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

CONTENTS

PART I

Item 1. Business

Sierra Pacific Resources

Nevada Power Company

Sierra Pacific Power Company

Other Subsidiaries of Sierra Pacific Resources

Item 1A. risk factors

Item 1B. unresolved staff comments

Item 2. Properties

Item 3. Legal Proceedings

Item 4. Submission of Matters to a Vote of Security Holders

Executive Officers

PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities (SPR)

Item 6. Selected Financial Data

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Executive Overview

Sierra Pacific Resources

RESULTS OF OPERATIONS

ANALYSIS OF CASH FLOWS

LIQUIDITY AND CAPITAL RESOURCES (SPR CONSOLIDATED)

Energy Supply (Utilities)

Nevada Power Company

RESULTS OF OPERATIONS

ANALYSIS OF CASH FLOWS

LIQUIDITY AND CAPITAL RESOURCES

Sierra Pacific Power Company

RESULTS OF OPERATIONS

ANALYSIS OF CASH FLOWS

LIQUIDITY AND CAPITAL RESOURCES

Regulatory Proceedings (Utilities)

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

Item 8. Financial Statements and Supplementary Data

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

Item 9A. Controls And Procedures

Item 9B. Other Information

PART III

Item 10. Directors and Executive Officers of the Registrant

Item 11. Executive Compensation

Item 12. Security Ownership of Certain Beneficial Owners and Management

Item 13. Certain Relationships and Related Transactions

Item 14. Principal Accounting Fees And Services

PART IV

Item 15. Exhibits, Financial Statement Schedules

Signatures

EX-4.(A) Second Supplemental Indenture, dated as of October 30, 2006

EX-10.(A) Beltway Warehouse No. 2 Lease Agreement

EX-10.(B) Financing Agreement Humboldt County dated November 1, 2006 Series 2006

EX-10.(C) Financing Agreement Washoe County dated November 1, 2006 Series 2006A

EX-10.(D) Financing Agreement Washoe County dated November 1, 2006 Series 2006B

EX-10.(E) Financing Agreement Washoe County dated November 1, 2006 Series 2006C

EX-12.(A) Statement regarding computation of Ratios of Earnings to fixed charges Sierra Pacific Resources

EX-12.(B) Statement regarding computation of Ratios of Earnings to fixed charges Nevada Power Company

EX-12.(C) Statement regarding computation of Ratios of Earnings to fixed charges Sierra Pacific Power Company

EX-23.(A) Consent of Independent Registered Public Accounting Firm

EX-23.(B) Consent of Independent Registered Public Accounting Firm

EX-23.(C) Consent of Independent Registered Public Accounting Firm

EX-31.1 Sierra Pacific Resources Section 302 Certification CEO

EX-31.2 Nevada Power Company Section 302 Certification of CEO

EX-31.3 Sierra Pacific Power Company Section 302 Certification of CEO

EX-31.4 Sierra Pacific Resources Section 302 Certification of CFO

EX-31.5 Nevada Power Company Section 302 Certification of CFO

EX-31.6 Sierra Pacific Power Company Section 302 Certification of CFO

EX-32.1 Sierra Pacific Resources Section 906 Certification of CEO

EX-32.2 Nevada Power Company Section 906 Certification of CEO

EX-32.3 Sierra Pacific Power Company Section 906 Certification of CEO

EX-32.4 Sierra Pacific Resources Section 906 Certification of CFO

EX-32.5 Nevada Power Company Section 906 Certification of CFO

EX-32.6 Sierra Pacific Power Company Section 906 Certification of CFO

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.

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

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

          The Utilities do not own generating facilities sufficient to meet the peak demands and reliability needs of Nevada’s growing population and, as a result, NPC is forecasting to purchase approximately 34% of its energy requirements from the wholesale market and SPPC is forecasting to purchase approximately 49% of its energy requirements from the wholesale market for year 2007. For the 2007 summer peak, NPC and SPPC have secured 100% of their forecast capacity needs.

          The amount of power purchased by the Utilities varies from time to time depending on demand, the cost of purchased power compared with our cost of generation, and the availability of such power. In 2006, NPC and SPPC purchased approximately 45.7% and 56.9%, respectively, of total system energy needs. Some purchased power contracts are indexed to natural gas prices. Due to the relatively large seasonal gas and purchased power usage, the Utilities purchase power and hedge a portion of their total natural gas exposure as discussed further in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Energy Supply.

          It is SPR’s strategy to grow the Utilities’ internal generating capacity in an effort to reduce reliance on purchased power. Consistent with this strategy, in 2006 NPC completed construction of the 1200 MW (unit ratings are nominal ratings) gas-fired Chuck Lenzie generating station (“Lenzie”) and acquired a 75% interest in the 560 MW, gas-fired Silverhawk generating station (“Silverhawk”). SPPC is constructing a new 514 MW facility at the Tracy Generating Station. (For further details, see the following Generation sections for NPC and SPPC).

          Additionally, as part of the strategy to grow and invest in, and improve the performance of their regulated businesses, the Utilities announced their intention to develop a major energy project located near Ely, Nevada, which will consist of two 750-megawatt coal fired generation units and includes the construction of a 250-mile transmission line to interconnect the transmission systems of NPC and SPPC. The total project costs are estimated to be $3.8 billion. In November 2006, the Public Utilities Commission of Nevada (PUCN) approved NPC’s 2006 Integrated Resource Plan (IRP) and SPPC’s thirteenth amendment to its 2004 IRP. Included in the PUCN’s approval is Phase 1 of the construction of the Ely Energy Center. The PUCN approved spending up to $300 million for development activities associated with Ely Energy Center with a limitation of $155 million placed on expenditures until the Utilities’ have obtained appropriate air permits. The PUCN approved the Utilities’ request to initially allocate Phase 1 costs between NPC and SPPC on an 80/20 split, respectively. The PUCN also required NPC and SPPC to file amendments to their IRPs in early 2008 once elements of the plan, including final costs, can be more accurately estimated. This project and details discussed above are collectively referred to in this report as the “Ely Energy Center”.

          As a result of expanded service territory growth, both Utilities have added transmission infrastructure. Discussions of new transmission lines are in NPC’s and SPPC’s respective Transmission sections below.

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

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

          Periodic reports on Form 10-K and Form 10-Q and current reports on Form 8-K are made available to the public, free of charge, on SPR’s, NPC’s and SPPC’s websites (www.sierrapacificresources.com, www.nevadapower.com, and www.sierrapacific.com) through links on these websites to the SEC’s website at www.sec.gov, as soon as reasonably practicable after they have been filed with the SEC. The contents of the above referenced website addresses are not part of this Form 10-K. Available on the sierrapacificresources.com website is the code of ethics for the chief executive officer, chief financial officer and controller, charters for the Audit, Compensation and Nominating and Governance Committees of SPR’s Board of Directors and our corporate

governance and standards of conduct guidelines. Printed copies of these documents may be obtained free of charge by writing to SPR’s Corporate Secretary at Sierra Pacific Resources, P.O. Box 30150, Reno, NV 89520-3150.

NEVADA POWER COMPANY

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

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

Business and Competitive Environment

      Overview

          NPC is a public utility that generates, transmits and distributes electric energy in southern Nevada. At year-end 2006, NPC served approximately 807,000 customers in Las Vegas, North Las Vegas, Henderson, Searchlight, Laughlin, and adjoining areas, including Nellis Air Force Base and the Department of Energy’s Nevada Test Site in Nye County.

      Electric Operations

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

          To serve its growing customer base, NPC purchases power and generates electricity in accordance with an Energy Supply Plan, as discussed in more detail later in this section and in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations. NPC’s strategy is to grow its internal generating capacity in an effort to reduce reliance on purchased power. Consistent with this strategy, in 2006, NPC completed construction of Lenzie and acquired Silverhawk, as discussed in further detail under the Generation section. Additionally, in November 2006, the PUCN approved NPC’s 2006 IRP. Included in the PUCN’s approval of NPC’s 2006 IRP, are the Ely Energy Center and the construction of 600 MW peaking units at Clark Station at an estimated cost of $395 million.

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

          Under federal law, wholesale rates charged by NPC are subject to certain jurisdictional regulation, primarily by the FERC. The FERC has jurisdiction under the Federal Power Act with respect to rates, service, interconnection, accounting, and other matters in connection with NPC’s sale of electricity for resale and interstate transmission. The FERC also has jurisdiction over the natural gas pipeline companies from which NPC takes service.

