NPC’s operating results for 2005 improved over 2004 primarily as a result of an increase in operating income, as discussed in detail below, an increase in Allowance for Other Funds Used During Construction and Allowance for Borrowed Funds During Construction and lower interest costs. NPC’s operating results for 2004 improved over 2003 primarily by the reversal in 2004 of

interest charges of approximately $28 million originally recognized in 2003, based on the U.S. District Court decision in our appeal of the Enron Judgment, as discussed in Note 14, Commitments and Contingencies of the Notes to Financial Statements. NPC’s operating results for 2004 compared to 2003 were further improved by the absence of the disallowed energy costs in 2003 detailed below. NPC’s operating results for 2003 were negatively affected by the write-off of $46 million of disallowed deferred energy costs in May 2003, and the recognition of $28 million of interest costs as a result of the September 26, 2003 judgment entered by the Enron Bankruptcy Court.

In 2005, NPC paid and declared common stock dividends of $35.3 million to its parent, SPR. In 2004, NPC paid and declared common stock dividends of $45 million to its parent, SPR.

Gross margin is presented by NPC in order to provide information by segment that management believes aids the reader in determining how profitable the electric business is at the most fundamental level. Gross margin, which is a “non-GAAP financial measure” as defined in accordance with SEC rules, provides a measure of income available to support the other operating expenses of the business and is utilized by management in its analysis of its business.

The components of gross margin for the years ended December 31 (dollars in thousands):


	2005			2004		2003
Operating Revenues:
Electric	$	1,883,267		$	1,784,092	$	1,756,146
Energy Costs:
Purchased power		963,888			764,347		781,014
Fuel for power generation		277,083			235,404		282,968
Deferred energy costs-disallowed		—			1,586		45,964
Deferral of energy costs-electric-net		(45,668	)		135,973		95,911

		1,195,303			1,137,310		1,205,857


Gross Margin	$	687,964		$	646,782	$	550,289

The causes for significant changes in specific lines comprising the results of operations for NPC for the respective years ended are provided below (dollars in thousands except for amounts per unit).

Electric Operating Revenue


	2005					2004					2003
			Change from					Change from
	Amount		Prior year			Amount		Prior year			Amount
Electric Operating Revenues:
Residential	$	823,095		7.9	%	$	762,907		11.5	%	$	684,331
Commercial		395,016		6.1	%		372,271		7.5	%		346,223
Industrial		560,059		5.7	%		529,916		3.2	%		513,521

Retail Revenues		1,778,170		6.8	%		1,665,094		7.8	%		1,544,075
Other ¹		105,097		-11.7	%		118,998		-43.9	%		212,071

Total Revenues	$	1,883,267		5.6	%	$	1,784,092		1.6	%	$	1,756,146


Retail sales in thousands of megawatt-hours (MWh)		19,455		4.6	%		18,607		3.6	%		17,959

Average retail revenue per MWh	$	91.40		2.1	%	$	89.49		4.1	%	$	85.98

¹ Primarily wholesale, as discussed below

NPC’s retail revenues were higher in 2005 compared to 2004 primarily due to customer growth and higher rates. Increases in the number of residential, commercial and industrial customers were 5.5%, 5.7% and 3.8%, respectively. Higher rates became effective April 1, 2004, which were the result of NPC’s 2003 General and Deferred Rates Cases and October 1, 2005, as a result of

NPC’s 2005 Base Tariff Energy Rate (BTER) Update. These increases were slightly offset by a decrease resulting from NPC’s 2004 Deferred Energy Rate Case effective April 1, 2005. Based on NPC’s projected customer forecast, NPC expects retail electric customers in the Clark County area to continue to grow in the upcoming year. On January 17, 2006, NPC filed a Deferred Energy Rate Case and an increase to its going forward BTER to reflect future energy costs. NPC requested that the BTER increase become effective on May 1, 2006. For further discussion on the various cases see Regulatory Proceedings, later and Note 3, Regulatory Actions of the Notes to Financial Statements.

NPC’s retail revenues were higher in 2004 compared to 2003 primarily due to increases in the number of residential, commercial and industrial customers (5.2%, 5.5% and 4.5%, respectively) and increases in energy related rates that became effective April 1, 2004, which was the result of NPC’s 2003 General & Deferred Energy Rate cases. Offsetting these increases in revenues was a decrease in energy related rates that was effective May 19, 2003, which was the result of NPC’s 2002 Deferred Energy Case. For further discussion on the various cases see Note 3, Regulatory Actions of the Notes to Financial Statements.

The decrease in Electric Operating Revenues – Other in 2005 compared to 2004 was primarily due to certain types of transactions that were reported in revenues for 2004, which are now netted in purchased power. The decrease also included decreased energy usage by Public Authority customers due to their transitioning to distribution only services by purchasing their energy from other sources, as allowed by Nevada law under certain circumstances. Partially offsetting this decrease was a refund in 2004 of $5.9 million owed to transmission customers as a result of FERC’s approval of a tariff agreement on July 8, 2004. For further discussion on the Transmission case see Note 3, Regulatory Actions of the Notes to Financial Statements. The tariff agreement also lowered the transmission rates which contributed to the decrease in 2005 revenues.

The decrease in Electric Operating Revenues – Other for 2004 compared to 2003 was primarily due to a 63% decrease in the sales volumes of wholesale power to other utilities at significantly lower prices per MWh and a refund of $5.9 million per the tariff agreement discussed above.

Purchased Power


	2005					2004					2003
			Change from					Change from
	Amount		Prior year			Amount		Prior year			Amount
Purchased Power	$	963,888		26.1	%	$	764,347		-2.1	%	$	781,014
Purchased power in thousands of MWs		12,894		4.7	%		12,319		-0.9	%		12,435
Average cost per MWh of Purchased Power (1)	$	74.77		19.8	%	$	62.41		1.5	%	$	61.51

(1)

Excludes contract termination costs (credits), of $(0.3) million, $(4.6) million, and $16.1 million for the years ending 2005, 2004, and 2003, respectively.

NPC’s purchased power costs increased in 2005 compared to 2004, due to higher prices and increased volume. NPC’s energy contracts calculate prices using gas indexes; therefore, higher natural gas prices in 2005 increased the price of purchased power. Furthermore, purchased power costs were higher due to gas tolling agreements entered into during the second quarter of 2004 and June 1, 2005. These gas tolling agreements are purchased power agreements where NPC provides natural gas to the supplier who generates the energy for NPC. The gas tolling agreements are based on gas indexes; therefore, the increase in natural gas prices increased the cost of purchased power. Volume increased because NPC satisfied more of its native load requirements through purchased power rather than generation.

NPC’s purchased power costs were lower in 2004 compared to 2003 primarily due to lower volumes purchased. Although NPC satisfied more of its native load requirements through purchased power rather than generation, this volume increase was offset by a significant volume decrease in wholesale sales to other utilities and energy marketers, as well as those associated with risk management activities. Additionally, offsetting the decrease was a $4.6 million credit for terminated contracts recorded in 2004 compared to a $16.1 million charge in 2003. Per unit costs of power increased primarily due to higher Intermediate-Term and Long-Term Firm energy prices.

Fuel for Power Generation


	2005					2004					2003
			Change from					Change from
	Amount		Prior year			Amount		Prior year			Amount
Fuel for Power Generation	$	277,083		17.7	%	$	235,404		-16.8	%	$	282,968

Thousands of MWhs generated		8,094		-4.4	%		8,470		-8.2	%		9,228
Average fuel cost per MWh of Generated Power	$	34.23		23.2	%	$	27.79		-9.4	%	$	30.66

Fuel for power generation costs increased in 2005 as compared to 2004 due to the increased price of natural gas. The decrease in volume of generation was primarily due to NPC satisfying more of its native load requirements through purchased power rather than generation. The increase in average unit fuel cost per megawatt-hour was primarily due to higher gas costs in 2005 compared to 2004.

Fuel for power generation costs decreased in 2004 as compared to 2003 due to lower volume and costs to generate electricity. The decrease in volume of generation was primarily due to NPC satisfying more of its native load requirements through purchased power rather than generation. The decrease in average unit fuel cost per megawatt-hour was primarily due to lower coal costs in 2004 compared to 2003.

Deferral of Energy Costs — Net


	2005					2004					2003
				Change from				Change from
	Amount			Prior year		Amount		Prior year			Amount
Deferred energy costs disallowed	$	—			N/A	$	1,586		-96.5	%	$	45,964
Deferral of energy costs-net		(45,668	)		N/A		135,973		41.8	%		95,911

	$	(45,668	)			$	137,559				$	141,875

Deferred energy costs disallowed for 2004 reflects the first quarter write-off of $1.6 million of electric deferred energy costs incurred in the twelve months ended September 30, 2003, that were disallowed by the PUCN in their March 24, 2004 decision on NPC’s deferred energy rate case. Deferred energy costs disallowed for 2003 reflects the second quarter write-off of $46 million of electric deferred energy costs incurred in the twelve months ended September 30, 2002, that were disallowed by the PUCN in its May 13, 2003 decision on NPC’s deferred energy rate case.

Deferred energy costs – net represents the difference between actual fuel and purchased power costs incurred during the period and amounts recoverable through current rates. To the extent actual costs exceed amounts recoverable through current rates the excess is recognized as a reduction in costs. Conversely to the extent actual costs are less than amounts recoverable through current rates the difference is recognized as an increase in costs. Deferred energy costs – net also include the current amortization of fuel and purchased power costs previously deferred. See Note 1, Summary of Significant Accounting Policies, Deferral of Energy Costs of Notes to Financial Statements for further detail of deferred energy balances.

Amounts for 2005, 2004, and 2003 include amortization of deferred energy costs of $131.5 million, $228.8 million, and $204.6 million, respectively; and under-collections of amounts recoverable in rates of $177.1 million, $92.7 million, and $108.7 million, respectively.

Allowance For Funds Used During Construction (AFUDC)


	2005				2004					2003
			Change from				Change from
	Amount		Prior year		Amount		Prior year			Amount
Allowance for other funds used during construction	$	18,683		N/A	$	4,230		48.7	%	$	2,845

Allowance for borrowed funds used during construction		23,187		N/A		5,738		N/A			2,700

	$	41,870		N/A	$	9,968		79.8	%	$	5,545

AFUDC for NPC was higher in 2005 compared to 2004 as a result of an increase in the average Construction Work-In- Progress (CWIP) balance on which AFUDC is calculated. The increase in the average CWIP balance was primarily driven by the Lenzie Generating Station project, as well as normal growth. AFUDC for NPC is higher in 2004 compared to 2003 as a result of an increase in the AFUDC rates as well as an increase in the average CWIP balance, driven by the initial purchase of the partially built Lenzie Generating Station in the latter part of 2004.

Other (Income) and Expenses


	2005						2004						2003
				Change from						Change from
	Amount			Prior year			Amount			Prior year			Amount
Other operating expense	$	211,039			14.9	%	$	183,736			-6.0	%	$	195,483
Maintenance expense	$	52,040			-8.7	%	$	57,030			18.3	%	$	48,226
Depreciation and amortization	$	124,098			4.4	%	$	118,841			8.4	%	$	109,655
Income tax expense/(benefit)	$	46,425			2.9	%	$	45,135			N/A		$	(12,734	)
Interest charges on long-term debt	$	159,106			4.2	%	$	152,764			7.5	%	$	142,143
Interest energy supplier s	$	(14,825	)		-38.7	%	$	(24,171	)		N/A		$	33,879
Interest charges-other	$	13,563			-6.7	%	$	14,533			-15.3	%	$	17,150
Interest accrued on deferred energy	$	(20,350	)		0.7	%	$	(20,199	)		-11.8	%	$	(22,891	)
Other income	$	(25,626	)		12.2	%	$	(22,844	)		24.5	%	$	(18,344	)
Disallowed merger costs	$	—			N/A		$	3,961			N/A		$	—
Other expense	$	8,525			27.9	%	$	6,665			12.1	%	$	5,944
Income taxes-other income and expense	$	17,570			53.6	%	$	11,437			-5.6	%	$	12,120

Other operating expense increased for 2005 compared to 2004 primarily due to increased advisory fees, amortization of regulatory assets and severance costs associated with the reorganization of SPPC, NPC and SPR.

The decrease in Other operating expense during 2004 compared to 2003 reflects the absence in 2004 of the provision for uncollected revenues on transmission service agreements (TSA). The TSA were challenged at FERC by three parties, who had subscribed for service on transmission facilities built to accommodate new generating stations under construction or to be constructed by these parties. Due to delays in constructing their generating facilities, the parties requested delays in the service commencement of their transmission service contracts, claiming that the Open Access Transmission Tariff excused them from paying their full payment obligations under the transmission contracts or otherwise postponed their obligation to pay. Other factors include fewer write-offs of uncollectible retail customer accounts. These decreases were partially offset by bank charges associated with NPC’s revolving credit facility, advisor and legal fees.

The decrease in Maintenance expense in 2005 compared to 2004 was due to the timing of scheduled and unscheduled plant maintenance at Clark Station, Reid Gardner and Navajo during 2004.

NPC’s maintenance expense fluctuates from period to period primarily as a result of the scheduling, magnitude and number of generation unit overhauls performed. The increase in 2004 compared to 2003 was a result of maintenance performed at the Clark and Reid Gardner generating facilities.

An increase in depreciation and amortization expense between 2005 and 2004 was the result of routine increases to plant-in-service to serve regular system growth. The increase in depreciation and amortization expense in 2004 compared to 2003 was the result of increases to plant-in-service. Large projects placed in service in 2004 include the Crystal 500KV Sub Expansion, the McCullough Upgrade, and the addition of several substations to accommodate growth in the region.

Income tax expense/(benefit) for the year ended December 31, 2005 was comparable to the year ended December 31, 2004. See Note 11, Income Taxes of the Notes to Financial Statements, for additional information regarding the computation of income taxes.

Interest charges on Long-Term Debt increased slightly for the year ended December 31, 2005, compared to 2004 due primarily to increases in long-term debt balances related to new debt issued in November 2004 of $250 million, interest associated with various draws from the Long-Term Credit Facility in 2005, and an increase in interest rates on NPC’s $115 million variable rate interest notes in 2005. This increase was partially offset by debt redemptions, in July 2005 of $87.5 million and $122.5 million. Interest charges on Long-Term Debt increased for the year ended December 31, 2004, compared to 2003 due primarily to increases in long-term debt balances related to new debt issued in November 2004 of $250 million and August 2003 of $350 million. This increase was partially offset by debt redemptions, in September 2003 of $210 and $140 million. See Note 7, Long-Term Debt of the Notes to Financial Statements, for additional information regarding long-term debt.

Interest charges for energy suppliers are comprised of interest accruals for terminated supplier balances being litigated. The amount reported in 2005 includes reversals of accrued balances due to settlements reached with suppliers. The amount reported in 2004 includes the reversal of $28 million resulting from a ruling by the U.S. District Court hearing the utilities appeal against the Bankruptcy Court Judge’s ruling in the bankruptcy proceedings of Enron Power Marketing (Enron). The amount reported in 2003 includes additional interest of $28 million as a result of a judgment issued on September 26, 2003, by the Bankruptcy Court Judge overseeing the bankruptcy proceedings of Enron. See Note 14, Commitments and Contingencies of the Notes to Financial Statements, for more information regarding the Enron litigation.

Interest charges-other for the year ended December 31, 2005 decreased compared to the same period in 2004 following reduced charges related to NPC’s short-term credit facilities. These costs were offset with additional costs associated with the debt redemption of $210 million (See Note 7, Long-Term Debt of the Notes to Financial Statements, for additional information regarding long-term debt). Interest charges-other for the year ended December 31, 2004 decreased compared to the same period in 2003 following reduced charges related to NPC’s short-term credit facilities. These facilities were replaced during 2004 with long-term facilities; when drawn upon, interest related to the new facilities is chargeable to long-term debt interest.

NPC’s interest accrued on deferred energy costs was comparable for 2005 to 2004. NPC’s interest accrued on deferred energy costs for the year ended December 31, 2004 decreased from the previous year due to lower deferred energy balances. See Note 3, Regulatory Actions of the Notes to Financial Statements, for further discussion of deferred energy accounting issues.

Disallowed merger costs for the year ended December 31, 2004 were a result of the PUCN decision in NPC’s 2003 General Rate Case. Disallowed merger costs expense includes the write-off of costs that resulted from the July 28, 1999 merger between SPR and NPC which were determined not to be recoverable through rates in the March 26, 2004, PUCN decision on NPC’s 2003 general rate case. The PUCN decision permitted substantially all of the merger costs that NPC requested recovery of except for a 20% reduction in merger costs that were to be amortized over the next two years. Also included in the write-off are merger costs allocable to non-Nevada jurisdictional sales that NPC had determined not to be recoverable in rates. See “Regulatory Proceedings” – and Note 19, Goodwill and Other Merger Costs of the Notes to Financial Statements, for additional information regarding NPC’s recovery of merger costs.

NPC’s Other income slightly increased for the year ended December 31, 2005 compared to the same period in 2004 due to higher interest income offset by lower amortization of gains associated with disposition of SO2 allowances. NPC’s Other income increased for the year ended December 31, 2004 compared to the same period in 2003 due to the recognition of revenue from the

disposition of the Flamingo Corridor and other non-utility property beginning during the third quarter, 2003, reduced slightly by lower interest income in 2004. See Note 18, Discontinued Operations and Disposal and Impairment of Long-Lived Assets, Other Property Disposals of the Notes to Financial Statements, for further discussion.

NPC’s Other expense increased for the year ended December 31, 2005 compared to the same period in 2004 due primarily to higher expenses associated with corporate advertising, lobbying activities, and various other charges, all of which were not individually significant. NPC’s Other expense was comparable for 2004 to 2003.

NPC’s Income Taxes—Other Income and Expense for the year ended December 31, 2005 increased compared to the same period during 2004, substantially as a result of an increase in the allowance for other funds used during construction incurred primarily for the construction of the Chuck Lenzie generating facility.

ANALYSIS OF CASH FLOWS

NPC’s cash flows decreased during the year ended December 31, 2005, compared to the same period in 2004, as a result of an increase in cash used for investing activities and by decreases in cash flows from operating and financing activities. Cash used in investing activities increased mainly due to an increase in utility construction for the Chuck Lenzie project under construction in 2005. The decrease in cash from operating activities is primarily due to energy costs being higher than amounts recovered in rates in 2005 and changes in accounts receivable for tax sharing agreements. Also partially offsetting the decrease in cash from operating activities was the $49 million escrow payment for Enron in 2004 and a reduction in prepayments and deposits for energy in 2005 due to the establishment of the revolving credit facility. Cash from financing activities decreased in 2005 due to a reduction in debt issued in 2005, offset by additional investments from the parent company and lower dividend payments. NPC was able to retire $210 million of high yield notes in the third quarter utilizing the majority of a $230 million equity contribution from SPR, per the equity claw-back provisions of the note.

NPC had improved operating cash flows in 2004, when compared to 2003, due mainly to rate increases that went into effect in the second quarter of 2004 to recover deferred energy balances and operating costs, and reduced requirements to prepay for energy costs due to the securing of credit lines. These benefits were partially offset by higher interest payments and the payment of $49 million into the Enron escrow account ordered by the court overseeing the Enron bankruptcy proceedings. Net cash used by investing activities increased due to the purchase of the partially constructed Lenzie project from Duke Energy financed entirely by new debt, which represents the increase in cash from financing activities. Cash from financing activities was offset by dividend payments to SPR of $45 million.

LIQUIDITY AND CAPITAL RESOURCES

Overall Liquidity

NPC’s primary source of operating cash flows are electric revenues, including the recovery of previously deferred energy costs. Significant uses of cash flows from operations include the purchase of electricity, natural gas, other operating expenses and interest. NPC had cash and cash equivalents of approximately $98.7 million at December 31, 2005 which does not include restricted cash of $49 million which was deposited into escrow in connection with the stay of the Enron Judgment.

On January 26, 2006, upon final approval of the settlement with Enron, NPC paid Enron approximately $89.8 million from available cash resources. On January 27, 2006, the approximate $49 million cash held in escrow, plus interest, and the Series H Bond was returned to NPC. The bond was cancelled and may be used to support future issuances of general and refunding securities by NPC. As part of the settlement, NPC was granted a general unsecured claim (the “Unsecured Claim”) in Class Six of Enron’s Plan of Reorganization in the amount of $80.7 million. On October 24, 2005, NPC purchased a put option from a major international banking institution that, if exercised, obligated that institution to purchase the Unsecured Claim (contingent upon allowance of the Unsecured Claim by the Bankruptcy Court), which ensured that NPC’s net cash outlay to settle Enron’s claim, would be no higher than $64.9 million. On February 16, 2006, the Unsecured Claim was sold to a separate third party resulting in a final net cash outlay which did not materially differ from the anticipated cash outlay. To the extent NPC is not permitted to recover the net amount paid under the settlement agreement through future regulatory filings, the amount not permitted would be charged as a current operating expense.

On November 4, 2005, NPC amended and restated its existing secured $350 million revolving credit facility, maturing in October 2007, increasing the size of the facility to $500 million and extending the maturity to November 2010. As of February 24, 2006 NPC had additional liquidity in the amount of $170.4 million under its amended revolving credit facility.

NPC anticipates that it will be able to meet operating costs, such as fuel and purchased power costs with internally generated funds, including the recovery of deferred energy. However, to fund capital requirements, as discussed below, NPC may meet such financial obligations with a combination of internally generated funds, the use of its revolving credit facility and, if necessary, the issuance of long-term debt.

NPC’s overall liquidity continues to improve. The increase in NPC’s general and electric rates, as discussed further in Regulatory Proceedings, improved debt profile, the settlement of various litigation, as discussed in Note 14, Commitments and Contingencies of the Notes to Financial Statements, and management of energy risk are allowing NPC to continue to improve its overall liquidity. NPC’s improved debt profile is partially due to the redemption of $210 million of high coupon debt in July 2005, which is expected to reduce future interest expense.

NPC designs operating and capital budgets to control operating costs and capital expenditures. In addition to operating expenses, NPC has continuing commitments for capital expenditures for construction improvement and maintenance of facilities.

Detailed below are NPC’s Capital Structure, Capital Requirements, Contractual Obligations, recently completed Financing Transactions and Factors Affecting Liquidity including our ability to obtain debt on favorable terms and limitations on indebtedness.

Capital Structure

NPC’s actual consolidated capital structure was as follows at December 31 (dollars in thousands):


	2005				2004
Short-Term Debt (1)	$	6,509	0.2	%	$	6,091	0.2	%
Long-Term Debt		2,214,063	55.6	%		2,275,690	61.2	%
Common Equity		1,762,089	44.2	%		1,436,788	38.6	%

Total	$	3,982,661	100	%	$	3,718,569	100	%


(1)		Includes current maturities of long-term debt and capital lease obligations.

Capital Requirements

Construction Expenditures

NPC’s cash construction expenditures have increased since 2003 and are expected to continue to increase due to programs designed to meet electric load growth and reliability needs. Cash construction expenditures for the years ended 2005, 2004 and 2003 were approximately $478 million, $454 million, and $207 million, respectively. NPC’s cash construction expenditures for 2006 are projected to be $483.5 million. NPC’s cash construction expenditures for 2006 through 2010 are projected to be $2.7 billion and are expected to be financed by external financing, internally generated funds, which include recovery of NPC’s deferred energy balances and NPC’s existing credit facility. The timing and extent of the estimated capital expenditures may change if NPC receives approval for the Ely Energy Center. If this project is approved by the PUCN, NPC’s steadily improving financial condition, as evidenced by the upgrade in credit ratings in 2005 and recent financing transactions, should allow it to successfully raise funds in the capital markets.

Contractual Obligations

The table below provides NPC’s consolidated contractual obligations, not including estimated construction expenditures described above, as of December 31, 2005, that NPC expects to satisfy through a combination of internally generated cash and, as necessary, through the issuance of short-term and long-term debt (dollars in thousands):


	Payment Due by Period
	2006		2007		2008		2009		2010		Thereafter		Total
Long-Term Debt Maturities(1)	$	6,509	$	5,950	$	7,066	$	184,638	$	157,843	$	1,863,508	$	2,225,514
Long-Term Debt Interest Payments (1)		148,313		146,807		146,806		143,738		128,646		1,159,932		1,874,242
Purchase Power		345,539		233,038		227,222		208,465		213,018		2,560,827		3,788,109
Coal and Natural Gas		486,995		49,156		37,098		37,022		37,022		208,661		855,954
Long -Term Service Agreements (2)		3,023		3,023		3,023		3,023		3,023		24,738		39,853
Capital Purchase Commitment(3)		208,000		—		—		—		—		—		208,000
Operating Leases		3,570		1,005		979		911		526		433		7,424


Total Contractual Cash Obligations	$	1,201,949	$	438,979	$	422,194	$	577,797	$	540,078	$	5,818,099	$	8,999,096


(1)		Does not include principal and interest associated with NPC’s January 2006 issuance of $210 million in General and Refunding Mortgage Notes, Series M, due March 2016.

(2)		Amount does not include variable or unplanned maintenance fees related to the Chuck Lenzie service contract, of which the total contract is estimated to be approximately $150 million.

(3)		Does not include various closing adjustments related to the Silverhawk purchase.

Pension Plan Matters

Financing Transactions

General and Refunding Mortgage Notes, Series M

On January 18, 2006, NPC issued and sold $210 million of its 5.95% General and Refunding Mortgage Notes, Series M, due March 15, 2016, through a private placement. The Series M Notes were issued with registration rights. The net proceeds of the issuance plus available cash were used to repay $210 million outstanding under NPC’s revolving credit facility, which amount was borrowed to finance the purchase of a 75% ownership interest in the Silverhawk Power Plant. NPC may redeem the notes at its option at any time, in whole or in part, at a price of 100% of the principal amount of the Series M Notes being redeemed plus a make-whole premium.

Amended Credit Facility

On November 4, 2005 NPC amended and restated its existing secured $350 million revolving credit facility, maturing in October 2007, reducing the fees on both the unused portion of the facility, and on the amounts borrowed, increasing the size of the facility to $500 million, extending the maturity to November 2010 and changing the Administrative Agent for the facility to Wachovia Bank, National Association. The rate for outstanding loans and/or letters of credit under the revolving credit facility will be at either an applicable base rate (defined as the higher of the Prime rate and the Federal Funds rate plus one-half of one percent) or a Eurodollar rate plus a margin that varies based upon NPC’s credit rating by at least two of the three rating agencies (S&P, Moody’s and Fitch). Currently, the base rate is Prime, and NPC’s applicable base rate margin is zero. The Eurodollar margin is 0.875%. As of December 31, 2005 NPC had $58.4 million of letters of credit and had borrowed $150 million under the revolving credit facility. As of February 24, 2006, NPC had $54.6 million of letters of credit and had borrowed $275 million under the revolving credit facility.

On October 21, 2005, NPC filed an application with the PUCN seeking financing authority for a two-year period ending December 31, 2007. Included in that application was a request to increase the size of NPC’s revolving credit facility to $600 million. The $100 million increase would provide NPC with additional liquidity to cover increased commodity prices. The hearing on this application was held on February 2, 2006 with a final decision expected in March 2006.

The NPC Credit Agreement contains two financial maintenance covenants. The first requires that NPC maintain a ratio of consolidated indebtedness to consolidated capital, determined as of the last day of each fiscal quarter, not to exceed 0.68 to 1. The second requires that NPC maintain a ratio of consolidated cash flow to consolidated interest expense, determined as of the last day of each fiscal quarter for the period of four consecutive fiscal quarters, not to be less than 2.0 to 1. As of December 31, 2005, NPC was in compliance with these covenants.

The revolving credit facility is secured by NPC’s General and Refunding Mortgage Bonds; however, in the event that NPC obtains an unsecured debt rating from at least two rating agencies that is at least BBB- from S&P and Fitch or Baa3 from Moody’s, the General and Refunding Mortgage Bonds securing the revolving credit facility will be released.

In addition, the credit agreement contains customary conditions to borrowing including requirements that no material litigation, defaults or other events that could have a material adverse effect on NPC’s business shall have occurred. See Note 9, Debt Covenant Restrictions of the Notes to Financial Statements. In the event that NPC’s unsecured debt ratings meet the conditions discussed above, the requirement that no material adverse changes shall have occurred ceases to be a condition to borrowing under the credit agreement.

The NPC Credit Agreement provides for an event of default if there is a failure under other financing agreements of that entity to meet payment terms or to observe other covenants that would result in an acceleration of payments due.

Redemption of Indebtedness

On July 14, 2005, NPC redeemed $87.5 million aggregate principal amount of its 10 7/8% General and Refunding Mortgage Notes, Series E, due 2009 (the “Series E Notes”) and $122.5 million aggregate principal amount of its 9% General and Refunding Mortgage Notes, Series G, due 2013 (the “Series G Notes”). These redemptions constituted 35% of the principal amount outstanding of each of the Series E Notes and the Series G Notes. The Series E Notes were redeemed at a redemption price equal to $1,108.75 for each $1,000 note redeemed for a redemption premium in excess of the principal amount of approximately $9.5 million. The Series G Notes were redeemed at a redemption price equal to $1,090.00 for each $1,000 note redeemed for a redemption premium in excess of the principal amount of approximately $11 million. In accordance with SFAS 71, Accounting for the Effects of Certain Types of Regulation, the redemption premium to redeem the debt will be amortized over the original term of the debt. NPC paid for the redemptions with the proceeds of an equity contribution of approximately $230.5 million from SPR, as discussed in Note 6, Short-Term Borrowings of the Notes to Financial Statements.

Factors Affecting Liquidity

Limitations on Indebtedness

The terms of NPC’s 10⅞% General and Refunding Mortgage Notes, Series E, due 2009, 9% General and Refunding Mortgage Notes, Series G, due 2013, 6.5% General and Refunding Mortgage Notes, Series I, 5⅞% General and Refunding Mortgage Notes, Series L, and NPC’s $500 million Revolving Credit Agreement, restrict NPC from incurring any additional indebtedness unless:

1. 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

remains investment grade. As of December 31, 2005, NPC would have been able to issue approximately $639 million of additional indebtedness on a consolidated basis, assuming an interest rate of 6.00% per the requirement stated in number 1 above. However, due to the terms of SPR debt, NPC’s combined debt limit is restricted to the $482 million of additional indebtedness SPR could incur on a consolidated basis. See Note 9, Debt Covenant Restrictions to the Notes to Financial Statements.

Mortgage Indentures

NPC’s Indenture of Mortgage, dated as of October 1, 1953, between NPC and Deutsche Bank Trust Company Americas (the “First Mortgage Indenture”), creates a first priority lien on substantially all of NPC’s properties. As of December 31, 2005, $372.5 million of NPC’s first mortgage bonds were outstanding. In connection with the issuance of its Series E, Series G and Series I Notes NPC agreed 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 December 31, 2005, $1.8 billion 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:

	1.		70% of net utility property additions,

	2.		the principal amount of retired General and Refunding Mortgage Bonds, and/or

	3.		the principal amount of first mortgage bonds retired after October 19, 2001.

On the basis of (1), (2) and (3) above and on plant accounting records as of January 31, 2006 NPC had the capacity to issue approximately $622 million 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 securities, the financial covenants contained in the Series E, Series G, Series I, and Series L Notes, and the Revolving Credit Facility limit the amount of additional indebtedness that NPC may issue and the reasons for which such indebtedness may be issued.

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 securities issuable under that indenture.

Credit Ratings

Energy Supplier Issues

With respect to NPC’s contracts for purchased power, NPC purchases and sell electricity with counterparties under the Western Systems Power Pool (WSPP) agreement, an industry standard contract that NPC is required to use as members of the WSPP. The WSPP contract is posted on the WSPP website.

Gas Supplier Issues

With respect to the purchase and sale of natural gas, NPC uses several types of standard industry contracts. The natural gas contract terms and conditions are more varied than the electric contracts. Consequently, some of the contracts contain language similar to that found in the WSPP agreement and other agreements have unique provisions dealing with material adverse changes. Because of creditworthiness concerns, most contracts and confirmations for natural gas purchases have been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery. At the present time, some natural gas purchase transactions require payment in advance of delivery

Gas transmission service is secured under FERC Tariffs or custom agreements. These service contracts and Tariffs require the user establish and maintain creditworthiness to obtain service or otherwise post cash or a letter of credit to be able to receive service. Service contracts are subject to FERC approved tariffs, which, under certain circumstances, require the Utility to provide collateral to continue receiving service. To date, a letter of credit has been provided to one of NPC’s gas transporters.

Cross Default Provisions

None of the financing agreements of NPC contain a cross-default provision that would result in an event of default by NPC upon an event of default by SPR or SPPC under any of its financing agreements. In addition, certain financing agreements of NPC provide for an event of default if there is a failure under other financing agreements of NPC 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 may rectify or correct the situation before it becomes an event of default.

SIERRA PACIFIC POWER COMPANY

RESULTS OF OPERATIONS

SPPC recognized net income of $52.1 million for the year ended December 31, 2005 compared to net income of $18.6 million in 2004 and a net loss of $23.3 million in 2003. SPPC’s operating results for 2005 improved over 2004 primarily by the absence of the $47 million charge associated with the Piñon Pine power plant project, consisting of an approximate $43 million disallowance and a $4 million impairment charge. On January 25, 2006, the Second Judicial District Court of the State of Nevada vacated and remanded back to the PUCN for review the PUCN order which disallowed recovery of $43 million in costs. See Note 14, Commitments and Contingencies for further discussion of the case.

SPPC’s operating results for 2004 improved over 2003 primarily by the reversal in 2004 of interest charges of approximately $12 million originally recognized in 2003 based on the U.S. District Court decision in our appeal of the Enron Judgment, as discussed in Note 14, Commitments and Contingencies of the Notes to Financial Statements. SPPC’s operating results for 2004 compared to 2003 were further improved by the absence of the disallowed energy costs in 2003 detailed below. Partially offsetting the improved operating results were costs of approximately $47 million write off as a result of the decision by the PUCN to disallow recovery of a portion of the costs associated with the Piñon Pine power plant project. In 2003, SPPC’s operating results were negatively affected by a write off of $45 million of disallowed deferred energy costs in June 2003, and the recognition of $12 million of interest costs as a result of the September 26, 2003, Judgment by the Bankruptcy Court.

In 2005, SPPC paid and declared $23.9 million in common dividends to its parent SPR and declared and paid $3.9 million in dividends to holders of its preferred stock. SPPC did not pay or declare a common dividend for the year ended December 31, 2004. For the year ended December 31, 2004, SPPC declared and paid $3.9 million in dividends to holders of its preferred stock.

Gross margin is presented by SPPC in order to provide information by segment that management believes aids the reader in determining how profitable the electric and gas businesses are at the most fundamental level. Gross margin, which is a “non-GAAP financial measure” as defined in accordance with SEC rules, provides a measure of income available to support the other operating expenses of the business and is utilized by management in its analysis of its business. The components of gross margin for the years ended December 31 (dollars in thousands):


	2005			2004			2003
Operating Revenues:
Electric	$	967,427		$	881,908		$	868,280
Gas		178,270			153,752			161,586

	$	1,145,697		$	1,035,660		$	1,029,866


Energy Costs:
Purchased Power		352,098			304,955			364,205
Fuel for power generation		233,653			224,074			197,569
Deferred energy costs disallowed		—			—			45,000
Deferral of energy costs-electric-net		8,110			7,060			1,982
Gas purchased for resale		140,850			121,526			111,675
Deferral of energy costs-gas-net		(749	)		(4,136	)		16,155

	$	733,962		$	653,479		$	736,586

Energy Costs by Segment:
Electric		593,861			536,089			608,756
Gas		140,101			117,390			127,830

	$	733,962		$	653,479		$	736,586


Gross Margin by Segment:
Electric	$	373,566		$	345,819		$	259,524
Gas		38,169			36,362			33,756

	$	411,735		$	382,181		$	293,280

The causes for significant changes in specific lines comprising the results of operations for the years ended are provided below (dollars in thousands except for amounts per unit):

Electric Operating Revenues


	2005					2004					2003
			Change from					Change from
	Amount		Prior year			Amount		Prior year			Amount
Electric Operating Revenues:
Residential	$	282,655		13.4	%	$	249,287		8.2	%	$	230,299
Commercial		325,456		10.3	%		294,956		6.7	%		276,453
Industrial		333,621		12.8	%		295,882		5.7	%		280,047

Retail revenues		941,732		12.1	%		840,125		6.8	%		786,799
Other (1)		25,695		-38.5	%		41,783		-48.7	%		81,481

Total Revenues	$	967,427		9.7	%	$	881,908		1.6	%	$	868,280


Retail sales in thousands of megawatt-hours (MWh)		9,234		1.0	%		9,143		2.7	%		8,901

Average retail revenue per MWh	$	101.99		11.0	%	$	91.89		4.0	%	$	88.39


(1)		Primarily wholesale sales

SPPC’s retail revenues increased in 2005 as compared to 2004 due to increased rates and customer growth. Customer rates for Nevada increased due to SPPC’s General Rate Case and various Deferred Energy and BTER Energy Cases and an increase in California customer rates effective December 1, 2004 and September 1, 2005. Growth in residential and commercial customers (3.1%, and 3.5%, respectively) also contributed to the increase. Additionally, contributing to the increase was the recognition in

December 2005 of $12 million in DEAA revenues as a result of Barrick’s transition to distribution only services customer effective December 1, 2005, offset by lower BTER revenues.

SPPC’s retail revenues increased in 2004 as compared to 2003 due to increases in Nevada customer rates as a result of SPPC’s General Rate Case, effective June 1, 2004, SPPC’s Deferred Energy Case, effective July 15, 2004, and as a result of an increase in California customer energy rates effective December 1, 2004 (refer to Regulatory Proceedings, later). Also contributing to this increase in retail revenues was colder winter weather mostly offset by cooler summer temperatures and an overall growth in retail customers of 2.9%.

The decrease in Electric Operating Revenues — Other in 2005 compared to 2004, was primarily due to certain types of transactions that were reported in revenues for 2004 which are now being netted in purchase power.

The decrease in Electric Operating Revenues — Other during 2004 compared to 2003 was primarily due to a 63% decrease in the sales volumes of wholesale power to other utilities at significantly lower prices per MWh.

Gas Operating Revenues


	2005					2004					2003
			Change from					Change from
	Amount		Prior year			Amount		Prior year			Amount
Gas Operating Revenues:
Residential	$	96,292		18.5	%	$	81,262		7.5	%	$	75,571
Commercial		44,286		13.5	%		39,019		6.8	%		36,531
Industrial		16,953		37.4	%		12,336		-11.4	%		13,930

Retail revenues		157,531		18.8	%		132,617		5.2	%		126,032
Wholesale		17,786		-1.9	%		18,122		-45.0	%		32,978
Miscellaneous		2,953		-2.0	%		3,013		17.0	%		2,576

Total Revenues	$	178,270		15.9	%	$	153,752		-4.8	%	$	161,586


Retail sales in thousands of decatherms		14,819		6.6	%		13,896		6.2	%		13,089

Average retail revenues per decatherm	$	10.63		11.4	%	$	9.54		-0.9	%	$	9.63

SPPC’s retail gas revenues increased in 2005 compared to 2004 primarily due to increases in Nevada customer rates, customer growth and weather. Customer rates increased as a result of SPPC’s Purchased Gas Adjustment filings effective November 2004, and SPPC’s Gas Deferred Energy Rate case and BTER Update effective November 1, 2005 (refer to Note 3, Regulatory Actions of Notes to Financial Statements). Customer growth increased as a result of an increase in the number of residential, commercial and industrial customers (4.3%, 3.5% and 15.9%, respectively). Weather contributed to the increase in revenues with colder temperatures in the winter and spring, partially offset by warmer temperatures in the fall.

SPPC’s retail residential and commercial gas revenues increased in 2004 compared to 2003 primarily due to colder fall and winter temperatures, which were partially offset by warmer spring temperatures. Also contributing to the increase was an increase in energy related rates effective November 1, 2004 and increases in the number of residential and commercial customers (4.3% and 2.8%, respectively). Partially offsetting these increases was a decrease in energy related rates effective November 1, 2003. These changes in energy rates were the result of SPPC’s Purchased Gas Adjustment. For further discussion of rate cases see, Note 3, Regulatory Actions of Notes to Financial Statements. The decrease in industrial retail revenues was attributable to a shift of industrial customers to either SPPC’s gas transportation tariff or to the Company’s commercial gas tariff. Under SPPC’s gas transportation tariff, customers can procure their own gas from a source other than SPPC but continue to compensate SPPC for its gas transportation costs (see miscellaneous revenues below). Gas usage is reviewed once a year and if a customer meets the requirement, they are migrated in October.

Wholesale and miscellaneous gas revenues for 2005 were comparable to the prior year.

Wholesale gas revenues decreased significantly in 2004 compared to 2003. U.S. western region gas prices in 2004 were higher than 2003 prices, which adversely affected resale opportunities in 2004.

Miscellaneous revenues increased in 2004 primarily due to an increase in revenues pertaining to the transportation of gas for industrial customers that shifted to SPPC’s transportation tariff.

Purchased Power


	2005					2004					2003
			Change from					Change from
	Amount		Prior Year			Amount		Prior Year			Amount
Purchased Power	$	352,098		15.5	%	$	304,955		-16.3	%	$	364,205

Purchased power in thousands of MWh		5,441		-4.9	%		5,719		-13.0	%		6,575

Average cost per MWh of Purchased power(1)	$	64.71		21.4	%	$	53.32		-3.2	%	$	55.07


(1)		Average cost per MWh calculation excludes contract termination costs of $2.1 million for the year ending 2003.

SPPC’s purchased power costs increased in 2005 compared to 2004, due to higher prices. SPPC’s energy contracts calculate prices using gas indexes, therefore, higher natural gas prices in 2005 increased the price of purchased power. Overall volumes for 2005 were lower than 2004 due to certain types of transactions that were reported in revenues for 2004 which are now being netted in purchased power and because purchases associated with risk management activities, which are included in purchased power, decreased in 2005.

Purchased power costs were lower in 2004 compared to 2003 due to overall price and volume decreases. Price decreases were primarily due to a decrease in the average cost for Short-Term Firm energy. Volume decreases were a result of SPPC satisfying more of its native load requirements through its own generation rather than purchased power (see Fuel For Power Generation, which follows) as well as decreases in wholesale electric sales as discussed in Electric Operating Revenue – Other. See Liquidity and Capital Resources, later, for a discussion of these terminated power contracts.

Fuel for Power Generation


	2005					2004					2003
			Change from Prior					Change from Prior
	Amount		year			Amount		year			Amount
Fuel for Power Generation	$	233,653		4.3	%	$	224,074		13.4	%	$	197,569

Thousands of MWh generated		4,379		-4.9	%		4,605		9.9	%		4,189
Average fuel cost per MWh of Generated Power	$	53.36		9.7	%	$	48.66		3.2	%	$	47.16

Fuel for power generation costs increased in 2005 as compared to 2004 due to increases in natural gas and coal prices. However, the natural gas cost increases were partially offset by SPPC’s hedging strategies, as discussed in Energy Supply (Utilities). The decrease in the volume of generation was primarily due to SPPC relying more on purchased power to satisfy its native load requirements.

Fuel for power generation costs increased in 2004 as compared to 2003 due to increases in natural gas prices, which were partially offset by decreases in coal prices. In addition, SPPC satisfied more of the native load thru its own generation, which resulted in the increase in MWh generated.

Gas Purchased for Resale


	2005					2004					2003
			Change from					Change from
	Amount		Prior year			Amount		Prior year			Amount
Gas Purchased for Resale	$	140,850		15.9	%	$	121,526		8.8	%	$	111,675

Gas Purchased for Resale		16,592		-6.1	%		17,673		-11.5	%		19,964
(in thousands of decatherms)

Average Cost per decatherm	$	8.49		23.4	%	$	6.88		23.1	%	$	5.59

The cost of gas purchased for resale increased in 2005 as compared to 2004 due to increases in natural gas prices. The volume of gas purchased for resale decreased during this period due to the fuel forecast more closely matching usage, leaving less fuel available for wholesale sales. This decrease in volume of gas was partially offset by the increase in demand for gas for resale during the first two quarters of 2005 due to the colder winter weather.

The cost of gas purchased for resale increased in 2004 as compared to 2003 as a result of higher natural gas prices and transportation costs. The decrease in volume was due to customers leaving the SPPC gas system therefore reducing the volume of gas required for wholesale sales.

Deferral of Energy Costs — Net


	2005						2004					2003
				Change from						Change from
	Amount			Prior year			Amount			Prior year		Amount
Deferred energy costs disallowed	$	—			N/A		$	—			N/A	$	45,000
Deferred energy costs — electric — net		8,110			14.9	%		7,060			N/A		1,982
Deferred energy costs — gas — net		(749	)		-81.9	%		(4,136	)		N/A		16,155

Total	$	7,361					$	2,924				$	63,137

Deferred energy costs disallowed for the year ended December 31, 2003, represents a write-off effective June 1, 2003, of $45 million pursuant to a stipulation approved by the PUCN in Docket 03-1014.

Deferred energy costs — net represents the difference between actual fuel and purchased power costs incurred during the period and amounts recoverable through current rates. To the extent actual costs exceed amounts recoverable through current rates the excess is recognized as a reduction in costs. Conversely to the extent actual costs are less than amounts recoverable through current rates the difference is recognized as an increase in costs. Deferred energy costs – net also includes the current amortization of fuel and purchased power costs previously deferred.

Deferred energy costs — electric – net for 2005, 2004 and 2003 reflect amortization of deferred energy costs of $56.7 million, $37.0 million and $45.5 million, respectively; and an under-collection of amounts recoverable in rates of $48.6 million, $29.9 million and $43.5 million, respectively. See Note 1, Summary of Significant Accounting Policies, Deferral of Energy Costs of Notes to Financial Statements for further detail of deferred energy balances.

Deferred energy costs — gas — net for 2005, 2004 and 2003 reflect amortization of deferred energy costs of $1.5 million, $3.3 million and $13.1 million, respectively; and an under-collection of amounts recoverable in rates in 2005 and 2004 of $2.3 million and $7.4 million, respectively, and an over-collection in 2003 of $3.1 million.

Allowance for Funds Used During Construction (AFUDC)


	2005					2004					2003
			Change from					Change from
	Amount		Prior year			Amount		Prior year			Amount
Allowance for other funds used during construction	$	1,639		-4.6	%	$	1,718		-41.2	%	$	2,920

Allowance for borrowed funds used during construction		1,504		-47.2	%		2,849		-13.0	%		3,276

	$	3,143		-31.2	%	$	4,567		-26.3	%	$	6,196

AFUDC for SPPC is lower in 2005 compared to 2004 due to a decrease in the average Construction Work-In-Progress (CWIP) balance on which AFUDC is calculated as well as a decrease in the AFUDC rate. AFUDC is lower in 2004 compared to 2003 due to a decrease in the average CWIP balance, partially offset by an increase in the AFUDC rate. The primary decrease in CWIP from 2003 to 2004 and from 2004 to 2005 resulted from the completion in May 2004 of the 3 year Falcon-Gonder 345KV Transmission Line project.

Other (Income) and Expenses


	2005						2004						2003
				Change from						Change from
	Amount			Prior year			Amount			Prior year			Amount
Other operating expense	$	131,901			3.0	%	$	128,091			10.1	%	$	116,390
Maintenance expense	$	26,690			22.0	%	$	21,877			2.2	%	$	21,410
Depreciation and amortization	$	90,569			4.3	%	$	86,806			6.5	%	$	81,514
Income tax expense/(benefit)	$	26,038			73.8	%	$	14,978			N/A		$	(13,704	)
Interest charges on long-term debt	$	69,240			-2.9	%	$	71,312			-6.2	%	$	76,002
Interest for energy suppliers (Note 14)	$	(2,396	)		-78.2	%	$	(10,999	)		N/A		$	14,453
Interest charges-other	$	3,727			-30.6	%	$	5,367			-39.8	%	$	8,914
Interest accrued on deferred energy	$	(7,092	)		38.2	%	$	(5,133	)		-0.6	%	$	(5,163	)
Other income	$	(5,940	)		74.4	%	$	(3,406	)		-22.6	%	$	(4,403	)
Disallowed merger costs	$	—			N/A		$	1,929			N/A		$	—
Plant costs disallowed	$	—			N/A		$	47,092			N/A		$	—
Other expense	$	7,493			30.9	%	$	5,726			-15.4	%	$	6,767
Income taxes-other income and expense	$	2,341			N/A		$	(14,653	)		N/A		$	1,467

Other operating expense increased for 2005 compared to 2004 primarily due to severance costs associated with the reorganization of SPPC, NPC and SPR.

The increase in Other operating expense during 2004 compared to 2003 was primarily due to amortization expense that is being recovered through rates for merger, goodwill and divestiture costs. Additional contributing factors include increased transmission and distribution activities along with bank charges associated with SPPC’s revolving credit facility, advisor and legal fees. These increases were offset by less provisions for uncollectible retail customer accounts.

The increase in Maintenance expense for 2005 compared to 2004 is primarily due to the timing of scheduled and unscheduled plant maintenance at Valmy. Maintenance expense in 2004 was comparable to the prior year.

Depreciation and amortization were higher in 2005 than 2004 due to an increase in plant-in-service from regular system growth. Depreciation and amortization were higher in 2004 than 2003 due to an increase in plant-in-service. This increase was driven by the completion of the Falcon-Gondor 345KV Transmission Line, partially offset by a PUCN-mandated write-off of the Piñon Pine facility.

Income tax expense/(benefit) increased compared to the same period in 2004, substantially as a result of an increase in pretax net income. Additionally, a flow-through tax benefit for tax deductible pension contributions was recognized in 2004 of $3.7 million. See Note 11, Income Taxes of the Notes to Financial Statements, for additional information regarding the computation of income taxes.

SPPC’s interest charges on Long-Term Debt for the year ended December 31, 2005 decreased from 2004 as a result of the reduction in interest rate during 2004 associated with the replacement of its 10.5% $100 million term loan facility with 6.25% $100 million Series H Notes, and a reduction in interest rate in April 2004, of SPPC’s $80 million Washoe Water Bonds from 7.5% to 5.0%. SPPC’s interest charges on Long-Term Debt for the year ended December 31, 2004 decreased from 2003 as a result of lower long-term debt balances after the redemption, in December 2003 of $18 million debt, the reduction in interest rate during 2004 associated with the replacement of its 10.5% $100 million term loan facility with 6.25% $100 million Series H Notes, and a reduction in interest rate in April 2004, of SPPC’s $80 million Washoe Water Bonds from 7.5% to 5.0%.

SPPC’s Interest charges for energy suppliers for the year ended December 31, 2005 reflects the reversal of interest of $3.2 million resulting from the November 2005 settlement agreement between the Utilities and Enron. SPPC’s Interest charges for energy suppliers for the year ended December 31, 2004 reflects the reversal of interest of $12.3 million resulting from a December 2004 ruling by the U.S. District Court hearing the utilities appeal against the Bankruptcy Court’s ruling in the bankruptcy proceedings of Enron. In September 2003, SPPC recorded $12.4 million of additional interest costs for energy suppliers as a result of a final judgment issued on September 26, 2003, by the Bankruptcy Court Judge overseeing the bankruptcy proceedings of Enron. See Note 14, Commitments and Contingencies, of the Notes to Financial Statements, for more information regarding the Enron litigation.

