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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2003

Indicate by check mark whether each of the registrants (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨

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

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

State the aggregate market value of the voting and non-voting stock held by non-affiliates. As of June 30, 2003: $687,979,039

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

Common Stock, $1.00 par value, of Sierra Pacific Resources outstanding at March 5, 2004: 117,245,771 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 3, 2004, 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

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 nine 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), Lands of Sierra (LOS), Sierra Energy Company (SEC), Independent Energy Consulting, Inc. (IEC) and e·three Custom Energy Solutions, LLC (CES). SEC, IEC and CES, collectively known as (“e·three”), were sold on September 26, 2003 and as a result, are reported separately on the financial statements of SPR as a discontinued operation. NPC and SPPC are referred to collectively in this report as the “Utilities.” References to SPR refer to the consolidated entity, except where the context provides otherwise.

SPR’s Utilities operate three regulated business segments (as defined by FASB Statement No. 131, Disclosure about Segments of an Enterprise and Related Information) which are Nevada Power electric, Sierra Pacific Power electric and Sierra Pacific Power 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 segment information includes segments below the quantitative threshold for separate disclosure. Parenthetical references are included after each major section title to identify the specific entity addressed in the section. See Note 3 of Notes to Financial Statements, Segment Information, 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 Sierra Pacific Resources, Nevada Power Company and Sierra Pacific Power 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. Sierra Pacific Resources, Nevada Power Company and Sierra Pacific Power Company have adopted a code of ethics for their chief executive officer, chief financial officer and controller. Printed copies of the code of ethics may be obtained free of charge by writing to SPR’s Corporate Secretary at Sierra Pacific Resources, P.O. Box 30150, Reno, NV 89520-3150.

ELECTRIC INDUSTRY TRENDS AFFECTING UTILITIES (SPR, NPC AND SPPC)

The year 2003 was marked by a back-to-basics approach for many electric utilities. In the aftermath of the western energy crisis, many utilities have focused on reducing or refinancing debt and rebuilding assets that provide regulated returns. As part of this restructuring, a number of companies sold non-core assets. In the third quarter of 2003, SPR sold its subsidiaries, e·three, which was originally formed to provide energy-related services to businesses.

Fall-out from the western energy crisis continued in nation-wide litigation and regulatory analysis and rulings related to energy markets. In March 2003, the Federal Energy Regulatory Commission (FERC) staff

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published its report on “Price Manipulation in Western Markets”. In November 2003, FERC adopted market behavior rules for sellers of electricity and natural gas to, as FERC stated in their press release, “help prevent market abuse, provide a more stable marketplace and create an environment that will attract needed investment capital in the electric and natural gas industries.” Prosecutions of individuals and investigations into trading conduct and market manipulation continue, particularly related to Enron Power Marketing Inc. (Enron).

In addition, considerable national attention was focused on the reliability of transmission in the United States as a result of outages related to Hurricane Isabel and the August 14, 2003 blackout in the northeast U.S. and Canada. Since a federal energy bill remains stalled in Congress, in December 2003, FERC instructed its staff to develop a plan to require transmission operators to publicly report to the FERC violations of the industry’s voluntary reliability standards. Also, in February 2004, the North American Electric Reliability Council (NERC) adopted a series of recommendations to correct direct causes of the August 14, 2004 blackout, improve compliance and tracking of implementation of NERC standards, and prevent or mitigate the effects of future blackouts. NERC indicated it would work closely with the FERC in its efforts to improve reliability which could relieve the FERC from proceeding with its own reliability plans. Both FERC and NERC continue to urge Congress to pass an energy bill granting the FERC authority to oversee enforcement of a mandatory system of grid reliability standards.

As a result of past federal and state initiative and regulations, electric utilities in some states moved towards retail competition. This transition has slowed and its full implementation as originally contemplated is highly uncertain. Uneven and changing deregulation has left substantial regional variations in retail energy markets. In Nevada, Assembly Bill 661 (AB 661) and Senate Bill 211 (SB 211) were passed in 2001 and allow certain large commercial and governmental customers to choose a new energy supplier beginning mid-2002 upon approval of the PUCN. See Regulation Assembly Bill 661, for further discussions. Although a small number of such customers have filed applications to receive approval to obtain electricity from alternative suppliers, to date no application has been approved and no large customer has actually left the system.