      Competition

          State law allows commercial customers with an average annual load of 1 MW or more to file a letter of intent and application with the PUCN to acquire electric energy, capacity, and ancillary services from another provider. The law requires customers wishing to choose a new supplier to receive the approval of the PUCN and meet public interest standards. In particular, departing customers must secure new energy resources that are not under contract to NPC, the departure must not burden NPC with increased costs or cause any remaining customers to pay increased costs, and the departing customers must pay their portion of any deferred energy balances. The PUCN adopted regulations prescribing the criteria that will be used to determine if there will be negative impacts to remaining customers or to NPC. Customers wishing to choose a new supplier must provide 180-day notice to NPC. NPC would continue to provide transmission, distribution, metering, and billing services to such customers. Management believes that those customers securing energy from new energy suppliers will reduce NPC’s need to purchase power from potentially volatile wholesale energy markets.

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

Sales

          NPC’s service territory continues to be among one of the fastest growing areas in the nation. In 2006, NPC set 44,103 meters and it is forecasted that NPC will set over 37,000 in 2007. In 2006, NPC’s operating revenues were approximately $2.1 billion.

          Summer peak loads are driven by air conditioning demand. Winter peak loads are low relative to the summer peak. Winter load above the base amount is driven by air handling in forced air furnaces. NPC’s peak load increased at an average annual growth rate of 4.7% over the past five years, reaching 5,623 MW in July 2006. NPC’s retail total electric megawatt-hour (MWh) sales have increased at an average annual growth rate of 4.3% over the past five years.

          NPC’s electric customers by class contributed the following toward 2006, 2005 and 2004 MWh sales:

		MWH Sales (Billed and Unbilled)
		2006								2005								2004
Residential			9,033,142				42.3	%			8,288,309				41.3	%			7,981,116				40.1	%
Commercial & Industrial:
Gaming/Recreation/Restaurants			3,736,608				17.5	%			3,711,790				18.5	%			3,587,428				18.0	%
All Other Retail			8,049,753				37.7	%			7,454,595				37.1	%			7,038,692				35.4	%
Total Retail			20,819,503				97.5	%			19,454,694				96.9	%			18,607,236				93.5	%
Wholesale			244,128				1.2	%			278,527				1.4	%			870,398				4.4	%
Sales to Public Authorities			281,369				1.3	%			349,912				1.7	%			408,927				2.1	%
Total			21,345,000				100	%			20,083,133				100	%			19,886,561				100	%

          Growth in NPC’s residential class sales continues primarily as a result of new home construction in Las Vegas and the surrounding areas. New home sales in the Las Vegas area in 2006 totaled 36,051.

          Tourism and gaming remain southern Nevada’s leading industries and together comprise one of NPC’s largest classes of customers (see Gaming/Recreation/Restaurants above). Currently, there are two major projects under construction in Las Vegas with over $11 billion estimated in construction costs.

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

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

Demand

Load and Resources Forecast

          NPC’s integrated peak electric demand rose from 5,563 MW in 2005 to 5,623 MW in 2006. Variations in energy usage by NPC’s customers occur as a result of varying weather conditions and other energy usage behaviors. This necessitates a continual balancing of loads and resources, and requires both purchases and sales of energy under short and long term contracts and the prudent management and optimization of available resources.

          NPC plans to meet its customers’ needs through a combination of company-owned-generation and purchased power. NPC filed its 2006 Integrated Resource Plan (IRP) with the PUCN, pursuant to which the company received approval to commence construction of peaking units at Clark Station. The first 413 MW of the Clark peaking units have a scheduled in-service date of June 2008 and the remaining 206 MW has a scheduled in-service date of June 2009. These additional units will reduce NPC’s reliance on purchased power. Remaining needs will be met through power purchases through RFPs or short term purchases.

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

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

Energy Supply

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

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

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

          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 2006 company generated MWhs increased 50.2% from NPC’s 2005 company generated MWhs. The increase in NPC’s generation in 2006 is primarily due to the purchase of a 75% ownership in the SilverHawk generating station and the addition of the Lenzie generating station. NPC’s 2006 purchased power MWhs decreased 20.5% from NPC’s 2005 purchased power MWhs. See Energy Supply in Management’s Discussion and Analysis of Financial Condition and Results of Operations for additional information regarding NPC’s purchasing strategies.

      Risk Management

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

      Generation

          NPC’s generation capacity consists of a combination of 27 gas, oil and coal generating units with a combined capacity of 3,148 MWs as described in Item 2, Properties. In 2006, NPC generated approximately 54.3% of its total system requirements.

          As described earlier, in an effort to reduce reliance on purchased power and diversify energy resources NPC acquired the Lenzie generating plant and a 75% ownership interest in the Silverhawk generating plant. The combination of the two plants added approximately 1,669 MWs of capacity in 2006. Additionally in 2006, NPC added a second 84 MW unit at the Harry Allen generating plant. The increase in capacity was partially offset by the loss of 403 MW of capacity due to the retirement of three steam units at the Clark Plant and the shut-down of the Mohave Plant on December 31, 2005, of which NPC is a 14% owner. See Note 13, Commitments and Contingencies, of the Notes to the Financial Statements, in Item 8 for further discussion of the Mohave shut-down.

          In November, 2006, the PUCN approved Phase 1 of the construction of the Ely Energy Center. The Ely Energy Center consists of two 750-megawatt coal fired generation units. The first unit is expected to become operational in late 2011 and the second within three years thereafter. The plan also includes further expansion possibilities involving two 500 MW coal gasification units when the technology becomes commercially viable.

          Also approved by the PUCN was NPC’s request to construct natural gas-fired combustion turbine peaking units at Clark Station with approximately 413 MWs of peaking capacity to be installed prior to the summer of 2008 and approximately 206 MWs of additional peaking capacity to be installed prior to the summer of 2009.

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

          Natural gas supplies are procured one season ahead of use through a competitive bidding process. The gas prices are set at an appropriate industry index during the month of current delivery. Monthly and daily gas supply adjustments are made by Gas Trading personnel based on the current energy marketplace. The addition of the Lenzie, Silverhawk and Harry Allen units during 2006 resulted in an increase of company generation. These generating units had the effect of reducing NPC’s exposure to fluctuations in the market price of gas because these units are more efficient than most generating facilities supplying energy to the market in which NPC purchases energy and, consequently, will require less fuel to produce the same amount of electric energy. This trend is expected to continue in 2007 since these generating units will be available for the entire year and NPC has made operating improvements at all sites.

          Coal delivered to the Reid Gardner Station originates from various mines in the Utah and Colorado coal fields and is delivered to the station via the Union Pacific Railroad. NPC had five coal contracts which expired on December 31, 2006. These contracts were with Canyon Fuel Company, LLC, a subsidiary of Arch Coal Company, Arch Coal Sales Company, Oxbow Carbon & Minerals, LLC, Andalex Resources, Inc., and Valmy. They provided the full requirements of coal for 2006. During 2006 NPC executed replacement coal supply agreements effective January 2007. These contracts are with Arch Coal Sales Company and Andalex Resources, Inc. and will provide 100%, 75%, 45%, and 30% of Reid Gardner’s projected coal requirements for the years 2007, 2008, 2009, and 2010, respectively.

          As of December 31, 2006, Reid Gardner Station’s coal inventory level was 397,033 tons, or approximately 66 days of consumption at 100% capacity.

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

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

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

      Purchased Power

          NPC, under the guidelines set forth in the NPC Energy Supply Plan, continues to manage a diverse portfolio of contracted and spot market supplies, as well as its own generation, with the objective of minimizing its net average system operating costs. During 2006, NPC purchased 45.7% of its total energy requirements.

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

          NPC has entered into long term purchase power contracts (3 or more years) with the following counterparties:

          NPC’s credit standing affects the terms under which NPC is able to purchase fuel and electricity in the western energy markets. As a result of NPC’s improved credit quality, during 2006 NPC was able to eliminate cash deposits held by counterparties for the purchase of fuel and electricity, reduce pre-payments for fuel to four counterparties, and reduce the number of counterparties requiring modified payment terms from the previous year. In early 2007, as further evidence of improving credit quality, NPC’s electric counterparties eliminated the requirement that NPC pre-pay electric purchases.

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

           Qualifying Facilities

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

          As of December 31, 2006, NPC had a total of 305 MW of contractual firm and non-firm capacity under contract with QFs. In 2006, energy purchased by NPC from the QFs constituted 22.7% of NPC’s net purchased power requirements for native load and 10.4% of NPC’s net system requirements (including generation).

           Renewable Energy

          Nevada law sets forth the renewable energy portfolio standard (“Portfolio Standard”) requiring providers of electric service to acquire, generate, or save a specific percentage of its energy from renewable energy resources (Renewables). Renewables include, but are not limited to: biomass, geothermal, solar and wind projects. Pursuant to the Portfolio Standard, NPC was required to obtain six percent of its total energy from Renewables for year 2006. The Portfolio Standard increases by three percent (3%) every other year until it reaches 20% in year 2015. In addition, the Portfolio Standard allows energy efficiency measures from qualified conservation programs to meet up to 25% of the Portfolio Standard. Moreover, not less than five percent (5%) of the total Portfolio Standard must be met from solar resources.