SPPC’s Interest charges-other for the year ended December 31, 2005 decreased compared to the same period in 2004 due primarily to the absence of charges related to the accounts receivable facility and short-term debt. Interest charges-other for the year ended December 31, 2004 decreased compared to the same period in 2003 following reduced charges related to SPPC’s short-term credit facilities. These facilities were replaced during 2004 with long-term facilities; when drawn upon, interest related to the new facilities is chargeable to long-term debt interest.

Interest accrued on deferred energy costs for the year ended December 31, 2005, was higher than the same period in 2004 due to higher deferred fuel and purchased power balances and carrying charge rates during 2005. Interest accrued on deferred energy costs for the year ended December 31, 2004, was slightly lower than the same period in 2003. Higher average deferred energy balances prevalent during the second half of 2004 were offset by lower balances during the first half, when compared to the same periods in 2003. (Refer to Regulatory Proceedings for discussion of deferred energy issues).

SPPC’s Other income increased for the year ended December 31, 2005, compared to the same period in 2004 due primarily to an increase in interest income. SPPC’s Other income decreased for the year ended December 31, 2004, compared to the same period in 2003 due to lower interest income and the gain recognized in 2003 from the sale of non-utility property.

Disallowed merger costs expense includes the 2004 write-off of costs that resulted from the July 28, 1999 merger between SPR and NPC, allocable to non-Nevada jurisdictional electricity sales, which were determined not to be recoverable in future rates.

SPPC’s Plant costs disallowed is the result of the decision by the PUCN to disallow recovery of a portion of the costs associated with the Piñon Pine power plant project. See Note 3, Regulatory Actions and Note 14, Commitments and Contingencies of the Notes to Financial Statements, for details.

SPPC’s Other expense for the year ended December 31, 2005 increased from the same period in 2004. Higher expense was recognized during 2005 related to SPPC’s California Restructure Implementation costs of approximately $1 million that were disallowed by the CPUC. SPPC’s Other expense for the year ended December 31, 2004 decreased from the same period 2003, following lower expenses associated with assistance programs, corporate advertising, and lobbying activities. These reductions were partially offset by costs associated with SPPC’S Supplementary Executive Retirement Plan which were disallowed by the PUCN in 2004.

Income taxes — other income and expense changed from an income tax benefits recognized for the year ended December 31, 2004 to income tax expense recognized during the same period in 2005. The 2004 tax benefit was recognized primarily as a result of an impairment charge associated with the Piñon Pine generating facility during the second quarter of 2004. See Note 3, Regulatory Actions of the Notes to the Financial Statements for additional information regarding the impairment charge.

ANALYSIS OF CASH FLOWS

SPPC’s cash flows increased during the year ended December 31, 2005, when compared to the same period in 2004, as a result of an increase in cash flows from operating activities partially offset by increases in cash used in investing activities and financing activities. Cash flows from operating activities were higher in 2005 due to rate increases that became effective in the second quarter of 2004, which was the result of SPPC’s General and Deferred Rate Cases (refer to “Regulatory Proceedings”). Also causing an increase in cash flow from operations was the $11 million escrow payment for Enron in 2004, a reduction in prepayments and deposits for energy in 2005 due to the establishment of the revolving credit facility and changes in accounts receivables for tax sharing

agreements, offset by energy costs being higher than amounts recovered in rates in 2005. Cash flows used in investing activities increased primarily as a result of construction activity related to growth. Cash used for financing activities increased due to payment of dividends to the parent in 2005, offset by the payoff of the short-term credit facility in 2004.

SPPC’s cash flows improved during 2004, when compared to 2003, due mainly to rate increases that went into effect in the second quarter of 2004 to recover deferred energy balances and operating costs. Also contributing to this increase was reduced construction expenditures as a result of the completion of the Falcon to Gonder project, a reduction in interest payments due to successful remarketing efforts and no dividends being paid to SPR. Partially offsetting these increases were a payoff of short-term borrowing of $25 million in March 2004, a payment of $11 million into the Enron escrow account ordered by the judge overseeing the Enron bankruptcy proceedings and funding for the pension plan.

LIQUIDITY AND CAPITAL RESOURCES

Overall Liquidity

SPPC’s primary source of operating cash flows are electric and gas revenues, including the recovery of previously deferred energy and gas costs. Significant uses of cash flows from operations include the purchase of electricity, natural gas, other operating expenses and interest. SPPC had cash and cash equivalents of approximately $38.2 million at December 31, 2005, not including $11 million in restricted cash which was deposited into escrow in connection with the stay of the Enron Judgment.

On January 26, 2006, upon final approval of the settlement with Enron, SPPC paid Enron approximately $39.2 million from available cash resources. On January 27, 2006, the approximate $11 million cash held in escrow, plus interest, and the Series E Bond was returned to SPPC. The bond was cancelled and may be used to support future issuances of general and refunding securities by SPPC. As part of the settlement, SPPC was granted a general unsecured claim (the “Unsecured Claim”) in Class Six of Enron’s Plan of Reorganization in the amount of $45.8 million. On October 24, 2005, SPPC purchased a put option from a major international banking institution that, if exercised, obligated that institution to purchase the Unsecured Claim (contingent upon allowance of the Unsecured Claim by the Bankruptcy Court), which ensured that SPPC’s net cash outlay to settle Enron’s claim would be no higher than $25.0 million. On February 16, 2006, the Unsecured Claim was sold to a separate third party resulting in a final net cash outlay which did not materially differ from the anticipated cash outlay. To the extent SPPC is not permitted to recover the net amount paid under the settlement agreement through future regulatory filings, the amount not permitted would be charged as a current operating expense.

On November 4, 2005, SPPC amended and restated its existing secured $50 million revolving credit facility, maturing in October 2007, increasing the size of the facility to $250 million and extending the maturity to November 2010. As of February 24, 2006, SPPC had additional liquidity in the amount of $216 million under its amended credit facility.

SPPC anticipates that it will be able to meet operating costs, such as fuel and purchased power costs with internally generated funds, including the recovery of deferred energy. However, to fund capital requirements, as discussed below, SPPC may meet such financial obligations with a combination of internally generated funds, the use of its revolving credit facility and if necessary, the issuance of long-term debt.

SPPC’s overall liquidity continues to improve. The increase in SPPC’s general, electric and gas rates cases, as discussed further in Regulatory Proceedings, improved debt profile, the settlement of various litigation, as discussed in Note 14, Commitments and Contingencies of the Notes to Financial Statements, and management of energy risk are allowing SPPC to continue to improve its overall liquidity.

SPPC designs operating and capital budgets to control operating costs and capital expenditures. In addition to operating expenses, SPPC has continuing commitments for capital expenditures for construction, improvement and maintenance of facilities.

Detailed below are SPPC’s Capital Structure, Capital Requirements, Contractual Obligations, recently completed Financing Transactions and Factors Affecting Liquidity including SPPC’s ability to obtain debt on favorable terms and limitations on indebtedness.

Capital Structure

SPPC’s actual consolidated capital structure was as follows at December 31:


	2005				2004
Short-Term Debt (1)	$	52,400	3.0	%	$	2,400	0.1	%
Long-Term Debt		941,804	53.1	%		994,309	56.9	%
Preferred Stock		50,000	2.8	%		50,000	2.9	%
Common Equity		727,777	41.1	%		705,395	40.1	%

Total	$	1,771,981	100	%	$	1,752,104	100	%


(1)		Includes current maturities of long-term debt.

Capital Requirements

Construction Expenditures

SPPC’s cash construction expenditures are expected to increase due to programs designed to meet electric load growth and reliability needs. Cash construction expenditures for the years ended 2005, 2004 and 2003 were approximately $113 million, $104 million and $127 million, respectively. SPPC’s cash construction expenditures for 2006 are projected to be $295.8 million. SPPC’s cash construction expenditures for 2006 through 2010 are projected to be $1.9 billion and are expected to be financed by external financing, internally generated funds, which included recovery of SPPC’s deferred energy balances and SPPC’s existing credit facility. The timing and extent of the estimated capital expenditures may change if SPPC receives approval for the Ely Energy Center. If this project is approved by the PUCN, SPPC’s steadily improving financial condition, as evidenced by the upgrade in credit ratings in 2005 and recent financing transactions, should allow it to successfully raise funds in the capital markets.

Contractual Obligations

The table below provides SPPC’s consolidated contractual obligations, not including estimated construction expenditures described above, as of December 31, 2005, that SPPC expects to satisfy through a combination of internally generated cash and, as necessary, through the issuance of short-term and long-term debt (dollars in thousands):


	Payment Due by Period
	2006		2007		2008		2009		2010		Thereafter		Total
Long-Term Debt Maturities	$	52,400	$	2,400	$	322,400	$	420	$	—	$	617,250	$	994,870
Long-Term Debt Interest Payments		68,084		66,204		51,117		40,268		40,258		397,603		663,534
Purchase Power		180,561		112,836		109,308		78,941		74,220		983,208		1,539,074
Coal and Natural Gas		384,636		89,122		64,264		55,540		38,574		269,647		901,783
Operating Leases		9,878		6,851		6,623		6,654		6,631		37,740		74,377


Total Contractual Cash Obligations (1)	$	695,559	$	277,413	$	553,712	$	181,823	$	159,683	$	2,305,448	$	4,173,638


(1)		Does not include the January 2006 long-term service contract totaling $328 million for equipment and construction services associated with the new generation plant at the Tracy facility^.

Pension Plan Matters

SPR has a qualified pension plan that covers substantially all employees of SPR, NPC and SPPC. The annual net benefit cost for the plan is expected to increase in 2006 by approximately $7.9 million compared to the 2005 cost of $22.7 million. As of September 30, 2005, the measurement date, the plan was fully funded on a FAS 87 ABO basis (fair value of assets exceeded ABO). During 2005, SPR contributed a total of $15 million to meet its funding obligations under the plan. At the present time it is not expected that any additional funding will be required in 2006 to meet the minimum funding level requirements defined by the Pension Benefit Guaranty Corporation and ERISA. SPR and the Utilities expect to contribute approximately $15 million to the plan in 2006; however, the amounts to be contributed may change, subject to market conditions.

Financing Transactions

Redemption of Indebtedness

On February 17, 2006, SPPC announced its intention to redeem its $110 million Series A Collateralized Medium-Term Notes, due June 2022, and its $58 million Series B Collateralized Medium-Term Notes, due November 2023. The redemption is scheduled to occur on March 20, 2006. SPPC intends to finance the redemption through internal cash or through the use of its Amended Credit Facility.

Amended Credit Facility

On November 4, 2005, SPPC amended and restated its existing secured $50 million revolving credit facility, maturing in October 2007, reducing the fees on both the unused portion of the facility, and the amounts borrowed, increasing the size of the facility to $250 million, extending the maturity to November 2010 and changing the Administrative Agent for the facility to Wachovia Bank, National Association. The rate for outstanding loans and/or letters of credit under the revolving credit facility will be at either an applicable base rate (defined as the higher of the Prime rate and the Federal Funds rate plus one-half of one percent) or a Eurodollar rate, plus a margin that varies based upon SPPC’s credit rating by at least two of the three rating agencies (S&P, Moody’s and Fitch). Currently, the base rate is Prime and SPPC’s applicable base rate margin is zero. The current Eurodollar margin is 0.875%. As of December 31, 2005 SPPC had $3.8 million of letters of credit and no direct borrowings under the revolving credit facility. As of February 24, 2006, SPPC had $9.0 million of letters of credit and $25 million borrowed under the revolving credit facility.

On October 21, 2005, SPPC filed an application with the PUCN seeking financing authority for a two-year period ending December 31, 2007. Included in that application was a request to increase the size of SPPC’s revolving credit facility to $350 million. The $100 million increase would provide SPPC with additional liquidity to cover increased commodity prices. The hearing on this application was held on February 2, 2006 with a final decision expected in March 2006.

The SPPC credit agreement contains two financial maintenance covenants. The first requires that SPPC maintain a ratio of consolidated indebtedness to consolidated capital, determined as of the last day of each fiscal quarter, not to exceed 0.68 to 1. The second requires that SPPC maintain a ratio of consolidated cash flow to consolidated interest expense, determined as of the last day of each fiscal quarter for the period of four consecutive fiscal quarters, not to be less than 2.0 to 1. As of December 31, 2005, SPPC was in compliance with these covenants. The revolving credit facility is secured by SPPC’s General and Refunding Mortgage Bonds; however, in the event that SPPC obtains an unsecured debt rating from at least two rating agencies that is at least BBB- from S&P and Fitch or Baa3 from Moody’s, the General and Refunding Mortgage Bonds securing the revolving credit facility will be released.

The credit agreement contains customary conditions to borrowing including requirements that no material litigation, defaults or other events that could have a material adverse effect on SPPC’s business shall have occurred. In the event that SPPC’s unsecured debt ratings meet the conditions discussed above, the requirement that no material adverse changes shall have occurred ceases to be a condition to borrowing under the credit agreement. The SPPC Credit Agreement provides for an event of default if there is a failure under other financing agreements of that entity to meet payment terms or to observe other covenants that would result in an acceleration of payments due.

The SPPC Credit Agreement, similar to SPPC’s Series H Notes, places certain restrictions on debt incurrence, liens and dividends. These limitations are discussed in Note 9 of Notes to Financial Statements, Debt Covenant Restrictions.

Factors Affecting Liquidity

Limitations on Indebtedness

Certain of SPPC’s financing agreements contain restrictions on SPPC’s ability to issue additional indebtedness. The terms of SPPC’s 6¼% General and Refunding Mortgage Notes, Series H, due 2012, and $250 million Revolving Credit Agreement restrict SPPC from issuing additional indebtedness unless:

1. at the time the debt is incurred, the ratio of consolidated cash flow to fixed charges for SPPC’s most recently ended four quarter period on a pro forma basis is at least 2 to 1, or

hedging obligations, indebtedness incurred to support bid, performance or surety bonds, and certain letters of credit issued to support SPPC’s obligations with respect to energy suppliers, or

3. indebtedness incurred to finance capital expenditures pursuant to SPPC’s 2004 Resource Plan.

If SPPC’s Series H Notes are upgraded to investment grade by both Moody’s and S&P, these restrictions will be suspended and will no longer be in effect so long as the Series H Notes remain investment grade. As of December 31, 2005, SPPC would have been able to issue approximately $494 million of additional indebtedness on a consolidated basis, assuming an interest rate of 6.00%, per the requirement stated in number 1 above. However, due to the terms of SPR debt, SPPC’s combined debt limit is restricted to the $482 million of additional indebtedness SPR could incur on a consolidated basis. See Note 9, Debt Covenant Restrictions to the Notes to Financial Statements.

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 December 31, 2005, $487.3 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 December 31, 2005, there were $842 million of SPPC’s General and Refunding Mortgage securities outstanding. Additional securities may be issued under the General and Refunding Mortgage Indenture on the basis of:

	1.		70% of net utility property additions,

	2.		the principal amount of retired General and Refunding Mortgage bonds, and/or

	3.		the principal amount of first mortgage bonds retired after April 8, 2002.

On the basis of (1), (2) and (3) above, as of January 31, 2006, SPPC had the capacity to issue approximately $324 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 the Revolving Credit Agreement limit the amount of additional indebtedness that SPPC may issue and the reasons for which such indebtedness may be issued.

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.

Credit Ratings

Energy Supplier Issues

With respect to SPPC’s contracts for purchased power, SPPC purchases and sell electricity with counterparties under the Western Systems Power Pool (WSPP) agreement, an industry standard contract that SPPC is required to use as members of the WSPP. The WSPP contract is posted on the WSPP website.

entire remaining term of all contracts between the parties aggregated to a single liquidated amount due within three business days following the date the notice of termination is received. The mark-to-market value, which is substantially based on quoted market prices, can be used to roughly approximate the termination payment and benefit at any point in time. The net mark-to-market value as of December 31, 2005 for all suppliers continuing to provide power under a WSPP agreement would approximate an $18.5 million payment by SPPC.

Gas Supplier Issues

With respect to the purchase and sale of natural gas, SPPC uses several types of standard industry contracts. The natural gas contract terms and conditions are more varied than the electric contracts. Consequently, some of the contracts contain language similar to that found in the WSPP agreement and other agreements have unique provisions dealing with material adverse changes. Because of creditworthiness concerns, most contracts and confirmations for natural gas purchases have been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery. At the present time, some natural gas purchase transactions require payment in advance of delivery.

Gas transmission service is secured under FERC Tariffs or custom agreements. These service contracts and Tariffs require the user establish and maintain creditworthiness to obtain service or otherwise post cash or a letter of credit to be able to receive service. Service contracts are subject to FERC approved tariffs, which, under certain circumstances, require the Utility to provide collateral to continue receiving service.

Cross Default Provisions

SPPC’s financing agreements do not contain any cross-default provisions that would result in an event of default by SPPC upon an event of default by SPR or NPC under any of their respective financing agreements. Certain financing agreements of SPPC provide for an event of default if there is a failure under other financing agreements of SPPC 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 may rectify or correct the situation before it becomes an event of default.

REGULATORY PROCEEDINGS (UTILITIES)

SPR is a “holding company” under the Public Utility Holding Company Act of 2005 (PUHCA 2005). As a result, SPR and all of its subsidiaries (whether or not engaged in any energy related business) are required to maintain books, accounts and other records in accordance with FERC regulations and to make them available to the FERC, the PUCN and CPUC. In addition, upon the request of the PUCN or CPUC, or of SPR, the FERC would have the authority to review allocations of costs of non-power goods and administrative services among SPR and its subsidiaries. The FERC has the authority generally to require that rates subject to its jurisdiction be just and reasonable and in this context would continue to be able to, among other things, review transactions between SPR, NPC and/or SPPC and/or any other affiliated company. SPR is in the process of evaluating the full extent of its obligations under PUHCA 2005 and available exemptions and waivers there under, and anticipates completing its FERC-65 filing on March 10, 2006.

The Utilities are subject to the jurisdiction of the PUCN and, in the case of SPPC, the 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 (IRPs) to the PUCN for approval.

Under federal law, the Utilities and 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. The following regulatory proceedings have affected, or are expected to affect the utilities financial positions, results of operations and cash flows.

The utilities are required to file periodic Deferred Energy Accounting Adjustment (DEAA) cases and General Rate Cases (GRC’s) in Nevada. As of December 31, 2005, NPC’s and SPPC’s balance sheet included approximately $118.9 million and $36.9 million, respectively, of approved deferred energy costs to be collected in current rates over various periods. Refer to Note 1, Summary of Significant Accounting Policies, of the Notes to Financial Statements. As of December 31, 2005, NPC’s and SPPC’s balance sheet included approximately $400.9 million and $114.7 million, respectively, of deferred energy costs, $171.5 million of which have been requested in NPC’s 2006 Deferred Energy case and $46.7 million of

which have been requested in SPPC’s Deferred Energy Case discussed below. The remaining amount will be requested in a future regulatory filing.

The following summarizes rate case applications filed in 2005 and 2006. Each of these rate cases, as well as other regulatory matters such as, the Utilities’ Integrated Resource Plans and subsequent amendments, other Nevada Matters, California Matters and FERC matters are discussed in more detail within this section.

Pending Rate Cases

	•		NPC 2006 Deferred Energy Case — Application to create a new Deferred Energy Accounting Adjustment (DEAA) rate and to update the Base Tariff Energy Rate (BTER) The requested increases are a) on August 1, 2006 to begin collecting $171.5 million of deferred costs for purchased fuel and power and b) on May 1, 2006, to increase the BTER for going forward energy costs such that an estimated $138 million of new revenues will be generated annually for fuel and power purchases. The two requested rate increases total approximately 17%.

	•		SPPC December 2005 Deferred Energy and BTER Update — Application to create a new Electric DEAA rate and to update the Electric BTER. The requested increases are a) on May 1, 2006, to begin collecting $46.7 million of deferred costs for purchased fuel and power and b) also on May 1, 2006, to increase the BTER for going forward energy costs such that an estimated $53 million of new revenues will be generated annually for fuel and power purchases. The two requested rate increases total 9.79%.

	•		SPPC 2005 Electric and Gas General Rate Cases — Applications to reset Electric and Gas General Rates and Depreciation Expense Rates. The legislatively mandated electric application requests authorization to increase electric general rate revenues by $3.2 million, a .4% rate increase, and the gas application requests authorization to increase gas general rate revenues by $8.3 million, a 5.4% rate increase. Both applications request an 11.4% return on equity. The new general rates are expected to become effective on May 1, 2006.

	•		SPPC 2005 California General Rate Case — Application to reset General Rates. The original application requested an $8.1 million, 12.7% rate increase, to become effective on January 1, 2006. The parties negotiated a settlement, which calls for a $4.1 million increase. SPPC expects the rates to become effective in July 2006.

Recently Approved Rate Cases

	•		NPC 2005 BTER Update — the PUCN approved a new BTER increasing purchased fuel and power revenues by $66.9 million

	•		SPPC July 2005 Electric BTER Update — the PUCN approved a new Electric BTER increasing purchased fuel and power revenues by $64 million

	•		SPPC January 2005 Electric Deferred Energy Rate Case — the PUCN approved a new Electric DEAA rate to recover $27.1 million of deferred expenses and a new BTER to better match going forward energy costs

	•		SPPC Gas Deferred Energy Rate Case and BTER Update — the PUCN approved a new Electric DEAA rate to recover $6.9 million of deferred expenses and a new BTER increasing purchased fuel and power revenues by $34.1 million

Nevada Matters

Nevada Power Company

2006 Deferred Energy Rate Case

On January 17, 2006, pursuant to recently enacted legislation, NPC filed a DEAA rate case application with the PUCN seeking recovery for purchased fuel and power costs accumulated between October 1, 2004 and November 30, 2005, and to increase its going forward BTER to reflect future energy costs. NPC requested a one year amortization period to recover the deferred balance.

NPC requested that the BTER increase become effective on May 1, 2006. The BTER change represented an 8% increase for the average customer and is expected to generate $138 million of new revenues for fuel and power purchases.

NPC requested authorization to begin a one year recovery of the $171.5 million deferred balance on August 1, 2006. The requested DEAA adjustment represents an additional rate increase of approximately 9.3%.

2005 Base Tariff Energy Rate Update

On June 3, 2005, pursuant to newly adopted regulations allowing more frequent energy cost adjustments, NPC filed a request to increase its BTER to reflect forecasted energy costs. NPC expected the request would increase revenue by $66.9 million for the 12 month period October 1, 2005 to September 30, 2006 and more closely correlate fuel and purchased power revenues with fuel and purchased power costs. The proposed increase would not affect NPC’s operating income. The increase was intended to recoup, on a more current basis, actual fuel and purchased power costs that NPC will incur during the rate effective period.

On September 27, 2005, the PUCN issued an order approving the BTER rate changes requested in NPC’s filing.

2004 Deferred Energy Rate Case

On November 15, 2004, NPC filed an application with the PUCN seeking recovery for purchased fuel and power costs accumulated between October 1, 2003 and September 30, 2004. The application sought to establish a rate to collect accumulated purchased fuel and power costs of $116 million, with a carrying charge. The application requested that the 2004 DEAA recovery begin with the expiration of the 2002 DEAA recovery, which was expected to occur in May 2006 and for the 2004 DEAA recovery period to be 22 months.

The application also requested an increase to NPC’s BTER.

In concert with this 2004 DEAA filing, NPC filed a petition with the PUCN requesting that other pending DEAA rate changes be synchronized to change on April 1, 2005 in order to stabilize rates and reduce the number of rate changes. On December 28, 2004, the PUCN issued an order approving a stipulation reached by all parties that allows NPC to defer previously approved DEAA rate changes until April 1, 2005 coincident with the DEAA rate change that will result from the 2004 DEAA case.

The combined effect of the requested synchronization of multiple rate changes (going forward BTER increase, 2001 DEAA expiration, and 2003 DEAA initiation) resulted in a request for an overall rate decrease of 2.4%.

On February 22, 2005, a stipulation of the parties was filed with the PUCN resolving all issues in the case. The stipulation provided for an overall decrease of 0.6% in total rates with no disallowances. The PUCN approved the stipulation in total on March 16, 2005.

For further detail of deferred energy cases see Note 3, Regulatory Actions of the Notes to Financial Statements.

Nevada Power Company 2003 Integrated Resource Plan

On July 1, 2003, NPC filed its 2003 IRP with the PUCN. The IRP was prepared in compliance with Nevada laws and regulations and covered the 20-year period from 2003 through 2022. The IRP developed a comprehensive, integrated plan that considered customer energy requirements and proposed the resources to meet those requirements in a manner that was consistent with prevailing market fundamentals. The ultimate goal of the IRP was to balance the objectives of minimizing costs and reducing volatility while reliably meeting the electric needs of NPC’s customers.

The IRP also included a three-year action plan that covered calendar years 2004, 2005, and 2006. During this period, NPC proposed a number of specific projects to be completed. NPC proposed building an 80 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.

The PUCN approved an order on NPC’s IRP on November 12, 2003. In general, the order approved NPC’s various requests made in its filing and also imposed additional requirements for various briefings, and required amendments to the IRP if there are delays in the combined cycle units’ construction, issues with transmission reservations, or difficulties financing the IRP.

Subsequent Material Amendments to NPC’s 2003 Integrated Resource Plan

Lenzie Generating Station Acquisition

On June 29, 2004, NPC filed its second amendment to its 2003 IRP. The second amendment requested PUCN authorization to acquire the partially completed Lenzie power plant from Duke Energy for $182 million. The amendment requested approval to substitute the 1200 MW Chuck Lenzie Generating Station for the previously approved Harry Allen 520 MW combined cycle generator, which was to come on line in 2007.

The PUCN granted NPC’s request and the transaction closed on October 13, 2004. The PUCN further granted NPC’s request for a critical facility designation and allowed a 2% enhancement of the authorized ROE to be applied to the rate base associated with the Lenzie construction costs expended after acquisition. The order allows for up to an additional 1% enhanced ROE if the two Lenzie generator units are brought on line early and the gradual elimination of the enhanced ROE if completion is delayed. The order allows NPC to include the plant investments during construction in rate base when NPC files its regularly scheduled general rate cases, which permits NPC to earn a return during construction. The PUCN also granted NPC’s request to establish regulatory asset accounts to prevent the erosion of earnings, which otherwise would occur due to regulatory lag. The regulatory asset account will capture the depreciation expense and return on rate base between the time the plant is placed in service and when the plant costs are included in rates.

In January 2006 the first 600MW combined cycle unit (Block #1 — two combustion turbines and one steam turbine) was declared commercially operable. NPC anticipates that Block #2 will be declared commercially operable in the spring of 2006.

Silverhawk Plant Acquisition and Clark Generating Unit Retirements

On June 29, 2005, NPC filed an application with the PUCN for approval to purchase the remaining 75% interest in the 560MW gas fired Silverhawk power plant from Pinnacle West Capital Corp, Pinnacle West Energy Corp and GenWest, LLC (“Pinnacle”). The Silverhawk generating plant is located 25 miles northeast of Las Vegas and is near NPC’s Lenzie Power plant. NPC also made concurrent filings requesting approval of an interim Silverhawk power purchase agreement and approval to issue $210 million of debt financing to close the transaction.

NPC also requested approval to retire and recover the associated retirement and decommissioning costs for the Clark Generating Station units 1, 2 and 3 (“Clark”). NPC requested approval to set up regulatory asset accounts to capture the Clark retirement and decommissioning costs.

The PUCN Staff, Bureau of Consumer Protection (BCP) and NPC filed a negotiated stipulation concerning the Silverhawk acquisition and on September 23, 2005, the PUCN issued its order approving the stipulation. All other regulatory authorities approved the acquisition of the power plant by December 31, 2005. On January 10, 2006, NPC consummated the purchase of Pinnacle’s 75 % interest of the Silverhawk facility.

Not included in the above stipulation was NPC’s requested accounting treatment for retirement and decommissioning costs of Clark. On September 13, 2005, NPC filed an amended application requesting: 1) authorization to set up a regulatory asset account for the net book value and decommissioning costs for the Clark Units 1, 2 and 3 and that any balance in the account be included in rate base in NPC’s next general rate case with a four year amortization schedule, 2) authorization to use decremental operations and maintenance costs associated with the shutdown of the Mohave generating station to offset the incremental operations and maintenance costs resulting from the addition of the Lenzie and Silverhawk generating units.

On January 5, 2006, the PUCN voted to issue an order authorizing NPC to establish regulatory asset accounts for the net book value and decommissioning costs and denied NPC’s request to use decremental operations and maintenance costs associated with Mohave to offset the incremental operations and maintenance costs resulting from the addition of the Lenzie and Silverhawk generating units.

Request for Authorization to Acquire Land & Land Rights for Transmission Facilities

On January 20, 2006, NPC filed an amendment to its 2003 Integrated Resource Plan requesting approval to acquire approximately $57 million of strategic investments in land and land rights necessary for future 500 kV and 230 kV transmission facilities. NPC also requested approval to accrue a carrying charge on the investments, which would be equal to the current Allowance for Funds Used During Construction.

Miscellaneous Amendments to NPC’s 2003 Integrated Resource Plan

NPC has filed, and the PUCN has approved, a number of resource plan amendments, which requested approval of a power exchange agreement with the Southern Nevada Water Authority, reaffirmed the need for a major transmission line, modified demand side management programs, modified previously approved renewable energy contracts and requested approval of new contracts for renewable credits.

Sierra Pacific Power Company

2005 Electric and Gas General Rate Cases

On October 3, 2005, SPPC filed a gas general rate case along with its statutorily required electric general rate case. SPPC’s last Gas general rate case was filed in 1992 and the last electric general rate case was filed in 2003. The following items are requested in the filings:

	•		Electric general revenue increase: $27 million or 3.4% effective May 1, 2006

	•		Gas general revenue increase: $8.3 million or 5.4%, effective May 1, 2006

	•		Electric Return on Equity and Rate of Return: 11.4% and 9.27% respectively

	•		Gas Return on Equity and Rate of Return: 11.4% and 8.29% respectively

	•		Approval to continue to recover an allocated amount of the 1999 NPC/SPPC merger costs from Electric customers

	•		Approval to recover an allocated amount of the 1999 NPC/SPPC merger costs from Gas customers

	•		New depreciation rates for Gas and Electric facilities

SPPC submitted its certification filing for cost of capital and depreciation rates on December 30, 2005 and its revenue requirements and rate design certification filing on January 23, 2006. These filings did not change the requested ROE, ROR or depreciation rates, but did adjust the requested electric revenue increase to $3.2 million.

On January 25, 2006 the interveners filed direct testimony addressing return on equity, overall rate of return and depreciation rates. The PUCN Staff has recommended a 10.28% ROE for Electric and Gas operations, an 8.97% Electric ROR, an 8.06% Gas ROR and depreciation rates that would result in decreased depreciation expenses. Other interveners are recommending ROE’s ranging from 9.1% to 10.9%, Electric ROR’s from 8.35% to 9.08% and Gas ROR’s from 7.52% to 8.10%. The other interveners have also suggested depreciation rates lower than SPPC’s filing.

On February 22, 2006 interveners filed direct testimony addressing overall revenue requirements, including the effects of their ROE, ROR and depreciation rate recommendations. The PUCN Staff recommended a $15 million decrease to current electric revenues and a $3.6 million increase to gas revenues. The Bureau of Consumer Protection (BCP) recommended a $32 million reduction to current electric revenues and a $600 thousand increase to current gas revenues. The Nevada Resort Association recommended a $12 million decrease to current electric revenues.

Hearings are scheduled to occur on various dates in March 2006. A decision on these cases is due early in the second quarter of 2006.

December 2005 Deferred Energy Rate Cases and Base Tariff Energy Rate Updates

On December 1, 2005, SPPC filed an electric deferred energy rate case application with the PUCN. The application sought recovery for purchased fuel and power costs accumulated between December 1, 2004 and September 30, 2005 and the unamortized balance from the previously approved deferred energy case, the remainder of which was due to the shortened amortization period.

The application sought to establish a rate to collect accumulated purchased fuel and power costs of $46.7 million from the December 2004 to September 2005 deferral period and $17.5 million from the previously approved unamortized deferrals, for a total $64.2 million. SPPC requested that the recovery begin May 1, 2006, the same effective date for its pending electric and gas general rate cases. SPPC requested a one year recovery period and that a carrying charge be allowed.

The application also requested an increase to the BTER. The combined effect of the requested deferred energy accounting adjustment and the BTER increase would be an overall rate increase of approximately 9.79%.

July 2005 Electric Base Tariff Energy Rate Update

On July 1, 2005, SPPC filed a request to increase its BTER to reflect forecasted energy costs. The request was expected to increase revenue by $32.3 million for the period October 1, 2005 to September 30, 2006 and was intended to more closely correlate fuel and purchased power revenues with fuel and purchased power costs. The proposed increase would not affect SPPC’s operating income. The increase was intended to recoup, on a more current basis, actual fuel and purchased power costs that SPPC were expected to be incurred during the rate effective period.

The request represented an increase of 3.7% for the average customer. SPPC agreed to a November 1, 2005 effective date due to procedural requirements.

The PUCN Staff filed testimony that recommended an increase to SPPC’s request. The PUCN Staff’s recommended BTER would have increased rates by 10.9% and increase revenues by $95.2 million for the 12 month period.

On October 27, 2005 the PUCN voted to approve a new electric BTER effective November 1, 2005. The new rate represented a 7.3% overall electric rate increase and was expected to produce $64 million additional revenues during the following 12 months.

January 2005 Electric Deferred Energy Rate Case Filing

On January 14, 2005, SPPC filed an application with the PUCN seeking recovery for purchased fuel and power costs accumulated between December 1, 2003 and November 30, 2004, as required by law.

The application sought to establish a rate to collect accumulated purchased fuel and power costs of $27.7 million, with a carrying charge. The application requested that the 2005 DEAA recovery begin on June 1, 2005 together with the commencement of recovery of the 2004 DEAA balance, both of which are coincident with the expiration of the 2002 and 2003 DEAA recovery. SPPC has requested a 24-month recovery period for the 2005 DEAA balance.

The application also requested an increase to the BTER or going-forward energy rate.

The combined effect of the proposed synchronization of multiple rate changes (going-forward BTER increase, 2002 and 2003 DEAA expiration, 2004 and 2005 DEAA initiation) resulted in a request for an overall rate increase of approximately 1.85%.

On March 30, 2005, SPPC filed an updated forecast of its going-forward BTER. On April 6, 2005, the PUCN Staff and the BCP filed written direct testimony in this case. The testimony recommended full recovery of the deferred balance after a $576 thousand reduction to reflect an accounting adjustment mutually agreed to by the parties. The PUCN Staff recommended adoption of the higher BTER rate that SPPC filed on March 30, 2005 while the BCP opposed the implementation of the higher BTER.

The PUCN issued its order on May 17, 2005 granting $27.1 million deferred expense recovery ($27.7 million requested less $.6 million), modifying the amortization period from the two years requested to one year and approving a BTER rate based on the historical costs methodology as provided for in the Nevada Administrative Code. The overall rate increase was 5.15%.

For further detail of deferred energy cases see Note 3, Regulatory Actions of the Notes to Financial Statements.

2005 Gas Deferred Energy Rate Case and Base Tariff Energy Rate Update

Regulations enacted in 2004 require SPPC to account for gas purchases to serve its gas customers in the same manner as it accounts for its fuel and power purchases for electric customers. On May 13, 2005, SPPC filed a gas deferred energy rate case requesting recovery of $6.9 million of deferred energy costs. The filing requested a two-year amortization of the deferred energy balance which represents a 3.2% average increase for all customers.

On July 1, 2005, SPPC filed a proposed gas BTER, which represented an average increase of 19.5% for all customer classes. The estimated BTER revenue would not change SPPC’s operating income.

The PUCN Staff filed testimony recommending full recovery of the deferred period gas expenditures. The PUCN Staff also filed testimony recommending a higher BTER that would increase rates by 28.7% overall and would add $42.4 million to current revenues.

On October 27, 2005, the PUCN voted to approve recovery of $6.9 million of deferred energy costs with a one year amortization and set a new gas BTER rate, both effective on November 1, 2005. The new BTER was expected to produce $34.1 million additional revenues during a 12 month period. The combined increases represented a 25.3% overall gas rate increase.

For further detail of deferred energy cases see Note 3, Regulatory Actions of the Notes to Financial Statements.

Sierra Pacific Power Company 2004 Integrated Resource Plan

SPPC filed its triennial resource plan with the PUCN on July 1, 2004. The significant provisions of the plan include efforts to minimize SPPC’s reliance on a volatile energy market through a mix of owned generation, fuel diversity and purchased power.

Consistent with this plan SPPC requested approval to construct a 514 MW combined cycle plant at SPPC’s Tracy generation station to be in service in 2008 and to conduct the permitting and development activities necessary to construct an additional 250 MW coal-fired unit at Valmy to be placed in service in the 2011 to 2015 time frame. SPPC will fill its remaining open position with purchased power from renewable energy providers and non-renewable sources.

Additionally SPPC sought PUCN approval of its 2005 through 2007 energy supply plan. The energy supply plan included a recommendation for the issuance of a request for proposals for short and intermediate term power contracts to fill a significant portion of SPPC’s capacity requirements during that period and a recommended gas hedging strategy for April 2005 through March 2006.

The interveners agreed that SPPC should continue with permitting activities for a 514 MW combined cycle power plant. SPPC also agreed to file another Resource Plan Amendment before August 1, 2005 to reaffirm the need for the additional 514 MW generating capacity. On November 18, 2004, the PUCN issued an Order approving the parties’ stipulated agreement.

In its Order, the PUCN approved and determined the power procurement element of the Energy Supply Plan to be prudent; however, the PUCN did not rule on the prudence of the fuel procurement plan and risk management strategy. The prudence of SPPC’s fuel procurement and risk management would be determined in the appropriate DEAA proceeding, which was filed on December 1, 2005.

Subsequent Material Amendments to SPPC’s 2004 Integrated Resource Plan

On August 1, 2005, SPPC filed an amendment to its previously approved Integrated Resource Plan. In the amendment SPPC requested approval to construct a 514 MW combined cycle unit at its Tracy Station located east of Reno. The estimated cost to construct the unit is $421 million and is scheduled to be in service by June 2008. The unit is intended to provide needed generation within SPPC’s control area to reliably serve the growing needs of Northern Nevada. SPPC also requested that the unit be designated as a Critical Facility under Nevada regulations, and as such, has requested the following cost recovery mechanisms: 1) an incentive return of 2% above SPPC’s authorized rate of return on equity and 2) include the project’s construction work in progress (CWIP) in rate base for all general rate cases prior to the facility being placed into service.

On December 14, 2005, the PUCN issued an order granting approval for SPPC to construct a 514 MW gas fired combined cycle generator. The PUCN also allowed SPPC to include construction work in progress balances in the rate base of any interim general rate cases and granted a 1.5% enhanced ROE for the estimated $421 million investment.

Other Nevada Matters

Large Customer Applications to Acquire Energy From New Supplies

Barrick Application

In February 2004, Barrick Gold (Barrick), a large SPPC mining customer filed an application with the PUCN, describing its plans to construct a generating facility to meet its electric power needs and purchase transmission and distribution service from SPPC. Barrick, SPPC and other parties reached an agreement prior to hearings, which was presented to the PUCN on May 19, 2004. The PUCN issued an order approving the application as stipulated in the agreement on June 22, 2004. Following the PUCN approval, Barrick provided official notice of departure to SPPC on October 22, 2004; Barrick’s departure was to occur in November 2005.

In January 2006, Barrick paid a lump sum $6.6 million to mitigate the impact of Barrick’s departure from bundled electric service and to insure no economic harm to remaining customers of SPPC. Barrick is also required to pay its share of uncollected DEAA balances. This payment is for the fuel and purchased power costs attributable to serving Barrick that had not been collected as of Barrick’s departure date. Also in January 2006, Barrick paid $5.2 million, which was their share of the previously approved and not yet recovered DEAA balances. Barrick has decided to pay their share of the as yet unapproved balances (refer to SPPC’s December 2005 DEAA application) over time.

Barrick began taking service from its generating facility in December 1, 2005.

The departure of Barrick is not expected to have a material impact on the results of operations of SPPC.

Newmont Mining Transaction

The Newmont Mining Corporation and SPPC have developed terms and conditions under which Newmont’s affiliate, Northern Nevada Energy Investment (NNEI), will construct a 203 MW coal fired generating plant, the output of which NNEI will sell to SPPC. SPPC will in turn sell part of the plant’s output to Newmont to serve a portion of Newmont’s mining loads under a new

tariff and will retain the remainder to serve its other system customers. Newmont’s peak load is forecasted to be 125 MW at the time its generation is expected to be operational in 2008. The Term Sheet provides that Newmont will remain a fully bundled customer of SPPC for at least 15 years after the plant achieves commercial operation.

SPPC and Newmont submitted a number of related filings to the PUCN and the PUCN approved the filings on February 23, 2005. On January 5, 2006, Newmont announced that it had completed the permitting phase of the project.

Nevada Power Company/Sierra Pacific Power Company Quality of Service Investigation

In compliance with the order issued in NPC’s 2003 General Rate case, NPC and SPPC jointly filed with the PUCN, on July 1, 2004, their recommended quality of service and customer service measurements. In the filing, the Utilities outlined their proposed methodologies for measuring the quality of service and customer service measurements, pre- and post-merger. More specifically the Utilities identified the quality of service and customer service measurements to be used in a future rate case, proposed methodology for comparing pre-merger and post-merger performance, and proposed consequences and rewards for under- or over- performance in a future test year.

On September 6, 2005, the PUCN issued an order specifying certain quality of service metrics that will be used in the next general rate case to determine the impact of the merger on quality of service and specified other metrics that will be used on a going-forward basis to monitor overall quality of service without regard to the merger.

SPPC has included these quality of service metrics and measurements into its previously discussed general rate case filings on October 3, 2005 and believes that it has met the performance metrics prescribed by this order.

California Electric Matters (SPPC)

Sierra Pacific Power Company 2005 General Rate Case

On June 3, 2005, SPPC filed a California general rate case requesting $8.1 million of new revenue from approximately 40,000 California customers. The request represents a 12.7% average increase. SPPC requested that the new rates become effective on January 1, 2006.

California’s Office of Ratepayer Advocates filed testimony proposing to reduce SPPC’s revenue increase to $1.8 million and The Utility Reform Network proposed a $7.8 million increase. A large customer coalition group and the Western Manufactured Housing Communities Association filed testimony proposing modifications to SPPC’s rate design.

On January 24, 2006, the parties presented a negotiated settlement to a CPUC Administrative Law Judge calling for a $4.1 million revenue increase. SPPC anticipates the CPUC will rule on the settlement in June 2006. The earliest rates will become effective is July 1, 2006.

FERC Matters

Sierra Pacific Power Company 2004 Transmission Rate Case

On October 1, 2004, the Utilities filed with the FERC revised rates for transmission service offered by SPPC under Docket No. ER05-14. The purpose of the filing was to update rates to reflect recent transmission additions and to improve rate design. The participants in the proceeding filed a Settlement Agreement with the FERC, which was certified by the Settlement Judge. On May 6, 2005, the FERC issued an order approving the negotiated settlement.

California Wholesale Spot Market Refunds

NPC and SPPC are participants in a FERC proceeding wherein California parties have been authorized to recalculate, or mitigate, the prices they paid for wholesale spot market power between October 2, 2000 and June 20, 2001. Both of the Utilities made spot market sales that are eligible for mitigation, therefore the Utilities expect to pay refunds resulting from the recalculated energy prices. Other parties have contested the FERC’s decision to limit the timeframe for the recalculations and a recent Ninth Circuit court decision remanded a related issue to the FERC, therefore NPC and SPPC are not able to determine the eventual magnitude of refunds that may result from this FERC process.

NPC and SPPC are actively participating in this docket to ensure their interests are represented.

Nevada Power Company

Based on the FERC’s orders to date, NPC believes the recalculated energy prices for NPC sales to the California Independent System Operator (CAISO) and the bankrupt California Power Exchange (CALPX) would result in an approximate $19 million refund. The FERC has also allowed for energy sellers to provide cost justification in the event the recalculated energy prices fall below sellers’ costs. NPC’s developed and filed a cost based filing, which justified a $6 million reduction to the estimated refunds resulting in a $13 million refund.

The CAISO and CALPX currently owe NPC approximately $19 million for power delivered during the same timeframe and a $13 million refund would reduce the amount owed to Nevada Power to $6 million. NPC previously recorded a reserve against the $19 million receivable in 2001.

Sierra Pacific Power Company

Based on the FERC’s orders to date, SPPC believes the recalculated energy prices for sales to the CAISO and CALPX during the October 2, 2000 to June 20, 2001 timeframe would result in a $4 million refund.

The CAISO and CALPX currently owe SPPC approximately $1 million for power delivered during the same timeframe and SPPC recorded a reserve against the $1 million receivable in 2001. In 2004, SPPC recorded an additional $3 million liability for this item.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risk

SPR, NPC and SPPC have evaluated their risk related to financial instruments whose values are subject to market sensitivity. Such instruments are fixed and variable rate debt and preferred trust securities obligations. Fair market value is determined using quoted market price for the same or similar issues or on the current rates offered for debt of the same remaining maturities (dollars in thousands).

December 31, 2005


	Expected Maturity Date
																						Fair
	2006			2007			2008			2009			2010			Thereafter			Total			Value (1)
Long-term Debt

SPR
Fixed Rate	$	—		$	—		$	—		$	—		$	—		$	659,142		$	659,142		$	689,131
Average Interest Rate																	7.86	%		7.86	%

NPC
Fixed Rate	$	15		$	17		$	13		$	162,500		$	—		$	1,741,048		$	1,903,593		$	1,979,608
Average Interest Rate		8.17	%		8.17	%		8.17	%		10.88	%					7.20	%		7.52	%
Variable Rate	$	—		$	—		$	—		$	15,000		$	150,000		$	100,000		$	265,000		$	265,000
Average Interest Rate											1.74	%		5.50	%		1.74	%		3.87	%

SPPC
Fixed Rate	$	52,400		$	2,400		$	322,400		$	420		$	—		$	617,250		$	994,870		$	1,013,385
Average Interest Rate		6.73	%		6.40	%		7.99	%		6.40	%		.			6.52	%		7.01	%

Total Debt	$	52,415		$	2,417		$	322,413		$	177,920		$	150,000		$	3,117,440		$	3,822,605		$	3,947,124


(1)		Fair value as of December 31, 2005 when compared to December 31, 2004 decreased primarily as a result of the reduction of debt at SPR and NPC. See Note 7, Long-Term Debt of the Notes to Financial Statements, for further details.

December 31, 2004


	Expected Maturity Date
																						Fair
	2005			2006			2007			2008			2009			Thereafter			Total			Value
Long-term Debt

SPR
Fixed Rate	$	—		$	—		$	240,218		$	—		$	—		$	635,000		$	875,218		$	1,200,538
Average Interest Rate								7.93	%								7.98	%		7.96	%

NPC
Fixed Rate	$	15		$	15		$	17		$	13		$	250,000		$	1,863,548		$	2,113,608		$	2,255,798
Average Interest Rate		8.17	%		8.17	%		8.17	%		8.17	%		10.88	%		7.99	%		8.62	%
Variable Rate	$	—		$	—		$	—		$	—		$	115,000					$	115,000		$	115,000
Average Interest Rate														1.74	%					1.74	%

SPPC
Fixed Rate	$	2,400		$	52,400		$	2,400		$	322,400		$	600		$	617,250		$	997,450		$	1,028,328
Average Interest Rate		6.10	%		6.71	%		6.10	%		7.99	%		6.10	%		6.52	%		6.59	%

Total Debt	$	2,415		$	52,415		$	242,635		$	322,413		$	365,600		$	3,115,798		$	4,101,276		$	4,599,664

Commodity Price Risk

Commodity price increases due to changes in market conditions are recovered through the deferred energy accounting mechanism. Although the Utilities actively manage energy commodity (electric, natural gas, coal and oil) price risk through their procurement strategies, the ability to recover commodity price changes through future rates substantially mitigates commodity price risk. However, the Utilities are subject to cash flow risk due to changes in the value of their open positions and are subject to regulatory risk because the PUCN may disallow recovery for any costs that it considers imprudently incurred. The Utilities mitigate both risk associated with its open positions and regulatory risk through prudent energy supply practices which include the use of long-term fuel supply agreements, long- term purchase power agreements and derivative instruments such as forwards, options and swaps to meet the anticipated fuel and power requirements. See Energy Supply in Item 7, Management’s Discussion and Analysis of

Financial Condition and Results of Operations, for a discussion of the Utilities’ purchased power procurement strategies and Note 14, Commitments and Contingencies, Regulatory Contingencies, of the Notes to Financial Statements, for a discussion of amounts subject to regulatory risk.

Credit Risk

The Utilities monitor and manage credit risk with their trading counterparties. Credit risk is defined as the possibility that a counterparty to one or more contracts will be unable or unwilling to fulfill its financial or physical obligations to the Utilities because of the counterparty’s financial condition. The Utilities’ credit risk associated with trading counterparties was approximately $90.4 million as of December 31, 2005, which increased significantly from December 31, 2004 due to an increase in trading transactions to meet the demand of the winter months, a general increase in gas prices and gas hedging options which were not present in 2004. In the event that the trading counterparties are unable to deliver under their contracts, it may be necessary for the Utilities to purchase alternative energy at a higher market price.


