UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

For the fiscal year ended December 31, 2004

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

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

State the aggregate market value of the voting and non-voting stock held by non-affiliates. As of June 30, 2004: $ 904,598,286

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 February 28, 2005: 117,561,828 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 2, 2005, 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

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FORWARD LOOKING STATEMENTS

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

PART I

ITEM 1. BUSINESS

SIERRA PACIFIC RESOURCES

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

     SPR has 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) which are 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. Other operations are below the quantitative threshold for separate segment disclosure and are combined under “all other”. 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.

     Periodic reports on Form 10-K and Form 10-Q and current reports on Form 8-K are made available to the public, free of charge, on the SPR, NPC and SPPC Company 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 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, through a predecessor corporation, has been providing electric services since 1906. NPC became a wholly owned subsidiary of SPR on July 28, 1999. Its mailing address is 6226 West Sahara Avenue, Las Vegas, Nevada 89146.

     Nevada Electric Investment Company (NEICO) is a wholly owned subsidiary of Nevada Power Company. 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.

     NPC is a public utility engaged in the distribution, transmission, generation, and sale of electric energy in Clark County in southern Nevada. NPC provides electricity to approximately 738,000 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.

Business and Competitive Environment

     NPC’s 2004 operating revenues were approximately $1.8 billion.

     Summer peak loads are driven by air conditioning demand. NPC’s peak load increased an average of 4.5% annually over the past five years, reaching 4,969 megawatts (MW) on August 11, 2004. NPC’s total retail electric megawatt-hour (MWh) sales have increased an average of 3.8% annually over the past five years. Winter peak loads are low relative to the summer peak. Winter load above the base amount is driven by air handling in forced air furnaces.

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     NPC’s service territory continues to be one of the fastest growing areas in the nation. In 2004, NPC set a company high 46,549 new electric meters and it is anticipated that NPC will match, if not surpass, that amount in 2005.

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

     Growth in NPC’s residential class sales continued primarily as a result of new home construction in Las Vegas. New home sales in 2004 of 29,248 in NPC’s service area surpassed the previous record of 25,230 new homes that was set in 2003.

     Tourism and gaming remain southern Nevada’s leading industries, and this category comprises one of NPC’s largest classes of customers (see Gaming/Recreation/Restaurants above). There were no mega-resort openings in 2004, but several openings and expansion projects are planned for 2005. The spring 2005 opening of Wynn Las Vegas will add 2,716 rooms, the South Coast Hotel and Casino will add 660 rooms and the Caesars Palace expansion is expected to add 949 rooms in 2005. Station Casinos is working on Red Rock Station, which will bring another 1,000 rooms to the Las Vegas Valley in 2006.

     MWh sales to NPC’s Office customer class continued to grow with the addition of new office space in Las Vegas. The addition of new office facilities is expected to continue during 2005, with a number of new sites currently under construction.

     Other Retail MWh sales are expected to benefit as Las Vegas continues to experience an increase in the number of conventions and conferences. The Las Vegas Convention and Visitors Authority (LVCVA) plans to add over 500,000 square feet of convention space in 2005 to accommodate the additional visitors and conventions. The Fashion Show Mall is close to completion of its $1 billion renovation and expansion project of its property on the strip.

     NPC’s All Other & Unclassified customer class consists of schools, manufacturing, grocery, healthcare, warehousing, construction, defense, and other miscellaneous. MWh sales to these customers increased primarily as a result of continued growth in Las Vegas.

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     During 2004, firm and non-firm sales to wholesale customers comprised 4.4% of NPC’s total energy sales, a decrease of 63.3% over the prior year. Wholesale customers consist of other utilities or municipalities that sell power to end users, marketing entities and others that exchange power with NPC.

NPC’s decrease in wholesale sales was a result of a change in procurement strategy from prior years. The strategy now focuses on executing contracts for power deliveries to NPC’s physical points of deliveries. On previous years, NPC used hedges to reduce price and commodity risk for future purchases. The hedge purchase was either delivered to NPC’s service territory to service its customers or, if the hedge purchase was not needed to fulfill power requirements, resold in the liquid market. With the significant drop in liquidity in wholesale markets, NPC has changed its procurement strategy to focus on power deliveries to NPC’s physical points of delivery. See Energy Supply in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations for a discussion of NPC’s purchased power procurement strategies.

     The 2001 session of the Nevada State Legislature enacted Assembly Bill 661 (AB 661). One provision of this bill allows commercial customers with an average annual load of 1 MW or more to file a letter of intent and application with the Public Utility Commission of Nevada (PUCN) to acquire electric energy, capacity, and ancillary services from another provider. In 2004, no new customer applications were processed by the PUCN for the NPC service territory. For additional information see discussion at Regulation, AB 661 later.

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. NPC’s service territory is one of the fastest growing areas in the nation. Capital construction expenditures and estimates are reflective of this obligation to serve.

     Gross construction expenditures for 2004, including allowance for funds used during construction (AFUDC), net salvage, and contributions in aid of construction, were $482.5 million, and for the period 2000 through 2004, were $1.4 billion. Estimated construction expenditures for 2005 and the period from 2006 to 2009 are as follows (dollars in thousands):

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     Total estimated construction and plant cash requirements related to construction projects for 2005 and the 2006 to 2009 period consist of the following (dollars in thousands):

     In October 2004, NPC purchased a partially constructed nominally rated 1200 megawatt 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 the station approved by the PUCN on September 21, 2004 was $550 million. Costs in 2004 were approximately $218.2 million, which includes the purchase price of $182 million. Budgeted construction costs for 2005 are $257.2 million. NPC is projecting half of the capacity to be in service by December 2005, and the remaining half to be in service by March 2006.

     NPC plans to build a coal fired generating station. Significant construction activity will not begin until 2007. The target date for completion is 2010. Construction expenditures for 2005 - - 2009 for this additional generation capacity are estimated to be $632 million.

     The PUCN approved NPC’s Centennial Plan as part of its 2001 Refiled Resource Plan. The Centennial Plan involves construction of the 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 $309.6 million (excluding AFUDC). Total project costs incurred through December 31, 2004, were $189 million. Estimated costs for 2005 are $66.4 million, which are expected to be paid for utilizing internally generated cash. See Transmission, later, for additional information about the Centennial Plan.

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Facilities and Operations

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 2004, NPC generated 40.7% of its total electric energy requirements, purchasing the remaining 59.3% as shown below:

     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 2004 company generation of 8,470,228 MWh decreased 8.2% from NPC’s 2003 company generation of 9,228,377 MWh. NPC’s 2004 purchased power of 12,319,261 MWh decreased 0.9% from NPC’s 2003 purchased power of 12,435,498 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.

Load and Resources Forecast

     NPC’s electric customer growth rate was 5.2%, 5% and 4.8% for the years ended 2004, 2003 and 2002, respectively. Retail electricity sales were 18.6 million MWh in 2004, which represented an increase of 4% over 2003 retail electricity sales of 17.9 million MWh. Annual wholesale electricity sales were approximately 870 thousand MWh in 2004, which represented a decrease of 63% from 2003 wholesale electricity sales of approximately 2.4 million MWh. Total annual system electricity sales were approximately 19.8 million MWh in 2004, which represented a decrease of approximately 4% from 2003 system electricity sales of approximately 20.7 million MWh. The peak electric demand rose from 4,808 MW in 2003 to 4,969 MW in 2004.

     Below are forecasts of the load to be provided to all of NPC’s current and forecasted customers. No adjustments have been made at this time to incorporate possible changes to NPC loads due to the passage of AB 661 and Senate Bill 211 (SB 211). SB 211 allows the Colorado River Commission to sell electricity to its purveyors of water. AB 661 allows commercial and governmental customers with an average demand greater than 1 MW to select other energy suppliers. The forecast takes into account many sources of information. The peak load forecast uses the population forecast produced by the University of Nevada Las Vegas’ Center for Business and Economic Research. The population forecast is used to develop a customer forecast for NPC. Another major assumption is normal weather, which is defined as the 20-year average of historic weather. Uncertainties include abnormal

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temperatures, the price levels NPC will be allowed to charge its customers, and the timing and effect of rules allowing customers to leave NPC under AB 661 and SB 211. Also, bundled retail price levels, as well as availability of power in the West, could affect consumption by customers of NPC. NPC’s total system capability and peak loads for 2004, and the forecast for summer peak demand from 2005 through 2009 (assuming no curtailment of supply or load, and normal weather conditions), are indicated below:

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

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Generation

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

Purchased Power

     NPC continues to manage a diverse portfolio of contracted and spot market supplies, as well as its own generation, with the objective of minimizing its net average system operating costs.

     During 2004, NPC’s credit standing affected the terms under which NPC was able to purchase fuel and electricity in the western energy markets. NPC was often required to contract with counterparties under modified payment terms including accelerated payments, pre-payments, and/or deposits. In the latter part of 2004, NPC experienced more favorable credit and payment terms.

