form10-k.htm

ACRONYMS AND TERMS
(The following common acronyms and terms are found in multiple locations within the document)

Acronyms/Terms		Meaning

AFUDC		Allowance for Funds Used During Construction or Allowance for Borrowed Funds Used During Construction
AOC		Administrative Order on Consent
BCP		Bureau of Consumer Protection
BOD		Board of Directors
BTER		Base Tariff Energy Rate
BTGR		Base Tariff General Rate
CDWR		California Department of Water Resources
CIAC		Contributions in Aid of Construction
Clark Generating Station		William Clark Generating Station
CPUC		California Public Utilities Commission
CSA		Coal Supply Agreement
CWIP		Construction Work-In-Progress
DBRS		Dominion Bond Rating Service
DEAA		Deferred Energy Accounting Adjustment
DOS		Distribution Only Service
DSM		Demand Side Management
Dth		Decatherms
e-three		Sierra Energy Company d/b/a e-three
EEC		Ely Energy Center
EN-ti line		250 mile 500 kV transmission line
EPA		Environmental Protection Agency
EPS		Earnings Per Share
EROC		Enterprise Risk Oversight Committee
ESP		Energy Supply Plan
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
FIN 46 (R)		Interpretation No. 46, “Consolidation of Variable Interest Entities”
FIN 47		Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations”
FIN 48		Interpretation No. 48, “Accounting for Uncertainty in Income Taxes”
Fitch		Fitch Ratings, Ltd.
FSP		FASB Staff Position
FSP 132(R)-1		FASB Staff Position No 132(R)-1, "Employers Disclosures about Pensions and Other Postretirement Benefits"
FSP 157-3		FASB Staff Position No. 157-3, "Determining the Fair Value of Financial Asset When the Market for that Asset is Not Active"
GAAP		Accounting Principles Generally Accepted in the United States
GRC		General Rate Case
IBEW		International Brotherhood of Electrical Workers
Higgins Generating Station		Walter M. Higgins, III Generating Station
IRP		Integrated Resource Plan
kV		Kilovolt
kWh		Kilowatt Hour
Lenzie Generating Station		Chuck Lenzie Generating Station
LDC		Local Distributing Company
LOS		Lands of Sierra, Inc.
Moody’s		Moody’s Investors Services, Inc.
MW		Megawatt
MWh		Megawatt hour
NDEP		Nevada Division of Environmental Protection
NEICO		Nevada Electrical Investment Company
NERC		North American Electric Reliability Corporation
NOV		Notice of Violation
NPC		Nevada Power Company d/b/a NV Energy
NVE		NV Energy, Inc.
OATT		Open Access Transmission Tariff
PEC		Portfolio Energy Credit
Portfolio Standard		Renewable Energy Portfolio Standard

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PPC		Piñon Pine Corporation
PPIC		Piñon Pine Investment Company
PUCN		Public Utilities Commission of Nevada
QFs		Qualifying Facilities
RFP		Request for Proposal
ROE		Return on Equity
ROR		Rate of Return
S&P		Standard and Poor’s
Salt River		Salt River Project
SEC		Securities and Exchange Commission
SFAS		Statement of Financial Accounting Standards
SFAS 13		Statement of Financial Accounting Standards No. 13, "Accounting for Leases"
SFAS 71		Statement of Financial Accounting Standards No. 71, “Accounting for the Effects of Certain Types of Regulation”
SFAS 87		Statement of Financial Accounting Standards No. 87, "Employer's Accounting for Pensions"
SFAS 90		Statement of Financial Accounting Standards No. 90, "Accounting for Abandonments and Disallowances of Plant Costs"
SFAS 106		Statement of Financial Accounting Standards No. 106, "Employers Accounting for Postretirement Benefits Other Than Pensions"
SFAS 109		Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes"
SFAS 123R		Statement of Financial Accounting Standards No. 123R, “Share Based Payments”
SFAS 128		Statement of Financial Accounting Standards No. 128, "Earnings Per Share"
SFAS 131		Statement of Financial Accounting Standards No. 131, "Disclosure About Segments of an Enterprise and Related Information"
SFAS 133		Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities”
SFAS 138		Statement of Financial Accounting Standards No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities - An Amendment of FASB Statement No. 133"
SFAS 143		Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations”
SFAS 144		Statement of Financial Accounting Standards No. 144, "Accounting for the Disposal or Impairment of Long-Lived Assets"
SFAS 149		Statement of Financial Accounting Standards No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities"
SFAS 155		Statement of Financial Accounting Standards No. 155, "Accounting for Certain Hybrid Financial Instruments - An Amendment of FASB Statements No. 133 and 140"
SFAS 157		Statement of Financial Accounting Standards No. 157, “Fair Value Measurement”
SFAS 158		Statement of Financial Accounting Standards No. 158, “Employer’s Accounting for Defined Benefit Pension and Other Postretirement Plans”
SFAS 159		Statement of Financial Accounting Standards No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities”
SFAS 161		Statement of Financial Accounting Standards No. 161, “Disclosures about Derivative Instruments and Hedging Activity”
SGHC		Sierra Gas Holding Company
SNWA		Southern Nevada Water Authority
SOP 96-1		Statement of Position, "Environmental Remediation Liabilities"
SPC		Sierra Pacific Communications
SPE		Sierra Pacific Energy Company
SPPC		Sierra Pacific Power Company d/b/a NV Energy
SPR		Sierra Pacific Resources
SRSG		Southwest Reserve Sharing Group
SWDC		Sierra Water Development Company
TGPC		Tuscarora Gas Pipeline Company
TGTC		Tuscarora Gas Transmission Company
TMWA		Truckee Meadows Water Authority
Tracy Generating Station		Frank A. Tracy Generating Station
U.S.		United States of America
Valmy Generating Station		North Valmy Generating Station
WECC		Western Electricity Coordinating Council
WSPP		Western Systems Power Pool

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FORWARD LOOKING STATEMENTS

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

NV Energy, Inc., formerly Sierra Pacific Resources, is an investor-owned holding company that was incorporated under Nevada law on December 12, 1983. The company’s stock is traded on the New York Stock Exchange under the symbol “NVE”. NVE’s mailing address is 6226 West Sahara Avenue, Las Vegas, Nevada 89146.

NVE has six primary, wholly-owned subsidiaries: Nevada Power Company d/b/a NV Energy, Sierra Pacific Power Company d/b/a NV Energy, Sierra Pacific Communications, Sierra Pacific Energy Company, and Lands of Sierra. References to NVE refer to the consolidated entity, except where the context provides otherwise. NPC and SPPC are referred to collectively in this report as the “Utilities”. In 2008, Sierra Pacific Resources changed its name to NV Energy, Inc. In addition, NPC and SPPC announced they will do business under the name NV Energy. The name change unifies under a single brand a company that serves Nevada's energy needs from north to south.

The Utilities operate three business segments, as defined by SFAS 131: NPC electric; SPPC electric; and SPPC natural gas. Electric service is provided to Las Vegas and surrounding Clark County, and to northern Nevada and the Lake Tahoe area of California. Natural gas service is provided in the Reno-Sparks area of Nevada. The Utilities are the major contributors to NVE’s financial position and results of operations. Other subsidiaries either do not meet the definition of a segment or are below the quantitative threshold for separate segment disclosure and are combined under “all other” in the following pages. Parenthetical references are included after each major section title to identify the specific entity or entities addressed in the section. See Note 2, Segment Information of the Notes to Financial Statements, for further discussion.

NPC and SPPC service territories are as follows:

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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. SPPC’s gas business typically peaks in the winter months due to heating demands.

Beginning in 2007, the Utilities embarked on a three part energy supply strategy to manage resources against our load by conserving energy, investing in renewable resources and building generation in an effort to reduce our reliance on purchased power.

Energy Efficiency and Conservation Programs

NPC and SPPC have designed a portfolio of cost effective DSM programs that allow every customer to take advantage of savings from energy efficiency measures. DSM programs are marketed across all segments of customer classes (residential, commercial, public, and low income).

The Portfolio Standard, discussed below, allows energy efficiency measures from qualified conservation programs to meet up to 25% of the Portfolio Standard. A PEC is created for each kWh of energy conserved by qualified energy efficiency programs, or generated by renewable energy systems. Energy saved during peak demand hours earns double the PEC's. After the DSM percentage allowance is fully utilized, NPC’s and SPPC’s strategy is to continue to implement cost-effective DSM programs.

In 2008, the Utilities invested $55 million towards energy efficiency and conservation programs. The Utilities are planning to invest between $45 million and $60 million in 2009. The final amount will be determined by numerous factors, such as the economy, the impact of the federal government stimulus legislation, the performance of existing and new programs and many other factors. The PUCN has approved investments in efficiency and qualified conservation programs of approximately $140 million, which will be deferred as a regulatory asset, subject to prudency review by the PUCN. Given the Utilities’ 2008 investment level, management believes that the Utilities are in a position to achieve the maximum allowable 25% in 2008 to meet renewable portfolio compliance. This report will be filed with the PUCN in April 2009.

Purchase and Development of Renewable Resources

Nevada law sets forth the Portfolio Standard requiring providers of electric service to acquire, generate, or save a specific percentage of its total retail energy sales from renewable energy resources. Renewables include biomass, geothermal, solar, waterpower and wind projects. Pursuant to the Portfolio Standard, NPC and SPPC were required to obtain an amount of PEC’s equivalent to nine percent of their total retail energy sales from renewables for year 2008. The Portfolio Standard increases by three percent to 12% in 2009 and by an additional three percent every other year until it reaches 20% in year 2015. Moreover, not less than five percent of the total Portfolio Standard must be met from solar resources. Compliance with the Portfolio Standard is measured in PEC's administered by the PUCN. PEC's not needed to fulfill the Utilities’ compliance obligation (excess) are carried over for future years’ compliance; and, with PUCN approval, can be exchanged between the Utilities.

Nevada law requires providers of electric services to file an annual report that describes the level of compliance with the Portfolio Standard. In the Utilities’ April 2008 Portfolio Standard Annual Report for Compliance Year 2007 (submitted to the PUCN jointly), the Utilities reported that with the PUCN approval of the transfer of SPPC’s excess non-solar PEC’s to NPC, the Utilities were able to comply with the non-solar Portfolio Standard. However, due to the late commercial operation of solar facilities, the Utilities did not meet the solar portion of the Portfolio Standard. The PUCN issued its order accepting the Utilities’ Portfolio Standard Annual Report for Compliance Year 2007. In addition, as a result of the Utilities’ efforts to add solar resources, the PUCN granted an exemption to the Utilities for non-compliance with the solar requirement.

Generation

In 2003, the Utilities embarked on a strategy to build or acquire generating facilities to decrease their dependence on purchased power. Since then, the Utilities have increased their summer net generating capacity by 100%. Additionally, in 2007, NPC began construction of a 500 MW (nominally rated) natural gas fired combined cycle generator at the Harry Allen Generating Station, with an expected completion date in 2011. The PUCN has currently approved approximately $130 million be spent towards the development of the EEC. The EEC consists of two 750 MW coal generation units to be located near Ely, Nevada. However, on February 9, 2009, NVE and the Utilities announced their intention to postpone plans to construct the EEC due to increasing environmental and economic uncertainties until such time as carbon sequestration becomes commercially viable, which is not expected for at least a decade. NVE and the Utilities still plan to proceed with the construction of the EN-ti line, which will link NPC’s and SPPC’s transmission systems in the southern and northern portions of the state, allowing for the transfer of energy, including renewable resources, between the Utilities. The Utilities and will seek approval from the PUCN to accelerate the development of the EN-ti line.

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Despite the significant investment since 2003, the Utilities do not own sufficient generating facilities to meet peak demands. As a result of this shortfall and forecasted market opportunities, NPC is forecasting to purchase approximately 23% of its total system energy needs from the wholesale market and SPPC is forecasting to purchase approximately 34% of its total system energy needs from the wholesale market for year 2009. For the 2009 summer peak, the Utilities have secured 100% of their forecasted 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. As a comparison, in 2008, NPC and SPPC purchased approximately 32.5% and 49.5%, respectively, of their 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.

The Utilities continue to evaluate the resource needs of their service territory; however, they expect more moderate construction of generating units in the future.

As a result of expanded service territory growth, both Utilities have added transmission infrastructure. The new transmission lines are discussed 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 one 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. In 2008, Newmont Mining Corporation, a large SPPC mining customer, began operations of a 203 MW facility. Moreover, the City of Las Vegas has filed with the PUCN to exit NPC's system in regards to nine premises. These matters are discussed further under Business and Competitive Environment, Competition, for NPC and SPPC below.

The FERC, PUCN and, in the case of the California service territory of SPPC, the 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 for NVE, NPC and SPPC 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 NVE’s website (www.nvenergy.com) through links on this website 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 address are not part of this Form 10-K. The public may also read any copy of materials filed with the SEC by NVE, NPC or SPPC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, D.C. 20549. Information on the operation of the Public Reference Room may be obtained by calling the SEC at 1-(800) SEC-0030. Reports, proxy and information statements, and other information regarding issuers that file electronically may also be obtained directly from the SEC’s website. Available on the nvenergy.com website are 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 NVE’s BOD and our corporate governance and standards of conduct guidelines. Printed copies of these documents may be obtained free of charge by writing to NVE’s Corporate Secretary at NV Energy, Inc., 6226 West Sahara Avenue, Las Vegas, Nevada 89146.

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 NVE in July 1999. Its mailing address is 6226 West Sahara Avenue, Las Vegas, Nevada 89146.

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% of Northwind Aladdin, LLC 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 2008, NPC served approximately 827,000 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.

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Electric Operations

NPC is charged with meeting the growing electric 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 customer base, NPC generates electricity and purchases power in accordance with an ESP, 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, Energy Supply. In 2008 in a continued effort to reduce reliance on purchased power, NPC completed the construction of 619 MWs (nominally rated) peaking units at the Clark Generating Station. Additionally, in October NPC completed the acquisition of the 598 MW (nominally rated) Higgins Generating Station. Construction also continues on a 500 MW (nominally rated) unit at the Harry Allen Generating Station which is scheduled to be completed in 2011.

Nevada regulations require NPC to file GRCs every three years with the PUCN to adjust rates including cost of service and return on investment. Nevada state regulations also require NPC to file annual DEAA applications to either recover or refund balances that have been deferred and that represent the difference between fuel and purchased power costs actually incurred and the amounts collected in current retail rates. Additionally, NPC is required quarterly to file to reset BTERs, reflecting more recent fuel and purchased power 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.

The FERC has jurisdiction under the Federal Power Act with respect to wholesale 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 buys transportation for natural gas.

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 would reduce NPC’s need to purchase power from potentially volatile wholesale energy markets. The City of Las Vegas has filed with the PUCN to exit NPC’s system in regards to nine premises. The departure is not expected to materially affect NPC’s load requirements.

Sales

In 2008, NPC’s operating revenues were approximately $2.3 billion. Summer peak loads are driven by air conditioning demand. Winter peak loads are low relative to the summer peak. NPC’s peak load increased at an average annual growth rate of 2.5% over the past five years, reaching 5,504 MW in July 2008. NPC’s retail total electric MWh sales have increased at an average annual growth rate of 3.3% over the past five years; however, retail electric MWh sales declined slightly from 2007 to 2008, as discussed below.

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NPC’s electric customers by class contributed the following MWh sales:

	MWh Sales (Billed and Unbilled)
	2008					2007					2006
	MWh		% of Total			MWh		% of Total			MWh		% of Total

Residential		9,041,403		41.4	%		9,371,726		42.4	%		9,033,142		42.3	%

Commercial & Industrial:
Gaming/Recreation/Restaurants		3,695,156		16.9	%		3,697,324		16.7	%		3,736,608		17.5	%
All Other Retail		8,644,314		39.5	%		8,551,874		38.7	%		8,049,753		37.7	%
Total Retail		21,380,873		97.8	%		21,620,924		97.8	%		20,819,503		97.5	%

Wholesale		238,511		1.1	%		240,934		1.1	%		244,128		1.2	%

Sales to Public Authorities		231,647		1.1	%		252,119		1.1	%		281,369		1.3	%

Total		21,851,031		100.0	%		22,113,977		100.0	%		21,345,000		100.0	%

Total retail MWh sales decreased approximately 1.1% in 2008 from 2007, primarily due to a decrease in residential customer usage as a result of cooler summer weather and, to a lesser extent, changes in residential customer usage patterns.

Nevada is ranked as the eighth fastest growing state in the nation by the U.S. Census Bureau for the twelve months ended June 30, 2008. However, the southern Nevada economy has been adversely affected by the recession facing the United States and the global economy, resulting in an increase in unemployment to 9.1% compared to 5.6% in 2007, a decrease in hotel/motel occupancy of 11.9% from the 2007 level, and a decrease in new home sales to 9,780 in 2008 compared to 19,670 and 36,051 in 2007 and 2006, respectively.

Demand

Load and Resources Forecast

NPC’s integrated peak electric demand decreased from 5,866 MW in 2007 to 5,504 MW in 2008. Variations in energy usage occur as a result of varying weather conditions, economic conditions, and other energy usage behaviors, such as conservation efforts. 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. See the Generation section and Purchased Power section below for details of NPC’s generation and contracts for purchased power. Remaining needs will be met through power purchases through RFPs or short term purchases.

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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):

	Forecasted Electric Capacity
	Requirements and Resources (MW)

	2009		2010		2011		2012		2013

Total requirements (1)		6,611		6,657		6,724		6,915		6,946

Resources:
Company-owned existing generation (2)		4,234		4,234		4,180		4,180		4,175
Company-owned new generation (3)		-		-		489		489		489
Contracts for power purchases		2,431		2,231		2,237		2,237		2,275
Total resources		6,665		6,465		6,906		6,906		6,939

Total additional required (4)		-		192		-		9		7

(1)	Includes system peak load plus planning reserves.

(2)	Includes 232 MW of peaking capacity at Reid Gardner Generating Station Unit No. 4, which is co-owned with CDWR, see Item 2, Properties.

(3)	Includes 484 MW combined cycle unit at the Harry Allen Generating Station in 2011, and 5 MW at the Goodsprings renewable energy plant in 2011.

(4)	Total additional required is the difference between the total requirements and total resources. Total additional required represents the amount needed to achieve the forecasted system peak plus a planning reserve margin.

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 generation from the wholesale markets subjects power prices to price volatilities due to available supply and gas prices.

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.

Total System

NPC manages a portfolio of energy supply options. The availability of alternate resources allows NPC to dispatch its electric generation system in a more cost-effective manner under varying operating and fuel market conditions while maintaining system integrity. During 2008, NPC generated approximately 67.5% of its total system requirements, purchasing the remaining 32.5% as shown below.

	2008					2007					2006
	MWh		% of Total			MWh		% of Total			MWh		% of Total
NPC Company Generation
Gas/Oil		10,976,006		49.5	%		10,437,115		45.3	%		8,093,020		36.1	%
Coal		3,992,392		18.0	%		4,083,262		17.7	%		4,067,209		18.2	%
Total Generated		14,968,398		67.5	%		14,520,377		63.0	%		12,160,229		54.3	%

Total Purchased		7,190,431		32.5	%		8,510,429		37.0	%		10,248,394		45.7	%

Total System		22,158,829		100.0	%		23,030,806		100.0	%		22,408,623		100.0	%

As a supplement to its own generation, NPC purchases spot, short-term firm, intermediate-term firm, long-term firm, and non-firm energy to meet its customer demand requirements. Total energy supply includes purchases from outside the electric system due to limited control area generation and also the need to access market energy supplies. NPC’s decision to purchase this energy is based on economics, mitigation of availability risk, and system import limits. Firm block purchases are transacted as both a price hedging strategy and to ensure that needed firm capacity is available over peak load periods. Spot market energy is purchased based on the economics of purchasing “as-available” energy when it is less expensive than NPC’s own generation, again, subject to net system import limits. NPC’s 2008 company generated MWhs increased 3.1% from 2007. NPC’s 2008 purchased power MWhs decreased 15.6% compared to 2007 due to NPC’s increased reliance on self generation and a decrease in total system demand. See Energy Supply in Management’s Discussion and Analysis of Financial Condition and Results of Operations for additional information regarding NPC’s purchasing strategies.

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Risk Management

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

Generation

NPC’s generation capacity consists of a combination of 33 gas, oil and coal generating units with a combined summer capacity of 4,002 MWs as described in Item 2, Properties. In 2008, NPC generated approximately 67.5% of its total system requirements.

In 2008, NPC completed construction of the Clark Peaking Units for a total additional capacity of 619 MWs. Currently, NPC is constructing a 500 MW (nominally rated) combined cycle unit at the existing Harry Allen Generating Station with a commercial operation date prior to summer of 2011, which was approved by the PUCN in 2008 as an amendment to NPC’s IRP. In addition, NPC received approval and completed the purchase of a 598 MW (nominally rated) natural gas fired, combined cycle power plant from Reliant Energy, Inc, now known as the Higgins Generating Station. The addition of these units increases NPC’s ability to self generate.

Fuel Availability

NPC’s 2008 fuel requirements for electric generation were provided by natural gas, coal, and oil. The average costs of gas, coal, and oil for energy generation per MMBTU for the years 2004 through 2008, along with the percentage contribution to NPC’s total fuel requirements were as follows:

		Average Consumption Cost & Percentage Contribution to Total Fuel Requirement

	Gas			Coal		Oil
	$/MMBTU		Percent	$/MMBTU	Percent	$/MMBTU	Percent
2008	7.79		66.5%	2.17	33.5%	18.87	0.0%
2007	6.32		64.4%	1.89	35.6%	17.17	0.0%
2006	7.40		58.8%	1.63	41.1%	16.66	0.1%
2005	6.18		32.7%	1.59	67.1%	13.50	0.1%
2004	6.13		27.3%	1.33	72.6%	8.75	0.1%

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 physical gas prices are set at an appropriate industry index during the month of current delivery. All natural gas is delivered to NPC through the use of firm gas transport contracts. Monthly and daily gas supply adjustments are made based on the current energy marketplace and operational considerations.

NPC continues to optimize the use of the Lenzie Generating Station and the Silverhawk Generating Station, as well as the recently acquired Higgins Generating Station, which results in a reduction of NPC’s exposure to fluctuations in the market price of gas. 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 2009 and beyond.

NPC utilizes a laddered strategy with respect to coal supply and has long term coal contracts with Arch Coal Company (expires 2011), Andalex Resources, Inc. (expires 2010), Hiawatha Mining Co. (expires 2012) and Bowie Resources (expires 2012) to supply the Reid Gardner Generating Station. These contracts represent 83% of projected coal requirements for 2009, 59% for 2010, 32% for 2011 and 9% for 2012.

As of December 31, 2008, Reid Gardner Generating Station’s coal inventory level was 272,744 tons, or approximately 81 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 Generating Station in Moapa, Nevada. 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. The Union Pacific contract expires December 31, 2009.

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Coal for the Navajo Generating Station, which is jointly owned and operated by Salt River, is obtained from surface mining operations conducted by Peabody on portions of the Black Mesa in Arizona within the Navajo and Hopi Indian tribes (the Tribes) reservations. The Navajo Generating Station's 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 ESP, 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 2008, NPC purchased 32.5% 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) generated by gas, hydro and renewable resource facilities with a total MW capacity of 2,090 and contract termination dates ranging from 2013 to 2032. Included in these contracts are 404 MWs of capacity of renewable energy of which approximately 325 MWs of capacity are under construction and not currently available.

NPC is a member of the WSPP and the SRSG. NPC’s membership in the SRSG has allowed it to network with other utilities in an effort to use its resources more efficiently in the sharing of responsibilities for reserves. NPC’s credit standing may affect the terms under which NPC is able to purchase fuel and electricity in the western energy markets; however, as a result of NPC’s credit rating, this was not a significant factor in 2008.

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 WECC. WECC is one of eight regional councils of the NERC, the entity responsible for the reliability, adequacy and security of North America’s bulk electric system.

NPC’s transmission system links generating units within and outside of the NPC Balancing Authority 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 Utilities have proposed the EN-ti line which will link NPC’s and SPPC’s transmission system in the southern and northern portions of the state, allowing for the transfer of energy, including renewable resources between the Utilities. The map below shows NPC’s transmission system and the proposed EN-ti line:

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Under the NERC guidelines, NPC is a Balancing Authority, a Transmission Operator, and a Transmission Owner among other roles. As defined by NERC, the Balancing Authority integrates resource plans ahead of time, maintains load-interchange-generation balance within a Balancing Authority Area, and supports Interconnection frequency in real time (i.e., the Balancing Authority is responsible for assuring that the demands on the system are matched by an equivalent amount of resources, whether from generators within its area or from imports). The Transmission Operator is responsible for the reliability of its local transmission system, and operates or directs the operations of the transmission facilities. The Transmission Owner owns and maintains transmission facilities. NPC also schedules power deliveries over its transmission system and maintains reliability through its operations and maintenance practices and by verifying that customers are matching loads with resources.

NPC plans, builds and operates a transmission system that delivered 21,851,031 MWh of electricity to customers in its Balancing Authority Area in 2008. The NPC system handled a peak load of 5,504 MW in 2008 through 1,908 line miles of transmission lines and other transmission facilities ranging from 60 kV to 500 kV. 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 growing system. In the last 10 years, due primarily to high customer growth, NPC has constructed major transmission projects with Centennial being the most recently completed project (100 miles).

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Transmission Regulatory Environment

Transmission for NPC's bundled retail customers is subject to the jurisdiction of the PUCN for rate making purposes. NPC’s wholesale and retail access transmission services are regulated by the FERC under cost based regulation subject to the OATT which NPC operates under. In accordance with the OATT, NPC offers several transmission services to wholesale customers:

·	Long-term and short-term firm point-to-point transmission service (“highest quality” 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 energy marketing business in accordance with FERC Standards of Conduct.

NPC is a member of WestConnect and the WestConnect Subregional Transmission Planning Committee. 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 2007 and 2008 the WestConnect members worked collaboratively to develop consistent responses to FERC Order 890 requirements and developed regional business practices including OATT Attachment K, Transmission Planning Process. The Subregional Transmission Planning Committee was established to provide coordinated transmission planning across the WestConnect footprint, including the Southwest Area Transmission Group that NPC participates in and the Sierra Nevada Planning Group that SPPC participates in.

Integrated Resource Plan

NPC files an IRP every three years. The IRP is prepared in compliance with Nevada laws and regulations and covers a 20 year period. The IRP develops a comprehensive, integrated plan that considers customer energy requirements and proposes the resources to meet those requirements in a manner that is consistent with prevailing market fundamentals. The ultimate goal of the IRP is to balance the objectives of minimizing costs and reducing volatility while reliably meeting the electric needs of NPC’s customers.

In June 2006, NPC filed its 2006 triennial IRP with the PUCN and has since filed several amendments to the IRP. The following are the key elements of the filing as amended:

Approval was requested and subsequently obtained for the construction of a 500 MW (nominally rated) combined cycle unit at the existing Harry Allen Generating Station with a scheduled commercial operation date of June 1, 2011. The estimated cost of this project is approximately $682 million (excluding AFUDC). Additionally, the PUCN approved NPC’s request to include the Harry Allen Generating Station CWIP in rate base. Following the PUCN's approval of NPC's 8th amendment to the 2006 IRP in October, 2008, the Nevada Attorney General's BCP filed a petition for a rehearing with respect to the portion of the PUCN's order approving the new combined cycle unit at the Harry Allen Generating Station. The PUCN denied the petition on November 26, 2008. On December 30, 2008, the BCP filed a petition for judicial review in the First Judicial District of the State of Nevada seeking a reversal of the PUCN's order as it relates to the Harry Allen Generating Station combined cycle unit and a remand of the matter to the PUCN to gather further evidence.

Approval was requested and subsequently obtained to purchase the 598 MW (nominally rated) combined cycle Generating Station from Reliant Energy, LLC., now known as the Higgins Generating Station, for approximately $510 million, including costs for inventory and other closing costs and adjustments. The purchase was completed in October 2008 and is included in NPC’s 2008 GRC.

·	Approval was obtained to construct 619 MW (nominally rated) quick start combustion turbine units at the Clark Generating Station at a cost of approximately $384 million. Construction of this project was completed in 2008.

The PUCN granted the Utilities’ initial request in its IRP filing to proceed with the development of Phase I of the EEC and accompanying transmission line. The PUCN also approved the Utilities’ request of $300 million for development activities associated with the EEC with a limitation of $155 million placed on expenditures until the Utilities have obtained the final air permit. The PUCN approved the request to initially allocate the costs between NPC and SPPC using an 80/20 cost allocation, respectively. Furthermore, the PUCN granted the Utilities’ request for critical facility designation, thereby allowing it to qualify for incentives to be determined at a later date. Since then, the Utilities filed amendments in regards to EEC and the PUCN, in its order, outlined certain minimum information regarding the EEC that shall be provided in NPC’s 2009 IRP filing, including but not limited to an update of the engineering, construction and then current cost estimates of the EEC, a refined project schedule, an initial analysis of the benefits of joint system analysis, an update of environmental costs and economic benefits attributed to the EEC and an update on the status of all the required permits. Additionally the limitation on expenditures was reduced to $130 million. However, on February 9, 2009, NVE and the Utilities announced their intention to postpone their plan to construct the EEC due to increasing environmental and economic uncertainties until such time as carbon sequestration becomes commercially viable, which is not expected for at least a decade. The Utilities have spent approximately $71.1 million as of December 31, 2008 towards the development of the EEC, including costs relating to the development of the EN-ti line.

·	Approval of various DSM programs was requested and obtained.

·	Approval was requested and subsequently obtained to acquire a 50% interest in the Carson Lake Project, providing a minimum of 30 MW of geothermal renewable energy (from a nominal net of 24 MW to 40 MW) under the terms of a Joint Operating Agreement with an affiliate of Ormat Technologies, Inc.

·	Approval was requested and subsequently obtained to construct the 6 MW Goodsprings Waste Heat Recovery Project at the compressor station on the Kern River Gas Pipeline.

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·	Approval was requested and subsequently obtained for various long-term power purchase agreements, primarily related to renewable energy, and long term tolling contracts.

·	Approval was requested and subsequently obtained to expend $60 million on new ultra-low emission burners on the four combustion turbines serving the combined cycle units at the Clark Generating Station.

·	Approval of an updated load forecast was requested and obtained.

Construction Program

NPC’s construction program and estimated expenditures are subject to continuing review, and are periodically 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, regulatory considerations and impact to customers, 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 2008, including AFUDC, net salvage and CIAC, were $1.3 billion, and for the period 2004 through 2008, were $3.7 billion. Estimated construction expenditures for PUCN approved projects, projects under contract, compliance projects and other base capital requirements are as follows (dollars in thousands):

	2009			2010-2013	Total 5 - Year
Electric Facilities
Generation	$	554,774	$	805,079	$	1,359,853
Distribution		128,530		580,124		708,654
Transmission		67,272		275,977		343,249
Other		77,488		163,205		240,693
Total	$	828,064	$	1,824,385	$	2,652,449

Total estimated cash requirements related to construction projects consist of the following (dollars in thousands):

	2009				2010-2013		Total 5 - Year

Construction Expenditures	$	828,064		$	1,824,385		$	2,652,449
AFUDC		(64,436	)		(250,754	)		(315,190	)
Net Salvage/ Cost of Removal		(10,100	)		(41,420	)		(51,520	)
Net Customer Advances and CIAC		(22,300	)		(91,452	)		(113,752	)
Total Cash Requirements	$	731,228		$	1,440,759		$	2,171,987

Major PUCN approved projects included in the 5 year estimated construction expenditures are as follows (dollars in thousands):

Projects	MW		Approved by PUCN		Total Cost 2009		Total Project Cost Cash Flows		Cumulative Expenditures as of December 31, 2008		Projected in service completion date year
EEC (1)		1,500	$	104,000	$	24,000	$	104,000	$	57,085		-
Harry Allen Generating Station		500		681,869		321,510		682,043		140,618	2011
Renewable Projects (2)		26		112,300		48,692		120,871		10,858		2010-2011
Reid Gardner Generating Station environmental compliance		-		83,940		11,700		93,760		82,060	2009
Clark Generating Station environmental compliance		-		60,000		23,116		58,861		35,745	2009

(1) See discussion below regarding the EEC by the PUCN. These costs assume 80% allocated to NPC.

(2) MWs reflect NPC’s expected ownership share of these projects.

As discussed under the IRP, the PUCN approved the Utilities spending on the EEC up to $130 million, of which the Utilities have spent approximately $71.1 million, which includes costs related to the EN-ti line, as of December 31, 2008. However, on February 9, 2009, NVE and the Utilities announced their intention to postpone the construction of the EEC but plan to proceed with the construction of the EN-ti line. In 2009, the Utilities intend to file amendments to their IRP’s requesting PUCN approval to accelerate the development of the EN-ti line.

In 2008 the PUCN approved the construction of a new 500 MW (nominally rated) natural gas combined cycle electric generating plant at NPC’s Harry Allen Generating Station. This facility, 25 miles northeast of Las Vegas, is expected to commence operations by 2011.

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NPC has various renewable energy projects, including wind, solar and geothermal, under development and negotiation. In 2008, the PUCN approved the Carson Lake project and Goodsprings Waste Heat Recovery project for $91 million and $21.3 million respectively. The Carson Lake project and the Goodsprings Waste Heat Recovery project are scheduled for commercial operation in 2011 and 2010, respectively.

NPC has entered into a joint development agreement, the China Mountain Wind Project, for approximately $238 million. Under the joint development agreement, NPC has the opportunity to evaluate the feasibility of the project. The PUCN has not yet approved the project; and as such, it has not been included in the above tables.

Reid Gardner Generating Station major capital and environmental projects include approximately $83.9 million of items previously approved by the PUCN and agreed upon with the EPA in April 2007. In addition, NPC is expecting to incur costs with respect to major projects at the Reid Gardner Generating Station of approximately $87.2 million for certain infrastructure and environmental projects as agreed upon with the NDEP and other compliance projects for which NPC has not received PUCN approval, but are included in the gross construction expenditures and estimated cash requirements. See Note 13, Commitments and Contingencies in the Notes to Financial Statements.

The Clark Generating Station major capital and environmental projects include the installation of capital equipment as agreed upon in the consent decree between NPC and the EPA in August 2007.

SIERRA PACIFIC POWER COMPANY

A Nevada corporation since 1965, SPPC was originally incorporated in Maine in 1912. SPPC became a subsidiary of NVE 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, PPC and 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 366,000 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 electric 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. Therefore, SPPC’s electric revenues and associated expenses are not incurred or generated evenly throughout the year.

To serve its customer base, SPPC generates electricity and purchases power in accordance with an ESP, 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. In a continued effort to reduce reliance on purchased power, SPPC completed the construction of a 541 MW gas-fired combined-cycle plant at Tracy, east of Reno during 2008.

Nevada regulations require SPPC to file GRCs every three years with the PUCN to adjust rates including cost of service and return on investment. Nevada state regulations also require SPPC to file annual DEAA applications to either recover or refund balances that have been deferred and that represent the difference between fuel and purchased power costs actually incurred and the amounts collected in current retail rates. Additionally, SPPC is required quarterly to file to reset BTER reflecting more recent fuel and purchased power 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.

The FERC has jurisdiction under the Federal Power Act with respect to wholesale 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 buys transportation for natural gas.

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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.

Newmont Mining Corporation achieved full commercial production of a new 204 MW (nominally rated) coal-fired power plant located in northeastern Nevada on May 1, 2008. In 2007, SPPC and Newmont entered into a wholesale power sale agreement and a new form of retail service, General Service New Generation (GS-4NG). Newmont will sell the electrical output from its plant to SPPC for at least 15 years under the 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 the new GS-4NG rate schedule.

In 2008, after Barrick Gold Corporation completed its acquisition of the Cortez mining property in Nevada, it applied for and received approval from the PUCN for Cortez to depart SPPC’s retail system and, effective November 1, 2008, to be served under the terms of a DOS Agreement and the applicable DOS Tariff. In 2005, Barrick Gold Corporation completed construction of a 118 MW generating facility and departed SPPC’s retain system, but continues to be served under a DOS agreement and applicable tariff.

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

Sales

In 2008, SPPC’s electric operations contributed approximately $1.0 billion, or 83%, of SPPC’s total revenues. SPPC’s peak load reached 1,648 MW in August 2008. 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 electric customers by class contributed the following MWh sales:

	MWh Sales (Billed and Unbilled)

	2008					2007					2006
	MWh		% of Total			MWh		% of Total			MWh		% of Total
Retail:
Residential		2,523,923		29.4	%		2,519,666		28.6	%		2,480,681		28.2	%
Mining		1,632,882		19.0	%		1,742,641		19.8	%		1,873,177		21.3	%
Commercial and Industrial		4,403,403		51.2	%		4,512,825		51.2	%		4,356,878		49.5	%
Total Retail		8,560,208		99.6	%		8,775,132		99.6	%		8,710,736		99.0	%

Wholesale		15,577		.2	%		14,581		0.2	%		69,757		0.8	%
Streetlights		16,108		.2	%		15,943		0.2	%		15,502		0.2	%
TOTAL		8,591,893		100.0	%		8,805,656		100.0	%		8,795,995		100.0	%

Total retail MWh sales decreased approximately 2.4% in 2008 from 2007, primarily due to a decrease in customer usage as a result of cooler summer weather and, to a lesser extent, changes in customer usage patterns. Also contributing to the decrease in MWhs is the transition of certain customers to DOS as discussed below.

Mining is a leading industry in Northern Nevada and comprises one of SPPC’s largest classes of customers. According to the Nevada Mining Association, spot gold price levels, coupled with Nevada’s reasonable regulatory environment, the state’s favorable geology for gold deposits, and the industry’s success in controlling its costs and attracting a high quality labor force offer a strong foundation for investment in continued mine development and the industry’s continuing high level of energy usage. However, SPPC has seen a decline in mining MWhs as a result of certain customers transferring to DOS.

SPPC has long-term electric service agreements with nine of its largest major account commercial and industrial customers, with yearly revenues under these agreements totaling approximately $104 million. For 2008, this represented approximately 10% of SPPC’s electric operating revenues of $1.0 billion. Such 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. Commercial customers who receive approval from the PUCN to acquire electric energy, capacity, and ancillary services from another provider, and who may have previously received service from SPPC under terms of a long-term service agreement, will migrate to being served under the provisions of a DOS Agreement. Under a DOS Agreement, customer-specific facilities charges will continue to be collected along with a flat distribution charge per meter.

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Demand

Load and Resources Forecast

SPPC’s integrated peak electric demand decreased from 1,743 MW in 2007 to 1,648 MW in 2008. Variations in energy usage occur as a result of varying weather conditions, economic conditions and other energy usage behaviors, such as conservation efforts. 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. Remaining needs will be met through power purchased through RFPs or short term purchases. See the Generations section and Purchased Power section below for details of SPPC’s generation and contracts for purchased power.

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):

	Forecasted Electric Capacity
	Requirements and Resources (MW)

	2009		2010		2011		2012		2013

Total requirements (1)		1,858		1,863		1,873		1,901		1,921

Resources:
Company-owned existing generation		1,577		1,577		1,577		1,567		1,567
Contracts for power purchases		320		449		449		449		297
Total resources		1,897		2,026		2,026		2,016		1,864

Total additional required (2)		-		-		-		-		57

(1)	Includes system peak load plus planning reserves.

(2)	Total additional required represents the difference between the total requirements and total resources. Total additional required represents the amount needed to achieve the forecasted system peak plus a planning reserve margin.

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 generation from the wholesale markets subjects power prices to price volatilities due to available supply and gas prices.

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.

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Total System

SPPC manages a portfolio of energy supply options. The availability of alternate resources allows SPPC to dispatch its electric generation system in a more cost-effective manner under varying operating and fuel market conditions while maintaining system integrity. During 2008, SPPC generated 50.5% of its total electric energy requirements, purchasing the remaining 49.5% as shown below.

	2008					2007					2006
	MWh		% of Total			MWh		% of Total			MWh		% of Total
SPPC Company Generation
Gas/Oil		2,819,767		30.7	%		2,282,636		24.3	%		2,167,898		23.2	%
Coal		1,812,918		19.8	%		1,705,789		18.1	%		1,848,591		19.8	%
Hydro		-		N/A			43,577		0.5	%		-		N/A
Total Generated		4,632,685		50.5	%		4,032,002		42.9	%		4,016,489		43.0	%

Total Purchased		4,547,062		49.5	%		5,376,364		57.1	%		5,334,341		57.0	%

Total System		9,179,747		100.0	%		9,408,366		100.0	%		9,350,830		100.0	%

As a supplement to its own generation, SPPC purchases spot, short-term firm, intermediate-term firm, long-term firm, and non-firm energy to meet its customer demand requirements. Total energy supply includes purchases from outside the electric system due to limited control area generation and also the need to access market energy supplies. SPPC’s decision to purchase this energy is based on economics, mitigation of availability risk, and system import limits. Firm block purchases are transacted as both a price hedging strategy and to ensure that needed firm capacity is available over peak load periods. Spot market energy is purchased based on the economics of purchasing “as-available” energy when it is less expensive than SPPC’s own generation, again, subject to net system import limits. SPPC’s 2008 company generation increased 14.9% compared to 2007. SPPC’s 2008 purchased power total MWhs decreased 15.4% compared to 2007 due to SPPC’s increased reliance on self generation and a decrease in total demand. 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 35 gas, oil and coal generating units with a combined summer capacity of 1,577 MWs as described in Item 2, Properties. In 2008, SPPC generated approximately 50.5% of its total system requirements.

In 2008, SPPC completed construction of a 541 MW (nominally rated) natural gas combined cycle facility at the existing Tracy Generating Station. The units became operational in the summer of 2008.

Fuel Availability

SPPC’s 2008 fuel requirements for electric generation were provided by natural gas, coal, and oil. The average costs of gas, coal and oil for energy generation per MMBTU for the years 2004-2008, along with the percentage contribution to SPPC’s total fuel requirements, were as follows:

	Average Consumption Cost & Percentage Contribution to Total Fuel

	Gas		Coal		Oil
	$/MMBTU	Percent	$/MMBTU	Percent	$/MMBTU	Percent
2008	8.95	57.5%	2.09	42.4%	20.90	0.2%
2007	8.34	57.8%	1.93	42.0%	12.10	0.2%
2006	8.92	55.9%	1.83	43.9%	10.15	0.3%
2005	7.87	56.8%	1.67	43.1%	7.37	0.1%
2004	7.32	53.1%	1.39	44.9%	6.14	2.0%

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.

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Natural gas supplies are procured one season ahead of use through a competitive bidding process. The physical gas prices are set at an appropriate industry index during the month of current delivery. All natural gas is delivered to SPPC through the use of firm gas transport contracts. Monthly and daily gas supply adjustments are made by gas trading personnel based on the current energy marketplace, and operational considerations.

SPPC utilizes a laddered strategy with respect to coal supply and has long-term coal contracts with Black Butte Coal Company and Arch Coal Sales Company that provide for deliveries through December 31, 2009 and December 31, 2011 respectively. These contracts represent 100% of the Valmy Generating Station’s projected coal requirements in 2009, and 78% for 2010, and 57% for 2011.

Union Pacific Railroad originates and delivers coal to the Valmy Generating Station. An extension to the transportation services contract is in place that expires December 31, 2009. Currently, SPPC is negotiating a new contract and does not expect any disruption to service.

As of December 31, 2008, Valmy Generating Station’s coal inventory level was 173,257 tons or approximately 60 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. Diesel inventory levels are kept at about five days full load operation supply since the diesel supply can be procured at various petroleum product terminals in and around the Reno-Sparks area.

Purchased Power

SPPC, under the guidelines set forth in the SPPC ESP, 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 2008, SPPC purchased 49.5% 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) generated by coal, gas and renewable resource facilities, with a total MW capacity of 470 and contract termination dates ranging from 2009 to 2039. Included in these contracts are 192 MWs of capacity of renewable energy.

As a result of SPPC’s improved credit quality during 2008, SPPC was able to eliminate pre-payments to counterparties for fuel; and reduce the number of counterparties requiring modified payment terms from the previous year.

SPPC is a member of the NWPP and WSPP. These pools have provided SPPC further access to reserves and spot market power, respectively, in the Pacific Northwest and Southwest. In turn, SPPC’s generation facilities provide a backup source for other pool members who rely heavily on hydroelectric systems. SPPC’s credit standing may affect the terms under which SPPC is able to purchase fuel and electricity in the western energy markets; however, as a result of SPPC’s credit quality, this was not a significant factor in 2008.

Transmission

SPPC’s electric transmission system is part of the Western Interconnection, the regional grid in the west. The Western Interconnection includes the interconnected transmission systems of fourteen western states, two Canadian provinces and the parts of Mexico that make up the WECC. WECC is one of eight regional councils of the NERC, 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 Balancing Authority 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 Utilities have proposed the EN-ti line which will link NPC’s and SPPC’s transmission system in the southern and northern portions of the state, allowing for the transfer of energy, including renewable resources between the Utilities. The map below shows SPPC’s transmission system and proposed EN-ti line:

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Under the NERC guidelines, SPPC is a Balancing Authority, a Transmission Operator, and a Transmission Owner among other roles. As defined by NERC, the Balancing Authority integrates resource plans ahead of time, maintains load-interchange-generation balance within a Balancing Authority Area, and supports Interconnection frequency in real time (i.e., the Balancing Authority is responsible for assuring that the demands on the system are matched by an equivalent amount of resources, whether from generators within its area or from imports). The Transmission Operator is responsible for the reliability of its local transmission system, and operates or directs the operations of the transmission facilities. The Transmission Owner owns and maintains transmission facilities. SPPC schedules power deliveries over its transmission system and maintains reliability through its operations and maintenance practices and by verifying that customers are matching loads with resources.

SPPC plans, builds and operates a transmission system that delivered 8,591,893 MWh of electricity to customers in its Balancing Authority Area in 2008. The SPPC system handled a peak load of 1,648 MW in 2008 through 2,137 line miles of transmission lines and other facilities ranging from 60 kV to 345 kV. 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 growing system.

In the last 10 years, due primarily to high customer growth, SPPC has constructed major high voltage transmission projects. The projects completed include the Alturas Line (167 miles) and the Falcon – Gonder Line (180 miles) among others which increased SPPC’s import capabilities.

Transmission Regulatory Environment

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

·	Long-term and short-term firm point-to-point transmission service (“highest quality” 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).

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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 energy marketing business in accordance with FERC Standards of Conduct.

SPPC is a member of WestConnect and the WestConnect Subregional Transmission Planning Committee. 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 2007 and 2008 the WestConnect members worked collaboratively to develop consistent responses to FERC Order 890 requirements and developed regional business practices including OATT Attachment K, Transmission Planning Process. The Subregional Transmission Planning Committee was established to provide coordinated transmission planning across the WestConnect footprint, including the Southwest Area Transmission Group that NPC participates in and the Sierra Nevada Planning Group that SPPC participates in.

SPPC Gas

Business and Competitive Environment

Overview

SPPC provides natural gas service to approximately 149,000 customers in an area of about 800 square miles in Nevada’s Reno/Sparks area. SPPC also procures natural gas for electric power generation at the Tracy and Fort Churchill Generating Stations east of Reno.

Gas Operations

SPPC is charged with meeting the growing energy needs of the residential population and expanding business and public sectors. In addition to customer growth and demand, resulting revenues are impacted by rate changes, seasonal or atypical weather and customer use. Gas demand and revenues are very seasonal for SPPC Gas. Average daily temperatures range from 72 to 34 degrees Fahrenheit and the average high temperature to low temperature range from 91 to 21 degrees Fahrenheit. This wide temperature swing causes gas volumes to vary substantially depending on the weather.

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 continue to be 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 only fuel source.

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: the Paiute Pipeline Company and the TGTC. 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 Report as well as a Gas Informational Report to be filed annually. Natural gas commodity costs are passed directly through to customers on a dollar for dollar basis. SPPC may also file GRCs 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 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 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, 2009, there were 14 large customers securing their own supplies. These customers have a combined firm distribution load of approximately 5,639 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.

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Sales

SPPC’s natural gas business accounted for $210.0 million in 2008 operating revenues or 17.3% of SPPC’s total revenues from continuing operations.

Demand

Growth in all sectors is expected to continue, although at a much slower pace due to a general slow down in real estate development activity experienced in 2008 and expected to continue into 2009. Projected peak demand, which will only occur when the calculated average of the high and low temperatures for a given day drops to negative 5 degrees Fahrenheit, is estimated to be 198,691 Dth per day for the winter of 2008/2009.

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. In 2008 seasonal and monthly gas supply net purchases averaged approximately 125,975 Dth per day with the winter period contracts averaging approximately 141,961 Dth per day, and the summer period contracts averaging approximately 114,620 Dth per day.