ITEM 8.		FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA


	Page
Reports of Independent Registered Public Accounting Firm		99

Financial Statements:

Sierra Pacific Resources:
Consolidated Balance Sheets as of December 31, 2005 and 2004		102
Consolidated Statements of Operations for the Years Ended December 31, 2005, 2004 and 2003		104
Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2005, 2004 and 2003		105
Consolidated Statements of Common Shareholders’ Equity for the Years Ended December 31, 2005, 2004 and 2003		106
Consolidated Statements of Cash Flows for the Years Ended December 31, 2005, 2004 and 2003		107
Consolidated Statements of Capitalization as of December 31, 2005 and 2004		108

Nevada Power Company:
Consolidated Balance Sheets as of December 31, 2005 and 2004		110
Consolidated Statements of Operations for the Years Ended December 31, 2005, 2004 and 2003		111
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2005, 2004 and 2003		112
Consolidated Statements of Common Shareholder’s Equity for the Years Ended December 31, 2005, 2004 and 2003		113
Consolidated Statements of Cash Flows for the Years Ended December 31, 2005, 2004 and 2003		114
Consolidated Statements of Capitalization as of December 31, 2005 and 2004		115

Sierra Pacific Power Company:
Consolidated Balance Sheets as of December 31, 2005 and 2004		116
Consolidated Statements of Operations for the Years Ended December 31, 2005, 2004 and 2003		117
Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2005, 2004 and 2003		118
Consolidated Statements of Common Shareholder’s Equity for the Years Ended December 31, 2005, 2004 and 2003		119
Consolidated Statements of Cash Flows for the Years Ended December 31, 2005, 2004 and 2003		120
Consolidated Statements of Capitalization as of December 31, 2005 and 2004		121

Notes to Financial Statements for Sierra Pacific Resources, Nevada Power Company and Sierra Pacific Power Company		122

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of
Sierra Pacific Resources
Reno, Nevada

We have audited the accompanying consolidated balance sheets and statements of capitalization of Sierra Pacific Resources and subsidiaries as of December 31, 2005 and 2004, and the related consolidated statements of operations, comprehensive income (loss), common shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2005. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Sierra Pacific Resources and subsidiaries as of December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company’s internal control over financial reporting as of December 31, 2005, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 3, 2006 expressed an unqualified opinion on management’s assessment of the effectiveness of the Company’s internal control over financial reporting and an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

DELOITTE & TOUCHE LLP

Reno, Nevada
March 3, 2006

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of
Nevada Power Company
Reno, Nevada

We have audited the accompanying consolidated balance sheets and statements of capitalization of Nevada Power Company and subsidiaries as of December 31, 2005 and 2004, and the related consolidated statements of operations, comprehensive income (loss), common shareholder’s equity, and cash flows for each of the three years in the period ended December 31, 2005. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Nevada Power Company and subsidiaries as of December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

DELOITTE & TOUCHE LLP

Reno, Nevada

March 3, 2006

100

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of
Sierra Pacific Power Company
Reno, Nevada

We have audited the accompanying consolidated balance sheets and statements of capitalization of Sierra Pacific Power Company and subsidiaries as of December 31, 2005 and 2004, and the related consolidated statements of operations, comprehensive income (loss), common shareholder’s equity, and cash flows for each of the three years in the period ended December 31, 2005. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Sierra Pacific Power Company and subsidiaries as of December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

DELOITTE & TOUCHE LLP

Reno, Nevada

March 3, 2006

101

SIERRA PACIFIC RESOURCES

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)


	December 31,
	2005		2004
ASSETS
Utility Plant at Original Cost:
Plant in service	$	6,801,916	$	6,604,449
Less accumulated provision for depreciation		2,169,316		2,083,434

		4,632,600		4,521,015
Construction work-in-progress		765,005		405,911

		5,397,605		4,926,926

Investments and other property, net		62,771		64,596


Current Assets:
Cash and cash equivalents		172,682		266,328
Restricted cash and investments (Note 1)		67,245		88,452
Accounts receivable less allowance for uncollectible accounts:
2005-$36,021; 2004-$36,197		413,171		320,676
Deferred energy costs — electric (Note 1)		253,697		148,008
Deferred energy costs — gas (Note 1)		5,825		3,106
Materials, supplies and fuel, at average cost		88,445		76,193
Risk management assets (Note 10)		50,226		14,585
Deposits and prepayments for energy		45,054		54,767
Other		26,544		37,494

		1,122,889		1,009,609

Deferred Charges and Other Assets:
Goodwill (Note 19)		22,877		22,877
Deferred energy costs — electric (Note 1)		255,312		526,159
Deferred energy costs — gas (Note 1)		845		2,491
Regulatory tax asset		249,261		279,766
Other regulatory assets (Note 1)		568,145		487,762
Risk management regulatory assets — net (Note 10)		—		6,673
Unamortized debt issuance costs		63,395		67,204
Other		107,330		114,297

		1,267,165		1,507,229

Assets of Discontinued Operations (Note 18)		20,116		20,107

TOTAL ASSETS	$	7,870,546	$	7,528,467

The accompanying notes are an integral part of the financial statements

(Continued)

102

SIERRA PACIFIC RESOURCES
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)


	December 31,
	2005		2004
CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholders’ equity	$	2,060,154	$	1,498,616
Preferred stock		50,000		50,000
Long-term debt		3,817,122		4,081,281

		5,927,276		5,629,897

Current Liabilities:
Current maturities of long-term debt		58,909		8,491
Accounts payable		252,900		179,559
Accrued interest		58,585		69,246
Dividends declared		1,043		1,046
Accrued salaries and benefits		32,186		28,547
Current income taxes payable		3,159		—
Deferred income taxes		129,041		54,501
Risk management liabilities (Note 10)		16,580		9,902
Accrued taxes		6,540		5,470
Contract termination liabilities (Note 14)		129,000		303,460
Other current liabilities		56,724		38,702

		744,667		698,924

Commitments and Contingencies (Note 14)

Deferred Credits and Other Liabilities:
Deferred income taxes		451,924		512,760
Deferred investment tax credit		38,625		42,064
Regulatory tax liability		38,224		40,575
Customer advances for construction		170,061		142,703
Accrued retirement benefits		77,245		67,907
Risk management regulatory liability — net (Note 10)		15,605		—
Contract termination liabilities (Note 14)		—		36,753
Regulatory liabilities (Note 1)		284,438		257,495
Other		112,281		89,189

		1,188,403		1,189,446

Liabilities of Discontinued Operations (Note18)		10,200		10,200

TOTAL CAPITALIZATION AND LIABILITIES	$	7,870,546	$	7,528,467

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

(Concluded)

103

SIERRA PACIFIC RESOURCES

CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in Thousands, Except Per Share Amounts)


	Year Ended December 31,
	2005			2004			2003
OPERATING REVENUES:
Electric	$	2,850,694		$	2,666,000		$	2,624,426
Gas		178,270			153,752			161,586
Other		1,255			4,087			1,531

		3,030,219			2,823,839			2,787,543

OPERATING EXPENSES:
Operation:
Purchased power		1,315,986			1,069,302			1,145,219
Fuel for power generation		510,736			459,478			480,537
Gas purchased for resale		140,850			121,526			111,675
Deferred energy costs disallowed		—			1,586			90,964
Deferral of energy costs — electric — net		(37,558	)		143,033			97,893
Deferral of energy costs — gas — net		(749	)		(4,136	)		16,155
Impairment of goodwill		—			11,695			—
Other		363,621			328,685			324,608
Maintenance		78,730			78,907			69,636
Depreciation and amortization		214,662			205,647			191,259
Taxes:
Income taxes (benefits)		39,240			24,443			(57,008	)
Other than income		45,920			44,888			45,141

		2,671,438			2,485,054			2,516,079

OPERATING INCOME		358,781			338,785			271,464

OTHER INCOME (EXPENSE):
Allowance for other funds used during construction		20,322			5,948			5,765
Interest accrued on deferred energy		27,442			25,332			28,054
Early debt conversion fees		(54,000	)		—			—
Disallowed merger costs		—			(5,890	)		—
Disallowed plant costs		—			(47,092	)		—
Other income		41,200			34,937			29,948
Other expense		(18,645	)		(13,770	)		(14,243	)
Income (taxes) / benefits		(3,933	)		3,812			(12,801	)
Unrealized gain/(loss) on derivative instrument		—			—			(46,065	)

		12,386			3,277			(9,342	)

Total Income Before Interest Charges		371,167			342,062			262,122

INTEREST CHARGES:
Long-term debt		302,668			312,399			293,482
Interest for Energy Suppliers (Note 14)		(17,221	)		(35,170	)		48,332
Other		24,171			37,785			30,444
Allowance for borrowed funds used during construction		(24,691	)		(8,587	)		(5,976	)

		284,927			306,427			366,282


INCOME (LOSS) FROM CONTINUING OPERATIONS		86,240			35,635			(104,160	)

DISCONTINUED OPERATIONS:

Loss from discontinued operations (net of income taxes) of $(56),		(103	)		(3,164	)		(32,469	)
$(1,704) and $(17,036) respectively)

NET INCOME (LOSS)		86,137			32,471			(136,629	)
Preferred stock dividend requirements of subsidiary		3,900			3,900			3,900

EARNINGS (DEFICIT) APPLICABLE TO COMMON STOCK	$	82,237		$	28,571		$	(140,529	)


Amount per share basic and diluted — (Note 17)
Income / (Loss) from continuing operations — basic	$	0.46		$	0.19		$	(0.90	)
Earnings / (Deficit) applicable to common stock — basic	$	0.44		$	0.16		$	(1.21	)
Income / (Loss) from continuing operations — diluted	$	0.46		$	0.19		$	(0.90	)
Earnings / (Deficit) applicable to common stock — diluted	$	0.44		$	0.16		$	(1.21	)

Weighted Average Shares of Common Stock Outstanding — basic		185,548,314			183,080,475			115,774,810

Weighted Average Shares of Common Stock Outstanding — diluted		185,932,504			183,400,303			115,774,810

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

104

SIERRA PACIFIC RESOURCES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Dollars in Thousands)


	Year ended December 31,
	2005			2004		2003
NET INCOME (LOSS)	$	86,137		$	32,471	$	(136,629	)

OTHER COMPREHENSIVE INCOME (LOSS)
Adoption of SFAS No. 133- Accounting for Derivative Instruments and Hedging Activities

Change in market value of risk management assets and liabilities as of December 31 (Net of taxes of $1,155, ($950), and ($884) in 2005, 2004 and 2003, respectively)		(2,146	)		1,763		1,642

Minimum pension liability adjustment (Net of taxes of ($0), ($15,486) and ($8,350) in 2005, 2004 and 2003, respectively)		(4,311	)		29,404		15,508


OTHER COMPREHENSIVE INCOME (LOSS)		(6,457	)		31,167		17,150

COMPREHENSIVE INCOME (LOSS)	$	79,680		$	63,638	$	(119,479	)

The accompanying notes are an integral part of the financial statements

105

SIERRA PACIFIC RESOURCES

CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS’ EQUITY
(Dollars in Thousands)


	Year ended December 31,
	2005			2004			2003
Common Stock:
Balance at Beginning of Year	$	117,469		$	117,236		$	102,177
Stock issuance/exchange, CSIP, DRP, ESPP and other		83,323			233			15,059

Balance at end of year		200,792			117,469			117,236


Other Paid-In Capital:
Balance at Beginning of Year		1,818,453			1,815,202			1,599,024
Premium on issuance/exchange of common stock		405,767			563			99,192
Common Stock issuance costs		(6,486	)		—			(1,184	)
Revaluation of investment		119			1,690			—
Value of derivative transferred to equity		—			—			118,143
CSIP, DRP, ESPP and other		3,043			998			27

Balance at End of Year		2,220,896			1,818,453			1,815,202


Retained Earnings (Deficit):
Balance at Beginning of Year		(438,112	)		(466,683	)		(326,524	)
Income (loss) from continuing operations before preferred Dividends		86,240			35,635			(104,160	)
Loss from discontinued operations, net of taxes		(103	)		(3,164	)		(32,469	)
Preferred stock dividends declared		(3,900	)		(3,900	)		(3,900	)
Common stock dividends declared, net of adjustments		(8	)		—			370

Balance at End of Year		(355,883	)		(438,112	)		(466,683	)


Accumulated Other Comprehensive Income (Loss):

Balance at Beginning of Year		806			(30,361	)		(47,511	)
Adoption of SFAS No. 133 – Accounting for Derivative Instruments and Hedging Activities
Change in market value of risk management assets and liabilities as of December 31 (Net of taxes of $1,155, ($950) and ($884) in 2005, 2004 and 2003, respectively)		(2,146	)		1,763			1,642
Minimum pension liability adjustment (Net of taxes of ($15,486) and ($8,350) in 2004, and 2003, respectively)		(4,311	)		29,404			15,508

Balance at End of Year		(5,651	)		806			(30,361	)


Total Common Shareholders’ Equity at End of Year	$	2,060,154		$	1,498,616		$	1,435,394

The accompanying notes are an integral part of the financial statements

106

SIERRA PACIFIC RESOURCES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)


	For the Year Ended December 31,
	2005			2004			2003
				(as Revised - Note 1)			(as Revised - Note 1)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income (Loss)	$	86,137		$	32,471		$	(136,629	)
Non-cash items included in net income (loss):
Depreciation and amortization		214,662			205,647			191,259
Deferred taxes and deferred investment tax credit		41,609			33,690			(50,724	)
AFUDC and capitalized interest		(45,013	)		(14,536	)		(11,741	)
Amortization of deferred energy costs — electric		188,221			265,418			250,134
Amortization of deferred energy costs — gas		1,446			3,242			13,095
Deferred energy costs disallowed		—			1,586			90,964
Goodwill impairment		—			11,695			—
Early retirement and severance amortization		—			—			2,786
Unrealized loss on derivative instrument		—			—			46,065
Impairment of assets of subsidiary		—			—			32,911
Loss on disposal of discontinued operations		—			2,346			9,555
Plant costs disallowed		—			47,092			—
Other non-cash		(4,119	)		(27,353	)		(7,131	)
Changes in certain assets and liabilities:
Accounts receivable		(92,494	)		(19,354	)		57,271
Deferral of energy costs — electric		(241,103	)		(152,140	)		(161,564	)
Deferral of energy costs — gas		(2,519	)		(7,480	)		2,592
Deferral of energy costs — terminated suppliers		218,040			4,551			(18,262	)
Materials, supplies and fuel		(12,251	)		3,331			6,277
Other current assets		20,663			4,601			(49,142	)
Accounts payable		55,985			13,623			(66,097	)
Escrow payment for terminating suppliers		—			(61,129	)		—
Other current liabilities		(162,416	)		20,609			358,213
Discontinued operations — operating activities		(9	)		(2,548	)		992
Other assets		(38,919	)		21,292			47,348
Other liabilities		6,625			(49,113	)		(334,889	)

Net Cash from Operating Activities		234,545			337,541			273,283


CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to utility plant		(686,394	)		(614,411	)		(379,319	)
AFUDC and other charges to utility plant		45,013			14,536			11,741
Customer advances for construction		27,358			16,197			10,475
Contributions in aid of construction		23,351			26,457			23,605

Net cash used for utility plant		(590,672	)		(557,221	)		(333,498	)
Discontinued operations — investing activities		—			—			(1,070	)
Investments in subsidiaries and other property — net		10,200			16,574			(8,439	)

Net Cash used by Investing Activities		(580,472	)		(540,647	)		(343,007	)


CASH FLOWS FROM FINANCING ACTIVITIES:
Increase (Decrease) in short-term borrowings		—			(25,000	)		25,000
Change in restricted cash and investments		23,711			27,382			(41,000	)
Proceeds from issuance of long-term debt		370,211			965,000			650,000
Retirement of long-term debt (Note 7)		(373,938	)		(673,872	)		(558,760	)
Discontinued operations — debt redemption		—			(5,500	)		(11,649	)
Sale of common stock, net of issuance cost (Note 7)		236,208			3,488			(756	)
Dividends paid		(3,911	)		(3,821	)		(3,524	)

Net Cash from Financing Activities		252,281			287,677			59,311


Net Increase (Decrease) in Cash and Cash Equivalents		(93,646	)		84,571			(10,413	)
Beginning Balance in Cash and Cash Equivalents		266,328			181,757			192,170

Ending Balance in Cash and Cash Equivalents	$	172,682		$	266,328		$	181,757


Supplemental Disclosures of Cash Flow Information:
Cash paid (received) during period for:
Interest	$	330,889		$	339,718		$	307,870
Income taxes	$	—		$	—		$	(1,521	)

Noncash Activities:
Exchange of Floating Rate Notes for SPR Common Stock	$	—		$	—		$	8,750
Exchange of Premium Income Equity Securities for SPR Common Stock		—		$	—		$	104,782
Exchange of Convertible Debt for SPR Common Stock	$	248,168		$	—		$	—

The accompanying notes are an integral part of the financial statements

107

SIERRA PACIFIC RESOURCES

CONSOLIDATED STATEMENTS OF CAPITALIZATION

(Dollars in Thousands)


	December 31,
	2005			2004
Common Shareholder’s Equity:
Common stock, $1.00 par value, authorized 250 million; issued and outstanding 2005: 200,792,000 shares; issued and outstanding 2004:117,469,000 shares	$	200,792		$	117,469
Other paid-in capital		2,220,896			1,818,453
Retained Deficit		(355,883	)		(438,112	)
Accumulated other comprehensive Income (Loss)		(5,651	)		806

Total Common Shareholder’s Equity		2,060,154			1,498,616

Preferred Stock of Subsidiaries:
Not subject to mandatory redemption; 2,000,000 shares outstanding; $25 stated value
SPPC Class A Series 1; $1.95 dividend		50,000			50,000

Long-Term Debt:
Secured Debt
First Mortgage Bonds
8.50% NPC Series Z due 2023		35,000			35,000
Debt Secured by First Mortgage Bonds
Revenue Bonds
Nevada Power Company
6.60% NPC Series 1992B due 2019		39,500			39,500
6.70% NPC Series 1992A due 2022		105,000			105,000
7.20% NPC Series 1992C due 2022		78,000			78,000
Sierra Pacific Power Company
6.35% SPPC Series 1992B due 2012		1,000			1,000
6.55% SPPC Series 1987 due 2013		39,500			39,500
6.30% SPPC Series 1987 due 2014		45,000			45,000
6.65% SPPC Series 1987 due 2017		92,500			92,500
6.55% SPPC Series 1990 due 2020		20,000			20,000
6.30% SPPC Series 1992A due 2022		10,250			10,250
5.90% SPPC Series 1993A due 2023		9,800			9,800
5.90% SPPC Series 1993B due 2023		30,000			30,000
6.70% SPPC Series 1992 due 2032		21,200			21,200
Medium Term Notes
Sierra Pacific Power Company
6.62% to 6.83% SPPC Series C due 2006		50,000			50,000
6.95% to 8.61% SPPC Series A due 2022		110,000			110,000
7.10% to 7.14% SPPC Series B due 2023		58,000			58,000

Subtotal		744,750			744,750

General and Refunding Mortgage Securities
Nevada Power Company
10.88% NPC Series E due 2009		162,500			250,000
8.25% NPC Series A due 2011		350,000			350,000
6.50% NPC Series I due 2012		130,000			130,000
9.00% NPC Series G due 2013		227,500			350,000
5.875% NPC Series L due 2015		250,000			250,000
Sierra Pacific Power Company
8.00% SPPC Series A due 2008		320,000			320,000
6.25% SPPC Series H due 2012		100,000			100,000

Subtotal		1,540,000			1,750,000

Debt Secured by General and Refunding Mortgage Securities
NPC Revolving Credit Facility		150,000
5.00% SPPC Series 2001 due 2036		80,000			80,000

Subtotal		230,000			80,000

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

(Continued)

108

SIERRA PACIFIC RESOURCES
CONSOLIDATED STATEMENTS OF CAPITALIZATION
(Dollars in Thousands)


	December 31,
	2005			2004
Unsecured Debt
Revenue Bonds
Nevada Power Company
5.30% NPC Series 1995D due 2011		14,000			14,000
5.35% NPC Series 1995E due 2022		13,000			13,000
5.45% NPC Series 1995D due 2023		6,300			6,300
5.50% NPC Series 1995C due 2030		44,000			44,000
5.60% NPC Series 1995A due 2030		76,750			76,750
5.90% NPC Series 1995B due 2030		85,000			85,000
5.80% NPC Series 1997B due 2032		20,000			20,000
5.90% NPC Series 1997A due 2032		52,285			52,285
6.38% NPC Series 1996 due 2036		20,000			20,000

Subtotal		331,335			331,335

Variable Rate Notes
NPC PCRB Series 2000B due 2009		15,000			15,000
NPC IDRB Series 2000A due 2020		100,000			100,000

Subtotal		115,000			115,000

Other Notes
Sierra Pacific Resources
7.93% SPR Senior Notes due 2007 (PIES)		—			240,218
7.25% SPR Convertible Notes due 2010		—			242,078
7.803% SPR Senior Notes due 2012		99,142			—
8.625% SPR Notes due 2014		335,000			335,000
6.75% SPR Senior Notes due 2017		225,000			—

Subtotal, excluding current portion		659,142			817,296

Unamortized bond premium and discount, net		(3,495	)		(16,604	)

Nevada Power Company
8.2% Junior Subordinated Debentures of NPC, due 2037		122,548			122,548
7.75% Junior Subordinated Debentures of NPC, due 2038		72,165			72,165

Subtotal		194,713			194,713

Obligations under capital leases		56,921			63,021
Current maturities and sinking fund requirements		(58,909	)		(8,491	)
Other, excluding current portion		7,665			10,261

Total Long-Term Debt		3,817,122			4,081,281

TOTAL CAPITALIZATION	$	5,927,276		$	5,629,897

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

(Concluded)

109

NEVADA POWER COMPANY

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)


	December 31,
	2005		2004
ASSETS
Utility Plant at Original Cost:
Plant in service	$	4,106,489	$	4,015,125
Less accumulated provision for depreciation		1,128,209		1,112,335

		2,978,280		2,902,790
Construction work-in-progress		698,206		355,431

		3,676,486		3,258,221


Investments and other property, net		29,249		30,809


Current Assets:
Cash and cash equivalents		98,681		243,323
Restricted cash (Note 1)		52,374		50,311
Accounts receivable less allowance for uncollectible accounts:
2005-$30,386; 2004-$30,900		232,086		178,077
Accounts receivable, affiliated companies		3,738		—
Deferred energy costs — electric (Note 1)		186,355		126,074
Materials, supplies and fuel, at average cost		46,835		44,858
Risk management assets (Note 10)		22,404		5,092
Deposits and prepayments for energy		16,303		23,091
Other		16,075		23,721

		674,851		694,547

Deferred Charges and Other Assets:
Deferred energy costs — electric (Note 1)		214,587		375,120
Regulatory tax asset		155,304		167,221
Other regulatory assets (Note 1)		362,567		277,450
Risk management regulatory assets — net (Note 10)		—		3,555
Unamortized debt issuance costs		37,157		43,802
Other		23,720		32,815

		793,335		899,963

TOTAL ASSETS	$	5,173,921	$	4,883,540

CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholder’s equity	$	1,762,089	$	1,436,788
Long-term debt		2,214,063		2,275,690

		3,976,152		3,712,478

Current Liabilities:
Current maturities of long-term debt		6,509		6,091
Accounts payable		164,169		114,242
Accounts payable, affiliated companies		—		3,920
Accrued interest		33,031		40,677
Dividends declared		397		399
Accrued salaries and benefits		15,537		12,780
Current income taxes payable		3,159		—
Deferred income taxes		57,392		36,981
Risk management liabilities (Note 10)		10,125		3,555
Accrued taxes		2,817		2,441
Contract termination liabilities (Note 14)		89,784		211,620
Other current liabilities		46,425		27,651

		429,345		460,357

Commitments and Contingencies (Note 14)
Deferred Credits and Other Liabilities:
Deferred income taxes		362,973		308,302
Deferred investment tax credit		16,832		18,642
Regulatory tax liability		15,068		16,506
Customer advances for construction		98,056		79,243
Accrued retirement benefits		24,614		21,025
Risk management regulatory liability — net (Note 10)		590		—
Contract termination liabilities (Note 14)		—		34,847
Regulatory liabilities (Note 1)		173,527		171,330
Other		76,764		60,810

		768,424		710,705


TOTAL CAPITALIZATION AND LIABILITIES	$	5,173,921	$	4,883,540

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

110

NEVADA POWER COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS

(Dollars in Thousands)


	Year Ended December 31,
	2005			2004			2003
OPERATING REVENUES:
Electric	$	1,883,267		$	1,784,092		$	1,756,146

OPERATING EXPENSES:
Operation:
Purchased power		963,888			764,347			781,014
Fuel for power generation		277,083			235,404			282,968
Deferred energy costs disallowed		—			1,586			45,964
Deferral of energy costs-net		(45,668	)		135,973			95,911
Other		211,039			183,736			195,483
Maintenance		52,040			57,030			48,226
Depreciation and amortization		124,098			118,841			109,655
Taxes:
Income taxes (benefits)		46,425			45,135			(12,734	)
Other than income		25,535			25,550			25,926

		1,654,440			1,567,602			1,572,413

OPERATING INCOME		228,827			216,490			183,733

OTHER INCOME (EXPENSE):
Allowance for other funds used during construction		18,683			4,230			2,845
Interest accrued on deferred energy		20,350			20,199			22,891
Disallowed merger costs		—			(3,961	)		—
Other income		25,626			22,844			18,344
Other expense		(8,525	)		(6,665	)		(5,944	)
Income taxes		(17,570	)		(11,437	)		(12,120	)

		38,564			25,210			26,016

Total Income Before Interest Charges		267,391			241,700			209,749

INTEREST CHARGES:
Long-term debt		159,106			152,764			142,143
Interest for Energy Suppliers (Note 14)		(14,825	)		(24,171	)		33,879
Other		13,563			14,533			17,150
Allowance for borrowed funds used during construction		(23,187	)		(5,738	)		(2,700	)

		134,657			137,388			190,472


NET INCOME	$	132,734		$	104,312		$	19,277

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

111

NEVADA POWER COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in Thousands)


	Year ended December 31,
	2005			2004		2003
NET INCOME	$	132,734		$	104,312	$	19,277

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX:
Adoption of SFAS No. 133- Accounting for Derivative
Instruments and Hedging Activities:
Change in market value of risk management assets and liabilities as of December 31 (Net of taxes of $785, ($688) and ($31) in 2005, 2004 and 2003, respectively)		(1,460	)		1,277		59
Minimum pension liability adjustment (Net of taxes of ($0), ($1,205) and ($3,326) in 2005, 2004 and 2003, respectively)		(2,769	)		2,239		6,178

OTHER COMPREHENSIVE INCOME (LOSS)		(4,229	)		3,516		6,237

COMPREHENSIVE INCOME	$	128,505		$	107,828	$	25,514

The accompanying notes are an integral part of the financial statements

112

NEVADA POWER COMPANY

CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER’S EQUITY

(Dollars in Thousands)


	December 31,
	2005			2004			2003
Common Stock:
Balance at Beginning of Year and End of Year	$	1		$	1		$	1

Other Paid-In Capital:

Balance at Beginning of Year		1,576,794			1,377,106			1,377,106
Transfer of Goodwill		—			197,998
Revaluation of investment		119			1,690			—
Capital infusion from parent		231,935			—			—

Balance at End of Year		1,808,848			1,576,794			1,377,106


Retained Earnings (Deficit):

Balance at Beginning of Year		(140,898	)		(199,837	)		(219,114	)
Income for the year		132,734			104,312			19,277
Common stock dividends declared		(35,258	)		(45,373	)		—

Balance at End of Year		(43,422	)		(140,898	)		(199,837	)

Accumulated Other Comprehensive Income (Loss):
Balance at Beginning of Year		891			(2,625	)		(8,862	)
Adoption of SFAS No. 133 - Accounting for Derivative Instruments and Hedging Activities
Change in market value of risk management assets and liabilities as of December 31 (Net of taxes of $785, ($688) and ($31) in 2005, 2004 and 2003, respectively)		(1,460	)		1,277			59
Minimum pension liability adjustment (Net of taxes of ($1,205) and ($3,326) in 2004 and 2003, respectively)		(2,769	)		2,239			6,178


Balance at End of Year		(3,338	)		891			(2,625	)


Total Common Shareholder’s Equity at End of Year	$	1,762,089		$	1,436,788		$	1,174,645

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

113

NEVADA POWER COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)


	For the Year Ended December 31,
	2005			2004			2003
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	132,734		$	104,312		$	19,277
Non-cash items included in net income:
Depreciation and amortization		124,098			118,841			109,655
Deferred taxes and deferred investment tax credit		86,910			57,066			2,710
AFUDC		(41,870	)		(9,969	)		(5,545	)
Amortization of deferred energy costs		131,471			228,765			204,610
Deferred energy costs disallowed		—			1,586			45,964
Other non-cash		(7,433	)		(44,149	)		(8,962	)
Changes in certain assets and liabilities:
Accounts receivable		(57,746	)		(7,247	)		31,761
Deferral of energy costs		(186,338	)		(117,543	)		(115,459	)
Deferral of energy costs — terminated suppliers		155,119			4,551			(16,132	)
Materials, supplies and fuel		(1,977	)		(3,782	)		2,998
Other current assets		14,434			14,522			(29,732	)
Accounts payable		30,855			10,350			(39,477	)
Escrow payment for terminating suppliers		—			(50,311	)		—
Other current liabilities		(107,575	)		10,504			253,009
Other assets		(23,708	)		12,333			21,303
Other liabilities		(24,765	)		12,811			(208,051	)

Net Cash from Operating Activities		224,209			342,640			267,929


CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to utility plant		(546,748	)		(482,484	)		(229,368	)
AFUDC and other charges to utility plant		41,870			9,969			5,545
Customer advances for construction		18,813			8,067			4,742
Contributions in aid of construction		8,544			10,703			12,168

Net cash used for utility plant		(477,521	)		(453,745	)		(206,913	)
Investments in subsidiaries and other property — net		1,875			5,404			(15,512	)

Net Cash used by Investing Activities		(475,646	)		(448,341	)		(222,425	)


CASH FLOWS FROM FINANCING ACTIVITIES:
Change in restricted cash and investments		—			2,600			1,250
Proceeds from issuance of long-term debt		150,000			530,000			350,000
Retirement of long-term debt		(238,486	)		(283,498	)		(346,867	)
Additional investment by parent company		230,541			—			—
Dividends paid		(35,260	)		(44,975	)		—

Net Cash from Financing Activities		106,795			204,127			4,383


Net (Decrease) Increase in Cash and Cash Equivalents		(144,642	)		98,426			49,887
Beginning Balance in Cash and Cash Equivalents		243,323			144,897			95,009

Ending Balance in Cash and Cash Equivalents	$	98,681		$	243,323		$	144,896


Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	173,775		$	161,126		$	149,686
Income taxes	$	—		$	—		$	—

Noncash Activities:
Transfer of Regulatory Asset	$	—		$	197,998		$	—

The accompanying notes are an integral part of the financial statements

114

NEVADA POWER COMPANY

CONSOLIDATED STATEMENTS OF CAPITALIZATION

(Dollars in Thousands)


	December 31,
	2005			2004
Common Shareholder’s Equity:
Common stock, $1.00 par value, 1,000 shares authorized, issued and Outstanding	$	1		$	1
Other paid-in capital		1,808,848			1,576,794
Retained Deficit		(43,422	)		(140,898	)
Accumulated other comprehensive Income (Loss)		(3,338	)		891

Total Common Shareholder’s Equity		1,762,089			1,436,788

Long-Term Debt:
Secured Debt
First Mortgage Bonds
8.50% Series Z due 2023		35,000			35,000
Debt Secured by First Mortgage Bonds
Revenue Bonds
6.60% Series 1992B due 2019		39,500			39,500
6.70% Series 1992A due 2022		105,000			105,000
7.20% Series 1992C due 2022		78,000			78,000

Subtotal		257,500			257,500

General and Refunding Mortgage Securities
10.88% Series E due 2009		162,500			250,000
8.25% Series A due 2011		350,000			350,000
6.50% Series I due 2012		130,000			130,000
9.00% Series G due 2013		227,500			350,000
5.875% Series L due 2015		250,000			250,000

Subtotal		1,120,000			1,330,000

Debt Secured by General and Refunding Mortgage Securities
Revolving Credit Facility		150,000			—

Unsecured Debt
Revenue Bonds
5.30% Series 1995D due 2011		14,000			14,000
5.35% Series 1995E due 2022		13,000			13,000
5.45% Series 1995D due 2023		6,300			6,300
5.50% Series 1995C due 2030		44,000			44,000
5.60% Series 1995A due 2030		76,750			76,750
5.90% Series 1995B due 2030		85,000			85,000
5.80% Series 1997B due 2032		20,000			20,000
5.90% Series 1997A due 2032		52,285			52,285
6.38% Series 1996 due 2036		20,000			20,000

Subtotal		331,335			331,335

Variable Rate Notes
PCRB Series 2000B due 2009		15,000			15,000
IDRB Series 2000A due 2020		100,000			100,000

Subtotal		115,000			115,000

Unamortized bond premium and discount, net		(4,942	)		(9,849	)

8.2% Junior Subordinated Debentures due 2037		122,548			122,548
7.75% Junior Subordinated Debentures due 2038		72,165			72,165

Subtotal		194,713			194,713

Obligations under capital leases		56,921			63,021
Current maturities and sinking fund requirements		(6,509	)		(6,091	)
Other, excluding current portion		45			61

Total Long-Term Debt		2,214,063			2,275,690

TOTAL CAPITALIZATION	$	3,976,152		$	3,712,478

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

115

SIERRA PACIFIC POWER COMPANY

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)


	December 31,
	2005		2004
ASSETS
Utility Plant at Original Cost:
Plant in service	$	2,695,427	$	2,589,324
Less accumulated provision for depreciation		1,041,107		971,099

		1,654,320		1,618,225
Construction work-in-progress		66,799		50,480

		1,721,119		1,668,705


Investments and other property, net		842		999


Current Assets:
Cash and cash equivalents		38,153		19,319
Restricted cash (Note 1)		14,871		16,464
Accounts receivable less allowance for uncollectible accounts:
2005-$5,634, 2004-$5,296		180,973		142,359
Accounts receivable, affiliated companies		40,278		67,261
Deferred energy costs — electric (Note 1)		67,342		21,934
Deferred energy costs — gas (Note 1)		5,825		3,106
Materials, supplies and fuel, at average cost		41,608		31,335
Risk management assets (Note 10)		27,822		9,493
Deposits and prepayments for energy		28,751		31,676
Other		9,547		9,728

		455,170		352,675

Deferred Charges and Other Assets:
Deferred energy costs — electric (Note 1)		40,725		151,039
Deferred energy costs — gas (Note 1)		845		2,491
Regulatory tax asset		93,957		112,545
Other regulatory assets (Note 1)		205,578		210,312
Risk management regulatory assets — net (Note 10)		—		3,118
Unamortized debt issuance costs		12,693		13,564
Other		15,372		8,872

		369,170		501,941

TOTAL ASSETS	$	2,546,301	$	2,524,320

CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholder’s equity	$	727,777	$	705,395
Preferred stock		50,000		50,000
Long-term debt		941,804		994,309

		1,719,581		1,749,704

Current Liabilities:
Current maturities of long-term debt		52,400		2,400
Accounts payable		56,661		42,884
Accrued interest		10,993		9,604
Dividends declared		968		968
Accrued salaries and benefits		14,032		13,846
Current income taxes payable		49,673		10,305
Deferred income taxes		21,832		6,833
Risk management liabilities (Note 10)		6,455		6,347
Accrued taxes		3,541		2,878
Contract termination liabilities (Note 14)		39,216		91,840
Other current liabilities		10,299		8,516

		266,070		196,421

Commitments and Contingencies (Note 14)
Deferred Credits and Other Liabilities:
Deferred income taxes		244,244		314,448
Deferred investment tax credit		21,793		23,422
Regulatory tax liability		23,156		24,069
Customer advances for construction		72,005		63,460
Accrued retirement benefits		41,507		41,558
Risk management regulatory liability — net (Note 10)		15,015		—
Contract termination liabilities (Note 14)		—		1,906
Regulatory liabilities (Note 1)		110,911		86,165
Other		32,019		23,167

		560,650		578,195

TOTAL CAPITALIZATION AND LIABILITIES	$	2,546,301	$	2,524,320

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

116

SIERRA PACIFIC POWER COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS

(Dollars in Thousands)


	Year Ended December 31,
	2005			2004			2003
OPERATING REVENUES:
Electric	$	967,427		$	881,908		$	868,280
Gas		178,270			153,752			161,586

		1,145,697			1,035,660			1,029,866

OPERATING EXPENSES:
Operation:
Purchased power		352,098			304,955			364,205
Fuel for power generation		233,653			224,074			197,569
Gas purchased for resale		140,850			121,526			111,675
Deferred energy costs disallowed		—			—			45,000
Deferral of energy costs — electric — net		8,110			7,060			1,982
Deferral of energy costs — gas — net		(749	)		(4,136	)		16,155
Other		131,901			128,091			116,390
Maintenance		26,690			21,877			21,410
Depreciation and amortization		90,569			86,806			81,514
Taxes:
Income taxes (benefits)		26,038			14,978			(13,704	)
Other than income		20,233			19,184			19,104

		1,029,393			924,415			961,300

OPERATING INCOME		116,304			111,245			68,566

OTHER INCOME (EXPENSE):
Allowance for other funds used during construction		1,639			1,718			2,920
Interest accrued on deferred energy		7,092			5,133			5,163
Disallowed merger costs		—			(1,929	)		—
Plant costs disallowed		—			(47,092	)		—
Other income		5,940			3,406			4,403
Other expense		(7,493	)		(5,726	)		(6,767	)
Income (taxes) benefits		(2,341	)		14,653			(1,467	)

		4,837			(29,837	)		4,252

Total Income Before Interest Charges		121,141			81,408			72,818

INTEREST CHARGES:
Long-term debt		69,240			71,312			76,002
Interest for Energy Suppliers (Note 14)		(2,396	)		(10,999	)		14,453
Other		3,727			5,367			8,914
Allowance for borrowed funds used during construction and capitalized interest		(1,504	)		(2,849	)		(3,276	)

		69,067			62,831			96,093


NET INCOME / (LOSS)		52,074			18,577			(23,275	)

Preferred Dividend Requirements		3,900			3,900			3,900

Earnings / (Deficit) applicable to common stock	$	48,174		$	14,677		$	(27,175	)

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

117

SIERRA PACIFIC POWER COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Dollars in Thousands)


	Year ended December 31,
	2005			2004			2003
NET INCOME (LOSS)	$	52,074		$	18,577		$	(23,275	)

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX:
Adoption of SFAS No. 133- Accounting for Derivative
Instruments and Hedging Activities:

Change in market value of risk management assets and liabilities as of December 31 (net of taxes of $370, ($323) and ($15) in 2005, 2004 and 2003, respectively)		(686	)		600			28

Minimum pension liability adjustment (net of taxes of $0, $65 and ($83) in 2005, 2004 and 2003, respectively)		(1,173	)		(123	)		153

OTHER COMPREHENSIVE INCOME (LOSS)		(1,859	)		477			181

COMPREHENSIVE INCOME (LOSS)	$	50,215		$	19,054		$	(23,094	)

The accompanying notes are an integral part of the financial statements

118

SIERRA PACIFIC POWER COMPANY

CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER’S EQUITY

(Dollars in Thousands)


	December 31,
	2005			2004			2003
Common Stock:
Balance at Beginning of Year and End of Year	$	4		$	4		$	4

Other Paid-In Capital:

Balance at Beginning of Year		810,103			713,633			713,633
Transfer of Goodwill (Note 19)		—			96,470			—

Balance at End of Year		810,103			810,103			713,633


Retained Earnings (Deficit):

Balance at Beginning of Year		(104,779	)		(119,456	)		(73,751	)
Income (Loss) from continuing operations before preferred dividends		52,074			18,577			(23,275	)
Preferred stock dividends declared		(3,900	)		(3,900	)		(3,900	)
Common stock dividends declared		(23,933	)		—			(18,530	)

Balance at End of Year		(80,538	)		(104,779	)		(119,456	)


Accumulated Other Comprehensive Income (Loss):

Balance at Beginning of Year		67			(410	)		(591	)
Adoption of SFAS No. 133 — Accounting for Derivative Instruments and Hedging Activities
Change in market value of risk management assets and liabilities as of December 31 (Net of taxes of $370, ($323) and ($15) in 2005, 2004 and 2003, respectively)		(686	)		600			28
Minimum pension liability adjustment (Net of taxes of $65 and $(83) in 2004 and 2003, respectively)		(1,173	)		(123	)		153

Balance at End of Year		(1,792	)		67			(410	)


Total Common Shareholder’s Equity at End of Year	$	727,777		$	705,395		$	593,771

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

119

SIERRA PACIFIC POWER COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)


	For the Year Ended December 31,
	2005			2004			2003
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income (Loss)	$	52,074		$	18,577		$	(23,275	)
Non-cash items included in net income (loss):
Depreciation and amortization		90,569			86,806			81,514
Deferred taxes and deferred investment tax credit		209			11,640			(23,676	)
AFUDC		(3,143	)		(4,567	)		(6,196	)
Amortization of deferred energy costs — electric		56,750			36,653			45,524
Amortization of deferred energy costs — gas		1,446			3,241			13,095
Deferred energy costs disallowed		—			—			45,000
Early retirement and severance amortization		—			—			2,786
Plant costs disallowed		—			47,092			—
Other non-cash		318			474			(5,203	)
Changes in certain assets and liabilities:								—
Accounts receivable		(11,631	)		(19,677	)		23,557
Deferral of energy costs — electric		(54,765	)		(34,598	)		(46,105	)
Deferral of energy costs — gas		(2,519	)		(7,480	)		2,592
Deferral of energy costs — terminated suppliers		62,921			—			(2,131	)
Materials, supplies and fuel		(10,272	)		7,113			3,278
Other current assets		3,106			(10,086	)		(18,363	)
Accounts payable		11,573			2,153			(30,516	)
Escrow payment for terminating supplier		—			(10,818	)
Other current liabilities		(48,603	)		5,567			99,904
Other assets		(15,211	)		8,959			26,055
Other liabilities		27,309			(13,770	)		(112,673	)

Net Cash from Operating Activities		160,131			127,279			75,167


CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to utility plant		(139,646	)		(131,927	)		(149,951	)
AFUDC and other charges to utility plant		3,143			4,567			6,196
Customer advances for construction		8,545			8,130			5,733
Contributions in aid of construction		14,807			15,754			11,437

Net cash used for utility plant		(113,151	)		(103,476	)		(126,585	)
Disposal of subsidiaries and other property — net		157			(82	)		(43	)

Net Cash used by Investing Activities		(112,994	)		(103,558	)		(126,628	)


CASH FLOWS FROM (USED BY) FINANCING ACTIVITIES:
Decrease in short-term borrowings		—			(25,000	)		25,000
Change in restricted cash and investments		2,034			3,130			829
Proceeds from issuance of long-term debt		—			100,000			—
Retirement of long-term debt		(2,504	)		(99,491	)		(19,989	)
Dividends paid		(27,833	)		(3,900	)		(22,430	)

Net Cash used by Financing Activities		(28,303	)		(25,261	)		(16,590	)


Net Increase (Decrease) in Cash and Cash Equivalents		18,834			(1,540	)		(68,051	)
Beginning Balance in Cash and Cash Equivalents		19,319			20,859			88,910

Ending Balance in Cash and Cash Equivalents	$	38,153		$	19,319		$	20,859


Supplemental Disclosures of Cash Flow Information:
Cash paid (received) during period for:
Interest	$	71,496		$	77,529		$	85,088
Income taxes	$	—		$	—		$	(1,521	)

Noncash Activities:
Transfer of Regulatory Asset (Note 19)	$	—		$	96,470		$	—

The accompanying notes are an integral part of the financial statements

120

SIERRA PACIFIC POWER COMPANY

CONSOLIDATED STATEMENTS OF CAPITALIZATION

(Dollars in Thousands)


	December 31,
	2005			2004
Common Shareholder’s Equity:
Common stock, $3.75 par value, 1,000 shares authorized, issued and Outstanding	$	4		$	4
Other paid-in capital		810,103			810,103
Retained Deficit		(80,538	)		(104,779	)
Accumulated other comprehensive Income (Loss)		(1,792	)		67

Total Common Shareholder’s Equity		727,777			705,395

Cumulative Preferred Stock:
Not subject to mandatory redemption; 2,000,000 shares outstanding; $25 stated value		50,000			50,000
SPPC Class A Series 1; $1.95 dividend
Long-Term Debt:
Secured Debt
Debt Secured by First Mortgage Bonds
Revenue Bonds
6.35% Series 1992B due 2012		1,000			1,000
6.55% Series 1987 due 2013		39,500			39,500
6.30% Series 1987 due 2014		45,000			45,000
6.65% Series 1987 due 2017		92,500			92,500
6.55% Series 1990 due 2020		20,000			20,000
6.30% Series 1992A due 2022		10,250			10,250
5.90% Series 1993A due 2023		9,800			9,800
5.90% Series 1993B due 2023		30,000			30,000
6.70% Series 1992 due 2032		21,200			21,200
Medium Term Notes
6.62% to 6.83% Series C due 2006		50,000			50,000
6.95% to 8.61% Series A due 2022		110,000			110,000
7.10% to 7.14% Series B due 2023		58,000			58,000

Subtotal		487,250			487,250

General and Refunding Mortgage Securities
8.00% Series A due 2008		320,000			320,000
6.25% Series H due 2012		100,000			100,000

Subtotal		420,000			420,000

Debt Secured by General and Refunding Mortgage Securities
5.00% Series 2001 due 2036		80,000			80,000

Subtotal		80,000			80,000

Unsecured Debt
Unamortized bond premium and discount, net		(666	)		(741	)
Current maturities and sinking fund requirements		(52,400	)		(2,400	)
Other, excluding current portion		7,620			10,200

Total Long-Term Debt		941,804			994,309

TOTAL CAPITALIZATION	$	1,719,581		$	1,749,704

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

121

NOTES TO FINANCIAL STATEMENTS

NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The significant accounting policies for both utility and non-utility operations are as follows:

Basis of Presentation

The consolidated financial statements include the accounts of Sierra Pacific Resources (SPR) and its wholly-owned subsidiaries, Nevada Power Company (NPC), Sierra Pacific Power Company (SPPC), Tuscarora Gas Pipeline Company (TGPC), Sierra Pacific Communications (SPC), Lands of Sierra, Inc. (LOS), Sierra Energy Company dba e ·three (e ·three), Sierra Pacific Energy Company (SPE), Sierra Water Development Company (SWDC) and Sierra Gas Holding Company (SGHC). SPC and e ·three are discontinued operations and as such are reported separately in the financial statements. NPC and SPPC are referred to together in this report as the Utilities. All significant intercompany balances and intercompany transactions have been eliminated in consolidation.

The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities. These estimates and assumptions also affect the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of certain revenues and expenses during the reporting period. Actual results could differ from these estimates.

NPC is an operating public utility that provides electric service in Clark County in southern Nevada. The assets of NPC represent approximately 66% of the consolidated assets of SPR at December 31, 2005. NPC provides electricity to approximately 774,000 customers in the communities of Las Vegas, North Las Vegas, Henderson, Searchlight, Laughlin and adjoining areas, including Nellis Air Force Base. Service is also provided to the Department of Energy’s Nevada Test Site in Nye County. The consolidated financial statements of SPR include NPC’s wholly-owned subsidiary, Nevada Electric Investment Company (NEICO).

SPPC is an operating public utility that provides electric service in northern Nevada and northeastern California. SPPC also provides natural gas service in the Reno/Sparks area of Nevada. The assets of SPPC represent approximately 32% of the consolidated assets of SPR at December 31, 2005. SPPC provides electricity to approximately 353,000 customers in a 50,000 square mile service area including western, central, and northeastern Nevada, including the cities of Reno, Sparks, Carson City, and Elko, and a portion of eastern California, including the Lake Tahoe area. SPPC also provides natural gas service in Nevada to approximately 140,000 customers in an area of about 600 square miles in the Reno and Sparks areas. The consolidated financial statements of SPPC include the accounts of SPPC’s wholly-owned subsidiaries, Piñon Pine Corporation, Piñon Pine Investment Company, GPSF-B, SPPC Funding LLC, and Sierra Pacific Power Capital I.

The Utilities’ accounts for electric operations and SPPC’s accounts for gas operations are maintained in accordance with the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission (FERC).

TGPC is a partner in a joint venture that developed, constructed, and operates a natural gas pipeline serving the expanding gas market in the Reno area and certain northeastern California markets. TGPC accounts for its joint venture interest under the equity method. SPC was formed in 1999 to provide telecommunications services using fiber optic cable technology in both northern and southern Nevada.

Reclassifications

Certain reclassifications of prior year’s information have been made for comparative purposes but have not affected previously reported net income (loss) or common shareholders’ equity.

Revised Statement of Cash Flow Information

For all periods presented, SPR has separately disclosed the operating, investing and financing portions of the cash flows attributable to its discontinued operations, which in prior periods were previously reported on a combined basis as a single line item in operating activity (previously ($8,048) and ($11,727) in 2004 and 2003, respectively (dollars in thousands)).

Regulatory Accounting and Other Regulatory Assets

The Utilities’ rates are currently subject to the approval of the Public Utilities Commission of Nevada (PUCN) and, in the case of SPPC, rates are also subject to the approval of the 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 deferral 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) regulated rates are designed to recover the specific costs of the regulated products or

122

services; and (iii) it is reasonable to assume that rates are set at levels that recovered costs can be charged to and collected from customers. Management periodically assesses whether the requirements for application of SFAS No. 71 are satisfied.

In addition to the deferral of energy costs discussed below, significant items to which SPR and the Utilities apply regulatory accounting include goodwill and other merger costs resulting from the 1999 merger of SPR and NPC, generation divestiture costs, and the loss on reacquired debt.

Regulatory assets represent incurred costs that have been deferred because it is probable they will be recovered through future rates collected from customers. If at any time the incurred costs no longer meet these criteria, these costs are charged to earnings. Regulatory liabilities generally represent obligations to make refunds to customers for previous collections, except for cost of removal which represents the cost of removing future electric and gas assets. Management regularly assesses whether the regulatory assets are probable of future recovery by considering actions of regulators, current laws related to regulation, applicable regulatory environment changes and the status of any current and pending or potential deregulation legislation.

Currently, the electric utility industry is predominantly regulated on a basis designed to recover the cost of providing electric power to its retail and wholesale customers. If cost-based regulation were to be discontinued in the industry for any reason, including competitive pressure on the cost-based prices of electricity, profits could be reduced, and the Utilities might be required to reduce their asset balances to reflect a market basis less than cost. Discontinuance of cost-based regulation could also require affected utilities to write off their associated regulatory assets. Management cannot predict the potential impact, if any, of these competitive forces on the Utilities’ future financial position and results of operations.