          Nevada law also requires providers of electric services to file an annual report that describes the level of compliance with the Portfolio Standard. In its April 2006 Portfolio Standard Annual Report for Compliance Year 2005, NPC reported that with PUCN approval of a sale and purchase of SPPC’s excess non-solar portfolio energy credits (“PCs”), NPC would meet the non-solar Portfolio Standard. However, NPC was non-compliant with the solar portion of the Portfolio Standard in 2005. Additionally, the report described NPC’s ongoing activities to reach full compliance with the Portfolio Standard in the near future. NPC will be required to meet nine percent (9%) of its total energy from Renewables for years 2007 and 2008.

          NPC’s IRP approved by the PUCN in November, included NPC’s three-year Action Plan for acquiring Renewables and developing renewable energy facilities. In addition, in January 2007, the PUCN approved NPC’s Portfolio Standard Annual Report for Compliance Year 2005 and granted its request for the purchase of SPPC’s excess non-solar PCs and granted an exemption from the solar portion of the Portfolio Standard for compliance year 2005.

          In April 2007, NPC will file with the PUCN its Portfolio Standard Annual Report for Compliance Year 2006. NPC expects it will meet the non-solar Portfolio Standard, but may not meet the solar requirement for 2006. If so, NPC will request an exemption from the PUCN for the solar portion of the Portfolio Standard for calendar year 2006.

Transmission

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

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

          NPC’s transmission system links generating units within the NPC control area and generating systems, located external to the NPC control area, to the NPC distribution system. NPC’s transmission system is directly interconnected with the transmission systems of Western Area Power Administration, Los Angeles Department of Water and Power, Southern California Edison, and PacifiCorp. NPC currently is not directly interconnected with SPPC; however, the Ely Energy Center includes a 500 kV line that will interconnect the transmission systems of the two companies by 2011. The map below shows NPC’s transmission system:

          As the control area operator, NPC is responsible for continuously balancing electric supply and demand by monitoring and controlling generating resources and interchange transactions so that generation internal to the control area plus net import power matches control area load. NPC also schedules power deliveries over its transmission system and maintains reliability by verifying that customers are matching loads with resources.

          NPC plans, builds and operates a transmission system that delivered 22,408,623 MWh of electricity to customers on its transmission system in 2006. The NPC system handled a peak load of 5,623 MW in 2006 through 2,062 circuit miles of transmission

lines and other transmission facilities ranging from 60kV to 500kV. NPC processes generation and transmission interconnection requests and requests for transmission service from a variety of customers. These requests usually involve new planning studies and the negotiation of contracts with new and existing customers in this high growth system.

          In the last 8 years, due primarily to high customer growth, NPC has constructed 4 major transmission projects totaling 210 miles of high voltage transmission. The projects completed include River Mountain (40 miles), Crystal (10 miles), Bighorn (60 miles), and Centennial (100 miles).

      Transmission Regulatory Environment

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

	•		Long-term and short-term firm point-to-point transmission service (“guaranteed” service with fixed delivery and receipt points),
	•		Non-firm point-to-point service (“as available” service with fixed delivery and receipt points), and
	•		Network transmission service (equivalent to the service NPC provides for NPC’s bundled retail customers).

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

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

Construction Program

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

          Gross construction expenditures for 2006, including allowance for funds used during construction (AFUDC), net salvage, and contributions in aid of construction, were $670.4 million, and for the period 2002 through 2006, were $2.2 billion. Estimated construction expenditures for 2007 and the period from 2008 to 2011 are as follows (dollars in thousands):

          Total estimated construction and plant cash requirements related to construction projects for 2007 and the 2008 to 2011 period consist of the following (dollars in thousands):

		2007				2008-2011				Total 5 - Year
Construction Expenditures		$	1,026,028			$	5,477,858			$	6,503,886
AFUDC			(23,373	)			(487,761	)			(511,134	)
Net Salvage/ Cost of Removal			(1,800	)			(7,400	)			(9,200	)
Net Customer Advances and CIAC			(20,800	)			(85,305	)			(106,105	)
Total Cash Requirements		$	980,055			$	4,897,392			$	5,877,447

          In November, 2006 the PUCN approved NPC’s IRP, which among other items, includes the approval of Phase 1 construction of the Ely Energy Center. The PUCN approved spending up to $300 million for development activities associated with Ely Energy Center with a limitation of $155 million placed on expenditures until the Utilities’ have obtained appropriate air permits. Current estimates to construct the Ely Energy Center, which includes a 500KV transmission line to connect NPC’s and SPPC’s transmission systems is approximately $3.8 billion. NPC’s estimated 80% allocation of the Ely Energy Center is included in construction expenditures above. The PUCN also required that NPC file an amendment to its 2006 IRP in early 2008 once elements of the plan, including final costs, can be more accurately estimated.

          Also included in the approval of the IRP was NPC’s request to construct natural gas-fired combustion turbine peaking units at Clark Station at a cost of approximately $395 million with approximately 413 MWs of peaking capacity to be installed prior to the summer of 2008 and approximately 206 MWs of additional peaking capacity to be installed prior to the summer of 2009.

SIERRA PACIFIC POWER COMPANY

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

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

SPPC Electric

Business and Competitive Environment

      Overview

          SPPC is a public utility that generates, transmits and distributes electric energy to approximately 361,000 customers. The service territory covers over 50,000 square miles of western, central and northeastern Nevada, including the cities of Reno, Sparks, Carson City, and Elko, and a portion of eastern California, including the Lake Tahoe area.

      Electric Operations

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

          To serve its growing customer base, SPPC purchases power and generates electricity in accordance with an Energy Supply Plan, approved by the PUCN, as discussed in more detail later in this section and in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations. SPPC’s strategy is to grow its generating capacity in an effort to reduce reliance on purchased power. As part of this strategy, SPPC is constructing a 514 MW gas-fired combined-cycle plant at Tracy, east of Reno. The plant is scheduled to be completed by the summer of 2008. Additionally, in November 2006, the PUCN approved SPPC’s thirteenth amendment to its 2004 IRP. Included in the PUCN’s approval is the Ely Energy Center.

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

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

          Under federal law, wholesale rates charged by SPPC are subject to certain jurisdictional regulation, primarily by the FERC. The FERC has jurisdiction under the Federal Power Act with respect to rates, service, interconnection, accounting, and other matters in connection with SPPC’s sale of electricity for resale and interstate transmission. The FERC also has jurisdiction over the natural gas pipeline companies from which SPPC takes service.

      Competition

          Nevada state law allows commercial customers with an average annual load of 1 MW or more to file a letter of intent and application with the PUCN to acquire electric energy, capacity, and ancillary services from another provider. The law requires customers wishing to choose a new supplier to receive the approval of the PUCN and meet certain public interest standards. In particular, departing customers must secure new energy resources that are not under contract to SPPC, the departure must not burden SPPC with increased costs or cause any remaining customers to pay increased costs, and the departing customers must pay their portion of any deferred energy balances. The PUCN adopted regulations prescribing the criteria that will be used to determine if there will be negative impacts to remaining customers or to SPPC. Customers wishing to choose a new supplier must provide 180-day notice to SPPC. SPPC would continue to provide transmission, distribution, metering, and billing services to such customers. Management believes that those customers securing energy from new energy suppliers will reduce SPPC’s need to purchase power from potentially volatile wholesale energy markets.

          In December 2005, Barrick Gold (Barrick), a large SPPC mining customer, concluded its construction of a 118 MW generating facility to meet the majority of its electric power needs. Barrick continues to purchase transmission and distribution services from SPPC and is selling approximately 8 MW of capacity from its new generating facility to SPPC. Barrick MWh retail sales for 2005 were approximately 10.1% of total system sales for SPPC.

          Newmont Mining Corporation (Newmont) is constructing 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. Under the term sheet, Newmont would sell the electrical output from its plant 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 to the PUCN which were approved on February 23, 2005.

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

Sales

          In 2006, SPPC set approximately 9,950 meters and forecasts that it will set over 9,000 meters in 2007. In 2006, SPPC’s electric operations contributed approximately $1.0 billion, or 83%, of SPPC’s total revenues.

          Summer retail peak loads are primarily driven by air conditioning demand and irrigation pumping. Winter retail electric peak loads are primarily driven by increased demand for space heating, air movement (with forced air gas and oil furnaces), and ski resorts (hotels, lifts, etc.). SPPC’s peak load increased at an average annual growth rate of 2.2% over the past five years, reaching 1,701 MW in July 2006.