SPPC’s firm natural gas supply is supplemented with natural gas storage services and supplies from the Northwest Pipeline Co. facility located at Jackson Prairie in southern Washington. The Jackson Prairie facility can contribute up to a total of 12,687 Dth per day of peaking supplies. SPPC also has storage on the Paiute Pipeline system. This liquefied gas storage facility 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, 2008:

Firm Transportation Capacity	Dth per day firm	Term

Northwest	68,696	(Annual)
Paiute	68,696	(November through March)
Paiute	61,044	(April through October)
Paiute	23,000	(LNG tank to Reno/Sparks)
Nova	130,217	(Annual)
ANG	128,932	(Annual)
GTN	140,169	(November through April)
GTN	79,899	(May through October)
Tuscarora	172,823	(Annual)

Storage Capacity

Williams:	281,242	Inventory capability at Jackson Prairie
	12,687	Withdrawal capability per day from Jackson Prairie
Paiute:	303,604	Inventory capability at Paiute LNG
	23,000	LNG Storage

Total LDC Dth supply requirements in 2008 and 2007 were 15.1 million Dth and 15.4 million Dth, respectively. Electric generating fuel requirements for 2008 and 2007 were 31.0 million Dth and 25.0 million Dth, respectively.

Gas Distribution

As of December 31, 2008, SPPC owned and operated 1,964 miles of three-inch equivalent natural gas distribution piping. SPPC constructed a combined total of 3,237 feet of new 18 inch steel gas main in 2008 to support system growth. In addition, and as part of its on going main and service replacement program, SPPC replaced approximately 18,213 feet of gas main of various sizes and approximately 256 service pipes that lead from the gas main to the individual meters in 2008.

SPPC Electric and Gas

Integrated Resource Plan

SPPC files an IRP every three years. The IRP is prepared in compliance with Nevada laws and regulations and covers a 20 year period. The IRP develops a comprehensive, integrated plan that considers customer energy requirements and proposes the resources to meet those requirements in a manner that is consistent with prevailing market fundamentals. The ultimate goal of the IRP is to balance the objectives of minimizing costs and reducing volatility while reliably meeting the electric needs of SPPC’s customers.

In June 2007, SPPC filed its 2007 triennial IRP with the PUCN and has since filed several amendments to the IRP. The following are the key elements of the filing as amended:

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·	The PUCN granted the Utilities’ initial request in its IRP filing to proceed with the development of Phase I of the EEC and accompanying transmission line. The PUCN also approved the Utilities’ request of $300 million for development activities associated with the EEC with a limitation of $155 million placed on expenditures until the Utilities have obtained the final air permit. The PUCN approved the request to initially allocate the costs between NPC and SPPC using an 80/20 cost allocation, respectively. Furthermore, the PUCN granted the Utilities’ requests for critical facility designation, thereby allowing it to qualify for incentives to be determined at a later date. Since then, the Utilities filed amendments in regards to EEC and the PUCN, in its order, outlined certain minimum information regarding the EEC that shall be provided by SPPC’s amendment to its 2007 IRP to be filed in conjunction with NPC’s 2009 IRP filing, including but not limited to an update of the engineering, construction and then current cost estimates of the EEC, a refined project schedule, an initial analysis of the benefits of joint system analysis, a update of environmental costs and economic benefits attributed to the EEC and an update on the status of all the required permits. Additionally, the limitation on expenditures was reduced to $130 million. However, on February 9, 2009, NVE and the Utilities announced their intention to postpone their plan to construct the EEC due to increasing environmental and economic uncertainties until such time as carbon sequestration becomes commercially viable, which is not expected for at least a decade. The Utilities have spent approximately $71.1 million as of December 31, 2008 towards the development of the EEC, including costs associated with the EN-ti line.

·	The PUCN approved expenditures of $16.5 million on the replacement of the diesel units in Kings Beach, California.

Construction Program

SPPC’s construction program and estimated expenditures are subject to continuing review and are periodically 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, regulatory considerations and impact to customers. 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.

Gross construction expenditures for 2008, including AFUDC and CIAC, were $221 million, and for the period 2004 through 2008, were $1.2 billion. Estimated construction expenditures for PUCN approved projects, projects under construction, compliance projects and base capital requirements, are as follows (dollars in thousands):

	2009			2010-2013	Total 5 - Year
Electric Facilities:
Generation	$	29,102	$	110,031	$	139,133
Distribution		63,142		259,266		322,408
Transmission		68,634		289,723		358,357
Other		31,271		53,934		85,205
TOTAL		192,149		712,954		905,103

Gas Facilities:
Distribution		13,469		63,097		76,566
Other		180		2,461		2,641
TOTAL		13,649		65,558		79,207

Common Facilities		13,028		49,453		62,481

TOTAL	$	218,826	$	827,965	$	1,046,791

Total estimated cash requirements related to construction projects consist of the following (dollars in thousands):

	2009				2010-2013		Total 5 - Year

Construction Expenditures	$	218,826		$	827,965		$	1,046,791
AFUDC		(8,520	)		(59,204	)		(67,724	)
Net Salvage/ Cost of Removal		(1,647	)		(6,631	)		(8,278	)
Net Customer Advances and CIAC		(19,376	)		(77,517	)		(96,893	)

Total Cash Requirements	$	189,283		$	684,613		$	873,896

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OTHER SUBSIDIARIES OF NV ENERGY, INC.

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. Currently, management is assessing various business opportunities in regards to the remaining Long Haul System. In 2008, SPC recorded an impairment of the Long Haul System of approximately $3.8 million, net of taxes. As of December 31, 2008, SPC’s recorded asset value for the Long Haul System is approximately $4.1 million. SPC does not otherwise contribute significantly to the results of operations of NVE.

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 NVE'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 NVE.

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 (NVE, 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 EPA, NDEP and Clark County Department of Air Quality and Environmental Management administer regulations involving air quality, water pollution, solid, and hazardous and toxic waste. The most significant environmental laws and regulations affecting NPC and SPPC include:

Federal Environmental Laws and Regulations

·	Clean Air Standards

The Clean Air Act provides a framework for protecting and improving the nation’s air quality and controlling mobile and stationary sources of air emissions. The 1990 amendments to the Clean Air Act impose limitations on the emissions of sulfur dioxide (SO2), nitrogen oxide (NOx) as well as other pollutants. All of the utilities' fossil fuel generating stations are subject to these limitations and are in compliance with current standards. 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 could require reductions in emissions of nitrogen oxides, sulfur dioxide, mercury and/or other pollutants.

The Clean Air Act programs, which most directly affect NVE’s electric generating facilities, are described below.

Regulated Air Pollutants

The federal Clean Air Mercury Rule (CAMR) was based on a national cap-and-trade system which was designed to achieve a 70 percent reduction in mercury emissions. It affected all coal and oil-fired generating units across the country greater than 25 MWs. Compliance with this rule was to have occurred in two phases, with the first phase beginning in 2010 and the second phase in 2018. Under this Federal program, states would have been allocated mercury allowances based on coal type and their baseline heat input relative to other states. Each electric generating unit would have been 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.

On February 8, 2008, in State of New Jersey v. EPA, the US Court of Appeals for the District of Columbia Circuit vacated two EPA rules issued under the Clean Air Act regarding the emission of hazardous air pollutants ("HAPs") from electric utility steam generating units ("EGUs"), including the CAMR as well as a rule delisting EGUs from HAPs requirements. EPA and industry groups each filed separate petitions for certiorari with the U.S. Supreme Court on Oct. 17, 2008 asking the Court to hear their appeal. On January 7, 2009, EPA issued a memo to regional administrators regarding the application of Clean Air Act Section 112(g) (case by case MACT) to Coal and Oil-fired Generating Units that began actual construction or reconstruction between March 29, 2005 and March 14, 2008. Then, on January 29, 2009, the EPA requested that the Department of Justice withdraw the Petition for Writ of Certiorari in the State of New Jersey case, stating in part that EPA intends to develop emission standard for utility units under section 112 of the Clean Air Act and thus to abide by the D.C. Circuit’s decision in this case. Based on this development, it appears that EPA will work to propose a new maximum achievable control technology ("MACT") standard for mercury emissions. The State of Nevada is also making a determination of whether or not to proceed with a new State Mercury rule. While the final outcome and timing for EPA's and/or the State’s actions cannot be estimated at this point, the Utilities will continue to monitor this issue and assess its potential impact on our generation fleet as new information becomes available.

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Regional Haze Rules

In June 2005, the EPA finalized amendments to the July 1999 regional haze rules; thereby requiring states to develop implementation plans to demonstrate compliance. 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. 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. In 2008, the State of Nevada began its BART rule development with an expected rollout occurring in early 2009, and NVE has been actively involved in the stakeholder process. The impacted BART units are Reid Gardner Generating Station Units 1, 2 & 3; Ft. Churchill Generating Station Units 1 & 2; and Tracy Generating Station Units 1, 2 & 3. The draft Nevada BART regulation contains targeted emission rates and compliance with the state’s BART program can be achieved through options such as retrofit of emission reduction equipment on the affected units or unit retirement. Due to the uncertainties of technology requirements necessary to meet the target emission rates, implementation timing and the economic profile of the impacted units at the projected time of implementation, NVE is not able to estimate the cost impact to its system at this time.

·	Clean Water Act Standards

The EPA administers rules establishing aquatic protection requirements for power generation facilities that withdraw and discharge large quantities of water from and into rivers, streams, lakes, reservoirs, estuaries, oceans, or other U.S. waters for cooling purposes. In consideration of the desert environment in which the Utilities operate, none of the Utilities’ generation plants employ cooling water intake structures into public water bodies. Further, all of the Utilities’ generation stations are designed to have either minimal or zero water discharge into the surrounding environment. Therefore, the various laws regulating cooling water intake structures and thermal discharges of wastewater from power generation facilities do not specifically apply to the NPC and SPPC generation sites.

·	Remediation Activities

Due to the age and/or historical usage of past and present operating properties, the Utilities may be responsible for various levels of environmental remediation at contaminated sites. This can include properties that are part of ongoing Utility operations, sites formerly owned or used by NVE or the Utilities, and/or sites owned by third parties. The responsibility to remediate typically involves management of contaminated soils and may involve groundwater remediation. Managed in conjunction with relevant federal, state and local agencies, activities vary with site conditions and locations, remedial requirements, complexity and sharing of responsibility. If remediation activities involve statutory joint and several liability provisions, strict liability, or cost recovery or contribution actions, NVE, the Utilities or their respective affiliates could potentially be held responsible for contamination caused by other parties. In some instances, NVE or the Utilities may share liability associated with contamination with other potentially responsible parties, and may also benefit from insurance policies or contractual indemnities that cover some or all cleanup costs. These types of sites/situations are generally managed in the normal course of business operations.

Federal Legislative and Regulatory Initiatives

·	Climate Change

The topic of climate change continues to evolve, and response to this issue brings with it significant environmental, economic and social implications for NVE and other electric utilities. The United States currently has no regulations addressing 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.

In July 2008, the Federal EPA issued an advance notice of proposed rulemaking (ANPR) that requested comments on a wide variety of issues the agency is considering in formulating its response to the U.S. Supreme Court’s decision in Massachusetts v. EPA. In that case, the court determined that CO2 is an “air pollutant” and that the Federal EPA has authority to regulate mobile sources of CO2 emissions under the Clean Air Act if appropriate findings are made. The Federal EPA has identified a number of issues that could affect stationary sources, such as electric generating plants, if the necessary findings are made for mobile sources, including the potential regulation of CO2 emissions for both new and existing stationary sources under the NSR programs of the CAA. As well, additional legislative measures to address CO2 and other green house gases have been introduced in Congress, and such legislative actions as well as any new programs introduced by the new Administration could impact our business. However, at this time we cannot predict the timing or economic impact.

NVE has and will continue to identify projects that minimize or offset greenhouse gas emissions and believes precautionary actions to limit greenhouse gas emissions are appropriate. In 2006, NVE joined the California Climate Action Registry (CCAR) and voluntarily committed to commence an annual inventory, certify and publicly report on greenhouse gas emissions from NPC and SPPC through this organization. In 2008, NVE became a founding member of The Climate Registry which is a national organization. At the close of 2008, NVE submitted its second year of verified emissions to the CCAR.

·	Water Supply

Assured supplies of water are important for the Utilities’ generating plants, and at the present time, the Utilities have adequate water to meet their generation needs. Reliable water supply is critical to the entire desert southwest region, including the State of Nevada. The newer generation facilities in the Utilities’ fleet have been designed to minimize water usage and employ innovative conservation based technologies such as dry cooling. Water resources for most of these facilities rely on regional aquifers that are not closely connected to transient drought conditions. In the event that significant drought conditions were to occur, the Utilities would work with its water suppliers, regulators, and other stakeholders to implement agreements to minimize the effect on its operations.

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Every generation alternative – whether fossil fuels, nuclear, or renewable power options– has environmental and financial impacts. NVE recognizes these impacts and closely links its business objective of generating reliable, cost-effective energy with its environmental responsibilities.

NVE’s environmental philosophy accentuates prudent use of natural resources and to that end, NVE 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. NVE’s new natural gas-fired generating plants require the combustion of far less fuel than older facilities to produce each kWh of electrical output. As new generation is added to the system, NVE is concurrently evaluating and eliminating older, less efficient units from its fleet.

Maintenance of robust DSM 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. NVE is currently participating with the Electric Power Research Institute (EPRI) to evaluate technologies potentially suitable for carbon capture.

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 NVE sells must come from renewable sources, reaching 20 percent by 2015. Refer to Purchase and Development of Renewable Resources earlier in this section.

GENERAL – EMPLOYEES (ALL)

NVE and its subsidiaries had 3,330 employees as of January 26, 2009, of which 1,901 were employed by NPC and 1,309 were employed by SPPC.

NPC’s amendment to its existing contract with the IBEW Local No. 396, which covers approximately 56% of NPC’s workforce, was ratified by the IBEW Local No. 396 on September 29, 2008. The contract will be in effect through February 1, 2011.

SPPC’s current contract with the IBEW Local No. 1245, which covers approximately 62% of SPPC’s workforce, was renegotiated and ratified in February 28, 2007 and is in effect until December 31, 2009.

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 2008 the Utilities collected $129.5 million in franchise or other fees based on gross revenues. They collected $10.0 million in UEC based on consumption. They also paid and recorded as expense $2.9 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 generation and transmission facilities. In addition, the Utilities require liquidity to bridge the cost of fuel and purchased power and other operating activities until recovered through rates. If we are unable to finance such construction or limit the amount of capital expenditures associated with those facilities to forecasted levels, finance or generate sufficient liquidity for fuel and purchased power including, risk management activities, and/or recover amounts spent on construction, fuel and purchased power and other operating activities through future filings with the PUCN, and/or maintain our credit ratings, our financial condition and results of operation could be adversely affected.

Our long term business objectives include plans to construct new generation and transmission facilities. We do not currently generate sufficient cash flow to fund the construction plan. Significant construction capital requirements and liquidity to bridge the cost of fuel and purchased power and other operating activities, until recovered through rates, require 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 NVE. See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Liquidity and Capital Resources, NVE. We cannot be sure that we will be able to obtain financing on favorable terms, or at all, depending on financial market conditions, including the effect of recent volatility in financial and credit markets, changes in availability and cost of capital either due to market conditions or as a result of the Utilities’ credit ratings, or interest rate fluctuations. 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, timing delays and other economic factors. If we cannot obtain favorable financing arrangements for our planned capital expenditures, limit such capital expenditures to forecasted amounts, finance or generate sufficient liquidity for fuel and purchased, including risk management activities and other operating costs, and/or recover or timely recover amounts spent on construction, fuel and purchased power and other operating activities through future filings with the PUCN, and/or maintain our credit ratings, our financial condition and results of operations could be adversely affected.

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If the Utilities do not receive favorable rulings in their future GRCs, 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 change as a result of regulatory proceedings known as GRCs, which the Utilities file with the PUCN approximately every three years. In the Utilities’ GRCs, the PUCN establishes, among other things, their recoverable rate base, their ROE, overall ROR, depreciation rates and their cost of capital.

For a discussion of NPC’s and SPPC’s recent GRCs, see Note 3, Regulatory Actions of the Notes to Financial Statements.

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

Economic conditions could negatively impact our business.

Our operations are affected by local, national and global economic conditions. Moreover, the growth of our business depends in part on continued customer growth and tourism demand in the Las Vegas portion of our service area. The consequences of a prolonged recession may include a lower level of economic activity and uncertainty regarding energy prices and the capital and commodity markets, including availability and cost of credit, inflation rates, monetary policy and unemployment rates. A lower level of economic activity, changes in discretionary spending and decreased tourism activity in Las Vegas might result in a decline in energy consumption, which may adversely affect our revenues and future growth. Instability in the financial markets, as a result of recession or otherwise, also may affect the cost of capital and our ability to raise capital, which are discussed in greater detail in “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources".

Current economic conditions may be exacerbated by insufficient financial sector liquidity leading to potential increased unemployment, which may impact customers’ ability to pay on a timely basis, increase customer bankruptcies, and lead to increased bad debt. It is expected that commercial and industrial customers will be impacted first with residential customers following, if such circumstances occur.

Adverse investment returns on pension plan assets and other factors may increase NVE’s pension liability and pension funding requirements.

Substantially all of NVE employees are covered by a defined benefit pension plan. At present, the pension plan is underfunded in that the projected pension benefit obligation exceeds the aggregate fair value of plan assets. The funded status of the plan can be affected by investment returns on plan assets, discount rates, mortality rates of plan participants, pension reform legislation and a number of other factors. There can be no assurance that the value of NVE’s pension plan assets will be sufficient to cover future liabilities. Although NVE has made significant contributions to its pension plan in recent years, it is possible that NVE could incur a significant pension liability adjustment, or could be required to make significant additional cash contributions to its plan, which would reduce the cash available for operating activities, and have a material impact on earnings. Refer to Note 11, Retirement Plan and Post-Retirement Benefits of the Notes to Financial Statements.

If Federal and/or State requirements are imposed on the Utilities mandating further emission reductions, including limitations on carbon dioxide (CO2) emissions, such requirements could make some electric generating units, uneconomical to 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. Certain Congressional leaders, environmental advocacy groups and regulatory agencies in the United States have also been focusing considerable attention on carbon dioxide (CO2) emissions from power generation facilities and their potential role in climate change. Moreover, there are many legislative and rulemaking initiatives pending at the federal and state level that are aimed at the reduction of greenhouse gas emissions. We cannot predict the outcome of pending or future legislative and rulemaking proposals. Future changes in environmental laws or regulations governing emissions reductions could make certain electric generating units, especially those utilizing coal for fuel, uneconomical to construct, maintain or operate or could require design changes or the adoption of new technologies that could significantly increase costs or delay in-service dates. In addition, any legal obligation that would require the Utilities to substantially reduce their 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, expose us to environmental liabilities, or make some electric generating units uneconomical to maintain or operate.

The Utilities are subject to extensive federal, state and local laws 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 or mercury emissions), water quality and other toxic pollutants may be revised or new climate change laws or regulations may be adopted or become applicable to us. Revised or additional laws or regulations, which may result in increased compliance costs, including the adoption of new technologies 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.

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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 delayed, halted or subjected to additional costs.

The Utilities are subject to fuel and wholesale electricity pricing risks, which could result in unanticipated liabilities and cash flow requirements or increased volatility in our earnings, and to related credit and liquidity risks.

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;

·	further concentration of gas as a source if the Utilities cannot diversify into coal;

·	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 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 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. In the event the Utilities’ credit ratings are downgraded below investment grade, the maximum amount of collateral the Utilities would be required to post is approximately $327.0 million. Refer to Management’s Discussion and Analysis, Factors Affecting Liquidity for NPC and SPPC.

As of February 20, 2009, NPC had approximately $289.7 million available under its $690 million revolving credit facilities and SPPC has approximately $110.6 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.

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If the Utilities 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.

Under Nevada law, purchased power, natural gas and fuel costs in excess of those included in base rates are deferred as an asset on the Utilities’ balance sheets and are not shown as an expense until recovered from their retail customers. The Utilities are required to file DEAA applications with the PUCN at least once every twelve months so that the PUCN may verify the prudence of the energy costs. 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, which resulted in ratings downgrades of our debt securities and adversely affected our liquidity and access to capital markets.

For a discussion of NPC’s and SPPC’s recent and pending deferred energy rate cases, see Note 3, Regulatory Actions of the Notes to Financial Statements.

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

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 NVE is precluded from receiving dividends from the Utilities, its financial condition, and its ability to meet its debt service obligations, pay dividends and make capital contributions to its subsidiaries, will be materially adversely affected.

Since NVE is a holding company, substantially all of its cash flow is provided by dividends paid to NVE by NPC and SPPC on their common stock, all of which is owned by NVE. Since NPC and SPPC are public utilities, they are subject to regulation by state utility commissions, which impose limits on investment returns or otherwise impact the amount of dividends that the Utilities may declare and pay.

In addition, certain agreements entered into by the Utilities set restrictions on the amount of dividends they may declare and pay and restrict the circumstances under which such dividends may be declared and paid. As a result of the Utilities’ credit rating on their senior secured debt at investment grade by S&P and Moody’s, these restrictions are suspended and no longer in effect so long as the debt remains investment grade by both rating agencies. In addition to the restrictions imposed by specific agreements, the Federal Power Act prohibits the payment of dividends from “capital accounts.” Although the meaning of this provision is unclear, the Utilities believe that the Federal Power Act restriction, as applied to their particular circumstances, would not be construed or applied by the FERC to prohibit the payment of dividends for lawful and legitimate business purposes from current year earnings, or in the absence of current year earnings, from other/additional paid-in capital accounts. If, however, the FERC were to interpret this provision differently, the ability of the Utilities to pay dividends to NVE could be jeopardized.

We cannot assure investors that future dividend payments on our Common Stock will be made or, if made, in what amounts they may be paid.

On July 28, 2007, NVE’s BOD declared a quarterly cash dividend of $0.08 per share of Common Stock, payable on September 12, 2007. This dividend was the first declared by the BOD since February 2002. Dividends are considered periodically by NVE’s BOD and are subject to factors that ordinarily affect dividend policy, such as current and prospective financial condition, earnings and liquidity, prospective business conditions, regulatory factors, and dividend restrictions in NVE’s and the Utilities’ financing agreements. The BOD will continue to review these factors on a periodic basis to determine if and when it would be prudent to declare a dividend on NVE’s Common Stock. Since the dividend on July 28, 2007 was declared, NVE’s BOD has declared in each of the successive quarters cash dividends; however, there is no guarantee that dividends will be paid in the future, or that, if paid, the dividends will be paid in the same amount or with the same frequency as in the past.

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

Because NVE 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. NVE conducts substantially all of its operations through its subsidiaries, and thus NVE’s ability to meet its obligations under its indebtedness and to pay any dividends on its common stock 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 NVE. As of December 31, 2008, the Utilities had approximately $4.8 billion of debt outstanding. The terms of NVE’s indebtedness restrict the amount of additional indebtedness that NVE and the Utilities may issue. Based on NVE’s December 31, 2008 financial statements, assuming an interest rate of 7%, NVE’s indebtedness restrictions would allow NVE and the Utilities to issue up to approximately $862 million of additional indebtedness in the aggregate, unless the indebtedness being issued is specifically permitted under the terms of NVE’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.

If the Utilities cannot maintain the required level of renewable energy or procure sufficient solar energy to meet Nevada’s increasing Portfolio Standard the PUCN may, among other things, impose an administrative fine for noncompliance.

Nevada law sets forth the Portfolio Standard requiring providers of electric service to acquire, generate, or save from renewable energy systems or energy efficiency measures a specific percentage of its total retail energy sales from renewable energy sources, including biomass, geothermal, solar, waterpower and wind projects. The Portfolio Standard requires the energy acquired from a renewable energy system be transmitted or distributed via a power line which is connected to a facility or system, owned, operated or controlled by the Utilities. Other restrictions are placed on energy acquired from energy efficiency measures which may not exceed more than 25 percent of the Portfolio Standard and half of those savings must come from residential customers.

In years 2008 and 2009, the Portfolio Standard requires that nine percent and 12%, respectively of total retail energy sales come from renewable energy as measured by PEC's. The Portfolio Standard increases by 3% every other year until it reaches 20% in 2015. Moreover, not less than 5% of the total Portfolio Standard must be met by solar resources.

Due to periodic increases in the Portfolio Standard and increasing retail sales, the Utilities must acquire increasing amounts of renewable energy. The Utilities’ success in meeting the increasing Portfolio Standard remains largely dependent on their ability to acquire additional renewable energy from either self-owned renewable generation facilities or the purchase of renewable energy from third-party developers and a decrease in demand through qualified conservation and energy efficiency measures. In 2008, with the PUCN approval of transfers of SPPC’s excess non-solar Portfolio Credit’s, both NPC and SPPC were able to comply with the non-solar Portfolio Standard. However, due to the late commercial operation of solar facilities, the Utilities did not meet the solar portion of the Portfolio Standard. As a result of the Utilities’ efforts to add solar resources, the PUCN did not fine the Utilities for non-compliance with the solar requirement. Although, historically, the Utilities have not been fined for non-compliance, the PUCN may levy fines on one or both of the Utilities; however, management cannot predict the amount if any that could be imposed.

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 are therefore 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. On February 4, 2009, the PUCN approved financing authority for NPC to issue up to $1.25 billion of long term debt securities over a two-year period ending December 31, 2010; ongoing authority to maintain a revolving credit facility of up to $1.3 billion and authority to refinance up to approximately $471 million of long term debt securities. SPPC has authority to issue up to $495 million of long term debt, which expires on December 31, 2009. However, we cannot assure you that in the future the PUCN will issue such favorable orders or that such favorable orders will be issued on a timely basis.

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, recession, war and the threat of terrorism or epidemics may harm our future growth and operating results.

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 the current recession, 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 the current recession, war, terrorism or epidemics may affect our ability to raise capital.

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ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

Substantially all of NPC’s and SPPC’s property in Nevada and California is subject to the lien of the General and Refunding Mortgage Indentures dated as of May 1, 2001, between NPC and SPPC, respectively, and The Bank of New York Mellon, as trustee, as amended and supplemented.

The following is a list of NPC’s share of electric generation plants including the type and fuel used to generate, the anticipated 2009 net capacity MW, and the years that the units were installed.

			Number of	Summer MW	Commercial Operation
Plant Name	Type	Fuel	Units	Capacity	Year
Clark Generating Station (1)	Combined Cycle	Gas/Oil	6	430	1979, 1979, 1980, 1982, 1993, 1994
	Gas	Gas/Oil	1	54	1973
	Peakers	Gas	3	619	2008
Sunrise	Steam	Gas	1	80	1964
	Gas	Gas/Oil	1	70	1974
Harry Allen Generating Station	Gas	Gas/Oil	2	142	1995, 2006
Lenzie Generating Station (2)	Combined Cycle	Gas	6	1,102	2006
Silverhawk Generating Station(3)	Combined Cycle	Gas	3	395	2004
Higgins Generating Station	Combined Cycle	Gas	3	530	2004
Mohave Generating Station (4)(5)	Steam	Coal	-	-	1971, 1971
Navajo Generating Station (6)	Steam	Coal	3	255	1974, 1975, 1976
Reid Gardner Generating Station (7)	Steam	Coal	4	325	1965, 1968, 1976, 1983
Total			33	4,002

(1) The two combined cycles at the Clark Generating Station each consist of two gas turbines, two Heat Recovery Steam Generators (HRSG), and one steam turbine. In 1993 and 1994, the original four gas turbines (1979-1982) were combined with four new HRSGs and two new steam turbines to form the combined cycles. Capacity of the Clark Peakers is derated due to low gas delivery pressure in the winter period.

(2) The two combined cycles at the Lenzie Generating Station each consist of two gas turbines, two HRSGs and one steam turbine.

(3) The acquisition of a 75% ownership interest in the Silverhawk Generating Station from Pinnacle West was consummated in 2006. SNWA continues to hold a 25% ownership interest in the plant. The combined cycle plant consists of two gas turbines, two HRSGs and one steam turbine.

(4) Per a 1999 Consent Decree, the Mohave Generating Station ceased operation on December 31, 2005. The PUCN approved establishing regulatory accounts related to the shutdown and decommissioning. See Note 1, Summary of Significant Accounting Policies, of the Notes to Financial Statements for further discussion.

(5) Prior to the shut down, the total summer net capacity of the Mohave Generating Station was 1,580 MW. Southern California Edison is the operating agent and NPC has a 14% interest in the Mohave Generating Station.

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

(7) Reid Gardner Generating Station Unit No. 4 is co-owned by the CDWR (67.8%) and NPC (32.2%); NPC is the operating agent. NPC is entitled to 25 MW of base load capacity and 232 MW of peaking capacity from that Unit, subject to the following limitations: 1,500 hours/year, 300 hours/month, and 8 hours/day. The total summer net capacity of the Unit, subject to heat input limitation, is 257 MW. Reid Gardner Generating Station Units 1, 2, and 3, subject to heat input limitations, have a combined net capacity of 300 MW. The summer capacity is 557 MW.

The following is a list of SPPC’s share of electric generation plants including the type and fuel used to generate, the anticipated 2009 net capacity MW, and the years that the units became operational.

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			Number of	Summer MW	Commercial Operation
Plant Name	Type	Fuel	Units	Capacity	Year
Ft. Churchill Generating Station	Steam	Gas/Oil	2	226	1968, 1971
Tracy Generating Station	Steam	Gas/Oil	3	244	1963, 1965, 1974
Tracy Generating Station 4&5 (1)	Combined Cycle	Gas	2	104	1996, 1996
Tracy Generating Station (2)	Combined Cycle	Gas	3	541	2008
Clark Mtn. CT's	Gas	Gas/Oil	2	132	1994, 1994
Valmy Generating Station(3)	Steam	Coal	2	261	1981, 1985
Other (4)	Gas, Diesels	Propane, Oil	21	69	1960-2008
Total			35	1,577

(1)	The combined cycle consists of one combustion turbine, one HRSG, and one steam turbine. In 2003, SPPC installed duct burners, which added 15 MW of capacity.

(2)	The new combined cycle at the Tracy Generating Station consists of 2 gas turbines, 2 HRSGs and 1 steam turbine. It became operational in the summer of 2008.

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

(4)	As of December 31, 2008 there were 3 combustion turbines and 18 diesel units included in the “Other” category.

ITEM 3.

LEGAL PROCEEDINGS

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.

In June 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. In July 2003, the Utilities filed a petition for rehearing, but the FERC reaffirmed its June decision (“July decision”). The Utilities appealed this decision to the Ninth Circuit. In December 2006, a three judge panel of the Ninth Circuit overturned the July decision and remanded the case back to the FERC for application of the factors that the Ninth Circuit outlines in its decision. In May 2007, American Electric Power Service Corporation and Allegheny Energy Supply Company and other interested parties filed petitions for certiorari (“Petitions”) with the U.S. Supreme Court seeking review of the Ninth Circuit’s decision. The Utilities, together with other parties and the FERC, filed their opposition to these Petitions in August 2007. In September 2007, the U.S. Supreme Court granted certiorari. In June 2008, the U.S. Supreme Court rejected the Ninth Circuit’s reasoning in reversing the FERC but nonetheless found that FERC’s order was defective and should be reversed for other reasons. The case was remanded to the FERC. The FERC established a formal settlement discussion protocol for bilateral settlement discussions with other respondents, including Allegheny Energy, American Electric Power and BP Energy, and stayed the case pending settlement discussions.

The Utilities already have negotiated settlements with Duke Energy Trading and Marketing, Morgan Stanley Capital Group, El Paso Merchant Energy (EPME), now known as El Paso Marketing L.P., Calpine Energy Services and Enron. Management cannot predict the timing or outcome of a decision in this matter.

Nevada Power Company

Lawsuit Against Natural Gas Providers

In April 2003, NVE (originally filed under the corporate name of SPR) and NPC filed a complaint in the U.S. District Court for the District of Nevada against several natural gas providers and traders. In July 2003, NVE and NPC filed a First Amended Complaint. A Second Amended Complaint was filed in June 2004, which named three different groups of defendants: (1) El Paso Corporation, El Paso Natural Gas Company, El Paso Merchant Energy, L.P., El Paso Merchant Energy Company, El Paso Tennessee Pipeline Company, El Paso Merchant Energy-Gas Company (“El Paso”); (2) Dynegy Marketing and Trade (“Dynegy”); and (3) Sempra Energy, Sempra Energy Trading Corporation, Southern California Gas Company, and San Diego Gas and Electric (“Sempra”). On December 13, 2005, the District Court dismissed NVE and NPC’s claims. NVE and NPC appealed this decision to the Ninth Circuit Court of Appeals. Subsequently, NVE abandoned its appeal and the matter proceeded only with respect to NPC. In September 2007, the Ninth Circuit reversed the District Court’s order. In November 2007, the Ninth Circuit denied the gas providers and traders’ petition for rehearing. The Ninth Circuit has remanded the case to the District Court for further proceedings. In January 2008, the defendants filed motions to dismiss, to which NPC responded in February 2008. In June 2008, NPC’s claims survived the defendant’s filed motions to dismiss and are now in discovery. On December 9, 2008, NPC settled with Sempra for an immaterial amount. NPC remains in litigation with El Paso and Dynegy. Management cannot predict the timing or outcome of a decision on this matter.

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Other Legal Matters

NVE 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. See Note 13, Commitments and Contingencies in the Notes to Financial Statements for further discussion of other legal matters.

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

A Special Meeting of Stockholders of NVE was held at the offices of NPC, 6226 West Sahara Avenue, Las Vegas, Nevada, on Wednesday, November 19, 2008. At the meeting, stockholders approved an amendment to the Restated Articles of Incorporation to change SPR’s name to NVE and to provide that the principal place of business shall be at such location as designated from time to time by our BOD.

At the close of business on October 6, 2008, the record date for the determination of shareholders entitled to vote at the Meeting, there were 234,149,821 shares of the Company’s Common Stock, each share being entitled to vote, constituting all of the outstanding voting securities of the Company.

At the Meeting, the holders of 210,359,050 shares of the Company’s Common Stock were represented in person or by proxy constituting a quorum approving an amendment to the Restated Articles of Incorporation to change SPR’s name to NVE as follows:

FOR AGAINST ABSTAIN

206,548,499 3,181,964 628,587

EXECUTIVE OFFICERS

The following are current executive officers of NVE, NPC and SPPC indicated and their ages as of December 31, 2008. There are no family relationships among them. Officers serve a term which extends to and expires at the annual meeting of the BOD or until a successor has been elected and qualified:

Michael W. Yackira, 57, President and Chief Executive Officer, NVE; President and Chief Executive Officer of NPC; Chief Executive Officer of SPPC

Mr. Yackira was elected in May 2007 to his current position, effective August 1, 2007. He was previously President and Chief Operating Officer from February 15, 2007 until August 1, 2007. Prior to that, he held the positions of Corporate Executive Vice President and Chief Financial Officer from October 2004 to February 15, 2007. From December 2003 to October 2004 he held the position of Executive Vice President and CFO of NVE, as well as both NPC and SPPC. Mr. Yackira was previously Executive Vice President, Strategy and Policy, from January to December 2003. Previously he was the Vice President and CFO of Mars Music, Inc. from 2001 to 2002. Prior to that, he was with Florida-based FPL Group, Inc. from 1989 to 2000. Mr. Yackira is a certified public accountant.

Jeffrey L. Ceccarelli, 54, Corporate Senior Vice President, Service Delivery & Operations, NVE; President, SPPC

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

Roberto R. Denis, 59, Corporate Senior Vice President, Energy Supply, NVE

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

Paul L. Kaleta, 53, Corporate Senior Vice President, General Counsel and Corporate Secretary, NVE

Mr. Kaleta was elected to his present position in February 2006, and holds the same position at NPC and SPPC. Previously he was General Counsel for Koch Industries, Inc. and various Koch subsidiaries from 1998 to 2005. Prior to that, he was Vice President and General Counsel of Niagara Mohawk Power Company for 8 years and, before that, in the private practice of law as an associate with Skadden, Arps, Slate, Meagher & Flom and as an associate and then equity member with Swidler Berlin, Chtd. (now Bingham McCutchen), both in Washington, D.C., for a total of 9 years.

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William D. Rogers, 48, Corporate Senior Vice President, Chief Financial Officer and Treasurer, NVE

Mr. Rogers was elected to his current position on February 15, 2007, and holds the same position at NPC and SPPC. 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 NVE, 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.

Tony F. Sanchez, III, 42, Corporate Senior Vice President, Public Policy and External Affairs, NVE

Mr. Sanchez was elected to his current position effective August 1, 2007, and holds the same position at NPC and SPPC. Prior to joining NVE, Mr. Sanchez was a partner in the Nevada based law firm of Jones Vargas. Prior to that, Mr. Sanchez served as executive assistant to Nevada’s then-Governor Bob Miller in 1999. From 1995 to 1998, he held the position of assistant General Counsel for the PUCN. From 1992 to 1995, he worked as associate legislative counsel in Washington, D.C handling energy and natural resource issues for Nevada's then-U.S. Senator Richard H. Bryan.

E. Kevin Bethel, 45, Vice President, Chief Accounting Officer, Corporate Controller, NVE

Mr. Bethel was elected as Vice President and Chief Accounting Officer of NVE on November 2, 2007, effective December 10, 2007, and holds the same position at NPC and SPPC. He was subsequently elected Corporate Controller of NVE as well as Vice President, Chief Accounting Officer, and Controller of NPC and SPPC on February 8, 2008. Prior to joining NVE, Mr. Bethel served as Assistant Controller for American Electric Power, Inc. (AEP), in Columbus, Ohio where he held management positions in accounting from 2001 to 2007. From 2000 to 2001, he held a management position with CSW Energy until they merged with AEP. Before that, he held accounting management positions with The Williams Company in 1999, Central & South West Services from 1994 to 1999 and the Public Service Company of Oklahoma from 1991 to 1994. Mr. Bethel is a certified public accountant.

Thomas R. Fair, 62, Vice President, Renewable Energy

Mr. Fair was elected to his present position in February 2009, and holds the same position at NPC and SPPC. Previously he was Executive, Renewable Energy from 2006 to 2009. Prior to that, he was Director, Environmental Services since 2004. Before that, Fair held a number of executive positions in renewables development and environmental affairs with such companies as Florida-based FPL Energy and Niagara Mohawk.

Kevin C. Geraghty, 43, Vice President Power Generation

Mr. Geraghty was elected to his present position in February, 2009, and holds the same position at NPC and SPPC. Previously, he was Executive, Generation since joining the company in June, 2008. Prior to that, he was at Allegheny Energy Supply, where he directed generation facilities and regions throughout the nation, including several years in the southwestern part of the United States.

Gary L. Lavey, 50, Vice President, Internal Audit, NVE

Mr. Lavey was elected as Vice President, Internal Audit of NVE in October, 2008, effective January 1, 2009. He reports to the Audit Committee of the BOD. Prior to joining NVE, Mr. Lavey was vice president of Risk Management for CNG Financial from 2006 to 2008. Prior to CNG, he held the position of Vice President of Global Risk Management for Cinergy Corporation from 1999 to 2006 and was President of their captive insurance company. Before that he held risk management positions at Ameren Energy Inc. and LG&E Energy Marketing Inc. Mr. Lavey is a certified public accountant and began his career with PricewaterhouseCoopers.

Mary O. Simmons, 53, Vice President, External Affairs, NVE

Ms. Simmons was elected to her current position in May 2008, and holds the same position at NPC and SPPC. From November 2004 to May 2008, she held the position of Vice President, External Affairs, SPPC. From May 2001 to November 2004, she held the position of Vice President, Rates and Regulatory Affairs, for NPC and SPPC. Previously she held the position of Controller for NVE 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 NVE since 1985.

Robert E. Stewart, 60, Vice President, Marketing, NVE

Mr. Stewart was elected to his current position in February 2008, and holds the same position at NPC and SPPC. From January 1997 to February 2008, he worked as an independent consultant in several industries, including energy services and telecommunications. He was Vice President of Marketing for Florida Power and Light from June 1991 to November 1996. Prior to that, he worked at GTE for 19 years and was Vice President of Product Management at GTE Telephone Operations from June 1989 to June 1991.

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PART II

ITEM 5.

MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES (NVE)

NVE’s Common Stock is traded on the New York Stock Exchange (symbol NVE). Dividends paid per share and high and low sale prices of the Common Stock as reported for 2008 and 2007 are as follows:

	Dividends Paid per share		2008		2007
	2008	2007	High	Low	High	Low
First Quarter	$ 0.08	$ 0.00	$ 17.03	$ 11.64	$ 18.26	$ 16.38
Second Quarter	0.08	0.00	14.26	12.60	19.60	16.87
Third Quarter	0.08	0.08	12.77	8.90	18.15	14.06
Fourth Quarter	0.10	0.08	10.01	6.90	17.76	14.89

Number of Security Holders:

Title of Class Number of Record Holders

Common Stock: $1.00 Par Value As of February 20, 2009: 15,407

Dividends are considered periodically by the BOD and are subject to factors that ordinarily affect dividend policy, such as current and prospective earnings, current and prospective business conditions, regulatory factors, NVE’s financial condition and other matters within the discretion of the BOD, as well as dividend restrictions set forth in NVE’s 8.625% Senior Notes due 2014, 7.803% Senior Notes due 2012 and 6.75% Senior Notes due 2017.

On July 28, 2007, NVE’s BOD declared a quarterly cash dividend of $0.08 per share paid on September 12, 2007, to common shareholders of record on August 24, 2007. The dividend was the first dividend declared by NVE since February 2002.

On November 1, 2007, NVE’s BOD declared a quarterly cash dividend of $0.08 per share payable on December 12, 2007, to common shareholders of record on November 19, 2007.

On February 7, 2008, NVE’s BOD declared a quarterly cash dividend of $0.08 per share payable on March 12, 2008, to common shareholders of record on February 22, 2008.

On April 28, 2008, NVE’s BOD declared a quarterly cash dividend of $0.08 per share payable on June 11, 2008, to common shareholders of record on May 23, 2008.

On August 4, 2008, NVE’s BOD declared a quarterly cash dividend of $0.08 per share payable on September 10, 2008, to common shareholders of record on August 22, 2008.

On October 30, 2008, NVE’s BOD declared a quarterly cash dividend of $0.10 per share payable on December 17, 2008, to common shareholders of record on December 2, 2008.

On February 5, 2009, NVE’s BOD declared a quarterly cash dividend of $0.10 per share payable on March 18, 2009, to common shareholders of record on March 3, 2009.

There is no guarantee that NVE will continue to pay dividends in the future, or that the dividends will be paid at the same amount or with the same frequency. See Note 8, Debt Covenant and Other Restrictions of the Notes to Financial Statements, for a description of the restrictions on NPC’s and SPPC’s ability to pay dividends to NVE and on NVE’s ability to pay dividends on its common stock.

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

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ITEM 6. SELECTED FINANCIAL DATA

See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, for a discussion of factors that may affect the future financial condition and results of operations of NVE, NPC and SPPC (Dollars in thousands, except per share amounts):

NV ENERGY, INC.

	Year ended December 31,

	2008		2007		2006(2)		2005(3)		2004(4)

Operating Revenues	$	3,528,113	$	3,600,960	$	3,355,950	$	3,030,242	$	2,824,796

Operating Income	$	475,328	$	414,567	$	488,797	$	358,678	$	333,858


Net Income Applicable to Common Stock	$	208,887	$	197,295	$	277,451	$	82,237	$	28,571

Net Income Applicable to Common Stock
Per Average Common Share - Basic and Diluted	$	0.89	$	0.89	$	1.33	$	0.44	$	0.16

Total Assets (1)	$	11,345,980	$	9,464,750	$	8,832,076	$	7,870,546	$	7,528,467

Long-Term Debt (not including current maturities)	$	5,266,982	$	4,137,864	$	4,001,542	$	3,817,122	$	4,081,281

Dividends Declared Per
Common Share	$	0.34	$	0.16	$	-	$	-	$	-

(1)	Total assets increased significantly in 2008 primarily due to an increase in plant in service as a result of NPC’s acquisition of the Higgins Generating Station, the completion of the Clark Peaking Units by NPC and the completion of the Tracy Generating Station by SPPC. Also contributing to the increase was an increase in Regulatory Assets and Regulatory Assets for Pensions.
(2)	Income for the year ended December 31, 2006 includes reinstatement of deferred energy of approximately $116.2 million net of taxes and a $40.9 million net of taxes gain on the sale of TGPC's partnership interest in TGTC.
(3)	Income for the year ended December 31, 2005 includes a charge of $35.1 million net of taxes for the inducement of debt conversion and the reversal of $13.6 million net of taxes in interest charges as a result of settlements with terminated suppliers.
(4)	Income for the year ended December 31, 2004 includes the reversal of $25.9 million net of taxes in interest expense due to the decision on the appeal of the Enron bankruptcy judgment and the write-off of $30.6 million net of taxes in disallowed plant costs at SPPC.

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NEVADA POWER COMPANY

	Year ended December 31,

	2008		2007		2006(2)		2005(3)		2004(4)

Operating Revenues	$	2,315,427	$	2,356,620	$	2,124,081	$	1,883,267	$	1,784,092

Operating Income	$	311,952	$	297,304	$	351,272	$	228,827	$	216,490

Net Income	$	151,431	$	165,694	$	224,540	$	132,734	$	104,312

Total Assets (1)	$	7,904,147	$	6,377,369	$	5,987,515	$	5,173,921	$	4,883,540

Long-Term Debt (not including current maturities)	$	3,385,106	$	2,528,141	$	2,380,139	$	2,214,063	$	2,275,690

Dividends Declared - Common Stock	$	44,000	$	25,667	$	48,917	$	35,258	$	45,373

(1)	Total assets increased significantly in 2008 primarily due to an increase in plant in service as a result of NPC’s acquisition of the Higgins Generating Station and the completion of the Clark Peaking Units by NPC. Also contributing to the increase was an increase in Regulatory Assets and Regulatory Assets for Pensions.
(2)	Income from continuing operations, for the year ended December 31, 2006 includes reinstatement of deferred energy of approximately $116.2 million net of taxes.
(3)	Income for the year ended 2005 included the reversal of $11.5 million net of taxes in interest charges as a result of settlements with terminated suppliers.
(4)	Income for the year ended December 31, 2004 included the reversal of $17.9 million net of taxes in interest expense due to the decision on the appeal of the Enron bankruptcy judgment.

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SIERRA PACIFIC POWER COMPANY

	Year ended December 31,

	2008		2007		2006		2005(2)		2004(3)

Operating Revenues	$	1,212,661	$	1,244,297	$	1,230,230	$	1,145,697	$	1,035,660

Operating Income	$	154,153	$	105,957	$	120,017	$	116,304	$	111,245

Net Income	$	90,582	$	65,667	$	57,709	$	52,074	$	18,577

Total Assets (1)	$	3,462,545	$	2,976,524	$	2,807,837	$	2,546,301	$	2,524,320

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

Long-Term Debt (not including current maturities)	$	1,395,987	$	1,084,550	$	1,070,858	$	941,804	$	994,309

Dividends Declared - Common Stock	$	233,000	$	12,833	$	24,619	$	23,933	$	-

Dividends Declared - Preferred Stock	$	-	$	-	$	975	$	3,900	$	3,900

(1)	Total assets increased significantly in 2008 primarily due to an increase in plant in service as a result of the completion of the Tracy Generating Station. Also contributing to the increase was an increase in Regulatory Assets and Regulatory Assets for Pensions.
(2)	Income for the year ended December 31, 2005 includes the reversal of $2.1 million net of taxes in interest expense as a result of settlements with terminated suppliers.
(3)	Income for the year ended December 31, 2004 was affected by the write-off of $30.6 million net of taxes in disallowed plant costs and the reversal of interest expense of $8.0 million net of taxes due to the decision on the appeal of the Enron Bankruptcy judgment and a reduction to income tax expense of $2.1 million net of taxes as a result of a flow-through adjustment for pension funding.

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ITEM 7.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Forward-Looking Statements

The information in this Form 10-K includes forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These forward-looking statements relate to anticipated financial performance, management’s plans and objectives for future operations, business prospects, outcome of regulatory proceedings, market conditions and other matters.