SIERRA PACIFIC RESOURCES
OTHER REGULATORY ASSETS AND LIABILITIES


	AS OF DECEMBER 31, 2005
		Receiving Regulatory								As of
	Remaining	Treatment				Pending				December
(dollars in thousands)	Amortization	Earning a		Not Earning		Regulatory		2005		31, 2004
DESCRIPTION	Period	Return		a Return		Treatment		Total		Total
Regulatory Assets
Loss on reacquired debt	Term of Related Debt	$	57,804	$	—	$	—	$	57,804	$	35,890
Plant assets	Various thru 2031		80,145		6,693		16,042		102,880		48,795
Nevada divestiture costs	Thru 5/12		28,497		—		—		28,497		33,009
Merger transition/transaction costs	Thru 5/14		—		32,569		—		32,569		35,518
Merger severance/relocation	Thru 5/14		—		17,951		—		17,951		19,909
Merger goodwill	Thru 5/44		—		281,739		—		281,739		288,112
California restructure costs	Thru 2009		1,469		990		—		2,459		3,904
Conservation programs			—		—		24,144		24,144		11,116
Legal costs			—		—		9,558		9,558		—
Other costs	Thru 2017		3,389		72		7,083		10,544		11,509

Total regulatory assets		$	171,304	$	340,014	$	56,827	$	568,145	$	487,762


Regulatory Liabilities
Cost of Removal	Various	$	246,960	$	—	$	—	$	246,960	$	211,940
Gain on Property Sales	Various thru 2007		11,285		—		—		11,285		24,386
SO2 Allowances	Various thru 2011		536		—		—		536		1,169
Gas Transportation Contract	Thru 2017		—		17,542		—		17,542		20,000
Plant liability			—		—		2,049		2,049		—
Impact Charge			—		—		6,066		6,066		—

Total regulatory liabilities		$	258,781	$	17,542	$	8,115	$	284,438	$	257,495

123

NEVADA POWER COMPANY
OTHER REGULATORY ASSETS AND LIABILITIES


	AS OF DECEMBER 31, 2005
		Receiving Regulatory								As of
	Remaining	Treatment				Pending				December
(dollars in thousands)	Amortization	Earning a		Not Earning		Regulatory		2005		31, 2004
DESCRIPTION	Period	Return		a Return		Treatment		Total		Total
Regulatory Assets
Loss on reacquired debt	Term of Related Debt	$	39,392	$	—	$	—	$	39,392	$	15,823
Plant assets			40,278		—		11,342		51,620		—
Nevada divestiture costs	Thru 3/12		17,459		—		—		17,459		20,252
Merger transition/transaction costs	Thru 3/14		—		22,838		—		22,838		24,867
Merger severance/relocation	Thru 3/14		—		8,417		—		8,417		9,437
Merger goodwill	Thru 3/44		—		189,088		—		189,088		193,048
Conservation programs			—		—		19,048		19,048		8,362
Legal costs			—		—		9,558		9,558		—
Other costs	Various thru 2008		1,508		27		3,612		5,147		5,661

Total regulatory assets		$	98,637	$	220,370	$	43,560	$	362,567	$	277,450


Regulatory Liabilities
Cost of Removal	Various	$	144,164	$	—	$	—	$	144,164	$	125,776
Gain on Property Sales	Various thru 2007		11,285		—		—		11,285		24,385
SO2 Allowances	Various thru 2011		536		—		—		536		1,169
Gas Transportation Contract	Thru 2017		—		17,542		—		17,542		20,000

Total regulatory liabilities		$	155,985	$	17,542	$	—	$	173,527	$	171,330

124

SIERRA PACIFIC POWER COMPANY
OTHER REGULATORY ASSETS AND LIABILITIES


	AS OF DECEMBER 31, 2005
		Receiving Regulatory								As of
	Remaining	Treatment				Pending				December
(dollars in thousands)	Amortization	Earning a		Not Earning		Regulatory		2005		31, 2004
DESCRIPTION	Period	Return		a Return		Treatment		Total		Total
Regulatory assets
Loss on reacquired debt	Term of Related Debt	$	18,412	$	—	$	—	$	18,412	$	20,067
Plant assets	Various thru 2031		39,867		6,693		4,700		51,260		48,795
Nevada divestiture costs	Thru 5/12		11,038		—		—		11,038		12,757
Merger transition/transaction costs	Thru 5/14		—		9,731		—		9,731		10,651
Merger severance/relocation	Thru 5/14		—		9,534		—		9,534		10,472
Merger goodwill	Thru 5/44		—		92,651		—		92,651		95,064
California Restructure Costs	Thru 2009		1,469		990		—		2,459		3,904
Conservation Programs			—		—		5,096		5,096		2,754
Other costs	Various through 2017		1,881		45		3,471		5,397		5,848

Total regulatory assets		$	72,667	$	119,644	$	13,267	$	205,578	$	210,312


Regulatory Liabilities

Cost of Removal	Various	$	102,796	$	—	$	—	$	102,796	$	86,164
Gain on Property Sales			—		—		—		—		1
Plant assets			—		—		2,049		2,049		—
Impact Charge			—		—		6,066		6,066		—

Total regulatory liabilities		$	102,796	$	—	$	8,115	$	110,911	$	86,165

Deferral of Energy Costs

Nevada and California statutes permit regulated utilities to adopt deferred energy accounting procedures. The intent of these procedures is to ease the effect on customers of fluctuations in the cost of purchased gas, fuel, and purchased power.

In January 2000, in accordance with a PUCN order, SPPC resumed using deferred energy accounting for its gas operations.

On April 18, 2001, the Governor of Nevada signed into law 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.

Pursuant to AB 369, Nevada Revised Statute (NRS) requires the Utilities to file applications to clear their respective deferred energy account balances at least every 12 months and 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, NRS specifies that fuel and purchased power costs include all costs incurred to purchase fuel, to purchase capacity, and to purchase energy. The Utilities also record and are eligible under the statute to recover a carrying charge on such deferred balances.

125

The following deferred energy costs were included in the consolidated balance sheets as of the dates shown (dollars in thousands):


		December 31, 2005
		NPC			SPPC		SPPC		SPR
Description		Electric			Electric		Gas		Total
Unamortized balances approved for collection in current rates
Electric — NPC Period 2⁽¹⁾	(effective 5/03, 3 years)	$	(1,199	)	$	—	$	—	$	(1,199	)
Electric — NPC Period 3	(effective 4/05, 2 years)		48,564			—		—		48,564
Electric — SPPC Period 3	(effective 6/05, 27 months)		—			23,208		—		23,208
Electric — NPC Period 4	(effective 4/05, 2 years)		71,490			—		—		71,490
Electric — SPPC Period 4	(effective 6/05, 1 year)		—			9,101		—		9,101
Natural Gas — Period 5	(effective 11/05, 1 year)		—			—		4,454		4,454
LPG Gas Period 3	(effective 11/04, 2 years)		—			—		36		36
LPG Gas Period 4	(effective 11/05, 1 year)		—			—		130		130
Balances pending PUCN approval			171,447			41,180		—		212,627
Cumulative CPUC Balance			—			6,699		—		6,699
Balances accrued since end of periods submitted for PUCN approval			26,647			6,768		2,050		35,465
Claims for terminated supply contracts⁽²⁾			83,993			21,111		—		105,104

Total		$	400,942		$	108,067	$	6,670	$	515,679


Current Assets
Deferred energy costs — electric		$	186,355		$	67,342	$	—	$	253,697
Deferred energy costs — gas			—			—		5,825		5,825
Deferred Assets
Deferred energy costs — electric			214,587			40,725		—		255,312
Deferred energy costs — gas			—			—		845		845

Total		$	400,942		$	108,067	$	6,670	$	515,679

126


		December 31, 2004
		NPC			SPPC			SPPC			SPR
Description		Electric			Electric			Gas			Total
Unamortized balances approved for collection in current rates
Electric — NPC Period 1⁽¹⁾	(effective 4/02, 3 years)	$	(11,894	)	$	—		$	—		$	(11,894	)
Electric — SPPC Period 1	(effective 6/02, 3 years)		—			14,734			—			14,734
Electric — NPC Period 2	(effective 5/03, 3 years)		57,746			—			—			57,746
Electric — SPPC Period 2⁽¹⁾	(effective 6/03, 2 years)		—			(6,349	)		—			(6,349	)
Electric — NPC Period 3	(effective 4/05, 2 years)		88,722									88,722
Electric — SPPC Period 3	(effective 6/05, 27 months)					42,398						42,398
Natural Gas — Period 3⁽¹⁾	(effective 11/03, 2 years)		—			—			(3,084	)		(3,084	)
Natural Gas — Period 4	(effective 11/04, 1 year)		—			—			2,320			2,320
LPG Gas — Period 2	(effective 11/03, 2 years)		—			—			18			18
LPG Gas — Period 3	(effective 11/04, 2 years)								62			62
Balances pending PUCN approval			115,752			27,676			—			143,428
Cumulative CPUC Balance						5,101						5,101
Balances accrued since end of periods submitted for PUCN approval			10,829			5,380			6,281			22,490
Claims for terminated supply contracts ⁽²⁾			240,039			84,033			—			324,072

Total		$	501,194		$	172,973		$	5,597		$	679,764


Current Assets
Deferred energy costs — electric		$	126,074		$	21,934		$	—		$	148,008
Deferred energy costs — gas			—			—			3,106			3,106
Deferred Assets
Deferred energy costs — electric			375,120			151,039			—			526,159
Deferred energy costs — gas			—			—			2,491			2,491

Total		$	501,194		$	172,973		$	5,597		$	679,764


(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)		Amounts related to claims for terminated supply contracts are discussed in Note 14, Commitments and Contingencies.

Utility Plant

The cost of additions, including betterments and replacements of units of property, are charged to utility plant. When units of property are replaced, renewed or retired, their cost plus removal or disposal costs, less salvage proceeds, are charged to accumulated depreciation. The cost of current repairs and minor replacements are charged to maintenance expense when incurred.

In addition to direct labor and material costs, certain other direct and indirect costs are capitalized. The indirect construction overhead costs capitalized are based upon the following cost components: the cost of time spent by administrative and supervision employees in planning and directing construction; property taxes; employee benefits including such costs as pensions, post retirement and post employment benefits, vacations and payroll taxes; and an allowance for funds used during construction (AFUDC) which includes the cost of debt and equity capital associated with construction activity.

Allowance for Funds Used During Construction

As part of the cost of constructing utility plant, the Utilities capitalize AFUDC. AFUDC represents the cost of borrowed funds and, where appropriate, the cost of equity funds used for construction purposes in accordance with rules prescribed by the FERC and the PUCN. AFUDC is capitalized in the same manner as construction labor and material costs, however, with an offsetting credit to “other income” for the portion representing the cost of equity funds; and as a reduction of interest charges for the portion representing borrowed funds. Recognition of this item as a cost of utility plant is in accordance with established regulatory ratemaking practices. Such practices are intended to permit the Utility to earn a fair return on, and recover in rates charged for utility services, all

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capital costs. This is accomplished by including such costs in the rate base and in the provision for depreciation. NPC’s AFUDC rates used during 2005, 2004 and 2003 were 9.03%, 9.03% and 8.37% respectively. SPPC’s AFUDC rates used during 2005, 2004 and 2003 were 8.96%, 9.26% and 8.61% respectively. As specified by the PUCN, certain projects may be assigned a lower AFUDC rate due to specific low-interest-rate financings directly associated with those projects.

Depreciation

Substantially all of the Utilities’ plant is subject to the ratemaking jurisdiction of the PUCN or the FERC, and, in the case of SPPC, the CPUC. Depreciation expense is calculated using the straight-line composite method over the estimated remaining service lives of the related properties, which approximates the anticipated physical lives of these assets in most cases. NPC’s depreciation provision for 2005, 2004, and 2003, as authorized by the PUCN and stated as a percentage of the average depreciable property balances for those years, are approximately 3.15%, 3.05% and 3.06% respectively. SPPC’s depreciation provision for 2005, 2004 and 2003, as authorized by the PUCN and stated as a percentage of the average cost of depreciable property, was approximately 3.3%, 3.35%, and 3.31%, respectively.

Impairment of Long-Lived Assets

SPR, NPC and SPPC evaluate on an ongoing basis the recoverability of its assets for impairments whenever events or changes in circumstance indicate that the carrying amount may not be recoverable as described in SFAS No. 144 “Accounting for the Disposal or Impairment of Long-Lived Assets.” (SFAS 144) See Note 18, Discontinued Operations and Disposal and Impairment of Long-Lived Assets.

Accounting For Goodwill

SFAS No. 142 “Goodwill and Other Intangible Assets”, adopted by SPR, NPC and SPPC on January 1, 2002, changed the accounting for goodwill from an amortization method to one requiring at least an annual review for impairment. See Note 19, Goodwill and Other Merger Costs, for further discussion.

Cash and Cash Equivalents

Cash is comprised of cash on hand and working funds. Cash equivalents consist of high quality investments in money market funds.

Restricted Cash

At December 31, 2005 and 2004, SPR had approximately $67.2 million and $88.5 million, respectively of restricted cash in SPR’s consolidated balance sheets, primarily consisting of an aggregate $49 million and $11 million in cash collateral deposited by NPC and SPPC, respectively, into escrow in connection with the stay of the Enron Judgment, as described in Note 14, Commitments and Contingencies. The cash collateral plus interest was returned to the Utilities on January 27, 2006.

Federal Income Taxes

SPR and its subsidiaries file a consolidated federal income tax return. Current income taxes are allocated based on SPR’s and each subsidiary’s respective taxable income or loss and investment tax credits as if each subsidiary filed a separate return. SPR accounts for income taxes in accordance with SFAS No. 109, “Accounting for Income Taxes.” SFAS No. 109 requires recognition of deferred tax liabilities and assets for the future tax consequences of events that have been included in the consolidated financial statements or tax returns. Under this method, deferred tax liabilities and assets are determined based on the difference between the financial statement and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse.

For regulatory purposes, the Utilities are authorized to provide for deferred taxes on the difference between straight-line and accelerated tax depreciation on post-1969 utility plant expansion property, deferred energy, and certain other differences between financial reporting and taxable income, including those added by the Tax Reform Act of 1986 (TRA). In 1981, the Utilities began providing for deferred taxes on the benefits of using the Accelerated Cost Recovery System for all post-1980 property. In 1987, the TRA required the Utilities to begin providing deferred taxes on the benefits derived from using the Modified Accelerated Cost Recovery System.

Deferred investment tax credits are being amortized over the estimated service lives of the related properties. Investment tax credits are no longer available to the Utilities.

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Revenues

Operating revenues include billed and unbilled utility revenues. The accrual for unbilled revenues represents amounts owed to the Utilities for service provided to customers for which the customers have not yet been billed. These unbilled amounts are also included in accounts receivable.

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. Accounts receivable as of December 31, 2005, include unbilled receivables of $80 million and $77 million for NPC and SPPC, respectively. Accounts receivable as of December 31, 2004, include unbilled receivables of $83 million and $67 million for NPC and SPPC, respectively.

Stock Compensation Plans

At December 31, 2005, SPR had several stock-based compensation plans, which are described more fully in Note 13, Stock Compensation Plans. SPR applies Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees,” in accounting for its stock option plans and in accordance with the disclosure only provisions of SFAS No. 123, “Accounting for Stock-Based Compensation,” and the updated disclosure requirements set forth in SFAS No. 148 “Accounting for Stock-Based Compensation-Transition and Disclosure.” Accordingly, no compensation cost has been recognized for nonqualified stock options and the employee stock purchase plan. SPR will be adopting SFAS No. 123R “Share-Based Payment” beginning in the first quarter of 2006. See SFAS 123R discussed later. 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 accounting provisions of SFAS No. 123, SPR’s Earnings (Loss) applicable to common stock would have been decreased to the pro forma amounts indicated in the table below (dollars in thousands, except per share amounts).


		2005			2004			2003
Earnings (Deficit) applicable to Common Stock, as reported		$	82,237		$	28,571		$	(140,529	)

Add: Stock Compensation Cost included in Net Income as Reported, net of related tax effects			2,187			1,958			410

Less: Pro Forma Stock Compensation Cost, net of related tax effects			(2,688	)		(2,158	)		(1,750	)


Pro Forma Earnings (Deficit) applicable to Common Stock		$	81,736		$	28,371		$	(141,869	)


Basic Earnings (Deficit) Per Share	As Reported	$	0.44		$	0.16		$	(1.21	)
	Pro Forma	$	0.44		$	0.16		$	(1.22	)
Diluted Earnings (Deficit) Per Share	As Reported	$	0.44		$	0.16		$	(1.21	)
	Pro Forma	$	0.44		$	0.16		$	(1.22	)

Asset Retirement Obligations

SFAS No. 143 “Accounting for Asset Retirement Obligations” provides accounting requirements for the recognition and measurement of liabilities associated with the retirement of tangible long-lived assets. Under the standard, these liabilities are 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 is classified as 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. SPR, NPC and SPPC adopted SFAS No. 143 on January 1, 2003.

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Management’s methodology to assess its legal obligation included an inventory of assets by company, system and components and a review of rights of way and easements, regulatory orders, leases and federal, state, and local environmental laws. Management 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. Provisions of the lease require the lessees to remove the facilities upon request of the Navajo Nation at the expiration of the leases.

In March, 2005, the Financial Accounting Standards Board (FASB) issued Interpretation No. 47 as clarification to SFAS No. 143. This Interpretation is effective no later than the end of fiscal years ending after December 15, 2005 (December 31, 2005, for calendar-year enterprises). The Interpretation clarifies the term conditional retirement obligation as used in SFAS No. 143 as well as when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation.

Similar to the methodology used to assess legal obligations under SFAS 143, management reviewed an inventory of assets by system and components, as well as a review of rights of way and easements, regulatory orders, leases and federal, state, and local environmental laws. As a result, management determined that five types of assets, evaporative ponds, dry ash landfills, fuel storage tanks, asbestos and oils treated with Poly Chlorinated Biphenyl met the conditional asset retirement obligations of FIN 47. As such included in NPC’s and SPPC’s Other Liabilities accounts, as of December 31, 2005, were approximately $10.9 million and $5.0 million of ARO’s. If this interpretation would have been in effect as of December 31, 2004, approximately $10.3 million and $4.7 million would have been included in NPC’s and SPPC’s Other Liabilities accounts, respectively. As the Utilities are subject to SFAS 71, accounting treatment, the cumulative effect of these ARO’s were recorded in Other Regulatory Assets.

Cost of Removal

In addition to the legal asset retirement obligation booked for the Navajo plant, the Utilities have accrued for the cost of removing non-legal retirement obligations of other electric and gas assets, in accordance with accepted accounting practices. The amount of such accruals included in regulatory liabilities in 2005 is approximately $144 million and $103 million for NPC and SPPC, respectively. In 2004 the amounts were approximately $126 million and $86 million for NPC and SPPC, respectively.

Variable Interest Entities

In December 2003, the FASB issued a revised Interpretation No. 46, “Consolidation of Variable Interest Entities” (FIN 46 (R)), which elaborates on Accounting Research Bulletin No. 51, “Consolidated Financial Statements.” Among other requirements, FIN 46 (R) provides that a variable interest entity be consolidated by the enterprise that is the primary beneficiary of the variable interest entity. As of December 31, 2003, SPR, NPC and SPPC adopted FIN 46 (R) for special purpose entities. As of March 31, 2004, SPR, NPC and SPPC adopted FIN 46 (R) for all variable interest entities. To identify potential variable interests, management reviewed long term purchase power contracts, including contracts with qualifying facilities (QFs), jointly owned facilities and partnerships that are not consolidated. The Utilities identified seven QFs with long-term purchase power contracts that are variable interests. However, the Utilities are not required at this time to consolidate these QFs under the scope exception provided for in FIN 46 (R) due to the inability to obtain information necessary to (1) determine whether the entity is a variable interest entity, (2) determine whether the enterprise is the variable interest entity’s primary beneficiary, or (3) perform the accounting required to consolidate the variable interest entity for which it is determined to be the primary beneficiary. The Utilities have requested financial information from these QFs but have not been successful in obtaining the information. The Utilities’ maximum exposure to loss is limited to the cost of replacing these purchase power contracts if the QFs are unable to deliver power. However, the Utilities believe their exposure is mitigated as they would likely recover these costs through their deferred energy accounting mechanism. The Utilities have not identified any other significant variable interests that require consolidation as of December 31, 2005.

Recent Pronouncements

SFAS 123 R

The Securities and Exchange Commission (SEC) announced on April 14, 2005 that it was delaying implementation of SFAS No. 123 (revised 2004), “Share-Based Payment” (SFAS 123R). Under SFAS 123R, registrants would have been required to implement the standard as of the beginning of the first interim or annual period that begins after June 15, 2005. SPR would have been permitted to follow the pre-existing accounting literature for the first and second quarters of 2005, but was required to follow SFAS 123R for third quarter reports and thereafter. The SEC’s new rule allows SPR to implement SFAS 123R at the beginning of the next fiscal year that begins after June 15, 2005, or periods beginning December 31, 2005. The SEC’s new rule does not change the accounting required by SFAS 123R. Amounts that were previously shown in footnote disclosure by SPR will now be recognized in the income statement. SPR intends to utilize the services of its actuaries to value share-based compensation.

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SFAS 154

In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections” (SFAS 154) which replaces Accounting Principles Board Opinions No. 20 “Accounting Changes” and SFAS No. 3, “Reporting Accounting Changes in Interim Financial Statements—An Amendment of APB Opinion No. 28.” SFAS 154 provides guidance on the accounting for and reporting of accounting changes and error corrections. It establishes retrospective application, or the latest practicable date, as the required method for reporting a change in accounting principle and the reporting of a correction of an error. SFAS 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. The implementation of SFAS 154 did not have an impact on SPR and the Utilities.

SFAS 109 Exposure Draft

On July 14, 2005, the FASB issued an Exposure Draft, “Accounting for Uncertain Tax Positions,” an interpretation of FASB Statement No. 109, “Accounting for Income Taxes.” This interpretation seeks to reduce the diversity in practice associated with certain aspects of the recognition and measurement requirements related to accounting for income taxes. Specifically, the interpretation would require that a tax position meet a “probable recognition threshold” for the benefit of an uncertain tax position to be recognized in the financial statements. Subsequent to the issuance of the initial Exposure Draft, the FASB has announced that the “probable recognition threshold” would be replaced by a “more-likely-than-not threshold,” a less restrictive threshold. The revised interpretation would require recognition in the financial statements of the best estimate of the effects of a tax position only if that position is more likely than not of being sustained on audit by the appropriate taxing authorities, based solely on the technical merits of the position. SPR and its Utilities’ are currently reviewing the provisions of the Exposure Draft to determine the impact it may have on SPR and the Utilities’ financial position and results of operations. The final interpretation will be effective as of the beginning of the first annual period beginning after December 15, 2006.

NOTE 2. SEGMENT INFORMATION

SPR’s Utilities operate three regulated business segments (as defined by SFAS 131, “Disclosure about Segments of an Enterprise and Related Information”); which are NPC electric, SPPC electric and SPPC natural gas service. Electric service is provided to Las Vegas and surrounding Clark County by NPC, northern Nevada and the Lake Tahoe area of California by SPPC. Natural gas services are provided by SPPC in the Reno-Sparks area of Nevada. Other segment information includes segments below the quantitative threshold for separate disclosure.

The net assets and operating results of SPC and e ·three are reported as discontinued operations in the financial statements for 2005, 2004 and 2003. Accordingly, the segment information excludes financial information of SPC and e ·three.

Operational information 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. The accounting policies of the business segments are the same as those described in Note 1, Summary of Significant Accounting Policies. Inter-segment revenues are not material (dollars in thousands).


	NPC		SPPC		Total							Reconciling
December 31, 2005	Electric		Electric		Electric		Gas		All Other			Eliminations		Consolidated
Operating Revenues	$	1,883,267	$	967,427	$	2,850,694	$	178,270	$	1,255			—	$	3,030,219
Operating income		228,827		107,213		336,040		9,091		13,650			—		358,781
Operating income taxes		46,425		24,209		70,634		1,829		(33,223	)		—		39,240
Depreciation		124,098		82,676		206,774		7,893		(5	)		—		214,662
Interest expense on long term debt		159,106		63,040		222,146		6,200		74,322			—		302,668
Assets		5,173,921		2,218,938		7,392,859		245,707		150,324			81,656		7,870,546
Capital expenditures		546,748		121,767		668,515		17,879		—			—		686,394

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	NPC		SPPC		Total							Reconciling
December 31, 2004	Electric		Electric		Electric		Gas		All Other			Eliminations		Consolidated
Operating Revenues	$	1,784,092	$	881,908	$	2,666,000	$	153,752	$	4,087			—	$	2,823,839
Operating income		216,490		103,513		320,003		7,732		11,050			—		338,785
Operating income taxes		45,135		12,740		57,875		2,238		(35,670	)		—		24,443
Depreciation		118,841		79,298		198,139		7,508		—			—		205,647
Interest expense on long term debt		152,764		64,729		217,493		6,583		88,323			—		312,399
Assets		4,883,540		2,226,949		7,110,489		232,092		120,607			65,279		7,528,467
Capital expenditures		482,484		117,329		599,813		14,598		—			—		614,411


	NPC			SPPC			Total								Reconciling
December 31, 2003	Electric			Electric			Electric			Gas		All Other			Eliminations		Consolidated
Operating Revenues	$	1,756,146		$	868,280		$	2,624,426		$	161,586	$	1,531			—	$	2,787,543
Operating income		183,733			61,323			245,056			7,243		19,165			—		271,464
Operating income taxes		(12,734	)		(14,288	)		(27,022	)		584		(30,570	)		—		(57,008	)
Depreciation		109,655			74,432			184,087			7,082		90			—		191,259
Interest expense on long term debt		142,143			69,888			212,031			6,114		75,337			—		293,482
Assets		4,210,759			2,061,255			6,272,014			230,365		490,530			70,849		7,063,758
Capital expenditures		229,368			127,014			356,382			22,937		—			—		379,319

The reconciliation of segment assets at December 31, 2005, 2004, and 2003 to the consolidated total includes the following unallocated amounts:


	2005		2004		2003
Cash	$	53,024	$	35,783	$	29,635
Other regulatory assets		19,265		21,124		31,812
Deferred charges-other		9,367		8,372		9,402

	$	81,656	$	65,279	$	70,849

NOTE 3. REGULATORY ACTIONS

The Utilities are subject to the jurisdiction of the PUCN and, in the case of SPPC, the 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 (IRPs) to the PUCN for approval.

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

Deferred Energy Accounting

The Utilities began using deferred energy accounting for their respective electric operations in March 2001. The intent of deferred energy accounting is to ease the effect of fluctuations in the cost of purchased power and fuel.

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Nevada Matters

Nevada Power Company 2003 General Rate Case

NPC filed its biennial General Rate Case on October 1, 2003, as required by law. On March 26, 2004, the PUCN issued an order allowing $48 million of the $133 million rate increase requested by NPC. The general rate decision reflects the following significant items:

	•		A Return on Equity (ROE) of 10.25%, and an overall Rate of Return (ROR) of 9.03%, an improvement over NPC’s previous ROE and ROR, which were 10.1% and 8.37%, respectively. NPC had requested an ROE of 12.4% and ROR of 10.0%;

	•		Approximately $7 million of the $8.8 million of goodwill and merger costs requested to be recovered annually over each of the next two years;

	•		Approximately $21.4 million of generation divestiture costs to be recovered over an extended period of 8 years;

	•		Approved the establishment of a regulatory asset account to capture costs related to the shutdown of the Mohave Power Plant; and

	•		Required NPC to file a set of recommended quality of service and customer service measurements to be used in future general rate case proceedings. On July 1, 2004, NPC and SPPC jointly filed with the PUCN their recommended quality of service and customer service measurements.

The PUCN removed from cost of service various items requested by NPC through its general rates filing including costs associated with NPC’s 2003 short-term incentive compensation plan and NPC’s request to earn a rate of return on the cash balances NPC maintained to ensure sufficient liquidity to procure power. In addition, the PUCN’s decision included a decrease to NPC’s general rates to allow NPC’s customers to share the benefit of approximately $8.3 million per year for the next two years of gains from recent land sales by NPC.

The PUCN responded to petitions filed by the Bureau of Consumer Protection (BCP) and NPC on May 20, 2004 and June 7, 2004, respectively. The PUCN’s May 20 order denied two of the issues on which the BCP requested reconsideration, and granted clarification on the third issue. The clarification addressing rental revenue resulted in an overall reduction in the revenue requirement of $1.6 million. The PUCN’s June 7, 2004 order concluded that the petition was granted in part since clarification had been given on the requested issues and denied in part since NPC’s requested revisions to the order were not accepted.

2006 Deferred Energy Rate Case

On January 17, 2006, pursuant to recently enacted legislation, NPC filed a Deferred Energy Accounting Adjustment (DEAA) rate case application with the PUCN seeking recovery for purchased fuel and power costs accumulated between October 1, 2004 and November 30, 2005, and to increase its going forward Base Tariff Energy Rate (BTER) to reflect future energy costs. NPC requested a one year amortization period to recover the deferred balance.

2005 Base Tariff Energy Rate Update

On September 27, 2005, the PUCN issued an order approving the BTER rate changes requested in NPC’s filing.

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Nevada Power Company 2004 Deferred Energy Case

The application also requested an increase to NPC’s BTER.

Nevada Power Company 2003 Deferred Energy Case

On November 14, 2003, NPC filed an application with the PUCN seeking repayment for purchased fuel and power costs accumulated between October 1, 2002 and September 30, 2003, as required by law. The application sought to establish a rate to collect accumulated purchased fuel and power costs of $93 million. On March 26, 2004, the PUCN granted approval for NPC to increase its going forward energy rate as filed, approved recovery for $89 million of its deferred balance, denied $4 million, and denied NPC’s request for a tax gross-up on the equity portion of carrying charges. Of the $4 million disallowed, $1.6 million was charged to income in the current period as the remaining amount had no impact on earnings or was charged to income in prior periods. The PUCN ordered the change in going forward rates to take effect April 1, 2004 and delayed the implementation of the deferred energy balance recovery until January 1, 2005 when recovery of the 2001 deferred balance was expected to have been completed.

On December 28, 2004, the PUCN issued an order approving a stipulation reached by all parties that allows NPC to defer the 2003 DEAA rate change until April 1, 2005, which will be coincident with the DEAA rate change that will result from the 2004 DEAA case.

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 approximately 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.

The BCP filed a Petition that challenged the recovery of all costs with the District Court of Clark County, Nevada, for Judicial Review of the PUCN Order on August 8, 2003, against PUCN, Case No. A471928. On September 8, 2003, the PUCN filed its answer to the BCP Petition. The PUCN response cites a number of affirmative defenses to the allegations contained in the BCP

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petition and asks that the court dismiss the BCP petition. The BCP filed its opening brief on January 8, 2004 and responding briefs were filed on March 9, 2004. The court has not yet ruled on this matter.

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.

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. NPC and the BCP both sought individual review of the PUCN Order in the First District Court of Nevada. The District Court affirmed the PUCN’s decision. Both NPC and the BCP filed Notices of Appeal to the Nevada Supreme Court.

Supreme Court rules mandate settlement talks before a matter is set for briefing and argument. As a result of that mandatory process, NPC filed a motion with the Nevada Supreme Court seeking remand of the matter back to the PUCN to consider evidence uncovered after the PUCN’s final decision. On November 2, 2004, the Nevada Supreme Court issued an order denying the motion for remand.

Oral argument was heard on February 23, 2006. A decision is not expected for several months thereafter. At this time, NPC is unable to predict either the outcome or timing of a decision in this matter.

Sierra Pacific Power Company

2005 Electric and Gas General Rate Cases

On October 3, 2005, SPPC filed a Gas general rate case along with its statutorily required Electric general rate case. SPPC’s last Gas general rate case was filed in 1992 and the last electric general rate case was filed in 2003. The following items are requested in the filings:

	•		Electric general revenue increase: $27 million or 3.4% effective May 1, 2006

	•		Gas general revenue increase: $8.3 million or 5.4%, effective May 1, 2006

	•		Electric Return on Equity and Rate of Return: 11.4% and 9.27% respectively

	•		Gas Return on Equity and Rate of Return: 11.4% and 8.29% respectively

	•		Approval to continue to recover an allocated amount of the 1999 NPC/SPPC merger costs from Electric customers

	•		Approval to recover an allocated amount of the 1999 NPC/SPPC merger costs from Gas customers

	•		New depreciation rates for Gas and Electric facilities

On January 25, the interveners filed direct testimony addressing return on equity, overall rate of return and depreciation rates. The PUCN Staff has recommended a 10.28% ROE for Electric and Gas operations, an 8.97% Electric ROR, an 8.06% Gas ROR and depreciation rates that would result in decreased depreciation expenses. Other interveners are recommending ROE’s ranging from 9.1% to 10.9%, Electric ROR’s from 8.35% to 9.08% and Gas ROR’s from 7.52% to 8.10%. The other interveners have also suggested depreciation rates lower than SPPC’s filing.

On February 22, interveners filed direct testimony addressing overall revenue requirements, including the effects of their ROE, ROR and depreciation rate recommendations. The PUCN Staff recommended a $15 million decrease to current electric revenues and a $3.6 million increase to gas revenues. The Bureau of Consumer Protection (BCP) recommended a $32 million reduction to current electric revenues and a $.6 million increase to current gas revenues. The Nevada Resort Association recommended a $12 million decrease to current electric revenues.

Hearings are scheduled to occur on various dates in February and March 2006. A decision on these cases is due early in the second quarter of 2006.

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Sierra Pacific Power Company 2003 General Rate Case

SPPC filed its biennial general rate case on December 1, 2003, as required by law. SPPC requested an $87 million increase in the annual revenue requirement for general rates. On April 1, 2004, SPPC, the Staff of the PUCN and other interveners in SPPC’s 2003 general rate case negotiated a settlement agreement that resolved most of the issues in the revenue requirement and cost of capital portions of SPPC’s case. The agreement, which has been approved by the PUCN, includes the following provisions:

	•		SPPC was allowed to recover a $40 million increase in annual rates.

	•		SPPC was allowed a Return on Equity (ROE) of 10.25%, and an overall Rate of Return (ROR) of 9.26%, an improvement over SPPC’s previous ROE and ROR, which were 10.17% and 8.61%, respectively. SPPC had sought an ROE of 12.4% and ROR of 10.03%.

	•		The agreement accepted SPPC’s requested accounting treatment as filed in its application for purposes of recording revenues, expenses and assets with the following exception. Accounting issues common to SPPC’s general rate case and NPC’s general rate case that was decided by the PUCN on March 26, 2004, in Docket No. 03-10001, are treated as set forth in the PUCN’s Order on NPC’s general rate case, except for merger costs. The accounting treatment for merger costs and goodwill established in the NPC decision will apply to the recovery of these costs by SPPC, except that SPPC will include in rates 100% of the costs as filed until recovery is reset by the PUCN in SPPC’s next general rate application.

	•		Required SPPC to file a set of recommended quality of service and customer service measurements to be used in future general rate case proceedings. On July 1, 2004, SPPC and NPC jointly filed with the PUCN their recommended quality of service and customer service measurements.

The parties also reached a stipulated agreement that resolved the rate design issues in the case.

Investments in the Piñon Pine generating facility were not addressed by the stipulation. SPPC had sought recovery of its investment of approximately $96 million ($90 million associated with the Nevada jurisdiction) for costs associated with this facility over an extended period (between 10 and 25 years). The recovery of these costs would be in addition to the $40 million annual increase provided for by the stipulation agreement.

On May 27, 2004, the PUCN issued an order accepting the two stipulations, discussed above, and responding to SPPC’s request for recovery of the Piñon investments. The PUCN permitted recovery of approximately $37 million (Nevada jurisdictional) of the costs plus a carrying charge to be amortized over 25 years and approximately $11 million (Nevada jurisdictional) of costs without a carrying charge to be amortized over 10 years. The PUCN order granted a $46.7 million increase to SPPC’s general revenues.

As a result of the PUCN order, SPPC evaluated the Piñon Pine generating facility for impairment under the provisions of SFAS No. 90, “Regulated Enterprises—Accounting for Abandonments and Disallowances of Plant Costs”. As a result of this evaluation, SPPC recognized an impairment loss of approximately $47 million in the second quarter of 2004. The impairment loss recognized consists of disallowed costs of approximately $43 million and an additional $4 million loss because the PUCN did not permit a carrying charge on $11 million of the costs to be recovered.

SPPC filed a petition for judicial review of the PUCN’s Piñon Decision in the Second Judicial District Court of Nevada on June 8, 2004. The petition is based on existing resource planning statutes and regulations as they apply to the Piñon project. The Piñon project was approved by the PUCN in SPPC’s 1992 Integrated Resource Plan as presented.

On January 25, 2006, the court vacated the PUCN’s disallowance in Sierra Pacific’s 2003 General Rate Case and remanded the case back to the PUCN for further review whether the costs were justly and reasonably incurred.

December 2005 Deferred Energy Rate Cases and Base Tariff Energy Rate Updates

136

July 2005 Electric Base Tariff Energy Rate Update

On July 1, 2005, SPPC filed a request to increase its BTER to reflect forecasted energy costs. The request was expected to increase revenue by $32.3 million for the period October 1, 2005 to September 30, 2006 and was intended to more closely correlate fuel and purchased power revenues with fuel and purchased power costs. The proposed increase would not affect SPPC’s operating income. The increase was intended to recoup, on a more current basis, actual fuel and purchased power costs that were expected to be incurred during the rate effective period.

The request represented an increase of 3.7% for the average customer. SPPC agreed to a November 1, 2005 effective date due to procedural requirements.

January 2005 Electric Deferred Energy Rate Case Filing

On January 14, 2005, SPPC filed an application with the PUCN seeking recovery for purchased fuel and power costs accumulated between December 1, 2003 and November 30, 2004, as required by law.

The application also requested an increase to the BTER or going-forward energy rate.

2005 Gas Deferred Energy Rate Case and Base Tariff Energy Rate Update

On July 1, 2005, SPPC filed a proposed gas BTER, which represented an average increase of 19.5% for all customer classes. The estimated BTER revenue would not change SPPC’s operating income.

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Sierra Pacific Power Company 2004 Deferred Energy Case

On January 14, 2004, 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, 2002, and November 30, 2003. The Application requested a deviation from regulation and historic practice and to put in place an asymmetric amortization of the deferred energy balance of approximately $42 million, which would result in recovery of $8 million effective July 2004; $17 million effective July 2005; and $17 million effective July 2006. The Application also requested a deviation from regulation in resetting the BTER. That methodology and its results would result in no change to the currently effective BTER.

On July 7, 2004, the PUCN ruled on the deferred energy case, and approved a full recovery of the fuel and purchased power costs. The PUCN order delayed the start of the deferred balance recovery until April 2005, which corresponds with the expected repayment of previous deferred balances. The PUCN also ordered SPPC to implement a higher BTER rate (the rate paid for going forward energy purchases) than that requested by SPPC. The higher BTER rate represents an overall increase of 4.4% in electric rates for SPPC and became effective July 15, 2004.

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 BCP agreed to file a motion to dismiss the civil lawsuits filed in relation to the 2002 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.

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Sierra Pacific Power Company 2002 Deferred Energy Case

On February 1, 2002, SPPC filed an application with the PUCN, as required by law, seeking to clear deferred balances for purchased fuel and power costs accumulated between March 1, 2001 and November 30, 2001. The application sought to establish a DEAA 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. It also sought to recalculate the BTER to reflect anticipated ongoing purchased fuel and power costs.

On May 28, 2002, the PUCN issued its decision on the deferred energy application, allowing SPPC three years to collect $150 million but disallowing $53 million of deferred purchased fuel and power costs and $2 million in carrying charges.

On August 22, 2002, SPPC filed a lawsuit in the First District Court of Nevada seeking to reverse portions of the decision of the PUCN denying the recovery of deferred energy costs incurred by SPPC on behalf of its customers in 2001 on the grounds that such power costs were not prudently incurred. As part of the settlement agreement reached in connection with SPPC’s 2003 deferred energy case, SPPC agreed to dismiss the lawsuit in May 2003.

SPPC Natural Gas Distribution 2004 Annual Purchased Gas Cost Adjustment

On May 14, 2004, SPPC filed its annual application for Purchased Gas Cost Adjustment for its natural gas local distribution company. In the application, SPPC asked for an increase of $0.09456 per therm to its Base Purchased Gas Rate to recover its expected going forward gas costs. SPPC also requested that $0.02857 per therm be added to the Balancing Account Adjustment (BAA) rate to amortize an approximate $3.9 million balance of deferred gas costs, which were accumulated during the accounting period. Combined with the simultaneous expiration of past BAA charges, the new BAA rate would be $0.03869 per therm less than the current BAA rate. Overall, this request would result in a rate increase of approximately 5%.

The parties agreed to a stipulation, which recommended the PUCN approve the requested rates and the PUCN issued an order approving the rate increase on November 8, 2004.

SPPC Natural Gas Distribution 2003 Purchased Gas Cost Adjustment

On May 15, 2003, SPPC filed its annual application for Purchased Gas Cost Adjustment for its natural gas local distribution company. In the application, SPPC asked for an increase of $0.02524 per therm to its Base Purchased Gas Rate (BPGR) and a BAA credit to customers of $0.04833 per therm to be amortized over two years. This request would have resulted in a decrease of approximately 5% in customer rates.

SPPC, the PUCN Staff, and the BCP agreed upon a Stipulation, which was approved by the PUCN on October 1, 2003.

As a result of the stipulation, overall, rates for SPPC’s natural gas customers decreased by approximately 3%. The Parties agreed that the new BAA would be amortized over two years with 67% of the balance recovered in the first year, and 33% of the balance recovered in the second year. The BAA rate for the first year will be a credit of $0.06448 per therm. The BAA rate for the second year will be a credit of $0.03176 per therm. A BPGR of $0.066375 per therm was approved, an increase from the previous BPGR of $0.05316 per therm. The new rates were implemented November 1, 2003.

California Electric Matters (SPPC)

Sierra Pacific Power Company 2005 General Rate Case

139

Sierra Pacific Power Company 2004 Energy Cost Adjustment Clause

On May 1, 2004, SPPC filed its annual Energy Cost Adjustment Clause (ECAC) in California. The filing updated its estimated fuel and purchase power costs for its California customers and sought to recover or refund any deferred amounts projected through September 30, 2004. The filing requests $8.3 million or a 14.8% overall increase consisting of $3.9 million increase in the base rate and $4.4 million for the projected balance. Pre-hearing conferences were held on July 14 and August 4, 2004. On August 16, 2004, the CPUC Office of Ratepayer Advocates issued a report recommending the CPUC accept SPPC’s ECAC proposal with a minor change to the rate design calculations. SPPC accepted the change and the resulting decrease to the request of $13,000. On October 4, 2004, the CPUC issued a draft order recommending approval of SPPC’s adjusted ECAC proposal. No hearings were necessary and on November 19, 2004, the CPUC approved SPPC’s adjusted request and the increase became effective December 1, 2004.

Rate Stabilization Plan

On June 29, 2001, SPPC filed with the 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%. If granted, the typical residential monthly electric bill for a customer using 650 kilowatt-hours would have increased from approximately $47.12 to $60.12. On July 17, 2002, the CPUC approved the requested 2-cent per kilowatt-hour surcharge, subject to refund and interest pending the outcome of Phase Two. The increase of $10 million or 26% is 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 included a general rate case and requests the CPUC to reinstate the ECAC, which would allow SPPC to file for annual rate adjustments to reflect its actual costs for wholesale energy supplies. This request was for an additional overall increase in revenues of 17.1%, or $8.9 million annually.

On January 8, 2004, the CPUC issued Decision No. 04-01-027, which approved a settlement agreement that included an increase of $3.02 million or 5.8%, adopted a rate design methodology and re-instituted the ECAC mechanism. The rate increase was effective January 16, 2004.

FERC Matters

Sierra Pacific Power Company 2004 Transmission Rate Case

Nevada Power Company 2003 Transmission Rate Case

On September 11, 2003, the Utilities filed with the FERC revised rates for transmission service offered by NPC under Docket No. ER03-1328. The purpose of the filing is to update rates to reflect recent transmission additions and to improve rate design. On November 7, 2003, FERC accepted the revised tariff sheets, made rates effective on November 10, 2003, subject to refund, and established hearing procedures. The active participants in the proceeding reached a settlement in principle of all issues. The Certification of Uncontested Offer of Settlement was issued on June 14, 2004. The FERC issued an Order approving the uncontested settlement on July 8, 2004. Refunds were issued within thirty days as required by FERC.

Nevada Power Company

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Sierra Pacific Power Company

NOTE 4. INVESTMENTS IN SUBSIDIARIES AND OTHER PROPERTY

Investments in subsidiaries and other property consisted of (dollars in thousands):

Sierra Pacific Resources


	December 31,
	2005		2004
Investment in Tuscarora Gas Transmission Company	$	30,898	$	31,019
Cash Value-Life Insurance		13,281		12,967
Non-utility property of NEICO		4,948		5,486
NVPCT-I & NVPCT-III		5,841		5,841
Decatur/Gilmore/Cheyenne/Centennial		5,179		6,515
Other non-utility Property		2,624		2,768

	$	62,771	$	64,596

Nevada Power


	December 31,
	2005		2004
Cash Value-Life Insurance	$	13,281	$	12,967
Non-utility property of NEICO		4,948		5,486
NVPCT—I & NVPCT-III		5,841		5,841
Decatur/Gilmore/Cheyenne/Centennial		5,179		6,515

	$	29,249	$	30,809

Sierra Pacific Power


	December 31,
	2005		2004
Non-utility Property	$	842	$	999

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NOTE 5. JOINTLY OWNED FACILITIES

At December 31, 2005, NPC and SPPC owned the following undivided interests in jointly owned electric utility facilities:


									Construction
	%		Plant		Accumulated		Net Plant		Work in
Joint Facility	Owned		in Service		Depreciation		in Service		Progress
NPC
Navajo Facility		11.3	$	244,216	$	120,249	$	123,967	$	7,515
Reid Gardner No. 4		32.2		124,816		91,510		33,306		6,543

Total NPC			$	369,032	$	211,759	$	157,273	$	14,058
SPPC
Valmy Facility		50.0	$	286,582	$	158,174	$	128,408	$	3,078

The amounts for Navajo include NPC’s share of transmission systems, general plant equipment and NPC’s share of the jointly owned railroad which delivers coal to the plant. Each participant provides its own financing for all of these jointly owned facilities. NPC’s share of operating expenses for these facilities is included in the corresponding operating expenses in its Consolidated Statements of Operations.

NPC has an approximate 14% ownership in Mohave. Southern California Edison is the operating partner of Mohave. On December 31, 2005, Mohave ceased operations due to unresolved legal matters, as such approximately $27.2 million has been reclassified from Plant in Service to Other Regulatory assets as of December 31, 2005, and approximately $4 million remains in Plant in Service which represents transmission systems that have not been reclassified. See Note 14, Commitments and Contingencies for further discussion of Mohave.

SPPC and Idaho Power Company each own an undivided 50% interest in the Valmy generating station, with each company being responsible for financing its share of capital and operating costs. SPPC is the operator of the plant for both parties. SPPC’s share of direct operation and maintenance expenses for Valmy is included in its accompanying Consolidated Statements of Operations.

NOTE 6. SHORT-TERM BORROWINGS

Sierra Pacific Resources

NOTE 7. LONG-TERM DEBT

As of December 31, 2005 NPC’s, SPPC’s and SPR’s aggregate annual amount of maturities for long-term debt (including obligations related to capital leases) for the next five years is shown below (dollars in thousands):


							SPR Holding Co.
	NPC			SPPC			and Other Subs.		SPR Consolidated
2006	$	6,509		$	52,400		$	—	$	58,909
2007		5,950			2,400			—		8,350
2008		7,066			322,400			—		329,466
2009		184,638			420			—		185,058
2010		157,843			—			—		157,843

		362,006			377,620			—		739,626
Thereafter		1,863,508			617,250			659,142		3,139,900

		2,225,514			994,870			659,142		3,879,526
Unamortized Premium (Discount) Amount		(4,942	)		(666	)		2,113		(3,495	)

Total	$	2,220,572		$	994,204		$	661,255	$	3,876,031

The preceding table includes obligations related to capital lease obligations.

142

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

Nevada Power Company

General and Refunding Mortgage Notes, Series M

On January 18, 2006, NPC issued and sold $210 million of its 5.95% General and Refunding Mortgage Notes, Series M, due March 15, 2016. The Series M Notes were issued with registration rights. The proceeds of the issuance were immediately deposited in short-term investments. On February 10, 2006 the net proceeds of the issuance plus available cash were used to repay $210 million of NPC’s revolving credit facility, which was borrowed to finance the purchase of a 75% ownership interest in the Silverhawk Power Plant.

Amended Credit Facility

On November 4, 2005 NPC amended and restated its existing secured $350 million revolving credit facility, maturing in October 2007, reducing the fees on both the unused portion of the facility and on the amounts borrowed, increasing the size of the facility to $500 million, extending the maturity to November 2010 and changing the Administrative Agent for the facility to Wachovia Bank, National Association. The rate for outstanding loans and/or letters of credit under the revolving credit facility will be at either an applicable base rate (defined as the higher of the Prime rate and the Federal Funds rate plus one-half of one percent) or a Eurodollar rate plus a margin that varies based upon NPC’s credit rating by at least two of the three rating agencies (S&P, Moody’s and Fitch). Currently, the base rate is Prime, and NPC’s applicable base rate margin is zero. The Eurodollar margin is 0.875%. As of December 31, 2005 NPC had $58.4 million of letters of credit and had borrowed $150 million under the revolving credit facility. As of February 24, 2006, NPC had $54.6 million of letters of credit and had borrowed $275 million under the revolving credit facility.

The NPC Credit Agreement, places certain restrictions on debt incurrence, liens and dividends. These restrictions are discussed in Note 9, Debt Covenant Restrictions.

General and Refunding Mortgage Notes, Series L

On November 16, 2004, NPC issued and sold $250 million of its 5⅞% General and Refunding Mortgage Notes, Series L, due January 15, 2015. The Series L Notes, which were issued with registration rights, were exchanged for registered notes in August 2005.

The Series L Notes limit the amount of payments in respect of common stock dividends that NPC may pay to SPR, and limits NPC’s ability to incur additional indebtedness. These limitations are discussed in Note 9, Debt Covenant Restrictions.

General and Refunding Mortgage Notes, Series I

On April 7, 2004, NPC issued and sold $130 million of its 6¹/2% General and Refunding Mortgage Notes, Series I, due April 15, 2012. The Series I Notes, which were issued with registration rights, were exchanged for registered notes in October 2004.

The Series I Notes limit the amount of payments in respect of common stock dividends that NPC may pay to SPR, and limits NPC’s ability to incur additional indebtedness. These limitations are discussed in Note 9, Debt Covenant Restrictions.

143

General and Refunding Mortgage Bond, Series H

On December 4, 2003, NPC issued its General and Refunding Mortgage Bond, Series H, in the principal amount of $235 million, to an escrow agent in accordance with the Enron stay order. As the bonds remained in escrow, they were not recorded in Long-Term Debt on NPC’s balance sheet as of December 31, 2005. See Note 14, Commitments and Contingencies, for more information regarding the Enron litigation.

On February 10, 2004, in accordance with the terms of the Enron stay order, NPC deposited approximately $24 million into the escrow account which amount was deducted from the outstanding principal amount of the Series H Bond. Subsequently, on April 16, 2004, NPC deposited an additional $25 million to the escrow account for a total of $49 million, reducing the principal amount of the bond held in escrow to approximately $186 million. SPR, the Utilities and Enron entered into a settlement agreement on November 15, 2005. Final approval of the settlement was reached on January 25, 2006. As such, on January 27, 2006, NPC’s escrowed Series H bond was cancelled and returned to NPC. The bond may be used to support future issuances of general and refunding securities by NPC.