          SPPC’s electric customers by class contributed the following toward 2006, 2005 and 2004 MWh sales:

          In 2006, mining MWh sales decreased significantly due to the departure of Barrick which represented approximately 10.1% of total system sales in 2005. However, Nevada’s precious metals mining industry continued to see positive developments as the spot price of gold on world markets increased in 2006 by 19%, from $530 per ounce on January 3, 2006 to $632 per ounce on December 28, 2006, as reported by Kitco.com. . This increase in price, coupled with Nevada’s reasonable regulatory environment and favorable geology for gold deposits, offers positive opportunities for future mine development. Given the substantial amounts of both proven and probable gold reserves at existing mining operations and the industry’s strong presence in the state, the mining industry’s resulting high energy usage is expected to continue into the future, assuming that 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 $94.7 million. For 2006, this represented 9.3% of SPPC’s electric operating revenues of $1.0 billion. These agreements include requirements for customers to maintain minimum demand and load factor levels. In addition, they include provisions to recover all investments for customer-specific facilities that have been made by SPPC on their behalf.

          In 2005, MWh sales in the wholesale segment decreased by 83.8% compared to sales in 2004. This decrease was a result of market conditions that resulted in fewer economic opportunities in layoffs/swap sales and purchases in 2005 compared to 2004. In addition, certain types of transactions that were reported in sales for 2004 are now being netted in purchased power.

Demand

Load and Resources Forecast

          SPPC’s integrated peak electric demand dropped from 1,740 MW in 2005 to 1,701 MW in 2006 mainly due to the Barrick departure from SPPC’s system. Variations in energy usage by SPPC’s customers occur as a result of varying weather conditions and other energy usage behaviors. This necessitates a continual balancing of loads and resources, and requires both purchases and sales of energy under short and long term contracts and the prudent management and optimization of available resources.

          SPPC plans to meet its customers’ needs through a combination of company-owned generation and purchased power. As discussed in Energy Supply – Generation, SPPC is constructing a new 514 MW Combined Cycle facility at the existing Tracy Generating Station with a scheduled in-service date of June 2008. The addition of this facility is expected to significantly reduce SPPC’s reliance on purchased power compared to prior years. Remaining needs will be met through power purchased through RFPs or short term purchases.

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

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

Energy Supply

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

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

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

          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. The decrease in total system was primarily due to the transition of Barrick to a distribution only services customer in 2006. SPPC’s 2006 company generation decreased 7.3% compared to 2005. SPPC’s 2006 purchased power total MWhs decreased 2.0% from SPPC’s 2005 purchased power MWhs. See Energy Supply in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, for additional information.

      Risk Management

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

      Generation

          SPPC’s generation capacity consists of a combination of 24 gas, oil and coal generating units with a combined capacity of 1,043 MWs as described in Item 2, Properties. In 2006, SPPC generated approximately 43.1% of its total system requirements.

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

          In November, 2006, the PUCN approved SPPC’s Phase 1 of the construction of the Ely Energy Center. The Ely Energy Center consists of two 750-megawatt coal fired generation units. The first unit is expected to become operational in late 2011 and the second within three years thereafter. The plan also includes further expansion possibilities involving two 500 MW coal gasification units when the technology becomes commercially viable.

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

          Natural gas supplies are procured one season ahead of use through a competitive bidding process. The gas prices are set at an appropriate industry index during the month of current delivery. Monthly and daily gas supply adjustments are made by Gas Trading personnel based on the current energy marketplace.

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

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

          As of December 31, 2006, Valmy’s coal inventory level was 354,103 tons or approximately 62 days of consumption at 100% capacity.

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

      Purchased Power

          SPPC, under the guidelines set forth in the SPPC Energy Supply Plan, continues to manage a diverse portfolio of contracted and spot market supplies, as well as its own generation, with the objective of minimizing its net average system operating costs. During 2006, SPPC purchased 56.9% of its total energy requirement.

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

          SPPC has entered into long term purchase power contracts (3 or more years) with the following counterparties:

          SPPC’s credit standing affects the terms under which SPPC is able to purchase fuel and electricity in the western energy markets. As a result of SPPC’s improved credit quality, during 2006 SPPC was able to eliminate cash deposits held by counterparties for the purchase of fuel and electricity; reduce pre-payments for fuel to four counterparties; and reduce the number of counterparties requiring modified payment terms from the previous year. In early 2007 as further evidence of improving credit quality, SPPC’s electric counterparties eliminated the requirement that SPPC pre-pay electric purchases.

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

           Qualifying Facilities

          Federal regulations, including the Public Utility Regulatory Policies Act of 1978 (PURPA), which were passed to promote renewable and alternative energy resources, and the Energy Policy Act of 2005 set out the requirements for utilities to purchase the output produced by Qualifying Facilities (QFs) at costs determined by the appropriate state’s public utility commission. QFs are small renewable energy power producers and co-generators. Certain QFs can qualify as renewable resources required by state law as discussed below.

          As of December 31, 2006, SPPC had a total of 151 MW of contractual firm and non-firm capacity under contract with QFs. In 2006, energy purchased by SPPC from the QFs constituted 17.4% of SPPC’s net purchased power requirements for native load and 9.9% of SPPC’s net system requirements (including generation).

           Renewable Energy

          Nevada law sets forth the Portfolio Standard requiring providers of electric service to acquire, generate, or save a specific percentage of its energy from Renewables. Renewables include, but are not limited to: biomass, geothermal, solar and wind projects. Pursuant to the Portfolio Standard, SPPC was required to obtain six percent of its total energy from Renewables for year 2006. The Portfolio Standard increases by three percent (3%) every other year until it reaches 20 percent in year 2015. In addition, the Portfolio Standard allows energy efficiency measures from qualified conservation programs to meet up to 25 percent of the Portfolio Standard. Moreover, not less than five percent (5%) of the total Portfolio Standard must be met from solar resources.

          Nevada law also requires providers of electric services to file an annual report that describes the level of compliance with the Portfolio Standard. In its April 2006 Portfolio Standard Annual Report for Compliance Year 2005, SPPC reported compliance with the non-solar Portfolio Standard. However, SPPC was non-compliant with the solar portion of the Portfolio Standard in 2005. Additionally the report described SPPC’s ongoing activities to reach full compliance with the Portfolio Standard in the near future. SPPC will be required to meet nine percent (9%) of its total energy from Renewables for years 2007 and 2008.

          In August 2006, the PUCN approved a long-term power purchase agreement for supply of renewable energy and portfolio energy credits (“PCs”) to SPPC from a project known as Galena 3 Geothermal Project being developed by Ormat Nevada, Inc.

          In January 2007, the PUCN approved SPPC’s Portfolio Standard Annual Report for Compliance Year 2005 and granted its request for an exemption from the solar portion of the Portfolio Standard for compliance year 2005.

          In April 2007, SPPC will file with the PUCN its Portfolio Standard Annual Report for Compliance Year 2006. SPPC expects it will meet the non-solar Portfolio Standard, but may not meet the solar requirement for 2006. If so, SPPC will request an exemption from the PUCN for the solar portion of the Portfolio Standard for calendar year 2006.

Transmission

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

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

          SPPC’s transmission system links generating units within the SPPC control area to the SPPC distribution system. SPPC’s transmission system is directly interconnected with the transmission systems of Idaho Power, Los Angeles Department of Water and Power, Southern California Edison, PacifiCorp, Bonneville Power Administration, Pacific Gas & Electric and Plumas Sierra Rural Electric Cooperative. SPPC currently is not directly interconnected with NPC; however, the Ely Energy Center includes a 500 kV line that will interconnect the transmission systems of the two companies by 2011. The map below shows SPPC’s transmission system:

          As the control area operator, SPPC is responsible for continuously balancing electric supply and demand by monitoring and controlling generating resources and interchange transactions so that generation internal to the control area plus net import power matches control area load. SPPC also schedules power deliveries over its transmission system and maintains reliability by verifying that customers are matching loads with resources.

          SPPC plans, builds and operates a transmission system that delivered 9,393,464 MWh of electricity to customers in its control area in 2006. The SPPC system handled a peak load of 1,701 MW in 2006 through 2,446 circuit miles of transmission lines and other facilities ranging from 60kV to 345kV. SPPC processes generation and transmission interconnection requests and requests for transmission service from a variety of customers. These requests usually involve new planning studies and the negotiation of contracts with new and existing customers in this fast growing system.

          In the last 8 years, due primarily to high customer growth, SPPC has constructed 2 major transmission projects totaling 347 miles of high voltage transmission. The projects completed include Alturas (167 miles), and Falcon – Gonder (180 miles).

      Transmission Regulatory Environment

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

	•		Long-term and short-term firm point-to-point transmission service (“guaranteed” service with fixed delivery and receipt points),
	•		Non-firm point-to-point service (“as available” service with fixed delivery and receipt points), and
	•		Network transmission service (equivalent to the service SPPC provides for SPPC’s bundled retail customers).

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

          SPPC is participating in the development of WestConnect. WestConnect is a group of southwest transmission-providing utilities that have agreed to work collaboratively to assess stakeholder and market needs and to investigate, analyze and recommend to its Steering Committee implementation of cost-effective enhancements to the western wholesale electricity market. In early 2006, SPPC discontinued its relationship with Grid West and joined WestConnect as a member.