While some regions of the country face lagging power demand and overcapacity, this is not the case in Nevada. Nevada continues to be the fastest growing state in the nation and will require generating plant additions.

NEVADA POWER COMPANY

NPC is a Nevada corporation organized in 1921. NPC became a wholly owned subsidiary of SPR on July 28, 1999. Its mailing address is 6226 West Sahara Avenue, Las Vegas, Nevada 89146. Nevada Electric Investment Company (NEICO) became a wholly owned subsidiary of NPC. In October of 1997, NEICO and UTT Nevada, Inc., an affiliate of Exelon Thermal Technologies, formed Northwind Las Vegas, LLC, a Nevada limited liability company, for the purpose of evaluating district energy projects in southern Nevada.

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 702,771 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 electric business contributed 100% of its 2003 operating revenues of $1.76 billion.

The system has an annual load factor of approximately 48.7%, which is lower than the industry norm of 50% to 55%. Summer peak loads are driven primarily by air conditioning demand. NPC’s peak load increased

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an average of 4.5% annually over the past five years, reaching 4,808 MW on July 21, 2003. NPC’s total retail electric megawatt-hour (MWh) sales have increased an average of 3.2% annually over the past three years. Winter peak loads are low relative to the summer peak. Winter load above the base amount is driven primarily by air handling in forced air furnaces.

NPC’s service territory continues to be one of the fastest growing areas in the nation. In 2003, NPC installed 40,153 electric meters and NPC currently believes it is likely that this level of growth will continue in 2004. A significant part of the growth in NPC’s electric sales has resulted from new residential, industrial, and gaming customers.

NPC’s electric customers by class contributed the following toward 2003 and 2002 MWh sales:

Growth in NPC’s residential class sales continues primarily as a result of new home construction in Las Vegas. New home sales in 2003 of 25,230 surpassed the previous record of 22,940 new homes that was set in 2001.

Tourism and gaming remain southern Nevada’s leading industries and comprise one of NPC’s largest class of customers (see Gaming/Recreation/Restaurants above). During 2003, several new gaming properties and expansion projects increased overall room capacity in Las Vegas by 4,063 rooms or 3.2%. Room capacity is expected to grow by an additional 1,370 rooms, or 1.1%, during 2004. An increase of 5,072 rooms is expected in 2005 with the addition of the Wynn Las Vegas, Caesars Palace expansion and other properties. Also, the addition of over 1.5 million square feet of convention space in 2003 has made Las Vegas one of the top 10 largest convention locations in North America.

MWh sales to NPC’s Office customer class continues to grow with the addition of new office space in Las Vegas. The addition of new office facilities is expected to continue during 2004, with a number of new sites currently under construction.

Other Retail MWh sales are expected to benefit during 2004 from additional sales as a result of approximately 1.1 million square feet of retail space under construction roughly split between discount store centers and grocery store centers.

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

During 2003, firm and non-firm sales to wholesale customers comprised 11.5% of total energy sales, a decrease of 48% from the prior year. Wholesale customers consist of other utilities or municipalities that sell power to end users, marketing entities and others that exchange power with NPC.

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NPC’s decrease in wholesale MWh sales from last year was a result of market conditions and NPC’s power procurement activities. Prior to 2003, NPC used hedges, reflected in non-firm sales, to reduce price and commodity risk. 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 AB 661. One provision of this bill allows commercial customers with an average annual load of 1 MW or more to file a letter of intent and application with the PUCN to acquire electric energy, capacity, and ancillary services from another provider. In 2003, thirteen NPC customer applications 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 their compliance items and none were granted final approval from the PUCN to procure their energy services from other suppliers. Currently there are no NPC customer applications pending in front of the PUCN. For additional information see Regulation, Assembly Bill 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, escalation of construction costs, availability of fuel types, the number and status of proposed independent generation projects, the need for additional transmission capacity in southern Nevada, adequacy of rate relief, NPC’s ability to raise necessary capital, NPC’s other cash needs and changes in environmental regulations. Under NPC’s franchise agreements, it is obligated to provide safe and reliable energy to its customers. NPC’s service territory is one of the fastest growing areas in the nation. NPC’s capital construction expenditures and estimates are reflective of its obligation to serve its customers.