General and Refunding Mortgage Notes, Series G

On August 13, 2003, NPC issued and sold $350 million of its 9% General and Refunding Mortgage Notes, Series G, due 2013. The Series G Notes, which were issued with registration rights, were exchanged for registered notes in June 2004. The Series G Notes will mature August 15, 2013. On July 14, 2005, NPC redeemed $122,500,000 aggregate principal amount of the Series G Notes. This redemption constituted 35% of the principal amount outstanding. The Series G Notes were redeemed at a redemption price equal to $1,090.00 for each $1,000 note redeemed for a redemption premium in excess of the principal amount of approximately $11 million. In accordance with SFAS 71, Accounting for the Effects of Certain Types of Regulation, the redemption premium to redeem the debt will be amortized over the original term of the debt. NPC paid for the redemption with the proceeds of an equity contribution of approximately $230.5 million from SPR, as discussed in Note 6, Short-Term Borrowings.

General and Refunding Mortgage Notes, Series E

On October 29, 2002, NPC issued and sold $250 million of its 10⅞% General and Refunding Mortgage Notes, Series E, due 2009. The Series E Notes, which were issued with registration rights, were exchanged for registered notes in January 2003. The Series E Notes will mature October 15, 2009. On July 14, 2005, NPC redeemed $87,500,000 aggregate principal amount of the Series E Notes. This redemption constituted 35% of the principal amount outstanding. The Series E Notes were redeemed at a redemption price equal to $1,108.75 for each $1,000 note redeemed for a redemption premium in excess of the principal amount of approximately $9.5 million. In accordance with SFAS 71, Accounting for the Effects of Certain Types of Regulation, the redemption premium to redeem the debt will be amortized over the original term of the debt. NPC paid for the redemption with the proceeds of an equity contribution of approximately $230.5 million from SPR, as discussed in Note 6, Short-Term Borrowings.

Preferred Trust Securities

NVP Capital I Trust

On April 2, 1997, NVP Capital I (Trust), a wholly owned subsidiary of NPC, issued 4,754,860, 8.2% preferred trust securities (QUIPS) at $25 per security. NPC owns all of the Series A common securities, 147,058 shares issued by the Trust for $3.7 million. The QUIPS and the common securities represent undivided beneficial ownership interests in the assets of the Trust, a statutory business trust formed under the laws of the state of Delaware. The existence of the Trust is for the sole purpose of issuing the QUIPS and the common securities and using the proceeds thereof to purchase from NPC its 8.2% Junior Subordinated Deferrable Interest Debentures (QUIDS) due March 31, 2037, extendible to March 31, 2046, under certain conditions, in a principal amount of $122.6 million. FIN 46(R) requires that the Trust be deconsolidated. As such, the Trust Preferred Securities are no longer consolidated with NPC and the Junior Subordinated Debt is now presented as Long-Term Debt.

Holders of the Series A QUIPS are entitled to receive preferential cumulative cash distributions accruing from the date of original issuance and payable quarterly on the last day of March, June, September and December of each year. Interest payments made by NPC in respect of the QUIDS are sufficient to provide the trust with funds to pay the required cash distribution on the QUIPS and the common securities of the trust. The Series A QUIPS are subject to mandatory redemption, in whole or in part, upon repayment of the Series A QUIDS at maturity or their earlier redemption in an amount equal to the amount of related Series A QUIDS maturing or being redeemed. The QUIPS are redeemable at $25 per preferred security plus accumulated and unpaid distributions thereon to the date of redemption.

144

NVP Capital III Trust

In October 1998, NVP Capital III (Trust), a wholly-owned subsidiary of NPC, issued 2,800,000, 7.75% Cumulative Trust Issued Preferred Securities (TIPS) at $25 per security. NPC owns the entire common securities, 86,598 shares issued by the Trust for $2.2 million. The TIPS and the common securities represent undivided beneficial ownership interests in the assets of the Trust, a statutory business trust formed under the laws of the state of Delaware. The existence of the Trust is for the sole purpose of issuing the TIPS and the common securities and using the proceeds thereof to purchase from NPC its 7.75% Junior Subordinated Deferrable Interest Debentures due September 30, 2038, extendible to September 30, 2047, under certain conditions, in a principal amount of $72.2 million. FIN 46(R) requires that the Trust be deconsolidated. As such, the Trust Preferred Securities are no longer consolidated with NPC and the Junior Subordinated Debt is now presented as Long-Term Debt.

Holders of the TIPS are entitled to receive preferential cumulative cash distributions accruing from the date of original issuance and payable quarterly on the last day of March, June, September and December of each year. Interest payments by NPC in respect of the Junior Subordinated Deferrable Interest Debentures are sufficient to provide the trust with funds to pay the required cash distributions on the TIPS and the common securities of the trust. The TIPS are subject to mandatory redemption, in whole or in part, upon repayment of the deferrable interest debentures at maturity or their earlier redemption in an amount equal to the amount of related deferrable interest debentures maturing or being redeemed. The TIPS are redeemable at $25 per preferred security plus accumulated and unpaid distributions thereon to the date of redemption.

Sierra Pacific Power Company

Redemption of Indebtedness

Amended Credit Facility

On November 4, 2005, SPPC amended and restated its existing secured $50 million revolving credit facility, maturing in October 2007, reducing the fees on both the unused portion of the facility, and on the amounts borrowed, increasing the size of the facility to $250 million, extending the maturity to November 2010 and changing the Administrative Agent for the facility to Wachovia Bank, National Association. The rate for outstanding loans and/or letters of credit under the revolving credit facility will be at either an applicable base rate (defined as the higher of the Prime rate and the Federal Funds rate plus one-half of one percent) or a Eurodollar rate, plus a margin that varies based upon SPPC’s credit rating by at least two of the three rating agencies (S&P, Moody’s and Fitch). Currently, the base rate is Prime and SPPC’s applicable base rate margin is zero. The current Eurodollar margin is 0.875%. As of December 31, 2005 SPPC had $3.8 million of letters of credit and no direct borrowings under the revolving credit facility. As of February 24, 2006, SPPC had $9 million of letters of credit and $25 million borrowed under the revolving credit facility.

The SPPC Credit Agreement provides for an event of default if there is a failure under other financing agreements of that entity to meet payment terms or to observe other covenants that would result in an acceleration of payments due.

The SPPC Credit Agreement, similar to SPPC’s Series H Notes, places certain restrictions on debt incurrence, liens and dividends. These limitations are discussed in Note 9, Debt Covenant Restrictions.

Water Facilities Refunding Revenue Bonds

145

On May 3, 2004, 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 one year 7.50% term rate to a 5.0% term rate for the period of May 3, 2004 up to and including July 1, 2009. The bonds will be subject to remarketing on July 1, 2009. 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 3, 2004 up to and including July 1, 2009, SPPC’s payment and purchase obligations in respect of the bonds are secured by SPPC’s $80 million General and Refunding Mortgage Note, Series J, due 2009.

General and Refunding Mortgage Notes, Series H

On April 16, 2004, SPPC issued and sold $100 million of its 6¹/4% General and Refunding Mortgage Notes, Series H, due April 15, 2012. The Series H Notes, which were issued with registration rights, were exchanged for registered notes in October 2004.

The Series H Notes place certain restrictions on debt incurrence, liens and dividends. These restrictions are discussed in Note 9, Debt Covenant Restrictions. If SPPC’s Series H Notes are upgraded to investment grade by both Moody’s and S&P, these restrictions will be suspended and will no longer be in effect so long as the Series H Notes remain investment grade.

General and Refunding Mortgage Bond, Series E

On December 4, 2003, SPPC issued its General and Refunding Mortgage Bond, Series E, in the principal amount of $103 million, to an escrow agent in accordance with the Enron stay order. As the bonds remained in escrow, they were not recorded in long-term debt on SPPC’s balance sheet as of December 31, 2005. See Note 14, Commitments and Contingencies, for more information regarding the Enron litigation.

On February 10, 2004, in accordance with the terms of the Enron stay order, SPPC deposited approximately $11 million into the escrow account which amount was deducted from the outstanding principal amount of the Series E Bond, reducing the principal amount of the bonds to approximately $92 million. SPR, the Utilities and Enron entered into a settlement agreement on November 15, 2005. Final approval of the settlement was reached on January 25, 2006. As such, on January 27, 2006, SPPC’s escrowed Series E bond was cancelled and returned to SPPC. The bond may be used to support future issuances of general and refunding securities by SPPC.

Sierra Pacific Resources

SPR Premium Income Equity Securities (PIES)

On November 16 and 21, 2001, SPR issued an aggregate of $345 million senior unsecured notes in connection with the public offering of 6,900,000 of its Premium Income Equity Securities (PIES). Each PIES unit consisted of a forward stock purchase contract and a senior unsecured note issued by SPR with a face amount of $50.

Each holder of PIES was entitled to receive quarterly payments consisting of purchase contract adjustment payments and interest on the senior unsecured notes. The PIES had a combined rate of 9.0%, which was comprised of the coupon on the senior note of 7.93% and the stated rate of the purchase contract adjustment payments of 1.07%.

As detailed below under PIES Transactions, as of December 31, 2005 there are no PIES outstanding. However, the 7.803%, $99,142,000 Senior Notes remain outstanding.

PIES Conversion Features

Each stock purchase contract obligated the holder to purchase SPR common stock on or before November 15, 2005, the Purchase Contract Settlement Date. The number of shares each investor was entitled to receive depended on the average closing price of SPR common stock over a 20-day trading period prior to the settlement.

PIES Transactions

On February 5, 2003, SPR acquired 2,095,650 of PIES including approximately $104.8 million of 7.93% Senior Notes due 2007 that are a component of the PIES, in exchange for 13,662,393 shares of its common stock in five privately-negotiated transactions exempt from the registration requirements of the Securities Act of 1933.

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On April 15, 2005, SPR commenced an offer to exchange its previously existing PIES (“Old PIES”) for newly issued PIES (“New PIES”) plus an exchange fee of $0.125 in cash for each Old PIES tendered. On May 24, 2005, the tender offer was completed with 1,982,822 or about 41% of the 4,804,350 Old PIES outstanding tendered for exchange. The remaining 2,821,528 Old PIES remained outstanding. The New PIES were similar to the Old PIES except that the New PIES: (i) allow for the remarketing of the senior notes that are associated with the New PIES prior to the earliest remarketing date for the Old PIES, (ii) provide for more flexible remarketing terms, and (iii) allowed certain terms of the senior notes to be modified upon their remarketing, including the maturity date of the senior notes, the redemption provisions, the interest payment dates and the addition of covenants applicable to the senior notes.

On May 24, 2005, as a component of the New PIES, SPR issued $99,142,000 aggregate principal amount of 7.93% Senior Notes, due 2007. These senior notes replaced the notes associated with the Old PIES. SPR successfully remarketed these notes on June 14, 2005. In connection with the remarketing, the interest rate of the senior notes issued in connection with the New PIES was reset to 7.803% per annum, effective on and after June 14, 2005. The remarketed senior notes will mature on June 15, 2012. The proceeds of the remarketing of the senior notes were to be used to purchase U.S. treasury securities and to pay the fee of the remarketing agents. The U.S. treasury securities served as substitute collateral for the senior notes component of the New PIES to secure holders’ obligations under the related forward purchase contracts. The proceeds of the U.S. treasury securities were used at maturity to fulfill holders’ payment obligations under the related forward purchase contracts on November 15, 2005, and to pay the aggregate amount of remaining interest payments to the holders of the New PIES through November 15, 2005.

On August 10, 2005, the remaining $141,076,000 aggregate principal amount of its 7.93% Senior Notes associated with the Old PIES were remarketed. On August 15, 2005, SPR used a portion of the proceeds from the $225 million 6.75% Senior Notes (described below under the heading Private Placement) to purchase all of the 7.93% Senior Notes that were remarketed. As with the May 2005 remarketing of the 7.93% Senior Notes, the proceeds of this remarketing were used to purchase U.S. treasury securities and to pay the fee of the remarketing agents. The U.S. treasury securities were to serve as substitute collateral for the senior notes component of the Old PIES to secure holders’ obligations under the related forward purchase contracts. The proceeds of the U.S. treasury securities were used at maturity to fulfill holders’ payment obligations under the related forward purchase contracts on November 15, 2005, and to pay the aggregate amount of remaining interest payments to the holders of the Old PIES through November 15, 2005.

On November 15, 2005, the Purchase Contract Settlement Date for the Old PIES and New PIES, 3.6101 shares per forward purchase contract were exchanged for a total of 17,344,183 shares of common stock issued to the holders of the Old PIES and New PIES.

Private Placement

SPR Convertible Notes

On February 14, 2003, SPR issued and sold $300 million of its 7.25% Convertible Notes due 2010 (the “Convertible Notes”). The Convertible Notes were issued with registration rights. On August 11, 2003, SPR obtained shareholder approval to issue up to 42,736,920 additional shares of SPR’s common stock in lieu of paying the cash payment component upon conversion of the Convertible Notes.

On August 3, 2005, SPR announced an offer to pay a cash premium to induce holders of the Convertible Notes to convert their Convertible Notes to shares of SPR common stock. The conversion offer, which was extended to September 2, 2005, was accepted by 100% of the holders of the Convertible Notes. Under the terms of the offer, for each $1,000 in liquidation amount of Convertible Notes tendered, holders received the conversion consideration and 219.1637 shares of common stock. The cash consideration offered was an amount equal to $180 per $1,000 principal amount of Convertible Notes validly surrendered for conversion plus an amount equivalent to the interest that would have accrued thereon from and after August 14, 2005 (which was the last interest payment date on the Convertible Notes prior to the expiration of the offer). On September 8, 2005, 65,749,096 shares of common stock, plus cash in lieu of fractional shares and an aggregate of $54 million in cash consideration were paid to the holders in exchange for the Convertible Notes. In accordance with SFAS No. 84, “Induced Conversion of Convertible Debt,” the $54 million cash payment was expensed during the third quarter of 2005.

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SPR Senior Unsecured Notes

On March 19, 2004, SPR issued and sold $335 million 8⅝% Senior Unsecured Notes due March 15, 2014. The Senior Unsecured Notes, which were issued with registration rights, were exchanged for registered notes in October 2004.

The terms of the SPR Senior Notes place certain restrictions on debt incurrence, liens and dividends. These restrictions are discussed in Note 9, Debt Covenant Restrictions. If these Notes are upgraded to investment grade by both Moody’s and S&P, these restrictions will be suspended and will no longer be in effect so long as the applicable series of Notes remains investment grade.

SPR Floating Rate Notes Exchange

In January 2003, SPR acquired $8.75 million aggregate principal amount of its Floating Rate Notes due April 20, 2003, in exchange for 1,295,211 million shares of its common stock, in two privately negotiated transactions exempt from the registration requirements of the Securities Act of 1933.

Sierra Pacific Communications

Sierra Pacific Communications (SPC) was formed as a Nevada corporation in 1999 to identify and develop business opportunities in telecommunications services and infrastructure. SPC entered 2004 with two distinct business areas. The first involved a fiber optic system extending between Salt Lake City, Utah and Sacramento, California (the Long Haul System or System) and the second was the Metro Area Network (MAN) business in Las Vegas and Reno, Nevada.

SPC formed a limited liability company with Touch America, Inc. (TAI) named Sierra Touch America LLC (STA) in 2000, to further the development of the Long Haul System. The project sustained significant cost overruns and several complaints and mechanic’s liens were filed against several parties, including STA and SPC, by System contractors and subcontractors. In September 2002, SPC and TAI entered into an agreement whereby SPC redeemed its membership interest in STA and acquired fiber optic assets in the System and an indemnity for System liabilities, for a total purchase price of $48.5 million. SPC also executed a $35 million promissory note in favor of STA. TAI remained as the sole member of STA. In June 2003, TAI and all its subsidiaries (including STA) filed a petition for Chapter 11 bankruptcy protection. SPC pursued litigation in TAI’s bankruptcy case to resolve its obligations to, and claims against, TAI and its affiliates. After more than a year of litigation and extensive negotiations among various parties, SPC entered into a settlement agreement dated July 28, 2004, with TAI, STA, and AT&T. The bankruptcy court approved TAI’s plan of liquidation and the settlement agreement by order dated October 6, 2004.

Under the terms of the settlement agreement, SPC paid $10 million and granted STA three ducts plus SPC’s portion of fiber in the main cable, in satisfaction of SPC’s remaining obligations to STA on the $35 million promissory note and an additional $2.3 million toward settlement of the various complaints and mechanic’s liens mentioned above.

NOTE 8. FAIR VALUE OF FINANCIAL INSTRUMENTS

The December 31, 2005, carrying amount of cash and cash equivalents, current assets, accounts receivable, accounts payable and current liabilities approximates fair value due to the short-term nature of these instruments.

The total fair value of NPC’s consolidated long-term debt at December 31, 2005, is estimated to be $2.2 billion (excluding current portion) based on quoted market prices for the same or similar issues or on the current rates offered to NPC for debt of the same remaining maturities. The total fair value (excluding current portion) was estimated to be $2.4 billion at December 31, 2004.

The total fair value of SPPC’s consolidated long-term debt at December 31, 2005, is estimated to be $1.0 billion (excluding current portion) based on quoted market prices for the same or similar issues or on the current rates offered to SPPC for debt of the same remaining maturities. The total fair value (excluding current portion) was estimated to be $1.0 billion as of December 31, 2004.

The total fair value of SPR’s consolidated long-term debt at December 31, 2005 is estimated to be $3.9 billion (excluding current portion) based on quoted market prices for the same or similar issues or on the current rates offered to SPR for debt of the same remaining maturities. The total fair value (excluding current portion) was estimated to be $4.6 billion as of December 31, 2004.

NOTE 9. DEBT COVENANT 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 a federal statutory limitation on the payment of dividends. Certain agreements entered into by the Utilities set restrictions on certain restricted payments, including the amount of dividends they may declare and pay and restrict the

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circumstances under which such dividends may be declared and paid. In addition, covenants of certain SPR, NPC and SPPC debt limit the company’s ability to incur additional debt. Material restrictions on dividends and on debt incurrence, contained in SPR’s and the Utilities’ financing agreements are summarized below. All securities issued by NPC and SPPC must be authorized by the PUCN.

Limits on Restricted Payments

Sierra Pacific Resources

SPR has paid no dividends since 2002. Dividends are considered periodically by SPR’s Board of Directors and are subject to factors that ordinarily affect dividend policy, such as current and prospective earnings, current and prospective business conditions, regulatory factors, SPR’s financial conditions and other matters within the discretion of the Board, as well as dividend restrictions set forth in SPR’s 8 5/8% Senior Notes due 2014, 7.803% Senior Notes due 2012 and 6.75% Senior Notes due 2017. The Board will continue to review the factors described above on a periodic basis to determine if and when it would be prudent to declare a dividend on SPR’s Common Stock. There is no guarantee that dividends will be paid in the future, or that, if paid, the dividends will be paid at the same amount or with the same frequency as in the past.

Certain of SPR debt contain covenants that limit restricted payments, which include dividends. If SPR were to resume paying a dividend, these restrictive covenants must first be satisfied. SPR must be able to incur additional indebtedness, as determined under a 2 to 1 fixed charge coverage ratio test. If that condition is met, the amount of dividends that can be paid is less than (i) 50% of the Consolidated Net Income for SPR for the period from April 1, 2004 to the end of the most recently ended fiscal quarter for which internal financial statements are available at the time of such payment, plus (ii) 100% of SPR’s net cash proceeds from the issuance or sale of its equity interests, including common stock. Since SPR meets the 2 to 1 fixed charge coverage ratio test, it could dividend up to a maximum of $321 million as of December 31, 2005. Under its most restrictive covenants, SPR can additionally pay up to an aggregate of $50 million in dividends during the period from April 1, 2004 to the end of the most recently ended fiscal quarter.

Material Dividend Restrictions Applicable to Nevada Power Company

•

The following notes and credit agreement limit the amount of payments in respect of common stock that NPC may make to SPR:

	o		NPC’s 5⅞% General and Refunding Mortgage Notes, Series L, due 2015, which were issued on November 16, 2004,

	o		NPC’s Revolving Credit Agreement, which was amended and restated on November 4, 2005.

	o		NPC’s 6½% General and Refunding Mortgage Notes, Series I, due 2012, which were issued on April 7, 2004,

	o		NPC’s 9% General and Refunding Mortgage Notes, Series G, due 2013, which were issued on August 13, 2003, and

	o		NPC’s 10⅞% General and Refunding Mortgage Notes, Series E, due 2009, which were issued on October 29, 2002.

However, the dividend payment limitation does not apply to payments by NPC to enable SPR to pay its reasonable fees and expenses, provided that:

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

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

	o		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 various series of Notes, and the Revolving Credit Agreement also permit NPC to make payments to SPR in excess of the amounts payable discussed above in an aggregate amount not to exceed:

	o		under the Series E Notes, $15 million from the date of the issuance of the Series E Notes, and

	o		under the Series G, Series I and Series L Notes, $25 million from the date of the issuance of the Series G, Series I and Series L Notes, respectively.

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Under the Second Amended and Restated Revolving Credit Facility, $50 million from the date of the establishment of the Amended and Restated Revolving Credit Facility.

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:

	i.		there are no defaults or events of default with respect to the Series E, G, I and L Notes or the Revolving NPC Credit Agreement,

	ii.		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 to 1, and

	iii.		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 applicable series of Notes, the Bond or Credit Agreement, 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.

			Since NPC meets (i) and (ii) above, NPC would be able to pay up to a maximum of $359 million to SPR as of December 31, 2005.

			If NPC’s Series E Notes, Series G Notes, Series I Notes, or Series L 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 applicable series of Notes remains investment grade.

Material Dividend Restrictions Applicable to Sierra Pacific Power Company

•

The following notes and credit facility limit the amount of payments in respect of common stock that SPPC may make to SPR:

	o		SPPC’s Revolving Credit Agreement, which was amended and restated on November 4, 2005, and

	o		SPPC’s 6 ¹/4 % General and Refunding Mortgage Notes, Series H, due 2012, which were issued on April 16, 2004.

However, the dividend payment limitation does not apply to payments by SPPC to enable SPR to pay its reasonable fees and expenses provided that:

	o		those payments do not exceed $50 million for any one calendar year,

	o		those payments comply with any regulatory restrictions then applicable to SPPC, and

	o		the ratio of consolidated cash flow to fixed charges for SPPC’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 H Notes also permit SPPC to make payments to SPR in excess of the amounts payable discussed above in an aggregate amount not to exceed $25 million from the date of the issuance of the Series H Notes.

			The terms of the Amended and Restated Revolving Credit Facility also permit SPPC to make payments to SPR in excess of the amounts payable above in an aggregate amount not to exceed $50 million from the date of the establishment of the Amended and Restated Revolving Credit Facility.

			In addition, SPPC 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:

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	i.		there are no defaults or events of default with respect to the Series H Notes or the SPPC Revolving Credit Agreement,

	ii.		SPPC has a ratio of consolidated cash flow to fixed charges for SPPC’s most recently ended four full fiscal quarters immediately preceding the payment date of at least 2 to 1, and

	iii.		the total amount of such dividends is less than:

	•		the sum of 50% of SPPC’s consolidated net income measured on a quarterly basis cumulative of all quarters from the date of issuance of the Series H Notes, the establishment of the Revolving Credit Agreement or the issuance of the Series E Bond, plus

	•		100% of SPPC’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 SPPC, plus

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

	•		the fair market value of SPPC’s investment in certain subsidiaries.

			Since SPPC meets (i) and (ii) above, SPPC would be able to pay up to a maximum of $22 million to SPR as of December 31, 2005.

			If SPPC’s Series H Notes are upgraded to investment grade by both Moody’s and S&P, these restrictions will be suspended and will no longer be in effect so long as the applicable series of Notes remain investment grade.

Dividend Restrictions Applicable to the Utilities

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 their capital account. Although the meaning of this provision is unclear, the Utilities believe that the Federal Power Act restriction, as applied to their particular circumstances, would not be construed or applied by the FERC to prohibit the payment of dividends for lawful and legitimate business purposes from current year earnings, or in the absence of current year earnings, from other/additional paid-in capital accounts. If, however, the FERC were to interpret this provision differently, the ability of the Utilities to pay dividends to SPR could be jeopardized.

Limitations on Indebtedness

Sierra Pacific Resources

Certain debt of SPR places restrictions on debt incurrence, liens and dividends, unless, at the time the debt is incurred, the ratio of consolidated cash flow to fixed charges for SPR’s most recently ended four quarter period on a pro forma basis is at least 2 to 1. Under this covenant restriction, as of December 31, 2005, SPR would be allowed to incur up to $482 million of additional indebtedness on a consolidated basis.

Notwithstanding this restriction, under the terms of the debt, SPR would still be permitted to incur debt including, but not limited to, obligations incurred to finance property construction or improvement, certain intercompany indebtedness, or indebtedness incurred to finance capital expenditures, pursuant to the two utilities’ integrated resource plans. NPC and SPPC would also be permitted to incur a combined total of up to $500 million in indebtedness and letters of credit under their respective revolving credit facilities.

If the debt is upgraded to investment grade by both Moody’s and S&P, these restrictions will be suspended and will no longer be in effect so long as the applicable series of Notes remains investment grade.

Nevada Power Company

Certain debt of NPC places restrictions on debt incurrence, liens and dividends, unless, 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. Under this covenant restriction, as of December 31, 2005, NPC would be allowed to incur $639 million of additional indebtedness. However, due to the terms of the SPR debt described above, NPC’s and SPPC’s combined debt limit is restricted to the $482 million of additional indebtedness SPR could incur on a consolidated basis.

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Under the terms of NPC’s debt, NPC would also be permitted to incur debt, including, but not limited to, obligations incurred to finance property construction or improvements, certain intercompany indebtedness, certain letters of credit indebtedness, or indebtedness incurred to finance capital expenditures, pursuant to NPC’s 2003 Integrated Resource Plan.

If the debt containing these covenants is 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 applicable debt remains investment grade.

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.

Sierra Pacific Power Company

Certain debt of SPPC places restrictions on debt incurrence, liens and dividends, unless, at the time the debt is incurred, the ratio of consolidated cash flow to fixed charges for SPPC’s most recently ended four quarter period on a pro forma basis is at least 2 to 1. Under this covenant restriction, as of December 31, 2005, SPPC would be allowed to incur up to $494 million of additional indebtedness on a consolidated basis. However, due to the terms of the SPR debt described above, NPC’s and SPPC’s combined debt limit is restricted to the $482 million of additional indebtedness SPR could incur on a consolidated basis.

Under the terms of SPPC’s debt, SPPC would also be permitted to incur debt including, but not limited to, obligations incurred to finance property construction or improvements, certain intercompany indebtedness, certain letters of credit indebtedness, or indebtedness incurred to finance capital expenditures, pursuant to SPPC’s 2004 Integrated Resource Plan.

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’ current objective in using derivatives is primarily to reduce exposure to energy price risk. Energy price risks result from activities that include the generation and procurement of power and the procurement 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.

The following table shows the amounts recorded on the Consolidated Balance Sheets of SPR, NPC and SPPC at December 31, 2005 and 2004, due to the fair value of the derivatives. 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, once realized (dollars in millions):


	2005									2004
	SPR			NPC			SPPC			SPR		NPC		SPPC
Risk management assets	$	50.2		$	22.4		$	27.8		$	14.6	$	5.1	$	9.5
Risk management liabilities	$	16.6		$	10.1		$	6.5		$	9.9	$	3.6	$	6.3
Risk management regulatory assets (liabilities)		($15.6	)		($.6	)		($15.0	)	$	6.7	$	3.6	$	3.1

The increase in risk management assets as of December 31, 2005 compared to December 31, 2004 is due to favorable positions on natural gas options held by the Utilities as a result of increasing prices.

Also included in risk management assets were $14.1 million, $7.7 million, and $6.4 million in payments for gas options for SPR, NPC, and SPPC, respectively and $4.0 million in payments for NPC’s electrical call options at December 31, 2005.

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In connection with SPR’s issuance of its Convertible Notes on February 14, 2003 (see Note 7, 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 EITF 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 and until August 11, 2003, the change in the fair value was recognized in earnings in the period of the change.

On August 11, 2003, SPR obtained shareholder approval to issue up to 42,736,920 additional shares of SPR’s common stock in lieu of paying the cash portion of the conversion price. Before SPR received shareholder approval, holders of the Convertible Notes were entitled to receive both shares of common stock and cash upon conversion on their notes. Issue No. 00-19 of the EITF of the FASB, “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 applicable provisions of EITF Issue No. 00-19 are met. Management believed that all such applicable provisions were met. Accordingly, the fair value of the derivative, $118 million on the date of the shareholder vote, was reclassified to equity at that date. The fair value of this option was determined using the closing stock price, which was $4.68 as of August 11, 2003, the strike price for conversion ($4.5628), a measurement for the volatility of the stock price and the time value of money. The August 11, 2003 valuation resulted in an unrealized gain of $61.5 million in the third quarter of 2003. The valuations at March 31, 2003, and June 30, 2003, resulted in an unrealized gain of $15.9 million in the first quarter and an unrealized loss of $123.5 million in the second quarter. The net impact of changes in market value was an unrealized loss of $46.1 million for the year ended December 31, 2003. EITF Issue No. 00-19 also indicates that subsequent changes in fair value should not be recognized as long as the derivative remains classified in equity. Accordingly, no unrealized gains or losses were recorded after August 11, 2003.

NOTE 11. INCOME TAXES (BENEFITS)

Sierra Pacific Resources

The following reflects the composition of taxes on income from continuing operations (dollars in thousands):


	2005			2004			2003
Provision for income taxes
Currently (receivable) payable:
Federal	$	3,159		$	(161	)	$	15,481
State		—			—			—

Total currently payable		3,159			(161	)		15,481


Deferred, net
Federal		43,888			27,029			(54,329	)
State		1,688			(775	)		—

Total deferred, net		45,576			26,254			(54,329	)


Amortization of excess deferred taxes		(2,123	)		(2,196	)		(2,196	)

Amortization of investment tax credits		(3,439	)		(3,266	)		(3,163	)


Total provision (benefit) for income taxes:	$	43,173		$	20,631		$	(44,207	)


Income statement classification of provision (benefit) for income taxes
Operating income	$	39,240		$	24,443		$	(57,008	)
Other income		3,933			(3,812	)		12,801

Total	$	43,173		$	20,631		$	(44,207	)

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The total income tax provision differs from amounts computed by applying the federal statutory tax rate to income before income taxes for the following reasons (dollars in thousands):


	2005			2004			2003
Income/(loss) from continuing operations	$	86,240		$	35,635		$	(104,160	)
Total income tax expense (benefit)		43,173			20,631			(44,207	)

Pretax income/(loss)		129,413			56,266			(148,367	)
Statutory tax rate		35	%		35	%		35	%

Federal income tax expense (benefit) at statutory rate		45,295			19,693			(51,928	)
Depreciation related to difference in costs basis for tax purposes		4,559			4,834			4,225
Allowance for funds used during construction — equity		(7,113	)		(2,082	)		(2,018	)
ITC amortization		(3,439	)		(3,266	)		(3,163	)
Goodwill		2,230			6,332			—
Convertible bond mark to market and interest accretion		2,132			2,786			18,291
Pension benefit plan		(945	)		(3,684	)		(1,113	)
Other — net		454			(632	)		(5,370	)

Provision for income taxes before effect of income tax settlements	$	43,173		$	23,981		$	(41,076	)


Effective tax rate before effect of income tax settlements		33.4	%		42.6	%		27.7	%

Effects of income tax settlements		—			(3,350	)		(3,131	)

Provision for income taxes	$	43,173		$	20,631		$	(44,207	)

Effective tax rate		33.4	%		36.7	%		29.8	%

As a large corporate taxpayer, the SPR consolidated group’s tax returns are examined by the Internal Revenue Service (IRS) on a regular basis. During 2003 and the first quarter of 2004, SPR reached tentative agreements with the IRS for certain matters. As a result of the tentative agreements, SPR recognized tax benefits which increased net income by approximately $3.1 million in 2003 and $3.4 million in 2004. SPR believes that it does not have any contingent income tax liabilities; therefore no income tax reserves have been established as of December 31, 2005.

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The net deferred income tax liability consists of deferred income tax liabilities less related deferred income tax assets, as shown (dollars in thousands):


	2005			2004
Deferred income tax assets
Net operating loss and credit carryovers	$	247,135		$	331,434
Employee benefit plans		10,190			(6,406	)
Customer advances		59,522			49,946
Gross-ups received on contribution in aid of construction and customer advances		25,862			20,068
Deferred revenues		11,303			19,754
Provision for contract termination		63,427			123,627
Other		19,765			14,831

Subtotal		437,204			553,254
Deferred income tax assets associated with regulatory matters
Excess deferred income taxes		17,426			17,852
Unamortized investment tax credit		20,798			22,723

Subtotal		38,224			40,575

Total deferred income tax assets before valuation allowance		475,428			593,829
Valuation allowance		(984	)		(925	)

Total deferred income tax assets after valuation allowance	$	474,444		$	592,904


Deferred income tax liabilities
Excess of tax depreciation over book depreciation	$	560,702		$	591,874
Deferred energy		180,488			232,930
Regulatory assets		20,139			23,286
Other		44,819			32,308

Subtotal		806,148			880,398
Deferred income tax liabilities associated with regulatory matters
Tax benefits flowed through to customers		249,262			279,767

Total deferred income tax liability	$	1,055,410		$	1,160,165


Net deferred income tax liability	$	369,928		$	328,069
Net deferred income tax liability associated with regulatory matters		211,038			239,192

Total net deferred income tax liability	$	580,966		$	567,261

SPR’s balance sheets contain a net regulatory asset of $211.0 million at December 31, 2005 and $239.2 million at December 31, 2004. The regulatory asset consists of future revenue to be received from customers due to flow-through of the tax benefits of temporary differences and goodwill recognized from the merger of NPC and SPR. Offset against these amounts are future revenues to be refunded to customers (regulatory liabilities). The regulatory liabilities consist of temporary differences for liberalized depreciation at rates in excess of current rates and unamortized investment tax credits. The regulatory liability for temporary differences related to liberalized depreciation will continue to be amortized using the average rate assumption method required by the Tax Reform Act of 1986. The regulatory liability for temporary differences caused by the investment tax credit will be amortized ratably in the same fashion as the accumulated deferred investment credit.

155

As reflected in SPR’s balance sheet (dollars in thousands):


	2005		2004
Tax benefits flowed through to customers
Related to property	$	98,330	$	114,854
Related to goodwill		150,931		164,913

Regulatory tax asset		249,261		279,767

Liberalized depreciation at rates in excess of current rates		17,426		17,852
Unamortized investment tax credits		20,798		22,723

Regulatory tax liability		38,224		40,575

Net regulatory tax asset	$	211,037	$	239,192

SPR and its subsidiaries file a consolidated federal income tax return. Current income taxes are allocated based on SPR’s and each subsidiaries respective taxable income or loss and investment tax credits as if each subsidiary filed a separate return. SPR owes SPPC $46.1 million and NPC $42.2 million in inter-company tax payments. Additionally, per the Company’s tax sharing agreement, SPR has a current tax receivable from SPPC of $49.7 million.


							Expiration
	Deferred Tax Asset		Valuation Allowance		Net Deferred Tax Asset		Period
Federal NOL	$	241,295	$	—	$	241,295		2020-2023
State NOLs		1,433		—		1,433		2006-2013
Alternative minimum tax credit		3,159				3,159	indefinite
Arizona coal credits		1,248		984		264		2006-2010

Total	$	247,135	$	984	$	246,151

At December 31, 2005, SPR has gross federal and state net operating loss carry-forwards of $689.4 million and $17.7 million, respectively.

Considering all positive and negative evidence regarding the utilization of SPR’s deferred tax assets, it has been determined that SPR is more-likely-than-not to realize all recorded deferred tax assets, except for the Arizona coal credits. As such, these Arizona coal credits represent the only valuation allowance that has been recorded as of December 31, 2005.

156

Nevada Power Company

The following reflects the composition of taxes on income (dollars in thousands):


	2005			2004			2003
Provision for income taxes
Currently (receivable) payable:
Federal	$	3,159		$	6		$	32,612
State		—			—			—

Total currently payable		3,159			6			32,612

Deferred, net
Federal		63,873			58,762			(31,097	)
State		(449	)		(67	)		—

Total deferred, net		63,424			58,695			(31,097	)

Amortization of excess deferred taxes		(778	)		(499	)		(499	)

Amortization of investment tax credits		(1,810	)		(1,630	)		(1,630	)


Total provision (benefit) for income taxes:	$	63,995		$	56,572		$	(614	)


Income statement classification of provision (benefit) for income taxes
Operating income	$	46,425		$	45,135		$	(12,734	)
Other income		17,570			11,437			12,120

Total	$	63,995		$	56,572		$	(614	)

The total income tax provision differs from amounts computed by applying the federal statutory tax rate to income before income taxes for the following reasons (dollars in thousands):


	2005			2004			2003
Income from continuing operations	$	132,734		$	104,312		$	19,277
Total income tax expense (benefits)		63,995			56,572			(614	)

Pretax income		196,729			160,884			18,663
Statutory tax rate		35	%		35	%		35	%

Federal income tax expense at statutory rate		68,855			56,309			6,532
Depreciation related to difference in cost basis for tax purposes		1,880			2,144			1,431
Allowance for funds used during construction — equity		(6,539	)		(1,481	)		(996	)
ITC amortization		(1,810	)		(1,630	)		(1,630	)
Goodwill		1,386			1,732			—
Other — net		223			(502	)		(525	)

Provision for income taxes before effect of income tax settlements	$	63,995		$	56,572		$	4,812


Effective tax rate before effects of income tax settlements		32.5	%		35.2	%		25.8	%

Effects of income tax settlements		—			—			(5,426	)

Provision for income taxes	$	63,995		$	56,572		$	(614	)

Effective tax rate		32.5	%		35.2	%		-3.3	%

157

As a large corporate taxpayer, the SPR consolidated group’s tax returns are examined by the IRS on a regular basis. During 2003 and the first quarter of 2004, SPR reached tentative agreements with the IRS for certain matters. As a result of the tentative agreements, NPC recognized tax benefits which increased net income by approximately $5.4 million in 2003. NPC believes that it does not have any contingent income tax liabilities; therefore, no income tax reserves have been established as of December 31, 2005.

The net deferred income tax liability consists of deferred income tax liabilities less related deferred income tax assets, as shown (dollars in thousands):


	2005			2004
Deferred income tax assets
Net operating loss and credit carryovers	$	129,420		$	221,566
Employee benefit plans		(530	)		(14,436	)
Customer advances		34,320			27,735
Gross-ups received on contributions in aid of construction and customer advances		18,424			14,028
Deferred revenues		11,303			19,754
Provision for contract termination		43,737			90,222
Other — net		12,797			12,464

Subtotal		249,471			371,333

Deferred income tax assets associated with regulatory matters
Excess deferred income taxes		6,005			6,395
Unamortized investment tax credit		9,063			10,111

Subtotal		15,068			16,506

Total deferred income tax assets before valuation allowance		264,539			387,839

Valuation allowance		(984	)		(925	)

Total deferred income tax assets after valuation allowance	$	263,555		$	386,914


Deferred income tax liabilities
Excess of tax depreciation over book depreciation	$	349,056		$	362,265
Deferred energy		140,330			175,045
Regulatory assets		11,061			13,162
Other — net		28,169			14,503

Subtotal		528,616			564,975

Deferred income tax liabilities associated with regulatory matters
Tax benefits flowed through to customers		155,304			167,222

Subtotal		155,304			167,222

Total deferred income tax liability	$	683,920		$	732,197


Net deferred income tax liability	$	280,129		$	194,567
Net deferred income tax liability associated with regulatory matters		140,236			150,716

Total net deferred income tax liability	$	420,365		$	345,283

NPC’s balance sheet contains a net regulatory asset of $140.2 million at December 31, 2005 and $150.7 million at December 31, 2004. The regulatory asset consists of future revenue to be received from customers due to flow-through of the tax benefits of temporary differences and goodwill recognized from the merger of NPC and SPR. Offset against these amounts are future revenues to be refunded to customers (regulatory liabilities). The regulatory liabilities consist of temporary differences for liberalized depreciation at rates in excess of current rates and unamortized investment tax credits. The regulatory liability for temporary differences related to liberalized depreciation will continue to be amortized using the average rate assumption method required by the Tax Reform Act of 1986. The regulatory liability for temporary differences caused by the investment tax credit will be amortized ratably in the same fashion as the accumulated deferred investment credit.

158

As reflected in NPC’s balance sheet (dollars in thousands)::


	2005		2004
Tax benefits flowed through to customers
Related to property	$	54,371	$	63,650
Related to goodwill		100,933		103,572

Regulatory tax asset		155,304		167,222

Liberalized depreciation at rates in excess of current rates		6,005		6,395
Unamortized investment tax credits		9,063		10,111

Regulatory tax liability		15,068		16,506

Net regulatory tax asset	$	140,236	$	150,716

The following table summarizes the tax NOL and credit carryforwards and associated carryforward periods, and a valuation allowance for amounts which NPC has determined that realization is uncertain (dollars in thousands):


							Expiration
Type of Carryforward	Deferred Tax Asset		Valuation Allowance		Net Deferred Tax Asset		Period
Federal NOL	$	124,523	$	—	$	124,523		2020-2023
State NOL		490		—		490		2006-2008
Alternative minimum tax credit		3,159				3,159	indefinite
Arizona coal credits		1,248		984		264		2006-2010

Total	$	129,420	$	984	$	128,436

At December 31, 2005, NPC has gross federal and state net operating loss carryforwards of $355.8 million and $7.0 million, respectively.

Considering all positive and negative evidence regarding the utilization of NPC’s deferred tax assets, it has been determined that NPC is more-likely-than-not to realize all recorded deferred tax assets, except for some of the Arizona coal credits. As such, these Arizona coal credits represent the only valuation allowance that has been recorded as of December 31, 2005.

159

Sierra Pacific Power Company

The following reflects the composition of taxes on income (dollars in thousands):


	2005			2004			2003
Provision for income taxes
Currently (receivable) payable
Federal	$	67,291		$	690		$	10,717
State		—			—			—

Total currently payable		67,291			690			10,717

Deferred, net
Federal		(38,074	)		3,676			(19,724	)
State		2,136			(708	)		—

Total deferred, net		(35,938	)		2,968			(19,724	)

Amortization of excess deferred taxes		(1,345	)		(1,697	)		(1,697	)

Amortization of investment tax credits		(1,629	)		(1,636	)		(1,533	)


Total provision (benefit) for income taxes	$	28,379		$	325		$	(12,237	)


Income statement classification of provision (benefit) for income taxes
Operating income	$	26,038		$	14,978		$	(13,704	)
Other income		2,341			(14,653	)		1,467

Total	$	28,379		$	325		$	(12,237	)

The total income tax provision differs from amounts computed by applying the federal statutory tax rate to income before income taxes for the following reasons (dollars in thousands):


	2005			2004			2003
Income/(loss) from continuing operations	$	52,075		$	18,577		$	(23,275	)
Total income tax expense (benefits)		28,379			325			(12,237	)

Pretax income/(loss)		80,454			18,902			(35,512	)
Statutory tax rate		35	%		35	%		35	%

Federal income tax expense (benefit) at statutory rate		28,159			6,616			(12,429	)
Depreciation related to difference in cost basis for tax purposes		2,678			2,691			2,794
Allowance for funds used during construction — equity		(574	)		(601	)		(1,022	)
ITC amortization		(1,629	)		(1,636	)		(1,533	)
Goodwill		844			506			—
Pension benefit plan		(945	)		(3,684	)		(1,113	)
Other — net		(154	)		(217	)		(491	)

Provision (benefit) for income taxes before effect of income tax settlements	$	28,379		$	3,675		$	(13,794	)


Effective tax rate before effects of income tax settlements		35.3	%		19.4	%		38.8	%

Effects of income tax settlements		—			(3,350	)		1,557

Provision (benefit) for income taxes	$	28,379		$	325		$	(12,237	)

Effective tax rate		35.3	%		1.7	%		34.5	%

160

As a large corporate taxpayer, the SPR consolidated group’s tax returns are examined by the IRS on a regular basis. During 2003 and the first quarter of 2004, SPR reached tentative agreements with the IRS for certain matters. As a result of the tentative agreements, SPPC recognized tax expense, which decreased net income by approximately $1.6 million in 2003 and increased net income by approximately $3.4 million in 2004. SPPC believes that it does not have any contingent income tax liabilities; therefore, no income tax reserves have been established as of December 31, 2005.

The net deferred income tax liability consists of deferred income tax liabilities less related deferred income tax assets, as shown (dollars in thousands):


	2005		2004
Deferred income tax assets
Net operating loss and credit carryforwards	$	6,127	$	6,150
Employee benefit plans		9,997		7,596
Customer advances		25,202		22,211
Gross-ups received on contributions in aid of construction and customer advances		7,438		6,040
Provision for contract termination		19,378		33,093
Other		6,658		2,243

Subtotal		74,800		77,333

Deferred income tax assets associated with regulatory matters
Excess deferred income taxes		11,421		11,457
Unamortized investment tax credit		11,735		12,612

Subtotal		23,156		24,069

Total deferred income tax assets	$	97,956	$	101,402


Deferred income tax liabilities
Excess of tax depreciation over book depreciation	$	211,645	$	229,609
Deferred energy		40,158		57,885
Regulatory assets		9,079		10,124
Other		9,193		12,520

Subtotal deferred tax liabilities		270,075		310,138

Deferred income tax liabilities associated with regulatory matters
Tax benefits flowed through to customers		93,957		112,545

Total deferred income tax liability	$	364,032	$	422,683


Net deferred income tax liability	$	195,275	$	232,805
Net deferred income tax liability associated with regulatory matters		70,801		88,476

Total net deferred income tax liability	$	266,076	$	321,281

SPPC’s balance sheet contains a net regulatory asset of $70.8 million at December 31, 2005 and $88.5 million at December 31, 2004. The regulatory asset consists of future revenue to be received from customers due to flow-through of the tax benefits of temporary differences and goodwill recognized from the merger of NPC and SPR. Offset against these amounts are future revenues to be refunded to customers (regulatory liabilities). The regulatory liabilities consist of temporary differences for liberalized depreciation at rates in excess of current rates and unamortized investment tax credits. The regulatory liability for temporary differences related to liberalized depreciation will continue to be amortized using the average rate assumption method required by the Tax Reform Act of 1986. The regulatory liability for temporary differences caused by the investment tax credit will be amortized ratably in the same fashion as the accumulated deferred investment credit.

161

As reflected in SPPC’s balance sheet (dollars in thousands):


	2005		2004
Tax benefits flowed through to customers
Related to property	$	43,959	$	51,204
Related to goodwill		49,998		61,341

Regulatory tax asset		93,957		112,545

Liberalized depreciation at rates in excess of current rates		11,421		11,457
Unamortized investment tax credits		11,735		12,612

Regulatory tax liability		23,156		24,069

Net regulatory tax asset	$	70,801	$	88,476

SPR and its subsidiaries file a consolidated federal income tax return. Current income taxes are allocated based on SPR’s and each subsidiaries respective taxable income or loss and investment tax credits as if each subsidiary filed a separate return. SPR owes SPPC $46.1 million in inter-company tax payments. Additionally, per the Company’s tax sharing agreement, SPPC owes SPR $49.7 million in current taxes payable.

The following table summarizes the tax NOL and credit carryforwards and associated carryforward periods for SPPC (dollars in thousands):


							Expiration
Type of Carryforward	Deferred Tax Asset		Valuation Allowance		Net Deferred Tax Asset		Period
Federal NOL	$	5,184	$	—	$	5,184		2020-2023
State NOL		943		—		943		2010-2013

Total	$	6,127	$	—	$	6,127

At December 31, 2005, SPPC has gross federal and state net operating loss carryforwards of $14.8 million and $10.7 million, respectively.

Considering all positive and negative evidence regarding the utilization of SPPC’s deferred tax assets, it has been determined that the company is more-likely-than-not to realize all recorded deferred tax assets and therefore no valuation allowance has been recorded as of December 31, 2005.

NOTE 12. RETIREMENT PLAN AND POST-RETIREMENT BENEFITS

SPR has pension plans covering substantially all employees. Benefits are based on years of service and the employee’s highest compensation for a period prior to retirement. SPR also has other postretirement plans which provide medical and life insurance benefits for certain retired employees. The following tables provide a reconciliation of benefit obligations, plan assets and the funded status of the plans. This reconciliation is based on a September 30 measurement date (dollars in thousands):


							Other Postretirement
	Pension Benefits						Benefits
	2005			2004			2005			2004
Change in benefit obligations
Benefit obligation, beginning of year	$	519,785		$	495,280		$	162,013		$	159,270
Service cost		18,481			17,988			3,281			3,058
Interest cost		32,248			30,273			9,858			9,258
Participant contributions		—			—			1,180			1,063
Plan Amendments		2,935			—			695
Actuarial loss (gain)		71,536			(6,226	)		10,389			(2,589	)
Special Termination Benefits		723						11
Benefits paid		(20,257	)		(17,530	)		(8,243	)		(8,047	)

Benefit obligation, end of year	$	625,451		$	519,785		$	179,184		$	162,013

162

The accumulated benefit obligation for Pension Benefits at the end of 2005 and 2004 was $504 million and $423 million respectively.

The weighted-average actuarial assumptions used to determine end of year benefit obligations were as follows:


							Other Postretirement
	Pension Benefits						Benefits
	2005			2004			2005			2004
Discount rate		5.75	%		6.10	%		5.75	%		6.10	%
Rate of compensation increase		4.50	%		4.50	%		N/A			N/A

For measurement purposes, a 6% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2005. The rate was assumed to remain at 6% for all future years.

In selecting an assumed discount rate for fiscal year 2005 pension cost, SPR considered the yield on high quality bonds as measured by Moody’s Investors Service, Inc. (Moody’s) Aa composite bond index. However, to select an assumed discount rate for fiscal year-end 2005 disclosures and for fiscal year 2005 pension cost, SPR’s projected benefit payments were matched to the yield curve derived from a portfolio of over 500 high quality Aa bonds with yields within the 40th to 90th percentiles of these bond yields.

Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effect (dollars in thousands):


Effect on the postretirement benefit obligation	2005			2004
Effect of a 1-percentage point increase	$	21,237		$	20,791
Effect of a 1-percentage point decrease	$	(17,410	)	$	(17,091	)

SPR contributions for the other post-retirement benefits reflect benefit payments made by SPR (dollars in thousands):


							Other Postretirement
	Pension Benefits						Benefits
	2005			2004			2005			2004
Change in plan assets
Fair value of plan assets, beginning of year	$	436,291		$	335,512		$	50,484		$	52,040
Actual return on plan assets		55,706			41,528			(985	)		5,202
SPR contributions		17,026			76,782			10,788			226
Participant contributions		—			—			1,179			1,063
Acquisition and divestiture		—			—			—			—
Benefits paid		(20,257	)		(17,530	)		(8,243	)		(8,047	)

Fair value of plan assets, end of year	$	488,766		$	436,292		$	53,223		$	50,484

The asset allocation for SPR’s pension plans at the end of 2005 and 2004, and the target allocation for 2006, by asset category, follows. The fair value of plan assets for these plans is $488.8 million and $436.3 million, at the end of 2005 and 2004, respectively. The expected long-term rate of return on these plan assets was 8.25% in 2005 and 8.50% in 2004.