SPPC Gas

Business and Competitive Environment

      Overview

          SPPC provides natural gas service to approximately 146,000 customers in an area of about 600 square miles in Nevada’s Reno/Sparks area. SPPC also procures natural gas for electric power generation at the Tracy and Fort Churchill plants east of Reno.

      Gas Operations

          SPPC is charged with meeting the growing energy needs of the residential population and expanding business and public sectors. In addition to customer growth and demand, resulting revenues are impacted by rate changes, seasonal or atypical weather and customer use. Gas demand and revenues are very seasonal for SPPC Gas. Average daily temperatures range from 71 to 34 degrees Fahrenheit and the average high temperature to low temperature range from 91 to 21 degrees Fahrenheit. This wide temperature swing causes gas send-out to vary substantially from a warm summer day to a cold winter day.

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

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

          Nevada state regulations require annual filings to reset base purchased gas rates and recover deferred balances that include purchased gas costs above or below amounts collected in current rates. The regulations also require a Gas Supply Plan to be filed annually. Natural gas commodity costs are passed directly through to customers on a dollar for dollar basis. SPPC does not profit from increased natural gas prices. SPPC may also file general rate cases to adjust gas division rates including cost of service and return on investment. Rate cases are discussed in more detail in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Regulatory Proceedings, and Note 3, Regulatory Actions, of the Notes to Financial Statements.

      Competition

          SPPC’s natural gas local distribution company (LDC) business is subject to competition from other suppliers and other forms of energy available to its customers. Large gas customers using 12,000 therms per month with fuel switching capability are allowed to participate in the Incentive Natural Gas Rate (INGR) tariff. Once a service agreement has been executed, a customer can compare natural gas prices under this tariff to alternative energy sources and choose their source of fuel. Additionally, customers using greater than 1,000 therms per day have the ability to secure their own gas supplies. As of January 1, 2007, there were 15 large customers securing their own supplies. These customers have a combined firm distribution load of approximately 4,940 Decatherms (Dth) per day. Transportation customers continue to pay firm and interruptible distribution charges. These customers are responsible for procuring and paying for their own gas supply, which reduces SPPC’s purchases, but does not have an impact on net income.

Revenue

          SPPC’s natural gas business accounted for $210 million in 2006 operating revenues or 17% of SPPC’s total revenues from continuing operations. SPPC expects to install approximately 5,000 meters in 2007.

Demand

          Growth in all sectors is expected to continue as a result of new real estate developments under construction and planned for the near future in SPPC’s distribution service area. Projected peak demand, which will only occur when the temperature drops to 3 degrees Fahrenheit, is estimated to be 193,500 Dth for the winter of 2006/2007, up from 187,000 Dth for the previous winter.

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

          SPPC’s firm natural gas supply is supplemented with natural gas storage services and supplies from a Northwest Pipeline Co. facility located at Jackson Prairie in southern Washington. The Jackson Prairie facility contributed a total of 12,687 Dth per day of peaking supplies. SPPC also has storage on the Paiute Pipeline system. This liquefied gas storage project provides for an incremental supply of 23,000 Dth per day and is available at any time with two hours notice. Therefore, this storage project supports increases in short term gas supply needs due to unforeseen events such as extreme weather patterns and pipeline interruptions.

          Following is a summary of SPPC’s transportation and storage portfolio as of December 31, 2006:

Firm Transportation Capacity

          Total LDC Dth supply requirements in 2006 and 2005 were 15.5 million Dth and 17.1 million Dth, respectively. Electric generating fuel requirements for 2006 and 2005 were 23.5 million Dth and 24.3 million Dth, respectively.

Gas Distribution

          As of December 31, 2006, SPPC owned and operated 1,988 miles of three-inch equivalent natural gas distribution piping. SPPC constructed approximately 2,600 feet of 12” steel gas main in the Stead area in 2006. SPPC also continued to increase its ongoing main and service replacement projects by replacing approximately 10,700 feet of various sized sections of main and approximately 124 services in 2006.

SPPC Electric and Gas

Construction Program

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

          SPPC’s gross construction expenditures for 2006, including AFUDC and contributions in aid of construction, were $316 million, and for the period 2002 through 2006, were $844 million. Estimated construction expenditures for 2007 and the period 2008-2011 are as follows (dollars in thousands):

		2007				2008-2011				5 - Year
Electric Facilities:
Generation		$	309,256			$	871,233			$	1,180,489
Distribution			61,596				262,460				324,056
Transmission			54,301				328,646				382,947
Other			29,258				123,852				153,110
Total			454,411				1,586,191				2,040,602
Gas Facilities:
Distribution			16,652				70,944				87,596
Other			80				339				419
Total			16,732				71,283				88,015
Common Facilities			15,349				64,965				80,314
TOTAL		$	486,492			$	1,722,439			$	2,208,931

          Total estimated construction and plant cash requirements for 2007 and the 2008-2011 periods consist of the following (dollars in thousands):

		2007				2008-2011				Total 5 - Year
Construction Expenditures		$	486,492			$	1,722,439			$	2,208,931
AFUDC			(28,926	)			(120,038	)			(148,964	)
Net Salvage/ Cost of Removal			(2,800	)			(11,465	)			(14,265	)
Net Customer Advances and CIAC			(22,000	)			(90,230	)			(112,230	)
Total Cash Requirements		$	432,766			$	1,500,706			$	1,933,472

          In December 2005, the PUCN approved the construction of a 514-megawatt, combined cycle natural gas power plant at Tracy Generating Station. Estimated construction costs are approximately $421 million with completion expected in 2008. Total project cost incurred was $168.9 million as of December 31, 2006.

          In November 2006, the PUCN approved SPPC’s thirteenth amendment to its 2004 IRP, which among other items includes the approval of Phase 1 construction of the Ely Energy Center. The PUCN approved spending up to $300 million for development activities associated with Ely Energy Center with a limitation of $155 million placed on expenditures until the Utilities have obtained appropriate air permits. Current estimates to construct the Ely Energy Center, which includes a 500KV transmission line to connect NPC and SPPC transmission systems is approximately $3.8 billion. SPPC’s estimated 20% allocation is included in construction expenditures above.

OTHER SUBSIDIARIES OF SIERRA PACIFIC RESOURCES

Tuscarora Gas Pipeline Company

          Tuscarora Gas Pipeline Company (TGPC) was formed in 1993 as a wholly owned subsidiary of SPR for the purpose of entering into a partnership with a wholly owned subsidiary of TransCanada PipeLines, Ltd., headquartered in Calgary, Alberta, Canada. The partnership, Tuscarora Gas Transmission Company (TGTC) owned 50% by TGPC was formed for the purpose of constructing and operating an interstate natural gas pipeline from Malin, Oregon to Reno, Nevada to serve an expanding natural gas market in northern Nevada and northeastern California. In November 2006, TGPC announced that it entered into an agreement to sell its interest in TGTC to TC PipeLines, LP for $100 million. In December 2006, TC PipeLines, LP assumed TGPC’s share in the pipeline company.

          As an interstate natural gas pipeline, TGTC provides only transportation service to its customers. SPPC was the only customer at the start of commercial operations in 1995 and while TGTC serves many other customers today, SPPC continues to be TGTC’s largest customer contributing 71.2% of gross revenues in 2006.

Sierra Pacific Communications

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

          In 2004, SPC disposed of their MAN assets and recognized a gain on sale of assets of approximately $2.5 million (pretax) in connection with the sale of the MAN assets. SPC retained possession of one duct and associated occupancy rights in the Long Haul System allowing SPC to complete the transfer and sale of this duct, which was negotiated under a 2002 contract with Qwest Communications (Qwest) for $20 million. In 2004, in accordance with Statement of Financial Accounting Standards 144 (SFAS 144), Accounting for the Disposition or Impairment of Long-Lived Assets , SPR reported the remaining Long Haul System as discontinued operations. However, due to certain legal issues, SPC was delayed in consummating the sale of the Long Haul System to Qwest. In January 2007, SPC agreed to dismiss pending arbitration against Qwest. As part of the Settlement Agreement, Qwest agreed to execute a quit claim deed disclaiming any further interest in the Long Haul system. In accordance with SFAS 144, if at any time the criteria for classifying assets as held for sale are no longer met, a long-lived asset classified as held for sale shall be reclassified as held and used. As of December 31, 2006, SPC assets associated with the Long-Haul were reclassified for all periods presented from assets held for sale in Discontinued Operations to assets held and used.