     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.

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

     NPC purchases Hoover Dam power pursuant to a contract with the State of Nevada, which became effective June 1, 1987, and will continue through September 30, 2017. NPC’s allocation of hydroelectric capacity is 235 MW annually.

     NPC has a tolling agreement to purchase 222 MW of generating capacity from Nevada Sun-Peak Limited Partnership, an independent power producer. The contract became effective June 8, 1991 and continues through May 31, 2016.

     NPC has a tolling agreement to purchase 224 MW of generating capacity from Las Vegas Cogeneration II, LLC, an independent power producer. The contract became effective April 1, 2004 and continues through December 31, 2013.

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     According to regulations issued pursuant to the Public Utility Regulatory Policies Act (PURPA), NPC is obligated, under certain conditions, to purchase the output produced by small power producers and co-generation facilities at costs determined by the appropriate state utility commission. Generation facilities that meet the specifications of the regulations are known as qualifying facilities (QFs). As of December 31, 2004, NPC had a total of 305 MW of contractual firm capacity under contract with four QFs. All QF contracts currently delivering power to NPC at long-term rates have been approved by the PUCN and have QF status as approved by the FERC. The QFs are as follows:

     Energy purchased by NPC from the QFs constituted 25% of NPC’s net purchased power requirements for native load and 11.4% of NPC’s net system requirements (including generation) during 2004.

     SB 372 enacted in the 2001 Nevada legislative session sets forth a renewable energy portfolio standard (RPS) requiring NPC to acquire or generate a specific percentage of its energy from renewable resources or to acquire Renewable Energy Credits (RECs). Qualified renewable resources include biomass, wind, solar, and geothermal projects. Pursuant to the statutory RPS, NPC was required to obtain 5% of its total energy from renewable resources for 2004. The statutory RPS requirements increase by 2% every two years to a maximum of 15% by 2013. NPC is required to meet 7% of its total energy from renewable resources for 2005 and 2006. Five percent (5%) of the total renewable energy required by the RPS must be derived from solar resources. SB 372 requires the PUCN to establish regulations that address among other items, the terms and conditions for renewable energy and/or REC contracts. SB 372 provides that all renewable energy contracts receiving approval of the PUCN are deemed to be a prudent investment and NPC may recover all just and reasonable costs associated with the contracts.

     In 2001, NPC issued a Request for Renewable Energy Proposals (Renewable RFP). In March 2003, following negotiations with the renewable energy developers that responded to the Renewable RFP, NPC received PUCN approval for: (1) four long term power purchase agreements (PPA) with geothermal developers totaling 97 MW, (2) two PPAs with wind developers totaling 130 MW, and (3) one PPA with a solar developer for 33 MW. Two of the PPAs with NPC (one geothermal PPA for 47 MW and one wind PPA for 80 MW), have subsequently been terminated. The generating facilities under the remaining PPAs have been delayed and are expected to be completed 1-2 years behind schedule.

     In June 2003, NPC issued another Renewable RFP to purchase additional renewable energy and/or RECs to comply with the requirements of Nevada’s RPS. In 2004 as a result of the Renewable RFP, NPC filed for PUCN approval of two additional contracts for the purchase of solar RECs. NPC is in negotiations with additional potential renewable suppliers to purchase renewable energy and/or RECs.

     In April 2004, NPC filed a statutorily mandated compliance report with the PUCN that reported NPC’s performance in meeting the RPS for the calendar year 2003. In 2003, NPC did not acquire the renewable resources set forth in the RPS. For 2003, the PUCN granted NPC an exemption from compliance with the RPS based on insufficient availability. NPC is allowed to purchase excess RECs from SPPC to help NPC comply with its RPS.

     In April 2005, NPC will file its compliance report with the PUCN for calendar year 2004. In 2004, NPC did not meet the RPS requirement. NPC will request an exemption from the PUCN due to insufficient availability of renewable energy.

Transmission

     NPC’s existing transmission lines are primarily located within Clark County, Nevada. Six 230 kV transmission lines and two 230/69 kV transformers connect NPC to the Western Area Power Administration’s (Western) transmission facilities at Henderson and Mead substations. Three 230 kV lines connect NPC to the Los Angeles Department of Water and Power’s transmission facilities at McCullough Substation. Two 500/69 kV transformers connect NPC to the Southern California Edison system at the Mohave Generating station. A 345 kV line connects NPC to PacifiCorp at the Utah-Nevada state line. Also, NPC has two 500/230 kV transformers that connect NPC to the Navajo Transmission System at the Crystal Substation. Finally, NPC has ownership rights in two

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500 kV transmission lines that allow for the transmittal of NPC’s share of power from its interests in the Mohave and Navajo Generating Stations to the NPC control area. If the Mohave Generating station is shut down in 2005, NPC intends to continue to utilize the Eldorado Transmission System that is connected to the Mohave Generating station to supply NPC load and to meet other transmission service obligations currently in place. The transmission lines and generation facilities are governed under separate contracts.

     In its 2003 Integrated Resource Plan (IRP), NPC received approval from the PUCN to construct four new 230 kV switchyards and other upgrades to the transmission system. Two of the four substations approved for construction and upgrade by the PUCN have been placed into service; of the remaining two substations, one is planned to be placed into service in 2006 and the other is planned for 2008. These upgrades will provide system reliability, increased import capability, and transmission capacity to deliver Centennial Independent Power Producer (IPP) energy into or through NPC’s system.

     As part of the 2^nd Amendment to the 2003 IRP, NPC was granted approval to construct the Lenzie 500 kV substation and fold in the existing Harry Allen to Northwest 500 kV line into this substation. This project is scheduled to be completed in March 2006. As part of the 3^rd Amendment to its 2003 IRP, the PUCN reaffirmed its approval for NPC to construct the Harry Allen to Mead 500kV component of the Centennial Plan, which is expected to be in service in January 2007.

     During 2001 and 2002, several IPPs proposed the construction of new generating plants in southern Nevada and requested transmission service from NPC. NPC proposed the Centennial Plan to address transmission service requests from these IPPs. The Centennial Plan was approved in NPC’s 2001 Refiled IRP. This plan, consistent with its tariff and the FERC pricing policies, involves the following lines (1) the Harry Allen substation to Crystal substation 500 kV line, (2) the Harry Allen substation to Northwest substation 500 kV line, (3) the Harry Allen substation to Mead substation 500 kV line and (4) two Bighorn to Arden 230 kV lines. Additional facilities include a new 500 kV substation at Harry Allen, 500/230 kV transformers at Mead and Northwest substations, two phase shifting transformers at Crystal substation, the Beltway 230/138 kV substation, the upgrade of the Arden to Decatur 230 kV line and several other sub-transmission upgrades and additions. The Harry Allen—Crystal 500 kV line and the Harry Allen 500 kV substation were energized in June 2002. The Arden- Bighorn 230 kV #1 and #2 lines were completed in July 2002. The Harry Allen—Northwest 500 kV line, the Northwest 500/230 kV transformer and the Northwest 500 kV substation were completed in March 2003. The Crystal 500 kV phase shifting transformers were installed in February 2004. The scheduled in-service date for the Harry Allen-Mead 500 kV line and the Mead 500/230 kV transformer is January 2007.

     See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations Nevada Power Company—Other (Income) Expenses.

Fuel Availability

     NPC’s 2004 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 2000-2004, along with the percentage contribution to NPC’s total fuel requirements were as follows:

Average Consumption Cost & Percentage Contribution to Total Fuel Requirement

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

     Coal delivered to the Reid Gardner Station originates from various mines in the Utah and Colorado coalfields and is delivered to the station via the Union Pacific Railroad. NPC has coal contracts with Canyon Fuel Company, LLC, a subsidiary of Arch Coal Company (expires December 31, 2006), with Oxbow Carbon and Minerals, LLC (expires December 31, 2006), and Andalex

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Resources, Inc (expires December 31, 2007). Full requirements for coal supplies for 2005 as well as partial requirements for various terms up to 2007 are under contract.

     As of December 31, 2004, Reid Gardner Station’s coal inventory level was 272,798 tons, or approximately 45 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 the Price, Utah area, to the Reid Gardner Station in Moapa, Nevada. This contract expired December 31, 2004, but has been extended for three months and negotiations are underway for a replacement transportation services contract. Union Pacific’s ongoing service problems are characterized by crew shortages and system congestion. These conditions affect Union Pacific’s ability to provide deliveries of coal on a timely basis to Reid Gardner. NPC continues its program of corrective actions that helped to prevent coal inventories from reaching low levels in 2004. In 2005, Union Pacific is continuing its program to restore service levels.

     The Utah Railway contract provides for delivery of the remainder of NPC’s Price, Utah area supplies to the Provo interchange with Union Pacific. Both of NPC’s rail transportation contracts contain certain tonnage requirements and railroad service criteria.