	Target Allocation Percentage of Plan Assets at Year End
	2006			2005			2004
Asset Category
Equity securities		60	%		60	%		60	%
Debt securities		39			39			39
Other		1			1			1

Total		100	%		100	%		100	%

163

The asset allocation for the other postretirement benefit plans at the end of 2005 and 2004, and target allocation for 2006, by asset category, follows. The fair value of plan assets for these plans is $53.2 million and $50.5 million at the end of 2005 and 2004, respectively. The expected long-term rate of return on these plan assets was 8.25% in 2005 and 8.50% in 2004.


	Target Allocation Percentage of Plan Assets at Year End
	2006			2005			2004
Asset Category
Equity securities		60	%		60	%		60	%
Debt securities		39			39			39
Other		1			1			1

Total		100	%		100	%		100	%

SPR’s investment strategy is to ensure the safety of the principal of the assets and obtain asset performance to meet the continuing obligations of the plan. SPR strives to maintain a reasonable and prudent amount of risk, and seeks to limit risk through diversification of assets. Also, SPR considers the ability of the plan to pay all benefit and expense obligations when due, and to control the costs of administering and managing the plan. SPR’s investment guidelines prohibit investing the plan assets in real estate and SPR’s own stock. Currently, the plan assets are invested in international and domestic equity securities, and fixed securities which include bonds.

Funded Status (dollars in thousands)


							Other Postretirement
	Pension Benefits						Benefits
	2005			2004			2005			2004
Funded Status, end of year	$	(136,684	)	$	(83,493	)	$	(125,961	)	$	(111,529	)
Unrecognized net actuarial (gains) losses		166,157			120,614			77,919			66,463
Unrecognized prior service cost		14,543			13,322			1,228			597
Unrecognized net transition obligation		—			—			6,405			7,374
Contributions made in 4th quarter		15,332			15,323			4,101			—

Accrued pension and postretirement benefit obligations	$	59,348		$	65,766		$	(36,308	)	$	(37,095	)

Amounts for pension and postretirement benefits recognized in the consolidated balance sheets consist of the following (dollars in thousands):


							Other Postretirement
	Pension Benefits						Benefits
	2005			2004			2005			2004
Prepaid benefit cost	$	75,769		$	81,838			N/A			N/A
Accrued benefit liability		(16,421	)		(16,072	)		(36,308	)		(37,095	)
Additional minimum liability		(7,950	)		(3,482	)		N/A			N/A
Intangible asset		15			31			N/A			N/A
Accumulated other comprehensive income		7,935			3,451			N/A			N/A

Net amount recognized	$	59,348		$	65,766		$	(36,308	)	$	(37,095	)

At the end of 2005 and 2004, the projected benefit obligation, accumulated benefit obligation, and fair value of plan assets for pension plans with a projected benefit obligation in excess of plan assets, and pension plans with an accumulated benefit obligation in excess of plan assets, were as follows (dollars in thousands):


	Projected Benefit Obligation Exceeds				Accumulated Benefit Obligation Exceeds
	the Fair Value of Plan's Assets				the Fair Value of Plan's Assets
End of Year	2005		2004		2005		2004
Projected benefit obligation	$	625,451	$	519,785	$	27,225	$	21,938
Accumulated benefit obligation		504,188		422,964		24,703		19,877
Fair value of plan assets		488,766		436,292		—		—

164

The accumulated postretirement benefit obligation exceeds plan assets for all of the company’s other postretirement benefit plans.

Expected Cash Flows (dollars in thousands):


			Other
	Pension		Postretirement
	Benefits		Benefits
Company contributions
2006 (expected)	$	15,000	$	14,700

Expected benefit payments
2006	$	21,677	$	7,861
2007		22,981		8,348
2008		24,460		8,831
2009		26,198		9,277
2010		28,205		9,764
2011-2015		179,590		57,108

The above benefit payments are obligations of the indicated plan, and reflect payments which do not include employee contributions. The expected benefit payment information that reflects the employee obligation is almost exclusively paid from plan assets. A small portion of the pension benefit obligation is paid from the plan sponsor’s assets.

165

Net periodic pension and other postretirement benefit costs include the following components (dollars in thousands):


	Pension Benefits
	2005			2004			2003
Service cost	$	18,481		$	17,988		$	15,206
Interest cost		32,247			30,273			29,400
Expected return on assets		(36,166	)		(30,632	)		(21,135	)
Amortization of:
Prior service costs		1,714			1,714			1,966

Transition obligation		—			—			—
Actuarial (gains) losses		6,454			8,971			10,086

Net periodic benefit cost		22,730			28,314			35,523
Additional charges (credits):
Special termination charges		723			—			—

Curtailment credits		—			—			—

Total net benefit cost	$	23,453		$	28,314		$	35,523


	Other Postretirement Benefits
	2005			2004			2003
Service cost	$	3,281		$	3,058		$	2,455
Interest cost		9,858			9,258			8,883
Expected return on assets		(3,862	)		(4,100	)		(3,860	)
Amortization of:
Prior service costs		63			63			63
Transition obligation		3,782			969			969
Actuarial (gains) losses		969			4,129			2,866

Net periodic benefit cost		14,091			13,377			11,376
Additional charges (credits):
Special termination charges		11			—			—

Curtailment loss		—			—			—

Total net benefit cost	$	14,102		$	13,377		$	11,376

Weighted-average assumptions used to determine net periodic cost:


										Other Postretirement
	Pension Benefits									Benefits
	2005			2004			2003			2005			2004			2003
Discount rate		6.10	%		6.00	%		6.75	%		6.10	%		6.00	%		6.75	%
Expected Return on Plan Assets		8.25	%		8.50	%		8.50	%		8.25	%		8.50	%		8.50	%
Rate of compensation increase		4.50	%		4.50	%		4.50	%		N/A			N/A			N/A

For measurement purposes, a 6% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2005. The rate was assumed to remain at 6% in all future years.

The expected rate of return on plan assets was determined by considering a realistic projection of what assets can earn, given existing capital market conditions, historical equity and bond premiums over inflation, the effect of “normative” economic conditions that may differ from existing conditions, and projected rates of return on reinvested assets.

The expected long-term rate of return on plan assets is 8.25% in 2006.

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The assumed health care cost trend rate has a significant effect on the amounts reported. A one percentage point change in the assumed health care cost trend rate would have had the following effect (dollars in thousands):


One percentage point change:	2005			2004
Effect on total of service and interest cost components
Effect of a 1-percentage point increase in health care trend	$	1,872		$	1,845
Effects of a 1-percentage point decrease in health care trend	$	(1,503	)	$	(1,486	)

There were no significant transactions between the plan and the employer or related parties during 2005, 2004, or 2003.

NOTE 13. STOCK COMPENSATION PLANS

At December 31, 2005, SPR had several stock-based compensation plans, which are described below.

SPR’s executive long-term incentive plan for key management employees, which was approved by shareholders in May 2004, provides for the issuance of up to 7,750,000 of SPR’s common shares to key employees through December 31, 2013. The plan permits the following types of grants, separately or in combination: nonqualified and qualified stock options, stock appreciation rights, restricted stock, performance units, performance shares, and bonus stock. During 2005, SPR issued nonqualified stock options and performance shares under the long-term incentive plan.

Non-Qualified Stock Options

Elected officers and key employees specifically designated by a committee of the Board of Directors are eligible to be awarded nonqualified stock options (NQSO’s) based on the guidelines in the plan. These grants are at 100% of the then current fair market value, and vest over different periods, as stated in the grant. These options have to be exercised within ten years of award, and no earlier than one year from the date of grant. At the time of grant, rights to dividend equivalents may also be awarded.

The total number of nonqualifying stock options granted to all employees in 2005 was 169,036, which were issued at an option price not less than market value at the date of grant. Of this amount, 135,230 will vest over three years from the grant date at one-third per year. The remaining 33,806 will vest only upon the restoration of the quarterly common stock dividend within five years of the date of grant; otherwise, these shares will expire unvested. The grant may be exercised for a period not exceeding ten years from the grant date. The options may be exercised using either cash or previously acquired shares valued at the current market price, or a combination of both. The Committee may also allow cashless exercises, subject to applicable securities law restrictions or other means consistent with the purpose of the plan and the applicable law.

A summary of the status of SPR’s nonqualified stock option plan as of December 31, 2005, 2004, and 2003, and changes during the year is presented below:


	2005				2004				2003
			Weighted-				Weighted-				Weighted-
			Average				Average				Average
Nonqualified Stock Options	Shares		Exercise Price		Shares		Exercise Price		Shares		Exercise Price

Outstanding at beginning of year		1,227,950	$	15.91		1,371,869	$	16.33		1,399,809	$	16.56
Granted		169,036	$	10.10		45,000	$	7.29		55,000	$	5.69
Exercised		20,000	$	6.83		8,000	$	5.39		—		—
Forfeited		299,214	$	18.73		180,919	$	17.41		82,940	$	13.25
Outstanding at end of year		1,077,772	$	14.38		1,227,950	$	15.91		1,371,869	$	16.33

Options exercisable at year-end		928,368	$	15.07		1,215,450	$	15.99		1,369,786	$	16.35
Weighted-average grant date fair value of options granted ¹:

Average of all grants for:
2005	$	5.52
2004					$	4.96
2003									$	3.61

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(1)		The fair value of each nonqualified option has been estimated on the date of grant using the Black-Scholes option pricing model with the following assumptions used for grants issued in 2005, 2004 and 2003:


Year of	Average			Average			Average
Option	Dividend			Expected			Risk-Free Rate of			Average Expected
Grant	Yield			Volatility			Return			Life
\
2005		0.00	%		39.56	%		2.32	%	10 years
2004		0.00	%		52.60	%		4.79	%	10 years
2003		0.00	%		46.97	%		4.64	%	10 years

The following table summarizes information about nonqualified stock options outstanding at December 31, 2005:


			Options Outstanding			Options Exercisable
	Weighted					Weighted
	Average		Number		Remaining	Average		Number
	Exercise		Outstanding		Contractual	Exercise		Exercisable
Year of Grant	Price		at 12/31/05		Life	Price		at 12/31/05
1996	$	16.23		—	<1 year	$	16.23		—
1997	$	19.97		3,188	1 year	$	19.97		3,188
1998	$	24.93		15,840	2 years	$	24.93		15,840
1999	$	25.35		36,440	3 - 3.6 years	$	25.35		36,440
2000	$	16.00		400,000	4 years	$	16.00		400,000
2001	$	15.08		151,540	5 - 5.9 years	$	15.08		151,540
2002	$	14.05		241,360	6 - 6.9 years	$	14.05		241,360
2003	$	5.69		55,000	7 - 8 years	$	5.69		55,000
2004	$	7.29		25,000	8.5 years	$	7.29		25,000

2005	$	10.06		149,404	9 - 9.4 years	$	10.06		—

Weighted Average Remaining Contractual Life					5.53 years

Dividend Equivalents were included for all grants awarded prior to 1997, and for those awarded on December 19, 2003 and June 29, 2004; all of the other grants do not include dividend equivalents. Each dividend equivalent entitles the participant to receive a contingent right to be paid an amount equal to dividends declared on shares originally granted from the date of grant through the exercise date. Dividend equivalents will be forfeited if options expire unexercised or are otherwise terminated.

Performance Shares

In 2005, 2004 and 2003, SPR granted performance shares in the following numbers and initial values:


	1/1/2005		1/16/2004		9/26/2003

Shares Granted		214,596		297,587		600,000
Value per Share	$	9.58	$	7.99	$	4.86

The 2005 grant of performance shares included 171,676 shares to be earned as explained below, plus 42,920 special grant shares to be earned only upon the restoration of both the NPC and SPPC investment grade credit status within three years of the date of grant.

The 2004 grant of performance shares was originally issued as 280,082 shares of restricted stock, but was then converted to performance shares. Due to the achievement of certain performance goals established for this grant, the number of shares available under this grant was increased to 297,587.

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The 2003 grant was originally issued as phantom stock, but was subsequently converted to performance shares.

The actual number of shares earned by each participant is dependent upon SPR achieving certain financial goals over three-year performance periods. The value of all performance share grants, if earned, will be equal to the market value of SPR’s common shares as of the end of the performance periods. Sierra Pacific Resources, at its sole discretion, may pay earned performance shares in the form of cash or in shares, or a combination thereof. In 2005, 70,115 shares of stock were issued under these grants.

Restricted Stock Shares

There were no restricted stock shares granted by SPR in 2005.

In 2004, SPR granted 280,082 shares of restricted stock, which were subsequently reclassified as performance shares. These grants are included in the above discussion of Performance Shares. The remaining grant of 3,700 restricted shares was issued at a grant price of $6.83 per share, and will vest over three years at one-third per year. In 2005, the remaining 2,467 shares available under this grant were forfeited.

In 2003, SPR granted 448,576 shares of restricted stock at an average grant price of $5.93 per share. Of the shares granted, 438,576 shares will vest over 4 years with one-third becoming available in each of the years ended December 31, 2004, 2005, and 2006. The remaining 10,000 shares will vest over three years at one-third per year. In 2005, according to the vesting schedule for each grant, 145,607 shares were issued under these grants.

Employee Stock Purchase Plan

Upon the inception of SPR’s employee stock purchase plan, SPR was authorized to issue up to an aggregate of 400,162 shares of common stock to all of its employees with minimum service requirements. On June 19, 2000, shareholders approved an additional 700,000 shares for distribution under the plan. According to the terms of the plan, employees can choose twice each year to have up to 15% of their base earnings withheld to purchase SPR’s common stock. The purchase price of the stock is the lesser of 90% of the market value on the offering commencement date, or 100% of the market value on the offering exercise date. Employees can withdraw from the plan at any time prior to the exercise date. Under the plan SPR sold 53,162, 77,511 and 100,660 shares to employees in 2005, 2004, and 2003, respectively. For purposes of determining the pro forma disclosure, compensation cost has been estimated for the employees’ purchase rights on the date of grant using the Black-Scholes option-pricing model with the following assumptions used for 2005, 2004 and 2003, with an option life of six months:


							Average
	Average			Average			Risk-Free			Weighted
	Dividend			Expected			Rate of			Average
Year	Yield			Volatility			Return			Fair Value
2005		0.00	%		35.87	%		2.23	%	$	2.65
2004		0.00	%		52.60	%		1.79	%	$	2.24
2003		0.00	%		52.40	%		0.98	%	$	1.29

NOTE 14. COMMITMENTS AND CONTINGENCIES (SPR, NPC and SPPC)

Purchased Power

At December 31, 2005, NPC has eight long-term contracts for the purchase of electric energy. Expiration of these contracts ranges from 2008 to 2024. SPPC has one long-term contract with an expiration date of 2009. In accordance with the Public Utility Regulatory Policies Act, the Utilities are obligated, under certain conditions, to purchase the generation produced by small power producers and cogeneration facilities at costs determined by the appropriate state utility commission. Generation facilities that meet

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the specifications of the regulations are known as qualifying facilities (QF). As of December 31, 2005, NPC had a total of 305 MWs of contractual firm capacity under contract with four QFs. The contracts terminate between 2022 and 2024. As of December 31, 2005, SPPC had a total of 200 MWs of contractual firm capacity under 20 contracts with QFs. SPPC’s long-term QF contracts terminate between 2006 and 2039.

Estimated future commitments under non-cancelable agreements (including agreements with QF’s as of December 31, 2005 were as follows (dollars in thousands):


			Purchased Power
	NPC		SPPC		Total
2006		345,539		180,561		526,100
2007		233,038		112,836		345,874
2008		227,222		109,308		336,530
2009		208,465		78,941		287,406
2010		213,018		74,220		287,238
Thereafter		2,560,827		983,208		3,544,035

Coal and Natural Gas

The Utilities have several long-term contracts for the purchase and transportation of coal and natural gas. These contracts expire in years ranging from 2006 to 2016. Estimated future commitments under non-cancelable agreements were as follows (dollars in thousands):


	Coal and Gas						Transportation
	NPC		SPPC		Total		NPC		SPPC		Total
2006	$	440,755	$	315,723	$	756,478	$	46,240	$	68,913	$	115,153
2007		—		23,770		23,770		49,156		65,352		114,508
2008		—		15,138		15,138		37,098		49126		86,224
2009		—		15,873		15,873		37,022		39,667		76,689
2010		—		—		—		37,022		38,574		75,596
Thereafter		—		—		—		208,661		269,647		478,308

Long-Term Service Agreements

NPC entered into a long-term service agreement in December 2005 to perform maintenance on generation units located at the Chuck Lenzie Generation Station. Estimated future commitments under this agreement are as follows (dollars in thousands):


Long Term Service Agreements
	NPC(1)
2006		3,023
2007		3,023
2008		3,023
2009		3,023
2010		3,023
Thereafter		24,738

(1) Amount does not include variable or unplanned maintenance fees related to the Chuck Lenzie service contract, of which the total contract is estimated to be approximately $150 million.

Leases

SPPC has an operating lease for its corporate headquarters building. The primary term of the lease is 25 years, ending 2010. The current annual rental is $5.4 million, which amount remains constant until the end of the primary term. The lease has renewal options for an additional 50 years.

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SPR’s estimated future minimum cash payments, including SPPC’s headquarters building, under non-cancelable operating leases as of December 31, 2005, were as follows (dollars in thousands):


	Operating Leases
	NPC		SPPC		Total
2006	$	3,570	$	9,878	$	13,448
2007		1,005		6,851		7,856
2008		979		6,623		7,602
2009		911		6,654		7,565
2010		526		6,631		7,157
Thereafter		433		37,740		38,173

Environmental

Nevada Power Company

Mohave Generation Station

Reid Gardner Station

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action plans and/or suggested additional assessment plans for each specified area. Pond construction and lining costs to satisfy the NDEP order expended to date are approximately $25 million. Expenditures for 2006 through 2010 are projected to be approximately $21 million.

Clark Station

NEICO

Sierra Pacific Power Company

PCB Treatment, Inc.

In September 1994, Region VII of the EPA notified SPPC that it was being named as a potentially responsible party (PRP) regarding the past improper handling of Polychlorinated Biphenyls (PCB’s) by PCB Treatment, Inc., in two buildings, one located in Kansas City, Kansas and the other in Kansas City, Missouri (the Sites). Prior to 1994, SPPC sent PCB contaminated material to PCB Treatment, Inc. for disposal. Certificates of disposal were issued to SPPC by PCB Treatment, Inc.; however, the contaminated material was not disposed of, but remained on-site. A number of the largest PRP’s formed a steering committee, which has completed site investigations and along with the EPA has determined that the Sites should be remediated by removing the buildings to the appropriate landfills. SPPC is a member of this steering committee. The EPA issued an administrative order on consent requiring the steering committee to oversee the performance of the work. One of the two buildings has been dismantled and the work has commenced on the other site. While the final cost to complete the work is not yet definite, SPPC’s share of the cost is not expected to be material.

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Litigation

Nevada Power Company and Sierra Pacific Power Company

Enron Litigation

Settlement Agreement

Enron Bankruptcy Court Judgment

On June 5, 2002, Enron filed suit against the Utilities in its bankruptcy proceeding before Enron Bankruptcy Court seeking liquidated damages of approximately $216 million from NPC and $93 million from SPPC asserting the Utilities had not provided adequate assurance of performance upon Enron’s demand, which triggered Enron to terminate all power contracts with the Utilities under a Western Systems Power Pool Agreement (WSPPA). The Utilities denied liability on numerous grounds, including wrongful termination, deceit and fraud in the inducement, fraud, breach of contract, and unfair trade practices.

On September 26, 2003, the Bankruptcy Court entered summary judgment in favor of Enron (the “Judgment”) for damages related to the termination of Enron’s power supply agreements with the Utilities. The Judgment required NPC and SPPC to pay approximately $235 million and $103 million, respectively, to Enron for liquidated damages and pre-judgment interest for power not delivered by Enron under the power supply contracts terminated by Enron and approximately $17.7 million and $6.7 million, respectively, for power previously delivered to the Utilities. Based on the pre-judgment rate of 12%, NPC and SPPC recognized additional interest expense of $27.8 million and $12.4 million, respectively, in contract termination liabilities in the third quarter 2003. Also, NPC and SPPC recorded additional contract termination liabilities for liquidated damages of $6.6 million and $2.1 million,

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respectively, in the third quarter of 2003. The Bankruptcy Court’s order provided that until paid, the amounts owed by the Utilities would accrue interest post-Judgment at a rate of 1.21% per annum.

On October 1, 2003, the Utilities appealed the Judgment with the District Court. The Utilities sought reversal of the Judgment, contending Enron was not entitled to recover termination charges on various grounds including breach of contract, breach of solvency representation, fraud, misrepresentation, and manipulation of the energy markets. Enron filed a cross-appeal asserting that post-judgment interest should have been calculated at 1% per month, instead of the Bankruptcy Court established rate of 1.21% per year.

In response to the Judgment, the Utilities filed a motion with the Enron Bankruptcy Court seeking a stay pending appeal of the Judgment and proposing to issue General and Refunding Mortgage Bonds as collateral to secure payment of the Judgment. On November 6, 2003, the Enron Bankruptcy Court ruled to stay execution of the Judgment conditioned upon NPC and SPPC posting into escrow $235 million and $103 million, respectively, of General and Refunding Mortgage Bonds plus approximately $282,000 by NPC for pre-judgment interest. On December 4, 2003, NPC and SPPC complied with the order of the Bankruptcy Court by issuing NPC’s $235 million General and Refunding Mortgage Bond, Series H and SPPC’s $103 million General and Refunding Mortgage Bond, Series E into escrow along with the required cash deposit for NPC. Additionally, the Utilities were ordered to place into escrow $35 million, approximately $24 million and $11 million for NPC and SPPC, respectively, within 90 days from the date of the order, which would lower the principal amount of General and Refunding Mortgage Bonds held in escrow by a like amount. The Utilities made the payments as ordered on February 10, 2004. The Enron Bankruptcy Court also ordered that, during the duration of the stay, the Utilities (i) could not transfer any funds or assets other than to unaffiliated third parties for ordinary course of business operating and capital expenses, (ii) could not pay dividends to SPR other than for SPR’s current operating expenses and debt payment obligations, and (iii) were to seek a ruling from the PUCN to determine whether the cash payments into escrow trigger the Utilities’ rights to seek recovery of such amounts through the Utilities’ deferred energy rate cases. On April 16, 2004, NPC agreed to post an additional cash sum of $25 million in escrow, which lowered the principal amount of NPC’s General and Refunding Mortgage Bond, Series H, by a like amount, as part of an agreement with Enron in which Enron agreed not to request any additional collateral from NPC or SPPC during the pendency of the Utilities’ appeal of the Judgment to the District Court.

On November 21, 2003, the Utilities petitioned the PUCN to determine whether the escrow payments related to the Judgment would be recoverable through a deferred energy accounting adjustment. On February 6, 2004, the PUCN decided by final order that posting or depositing money in escrow does not constitute a fuel or purchased power cost payment and thus is not eligible for recovery in a deferred account.

On June 30, 2004, the parties stipulated before the Enron Bankruptcy Court that (1) the Utilities would withdraw their objections to the confirmation of Enron’s bankruptcy plan, (2) the collateral in the Utilities’ escrow accounts would not be deemed property of Enron’s bankruptcy estate or the Utilities’ estates in the event of a bankruptcy filing, and (3) the stay of execution of the Judgment would remain in place without any additional principal contributions by the Utilities to their escrow accounts until a final non-appealable judgment was obtained.

On October 2004, the Enron Bankruptcy Court ruled that Enron was entitled to take the $17.7 million and $6.7 million deposited by NPC and SPPC, respectively, for power previously delivered to them, out of escrow for the benefit of Enron’s bankruptcy estate.

On October 10, 2004, the District Court vacated the Judgment and remanded the case to the Enron Bankruptcy Court for fact-finding on several issues including:

	•		whether Enron’s demand for assurances at the time of termination of its power supply contracts with NPC and SPPC was reasonable;

	•		whether the assurances offered by NPC and SPPC to Enron were “reasonably satisfactory assurances”; and

	•		whether Enron would have been able to perform all of its obligations under each of the power supply contracts at the time the contracts were terminated and following termination.

The District Court further held that Enron’s demand for assurances should have been limited to its actual loss and rejected Enron’s cross-appeal. The terms of the June 30, 2004 stipulation, discussed above, remained in place pending all remands and appeals of the reversed Judgment.

Enron Litigation before FERC

FERC Early Termination Case

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FERC Revocation Show Cause Proceeding

Western United States Energy Crisis Proceedings before the FERC

FERC Gaming and Partnership Show Cause Proceeding

FERC 206 complaints

The Utilities have negotiated settlements with Duke Energy Trading and Marketing, Reliant Energy Services, Inc., Morgan Stanley Capital Group, El Paso Merchant Energy (EPME), now known as El Paso Marketing L.P.;and Enron, but have been unable to reach agreement in bilateral settlement discussions with other respondents. In accordance with the Enron Settlement Agreement, the Utilities withdrew from further participation in the FERC 206 Complaints (including any associated appeals) as against Enron.

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Reliant and Duke Antitrust Litigation

Nevada Power Company

Morgan Stanley Proceedings

El Paso Merchant Energy

Peabody Western Coal Company

NPC owns an 11%, 255 MW interest in the Navajo Generating Station (Navajo) which includes three coal-fired electrical generating units and is located in Northern Arizona. Other participants in Navajo, are the Salt River Project (Salt River), Arizona Public Service Company, Los Angeles Department of Water and Power, and Tucson Electric Power Company (together the Joint Owners).

On October 15, 2004, coal supplier Peabody Western Coal Co. (Peabody) filed a complaint in Missouri State Court in St. Louis, seeking reimbursement of royalties and other costs and damages for alleged breach of the coal supply agreement for the Navajo

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plant. In January 2005, the Joint Owners were served and operating agent, Salt River, has engaged counsel and is defending the suit on behalf of the Joint Owners. NPC believes Peabody’s claims are without merit and intends to contest these.

On February 10, 2005, the Joint Owners filed Notice of Removal of the complaint to the U. S. District Court, Eastern District of Missouri. On March 17, 2005, Peabody filed a motion to remand the case back to state court in St. Louis, Missouri. Joint Owners have filed a motion to dismiss the complaint for lack of jurisdiction. Both motions are pending and the parties are conducting limited discovery in Federal court in connection with the motions. NPC is unable to predict the outcome of the decision.

Sierra Pacific Power Company

Farad Dam

SPPC owns 4 hydro generating plants (10.3 MW capacity) located in California that were to be included in the sale of SPPC’s water business for $8 million to the Truckee Meadows Water Authority (TMWA) in June 2001. The contract with TMWA requires that SPPC transfer the hydro assets in working condition. However, one of the four hydro generating plants, Farad 2.8 MW, has been out of service since the summer of 1996 due to a collapsed flume. While planning the reconstruction, a flood on the Truckee River in January 1997 destroyed the diversion dam.

SPPC filed a claim with the insurers Hartford Steam Boiler Inspection and Insurance Co. and Zurich-American Insurance Company (Insurers) for the flume and dam. In December, 2003, SPPC sued Insurers in the U.S. District Court for the District of Nevada on a coverage dispute relating to potential rebuild costs. In May 2005, Insurers filed a motion for summary judgment on the coverage issue, which has been denied. In October 2005, insurers filed a new (partial) summary judgment motion with respect to coverage, which SPPC opposed in November 2005. The court decision remains pending.

The current estimate to rebuild the diversion dam, if management decides to proceed, is approximately $20 million. Management believes that it has a valid insurance claim and is likely to recover the costs to rebuild the dam through the courts or from other sources. Management has not recorded a loss contingency for the cost to rebuild the dam as it believes its overall exposure is insignificant.

Piñon Pine

Other Legal Matters

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, in the opinion of management, is expected to have a significant impact on their financial positions, results of operations, or cash flows.

Contract Termination Liabilities

At December 31, 2005, included in NPC’s and SPPC’s Consolidated Balance Sheets as “Contract termination liabilities,” were approximately $89.8 million and $39.2 million of charges, respectively, for terminated power supply contracts and associated interest. Correspondingly, pursuant to the deferred energy accounting provisions of AB 369, included in NPC and SPPC deferred energy balances as of December 31, 2005, were approximately $84.0 million and $21.1 million of charges, respectively, for recovery in rates in future periods associated with the terminated power supply contracts. The Utilities will pursue recovery of the payments through future regulatory filings. To the extent that the Utilities are not permitted to recover any portion of these costs, 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 effect on the future financial position, results of operations, and cash flows of SPR, NPC, and SPPC.

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Regulatory Contingencies

Nevada Power Company

Mohave Generation Station

NPC’s ownership interest in Mohave comprises approximately 10% of NPC’s peak generation capacity. SCE is the operating partner of Mohave.

Mohave obtains all of its coal supply from a mine in northeast Arizona on lands of the Tribes. This coal is delivered from the mine to Mohave by means of a coal slurry pipeline which requires water that is obtained from groundwater wells located on lands of the Tribes in the mine vicinity. Due to the uncertainty over a post-2005 coal supply, the 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. See the Environmental section above for further discussion on Mohave’s environmental issue. As such, on December 31, 2005 the Owners of the Mohave plant suspended operation, pending resolution of these issues.

NPC’s Integrated Resource Plan (IRP) accepted by the PUCN in November 2003, assumes the Plant will be unavailable after December 31, 2005. In addition, in its General Rate Case filed on October 1, 2003, NPC requested that the PUCN authorize a higher depreciation rate be applied to Mohave in order to recover the remaining book value to a regulatory asset account to be amortized over a period as determined by the PUCN. While the PUCN did not approve higher depreciation rates, they did authorize the use of a regulatory asset to accumulate the costs and savings associated with Mohave in the event of its shutdown with recovery of any accumulated costs in a future rate case proceeding. NPC continues to recover the cost of Mohave in rates. Approximately, $27.2 million has been reclassified from Plant in Service to Other Regulatory assets as of December 31, 2005. In its next general rate case, NPC will seek further clarification on the regulatory treatment of Mohave. In the event any portion of Mohave is disallowed, NPC will have to evaluate the asset for impairment.

NOTE 15. COMMON STOCK AND OTHER PAID-IN CAPITAL

Rights Agreement

On December 19, 2005, the Board of Directors of SPR (the Board) voted to amend the Rights Agreement, dated as of February 28, 2001 (as amended and restated, the “Rights Agreement”), between the SPR and Wells Fargo Bank Minnesota, N.A., to accelerate the final expiration date of the rights (“Rights”) issued there under to December 19, 2005, and to terminate the Rights Agreement upon the expiration of the Rights. The Board also adopted a policy governing future entry into a shareholder rights agreement or similar agreement (a “shareholder rights plan”). SPR’s policy is to seek shareholder approval prior to the adoption of a shareholder rights plan, unless the board, in the exercise of its fiduciary duties and with the concurrence of a majority of its independent members, determines that, under the circumstances existing at the time, it is in the best interest of SPR’s shareholders to adopt a shareholder rights plan without first obtaining shareholder approval. If a shareholder rights plan is adopted without prior shareholder approval, the plan must provide that is shall expire, unless ratified by shareholders, within one year of adoption.

Employee Stock Ownership Plans

As of December 31, 2005, 8,517,865 shares of common stock were reserved for issuance under the Common Stock Investment Plan (CSIP), Employees’ Stock Purchase Plan (ESPP), and Executive Long-Term Incentive Plan (LTIP).

The 2005 LTIP for officers and key employees allows for the issuance of SPR’s common shares through December 31, 2013, which can be earned and issued prior to December 31, 2013. This Plan permits the following types of grants, separately or in combination: nonqualified and qualified stock options; stock appreciation rights; restricted stock; performance units; performance shares, bonus stock and cash.

SPR also provides an ESPP to all of its employees meeting minimum service requirements. Employees can choose twice each year (offering date) to have up to 15% of their base earnings withheld to purchase SPR common stock. The purchase price of the stock is 90% of the market value on the offering date or 100% of the market price on the execution date, if less.

The Non-employee Director Stock Plan provides that a portion of SPR’s outside directors’ annual retainer be paid in SPR common stock. SPR records the costs of these plans in accordance with Accounting Principles Board Opinion No. 25. In addition, in 1996 SPR eliminated its outside director retirement plan and converted the present value of each director’s vested retirement benefit to phantom stock based on the stock price at the time of conversion. Phantom stock earns dividends, also payable in phantom stock, which are recorded in each Director’s phantom account. The value of these accounts is issued in stock or cash, at the election of the Board, at the time the Director leaves the Board.

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Non-Employee Director Stock

The annual retainer for non-employee directors is $57,000, and the minimum amount to be paid in SPR stock is $35,000 per director. During 2005, 2004, and 2003, SPR granted the following total shares and related compensation to directors in SPR stock, respectively: 31,631, 18,740 and 39,370 shares, and $176,000, $140,000, and $150,000.

Convertible Notes Issuance

On February 14, 2003, SPR issued and sold $300 million of its 7.25% Convertible Notes due 2010. On August 11, 2003, SPR obtained shareholder approval to issue additional shares of SPR’s common stock in lieu of paying the cash payment component upon conversion of the Convertible Notes. On August 3, 2005, SPR announced an offer to pay a cash premium to induce holders to convert their 7.25% Notes to shares of SPR common stock. The conversion offer was accepted by 100% of the holders. On September 8, 2005, 65,749,096 shares of common stock, plus cash in lieu of fractional shares, were issued to the holders in exchange for the 7.25% Notes. For additional information regarding these Convertible Notes see Note 7, Long-Term Debt.

Stock Exchange Transactions

On November 15, 2005 SPR issued 17,344,183 shares of common stock, along with cash in lieu of fractional shares in connection with its PIES. For additional information regarding the PIES transactions see Note 7, Long-Term Debt.

NOTE 16. PREFERRED STOCK

Sierra Pacific Power Company

Preferred Stock

SPPC’s Restated Articles of Incorporation, as amended on August 19, 1992, authorize an aggregate amount of 11,780,500 shares of preferred stock at any given time. SPPC’s preferred stock is superior to SPPC’s common stock with respect to dividend payments (which are cumulative) and liquidation rights. SPPC paid $3.9 million in dividends for the year ending December 31, 2005.

On November 3, 2005, a dividend of $975,000 (.04875 per share) was declared on SPPC’s preferred stock. The dividend was paid on March 1, 2006 to holders of record as of February 14, 2006.

The following table indicates the dollar amount and number of shares of SPPC preferred stock outstanding at December 31 of each year (dollars in thousands).


	Amount				Shares Outstanding
Preferred Stock	2005		2004		2005		2004
Not subject to mandatory redemption SPPC Class A Series 1	$	50,000	$	50,000		2,000,000		2,000,000

Total Preferred Stock	$	50,000	$	50,000		2,000,000		2,000,000

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NOTE 17. EARNINGS PER SHARE (EPS) (SPR)

The difference, if any, between basic EPS and diluted EPS is due to potentially dilutive common shares resulting from stock options, the employee stock purchase plan, performance and restricted stock plans, and the non-employee director stock plan. Due to net losses for the year ended December 31, 2003 these items are anti-dilutive. Accordingly, diluted EPS for these periods are computed using the weighted average shares outstanding before dilution.

For the years ended December 31, 2004 and 2003, SPR had outstanding $300 million in 7.25% convertible notes due 2010 that were entitled to receive (non-cumulative) dividend payments on a 1:1 basis for dividends paid to common shareholders without exercising the conversion option. These convertible notes met the criteria of a participating security in the calculation basic EPS, and were convertible at the option of the holders into 65,749,110 common shares. See Note 7, Long-Term Debt, for discussion of the Convertible Notes.

Emerging Issues Task Force, Participating Securities and the Two-Class Method under FASB Statement No. 128, (EITF 03-6) requires companies to use the “two-class” method to calculate basic EPS, and the “if-converted” method to calculate diluted EPS if the result was dilutive. The “two-class” method was used to calculate basic EPS for the year ended December 31, 2004. This method was not used to calculate basic EPS for the year ended December 31, 2003, as the effect was anti-dilutive. On September 8, 2005 SPR issued approximately 65.7 million shares of common stock in connection with the early conversion of the 7.25% Convertible Notes.

On November 15, 2005 the conversion of SPR’s PIES resulted in the issuance of 17.3 million shares. For the year ended December 31, 2005 these shares are included in the denominator on a weighted average basis. See Note 7, Long-Term Debt, for discussion of the PIES transaction.

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The following table outlines the calculation for earnings per share (EPS):


	Year ended December 31,
	2005			2004			2003
Basic EPS
Numerator ($000)
Income / (Loss) from continuing operations	$	86,240		$	35,635		$	(104,160	)
Loss from discontinued operations	$	(103	)	$	(3,164	)	$	(32,469	)

Earnings / (Deficit) applicable to common stock	$	62,198		$	18,310		$	(140,529	)
Earnings applicable to convertible notes	$	20,039		$	10,261		$	—

Earnings / (Deficit) used for basic calculation	$	82,237		$	28,571		$	(140,529	)


Denominator
Weighted average number of common shares outstanding		140,334,552			117,331,365			115,774,810
Shares issuable for Convertible Notes		45,213,762			65,749,110			—

		185,548,314			183,080,475			115,774,810


Earnings (Deficit) Per Share Amounts
Income / (Loss) from continuing operations	$	0.46		$	0.19		$	(0.90	)
Loss from discontinued operations	$	—		$	(0.02	)	$	(0.28	)

Earnings / (Deficit) applicable to common stock	$	0.44		$	0.16		$	(1.21	)
Earnings applicable to convertible notes	$	0.44		$	0.16		$	—

Diluted EPS
Numerator ($000)
Income / (Loss) from continuing operations	$	86,240		$	35,635		$	(104,160	)
Loss from discontinued operations	$	(103	)	$	(3,164	)	$	(32,469	)

Earnings / (Deficit) applicable to common stock	$	82,237		$	28,571		$	(140,529	)

Denominator ^{(1, 2)}

Weighted average number of shares outstanding before dilution		140,334,552			117,331,365			115,774,810
Stock options		47,255			24,949			—
Executive long term incentive plan — restricted/performance shares		311,817			264,823			—
Non-Employee Director stock plan		21,193			15,028			—
Employee stock purchase plan		3,925			15,028			—
Convertible Stock		45,213,762			65,749,110			—

		185,932,504			183,400,303			115,774,810


Earnings (Deficit) Per Share Amounts
Income / (Loss) from continuing operations	$	0.46		$	0.19		$	(0.90	)
Loss from discontinued operations	$	—		$	(0.02	)	$	(0.28	)
Earnings / (Deficit) applicable to common stock	$	0.44		$	0.16		$	(1.21	)


(1)		The denominator does not include stock equivalents resulting from the options issued under the Nonqualified stock option plan for the years ended December 31, 2005, 2004 and 2003, due to conversion prices being higher than market prices for all periods. Under the nonqualified stock option plan for the years ended December 31, 2005, 2004 and 2003, 917,623, 1,146,728 and 1,357,228 shares, respectively, would be included. The denominator does not include stock equivalents resulting from the conversion of the Corporate PIES, for the years ended December 31, 2004 and 2003. The amounts that would be included in the calculation, if the conversion price were met would be 17.3 million shares for each year.

(2)		The denominator used for the diluted EPS calculation does not include stock equivalents for stock options, restricted and performance shares issued under the executive long-term incentive plan, options under the non-employee director stock plan, and the employee stock purchase plan, for the year ended December 31, 2003 due to their anti-dilutive effect. The number of shares for the year ended December 31, 2003 would have been 87,321.

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NOTE 18. DISCONTINUED OPERATIONS AND DISPOSAL AND IMPAIRMENT OF LONG-LIVED ASSETS

Effective January 1, 2002, SPR, NPC and SPPC adopted SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets”, which addresses financial accounting and reporting for the impairment or disposal of long-lived assets. SFAS No. 144 requires a component of an entity that either has been disposed of or is classified as held for sale to be reported as discontinued operations if certain conditions are met. Further, SFAS No. 144 requires that assets to be held and used be tested for recoverability whenever events or circumstances indicate that its carrying amount may not be recoverable.

e ·three Business Sale

SPR’s subsidiary, e ·three, was organized in October 1996 to provide energy and other business solutions in commercial and industrial markets.

In keeping with management’s strategy to focus on its core utility businesses, SPR sold e three on September 26, 2003. The operation of e ·three was included in the “Other” business segment.

The operation of e ·three discussed above is classified as a discontinued operation in the accompanying consolidated statements of operations.

Other Property Disposals

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 $4.9 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 two years consistent with the accounting treatment directed by the PUCN.

On August 12, 2003, NPC auctioned parcels of land located on Flamingo Road from Koval Lane to Maryland Parkway, commonly known as “the Flamingo Corridor.” The net sales price for these properties was $24.4 million. The carrying value of the properties was approximately $0.2 million. The sale closed on October 28, 2003. The transaction resulted in an approximate gain of $24.2 million, of which $2.4 million is being held in escrow pending the final outcome of related litigation. The gain will be recognized in revenue over a period of four years consistent with the accounting treatment directed by the PUCN.

Sierra Pacific Communications

SPC was formed as a Nevada corporation in 1999 to identify and develop business opportunities in telecommunications services and infrastructure. SPC’s business activities have included the development of a fiber optic system extending between Salt Lake City, Utah and Sacramento, California (Long Haul Assets) and the development of Metro Area Networks (MAN) in Las Vegas and Reno, Nevada.

SPC formed a limited liability company with Touch America, INC. (TAI) named Sierra Touch America LLC (STA) in 2000, to further the development of the Long Haul System (System). In September 2002, SPC and TAI entered into an agreement whereby SPC redeemed its membership interest in STA and acquired fiber optic assets in the System and provided an indemnity for System liabilities. In June 2003, TAI and all its subsidiaries (including STA) filed a petition for Chapter 11 bankruptcy protection. SPC pursued litigation in TAI’s bankruptcy case to resolve its obligations to and claims against, TAI and its affiliates. On July 28, 2004, SPC entered into a settlement agreement with TAI, STA and AT&T (the Settlement). The bankruptcy court approved TAI’s plan of liquidation and the Settlement on October 6, 2004.

In light of the bankruptcy of Touch America Holdings and STA, SPC evaluated its business to determine whether the Touch America bankruptcy has caused an impairment of SPC’s assets. This evaluation was conducted in conformance with the guidelines of SFAS No. 144, “Accounting for the Disposition or Impairment of Long-Lived Assets” and also considered factors such as the anticipated liquidation of Sierra Touch America LLC assets, resulting in significant changes in business climate and projected discounted cash flows from the assets. SPC evaluated its MAN 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-

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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 market factors that resulted from the Touch America bankruptcy discussed above. Based on the evaluation, SPC 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 MAN, and $18.2 million in fiber optic cable, conduits, and other related business equipment write-downs of its long haul network assets.

SPR sold SPC’s MAN assets on June 30, 2004. SPC recognized a gain on sale of assets of approximately $2.5 million (pretax) in connection with the sale of the MAN assets.

The Settlement provided SPC with one remaining duct and associated occupancy right in the System and allowed SPC to complete the transfer and sale of the duct, which was negotiated under a 2002 contract with Qwest Communications (Qwest) for $20 million. Upon reaching the Settlement management had the ability and a plan in place to dispose of SPC’s Long Haul Assets, and in accordance with SFAS 144, classified all of SPC’s activities as Discontinued Operations. SPC received $10 million of the amount due from Qwest in 2003, which is included in current liabilities of discontinued operations until the consummation of the deal between Qwest and SPC is completed.

Due to certain legal issues, SPR has been delayed in consummating the sale of the Long Haul System to Qwest. In October 2005, the assets were presented to Qwest, however, Qwest rejected SPC’s request to tender alleging primarily that SPC failed to deliver a timely completion notice. SPC denies these claims, and believes that Qwest remains obligated to perform under the contract terms and expects a favorable resolution of this matter. SPC has initiated mandatory arbitration with Qwest.

The assets and liabilities associated with the discontinued operation of SPC are segregated on the consolidated balance sheets at December 31, 2005 and 2004. Revenues from SPC for the years ended December 31, 2005 and 2004 were $23 thousand and $957 thousand respectively, and pre-tax loss of approximately $48 thousand and $4.9 million. The carrying amount of major asset and liability classifications are as follows (dollars in thousands):


	December 31,		December 31,
	2005		2004
Investments and other property, net	$	20,000	$	20,000
Cash		53		2
Accounts receivable		63		—
Current assets — Other		—		105


Total Assets	$	20,116	$	20,107


Current liabilities	$	10,200	$	10,200

NOTE 19. GOODWILL AND OTHER MERGER COSTS

On March 26, 2004, the PUCN issued a decision on NPC’s general rate case that included the recovery of goodwill and other merger costs allocated to NPC resulting from the merger of SPR and NPC in 1999. In its decision, the PUCN affirmed that NPC demonstrated merger savings exceeded merger costs, the requisite requirement for recovery of goodwill and merger costs through rates charged to NPC customers. The PUCN decision permits NPC to recover approximately $4 million per year for two years beginning April 1, 2004, based on a forty-year amortization of NPC’s total goodwill. The amount to be recovered over the next two years reflects a reduction of 20% from the amounts sought by NPC, or approximately $1 million per year, due to customer satisfaction survey results that the PUCN determined required improvement. The decision requires NPC to again demonstrate in its next general rate application that merger savings continue during the test period in that case. The PUCN’s order in that case will determine if any further documentation of merger savings is required in the future. Management expects that it will be able to demonstrate continued savings as a result of the merger as well as satisfactory customer survey results. As a result of the PUCN decision, goodwill of approximately $198 million was reclassified as a regulatory asset and then transferred from the financial statements of SPR to the financial statements of NPC as of March 31, 2004.

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order to continue to recover goodwill costs SPPC is required to again demonstrate in its next general rate application filed October 3, 2005, that merger savings continue during the test period in that case. Management expects that it will be able to demonstrate continued savings resulting from the merger. As a result of the PUCN decision, goodwill of approximately $96 million was reclassified to a regulatory asset and transferred from the financial statements of SPR to the financial statements of SPPC as of June 30, 2004. See Note 3, Regulatory Actions for more information regarding the NPC and SPPC general rate decisions.

In addition to amounts discussed above, SPR’s Consolidated Balance Sheet as of March 31, 2004, included approximately $4 million of goodwill assigned to SPR’s unregulated operations and $31 million of goodwill allocated to its regulated operations that was not considered for recovery in NPC’s or SPPC’s general rate cases described above. The $31 million of goodwill was comprised of approximately $19 million assigned to SPPC’s regulated gas business and $2 million and $10 million for non-Nevada jurisdictional sales allocated to NPC’s and SPPC’s electric businesses, respectively. SPPC expects to demonstrate in its general rate case filed October 3, 2005 for the gas distribution business that savings from the merger allocable to the gas business exceed goodwill and other merger costs and, as a result, to recover goodwill and merger costs through future gas rates. Accordingly, management has not reviewed goodwill assigned to the gas business for impairment. However, the approximate $12 million of goodwill assigned to NPC’s and SPPC’s electric businesses that are not recoverable through future rates and approximately $4 million of goodwill assigned to SPR’s unregulated operations were subject to impairment review under the provisions of SFAS No. 142.

SFAS No. 142 provides that an impairment loss is to be recognized if the carrying value of each reporting unit’s goodwill exceeds its fair value. For purposes of testing goodwill for impairment, a discounted cash flow model was developed for NPC’s and SPPC’s electric business and for SPR’s unregulated businesses to determine the fair value of each reporting unit as of March 31, 2004. As part of the impairment testing analysis, management revised certain underlying assumptions utilized in previously performed preliminary analyses, that included, revised cash flow forecasts, an increase in the discount rate applied to future cash flows and other assumptions related to the outcomes of NPC’s and SPPC’s general rate cases. As a result of this impairment testing, SPR recorded a goodwill impairment charge related to NPC’s and SPPC’s electric reporting units of approximately $2 million and $10 million as a charge to other operating expenses in SPR’s, NPC’s and SPPC’s Consolidated Statements of Operations for the quarter ended March 31, 2004. Goodwill assigned to SPR’s unregulated businesses was determined not to be impaired.


	Regulated			Unregulated
	Operations			Operations		Total
Goodwill balance as of January 1, 2004	$	305,982		$	3,989	$	309,971

Goodwill included in regulatory assets as of January 1, 2004		19,070			—		19,070

Subtotal		325,052			3,989		329,041

Transfer to NPC regulatory asset as of March 31, 2004		(197,998	)		—		(197,998	)

Impairment loss recognized as of March 31, 2004		(11,696	)		—		(11,696	)
Transfer to SPPC regulatory asset as of June 30, 2004		(96,470	)		—		(96,470	)


Balance as of December 31, 2004	$	18,888		$	3,989	$	22,877


Goodwill Allocation to Reporting Units:

SPPC GAS	$	18,888		$	—	$	18,888
TGPC		—			3,520		3,520
LOS		—			469		469


Balance as of December 31, 2004	$	18,888		$	3,989	$	22,877

Balances have remained unchanged as of December 31, 2005.

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NOTE 20. QUARTERLY FINANCIAL DATA (UNAUDITED)

The following figures are unaudited and include all adjustments necessary in the opinion of management for a fair presentation of the results of interim periods. Dollars are presented in thousands except per share amounts.


	SIERRA PACIFIC RESOURCES
	2005 Quarter Ended
	March			June		September			December
Operating Revenues	$	648,974		$	701,038	$	959,126		$	721,081

Operating Income	$	58,948		$	80,893	$	162,884		$	56,056

Income(loss) from continuing operations	$	(8,516	)	$	10,025	$	62,127	⁽¹⁾	$	22,604	⁽²⁾

Income (loss) from discontinued operations	$	5		$	1	$	(134	)	$	25

Earnings (deficit) applicable to common stock	$	(9,486	)	$	9,051	$	61,018		$	21,654


Income (loss) per share-Basic:
From continuing operations	$	(0.07	)	$	0.05	$	0.34		$	0.12
From discontinued operations	$	0.00		$	0.00	$	(0.00	)	$	0.00
Earnings (deficit) applicable to common stock	$	(0.08	)	$	0.05	$	0.33		$	0.11
Income (loss) per share-diluted:
From continuing operations	$	(0.07	)	$	0.05	$	0.34		$	0.12
From discontinued operations	$	0.00		$	0.00	$	(0.00	)	$	0.00
Earnings (deficit) applicable to common stock	$	(0.08	)	$	0.05	$	0.33		$	0.11


	2004 Quarter Ended
	March			June			September			December
Operating Revenues	$	588,117		$	677,420		$	903,915		$	654,387

Operating Income	$	46,086		$	74,734		$	162,268		$	55,697

Income(loss) from continuing operations	$	(42,800	)	$	(40,942	)⁽³⁾	$	91,749		$	27,628	⁽⁴⁾

Income (loss) from discontinued operations	$	(675	)	$	(2,967	)	$	(127	)	$	605

Earnings (deficit) applicable to common stock	$	(44,450	)	$	(44,884	)	$	90,647		$	27,258


Income (loss) per share-Basic:
From continuing operations	$	(0.37	)	$	(0.35	)	$	0.50		$	0.15
From discontinued operations	$	(0.01	)	$	(0.03	)	$	(0.00	)	$	0.00
Earnings (deficit) applicable to common stock	$	(0.38	)	$	(0.38	)	$	0.50		$	0.15
Income (loss) per share-diluted:
From continuing operations	$	(0.37	)	$	(0.35	)	$	0.50		$	0.15
From discontinued operations	$	(0.01	)	$	(0.03	)	$	(0.00	)	$	0.00
Earnings (deficit) applicable to common stock	$	(0.38	)	$	(0.38	)	$	0.49		$	0.15


(1)		In the third quarter of 2005, income from continuing operations includes a charge of $54 million for the inducement for debt conversion.