NPC’s gross construction expenditures for 2003, including allowance for funds used during construction (AFUDC) and contributions in aid of construction, were $227.0 million, and for the period 1999 through 2003 were $1.15 billion. NPC’s estimated construction expenditures for 2004 and the period from 2005 to 2008 are as follows (dollars in thousands):

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Total estimated cash requirements for 2004 and the 2005-2008 periods consist of the following (dollars in thousands):

Distribution expenditures fund the infrastructure that moves power from substations to the customer’s meter. There are several projects included in the construction expenditures estimate to provide for factors such as: age of the system, system growth, density of the service territory, and special requirements like underground lines.

As discussed in Regulation, Nevada Power Company 2003 IRP, within this section, the Company has plans for the construction of additional generating capacity at the Harry Allen generating station. NPC plans 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. NPC has received PUCN approval to study the feasibility of building a coal fired generating station. Construction expenditures for 2004 – 2008 for this additional generation capacity are estimated to be $867 million.

The Centennial Plan involves construction of the following 500 kV lines: (1) the Harry Allen substation to Crystal substation 500 kV lines, (2) the Harry Allen substation to Northwest substation 500 kV line, and (3) the Harry Allen substation to Mead substation 500 kV line. Additional facilities include a new 500 kV substation at Harry Allen, 500/230 kV transformers at Mead, McCullough and Northwest substation, phase shifting transformers at Crystal substation; rebuild of the McCullough 500 kV series compensation; and several other sub-transmission upgrades and additions. The total estimated cost of the Centennial project is $309.6 million (excluding AFUDC). Total project costs incurred through December 31, 2003 were $170.3 million. Estimated costs for 2004 are $49 million, which are expected to be financed by internally generated cash.

The Centennial Plan was approved in NPC’s 2001 Refiled IRP. NPC has adjusted the Harry Allen to Mead 500 kV project in-service date to January 2007 as reflected in NPC’s 2003 IRP filing. See Transmission, later, for additional information about the Centennial Project.

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Facilities and Operations

Total System

NPC manages a portfolio of energy supply options. During 2003, NPC generated 46.3% of its total electric energy requirements, purchasing the remaining 53.7% as shown below:

NPC’s decision to purchase short-term and spot energy is based on the economics of purchasing “as-available” energy when it is less expensive than NPC’s own generation. NPC’s 2003 company generation of 10,026,806 MWh decreased 1.2% from NPC’s 2002 company generation of 10,147,053 MWh. NPC’s 2003 purchased power of 11,637,070 MWh was down 9.8% from NPC’s 2002 purchased power of 12,907,835 MWh. The overall decrease in the total company generation and purchased power was primarily attributable to the decrease in system electricity sales. 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 5.0% in 2003, 4.8% in 2002, and 4.5% in 2001. Annual retail electricity sales were 17.9 million MWh in 2003, which represents an increase of 4.4% over 2002 retail electricity sales of 17.2 million MWh. Annual wholesale electricity sales reached 2.4 million MWh in 2003, which represents a decrease of 48.0% from 2002 wholesale electricity sales of 4.6 million MWh. Overall, annual system electricity sales reached 20.7 million MWh in 2003, which represented a decrease of approximately 6.4% from 2002 system electricity sales of 22.2 million MWh. The bulk of the decrease is attributed to decreases in wholesale sales and one wholesale customer taking transportation service instead of sales service. The peak electric demand rose from 4,617 MW in 2002 to 4,808 MW in 2003.