Words such as “anticipate,” “believe,” “estimate,” “expect,” “intend,” “plan” and “objective” and other similar expressions identify those statements that are forward-looking. These statements are based on management’s beliefs and assumptions and on information currently available to management. Actual results could differ materially from those contemplated by the forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with such statements, factors that could cause the actual results of NVE, NPC or SPPC; (NPC and SPPC are collectively referred to as the Utilities) to differ materially from those contemplated in any forward-looking statement include, among others, the following:

(1)

economic conditions both nationwide and regionally, including availability and cost of credit, inflation rates, monetary policy, unemployment rates, customer bankruptcies, weaker housing markets, a decrease in tourism, particularly in southern Nevada, and cancelled or deferred hotel construction projects, which could affect customer collections, customer demand and usage patterns;

(2)	changes in the rate of industrial, commercial and residential growth in the service territories of the Utilities, including the effect of weaker housing markets and increased unemployment, which could affect the Utilities’ ability to accurately forecast electric and gas demand;

(3)

the ability and terms upon which NVE, NPC and SPPC will be able to access the capital markets to support their requirements for working capital, including amounts necessary for construction and acquisition costs and other capital expenditures, as well as to finance deferred energy costs, particularly in the event of: continued volatility in the global credit markets, unfavorable rulings by the PUCN, untimely regulatory approval for utility financings, and/or a downgrade of the current debt ratings of NVE, NPC or SPPC;

(4)	financial market conditions, including the effect of recent volatility in financial and credit markets, changes in availability and cost of capital either due to market conditions or as a result of the Utilities’ credit ratings, or interest rate fluctuations;

(5)

unseasonable weather, drought, threat of wildfire and other natural phenomena, which could affect the Utilities’ customers’ demand for power, could seriously impact the Utilities’ ability to procure adequate supplies of fuel or purchased power and the cost of procuring such supplies, and could affect the amount of water available for electric generating plants in the Southwestern United States;

(6)	further increases in the unfunded liability or changes in actuarial assumptions, the interest rate environment and the actual return on plan assets for our pension plan, which can affect future funding obligations, costs and pension plan liabilities;

(7)

whether the Utilities will be able to continue to obtain fuel and power from their suppliers on favorable payment terms and favorable prices, particularly in the event of unanticipated power demands (for example, due to unseasonably hot weather), physical availability, sharp increases in the prices for fuel (including increases in long term transportation costs) and/or power or a ratings downgrade;

(8)

unfavorable or untimely rulings in rate or other cases filed or to be filed by the Utilities with the PUCN, including the periodic applications to recover costs for fuel and purchased power that have been recorded by the Utilities in their deferred energy accounts, and deferred natural gas costs recorded by SPPC for its gas distribution business;

(9)

construction risks, such as delays in permitting, changes in environmental laws, difficulty in securing adequate skilled labor, cost and availability of materials and equipment (including escalating costs for materials, labor and environmental compliance due to timing delays and other economic factors which may affect vendor access to capital), equipment failure, work accidents, fire or explosions, business interruptions, possible cost overruns, delay of in-service dates, and pollution and environmental damage;

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(10)	whether the Utilities can procure sufficient renewable energy sources in each compliance year to satisfy the Nevada Portfolio Standard;

(11)	changes in environmental laws or regulations, including the imposition of limits on emissions of carbon dioxide from electric generating facilities, which could significantly affect our existing operations as well as our construction program;

(12)

wholesale market conditions, including availability of power on the spot market and the availability to enter into gas financial hedges with creditworthy counterparties, which affect the prices the Utilities have to pay for power as well as the prices at which the Utilities can sell any excess power;

(13)	whether the Utilities will be able to continue to pay NVE dividends under the terms of their respective financing and credit agreements and limitations imposed by the Federal Power Act;

(14)

the discretion of NVE's BOD regarding NVE's future common stock dividends based on the BOD's periodic consideration of factors ordinarily affecting dividend policy, such as current and prospective financial condition, earnings and liquidity, prospective business conditions, regulatory factors, and restrictions in NVE's and the Utilities' agreements;

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

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

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

(18)

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

(19)	employee workforce factors, including changes in and renewals of collective bargaining unit agreements, strikes or work stoppages, and potential difficulty in recruiting new talent to mitigate losses in critical knowledge and skill areas due to an aging workforce; and

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

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

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EXECUTIVE OVERVIEW

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

●	Critical Accounting Policies and Estimates

§	Recent Pronouncements

●	For each of NVE, NPC and SPPC:

§	Results of Operations

§	Analysis of Cash Flows

§	Liquidity and Capital Resources

●	Energy Supply (Utilities)

●	Regulatory Proceedings (Utilities)

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

The Utilities are regulated by the PUCN and, for the California service territory of SPPC, the CPUC, with respect to rates, standards of service, siting of and necessity for generation and certain transmission facilities, accounting, issuance of securities and other matters with respect to generation, distribution and transmission operations. The FERC has jurisdiction under the Federal Power Act with respect to wholesale rates, service, interconnection, accounting, and other matters in connection with the Utilities’ sale of electricity for resale and interstate transmission. The FERC also has jurisdiction over the natural gas pipeline companies from which the Utilities take service. As a result of regulation, many of the fundamental business decisions of the Utilities, as well as the ROR they are permitted to earn on their utility assets, are subject to the approval of governmental agencies.

The Utilities’ revenues and operating income are subject to fluctuations during the year due to impacts that seasonal weather, rate changes, and customer usage patterns have on demand for electric energy and resources. 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 typically occurs in the summer, while its gas business typically peaks in the winter. The variations in energy usage by the Utilities’ customers due to varying weather and other energy usage patterns necessitates a continual balancing of loads and resources and purchases and sales of energy under short and long term contracts. As a result, the prudent management and optimization of available resources has a direct effect on the operating and financial performance of the Utilities. Additionally, the recovery of purchased power and fuel costs, and other costs, on a timely basis, and the ability to earn a fair return on investments are essential to the operating and financial performance of the Utilities.

Overview of Major Factors Affecting Results of Operations

During 2008, NVE’s net income applicable to common stock was $208.9 million compared to $197.3 million in 2007. Earnings were higher primarily due to an increase in gross margin at both Utilities. At NPC gross margin increased primarily due to an increase in BTGR as a result of NPC’s 2006 GRC, effective June 1, 2007 and increased customer growth; partially offsetting these increases was a decrease in customer usage due to cooler weather and a change in customer usage patterns. At SPPC gross margin increased primarily due to an increase in BTGR revenue as a result of SPPC’s 2007 GRC, effective July 1, 2008, increased customer growth and in 2007 a charge of approximately $9.2 million, net of taxes, for deferred energy disallowed. Partially offsetting these increases was a decrease in customer usage primarily due to cooler summer weather. Partially offsetting the increase in gross margin was higher interest expense and in 2007, NPC recorded income of approximately $7.2 million, net of taxes, for reinstated interest on deferred energy, which was expensed in prior years.

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During 2007, NVE’s net income applicable to common stock was $197.3 compared to $277.5 in 2006. Earnings were lower in 2007 compared to 2006 primarily as a result of the reinstatement of deferred energy in 2006 of approximately $116.2 million net of taxes and the $40.9 million gain on sale (net of taxes), recorded in 2006, of the partnership interest in TGTC held by TGPC, a wholly owned subsidiary of NVE. Partially offsetting this was:

·	an increase in gross margin in 2007, exclusive of Reinstatement of Deferred Energy (as defined under NPC’s and SPPC’s respective, Results of Operations) of almost 18% at NPC. See discussion of gross margin in NPC and SPPC’s, respective Results of Operations;

·	settlement in 2007 with the PUCN regarding accrued interest on NPC’s 2001 deferred energy case;

·	an increase in 2007 in AFUDC and allowance for borrowed funds used during construction due to the construction of NPC’s Clark Peaking Units and SPPC’s Tracy Generating Station; and

·	a decrease in 2007 in interest charges.

2008 Key Objectives

·	Management of Energy Resources

o	Energy Efficiency and Conservation Programs

o	Purchase and Development of Renewable Energy Projects

o	Construction of Generating Facilities

o	Management of Energy Risk, including fuel and purchased power costs

·	Management of Environmental Matters

·	Management of Regulatory Filings

·	Further Broaden Access to Capital

2008 Accomplishments

Management of Energy Resources

·	Energy Efficiency and Conservation Programs – The Utilities received additional PUCN approval on DSM projects. Additionally, the Utilities reported in their Portfolio Standard Annual Report for Compliance Year 2007, that they met 60% of the allowable 25% that may be used to meet the Portfolio Standard, and reported that NPC is in a position to achieve the maximum 25% in 2008.

Purchase and Development of Renewable Energy Projects – In 2008, NPC entered into contracts to either jointly construct or pursue the development of projects using wind, geothermal and recovered energy generation technologies, and for purchase, subject to PUCN approval, of an additional 32 MW of output from three geothermal plants now under construction. Additionally, in 2008 the PUCN issued its order accepting the Utilities Portfolio Standard Annual Report for Compliance Year 2007 and accepted a stipulation that granted an exemption from meeting the Portfolio Standard.

Construction of Generating Facilities – In 2008 NPC completed the construction of 619 MWs (nominally rated) of natural gas-fired combustion turbine peaking units at the Clark Generating Station and began the construction of a 500 MW (nominally rated) natural gas generating station at the existing Harry Allen Generating Station which is expected to be operational by summer 2011. NPC also purchased a 598 MW (nominally rated) natural gas fired combined cycle generating station from Reliant Resources, which has now been named the Higgins Generating Station. In 2008, SPPC completed the construction of a 541 MW (nominally rated) gas fired generating station at Tracy.

·	Management of Energy Risk – In 2008, the Utilities received PUCN approval to implement a longer term sales program for non-peaking months. The longer term sales program will allow the Utilities to sell their excess energy during non peak months on the open market.

Management of Environmental Matters

As of December 31, 2008, NPC has spent a cumulative $117.8 million on environmental upgrades. This included the installation of pollution control technologies at both the Reid Gardner Generating Station and the Clark Generating Station, which have already resulted in significant emissions reduction.

Management of Regulatory Filings

In December 200, NPC filed its GRC, if approved as requested, rates would be effective September 1, 2009. In July 2008, the PUCN issued its order on SPPC's 2007 GRC, which among other items increased general rates by $87.1 million or a 10.45% increase, set the ROE and ROR at 10.6% and 8.41%, respectively, authorized the recovery of the 541 MW expansion at the Tracy Generating Station and authorized the recovery of projected operating and maintenance costs associated with the Tracy Generating Station expansion.

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Further Broaden Access to Capital

Despite the credit market turmoil the Utilities were able to issue $750 million in General and Refunding Mortgage Notes in 2008 and in early 2009, completed an offering of $125 million in General and Refunding Mortgage Notes and entered into a supplemental revolving credit facility at NPC, which increased NPC's revolving credit facility by $90 million. Additionally, in 2008, the Utilities converted and repurchased several of their auction rate securities to variable rate demand notes. The securities were purchased with cash on hand and the use of the Utilities' revolving credit facilities to be held until such time as the securities are reoffered to investors. See Financing Transactions in the Utilities' Liquidity and Capital Resources sections.

2009 and Beyond Outlook

Although Nevada is ranked as the eighth fastest growing state in the nation by the U.S. Census Bureau for the twelve months ended June 30, 2008, the economy in Nevada has been adversely affected by the recession facing the United States and the global economy, resulting in an increase in unemployment to 9.1%, compared to 5.6% in 2007, and, in southern Nevada, a decrease in hotel/motel occupancy of 7.7% and a decrease in new home sales to 9,780 in 2008 compared to 19,670 and 36,051 in 2007 and 2006, respectively. As a result of economic conditions both regionally and nationally, Southern Nevada has experienced decreased activity in the real estate, construction and tourism markets. Additionally, the recent credit and capital market crisis will likely impact Nevada’s economy as major commercial and residential developments are delayed or potentially halted due to the high cost of capital or the inability to obtain credit.

Tourism and gaming remain southern Nevada’s leading industries and together comprise one of NPC’s largest classes of customers. Management believes hotel room growth rate is one of the key indicators of southern Nevada’s economic health and leading indicators of overall system load growth. The expected room growth rate for 2009 is 9.1% and 2.7% for 2010. The significant increase in room growth for 2009 is primarily due to Project City Center, which is expected to add approximately 6,000 rooms to Las Vegas. The current recession, as well as recent volatility in the global credit and financial markets, have created an unprecedented level of uncertainty regarding future business conditions. As a result, our management is continually focusing on and reevaluating our assessments, strategies and projections for factors such as customer growth, load forecasts, capital expenditures, rising fuel costs, access to capital markets, collections on accounts receivable and counterparty risk among other factors. While management expects to maintain this process of continual reevaluation for the foreseeable future, it is not possible to predict how long current market volatility will continue or what its long-term effect will be on the economy in general or on our financial position or results of operations in particular.

Despite current economic conditions, long-term energy needs continue to increase in the Western and Southwestern portions of the United States. At the same time, however, the development of generating facilities by utility companies has decreased. As a result, the cost of energy and natural gas continues to change with increased demand and the decline in the ability to meet those demands. The economics of this situation coupled with variations in weather, the capabilities and limits on the Utilities, owned generating facilities, transmission constraints, regulations, and changes and potential changes in environmental laws are significant business issues for the Utilities. As a result, the Utilities’ strategies, as evidenced by their most recent amendments to their IRPs, are aimed at reducing dependence on purchased power by the use of energy efficiency and conservation programs and diversifying fuel mix, including renewable energy and owning more generating facilities.

2009 Key Objectives

In 2009, management’s key objectives remain focused on implementing their three part strategy of energy efficiency, and conservation programs, purchase and development of renewable energy projects and construction of generating facilities. However, as current construction projects for generation are completed, the focus may shift to emphasize and maximize the operations of the Utilities’ current generation assets. Additional key objectives include management of energy risk, management of environmental matters, management of regulatory filings and to further broaden access to capital.

Energy Efficiency and Conservation Programs

A part of our strategy to reduce dependence on purchased power is to manage our resources against our load requirements with energy efficiency and conservation programs, also known as DSM programs. NPC and SPPC have designed a portfolio of cost effective DSM programs that allow every customer to take advantage of savings from energy efficiency measures. DSM programs are marketed across all segments of customer classes (residential, commercial, public and low income).

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Beginning in 2007, the Utilities implemented new and expanded qualified DSM programs. In 2008, the Utilities invested $55 million towards energy efficiency and conservation programs. The Utilities are planning to invest between $45 million and $60 million in 2009. The final amount will be determined by numerous factors, such as the economy, the impact of federal government stimulus legislation, performance of existing and new programs and many other factors.

The Portfolio Standard, discussed below, allows energy efficiency measures from qualified conservation programs to meet up to 25% of the Portfolio Standard. A PEC is created for each kWh of energy conserved by qualified energy efficiency programs. Energy saved during peak demand hours earns double the PEC's. The PUCN has approved investments in efficiency and qualified conservation programs of approximately $140 million, which will be deferred as a regulatory asset, subject to prudency review by the PUCN.

After the DSM percentage allowance is fully utilized, NPC’s and SPPC’s strategy is to continue to implement cost-effective DSM programs.

Purchase and Development of Renewable Energy Projects

The Utilities have embarked on a strategy to invest in renewable energy that, along with purchased power contracts and an increase in DSM programs, will enhance the opportunity for the Utilities to fully meet the Portfolio Standard as required by Nevada law. The Utilities' compliance with the Portfolio Standard is dependent on the availability of renewables.

NPC’s current capital budget includes investing approximately $110 million for renewable energy projects through 2011. As discussed earlier, in 2008, NPC entered into contracts to either jointly construct or pursue the development of projects using wind, geothermal and recovered energy generation technologies, and for purchase, subject to PUCN approval, of an additional 32 MW of output from three geothermal plants now under construction. In 2009, the Utilities will further develop these projects and explore other opportunities.

Construction of Generating Facilities

In 2009, NPC will continue the construction of the 500 MW (nominally rated) natural gas generating station at the existing Harry Allen Generating Station, which is expected to be operational by summer 2011.

In the latter part of 2006, NVE and the Utilities announced their intention to develop the EEC, two 750 MW coal generation units to be located near Ely, Nevada, and the EN-ti line, which would link NPC’s and SPPC’s transmission systems in the southern and northern portions of the state, allowing for the transfer of energy, including renewable resources, between the Utilities. However, on February 9, 2009, NVE and the Utilities announced their intention to postpone the construction of the EEC due to increasing environmental and economic uncertainties until such time as carbon sequestration becomes commercially viable, which is not expected for at least a decade. The Utilities plan to proceed with the construction of the EN-ti line. In 2009, the Utilities intend to file amendments to their IRP’s requesting PUCN approval to accelerate the development of the EN-ti line.

Management of Energy Risk

Entering 2009, the Utilities expect to have open positions resulting from the management of their portfolio of generation resources, load obligations, and purchased power and fuel contracts, in the context of unfolding developments in regional energy markets. The risks associated with the open positions are addressed in various ways. The Utilities implement a prudent strategy of piecemeal procurements transacted in regular intervals and completed before the start of the peak summer season. This provides the Utilities with ample opportunities for optimizing their portfolio on a rolling basis in anticipation of changes in system conditions, load forecasts, and regional energy market fundamentals. The Utilities also coordinate the planned maintenance schedules of their owned generating plants and transmission facilities with expectations of start dates of new generating plants or purchased power contracts.

Management of Environmental Matters

The impact environmental laws can have on existing generating facilities and current and prospective capital construction projects include but are not limited to increased costs, closure of existing facilities, mandated equipment upgrades, and termination of the construction of facilities. Environmental laws already affect the energy we buy; as discussed above under Purchase and Development of Renewable Energy Projects.

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A key objective for the Utilities in 2009 will be to enhance and maintain our energy infrastructure investments in ways that meet customer demand for reliable energy in an efficient and environmentally responsible manner. The Utilities believe that a diverse and balanced portfolio of energy resources represents opportunity for reliability and cost control, yet are also mindful of our overriding environmental responsibility. The Utilities are committed to making technology choices with a primary focus on limiting emissions and optimizing our investments so that prices remain competitive. To meet the growing demand for power, the Utilities are investing in a new generation of highly efficient and environmentally advanced power plants, both coal and natural gas fired as well as adding new environmental controls to their existing plants. To help manage load demand, the Utilities are also increasing their participation and development of new energy efficiency, DSM and conservation programs.

Management of Regulatory Filings

As is the case with most regulated entities, the Utilities are frequently involved in various regulatory proceedings. The Utilities are required to file for quarterly rate adjustments to provide recovery of their fuel and purchased power costs. They are also required to file rate cases every three years to adjust general rates that include their cost of service and return on investment in order to more closely align earned returns with those allowed by regulators. Furthermore, the Utilities are required to file a triennial IRP which is a comprehensive plan that considers customer energy requirements and proposes the resources to meet that requirement. Resource additions approved by the PUCN in the resource planning process are deemed prudent for ratemaking purposes. Between IRP filings, the Utilities may seek PUCN approval for modifications to their resource plans and for power purchases. The Utilities incur costs for such items as deferred fuel and purchased power costs, operations and maintenance and capital projects; however, as costs are not recovered through rates until approved by regulators, the timing between costs incurred and recovery is considered regulatory lag. As such, timely and accurate filings of these various rate cases is essential to the Utilities’ operating and financial performance as it reduces regulatory lag, which has a direct effect on the cash flows of the Utilities. Furthermore, the timing of the filings/decisions can affect the timing of construction and thus the economic benefits. As a result, the Utilities file quarterly BTER updates to minimize exposure to changes in fuel and purchased power expense and file amendments to IRP’s as changes in resource needs occur. See Note 3, Regulatory Actions of the Notes to Financial Statements.

Further Broaden Access to Capital

A significant focus in 2009 will again be to generate sufficient cash from operations to meet operating needs and contribute to capital projects by managing recovery of deferred fuel and purchased power costs, reducing regulatory lag in recovery of costs and controlling costs. However, significant amounts of capital will be necessary to fund existing and prospective construction projects, as discussed further under NVE’s Liquidity and Capital Resources. Additionally, if energy costs rise at a rapid rate and the Utilities do not recover the cost of fuel and purchased power in a timely manner, the Utilities may need to issue additional debt to support their operating costs or delay capital expenditures. Management will be required to meet such financial obligations with a combination of internally generated funds, the use of the Utilities’ revolving credit facilities, the issuance of long-term debt, and/or the issuance of equity by NVE. As such, the ability to issue new debt or equity securities on favorable terms will be a significant focus in 2009. Additionally, maintaining sufficient liquidity through the use of the Utilities revolving credit facilities will be another significant focus in 2009.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

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

Regulatory Accounting

The Utilities’ retail rates are currently subject to the approval of the PUCN and, in the case of the California service territory of SPPC, they are also subject to the CPUC and are designed to recover the cost of providing generation, transmission and distribution services. As a result, the Utilities qualify for the application of SFAS 71 issued by the FASB. This statement recognizes that the rate actions of a regulator can provide reasonable assurance of the existence of an asset and requires the capitalization of incurred costs that would otherwise be charged to expense where it is probable that future revenue will be provided to recover these costs. SFAS 71 prescribes the method to be used to record the financial transactions of a regulated entity. The criteria for applying SFAS 71 include the following: (i) rates are set by an independent third party regulator, (ii) approved rates are intended to recover the specific costs of the regulated products or services, and (iii) rates that are set at levels that will recover costs can be charged to and collected from customers. Under federal law, wholesale rates charged by the Utilities are subject to certain jurisdictional regulation, primarily by the FERC. The FERC has jurisdiction under the Federal Power Act with respect to rates, service, interconnection, accounting, and other matters in connection with the Utilities’ sale of electricity for resale and interstate transmission. The FERC also has jurisdiction over the natural gas pipeline companies from which the Utilities take service.

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Regulatory assets represent incurred costs that have been deferred because it is probable they will be recovered through future rates collected from customers. Regulatory liabilities generally represent obligations to make refunds to customers for previous collections for costs that are not likely to be incurred. Although current rates do not include the recovery of all existing regulatory assets as discussed further below and in Note 1, Summary of Significant Accounting Policies of the Notes to Financial Statements, management believes the existing regulatory assets are probable of recovery either because we have received prior PUCN approval or due to regulatory precedent set for similar circumstances. Management’s judgment reflects the current political and regulatory climate in the state, and is subject to change in the future. If future recovery of costs ceases to be probable, the write-off of regulatory assets would be required to be recognized as a charge and expensed in current period earnings.

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

Deferred Energy Accounting

Under deferred energy accounting, to the extent actual fuel and purchased power costs exceed fuel and purchased power costs recoverable through current rates, the excess is not recorded as a current expense on the statement of operations but rather is deferred and recorded as an asset on the balance sheet. Conversely, a liability is recorded to the extent fuel and purchased power costs recoverable through current rates exceed actual fuel and purchased power costs. These excess amounts are reflected in adjustments to rates and recorded as revenue or expense in future time periods, subject to PUCN approval. Nevada law provides that the PUCN may not allow the recovery of any costs for purchased fuel or purchased power “that were the result of any practice or transaction that was undertaken, managed or performed imprudently by the electric utility.” Nevada law specifies that fuel and purchased power costs include all costs incurred to purchase fuel, to purchase capacity, and to purchase energy. Both Utilities are entitled under statute to utilize deferred energy accounting for their electric operations and both Utilities accumulate amounts in their deferral of energy costs accounts. The Utilities also record, and are eligible under the statute to recover, a carrying charge on such deferred balances, recognized as interest income in the current period.

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

See Note 3, Regulatory Actions of the Notes to Financial Statements, for additional discussion of the regulatory process to recover these deferred costs.

Accounting for Derivatives and Hedging Activities

NVE, NPC and SPPC apply SFAS 133. SFAS 133 requires that an entity recognize all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. The accounting for derivatives depends on the intended use of the derivatives and the resulting designation.

Fuel and Purchased Power Contracts

In order to manage loads, resources and energy price risk, the Utilities enter into forward contracts to purchase or sell a specified amount of energy at a specified time or during a specified period in the future. In addition to forward fuel and power contracts, the Utilities’ also use over-the-counter options with financial institutions and other energy companies to manage price risk. These instruments are considered to be derivatives under SFAS 133 and are marked to market in the statement of financial position unless the contract qualifies for the normal purchases or sales exemption per the criteria in SFAS 133. The risk management assets and liabilities recorded in the balance sheets of the Utilities’ and NVE are primarily comprised of the fair value of natural gas options and swaps.

In conjunction with the issuance of SFAS 133, the PUCN and in the case of the California service territory of SPPC, the CPUC issued accounting orders authorizing the Utilities to offset any derivative assets or liabilities with a regulatory asset or liability. This accounting treatment is intended to defer the recognition of mark to market gains and losses on energy commodity transactions until the period of settlement. The orders provide for the Utilities’ to not recognize the unrealized gain or loss on utility derivative commodity instruments in the statement of operations and comprehensive income. Fuel and purchased power costs are subject to this accounting order and apply deferred energy accounting. Upon settlement of a derivative instrument, actual fuel and purchased power costs are recognized in the period of settlement if currently recoverable or deferred if they are recoverable or payable through future rates.

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Adoption of SFAS 157

Effective January 1, 2008, NVE and the Utilities adopted SFAS 157, which defines fair value, establishes a framework for measuring fair value and enhances disclosures about assets and liabilities recorded at fair value. As defined in SFAS 157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). However, as permitted under SFAS 157, NVE and the Utilities use a mid-market pricing convention (the mid-point price between the bid and ask prices) as a practical expedient for valuing their assets and liabilities carried at fair value. NVE and the Utilities use market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about counterparty risk, and the impact of NVE and the Utilities nonperformance risk on their liabilities. Nonperformance risk is based on the credit quality of NVE and the Utilities and had no impact to the fair value of their derivative instruments at the reporting date.

Forwards and swaps are valued using a market approach that uses quotes obtained from independent brokers and exchanges. Options are valued based on an income approach that uses an option pricing model that incorporates assumptions such as the underlying commodity’s forward price curve, time to expiration, strike price, interest rates and volatility. The use of different assumptions and variables in determining fair value of their commodity derivative instruments could have a significant impact on the valuation of the instruments and its classification within the fair value hierarchy. NVE and the Utilities’ assessment of the significance of a particular input to fair value measurements require judgment. The fair value of the Utilities’ derivative commodity instruments, which are recorded on the Consolidated Balance Sheets, are sensitive to market price fluctuations that can occur on a daily basis.

Accounting for Income Taxes

As of December 31, 2008, the deferred tax asset for tax credit carryovers was $34.8 million. The tax credit carryovers may be utilized in future periods to reduce taxes payable to the extent that NVE and the Utilities recognize taxable income.

The following table summarizes the tax credit carryovers and associated carryover periods, as adjusted for FIN 48, and valuation allowance for amounts which NVE has determined that realization is uncertain (dollars in thousands):

	Deferred		Valuation		Net Deferred		Expiration
	Tax Asset		Allowance		Tax Asset		Period
Research and development credit	$	8,883	$	-	$	8,883		2021-2028
Alternative minimum tax credit		24,572		-		24,572	indefinite
Arizona state coal credits		1,384		1,160		224		2009-2013
Total	$	34,839	$	1,160	$	33,679

In accordance with the recognition and measurement standards promulgated by FIN 48, NVE recognized certain tax benefits during the year. Thus, there is no deferred tax balance for the net operating loss of $99,667, which is reflected in the federal tax return. The net operating loss reflected in the federal tax return will expire from 2021-2024.

Considering all positive and negative evidence regarding the utilization of the Utilities’ deferred tax assets, it has been determined that the Utilities are more likely than not to realize all recorded deferred tax assets, except for the Arizona coal tax credits. As such, these Arizona coal tax credits represent the only valuation allowance that has been recorded as of December 31, 2008.

Environmental Contingencies

NVE and its subsidiaries are subject to federal, state and local regulations governing air and water quality, hazardous and solid waste, land use and other environmental considerations. Nevada’s Utility Environmental Protection Act requires approval of the PUCN prior to construction of major utility, generation or transmission facilities. The EPA, NDEP and Clark County Department of Air Quality and Environmental Management administer regulations involving air and water quality, solid, and hazardous and toxic waste.

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

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Depending on whether environmental liabilities occurred from normal operations or as part of new environmental laws, the Utilities accrue for environmental remediation liabilities in accordance with SFAS 143, or SOP 96-1. Estimated costs from environmental remediation obligations generally are recognized no later than completion of the remedial feasibility study or when the criteria for SFAS 143 or SOP 96-1 have been met. Such costs are adjusted as additional information develops or circumstances change. Certain environmental costs receive regulatory accounting treatment, under which the costs are recorded as regulatory assets. Recoveries of environmental remediation costs from other parties are recognized when their receipt is deemed probable. Environmental expenditures that have future economic benefits are capitalized in accordance with our asset capitalization policy.

Note 13, Commitments and Contingencies of the Notes to Financial Statements, discusses the environmental matters of NVE and its subsidiaries that have been identified, and the estimated financial effect of those matters. To the extent that (1) actual results differ from the estimated financial effects, (2) there are environmental matters not yet identified for which NVE or its subsidiaries are determined to be responsible, or (3) the Utilities are unable to recover through future rates the costs to remediate such environmental matters, there could be a material adverse effect on the financial condition and future liquidity and results of operations of NVE and its subsidiaries.

Defined Benefit Plans and Other Postretirement Plans

As further explained in Note 11, Retirement Plan and Post-Retirement Benefits of the Notes to Financial Statements, NVE maintains a qualified pension plan, a non-qualified supplemental executive retirement plan and restoration plan, as well as a postretirement benefit plan which provides health and life insurance for retired employees. All employees are eligible for these benefits if they terminate with certain age and service requirements from the qualified and restoration plans, or if they reach retirement age and meet certain service requirements under the SERP and OPEB plans while still working for NVE or its subsidiaries. There are no restrictions on age or service requirements for those employees earning benefits under the qualified plan using the cash balance formula. The costs for these plans are determined in accordance with the provisions of SFAS 87 and SFAS 106, and are expected to be collected in rates billed to customers. Amounts are funded to trusts maintained for the plans. The amounts funded are then used to meet benefit payments to plan participants.

NVE funded $92.0 million and $54.0 million for its pension plan, in 2008 and 2007, respectively, and $8.0 million and $46.0 million for the other postretirement benefits plan in 2008 and 2007, respectively. At the present time it is expected that additional funding for these plans could be required for plan year 2009 to meet the minimum funding levels defined by the Pension Protection Act of 2006. NVE’s funding requirements may change subject to market conditions; as a result, NVE is unable to predict what the funding amount may be in 2009. As required under SFAS 158, NVE has changed the measurement date for its benefit plans from September 30 to December 31, which coincides with NVE’s fiscal year end.

Pension Plans

NVE’s reported costs of providing non-contributory defined pension benefits (described in Note 11, Retirement Plan and Post-Retirement Benefits of the Notes to Financial Statements) are dependent upon numerous factors resulting from actual plan experience and assumptions for future experience.

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

In accordance with SFAS 87, changes in pension obligations associated with these factors may not be immediately recognized as pension costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. As such, significant portions of pension costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants. NVE adopted SFAS 158 in 2006, which requires the immediate recognition of changes in benefit obligations due to differences between actuarial assumptions and actual experience in Accumulated Other Comprehensive Income, net of taxes. However, since NVE recovers SFAS 87 and SFAS 106 costs through rates, these amounts will be recorded as Other Regulatory Assets under the provisions of SFAS 71, and will be recognized as expense over a period of time. For the year ended December 31, 2008, 2007, and 2006, NVE recorded pension expense for all pension plans of approximately $24 million, $29.3 million, and $30.6 million, respectively, in accordance with the provisions of SFAS 87. Actual payments of benefits made to retirees and terminated vested employees for the year ended December 31, 2008 was $27.4 million, and for the twelve months ended September 30, 2007 and 2006 were $31.9 million and $21 million respectively.

In November 2007, the BOD approved a change in the plan for its management, professional, administrative and technical employees (MPAT) from a defined benefit plan to a cash balance plan. Employees with combined age and service totaling 75 years or more had the choice of staying with the current plan or electing to switch to the new plan. The new plan went into effect on April 1, 2008; all employees hired after that date will be eligible for the cash balance plan, and will be vested after three years of service. This change, along with market conditions and plan asset values at the time of the re-measurement of the plan obligation, increased 2008 pension expense by $2.7 million over the original estimate of $21.3 million.

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Under the terms of NPC’s current contract with IBEW Local No. 396, the pension benefits for those employees covered under that agreement, have also changed from a defined benefit plan to a cash balance plan, effective December 31, 2008. However, the impact of this change has been offset by current market conditions and plan asset values. NVE did not make changes to pension plan provisions in 2007 and 2006 that had significant impacts on recorded pension expense for those years.

As further described in Note 11, Retirement Plan and Post-Retirement Benefits of the Notes to Financial Statements, NVE reduced the discount rate used in determining pension expense from 6.38% in 2008 to 6.09% for the calendar year 2009.

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

NVE strives to maintain a reasonable and prudent amount of risk, and seeks to limit risk through diversification of assets. Also, NVE considers the ability of the plan to pay all benefit and expense obligations when due, and to control the costs of administering and managing the plan. NVE’s investment guidelines prohibit investing the plan assets in real estate and NVE’s own stock. Currently, the plan assets are invested in international and domestic equity securities, and fixed income investments which include bonds.

The asset allocation for NVE’s pension plans at the end of 2008 and 2007, and the target allocation for 2009, by asset category, follows. The fair value of plan assets for these plans is $531 million and $640 million, at the end of 2008 and 2007, respectively. The asset values are determined using quoted market prices. The expected long-term ROR on the plan assets is 7.10%, 8.00% and 8.00% in 2009, 2008 and 2007, respectively.

	Allocation Percentage of Plan Assets at Year End
Asset Category	2009	2008	2007

Equity securities	45%	46%	60%
Debt securities	50%	41%	40%
Cash/other	5%	13%	0%
Total	100%	100%	100%

NVE’s investment strategy is to ensure the safety of the principal of the assets and obtain asset performance to meet the continuing obligations of the plan. In third quarter 2008, NVE began an asset liability study on all plan assets. Of the amounts funded to the pension plan in 2008 by NVE, $70 million was funded to the plan in December. The year end allocations were not rebalanced in anticipation of the results of the study early in 2009. Therefore, the $70 million contribution on December 30, 2008 was temporarily invested into cash until a new asset allocation plan is approved by the NVE Pension Committee.

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

Actuarial Assumption (dollars in millions)	Change in Assumption Increase/(Decrease)	Impact on PBO Increase/(Decrease)	Impact on PC Increase/(Decrease)
Discount Rate	1%	$ (77.2)	$ (6.1)
ROR on Plan Assets	1%	$ 0.0	$ (6.4)

In selecting an assumed discount rate for fiscal years 2008 and 2007 disclosures, and for fiscal years 2008, 2007 and 2006 pension cost, NVE’s projected benefit payments were matched to the yield curve derived from a portfolio of over 300 high quality Aa bonds with yields within the 10th to 90th percentiles of these bond yields.

In selecting an assumed ROR on plan assets, NVE considers past performance and economic forecasts for the types of investments held by the plan. Investment returns on plan assets in the retirement plan decreased by approximately $181.8 million in 2008 and gained approximately $73.5 million in 2007. Despite contributions by NVE, these returns have reduced the funded status of the plan compared to prior years.

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Other Postretirement Benefits

NVE’s reported costs of providing other postretirement benefits (described in Note 11, Retirement Plan and Post-Retirement Benefits of the Notes to Financial Statements) are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience.

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

For the year ended December 31, 2008, 2007, and 2006, NVE recorded other postretirement benefit expense of approximately $7.4 million, $11.3 million, and $14.9 million, respectively, in accordance with the provisions of SFAS 106. Actual payments of benefits made to retirees for the year ended December 31, 2008 was $11.8 million, and for the twelve months ended September 30, 2007 and 2006, were $10.0 million and $12.0 million, respectively.

In 2007, NVE completed negotiations with SPPC’s IBEW Local No. 1245 employees, and reached a settlement with regards to postretirement medical coverage. This agreement resulted in changes to NVE’s future obligations under this plan, and as a result of a re-measurement of the plan obligation, NVE’s 2007 expense was reduced by $1.3 million. There were no changes made to other postretirement benefit plan provisions in 2006 which had any significant impact on recorded benefit plan amounts in that year.

In 2008, the postretirement plan was amended to provide that all MPAT employees hired after April 1, 2008 will not be eligible for retiree medical coverage, and those hired after January 1, 2009 will not be eligible for retiree life insurance coverage. Additionally, all IBEW Local No. 396 employees hired after October 13, 2008 will cease to have retiree medical coverage after attaining the age of 65, and they will not be eligible for retiree life insurance coverage. The impact of these changes on the postretirement plan costs is not yet known.

As further described in Note 11, Retirement Plan and Post-Retirement Benefits of the Notes to Financial Statements, NVE has revised the discount rate for its 2008 disclosures to 6.07%, as compared to 2007 disclosures of 6.30%. For determining the expense to be recorded in 2009, NVE moved to a 6.07% discount rate from 6.25% in 2008. In determining the other postretirement benefit obligation and related cost, these assumptions can change with each measurement date, and such changes could result in material changes to such amounts.

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

The asset allocation for the other postretirement benefit plans at the end of 2008 and 2007, and target allocation for 2009, by asset category, follows. The fair value of plan assets for these plans is $84.7 million and $108.9 million at the end of 2008 and 2007, respectively. The asset values are determined using recorded closing sales on a national securities exchange. The expected long-term ROR on the plan assets is 7.10%, 8.00% and 8.00% in 2009, 2008 and 2007, respectively.

	Allocation Percentage of Plan Assets at Year End
Asset Category	2009	2008	2007

Equity securities	45%	29%	60%
Debt securities	50%	35%	40%
Cash/other	5%	36%	0%
Total	100%	100%	100%

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NVE’s investment strategy is to ensure the safety of the principal of the assets and obtain asset performance to meet the continuing obligations of the plan.

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

Actuarial Assumption (dollars in millions)	Change in Assumption Increase			Impact on APBO Increase/(Decrease)			Impact on PBC Increase/(Decrease)
Discount Rate		1	%	$	(17.8	)	$	(1.4	)
Health Care Cost Trend Rate		1	%	$	14.4		$	2.2
ROR on Plan Assets		1	%	$	0.0		$	(1.0	)

In selecting an assumed discount rate for fiscal year 2008 other postretirement benefits cost and disclosures, NVE’s projected benefit payments were matched to the yield curve derived from a portfolio of over 300 high quality Aa bonds with yields within the 10th to 90th percentiles of these bond yields.

Unbilled Receivables

Revenues related to the sale of energy are recorded based on meter reads, which occur on a systematic basis throughout a month, rather than when the service is rendered or energy is delivered. At the end of each month, the energy delivered to the customers from the date of their last meter read to the end of the month is estimated and the corresponding unbilled revenues are calculated. These estimates of unbilled sales and revenues are based on the ratio of billable days versus unbilled days, amount of energy procured and generated during that month, historical customer class usage patterns and the Utilities’ current tariffs. Customer accounts receivable as of December 31, 2008, include unbilled receivables of $103 million and $76 million for NPC and SPPC, respectively. Customer accounts receivable as of December 31, 2007 include unbilled receivables of $106 million and $79 million for NPC and SPPC, respectively.

RECENT PRONOUNCEMENTS

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

NV ENERGY, INC.

RESULTS OF OPERATIONS

NV Energy, Inc. (Holding Company) and Other Subsidiaries

NVE (Holding Company)

The Holding Company’s (stand alone) operating results included approximately $40.3 million, $42.5 million and $51.4 million of long-term debt interest costs for the years ended December 31, 2008, 2007 and 2006, respectively. The decrease in interest costs for the year ended December 31, 2008 as compared to the same period in 2007 was primarily due to debt redemptions in 2008 and in December 2007. See Note 6, Long-Term Debt of the Notes to Financial Statements, for further discussion of the debt repurchase. The decrease in interest costs for the year ended December 31, 2007 as compared to the same period in 2006 was primarily due to lower interest costs and amortization costs related to debt redemption in 2006.

Other Subsidiaries

Other Subsidiaries of NVE, except for NPC and SPPC, did not contribute materially to the consolidated results of operations of NVE.

NV Energy, Inc. (Consolidated)

See Executive Overview, Overview of Major Factors Affecting Results of Operations for NVE Consolidated.

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ANALYSIS OF CASH FLOWS

NVE’s cash flows decreased during the year ended December 31, 2008 compared to the same period in 2007 due to a decrease in cash from operating activities and an increase in cash used for investing activities, partially offset by an increase in cash from financing activities.

Cash From Operating Activities. The decrease in cash from operating activities was primarily due to increases in fuel and purchased power costs in excess of revenue collected in rates and a decrease in the collection of previously approved deferred energy costs. Also contributing to the decrease in cash from operating activities was the timing of payments to vendors, increases in expenditures for conservation programs, site studies and other regulatory activities in 2008. The decrease was partially offset by the settlement with Calpine, prepaid transmission revenue, and a reduction in outstanding receivables.

Cash Used By Investing Activities. Cash used by investing activities increased primarily due to the purchase of a 598 MW (nominally rated) natural gas fired, combined cycle generating station from Reliant Energy, Inc, now known as the Higgins Generating Station, for approximately $510 million, construction at the Harry Allen Generating Station, environmental compliance upgrades and increase in construction for infrastructure, offset partially by the closing stages of major construction activity; the peaking units at Clark Generating Station, which began in 2007 and the Tracy Generating Station, which began in 2006.

Cash From Financing Activities. Cash from financing activities increased due to the proceeds from the issuance by NPC of $500 million 6.5% General and Refunding Mortgage Notes, Series S, due 2018, the issuance by SPPC of $250 million 5.45% General and Refunding Mortgage Notes, Series Q, due 2013 and draws on the Utilities long term revolving credit facilities. This increase was partially offset by an increase in dividends paid by NVE to common shareholders and the issuance of common stock in 2007 for approximately $202.8 million.

NVE’s cash flows increased during the year ended December 31, 2007 compared to the same period in 2006 due to increases in cash from operating and financing activities offset by an increase in cash used by investing activities.

Cash From Operating Activities. Cash flows from operating activities increased during the year ended December 31, 2007 compared to the same period in 2006 primarily due to NPC’s increased operating income (excluding Reinstated Deferred Energy). NPC’s operating income (excluding Reinstated Deferred Energy) increased primarily as a result of increases in rates due to NPC’s GRC, the Western Energy Crisis Rate Case and the 2001 Deferred Energy Case as discussed in Note 3, Regulatory Actions of the Notes to Financial Statements. Other factors contributing to the increase in cash flows were a decrease in payments made to suppliers, the timing of payments, improved credit terms with suppliers resulting in a decrease in deposits and prepayments, a BTER rate which better reflected actual energy costs, a decrease in interest paid and the net settlement with Enron, offset by an increase in funding for retirement plans.

Cash Used By Investing Activities. Cash used by investing activities increased for the year ended December 31, 2007 compared to the same period in 2006 primarily due to expenditures for the Clark Peaking Units, the expansion of the Tracy Generating Station, the EEC and utility infrastructure to support growth.

Cash From Financing Activities. Cash from financing activities increased during the year ended December 31, 2007 compared to the same period in 2006 primarily due to a reduction in the redemption of debt and preferred stock by the Utilities. This increase was partially offset by a decrease in the sale of common stock and the restoration of dividend payments by NVE in 2007 of approximately $35.4 million.

LIQUIDITY AND CAPITAL RESOURCES (NVE CONSOLIDATED)

Overall Liquidity

NVE’s consolidated operating cash flows are primarily derived from the operations of NPC and SPPC. The primary source of operating cash flows for the Utilities is revenues (including the recovery of previously deferred energy costs and natural gas costs) from sales of electricity and, in the case of SPPC, natural gas. Significant uses of cash flows from operations include the purchase of electricity and natural gas, other operating expenses, capital expenditures and interest. Operating cash flows can be significantly influenced by factors such as weather, regulatory outcomes, and economic conditions.

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Available Liquidity as of December 31, 2008 (in millions)
	NVE		NPC		SPPC
Cash and Cash Equivalents	$	4.1	$	28.6	$	21.4
Balance available on Revolving Credit Facilities (1)(2)		N/A		164.0		162.0

	$	4.1	$	192.6	$	183.4

(1)

NPC’s and SPPC’s available balance reflects management’s estimate of a reduction in availability under their revolving credit facilities of approximately $11.0 million and $18.0 million, respectively, as a result of the bankruptcy of a lending bank.

(2)

As of February 20, 2009, NPC and SPPC had approximately $289.7 million and $110.6 million available under their revolving credit facilities, which reflects the reduction discussed under (1) above and outstanding letter of credits of $15.3 million and $17.1 million, respectively. The NPC balance includes the combined total of the multi-year revolving credit facility and the 364-day supplemental revolving credit facility, described below.

NVE and the Utilities attempt to maintain their cash and cash equivalents in highly liquid investments, such as United States treasury bills. In addition to cash on hand and the Utilities’ revolving credit facilities, the Utilities may issue debt up to $862 million on a consolidated basis, subject to certain limitations discussed below and in the Utilities’ respective sections, to meet their respective financial obligations. NVE and the Utilities have no significant debt maturities in 2009 or 2010, except for the balances on their revolving credit facilities, which, as of February 20, 2009 are $374.1 million and $204.7 million, for NPC and SPPC, respectively. On February 4, 2009, the PUCN approved NPC’s request for financing authority to issue up to $1.25 billion of long-term debt securities over a two-year period ending December 31, 2010; ongoing authority to maintain a revolving credit facility of up to $1.3 billion, and authority to refinance up to approximately $471 million of long-term debt securities.

NVE and the Utilities anticipate that they will be able to meet short-term operating costs, such as fuel and purchased power costs, with internally generated funds, including the recovery of deferred energy, and the use of their revolving credit facilities. To manage liquidity needs as a result of seasonal peaks in fuel requirements, NVE and the Utilities may use hedging activities. In order to fund long-term capital requirements, NVE and the Utilities will likely meet such financial obligations with a combination of internally generated funds, the use of the Utilities’ revolving credit facilities, the issuance of long-term debt and/or equity and in the case of the Utilities capital contributions from NVE.

The credit ratings of NVE and the Utilities continued to improve in 2008 (see Credit Ratings below). However, disruptions in the banking and capital markets not specifically related to NVE or the Utilities may affect their ability to access funding sources or cause an increase in the interest rates paid on newly issued debt.

NVE has approximately $37.7 million payable of debt service obligations for 2009, which it intends to pay through dividends from subsidiaries. (See “Factors Affecting Liquidity-Dividends from Subsidiaries” below).

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

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

Capital Structure (NVE Consolidated)

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

	2008					2007
	Amount		Percent of Total Capitalization			Amount		Percent of Total Capitalization
Current Maturities of Long-Term Debt	$	9,291		0.1	%	$	110,285		1.5	%
Long-Term Debt		5,266,982		62.6	%		4,137,864		57.1	%
Common Equity		3,131,186		37.3	%		2,996,575		41.4	%
Total	$	8,407,459		100.0	%	$	7,244,724		100.0	%

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Capital Requirements

Construction Expenditures

NVE’s consolidated cash requirements for construction expenditures for 2009 are projected to be $920.5 million. NVE’s consolidated cash requirements for cash construction expenditures for 2009-2013 are projected to be $3.0 billion. Cash used by investing activities for the years ended 2008, 2007 and 2006 were approximately $1.5 billion, $1.1 billion and $803.5 million, respectively. To fund future capital projects, NVE and the Utilities may meet such financial obligations with a combination of internally generated funds, the use of the Utilities’ revolving credit facilities, the issuance of long-term debt, and if necessary, the issuance of equity by NVE.

Estimated construction expenditures for PUCN approved projects, projects under contract, compliance projects and other base capital requirements are as follows (dollars in thousands):

	2009			2010-2013	Total 5 - Year
Electric Facilities:
Generation	$	583,876	$	915,110	$	1,498,986
Distribution		191,672		839,390		1,031,062
Transmission		135,906		565,700		701,606
Other		108,759		217,139		325,898
Total		1,020,213		2,537,339		3,557,552

Gas Facilities:
Distribution		13,469		63,097		76,566
Other		180		2,461		2,641
Total		13,649		65,558		79,207

Common Facilities		13,028		49,453		62,481

Total	$	1,046,890	$	2,652,350	$	3,699,240

Total estimated cash requirements related to construction projects consist of the following (dollars in thousands):

	2009				2010-2013		Total 5 - Year
Construction Expenditures	$	1,046,890		$	2,652,350		$	3,699,240
AFUDC		(72,956	)		(309,958	)		(382,914	)
Net Salvage/ Cost of Removal		(11,747	)		(48,051	)		(59,798	)
Net Customer Advances and CIAC		(41,676	)		(168,969	)		(210,645	)

Total Cash Requirements	$	920,511		$	2,125,372		$	3,045,883

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Contractual Obligations (NVE Consolidated)

The table below provides NVE’s contractual obligations on a consolidated basis (except as otherwise indicated) that NVE expects to satisfy through a combination of internally generated cash and, as necessary, through the issuance of short-term and long-term debt. Certain contracts contain variable factors which required NVE to estimate the obligation depending on the final variable amount. Actual amounts could differ. The table does not include estimated construction expenditures described above, except for major capital projects for which the Utilities have executed contracts by December 31, 2008, or Pension funding requirements as discussed in Note 11, Retirement Plan and Post-Retirement Benefits of the Notes to Financial Statements, as of December 31, 2008. Additionally, at December 31, 2008, NVE has recorded a FIN 48 liability of $93.9 million, all of which is classified as non-current. NVE is unable to make a reasonably reliable estimate of the period of cash payments to relevant tax authorities; consequently, none of the FIN 48 liability is included in the contractual obligations table below (dollars in thousands):

	Payment Due by Period
	2009		2010		2011		2012		2013		Thereafter		Total

NPC/SPPC Long-Term Debt Maturities	$	600	$	562,541	$	364,000	$	230,000	$	250,000	$	3,332,335	$	4,739,476
NPC/SPPC Long-Term Debt Interest Payments		261,507		257,390		240,361		217,361		213,073		2,513,830		3,703,522
NVE Long-Term Debt Maturities		-		-		-		63,670		-		421,539		485,209
NVE Long-Term Debt Interest Payments		37,735		37,735		37,735		35,044		32,767		50,991		232,007
Purchased Power (1)		409,713		446,480		493,684		512,160		523,160		6,094,331		8,479,528
Coal, Natural Gas and Transportation		697,016		183,425		115,564		117,364		116,780		1,191,257		2,421,406
Long-Term Service Agreements (2)		31,348		31,630		31,920		32,219		32,526		169,819		329,462
Capital Projects (3)		332,797		166,124		8,113		-		30,638		-		537,672
Operating Leases		22,813		18,926		9,378		8,868		8,820		89,856		158,661
Capital Leases		12,467		12,466		9,630		9,493		9,510		32,668		86,234

Total Contractual Cash Obligations	$	1,805,996	$	1,716,717	$	1,310,385	$	1,226,179	$	1,217,274	$	13,896,626	$	21,173,177

(1)	Related party purchase power agreements have been eliminated.