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

     In 2004, NPC purchased natural gas on a firm, fixed and indexed price basis from near the Southern California border and Rocky Mountain Basin areas. Gas obtained from the Rocky Mountain region was transported on the Kern River Gas Transmission Company pipeline and delivered to both NPC’s Harry Allen station and Southwest Gas Company’s distribution system. Southwest Gas’s system provided downstream transportation services to NPC’s Clark and Sunrise stations and to the Las Vegas Co-Generation II unit on behalf of NPC in support of a long-term gas tolling arrangement. Rocky Mountain Basin gas supplies were also delivered to Reliant Energy Services at the Opal Receipt Point on Kern River Pipeline in support of the gas tolling arrangement for the Reliant Big Horn Power Generating Station. Natural gas supplies, which were considered to be Southern California equivalent purchases, also were delivered gas products for all of NPC’s generating units.

     NPC entered into a summer seasonal transportation contract in 2001 for 50,000 decatherms (Dth)/day and an annual contract for 75,000 Dth/day of Kern River’s transportation capacity. Under the contract, deliveries began in May 2003, and were contracted to continue for a period of 15 years. During November 2004, NPC agreed to take permanent assignment of about 50,433 decatherms (Dth)/day from two gas transportation contracts being held by Duke Energy Trading and Marketing. In December 2004 the Board of Directors approved the permanent assignment of three Kern River Pipeline gas transportation contracts totaling about 31,775 decatherms (Dth)/day from Sempra Energy Trading. These contracts have an effective assignment date of June 1, 2006 to coincide with expected summertime operations of Lenzie and the added peaking unit to be installed at the Harry Allen site. As part of this arrangement, Sempra Energy Trading agreed to take assignment of about 37,933 decatherms (Dth)/day of Kern River Pipeline capacity at full tariff rate for the time period of January 1, 2005 until June 1, 2006.

     The Harry Allen Station, which is directly connected to the Kern River pipeline system, retained the Operator Balancing Agreement (OBA) with Kern River that has been in place since April 1995. The OBA enables NPC to have rights to Kern River’s capacity.

     Local natural gas transportation service to Clark and Sunrise Stations is provided under a 32-year transportation services contract with Southwest Gas Company signed in 1995. The contact provides firm service with certain operating and nominating provisions.

SIERRA PACIFIC POWER COMPANY

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

     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, L.L.C., which was formed to utilize federal income tax

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credits available under Section 29 of the Internal Revenue Code associated with the alternative fuel (syngas) produced by the coal gasifier located at the Piñon Pine facility.

     SPPC is a public utility primarily engaged in the distribution, transmission, generation, and sale of electric energy. It provides electricity to approximately 342,600 customers in an approximately 50,000 square mile service area in western, central and northeastern Nevada, including the cities of Reno, Sparks, Carson City, and Elko, and a portion of eastern California, including the Lake Tahoe area. In 2004, electric revenues were 85% of SPPC’s revenue.

     SPPC also provides natural gas service in Nevada to approximately 134,800 customers in an area of about 600 square miles in Reno/Sparks and environs. In 2004, natural gas revenues were approximately 15% of SPPC’s revenues.

Business and Competitive Environment

     In 2004, SPPC’s electric business contributed $882 million in revenues from continuing operations. The electric system peak typically occurs in the summer, while the winter peak is nearly as high. The system has an annual load factor of approximately 68%, which is above the industry norm of 50% to 55%.

     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.). Summer retail peak loads are primarily driven by cooling equipment demand (including air conditioning demand) and irrigation pumping. SPPC’s peak load increased an average of 2.2% annually over the past five years, reaching 1,631 MW on August 11, 2004. SPPC’s total retail electric MWh sales have increased an average of 1.7% annually over the past five years.

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

     Nevada’s precious metals mining industry continued to see positive developments during 2004. According to the Nevada Mining Association, the continuing rise in the average price of gold, from approximately $270 per ounce during the period of 1998 to 2001, to approximately $400 per ounce at the end of 2003, to nearly $440 per ounce at the end of 2004, has resulted in a significant improvement in the financial health of the state’s mining industry. This increase in price, coupled with Nevada’s reasonable regulatory environment and favorable geology for gold deposits, offers positive opportunities for future mine development. The state’s gold mining industry currently produces in excess of seven million ounces of gold per year. 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 $148 million. For 2004, this represented 16.8% of SPPC’s electric operating revenues of $882 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.

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     The offices, schools, government and healthcare customer segments continue to grow with the addition of new schools, government facilities and healthcare facilities. Customers in all segments continued to implement energy conservation and efficiency programs at the same time they were experiencing new growth, keeping the overall increase modest. In healthcare, expansion continues with a number of new facilities scheduled to open in 2006. In the education sector, two new elementary schools and a new middle school are scheduled to open fall 2006, while the University of Nevada at Reno will see the opening of new facilities on its campus in 2007. In the government sector, in response to the region’s continuing growth, a variety of new facilities (including maintenance facilities, judicial facilities, libraries, emergency response facilities and fire stations) are in various stages of planning and construction and will be completed and become operational in the near future.

     Sales in the resort and recreation segment declined for the second year due to continued energy conservation measures, weather conditions, and the closure of two properties. Inspite of the declining sales the regional economy continues to thrive through business segment diversification. Customers in the recreation segment are continuing to see an improving business climate and increasing convention and entertainment sales as a result of the region’s efforts to strengthen its competitive position in the tourism, gaming and leisure markets by re-branding the Reno/Tahoe market as a premier four-season resort, recreation and meeting destination. These marketing efforts are scheduled to continue with the region promoting Reno/Tahoe as “America’s Adventure Place.” At the same time, downtown revitalization efforts in Reno and Sparks are successfully moving forward, with a number of major projects scheduled for completion in 2005 including renovation and conversion of two large casino/hotel properties in Reno to condominiums, and the opening of the $282 million, 3.1 mile train trench project that runs through Reno’s downtown core.

     In 2004, MWh sales in the manufacturing and warehousing segment increased by 10.4% over sales in 2003. This represented the second year of double-digit growth in the segment. This continuing increase in MWh sales is the result of activities by existing customers to expand their operations, facilities and hours of production, and by new customers who continue to move to northern Nevada to take advantage of the region’s positive business climate and easy access to markets in the western United States.

     AB 661, enacted by the 2001 Session of the Nevada State Legislature, 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. In February 2004, Barrick Gold (Barrick), a large SPPC mining customer, filed an AB 661 application indicating its intention to construct a 118 MW generating facility to meet a majority of its electric power needs. Barrick indicates it intends to continue to purchase transmission and distribution services from SPPC and sell approximately 8 MW of capacity from this new facility to SPPC. When Barrick’s new generating facility becomes operational in November 2005, this customer will reduce kilowatt-hour retail consumption on SPPC’s electric system by approximately 11% and, in turn, SPPC will reduce its power purchases.

     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. The proposed transaction is anticipated to be a significant benefit to SPPC’s remaining customers.

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     SPPC’s MWh sales to wholesale customers have decreased 63% over the past year. During 2004, firm and non-firm sales to wholesale customers comprised 5.2% of SPPC’s total energy sales. Wholesale customers consist of other utilities or municipalities that sell power to end users, marketing entities and others that exchange power with SPPC.

     SPPC’s decrease in wholesale sales was a result of a change in procurement strategy from prior years. The strategy now focuses on executing contracts for power deliveries to SPPC’s physical points of deliveries. On previous years, SPPC used hedges to reduce price and commodity risk for future purchases. The hedge purchase was either delivered to SPPC’s service territory to service its customers or, if the hedge purchase was not needed to fulfill power requirements, resold in the liquid market. With the significant drop in liquidity in wholesale markets, SPPC has changed its procurement strategy to focus on power deliveries to SPPC’s physical points of delivery. See Energy Supply in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, for a discussion of the Utilities’ purchased power procurement strategies.

Construction Program

     SPPC’s construction program and estimated expenditures are subject to continuing review and are revised from time to time due to various factors, including the rate of load growth, escalation of construction 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. SPPC’s service territory continues to experience steady growth. Capital construction expenditures and estimates are reflective of this obligation to serve its customers.

     SPPC’s gross construction expenditures for 2004, including AFUDC and contributions in aid of construction, were $131.9 million, and for the period 2000 through 2004, were $677.6 million. Estimated construction expenditures for 2005 and the period 2006-2009 are as follows (dollars in thousands):

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     Total estimated construction and plant cash requirements for 2005 and the 2006-2009 period consist of the following (dollars in thousands):

     SPPC is planning to construct additional combined cycle generation capacity at the Tracy Plant. The PUCN has not given final approval for the project, pending the submission of the results of additional studies by August 1, 2005. If approved, the expected project cost (which is reflected on the tables above) will be $381 million, with completion expected in 2008.