The projections shown below are forecasts of the load to be provided to all of NPC’s current and forecasted customers. No adjustments have been made at this time to incorporate possible changes to NPC loads due to the provisions of AB 661 and 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. See Regulation and Rate Proceedings, Nevada Matters, Customers File Under AB 661 in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations. 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

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Research. The population forecast is used to develop a customer forecast for NPC. Also, the forecast includes normal weather, which is defined as the 20-year average of historic weather. Major assumptions used in the forecast include weather, price levels and number of customers. Changes in these assumptions such as abnormal weather, a decrease or increase to the projected number of customers and price levels NPC is allowed to charge could affect the accuracy of these forecasts. Also, bundled retail price levels, as well as availability of power in the West, could affect consumption by customers of NPC. Actual demand may be very different to the extent one or more of the uncertainties or assumptions discussed above differ. NPC’s total system capability and peak loads for 2003, and the forecast for summer peak demand from 2004 through 2008 (assuming, among other things, no curtailment of supply or load, and normal weather conditions), are indicated below:

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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 2003, NPC experienced favorable market energy prices when compared to the prices it experienced during 2000 and 2001 when high and extremely volatile fuel and purchased power prices in the Western United States led to deterioration in the credit quality of a number of utilities and power merchants and the onset of the “Western Energy Crisis”.

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During 2003, 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 provide deposits.

If NPC’s credit rating is further downgraded, it may be unable to transact under standard payment terms and counterparties or suppliers may require that all payments be pre-paid. If NPC does not have sufficient funds or liquidity to prepay its power requirements, particularly at the onset of the summer months and is unable to obtain power through other means, NPC’s business, operations and financial condition would be materially adversely affected and could make it difficult to provide reliable service to its customers. See Liquidity and Capital Resources in Management’s Discussion and Analysis of Financial Condition and Results of Operations later for additional liquidity discussion.

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

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

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

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

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, 2003, 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 23.6% of the net purchased power requirements (excluding wholesale purchases) and 11.1% of the net system requirements during 2003.

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. Qualified renewable resources include biomass, wind, solar, and geothermal projects. Pursuant to the statutory RPS, NPC is required to obtain 5% of its total energy from renewable resources for 2003 and 2004. Five percent (5%) of the total renewable energy required by the RPS must be derived from solar resources. The statutory RPS

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requirements increase every two years to a maximum of 15% of total energy sales by 2013. SB 372 requires the PUCN to establish regulations that address among other items, the terms and conditions for renewable energy 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 (RFP). In March 2003, following negotiations with the renewable energy developers that responded to the 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. In June 2003, NPC issued another RFP to purchase additional renewable energy to comply with the requirements of Nevada’s renewable portfolio standard. The RFP closed in August 2003 and NPC is in negotiations with potential renewable suppliers to purchase additional renewable energy and/or renewable energy credits.

In April 2004, NPC will file a statutorily mandated compliance report with the PUCN. NPC expects to advise the PUCN that the RPS for 2003 and 2004 could not be met and will provide a full accounting of the effort that was expended to meet the RPS. The governing renewable energy regulations specify infeasibility criteria upon which NPC expects to rely. The governing regulations also allow NPC to purchase renewable energy credits to meet the RPS. SPPC has available excess renewable energy credits as a result of its extensive geothermal contracts. Purchase of these credits by NPC could allow NPC to meet up to 40-49% of the non-solar RPS requirements for 2003 and 2004. NPC expects to evaluate a number of factors prior to determining if the available credits should be acquired. The PUCN may, but is not required to impose an administrative fine for noncompliance with the RPS requirements. At this time we cannot predict whether the PUCN will consider or decide to impose a fine for non-compliance with the RPS requirements. The PUCN may schedule a hearing to determine compliance with the RPS.

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. In 2003, NPC placed into service the Avera 230 kV substation, the Avera 230/138 kV autotransformer and the Faulkner to Tolson 230 kV transmission line. These 2003 upgrades were system improvements within the NPC control area. Finally, NPC has ownership rights in two 500 kV transmission lines that allow for the transmittal of NPC’s share of power from its interests in the Mohave and Navajo Generating Stations to the NPC control area. If the Mohave Generating station is shut down in 2005, NPC intends to continue to utilize the Eldorado Transmission System that is connected to the Mohave Generating station to supply NPC load and to meet other transmission service obligations currently in place. The transmission lines and generation facilities are governed under separate contracts.

NPC received approval from the PUCN to construct four 230 kV switchyards proposed in NPC’s 2003 IRP:

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The Avera and Beltway projects are needed for system reliability, increased import capability, and to provide a path for Centennial IPP energy to be delivered into or through NPC’s transmission system.