(2)	Includes long term service agreements for the Lenzie Generating Station, Silverhawk Generating Station, Higgins Generating Station and the Tracy Generating Station.

(3)	Capital Projects include the tenant improvement project for the Beltway Complex, an operations center in southern Nevada, Harry Allen Generating Station Combined Cycle Project, and Clark Generating Station Units 5-8 Dry Low Nox Burner Project.

Pension Plan and Other Post-Retirement Matters

NVE has a qualified pension plan and other postretirement benefits plan which cover substantially all employees of NVE, NPC and SPPC. The annual net benefit cost for the plans is expected to increase in 2009 by approximately $31.7 million compared to the 2008 cost of $31.5 million. As of December 31, 2008, the measurement date, the plans were under funded under the provisions of FAS 158. Refer to Note 11, Retirement Plan and Post-Retirement Benefits, of the Notes to Financial Statements. During 2008, NVE funded a total of $100 million to the trusts established for these plans. At the present time it is expected that additional funding will be required in 2009 to meet the minimum funding level requirements defined by the Pension Protection Act of 2006. NVE’s funding requirements may change subject to market conditions; as a result, NVE is unable to predict what the funding amount may be in 2009. NVE is expected to fund approximately $70 million to the trusts in 2009.

Financing Transactions (NVE-Holding Company)

Debt Repurchase

In the fourth quarter of 2008, NVE repurchased approximately $20 million of the 8.625% Senior Notes and approximately $19 million of the 6.75% Senior Notes. NVE used cash on hand to pay the total consideration of approximately $34.7 million, including accrued interest. As of December 31, 2008, the outstanding balances for the 6.75% Senior Notes and 8.625% Senior Notes were $191.5 million and $230 million, respectively.

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Factors Affecting Liquidity

Effect of Holding Company Structure

As of December 31, 2008, NVE (on a stand-alone basis) has outstanding debt and other obligations including, but not limited to: $63.7 million of its unsecured 7.803% Senior Notes due 2012; $191.5 million of its unsecured 6.75% Senior Notes due 2017; and $230 million of its unsecured 8.625% Senior Notes due 2014.

Due to the holding company structure, NVE’s right as a common shareholder to receive assets of any of its direct or indirect subsidiaries upon a subsidiary’s liquidation or reorganization is junior to the claims against the assets of such subsidiary by its creditors. Therefore, NVE’s debt obligations are effectively subordinated to all existing and future claims of the creditors of NPC and SPPC and its other subsidiaries, including trade creditors, debt holders, secured creditors, taxing authorities and guarantee holders.

As of December 31, 2008, NVE, NPC, SPPC and their subsidiaries had approximately $5.3 billion of debt and other obligations outstanding, consisting of approximately $3.4 billion of debt at NPC, approximately $1.4 billion of debt at SPPC and approximately $485 million of debt at the holding company and other subsidiaries. Although NVE and the Utilities are parties to agreements that limit the amount of additional indebtedness they may incur, NVE and the Utilities retain the ability to incur substantial additional indebtedness and other liabilities.

Dividends from Subsidiaries

Credit Ratings

NVE, NPC and SPPC are rated by four Nationally Recognized Statistical Rating Organizations (NRSRO’s): DBRS, Fitch, Moody’s and S&P. The senior secured debt of NPC and SPPC is rated investment grade by all four rating organizations. As of December 31, 2008, the ratings are as follows:

		Rating Agency
		DBRS	Fitch	Moody’s	S&P
NVE	Sr. Unsecured Debt	BB (low)	BB-	Ba3	BB
NPC	Sr. Secured Debt	BBB (low)*	BBB-*	Baa3*	BBB*
NPC	Sr. Unsecured Debt	Not rated	BB	Not rated	BB+
SPPC	Sr. Secured Debt	BBB (low)*	BBB-*	Baa3*	BBB*

*Investment grade

S&P’s, Moody’s and DBRS’s rating outlook for NVE, NPC and SPPC is Stable. Fitch’s rating outlook for NVE, NPC and SPPC is Positive.

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

Energy Supplier Matters

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

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Under these contracts, a material adverse change (e.g., a credit rating downgrade) in NPC and SPPC may allow the counterparty to request adequate financial assurance, which, if not provided within three business days, could cause a default. A default must be declared within 30 days of the event, giving rise to the default becoming known. A default will result in a termination payment equal to the present value of the net gains and losses for the entire remaining term of all contracts between the parties aggregated to a single liquidated amount due within three business days following the date the notice of termination is received. The mark-to-market value, which is substantially based on quoted market prices, can be used to roughly approximate the termination payment and benefit at any point in time. The net mark-to-market value as of December 31, 2008 for all suppliers continuing to provide power under a WSPP agreement would approximate a $326.3 million payment or obligation to NPC. No amounts would be due to or from SPPC. These contracts qualify for the normal purchases scope exception of SFAS 133, and as such, are not required to be mark-to-market on the balance sheet. Refer to Note 9, Derivatives and Hedging Activities, of the Notes to Financial Statements for further discussion.

Gas Supplier Matters

With respect to the purchase and sale of natural gas, NPC and SPPC use several types of standard industry contracts. The natural gas contract terms and conditions are more varied than the electric contracts. Consequently, some of the contracts contain language similar to that found in the WSPP agreement and other agreements have unique provisions dealing with material adverse changes, which primarily means a credit rating downgrade below investment grade. Forward physical gas supplies are purchased under index based pricing terms and as such do not carry forward mark-to-market exposure. Because of creditworthiness concerns, most contracts and confirmations for natural gas purchases have been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery. At the present time, no counter-parties require payment in advance of delivery.

Gas transmission service is secured under FERC Tariffs or custom agreements. These service contracts and Tariffs require the user to establish and maintain creditworthiness to obtain service or otherwise post cash or a letter of credit to be able to receive service. Service contracts are subject to FERC approved tariffs, which, under certain circumstances, require the Utilities to provide collateral to continue receiving service. NPC has one transmission counterparty for which it is required to post cash collateral or a letter of credit in the event of credit rating downgrades. For this counterparty if NPC’s senior secured ratings from both Moody’s and S&P are below investment grade, the maximum collateral amount would be $46.1 million. If NPC’s senior unsecured rating from both Moody’s and S&P are below investment grade the maximum collateral requirement would be $11.5 million.

Financial Gas Hedges

The Utilities enter into certain hedging contracts with various counterparties to manage the gas price risk inherent in purchased power and fuel contracts. The contracts require that the Utilities maintain their Moody’s and S&P Sr. Unsecured or equivalent ratings in place at the time the contracts were entered into. In the event that the Utilities Sr. Unsecured debt rating is downgraded by two out of the three rating agencies, the counterparties have the right to require the Utilities to post cash or a letter of credit to the extent the counterparties have mark-to-market exposure to the Utilities, subject to certain caps. As of December 31, 2008, the maximum amount of collateral the Utilities would be required to post under these agreements is approximately $280.9 million based on mark-to-market values, which are substantially based on quoted market prices. Of this amount, approximately $171.0 million would be required if the Utilities are downgraded one level and an additional amount of approximately $109.9 million would be required if the Utilities are downgraded two levels.

Ability to Issue Debt

NV Energy, Inc.

Certain debt of NVE (holding company) places restrictions on debt incurrence, liens and dividends, unless, at the time the debt is incurred, the ratio of cash flow to fixed charges for NVE’s (consolidated) most recently ended four quarter period on a pro forma basis is at least 2 to 1. Under this covenant restriction, as of December 31, 2008, NVE (consolidated) would be allowed to incur up to $862 million of additional indebtedness.

Notwithstanding this restriction, under the terms of the debt, NVE (consolidated) would still be permitted to incur debt including, but not limited to, obligations incurred to finance property construction or improvement, certain intercompany indebtedness, or indebtedness incurred to finance capital expenditures, pursuant to the two Utilities’ IRPs. NPC and SPPC would also be permitted to incur a combined total of up to $500 million in indebtedness and letters of credit under their respective revolving credit facilities.

If the applicable series of debt is upgraded to investment grade by both Moody’s and S&P, these restrictions will be suspended and will no longer be in effect so long as the applicable series of Notes remain investment grade by both Moody’s and S&P (see Credit Ratings above).

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Nevada Power Company

Ability to Issue Debt

NPC’s ability to issue debt is impacted by certain factors such as financing authority from the PUCN, financial covenants in its financing agreements and revolving credit facility agreement, and the terms of certain NVE debt.

On February 4, 2009, the PUCN approved NPC’s request for financing authority to issue up to $1.25 billion of long-term debt securities over a two-year period ending December 31, 2010; ongoing authority to maintain a revolving credit facility of up to $1.3 billion, and authority to refinance up to approximately $471 million of long-term debt securities.

NPC's $600 million Second Amended and Restated Revolving Credit Agreement dated November 2005, and its supplemental Revolving Credit Agreement, dated January 5, 2009, each contain two financial maintenance covenants. The first requires NPC to maintain a ratio of consolidated indebtedness to consolidated capital, determined as of the last day of each fiscal quarter, not to exceed 0.68 to 1. The second requires NPC to maintain a ratio of consolidated cash flow to consolidated interest expense, determined as of the last day of each fiscal quarter for the period of four consecutive fiscal quarters, not to be less than 2.0 to 1. As of December 31, 2008, NPC was in compliance with these covenants. In order to maintain compliance with these covenants, NPC is limited to $898 million of additional indebtedness.

All other financial covenants contained in NPC’s revolving credit facility agreement and its financing agreements are suspended, as NPC’s senior secured debt is rated investment grade. However, if NPC’s senior secured debt ratings fall below investment grade by either Moody’s or S&P, NPC would again be subject to the limitations on indebtedness under these covenants.

Furthermore, NPC may be subject to NVE’s cap on additional consolidated indebtedness. See NVE’s Ability to Issue Debt. As of December 31, 2008, NPC’s own covenant restriction of $898 million is less restrictive than NVE’s cap on additional consolidated indebtedness of $862 million. As such, NPC is limited by NVE’s cap on additional indebtedness.

Ability to Issue General and Refunding Mortgage Securities

To the extent that NPC has the ability to issue debt under the most restrictive covenants in its financing agreements and has financing authority to do so from the PUCN, NPC’s ability to issue secured debt is still limited by the amount of bondable property or retired bonds that can be used to issue debt under NPC’s General and Refunding Mortgage Indenture (“Indenture”).

The Indenture creates a lien on substantially all of NPC’s properties in Nevada. As of December 31, 2008, $3.3 billion of NPC’s General and Refunding Mortgage Securities were outstanding. NPC had the capacity to issue $1.2 billion of General and Refunding Mortgage Securities as of December 31, 2008. That amount is determined on the basis of:

1.	70% of net utility property additions;

2.	the principal amount of retired General and Refunding Mortgage Securities; and/or

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

Property additions include plant in service and specific assets in CWIP. The amount of bond capacity listed above does not include eligible property in CWIP.

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

Sierra Pacific Power Company

Ability to Issue Debt

SPPC’s ability to issue debt is impacted by certain factors such as financing authority from the PUCN, financial covenants in its financing agreements and its revolving credit facility agreement, and the terms of certain NVE debt.

As of December 31, 2008, SPPC had approximately $495 million of PUCN financing authority, which expires on December 31, 2009.

SPPC's $350 million Amended and Restated Revolving Credit Agreement dated November 2005, contains two financial maintenance covenants. The first requires SPPC to maintain a ratio of consolidated indebtedness to consolidated capital, determined as of the last day of each fiscal quarter, not to exceed 0.68 to 1. The second requires SPPC to maintain a ratio of consolidated cash flow to consolidated interest expense, determined as of the last day of each fiscal quarter for the period of four consecutive fiscal quarters, not to be less than 2.0 to 1. As of December 31, 2008, SPPC was in compliance with these covenants. In order to maintain compliance with these covenants, SPPC is limited to $452 million of additional indebtedness.

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All other financial covenants contained in SPPC’s revolving credit facility and financing agreements are suspended as SPPC’s senior secured debt is rated investment grade. However, if SPPC’s senior secured debt ratings fall below investment grade by either Moody’s or S&P, SPPC would again be subject to the limitations on indebtedness under these covenants.

Furthermore, SPPC may be subject to NVE’s cap on additional consolidated indebtedness. See NVE’s Ability to Issue Debt. However, as of December 31, 2008, SPPC’s own covenant restriction of $452 million is more restrictive than NVE’s cap on additional consolidated indebtedness of $862 million unless NVE or NPC were to issue debt in excess of $410 million.

Ability to Issue General and Refunding Mortgage Securities

To the extent that SPPC has the ability to issue debt under the most restrictive covenants in its financing agreements and has financing authority to do so from the PUCN, SPPC’s ability to issue secured debt is still limited by the amount of bondable property or retired bonds that can be used to issue debt under SPPC’s General and Refunding Mortgage Indenture (“Indenture”).

The Indenture creates a lien on substantially all of SPPC’s properties in Nevada and California. As of December 31, 2008, $1.7 billion of SPPC’s General and Refunding Mortgage Securities were outstanding. SPPC had the capacity to issue $599 million of General and Refunding Mortgage Securities as of December 31, 2008. That amount is determined on the basis of:

1.	70% of net utility property additions;

2.	the principal amount of retired General and Refunding Mortgage Securities; and/or

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

Property additions include plant in service and specific assets in CWIP. The amount of bond capacity listed above does not include eligible property in CWIP.

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

Cross Default Provisions

None of the Utilities’ financing agreements contains a cross-default provision that would result in an event of default by that Utility upon an event of default by NVE or the other Utility under any of their respective financing agreements. Certain of NVE’s financing agreements, however, do contain cross-default provisions that would result in event of default by NVE upon an event of default by the Utilities under their respective financing agreements. In addition, certain financing agreements of each of NVE and the Utilities provide for an event of default if there is a failure under other financing agreements of that entity to meet payment terms or to observe other covenants that would result in an acceleration of payments due. Most of these default provisions (other than ones relating to a failure to pay other indebtedness) provide for a cure period of 30-60 days from the occurrence of a specified event, during which time NVE or the Utilities may rectify or correct the situation before it becomes an event of default.

ENERGY SUPPLY (UTILITIES)

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

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

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

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Energy Supply Planning

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

1.	the PUCN-approved long-term IRP filed every three years, which has a twenty-year planning horizon;

2.	the ESP, approved by the PUCN, which is an intermediate term resource procurement and risk management plan that establishes the supply portfolio strategies within which intermediate term resource requirements will be met, has a one to three year planning horizon; and

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

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

In developing and executing ESPs, management guidelines followed by the Utilities include:

•

Maintaining an ESP that balances the goals of minimizing costs, risks and price volatility (retail price stability), while maximizing reliability and predictability of supply;

•

Investigating feasible commercial options to execute the ESP;

•

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

•

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

•

Ensuring transparent and well-documented decisions and execution processes.

Energy Risk Management and Control

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

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

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

Regulatory Issues

The Utilities’ long-term IRPs are filed with the PUCN for approval every three years. Nevada law provides that resource additions approved by the PUCN in the resource planning process are deemed prudent for ratemaking purposes. NPC’s last IRP was filed in June 2006 and received approval in November 2006. SPPC’s last IRP was filed in June 2007 and received approval in December 2007. Between IRP filings, the Utilities are required to seek PUCN approval for modifications to their resource plans and for power purchases with terms of three years or greater by filing amendments to prior IRP filings. NPC’s and SPPC’s next IRP filings will be in 2009 and 2010, respectively.

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

Intermediate Term ESPs

The Utilities update their intermediate term ESPs annually. In August 2008, both SPPC and NPC filed their ESP updates for the periods 2009-2010 and 2009 respectively. Both plans were approved by the EROC and the CEO prior to submission to the PUCN. The ESPs operate within the framework of the PUCN-approved 20-year IRPs and serve as a guide for near-term execution and fulfillment of energy needs. When the ESPs call for the execution of contracts of duration of more than three years, an amendment to the IRP is prepared and submitted for PUCN approval. The fuel, power procurement and risk management strategies contained in the ESPs filed in 2008 were found to be reasonable and prudent by the PUCN in December 2008. In August 2008, SPPC filed the Fourth Amendment to its 2007 IRP and NPC filed the Ninth Amendment to its 2006 IRP as they relate to the Carson Lake Geothermal Power Project.

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In October 2008, NPC acquired the Higgins Generating Station, a 598 MW (nominally rated) natural gas-fired, combined-cycle power plant located near Primm, NV, approximately 35 miles south of Las Vegas. For the remainder of their power needs, the PUCN-approved ESPs provide for a competitive acquisition process to secure the required resources. Both Utilities have issued RFPs and executed forward contracts for their resource needs for the summer of 2009. The portfolio mix consists of owned generating resources, forward contracts for power and peaking and seasonal capacity, or synthetic tolling based contracts (i.e., power prices indexed to gas prices), to meet the following requirements:

•

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

•

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

•

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

•

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

•

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

•

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

•

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

Both of the ESPs reflect the Utilities’ strategies, embedded in their filed IRPs, to minimize supply and price risk through acquisition or construction of company owned generating resources in the intermediate term (e.g., peaking capacity at the Clark Generating Station; the Tracy Generating Station combined cycle addition), forward contracts to meet capacity needs in the shorter term, and pursuit of fuel diversity options such as coal and renewables in the longer term.

Long Term Purchased Power Activities

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

Currently, NPC has approximately 1,686 MWs of long term contracts for non-renewable resources with various providers, terms and expiration dates. SPPC currently has 278 MWs of long term contracts for non-renewable resources with various providers, terms and expiration dates.

Currently, NPC has long-term contracts for renewable resources with nameplate capacities of 404 MWs, of which 325 MWs are under construction, and SPPC has similar contracts for 192 MWs. Pursuant to those contracts, NPC and SPPC will receive renewable energy and associated PECs from solar, geothermal, hydroelectric, and biomass facilities.

Short-Term Resource Optimization Strategy

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

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

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

NEVADA POWER COMPANY

RESULTS OF OPERATIONS

NPC recognized net income of $151.4 million in 2008 compared to net income of $165.7 million in 2007 and $224.5 million in 2006. In 2008 NPC paid dividends to NVE of approximately $54.9 million. In February 2009, NPC declared a dividend of approximately $22 million to NVE. Details of NPC’s operating results are further discussed below.

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

NPC believes presenting gross margin allows the reader to assess the impact of NPC’s regulatory treatment and its overall regulatory environment on a consistent basis. Gross margin, as a percentage of revenue, is primarily impacted by the fluctuations in electric and natural gas supply costs versus the fixed rates collected from customers. While these fluctuating costs impact gross margin as a percentage of revenue, they only impact gross margin amounts if the costs cannot be passed through to customers. Gross margin, which NPC calculates as operating revenues less fuel and purchased power costs, provides a measure of income available to support the other operating expenses of NPC. For reconciliation to operating income, see Note 2, Segment Information in the Notes to Financial Statements. Gross margin changes based on such factors as general base rate adjustments (which are required to be filed by statute every three years) and reflect NPC’s strategy to increase self generation versus purchased power, which generates no gross margin.

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

	2008						2007					2006
	Amount			Change from Prior Year			Amount		Change from Prior Year			Amount
	Amount			Change from Prior Year			Amount		Change from Prior Year			Amount
Operating Revenues:
Electric	$	2,315,427			-1.7	%	$	2,356,620		10.9	%	$	2,124,081

Energy Costs:
Fuel for power generation		755,925			27.2	%		594,382		7.5	%		552,959
Purchased power		680,816			-1.1	%		688,606		-10.0	%		764,850
Deferral of energy costs - net		(6,947	)		-103.0	%		233,166		152.6	%		92,322
	$	1,429,794			-5.7	%	$	1,516,154		7.5	%	$	1,410,131


Gross Margin before reinstatement of Deferred Energy Costs	$	885,633			5.4	%	$	840,466		17.7	%	$	713,950

Reinstatement of Deferred Energy Costs1	$	-			N/A		$	-		N/A		$	178,825

Gross Margin after reinstatement of Deferred Energy Costs	$	885,633			5.4	%	$	840,466		-5.9	%	$	892,775

1Gross Margin for the year ended December 31, 2006 increased significantly from prior periods primarily due to the reinstatement of deferred energy costs as discussed further in Note 3, Regulatory Actions of the Notes to Financial Statements.

NPC’s gross margin increased for the year ended 2008 compared to the same period in 2007, primarily due to an increase in BTGR as a result of NPC’s 2006 GRC, effective June 1, 2007 and increased customer growth partially offsetting these increases was a decrease in customer usage due to cooler weather and a change in customer usage patterns.

NPC’s gross margin before reinstatement of deferred energy cost increased for the year ended 2007 compared to the same period in 2006 primarily due to an increase in BTGR revenue, as discussed above, and an increase in customer growth.

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

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Electric Operating Revenue

	2008					2007					2006
	Amount		Change from Prior Year			Amount		Change from Prior Year			Amount
Electric Operating Revenues:
Residential	$	1,064,510		-3.4	%	$	1,102,418		13.0	%	$	975,568
Commercial		471,236		-2.0	%		480,613		8.6	%		442,477
Industrial		678,117		-0.9	%		684,221		8.3	%		631,762
Retail Revenues		2,213,863		-2.4	%		2,267,252		10.6	%		2,049,807
Other		101,564		13.6	%		89,368		20.3	%		74,274
Total Revenues	$	2,315,427		-1.7	%	$	2,356,620		10.9	%	$	2,124,081

Retail sales in thousands
of megawatt-hours (MWh)		21,381		-1.1	%		21,621		3.8	%		20,820

Average retail revenue per MWh	$	103.54		-1.3	%	$	104.86		6.5	%	$	98.45

NPC’s retail revenues decreased in 2008 compared to 2007 due to decreases in retail rates and decreases in customer usage as a result of cooler summer weather and changes in customer usage patterns. Retail rates decreased as a result of NPC’s various BTER quarterly cases and Deferred Energy Cases partially offset by an increase in rates as a result of NPC’s 2006 GRC, effective June 1, 2007, see Note 3, Regulatory Actions in the Notes to Financial Statements. In 2007, NPC experienced hotter summer weather, whereas in 2008, NPC experienced milder summer weather. Average residential, commercial, and industrial customers increased by 0.8%, 2.6% and 3.8%, respectively.

NPC’s retail revenues increased in 2007 compared to 2006 due to increases in retail rates, customer growth and hotter summer weather. Retail rates increased as a result of NPC’s various BTER and Deferred Energy Cases and NPC 2006 GRC, effective June 1, 2007 (see Note 3, Regulatory Actions of the Notes to Financial Statements). Average residential, commercial and industrial customers increased by 2.7%, 4.6% and 4.6%, respectively.

Electric Operating Revenues – Other increased in 2008 compared to 2007, primarily due to the elimination of the reclassification of revenues associated with the Mohave Generating Station, as a result of NPC’s 2006 GRC which in 2007 were reclassified to Other Regulatory Assets as a result of the shut down of the Mohave Generating Station. For further discussion on the Mohave Generating Station, refer to Note 1, Summary of Significant Accounting Policies in the Notes to Financial Statements. Also contributing to the increase was transmission related revenue as a result of the Calpine settlement, as discussed further in Note 13, Commitments and Contingencies. This increase was partially offset by a decrease in energy usage by Public Authority customers due to their transitioning to DOS by purchasing their energy from other sources, as allowed by Nevada law under certain circumstances.

Electric Operating Revenues – Other increased in 2007 compared to 2006, primarily due to a decrease in the reclassification of revenues in 2007 associated with the Mohave Generating Station which have been reclassified to Other Regulatory Assets as a result of the shut down of the Mohave Generating Station. For further discussion on the Mohave Generating Station, refer to Note 1, Summary of Significant Accounting Policies in the Notes to Financial Statements. This increase was partially offset by a decrease in energy usage by Public Authority customers due to their transitioning to DOS by purchasing their energy from other sources, as allowed by Nevada law under certain circumstances.

Energy Costs

Energy Costs include Fuel for Generation and Purchased Power. Energy costs are dependent upon several factors which may vary by season or period. As a result, NPC’s usage and average cost per MWh of Fuel for Generation versus Purchased Power to meet demand can vary significantly. Factors that may affect Energy Costs include, but are not limited to:

Weather

·	Generation efficiency

·	Plant outages

·	Total system demand

·	Resource constraints

·	Transmission constraints

·	Natural gas constraints,

·	Long term contracts; and

·	Mandated power purchases

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	2008					2007					2006
			Change from					Change from
	Amount		Prior Year			Amount		Prior Year			Amount
Energy Costs	$	1,436,741		12.0	%	$	1,282,988		-2.6	%	$	1,317,809
Total System Demand		22,158		-3.8	%		23,030		2.8	%		22,408
Average cost per MWh	$	64.84		16.4	%	$	55.71		-5.3	%	$	58.81

Energy Costs and the average cost per MWh increased for the year ended December 31, 2008 compared to the same period in 2007 primarily due to higher natural gas prices. Total system demand decreased primarily due to a decrease in customer usage as a result of cooler weather and a change in customer usage patterns.

Energy costs and the average cost per MWh decreased for the year ended December 31, 2007 as compared to 2006 primarily due to NPC’s increased ability to generate its own power economically and a decrease in natural gas prices. The decrease in the average cost per MWh was partially offset by an increase in the average cost per MWh for purchased power due to hotter weather. NPC’s generation capacity is not sufficient to meet total system demand, particularly during peak times, therefore it must purchase power which is on average typically more expensive than internal generation. Total system demand increased slightly as a result of hotter weather and customer growth.

Fuel for Power Generation

	2008					2007					2006
	Amount		Change from Prior Year			Amount		Change from Prior Year			Amount

Fuel for Power Generation	$	755,925		27.2	%	$	594,382		7.5	%	$	552,959

Thousands of MWhs generated		14,968		3.1	%		14,520		19.4	%		12,160
Average fuel cost per MWh
of Generated Power	$	50.50		23.4	%	$	40.94		-10.0	%	$	45.47

Fuel for power generation costs and the average cost per MWh increased for the year ended December 31, 2008 compared to the same period in 2007 primarily due to higher natural gas prices partially offset by a decrease in the cost of hedging instruments. MWhs generated increased due to increased self generation as a result of the addition of the Clark Peaking Units and the acquisition of the Higgins Generating Station.

Fuel for power generation costs increased for the year ended December 31, 2007 compared to the same period in 2006 primarily due to an increase in volume. The additions of the Silverhawk Generating Station and the Lenzie Generating Station, which are highly efficient generating plants, greatly increased NPC’s ability to generate power at economical rates. As a result volume has increased significantly in 2007 when compared to 2006. Also contributing to the increase in volume was a 2.8% growth in total system demand as a result of hotter weather and customer growth. The average cost per MWh decreased primarily due to lower natural gas prices and efficiency of the Lenzie Generating Station and the Silverhawk Generating Station.

Purchased Power

	2008					2007					2006
			Change from					Change from
	Amount		Prior Year			Amount		Prior Year			Amount

Purchased Power	$	680,816		-1.1	%	$	688,606		-10.0	%	$	764,850

Purchased power in thousands
of MWhs		7,190		-15.5	%		8,510		-17.0	%		10,248

Average cost per MWh of
Purchased power	$	94.69		17.0	%	$	80.92		8.4	%	$	74.63

Purchased power costs decreased for the year ended December 31, 2008 compared to the same period in 2007 primarily due to a decrease in volume partially offset by higher natural gas prices. MWhs decreased primarily as a result of an increase in self generation and a decrease in total system demand. The average cost per MWh of purchased power for the year ended December 31, 2008 increased primarily due to higher natural gas prices partially offset by a decrease in the cost of hedging instruments.

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Purchased power costs decreased for the year ended December 31, 2007 compared to the same period in 2006 primarily due to a decrease in volume. The average cost per MWh increased due to fixed capacity charges associated with long term Qualified Facility contracts and other mid to long term contracts, coupled with a decrease in volume for the year. Also contributing to the increase in average cost of MWh was hotter weather, particularly during the third quarter 2007, which increased the demand for electricity and therefore required NPC to purchase additional power at peak rates.

Deferral of Energy Costs – Net

	2008						2007					2006
	Amount			Change from Prior Year			Amount		Change from Prior Year			Amount
Reinstatement of deferred energy	$	-			N/A		$	-		N/A		$	(178,825	)
Deferral of energy costs - net		(6,947	)		-103.0	%		233,166		152.6	%		92,322
	$	(6,947	)		-103.0	%	$	233,166		369.5	%	$	(86,503	)

Reinstatement of deferred energy represents the July 2006 decision by the Nevada Supreme Court which allowed NPC to recover $178.8 million of previously disallowed deferred energy costs. In March 2007, the PUCN approved the settlement agreement allowing NPC to recover such costs. Reference further discussion in Note 3, Regulatory Actions of the Notes to Financial Statements.

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

Amounts for 2008, 2007 and 2006 include amortization of deferred energy costs of $132.6 million, $177.3 million and $120.5 million, respectively; and an under-collection of amounts recoverable in rates of $139.6 million in 2008, an over-collection of $55.8 million in 2007, and an under-collection of $28.2 million in 2006.

Allowance for Funds Used During Construction

	2008					2007					2006
	Amount		Change from Prior Year			Amount		Change from Prior Year			Amount
Allowance for other funds used
during construction	$	25,917		63.4	%	$	15,861		34.9	%	$	11,755

Allowance for borrowed funds used
during construction		20,063		52.0	%		13,196		13.6	%		11,614
	$	45,980		58.2	%	$	29,057		24.3	%	$	23,369

AFUDC increased for the year ended December 31, 2008 compared to 2007 primarily due to an increase in the CWIP balance due to the expansion of the Clark Peaking Units. One block was completed in July 2008 and the remaining two blocks were completed by the end of 2008.

AFUDC was higher in 2007 compared to 2006 primarily due to construction of the Clark Peaking Units partially offset by the completion of the Lenzie Blocks 1 and 2 in early spring of 2006.

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Other (Income) and Expenses

	2008						2007						2006
	Amount			Change from Prior Year			Amount			Change from Prior Year			Amount

Other operating expense	$	249,236			7.1	%	$	232,610			6.6	%	$	218,120
Maintenance expense	$	63,282			-6.2	%	$	67,482			9.0	%	$	61,899
Depreciation and amortization	$	171,080			12.4	%	$	152,139			7.5	%	$	141,585
Interest charges on long-term debt	$	180,672			10.2	%	$	164,002			-4.2	%	$	171,188
Interest charges-other	$	26,213			9.9	%	$	23,861			40.0	%	$	17,038
Carrying charge for Lenzie	$	-			N/A		$	(16,080	)		51.9	%	$	(33,440	)
Interest accrued on deferred energy	$	(7,342	)		-71.0	%	$	(25,289	)		-15.5	%	$	(21,902	)
Other income	$	(16,631	)		15.3	%	$	(14,423	)		-15.1	%	$	(16,992	)
Other expense	$	10,221			-10.0	%	$	11,352			33.9	%	$	8,480

Other operating expense increased in 2008 compared to 2007, primarily due to the reversal of a reserve established for Enron legal fees in 2007. In March 2007, the PUCN granted recovery of these expenses, see Note 3, Regulatory Actions, of the Notes to Financial Statements for further discussion. Additionally, in 2007 certain consulting fees were reclassified to a regulatory asset, reducing expense. Also contributing to the increase in other operating expenses were higher costs for regulatory amortizations in 2008 as compared to the same period in 2007, as well as an increase in reserves for uncollectible accounts; partially offset by a decrease in claims and labor costs.

Other operating expense increased in 2007 compared to 2006 as a result of higher operating expenses for the Navajo Generating Station, operating costs associated with the Centennial Transmission line that was placed in service in 2007, increased costs for claims, legal fees and higher regulatory amortizations, partially offset by lower consulting fees and the reversal of Enron legal fees, which are now being recovered in rates as a result of NPC’s Western Energy Crisis Rate Case, as discussed above. Additionally, in 2006, operating expenses were lower primarily as a result of the settlement of contingency fees associated with Enron in the second quarter and a reallocation of expenses to our joint facility partner which decreased other operating expenses.

Maintenance expense decreased in 2008 compared to 2007 due to a forced outage at the Harry Allen Generating Station and maintenance costs incurred for the Lenzie Generating Station in 2007; partially offset by a major turbine overhaul at the Clark Generating Station as well as major forced outages at the Reid Gardner Generating Station in 2008.

Maintenance expense increased for 2007 compared to 2006 mainly due to the operation of the Lenzie Generating Station Units 1 and 2, which were placed in service in January 2006 and April 2006, respectively, the timing of outages at the Reid Gardner Generating Station (forced outages and scheduled maintenance in 2007 and deferred maintenance in 2006) and forced outages at the Harry Allen Generating Station in 2007. Also contributing to the increase were costs incurred to implement new transmission compliance requirements. These expenses were partially offset by scheduled and forced outages at the Clark Generating Station in 2006 and deferred maintenance in 2007.

Depreciation and amortization increased for the year ended December 31, 2008 compared to the same period in 2007 primarily due to an increase in plant-in-service. Plant-in-service increased primarily as a result of the inclusion of the Lenzie Generating Station in depreciation, beginning June 2007, as a result of NPC’s 2006 GRC, the completion of the Clark Peaking units in the latter part of 2008, and the purchase of the Higgins Generating Station in October of 2008. This increase was partially offset by deferred taxes for the Temporary Renewable Energy Development trust (“TRED trust”).

Depreciation and amortization increased for the year ended December 31, 2007 compared to the same period in 2006 primarily due to the inclusion of the Lenzie Generating Station in depreciation, beginning June 2007, an adjustment for the Silverhawk Generating Station depreciation based on regulatory clarification, an increase to plant-in-service for the Harry Allen Generating Station No. 4 in May 2006, an increase to plant-in-service for Centennial Transmission Project in March 2007, partially offset by the overall reduction in depreciation rates, as ordered by the PUCN in NPC’s 2006 GRC.

Interest charges on Long-Term Debt increased for the year ended December 31, 2008, compared to the same period in 2007, primarily due to the issuance of $500 million Series S General and Refunding Mortgage Notes in July 2008, the issuance of $350 million in Series R General and Refunding Mortgage Notes. This increase was partially offset by the redemption of the Series G General and Refunding Mortgage Notes of approximately $210.3 million in June 2007 and the remaining $17.2 million in August 2008.

Interest charges on Long-Term Debt decreased for the year ended December 31, 2007, compared to 2006 due primarily to various re-financings of debt in 2006 and 2007 at lower interest rates and a decrease in the use of the Revolving Credit Facility in 2007. Interest expense for the Revolving Credit Facility was approximately $6.5 million in 2007 compared to $12 million in 2006. See Note 6, Long-Term Debt of the Notes to Financial Statements for additional information regarding long-term debt.

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Interest charges-other increased for the year ended December 31, 2008, as compared to the same period in 2007, primarily due to interest charges related to IRS income tax settlements, as well as interest expense associated with refunds for construction advances. This expense was partially offset by lower interest associated with customer transmission deposits in 2008.

Interest charges-other increased for the year ended December 31, 2007, when compared to the same period in 2006, due to amortization of debt issuances and redemption costs, as well as additional interest associated with customer transmission deposits, and lease of property. See Note 6, Long-Term Debt of the Notes to Financial Statements, for additional information regarding long-term debt.

Carrying charges on the Lenzie Generating Station represent carrying charges earned on the incurred debt component of the acquisition and construction costs of the completed Lenzie Generating Station. The PUCN authorized NPC to accrue a carrying charge for the cost of acquisition and construction until the plant is included in rates. Carrying charges decreased for the year ended December 31, 2008, as compared to the same period in 2007, as a result of NPC’s 2006 GRC, which includes the cost of the Lenzie Generating Station in rates. See Note 1, Summary of Significant Accounting Policies, of the Notes to Financial Statements for discussion of the accounting for the carrying charge for the Lenzie Generating Station and Note 3, Regulatory Actions of the Notes to Financial Statements for discussion of NPC’s 2006 GRC.

Interest accrued on deferred energy decreased for the year ended December 31, 2008, when compared to the same period in 2007 primarily due to the reinstatement in 2007 of approximately $11.1 million, before taxes, for interest on deferred energy which was approved by the PUCN in 2007. See Note 3, Regulatory Actions of the Notes to Financial Statements for discussion. Also contributing to the decrease was lower deferred energy balances, partially offset by carrying charges associated with NPC’s Western Energy Crisis Rate Case, which began June 1, 2007. Interest accrued on deferred energy increased for the year ended December 31, 2007, when compared to the same period in 2006, primarily due to the reinstatement of interest on deferred energy discussed above and carry charges associated with NPC’s Western Energy Crisis Rate Case, partially offset by lower deferred energy balances. See Note 3, Regulatory Actions of the Notes to Financial Statements for further details of deferred energy balances.

Other income increased for the year ended December 31, 2008, compared to the same period in 2007, primarily due to carrying charges on energy conservation programs and the gain from the settlement with Calpine as discussed further in Note 13, Commitments and Contingencies in the Notes to Financial Statements. This income was partially offset by lower interest income in 2008 and the adjustment for and expiration of the amortization of gains associated with the disposition of property. Other income decreased for the year ended December 31, 2007, compared to the same period in 2006, due to lower interest income, and the adjustment for and expiration of the amortization of gains associated with the disposition of property.

Other expense decreased during for the year ended December 31, 2008, compared to the same period in 2007, primarily due to a decrease in deferred compensation costs and donations, partially offset by an increase in advertising costs.

Other expense increased for the year ended December 31, 2007 compared to the same period in 2006 due primarily to costs associated with the Energy Savings Project for the Clark County School District, as agreed upon in the Reid Gardner Consent Decree discussed in Note 13, Commitments and Contingencies of the Notes to Financial Statements.

ANALYSIS OF CASH FLOWS

NPC’s cash flows decreased during the year ended December 31, 2008 compared to the same period in 2007 due to a decrease in cash from operating activities and an increase in cash used for investing activities, offset partially by an increase in cash from financing activities.

Cash Used By Investing Activities. Cash used by investing activities increased primarily due to the purchase of a 598 MW (nominally rated) natural gas fired, combined cycle generating station from Reliant Energy, Inc, now known as the Higgins Generating Station, for approximately $510 million, construction at the Harry Allen Generating Station, environmental compliance upgrades and increase in construction for infrastructure, offset partially by the closing stages of major construction activity for the peaking units at the Clark Generating Station, which began in 2007.

Cash From Financing Activities. Cash from financing activities increased due to the proceeds from the issuance of $500 million 6.5% General and Refunding Mortgage Notes, Series S, due 2018, draws on the long term revolving credit facility primarily for the purchase of the Higgins Generating Station and an investment of $147 million by NVE, partially offset by higher dividends paid to NVE.

NPC’s cash flows increased during the year ended December 31, 2007, when compared to the same period in 2006 due to an increase in cash from operating activities offset by a decrease in cash from financing activities and an increase in cash used by investing activities.

Cash From Operating Activities. Cash flows from operating activities increased during the year ended December 31, 2007 compared to the same period in 2006 primarily due to increased operating income (excluding Reinstated Deferred Energy). Operating income (excluding Reinstated Deferred Energy) increased primarily as a result of increases in rates due to NPC’s GRC, the Western Energy Crisis Rate Case and the 2001 Deferred Energy Case as discussed in Note 3, Regulatory Actions of the Notes to Financial Statements. In addition, operating cash flow (excluding Reinstated Deferred Energy) increased as a result of a decrease in payments made to suppliers, the timing of payments, improved credit terms with suppliers resulting in a decrease in deposits and prepayments, a BTER rate which better reflected actual energy costs, a decrease in interest paid and the net settlement with Enron, offset by an increase in funding for retirement plans.

Cash Used By Investing Activities. Cash used by investing activities for the year ended December 31, 2007 increased compared to the same period in 2006. The increase is primarily due to 2007 expenditures for the Clark Peaking Units, the EEC and utility infrastructure to support the growth in the Las Vegas area, compared to expenditures for the Silverhawk and Lenzie Generating Stations in 2006.

Cash From Financing Activities. Cash flows from financing activities decreased for the year ended December 31, 2007 compared to the same period in 2006 due to a decrease in financing activities and capital contributions from NVE. Financing activities decreased as a result of the utilization of cash generated from operating activities.

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LIQUIDITY AND CAPITAL RESOURCES

Overall Liquidity

NPC’s primary source of operating cash flows is electric revenues, including the recovery of previously deferred energy costs. Significant uses of cash flows from operations include the purchase of electricity and natural gas, other operating expenses, capital expenditures and the payment of interest on NPC’s outstanding indebtedness. Operating cash flows can be significantly influenced by factors such as weather, regulatory outcome, and economic conditions.

Available Liquidity as of December 31, 2008 (in millions)
	NPC
Cash and Cash Equivalents	$	28.6
Balance available on Revolving Credit Facility (1)(2)		164.0

	$	192.6

	(1) NPC's available balance reflects management's estimate of a reduction in availability under its $600 million revolving credit facility of approximately $11.0 million as a result of the bankruptcy of a lending bank.
	(2) As of February 20, 2009, NPC had approximately $289.7 million available under its revolving credit facilities, which reflects the reduction discussed under (1) above and outstanding letter of credits of $15.3 million. This balance includes the combined amount available under the multi-year revolving credit facility and the 364-day supplemental revolving credit facility, described below.

NPC attempts to maintain its cash and cash equivalents in highly liquid investments, such as United States treasury bills. In addition to cash on hand and the revolving credit facilities, NPC may issue debt up to $862 million on a consolidated basis, subject to certain limitations discussed below. NPC has no significant debt maturities in 2009 or 2010, except for the balances on its revolving credit facilities, which, as of February 20, 2009 is $374.1 million. On February 4, 2009, the PUCN approved NPC’s request for financing authority to issue up to $1.25 billion of long-term debt securities over a two-year period ending December 31, 2010; ongoing authority to maintain a revolving credit facilities of up to $1.3 billion, and authority to refinance up to approximately $471 million of long-term debt securities.

In 2008, NVE contributed capital to NPC of approximately $146.6 million for general corporate purposes. In 2008, NPC paid dividends to NVE of approximately $54.9 million.

NPC anticipates that it will be able to meet short-term operating costs, such as fuel and purchased power costs, with internally generated funds, including the recovery of deferred energy and the use of its revolving credit facilities. To manage liquidity needs as a result of seasonal peaks in fuel requirements, NPC may use hedging activities. In order to fund long-term capital requirements, NPC will likely meet such financial obligations with a combination of internally generated funds, the use of the revolving credit facilities, the issuance of long-term debt, and capital contributions from NVE.

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

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

Capital Structure

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

	2008					2007
	Amount		Percent of Total Capitalization			Amount		Percent of Total Capitalization
Current Maturities of Long-Term Debt	$	8,691		0.1	%	$	8,642		0.2	%
Long-Term Debt		3,385,106		56.2	%		2,528,141		51.4	%
Common Equity		2,627,567		43.7	%		2,376,740		48.4	%
Total	$	6,021,364		100.0	%	$	4,913,523		100.0	%

Capital Requirements

Construction Expenditures

NPC’s cash requirement for construction expenditures for 2009 is projected to be $731.2 million. The majority of this requirement is for the construction of the 484 MW (nominally rated) Harry Allen Generating Station. NPC’s cash requirements for construction expenditures for 2009 through 2013 are projected to be $2.2 billion. Cash used by investing activities for the years ended 2008, 2007 and 2006 were approximately $1.3 billion, $729 million, and $620 million, respectively. To fund future capital projects NPC may meet such financial obligations with a combination of internally generated funds, the use of its revolving credit facilities, the issuance of long-term debt, and if necessary, capital contributions from NVE.

Contractual Obligations

The table below provides NPC’s consolidated contractual obligations that NPC expects to satisfy through a combination of internally generated cash and, as necessary, through the issuance of short-term and long-term debt. Certain contracts contain variable factors which required NPC to estimate the obligation depending on the final variable amount. Actual amounts could differ. The table does not include estimated construction expenditures described above, except for major capital projects for which NPC has executed contracts by December 31, 2008. Additionally, at December 31, 2008, NPC has recorded a $48.5 million liability in accordance with FIN 48, all of which is classified as non-current. NPC is unable to make a reasonably reliable estimate of the period of cash payments to relevant tax authorities; consequently, none of the FIN 48 liability is included in the contractual obligations table below (dollars in thousands):

	Payment Due by Period

	2009		2010		2011		2012		2013		Thereafter		Total

Long-Term Debt Maturities (1)	$	-	$	409,629	$	364,000	$	130,000	$	-	$	2,448,835	$	3,352,464
Long-Term Debt Interest Payments		189,551		186,072		169,043		150,470		148,005		1,712,597		2,555,738
Purchased Power		306,459		347,614		399,369		420,594		430,237		5,158,546		7,062,819
Coal, Natural Gas and Transportation		415,086		90,590		57,040		73,926		73,799		944,739		1,655,180
Long-Term Service Agreements (2)		26,108		26,390		26,680		26,979		27,286		129,610		263,053
Capital Projects (3)		332,797		166,124		8,113		-		30,638		-		537,672
Operating Leases		11,249		9,100		6,678		6,353		6,312		52,517		92,209
Capital Leases		12,467		12,466		9,630		9,493		9,510		32,668		86,234

Total Contractual Cash Obligations	$	1,293,717	$	1,247,985	$	1,040,553	$	817,815	$	725,787	$	10,479,512	$	15,605,369

(1)	Long Term Debt Maturities for 2010 includes amounts outstanding under NPC’s $600 million Revolving Credit Facility.

(2)	Includes long term service agreements for the Lenzie Generating Station, the Silverhawk Generating Station, and the Higgins Generating Station.

(3)	Capital Projects include tenant improvement project for the Beltway Complex, an operations center in southern Nevada, Harry Allen Generating Station Combined Cycle Project, Goodsprings Energy Recovery project, and the Clark Generating Station Units 5-8 Dry Low Nox Burner project.

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Pension Plan and Other Post-Retirement Matters

Financing Transactions

General and Refunding Mortgage Notes, Series U

In January 2009, NPC issued and sold $125 million of its 7.375% General and Refunding Mortgage Notes, Series U due 2014. The net proceeds of the issuance were used to repay approximately $124 million of amounts outstanding under NPC’s $600 million revolving credit facility.

Revolving Credit Facilities

In January 2009, NPC entered into a new $90 million supplemental revolving credit facility. The facility has a term of 364 days, and is secured by General and Refunding Mortgage bonds. This credit facility matures on January 3, 2010, and is in addition to NPC’s existing $600 million revolving credit facility, which matures in November 2010.

General and Refunding Mortgage Notes, Series S

In July 2008, NPC issued and sold $500 million of its 6.5% General and Refunding Mortgage Notes, Series S, due 2018. The net proceeds of the issuance were used to repay $270 million of amounts outstanding under NPC’s $600 million revolving credit facility and for general corporate purposes.

Redemption Notice

In July 2008, NPC provided a notice of redemption to the holders of all of its remaining 9.00% General and Refunding Mortgage Notes, Series G, for approximately $17.2 million. The notes were redeemed in August 2008, at 104.50% of the stated principal amount, plus accrued interest to the date of redemption. NPC used available cash on hand to redeem these notes.

Conversion of Coconino County Pollution Control Refunding Revenue Bonds and Clark County Pollution Control Revenue Bonds

In July 2008, NPC converted the $13 million principal amount Coconino County, Arizona Pollution Control Refunding Revenue Bonds Series 2006B bonds, due 2039 and the $15 million principal amount Clark County Nevada Pollution Control Revenue Bonds, Series 2000B due 2009, (collectively, the “Bonds”) from auction rate securities to variable rate demand notes. The purpose of these conversions was to reduce interest costs and volatility associated with these Bonds. NPC purchased 100% of the Bonds with the use of its revolving credit facility and available cash, and are the sole holder of the Bonds until such time as NPC determines to reoffer the Pollution Control Bonds to investors. The Bonds remain outstanding and have not been retired or cancelled. However, as NPC is the sole holder of the Bonds, for financial reporting purposes the investment in the Bonds and the indebtedness will be offset for presentation purposes.

Factors Affecting Liquidity

Ability to Issue Debt

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Ability to Issue General and Refunding Mortgage Securities

1.	70% of net utility property additions;

2.	the principal amount of retired General and Refunding Mortgage Securities; and/or

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

Property Additions include plant in service and specific assets in CWIP. The amount of bond capacity listed above does not include eligible property in CWIP.