(2)		In the fourth quarter of 2005, income from continuing operations includes the reversal of $20.9 million in interest charges as a result of settlements with terminated suppliers.

(3)		In the second quarter 2004, income from continuing operations includes the write-off of $47.1 million in disallowed plant costs at SPPC

(4)		In the fourth quarter of 2004, income includes the reversal of $40 million in interest expense due to the decision on the appeal of the Enron bankruptcy judgment.

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	NEVADA POWER COMPANY
	2005 Quarter Ended
	March			June		September		December
Operating Revenues	$	354,134		$	451,384	$	675,181	$	402,568

Operating Income	$	23,265		$	54,031	$	126,173	$	25,358

NET INCOME (LOSS)	$	(8,033	)	$	20,969	$	99,472	$	20,326	(1)


	2004 Quarter Ended
	March			June		September		December
Operating Revenues	$	326,533		$	449,925	$	633,609	$	374,025

Operating Income	$	21,000		$	49,470	$	120,842	$	25,178

NET INCOME (LOSS)	$	(15,406	)	$	13,590	$	86,198	$	19,930	(2)


(1)		In the fourth quarter of 2005, income from continuing operations includes the reversal of $17.7 million in interest charges as a result of settlements with terminated suppliers.

(2)		In the fourth quarter of 2004, income includes the reversal of $28 million in interest expense due to the decision on the appeal of the Enron bankruptcy judgment .


	SIERRA PACIFIC POWER COMPANY
	2005 Quarter Ended
	March		June		September		December
Operating Revenues	$	294,548	$	249,335	$	283,683	$	318,131

Operating Income	$	29,519	$	21,710	$	38,139	$	26,936

NET INCOME (LOSS)	$	12,137	$	4,899	$	21,858	$	13,180	(1)

Earnings (deficit) applicable to common stock	$	11,162	$	3,924	$	20,883	$	12,205


	2004 Quarter Ended
	March		June			September		December
Operating Revenues	$	261,317	$	224,304		$	270,002	$	280,037

Operating Income (loss)	$	27,642	$	17,892		$	39,055	$	26,656

NET INCOME (LOSS)	$	7,671	$	(32,187	)(2)	$	21,788	$	21,305	(3)

Earnings (deficit) applicable to common stock	$	6,696	$	(33,162	)	$	20,813	$	20,330


(1)		In the fourth quarter of 2005, income includes the reversal of $3.2 million in interest expense due to settlements with terminated suppliers.

(2)		In the second quarter 2004, income includes the write-off of $47.1 million in disallowed plant costs at SPPC.

(3)		In the fourth quarter of 2004, income includes the reversal of $12 million in interest expense due to the decision on the appeal of the Enron bankruptcy judgment.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

(a) Evaluation of Disclosure Controls and Procedures — Sierra Pacific Resources, Nevada Power Company and Sierra Pacific Power Company’s principal executive officers and principal financial officers, based on their evaluation of the registrants’ disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934) have

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concluded that, as of December 31, 2005, the registrants’ disclosure controls and procedures are adequate and effective to ensure that material information relating to the registrants’ and their consolidated subsidiaries is recorded, processed, summarized and reported within the time period specified by the SEC’s rules and forms, particularly during the period for which this annual report has been prepared.

(b) Reports on Internal Control Over Financial Reporting

Management’s Report on Internal Control Over Financial Reporting

The management of Sierra Pacific Resources is responsible for establishing and maintaining adequate internal control over financial reporting. Sierra Pacific Resources’ internal control system was designed to provide reasonable assurance to the company’s management and board of directors regarding the preparation and fair presentation of published financial statements.

Although Sierra Pacific Resources is firmly committed to effective internal controls over financial reporting, internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

Sierra Pacific Resources’ management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2005. In making this assessment, Sierra Pacific Resources used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Based on our assessment we believe that, as of December 31, 2005, the Company’s internal control over financial reporting is effective based on those criteria.

Sierra Pacific Resources’ independent registered public accountants have issued an audit report on our assessment of the Company’s internal control over financial reporting.

March 3, 2006

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of
Sierra Pacific Resources
Reno, Nevada

We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting, that Sierra Pacific Resources and subsidiaries (the “Company”) maintained effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

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Because of its inherent limitations, internal control over financial reporting including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, management’s assessment that the Company maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedule as of and for the year ended December 31, 2005 of the Company and our report dated March 3, 2006 expressed an unqualified opinion on those financial statements and financial statement schedule.

DELOITTE & TOUCHE LLP

Reno, Nevada
March 3, 2006

(c) Changes in Internal Controls

None.

ITEM 9B. OTHER INFORMATION

None.

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PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

(a) Directors

The following is a listing of all the current directors of SPR, NPC, and SPPC, and their ages. There are no family relationships among them. Directors serve three-year terms with three (or four) terms of office expiring at each Annual Meeting, or until their successors have been elected and qualified.

Directors whose terms expire in 2006:

Mary Lee Coleman, 69

President of Coleman Enterprises, a developer of shopping centers and industrial parks. She is also a director of First Dental Health, Inc. Ms. Coleman has served as a Director of NPC since 1980, and was elected a Director of SPR and SPPC in July 1999.

Theodore J. Day, 56

Chairman of Dacole Company, an investment firm, and President of Nevada Superior, Inc., a mining Company. Formerly Senior Partner of Hale, Day, Gallagher Company, a real estate brokerage and investment firm. Mr. Day has served as a Director of SPPC since 1986, of SPR since 1987, and was elected a Director of NPC in July 1999. He is also a Director of the W.M. Keck Foundation, the W.K. Day Foundation, the Boy Scouts of America, Nevada Area Council, the Reno Air Race Association, Sierra Nevada College, Western Exploration and Development, Ltd., and the National Cowboy and Western Heritage Museum.

Jerry E. Herbst, 68

Chief Executive Officer of Terrible Herbst, Inc., a gasoline retail company, since 1968. Mr. Herbst has served as a Director of NPC since 1990, and was elected a Director of SPR and SPPC in July 1999.

Donald D. Snyder, 58

Mr. Snyder retired in March 2005, as President of Boyd Gaming, a gaming entertainment company. Previously, he was Chairman and CEO of First Interstate Bank of Nevada from 1987 to 1991. He is Chairman of the Las Vegas Performing Arts Center Foundation and Fremont Street Experience LLC. He is Director of BankWest of Nevada, Western Alliance Bancorporation, Cash Systems, Inc., Nathan Adelson Hospice, the Nevada Development Authority, University of Nevada Las Vegas Foundation, and Tournament Players Club at Summerlin. Mr. Snyder was elected a Director of SPR, SPPC and NPC in November, 2005.

Directors whose terms expire in 2007:

James R. Donnelley, 70

Partner, Stet and Query, Ltd., a family-owned investment company, since June 2000. He retired from R.R. Donnelley & Sons Company in June 2000, where he served as Vice Chairman of the Board from July 1990 to June 2000 and as a Director from 1976 to May 2005. He is also a Director of PMP Limited, and Chairman of National Merit Scholarship Corporation. Mr. Donnelley has served as a Director of SPR since 1987, of SPPC since 1992, and was elected a Director of NPC in July 1999.

Walter M. Higgins, 61

Chairman, President and Chief Executive Officer of SPR and Director and Chief Executive Officer of NPC and SPPC since August 2000. Mr. Higgins served as Chairman, President and Chief Executive Officer of AGL Resources, Inc., from January 1998 to August 2000. He is also a director of AEGIS Insurance Services, Inc., Edison Electric Institute, American Gas Institute, Desert Research Institute Foundation Board, Western Energy Institute and several not-for-profit organizations.

John F. O’Reilly, 60

Chairman and Chief Executive Officer of the law firm of O’Reilly Law Group LLC and John F. O’Reilly, APC, Chairman and an Officer and/or a Board member of various family-owned business entities and related investments and businesses. He serves as a Director of the Community Board of Wells Fargo Bank Nevada, N.A., Director of Herbst Gaming, Inc., UNLV Foundation,

189

Nevada Development Authority, Advisory Board of Boys and Girls Clubs of Las Vegas, a member of the Las Vegas Chamber of Commerce Government Affairs Committee, and is involved in various other capacities in other not-for-profit organizations, including Vision 2020, on which he serves as Chairman/CEO and Board member.

Directors whose terms expire in 2008:

Joseph B. Anderson, Jr., 63

Chairman and CEO of TAG Holdings, LLC. Mr. Anderson is on the Board of Rite Aid Corporation, Quaker Chemical Corporation and ArvinMeritor, Inc., the Board of Governors of the Center for Creative Leadership, and the Board of Trustees for the National Recreation Foundation. He is Director of the Original Equipment Suppliers Association and Director of the Society of Automotive Engineers Foundation. Mr. Anderson was elected as a Director of SPR, SPPC and NPC in February 2005.

Krestine M. Corbin, 68

President and Chief Executive Officer of Sierra Machinery, Incorporated, a machine tool manufacturing company, since 1984 and a director of that company since 1980. Ms. Corbin has served as a Director of SPR since 1989, of SPPC since 1992, and was elected a Director of NPC in July 1999.

Philip G. Satre, 56

Mr. Satre retired January 1, 2005, as Chairman of the Board, Harrah’s Entertainment, Inc., a gaming entertainment company. Previously he was CEO of Harrah’s Entertainment from 1993 to 2003. He is a Director of the National Center for Responsible Gaming, the Nevada Cancer Institute, TABCORP Holdings Limited (Australia), Nordstrom Inc., and Rite Aid Corporation. He is a Trustee of Stanford University, The National D-Day Museum Foundation and the UC Davis School of Law Alumni Association Board. Mr. Satre was elected as a Director of SPR, SPPC, and NPC in January 2005.

Clyde T. Turner, 68

Owner and Manager of Turner Investments, a general-purpose investment company, Global Trust Ventures, LLC and Global Trust Ventures Management, LLC, Private Equity Fund and several special-purpose real estate development companies known as Spectrum Companies and TurnKee, Ltd. Mr. Turner is the retired Chairman and Chief Executive Officer of Mandalay Bay Resort & Casino. He was elected a Director of SPR, NPC, and SPPC in November 2001.

Messrs. Day and Higgins are Directors of Tuscarora Gas Pipeline Company; Mr. Higgins is a Director of Lands of Sierra, Inc., Great Basin Energy Company, Sierra Pacific Energy Company, Sierra Pacific Communications, Sierra Water Development Company, Sierra Gas Holdings Company, Piñon Pine Co. LLC, SPPC Funding LLC, and Nevada Electric Investment Co. All of the above-listed companies are subsidiaries of Sierra Pacific Resources, with the exception of Piñon Pine Co. LLC, and SPPC Funding LLC which are subsidiaries of Sierra Pacific Power Company and Nevada Electric Investment Co. which is a subsidiary of Nevada Power Company.

(b) Executive Officers

See Executive Officers of the Registrant immediately following Item 4.

(c) Although all outstanding shares of SPPC’s common stock are held by SPR and it is SPR’s common stock which is traded on the New York Stock Exchange, SPPC has one series of non-voting preferred stock outstanding and registered under the Securities Exchange Act of 1934 (the Act). As a technical matter, SPPC is thus deemed an “issuer” for purposes of the Act whose officers are required to make filings with respect to beneficial ownership, if any, of those non-voting preferred securities. SPPC’s officers, all of whom are currently reporting pursuant to Section 16(a) of the Act with respect to SPR’s common stock, have filed reports with respect to SPPC’s preferred stock, which reports show no past or current beneficial ownership of such preferred stock.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Securities Exchange Act of 1934, or the Exchange Act, requires that Directors, officers, and any holders of more than 10% of the Company’s common stock file reports with the SEC disclosing ownership of the Company’s stock and changes in beneficial ownership. Officers, Directors and 10% stockholders are required by SEC regulations to furnish the Company with copies of all Section 16(a) forms they file.

To SPR’s knowledge, based solely on review of the Company’s records and written representations by persons required to file these reports, during 2005, all filing requirements under Section 16(a) were complied with in a timely fashion, except that Stephen R.

190

Wood, an officer of SPR, filed on May 6, 2005 a Form 4 for a stock issuance related to restricted stock that had vested, which report was due on April 8, 2005; each of Roberto R. Denis and Julian C. Leone, officers of the Company, filed on August 11, 2005, a Form 4 for stock issuance related to restricted stock that had vested, which reports were due on July 19, 2005 and June 16, 2005, respectively; each of T.J. Day and Clyde Turner, directors of the Company, filed on February 14, 2006 a Form 5 for stock deemed acquired, which reports were due on June 3, 2005; and each of Carolyn Barbash, Susan Brennan, John Brown, Jeff Ceccarelli, Roberto Denis, Julian Leone, Carol Marin, Donald Shalmy, Mary Simmons, Michael Smart, Stephen R. Wood and Michael Yackira, officers of the Company, filed on February 14, 2006, a Form 4 for options grants; which reports were due on February 9, 2005.

Audit Committee

The Audit Committee consists of the following individuals: Philip Satre, Krestine M. Corbin, Donald Snyder and Clyde T. Turner who are all independent as defined under applicable rules promulgated under the Exchange Act. The Board of Directors of SPR, NPC and SPPC have determined that Audit Committee member Clyde T. Turner is an “audit committee financial expert” as defined by the SEC.

Code of Ethics

SPR, NPC and SPPC have adopted a code of ethics that applies to its Chief Executive Officer, Chief Financial Officer and to its Controller. Printed copies of the code of ethics may be obtained free of charge by writing to SPR’s Corporate Secretary at Sierra Pacific Resources, P.O. Box 30150, Reno, NV 89520-3150.

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ITEM 11. EXECUTIVE COMPENSATION

SUMMARY COMPENSATION TABLE

The following table sets forth information about the compensation of the Chief Executive Officer and each of the four most highly compensated officers for services in all capacities to SPR and its subsidiaries.


									Long-Term Compensation
									Awards
			Annual Compensation								Securities
							Other Annual		Restricted		Underlying		Payout		All Other
Name and Principal							Compensation		Stock Awards		Options/ SARs		LTIP Payouts		Compensation
Position	Year		Salary ($)		Bonus ($)		($)		($)		(#)		($)		($)
(a)	(b)		(c)		(d)		(e) (2)		(f) (3)		(g)		(h)		(i) (4)
\| \| \| \| \| \| \| \|
Walter M. Higgins		2005	$	689,808	$	632,798	$	93,887	$	—		—	$	1,352,470	$	444,271
Chairman of the Board,		2004	$	646,538	$	520,041	$	75,344	$	—		—	$	1,324,302	$	108,795
President, and Chief		2003	$	640,385	$	325,500	$	91,753	$	837,540		—	$	—	$	472,830
Executive Officer

Michael W. Yackira		2005	$	362,116	$	219,000	$	47,850	$	—		23,298	$	131,723	$	25,859
Corporate Executive Vice		2004	$	343,139	$	185,000	$	38,392	$	—		—	$	—	$	24,945
President, Chief Financial		2003	$	276,923	$	120,000	$	20,400	$	248,384		30,000	$	—	$	256,257
Officer

Jeffrey L. Ceccarelli		2005	$	304,808	$	182,900	$	23,728	$	—		18,159	$	118,335	$	67,179
Corporate Sr. Vice		2004	$	263,269	$	142,000	$	29,514	$	—		—	$	48,420	$	31,265
President, Service Delivery		2003	$	257,308	$	110,000	$	28,711	$	223,146		—	$	—	$	23,901
and Operations

Donald L. Shalmy		2005	$	304,423	$	179,035	$	39,517	$	—		20,557	$	132,804	$	24,060
Corporate Sr. Vice		2004	$	300,000	$	150,000	$	38,738	$	—		—	$	—	$	21,535
President, Policy and		2003	$	311,539	$	120,000	$	38,702	$	250,424		—	$	—	$	21,089
External Affairs

Roberto R. Denis		2005	$	278,846	$	180,000	$	16,739	$	—		13,876	$	122,062	$	23,792
Corporate Sr. Vice		2004	$	268,846	$	131,000	$	29,056	$	—		—	$	27,397	$	24,860
President, Generation and		2003	$	100,000	$	60,000	$	3,808	$	203,080		25,000	$	—	$	206,806
Energy Supply

The table below shows executive perquisites for Mr. Higgins under Other Annual Compensation which exceed 25% of total perquisites included in column (e).


	Walter M.
Description	Higgins

Cash in lieu of Forgone Vacation	$	63,887

Tax, Memberships, Automobile & Other	$	30,000

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Restricted Stock Grants:

•

Restricted stock grants were issued in 2003 to each of the named executive officers. The shares vest in three equal installments, with one third vesting in each of the years ended December 31, 2004, 2005, and 2006. These shares are entitled to receive dividends, if declared. The shares that vested on December 31, 2005 were issued in early January 2006. The aggregate value of those shares that vested on December 31, 2005 and the restricted stock remaining unvested at December 31, 2005, calculated using the closing price of the Company’s common stock as listed on the NYSE on December 31, 2005 of $13.04, was as follows:


			Value
	Remaining		at December 31, 2005
Name	Shares (#)		($)

Walter M. Higgins		84,600	$	1,103,184
Michael W. Yackira		25,089	$	327,161
Jeffrey L. Ceccarelli		22,540	$	293,922
Donald L. Shalmy		25,295	$	329,847
Roberto R. Denis		18,534	$	241,683

•

In addition, Mr. Denis was awarded a grant of 10,000 restricted shares upon his hire in 2003 at a grant price of $5.26 per share. The shares vest in three equal installments, with one-third vesting on July 17, 2004, 2005 and 2006. The value of the 3,334 shares remaining unvested on December 31, 2005, calculated using the closing price of the Company’s common stock as listed on the NYSE on December 31, 2005 of $13.04, was $43,475.

Amounts for All Other Compensation include the following for 2005:


	Walter M.		Michael W.		Jeffrey L.		Donald L.		Roberto R.
Description	Higgins		Yackira		Ceccarelli		Shalmy		Denis

Company contributions to the 401k deferred compensation plan	$	12,600	$	12,600	$	12,600	$	12,600	$	12,600

Company paid portion of Medical/Dental/Vision Benefits	$	10,422	$	10,422	$	10,422	$	3,722	$	7,817

Imputed income on group term life insurance premiums paid by SPR	$	4,308	$	1,567	$	1,197	$	4,570	$	1,543

Insurance premiums paid for executive term life policies	$	8,077	$	1,270	$	960	$	3,168	$	1,832

Retention Incentive	$	333,333	$	—	$	—	$	—	$	—

Housing Allowance	$	75,531	$	—	$	42,000	$	—	$	—

Total	$	444,271	$	25,859	$	67,179	$	24,060	$	23,792

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Options/SAR Grants in Last Fiscal Year

The following table shows all grants of options to the named executive officers of SPR in 2005. Pursuant to SEC rules, the table also shows the present value of the grant at the date of grant.


	Number of		Percent of Total
	Securities		Options/SAR’s
	Underlying		Granted to
	Options/SAR’s		Employees in			Exercise Base				Grant Date
Name	Granted		Fiscal Year			Price ($/share)		Expiration Date		Present Value
(a)	(b) (1)		(c)			(d)		(e)		(f) (2)

Walter M. Higgins		—		—		$	—			$	—

Michael W. Yackira		23,298		13.78	%	$	10.05		02/07/2015	$	117,189

Jeffrey L. Ceccarelli		18,159		10.74	%	$	10.05		02/07/2015	$	91,340

Donald L. Shalmy		20,557		12.16	%	$	10.05		02/07/2015	$	103,402

Roberto R. Denis		13,876		8.21	%	$	10.05		02/07/2015	$	69,796


1.		Eighty percent of each of these options vests in equal annual installments over the three years following the date of grant, which was February 7, 2005, in each case, and the remaining 20% will vest only upon the restoration of the quarterly common stock dividend within five years of the date of grant.

The hypothetical grant-date present values are calculated under the Black-Scholes Model. The Black-Scholes Model is a mathematical formula used to value options traded on stock exchanges. The assumptions used in determining the option grant date present value listed above include the stock’s average expected volatility (39.56%), average risk free rate of return (2.32%), average projected dividend yield (0.00%), and the stock option term (10 years).

Aggregated Option/SAR Exercises in Last Fiscal Year and Fiscal Year-End Option/SAR Values

The following table provides information as to the value of the options held by the named executive officers at year-end measured in terms of the closing price of Sierra Pacific Resources common stock on December 31, 2005:


	Shares				Number of Securities Underlying				Value of Unexercised in-the-
	Acquired on		Value		Unexercised Options/SARs at Fiscal				money Options/SARs at Fiscal
Name	Exercise		Realized		Year-End				Year-End
(a)	(b)		(c)		(d)				(e)
					Exercisable		Unexercisable		Exercisable		Unexercisable

Walter M. Higgins		—		—		634,030		—	$	—	$	—
Michael W. Yackira		—		—		30,000		23,298	$	209,700	$	69,661
Jeffrey L. Ceccarelli		—		—		83,150		18,159	$	—	$	54,295
Donald L. Shalmy		—		—		25,000		20,557	$	163,000	$	61,465
Roberto R. Denis		—		—		25,000		13,876	$	194,500	$	41,489


(e)		Pre-tax value of in-the-money options based on December 31, 2005, closing trading price of $13.04, less the option exercise price.

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Long-Term Incentive Plans

The executive Long-Term Incentive Plan (LTIP), which was approved by stockholders in 1994 and renewed by stockholders in the merger of SPR and NPC in 1999, expired at the end of 2003. Because of its long-term success in motivating management and tying executive compensation to long-term stockholder value and overall corporate performance, the Board adopted a new LTIP, with substantially the same terms and conditions, for an additional ten years beginning in 2004. The stockholders subsequently approved the new LTIP. The LTIP provides for the granting of a wide variety of long-term incentive compensation, including stock options (both nonqualified and qualified), stock appreciation rights (SARs), restricted stock, performance units, performance shares, bonus stock, incentive stock and cash, to participating employees as an incentive for outstanding performance. Incentive compensation is based on the achievement of pre-established goals for SPR. Goals are established by the Board prior to the performance period in question, and are based on criteria which the Board, in its discretion, determines will best promote or enhance stockholder value and the overall interests of the corporation.

In January 2005, the Board of Directors granted the named executive officers 96,343 performance shares. The specific grants to the named executive officers appear opposite their respective names in the table below, together with the period, threshold, target, and maximum levels of possible award under the grant. The grants will be earned based on performance criteria which include total shareholder return performance against a peer group and other measures established by the Board in February 2005, over a performance period ending in 2008. The grants are subject to adjustment based on the level of achievement of these performance measures.


	Number of		Performance
	Shares,		or Other
	Units or		Period Until		Future Payouts Under Non-Stock Price-Based Plans
	Other		Maturation or		Threshold
Name	Rights		Payout		(#)		Target (#)		Maximum (#)
(a)	(b)		(c)		(d) (1)		(e) (2)		(f) (3)

Walter M. Higgins		—		—		—		—		—

Michael W. Yackira
Grant Date 01/01/2005		23,662		2008		11,831		23,662		35,493
Grant Date 01/01/2005		5,915		2008		N/A		5,915		N/A

Donald L. Shalmy
Grant Date 01/01/2005		20,878		2008		10,439		20,878		31,317
Grant Date 01/01/2005		5,219		2008		N/A		5,219		N/A

Jeffrey L. Ceccarelli
Grant Date 01/01/2005		18,442		2008		9,221		18,442		27,663
Grant Date 01/01/2005		4,611		2008		N/A		4,611		N/A

Roberto R. Denis
Grant Date 01/01/2005		14,093		2008		7,047		14,093		21,140
Grant Date 01/01/2005		3,523		2008		N/A		3,523		N/A


1.		The threshold represents the minimum acceptable performance which, if attained, results in payment of 50% of the target award. Performance below the minimum acceptable level results in no award earned.

2.		The target indicates a level of outstanding performance and which, if attained, results in payment of 100% of the target award.

3.		The maximum represents a level indicative of exceptional performance which, if attained, results in a payment of 150% of the target award.

Mr. Higgins did not receive a grant of performance shares under the plan described above. However, his employment contract provides for incentives in the form of an opportunity to earn 600,000 shares of Company stock based on a company performance over a six year period commencing September 26, 2003. This incentive was originally in the form of phantom stock, but was subsequently converted to performance shares at the time the LTIP was approved by shareholders in May 2004. Mr. Higgins earned 76,400 shares during 2005, the value of which is included in column (h) of the Summary Compensation Table.

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Nonqualifying stock options granted to the named executives as part of the LTIP are shown in the table “Option/SAR Grants in Last Fiscal Year,” and restricted stock grants are detailed in the footnotes to the “Summary Compensation Table.”

Pension Plans

The following table shows annual benefits payable on retirement at normal retirement age 65 to elected officers under SPR’s qualified and non-qualified defined benefit plans based on various levels of remuneration and years of service which may exist at the time of retirement. The amounts below are based upon a maximum benefit of 60% of final average earnings used under the Supplemental Executive Retirement Plan. This maximum is reduced to 50% for any Officer who became a participant after November 1, 1999.


Highest
Average Five-
Years	Annual Benefits for Years of Services Indicated
Remuneration	15 Years		20 Years		25 Years		30 Years		35 Years

$ 60,000	$	27,000	$	31,500	$	36,000	$	36,000	$	36,000
$120,000	$	54,000	$	63,000	$	72,000	$	72,000	$	72,000
$180,000	$	81,000	$	94,500	$	108,000	$	108,000	$	108,000
$240,000	$	108,000	$	126,000	$	144,000	$	144,000	$	144,000
$300,000	$	135,000	$	157,500	$	180,000	$	180,000	$	180,000
$360,000	$	162,000	$	189,000	$	216,000	$	216,000	$	216,000
$420,000	$	189,000	$	220,500	$	252,000	$	252,000	$	252,000
$480,000	$	216,000	$	252,000	$	288,000	$	288,000	$	288,000
$540,000	$	243,000	$	283,500	$	324,000	$	324,000	$	324,000
$600,000	$	270,000	$	315,000	$	360,000	$	360,000	$	360,000
$660,000	$	297,000	$	346,500	$	396,000	$	396,000	$	396,000
$720,000	$	324,000	$	378,000	$	432,000	$	432,000	$	432,000

SPR’s noncontributory qualified retirement plan provides retirement benefits to eligible employees upon retirement at a specified age. Annual benefits payable are determined by a formula based on years of service and final average earnings consisting of base salary and annual incentive compensation. Remuneration for the named executives is the amount shown in columns (c) and (d) of the Summary Compensation Table. Pension costs of the retirement plan, to which SPR contributes 100% of the funding, are not and cannot be readily allocated to individual employees and are not subject to Social Security or other offsets.

The years of credited service under the qualified retirement plan for the named executive officers are as follows: Mr. Higgins 9.5, Mr. Yackira 2.9 (not vested), Mr. Ceccarelli 30.3, Mr. Shalmy 3.6 and Mr. Denis 2.3 (not vested).

A supplemental executive retirement plan (SERP) and a restoration plan are also offered to the named executive officers. The SERP is intended to ensure the payment of a competitive level of retirement income to attract, retain and motivate selected executives. The Restoration Plan is intended to provide benefits to executive officers whose benefits cannot be paid under the qualified plan because of salary deferrals to the Non-Qualified Deferred Compensation Plan, IRS limitations on compensation that can be recognized by a qualified plan, and IRS limitations on benefits payable from a qualified plan.

The years of credited service under the non-qualified SERP are as follows: Mr. Higgins 14.4, Mr. Yackira 2.9 (not vested), Mr. Ceccarelli 31.3 (not vested), Mr. Shalmy 3.6 (not vested) and Mr. Denis 2.3 (not vested).

Severance Arrangements

Individual change of control severance allowance plans exist for the named executive officers which provide for severance pay, payable in a lump sum, if within 24 months after a change in control of SPR, there is a termination of employment by SPR or a termination of employment by the employee for good reason, in each case as described in the plans. In these circumstances, officers are entitled to a severance allowance not to exceed an amount equal to 24 or 36 months of the officer’s base salary and any bonus and the continuation for up to 24 or 36 months of participation in SPR’s group medical and life insurance plans, and certain other benefits. Change in control is defined in the plans as, among other things, a dissolution or liquidation, a reorganization, merger or consolidation in which SPR is not the surviving corporation, the sale of all or substantially all the assets of SPR, or the acquisition by any person or

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entity of 30% or more of the voting power of SPR, or except in the case of Mr. Higgins, a sale or disposition of either NPC or SPPC. See Exhibits to 2004 Form 10K for the Employment Agreement for Walter M. Higgins, which contains severance arrangements applicable to him.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

Voting Stock

The following table indicates the shares owned by the only investors known to SPR, to beneficially own or control more than 5 percent of any class of its voting stock as of March 1, 2006.


	Shares Beneficially
Name and Address of Beneficial Owner	Owned		Percent of Class
Canyon Capital Advisors LLC (1)		10,486,013		5.22	%
9665 Wilshire Blvd. Suite 200
Beverly Hills, CA 90212

Kinetics Asset Management, Inc. (2)		10,478,530		5.21	%
470 Park Avenue South
4^th Floor South
New York, NY 10016


(1)		Based on a Form 13-G filed by Canyon Capital Advisors LLC on February 14, 2006 reporting the above stock ownership as of such date.

(2)		Based on a Form 13F-HR filed by Kinetic Asset Management, Inc. on November 17, 2005, reporting the above stock ownership as of September 30, 2005.

The table below sets forth the shares of Sierra Pacific Resources Common Stock beneficially owned by each director, nominee for director, the Chief Executive Officer, and the four other most highly compensated executive officers. No director, nominee for director or executive officer owns, nor do the directors and executive officers as a group own, in excess of one percent of the outstanding and issued Common Stock of SPR. Unless otherwise indicated, all persons named in the table have sole voting and investment power with respect to the shares shown.


	Common Shares
	Beneficially		Percent of Total Common
	Owned as of		Shares Outstanding as of
Name of Director or Nominee	March 1, 2006		March 1, 2006
Joseph B. Anderson		3,285
Mary L. Coleman (1)		167,881
Krestine M. Corbin (1)		39,851
Theodore J. Day (1)		53,899
James R. Donnelley (1)		58,791
Jerry E. Herbst (1)		29,099	No director or nominee for director owns in excess of one percent.
Walter M. Higgins (2)(3)		684,585
John F. O’Reilly (1)		33,718
Philip G. Satre		11,435
Donald D. Snyder		4,000
Clyde T. Turner		11,211

Total		1,097,755


	Common Shares
	Beneficially	Percent of Total Common
	Owned as of	Shares Outstanding as of
Executive Officers	March 1, 2006	March 1, 2006
Walter M. Higgins (2)(3)	684,585
Donald L. Shalmy (2)(3)	49,081	No executive officer owns
Michael W. Yackira (2)(3)	53,148	in excess of one percent
Jeffrey L. Ceccarelli (2)(3)	112,243
Roberto R. Denis (2)(3)	41,690
All executive officers and directors as a group (27 persons) (1)(2)(3)	1,445,738


(1)		Includes shares of “phantom stock” representing the actuarial value of certain directors’ vested benefits in the terminated Retirement Plan for Outside Directors, payable at the time of the respective directors’ departure from the Board, in the following amounts: Ms. Coleman, Ms. Corbin, Messrs. Day, Donnelly, Herbst and O’Reilly 9,217, 10,188, 15,354, 13,818, 7,731 and 6,957 shares, respectively.

(2)		Includes shares acquired through participation in the Employee Stock Purchase Plan and/or the 401(k) plan.

(3)		Includes shares issuable under the Long-Term Incentive Plan within 60 days of March 1, 2006, to Messrs. Higgins, Shalmy, Yackira, Ceccarelli, Denis, and directors and executive officers as a group in the amounts of 634,030, 30,427, 36,150, 87,943, 28,663 shares, and 965,287 shares, respectively.

197

Equity Compensation Plan Information

Number of securities remaining

available for future issuance

Number of securities to be issued

Weighted-average exercise

under equity compensation

upon exercise of outstanding

price of outstanding

plans (excluding securities

options, warrants and rights

reflected in column(a))

Plan category

(a)

(b)

(c)

(1) Non-Employee Director Stock Plan

602,598 shares

(2) Employee Stock Purchase Plan

428,966 shares

(3) Long-Term Incentive Plan

928,368 shares

14.91

6,557,933 shares

Total

7,589,497 shares


	(1)		The 2003 Non-Employee Director Stock Plan was approved at the April 11, 2003 meeting of shareholders. The 2003 Non-Employee Director Stock Plan provides for the issuance of up to 700,000 shares of Common Stock over a ten-year period to members of the Company’s Board of Directors who are not employees of the Company in lieu of a portion of the annual retainer paid to those individuals for their service on the Company’s Board of Directors. The 2003 Director Stock Plan replaced a similar plan that was approved by shareholders in 1999 and expired on December 31, 2001.

	(2)		The Employee Stock Purchase Plan was approved by the shareholders of SPR on June 19, 2000. Under SPR’s Employee Stock Purchase Plan, eligible employees of SPR and any of its subsidiaries may save regularly by payroll deductions and twice each year use their savings to purchase SPR’s Common Stock. A total of 428,966 shares of SPR common stock are reserved for issuance under the Employee Stock Purchase Plan. Through March 1, 2006 we had issued 271,034 shares thereunder. In addition, an offering period under the Plan is currently in effect and scheduled to expire on June 1, 2006 on which date we will issue an additional number of shares to be determined at such time.

	(3)		The Executive Long-Term Incentive Plan (LTIP) provides for the granting of stock options (both “nonqualified” and “qualified”), stock appreciation rights (SAR’s), restricted stock performance units, performance shares and bonus stock to participating employees an incentive for outstanding performance. Incentive compensation is based on the achievement of pre-established financial goals for SPR.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Change in Control Agreements

On January 1, 2005, SPR entered into change in control severance agreements with certain members of its executive staff, including Jeffrey L. Ceccarelli, Michael W. Yackira, Stephen R. Wood, Roberto R. Denis, Mary O. Simmons, John E. Brown, and Donald L. Shalmy. Upon their hire in June 2005 and February 2006, William D. Rogers and Paul L. Kaleta were provided agreements, respectively. These agreements expire on December 31, 2007, except in the case of Paul L. Kaleta whose agreement expires February 28, 2009, and provide that, upon termination of the executive’s employment during the term of the Agreement (subject to an extension in the event a Potential Change in Control, as defined in the agreement, occurs during the term) following a change in control of SPR (as defined in the agreement) either (a) by SPR for reasons other than cause (as defined in the agreements), death or disability, or (b) by the executive for good reason (as defined in the agreement), including a diminution of responsibilities, compensation, or benefits (unless, with respect to reduction in salary or benefits, such reduction is applicable to all senior executives of SPR), the executive will receive certain payments and benefits. These severance payments and benefits include (i) a lump sum payment equal to two or, with respect to certain senior officers, three times the sum of the executive’s base salary and target incentive, (ii) a lump sum payment equal to the present value of the benefits the executive would have received had he continued to participate in SPR’s retirement plans for an additional two or three years (or, in the case of SPR’s Supplemental Executive Retirement Plan only, the greater of three years or the period from the date of termination until the executive’s early retirement date, as defined in such plan), and (iii) continuation of life, disability, accident and health insurance benefits for a period of 24 or 36 months immediately following termination of employment The agreements also provide that if any compensation paid, or benefit provided, to the executive, whether or not pursuant to the change in control agreements, would be subject to the federal excise tax on “excess parachute payments,” payments and benefits provided pursuant to the agreement will be cut back to the largest amount that would not be subject to such excise tax, if such cutback results in a higher after-tax payment to the executive. The Board of Directors entered into these agreements in order to attract and retain management and to encourage and reinforce continued attention to the executives’ assigned duties without distraction under circumstances arising from the possibility of a change in control of SPR. In entering into these agreements, the Board was advised by Towers Perrin, the national compensation

198

and benefits consulting firm described above, to insure that the agreements entered into were in line with existing industry standards, and provided benefits to management consistent with those standards.

Employment Agreements

Walter M. Higgins

On September 26, 2003, SPR, NPC and SPPC entered into an employment agreement with Mr. Higgins, which superseded and replaced his existing employment agreement, which was entered into when Mr. Higgins agreed to leave his former employment as Chairman and CEO of AGL Resources, and accept a similar position with the Company. The agreement expires September 26, 2006, unless the parties mutually agree to extend it. Negotiations to extend Mr. Higgins’ agreement are currently in process. The agreement provides that Mr. Higgins will remain in his current position as CEO and Chairman of the Board of the Companies for the full term of the contract, and will devote full-time best efforts to his office and to the business of the Company. The contract provides that, during the term, Mr. Higgins will receive a base salary commensurate with his position as determined by the Board, but generally in an amount not less than $620,000 per annum, and shall be eligible to receive annual cash incentive awards at a target level of not less than 70% of base salary based on the extent to which he and the Company achieve criteria and performance targets established by the Board at the commencement of each annual performance period. As a special incentive to remain with the Company for the entire duration of his contract, the agreement provides that he shall receive a cash payment of $333,333 on September 26, 2003, and on the second and third anniversaries of such date. Mr. Higgins will also be entitled to benefits provided by all Company health, welfare, and pension plans and vacation, and remains eligible for long-term incentive awards based on and in accordance with the terms and conditions of the plans and generally on the same basis as such plans are made available to all other senior officers of the Company, except that with respect to the SERP, Mr. Higgins shall be entitled to one year of credit for each year of service for previous employment with AGL Resources and Louisville Gas & Electric. The agreement also provides that Mr. Higgins shall be reimbursed for travel and other business expenses plus reasonable car allowance and tax preparation fees and the Company agreed to maintain his existing life insurance policy at its existing $2,000,000 level, plus an additional $1,000,000 should Mr. Higgins die while on Company business.

As a special incentive, Mr. Higgins was awarded an opportunity to earn 600,000 performance-based phantom shares of stock, which were converted into performance shares in 2004 after stockholders renewed the Company’s long-term incentive plan. Vesting is subject to performance-based criteria over a six-year period, commencing September 26, 2003. As of December 31, 2005, 225,000 of these shares had vested. The shares vest based on achievement of specified performance targets or criteria. One-half of any remaining unvested shares shall vest on expiration of the agreement (unless renewed) if the Board determines that the targets and criteria for vesting either were or could reasonably be achieved within the remaining time of the six-year vesting period.

In the event Mr. Higgins’ employment is involuntarily terminated without cause or he terminates employment for good reason (as defined in the agreement) during the employment term, he shall be entitled to receive all unpaid base salary and any fully vested unpaid benefits, one-year’s base salary, and an annual incentive award based on target performance (i.e., not less than 70% of annual base salary), and a pro-rata share (based on the length of time employed during the term of the applicable period) of any unvested phantom shares and/or other incentive-based form of compensation he was eligible to receive at the time of termination had his employment continued; provided, that no payment will be made, in respect of the 600,000 performance-based phantom shares, unless the Board determines at that time that the targets established could be reasonably achieved by the end of the term. After termination, he and his eligible dependents would also receive 36 months of health, dental, and life benefits. In the event of termination without cause following a change in control of the Company as further defined in the agreement, Mr. Higgins would not receive the benefits on termination without cause as defined above. In the event of a termination, within 24 months following a change in control of SPR either (a) by SPR for reasons other than cause (as defined in the agreement), death or disability, or (b) by Mr. Higgins for good reason (as defined in the agreement), he will receive (i) a lump sum payment equal to three times the sum of his base salary and target incentive, (ii) a lump sum payment equal to the present value of the benefits he would have received had he continued to participate in SPR’s retirement plans for an additional three years, and (iii) continuation of life, disability, accident and health insurance benefits for a period of 36 months immediately following termination of employment.

If Mr. Higgins becomes subject to an excise tax on “excess parachute payments,” SPR will provide Mr. Higgins with a tax gross-up so that the net amount he receives after paying the excise tax and any additional taxes on the gross-up will equal the amount he would have received if he had not been subject to the excise tax. However, if up to a 10% reduction in the benefits otherwise payable to Mr. Higgins would result in Mr. Higgins not being subject to the excise tax, then Mr. Higgins’ benefits will be so reduced, the excise tax would not apply and no additional payment will be made to Mr. Higgins in respect of the excise tax.

Affiliate Transactions and Relationships

Employees of SPR provide certain accounting, treasury, information technology and administrative services to NPC and SPPC. The costs of those services are allocated among the three Utilities according to each Utility’s usage. Additionally, many of SPR’s officers are also officers of NPC and SPPC. All three Companies have the same members of their respective boards of directors.

199

SPR files a consolidated federal income tax return for itself and its subsidiaries. Current income taxes are allocated based on each entity’s respective taxable income or loss and investment tax credits as if each subsidiary filed a separate return. SPR does not believe that any significant additional tax liability would be incurred by any of its subsidiaries on behalf of any other subsidiary; however, SPR and its subsidiaries could potentially incur certain tax liabilities as a result of the joint tax filing in the event of a change in applicable law or as a result of an audit.

As part of their on-going cash management practices and operations, SPR may make intercompany loans to the Utilities, subject to any applicable regulatory restrictions and restrictions under SPR’s or the Utilities’ financing agreements.

Related Party Transactions

The son of John F. O’Reilly, a member of the Company’s Board of Directors, is associated with the Waller Law Group, which is acting as co-counsel for the Company in two significant litigation matters. Mr. O’Reilly’s son is not working on either matter, and neither Mr. O’Reilly nor his son receives any compensation or other benefits from the Company related to these matters.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

The following table summarizes the aggregate fees billed to SPR, NPC and SPPC by our independent registered public accounting firm, Deloitte and Touche LLP.


	NPC				SPPC				SPR Consolidated
	2005		2004		2005		2004		2005		2004 (d)
Audit Fees (a)	$	1,359,499	$	1,506,977	$	1,295,521	$	1,298,232	$	3,193,123	$	3,245,688
Audit Related Fees (b)		—		171,263		36,308		171,263		94,693		360,554
All Other Fees (c)		—		224,128		—		21,348		29,560		247,723

Total	$	1,359,499	$	1,902,368	$	1,331,829	$	1,490,843	$	3,317,376	$	3,853,965


(a)		Fees for audit services billed in 2005 and 2004 consisted of:

	§		Audit of the companies financial statements

	§		Reviews of the companies quarterly financial statements

	§		Comfort letters, statutory and regulatory audits, consents and other services related to SEC matters.

(b)

Fees for audit related services billed in 2005 and 2004 consisted of:

	§		Sarbanes-Oxley Act, Section 404 advisory services

	§		Agreed upon procedures

(c)

Fees for all other services billed in 2004 consisted of permitted non-audit services, such as:

	§		Financial accounting consultations

	§		Business consulting

(d) 2004 Audit fees have been adjusted from information previously presented to reflect fees for audit services relating to the audit of the 2004 financial statements, including internal controls over financial reporting for SPR, billed subsequent to the filing of the 2004 proxy statement.

In considering the nature of the services provided by the independent registered public accounting firm, the Audit Committee determined that such services are compatible with the provision of independent audit services. The Audit Committee discussed these services with the independent auditor and management to determine that they are permitted under the rules and regulations concerning auditor independence promulgated by the SEC to implement the Sarbanes-Oxley Act of 2002, as well as the American Institute of Certified Public Accountants.

Pre-Approval Policy

The services performed by Deloitte and Touche LLP, in 2005 were pre-approved in accordance with the pre-approval policy and procedures adopted by the Audit Committee at its March 10, 2005 meeting. This policy describes the permitted audit, audit-related, tax, and other services (collectively, the “Disclosure Categories”) that Deloitte and Touche may perform. The policy requires that prior to the beginning of each fiscal year, a description of the services (the “Service List”) expected to be performed by Deloitte and Touche in each of the Disclosure Categories in the following fiscal year be presented to the Audit Committee for approval.

Services to be provided by Deloitte and Touche LLP for 2005 that are included in the Service List were pre-approved following the policies and procedures of the Audit Committee.

Any requests for audit, audit related, tax, and other services not contemplated on the Service List must be submitted to the Audit Committee for specific pre-approval and cannot commence until such approval has been granted. Normally, pre-approval is provided at regularly scheduled meetings. However, the authority to grant specific pre-approval between meetings, as necessary, has been delegated to the Chairman of the Audit Committee. Under the policy, the Chairman must update the Audit Committee at the next regularly scheduled meeting of any services that were granted specific pre-approval.

In addition, although not required by the rules and regulations of the SEC, the Audit Committee (generally) requests a range of fees associated with each proposed service on the Service List and any services that were not originally included on the Service

200

List. Providing a range of fees for a service incorporates appropriate oversight and control of the independent auditor relationship, while permitting the Company to receive immediate assistance from the independent auditor when time is of the essence.

On a quarterly basis, the Audit Committee reviews the status of services and fees incurred year-to-date against the original Service List and the forecast of remaining services and fees for the fiscal year.

The policy contains a de minimis provision that operates to provide retroactive approval for small immaterial and permissible non-audit services under certain circumstances. The provision allows for the pre-approval requirement to be waived if all of the following criteria are met:

	1.		The service is not an audit, review or other attest service;

	2.		The aggregate amount of all such services provided under this provision does not exceed the lesser of $50,000 or five percent of total fees paid to the independent auditor in a given fiscal year;

	3.		Such services were not recognized at the time of the engagement to be non-audit services;

	4.		Such services are promptly brought to the attention of the Audit Committee and approved by the Audit Committee or its designee; and

	5.		The service and fee are specifically disclosed in the Proxy Statement as meeting the de minimis requirements.

During 2005, fees for audit related services, tax services and all other fees were pre-approved by the Audit Committee or Chairman of the Audit Committee.

201

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) Financial Statements, Financial Statement Schedules and Exhibits


		Page
1.	Financial Statements:

	Reports of Independent Registered Public Accounting Firm		99

	Sierra Pacific Resources:
	Consolidated Balance Sheets as of December 31, 2005 and 2004		102
	Consolidated Statements of Operations for the Years Ended December 31, 2005, 2004 and 2003		104
	Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2005, 2004 and 2003		105
	Consolidated Statements of Common Shareholders’ Equity for the Years Ended December 31, 2005, 2004 and 2003		106
	Consolidated Statements of Cash Flows for the Years Ended December 31, 2005, 2004 and 2003		107
	Consolidated Statements of Capitalization as of December 31, 2005 and 2004		108

	Nevada Power Company:		110
	Consolidated Balance Sheets as of December 31, 2005 and 2004		111
	Consolidated Statements of Operations for the Years Ended December 31, 2005, 2004 and 2003		112
	Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2005, 2004 and 2003		113
	Consolidated Statements of Common Shareholder’s Equity for the Years Ended December 31, 2005, 2003 and 2004		114
	Consolidated Statements of Cash Flows for the Years Ended December 31, 2005, 2004 and 2003		115
	Consolidated Statements of Capitalization as of December 31, 2005 and 2004		116

	Sierra Pacific Power Company:		117
	Consolidated Balance Sheets as of December 31, 2005 and 2004		118
	Consolidated Statements of Operations for the Years Ended December 31, 2005, 2004 and 2003		119
	Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2005, 2004 and 2003		120
	Consolidated Statements of Common Shareholder’s Equity for the Years Ended December 31, 2005, 2004 and 2003		121
	Consolidated Statements of Cash Flows for the Years Ended December 31, 2005, 2004 and 2003		122
	Consolidated Statements of Capitalization as of December 31, 2005 and 2004		99
	Notes to Financial Statements for Sierra Pacific Resources, Nevada Power Company and Sierra Pacific Power Company

2.	Financial Statement Schedules:
	Schedule II — Consolidated Valuation and Qualifying Accounts		198

	All other schedules have been omitted because they are not required or are not applicable, or the required information is shown in the financial statements or notes thereto. Columns omitted from schedules have been omitted because the information is not applicable.

3.	Exhibits:

	Exhibits are listed in the Exhibit Index on pages 200 to 215.

202

SIGNATURES

Pursuant to the requirements of Section 13 and 15(d) of the Securities Exchange Act of 1934, Sierra Pacific Resources, Nevada Power Company and Sierra Pacific Power Company have each duly caused this report to be signed on their behalf by the undersigned, thereunto duly authorized. The signatures for each undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.


	SIERRA PACIFIC RESOURCES NEVADA POWER COMPANY SIERRA PACIFIC POWER COMPANY
	By /s/ Walter M. Higgins
	Walter M. Higgins
	Chairman, Chief Executive Officer and Director February 28, 2006

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of Sierra Pacific Resources, Nevada Power Company and Sierra Pacific Power Company and in the capacities indicated on the 28 day of February, 2006.


/s/	Michael W. Yackira	/s/	John E. Brown

	Michael W. Yackira		John E. Brown
	Executive Vice President,		Controller (Principal Accounting Officer)
	Chief Financial Officer (Principal Financial Officer)

/s/	Mary Lee Coleman	/s/	Jerry E. Herbst

	Mary Lee Coleman		Jerry E. Herbst
	Director		Director

/s/	Krestine M. Corbin	/s/	John F. O’Reilly

	Krestine M. Corbin		John F. O’Reilly
	Director		Director

/s/	Theodore J. Day	/s/	Clyde T. Turner

	Theodore J. Day		Clyde T. Turner
	Director		Director

/s/	James R. Donnelley	/s/	Joseph B. Anderson, Jr.

	James R. Donnelley		Joseph B. Anderson, Jr.
	Director		Director

/s/	Philip G. Satre	/s/	Donald D. Snyder.