Also approved as part of the 2003 IRP was the construction and or upgrades of the following facilities:

See Construction Program for estimated transmission costs.

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, McCullough 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, the Mead 500/230 kV transformer and the McCullough 500/230 kV transformer is January 2007.

See Regulation later for a discussion of regional and regulatory transmission issues.

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

Fuel Availability

NPC’s 2003 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 million British thermal units (MMBtu) for the years 1999–2003, along with the percentage contribution to total fuel requirements were as follows:

Average Consumption Cost & Percentage Contribution to Total Fuel

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

Coal delivered to the Reid Gardner Station originates from various mines in the Utah coalfields and is delivered to the station via the Union Pacific Railroad (UP). Full requirements for coal supplies for 2003 as well as partial requirements for various terms up to 2006 are under contract.

NPC’s long-term coal supply agreement with RAG Coal Sales of America, Inc., supplied from its Willow Creek Mine in Carbon County, Utah and due to expire in 2007, remains in a force majeure status. Lodestar Energy has filed for bankruptcy and is not performing under its coal supply contract with NPC that runs through 2004. NPC continues to pursue its claim against Lodestar through the U.S. Bankruptcy Court for the Eastern District of Kentucky. These contracts have been replaced by short-term purchases.

The UP contract provides for deliveries from the Provo, Utah interchange as well as various mines in the Price, Utah area, to the Reid Gardner Station in Moapa, Nevada. This contract was effective January 1, 1996 and has been extended through December 31, 2004 and management expects to be able to extend it beyond 2004. Beginning in mid-2003, UP began to experience crew shortages that affected their ability to provide deliveries of coal on a timely basis to Reid Gardner Station. NPC implemented a wide range of corrective actions during this period to prevent coal inventories from reaching critically low levels. In the second half of 2003, UP initiated measures to address these problems, which included an accelerated hiring/training program. UP’s chronic delivery problems are expected to be resolved by mid-2004. The Utah Railway contract provides for the remainder of NPC’s Price, Utah area supplies. All of NPC’s rail transportation contracts contain certain tonnage requirements and railroad service criteria.

As of December 31, 2003, Reid Gardner’s coal inventory level was 188,974 tons, or approximately 29 days of consumption at 100% capacity.

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 having an option to extend for an additional 15 years. The Mohave coal is delivered from the mine to Mohave by means of a coal slurry pipeline, which requires water that is obtained from groundwater wells located on lands of the Tribes in the mine vicinity.

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

In 2003, 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. Southern California equivalent purchases also 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. Also, NPC completed its

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participation in the Kern River California Emergency Expansion capacity program for 5,600 Dth/day in April 2003. The Kern River California Emergency Expansion service did not carry any renewal rights.

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 was provided under a 32-year transportation services contract with Southwest Gas Company signed in 1995. The contact provided firm service with certain operating and nominating provisions.

Finally, oil provides an alternate fuel source for Clark, Sunrise and Harry Allen gas generating stations, and was used in the igniters at Reid Gardner.

SIERRA PACIFIC POWER COMPANY

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

SPPC is a public utility primarily engaged in the distribution, transmission, generation, and sale of electric energy. It provides electricity to more than 334,000 customers in an approximately 50,000 square mile service area in western, central and northeastern Nevada, including the cities of Reno, Sparks, Carson City, and Elko, and a portion of eastern California, including the Lake Tahoe area. In 2003, electric revenues were 84.3% of SPPC’s revenue.

SPPC also provides natural gas service in Nevada to approximately 129,000 customers in an area of about 600 square miles in Reno/Sparks and environs. In 2003, natural gas revenues were 15.7% of SPPC’s revenues.

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 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.

Business and Competitive Environment

In 2003, SPPC’s electric business contributed $868 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 65%, 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 3.1% annually over the past five years, reaching 1,657 MW on July 30, 2003. SPPC’s total retail electric MWh sales have increased an average of 2.2% annually over the past five years.