Credit Ratings

NPC’s senior secured debt is rated investment grade by four Nationally Recognized Statistical Rating Organizations: DBRS, Fitch, Moody’s and S&P. As of December 31, 2008, the ratings are as follows:

		Rating Agency
		DBRS	Fitch	Moody’s	S&P
NPC	Sr. Secured Debt	BBB (low)*	BBB-*	Baa3*	BBB*
NPC	Sr. Unsecured Debt	Not rated	BB	Not rated	BB+

* Investment grade

S&P’s, Moody’s and DBRS’s rating outlook for NPC is Stable. Fitch’s rating outlook is Positive.

Energy Supplier Matters

With respect to NPC’s contracts for purchased power, NPC purchases and sells electricity with counterparties under the WSPP agreement, an industry standard contract that NPC uses as a member of the WSPP. The WSPP contract is posted on the WSPP website.

Under these contracts, a material adverse change (e.g., a credit rating downgrade) in NPC may allow the counterparty to request adequate financial assurance, which, if not provided within three business days, could cause a default. A default must be declared within 30 days of the event, giving rise to the default becoming known. A default will result in a termination payment equal to the present value of the net gains and losses for the entire remaining term of all contracts between the parties aggregated to a single liquidated amount due within three business days following the date the notice of termination is received. The mark-to-market value, which is substantially based on quoted market prices, can be used to roughly approximate the termination payment and benefit at any point in time. The net mark-to-market value as of December 31, 2008 for all suppliers continuing to provide power under a WSPP agreement would approximate a $326.3 million payment or obligation to NPC. These contracts qualify for the normal purchases scope exception of SFAS 133, and as such, are not required to be marked-to-market on the balance sheet. Refer to Note 9, Derivatives and Hedging Activities, of the Notes to Financial Statements for further discussion.

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Gas Supplier Matters

With respect to the purchase and sale of natural gas, NPC uses several types of standard industry contracts. The natural gas contract terms and conditions are more varied than the electric contracts. Consequently, some of the contracts contain language similar to that found in the WSPP agreement and other agreements have unique provisions dealing with material adverse changes, which primarily means a credit rating downgrade below investment grade. Forward physical gas supplies are purchased under index based pricing terms and as such do not carry forward mark-to-market exposure. Because of creditworthiness concerns, most contracts and confirmations for natural gas purchases have been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery. At the present time, no counter-parties require payment in advance of delivery.

Financial Gas Hedges

NPC enters into certain hedging contracts with various counterparties to manage the gas price risk inherent in purchased power and fuel contracts. The contracts require that NPC maintain its Moody’s and S&P Sr. Unsecured or equivalent ratings in place at the time the contracts were entered into. In the event that NPC’s Sr. Unsecured debt rating is downgraded by two out of the three rating agencies, the counterparties have the right to require NPC to post cash or a letter of credit to the extent the counterparties have mark-to-market exposure to NPC, subject to certain caps. As of December 31, 2008, the maximum amount of collateral NPC would be required to post under these agreements is approximately $193.1 million based on mark-to-market values, which are substantially based on quoted market prices. Of this amount, approximately $117.9 million would be required if NPC is downgraded one level and an additional amount of approximately $75.2 million would be required if NPC is downgraded two levels.

Cross Default Provisions

None of the financing agreements of NPC contains a cross-default provision that would result in an event of default by NPC upon an event of default by NVE or SPPC under any of its financing agreements. In addition, certain financing agreements of NPC provide for an event of default if there is a failure under other financing agreements of NPC to meet payment terms or to observe other covenants that would result in an acceleration of payments due. Most of these default provisions (other than ones relating to a failure to pay such other indebtedness when due) provide for a cure period of 30-60 days from the occurrence of a specified event during which time NPC may rectify or correct the situation before it becomes an event of default.

SIERRA PACIFIC POWER COMPANY

RESULTS OF OPERATIONS

SPPC recognized net income of $90.6 million for the year ended December 31, 2008, compared to net income of $65.7 million in 2007 and a net income of $57.7 million in 2006. In 2008, SPPC paid dividends to NVE of approximately $141.5 million and had approximately $96.8 million in dividends payable to NVE as of December 31, 2008. In 2009, SPPC paid $96.8 million for dividends declared prior to December 31, 2008, and declared an additional dividend of $12 million in February 2009. Details of SPPC’s operating results are further discussed below.

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

SPPC believes presenting gross margin allows the reader to assess the impact of SPPC’s regulatory treatment and its overall regulatory environment on a consistent basis. Gross margin, as a percentage of revenue, is primarily impacted by the fluctuations in regulated electric and natural gas supply costs versus the fixed rates collected from customers. While these fluctuating costs impact gross margin as a percentage of revenue, they only impact gross margin amounts if the costs cannot be passed through to customers. Gross margin, which SPPC calculates as operating revenues less fuel and purchased power costs, provides a measure of income available to support the other operating expenses of SPPC. For reconciliation to operating income, see Note 2, Segment Information in the Notes to Financial Statements. Gross margin changes based on such factors as general base rate adjustments (which are required to be filed by statute every three years) and reflect SPPC’s strategy to increase self generation versus purchased power, which generates no gross margin.

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

	2008						2007					2006
				Change from					Change from
	Amount			Prior Year			Amount		Prior Year			Amount
Operating Revenues:
Electric	$	1,002,674			-3.5	%	$	1,038,867		1.8	%	$	1,020,162
Gas		209,987			2.2	%		205,430		-2.2	%		210,068
	$	1,212,661			-2.5	%	$	1,244,297		1.1	%	$	1,230,230

Energy Costs:
Fuel for power generation	$	283,342			16.6	%	$	242,973		-1.9	%	$	247,626
Purchased power		293,527			-15.7	%		348,299		1.1	%		344,590
Gas purchased for resale		170,468			13.0	%		150,879		-6.1	%		160,739
Deferral of energy costs – electric - net		1,291			-98.3	%		78,044		65.9	%		47,043
Deferral of energy costs – gas - net		(4,609	)		-142.8	%		10,763		54.9	%		6,947
	$	744,019			-10.5	%	$	830,958		3.0	%	$	806,945
Energy Costs by Segment:
Electric	$	578,160			-13.6	%	$	669,316		4.7	%	$	639,259
Gas		165,859			2.6	%		161,642		-3.6	%		167,686
	$	744,019			-10.5	%	$	830,958		3.0	%	$	806,945

Gross Margin by Segment:
Electric	$	424,514			14.9	%	$	369,551		3.0	%	$	380,903
Gas		44,128			0.8	%		43,788		3.3	%		42,382
	$	468,642			13.4	%	$	413,339		2.3	%	$	423,285

SPPC’s electric gross margin increased for the year ended 2008, compared to the same period in 2007, primarily due to an increase in BTGR revenue as a result of SPPC’s 2007 GRC, effective July 1, 2008, increased customer growth, and in 2007 a charge of approximately $14.2 million for deferred energy disallowed. See Note 3, Regulatory Actions of the Notes to Financial Statements. Partially offsetting these increases was a decrease in customer usage primarily due to cooler weather.

SPPC’s electric gross margin decreased for the year ended 2007 compared to the same period in 2006, primarily due to deferred energy costs disallowed as discussed above and a decrease in revenue per MWh for commercial and industrial customers and usage per industrial customers. These decreases were partially offset by an increase to customer growth.

SPPC’s gas gross margin increased for the year ended 2008, compared to the same period in 2007, primarily due to increased customer usage as a result of colder winter temperatures. SPPC’s gas gross margin increased slightly for the year ended 2007, compared to the same period in 2006, primarily due to customer growth, partially offset by a decrease in usage by customers due to warmer weather, and a decrease in BTGR rates as a result of SPPC’s gas GRC.

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

Electric Operating Revenues

	2008					2007					2006
	Amount		Change from Prior Year			Amount		Change from Prior Year			Amount
Electric Operating Revenues:
Residential	$	340,972		3.2	%	$	330,557		3.6	%	$	319,140
Commercial		386,678		0.6	%		384,364		3.7	%		370,617
Industrial		240,711		-17.9	%		293,270		-2.0	%		299,163
Retail revenues		968,361		-4.0	%		1,008,191		1.9	%		988,920
Other		34,313		11.9	%		30,676		-1.8	%		31,242
Total Revenues	$	1,002,674		-3.5	%	$	1,038,867		1.8	%	$	1,020,162

Retail sales in thousands
of megawatt-hours (MWh)		8,560		-2.4	%		8,773		0.7	%		8,711

Average retail revenue per MWh	$	113.13		-1.6	%	$	114.92		1.2	%	$	113.53

Retail revenues decreased for the year ended December 31, 2008 compared to the same period in 2007 primarily due to lower industrial revenue, decreases in retail rates, and decreased customer usage due to cooler summer temperatures. Industrial revenues decreased primarily due to a new retail service agreement with Newmont Mining Corporation beginning in June 2008. In addition, Cortez Mine transitioned to DOS effective November 1, 2008. Two large industrial customers also moved to DOS and standby service during the second quarter of 2007. Retail rates decreased as a result of SPPC’s various BTER quarterly cases and the annual Deferred Energy case but were partially offset by increased BTGR as a result of the GRC effective July 1, 2008 (see Note 3, Regulatory Actions of the Notes to Financial Statements). These decreases were partially offset by increases in the average number of residential, commercial, and industrial customers (0.5%, 2.0% and 4.5% respectively).

In 2007, SPPC and Newmont Mining Corporation entered into a wholesale power sale agreement and a new form of retail service, whereby Newmont will sell the electrical output from it’s generating plant to SPPC for at least 15 years under a long-term wholesale purchase power agreement and remain a retail customer of SPPC during at least that period under the terms of the retail service agreement and pursuant to a new rate schedule. The terms of these contracts became effective on June 1, 2008, at which point Newmont moved to a new retail service agreement at a reduced energy rate, which resulted in decreased electric revenues.

Retail revenues increased for the year ended December 31, 2007, compared to the same period in 2006, primarily due to customer growth and increases in retail rates. The average number of residential, commercial and industrial customers increased (1.6%, 3.0% and 5.4% respectively). Retail rates increased as a result of SPPC’s various general, energy and deferred energy cases (see Note 3, Regulatory Actions of the Notes to Financial Statements). These increases were partially offset by lower industrial energy revenues and MWh’s as a result of two large industrial customers moving to DOS and standby service.

Electric Operating Revenues - Other increased for the year ended December 31, 2008, compared to the same period in 2007, was primarily due to increased transmission wheeling revenue. Additionally, contributing to the increase was the recognition of BTGR impact charge as a result of Newmont Mining Corporation’s transition discussed above. These increases were offset by a decrease in charges related to the departure of Barrick Gold Corporation from SPPC’s system.

Electric Operating Revenues - Other decreased for the year ended December 31, 2007, compared to 2006, primarily due to a decrease in the amortization of impact charges resulting from Barrick Gold Corporation becoming a DOS customer.

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Gas Operating Revenues

	2008					2007					2006
	Amount		Change from Prior Year			Amount		Change from Prior Year			Amount
Gas Operating Revenues:
Residential	$	114,845		-2.6	%	$	117,871		-2.4	%	$	120,734
Commercial		52,163		-2.6	%		53,551		-1.4	%		54,316
Industrial		19,514		-3.1	%		20,145		-1.8	%		20,509
Retail revenues		186,522		-2.6	%		191,567		-2.0	%		195,559
Wholesale		20,956		88.5	%		11,116		-4.6	%		11,650
Miscellaneous		2,509		-8.7	%		2,747		-3.9	%		2,859
Total Revenues	$	209,987		2.2	%	$	205,430		-2.2	%	$	210,068

Retail sales in thousands
of Dth		15,070		1.2	%		14,893		-1.1	%		15,058

Average retail revenues per Dth	$	12.38		-3.7	%	$	12.86		-1.0	%	$	12.99

Retail gas revenues decreased for the year ended December 31, 2008, as compared to the same period in 2007, primarily due to decreases in retail customer rates. Retail rates decreased as a result of SPPC’s 2007 and 2008 Natural Gas and Propane Deferred Rate Case and BTER updates. See Note 3, Regulatory Actions of the Notes to Financial Statements. This decrease was partially offset by increased usage due to colder winter temperatures and growth in retail customers. The average number of retail customers increased by 1.2%.

Retail gas revenues decreased for the year ended December 31, 2007, compared to the same period in 2006, primarily due to warmer temperatures during 2007 and decreases in retail customer rates. Retail rates decreased as a result of SPPC’s Gas GRC and 2006 and 2007 Natural Gas and Propane Deferred Rate Case and BTER updates. See Note 3, Regulatory Actions of the Notes to Financial Statements. Partially offsetting these decreases was the growth in retail customers. The average number of retail customers increased by 3.0%.

Wholesale revenues increased for the year ended December 31, 2008, compared to the same period in 2007, primarily due to increased availability of gas for wholesale sales during the second half of 2008. Wholesale revenues decreased in 2007, compared to 2006, primarily due to decreased availability of gas for wholesale sales.

Energy Costs

Energy Costs include Fuel for Generation and Purchased Power. These costs are dependent upon many factors which may vary by season or period. As a result, SPPC’s usage and average cost per MWh of Fuel for Generation versus Purchased Power can vary significantly as the company meets the demands of the season. These factors include, but are not limited to:

Weather

·	Plant outages

·	Total system demand

·	Resource constraints

·	Transmission constraints

·	Gas transportation constraints

·	Natural gas constraints

·	Long term contracts

·	Mandated power purchases; and

·	Generation efficiency

	2008					2007					2006
			Change from					Change from
	Amount		Prior Year			Amount		Prior Year			Amount
Energy Costs	$	576,869		-2.4	%	$	591,272		-0.2	%	$	592,216
Total System Demand		9,180		-2.4	%		9,408		0.6	%		9,350
Average cost per MWh	$	62.84		0.0	%	$	62.85		-0.8	%	$	63.34

Energy costs decreased for the year ended December 31, 2008, compared to the same period in 2007, primarily due to a decrease in total system demand. The average cost per MWh remained relatively stable in 2008 compared to 2007. The average cost per MWh for energy costs, self generation and purchased power can fluctuate considerably during the year. When hydro conditions are favorable it is more economical for SPPC to purchase more power relative to self generation. However, transmission capacity constraints limit the amount of power that SPPC can purchase and import into its service territory. In the third quarter 2008, SPPC’s Tracy Generating Station expansion became commercially operable, thereby increasing SPPC’s ability to self generate compared to prior years.

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Energy costs and the average cost per MWh remained relatively stable for the year ended December 31, 2007 compared to the same period in 2006.

Fuel for Power Generation

	2008					2007					2006
	Amount		Change from Prior Year			Amount		Change from Prior Year			Amount

Fuel for Power Generation	$	283,342		16.6	%	$	242,973		-1.9	%	$	247,626

Thousands of MWhs generated		4,633		14.9	%		4,032		0.4	%		4,016
Average fuel cost per MWh
of Generated Power	$	61.16		1.5	%	$	60.26		-2.3	%	$	61.66

Fuel for power generation increased for the year ended December 31, 2008, compared to the same period in 2007, primarily due to an increase in the use of self generation with the expansion at the Tracy Generating Station and higher natural gas prices. The average fuel cost per MWh increased in 2008, compared to 2007, primarily due to higher natural gas prices, partially offset by a decrease in costs for hedging instruments and the use of the new Tracy Generating Station units which are more efficient generating units than SPPC had available in prior years.

Fuel for power generation and the average fuel cost per MWh decreased in 2007 compared to 2006. The decrease is primarily due to a decrease in natural gas costs in 2007 and higher cost for hedging instruments in 2006.

Purchased Power

	2008					2007					2006
			Change from					Change from
	Amount		Prior Year			Amount		Prior Year			Amount

Purchased Power	$	293,527		-15.7	%	$	348,299		1.1	%	$	344,590

Purchased power in thousands
of MWh		4,547		-15.4	%		5,376		0.8	%		5,334

Average cost per MWh of
Purchased Power	$	64.55		-0.4	%	$	64.79		0.3	%	$	64.60

Purchased power costs decreased for the year ended December 31, 2008, compared to the same period in 2007, primarily due to increased self generation with the expansion at the Tracy Generating Station. The average cost per MWh decreased slightly in 2008 compared to 2007 primarily due to the Newmont Mining Corporation contract, discussed under Electric Operating Revenues above, partially offset by higher natural gas prices.

Purchased power costs increased slightly for the year ended December 31, 2007, compared to the same period in 2006. Typically, in the first half of the year, SPPC is able to purchase hydro power at low prices; however, the availability of hydro power can fluctuate from year to year depending weather. In the first half of 2007, the availability of hydro power was lower compared to 2006, as such, purchased power costs were higher. This increase was partially offset by a decrease in purchased power costs in the second half of 2007 as a result of lower natural gas prices.

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Gas Purchased for Resale

	2008					2007					2006
	Amount		Change from Prior Year			Amount		Change from Prior Year			Amount

Gas Purchased for Resale	$	170,468		13.0	%	$	150,879		-6.1	%	$	160,739

Gas Purchased for Resale (in thousands of Dth)		19,265		10.9	%		17,378		-0.6	%		17,491

Average Cost per Dth	$	8.85		2.0	%	$	8.68		-5.5	%	$	9.19

The cost of gas purchased for resale and average cost per Dth increased for the year ended December 31, 2008, compared to the same period in 2007. The increase is primarily due to an increase in natural gas prices which were partially offset by a decrease in the costs associated with hedging instruments. The volume of gas purchased for resale increased in 2008 compared to 2007 primarily due to colder weather in 2008.

The cost of gas purchased for resale decreased for the year end December 31, 2007, compared to the same period in 2006. The decrease is primarily due to a decrease in natural gas prices which were partially offset by an increase in hedging instrument costs. The volume of gas purchased for resale decreased slightly in 2007 compared to 2006 primarily due to milder winter weather in the beginning of 2007.

Deferral of Energy Costs – Net

	2008						2007					2006
	Amount			Change from Prior Year			Amount		Change from Prior Year			Amount

Deferral of energy costs - electric - net	$	1,291			-98.3	%	$	78,044		65.9	%	$	47,043
Deferral energy costs - gas - net		(4,609	)		-142.8	%		10,763		54.9	%		6,947
Total	$	(3,318	)				$	88,807				$	53,990

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

Deferral of energy costs - electric – net for 2008, 2007 and 2006 reflect amortization of deferred energy costs of $16.3 million, $44.1 million and $46.3 million, respectively; and an under-collection of amount recoverable in rates of $15 million in 2008, and an over-collection of $19.7 million and $0.7 million, in 2007 and 2006 respectively. See Note 1, Summary of Significant Accounting Policies, Deferral of Energy Costs of the Notes to Financial Statements for further detail of deferred energy balances. In addition, the amount for 2007 includes the November 2007 disallowance of $14.2 million by the PUCN of deferred settlement costs incurred to resolve claims arising from the Western Energy Crisis. Reference Note 3, Regulatory Actions of the Notes to Financial Statements.

Deferral of energy costs - gas - net for 2008, 2007 and 2006 reflect amortization of deferred energy costs of $1 million, $0.7 million and $6.3 million, respectively; and an under-collection of amount recoverable in rates of $3.6 million in 2008, and an over-collection of $10.1 million and $0.6 million in 2007 and 2006, respectively.

Allowance for Funds Used During Construction

	2008					2007					2006
	Amount		Change from Prior Year			Amount		Change from Prior Year			Amount
Allowance for other funds used
during construction	$	12,524		-21.5	%	$	15,948		146.5	%	$	6,471

Allowance for borrowed funds used
during construction		9,464		-25.9	%		12,771		132.0	%		5,505
	$	21,988		-23.4	%	$	28,719		139.8	%	$	11,976

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AFUDC was lower for the year ended December 31, 2008 compared to the same period in 2007 primarily due to the completion of the Tracy Generating Station in July of 2008, which resulted in a decrease in the CWIP balance.

AFUDC increased for the year ended December 31, 2007 compared to the same period in 2006 primarily due to an increase in the CWIP balance due to the expansion of the Tracy Generating Station which started in late 2005.

Other (Income) and Expenses

	2008						2007						2006
	Amount			Change from Prior Year			Amount			Change from Prior Year			Amount

Other operating expense	$	141,064			-0.9	%	$	142,348			0.7	%	$	141,350
Maintenance expense	$	30,787			-2.4	%	$	31,553			0.8	%	$	31,273
Depreciation and amortization	$	89,528			7.4	%	$	83,393			-4.5	%	$	87,279
Interest charges on long-term debt	$	76,256			13.0	%	$	67,502			-6.1	%	$	71,869
Interest charges-other	$	5,920			-1.4	%	$	6,004			16.8	%	$	5,142
Interest accrued on deferred energy	$	2,087			-341.3	%	$	(865	)		-85.6	%	$	(5,996	)
Other income	$	(12,819	)		58.4	%	$	(8,091	)		-14.0	%	$	(9,412	)
Other expense	$	8,318			-1.5	%	$	8,441			0.2	%	$	8,422

Other operating expense decreased for the year ended December 31, 2008, compared to the same period in 2007, primarily due to a disallowance by the PUCN of deferred settlement costs incurred to resolve claims arising from the Western Energy Crisis in November 2007. Also contributing to the decrease in other operating expense were lower cost for claims and legal fees, as well as, a reduction in bad debt expense and lower labor costs; partially offset by higher regulatory amortizations.

Other operating expense increased slightly in 2007 compared to 2006, primarily due to an increase in legal claims, higher regulatory amortizations and in 2006, operating expenses were lower primarily as a result of the settlement of contingency fees associated with Enron in the second quarter.

Maintenance expense decreased for 2008 compared to 2007 due to outages in 2007 at the Valmy Generating Station for turbine and boiler tube repairs; partially offset by higher maintenance expense for the Tracy Generating Station placed in service July 2008.

Maintenance expense increased slightly in 2007 compared to 2006 primarily due to new transmission regulations, partially offset by lower maintenance cost for Ft. Churchill Generating Station due to planned outages in 2006 and delayed outages for 2007.

Depreciation and amortization increased for the year ended December 31, 2008, compared to the same period in 2007, primarily due to the completion of the Tracy Generating Station in July of 2008. This increase was partially offset by deferred taxes for the TRED trust.

Depreciation and amortization decreased for the year ended 2007 compared to the same period in 2006 due to retirement of plant assets as approved by the PUCN in SPPC’s general electric and gas rate cases in June 2006. Also contributing to the decrease was a reduction in depreciation rates as ordered by the PUCN in SPPC’s general electric and gas rate cases in June 2006.

Interest charges on long-term debt increased for the year ended December 31, 2008, compared to the same period in 2007, primarily due to the issuance of $250 million Series Q General and Refunding Mortgage Notes in September 2008, and the issuance of the $325 million Series P General and Refunding Mortgage Notes in June 2007. These amounts were partially offset by the redemption of $99 million Series A General and Refunding Mortgage Bonds in June 2008, and the redemption of the $221 million Series A General and Refunding Mortgage Bonds in June 2007.

Interest charges on long-term debt for the year ended December 31, 2007 decreased from 2006 primarily due to various re-financings of debt in 2006 at lower interest rates, redemption of debt, and the refinancing of $80 million Water Facilities Refunding Revenue Bonds from fixed to variable rate in April 2007. These re-financings and redemptions were partially offset by the issue of $300 million Series M notes in March 2006 and the issue of $325 million Series P notes in June 2007.

Interest charges-other for the year ended December 31, 2008 was comparable to the same period in 2007. Interest charges-other for the year ended December 31, 2007 increased compared to the same period in 2006 due to higher amortization costs related to new debt issues in 2006 and 2007

Interest accrued on deferred energy costs decreased for the year ended December 31, 2008, compared to the same period in 2007, due to over collected deferred energy costs in 2008. Interest accrued on deferred energy costs for the year ended December 31, 2007 decreased compared to the same period in 2006 primarily due to lower deferred energy balances during 2007. See Note 3, Regulatory Actions of the Notes to Financial Statements for further details of deferred energy balances.

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Other income increased for the year ended December 31, 2008 compared to the same period in 2007, primarily due to the reinstatement of previously disallowed costs associated with Pinon Pine, as discussed in Note 3, Regulatory Actions of the Notes to Financial Statements, and the settlement with Calpine, as discussed further in Note 13, Commitments and Contingencies of the Notes to Financial Statements. This increase was partially offset by lower interest income on investments and a refund of expenses in 2007. Other income decreased for the year ended December 31, 2007, compared to the same period in 2006 due to the expiration of the amortization of gains associated with the disposition of property and lower interest income in 2007, offset by a refund of expenses.

Other expense decreased slightly during the year ended December 31, 2008, when compared to the same period in 2007, due primarily to development costs in 2007 associated with an information technology system conversion project, offset by higher advertising costs and donations in 2008. Other expense for the year ended December 31, 2007 was comparable to the same period in 2006.

ANALYSIS OF CASH FLOWS

SPPC’s Cash flows decreased for the year ended December 31, 2008, compared to the same period in 2007, due to a decrease in cash flows from operating activities and cash from financing activities partially offset by a decrease in cash used in investing activities.

Cash Used By Investing Activities. Cash used by investing activities decreased primarily due to the closing stages of major construction activity at the Tracy Generating Station, which began in 2006.

Cash From Financing Activities. The decrease in cash from financing activities is primarily due to dividend payments to NVE of approximately $142 million and a reduction in investment from NVE, partially offset by the issuance of $250 million 5.45%, General and Refunding Mortgage Notes, Series Q due 2013 and draws on the long term revolving credit facility.

Cash flows decreased for the year ended December 31, 2007, compared to the same period in 2006, due to an increase in cash used by investing activities and a decrease in cash from operating activities, partially offset by an increase in cash from financing activities.

Cash From Operating Activities. Cash from operating activities decreased for the year ended December 31, 2007, as compared to the same period in 2006, as a result of a decrease in cash from accounts receivable and an increase in payments for pension and other post retirement benefits, offset by an increase in accrued interest related to the issuance of SPPC’s 6.75% General and Refunding Mortgage Notes, Series P, a reduction in prepayments for energy in 2006 and the net settlement with Enron in 2006. The decrease in cash from accounts receivable is primarily due to $49.7 million affiliated accounts receivable related to tax sharing agreements which were outstanding at December 31, 2005 and settled in 2006, offset by increased customer payments.

Cash Used By Investing Activities. Cash used by investing activities increased during the year ended December 31, 2007, compared to the same period in 2006, primarily due to construction costs associated with the expansion of the Tracy Generating Station and utility infrastructure to support growth.

Cash From Financing Activities. Cash from financing activities increased during the year ended December 31, 2007, compared to the same period in 2006, primarily due to the issuance of $325 million of SPPC’s 6.75% General and Refunding Mortgage Notes, Series P, a reduction in the redemption of debt and preferred stock and dividends paid to NVE in 2006.

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LIQUIDITY AND CAPITAL RESOURCES

Overall Liquidity

SPPC’s primary source of operating cash flows is electric revenues, including the recovery of previously deferred energy costs. Significant uses of cash flows from operations include the purchase of electricity and natural gas, other operating expenses, capital expenditures and the payment of interest on SPPC’s outstanding indebtedness. Operating cash flows can be significantly influenced by factors such as weather, regulatory outcome and economic conditions.

Available Liquidity as of December 31, 2008 (in millions)
	SPPC
Cash and Cash Equivalents	$	21.4
Balance available on Revolving Credit Facility (1)(2)		162.0

	$	183.4

	(1)		SPPC's available balance reflects management's estimate of a reduction in availability under its $350 million revolving credit facility of approximately $18.0 million as a result of the bankruptcy of a lending bank.
	(2)		As of February 20, 2009, SPPC had approximately $110.6 million available under its $350 million revolving credit facility, which reflects the reduction discussed under (1) above and outstanding letter of credits of $17.1 million.

SPPC attempts to maintain its cash and cash equivalents in highly liquid investments, such as United States treasury bills. In addition to cash on hand and the revolving credit facility, SPPC may issue debt up to $452 million on a consolidated basis, subject to certain limitations discussed below. SPPC has no debt maturing in 2009 or 2010, except for the balance on its revolving credit facility, which as of February 20, 2008 is $204.7 million.

In 2008, NVE contributed capital to SPPC of approximately $20 million for general corporate purposes. In 2008, SPPC paid dividends to NVE of approximately $141.5 million.

SPPC anticipates that it will be able to meet short-term operating costs, such as fuel and purchased power costs, with internally generated funds, including the recovery of deferred energy and the use of its revolving credit facility. To manage liquidity needs as a result of seasonal peaks in fuel requirements, SPPC may use hedging activities. In order to fund long-term capital requirements, SPPC will likely meet such financial obligations with a combination of internally generated funds, the use of the revolving credit facility, the issuance of long-term debt and capital contributions from NVE.

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

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

Capital Structure

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

	2008					2007
	Amount		Percent of Total Capitalization			Amount		Percent of Total Capitalization
Current Maturities of Long-Term Debt	$	600		0.0	%	$	101,643		4.6	%
Long-Term Debt		1,395,987		61.4	%		1,084,550		49.6	%
Common Equity		877,961		38.6	%		1,001,840		45.8	%
Total	$	2,274,548		100.0	%	$	2,188,033		100.0	%

Capital Requirements

Construction Expenditures

SPPC’s cash construction expenditures for 2009 are projected to be $189.3 million. SPPC’s cash construction expenditures for 2009 through 2013 are projected to be $873.9 million. Cash construction expenditures for the years ended 2008, 2007 and 2006 were approximately $207.8 million, $393.2 million and $284.4 million, respectively. To fund future capital projects SPPC may meet such financial obligations with a combination of internally generated funds, the use of its revolving credit facility and if necessary, the issuance of long-term debt and/or capital contributions from NVE.

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Contractual Obligations

The table below provides SPPC’s consolidated contractual obligations that SPPC expects to satisfy through a combination of internally generated cash and, as necessary, through the issuance of short-term and long-term debt. Certain contracts contain variable factors which required SPPC to estimate the obligation depending on the final variable amount. Actual amounts could differ. The table does not include estimated construction expenditures described above, except for major capital projects for which SPPC has executed contracts by December 31, 2008. Additionally, at December 31, 2008, SPPC recorded a $40.2 million liability in accordance with FIN 48, all of which is classified as non-current. SPPC is unable to make a reasonably reliable estimate of the period of cash payments to relevant tax authorities; consequently, none of the FIN 48 liability is included in the contractual obligations table below (dollars in thousands):

	Payment Due by Period
	2009		2010		2011		2012		2013		Thereafter		Total

Long-Term Debt Maturities (1)	$	600	$	152,912	$	-	$	100,000	$	250,000	$	883,500	$	1,387,012
Long-Term Debt Interest Payments		71,956		71,318		71,318		66,891		65,068		801,233		1,147,784
Purchased Power		126,847		188,451		237,668		253,886		260,250		4,015,875		5,082,977
Coal, Natural Gas and Transportation		281,930		92,835		58,524		43,438		42,981		246,518		766,226
Long-Term Service Agreements		5,240		5,240		5,240		5,240		5,240		40,209		66,409
Operating Leases		11,564		9,826		2,700		2,515		2,508		37,339		66,452

Total Contractual Cash Obligations	$	498,137	$	520,582	$	375,450	$	471,970	$	626,047	$	6,024,674	$	8,516,860

(1)	Long Term Debt Maturities for 2010 includes amounts outstanding under SPPC’s Revolving Credit Facility.

Pension Plan and Other Post-Retirement Matters

NVE has a qualified pension plan and other post retirement benefits plan which cover substantially all employees of NVE, NPC and SPPC. The annual net benefit cost for the plans is expected to increase in 2009 by approximately $31.7 million compared to the 2008 cost of $31.5 million. As of December 31, 2008, the measurement date, the plans were under funded under the provisions of FAS 158. Refer to Note 11, Retirement Plan and Post-Retirement Benefits, of the Notes to Financial Statements. During 2008, NVE funded a total of $100 million to the trusts established for these plans. At the present time it is expected that additional funding will be required in 2009 to meet the minimum funding level requirements defined by the Pension Protection Act of 2006. NVE’s funding requirements may change subject to market conditions; as a result, NVE is unable to predict what the funding amount may be in 2009. NVE is expected to fund approximately $70 million to the trusts in 2009.

Financing Transactions

Revolving Credit Facility

SPPC’s existing $350 million revolving credit facility has a maturity date of November 2010.

Conversion of Washoe County Water Facilities Refunding Revenue Bonds

In January 2009, SPPC converted the $40 million principal amount, Washoe County, Nevada Water Facilities Refunding Revenue Bonds Series 2007A bonds, due 2036 (the “Water Bonds”) from auction rate securities to variable rate demand notes. The purpose of the conversion was to reduce interest costs and volatility associated with these bonds. SPPC purchased 100% of the Water Bonds on that date, with the use of its revolving credit facility and available cash, and will remain the sole holder of the Water Bonds, until such time as SPPC determines to reoffer the Water Bonds to investors. These Water Bonds remain outstanding and have not been retired or cancelled. However, as SPPC is the sole holder of the Water Bonds, for financial reporting purposes the investment in the Water Bonds and the indebtedness will be offset for presentation purposes.

Conversion of Humboldt County Pollution Control Refunding Revenue Bonds Series 2006

In October 2008, SPPC converted the $49.8 million principal amount, Humboldt County, Nevada Pollution Control Refunding Revenue Bonds Series 2006 bonds, due 2029 (the “Pollution Control Bonds”) from auction rate securities to variable rate demand notes. The purpose of the conversion was to reduce interest costs and volatility associated with these bonds. SPPC purchased 100% of the Pollution Control Bonds on that date, with the use of its revolving credit facility and available cash, and are the sole holder of the Pollution Control Bonds until such time as SPPC determines to reoffer the Pollution Control Bonds to investors. The Pollution Control Bonds remain outstanding and have not been retired or cancelled. However, as SPPC is the sole holder of the Pollution Control Bonds, for financial reporting purposes the investment in the Pollution Control Bonds and the indebtedness will be offset for presentation purposes.

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General and Refunding Mortgage Notes, Series Q

In September 2008, SPPC issued and sold $250 million of its 5.45% General and Refunding Mortgage Notes, Series Q, due 2013. The net proceeds of the issuance were used to repay $238 million of amounts outstanding under SPPC’s revolving credit facility and for general corporate purposes.

Conversion of Washoe County Water Facilities Refunding Revenue Bonds

In July 2008, SPPC converted the $40 million principal amount, Washoe County, Nevada Water Facilities Refunding Revenue Bonds Series 2007B bonds, due 2036 (the “Water Bonds”) from auction rate securities to variable rate demand notes. The purpose of the conversion was to reduce interest costs and volatility associated with these bonds. SPPC purchased 100% of the Water Bonds on that date, with the use of its revolving credit facility and available cash, and will remain the sole holder of the Water Bonds, until such time as SPPC determines to reoffer the Water Bonds to investors. These Water Bonds remain outstanding and have not been retired or cancelled. However, as SPPC is the sole holder of the Water Bonds, for financial reporting purposes the investment in the Water Bonds and the indebtedness will be offset for presentation purposes.

Maturity of General and Refunding Mortgage Bonds, Series A

In June 2008, the 8.00% General and Refunding Mortgage Bonds, Series A, in the aggregate principal amount of approximately $99.2 million, matured. SPPC paid for the maturing debt plus interest with the use of $90 million from its revolving credit facility plus cash on hand.

Factors Affecting Liquidity

Ability to Issue Debt

As of December 31, 2008, SPPC had approximately $495 million of PUCN financing authority, which expires on December 31, 2009.

Ability to Issue General and Refunding Mortgage Securities

The Indenture creates a lien on substantially all of SPPC’s properties in Nevada. As of December 31, 2008, $1.7 billion of SPPC’s General and Refunding Mortgage Securities were outstanding. SPPC had the capacity to issue $599 million of General and Refunding Mortgage Securities as of December 31, 2008. That amount is determined on the basis of:

1.	70% of net utility property additions;

2.	the principal amount of retired General and Refunding Mortgage Securities; and/or

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

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Property Additions include plant in service and specific assets in CWIP. The amount of bond capacity listed above does not include eligible property in CWIP.

Credit Ratings

SPPC’s senior secured debt is rated investment grade by four Nationally Recognized Statistical Rating Organizations: DBRS, Fitch, Moody’s and S&P. As of December 31, 2008, the ratings are as follows:

		Rating Agency
		DBRS	Fitch	Moody’s	S&P
SPPC	Sr. Secured Debt	BBB (low)*	BBB-*	Baa3*	BBB*

* Investment grade

S&P’s, Moody’s and DBRS’s rating outlook for SPPC is Stable. Fitch’s rating outlook is Positive.

Energy Supplier Matters

With respect to SPPC’s contracts for purchased power, SPPC purchases and sells electricity with counterparties under the WSPP agreement, an industry standard contract that SPPC uses as a member of the WSPP. The WSPP contract is posted on the WSPP website.

Under these contracts, a material adverse change (e.g., a credit rating downgrade) in SPPC may allow the counterparty to request adequate financial assurance, which, if not provided within three business days, could cause a default. A default must be declared within 30 days of the event, giving rise to the default becoming known. A default will result in a termination payment equal to the present value of the net gains and losses for the entire remaining term of all contracts between the parties aggregated to a single liquidated amount due within three business days following the date the notice of termination is received. The mark-to-market value, which is substantially based on quoted market prices, can be used to roughly approximate the termination payment and benefit at any point in time. Under the net mark-to-market value as of December 31, 2008 for all suppliers continuing to provide power under a WSPP agreement no amounts would be due to or from SPPC. These contracts qualify for the normal purchases scope exception of SFAS 133, and as such, are not required to be mark-to-market on the balance sheet. Refer to Note 9, Derivatives and Hedging Activities, of the Notes to Financial Statements for further discussion.

Gas Supplier Matters

With respect to the purchase and sale of natural gas SPPC uses several types of standard industry contracts. The natural gas contract terms and conditions are more varied than the electric contracts. Consequently, some of the contracts contain language similar to that found in the WSPP agreement and other agreements have unique provisions dealing with material adverse changes, which primarily means a credit rating downgrade below investment grade. Forward physical gas supplies are purchased under index based pricing terms and as such do not carry forward mark-to-market exposure. Because of creditworthiness concerns, most contracts and confirmations for natural gas purchases have been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery. At the present time, no counter-parties require payment in advance of delivery.

Financial Gas Hedges

SPPC enters into certain hedging contracts with various counterparties to manage the gas price risk inherent in purchased power and fuel contracts. The contracts require that SPPC maintain its Moody’s and S&P Sr. Unsecured or equivalent ratings in place at the time the contracts were entered into. In the event that SPPC’s Sr. Unsecured debt rating is downgraded by two out of the three rating agencies, the counterparties have the right to require SPPC to post cash or a letter of credit to the extent the counterparties have mark to market exposure to SPPC, subject to certain caps. As of December 31, 2008, the maximum amount of collateral SPPC would be required to post under these agreements is approximately $87.8 million based on mark-to-market values, which are substantially based on quoted market prices. Of this amount, approximately $53.1 million would be required if SPPC is downgraded one level and an additional amount of approximately $34.7 million would be required if SPPC is downgraded two levels.

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Cross Default Provisions

None of the financing agreements of SPPC contains a cross-default provision that would result in an event of default by SPPC upon an event of default by NVE or SPPC under any of its financing agreements. In addition, certain financing agreements of SPPC provide for an event of default if there is a failure under other financing agreements of SPPC to meet payment terms or to observe other covenants that would result in an acceleration of payments due. Most of these default provisions (other than ones relating to a failure to pay such other indebtedness when due) provide for a cure period of 30-60 days from the occurrence of a specified event during which time SPPC may rectify or correct the situation before it becomes an event of default.

REGULATORY PROCEEDINGS (UTILITIES)

NVE is a “holding company” under the Public Utility Holding Company Act of 2005 (PUHCA 2005). As a result, NVE and all of its subsidiaries (whether or not engaged in any energy related business) are required to maintain books, accounts and other records in accordance with FERC regulations and to make them available to the FERC, the PUCN and CPUC. In addition, the PUCN, CPUC or the FERC have the authority to review allocations of costs of non-power goods and administrative services among NVE and its subsidiaries. The FERC has the authority generally to require that rates subject to its jurisdiction be just and reasonable and in this context would continue to be able to, among other things, review transactions between NVE, NPC and/or SPPC and/or any other affiliated company.

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

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

The Utilities are required to file annual electric and gas DEAA cases on March 1 as mandated by the 2007 Nevada Legislature, quarterly BTER Updates for the Utilities’ electric and gas departments, and triennial GRCs in Nevada. A DEAA case is filed to recover/refund any under/over collection of prior energy costs and the BTER Updates recover current energy costs. As of December 31, 2008, NPC’s and SPPC’s balance sheets included approximately $281.5 million and credit of $26.7 million, respectively, of deferred energy costs of which $150.9 million and credits of $45.9 million had been previously approved for collection over various periods. The remaining amounts will be requested in future DEAA filings. A GRC filing is to set rates to recover operation and maintenance expenses, depreciation, taxes and provide a return on invested capital. Refer to Note 3, Regulatory Actions, of the Notes to Financial Statements for further information on significant regulatory matters and deferred energy and regulatory asset and liability balances.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risk

As of December 31, 2008, NVE, NPC and SPPC have evaluated their risk related to financial instruments whose values are subject to market sensitivity. Such instruments are fixed and variable rate debt. Fair market value is determined using quoted market price for the same or similar issues or on the current rates offered for debt of the same remaining maturities (dollars in thousands).

December 31, 2008

	Expected Maturity Date
																						Fair
	2009			2010			2011			2012			2013			Thereafter			Total			Value
Long-Term Debt
NVE
Fixed Rate	$	-		$	-		$	-		$	63,670		$	-		$	421,539		$	485,209		$	427,348
Average Interest Rate		-			-			-			7.80	%		-			7.77	%		7.78	%

NPC
Fixed Rate	$	-		$	-		$	364,000		$	130,000		$	-		$	2,269,335		$	2,763,335		$	2,531,977
Average Interest Rate		-			-			8.14	%		6.50	%		-			6.35	%		6.60	%
Variable Rate	$	-		$	409,629		$	-		$	-		$	-		$	179,500		$	589,129		$	589,129
Average Interest Rate		-			2.32	%		-			-			-			5.92	%		3.42	%

SPPC
Fixed Rate	$	600		$	-		$	-		$	100,000		$	250,000		$	625,000		$	975,600		$	899,098
Average Interest Rate		6.40	%		-			-			6.25	%		5.45	%		6.39	%		6.13	%
Variable Rate	$	-		$	152,912		$	-		$	-		$	-		$	258,500		$	411,412		$	411,412
Average Interest Rate		-			2.15	%		-			-			-			5.72	%		4.39	%

Total Debt	$	600		$	562,541		$	364,000		$	293,670		$	250,000		$	3,753,874		$	5,224,685		$	4,858,964

December 31, 2007

	Expected Maturity Date
																					Fair
	2008			2009			2010		2011			2012			Thereafter			Total			Value
Long-Term Debt
NVE
Fixed Rate	$	-		$	-		$	-	$	-		$	63,670		$	460,539		$	524,209		$	544,587
Average Interest Rate		-			-			-		-			7.80	%		7.77	%		7.77	%

NPC
Fixed Rate	$	12		$	-		$	-	$	364,000		$	130,000		$	1,786,579		$	2,280,591		$	2,354,641
Average Interest Rate		8.17	%		-			-		8.14	%		6.50	%		6.34	%		6.64	%
Variable Rate	$	-		$	15,000		$	-	$	-		$	-		$	192,500		$	207,500		$	207,500
Average Interest Rate		-			4.33	%		-		-			-			4.05	%		4.07	%

SPPC
Fixed Rate	$	101,643		$	600		$	-	$	-		$	100,000		$	625,000		$	827,243		$	842,654
Average Interest Rate		7.96	%		6.40	%		-		-			6.25	%		6.39	%		6.57	%
Variable Rate	$	-		$	-		$	-	$	-		$	-		$	348,250		$	348,250		$	348,250
Average Interest Rate		-			-			-		-			-			3.86	%		3.86	%

Total Debt	$	101,655		$	15,600		$	-	$	364,000		$	293,670		$	3,412,868		$	4,187,793		$	4,297,632

Commodity Price Risk

Commodity price increases due to changes in market conditions are recovered through the deferred energy mechanism. Although the Utilities actively manage energy commodity (electric, natural gas, coal and oil) price risk through their procurement strategies, the ability to recover commodity price changes through future rates substantially mitigates commodity price risk. However, the Utilities are subject to cash flow risk due to changes in the value of their open positions and are subject to regulatory risk because the PUCN may disallow recovery for any costs that it considers imprudently incurred. The Utilities mitigate both risk associated with its open positions and regulatory risk through prudent energy supply practices which include the use of long-term fuel supply agreements, long-term purchase power agreements and derivative instruments such as forwards, options and swaps to meet the anticipated fuel and power requirements. See Energy Supply in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, for a discussion of the Utilities’ purchased power procurement strategies.

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Credit Risk

The Utilities monitor and manage credit risk with their trading counterparties. Credit risk is defined as the possibility that a counterparty to one or more contracts will be unable or unwilling to fulfill its financial or physical obligations to the Utilities because of the counterparty's financial condition. The Utilities' credit risk associated with trading counterparties was approximately $334.3 million as of December 31, 2008, which increased significantly from December 31, 2007 as a result of the addition of a 10-year tolling agreement with Dynegy Power Marketing for the entire output of the 570 MW Griffith Energy facility executed during the second quarter of 2008. In the event that the trading counterparties are unable to deliver under their contracts, it may be necessary for the Utilities to purchase alternative energy at a higher market price.

Pursuant to rules and tariffs governing the extension of electric service to residential and commercial real estate developments the Utilities’ have made certain electric system investments which may be affected by the current real estate and credit markets. The Utilities are exposed to credit risk in the event that developers are unable to satisfy their obligations to complete these projects. At the present time, the Utilities’ credit risk related to the recovery of these investments is not believed to be significant.

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ITEM 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

	Page

Reports of Independent Registered Public Accounting Firm	89
Financial Statements:
NV Energy, Inc.:
Consolidated Balance Sheets as of December 31, 2008 and 2007	92
Consolidated Income Statements for the Years Ended December 31, 2008, 2007 and 2006	93
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2008, 2007 and 2006	94
Consolidated Statements of Common Shareholders’ Equity for the Years Ended December 31, 2008, 2007 and 2006	95
Consolidated Statements of Cash Flows for the Years Ended December 31, 2008, 2007 and 2006	96
Consolidated Statements of Capitalization as of December 31, 2008 and 2007	97
Nevada Power Company:
Consolidated Balance Sheets as of December 31, 2008 and 2007	99
Consolidated Income Statements for the Years Ended December 31, 2008, 2007 and 2006	100
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2008, 2007 and 2006	101
Consolidated Statements of Common Shareholder’s Equity for the Years Ended December 31, 2008, 2007 and 2006	102
Consolidated Statements of Cash Flows for the Years Ended December 31, 2008, 2007 and 2006	103
Consolidated Statements of Capitalization as of December 31, 2008 and 2007	104
Sierra Pacific Power Company:
Consolidated Balance Sheets as of December 31, 2008 and 2007	105
Consolidated Income Statements for the Years Ended December 31, 2008, 2007 and 2006	106
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2008, 2007 and 2006	107
Consolidated Statements of Common Shareholder’s Equity for the Years Ended December 31, 2008, 2007 and 2006	108
Consolidated Statements of Cash Flows for the Years Ended December 31, 2008, 2007 and 2006	109
Consolidated Statements of Capitalization as of December 31, 2008 and 2007	110
Notes to Financial Statements for NV Energy, Inc., Nevada Power Company and Sierra Pacific Power Company	111

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

NV Energy, Inc.

Las Vegas, Nevada

We have audited the accompanying consolidated balance sheets and statements of capitalization of NV Energy, Inc. (formerly Sierra Pacific Resources) and subsidiaries (the "Company") as of December 31, 2008 and 2007, and the related consolidated statements of income, comprehensive income (loss), common shareholders' equity, and cash flows for each of the three years in the period ended December 31, 2008. Our audits also included the financial statement schedule listed in the Index at Item 15(a) (2). These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of NV Energy, Inc. and subsidiaries as of December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of December 31, 2008, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 23, 2009 expressed an unqualified opinion on the Company's internal control over financial reporting.