	Philip G. Satre		Donald D. Snyder
	Director		Director

203

Sierra Pacific Resources

Schedule II — Consolidated Valuation and Qualifying Accounts

For The Years Ended December 31, 2005, 2004 and 2003

(Dollars in Thousands)


	Provision for Uncollectible Accounts
Balance at January 1, 2003	$	44,184
Provision charged to income		26,858
Amounts written off, less recoveries		(26,125	)

Balance at December 31, 2003	$	44,917


Balance at January 1, 2004	$	44,917
Provision charged to income		10,813
Amounts written off, less recoveries		(19,533	)

Balance at December 31, 2004	$	36,197


Balance at January 1, 2005	$	36,197
Provision charged to income		9,342
Amounts written off, less recoveries		(9,519	)

Balance at December 31, 2005	$	36,020

Nevada Power Company

Schedule II — Consolidated Valuation and Qualifying Accounts

For The Years Ended December 31, 2005, 2004 and 2003

(Dollars in Thousands)


	Provision for Uncollectible Accounts
Balance at January 1, 2003	$	33,841
Provision charged to income		24,254
Amounts written off, less recoveries		(17,798	)

Balance at December 31, 2003	$	40,297


Balance at January 1, 2004	$	40,297
Provision charged to income		7,794
Amounts written off, less recoveries		(17,190	)

Balance at December 31, 2004	$	30,901


Balance at January 1, 2005	$	30,901
Provision charged to income		6,966
Amounts written off, less recoveries		(7,481	)

Balance at December 31, 2005	$	30,386

204

Sierra Pacific Power Company

Schedule II — Consolidated Valuation and Qualifying Accounts

For The Years Ended December 31, 2005, 2004 and 2003

(Dollars in Thousands)


	Provision for Uncollectible Accounts
Balance at January 1, 2003	$	10,343
Provision charged to income		2,604
Amounts written off, less recoveries		(8,327	)

Balance at December 31, 2003	$	4,620


Balance at January 1, 2004	$	4,620
Provision charged to income		3,019
Amounts written off, less recoveries		(2,343	)

Balance at December 31, 2004	$	5,296


Balance at January 1, 2005	$	5,296
Provision charged to income		2,376
Amounts written off, less recoveries		(2,038	)

Balance at December 31, 2005	$	5,634

205

2005 FORM 10-K EXHIBIT INDEX

(a) Exhibits Index

Certain of the following exhibits with respect to SPR and its subsidiaries, Nevada Power Company, Sierra Pacific Power Company, Lands of Sierra, Inc., Sierra Pacific Energy Company, Tuscarora Gas Pipeline Company and Sierra Water Development Company, are filed herewith. Certain other of such exhibits has heretofore been filed with the Commission and is incorporated herein by reference.
(* filed herewith)

(3) Sierra Pacific Resources

	•		Restated Articles of Incorporation of Sierra Pacific Resources dated July 28, 1999 (filed as Exhibit 3(A) to Form 10-K for year ended December 31, 1999).

	•		By-laws of Sierra Pacific Resources as amended through May 3, 2005 (filed as Exhibit 3.1 to Form 8-K filed May 9, 2005).

Nevada Power Company

	•		Restated Articles of Incorporation of Nevada Power Company, dated July 28, 1999 (filed as Exhibit 3(B) to Form 10-K for year ended December 31, 1999).

	•		Amended and Restated By-Laws of Nevada Power Company dated July 28, 1999 (filed as Exhibit 3(C) to Form 10-K for year ended December 31, 1999).

Sierra Pacific Power Company

	•		Restated Articles of Incorporation of Sierra Pacific Power Company dated May 19, 1987 (filed as Exhibit (3)(A) to Form 10-K for the year ended December 31, 1993).

	•		Certificate of Amendments dated August 26, 1992 to Restated Articles of Incorporation of Sierra Pacific Power Company dated May 19, 1987, in connection with Sierra Pacific Power Company’s preferred stock (filed as Exhibit 3.1 to Form 8-K dated August 26, 1992).

	•		Certificate of Designation, Preferences and Rights dated August 31, 1992 to Restated Articles of Incorporation of Sierra Pacific Power Company dated May 19, 1987, in connection with Sierra Pacific Power Company’s Class A Series 1 Preferred Stock (filed as Exhibit 4.3 to Form 8-K dated August 26, 1992).

	•		By-laws of Sierra Pacific Power Company, as amended through November 13, 1996 (filed as Exhibit (3)(A) to Form 10-K for the year ended December 31, 1996).

	•		Articles of Incorporation of Piñon Pine Corp., dated December 11, 1995 (filed as Exhibit (3)(A) to Form 10-K for the year ended December 31, 1995).

	•		Articles of Incorporation of Piñon Pine Investment Co., dated December 11, 1995 (filed as Exhibit (3)(B) to Form 10-K for the year ended December 31, 1995).

	•		Agreement of Limited Liability Company of Piñon Pine Company, L.L.C., dated December 15, 1995, between Piñon Pine Corp., Piñon Pine Investment Co. and GPSF-B INC 1995 (filed as Exhibit (3)(C) to Form 10-K for the year ended December 31, 1995).

	•		Amended and Restated Limited Liability Company Agreement of SPPC Funding LLC dated as of April 9, 1999, in connection with the issuance of California rate reduction bonds (filed as Exhibit (3)(A) to Form 10-K for the year ended December 31, 1999).

(4) Sierra Pacific Resources

•

Indenture between Sierra Pacific Resources and The Bank of New York, dated as of May 1, 2000 for the issuance of debt securities (filed as Exhibit 4.1 to Form 8-K dated May 22, 2000).

	•		Officers’ Certificate dated August 12, 2005, establishing the terms of Sierra Pacific Resources’ 6 3/4% Senior Notes due 2017 (filed as Exhibit 4.1 to Form 10-Q for the quarter ended September 30, 2005).

	•		Form of Sierra Pacific Resources' 6 3/4% Senior Notes due 2017 (filed as Exhibit 4.2 to Form 10-Q for the quarter ended September 30, 2005).

	•		Registration Rights Agreement dated August 12, 2005 among Sierra Pacific Resources and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as representative of the Initial Purchasers of the 6 3/4% Senior Notes due 2017 (filed as Exhibit 4.3 to Form 10-Q for the quarter ended September 30, 2005).

	•		Officers’ Certificate dated June 14, 2005, establishing the terms of Sierra Pacific Resources’ 7.803% Senior Notes due 2007 (filed as Exhibit 99.1 to Form 8-K filed June 16, 2005).

	•		Form of Sierra Pacific Resources’ 7.93% Senior Notes due 2007, the terms of which were amended by the Officers’ Certificate dated June 14, 2005 as a result of remarketing the Notes (filed as Exhibit 99.1 to Form 8-K filed June 16, 2005).

206

•

Indenture dated as of March 19, 2004, between Sierra Pacific Resources and the Bank of New York, as Trustee, in connection with the issuance of 8 5/8% Senior Notes due 2014 (filed as Exhibit 4.1 to Form 10-Q for the quarter ended March 31, 2004).

•

Form of Sierra Pacific Resources’ 8 5/8% Senior Notes due 2014 (filed as Exhibit 4.1 to Form 10-Q for the quarter ended March 31, 2004).

Nevada Power Company

•

General and Refunding Mortgage Indenture, dated as of May 1, 2001, between Nevada Power Company and The Bank of New York, as Trustee (filed as Exhibit 4.1(a) to Form 10-Q for the quarter ended June 30, 2001).

	•		First Supplemental Indenture, dated as of May 1, 2001, establishing Nevada Power Company’s 8.25% General and Refunding Mortgage Bonds, Series A, due June 1, 2011 (filed as Exhibit 4.1(b) to Form 10-Q for the quarter ended June 30, 2001).

	•		Officer’s Certificate establishing the terms of Nevada Power Company’s 8.25% General and Refunding Mortgage Bonds, Series A, due June 1, 2011 (filed as Exhibit 4.l(c) to Form 10-Q for the quarter ended June 30, 2001).

	•		Form of Nevada Power Company’s 8.25% General and Refunding Mortgage Bonds, Series A, due June 1, 2011 (filed as Exhibit 4.1(d) to Form 10-Q for the quarter ended June 30, 2001).

	•		Officer’s Certificate establishing the terms of Nevada Power Company’s 10 7/8% General and Refunding Mortgage Notes, Series E, due 2009 (filed as Exhibit 4.1 to Form 10-Q for the quarter ended September 30, 2002).

	•		Form of Nevada Power Company’s 10 7/8% General and Refunding Mortgage Notes, Series E, due 2009 (filed as Exhibit 4.2 to Form 10-Q for the quarter ended September 30, 2002).

	•		Officer’s Certificate establishing the terms of Nevada Power Company’s 9% General and Refunding Mortgage Notes, Series G, due 2013 (filed as Exhibit 4.1 to Form 10-Q for the quarter ended September 30, 2003).

	•		Form of Nevada Power Company’s 9% General and Refunding Mortgage Notes, Series G, due 2013 (filed as Exhibit 4.2 to Form 10-Q for the quarter ended September 30, 2003).

	•		Officer’s Certificate establishing the terms of Nevada Power Company’s 6 1/2% General and Refunding Mortgage Notes, Series I, due 2012 (filed as Exhibit 4.1 to Form 10-Q for quarter ended June 30, 2004).

	•		Form of Nevada Power Company’s 6 1/2% General and Refunding Mortgage Notes, Series I due 2012 (filed as Exhibit 4.2 to Form 10-Q for quarter ended June 30, 2004).

	•		Officer’s Certificate establishing the terms of Nevada Power Company’s 5 7/8% General and Refunding Mortgage Notes, Series L, due 2015 (filed as Exhibit 4(A) to Form 10-K filed for year ended December 31, 2004).

	•		Form of Nevada Power Company’s 5 7/8% General and Refunding Mortgage Notes, Series L, due 2015 (filed as Exhibit 4(B) to Form 10-K filed for year ended December 31, 2004).

	•		*(A) Officer’s Certificate establishing the terms of Nevada Power Company’s 5.95% General and Refunding Mortgage Notes, Series M, due 2016.

	•		*(B) Form of Nevada Power Company’s 5.95% General and Refunding Mortgage Notes, Series M, due 2016.

	•		*(C) Registration Rights Agreement dated January 18, 2006 among Nevada Power Company, Credit Suisse First Boston LLC and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as representatives of the Initial Purchasers of the 5.95% General and Refunding Mortgage Notes, Series M, due 2016.

•

Junior Subordinated Indenture between Nevada Power and IBI Schroder Bank & Trust Company, as Debenture Trustee dated March 1, 1997 (filed as Exhibit 4.01 to Form S-3, File No. 333-21091).

	•		Trust Agreement of NVP Capital I dated March 1, 1997 (filed as Exhibit 4.03 to Form S-3, File No. 333-21091).

	•		Form of Amended and Restated Trust Agreement dated March 1, 1997 (filed as Exhibit 4.10 to Form S-3, File No. 333-21091).

	•		Form of Agreement as to Expenses and Liabilities between Nevada Power and NVP Capital I dated March 1, 1997 (filed as Exhibit 4.14 to Form S-3, File No. 333-21091).

	•		Form of Preferred Security Certificate for NVP Capital I and NVP Capital II dated March 1, 1997 (filed as Exhibit 4.11 to Form S-3, File No. 333-21091).

	•		Form of Guarantee Agreement dated March 1, 1997 (filed as Exhibit 4.12 to Form S-3, File No. 333-21091).

207

	•		Form of Supplemental Indenture between Nevada Power and IBJ Schroder Bank & Trust Company as Debenture Trustee, dated March 1, 1997 (filed as Exhibit 4.13 to Form S-3, File No. 333-21091).

	•		Supplemental Indenture No. 2 and Assumption Agreement dated as of June 1, 1999, between Nevada Power Company and IBJ Whitehall Bank & Trust Company, supplementing and assuming the Junior Subordinated Indenture dated as of March 1, 1997 between Nevada Power Company and IBJ Whitehall Bank & Trust Company (filed as Exhibit 4(D) to Form 10-K for year ended December 31, 1999).

•

Form of indenture between Nevada Power and IBJ Schroder Bank & Trust Company as Trustee, dated October 1, 1998 (filed as Exhibit 4.1 to Form S-3, File Nos. 333-63613 and 333-63613-01).

	•		Certificate of Trust of NVP Capital III dated October 1, 1998 (filed as Exhibit 4.2 to Form S-3, File Nos. 333-63613 and 333-63613-01).

	•		Trust Agreement for NVP Capital III dated October 1, 1998 (filed as Exhibit 4.3 to Form S-3, File Nos. 333-63613 and 333-63613-01).

	•		Form of Amended and Restated Declaration of Trust dated October 1, 1998 (filed as Exhibit 4.4 to Form S-3, File Nos. 333-63613 and 333-63613-01).

	•		Form of Preferred Security Certificate for NVP Capital III dated October 1, 1998 (filed as Exhibit 4.5 to Form S-3, File Nos. 333-63613 and 333-63613-01).

	•		Form of Preferred Securities Guarantee Agreement dated October 1, 1998 (filed as Exhibit 4.7 to Form S-3, File Nos. 333-63613 and 333-63613-01).

	•		Form of Junior Subordinated Deferrable Interest Debenture dated October 1, 1998 (filed as Exhibit 4.9 to Form S-3, File Nos. 333-63613 and 333-63613-01).

	•		Supplemental Indenture No. 1 and Assumption Agreement, dated as of June 1, 1999, between Nevada Power Company and IBJ Whitehall Bank & Trust Company, supplementing and assuming the Indenture dated as of October 1, 1998 between Nevada Power Company and IBJ Whitehall Bank & Trust Company (filed as Exhibit 4(E) to Form 10-K for the year ended December 31, 1999).

•

Indenture of Mortgage and Deed of Trust providing for Nevada Power Company’s First Mortgage Bonds, dated as of October 1, 1953 and Twenty-Eight Supplemental Indentures as follows:

	•		First Supplemental Indenture, dated as of August 1, 1954 (filed as Exhibit 4.2 to Form S-1, File No. 2-11440).

	•		Instrument of Further Assurance dated April 1, 1956 to Indenture of Mortgage and Deed of Trust dated October 1, 1953 (filed as Exhibit 4.8 to Form S- 1, File No. 2-12666).

	•		Second Supplemental Indenture, dated as of September 1, 1956 (filed as Exhibit 4.9 to Form S-1, File No. 2-12566).

	•		Third Supplemental Indenture, dated as of May 1, 1959 (filed as Exhibit 4.13 to Form S-1, File No. 2-14949).

	•		Fourth Supplemental Indenture, dated as of October 1, 1960 (filed as Exhibit 4.5 to S-1, File No. 2-16968).

	•		Fifth Supplemental Indenture, dated as of December 1, 1961 (filed as Exhibit 4.6 to Form S-16, File No. 2-74929).

	•		Sixth Supplemental Indenture, dated as of October 1, 1963 (filed as Exhibit 4.6A to Form S-1, File No. 2-21689).

	•		Seventh Supplemental Indenture, dated as of August 1, 1964 (filed as Exhibit 4.6B to Form S-1, File No. 2-22560).

	•		Eighth Supplemental Indenture, dated as of April 1, 1968 (filed as Exhibit 4.6C to Form S-9, File No. 2-28348).

	•		Ninth Supplemental Indenture, dated as of October 1, 1969 (filed as Exhibit 4.6D to Form S-1, File No. 2-34588).

	•		Tenth Supplemental Indenture, dated as of October 1, 1970 (filed as Exhibit 4.6E to Form S-7, File No. 2-38314).

	•		Eleventh Supplemental Indenture, dated as of November 1, 1972 (filed as Exhibit 2.12 to Form S-7, File No.2-45728).

	•		Twelfth Supplemental Indenture, dated as of December 1, 1974 (filed as Exhibit 2.13 to Form S-7, File No. 2-52350).

	•		Thirteenth Supplemental Indenture, dated as of October 1, 1976 (filed as Exhibit 4.14 to Form S-16, File No. 2-74929).

	•		Fourteenth Supplemental Indenture, dated as of May 1, 1977 (filed as Exhibit 4.15 to Form S-16, File No. 2-74929).

	•		Fifteenth Supplemental Indenture, dated as of September 1, 1978 (filed as Exhibit 4.16 to Form S-16, File No. 2-74929).

208

	•		Sixteenth Supplemental Indenture, dated as of December 1, 1981(filed as Exhibit 4.17 to Form S-16, File No. 2-74929).

	•		Seventeenth Supplemental Indenture, dated as of August 1, 1982 (filed as Exhibit 4.2 to Form 10-K, File No. 1-4698, for the year ended December 31, 1982).

	•		Eighteenth Supplemental Indenture, dated as of November 1, 1986 (filed as Exhibit 4.6 to Form S-3, File No. 33-9537).

	•		Nineteenth Supplemental Indenture, dated as of October 1, 1989 (filed as Exhibit 4.2 to Form 10-K, File No. 1-4698, for the year ended December 31, 1989).

	•		Twentieth Supplemental indenture, dated as of May 1, 1992 (filed as Exhibit 4.21 to Form S-3, File No. 33-53034).

	•		Twenty-First Supplemental Indenture, dated as of June 1, 1992 (filed as Exhibit 4.22 to Form S-3, File No. 33-53034).

	•		Twenty-Second Supplemental Indenture, dated as of June 1, 1992 (filed as Exhibit 4.23 to Form S-3, Filed No. 33-53034).

	•		Twenty-Third Supplemental Indenture, dated as of October 1, 1992 (filed as Exhibit 4.23 to Form S-3, File No. 33-53034).

	•		Twenty-Fourth Supplemental Indenture, dated as of October 1, 1992 (filed as Exhibit 4.23 to Form S-3, File No. 33-53034).

	•		Twenty-Fifth Supplemental Indenture, dated as of January 1, 1993 (filed as Exhibit 4.23 to Form S-3, File No. 33-53034).

	•		Twenty-Sixth Supplemental Indenture, dated as of May 1, 1995 (filed as Exhibit 4.2 to Form 10-K, File No. 1-4698, for the year ended December 31, 1995).

	•		Twenty-Seventh Supplemental Indenture dated as of July 1, 1999 (filed as Exhibit 4(C) to Form 10-K for the year ended December 31, 1999).

	•		Twenty-Eighth Supplemental Indenture dated as of July 1, 2001 (filed as Exhibit 4(D) to Form 10-K for the year ended December 31, 2001).

	•		Twenty-Ninth Supplemental Indenture dated as of February 23, 2004 (filed as Exhibit 4(D) to Form 10-K for the year ended December 31, 2004).

Sierra Pacific Power Company

•

General and Refunding Mortgage Indenture, dated as of May 1, 2001, between Sierra Pacific Power Company and The Bank of New York as Trustee (filed as Exhibit 4.2(a) to Form 10-Q for the quarter ended June 30, 2001).

	•		First Supplemental Indenture, dated as of May 1, 2001, establishing Sierra Pacific Power Company’s 8% General and Refunding Mortgage Bonds, Series A, due June 1, 2008 (filed as Exhibit 4.2(b) to Form 10-Q for the quarter ended June 30, 2001).

	•		Officer’s Certificate establishing the terms of Sierra Pacific Power Company’s 8% General and Refunding Mortgage Bonds, Series A, due June 1, 2008 (filed as Exhibit 4.2(c) to Form 10-Q for the quarter ended June 30, 2001).

	•		Form of Sierra Pacific Power Company’s 8% General and Refunding Mortgage Bonds, Series A, due June 1, 2008 (filed as Exhibit 4.2(d) to Form 10-Q for the quarter ended June 30, 2001).

	•		Officer’s Certificate establishing the terms of Sierra Pacific Power Company’s 6 1/4% General and Refunding Mortgage Bonds, Series H, due 2012 (filed as Exhibit 4.4 to Form 10-Q for the quarter ended March 31, 2004).

	•		Form of Sierra Pacific Power Company’s 6 1/4% General and Refunding Mortgage Bonds, Series H, due 2012 (filed as Exhibit 4.5 to Form 10-Q for the quarter ended March 31, 2004).

	•		Officer’s Certificate establishing the terms of Sierra Pacific Power Company’s General and Refunding Mortgage Notes, Series J, due 2009 (filed as Exhibit 4(E) to Form 10-K for the year ended December 31, 2004).

	•		Form of Sierra Pacific Power Company’s General and Refunding Mortgage Notes, Series J, due 2009 (filed as Exhibit 4(F) to Form 10-K for the year ended December 31, 2004).

•

Indenture of Mortgage providing for Sierra Pacific Power Company’s First Mortgage Bonds, dated as of December 1, 1940 (filed as Exhibit 7-A to Registration No. 2-7475).

	•		Ninth Supplemental Indenture, dated as of June 1, 1964 (filed as Exhibit 2-M to Registration No. 2-59509).

	•		Tenth Supplemental Indenture, dated as of March 31, 1965 (filed as Exhibit 4-K to Registration No. 2-23932).

	•		Eleventh Supplemental Indenture, dated as of October 1, 1965 (filed as Exhibit 4-L to Registration No. 2-26552).

	•		Twelfth Supplemental Indenture dated as of July 1, 1967 (filed as Exhibit 4-L to Registration No. 2-36982).

209

	•		Sixteenth Supplemental Indenture, dated as of October 1, 1975 (filed as Exhibit 2-Y to Registration No. 2-53404).

	•		Nineteenth Supplemental Indenture, dated as of April 1, 1978 (filed as Exhibit (4)(A) to the 1991 Form 10-K).

	•		Twentieth Supplemental Indenture, dated as of October 1, 1978 (filed as Exhibit (4)(B) to the 1991 Form 10-K).

	•		Twenty-Seventh Supplemental Indenture, dated as of August 1, 1989 (filed as Exhibit (4)(A) to the 1989 Form 10-K).

	•		Twenty-Eighth Supplemental Indenture, dated as of May 1, 1992 (filed as Exhibit (4)(A) to the 1992 Form 10-K).

	•		Twenty-Ninth Supplemental Indenture, dated as of June 1, 1992 (filed as Exhibit D to Form 8-K dated July 15, 1992).

	•		Thirtieth Supplemental Indenture, dated as of July 1, 1992 (filed as Exhibit (4)(B) to the 1992 Form 10-K).

	•		Thirty-First Supplemental Indenture, dated as of November 1, 1992 (filed as Exhibit (4)(C) to the 1992 Form 10-K).

	•		Thirty-Second Supplemental Indenture, dated as of June 1, 1993 (filed as Exhibit 4.6 to Registration No. 33-69550).

	•		Thirty-Third Supplemental Indenture, dated as of October 1, 1993 (filed as Exhibit C to Form 8-K dated October 20, 1993).

	•		Thirty-Fourth Supplemental Indenture, dated as of February 1, 1996 (filed as Exhibit C to Form 8-K dated March 11, 1996).

	•		Thirty-Fifth Supplemental Indenture, dated as of February 1, 1997 (filed as Exhibit C to Form 8-K dated March 10, 1997).

•

Indenture dated as of April 9, 1999 between SPPC Funding LLC and Bankers Trust Company of California, N.A., in connection with the issuance of California rate reduction bonds (filed as Exhibit 4(C) to Form 10-K for the year ended December 31, 1999).

•

First Series Supplement dated as of April 9, 1999 to Indenture between SPPC Funding LLC and Bankers Trust Company of California, N.A., in connection with the issuance of California rate reduction bonds (filed as Exhibit 4(D) to Form 10-K for year ended December 31, 1999).

•

Form of SPPC Funding LLC Notes, Series 1999-1, in connection with the issuance of California rate reduction bonds (filed as Exhibit 4(E) to Form 10-K for year ended December 31, 1999).

•

Collateral Trust Indenture dated June 1, 1992 between Sierra Pacific Power Company and Bankers Trust Company, as Trustee, relating to Sierra Pacific Power Company’s medium-term note program (filed as Exhibit B to Form 8-K dated July 15, 1992).

	•		First Supplemental Indenture dated June 1, 1992 (filed as Exhibit C to Form 8-K dated July 15, 1992).

	•		Second Supplemental Indenture dated October 1, 1993 (filed as Exhibit B to Form 8-K dated October 20, 1993).

	•		Third Supplemental Indenture dated as of February 1, 1996 (filed as Exhibit B to Form 8-K dated March 11, 1996).

	•		Fourth Supplemental Indenture dated as of February 1, 1997 (filed as Exhibit B to Form 8-K dated March 10, 1997).

	•		Form of Medium-Term Global Fixed Rate Note, Series A, in connection with Sierra Pacific Power Company’s medium-term note program (filed as Exhibit E to Form 8-K dated July 15, 1992).

	•		Form of Medium-Term Global Fixed Rate Note, Series B, in connection with Sierra Pacific Power Company’s medium-term note program (filed as Exhibit D to Form 8-K dated October 25, 1993).

	•		Form of Medium-Term Global Fixed-Rate Note, Series C, in connection with Sierra Pacific Power Company’s medium-term note program (filed as Exhibit D to Form 8-K dated March 11, 1996).

(10) Sierra Pacific Resources

	•		*(A) Paul L. Kaleta Employment Letter dated January 9, 2006.

	•		Stephen R. Wood Employment Letter dated June 29, 2004 (filed as Exhibit 10.1 to Form 10-Q for the quarter ended March 31, 2004).

	•		Sierra Pacific Resources’ 2004 Executive Long-Term Incentive Plan (filed as Appendix A to 2004 Proxy Statement).

	•		Roberto Denis Employment Letter dated July 11, 2003 (filed as Exhibit 10(B) to Form 10-K for the year ended December 31, 2003).

	•		Employment Agreement for Walter M. Higgins (filed as Exhibit 10.1 to Form 10-Q dated September 30, 2003).

	•		Change in Control Agreement by and among Sierra Pacific Resources and the following officers (individually): Jeffrey L. Ceccarelli, Donald L. Shalmy, Michael W. Yackira, Roberto R. Denis, Stephen R. Wood and Paul L. Kaleta in substantially the same form as the Change in Control Agreement dated May 21, 2001 by and between Sierra Pacific Resources and Dennis D. Schiffel (filed as Exhibit 10(C) to Form 10-K for the year ended December 30, 2001).

210


	•		Change in Control Agreement by and among Sierra Pacific Resources and the following officers (individually): Mary O. Simmons and John E. Brown in substantially the same form as the Change in Control Agreement dated May 21, 2001 by and between Sierra Pacific Resources and John E. Brown (filed as Exhibit 10(D) to Form 10-K for the year ended December 30, 2001).

	•		Donald L. Shalmy Employment Letter dated May 21, 2002 (filed as Exhibit 10.1 to Form 10-Q for the quarter ended September 30, 2002).

	•		Michael W. Yackira Employment Letter dated March 17, 2003 (filed as Exhibit 10(A) to Form 10-K for the year ended December 31, 2002).

	•		Sierra Pacific Resources’ Non-Employee Director Stock Plan (filed as Exhibit 99.2 to Form S-8 dated December 13, 1999).

	•		Sierra Pacific Resources’ Employee Stock Purchase Plan (filed as Exhibit 99.3 to Form S-8 dated December 13, 1999).

Nevada Power Company

	•		Second Amended and Restated Credit Agreement, dated as of November 4, 2005, among Nevada Power Company, Wachovia Bank, as administrative agent, the Lenders from time to time party thereto and the other parties named therein (filed as Exhibit 10.1 to the Form 10-Q for the quarter ended September 30, 2005).

	•		Purchase Agreement for the Silverhawk Power Station dated as of June 21, 2005 by and among Pinnacle West Capital Corporation, Pinnacle West Energy Corporation, GenWest, LLC and Nevada Power Company (filed as Exhibit 10.1 to Form 10-Q for the quarter ended June 30, 2005).

	•		Collective Bargaining Agreement dated as of February 1, 2005, effective through February 1, 2008, between Nevada Power Company and the International Brotherhood of Electrical Workers Local Union No. 396 (filed as Exhibit 10.1 to Form 10-Q for the quarter ended March 31, 2005).

	•		Closing Agreement and Amendment to Purchase Agreement (Moapa Energy Facility) dated October 2004 (filed as Exhibit 10.2 to Form 10-Q for the quarter ended September 30, 2004).

	•		Purchase Agreement dated June 22, 2004 by and among Duke Energy Moapa, LLC, Duke Energy North America, LLC and Nevada Power Company (filed as Exhibit 10.1 to Form 10-Q for the quarter ended September 30, 2004).

	•		Engineering, Procurement and Construction Agreement dated October 13, 2004 between Nevada Power Company and Fluor Enterprises, Inc. and Exhibit A thereto (filed as Exhibit 10.3 and Exhibit 10.4 to Form 10-Q for the quarter ended September 30, 2004).

	•		*(B) Western Systems Power Pool (WSPP) Agreement effective February 1, 2005 between Nevada Power Company as a member of the WSPP, Sierra Pacific Power Company as a member of the WSPP and the other members of the WSPP.

	•		*(C) Western Systems Power Pool (WSPP) Agreement effective September 1, 2005 between Nevada Power Company as a member of the WSPP, Sierra Pacific Power Company as a member of the WSPP and the other members of the WSPP.

	•		Western Systems Power Pool (WSPP) Agreement effective February 1, 2004 between Nevada Power Company as a member of the WSPP, Sierra Pacific Power Company as a member of the WSPP and the other members of the WSPP (filed as Exhibit 10.1 to Form 10-Q for the quarter ended March 31, 2004).

	•		Financing Agreement No. 1 between Clark County, Nevada and Nevada Power Company dated as of June 1, 2000 (Series 2000A) (filed as Exhibit 10(O) to Form 10-K for the year ended December 31, 2000)

	•		Financing Agreement No. 2 between Clark County, Nevada and Nevada Power Company dated as of June 1, 2000 (Series 2000B) (filed as Exhibit 10(P) to Form 10-K for the year ended December 31, 2000).

	•		Financing Agreement between Clark County, Nevada and Nevada Power Company dated November 1, 1997 (relating to Clark County, Nevada $52,285,000 Industrial Development Revenue Bonds, Series 1997A) (filed as Exhibit 10.83 to Form 10-K, File No. 1-4698, for the year ended December 31, 1997)

	•		Financing Agreement between Coconino County, Arizona Pollution Control Corporation and Nevada Power Company dated November 1, 1997 (relating to Coconino County, Arizona $20,000,000 Pollution Control Corporation Pollution Control Revenue Bonds, Series 1997B) (filed as Exhibit 10.84 to Form 10-K, File No. 1-1698, for the year ended December 31, 1997).

	•		Financing Agreement between Coconino County, Arizona Pollution Control Corporation and Nevada Power Company dated October 1, 1996 (relating to Coconino County, Arizona Pollution Control Corporation $20,000,000 Pollution Control Revenue Bonds, Series 1996) (filed as Exhibit 10.82 to Form 10-K, File 1-4698, for the year ended December 31, 1996).

211

	•		Financing Agreement between Clark County, Nevada and Nevada Power Company dated October 1, 1995 (relating to Clark County, Nevada $76,750,000 Industrial Development Revenue Bonds, Series 1995A) (filed as Exhibit 10.75 to Form 10-K, File No. 1-4698, for the year ended December 31, 1995).

	•		Financing Agreement between Clark County, Nevada and Nevada Power Company dated October 1, 1995 (relating to Clark County, Nevada $85,000,000 Industrial Development Refunding Revenue Bonds, Series 1995B) (filed as Exhibit 10.76 to Form 10-K, File No. 1-4698, for the year ended December 31, 1995).

	•		Financing Agreement between Clark County, Nevada and Nevada Power Company dated October 1, 1995 (relating to Clark County, Nevada $76,750,000 Industrial Development Revenue Bonds, Series 1995A and $44,000,000 Industrial Development Refunding Revenue Bonds, Series 1995C) (filed as Exhibit 10.77 to Form 10-K, File No. 1-1698, for the year ended December 31, 1995).

	•		Financing Agreement between Clark County, Nevada and Nevada Power Company dated October 1, 1995 (relating to Clark County, Nevada $20,300,000 Pollution Control Refunding Revenue Bonds, Series 1995D) (filed as Exhibit 10.78 to Form 10-K, File No. 1-4698, for the year ended December 31, 1995).

	•		Financing Agreement between Coconino County, Arizona Pollution Control Corporation and Nevada Power Company dated October 1, 1995 (relating to Coconino County, Arizona Pollution Control Corporation $13,000,000 Pollution Control Refunding Revenue Bonds, Series 1995E) (filed as Exhibit 10.79 to Form 10-K, File No. 14698, for the year ended December 31, 1995).

	•		Financing Agreement between Clark County, Nevada and Nevada Power Company dated October 1, 1992 (Relating to Industrial Development Refunding Revenue Bonds, Series 1992C) (filed as Exhibit 10.67 to Form 10-K, File No. 1-4698, for the year ended December 31, 1992).

	•		Financing Agreement between Clark County, Nevada and Nevada Power Company dated June 1, 1992 (Relating to Clark County, Nevada $105,000,000 Industrial Development Revenue Bonds, Series 1992A) (filed as Exhibit 10.65 to Form 10-K, File No. 1-4698, for the year ended December 31, 1992).

	•		Financing Agreement between Clark County, Nevada and Nevada Power Company dated June 1, 1992 (Relating to Pollution Control Refunding Revenue Bonds, Series 1992B) (filed as Exhibit 10.66 to Form 10-K, File No. 1-4698, for the year ended December 31, 1992).

	•		Western Systems Power Pool (WSPP) Agreement effective September 1, 2002 between Nevada Power Company as a member of WSPP and the other members of the WSPP (filed as Exhibit 10(C) to Form 10-K for the year ended December 31, 2002).

	•		Agreement for Transmission Service dated March 29, 1989 between Overton Power District No. 5, Lincoln County Power District No. 1 and Nevada Power Company (filed as Exhibit 10.51 to Form 10-K, File No. 1-4698, for the year ended December 31, 1989).

	•		Contract for Operation, Maintenance, Replacement, Ownership, and Interconnection of Facilities dated June 30, 1988 between United States Department of Energy Western Area Power Administration and Nevada Power Company (filed as Exhibit 10.52 to Form 10-K, File No. 14698, for the year ended December 31, 1989).

	•		Transmission Facilities Agreement between Utah Power & Light Company and Nevada Power Company, dated August 17, 1987 (filed as Exhibit 10.41 to Farm 10-K, File No. 1-4698, for the year ended December 31, 1987).

	•		Contract for Sale of Electrical Energy between the State of Nevada and Nevada Power Company, dated July 8, 1987 (filed as Exhibit 10.39 to Form 10-K, File No. 1-4698, for the year ended December 31, 1987).

	•		Participation Agreement Reid Gardner Unit No. 4 dated July 11, 1979 between Nevada Power Company and California Department of Water Resources (filed as Exhibit 5.34 to Form S-7, File No. 2-65097).

	•		Amended Mohave Project Coal Slurry Pipeline Agreement dated May 26, 1976 between Peabody Coal Company and Black Mesa Pipeline, Inc. (Exhibit B to Exhibit 10.18) (filed as Exhibit 5.36 to Form S-7, File No. 2-56356).

	•		Amended Mohave Project Coal Supply Agreement dated May 26, 1976 between Nevada Power Company and Southern California Edison Company, Department of Water and Power of the City of Los Angeles, Salt River Project Agricultural Improvement and Power District and the Peabody Coal Company (filed as Exhibit 5.35 to Porto S-7, File No. 2-56356).

	•		Navajo Project Co-Tenancy Agreement dated March 23, 1976 between Nevada Power Company, Arizona Public Service Company, Department of Water and Power of the City of Los Angeles, Salt River Project Agricultural Improvement and Power District, Tucson Gas & Electric Company and the United States of America (filed as Exhibit 5.31 to Form 8-K, File No. 1-4696, April 1974).

	•		Mohave Operating Agreement dated July 6, 1970 between Nevada Power Company, Salt River Project Agricultural Improvement and Power District, Southern California Edison Company and Department of Water and Power of the City of Los Angeles (filed as Exhibit 13.26F to Form S-1, File No. 2-38314).

	•		Navajo Project Coal Supply Agreement dated June 1, 1970 between Nevada Power Company, the United States of America, Arizona Public Service Company, Department of Water and Power of the City of Los Angeles, Salt River Project Agricultural District Tucson Gas & Electric Company and the Peabody Coal Company (filed as Exhibit 13.27B to Form S-1, File No. 2-38314).

212

	•		Eldorado System Conveyance and Co-Tenancy Agreement dated December 20, 1967 between Nevada Power Company and Salt River Project Agricultural Improvement and Power District and Southern California Edison Company (filed as Exhibit 13.30 to Form S-9, File No. 2-28348).

	•		Mohave Project Plant Site Conveyance and Co-Tenancy Agreement dated May 29, 1967 between Nevada Power Company and Salt River Project Agricultural Improvement and Power District and Southern California Edison Company (filed as Exhibit 13.27 to Form S-9, File No. 2-28348).

	•		Reliability Management System Agreement dated June 18, 1999 by and between Western Systems Coordinating Council and Nevada Power Company (filed as Exhibit 10(U) to Form 10-K for the year ended December 31, 2000).

	•		Service Agreement No. 90 for Long-Term Firm Point-To-Point Transmission Service filed with the Federal Energy Regulatory Commission July 20, 2001 between Nevada Power Company and Reliant Energy Services, Inc. (filed as Exhibit 10(G) to Form 10-K for the year ended December 30, 2001).

	•		Service Agreement Nos. 98 and 99 for Long-Term Firm Point-To-Point Transmission Service filed with the Federal Energy Regulatory Commission August 1, 2001 between Nevada Power Company and Mirant Americas Development, Inc. (filed as Exhibit 10(J) to Form 10-K for the year ended December 30, 2001).

	•		Settlement Agreement dated April 16, 2002, by and between Nevada Power Company and each of Calpine Corporation, Duke Energy Trading and Marketing, L.L.C., Mirant Las Vegas, LLC, Pinnacle West Energy Corporation and Reliant Energy Services (filed as Exhibit 10(D) to Form 10-K for the year ended December 31, 2002).

	•		Service Agreement No. 96 for Long-Term Firm Point-To-Point Transmission Service filed with the Federal Energy Regulatory Commission July 9, 2002 between Nevada Power Company and Calpine Corporation (filed as Exhibit 10(E) to Form 10-K for be year ended December 31, 2002).

	•		Service Agreement No. 97 for Long-Term Firm Point-To-Point Transmission Service filed with the Federal Energy Regulatory Commission July 3, 2002 between Nevada Power Company and Duke Energy Trading and Marketing (filed as Exhibit 10(F) to Form 10-K for the year ended December 31, 2002).

	•		Service Agreement No. 100 for Long-Term Firm Point-To-Point Transmission Service filed with the Federal Energy Regulatory Commission December 12, 2002 between Nevada Power Company and Reliant Energy Services, Inc. (filed as Exhibit 10(G) to Form 10-K for the year ended December 31, 2002).

	•		Assignment and Assumption of Long-Term Firm Point to Point Transmission Service Agreement No. 101.A, between Pinnacle West Energy Corporation and Pinnacle West Capital Corporation (filed as Exhibit 10(E) to the Form 10-K for the year ended December 31, 2003).

	•		Service Agreement No. 101.A for Long-Term Firm Point To Point Transmission Service filed with the Federal Energy Regulatory Commission December 19, 2003 between Nevada Power Company and Pinnacle West Capital Corporation (filed as Exhibit 10.1(F) to the Form 10-K for the year ended December 31, 2003).

	•		Service Agreement No.101.B for Long-Term Firm Point-To-Point Transmission Service filed with the Federal Energy Regulatory Commission December 12, 2002 between Nevada Power Company and Southern Nevada Water Authority (filed as Exhibit 10(I) to Form 10-K for the year ended December 31, 2002).

	•		Settlement Agreement dated December 19, 2003, between Nevada Power Company, Pinnacle West Energy Corporation and Southern Nevada Water Authority (filed as Exhibit 10(G) to the Form 10-K for the year ended December 31, 2003).

	•		Service Agreement No. 101.B for Long-Term Firm Point-To-Point Transmission Service filed with the Federal Energy Regulatory Commission December 19, 2003 between Nevada Power Company and Southern Nevada Water Authority (filed as Exhibit 10(H) to the Form 10-K for the year ended December 31, 2003).

	•		Service Agreement No. 102 For Long-Term Firm Point-To-Point Transmission Service filed with the Federal Energy Regulatory Commission April 21, 2003 between Nevada Power Company and Las Vegas Cogeneration II, LLC (filed as Exhibit 10(I) to the Form 10-K for the year ended December 31, 2003).

	•		Sublease Agreement between Powveg Leasing Corp., as Lessor and Nevada Power Company as lessee, dated January 1, 1984 for lease of administrative headquarters (the primary term of the sublease ends in 2014 and the lessee has the option to extend the term up to 25 additional years) (filed as Exhibit 10.31 to Form 10-K, File No. 1-4698, for the year ended December 31, 1983).

Sierra Pacific Power Company

	•		Amended and Restated Credit Agreement, dated as of November 4, 2005 among Sierra Pacific Power Company, Wachovia Bank, National Association, as administrative agent, the Lenders from time to time party thereto and the other parties named therein (filed as Exhibit 10.2 to the Form 10-Q for the quarter ended September 30, 2005).

	•		Western Systems Power Pool (WSPP) Agreement effective February 1, 2005 between Nevada Power Company as a member of the WSPP, Sierra Pacific Power Company as a member of the WSPP and the other members of the WSPP (filed as Exhibit 10(B) to this Form 10-K).

	•		Western Systems Power Pool (WSPP) Agreement effective September 1, 2005 between Nevada Power Company as a member of the WSPP, Sierra Pacific Power Company as a member of the WSPP and the other members of the WSPP (filed as Exhibit 10(C) to this Form 10-K).

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	•		Western Systems Power Pool (WSPP) Agreement effective February 1, 2004 between Nevada Power Company as a member of the WSPP, Sierra Pacific Power Company as a member of the WSPP and the other member of the WSPP (filed as Exhibit 10.1 to Form 10-Q for the quarter ended March 31, 2004)..

	•		Financing Agreement dated June 1, 1993 between Sierra Pacific Power Company and Washoe County, Nevada relating to the Washoe County, Nevada Water Facilities Refunding Revenue Bonds (Sierra Pacific Power Company Project) Series 1993A (filed as Exhibit (10)(I) to Form 10-K for the year ended December 31, 1993).

	•		Financing Agreement dated June 1, 1993 between Sierra Pacific Power Company and Washoe County, Nevada relating to the Washoe County, Nevada Gas and Water Facilities Refunding Revenue Bonds (Sierra Pacific Power Company Project) Series 1993B (filed as Exhibit (10)(J) to Form 10-K for the year ended December 31, 1993).

	•		Financing Agreement dated as of March 1, 2001 between Sierra Pacific Power Company and Washoe County, Nevada relating to the Washoe County, Nevada Water Facilities Refunding Revenue Bonds (Sierra Pacific Power Company Project) Series 2001 (filed as Exhibit 10(O) to Form 10-K for the year ended December 31, 2001).

	•		Financing Agreement dated September 1, 1990 between Sierra Pacific Power Company and Washoe County, Nevada relating to the Washoe County, Nevada Gas Facilities Revenue Bonds (Sierra Pacific Power Company Project) Series 1990 (filed as Exhibit (10)(C) to Form 10-K for the year ended December 31, 1990).

	•		Financing Agreement dated December 1, 1987 between Sierra Pacific Power Company and Washoe County, Nevada relating to the Washoe County, Nevada Variable Rate Demand Gas Facilities Revenue Bonds (Sierra Pacific Power Company Project) Series 1987 (filed as Exhibit (10)(H) to Form 10-K for the year ended December 31, 1993).

	•		Financing Agreement dated June 1, 1987 between Sierra Pacific Power Company and Washoe County, Nevada relating to the Washoe County, Nevada Variable Rate Demand Water Facilities Revenue Bonds (Sierra Pacific Power Company Project) Series 1987 (filed as Exhibit (10)(G) m Form 10-K for the year ended December 31, 1993).

	•		Financing Agreement dated March 1, 1987 between Sierra Pacific Power Company and Humboldt County, Nevada relating to the Humboldt County, Nevada Variable Rate Demand Pollution Control Refunding Revenue Bonds (Sierra Pacific Power Company Project) Series 1987 (filed as Exhibit (10)(E) to Form 10-K for the year ended December 31, 1993).

	•		Financing Agreement dated March 1, 1987 between Sierra Pacific Power Company and Washoe County, Nevada relating to the Washoe County, Nevada Variable Rate Demand Gas and Water Facilities Refunding Revenue Bonds (Sierra Pacific Power Company Project) Series 1987 (filed as Exhibit (10)(F) to Form 10-K for the year ended December 31, 1993).

	•		Transition Property Purchase and Sale Agreement dated as of April 9, 1999 between Sierra Pacific Power Company and SPPC Funding LLC in connection with the issuance of California rate reduction bonds (filed as Exhibit 10(B) to Form 10-K for the year ended December 31, 1999).

	•		Transition Property Servicing Agreement dated as of April 9, 1999 between Sierra Pacific Power Company and SPPC Funding LLC in connection with the issuance of California rate reduction bonds (filed as Exhibit 10(C) to Form 10-K for the year ended December 31, 1999).

	•		Administrative Services Agreement dated as of April 9, 1999 between Sierra Pacific Power Company and SPPC Funding LLC in connection with the issuance of California rate reduction bonds (filed as Exhibit 10(D) b Form 10-K for the year ended December 31, 1999).

	•		Collective Bargaining Agreement dated January 1, 2003, effective through December 31, 2005 between Sierra Pacific Power Company and the International Brotherhood of Electrical Workers Local No. 1245 (filed as Exhibit 10(J) to the Form 10-K for the year ended December 31, 2003).

	•		Settlement Agreement and Mutual Release dated May 8, 1992 between Sierra Pacific Power Company and Coastal States Energy Company (filed as Exhibit (10)(D) to Form 10-K for the year ended December 31, 1992; confidential portions omitted and filed separately with the SEC).

	•		Coal Supply Agreement dated January 1, 2002 between Sierra Pacific Power Company and Arch Coal Sales Company, Inc. (5 year term ending on December 31, 2006) (filed as Exhibit 10(R) to Form 10-K for the year ended December 31, 2001).

	•		Interconnection Agreement dated May 29, 1981 between Sierra Pacific Power Company and Idaho Power Company (filed as Exhibit (10)(C) to Form 10-K for the year ended December 31, 1991).

	•		Amendatory Agreement dated February 14, 1992 to Interconnection Agreement dated May 29, 1981 between Sierra Pacific Power Company and Idaho Power Company (filed as Exhibit (10)(D) to Form 10-K for the year ended December 31, 1991).

	•		Coal Sales Agreement dated May 16, 1978 between Sierra Pacific Power Company and Coastal States Energy Company (confidential portions omitted and flied separately with the SEC) (filed as Exhibit 5-GG to Registration No. 2-62476).

	•		Amendment No. 1 dated November 8, 1983 to Coal Sales Agreement dated May 16, 1978 between Sierra Pacific Power Company and Coastal States Energy Company (filed as Exhibit(10)(B) to Form 10-K for the year ended December 31, 1991).

	•		Amendment No. 2 dated February 25, 1987 to Coal Sales Agreement dated May 16, 1978 between Sierra Pacific Power Company and Coastal Stores Energy Company (filed as Exhibit (10)(A) to Form 10-K for the year ended December 31, 1993).

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	•		Amendment No. 3 dated May 8, 1992 to Coal Sales Agreement dated May 16, 1978 between Sierra Pacific Power Company and Coastal States Energy Company (filed as Exhibit (10(B) to Form 10-K for the year ended December 31, 1992; confidential portions omitted and filed separately with the SEC).

	•		Lease dated January 30, 1986 between Sierra Pacific Power Company and Silliman Associates Limited Partnership relating to the Company’s corporate headquarters building (filed as Exhibit(10)(I) to Form 10-K for the year ended December 31, 1992).

	•		Letter of Amendment dated May 18, 1987 to Lease dated January 30, 1986 between Sierra Pacific Power Company and Silliman Associates Limited Partnership relating to the company’s corporate headquarters building (filed as Exhibit (10)(K) to Form 10-K for the year ended December 31, 1993).

Sierra Pacific Communications

•

Unit Redemption, Release, and Sale Agreement entered into by and among Touch America, Inc., Sierra Pacific Communications, and Sierra Touch America LLC, dated as of September 9, 2002 (filed as Exhibit 10.4 to Form 10-Q for the quarter ended September 30, 2002).

•

Amended and Restated Conduit Sale Agreement dated September 11, 2002, made by and between Sierra Pacific Communications and Quest Communications Corporation (filed as Exhibit 10.5 to Form 10-Q for the quarter ended September 30, 2002).

(11) Nevada Power Company and Sierra Pacific Power Company

•

Nevada Power Company and Sierra Pacific Power Company are wholly owned subsidiaries and, in accordance with Paragraph 6 of SFAS No. 128 (Earnings Per Share), earnings per share data have been omitted.

(12) Sierra Pacific Resources

•

*(A) Statement regarding computation of Ratios of Earnings to Fixed Charges.

Nevada Power Company

•

*(B) Statement regarding computation of Ratios of Earnings to Fixed Charges.

Sierra Pacific Power Company

•

*(C) Statement regarding computation of Ratios of Earnings to Fixed Charges.

(21) Sierra Pacific Resources

•

Nevada Power Company, a Nevada Corporation.
Sierra Pacific Power Company, a Nevada Corporation.
Great Basin Energy Company, a Nevada Corporation.
Lands of Sierra Inc., a Nevada Corporation.
Sierra Energy Company dba e-three, a Nevada Corporation.
Sierra Gas Holdings Company, a Nevada Corporation.
Sierra Pacific Energy Company, a Nevada Corporation.
Sierra Pacific Resources Capital Trust I, a Delaware Business Trust.
Sierra Pacific Resources Capital Trust II, a Delaware Business Trust.
Sierra Water Development Company, a Nevada Corporation.
Tuscarora Gas Pipeline Company, a Nevada Corporation.
Tuscarora Gas Operating Company, a Nevada Corporation.

Nevada Power Company

•

Nevada Electric Investment Company, a Nevada Corporation.
Commonsite, Inc., a Nevada Corporation.
NVP Capital I, a Delaware Business Trust.
NVP Capital II, a Delaware Business Trust.

Sierra Pacific Power Company

•

Piñon Pine Company, a Nevada Corporation.
Piñon Pine Investment Company, a Nevada Corporation.
Piñon Pine Investment Co. LLC, a Nevada Limited Liability Company.
GPSF-B, a Delaware Corporation.
SPPC Funding LLC, a Delaware Limited Liability Company.
Sierra Pacific Power Capital Trust I, a Delaware Business Trust.

(23) Sierra Pacific Resources

•

*(A) Consent of Independent Registered Public Accounting Firm in connection with the Sierra Pacific Resources’ Registration Statements No. 333-77523 (Common Stock Investment Plan) on Form S-3, No. 333-92651 (Employees’ Stock Ownership Plan, Executive Long-Term Incentive Plan, and Non-Employee Director Stock Plan) on Form S-8, and Registration Statement No. 333-130186 on Form S-4 (6 3/4% Senior Notes).

(31) Sierra Pacific Resources, Nevada Power Company and Sierra Pacific Power Company

	•		*(31.1) Annual Certification of Principal Executive Officer Required by Section 302(A) of the Sarbanes-Oxley Act of 2002.

	•		*(31.2) Annual Certification of Principal Financial Officer Required by Section 302(A) of the Sarbanes-Oxley Act of 2002.

(32) Sierra Pacific Resources, Nevada Power Company and Sierra Pacific Power Company

	•		*(32.1) Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Am of 2002.

	•		*(32.2) Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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