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SPPC’s electric customers by class contributed the following toward 2003 and 2002 MWh sales:

The year 2003 saw a number of trends that were positive for Nevada’s precious metals mining industry. 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 by the end of 2003, will make a significant difference to the state’s mining industry, which produces in excess of eight million ounces of gold per year. This increase in price, coupled with regulatory changes that open up opportunities for future mine development and the state’s vast amount of both proven and probably gold reserves, offer the potential for a strong industry presence and high-energy usage for future years.

SPPC has long-term electric service agreements with six of its major mining customers, with revenues under these agreements totaling approximately $136 million. For 2003, this represented 15.7% of SPPC’s electric operating revenues of $868 million. The terms of these agreements range from 5 to 15 years, with the longest-term contract expiring in 2011. The agreements require that customers maintain minimum demand and load factor levels and provisions to recover all of SPPC’s customer-specific facilities investment.

The offices/schools/government and healthcare customer segment continues to grow with the addition of new schools, government facilities and healthcare facilities. Even with customer implementation of energy conservation and efficiency programs in conjunction with growth, there was a slight increase of .2% in energy sales to the overall segment. In healthcare, increasing demands for new long term and acute care facilities is expected to double the number of facilities by 2006. In the education sector, two new schools will be added in the Reno/Sparks area each year between 2004 and 2007.

MWh sales to the resorts and recreation customer segment, consisting of hotels, casinos and ski resorts have decreased primarily as a result of customers’ continued efforts to implement energy conservation measures. Similar to 2002, this year the ski resort segment energy consumption was slightly reduced as a result of heavy natural precipitation and snow early in the 2003-2004 ski season that enabled resorts to decrease their use of artificial snowmaking equipment.

A continued increase in competition from gaming on Indian reservations in California has continued to impact gaming revenues. The recent opening of Thunder Valley Casino located less than 100 miles from the Nevada border has resulted in decreased daily and weekend visits from Northern California gamers. In response, the industry and the community continue to work together to strengthen the region’s 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 by promoting its natural resources, diversified entertainment and recreation opportunities.

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The manufacturing and warehouse segment revenues increased in 2003 as compared with years 2002 and 2001. After two straight years of declining sales, 2003 demonstrated an increase of 10.47% in MWh sales for this segment and brought the figures in line with sales demonstrated in the year 2000. This increase reflects a rebound of existing customers’ operations due to improved market conditions as well as the continued influx of new customers who are exiting the California market in favor of Northern Nevada.

The 2001 session of the Nevada State Legislature enacted AB 661. One provision of this bill allows commercial customers with an average annual load of 1 MW or more to file a letter of intent and application with the PUCN to acquire electric energy, capacity, and ancillary services from another provider. In February 2004, a large SPPC mining customer filed an application to procure energy services from a new provider in the spring of 2005. PUCN hearings on this application are anticipated in the second quarter of 2004 with a decision to be issued in June 2004. This customer has a peak usage of 135 MWh. The revenue impact is not expected to be material.

SPPC’s MWh sales to wholesale customers have decreased 47.6% over the past year. During 2003, firm and non-firm sales to wholesale customers comprised 13.3% of total energy sales. Wholesale customers consist of other utilities or municipalities that sell power to end users, marketing entities and others that exchange power with SPPC.

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

Construction Program

SPPC’s construction program and estimated expenditures are subject to continuing review, and are revised from time to time due to various factors, including the rate of load growth, escalation of construction 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 its obligation to serve its customers. SPPC intends to file its IRP with the PUCN in July 2004. If approval of the Integrated Resource Plan is obtained, the estimated construction expenditures set forth below will be adjusted accordingly.

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SPPC’s gross construction expenditures for 2003, including AFUDC and contributions in aid of construction, were $146.9 million, and for the period 1999 through 2003 were $682.9 million. SPPC’s estimated construction expenditures for 2004 and the period 2005-2008 are as follows (dollars in thousands):

Total estimated cash requirements for 2004 and the 2005-2008 period, for each segment of SPPC’s business, consist of the following (dollars in thousands):

The Falcon to Gonder Transmission Project is a 345 kV transmission line within northern Nevada with a planned in-service date of May 2004. Total project costs incurred through December 31, 2003, were $79.0 million. Actual costs incurred in 2003 were $46.2 million. Estimated costs for 2004 are $21.4 million.