     The Falcon to Gonder Transmission Project, a 345kV transmission line within northern Nevada, was completed May 2004. Total project costs incurred were $98 million. Actual costs incurred in 2004 were $19 million.

Facilities and Operations

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 2004, SPPC generated 44.6% of its total electric energy requirements, purchasing the remaining 55.4% as shown below:

     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 2004 company generation of 4.6 million MWh increased 9.9% from SPPC’s 2003 company generation of 4.2 million MWh. SPPC’s 2004 purchased power of 5.7 million MWh decreased 13% from SPPC’s 2003 purchased power of 6.5 million MWh. See Energy Supply in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, for additional information.

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Risk Management

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

Load and Resources Forecast

     SPPC’s electric customer growth rate was 2.9%, 3.3% and 2.3% in the years ended 2004, 2003, and 2002, respectively. Retail electricity sales were approximately 9.1 million MWh in 2004, which represented an increase of approximately 3% over 2003 retail electricity sales of approximately 8.9 million MWh in 2003. Annual wholesale electricity sales reached 506 thousand MWh in 2004, which represents a decrease of approximately 64% from 2003 wholesale electricity sales of 1.4 million MWh. Overall, annual system electricity sales were 9.7 million MWh in 2004, which represents a decrease of 5.8% from 2003 system electricity sales of 10.3 million MWh. The bulk of the decrease resulted from a decrease in the economy portion of wholesale. The 2004 peak electric demand was 1,631 MW. The 2003 peak demand was 1,657 MW.

     The projections shown below are forecasts of the load to be provided to all of SPPC’s current and forecasted customers. An adjustment was made to incorporate a change to SPPC loads because it is expected that one mining customer will no longer be a retail customer. This customer will leave under AB 661. AB661 allows commercial and governmental customers with an average demand greater than 1 MW to select other energy suppliers. The forecast includes an assumption that normal weather (based on 20-year averages) will occur. Other uncertainties to the forecast include abnormal weather, a down turn in the local economy, and customer losses due to AB 661. SPPC continues to provide energy through generation and purchased power to meet both summer and winter peak loads. SPPC’s total system capability and peak loads for 2004, and the forecast for summer peak demand through 2009 (assuming no curtailment of supply or load and normal weather conditions), are indicated below:

     SPPC plans its system capacity needs in accordance with the WECC reliability criteria, which recommends planning reserves in excess of required operating reserves.

Generation

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

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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.

     In the latter part of 2004, SPPC experienced more favorable credit and payment terms. During 2004, SPPC’s credit standing affected the terms under which SPPC was able to purchase fuel and electricity in the western energy markets. SPPC was often required to contract with counterparties under modified payment terms including accelerated payments, pre-payments, and/or provide deposits.

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

     SPPC purchases hydroelectric and thermal generation spot market energy, by the hour 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.

     SPPC contracted with the following parties for power deliveries during the summer of 2004: Morgan Stanley for a total of 100 MW capacity from the Naniwa Plant, Calpine for a total of 150 MW capacity for delivery at Gonder and 94 MW delivered to COB, APS for a total of 50 MW delivered to Mona, and Constellation for a total of 50 MW delivered to Mona, for the summer of 2004.

     Currently, SPPC has contracted for a total of 75 MW of long-term firm purchased power from PacifiCorp. SPPC’s firm purchase power contract with PacifiCorp is from June 1989 to February 28, 2009 and contains a 70% minimum purchase and 80% maximum monthly obligation.

     According to PURPA, SPPC is obligated under certain conditions to purchase the output produced by small power producers and co-generation facilities at costs determined by the appropriate state utility commission. As of December 31, 2004, SPPC had a total of 109 MW of maximum contractual firm capacity under 15 contracts with renewable developers. SPPC had contracts with three of the 15 projects at variable short-term avoided cost rates. All renewable developer contracts currently delivering power to SPPC at

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long–term rates have been approved by either the PUCN or the CPUC, and have renewable developer status as approved by the FERC. One long-term renewable developer contract terminates in 2006, one terminates in 2039, and the remaining terminate between 2014 and 2022.

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

     SB 372 enacted in the 2001 Nevada legislative session sets forth a renewable energy portfolio standard (RPS) requiring SPPC to acquire or generate a specific percentage of its energy from renewable resources or to acquire Renewable Energy Credits (RECs). Qualified renewable resources include biomass, wind, solar, and geothermal projects. Pursuant to the statutory RPS, SPPC is required to obtain 5% of its total energy from renewable resources for 2003 and 2004. SPPC is required to meet 7% of its total energy from renewable resources for 2005 and 2006. Five percent (5%) of the total renewable energy required by the RPS must be derived from solar resources. SB 372 requires the PUCN to establish regulations that address among other items, the terms and conditions for renewable energy and/or REC contracts. SB 372 provides that all renewable energy contracts receiving approval of the PUCN are deemed to be a prudent investment and SPPC may recover all just and reasonable costs associated with the contracts.

     In 2001, SPPC issued a Renewable RFP. In March 2003, following negotiations with the renewable energy developers that responded to the Renewable RFP, SPPC received PUCN approval of one long term Power Purchase Agreement (PPA) with a solar developer for its 17 MW share of a 50 MW solar generating facility. The solar developer has informed SPPC that it will not complete the generating facility on time to meet the March 2005 completion date and the project is expected to be at least one year behind schedule.

     In June 2003, SPPC issued another Renewable RFP to purchase additional renewable energy and/or RECs to comply with the requirements of Nevada’s RPS. In 2004 as a result of the Renewable RFP, SPPC received PUCN approval of one long term PPA to purchase renewable energy from a new 20 MW geothermal generating facility. SPPC has filed for PUCN approval of three additional contracts for the purchase of geothermal RECs.

     In April 2004, SPPC filed a statutorily mandated compliance report with the PUCN that reported SPPC’s performance in meeting the RPS for the calendar year 2003. In 2003, SPPC exceeded its non-solar renewable energy portfolio requirement but did not acquire the solar renewable resources set forth in the RPS. For 2003, the PUCN granted SPPC an exemption from compliance with the solar portion of the RPS based on insufficient supplies available. The PUCN authorized SPPC to bank its excess non-solar RECs. These excess RECs can be used in future years by SPPC or sold to NPC to help NPC comply with its RPS.

     In April 2005, SPPC will file its compliance report with the PUCN for calendar year 2004. In 2004, SPPC acquired or generated approximately 8% of its total energy from qualified renewable resources. SPPC exceeded its non-solar RPS requirement but again did not meet the solar requirement. SPPC will request an exemption from the PUCN for the solar portion of the RPS.

Transmission

     SPPC’s existing transmission lines extend some 300 miles from the crest of the Sierra Nevada mountain range in eastern California, northeast to the Nevada-Idaho border at Jackpot, Nevada, about 160 miles from Reno northwest to Alturas, California, and 250 miles from the Reno area south to Tonopah, Nevada. A 230 kV transmission line connects SPPC to facilities near the Utah-Nevada state line, which in turn interconnects SPPC to PacifiCorp and the Los Angeles Department of Water and Power facilities located in Utah. A 345 kV transmission line connects SPPC to Idaho Power’s facilities at the Idaho-Nevada state line. A 345 kV line connects SPPC to the Bonneville Power Administration’s facilities near Alturas, California. Two 120 kV lines and one 60 kV line connect SPPC with Pacific Gas & Electric at Donner Summit, California. Two 55 kV transmission ties connect SPPC to Southern California Edison.

     The Falcon to Gonder Project, a new 180-mile 345 kV line connecting SPPC’s Falcon Substation to Mt. Wheeler Power’s Gonder Substation, was placed into service in May 2004. This project improves system import and export capabilities and enables SPPC to provide transmission service between Idaho, Utah, and the northwest U.S. The total project costs incurred were approximately $98 million.

     As part of the 2004 IRP filing, SPPC was granted approval to construct a new 345kV transmission line from the existing East Tracy 345kV substation to a new 345kV substation (Emma) located east of Virginia City and to acquire transmission easements for a future line between the proposed Emma substation and the existing Mira Loma 345kV substation.

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Fuel Availability

     SPPC’s 2004 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 2000-2004, along with the percentage contribution to SPPC’s total fuel requirements, were as follows:

Average Consumption Cost & Percentage Contribution to Total Fuel

     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’s long-term coal contract with Canyon Fuel Company, LLC, a subsidiary of Arch Coal Company, provides for deliveries through December 31, 2006. This contract supply represents approximately 85% of Valmy’s coal requirements. During 2004, the remaining needs were filled through a contract with Kiewit Mining Group Inc. for the supply of coal from their Black Butte Mine in Southern Wyoming. The Kiewit contract has been extended through 2005.

     As of December 31, 2004, Valmy’s coal inventory level was 83,212 tons, or approximately 14 days of consumption at 100% capacity.