/s/ Deloitte & Touche LLP
Las Vegas, Nevada

February 23, 2009

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

Nevada Power Company

Las Vegas, Nevada

We have audited the accompanying consolidated balance sheets and statements of capitalization of Nevada Power Company and subsidiaries (the "Company") as of December 31, 2008 and 2007, and the related consolidated statements of income, comprehensive income (loss), common shareholder’s equity, and cash flows for each of the three years in the period ended December 31, 2008. Our audits also included the financial statement schedule listed in the Index at Item 15(a) (2). These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Nevada Power Company and subsidiaries as of December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

/s/ Deloitte & Touche LLP
Las Vegas, Nevada

February 23, 2009

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

Sierra Pacific Power Company

Reno, Nevada

We have audited the accompanying consolidated balance sheets and statements of capitalization of Sierra Pacific Power Company and subsidiaries (the "Company") as of December 31, 2008 and 2007, and the related consolidated statements of income, comprehensive income (loss), common shareholder’s equity, and cash flows for each of the three years in the period ended December 31, 2008. Our audits also included the financial statement schedule listed in the Index at Item 15(a) (2). These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Sierra Pacific Power Company and subsidiaries as of December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

/s/ Deloitte & Touche LLP
Las Vegas, Nevada

February 23, 2009

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NV ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)

		December 31,
		2008		2007
ASSETS
Utility Plant at Original Cost:
Plant in service		$	10,358,843	$	8,468,711
Less accumulated provision for depreciation			2,659,219		2,526,379
			7,699,624		5,942,332
Construction work-in-progress			610,667		1,068,666
			8,310,291		7,010,998

Investments and other property, net			25,189		31,061

Current Assets:
Cash and cash equivalents			54,359		129,140
Accounts receivable less allowance for uncollectible accounts:
	2008- $32,695, 2007-$36,061		415,856		434,359
Deferred energy costs - electric (Note 3)			50,436		75,948
Materials, supplies and fuel, at average cost			125,391		117,483
Risk management assets (Note 9)			16,118		22,286
Current income taxes receivable			5,487		-
Deferred income taxes			49,996		43,295
Other			52,633		45,909
			770,276		868,420
Deferred Charges and Other Assets:
Deferred energy costs - electric (Note 3)			231,027		205,030
Regulatory assets			1,415,436		1,052,202
Regulatory asset for pension plans			413,544		133,984
Risk management assets (Note 9)			9,959		12,429
Other			170,258		150,626
			2,240,224		1,554,271
TOTAL ASSETS		$	11,345,980	$	9,464,750
CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholders' equity		$	3,131,186	$	2,996,575
Long-term debt			5,266,982		4,137,864
			8,398,168		7,134,439
Current Liabilities:
Current maturities of long-term debt			9,291		110,285
Accounts payable			400,084		357,867
Accrued expenses			131,720		112,841
Current income taxes payable			-		3,544
Risk management liabilities (Note 9)			313,846		39,509
Other			114,442		94,933
			969,383		718,979
Commitments and Contingencies (Note 13)

Deferred Credits and Other Liabilities:
Deferred income taxes			920,481		852,630
Deferred investment tax credit			25,923		28,895
Accrued retirement benefits			288,841		77,525
Risk management liabilities			53,403		7,369
Regulatory liabilities			361,337		332,471
Other			328,444		312,442
			1,978,429		1,611,332
TOTAL CAPITALIZATION AND LIABILITIES		$	11,345,980	$	9,464,750

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

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NV ENERGY, INC.
CONSOLIDATED INCOME STATEMENTS
(Dollars in Thousands, Except Per Share Amounts)


	Year Ended December 31,
	2008			2007			2006

OPERATING REVENUES:
Electric	$	3,318,101		$	3,395,487		$	3,144,243
Gas		209,987			205,430			210,068
Other		25			43			1,639
		3,528,113			3,600,960			3,355,950
OPERATING EXPENSES:
Operation:
Fuel for power generation		1,039,267			837,355			800,585
Purchased power		974,343			1,036,905			1,109,440
Gas purchased for resale		170,468			150,879			160,739
Deferral of energy costs - electric - net		(5,656	)		311,210			139,365
Deferral of energy costs - gas - net		(4,609	)		10,763			6,947
Reinstatement of deferred energy		-			-			(178,825	)
Other		394,019			379,446			367,198
Maintenance		94,069			99,035			93,172
Depreciation and amortization		260,608			235,532			228,875
Taxes:
Income taxes		76,751			75,155			91,571
Other than income		53,525			50,113			48,086
		3,052,785			3,186,393			2,867,153
OPERATING INCOME		475,328			414,567			488,797

OTHER INCOME (EXPENSE):
Allowance for other funds used during construction		38,441			31,809			18,226
Interest accrued on deferred energy		5,255			26,154			27,898
Carrying charge for Lenzie		-			16,080			33,440
Gain on sale of investment		-			1,369			62,927
Other income		34,278			24,580			37,123
Other expense		(24,955	)		(25,076	)		(23,497	)
Income taxes		(18,603	)		(12,400	)		(54,034	)
		34,416			62,516			102,083
Total Income Before Interest Charges		509,744			477,083			590,880

INTEREST CHARGES:
Long-term debt		297,271			273,985			294,488
Other		33,113			31,770			33,719
Allowance for borrowed funds used during construction		(29,527	)		(25,967	)		(17,119	)
		300,857			279,788			311,088

Preferred stock dividend requirements of subsidiary and premium on redemption		-			-			2,341
NET INCOME APPLICABLE TO COMMON STOCK	$	208,887		$	197,295		$	277,451

Amount per share basic and diluted - (Note #)
Net Income applicable to common stock	$	0.89		$	0.89		$	1.33

Weighted Average Shares of Common Stock Outstanding - basic		234,031,750			222,180,440			208,531,134
Weighted Average Shares of Common Stock Outstanding - diluted		234,585,004			222,554,024			209,020,896
Dividends Declared Per Share of Common Stock	$	0.34		$	0.16		$	-

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

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NV ENERGY, INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Dollars in Thousands)


	Year Ended December 31,
	2008			2007			2006


NET INCOME APPLICABLE TO COMMON STOCK	$	208,887		$	197,295		$	277,451

OTHER COMPREHENSIVE INCOME (LOSS)
Minimum pension liability adjustment (Net of taxes of ($1,132) in 2006)		-			-			2,106
Change in SFAS 158 liability and amortization (Net of taxes $284 and $1,250
in 2008 and 2007, respectively)		(492	)		(2,323	)		-

OTHER COMPREHENSE INCOME (LOSS)		(492	)		(2,323	)		2,106
COMPREHENSIVE INCOME	$	208,395		$	194,972		$	279,557


The accompanying notes are an integral part of the financial statements

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NV ENERGY, INC.
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS’ EQUITY
(Dollars in Thousands)


	December 31,
	2008			2007			2006
Common Stock:
Balance at Beginning of Year	$	233,739		$	221,030		$	200,792
Stock issuance/exchange, CSIP, DRP, ESPP and other		578			12,709			20,238
Balance at end of year		234,317			233,739			221,030

Other Paid-In Capital:
Balance at Beginning of Year		2,684,845			2,483,244			2,220,896
Premium on issuance/exchange of common stock		-			190,808			260,600
Common Stock issuance costs		(90	)		(298	)		(857	)
Stock purchase and dividend reinvestment		2,141			504			-
Tax Benefit from stock option exercises		365			891			-
CSIP, DRP, ESPP and other		7,531			9,696			2,605
Balance at End of Year		2,694,792			2,684,845			2,483,244

Retained Earnings (Deficit):
Balance at Beginning of Year		83,859			(78,432	)		(355,883	)
Adjustments to beginning balances: FAS 158 in 2008 (Net of taxes of ($2,514)) and FIN 48 in 2007		(4,669	)		487			-
Net Income applicable to Common Stock		208,887			197,295			277,451
Common stock dividends declared		(79,640	)		(35,491	)		-
Balance at End of Year		208,437			83,859			(78,432	)

Accumulated Other Comprehensive Income (Loss):
Balance at Beginning of Year		(5,868	)		(3,545	)		(5,651	)
Minimum pension liability adjustment (Net of taxes of ($1,132) in 2006)		-			-			2,106
Change in SFAS 158 liability and amortization (Net of taxes $284 and $1,250 in 2008 and 2007, respectively).		(492	)		(2,323	)		-
Balance at End of Year		(6,360	)		(5,868	)		(3,545	)

Total Common Shareholders' Equity at End of Year	$	3,131,186		$	2,996,575		$	2,622,297

The accompanying notes are an integral part of the financial statements

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NV ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)

	Year Ended December 31,
	2008			2007			2006

CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income applicable to common stock	$	208,887		$	197,295		$	277,451
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		260,608			235,532			228,875
Deferred taxes and deferred investment tax credit		52,060			79,337			136,026
AFUDC		(38,441	)		(31,809	)		(18,226	)
Amortization of energy costs, net of deferrals		2,717			309,587			127,495
Reinstatement of deferred energy		-			-			(178,825	)
Carrying charge on Lenzie plant		-			(16,080	)		(33,440	)
Reinstated interest on deferred energy		-			(11,076	)		-
Gain on sale of investment		-			(1,369	)		(62,927	)
Other, net		100,482			71,543			53,561
Changes in certain assets and liabilities:
Accounts receivable		39,776			(19,276	)		(43,214	)
Materials, supplies and fuel		(7,908	)		(13,725	)		(15,312	)
Other current assets		(6,724	)		1,639			24,050
Accounts payable		(12,028	)		42,958			(2,739	)
Payment to terminating supplier		-			-			(65,368	)
Proceeds from claim on terminating supplier		-			-			41,365
Accrued retirement benefits		(79,242	)		(75,820	)		(3,393	)
Other current liabilities		40,747			22,475			2,356
Risk management assets and liabilities		(4,924	)		10,088			(5,950	)
Other deferred assets		(51,874	)		498			(9,071	)
Other regulatory assets		(67,460	)		(45,864	)		(29,962	)
Other deferred liabilities		22,238			(2,112	)		6,690
Net Cash from Operating Activities		458,914			753,821			429,442

CASH FLOWS USED BY INVESTING ACTIVITIES:
Additions to utility plant (excluding equity related to AFUDC)		(1,535,503	)		(1,165,517	)		(967,793	)
Customer advances for construction		(11,981	)		8,230			17,348
Contributions in aid of construction		62,521			32,165			38,792
Proceeds from sale of Investment		-			1,935			99,730
Investments and other property - net		4,301			2,810			8,423
Net Cash used by Investing Activities		(1,480,662	)		(1,120,377	)		(803,500	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Change in restricted cash and investments		-			-			3,612
Proceeds from issuance of long-term debt		2,135,151			1,246,383			2,491,883
Retirement of long-term debt		(1,114,226	)		(1,044,866	)		(2,407,745	)
Redemption of preferred stock		-			-			(51,366	)
Sale of Common Stock		5,756			213,339			281,554
Proceeds from exercise of stock options		-			548			1,040
Dividends paid		(79,714	)		(35,417	)		(1,945	)
Net Cash from Financing Activities		946,967			379,987			317,033

Net Increase (Decrease) in Cash and Cash Equivalents		(74,781	)		13,431			(57,025	)
Beginning Balance in Cash and Cash Equivalents		129,140			115,709			172,734
Ending Balance in Cash and Cash Equivalents	$	54,359		$	129,140		$	115,709

Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	284,044		$	267,082		$	338,665
Income taxes	$	10,677		$	9,727		$	4,726

The accompanying notes are an integral part of the financial statements

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NV ENERGY, INC.

CONSOLIDATED STATEMENTS OF CAPITALIZATION

(Dollars in Thousands, Except Per Share Amounts)

	December 31,
	2008			2007

Common Shareholder’s Equity:
Common stock, $1.00 par value, authorized 350 million; issued	$	234,317		$	233,739
and outstanding 2008: 234,317,000 shares; issued and outstanding
2007: 233,739,000 shares issued and outstanding
Other paid-in capital		2,694,792			2,684,845
Retained Earnings		208,437			83,859
Accumulated other comprehensive Income (Loss)		(6,360	)		(5,868	)
Total Common Shareholders’ Equity		3,131,186			2,996,575
Long-Term Debt:
Secured Debt
Debt Secured by General and Refunding Mortgage Securities
Nevada Power Company
8.25% NPC Series A due 2011		350,000			350,000
6.50% NPC Series I due 2012		130,000			130,000
9.00% NPC Series G due 2013		-			17,244
5.875% NPC Series L due 2015		250,000			250,000
5.95% NPC Series M due 2016		210,000			210,000
6.65% NPC Series N due 2036		370,000			370,000
6.50% NPC Series O due 2018		325,000			325,000
6.75% NPC Series R due 2037		350,000			350,000
6.50% NPC Series S due 2018		500,000			-
Subtotal		2,485,000			2,002,244
Sierra Pacific Power Company
8.00% SPPC Series A due 2008		-			99,243
6.25% SPPC Series H due 2012		100,000			100,000
6.00% SPPC Series M due 2016		300,000			300,000
6.75% SPPC Series P due 2037		325,000			325,000
5.45% SPPC Series Q due 2013		250,000			-
Subtotal		975,000			824,243
Variable Rate Instruments
Nevada Power Company
NPC PCRB Series 2000B due 2009		-			15,000
NPC IDRB Series 2000A due 2020		100,000			100,000
NPC PCRB Series 2006 due 2036		39,500			39,500
NPC PCRB Series 2006A due 2032		40,000			40,000
NPC PCRB Series 2006B due 2039		-			13,000
Revolving Credit Facility		409,629			-
Subtotal		589,129			207,500
Sierra Pacific Power Company
SPPC PCRB Series 2006 due 2029		-			49,750
SPPC PCRB Series 2006A due 2031		58,700			58,700
SPPC PCRB Series 2006B due 2036		75,000			75,000
SPPC PCRB Series 2006C due 2036		84,800			84,800
SPPC WFRB Series 2007A due 2036		40,000			40,000
SPPC WFRB Series 2007B due 2036		-			40,000
Revolving Credit Facility		152,912			-
Subtotal		411,412			348,250
Unsecured Debt
Revenue Bonds
Nevada Power Company
5.30% NPC Series 1995D due 2011		14,000			14,000
5.45% NPC Series 1995D due 2023		6,300			6,300
5.50% NPC Series 1995C due 2030		44,000			44,000
5.60% NPC Series 1995A due 2030		76,750			76,750
5.90% NPC Series 1995B due 2030		85,000			85,000
5.90% NPC Series 1997A due 2032		52,285			52,285
Subtotal		278,335			278,335

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

Table of Contents



NV ENERGY, INC.
CONSOLIDATED STATEMENTS OF CAPITALIZATION
(Dollars in Thousands)

	December 31,
	2008			2007
Other Notes
NV ENERGY
7.803% NVE Senior Notes due 2012		63,670			63,670
8.625% NVE Notes due 2014		230,039			250,039
6.75% NVE Senior Notes due 2017		191,500			210,500
Subtotal, excluding current portion		485,209			524,209
Unamortized bond premium and discount, net		(2,677	)		(1,068	)
Obligations under capital leases		54,265			61,424
Current maturities		(9,291	)		(110,285	)
Other, excluding current portion		600			3,012
Total Long-Term Debt		5,266,982			4,137,864
TOTAL CAPITALIZATION	$	8,398,168		$	7,134,439

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

(Concluded)

Table of Contents

NEVADA POWER COMPANY
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)

		December 31,
		2008		2007
ASSETS
Utility Plant at Original Cost:
Plant in service		$	6,884,033	$	5,571,492
Less accumulated provision for depreciation			1,500,502		1,407,334
			5,383,531		4,164,158
Construction work-in-progress			514,096		576,127
			5,897,627		4,740,285

Investments and other property, net			19,701		19,544

Current Assets:
Cash and cash equivalents			28,594		37,001
Accounts receivable less allowance for uncollectible accounts:
	2008- $30,621 , 2007-$30,392		238,379		274,242
Deferred energy costs - electric (Note 3)			50,436		75,948
Materials, supplies and fuel, at average cost			74,103		68,671
Risk management assets (Note 9)			11,724		16,078
Intercompany income taxes receivable			20,695		-
Deferred income taxes			2,682		2,383
Other			34,657		28,352
			461,270		502,675
Deferred Charges and Other Assets:
Deferred energy costs - electric (Note 3)			231,027		205,030
Regulatory assets			971,354		706,903
Regulatory asset for pension plans			187,894		86,909
Risk management assets (Note 9)			7,346		9,069
Other			127,928		106,954
			1,525,549		1,114,865
TOTAL ASSETS		$	7,904,147	$	6,377,369
CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholder's equity		$	2,627,567	$	2,376,740
Long-term debt			3,385,106		2,528,141
			6,012,673		4,904,881
Current Liabilities:
Current maturities of long-term debt			8,691		8,642
Accounts payable			262,552		231,205
Accounts payable, affiliated companies			32,901		32,706
Accrued expenses			80,069		63,330
Dividends declared			-		10,907
Current income taxes payable			-		3,544
Intercompany Income taxes payable			-		15,403
Risk management liabilities (Note 9)			222,856		26,982
Other			72,762		50,902
			679,831		443,621
Commitments and Contingencies (Note 13)
Deferred Credits and Other Liabilities:
Deferred income taxes			635,523		585,168
Deferred investment tax credit			10,001		11,169
Accrued retirement benefits			103,023		25,693
Risk management liabilities (Note 9)			35,241		5,116
Regulatory liabilities			188,709		178,419
Other			239,146		223,302
			1,211,643		1,028,867

TOTAL CAPITALIZATION AND LIABILITIES		$	7,904,147	$	6,377,369

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

Table of Contents

NEVADA POWER COMPANY
CONSOLIDATED INCOME STATEMENTS
(Dollars in Thousands)


	Year Ended December 31,
	2008			2007			2006
OPERATING REVENUES:
Electric	$	2,315,427		$	2,356,620		$	2,124,081

OPERATING EXPENSES:
Operation:
Fuel for power generation		755,925			594,382			552,959
Purchased power		680,816			688,606			764,850
Deferral of energy costs - net		(6,947	)		233,166			92,322
Other		249,236			232,610			218,120
Reinstatement of deferred energy		-			-			(178,825	)
Maintenance		63,282			67,482			61,899
Depreciation and amortization		171,080			152,139			141,585
Taxes:
Income taxes		58,014			61,108			91,781
Other than income		32,069			29,823			28,118
		2,003,475			2,059,316			1,772,809
OPERATING INCOME		311,952			297,304			351,272

OTHER INCOME (EXPENSE):
Allowance for other funds used during construction		25,917			15,861			11,755
Interest accrued on deferred energy		7,342			25,289			21,902
Carrying charge for Lenzie		-			16,080			33,440
Other income		16,631			14,423			16,992
Other expense		(10,221	)		(11,352	)		(8,480	)
Income taxes		(13,368	)		(17,244	)		(25,729	)
		26,301			43,057			49,880
Total Income Before Interest Charges		338,253			340,361			401,152

INTEREST CHARGES:
Long-term debt		180,672			164,002			171,188
Other		26,213			23,861			17,038
Allowance for borrowed funds used during construction		(20,063	)		(13,196	)		(11,614	)
		186,822			174,667			176,612

NET INCOME	$	151,431		$	165,694		$	224,540


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

100

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NEVADA POWER COMPANY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Dollars in Thousands)


	Year Ended December 31,
	2008			2007			2006


NET INCOME	$	151,431		$	165,694		$	224,540

OTHER COMPREHENSIVE INCOME (LOSS)
Minimum pension liability adjustment (Net of taxes of ($520) in 2006)		-			-			965
Change in SFAS 158 liability and amortization (Net of taxes $207 and $487
in 2008 and 2007, respectively)		(393	)		(905	)		-

OTHER COMPREHENSE INCOME (LOSS)		(393	)		(905	)		965
COMPREHENSIVE INCOME	$	151,038		$	164,789		$	225,505


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

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NEVADA POWER COMPANY
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER'S EQUITY
(Dollars in Thousands)

	December 31,
	2008			2007			2006

Common Stock:
Balance at Beginning of Year
and End of Year	$	1		$	1		$	1

Other Paid-In Capital:

Balance at Beginning of Year		2,107,582			2,042,369			1,808,848
Transfer of pension assets		-			-			33,521
Capital contribution from parent		146,600			65,000			200,000
Tax Benefit from stock option exercises		-			213			-
Balance at End of Year		2,254,182			2,107,582			2,042,369

Retained Earnings (Deficit):

Balance at Beginning of Year		272,435			132,201			(43,422	)
Adjustments to beginning balances: FAS 158 in 2008 (Net of taxes of ($1,514)) and FIN 48 in 2007		(2,811	)		207			-
Income for the year		151,431			165,694			224,540
Common stock dividends declared		(44,000	)		(25,667	)		(48,917	)
Balance at End of Year		377,055			272,435			132,201

Accumulated Other Comprehensive (Loss):

Balance at Beginning of Year		(3,278	)		(2,373	)		(3,338	)
Minimum pension liability adjustment (Net of taxes of ($520) in 2006)		-			-			965
Change in SFAS 158 liability and amortization (Net of taxes $207 and $487 in 2008 and 2007, respectively		(393	)		(905	)		-
Balance at End of Year		(3,671	)		(3,278	)		(2,373	)

Total Common Shareholder’s Equity at End of Year	$	2,627,567		$	2,376,740		$	2,172,198

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

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NEVADA POWER COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)


	Year Ended December 31,
	2008			2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	151,431		$	165,694		$	224,540
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		171,080			152,139			141,585
Deferred taxes and deferred investment tax credit		45,039			56,868			107,392
AFUDC		(25,917	)		(15,861	)		(11,755	)
Amortization of energy costs, net of deferrals		4,211			218,992			74,413
Reinstatement of deferred energy		-			-			(178,825	)
Carrying charge on Lenzie plant		-			(16,080	)		(33,440	)
Reinstated interest on deferred energy		-			(11,076	)		-
Other, net		73,209			38,821			25,783
Changes in certain assets and liabilities:
Accounts receivable		35,863			(29,619	)		(35,191	)
Materials, supplies and fuel		(5,432	)		(7,916	)		(13,919	)
Other current assets		(6,305	)		(1,395	)		5,421
Accounts payable		(47,424	)		60,269			(2,431	)
Payment to terminating supplier		-			-			(37,410	)
Proceeds from claim on terminating supplier		-			-			26,391
Accrued retirement benefits		(32,413	)		(46,067	)		(11,853	)
Other current liabilities		38,598			11,267			5,083
Risk management assets and liabilities		(3,622	)		3,673			(2,219	)
Other deferred assets		(51,172	)		(2,164	)		(9,474	)
Other regulatory assets		(50,347	)		(31,790	)		(22,817	)
Other deferred liabilities		24,063			18,873			8,907
Net Cash from Operating Activities		320,862			564,628			260,181

CASH FLOWS USED BY INVESTING ACTIVITIES:
Additions to utility plant (excluding equity related to AFUDC)		(1,314,697	)		(750,275	)		(658,686	)
Customer advances for construction		(13,121	)		(1,150	)		10,417
Contributions in aid of construction		52,261			19,576			21,241
Investments and other property - net		2,690			2,768			7,363
Net Cash used by Investing Activities		(1,272,867	)		(729,081	)		(619,665	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		1,437,412			724,391			1,687,726
Retirement of long-term debt		(585,507	)		(596,339	)		(1,554,521	)
Additional investment by parent company		146,600			65,000			200,000
Dividends paid		(54,907	)		(28,231	)		(35,769	)
Net Cash from Financing Activities		943,598			164,821			297,436

Net Increase (Decrease) in Cash and Cash Equivalents		(8,407	)		368			(62,048	)
Beginning Balance in Cash and Cash Equivalents		37,001			36,633			98,681
Ending Balance in Cash and Cash Equivalents	$	28,594		$	37,001		$	36,633

Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	170,281		$	164,704		$	190,023
Income taxes	$	15,535		$	6,760		$	4,714

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

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NEVADA POWER COMPANY

CONSOLIDATED STATEMENTS OF CAPITALIZATION

(Dollars in Thousands, Except Per Share Amounts)

	December 31,
	2008			2007
Common Shareholder’s Equity:
Common stock, $1.00 par value, 1,000 shares authorized, issued and
Outstanding	$	1		$	1
Other paid-in capital		2,254,182			2,107,582
Retained Earning		377,055			272,435
Accumulated other comprehensive Income (Loss)		(3,671	)		(3,278	)
Total Common Shareholder’s Equity		2,627,567			2,376,740
Long-Term Debt:
Secured Debt
Debt Secured by General and Refunding Mortgage Securities
8.25% Series A due 2011		350,000			350,000
6.50% Series I due 2012		130,000			130,000
9.00% Series G due 2013		-			17,244
5.875% Series L due 2015		250,000			250,000
5.95% Series M due 2016		210,000			210,000
6.65% Series N due 2036		370,000			370,000
6.50% Series O due 2018		325,000			325,000
6.75% Series R due 2037		350,000			350,000
6.50% Series S due 2018		500,000			-
Subtotal		2,485,000			2,002,244
Variable Rate Instruments
PCRB Series 2000B due 2009		-			15,000
IDRB Series 2000A due 2020		100,000			100,000
PCRB Series 2006 due 2036		39,500			39,500
PCRB Series 2006A due 2032		40,000			40,000
PCRB Series 2006B due 2039		-			13,000
Revolving Credit Facility		409,629			-
Subtotal		589,129			207,500
Unsecured Debt
Revenue Bonds
5.30% Series 1995D due 2011		14,000			14,000
5.45% Series 1995D due 2023		6,300			6,300
5.50% Series 1995C due 2030		44,000			44,000
5.60% Series 1995A due 2030		76,750			76,750
5.90% Series 1995B due 2030		85,000			85,000
5.90% Series 1997A due 2032		52,285			52,285
Subtotal		278,335			278,335
Unamortized bond premium and discount, net		(12,932	)		(12,732	)
Obligations under capital leases		54,265			61,424
Current maturities		(8,691	)		(8,642	)
Other, excluding current portion		-			12
Total Long-Term Debt		3,385,106			2,528,141
TOTAL CAPITALIZATION	$	6,012,673		$	4,904,881

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

104

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SIERRA PACIFIC POWER COMPANY
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)

		December 31,
		2008		2007
ASSETS
Utility Plant at Original Cost:
Plant in service		$	3,474,810	$	2,897,219
Less accumulated provision for depreciation			1,158,717		1,119,045
			2,316,093		1,778,174
Construction work-in-progress			96,571		492,539
			2,412,664		2,270,713

Investments and other property, net			411		570

Current Assets:
Cash and cash equivalents			21,411		23,807
Accounts receivable less allowance for uncollectible accounts:
	2008- $2,073; 2007 - $5,669		177,401		160,014
Materials, supplies and fuel, at average cost			51,252		48,799
Risk management assets (Note 9)			4,394		6,208
Intercompany income taxes receivable			64,932		-
Deferred income taxes			12,253		17,728
Other			17,631		17,255
			349,274		273,811
Deferred Charges and Other Assets:
Regulatory assets			444,082		345,299
Regulatory asset for pension plans			218,550		43,778
Risk management assets (Note 9)			2,613		3,360
Other			34,951		38,993
			700,196		431,430
TOTAL ASSETS		$	3,462,545	$	2,976,524
CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholder’s equity		$	877,961	$	1,001,840
Long-term debt			1,395,987		1,084,550
			2,273,948		2,086,390
Current Liabilities:
Current maturities of long-term debt			600		101,643
Accounts payable			109,410		94,722
Accounts payable, affiliated companies			17,433		19,288
Accrued expenses			37,787		34,122
Dividends declared			96,800		5,333
Intercompany income taxes payable			-		2,479
Risk management liabilities (Note 9)			90,990		12,527
Other			41,680		43,957
			394,700		314,071
Commitments and Contingencies (Note 13)
Deferred Credits and Other Liabilities:
Deferred income taxes			287,251		267,801
Deferred investment tax credit			15,922		17,726
Accrued retirement benefits			180,209		48,025
Risk management liabilities (Note 9)			18,162		2,253
Regulatory liabilities			172,628		154,052
Other			119,725		86,206
			793,897		576,063
TOTAL CAPITALIZATION AND LIABILITIES		$	3,462,545	$	2,976,524

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

105

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SIERRA PACIFIC POWER COMPANY
CONSOLIDATED INCOME STATEMENTS
(Dollars in Thousands)


	Year Ended December 31,
	2008			2007			2006
OPERATING REVENUES:
Electric	$	1,002,674		$	1,038,867		$	1,020,162
Gas		209,987			205,430			210,068
		1,212,661			1,244,297			1,230,230
OPERATING EXPENSES:
Operation:
Fuel for power generation		283,342			242,973			247,626
Purchased power		293,527			348,299			344,590
Gas purchased for resale		170,468			150,879			160,739
Deferral of energy costs - electric - net		1,291			78,044			47,043
Deferral of energy costs - gas - net		(4,609	)		10,763			6,947
Other		141,064			142,348			141,350
Maintenance		30,787			31,553			31,273
Depreciation and amortization		89,528			83,393			87,279
Taxes:
Income taxes		31,806			29,991			23,570
Other than income		21,304			20,097			19,796
		1,058,508			1,138,340			1,110,213
OPERATING INCOME		154,153			105,957			120,017

OTHER INCOME (EXPENSE):
Allowance for other funds used during construction		12,524			15,948			6,471
Interest (expense) accrued on deferred energy		(2,087	)		865			5,996
Other income		12,819			8,091			9,412
Other expense		(8,318	)		(8,441	)		(8,422	)
Income taxes		(5,797	)		3,982			(4,259	)
		9,141			20,445			9,198
Total Income Before Interest Charges		163,294			126,402			129,215

INTEREST CHARGES:
Long-term debt		76,256			67,502			71,869
Other		5,920			6,004			5,142
Allowance for borrowed funds used during construction		(9,464	)		(12,771	)		(5,505	)
		72,712			60,735			71,506

NET INCOME		90,582			65,667			57,709

Preferred stock dividend and premium on redemption		-			-			2,341
EARNINGS APPLICABLE TO COMMON STOCK	$	90,582		$	65,667		$	55,368

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

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SIERRA PACIFIC POWER COMPANY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Dollars in Thousands)


	Year Ended December 31,
	2008			2007			2006


NET INCOME APPLICABLE TO COMMON STOCK	$	90,582		$	65,667		$	57,709

OTHER COMPREHENSIVE INCOME (LOSS)
Minimum pension liability adjustment (Net of taxes of ($462) in 2006)		-			-			861
Change in SFAS 158 liability and amortization (Net of taxes $126 and $620
in 2008 and 2007, respectively)		(234	)		(1,153	)		-

OTHER COMPREHENSIVE INCOME (LOSS)		(234	)		(1,153	)		861
COMPREHENSIVE INCOME	$	90,348		$	64,514		$	58,570


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

107

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SIERRA PACIFIC POWER COMPANY
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER'S EQUITY
(Dollars in Thousands)

	December 31,
	2008			2007			2006

Common Stock:
Balance at Beginning of Year
and End of Year	$	4		$	4		$	4

Other Paid-In Capital:

Balance at Beginning of Year		1,000,595			935,453			810,103
Transfer of Goodwill		-			-			18,888
Transfer of pension assets		-			-			31,462
Capital contribution from parent		20,000			65,000			75,000
Tax Benefit from stock option exercises		365			142			-
Balance at End of Year		1,020,960			1,000,595			935,453

Retained Earnings (Deficit):

Balance at Beginning of Year		3,325			(49,789	)		(80,538	)
Adjustments to beginning balances: FAS 158 in 2008 (Net of taxes of ($857)) and FIN 48 in 2007		(1,592	)		280			-
Income before preferred dividends		90,582			65,667			57,709
Preferred stock redemption		-			-			(1,366	)
Preferred stock dividends declared		-			-			(975	)
Common stock dividends declared		(233,000	)		(12,833	)		(24,619	)
Balance at End of Year		(140,685	)		3,325			(49,789	)

Accumulated Other Comprehensive Income (Loss):

Balance at Beginning of Year		(2,084	)		(931	)		(1,792	)
Minimum pension liability adjustment (Net of taxes of ($462) in 2006)		-			-			861
Change in SFAS 158 liability and amortization (Net of taxes $126 and $620 In 2008 and 2007, respectively		(234	)		(1,153	)		-
Balance at End of Year		(2,318	)		(2,084	)		(931	)

Total Common Shareholder’s Equity at End of Year	$	877,961		$	1,001,840		$	884,737

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

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SIERRA PACIFIC POWER COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)

	Year Ended December 31,
	2008			2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	90,582		$	65,667		$	57,709
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		89,528			83,393			87,279
Deferred taxes and deferred investment tax credit		24,598			(36,713	)		(39,361	)
AFUDC		(12,524	)		(15,948	)		(6,471	)
Amortization of energy costs, net of deferrals		(1,494	)		90,595			53,082
Other, net		22,872			29,451			23,457
Changes in certain assets and liabilities:
Accounts receivable		(59,701	)		10,092			36,171
Materials, supplies and fuel		(2,453	)		(5,809	)		(1,382	)
Other current assets		(376	)		2,839			18,204
Accounts payable		(574	)		15,010			19,670
Payment to terminating supplier		-			-			(27,958	)
Proceeds from claim on terminating supplier		-			-			14,974
Accrued retirement benefits		(47,923	)		(25,248	)		8,781
Other current liabilities		3,673			11,196			(925	)
Risk management assets and liabilities		(1,302	)		6,415			(3,731	)
Other deferred assets		(702	)		2,662			403
Other regulatory assets		(17,113	)		(14,074	)		(7,145	)
Other deferred liabilities		31,536			(5,349	)		(2,320	)
Net Cash from Operating Activities		118,627			214,179			230,437

CASH FLOWS USED BY INVESTING ACTIVITIES:
Additions to utility plant (excluding equity related to AFUDC)		(220,806	)		(415,242	)		(309,107	)
Customer advances for construction		1,140			9,380			6,931
Contributions in aid of construction		10,260			12,590			17,551
Investments and other property - net		1,611			39			233
Net Cash used by Investing Activities		(207,795	)		(393,233	)		(284,392	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Change in restricted cash and investments		-			-			3,612
Proceeds from issuance of long-term debt		697,739			521,992			804,157
Retirement of long-term debt		(489,434	)		(423,155	)		(742,514	)
Redemption of preferred stock		-			-			(51,366	)
Investment by parent company		20,000			65,000			75,000
Dividends paid		(141,533	)		(14,236	)		(19,827	)
Net Cash from Financing Activities		86,772			149,601			69,062

Net Increase (Decrease) in Cash and Cash Equivalents		(2,396	)		(29,453	)		15,107
Beginning Balance in Cash and Cash Equivalents		23,807			53,260			38,153
Ending Balance in Cash and Cash Equivalents	$	21,411		$	23,807		$	53,260

Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	72,443		$	59,496		$	83,327
Income taxes	$	19		$	64		$	12

Noncash Activities:
Transfer of Regulatory Asset	$	-		$	-		$	18,888

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

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SIERRA PACIFIC POWER COMPANY

CONSOLIDATED STATEMENTS OF CAPITALIZATION

(Dollars in Thousands, Except Per Share Amounts)

	December 31,
	2008			2007

Common Shareholder’s Equity:
Common stock, $3.75 par value, 20,000,000 shares authorized, 1,000 shares issued and outstanding	$	4		$	4
Other paid-in capital		1,020,960			1,000,595
Retained Deficit		(140,685	)		3,325
Accumulated other comprehensive Income (Loss)		(2,318	)		(2,084	)
Total Common Shareholder’s Equity		877,961			1,001,840
Long-Term Debt:
Secured Debt
Debt Secured by General and Refunding Mortgage Securities
8.00% Series A due 2008		-			99,243
6.25% Series H due 2012		100,000			100,000
6.00% Series M due 2016		300,000			300,000
6.75% Series P due 2037		325,000			325,000
5.45% Series Q due 2013		250,000			-
Subtotal		975,000			824,243
Variable Rate Instruments
PCRB Series 2006 due 2029		-			49,750
PCRB Series 2006A due 2031		58,700			58,700
PCRB Series 2006B due 2036		75,000			75,000
PCRB Series 2006C due 2036		84,800			84,800
WFRB Series 2007A due 2036		40,000			40,000
WFRB Series 2007B due 2036		-			40,000
Revolving Credit Facility		152,912			-
Subtotal		411,412			348,250

Unsecured Debt
Unamortized bond premium and discount, net		9,575			10,700
Current maturities		(600	)		(101,643	)
Other, excluding current portion		600			3,000
Total Long-Term Debt		1,395,987			1,084,550
TOTAL CAPITALIZATION	$	2,273,948		$	2,086,390

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

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NOTES TO FINANCIAL STATEMENTS

NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The significant accounting policies for both utility and non-utility operations are as follows:

Basis of Presentation

The consolidated financial statements include the accounts of NV Energy, Inc. and its wholly-owned subsidiaries, Nevada Power Company, Sierra Pacific Power Company, Tuscarora Gas Pipeline Company, which was dissolved in 2008, Sierra Pacific Communications, Lands of Sierra, Inc., Sierra Energy Company dba e·three, Sierra Pacific Energy Company, Sierra Water Development Company and Sierra Gas Holding Company. All significant intercompany balances and intercompany transactions have been eliminated in consolidation.

The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities. These estimates and assumptions also affect the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of certain revenues and expenses during the reporting period. Actual results could differ from these estimates.

NPC is an operating public utility that provides electric service in Clark County in southern Nevada. The assets of NPC represent approximately 70% of the consolidated assets of NVE at December 31, 2008. NPC provides electricity to approximately 827,000 customers in the communities of Las Vegas, North Las Vegas, Henderson, Searchlight, Laughlin and adjoining areas, including Nellis Air Force Base. Service is also provided to the Department of Energy’s Nevada Test Site in Nye County. The consolidated financial statements of NVE include NPC’s wholly-owned subsidiary, NEICO.

SPPC is an operating public utility that provides electric service in northern Nevada and northeastern California. SPPC also provides natural gas service in the Reno/Sparks area of Nevada. The assets of SPPC represent approximately 30% of the consolidated assets of NVE at December 31, 2007. SPPC provides electricity to approximately 366,000 customers in a 50,000 square mile service area including western, central, and northeastern Nevada, including the cities of Reno, Sparks, Carson City, and Elko, and a portion of eastern California, including the Lake Tahoe area. SPPC also provides natural gas service in Nevada to approximately 149,000 customers in an area of about 800 square miles in the Reno and Sparks areas. The consolidated financial statements of SPPC include the accounts of SPPC’s wholly-owned subsidiaries, PPC, PPIC, GPSF-B, SPPC Funding LLC, and Sierra Pacific Power Capital I.

The Utilities’ accounts for electric operations and SPPC’s accounts for gas operations are maintained in accordance with the Uniform System of Accounts prescribed by the FERC.

TGPC was a partner in a joint venture that developed, constructed and operates a natural gas pipeline serving the expanding gas market in the Reno area and certain northeastern California markets. TGPC accounted for its joint venture interest under the equity method. In December 2006, TGPC substantially sold its partnership interest in the joint venture.

Reclassifications

Certain financial statement line items of prior year’s information have been re-grouped or reclassified to conform with current year presentation. The re-groupings or reclassifications have not affected previously reported results of operations or common shareholders’ equity.

Regulatory Accounting and Other Regulatory Assets

The Utilities’ rates are currently subject to the approval of the PUCN and, in the case of SPPC, rates are also subject to the approval of the CPUC and are designed to recover the cost of providing generation, transmission and distribution services. As a result, the Utilities qualify for the application of SFAS 71, issued by the FASB. This statement recognizes that the rate actions of a regulator can provide reasonable assurance of the existence of an asset and requires the deferral of incurred costs that would otherwise be charged to expense where it is probable that future revenue will be provided to recover these costs. SFAS 71 prescribes the method to be used to record the financial transactions of a regulated entity. The criteria for applying SFAS 71 include the following: (i) rates are set by an independent third party regulator; (ii) regulated rates are designed to recover the specific costs of the regulated products or services; and (iii) it is reasonable to assume that rates are set at levels that recovered costs can be charged to and collected from customers. Management periodically assesses whether the requirements for application of SFAS 71 are satisfied.

Regulatory assets represent incurred costs that have been deferred because it is probable they will be recovered through future rates collected from customers. If at any time the incurred costs no longer meet these criteria, these costs are charged to earnings. Regulatory liabilities generally represent obligations to make refunds to customers for previous collections, except for cost of removal which represents the cost of removing future electric and gas assets. Management believes the existing regulatory assets are probable of recovery either because the Utilities received prior PUCN approval or due to regulatory precedent set for similar circumstances. Included in Note 3, Regulatory Actions, are details of other regulatory assets and liabilities, and their current regulatory treatment.

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Deferral of Energy Costs

Nevada and California statutes permit regulated utilities to adopt deferred energy accounting procedures. The intent of these procedures is to ease the effect on customers of fluctuations in the cost of purchased gas, fuel, and purchased power.

Under deferred energy accounting, to the extent actual fuel and purchased power costs exceed fuel and purchased power costs recoverable through current rates that excess is not recorded as a current expense on the statement of operations but rather is deferred and recorded as an asset on the balance sheet in accordance with the provisions of SFAS 71. Conversely, a liability is recorded to the extent fuel and purchased power costs recoverable through current rates exceed actual fuel and purchased power costs. These excess amounts are reflected in adjustments to rates and recorded as revenue or expense in future time periods, subject to PUCN review.

Nevada law requires the Utilities file annual DEAA applications and provides that the PUCN may not allow the recovery of any costs for purchased fuel or purchased power “that were the result of any practice or transaction that was undertaken, managed or performed imprudently by the electric utility.” Nevada law also specifies that fuel and purchased power costs include all costs incurred to purchase fuel, to purchase capacity, and to purchase energy. The Utilities also record and are eligible under the statute to recover a carrying charge on such deferred balances. See Note 3, Regulatory Actions for details regarding deferred energy balances.

Utility Plant

The cost of additions, including betterments and replacements of units of property, are charged to utility plant. When units of property are replaced, renewed or retired, their cost plus removal or disposal costs, less salvage proceeds, are charged to accumulated depreciation. The cost of current repairs and minor replacements are charged to maintenance expense when incurred, with the exception of long term service agreements. These agreements may have annual payment amounts for repairs which could vary over the life of the agreement between maintenance expense and amounts to be capitalized. To ensure consistency in annual expense for rate making purposes, the amounts to be charged to maintenance expense are smoothed over the life of the contract, with an offset to a regulatory asset or liability account. Amounts prepaid for capital expenditure are recorded in a prepaid asset account.

In addition to direct labor and material costs, certain other direct and indirect costs are capitalized. The indirect construction overhead costs capitalized are based upon the following cost components: the cost of time spent by administrative and supervision employees in planning and directing construction; property taxes; employee benefits including such costs as pensions, post retirement and post employment benefits, vacations and payroll taxes; and an AFUDC which includes the cost of debt and equity capital associated with construction activity.

AFUDC

As part of the cost of constructing utility plant, the Utilities capitalize AFUDC. AFUDC represents the cost of borrowed funds and, where appropriate, the cost of equity funds used for construction purposes in accordance with rules prescribed by the FERC and the PUCN. AFUDC is capitalized in the same manner as construction labor and material costs, however, with an offsetting credit to “other income” for the portion representing the cost of equity funds; and as a reduction of interest charges for the portion representing borrowed funds. Recognition of this item as a cost of utility plant is in accordance with established regulatory ratemaking practices. Such practices are intended to permit the Utility to earn a fair return on, and recover in rates charged for utility services, all capital costs. This is accomplished by including such costs in the rate base and in the provision for depreciation. NPC’s AFUDC rate used during 2008 and 2007 was 9.06% and 9.03% during 2006. SPPC’s AFUDC rates used during 2008, 2007 and 2006 were 8.54%, 8.60% and 8.97%, respectively. As specified by the PUCN, certain projects may be assigned a lower or higher AFUDC rate due to specific interest-rate financings directly associated with those projects.

Depreciation

Substantially all of the Utilities’ plant is subject to the ratemaking jurisdiction of the PUCN or the FERC, and, in the case of SPPC, the CPUC. Depreciation expense is calculated using the straight-line composite method over the estimated remaining service lives of the related properties, which approximates the anticipated physical lives of these assets in most cases. NPC’s depreciation provision, as authorized by the PUCN and stated as a percentage of the average depreciable property balances for those years, was approximately 2.56%, 2.66%, and 3.15% during 2008, 2007 and 2006, respectively. SPPC’s depreciation provision for 2008, 2007 and 2006, as authorized by the PUCN and stated as a percentage of the average cost of depreciable property, was approximately 2.77%, 3.01% and 3.08%, respectively.

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Impairment of Long-Lived Assets

NVE, NPC and SPPC evaluate on an ongoing basis the recoverability of its assets for impairments whenever events or changes in circumstance indicate that the carrying amount may not be recoverable as described in SFAS 144.

Cash and Cash Equivalents

Cash is comprised of cash on hand and working funds. Cash equivalents consist of high quality investments in money market funds and do not have any withdrawal restrictions.

Federal Income Taxes

NVE and its subsidiaries file a consolidated federal income tax return. Current income taxes are allocated based on NVE’s and each subsidiary’s respective taxable income or loss and tax credits as if each subsidiary filed a separate return. NVE accounts for income taxes in accordance with SFAS 109. SFAS 109 requires recognition of deferred tax liabilities and assets for the future tax consequences of events that have been included in the consolidated financial statements or tax returns. Under this method, deferred tax liabilities and assets are determined based on the difference between the financial statement and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse.

In prior years, the Utilities reduced rates to reflect the current tax benefits associated with recognizing certain tax deductions sooner than when the expenses were recognized for financial reporting purposes. A regulatory asset has been recorded for these amounts to reflect the future increases in income taxes payable that will be recovered from customers when these temporary differences reverse. The Utilities have been fully normalized since 1987. AFUDC-Equity is recorded on an after-tax basis. Accordingly, a regulatory asset is recorded when AFUDC-Equity is recognized. This regulatory asset reverses as the related plant is depreciated, resulting in an increase to the tax provision.

The Utilities also have recorded a regulatory liability for the obligation to reduce rates charged customers for deferred taxes recovered from customers in prior years at corporate tax rates higher than the current tax rates. The reduction in rates charged customers will occur as the temporary differences resulting in the excess deferred tax liabilities reverse.

Deferred investment tax credits are being amortized over the estimated service lives of the related properties. Investment tax credits are no longer available to the Utilities.

Revenues

Operating revenues include billed and unbilled utility revenues. The accrual for unbilled revenues represents amounts owed to the Utilities for service provided to customers for which the customers have not yet been billed. These unbilled amounts are also included in accounts receivable.

Revenues related to the sale of energy are recorded based on meter reads, which occur on a systematic basis throughout a month, rather than when the service is rendered or energy is delivered. At the end of each month, the energy delivered to the customers from the date of their last meter read to the end of the month is estimated and the corresponding unbilled revenues are calculated. These estimates of unbilled sales and revenues are based on the ratio of billable days versus unbilled days, amount of energy procured and generated during that month, historical customer class usage patterns and the Utilities’ current tariffs. Accounts receivable as of December 31, 2008, include unbilled receivables of $103 million and $76 million for NPC and SPPC, respectively. Accounts receivable as of December 31, 2007, include unbilled receivables of $106 million and $79 million for NPC and SPPC, respectively.

Asset Retirement Obligations

SFAS 143 provides accounting requirements for the recognition and measurement of liabilities associated with the retirement of tangible long-lived assets. Under the standard, these liabilities are recognized at fair value as incurred and capitalized as part of the cost of the related tangible long-lived assets. Accretion of the liabilities due to the passage of time is classified as an operating expense. Retirement obligations associated with long-lived assets included within the scope of SFAS 143 are those for which a legal obligation exists under enacted laws, statutes written or oral contracts, including obligations arising under the doctrine of promissory estoppel. NVE, NPC and SPPC adopted SFAS 143 on January 1, 2003.

Management’s methodology to assess its legal obligation included an inventory of assets by company, system and components and a review of rights of way and easements, regulatory orders, leases and federal, state, and local environmental laws. Management identified a legal obligation to retire generation plant assets specified in land leases for NPC’s jointly-owned Navajo Generating Station and the newly acquired Higgins Generating Station. Provisions of the lease require the lessees to remove the facilities upon request of the lessors at the expiration of the leases.

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In March, 2005, the FASB issued FIN 47 as clarification to SFAS 143. FIN 47 was effective no later than the end of fiscal years ending after December 15, 2005 (December 31, 2005, for calendar-year enterprises). FIN 47 clarified the term conditional retirement obligation as used in SFAS 143 as well as when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation.

Similar to the methodology used to assess legal obligations under SFAS 143, management reviewed the inventory of assets by system and components, as well as rights of way and easements, regulatory orders, leases and federal, state, and local environmental laws. Management has determined evaporative ponds, dry ash landfills, fuel storage tanks, asbestos and oils treated with Poly Chlorinated Biphenyl to have met the conditional asset retirement obligations of FIN 47.

The following table presents a reconciliation of the beginning and ending aggregate carrying amounts of asset retirement obligation for the years presented below (dollars in thousands):

	NVE					NPC						SPPC
	2008			2007		2008			2007			2008			2007
Balance at January 1	$	53,462		$	18,194	$	46,270		$	12,895		$	7,192		$	5,299
Liabilities incurred in current period		3,424			32,867		3,162			32,867			262			-
Liabilities settled in current period		(4,160	)		-		(4,160	)		-			-			-
Accretion expense		2,904			1,879		2,503			1,488			401			391
Revision in estimated cash flows		1,997			522		2,441			(980	)		(444	)		1,502
Balance at December 31	$	57,627		$	53,462	$	50,216		$	46,270		$	7,411		$	7,192

Cost of Removal

In addition to the legal asset retirement obligations booked under SFAS 143 and FIN 47, the Utilities have accrued for the cost of removing non-legal retirement obligations of other electric and gas assets, in accordance with accepted accounting practices. The amounts of such accruals included in regulatory liabilities in 2008 are approximately $174.3 million and $150.5 million for NPC and SPPC, respectively. In 2007, the amounts were approximately $161.7 million and $129.6 million.