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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. SPPC also supplies its customers’ electric power needs using a combination of firm and interruptible resources to maximize operating flexibility and reliability while minimizing cost. During 2003, SPPC generated 39.1% of its total electric energy requirements in its own plants, purchasing the remaining 60.9% as shown below:

As a supplement to its own generation, SPPC purchases both firm and non-firm energy to meet its customer demand requirements. Total energy supply includes purchases from outside the electric system due to limited control area generation and also the need to access market energy supplies. SPPC’s decision to purchase this energy is based on economics, mitigation of availability risk, and system import limits. Firm block purchases are transacted as both a price hedging strategy and to ensure that needed firm capacity is available over peak load periods. Spot market energy is purchased based on the economics of purchasing “as-available” energy when it is less expensive than SPPC’s own generation, again, subject to net system import limits. In 2003, most of SPPC’s non-utility generation came from QFs. See Energy Supply in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, for additional information.

Risk Management

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

Load and Resources Forecast

SPPC’s electric customer growth rate was 3.3% in 2003, 2.3% in 2002, and 1.9% in 2001. Annual retail electricity sales were 8.9 million MWh in 2003. Annual retail electricity sales were 8.7 million MWh in 2002. Annual wholesale electricity sales reached 1.4 million MWh in 2003, which represents a decrease of approximately 47.6% from 2002 wholesale electricity sales of 2.6 million MWh. Overall, annual system electricity sales reached 10.3 million MWh in 2003, which represents a decrease of approximately 9.1% from 2002 system electricity sales of 11.3 million MWh. The bulk of the decrease is attributed to a decrease in the economy portion of wholesale. The 2003 peak electric demand was 1,657 MW. The 2002 peak demand was 1,590 MW. See Electric Operating Revenue for a discussion of Wholesale Electric Sales in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations.

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The projections shown below are forecasts of the load to be provided to all of SPPC’s current and forecasted customers. No adjustments have been made at this time to incorporate possible changes to SPPC loads due to the passage of AB 661 by the 2001 Nevada Legislature that allows commercial and governmental customers with an average demand greater than one MW to select other energy supplies. See Regulation and Rate Proceedings, Nevada Matters, Customers File Under AB 661 in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations. Major assumptions used in the forecast include weather, price levels and number of customers. Changes in these assumptions such as abnormal weather, a decrease or increase to the projected number of customers and price levels SPPC is allowed to charge could affect the accuracy of these forecasts. 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 2003, and the forecast for summer peak demand through 2008 (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. The “Additional Required” represents the additional, uncommitted capacity needed in order to maintain adequate reserve margin consistent with the WECC planning reserve criteria. These additional reserves will be met, if needed, with short-term purchases through 2008 to the extent available.

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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 were installed.

Purchased Power

SPPC continues to manage a diverse portfolio of contracted and spot market supplies, as well as its own generation, with the objective of minimizing its net average system operating costs. During 2003, SPPC experienced favorable market energy prices when compared with the previous four years. The decrease is reflective of FERC price cap regulation, which decreased electricity costs throughout the western United States.

During 2003, 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.

If SPPC’s credit rating is further downgraded, it may be unable to transact under standard payment terms and counterparties or suppliers may require that all payments be pre-paid. If SPPC does not have sufficient funds

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or access to liquidity to prepay its power requirements, particularly at the onset of the summer months and is unable to obtain power through other means, SPPC’s business, operations and financial condition would be materially adversely affected and could make it difficult to provide reliable service to its customers. See Liquidity and Capital Resources in Management’s Discussion and Analysis of Financial Condition and Results of Operations.

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

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

SPPC contracted with Morgan Stanley for a total of 150 MW capacity from the Naniwa Plant for the summer of 2003.

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 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, 2003, SPPC had a total of 109 MW of maximum contractual firm capacity under 15 contracts with QFs. SPPC had contracts with three of the 15 projects at variable short-term avoided cost rates. All QF contracts currently delivering power to SPPC at long–term rates have been approved by either the PUCN or the CPUC, and have QF status as approved by the FERC. One long-term QF contract terminates in 2006, one terminates in 2039, and the remaining terminate between 2014 and 2022.

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