     During 2004, transportation of coal to Valmy was provided by the Union Pacific Railroad under a contract that expired December 31, 2004. This rail transportation contract contained certain tonnage requirements and railroad service criteria. This contract has been extended for three months and negotiations are underway for a replacement transportation services contract. The above inventory level reflects the continuing crew shortages and system congestion experienced by Union Pacific that affected their ability to provide deliveries of coal on a timely basis to Valmy. SPPC continues its program of corrective actions aimed at preventing coal inventories from reaching critically low levels

     During 2004, SPPC operated the Piñon Pine facility exclusively on natural gas. See the next section, Natural Gas Business, for discussions related to natural gas procurement for generation. No coal was purchased in 2004 for synthetic gas production in the plant’s coal gasification facility.

     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.

Natural Gas Business

     SPPC’s natural gas business consists of operating the local distribution company (LDC) for the Reno/Sparks metropolitan area and procuring gas for electrical power generation at the Tracy and Ft. Churchill plants. The LDC accounted for $154 million in 2004 operating revenues or 15% of SPPC’s revenues from continuing operations. Growth in SPPC’s LDC service territory continues to be strong with customer meter counts growing by approximately 4% in 2004.

     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. SPPC expects to install approximately 5,000 meters in 2005.

     SPPC’s natural gas 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 February 1, 2005, there are 15 large customers securing their own supplies. These customers have a combined firm distribution load of approximately 4,480 Decatherms (Dth) per day. Transportation customers

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continue to pay firm and interruptible distribution charges. These customers are responsible for procuring and paying for their own gas supply.

     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, 2004):

     Total LDC Dth supply requirements in 2003 and 2004 were 14.9 million Dth and 16.1 million Dth, respectively. Electric generating fuel requirements for 2003 and 2004 were 23.3 million Dth and 25.3 million Dth, respectively.

     In addition to the capacity reflected above SPPC has contracted with Paiute Pipeline for 23,000 Dth per day of LNG service and related gas transportation to meet peak day growth in 2005 and 2006. This is a long term contract and is waiting final Federal Energy Regulatory Commission approvals.

     In October 2004, the PUCN released its order regarding SPPC’s Purchase Gas Adjustment filing made on May 14, 2004 and the new rates became effective November 1, 2004. An average residential customer received an increase in their rates of approximately 5%.

     As of December 31, 2004, SPPC owned and operated 1,845 miles of three-inch equivalent natural gas distribution piping, 93 miles of which were added in 2004. There were three significant projects completed in 2004. Two gas regulator stations were constructed to supply the fast growing areas north of Reno. SPPC constructed 3,400 feet of 18” steel gas main to complete a multi-year project to serve our customers south of Reno. SPPC also continued its ongoing main and service replacement projects.

REGULATION (UTILITIES)

     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 IRPs to the PUCN for approval.

     The Utilities and Tuscarora Gas Pipeline Company (TGPC) are subject to certain federal 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.

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     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.

Nevada Legislation

Assembly Bill 661

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

     In 2003, thirteen NPC customer applications under AB 661 were processed by the PUCN. These customers received conditional approval to depart upon the completion of items in the compliance order. However, none of the customers successfully completed compliance items and none was granted final approval from the PUCN to procure their energy services from other suppliers. Currently there are no applications pending with the PUCN in NPC’s service territory.

     In February 2004, Barrick, a large SPPC mining customer filed an application to depart in spring 2005. The PUCN issued an order on June 22, 2004 approving the application as stipulated by the parties. The customer has provided an official notice to SPPC specifying November 2005 as the departure date.

     Newmont Mining Corporation, another large mining customer approached SPPC to develop terms and conditions under which the customer will construct a 203 MW coal fired generating plant and sell the output to SPPC. SPPC will in turn sell part of the plant’s output to the customer to serve its mining loads under a new tariff. This customer is expected to 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 which were approved by the PUCN on February 23, 2005. The proposed transaction is anticipated to be a significant benefit to SPPC’s remaining customers.

     Any customer who departs the Utility’s system and later decides to return to the Utility as their energy provider will be charged for their energy at a rate equivalent to Utility’s incremental cost of service.

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. Delivery of the energy from this new generation to NPC’s customers would require a reservation on the Harry Allen-to-Mead 500 kilovolt (kV) transmission line. The construction of this transmission project is required to fulfill existing wholesale transmission contractual obligations to Independent Power Producers located within NPC’s control area.

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     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. As such, NPC expected to expend up to approximately $500 million prior to the summer of 2007 for the construction and/or acquisition of generation facilities. NPC acknowledged that if internally generated funds were inadequate, it may need to access the capital markets. NPC has since issued new debt, which is discussed below. See NPC’s Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources for a discussion of NPC’s financial condition and limitations on NPC’s ability to issue additional indebtedness.

Nevada Power Company Subsequent Material Amendment to its 2003 Integrated Resource Plan

     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. This amendment requested approval to substitute the nominally rated 1200 MW Chuck Lenzie Generating Station, which is expected to become operational in early 2006, for the previously approved Harry Allen 520 MW combined cycle generator, which is to come on line in 2007.

     Lenzie is comprised of two nominally rated 600 MW combined cycle generators located north of Las Vegas. The filing provides NPC’s due diligence work, the contract and finance plan. The estimated cost to complete construction is $376 million making the total cost $558 million.

     The PUCN held hearings to consider the Resource Plan amendment and an associated financing filing and rendered an order on September 21, 2004. The PUCN 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 PUCN also granted NPC’s request for $500 million in long-term debt authority. 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.

     The transaction with Duke Energy closed on October 13, 2004. A future general rate case will be required before NPC can include the costs for this facility in rates.

Nevada Power Company – Miscellaneous Amendments to its 2003 Integrated Resource Plan

     NPC has filed a number of other resource plan amendments, which reaffirm the need for a major transmission line, modify demand side management programs, modify four previously approved renewable energy contracts and request approval of two new contracts for renewable energy credits.

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 is a request for approval to construct a 500 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 on the following items:

•

Designation of the combined cycle plant as a “critical facility” in accordance with the PUCN’s regulations which allows for an enhanced return on equity on the designated “critical facility” over the life of the facility. The Tracy facility is a “critical facility” under the PUCN’s recently amended resource planning regulations because it promotes price stability and reliability and reduces dependence on purchased power.

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	•	Approval to upgrade the combustion systems at SPPC’s Valmy generating station to comply with the emission standards of the “Clear Skies Initiative”.
	•	Approval to conduct a study on the feasibility of additional coal-fired generation at SPPC’s Valmy generation plant.
	•	Approval of the renewable energy promotion program through which SPPC will promote renewable energy development.
	•	Approval of SPPC’s energy supply plan for the period from 2005 through 2007. The energy supply plan includes 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. The energy supply plan also includes a recommended gas hedging strategy for April 2005 through March 2006.
	•	Approval of the construction of a new 345 kV transmission line from SPPC’s existing East Tracy 345 kV substation to a new 345 kV substation (Emma) located east of Virginia City.

     SPPC and parties reached agreement on the issues and presented a stipulation to the PUCN on October 12, 2004. The stipulation calls for budget adjustments in the Demand Side Management programs and continued discussions to develop a new cost/benefit test for such programs. The stipulation authorizes SPPC to proceed with permitting activities for a 500 MW combined cycle power plant as requested and requires SPPC to file a Resource Plan Amendment to reaffirm the need for the 500 MW capacity addition before August 1, 2005. SPPC’s request for a “critical facility” designation and the associated enhanced ROE was deferred for consideration during the amendment proceedings. On November 18, 2004, the PUCN issued an Order approving the stipulation. All other supply side proposals were approved as filed. In its Order, the PUCN approved and determined the power procurement element of the Energy Supply Plan to be prudent; however, no determination of prudency was made in regard to the fuel procurement plan and risk management strategy. Prudency with regard to fuel procurement and risk management will be determined in the appropriate deferred energy proceeding.

Sierra Pacific Power Company – Miscellaneous Amendments to its 2004 Integrated Resource Plan

     SPPC has filed four amendments to its 2004 IRP. The first three amendments requested approval of a 20 year 7MW renewable energy contract, an 8MW power purchase agreement from Barrick’s planned new generation plant and contracts to purchase renewable energy credits from existing renewable energy generators.

Temporary Renewable Energy Development Trust

     On July 9, 2004, NPC and SPPC together with the Regulatory Operations Staff of the PUCN, the Nevada Bureau of Consumer Protection (BCP), the Nevada State Office of Energy, and certain renewable energy providers filed a joint petition with the PUCN requesting that Nevada regulations be amended to establish a Temporary Renewable Energy Development (TRED) program to assist with the completion of new renewable energy projects. The PUCN agreed to amend its regulations to establish the TRED program at its September 29, 2004 agenda meeting.