Variable Interest Entities

In December 2003, the FASB issued a revised FIN 46 (R), which elaborates on Accounting Research Bulletin No. 51, "Consolidated Financial Statements." Among other requirements, FIN 46 (R) provides that a variable interest entity be consolidated by the enterprise that is the primary beneficiary of the variable interest entity. As of December 2003, NVE, NPC and SPPC adopted FIN 46 (R) for special purpose entities. In 2004, NVE, NPC and SPPC adopted FIN 46 (R) and the various amendments and interpretations for all variable interest entities. To identify potential variable interests, management reviewed long term purchase power contracts, including contracts with QFs, jointly owned facilities and partnerships that are not consolidated. The Utilities identified seven QFs with long-term purchase power contracts that are variable interests. However, the Utilities are not required at this time to consolidate these QFs under the scope exception provided for in FIN 46 (R) due to the inability to obtain information necessary to (1) determine whether the entity is a variable interest entity, (2) determine whether the enterprise is the variable interest entity’s primary beneficiary, or (3) perform the accounting required to consolidate the variable interest entity for which it is determined to be the primary beneficiary. The Utilities have requested financial information from these QFs but have not been successful in obtaining the information. The Utilities' maximum exposure to loss is limited to the cost of replacing these purchase power contracts if the QFs are unable to deliver power. However, the Utilities believe their exposure is mitigated as they would likely recover these costs through their deferred energy accounting mechanism. The Utilities have not identified any other significant variable interests that require consolidation as of December 31, 2008.

Franchise Fees and Universal Energy Charges

NPC and SPPC, as agents for some state and local governments collect from customers franchise fees and universal energy charges (UEC) levied by the state or local governments on our customers. NPC and SPPC do not record these fees or charges as revenue or expense.

Recent Pronouncements

SFAS 157

Effective January 1, 2008, NVE and the Utilities adopted the provisions of SFAS 157 related to its financial assets and liabilities and nonfinancial assets and liabilities measured at fair value on a recurring basis. In February 2008, the FASB issued FSP 157-2, which deferred the effective date for certain portions of SFAS 157 related to nonrecurring measurements of nonfinancial assets and liabilities. NVE and the Utilities will be required to adopt those provisions of SFAS 157 beginning January 1, 2009, but do not expect the adoption to have a material impact on the consolidated financial statements. In October 2008, the FASB issued FSP 157-3. FSP 157-3 is effective immediately. NVE and the Utilities considered the guidance in FSP 157-3 and have determined that the adoption did not have a material impact on the consolidated financial statements.

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SFAS 159

In February 2007, the FASB issued SFAS 159, which permits entities to choose to measure many financial instruments and certain other items at fair value. The objective of the statement is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. The provisions of SFAS 159 are effective for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. SFAS 159 was effective for SPR and the Utilities beginning January 1, 2008. The adoption of SFAS 159 did not have a material impact on the consolidated financial statements.

SFAS 161

In March 2008, the FASB issued SFAS 161, an amendment of FASB 133. The purpose of SFAS 161 is to provide more adequate disclosure about how derivative and hedging activities affect an entity’s financial position, financial performance and cash flows. The provisions of SFAS 161 are effective for fiscal years beginning after November 15, 2008 and interim periods within those fiscal years. SFAS 161 was effective for NVE and the Utilities beginning January 1, 2009. NVE and the Utilities do not expect the adoption of SFAS 161 to have a significant impact on their disclosure requirements.

FSP 132(R) -1

In December 2008, the FASB issued FSP 132(R)-1, requiring enhanced disclosures about plan assets of a defined benefit pension or other postretirement plan. The provisions of FSP 132(R)-1 that amend SFAS 132 are effective for fiscal years ending after December 15, 2009. NVE and the Utilities will likely be required to include additional disclosure; however, FSP 132(R)-1 will not impact NVE and the Utilities results of operations or financial position.

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NOTE 2. SEGMENT INFORMATION

The Utilities operate three regulated business segments (as defined by SFAS 131); which are NPC electric, SPPC electric and SPPC natural gas service. Electric service is provided to Las Vegas and surrounding Clark County by NPC, and northern Nevada and the Lake Tahoe area of California by SPPC. Natural gas services are provided by SPPC in the Reno-Sparks area of Nevada. Other segment information includes segments below the quantitative thresholds for separate disclosure.

Operational information of the different business segments is set forth below based on the nature of products and services offered. NVE evaluates performance based on several factors, of which, the primary financial measure is business segment gross margin. Gross margin, which the Utilities calculate as operating revenues less fuel, purchased power, and deferred energy costs, provides a measure of income available to support the other operating expenses of the Utilities. Operating expenses are provided by segment in order to reconcile to operating income as reported in the consolidated financial statements. SPPC's deferred energy costs-net for the year ended December 31, 2007 include $14.2 million of disallowed energy costs. NPC’s operating income for the year ended December 31, 2006 includes the reinstatement of deferred energy costs of $178.8 million, which is not reflected in its respective gross margin (dollars in thousands):

									SPPC
	NPC			SPPC		SPPC			Reconciling	SPPC			NVE			NVE
December 31, 2008	Electric			Electric		Gas			Eliminations(1)	Total			Other			Consolidated
Operating Revenues	$	2,315,427		$	1,002,674	$	209,987			$	1,212,661		$	25		$	3,528,113

Energy Costs:
Fuel for power generation		755,925			283,342		-				283,342						1,039,267
Purchased Power		680,816			293,527		-				293,527						974,343
Gas purchased for resale		-			-		170,468				170,468						170,468
Deferred energy costs - net		(6,947	)		1,291		(4,609	)			(3,318	)					(10,265	)
		1,429,794			578,160		165,859				744,019			-			2,173,813

Gross Margin	$	885,633		$	424,514	$	44,128			$	468,642		$	25		$	1,354,300


Other		249,236									141,064			3,719			394,019
Maintenance		63,282									30,787						94,069
Depreciation and amortization		171,080									89,528						260,608
Taxes:
Income taxes		58,014									31,806			(13,069	)		76,751
Other than income		32,069									21,304			152			53,525

Operating Income	$	311,952								$	154,153		$	9,223		$	475,328

Assets	$	7,904,147		$	3,111,649	$	315,095		$ 35,801	$	3,462,545		$	(20,712	)	$	11,345,980

Capital expenditures	$	1,314,697		$	202,011	$	18,795			$	220,806					$	1,535,503

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							SPPC
	NPC		SPPC		SPPC		Reconciling	SPPC		NVE			NVE
December 31, 2007	Electric		Electric		Gas		Eliminations(1)	Total		Other			Consolidated
Operating Revenues	$	2,356,620	$	1,038,867	$	205,430		$	1,244,297	$	43		$	3,600,960

Energy Costs:
Fuel for power generation		594,382		242,973		-			242,973					837,355
Purchased Power		688,606		348,299		-			348,299					1,036,905
Gas purchased for resale		-		-		150,879			150,879					150,879
Deferred energy costs - net		233,166		78,044		10,763			88,807					321,973
		1,516,154		669,316		161,642			830,958		-			2,347,112

Gross Margin	$	840,466	$	369,551	$	43,788		$	413,339	$	43		$	1,253,848

Other		232,610							142,348		4,488			379,446
Maintenance		67,482							31,553		-			99,035
Depreciation and amortization		152,139							83,393		-			235,532
Taxes:
Income taxes		61,108							29,991		(15,944	)		75,155
Other than income		29,823							20,097		193			50,113

Operating Income	$	297,304						$	105,957	$	11,306		$	414,567

Assets	$	6,377,369	$	2,665,943	$	273,220	$ 37,361	$	2,976,524	$	110,857		$	9,464,750

Capital expenditures	$	750,275	$	379,692	$	35,550		$	415,242				$	1,165,517

								SPPC
	NPC			SPPC		SPPC		Reconciling	SPPC		NVE			NVE
December 31, 2006	Electric			Electric		Gas		Eliminations(1)	Total		Other			Consolidated
Operating Revenues	$	2,124,081		$	1,020,162	$	210,068		$	1,230,230	$	1,639		$	3,355,950

Energy Costs:
Fuel for power generation		552,959			247,626					247,626					800,585
Purchased Power		764,850			344,590					344,590					1,109,440
Gas purchased for resale		-			-		160,739			160,739					160,739
Deferred energy costs - net		92,322			47,043		6,947			53,990					146,312
		1,410,131			639,259		167,686			806,945		-			2,217,076

Gross Margin	$	713,950		$	380,903	$	42,382		$	423,285	$	1,639		$	1,138,874

Reinstatement of deferred energy costs		(178,825	)							-		-			(178,825	)
Other		218,120								141,350		7,728			367,198
Maintenance		61,899								31,273		-			93,172
Depreciation and amortization		141,585								87,279		11			228,875
Taxes:
Income taxes		91,781								23,570		(23,780	)		91,571
Other than income		28,118								19,796		172			48,086

Operating Income	$	351,272							$	120,017	$	17,508		$	488,797

Assets	$	5,987,515		$	2,476,483	$	275,294	$ 56,060	$	2,807,837	$	36,724		$	8,832,076

Capital expenditures	$	658,686		$	279,985	$	29,122		$	309,107				$	967,793

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(1) The reconciliation of segment assets at December 31, 2008, 2007, and 2006 to the consolidated total includes the following unallocated amounts:

	2008		2007		2006
Cash	$	21,411	$	23,807	$	53,260
Deferred charges-other		14,390		13,554		2,800
	$	35,801	$	37,361	$	56,060

NOTE 3. REGULATORY ACTIONS

The Utilities are subject to the jurisdiction of the PUCN and, in the case of SPPC, the CPUC with respect to rates, standards of service, siting of and necessity for generation and certain transmission facilities, accounting, issuance of securities and other matters with respect to electric distribution and transmission operations. Additionally, under federal law, the Utilities are subject to certain jurisdictional regulation, primarily by the FERC. The FERC has jurisdiction under the Federal Power Act with respect to rates, service, interconnection, accounting and other matters in connection with the Utilities’ sale of electricity for resale and interstate transmission.

As a result of regulation, the Utilities are required to file annual electric and gas DEAA cases on March 1, quarterly BTER updates for the Utilities’ electric and gas departments and triennial GRCs. A DEAA case is filed to recover/refund any under/over collection of prior energy costs and the BTER updates recover current energy costs. A GRC filing is to set rates to recover operation and maintenance expenses, depreciation, taxes and provide a return on invested capital. Detailed below are Deferred Energy Costs which relate to the DEAA and BTER filings and further below are other regulatory assets and liabilities which primarily relate to the GRCs. Additionally, significant pending or settled rate cases are discussed below.

The following deferred energy costs were included in the consolidated balance sheets as of the dates shown (dollars in thousands):

	December 31, 2008
Description	NPC Electric			SPPC Electric			SPPC Gas			NVE Total

Nevada Deferred Energy
Cumulative Balance requested in 2008 DEAA(1)	$	35,500		$	(21,043	)	$	(11,382	)	$	3,075
2008 Amortization		(89,659	)		(13,100	)		993			(101,766	)
2008 Deferred Energy Costs (2)		130,597			14,330			1,656			146,583
Subtotal – Deferred Energy Balance @ December 31, 2008 - NV	$	76,438			(19,813	)		(8,733	)		47,892
Cumulative CPUC balance		-			1,890			-			1,890
Subtotal – Deferred Energy Balance @ December 31, 2008 - Total	$	76,438		$	(17,923	)	$	(8,733	)	$	49,782
Western Energy Crisis Rate Case (effective 6/07, 3 years)		41,704			-			-			41,704
Reinstatement of deferred energy (effective 6/07, 10 years)		163,321			-			-			163,321

Total	$	281,463		$	(17,923	)	$	(8,733	)	$	254,807

Current Assets
Deferred energy costs – electric		50,436			-			-			50,436
Deferred Assets
Deferred energy costs - electric		231,027			-			-			231,027
Other Current Liabilities		-			(17,923	)		(8,733	)		(26,656	)
Total	$	281,463		$	(17,923	)	$	(8,733	)	$	254,807

(1)	Reflects ordered adjustments.

(2)	These costs to be requested in 2009 DEAA filings on 2/27/2009.

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	December 31, 2007
Description	NPC Electric			SPPC Electric			SPPC Gas			NVE Total

Nevada Deferred Energy
Cumulative Balance requested in 2007 DEAA	$	229,971		$	35,432		$	(112	)	$	265,291
2007 Amortization		(148,361	)		(38,872	)		(702	)		(187,935	)
2007 Deferred Energy Costs		(45,385	)		(17,501	)		(10,555	)		(73,441	)
Subtotal – Deferred Energy Balance @ December 31, 2007 - NV	$	36,225		$	(20,941	)	$	(11,369	)	$	3,915
Cumulative CPUC balance		-			3,368			-			3,368
Subtotal – Deferred Energy Balance @ December 31, 2007 - Total	$	36,225		$	(17,573	)	$	(11,369	)	$	7,283
Western Energy Crisis Rate Case (1) (effective 6/07, 3 years)		65,344			-			-			65,344
Reinstatement of deferred energy (2) (effective 6/07, 10 years)		179,409			-			-			179,409

Total	$	280,978		$	(17,573	)	$	(11,369	)	$	252,036

Current Assets
Deferred energy costs – electric		75,948			-			-			75,948
Deferred Assets
Deferred energy costs - electric		205,030			-			-			205,030
Other Current Liabilities		-			(17,573	)		(11,369	)		(28,942	)
Total	$	280,978		$	(17,573	)	$	(11,369	)	$	252,036

(1)	NPC’s Western Energy Crisis Rate Case is discussed below.

(2)	Reinstatement of Deferred Energy is discussed below.

As discussed in Note 1, Summary of Significant Accounting Policies, regulatory assets represent incurred costs that have been deferred because it is probable they will be recovered through future rates collected from customers. If at any time the incurred costs no longer meet these criteria, these costs are charged to earnings. Regulatory liabilities generally represent obligations to make refunds to customers for previous collections, except for cost of removal which represents the cost of removing future electric and gas assets. Management regularly assesses whether the regulatory assets are probable of future recovery by considering actions of regulators, current laws related to regulation, applicable regulatory environment changes and the status of any current and pending or potential deregulation legislation. Detailed below are Other Regulatory Assets and Liabilities included in the balance sheet of NVE, NPC and SPPC and their current regulatory treatment.

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	NV ENERGY, INC.
	OTHER REGULATORY ASSETS AND LIABILITIES

	AS OF DECEMBER 31, 2008
(dollars in thousands)	Remaining	Receiving Regulatory Treatment				Pending					As of
DESCRIPTION	Amortization	Earning a		Not Earning		Regulatory			2008		December 31, 2007
	Period	Return(1)		a Return		Treatment (2)			Total		Total
Regulatory assets
Loss on reacquired debt	Term of Related Debt	$	87,381	$	-	$	-		$	87,381	$	100,271
Income taxes	various		-		264,779		-			264,779		267,848
Risk management			-		360,000		-			360,000		26,067
Lenzie Generating Station	2042		-		41,673		35,943			77,616		80,284
Mohave Generating Station and deferred costs	2015		19,166		-		(76	)		19,090		18,224
Clark Generating Station Units 1-3	Various thru 2011		6,434		-		12,255			18,689		16,145
PPC	Various thru 2029		32,093		9,421		1,439			42,953		40,629
Plant assets	Various thru 2031		2,513		-		458			2,971		3,014
Asset retirement obligations					-		43,812			43,812		36,498
Nevada divestiture costs	2012		14,955		-		-			14,955		19,469
Merger transition/transaction costs	2016		-		21,096		-			21,096		25,006
Merger severance/relocation	2016		-		11,640		-			11,640		13,762
Merger goodwill	2046		-		277,531		-			277,531		285,365
California restructure costs	Thru 2009		-		220		-			220		1,040
Conservation programs	Thru 2014		33,465		-		92,475			125,940		73,201
Renewable energy programs	2009		4,042		-		-			4,042		5,841
Legal costs					-		6,044			6,044		7,138
Peabody coal costs					-		17,126			17,126		17,406
Legal fees-Western Energy Crisis	2010		1,788		-		-			1,788		5,259
Union contract OPEB change	2017		-		-		10,155			10,155		3,702
Other costs	Thru 2017		785		2,290		4,533			7,608		6,033
Subtotal		$	202,622	$	988,650	$	224,164		$	1,415,436	$	1,052,202
Pensions-SFAS 158			-		413,544		-			413,544		133,984
Total regulatory assets		$	202,622	$	1,402,194	$	224,164		$	1,828,980	$	1,186,186


Regulatory Liabilities
Cost of removal	Various	$	324,721	$	-	$	-		$	324,721	$	291,274
Income taxes	various		-		25,479		-			25,479		28,445
Gain on property sales	2010		1,184		-		-			1,184		1,829
SO2 allowances	Various thru 2014		696		-		-			696		746
Plant liability			-		-		-			-		259
Impact charge			-		-		-			-		711
Depreciation-customer advances	2011		3,951				4,003			7,954		8,745
Domestic production tax deduction			-		-		943			943		380
Other			-		-		360			360		82
Total regulatory liabilities		$	330,552	$	25,479	$	5,306		$	361,337	$	332,471

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	NEVADA POWER COMPANY
	OTHER REGULATORY ASSETS AND LIABILITIES

	AS OF DECEMBER 31, 2008
(dollars in thousands)	Remaining	Receiving Regulatory Treatment				Pending					As of
DESCRIPTION	Amortization	Earning a		Not Earning		Regulatory			2008			December 31, 2007
	Period	Return(1)		a Return		Treatment (2)			Total		Total
Regulatory Assets
Loss on reacquired debt	Term of Related Debt	$	55,659	$	-	$	-		$	55,659	$	67,414
Income taxes	various		-		169,506		-			169,506		165,257
Risk management			-		252,884		-			252,884		17,186
Lenzie Generating Station	2042		-		41,673		35,943			77,616		80,284
Mohave Generating Station	2015		19,166				(76	)		19,090		18,224
Clark Generating Station Units 1-3	2011		6,434				12,255			18,689		16,145
Asset retirement obligations			-				38,847			38,847		32,059
Nevada divestiture costs	2012		9,078		-		-			9,078		11,872
Merger transition/transaction costs	2014		-		14,655		-			14,655		17,446
Merger severance/relocation	2014		-		5,356		-			5,356		6,377
Merger goodwill	2044		-		174,486		-			174,486		179,436
Conservation programs	2013		25,544		-		79,064			104,608		60,222
Renewable energy programs	2009		1,932		-					1,932		2,957
Legal costs	2013		-		-		6,044			6,044		7,138
Peabody coal costs			-		-		17,126			17,126		17,406
Legal fees-Western Energy Crisis	2010		1,788		-		-			1,788		2,801
Other costs	2009		162		1,214		2,614			3,990		4,679
Subtotal		$	119,763	$	659,774	$	191,817		$	971,354	$	706,903
Pensions-SFAS 158			-		187,894		-			187,894		86,909
Total regulatory assets		$	119,763	$	847,668	$	191,817		$	1,159,248	$	793,812

Regulatory Liabilities
Cost of removal	Various	$	174,262	$	-	$	-		$	174,262	$	161,690
Income taxes	Various				8,713		-			8,713		10,038
Gain on property sales	2008				-		-			-		1,829
SO2 allowances	Various thru 2014		696		-		-			696		746
Depreciation-customer advances					-		3,735			3,735		3,736
Domestic production tax deduction					-		943			943		380
Other			-		-		360			360		-
Total regulatory liabilities		$	174,958	$	8,713	$	5,038		$	188,709	$	178,419

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	SIERRA PACIFIC POWER COMPANY
	OTHER REGULATORY ASSETS AND LIABILITIES

	AS OF DECEMBER 31, 2008
(dollars in thousands)	Remaining	Receiving Regulatory Treatment				Pending				As of
DESCRIPTION	Amortization	Earning a		Not Earning		Regulatory		2008			December 31, 2007
	Period	Return(1)		a Return		Treatment (2)		Total		Total
Regulatory assets
Loss on reacquired debt	Term of Related Debt	$	31,722	$	-	$	-	$	31,722	$	32,857
Income taxes	various		-		95,273		-		95,273		102,591
Risk management			-		107,116		-		107,116		8,881
Piñon Pine	Various thru 2029		32,093		9,421		1,439		42,953		40,629
Plant assets	Various thru 2031		2,513				458		2,971		3,014
Asset retirement obligations							4,965		4,965		4,439
Nevada divestiture costs	2012		5,877		-		-		5,877		7,597
Merger transition/transaction costs	2016		-		6,441		-		6,441		7,560
Merger severance/relocation	2016		-		6,284		-		6,284		7,385
Merger goodwill	2046		-		103,045		-		103,045		105,929
California restructure costs	Thru 2009				220		-		220		1,040
Conservation programs	Thru 2014		7,921		-		13,411		21,332		12,979
Renewable energy programs	2009		2,110		-				2,110		2,884
Union contract OPEB change	2017				-		10,155		10,155		3,702
Legal fees-Western Energy Crisis					-				-		2,458
Other costs	Various thru 2017		623		1,076		1,919		3,618		1,354
Subtotal		$	82,859	$	328,876	$	32,347	$	444,082	$	345,299
Pensions-SFAS 158			-		218,550		-		218,550		43,778
Total regulatory assets		$	82,859	$	547,426	$	32,347	$	662,632	$	389,077

Regulatory Liabilities

Cost of removal	Various	$	150,459	$	-	$	-	$	150,459	$	129,584
Income taxes	Various				16,766		-		16,766		18,407
Gain on property sales	2010		1,184		-		-		1,184		-
Plant liability			-		-				-		259
Impact charge			-		-				-		711
Depreciation-customer advances	2011		3,951		-		268		4,219		5,009
Other			-		-		-		-		82
Total regulatory liabilities		$	155,594	$	16,766	$	268	$	172,628	$	154,052

(1) Earning a Return includes either a carrying charge on the asset/liability balance, or a return as a component of weighted cost of capital.

(2) Pending regulatory treatment includes either amounts which have prior regulatory precedent or have been approved and are subject to prudency review.

Pending Regulatory Actions

Nevada Power Company and Sierra Pacific Power Company

Ely Energy Center

On February 9, 2009, NVE and the Utilities announced their intention to postpone plans to construct the EEC due to increasing environmental and economic uncertainties until such time as carbon sequestration becomes commercially viable, which is not expected for at least a decade. NVE and the Utilities still plan to proceed with the construction of the EN-ti line, which will link NPC’s and SPPC’s transmission systems in the southern and northern portions of the state, allowing for the transfer of energy, including renewable resources, between the Utilities. The Utilities will seek approval from the PUCN to accelerate its development of the EN-ti line. The PUCN had previously approved the Utilities spending on the EEC up to $130 million, of which the Utilities have spent and recorded as an other deferred asset approximately $71.1 million including amounts related to the En-ti line as of December 31, 2008, as such, management expects full recovery of the amounts expended through December 31, 2008.

Nevada Power Company

NPC General Rate Case

In December 2008, NPC filed its statutorily required GRC. In this GRC, NPC is requesting the following:

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·	Increase in general rates by $323.9 million, approximately a 14.95% increase;

·	ROE and ROR of 11.0% and 8.88%, respectively;

Authorization to recover the costs of major plant additions including the purchase of the 598 MW (nominally rated) combined cycle Higgins Generating Station, construction of 600 MW (nominally rated) peaking units at the Clark Generating Station, an upgrade to the emission control systems on existing units at the Clark Generating Station, installation of environmental equipment upgrades at the Reid Gardner Generating Station and new transmission and distribution projects;

·	CWIP in rate base for the construction of a 500 MW (nominally rated) combined cycle unit at the existing Harry Allen site;

·	Implementation of a low-income rate discount for customers;

Delay the rate effective date from July 1, 2009 to September 1, 2009. The delay in the rate effective date is contingent on PUCN approval to track and defer the revenues that NPC would otherwise collect during this sixty day period in a regulatory asset account and permit that NPC be allowed to record a carrying charge. NPC would seek authority to amortize this regulatory asset in its next GRC filing, currently scheduled for December 2011.

If approved, the new rates would be effective September 1, 2009.

Sierra Pacific Power Company

SPPC California General Rate Case

In July 2008, SPPC filed a GRC. SPPC requested the following:

·	Increase in general rates of $6.6 million, approximately an 8.1% increase;

·	ROE and ROR of 11.4% and 8.81%, respectively;

·	Authorization to recover the costs of major plant additions, which include the new Tracy 541 MW (nominally rated) Generating Station, distribution plant additions and an increase to the California Energy Efficiency Program;

·	A two-part mechanism to recover changes in non-energy cost adjustment clause costs incurred during the two years between rate cases.

If approved, the new rates would be effective April 1, 2009.

Settled Regulatory Actions

Nevada Power Company

NPC 2008 Deferred Energy Rate Case and BTER Update

In February 2008, NPC filed applications to create a new DEAA rate and to update the going forward BTER. In these applications, NPC requested to decrease rates by $116.3 million, a decrease of 5.04% while recovering $36 million of deferred fuel and purchased power costs. The going forward BTER became effective April 1, 2008. The PUCN issued its order in September 2008 setting the DEAA rate for all customers at $0.00 per kWh effective October 1, 2008. The PUCN found that NPC’s purchases of fuel and power were prudent and approved those costs for the test period.

Sierra Pacific Power Company

SPPC Nevada Gas DEAA and BTER Update

In December 2007, SPPC filed for the authority to implement quarterly BTER adjustments for its natural gas and liquefied propane gas services. The authority was approved in January 2008, and as a result, in February 2008, SPPC filed applications to create a new DEAA rate and to update the going forward BTER. In these applications SPPC requested to decrease rates by $9.9 million, a decrease of 5.53%, while refunding an over collection of $11.4 million in deferred natural gas and liquid propane costs. The going forward BTER became effective April 1, 2008. The PUCN issued its order in October 2008 setting the DEAA rate at $0.00 per therm effective October 1, 2008 and approving SPPC’s purchases of natural gas and propane for the test period as prudent.

SPPC Nevada Electric DEAA and BTER Update

In February 2008, SPPC filed applications to create a new DEAA rate and to update the going forward BTER. In these applications SPPC requested to decrease rates by $42.1 million, a decrease of 4.57%, while refunding an over collection of $20.9 million in deferred fuel and purchased power costs. The going forward BTER became effective April 1, 2008. The PUCN issued its order in October 2008 setting the DEAA rate at $0.00 per kWh effective October 1, 2008. The PUCN found that SPPC’s purchases of fuel and power were prudent and approved those costs for the test period.

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SPPC California Energy Cost Adjustment Clause

In April 2008, SPPC filed to decrease rates by $12.2 million, a decrease of 15.2%. The CPUC approved the filing in August 2008. The rates requested in this filing were effective September 1, 2008.

SPPC Nevada 2007 GRC

In December 2007, SPPC filed its statutorily required electric GRC. The filing requested a ROE and ROR of 11.5% and 8.73%, respectively, and an increase to general revenues of $110.8 million.

The PUCN issued its order in June 2008, with rates effective July 1, 2008. The PUCN order resulted in the following significant items:

·	Increase in general rates of $87.1 million, a 10.45% increase;

·	ROE and ROR of 10.6% and 8.41%, respectively;

·	Authorization to recover the costs of the new 541 MW (nominally rated) Tracy Generating Station; and

·	Authorization to recover the projected operating and maintenance costs associated with the new Tracy Generating Station.

SPPC Nevada 2003 GRC

In its 2003 GRC, 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 IRP. While the conventional portion of the plant, a gas-fired combined cycle unit, was installed and performed as planned, the coal gasification unit never became fully operational. After numerous attempts to re-engineer the coal gasifier, the technology was determined to be unworkable.

In its order of May 25, 2004, the PUCN disallowed $43 million of unreimbursed costs associated with the Project. As a result, these amounts were expensed in 2004. SPPC filed a Petition for Judicial Review with the Second Judicial District Court of Nevada (District Court) in June 2004 (CV04-01434). On January 25, 2006, the District Court vacated the PUCN’s disallowance in SPPC’s 2003 GRC and remanded the case back to the PUCN for further review as to whether the costs were justly and reasonably incurred (“the Order”). On March 27, 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. On June 12, 2006, the District Court granted the PUCN’s motion to stay the Order. The Supreme Court dismissed the appeal in September 2006. Requests for rehearing were denied in late December 2006, and on January 18, 2007 the matter was remitted back to the District Court, which, consistent with the Order, remanded the matter back to the PUCN for further review.

On March 18, 2008, the PUCN issued an order to place $5.8 million (Nevada jurisdiction) of the previously disallowed $43 million unreimbursed costs in a regulatory asset account without a carrying charge. As a result of this order and in accordance with SFAS 90, SPPC recognized approximately $4.3 million in income for the year ended December 31, 2008. The remaining difference of $1.5 million will be recognized over an approximate six year period. The time for any party to appeal the PUCN’s decision ended in June 2008 and no appeals were filed.

NPC 2007 Western Energy Crisis Rate Case

In January 2007, NPC filed an application to recover $83.6 million in deferred legal and settlement costs incurred to resolve claims associated with power supply contracts terminated during the Western Energy Crisis. This application requested to begin amortizing the costs over a four-year period beginning June 1, 2007.

In March 2007, the PUCN approved a negotiated settlement where NPC is authorized to recover the $83.6 million plus carrying charges over a three-year period beginning June 1, 2007, which differed from the four-year period requested in the application.

NPC 2001 Deferred Energy Case

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

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In March 2002, the PUCN issued its Order on the application, allowing NPC to recover $478 million over a three-year period, but disallowing $434 million of deferred purchased fuel and power costs and $30.9 million in carrying charges consisting of $10.1 million in carrying charges accrued through September 2001 and $20.8 million in carrying charges accrued from October 2001 through February 2002. The Order stated that the disallowance was based on alleged imprudence in incurring the disallowed costs. NPC and the BCP both sought individual review of the PUCN Order in the First District Court of Nevada (the District Court). The District Court affirmed the PUCN’s decision. Both NPC and the BCP filed Notices of Appeal with the Nevada Supreme Court.

In July 2006, the Supreme Court of Nevada issued a ruling reversing $178.8 million of the PUCN’s disallowance which was part of the NPC’s 2001 Deferred Energy Case. The decision directed the District Court to remand the matter back to the PUCN to determine the appropriate rate schedule.

In March 2007, the PUCN approved a stipulation that authorizes NPC to recover in rates $189.9 million over ten years beginning on June 1, 2007, with no additional carrying charges. The $189.9 million represents Nevada’s jurisdictional portion of the $178.8 million disallowance plus carrying charges of $11.1 million from the date the costs were incurred to the date of disallowance by the PUCN.

NPC 2006 General Rate Case

In November 2006, NPC filed its statutorily required electric GRC and further updated the filing in February 2007. The filing requested an ROE and ROR of 11.4% and 9.39% and an increase to general revenues of $156.4 million.

The PUCN issued its order in May 2007, with rates effective as of June 1, 2007. The PUCN order resulted in the following significant items:

·	increase in general rates of $120.1 million, a 5.66% increase;

·	ROE and ROR of 10.7% and 9.06%, respectively;

·	authorized 100% recovery of unamortized 1999 NPC / SPPC merger costs;

·	authorized incentive rate making for the Lenzie Generating Station;

·	authorized recovery of accumulated cost and savings, including the net book value of the Mohave Generating Station over an eight year period, see Note 1, Significant Accounting Policies for further discussion of the Mohave Generating Station.

Carrying Charge on the Lenzie Generating Station

In 2004, the PUCN granted NPC’s request to designate the Lenzie Generating Station as a critical facility and allowed a 2% enhanced ROE to be applied to the Lenzie Generating Station construction costs expended after acquisition. The order allowed for an additional 1% enhanced ROE if the two Lenzie Generating Station units were brought on line early. In addition, the PUCN granted NPC’s request to begin accumulating a carrying charge as a regulatory asset including the 3% enhanced ROE (collectively referred to as “carrying charges”), until the plant is included in rates. Units 1 and 2 were declared commercially operable in January 2006 and April 2006, respectively, qualifying for the incentive ROE treatment.

Through June 30, 2007, NPC had accumulated approximately $57.6 million in carrying charges; however, $7.9 million of this amount was not recorded for financial reporting purposes as it represents equity carrying costs that are not recognized until collected through rates. NPC did not record a separate carrying charge component related to the Lenzie Generating Station during 2008 as the plant is in rate base effective June 1, 2007 as discussed below.

In May 2007, the PUCN issued its order on NPC’s 2006 GRC authorizing recovery of the carrying charges, effective as of June 1, 2007. NPC was authorized to recover over a 35 year period $30.3 million of the carrying charges calculated through the certification period ending October 31, 2006. Beginning June 1, 2007, NPC began recognizing its full return on the Lenzie Generating Station through rates rather than as a separate carrying charge component. NPC has requested recovery of the remaining $27.3 million of carrying charges calculated subsequent to the certification period in its 2008 GRC.

Mohave Generating Station

NPC owns approximately 14% of the Mohave Generating Station. Southern California Edison is the operating partner of the Mohave Generating Station.

When operating, the Mohave Generating Station obtained all of its coal supply from a mine in northeast Arizona on lands of the Navajo Nation and the Hopi Tribe (the Tribes). This coal was delivered from the mine to the Mohave Generating Station by means of a coal slurry pipeline, which requires water that is obtained from groundwater wells located on lands of the Tribes in the mine vicinity.

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The Grand Canyon Trust and Sierra Club filed a lawsuit in the U.S. District Court, District of Nevada in February 1998 against the owners (including NPC) of the Mohave Generating Station, alleging violations of the Clean Air Act regarding emissions of sulfur dioxide and particulates. An additional plaintiff, National Parks and Conservation Association, later joined the suit. In 1999, the plant owners and plaintiffs filed a settlement with the court, which resulted in a consent decree, approved by the court in November 1999. The consent decree established emission limits for sulfur dioxide and opacity and required installation of air pollution controls for sulfur dioxide, nitrogen oxides, and particulate matter. Pursuant to the decree, the Mohave Generating Station Units 1 and 2 ceased operations as of January 2006 as the new emission limits were not met. Due to the lack of resolution regarding continual availability of the coal and water supply with the Tribes, the Owners did not proceed with the Consent Decree.

In December 2005, the Owners of the Mohave Generating Station suspended operation, pending resolution of these issues. However, in June 2006, majority stake holder Southern California Edison announced it would no longer participate in the efforts to return the plant to service. As a result, NPC decided it is not economically feasible to continue its participation in the project. In September 2006, Salt River’s co-tenancy agreement expired and the operating agreement between the Owners expired in July 2006. The Owners are negotiating an extension of both agreements including a process that addresses how Owners may sell or assign their right, title, interest and obligations in the Mohave Generating Station.

In NPC’s 2006 GRC, the PUCN approved the recovery of the net book value of the plant and costs and savings related to the plant through the certification period of October 31, 2006. The balance to be recovered, over the eight year period, is approximately $19.2 million as of December 31, 2008 and is recorded in Other Regulatory Assets. All costs incurred subsequent to the certification period are accumulated in Other Regulatory Assets. NPC is seeking recovery of approximately $2.1 million in its GRC for those costs.

FERC Matters

California Wholesale Spot Market Refunds

NPC and SPPC are participants in a FERC proceeding wherein California parties have been authorized to recalculate, or mitigate, the prices they paid for wholesale spot market power between October 2, 2000 and June 20, 2001. Both of the Utilities made spot market sales that are eligible for mitigation, therefore the Utilities expect to pay refunds resulting from the recalculated energy prices. Parties have contested the FERC’s decision to limit the timeframe for the recalculations and a Ninth Circuit court decision remanded a related issue to the FERC, therefore NPC and SPPC are not able to determine the eventual magnitude of refunds that may result from this FERC process. NPC and SPPC are actively participating in this docket to ensure their interests are represented.

Nevada Power Company

Based on the FERC’s orders to date, NPC believes the recalculated energy prices for NPC sales to the California Independent System Operator (CAISO) and the bankrupt California Power Exchange (CALPX) would result in an approximate $19 million refund. The FERC has also allowed for energy sellers to provide cost justification in the event the recalculated energy prices fall below sellers’ costs. NPC developed and filed a cost based filing, which justified a $6 million reduction to the estimated refunds resulting in a $13 million refund.

CAISO and CALPX currently owe NPC approximately $19 million for power delivered during the same timeframe for which NPC had fully reserved for in 2001. As such, if NPC is ordered to pay CAISO and CALPX the refunds discussed above, NPC would apply such payments towards NPC’s receivable of $19 million from CAISO and CALPX.

Sierra Pacific Power Company

Based on the FERC’s orders to date, SPPC believes the recalculated energy prices for sales to the CAISO and CALPX during the October 2, 2000 to June 20, 2001 timeframe would result in a $4 million refund.

CAISO and CALPX currently owe SPPC approximately $1 million for power delivered during the same timeframe and SPPC recorded a reserve against the $1 million receivable in 2001. In 2004, SPPC recorded an additional $3 million liability for this item.

NOTE 4. INVESTMENTS IN SUBSIDIARIES AND OTHER PROPERTY

Investments in subsidiaries and other property consisted of (dollars in thousands):

NV Energy, Inc.

	December 31,
	2008		2007
Cash Value-Life Insurance	$	2,456	$	2,401
Non-utility property of NEICO		5,238		5,136
Non-utility property of SPC (1)		4,130		10,000
Property not designated for utility use		12,418		12,577
Other non-utility property		947		947
	$	25,189	$	31,061

(1) SPC, a wholly owned subsidiary of NVE, had an impairment charge of its long haul network assets of $5.9 million (before taxes).

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Nevada Power Company

	December 31,
	2008		2007
Cash Value-Life Insurance	$	2,456	$	2,401
Non-utility property of NEICO		5,238		5,136
Property not designated for utility use		12,007		12,007
	$	19,701	$	19,544

Sierra Pacific Power Company

	December 31,
	2008		2007
Property not designated for utility use	$	411	$	570

NOTE 5. JOINTLY OWNED FACILITIES

At December 31, 2008, NPC and SPPC owned the following undivided interests in jointly owned electric utility facilities:

	% Owned			Plant in Service		Accumulated Depreciation		Net Plant in Service		CWIP
NPC
Navajo Generating Station		11.3	%	$	245,047	$	130,071	$	114,976	$	34
Reid Gardner Generating Station No. 4		32.2	%		177,940		104,409		73,531		907
Silverhawk Generating Station		75.1	%		243,616		31,891		211,725		25
				$	666,603	$	266,371	$	400,232	$	966

SPPC
Valmy Generating Station		50.0	%	$	315,574	$	196,473	$	119,101	$	2,278

The amounts for the Navajo Generating Station, operated by the Salt River, include NPC’s share of transmission systems, general plant equipment and NPC’s share of the jointly owned railroad which delivers coal to the plant. Each participant provides its own financing for all these jointly owned facilities. NPC’s share of the operating expenses for these facilities is included in the corresponding operating expenses in its Consolidated Statement of Operations.

Reid Gardner Generating Station Unit No. 4 is owned by the CDWR (67.8%) and NPC (32.2%). NPC is operating agent. Contractually, NPC is entitled to receive 25 MW of base load capacity and 232 MW of peaking capacity. Operationally, Unit No. 4 subject to heat input at 257 MW is entitled to use 100% of the unit’s peaking capacity for 1500 hours each year and is entitled to 9.6% of the first 250 MW of capacity and associated energy.

NPC is the operator of the Silverhawk Generating Station, which is jointly owned with SNWA. NPC’s owns 75% and its share of direct operation and maintenance expenses is included in its accompanying Consolidated Statement of Operations.

SPPC and Idaho Power Company each own an undivided 50% interest in the Valmy Generating Station, with each company being responsible for financing its share of capital and operating costs. SPPC is the operating agent of the plant for both parties. SPPC’s share of direct operation and maintenance expenses for the Valmy Generating Station are in included in its accompanying Consolidated Statement of Operations.

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NOTE 6. LONG-TERM DEBT

As of December 31, 2008, NPC’s, SPPC’s and NVE’s aggregate annual amount of maturities for long-term debt (including obligations related to capital leases) for the next five years and thereafter are shown below (dollars in thousands):

	NPC			SPPC		NVE Holding Co. and Other Subs.		NVE Consolidated
2009	$	7,218		$	600	$	-	$	7,818
2010		417,633			152,912		-		570,545
2011		369,924			-		-		369,924
2012		136,448			100,000		63,670		300,118
2013		7,146			250,000		-		257,146
		938,369			503,512		63,670		1,505,551
Thereafter		2,468,360			883,500		421,539		3,773,399
		3,406,729			1,387,012		485,209		5,278,950
Unamortized Premium(Discount) Amount		(12,932	)		9,575		680		(2,677	)
Total	$	3,393,797		$	1,396,587	$	485,889	$	5,276,273

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

Nevada Power Company

General and Refunding Mortgage Notes, Series U

General and Refunding Mortgage Notes, Series S

In July 2008, NPC issued and sold $500 million of its 6.5% General and Refunding Mortgage Notes, Series S, due 2018. The net proceeds of the issuance were used to repay $270 million of amounts outstanding under NPC’s revolving credit facility and for general corporate purposes.

6.75% General and Refunding Mortgage Notes, Series R

In June 2007, NPC issued and sold $350 million of its 6.750% General and Refunding Mortgage Notes, Series R, due July 1, 2037. The Series R Notes were issued pursuant to a registration statement previously filed with the SEC. The net proceeds from the issuance were used to fund the purchase of the tendered Series G Notes (discussed below), repay amounts outstanding under NPC’s revolving credit facility, and for general corporate purposes.

Redemptions

Tender Offer for General and Refunding Mortgage Notes, Series G

In June 2007, NPC settled its cash tender offer for its 9.00% General and Refunding Mortgage Notes, Series G, due 2013. Those holders who tendered their notes were entitled to receive a purchase price of $1,079.75 per $1,000 principal amount of Series G Notes. Approximately $210.3 million of the $227.5 million Series G Notes outstanding were validly tendered and accepted by NPC. Approximately $17.2 million aggregate principal amount of the 9.00% General and Refunding Mortgage Bonds remained outstanding.

In August 2008, NPC redeemed the remaining approximately $17.2 million 9.00% General and Refunding Mortgage Notes, Series G, at 104.50% of the stated principal amount, plus accrued interest to the date of redemption. NPC used available cash on hand to redeem these notes.

Conversions

Conversion of Coconino County Pollution Control Refunding Revenue Bonds and Clark County Pollution Control Revenue Bonds

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Revolving Credit Facilities

In April 2006, NPC increased the size of its revolving credit facility from $350 million to $600 million. The facility provides additional liquidity for increased commodity prices and temporary bridge financing of capital expenditures. As of December 31, 2008, NPC had $15.5 million of letters of credit outstanding and had $409.6 million in borrowings outstanding under the $600 million revolving credit facility. In January 2009, NPC entered into an additional $90 million supplemental revolving credit facility. The facility has a term of 364 days, and is secured by General and Refunding Mortgage bonds. This credit facility matures on January 3, 2010, and is in addition to NPC’s existing $600 million revolving credit facility, which matures in November 2010. As of February 20, 2009, NPC had $15.3 million of letters of credit outstanding and had $374.1 million borrowed under the $600 million revolving credit facility.

The NPC Credit Agreements contain two financial maintenance covenants. The first requires that NPC maintain a ratio of consolidated indebtedness to consolidated capital, determined as of the last day of each fiscal quarter, not to exceed 0.68 to 1. The second requires that NPC maintain a ratio of consolidated cash flow to consolidated interest expense, determined as of the last day of each fiscal quarter for the period of four consecutive fiscal quarters, not to be less than 2.0 to 1. As of December 31, 2008, NPC was in compliance with these covenants.

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

The NPC Credit Agreement places certain restrictions on debt incurrence, liens and dividends. These restrictions are discussed in Note 8, Debt Covenant and Other Restrictions.

Sierra Pacific Power Company

General and Refunding Mortgage Notes, Series Q

6.75% General and Refunding Mortgage Notes, Series P

In June, 2007, SPPC issued and sold $325 million of its 6.75% General and Refunding Mortgage Notes, Series P, due July 1, 2037. The Series P Notes were issued pursuant to a registration statement previously filed with the SEC. The net proceeds from the issuance were used to fund the purchase of the tendered Series A Notes (discussed below), repay amounts outstanding under SPPC’s revolving credit facility and for general corporate purposes.

Washoe County Water Facilities Refunding Revenue Bonds

In April 2007, on behalf of SPPC, Washoe County, Nevada (Washoe County) issued $80 million aggregate principal amount of its Water Facilities Refunding Revenue Bonds, Series 2007A and B, due March 1, 2036 (the “Water Bonds”).

In connection with the issuance of the Water Bonds, SPPC entered into financing agreements with Washoe County, pursuant to which Washoe County loaned the proceeds from the sales of the Water Bonds to SPPC. SPPC’s payment obligations under the financing agreements are secured by SPPC’s General and Refunding Mortgage Notes, Series O.

The Water Bonds initial rates, as determined by auction on April 25, 2007, were 3.85%. The method of determining the interest rate on the Water Bonds may be converted from time to time so that such Bonds would thereafter bear interest at a daily, weekly, flexible, auction or term rate as designated.

The proceeds of the offerings were used to refund the $80 million aggregate principal amount of 5.00% Washoe County Water Facilities Revenue Bonds, Series 2001.

Redemptions

Tender Offer for General and Refunding Mortgage Notes, Series A

In June 2007, SPPC settled its cash tender offer, for its 8.00% General and Refunding Mortgage Notes, Series A, due 2008. Those holders who tendered their notes by the expiration date were entitled to receive a purchase price of $1,022.10 per $1,000 principal amount of Series A Notes. Approximately $220.8 million of the $320 million Series A Notes outstanding were validly tendered and accepted by SPPC, and $99.2 million aggregate principal amount of the 8.00% General and Refunding Mortgage Notes remained outstanding.

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Conversions

Conversion of Washoe County Water Facilities Refunding Revenue Bonds

In January 2009, SPPC converted the $40 million principal amount, Washoe County, Nevada Water Facilities Refunding Revenue Bonds Series 2007A bonds, due 2036 (the “Water Bonds”) from auction rate securities to variable rate demand notes. The purpose of the conversion was to reduce interest costs and volatility associated with these bonds. SPPC purchased 100% of the Water Bonds on that date, with the use of its revolving credit facility and available cash, and will remain the sole holder of the Water Bonds until such time as SPPC determines to reoffer the Water Bonds to investors. These Water Bonds remain outstanding and have not been retired or cancelled. However, as SPPC is the sole holder of the Water Bonds, for financial reporting purposes the investment in the Water Bonds and the indebtedness is offset for presentation purposes.”

Conversion of Humboldt County Pollution Control Refunding Revenue Bonds Series 2006

Conversion of Washoe County Water Facilities Refunding Revenue Bonds

In July 2008, SPPC converted the $40 million principal amount, Washoe County, Nevada Water Facilities Refunding Revenue Bonds Series 2007B bonds, due 2036 (the “Water Bonds”) from auction rate securities to variable rate demand notes. The purpose of the conversion was to reduce interest costs and volatility associated with these bonds. SPPC purchased 100% of the Water Bonds on that date, with the use of its revolving credit facility and available cash, and will remain the sole holder of the Water Bonds until such time as SPPC determines to reoffer the Water Bonds to investors. These Water Bonds remain outstanding and have not been retired or cancelled. However, as SPPC is the sole holder of the Water Bonds, for financial reporting purposes the investment in the Water Bonds and the indebtedness is offset for presentation purposes.

Revolving Credit Facility

In April 2006, SPPC increased the size of its revolving credit facility from $250 million to $350 million. The facility provides additional liquidity for increased commodity prices and temporary bridge financing of capital expenditures. As of December 31, 2008, SPPC had $17.5 million of letters of credit outstanding and had $152.9 million borrowed under the revolving credit facility. As of February 20, 2009, SPPC had $17.1 million of letters of credit and had $204.7 borrowed under the revolving credit facility.

The SPPC Credit Agreement contains two financial maintenance covenants. The first requires that SPPC maintain a ratio of consolidated indebtedness to consolidated capital, determined as of the last day of each fiscal quarter, not to exceed 0.68 to 1. The second requires that SPPC maintain a ratio of consolidated cash flow to consolidated interest expense, determined as of the last day of each fiscal quarter for the period of four consecutive fiscal quarters, not to be less than 2.0 to 1. As of December 31, 2008, SPPC was in compliance with these covenants.

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

The SPPC Credit Agreement, similar to SPPC's Series H Notes, places certain restrictions on debt incurrence, liens and dividends. These limitations are discussed in Note 8, Debt Covenant and Other Restrictions.

NV Energy, Inc.

Debt Repurchase

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In December 2007, NVE repurchased approximately $10.5 million of the 7.803% Senior Notes and approximately $14.5 million of the 6.75% Senior Notes. The total consideration was approximately $26 million (which included a premium and accrued interest), and was paid from NVE’s cash on hand. As of December 31, 2008, the outstanding balance for the 7.803% Senior Notes was $63.7 million.