Lands of Sierra

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

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

ENVIRONMENTAL (SPR, NPC AND SPPC)

          As with other utilities, NPC and SPPC are subject to federal, state and local regulations governing air, water quality, hazardous and solid waste, land use and other environmental considerations. Nevada’s Utility Environmental Protection Act requires approval of the PUCN prior to construction of major utility, generation or transmission facilities. The United States Environmental Protection Agency (EPA), Nevada Division of Environmental Protection (NDEP), and Clark County Department of Air Quality and Environmental Management (DAQEM) administer regulations involving air quality, water pollution, solid, and hazardous and toxic waste. See Note 13, Commitments and Contingencies, Environmental of the Notes to Financial Statements, for further discussion.

Federal Legislative and Regulatory Initiatives

          The topic of climate change continues to evolve, and response to this issue brings with it environmental, economic and social implications for SPR and other electric utilities. The United States currently has no policy or regulation to address greenhouse gas emissions; the main emphasis to date being reliance on voluntary measures. While several bills have been introduced in Congress that would address carbon dioxide emissions, none have been enacted to-date. Environmental advocacy groups and regulatory agencies in the United States are also focusing considerable attention on carbon dioxide emissions from power generating facilities and their potential role in climate change.

          Every generation alternative – whether fossil fuels, nuclear, or renewable power options– has environmental and financial impacts. SPR recognizes these impacts and closely links its business objective of generating reliable, cost-effective energy with its environmental responsibilities. SPR has and will continue to identify projects that minimize or offset greenhouse gas emissions and believes precautionary actions to slow greenhouse gas emissions are appropriate. In 2006, SPR joined the California Climate Action Registry, in which SPR will voluntarily inventory, certify and publicly report on greenhouse gas emissions from NPC and SPPC by the end of 2007.

          SPR’s environmental philosophy accentuates prudent use of natural resources and to that end, SPR supports multiple program areas aimed at achieving overall air emission reductions. Some examples are:

•

Installation of commercially-proven pollution controls coupled with an emphasis on continued operational excellence to achieve further plant efficiency improvements. SPR’s new natural gas-fired generating plants require the combustion of far less fuel than older facilities to produce each kilowatt hour of electrical output. As new generation is added to the system, SPR is concurrently evaluating and eliminating older, less efficient units from its fleet.

	•		Maintenance of robust demand-side management programs, including energy efficiency and conservation education and support. These programs increase the adoption of energy-efficient equipment by our customers, thereby creating savings on energy bills and potentially delaying the need for additional power plant, transmission, and distribution construction.
	•		Development of technology solutions through funding and participation in collaborative research programs for advanced coal technologies, as well as potential options for carbon sequestration. SPR is reserving space in its proposed Ely Energy Center design that will allow the retrofit of carbon capture technology once it becomes commercially viable.
	•		Expansion of company owned renewable energy sources and continued use of purchase power agreements and investments that focus on lower or non-emitting generation resources. The State of Nevada mandates that an increasing percentage of the energy SPR sells must come from renewable sources, reaching 20 percent by 2015. With two large-scale solar projects presently under construction in the State, by the end of 2007, Nevada will be number one in the nation for solar watts generated per person and the percentage of solar to total kilowatt hours sold.

          SPR and the Utilities 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 when any legislation or regulations will be adopted in this area or what form they will take, management is unable at this time to evaluate the potential economic impact of any such measures on SPR or the Utilities.

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

          Of particular importance to SPR, in 2005 the EPA issued its Clean Air Mercury Rule (CAMR) and Regional Haze Rule. SPR notes that both rules have been the subject of litigation by various parties.

           CAMR — The EPA’s CAMR uses a national cap-and-trade system and is designed to achieve a 70 percent reduction in mercury emissions. It affects all coal and oil-fired generating units across the country that are greater than 25 megawatts. Compliance with this rule also occurs in two phases, with the first phase beginning in 2010 and the second phase in 2018. Under the Federal program, states will be allocated mercury allowances based on coal type and their baseline heat input relative to other states. Each electric generating unit will be allocated mercury allowances based on its percentage of total coal heat input for the state. In late 2006, the State of Nevada proposed its own mercury emission reduction rule in keeping with EPA’s proposed model program. The State rule was submitted to EPA for approval in late 2006, and is currently pending approval.

          Under the Nevada Clean Air Mercury Rule (NV CAMR), existing coal-fired facilities will be granted allowances for use during Phase I of the compliance period (2010 -2017). New SPR coal-fired units will be required to meet a specified emission limit and procure sufficient mercury emission allowances for compliance. SPR’s preliminary analysis of Phase I of the NV CAMR suggests that several of SPR’s existing units will be eligible to earn extra allowances, which may be applied to cover emissions from new sources as necessary.

          Under Phase II of the compliance period (2018 and beyond), is it not certain whether or not SPR will be allotted the required allowances to cover its mercury emissions. The determining factor will be the amount of coal-fired generation added to Nevada in 2018 and beyond. SPR continues to evaluate future potential available allowances as well as evaluation of additional technology to meet the 2018 Phase II cap. New mercury reduction technology is still in its infancy and as such the form of technology or associated costs cannot be determined at this time.

           Regional Haze Rules — In June 2005, the EPA finalized amendments to the July 1999 regional haze rules. These amendments apply to the provisions of the regional haze rule that require emission controls for industrial facilities emitting air pollutants that reduce visibility by causing or contributing to regional haze. The EPA requires states to develop implementation plans to comply with regional haze rules by December 2007. States are required to identify the facilities that will have to reduce emissions through installation of emission controls, known as best available retrofit technology (BART), and then set emissions limits for those facilities. The State of Nevada has just begun its BART rule development as the first step toward the December 2007 deadline, and SPR is actively involved in the stakeholder process. At this time, it is not clear which, if any, SPR facilities will require the installation of BART technology or an approved BART alternative. Due to the uncertainties of technology requirements and timing, SPR is not able to estimate the cost impact to its facilities at this time.

GENERAL – EMPLOYEES (ALL)

          SPR and its subsidiaries had 3,212 employees as of January 30, 2007, of which 1,828 were employed by NPC and 1,266 were employed by SPPC.

          NPC’s current contract with the International Brotherhood of Electrical Workers (IBEW) Local No. 396, which covers approximately 60% of NPC’s workforce, was renegotiated and ratified in April 2005. The new contract is in effect until February 2008. The three-year contract provided for a 4% general wage increase for bargaining unit employees effective February 2, 2005, with 3.75% increases in 2006 and 2007. In addition, the agreement includes modifications to holiday schedules, health care cost sharing, retirement benefits and other operational productivity improvements.

           SPPC’s proposed amendment to its existing contract with the IBEW Local No. 1245, which represents approximately 65% of SPPC’s workforce, was ratified by the IBEW on February 28, 2007. The contract, which is expected to be executed in the near future, will be in effect through December 31, 2009. The three-year contract will provide for an 8% general wage increase for most bargaining unit employees effective March 5 ^th , 2007, with 4% increases in 2008 and 2009. Due to protracted negotiations, bargaining unit employees did not receive a wage increase in 2006 and the negotiated 8% wage increase in 2007 reflects this. Some classifications will receive lump sum payments in lieu of a general wage increase and others will receive equity raises in addition to their general wage increase. Other significant negotiated items include modifications to holiday schedules, health care cost sharing, post retirement benefits, and other operational productivity improvements.

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 2006, the Utilities collected $107.8 million in franchise or other fees based on gross revenues. They collected $9.8 million in UEC based on consumption. They also paid and recorded as expense $1.0 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.

ITEM 1A RISK FACTORS

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

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

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

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

If Federal and/or State requirements are imposed on NPC and SPPC mandating further emission reductions, including limitations on carbon dioxide (CO2) emissions, such requirements could make some electric generating units uneconomical to construct, maintain or operate.

          Emissions of nitrogen and sulfur oxides, mercury and particulates from fossil fueled generating plants are potentially subject to increased regulations, controls and mitigation expenses. Environmental advocacy groups and regulatory agencies in the United States have also been focusing considerable attention on CO2 emissions from power generation facilities and their potential role in climate change. Although several bills have been introduced in Congress that would compel CO2 emission reductions, none have advanced through the legislature. Future changes in environmental regulations governing emissions reductions could make certain electric generating units uneconomical to construct, maintain or operate. In addition, any legal obligation that would require the Utilities to substantially reduce its emissions beyond present levels could require extensive mitigation efforts and, in the case of CO2 legislation, would raise uncertainty about the future viability of fossil fuels, particularly coal, as an energy source for new and existing electric generation facilities.

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

          The Utilities are subject to extensive federal, state and local statutes, rules and regulations relating to environmental protection. These laws and regulations can result in increased capital, construction, operating, and other costs. These laws and regulations generally require us to obtain and comply with a wide variety of environmental licenses, permits, inspections and other approvals, and may be enforced by both public officials and private individuals. We cannot predict the outcome or effect of any action or litigation that may arise from applicable environmental regulations.