     It is anticipated that the TRED program will assist developers of new renewable energy projects in successfully financing their projects, thereby resulting in a higher rate of completion for new renewable energy projects with PUCN-approved contracts, thereby allowing the Utilities to more quickly satisfy their renewable energy portfolio requirements.

     Specifically the TRED program will establish a TRED charge to be separately collected from customers to pay renewable energy suppliers under PUCN-approved contract. TRED program revenues will be forwarded 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 October 15, 2004, the Utilities filed an application requesting approval to set up a TRED trust. The PUCN issued an order approving the application on January 6, 2005.

     See Regulatory Proceedings in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations for additional regulatory information.

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OTHER SUBSIDIARIES OF SIERRA PACIFIC RESOURCES

Tuscarora Gas Pipeline Company

     TGPC was formed as a wholly owned subsidiary of SPR in 1993 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) was formed for the purpose of constructing and operating an interstate natural gas pipeline from Malin, Oregon to Reno, Nevada to serve an expanding gas market in Reno, 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 takes custody of its customers’ gas near Malin, Oregon at a pipeline interconnect with Gas Transmission Northwest Corporation (GTN), the upstream pipeline. Upon custody transfer, Tuscarora transports its shippers’ gas to various delivery points along the Tuscarora system as prescribed by its customers. GTN is a major interstate natural gas pipeline extending from the U.S./Canadian border, at a point near Bonners Ferry, Idaho to the Oregon/California border. The GTN system provides Tuscarora customers access to Canadian natural gas reserves 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 largest customer at the start of commercial operations and continues to be Tuscarora’s largest customer contributing 75% of gross revenues in 2004.

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.

     In 2004, under the terms of the settlement agreement, SPC paid $10 million to STA 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. The settlement also provides SPC with one remaining duct and associated occupancy rights in the System and allows SPC to complete the transfer and sale of this duct, which was negotiated under a 2002 contract with a telecommunications carrier for $20 million.

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. In June of 2004, LOS sold its property in California. The remaining land located in Nevada, is of minimal book value.

     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

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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 is currently considering 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, the EPA is required by the terms of a settlement agreement to issue regulations by March 15, 2005 providing for the reduction of mercury emissions, and it is possible that the EPA may issue other air pollution control regulations at that same time. Because of the uncertainty relating to the proposed legislation and regulations, management is not able at this time to evaluate 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 3,152 employees as of December 31, 2004, of which 1,771 were employed by NPC and 1,308 were employed by SPPC.

     NPC’s current contract with the International Brotherhood of Electrical Workers (IBEW) Local No. 396, which covers approximately 57% of NPC’s workforce, was renegotiated in February 2002 and was in effect until February 1, 2005. The three-year contract provided for a 3% general wage increase for bargaining unit employees effective February 2, 2002, with 3% increases in 2003 and 2004. In addition, the contract provided for participation by bargaining unit employees in the incentive compensation program.

     On February 7, 2005, NPC and IBEW Local 396 executed an agreement, which extends the current contract while negotiations on a new labor contract continue. The purpose of the extension agreement is to continue operating under the terms of the current collective bargaining agreement (CBA) during the negotiating process and until a new contract is ratified by IBEW membership. The extension agreement will terminate at midnight on May 1, 2005.

     SPPC’s current contract with the IBEW Local No. 1245, which represents approximately 64% of SPPC’s workforce, was renegotiated in December 2002 and is in effect until December 31, 2005. The three-year contract provides for a 3% general wage increase for bargaining unit employees beginning January 13, 2003, with 3.25% and 3.75% increases in 2004 and 2005, respectively. In addition, the contract provides for participation by bargaining unit employees in the incentive compensation program.

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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 2004, the Utilities collected $76.2 million in franchise or other fees based on gross revenues. They collected $9.1 million in UEC based on consumption. They also paid and recorded as expense $.6 million of fees based on net profits.

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

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ITEM 2. PROPERTIES

     The general character of SPR’s, NPC’s, and SPPC’s principal facilities is discussed in Item 1 – Business.

     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.

ITEM 3. LEGAL PROCEEDINGS

Nevada Power Company and Sierra Pacific Power Company

Enron Litigation

     On October 10, 2004, the U.S. District Court for the Southern District of New York rendered a decision vacating an earlier judgment by the Bankruptcy Court (also for the Southern District of New York) against the Utilities in favor of Enron Power Marketing, Inc. (Enron), and remanded the case back to the Bankruptcy Court for fact-finding. A trial date has been set for April 18, 2005 before the Bankruptcy Court. A description of the legal proceedings leading up to District Court’s order to vacate follows, along with a discussion of all pending matters related to the Enron litigation.

     Bankruptcy Court Judgment

     On June 5, 2002, Enron filed suit against the Utilities in its bankruptcy case in the U.S. Bankruptcy Court for the Southern District of New York asserting claims for termination payments Enron claimed it was owed under purchased power contracts with the Utilities. Enron sought liquidated damages in the amount of approximately $216 million from NPC and $93 million from SPPC based on assertions by Enron that it had contractual rights under the Western Systems Power Pool Agreement (WSPPA) to terminate deliveries to the Utilities. Enron based its assertion on a claim that the Utilities did not provide adequate assurance of the Utilities’ performance under the WSPPA. The Utilities dispute that they owe the monies sought by Enron and have denied liability on numerous grounds, including termination, deceit and fraud in the inducement, fraud, breach of contract, and unfair trade practices.

     On September 26, 2003, the Bankruptcy Court entered a summary judgment (the Judgment) in favor of Enron 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 in May 2002 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, respectively, in the third quarter of 2003. The Bankruptcy Court’s order provided that until paid, the amounts owed by the Utilities will accrue interest post-Judgment at a rate of 1.21% per annum.

     In response to the Judgment, the Utilities filed a motion with the 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 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 $282 thousand in cash 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

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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 Bankruptcy Court also ordered that during the duration of the stay, the Utilities (i) cannot transfer any funds or assets other than to unaffiliated third parties for ordinary course of business operating and capital expenses, (ii) cannot pay dividends to SPR other than for SPR’s current operating expenses and debt payment obligations, and (iii) shall 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 November 21, 2003, the Utilities filed a Petition for Declaratory Order with the PUCN, as required by the Bankruptcy Court’s stay order seeking a determination as to whether payment of all or part of the Judgment into escrow would be subject to recovery through a deferred energy accounting adjustment. On February 6, 2004, the PUCN issued its final order indicating that posting or depositing money in escrow would not constitute payment of fuel or purchased power costs eligible for recovery in a deferred account.

     A hearing was held on April 5, 2004 before the Bankruptcy Court to review the Utilities’ ability to provide additional cash collateral. Prior to the introduction of any testimony or evidence, Enron and the Utilities entered into a settlement whereby NPC agreed to post an additional cash sum of $25 million to be held in escrow pending the issuance of the U.S. District Court’s opinion. NPC made the agreed-upon payment on April 16, 2004, which lowered the principal amount of NPC’s General and Refunding Mortgage Bond, Series H, currently held in escrow, by a like amount. In addition, Enron agreed not to request any additional collateral from NPC or SPPC during the pendency of the Utilities’ appeal of the Judgment to the U.S. District Court for the Southern District of New York.

     The Utilities entered into a stipulation and agreement with Enron which was signed by the Bankruptcy Court on June 30, 2004 and provides that (1) the Utilities shall withdraw their objections to the confirmation of Enron’s bankruptcy plan, (2) the collateral contained in the Utilities’ escrow accounts securing their stay of execution of the Judgment shall 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, as previously ordered by the Bankruptcy Court, shall remain in place without any additional principal contributions by the Utilities to their existing escrow accounts during the pendency of any and all of their appeals of the Judgment, including to the United States Supreme Court, until a final non-appealable judgment is obtained. There can be no assurances that the U.S. District Court or any higher court to which the Utilities appeal the Judgment will accept the existing collateral arrangement to secure further stays of execution of the Judgment.

     On October 1, 2004, the 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. The Utilities have challenged the Bankruptcy Court’s order with respect to these payments, and no final ruling has been made by the Bankruptcy Court.

     Appeal of Bankruptcy Court Judgment to U.S. District Court (SDNY)

     On October 1, 2003, the Utilities filed a Notice of Appeal from the Judgment with the U.S. District Court for the Southern District of New York. In the Utilities’ appeal, the Utilities sought reversal of the Judgment and contended that Enron is not entitled to recover termination charges under the contracts on various grounds including breach of contract, breach of solvency representation, fraud, misrepresentation, and manipulation of the energy markets and that the Bankruptcy Court erred in holding that the filed rate doctrine barred various claims which were purported to challenge the reasonableness of the rate. Enron filed a cross-appeal on the grounds that the amount of post-judgment interest should have been 12% per year instead of 1.21% as ordered by the Bankruptcy Court.