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

          Existing environmental regulations regarding air emissions (such as NOx, SO2, mercury emissions or greenhouse-gas emissions), water quality and other toxic pollutants may be revised or new climate change regulations may be adopted or become applicable to us. Revised or additional regulations, which result in increased compliance costs, increased construction costs or additional operating restrictions, could have a material adverse effect on our financial condition and results of operations particularly if those costs are not fully recoverable from our customers and/or if such regulations make currently contemplated construction projects technologically obsolete or economically non-viable.

          Furthermore, we may not be able to obtain or maintain all environmental regulatory approvals necessary to our business. If there is a delay in obtaining any required environmental regulatory approval or if we fail to obtain, maintain or comply with any such approval, operations at our affected facilities could be halted or subjected to additional costs.

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

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

	•		prevailing market prices for coal, oil, natural gas and other fuels used in generation plants, including associated transportation costs, and supplies of such commodities;
	•		changes in the regulatory framework for the commodities markets that they rely on for purchased power and fuel;
	•		liquidity in the general wholesale electricity market;
	•		the actions of external parties, such as the FERC or independent system operators, that may impose price limitations and other mechanisms to address some of the volatility in the western energy markets;
	•		weather conditions impacting demand for electricity or availability of hydroelectric power or fuel supplies;
	•		union and labor relations;
	•		natural disasters, wars, acts of terrorism, embargoes and other catastrophic events; and
	•		changes in federal and state energy and environmental laws and regulations.

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

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

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

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

          As of February 23, 2007, NPC had approximately $476.3 million available under its $600 million revolving credit facility and SPPC has approximately $331.1 million available under its $350 million revolving credit facility. The combined effects of higher natural gas prices, significant deferred energy balances and ongoing under-recovery of fuel, energy and natural gas costs may have a negative effect on our short-term liquidity.

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

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

          In January 2007, NPC filed its annual mandatory deferred energy rate case with the PUCN along with a request to recover costs associated with terminated power contracts. In its deferred filing, NPC seeks to reduce its base tariff energy rate due to expected lower fuel costs and asks for recovery of approximately $75 million in past fuel and purchased power costs, both rate changes to be effective June 1, 2007. The second filing requests recovery of costs associated with the settlement of claims for power contracts executed during the western energy crisis. NPC is seeking approximately $21 million per year for a period of four years, to recover costs relating to the settlement of these claims. While the PUCN has up to 210 days to decide a fuel and purchased power case, NPC has requested that the rates become effective June 1, 2007.

          In December 2006, SPPC filed its annual mandatory deferred energy filing with the PUCN along with a request to recover costs associated with terminated power contracts. SPPC’s total deferred energy filing asks for recovery of approximately $18.7 million in past fuel and purchased power costs. In addition, the required deferred filing includes the setting of a new forward-looking rate to match the current estimate of costs of fuel and purchased power as well as the expiration of some rates previously approved by the PUCN. In its terminated power contract filing, SPPC is also seeking approximately $5 million per year for a period of four years, to recover costs relating to the settlement of the claims associated with the terminated power contracts.

          As of December 31, 2006, NPC’s and SPPC’s unapproved deferred energy costs were $154.1 million and $28 million, respectively.

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

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

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

          In November 2006, NPC filed its 2006 general rate case with the PUCN. The filing, if approved, would provide for a $156.4 million increase in its electric rates, for an overall increase of 7.4%. A decision on NPC’s general rate case is expected in the Spring of 2007.

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

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

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

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

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

          SPR is a holding company with no significant operations of its own. Its cash flows are substantially derived from dividends paid to it by the Utilities, which are typically utilized to service SPR’s debt, with the balance, if any, reinvested in SPR’s subsidiaries as contributions to capital. In the future, subject to various factors to be considered by SPR’s Board of Directors, a portion of SPR’s cash flow may be used to resume dividend payments on its common stock, in addition to paying debt service and making capital contributions to SPR’s subsidiaries.

          The Utilities are subject to restrictions on their ability to pay dividends to SPR under the terms of certain of their respective financing agreements and a PUCN order. In addition, certain provisions of the Federal Power Act could, depending on the interpretation thereof, limit or prohibit the payment of dividends to SPR.

          Assuming that the Utilities meet the requirements to pay dividends under the Federal Power Act and that any dividends paid to SPR are for SPR’s debt service obligations, under their material dividend restrictions, each of the Utilities may pay dividends to SPR if each such Utility can meet a 2 to 1 fixed charge coverage ratio test. If that condition is met, the amount of dividends that can be paid is an amount less than 50% of such Utilities’ consolidated net income plus the amount of capital contributions made to such Utility by SPR for the period from the date of issuance of the respective series of debt securities to the end of the most recently ended fiscal quarter. If they do not meet these conditions, the Utilities can still pay SPR’s reasonable fees and expenses, provided that each such Utility has a cash flow to fixed charge coverage ratio of at least 1.75:1 over the prior four fiscal quarters. Due to the cumulative calculation of this restriction, NPC’s Series G Notes and SPPC’s Series H Notes are effectively the most restrictive dividend limitations. In addition, under the most restrictive of their dividend restrictions, each of the Utilities has a carve-out that permits them to pay up to $25 million to SPR from the date of issuance of the applicable debt securities, regardless of whether the other conditions to paying dividends have been met. Although each Utility currently meets the conditions described above, a significant loss by either Utility could cause that Utility to be precluded from paying dividends to SPR until such time as that Utility again meets the coverage test. The dividend restriction in the PUCN order may be more restrictive than the Utilities’ individual dividend restrictions because the PUCN dividend restriction currently limits the amount of dividends paid to SPR collectively by the Utilities to SPR’s actual cash debt service payments, which amount may be less than the aggregate amount of the Utilities’ individual dividend restrictions. In 2006, SPR received approximately $53.7 million in dividends from the Utilities to meet its debt service obligations.

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

          Because SPR is a holding company, its indebtedness is effectively subordinated to the Utilities’ existing indebtedness and other future liabilities, including claims by the Utilities’ trade creditors, debt holders, secured creditors, taxing authorities, and guarantee holders. SPR conducts substantially all of its operations through its subsidiaries, and thus SPR’s ability to meet its obligations under its indebtedness will be dependent on the earnings and cash flows of those subsidiaries and the ability of those subsidiaries to pay dividends or to advance or repay funds to SPR. As of January 31, 2007, the Utilities had approximately $3.5

billion of debt outstanding. The terms of SPR’s indebtedness restrict the amount of additional indebtedness that SPR and the Utilities may issue. Based on SPR’s December 31, 2006 financial statements, assuming an interest rate of 7%, SPR’s indebtedness restrictions would allow SPR and the Utilities to issue up to approximately $2.1 billion of additional indebtedness in the aggregate, unless the indebtedness being issued is specifically permitted under the terms of SPR’s indebtedness. In addition, NPC and SPPC are subject to restrictions under the terms of their various financing agreements on their ability to issue additional indebtedness.

Whether SPR can procure sufficient renewable energy sources in each compliance year to comply with the Portfolio Standard for Renewable Energy.

          Currently, the State of Nevada requires compliance with its Portfolio Standard for Renewable Energy, which mandates that a share of the energy delivered to Nevada retail customers come from renewable energy resources. This energy is to be provided via direct generation, saved from portfolio energy systems or realized from implementation of efficiency measures. The Utilities continue to take affirmative actions to fulfill the Portfolio Standard requirements on their system. However, the Utilities’ success in meeting the standard remains dependent on creation of new renewable energy projects, both owned or via output which is purchased from third parties, as well as maintenance of an ongoing positive climate for renewable energy development across Nevada.

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

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

Changes in consumer preferences, war and the threat of terrorism or epidemics may harm our future growth and operating results.

          The growth of our business depends in part on continued customer growth and tourism demand in the Las Vegas portion of our service area. Changes in consumer preferences or discretionary consumer spending in the Las Vegas portion of our service area could harm our business. We cannot predict the extent to which future terrorist and war activities, or epidemics, in the United States and elsewhere may affect us, directly or indirectly. An extended period of reduced discretionary spending and/or disruptions or declines in airline travel and business conventions could significantly harm the businesses in and the continued growth of the Las Vegas portion of our service area, which could harm our business and results of operations. In addition, instability in the financial markets as a result of war, terrorism or epidemics may affect our ability to raise capital.

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

ITEM 1B. UNRESOLVED STAFF COMMENTS

          SPR, NPC and SPPC have received no written comments regarding their periodic or current reports from the SEC staff that were issued 180 days or more preceding the end of their 2006 fiscal year and that remain unresolved .

          The following is a list of NPC’s share of electric generation plants including the type and fuel used to generate, the anticipated 2007 net capacity (MW), and the years that the units were installed.

     The following is a list of SPPC’s share of electric generation plants including the type and fuel used to generate, the anticipated 2007 net capacity (MW), and the years that the units became operational.