     On October 10, 2004, the U.S. District Court rendered a decision in the Utilities’ appeal. The U.S. District Court’s decision vacated the judgment entered by the Bankruptcy Court against the Utilities in favor of Enron and remanded the case to the 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.

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     The District Court further held that the demand for assurances by Enron should have been limited to the amount of its actual loss. The District Court rejected Enron’s cross-appeal seeking a 12% per year post-judgment interest rate instead of the 1.21% interest rate ordered by the Bankruptcy Court. The District Court decision also provided that Enron could, if proper, renew its motion to enjoin the proceedings currently before the FERC addressing Enron’s termination of its power supply contracts with NPC and SPPC. Although the Judgment has been reversed, the terms of NPC’s and SPPC’s June 30, 2004 stipulation and agreement with Enron, discussed above, will remain in place through the pendency of all remands and appeals of the Judgment.

     The Utilities filed a motion seeking clarification of the District Court rulings with respect to the Utilities’ affirmative defense and counterclaims regarding: fraud by Enron, violation of the Racketeer Influence Corrupt Organizations Act (RICO), anti-trust activities carried out by Enron, the constitutional power of a bankruptcy court to enter a final judgment in a “non-core matter,” and whether the Bankruptcy Court had properly determined the interest rate applicable to pre-judgment interest. On December 23, 2004, the Court affirmed the dismissal of the Utilities’ affirmative defenses and counterclaims were barred under the filed rate doctrine. However, the Court ruled in favor of the Utilities on the calculation of pre-judgment interest.

     FERC Early Termination Case

     On October 6, 2003, the Utilities filed a Complaint with FERC requesting the opportunity to develop a record regarding three issues: (a) whether Enron exercised reasonable discretion in terminating its various 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 the public interest.

     On July 22, 2004, the FERC issued an order granting the Utilities’ request to the FERC for an expedited hearing to review Enron’s termination of the energy contracts entered into between the Utilities and Enron under the WSPPA. Hearings were scheduled to begin on October 25, 2004 and an initial decision was expected from the FERC by December 31, 2004. However, on October 27, 2004, Enron filed a motion in the Bankruptcy Court to enjoin the Utilities from participating in the FERC 206 proceeding. The disposition of this motion is described below.

     Bankruptcy Court Injunction and Order Setting Trial

     After the U.S. District Court issued its October 10, 2004 ruling, Enron renewed its motion with the Bankruptcy Court seeking to enjoin the Utilities from proceeding in the FERC Early Termination Case. On December 3, 2004 the Bankruptcy Court enjoined the Utilities from further prosecution of the scheduled hearing in the FERC proceeding. The Utilities have appealed this decision to the U.S. District Court and are seeking a stay of the adversary proceeding in the Bankruptcy Court, which is set to begin on April 18, 2005. The Utilities are unable to predict the outcome of the trial at this time.

     FERC Revocation Show Cause Proceeding

     In March 2003, FERC instituted a “Show Cause” proceeding involving whether Enron’s market-based rate authority should be revoked in light of Enron’s engagement in illicit trading activities. The Utilities intervened. On June 25, 2003, FERC removed Enron’s market-based rate authority, but only on a prospective basis. The Utilities filed a request for rehearing, along with certain other parties. On October 16, 2003, FERC changed the nature of the proceeding, thereby prohibiting further active participation by the interveners (including the Utilities). On December 15, 2003, the Utilities filed an appeal in the United States Circuit Court of Appeals for the District of Columbia concerning these two actions. The appeals have been consolidated with a number of other appeals of FERC’s decisions, and the matter is pending. The D.C. Circuit has yet to establish a briefing schedule and there is no current time line for argument or a decision in the case.

     FERC Gaming and Partnership Show Cause Proceeding

     On June 25, 2003, FERC issued orders in two separate cases involving Enron and potential gaming of power markets. The first was referred to as the “Gaming Show Cause Proceeding” and the second as the “Partnership Show Cause Proceeding”. The proceedings focused on Enron’s illicit trading activity in California with a variety of counterparties. On July 21, 2004, FERC consolidated the two proceedings and expanded the scope of its inquiry. FERC announced that it was revisiting its decision not to revoke Enron’s market-based rate authority and 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 has sought rehearing of this order, challenging the expanded scope of the proceeding. The Utilities have joined a coalition of other Western Parties and on August 4, 2004, sought clarification that remedies other than disgorgement might be available.

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On March 11, 2005, the FERC issued an order clarifying issues to be covered in the administrative trial scheduled to begin June 13, 2005. In that order, the FERC stated that Enron’s profits under the terminated power contracts fell within the scope of that proceeding.

FERC 206 complaints

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

     The Utilities are contesting the amounts paid for power actually delivered by these suppliers as well as claims made by terminating power suppliers that did not deliver power, including Enron.

     On June 26, 2003, the FERC dismissed the Utilities’ Section 206 complaints finding that the strict public interest standard applied to the case and that the Utilities had failed to satisfy the burden of proof required by that standard. On July 28, 2003, the Utilities filed a petition for rehearing at the FERC requesting that the FERC either reconsider or rehear the case. On November 10, 2003, the FERC reaffirmed the June 26, 2003, decision. That decision has been appealed to the United States Court of Appeals for the Ninth Circuit. Oral argument was held on December 8, 2004. A decision is expected within three to six months. The Utilities are unable to predict the outcome of this appeal at this time.

Reliant Antitrust Litigation

     On April 22, 2002, Reliant Energy Services, Inc. (Reliant) filed a cross-complaint against NPC and SPPC in the wholesale electricity antitrust cases, which cases were consolidated in the Superior Court of the State of California. Plaintiffs (original plaintiffs consist of The People of the State of California, City and County of San Francisco, City of Oakland, and County of Santa Clara) seek damages and restitution from the named defendants for alleged fraud, misrepresentation, and anticompetitive conduct in manipulating the energy markets in California resulting in prices far in excess of what would otherwise have been a fair price to the plaintiff class in a competitive market. Reliant filed cross-complaints against all energy suppliers selling energy in California who were not named as original defendants in the complaint, denying liability but alleging that if there was liability, it should be spread among all energy suppliers. The court granted motions to dismiss, and the case is currently on appeal. Both NPC and SPPC believe they should have no liability regarding this matter, but at this time management is not able to predict either the outcome or timing of a decision.

Nevada Power Company

Morgan Stanley Proceedings

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

     NPC filed a complaint for declaratory relief in the U.S. District Court for the District of Nevada asking the Court to declare that NPC is not liable for any damages as a result of MSCG’s termination of its power supply contracts. On April 17, 2003, MSCG answered the complaint and filed a counterclaim against NPC alleging non-payment of the termination payment in the amount of $25 million. In April 2003, MSCG also filed a complaint against NPC at the FERC alleging that NPC should be required to pay MSCG the amount of the claimed termination payment pending resolution of the case. MSCG filed a motion to intervene in the Section 206 action commenced by NPC against Enron at the FERC, and the FERC denied MSCG’s motion. On October 23, 2003, NPC filed a motion to stay the District Court proceedings, pending guidance on applicable legal principles from the FERC, which guidance may be provided in connection with a complaint NPC filed against Enron with regard to exercise of default and early termination rights. On February 2, 2004, the District Court granted NPC’s motion, and NPC’s complaint for declaratory relief before that court is now stayed pending FERC guidance. On July 22, 2004, the FERC issued an order stating that it would convene a hearing regarding the NPC complaint against Enron (discussed above). On August 11, 2004, NPC filed a motion to continue the stay, and on October 4, 2004, the Court granted the stay for another 90 days. At the February 28, 2005 status conference, the Judge lifted the stay

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and ordered the case to go forward. The parties will meet to set the discovery and trial schedule. On February 28, 2005, NPC filed a motion for summary judgment. At this time, NPC is unable to predict the outcome or timing of the District Court complaint.

El Paso Merchant Energy

     In September 2002, El Paso Merchant Energy (EPME) terminated all forward contracts for energy with NPC for alleged defaults under the WSPPA consisting of alleged failure to pay full contract price for power 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 under contracts for delivered power during the period May 15 to September 15, 2002, together with approximately $10 million in alleged mark to market damages for future undelivered power. With interest, the amount presently claimed by EPME is $42 million. NPC alleges that EPME’s termination resulted in net payments due to NPC under the WSPPA for liquidated damages measured by the difference between the contract price and market price of energy EPME was to deliver from 2004 to 2012. The precise amount due would depend on the manner in which the termination payments are calculated.

     In June 2003, EPME demanded mediation of its claim for a termination payment arising out of EPME’s September 25, 2002, termination of all executory purchase power contracts between NPC and EPME. The mediation was unsuccessful, and on July 25, 2003, NPC commenced an action against EPME and several of its affiliates in the Federal District Court for the District of Nevada for damages resulting from breach of these purchase power contracts. Discovery is ongoing and the case is set for trial to commence in September 2005. At this time, NPC is unable to predict either the outcome or timing of a decision in 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 Bureau of Consumer Protection 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.