Nevada Power Company and Sierra Pacific Power Company

Western United States Energy Crisis Proceedings before the FERC

           FERC 206 complaints

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

          On June 26, 2003, the FERC dismissed the Utilities’ Section 206 complaints, stating that the Utilities had failed to satisfy their burden of proof under the strict public interest standard. On July 28, 2003, the Utilities filed a petition for rehearing, but the FERC reaffirmed its June 26, 2003 decision. The Utilities appealed this decision to the Ninth Circuit. Oral argument was held on December 8, 2004. On December 19, 2006, a three judge panel of the Ninth Circuit overturned the FERC decision and remanded the case back to the FERC for application of the factors that the Ninth Circuit outlines in its decision. The Company expects one or more of the losing parties to file a petition for certiorari seeking review by the U.S. Supreme Court. The parties must file such a petition within 90 days.

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

Sierra Pacific Power Company

Piñon Pine

          In its 2003 General Rate Case, SPPC sought recovery of its unreimbursed costs associated with the Piñon Pine Coal Gasification Demonstration Project (the “Project”). The Project represented experimental technology tested pursuant to a Department of Energy (DOE) Clean Coal Technology initiative. Under the terms of the Project agreement, SPPC and DOE agreed to each fund 50% of construction costs of the Project. SPPC’s participation in the Project had received PUCN approval as part of SPPC’s 1993 integrated electric resource plan. While the conventional portion of the plant, a gas-fired combined cycle unit, was installed and performed as planned, the coal gasification unit never became fully operational. After numerous attempts to re-engineer the coal gasifier, the technology was determined to be unworkable. In its order in May 2004, the PUCN disallowed $43 million of unreimbursed costs associated with the Project. SPPC filed a Petition for Judicial Review with the Second Judicial District Court of Nevada (District Court) in June 2004 (CV04-01434). In January 2006, the District Court vacated the PUCN’s disallowance in SPPC’s 2003 General Rate Case and remanded the case back to the PUCN for further review as to whether the costs were justly and reasonably incurred (Order). In March 2006, the PUCN appealed the Order to the Nevada Supreme Court (the “Supreme Court”) and filed a motion to stay the Order pending the appeal to the Supreme Court. In June 2006, the District Court granted PUCN’s motion to stay the Order. In July 2006, the Supreme Court issued an order questioning the finality of the District Court’s decision and thus whether it has jurisdiction over the appeal and invited the parties to brief this matter. The BCP and PUCN responded in early August 2006. The Supreme Court dismissed the appeal in September 2006. Requests for rehearing were denied in late December 2006, and in January 2007, the matter was remitted back to the District Court, which, consistent with its January 2006 order, remanded the matter back to the PUCN for further review. A procedural schedule for this review has not yet been established.

Other Legal Matters

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

Environmental Matters

Nevada Power Company

Reid Gardner Station

          In August 1999, the Nevada Department of Environmental Protection (NDEP) issued a discharge permit to Reid Gardner Station and an order that requires all wastewater ponds to be closed or lined with impermeable liners over the following 10 years.

This order also required NPC to submit a Site Characterization Plan to NDEP to ascertain impacts. This plan has been reviewed and approved by NDEP. In collaboration with NDEP, NPC has evaluated remediation requirements. In May 2004, NPC submitted a schedule of remediation actions to NDEP which included proposed dates for corrective action plans and/or suggested additional assessment plans for each specified area. Any future ponds will be double-lined with inter-liner leak detection in accordance with the NDEP Authorization to Discharge Permit issued October 2005.

          Pond construction and lining costs to satisfy the NDEP order expended to date is approximately $36 million. Expenditures for 2007 through 2010 are projected to be approximately $10 million.

          In August 2004, NDEP conducted a Facility Air Quality Operating Permit (Title V permit) inspection at the Reid Gardner Station. NDEP requested monitoring, recordkeeping and reporting items and information pertaining to the sources identified in the Title V permit. NPC complied with the request and any subsequent requests that followed. In September and October 2004, NPC met with NDEP to review the results of NDEP’s inspection. NDEP informed NPC of possible non-compliance with some elements of its Title V permit, and in December 2004, issued Notices of Alleged Violation (NOAVs) relating to record-keeping, monitoring and other alleged administrative infractions. Discussions between NPC and NDEP ensued. In July 2005, NDEP issued new NOAVs. In part, these NOAVs represent reissuance of the previously issued NOAVs dated December 2004 and address additional monitoring and reporting issues for the period September 2002 through December 2004. Additional NOAVs were issued concerning intermittent opacity emissions and the monitoring, record-keeping and reporting of such emissions. All NOAVs are subject to an administrative hearing before the Nevada State Environmental Commission and then to judicial review. In July, 2005 NPC received a letter from the Environmental Protection Agency (EPA) requiring submittal of information relating to compliance of Reid Gardner Station with opacity emission limits and reporting requirements. NPC has responded to the EPA information request. In June, 2006, the EPA issued a Finding and Notice of Violation (NOV).

          NPC has progressed to the final draft stage of dialogue and settlement discussions with NDEP, EPA and Department of Justice (DOJ) regarding the NOVs and additional environmental controls and equipment changes, environmental benefit projects, monetary penalties, and/or other measures that may be required to achieve a settlement of the alleged violations. Management has booked an estimated minimum liability with respect to these matters. Certain environmental controls and equipment changes needed to assure compliance with existing or modified regulations were submitted by NPC to the PUCN in NPC’s 2006 IRP filing. These expenditures were approved by the PUCN in late 2006 and include equipment installation on the various units to control startup opacity and particulates and reduce operating opacity and oxides of nitrogen.

Clark Station

          In July 2000, NPC received a request from the EPA for information to determine the compliance of certain generation facilities at NPC’s Clark Station with the applicable State Implementation Plan. In November 2000, NPC and the DAQEM 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. In October 2003, the EPA issued a violation regarding turbine blade upgrades, which occurred in July 1993. A conference between the EPA and NPC occurred in December 2003. NPC presented evidence on the nature and finding of the alleged violations. In March 2004, the EPA issued another request for information regarding the turbine blade upgrades, and NPC provided information responsive to this request in April and May 2004. NPC’s position is that a violation did not occur. In May 2006, the EPA, by letter from the DOJ, notified NPC that it intends to initiate an enforcement action against NPC seeking unspecified civil penalties, together with injunctive relief, for alleged violations of the Prevention of Significant Deterioration requirements and Title V operating permit requirements of the Clean Air Act. NPC has entered into ongoing dialogue and settlement discussions with the EPA and DOJ regarding the alleged violations. Monetary penalties are not expected to be material and certain environmental controls and equipment changes needed to assure compliance with existing or modified regulations were submitted by NPC to the PUCN in January 2007 in NPC’s Second Amendment to the 2006 IRP filing.

NEICO

          NEICO, a wholly owned subsidiary of NPC, owns property in Wellington, Utah, which was the site of a coal washing and load-out facility. The site has a reclamation estimate supported by a bond of approximately $5 million with the Utah Division of Oil and Gas Mining, which management believes is sufficient to cover reclamation costs. Management is continuing to evaluate various options including reclamation and sale.

Sierra Pacific Power Company

PCB Treatment, Inc.

          In September 1994, Region VII of the EPA notified SPPC that it was being named as a potentially responsible party (PRP) regarding the past improper handling of Polychlorinated Biphenyls (PCB’s) by PCB Treatment, Inc., in two buildings, one located in Kansas City, Kansas and the other in Kansas City, Missouri (the Sites). Prior to 1994, SPPC sent PCB contaminated material to PCB

Treatment, Inc. for disposal. Certificates of disposal were issued to SPPC by PCB Treatment, Inc.; however, the contaminated material was not disposed of, but remained on-site. A number of the largest PRP’s formed a steering committee, which completed site investigations and along with the EPA determined that the Sites should be remediated by removing the buildings to the appropriate landfills. SPPC is a member of this steering committee. The cleanup has now been completed on both buildings and is pending inspection and sign off by EPA. The cleanup for the two buildings came in under budget, as such, SPPC does not expect any further obligations.

Stephen R. Wood, 63, Corporate Senior Vice President, Administration, SPR

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

William D. Rogers, 46, Corporate Senior Vice President, Chief Financial Officer and Treasurer, SPR

          Mr. Rogers was elected to his current position on February 15, 2007. He was previously Vice President, Finance and Risk and Corporate Treasurer from November 14, 2006 to February 15, 2007. Prior to that, he was Corporate Treasurer from June 8, 2005 to November 14, 2006. Before joining SPR, he served as managing director of debt capital markets for Merrill Lynch & Co. in New York from 2000 to 2005. Prior to that, he served as managing director of debt capital markets with JP Morgan Chase in New York from 1992 until 2000.

John E. Brown, 56, Controller, SPR

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

Mary O. Simmons, 51, Vice President, External Affairs, SPPC

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

PART II

ITEM 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.