     A briefing schedule on the underlying appeal has since been established. A decision is not expected for six to twelve months. At this time NPC is unable to predict either the outcome or timing of a decision in this matter.

Environmental Matters

     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. It is NPC’s position that a violation did not occur and management is presently involved in the discovery process to support this position. Monetary penalties and retrofit control cost, if any, cannot be reasonably estimated at this time.

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     In August 2004, NDEP conducted a Facility Air Quality Operating Permit (Title V) inspection at the Reid Gardner Station. Monitoring, recordkeeping and other reporting items including maintenance records, operating logs, recorded oil/coal data and other information pertaining to the sources identified in the Title V permit were requested. NPC has provided information in connection with this and subsequent requests. In September and October 2004, NPC met with the NDEP to review the outcome of NDEP’s inspection. NDEP informed NPC that it may not be in compliance with certain aspects of its Title V permit and on December 2, 2004 issued Notices of Alleged Violation (NOAVs). NPC is continuing to provide information to NDEP as requested. Because no penalty has been specified by NDEP and discussions are continuing, management cannot reasonably estimate the amount of any potential monetary penalties that may ultimately be assessed in connection with the alleged violations.

Sierra Pacific Resources

Touch America and Sierra Touch America LLC

     In 2000, SPC, a wholly owned subsidiary of SPR, and Touch America, Inc. (TAI, formerly Montana Power) formed Sierra Touch America LLC (STA), a limited liability company whose primary purpose was to engage in communications and fiber optics business projects, including construction of a fiber optic line (the System) between Salt Lake City, Utah, and Sacramento, California. 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 executed a $35 million promissory note in favor of STA. TAI remained as the sole member of STA. The project sustained significant cost overruns and several complaints and mechanics liens were filed against several parties, including STA and SPC, by System contractors and subcontractors, including Bayport Pipeline Company and MasTec North America, Inc.

     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 was entered on October 6, 2004.

     In 2004, under the terms of the settlement agreement, SPC paid $10 million to STA, 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.

Sierra Pacific Power Company

Piñon Pine

     In its 2003 General Rate Case, SPPC sought recovery of all of its unreimbursed costs associated with the Piñon Pine Coal Gasification Demonstration Project. The coal gasifier represented an experimental technology that was being tested pursuant to a Department of Energy (DOE) Clean Coal Technology initiative. Under the terms of a cooperative agreement with the DOE, SPPC agreed to fund 50% of the costs of constructing the Piñon Pine unit, with the DOE funding the remaining 50% of the costs of the project. SPPC’s participation in the Coal Gasification Demonstration Project was permitted and constructed with 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 was never fully operational. After numerous attempts to re-engineer various components of the coal gasifier, the technology has been determined to be unworkable. In its order of May 25, 2004, the PUCN disallowed $43 million of unreimbursed costs associated with the Piñon Pine Coal Gasification Demonstration Project. SPPC filed a Petition for Judicial Review with the Second Judicial District Court of Nevada in June 2004 (CV04-01434). SPPC filed its opening brief in early October. Answering and Reply briefs were filed in November and December and oral argument is being calendared for the first quarter of 2005. SPPC cannot predict the timing or outcome of a decision from this court.

Sierra Pacific Resources and Nevada Power Company

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. Motions to dismiss were filed by all of the defendants and were heard by the court on January 27, 2004. The motions to dismiss were granted based on a filed rate defense asserted by the defendants. SPR and NPC filed a Motion to Reconsider, which was heard by the court on April 20, 2004. The

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court granted the Motion to Reconsider and allowed SPR and NPC to amend the complaint. A Second Amended Complaint was filed on June 4, 2004.

     The Second Amended Complaint names 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 (El Paso); (2) Dynegy Marketing and Trade; and (3) Sempra Energy, Sempra Energy Trading Corporation, Southern California Gas Company (SoCal), and San Diego Gas and Electric (SDG&E) (collectively Sempra). New motions to dismiss were filed by all of the defendants and a hearing was held on November 29, 2004. The District Court granted the defendants’ motions to dismiss. The case has been appealed to the Ninth Circuit Court of Appeals. 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 filed suit in United States District Court, District of Nevada, against Citigroup, Inc., Solomon Smith Barney, Inc., J.P. Morgan Chase Bank and numerous other investment banks and financial institutions asserting claims for damages arising out of the defendants’ conduct in acting in concert with Enron to falsely portray Enron’s financial condition and induce the reliance of business counterparties, including NPC, upon the statements and representations of Enron regarding its financial health in the 1990s and early 2000 time period. The suit alleges, among other things, that the defendants aided and abetted Enron’s fraud through financial transactions with so-called Special Purpose Entities, which were designed to conceal Enron liabilities or artificially inflate revenues and reported financial condition. The complaint seeks damages in excess of $500 million.

     Effective January 10, 2005, the suit was transferred to MDL-1446, In re Enron Corp. Securities, Derivative and Erisa Litigation, pending in the U.S.D.C. in Houston Texas before Judge Melinda Harmon. At this time the Utilities are unable to predict the outcome or the timing of future proceedings related to the complaint.

     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.

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, 2004. 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, 60, Chairman, President and Chief Executive Officer, Sierra Pacific Resources

     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, Inc., The National Environmental Education and Training Foundation, Edison Electric Institute, Western Energy Institute and several not-for-profit organizations.

Michael W. Yackira, 53, Corporate Executive Vice President and Chief Financial Officer, Sierra Pacific Resources

     Mr. Yackira was elected to his position in October 2004 and holds the same position at Nevada Power Company and Sierra Pacific Power Company. From December 2003 to October 2004 he held the position of Executive Vice President and CFO, at both Nevada Power Company and Sierra Pacific Power Company. 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.

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Donald L. “Pat” Shalmy, 64, Corporate Senior Vice President, Policy & External Affairs, Sierra Pacific Resources; President, Nevada Power Company

     Mr. Shalmy was elected to his present position in November 2004. From July 2002 to October 2004 he held the position of President, Nevada Power Company. 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.

Jeffrey L. Ceccarelli, 50, Corporate Senior Vice President, Service Delivery & Operations; President, Sierra Pacific Power Company

     Mr. Ceccarelli was elected to his present position in October 2004. From June 2000 to October 2004 he held the position of President, Sierra Pacific Power Company. 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.

Ernest E. East, 62, Corporate Senior Vice President, General Counsel and Secretary, Sierra Pacific Resources.

     Mr. East was elected to his present position in October 2004, and holds the same position at Nevada Power Company and Sierra Pacific Power Company. From January to November 2004 he held the position of Vice President, General Counsel and Corporate Secretary, at both Nevada Power Company and Sierra Pacific Power Company. Previously he was Senior Vice President and General Counsel/Chief Compliance Officer for Hyatt Gaming Services, LLC, from August 1998 to January 2004.

Victor H. Peña, 56, Senior Vice President, Transformation, Sierra Pacific Resources

     Mr. Peña was elected to his current position in October 2004. From May 2001 to October 2004 he held the position of Senior Vice President and Chief Administrative Officer, and held the same position at SPPC and NPC.

Roberto R. Denis, 55, Corporate Senior Vice President, Generation & Energy Supply, Sierra Pacific Resources, Nevada Power Company and Sierra Pacific Power Company

     Mr. Denis was elected to his present position in October 2004. From August 2003 to October 2004 held the position of Vice President, Energy Supply, for Nevada Power Company and Sierra Pacific Power Company. 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, 61, Corporate Senior Vice President, Administration, Sierra Pacific Resources

     Mr. Wood was elected to his present position in July 2004 and holds the same position at Nevada Power Company and Sierra Pacific Power Company. 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.

John E. Brown, 54, Corporate Controller, Sierra Pacific Resources

     Mr. Brown was elected to his current position in July 2002, and holds the same position at SPPC and NPC. He was formerly Controller since May 2001. Previously he held the position of Director, Corporate and Tax Accounting. Mr. Brown has been with SPR 24 years.

Mary O. Simmons, 49, Vice President, External Affairs, Sierra Pacific Power Company

     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 Nevada Power Company and Sierra Pacific Power Company. Previously she held the position of Controller for SPR since 1999 and held the same position with SPPC and NPC. Ms. Simmons is a certified public accountant and has been with SPR since 1985.

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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 2004 and 2003 are as follows:

Number of Security Holders:

     SPR paid no dividends in 2003 or 2004. 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. 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. 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, Dividend 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.

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Equity Compensation Plan Information

The following table presents information as of December 31, 2004, about securities authorized for issuance under our equity compensation plans, consisting of our 2003 Non-Employee Director Stock Plan, our Employer Stock Purchase Plan and our Executive Long-Term Incentive Plan. Each of these plans has been approved by our shareholders.

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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