Lease Commitments

In 1984, NPC entered into a 30-year capital lease for its Pearson building with five-year renewal options beginning in year 2015. The fixed rental obligation for the first 30 years is $5.1 million per year. Also, NPC has a power purchase contract with Nevada Sun-Peak Limited Partnership. The contract contains a buyout provision for the facility at the end of the contract term in 2016. The facility is situated on NPC property. In 2007, NPC entered into a 20-year lease, with three 10 year renewal options, to occupy land and building for its Beltway Complex, an operations center in southern Nevada. In accordance with SFAS 13, NPC accounts for the building portion of the lease as a capital lease and the land portion of the lease as an operating lease. NPC has not begun depreciating the property as it continues to construct leasehold improvements. NPC expects to transfer operations to the facilities in or around spring 2009. In 2007, the Utilities entered into Master leasing agreements of which various pieces of equipment qualify as capital leases. The remaining equipment is treated as operating leases. The lease term is for 7 years.

Future cash payments for these capital leases, combined, as of December 31, 2008, were as follows (dollars in thousands):

2009	$	12,467
2010		12,466
2011		9,630
2012		9,493
2013		9,510
Thereafter		32,668
Total Minimum Lease Payments	$	86,234

Less amounts representing interest	$	31,963

Present Value of Net minimum lease payments	$	54,271

NOTE 7. FAIR VALUE OF FINANCIAL INSTRUMENTS

The December 31, 2008, carrying amount of cash and cash equivalents, current assets, accounts receivable, accounts payable and current liabilities approximates fair value due to the short-term nature of these instruments.

The total fair value of NPC’s consolidated long-term debt at December 31, 2008, is estimated to be $3.1 billion (excluding current portion) based on quoted market prices for the same or similar issues or on the current rates offered to NPC for debt of the same remaining maturities. The total fair value (excluding current portion) was estimated to be $2.6 billion at December 31, 2007.

The total fair value of SPPC’s consolidated long-term debt at December 31, 2008, is estimated to be $1.3 billion (excluding current portion) based on quoted market prices for the same or similar issues or on the current rates offered to SPPC for debt of the same remaining maturities. The total fair value (excluding current portion) was estimated to be $1.2 billion as of December 31, 2007.

The total fair value of NVE’s consolidated long-term debt at December 31, 2008 is estimated to be $4.9 billion (excluding current portion) based on quoted market prices for the same or similar issues or on the current rates offered to NVE for debt of the same remaining maturities. The total fair value (excluding current portion) was estimated to be $4.3 billion as of December 31, 2007.

NOTE 8. DEBT COVENANT AND OTHER RESTRICTIONS

Dividends from Subsidiaries

Since NVE is a holding company, substantially all of its cash flow is provided by dividends paid to NVE by NPC and SPPC on their common stock, all of which is owned by NVE. In 2008, NPC and SPPC paid $54.9 million and $141.5 million in dividends, respectively, to NVE. In 2009, SPPC paid $96.8 million for dividends declared prior to December 31, 2008.

On February 5, 2009, NPC and SPPC declared a $22.0 million and $12.0 million dividend, respectively, to NVE, to be paid in March 2009.

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Since NPC and SPPC are public utilities, they are subject to regulation by state utility commissions, which impose limits on investment returns or otherwise may impact the amount of dividends that the Utilities may declare and pay.

Certain debt agreements entered into by NVE and the Utilities contain covenants which set restrictions on certain payments, including the amount of dividends they may declare and pay, and restrict the circumstances under which such dividends may be declared and paid.

Limits on Restricted Payments

NV Energy, Inc.

Dividends are considered periodically by NVE’s BOD and are subject to factors that ordinarily affect dividend policy, such as current and prospective earnings, current and prospective business conditions, regulatory factors, NVE’s financial conditions and other matters within the discretion of the BOD, as well as dividend restrictions set forth in NVE’s debt. The BOD will continue to review the factors described above on a periodic basis to determine if and when it is prudent to declare a dividend on NVE’s Common Stock. There is no guarantee that dividends will be paid in the future, or that, if paid, the dividends will be paid at the same amount or with the same frequency as in the past. In February, June and September 2008, NVE paid a cash dividend of $0.08 per share. In October 2008, the BOD increased the cash dividend to $0.10 per share, which was paid in in December 2008. In February 2009, NVE declared a cash dividend of $0.10 per share for common stock holders of record as of March 3, 2009.

Certain NVE debt agreements contain covenants that limit the amount of restricted payments, including dividends that may be made by NVE. However, as of December 31, 2008, NVE complied with all such covenants, and management does not believe that these covenants will materially affect NVE’s ability to pay dividends.

Dividend Restrictions Applicable to the Utilities

Ability to Issue Debt

NV Energy, Inc.

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Nevada Power Company

Ability to Issue General and Refunding Mortgage Securities

1.	70% of net utility property additions;

2.	the principal amount of retired General and Refunding Mortgage Securities; and/or

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

Property additions include plant in service and specific assets in CWIP. The amount of bond capacity listed above does not include eligible property in CWIP.

Sierra Pacific Power Company

As of December 31, 2008, SPPC had approximately $495 million of PUCN financing authority, which expires on December 31, 2009.

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Ability to Issue General and Refunding Mortgage Securities

1.	70% of net utility property additions;

2.	the principal amount of retired General and Refunding Mortgage Securities; and/or

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

Property additions include plant in service and specific assets in CWIP. The amount of bond capacity listed above does not include eligible property in CWIP.

NOTE 9. DERIVATIVES AND HEDGING ACTIVITIES

NVE, SPPC and NPC apply SFAS 133, as amended by SFAS 138, SFAS 149, SFAS 155, and SFAS 157. As amended, SFAS 133 establishes accounting and reporting standards for derivatives instruments, including certain derivative instruments embedded in other contracts and for hedging activities. It requires that an entity recognize all derivatives as either assets or liabilities in the statement of financial position, measure those instruments at fair value, and recognize changes in the fair value of the derivative instruments in earnings in the period of change, unless the derivative meets certain defined conditions and qualifies as an effective hedge. SFAS 133 also provides a scope exception for contracts that meet the normal purchase and sales criteria specified in the standard. The normal purchases and normal sales exception requires, among other things, physical delivery in quantities expected to be used or sold over a reasonable period in the normal course of business. Contracts that are designated as normal purchase and normal sales are accounted for under deferred energy accounting and not recorded on the Consolidated Balance Sheets at fair value.

Commodity Risk

The energy supply function encompasses the reliable and efficient operation of the Utilities’ generation, the procurement of all fuels and power and resource optimization (i.e., physical and economic dispatch) and is exposed to risks relating to, but not limited to, changes in commodity prices. NVE and the Utilities’ objective in using derivative instruments is to reduce exposure to energy price risk. Energy price risks result from activities that include the generation, procurement and sale of power and the procurement and sale of natural gas. Derivative instruments used to manage energy price risk from time to time may include: forward contracts, which involve physical delivery of an energy commodity; over-the-counter options with financial institutions and other energy companies, which mitigate price risk by providing the right, but not the requirement, to buy or sell energy related commodities at a fixed price; and swaps, which require the Utilities’ to receive or make payments based on the difference between a specified price and the actual price of the underlying commodity. These contracts assist the Utilities’ to reduce the risks associated with volatile electricity and natural gas markets.

Interest Rate Risk

NVE and the Utilities’ are subject to risk of fluctuating interest rates in the normal course of business. We manage interest rate risk by taking advantage of market conditions when timing the issuance of long-term debt financings. In order to manage the risks associated with changes in and the future impact of interest rate payments we may enter into interest rate lock agreements and forward starting swaps. The settlements of those agreements are amortized over the life of the debt in accordance with regulatory accounting practices under SFAS 71. There were no interest rate lock agreements or forward starting swaps outstanding as of December 31, 2008.

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Adoption of SFAS 157

Effective January 1, 2008, NVE and the Utilities’ adopted SFAS 157, which defines fair value, establishes a framework for measuring fair value and enhances disclosures about assets and liabilities recorded at fair value.

SFAS 157 also establishes a three-level hierarchy which requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. Derivative instruments used by NVE and the Utilities’ to manage energy price risk are valued using quoted exchange prices, external dealer prices and option pricing modules that utilize readily observable market parameters and are therefore classified within level 2 of the fair value hierarchy. The three levels are defined as follows:

Level 1 – Quoted prices in active markets for identical assets or liabilities. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives and listed equities.

Level 2 – Observable inputs other than Level 1 prices, such as quoted prices for similar assets or liabilities; quoted prices in markets that are not active; or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities.

Level 3 – Unobservable inputs that are supported by little or no market activity and that are significant.

Determination of Fair Value

As required by SFAS 157, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Risk management assets and liabilities in the recurring fair value measures table below include over-the-counter forwards, swaps and options. Total risk management assets below do not include option premiums which are not considered a derivative asset. Option premiums upon settlement are recorded in fuel and purchased power expense and are subsequently requested for recovery through the deferred energy mechanism. Option premium amounts included in risk management asserts at December 31, 2008 for NVE, NPC and SPPC were $18.9 million ($13.3 million current, $5.6 million non-current), $13.9 million ($9.7 million current, $4.2 million non-current) and $5.0 million ($3.6 million current, $1.4 million non-current), respectively. At December 31, 2007, option premium amounts for NVE, NPC and SPPC were $13.9 million ($11.2 million current, $2.7 million non-current), $10.2 million ($7.8 million current, $2.4 million non-current) and $3.7 million ($3.4 millon current, $.3 million non-current), respectively.

Forwards and swaps are valued using a market approach that uses quoted forward commodity prices for similar assets and liabilities, which incorporates a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical expedient for valuing its assets and liabilities measured and reported at fair value. Options are valued based on an income approach that uses an option pricing model that includes various inputs; such as forward commodity prices, interest rate yield curves and option volatility rates. The determination of the fair value for its derivative instruments not only include counterparty risk, but also incorporate the impact of NVE and the Utilities nonperformance risk on its liabilities. Nonperformance risk is based on the credit quality of NVE and the Utilities and had no impact to the fair value of its derivative instruments.

The following table shows the fair value of the open derivative positions recorded on the Consolidated Balance Sheets of NVE, NPC and SPPC and the related regulatory assets/liabilities that did not meet the normal purchase and normal sales exception criteria in SFAS 133. Due to deferred energy accounting treatment under which the Utilities’ operate, regulatory assets and liabilities are established to the extent that electricity and natural gas derivative gains and losses are recoverable or payable through future rates, once realized. This accounting treatment is intended to defer the recognition of mark-to-market gains and losses on energy commodity transactions until the period of settlement and to not recognize gains and losses on the Consolidated Statements of Income (dollars in millions):

	December 31, 2008 Fair Value (1) Level 2 (dollars in millions)									December 31, 2007 Fair Value (dollars in millions)
	NVE			NPC			SPPC			NVE			NPC			SPPC

Risk management assets- current	$	2.8		$	2.0		$	.8		$	11.1		$	8.3		$	2.8
Risk management assets- noncurrent		4.4			3.2			1.2			9.8			6.7			3.1
Total risk management assets		7.2			5.2			2.0			20.9			15.0			5.9

Risk management liabilities- current		313.8			222.9			90.9			39.5			27.0			12.5
Risk management liabilities- noncurrent		53.4			35.2			18.2			7.4			5.1			2.3
Total risk management liabilities		367.2			258.1			109.1			46.9			32.1			14.8

Risk management regulatory assets/liabilities – net (2)	$	(360.0	)	$	(252.9	)	$	(107.1	)	$	(26.0	)	$	(17.1	)	$	(8.9	)

(1)	SFAS 157 only applies to the asset and liability positions in 2008.

(2)	When amount is negative it represents a Risk Management Regulatory Asset (loss), when positive it represents a Risk Management Regulatory Liability (gain).

As a result of the nature of operations and the use of mark-to-market accounting for certain derivatives that do not meet the normal purchase and normal sales exception criteria, mark-to-market fair values will fluctuate. The Utilities’ cannot predict these fluctuations, but the primary factors that cause changes in the fair values are the number and size of the Utilities’ open derivative positions with their counterparties and the changes in forward commodity prices. The increase in risk management liabilities as of December 31, 2008, as compared to December 31, 2007, is mainly due to unfavorable open derivative positions on natural gas options held by the Utilities’ to hedge energy price risk for their customers resulting from lower commodity prices for natural gas at December 31, 2008 relative to contract prices.

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NOTE 10. INCOME TAXES (BENEFITS)

NV Energy, Inc.

The following reflects the composition of taxes on income from continuing operations (dollars in thousands):

	2008			2007			2006
Provision for income taxes
Current and other
Federal	$	44,647		$	10,503		$	5,914
State		12			70			-
Total current and other		44,659			10,573			5,914

Deferred
Federal		54,341			85,165			144,919
State		693			366			494
Total deferred		55,034			85,531			145,413

Amortization of excess deferred taxes		(1,365	)		(2,226	)		(2,315	)

Amortization of investment tax credits		(2,974	)		(6,323	)		(3,407	)

Total provision for income taxes	$	95,354		$	87,555		$	145,605

Income statement classification of provision (benefit) for income taxes
Operating income		76,751			75,155			91,571
Other income		18,603			12,400			54,034
Total	$	95,354		$	87,555		$	145,605

The total income tax provision differs from amounts computed by applying the federal statutory tax rate to income before income taxes for the following reasons (dollars in thousands):

	2008			2007			2006

Net Income applicable to common stock	$	208,887		$	197,295		$	277,451
Preferred stock dividend requirement					-			2,341
Subtotal		208,887			197,295			279,792
Total income tax expense		95,354			87,555			145,605
Pretax income		304,241			284,850			425,397
Statutory tax rate		35	%		35	%		35	%
Federal income tax expense at statutory rate		106,484			99,698			148,889
Depreciation related to difference in costs basis for tax purposes		1,132			2,970			4,709
AFUDC - equity		(13,454	)		(11,133	)		(6,379	)
Investment tax credit amortization		(2,973	)		(6,322	)		(3,407	)
Regulatory asset for goodwill		2,742			2,742			2,600
Research and development credit		(1,310	)		(1,130	)		(3,764	)
Other – net		2,733			730			2,957
Provision for income taxes	$	95,354		$	87,555		$	145,605

Effective tax rate		31.3	%		30.7	%		34.2	%

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The net deferred income tax liability consists of deferred income tax liabilities less related deferred income tax assets, as shown (dollars in thousands):

	2008			2007
Deferred income tax assets
Credit carryovers and net operating loss	$	34,839		$	52,925
Employee benefit plans		107,622			25,587
Customer advances		30,851			35,044
Gross-ups received on contribution in aid of construction and customer advances		30,870			31,060
Deferred revenues		5,440			4,069
Reserves		15,419			13,743
Other		30,473			22,232
Subtotal		255,514			184,660
Deferred income tax assets associated with regulatory matters
Excess deferred income taxes		11,521			12,886
Unamortized investment tax credit		13,958			15,559
Subtotal		25,479			28,445
Total deferred income tax assets before valuation allowance		280,993			213,105
Valuation allowance		(1,160	)		(588	)
Total deferred income tax assets after valuation allowance	$	279,833		$	212,517

Deferred income tax liabilities
Excess of tax depreciation over book depreciation	$	530,048		$	509,161
Deferred energy		89,182			88,213
Regulatory assets		183,622			86,517
Other		82,687			70,113
Subtotal		885,539			754,004
Deferred income tax liabilities associated with regulatory matters
Tax benefits flowed through to customers		264,779			267,848
Total deferred income tax liability	$	1,150,318		$	1,021,852

Net deferred income tax liability	$	631,185		$	569,932
Net deferred income tax liability associated with regulatory matters		239,300			239,403
Total net deferred income tax liability	$	870,485		$	809,335

NVE’s balance sheets contain a net regulatory tax asset of $239.3 million at December 31, 2008 and $239.4 million at December 31, 2007. For balance sheet presentation, the regulatory tax asset is included in regulatory assets. The regulatory tax asset balance consists of future revenue to be received from customers due to flow-through of the tax benefits of temporary differences and goodwill recognized from the merger of NPC and NVE. Offset against these amounts are future revenues to be refunded to customers (regulatory tax liabilities). For balance sheet presentation, the regulatory tax liability is included in regulatory liabilities. The regulatory tax liability balance consists of temporary differences for liberalized depreciation at rates in excess of current rates and unamortized investment tax credits. The regulatory liability for temporary differences related to liberalized depreciation will continue to be amortized using the average rate assumption method required by the Tax Reform Act of 1986. The regulatory liability for temporary differences caused by the investment tax credit will be amortized ratably in the same fashion as the accumulated deferred investment credit.

The following table summarizes NVE’s net regulatory tax asset and liability (dollars in thousands):

	2008		2007
Tax benefits flowed through to customers
Related to property	$	116,167	$	115,045
Related to goodwill		148,612		152,803
Regulatory tax asset		264,779		267,848

Liberalized depreciation at rates in excess of current rates		11,521		12,886
Unamortized investment tax credits		13,958		15,559
Regulatory tax liability		25,479		28,445
Net regulatory tax asset	$	239,300	$	239,403

NVE and its subsidiaries file a consolidated federal income tax return. Current income taxes are allocated based on NVE’s and each subsidiaries’ respective taxable income or loss and tax credits as if each subsidiary filed a separate return.

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The following table summarizes as of December 31, 2008 the tax credit carryovers and associated carryover periods, and valuation allowance for amounts which NVE has determined that realization is uncertain (dollars in thousands):


	Deferred Tax Asset		Valuation Allowance		Net Deferred Tax Asset		Expiration Period
Research and development credit		8,883				8,883		2021-2028
Alternative minimum tax credit		24,572		-		24,572	indefinite
Arizona coal credits		1,384		1,160		224		2009-2013
Total	$	34,839	$	1,160	$	33,679

In accordance with the recognition and measurement standards promulgated by FIN 48, NVE derecognized certain tax benefits during the year. Thus, there is no deferred tax balance for the net operating loss of $99,667, which is reflected in the federal tax return. The net operating loss reflected in the federal tax return will expire from 2021-2024.

Considering all positive and negative evidence regarding the utilization of NVE’s deferred tax assets, it has been determined that NVE is more-likely-than-not to realize all recorded deferred tax assets, except the Arizona coal credits. As such, these Arizona coal credits represent the only valuation allowance that has been recorded as of December 31, 2008.

NVE and the Utilities adopted the provisions of FIN 48 as of January 1, 2007. FIN 48 liabilities are all long term and are included in the other liabilities line item on the balance sheet. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows (dollars in thousands):

	2008			2007

Balance at January 1	$	25,016		$	27,766
Additions based on tax positions related to the current year		8,855			9,487
Additions for tax positions of prior years		65,426			5,052
Reductions for tax positions of prior years		(5,369	)		(17,289	)
Balance at December 31	$	93,928		$	25,016

On or about December 31, 2007, NVE and the Utilities filed a Form 3115, Application for Change in Accounting Method (“Application”), with the IRS requesting a change in accounting for deducting repair expenditures. NVE reflected the tax benefits sought on the Application on its 2007 tax return, which was filed during 2008, thus yielding an increase in uncertain tax benefits related to prior periods. NVE has yet to receive IRS consent to make the method change. Since this type of voluntary method change requires IRS consent and the IRS has considerable discretion in granting such consent, NVE will only reflect the method change in its financial statements once IRS consent is granted.

NVE and the Utilities classify interest and penalties related to income taxes as interest and other expense, respectively. The total amount of unrecognized tax benefits as of December 31, 2008 and December 31, 2007 is $93.9 million and $25.0 million, respectively, of which $3.2 million and $2.4 million, respectively, would affect the effective tax rate if recognized. No interest or penalties have been accrued as of December 31, 2008 and 2007. The Utilities expect certain unrecognized tax benefits to statutorily expire within the next twelve months and it is reasonably possible that approval of the Application from the IRS will be received. This would cause a significant decrease in the FIN 48 liability in the range of $7.2 million to $78.7 million within the coming year. As of December 31, 2007, the Utilities believed that no significant increases or decreases to unrecognized tax benefits would have occurred during the year ended December 31, 2008. During the year ended December 31, 2008, unrecognized tax benefits, primarily related to the Application, increased by $68.9 million as illustrated in the table above.

NVE and the Utilities file a consolidated U.S. federal income tax return. The U.S. federal jurisdiction is the only “significant” tax jurisdiction for NVE. The statue of limitations for tax years 2005, 2006 and 2007 expires on September 15, 2009, 2010, and 2011, respectively. All earlier years are closed by statute. Tax year 2004 was open as of December 31, 2008.

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Nevada Power Company

The following reflects the composition of taxes on income (dollars in thousands):

	2008			2007			2006
Provision for income taxes
Current and other
Federal	$	27,038		$	25,351		$	4,865
State		-			-			-
Total current and other		27,038			25,351			4,865

Deferred
Federal		45,830			58,344			114,741
State		378			(63	)		268
Total deferred, net		46,208			58,281			115,009

Amortization of excess deferred taxes		(695	)		(1,236	)		(745	)

Amortization of investment tax credits		(1,169	)		(4,044	)		(1,619	)

Total provision for income taxes	$	71,382		$	78,352		$	117,510

Income statement classification of provision for income taxes
Operating income	$	58,014		$	61,108		$	91,781
Other income		13,368			17,244			25,729
Total	$	71,382		$	78,352		$	117,510

The total income tax provision differs from amounts computed by applying the federal statutory tax rate to income before income taxes for the following reasons (dollars in thousands):

	2008			2007			2006

Net income	$	151,431		$	165,694		$	224,540
Total income tax expense		71,382			78,352			117,510
Pretax income		222,813			244,046			342,050
Statutory tax rate		35	%		35	%		35	%
Federal income tax expense at statutory rate		77,985			85,416			119,718
Depreciation related to difference in cost basis for tax purposes		1,209			1,291			2,192
AFUDC - equity		(9,071	)		(5,551	)		(4,114	)
Investment tax credit amortization		(1,169	)		(4,044	)		(1,619	)
Regulatory asset for goodwill		1,732			1,732			1,646
Research and development credit		(1,078	)		(527	)		(1,666	)
Other - net		1,774			35			1,353
Provision for income taxes	$	71,382		$	78,352		$	117,510

Effective tax rate		32.0	%		32.1	%		34.4	%

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The net deferred income tax liability consists of deferred income tax liabilities less related deferred income tax assets, as shown (dollars in thousands):

	2008			2007
Deferred income tax assets
Credit carryovers and net operating loss	$	1,384		$	26,341
Employee benefit plans		45,127			13,940
Customer advances		16,019			20,611
Gross-ups received on CIAC and customer advances		21,934			21,334
Deferred revenues		3,549			1,948
Reserves		12,670			10,633
Other - net		21,135			12,928
Subtotal		121,818			107,735
Deferred income tax assets associated with regulatory matters
Excess deferred income taxes		3,328			4,024
Unamortized investment tax credit		5,385			6,014
Subtotal		8,713			10,038
Total deferred income tax assets before valuation allowance		130,531			117,773
Valuation allowance		(1,160	)		(588	)
Total deferred income tax assets after valuation allowance	$	129,371		$	117,185

Deferred income tax liabilities
Excess of tax depreciation over book depreciation	$	333,888		$	319,926
Deferred energy		98,512			98,342
Regulatory assets		97,932			65,038
Other - net		62,374			51,407
Subtotal		592,706			534,713
Deferred income tax liabilities associated with regulatory matters
Tax benefits flowed through to customers		169,506			165,257
Total deferred income tax liability	$	762,212		$	699,970

Net deferred income tax liability	$	472,048		$	427,566
Net deferred income tax liability associated with regulatory matters		160,793			155,219
Total net deferred income tax liability	$	632,841		$	582,785

NPC’s balance sheet contains a net regulatory asset of $160.8 million at December 31, 2008 and $155.2 million at December 31, 2007. For balance sheet presentation, the regulatory tax asset is included in regulatory assets. The regulatory tax asset balance consists of future revenue to be received from customers due to flow-through of the tax benefits of temporary differences and goodwill recognized from the merger of NPC and NVE. Offset against these amounts are future revenues to be refunded to customers (regulatory tax liabilities). For balance sheet presentation, the regulatory tax liability is included in regulatory liabilities. The regulatory tax liability balance consists of temporary differences for liberalized depreciation at rates in excess of current rates and unamortized investment tax credits. The regulatory liability for temporary differences related to liberalized depreciation will continue to be amortized using the average rate assumption method required by the Tax Reform Act of 1986. The regulatory liability for temporary differences caused by the investment tax credit will be amortized ratably in the same fashion as the accumulated deferred investment credit.

The following table summarizes NPC’s net regulatory tax asset and liability (dollars in thousands):

	2008		2007
Tax benefits flowed through to customers
Related to property	$	76,489	$	69,602
Related to goodwill		93,017		95,655
Regulatory tax asset		169,506		165,257

Liberalized depreciation at rates in excess of current rates		3,328		4.024
Unamortized investment tax credits		5,385		6,014
Regulatory tax liability		8,713		10,038
Net regulatory tax asset	$	160,793	$	155,219

Current income taxes are allocated based on NVE’s and each subsidiaries’ respective taxable income or loss and tax credits as if each subsidiary filed a separate return.

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The following table summarizes as of December 31, 2008 tax credit carryovers and associated carryover periods, as adjusted for FIN 48, and valuation allowance for amounts which NPC has determined that realization is uncertain (dollars in thousands):


Type of Carryforward	Deferred Tax Asset		Valuation Allowance		Net Deferred Tax Asset		Expiration Period
Arizona coal credits	$	1,384	$	1,160	$	224		2009-2013
Total	$	1,384	$	1,160	$	224

Considering all positive and negative evidence regarding the utilization of NPC’s deferred tax assets, it has been determined that NPC is more-likely-than-not to realize all recorded deferred tax assets, except for a portion of the Arizona coal credits. As such, these Arizona coal credits represent the only valuation allowance that has been recorded as of December 31, 2008.

	2008			2007

Balance at January 1	$	20,129		$	6,784
Additions based on tax positions related to the current year		3,549			8,918
Additions for tax positions of prior years		34,353			4,989
Reductions for tax positions of prior years		(9,544	)		(562	)
Balance at December 31	$	48,487		$	20,129

NVE and the Utilities classify interest and penalties related to income taxes as interest and other expense, respectively. The total amount of unrecognized tax benefits for NPC as of December 31, 2008 and December 31, 2007 is $48.5 million and $20.1 million, respectively, of which $2.0 million and $0.9 million, respectively, would affect the effective tax rate if recognized. No interest or penalties have been accrued as of December 31, 2008 and December 31, 2007. The Utilities expect certain unrecognized tax benefits to statutorily expire within the next twelve months and it is reasonably possible that approval of the Application from the IRS will be received. This would cause a significant decrease in the FIN 48 liability in the range of $3.6 million to $39.3 million within the coming year. As of December 31, 2007, the Utilities believed that no significant increases or decreases to unrecognized tax benefits would have occurred during the year ended December 31, 2008. During the year ended December 31, 2008, unrecognized tax benefits, primarily related to the Application, increased by $28.4 million as illustrated in the table above.

NVE and the Utilities file a consolidated U.S. federal income tax return. The U.S. federal jurisdiction is the only “significant” tax jurisdiction for NVE. The statute of limitations for tax years 2005, 2006, 2007 expires on September 15, 2009, 2010, and 2011, respectively. All earlier years are closed by statute. Tax year 2004 was open as of December 31, 2008.

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Sierra Pacific Power Company

The following reflects the composition of taxes on income (dollars in thousands):

		2008			2007			2006
Provision for income taxes
	Current and other
	Federal	$	13,663		$	57,483		$	28,497
	State		12			70			-
	Total current and other		13,675			57,553			28,497

	Deferred
	Federal		26,087			(28,705	)		2,464
	State		315			429			226
	Total deferred		26,402			(28,276	)		2,690

	Amortization of excess deferred taxes		(670	)		(990	)		(1,570	)

	Amortization of investment tax credits		(1,804	)		(2,278	)		(1,788	)

Total provision for income taxes		$	37,603		$	26,009		$	27,829

Income statement classification of provision (benefit) for income taxes
	Operating income	$	31,806		$	29,991		$	23,570
	Other income		5,797			(3,982	)		4,259
Total		$	37,603		$	26,009		$	27,829

The total income tax provision differs from amounts computed by applying the federal statutory tax rate to income before income taxes for the following reasons (dollars in thousands):

	2008			2007			2006

Income from continuing operations	$	90,582		$	65,667		$	57,709
Total income tax expense		37,603			26,009			27,829
Pretax income		128,185			91,676			85,538
Statutory tax rate		35	%		35	%		35	%
Federal income tax expense (benefit) at statutory rate		44,865			32,087			29,938
Depreciation related to difference in cost basis for tax purposes		(77	)		1,679			2,517
AFUDC - equity		(4,383	)		(5,582	)		(2,265	)
Investment tax credit amortization		(1,804	)		(2,278	)		(1,788	)
Regulatory asset for goodwill		1,009			1,009			954
Research and development credit		(232	)		(603	)		(2,097	)
Other - net		(1,775	)		(303	)		570
Provision for income taxes	$	37,603		$	26,009		$	27,829
Effective tax rate		29.3	%		28.4	%		32.5	%

As a large corporate taxpayer, the NVE consolidated group’s tax returns are examined by the IRS on a regular basis. SPPC believes that it has adequately provided reasonable reserves for reasonable and foreseeable outcomes related to uncertain tax matters.

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The net deferred income tax liability consists of deferred income tax liabilities less related deferred income tax assets, as shown (dollars in thousands):

	2008		2007
Deferred income tax assets
Credit carryforwards and net operating loss	$	-	$	5,311
Employee benefit plans		59,083		8,327
Customer advances		14,831		14,432
Gross-ups received on CIAC and customer advances		8,936		9,726
Deferred revenues		1,891		2,121
Deferred energy		9,330		10,130
Reserves		2,542		2,903
Other		6,463		9,034
Subtotal		103,076		61,984
Deferred income tax assets associated with regulatory matters
Excess deferred income taxes		8,193		8,862
Unamortized investment tax credit		8,573		9,545
Subtotal		16,766		18,407
Total deferred income tax assets	$	119,842	$	80,391

Deferred income tax liabilities
Excess of tax depreciation over book depreciation	$	196,161	$	189,234
Regulatory assets		83,608		20,446
Other		19,798		18,192
Subtotal deferred tax liabilities		299,567		227,872
Deferred income tax liabilities associated with regulatory matters
Tax benefits flowed through to customers		95,273		102,591
Total deferred income tax liability	$	394,840	$	330,463

Net deferred income tax liability	$	196,491	$	165,889
Net deferred income tax liability associated with regulatory matters		78,507		84,184
Total net deferred income tax liability	$	274,998	$	250,073

SPPC’s balance sheet contains a net regulatory asset of $78.5 million at December 31, 2008 and $84.2 million at December 31, 2007. For balance sheet presentation, the regulatory tax asset is included in regulatory assets. The regulatory tax asset consists of future revenue to be received from customers due to flow-through of the tax benefits of temporary differences and goodwill recognized from the merger of NPC and NVE. Offset against these amounts are future revenues to be refunded to customers (regulatory liabilities). For balance sheet presentation, the regulatory tax liability is included in regulatory liabilities. The regulatory tax liabilities consist of temporary differences for liberalized depreciation at rates in excess of current rates and unamortized investment tax credits. The regulatory liability for temporary differences related to liberalized depreciation will continue to be amortized using the average rate assumption method required by the Tax Reform Act of 1986. The regulatory liability for temporary differences caused by the investment tax credit will be amortized ratably in the same fashion as the accumulated deferred investment credit.

The following table summarizes SPPC’s net regulatory tax asset and liability (dollars in thousands):

	2008		2007
Tax benefits flowed through to customers
Related to property	$	39,678	$	45,443
Related to goodwill		55,595		57,148
Regulatory tax asset		95,273		102,591

Liberalized depreciation at rates in excess of current rates		8,193		8,862
Unamortized investment tax credits		8,573		9,545
Regulatory tax liability		16,766		18,407
Net regulatory tax asset	$	78,507	$	84,184

Considering all positive and negative evidence regarding the utilization of SPPC’s deferred tax assets, it has been determined that the company is more-likely-than-not to realize all recorded deferred tax assets and therefore no valuation allowance has been recorded as of December 31, 2008.

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	2008			2007

Balance at January 1	$	4,430		$	4,403
Additions based on tax positions related to the current year		4,536			569
Additions for tax positions of prior years		31,709			-
Reductions for tax positions of prior years		(549	)		(542	)
Balance at December 31	$	40,126		$	4,430

NVE and the Utilities classify interest and penalties related to income taxes as interest and other expense, respectively. The total amount of unrecognized tax benefits for SPPC as of December 31, 2008 and December 31, 2007 is $40.1 million and $4.4 million, respectively, of which $1.2 million and $1.1 million, respectively, would affect the effective tax rate if recognized. No interest or penalties have been accrued as of December 31, 2008 and December 31, 2007. The Utilities expect certain unrecognized tax benefits to statutorily expire within the next twelve months and it is reasonably possible that approval of the Application from the IRS will be received. This would cause a significant decrease in the FIN 48 liability in the range of $3.6 million to $39.3 million within the coming year. As of December 31, 2007, the Utilities believed that no significant increases or decreases to unrecognized tax benefits would have occurred during the year ended December 31, 2008. During the year ended December 31, 2008, unrecognized tax benefits, primarily related to the Application, increased by $35.7 million as illustrated in the table above.

NVE and the Utilities file a consolidated U.S. federal income tax return. The U.S. federal jurisdiction is the only “significant” tax jurisdiction for NVE. The statue of limitations for tax years 2005, 2006, and 2007 expires on September 15, 2009, 2010, and 2011, respectively. All earlier years are closed by statute. Tax year 2004 was open as of December 31, 2008.

NOTE 11. RETIREMENT PLAN AND POST-RETIREMENT BENEFITS

NVE has a defined benefit pension plan covering substantially all employees. Certain grandfathered and certain union employees are covered under a benefit formula based on years of service and the employee's highest compensation for a period prior to retirement, while most employees are covered under a cash balance formula. NVE also has other postretirement plans which provide medical and life insurance benefits for certain retired employees.

Plan Changes

Also, in 2007 NVE completed negotiations with SPPC’s IBEW Local No. 1245 employees, and reached a settlement with regards to postretirement medical coverage. This agreement resulted in changes to NVE’s future obligations under this plan, and as a result of a re-measurement of the plan obligation, NVE’s 2007 expense was reduced by $1.3 million. There were no changes made to other postretirement benefit plan provisions in 2006 which had any significant impact on recorded benefit plan amounts in that year.

Under the terms of NPC’s current contract with IBEW Local No. 396, the pension benefits for those employees covered under that agreement have also changed from a defined benefit plan to a cash balance plan, effective December 31, 2008. However, the impact of this change has been offset by current market conditions and plan asset values. During 2007 and 2006 NVE did not make significant changes to its pension plan provisions

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Reconciliation of benefit obligations, plan assets and the funded status of the plans

In 2008, in accordance with SFAS 158, NVE, NPC and SPPC recorded additional pension costs relating to the elimination of the early measurement date, as discussed in SFAS 158 to retained earnings, of $5.3 million, $3.6 million and $1.4 million, respectively, before taxes. Additionally, in 2008 in accordance with SFAS 158, NVE, NPC and SPPC recorded additional post retirement benefit costs relating to the elimination of the early measurement date , as discussed in SFAS 158 to retained earnings, of $1.9 million, $0.7 million and $1.1million, respectively, before taxes. These amounts represent the expense attributable to the three-month period from September 30, 2007 to December 31, 2007. NVE has changed the measurement date for its benefit plans from September 30 to December 31, which coincides with NVE’s fiscal year end. The following tables provide a reconciliation of benefit obligations, plan assets and the funded status of the plans. These reconciliations are based on a December 31 measurement date for 2008, and a September 30 measurement date for 2007 (dollars in thousands):

							Other Postretirement
	Pension Benefits						Benefits
	2008			2007			2008			2007
Change in benefit obligations
Benefit obligation, beginning of year	$	674,687		$	645,373		$	150,175		$	172,192
Effect of eliminating early measurement Date		10,708			-			2,438			-
Service cost		21,748			22,901			2,562			2,680
Interest cost		42,818			39,420			10,732			10,088
Plan participants' contributions		-			-			1,475			2,044
Actuarial loss (gain)		38,174			(8,414	)		(7,567	)		6,382
Gross benefits paid		(31,944	)		(31,949	)		(11,838	)		(10,031	)
less: federal subsidy on benefits paid		-			-			-			596
Administrative expenses		(455	)		(328	)		-			-
Plan amendments		(28,264	)		-			4,562			(28,804	)
Plan amendments - IBEW Local No. 1245 buy down		-			-			-			(12,600	)
Change in estimates		-			-			23,520			-
Utility discount adjustment		-			-			-			6,545
Death benefit obligation adjustment		-			-			-			1,083
Settlements		-			7,684			-			-
Benefit obligation, end of year	$	727,472		$	674,687		$	176,059		$	150,175

The accumulated benefit obligation for Pension Benefits at the end of 2008 and 2007 was $659 million and $545 million respectively.

The actuarial assumptions used to determine end of year benefit obligations were as follows:

							Other Postretirement
	Pension Benefits						Benefits
	2008			2007			2008			2007
Discount rate		6.09	%		6.30	%		6.07	%		6.25	%
Rate of compensation increase		4.50	%		4.50	%		-			-

In 2008, for measurement purposes, the assumed annual rate of increase in the per capita cost of covered health care benefits was 8.5%, grading down to 5% in 2014.

In selecting an assumed discount rate for fiscal year 2008 pension cost and for fiscal year-end 2008 disclosures, NVE’s projected benefit payments were matched to the yield curve derived from a portfolio of over 300 high quality Aa bonds with yields within the 10th to 90th percentiles of these bond yields.

Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effect:

Effect on the postretirement benefit obligation	2008			2007
Effect of a 1-percentage point increase	$	14,407		$	9,860
Effect of a 1-percentage point decrease	$	(12,333	)	$	(8,538	)

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The following table shows the change in plan assets for 2008 and 2007. Employer contributions reflect funding and benefit payments made by NVE (dollars in thousands):

							Other Postretirement
	Pension Benefits						Benefits
	2008			2007			2008			2007
Change in plan assets
Fair value of plan assets, beginning of year	$	639,996		$	534,260		$	108,921		$	63,236
Effect of eliminating early measurement date		6,893			-			1,202			-
Actual return on plan assets		(181,760	)		73,483			(23,280	)		7,613
Employer contributions		94,143			64,529			8,181			46,059
Plan participants' contributions		-			-			1,475			2,044
Gross benefits paid		(27,444	)		(31,949	)		(11,838	)		(10,031	)
Expenses paid		(455	)		(327	)		-			-
Fair value of plan assets, end of year	$	531,373		$	639,996		$	84,661		$	108,921

	Allocation Percentage of Plan Assets at Year End
Asset Category	2009			2008			2007

Equity securities		45	%		46	%		60	%
Debt securities		50	%		41	%		40	%
Cash/other		5	%		13	%		-
Total		100	%		100	%		100	%

	Allocation Percentage of Plan Assets at Year End
Asset Category	2009			2008			2007

Equity securities		45	%		29	%		60	%
Debt securities		50	%		35	%		40	%
Cash/other		5	%		36	%		-
Total		100	%		100	%		100	%

NVE’s investment strategy is to ensure the safety of the principal of the assets and obtain asset performance to meet the continuing obligations of the plan. NVE contributed a total of $100 million in 2008; $30 million was funded across the pension and other postretirement benefit plans in September, and $70 million was funded to the pension plan in December. The $70 million contribution on December 30, 2008 was temporarily invested into cash until a new asset allocation plan is approved by the NVE Pension Committee.

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The following table shows the funded status of each of the plans for 2008 and 2007 (dollars in thousands):

							Other Postretirement
	Pension Benefits						Benefits
Funded Status, end of year:	2008			2007			2008			2007
Fair value of plan assets	$	531,373		$	639,996		$	84,660		$	108,921
Benefit obligations		(727,472	)		(674,687	)		(176,059	)		(150,175	)
Funded status	$	(196,099	)	$	(34,691	)	$	(91,399	)	$	(41,254	)

Amounts for pension and postretirement benefits recognized in the consolidated balance sheets consist of the following (dollars in thousands):

							Other Postretirement
	Pension Benefits						Benefits
Amounts recognized in the statement of financial position consist of:	2008			2007			2008			2007
Current liability	$	(1,561	)	$	(6,381	)	$	-		$	-
Noncurrent liability		(194,537	)		(27,973	)		(91,399	)		(41,254	)
Net amount recognized	$	(196,098	)	$	(34,354	)	$	(91,399	)	$	(41,254	)

The following amounts would have been recognized in Accumulated Other Comprehensive Income, net of taxes, according to the provisions of SFAS 158, which NVE adopted in 2006. Since NVE is able to recover SFAS 87 and SFAS 106 expenses through rates, the amounts will be recorded as Other Regulatory Assets under the provisions of SFAS 71 (dollars in thousands).

						Other Postretirement
	Pension Benefits					Benefits
Amounts recognized as other regulatory assets:	2008			2007		2008			2007
Net actuarial (gain)/loss	$	355,553		$	95,800	$	80,836		$	61,136
Prior service (credit)/cost		(16,965	)		10,958		(5,880	)		(33,910	)
	$	338,588		$	106,758	$	74,956		$	27,226

The estimated amounts that will be amortized from other regulatory assets and accumulated other comprehensive income into net periodic cost in 2009 are as follows (dollars in thousands):

	Pension Benefits			Other Postretirement Benefits
Actuarial (gain)/loss	$	27,575		$	5,126
Prior service (credit)/cost		(1,669	)		(685	)

At the end of 2008 and 2007, the projected benefit obligation, accumulated benefit obligation, and fair value of plan assets for pension plans with a projected benefit obligation in excess of plan assets, and pension plans with an accumulated benefit obligation in excess of plan assets, were as follows (dollars in thousands):

	Benefit Obligation Exceeds				Accumulated Benefit Obligation Exceeds
	the Fair Value of Plan's Assets				the Fair Value of Plan's Assets
	2008		2007		2008		2007
Projected benefit obligation, end of year	$	727,472	$	674,687	$	-	$	-
Accumulated benefit obligation, end of year		-		-		659,404		18,583
Fair value of plan assets, end of year		531,373		639,996		531,373		-

At the end of 2007, using the projected benefit obligation measure, all pension plans, defined benefit and nonqualified, were underfunded; only the nonqualified pension plans were underfunded using the accumulated benefit obligation measure for 2007. At the end of 2008, all pension plans were underfunded for both measurements. The accumulated postretirement benefit obligation exceeds plan assets for all of the company’s other postretirement benefit plans.

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The expected cash flows for the plans, including trust accounts, are as follows (dollars in thousands):

			Other
			Postretirement
Company contributions	Pension Benefits		Benefits
2009 (expected)	$	51,561	$	20,282

Expected benefit payments (gross)
2009		42,630		9,288
2010		44,650		10,000
2011		46,483		10,627
2012		49,291		11,132
2013		50,061		11,577
2014-2018		277,769		64,939

The above benefit payments are obligations of the indicated plan, and reflect payments which do not include employee contributions. The expected benefit payment information that reflects the employee obligation is almost exclusively paid from plan assets. A small portion of the pension benefit obligation is paid from the plan sponsor’s assets.

The components of net periodic pension and other postretirement benefit costs for NVE, NPC and SPPC are presented below (dollars in thousands):

NVE
				Pension Benefits						Other Postretirement Benefits
	2008			2007			2006			2008			2007			2006

Service cost	$	21,748		$	22,901		$	23,033		$	2,562		$	2,680		$	3,533
Interest cost		42,818			39,420			36,627			10,732			10,088			10,283
Expected return on plan assets		(47,051	)		(41,895	)		(40,729	)		(8,351	)		(5,182	)		(4,919	)
Amortization of:
Actuarial (gain)/loss		6,714			7,211			9,778			3,489			3,413			4,614
Prior service (credit)/cost		(166	)		1,629			1,892			(1,028	)		(225	)		122
Transition (asset)/obligation		-			-			-			-			484			969
Settlement (gain)/loss		-			4,441			-			338			-			-
Total net benefit cost	$	24,063		$	33,707		$	30,601		$	7,742		$	11,258		$	14,602

The average percentage of NVE net periodic costs capitalized during 2008, 2007 and 2006 was 37.1%, 34.7% and 35.5%, respectively.

Nevada Power Company
				Pension Benefits						Other Postretirement Benefits
	2008			2007			2006			2008			2007			2006

Service cost	$	12,798		$	13,092		$	12,900		$	1,217		$	1,079		$	1,052
Interest cost		21,240			18,977			17,466			2,524			2,178			2,105
Expected return on plan assets		(22,554	)		(19,000	)		(18,265	)		(2,702	)		(1,232	)		(1,079	)
Amortization of:
Actuarial (gain)/loss		3,321			-			-			808			729			940
Prior service (credit)/cost		57			1,430			1,677			1,157			606			122
Transition (asset)/obligation		-			3,429			4,636			-			485			969
Total net benefit cost	$	14,862		$	17,928		$	18,414		$	3,004		$	3,845		$	4,109

The average percentage of NPC net periodic costs capitalized during 2008, 2007 and 2006 was 40.5%, 38.8% and 39.0%, respectively.

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Sierra Pacific Power Company
				Pension Benefits						Other Postretirement Benefits
	2008			2007			2006			2008			2007			2006

Service cost	$	7,998		$	8,553		$	8,989		$	1,275		$	1,542		$	2,417
Interest cost		20,248			19,100			18,224			8,054			7,844			8,114
Expected return on plan assets		(23,270	)		(21,969	)		(21,617	)		(5,512	)		(3,823	)		(3,715	)
Amortization of:
Actuarial (gain)/loss		3,085			-			-			2,633			2,663			3,646
Prior service (credit)/cost		(137	)		212			212			(2,201	)		(831	)		-
Transition (asset)/obligation		-			3,467			4,880			-			-			-
Total net benefit cost	$	7,924		$	9,363		$	10,688		$	4,249		$	7,395		$	10,462

The average percentage of SPPC net periodic costs capitalized during 2008, 2007 and 2006 was 36.5%, 35.7% and 33.3%, respectively.

The weighted-average assumptions used to determine net periodic cost are as follows:

										Other Postretirement
	Pension Benefits									Benefits
	2008			2007			2006			2008			2007			2006
Discount rate		6.38	%		6.00	%		5.75	%		6.25	%		6.00	%		5.75	%
Expected ROR on Plan Assets		8.00	%		8.00	%		8.25	%		8.00	%		8.00	%		8.25	%
Rate of compensation increase		4.50	%		4.50	%		4.50	%		N/A			N/A			N/A

For measurement purposes, an 8% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2008. The rate was assumed to average to 5% in all future years.

The expected ROR on plan assets was determined by considering a realistic projection of what assets can earn, given existing capital market conditions, historical equity and bond premiums over inflation, the effect of “normative” economic conditions that may differ from existing conditions, and projected ROR on reinvested assets.

The assumed health care cost trend rate has a significant effect on the amounts reported. A one percentage point change in the assumed health care cost trend rate would have had the following effect:

One percentage point change:	2008			2007			2006
Effect on total of service and interest cost components:
Effect of a 1-percentage point increase in health care trend		1,130			1,476			1,669
Effects of a 1-percentage point decrease in health care trend		(947	)		(1,210	)		(1,360	)

There were no significant transactions between the plan and the employer or related parties during 2008, 2007, or 2006.

NOTE 12. STOCK COMPENSATION PLANS

At December 31, 2008, NVE had several stock-based compensation plans, which are described below.

NVE’s executive long-term incentive plan for key management employees, which was approved by shareholders in May 2004, provides for the issuance of up to 7,750,000 of NVE’s common shares to key employees through December 31, 2013. The plan permits the following types of grants, separately or in combination: nonqualified and qualified stock options, stock appreciation rights, restricted stock, performance units, performance shares, and bonus stock. During 2008, NVE issued restricted shares and performance shares under the long-term incentive plan.

NVE recorded $4.1 million, $8.5 million and $5.3 million as stock compensation expense in 2008, 2007 and 2006, respectively.

Non-Qualified Stock Options

Elected officers and key employees specifically designated by a committee of the BOD are eligible to be awarded non-qualified stock options (NQSO’s) based on the guidelines in the plan. These grants are at 100% of the then current fair market value, and vest over different periods as stated in the grant. These options have to be exercised within ten years of award, and no earlier than one year from the date of grant. At the time of grant, rights to dividend equivalents may also be awarded.

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In 2008, there were no grants of non-qualified stock options made to employees. The total number of non-qualifying stock options granted to all employees in 2007 was 411,036, which were issued at an option price not less than market value at the date of grant. Of this amount, 409,934 will vest over three years from the grant date at one-third per year. The remaining 1,102, granted on November 1, 2007 will vest over three years beginning on February 15, 2008. The grants may be exercised for a period not exceeding ten years from the grant date. The options may be exercised using either cash or previously acquired shares valued at the current market price, or a combination of both. The Committee also allows cashless exercises, subject to applicable securities law restrictions or other means consistent with the purpose of the plan and the applicable law.

A summary of the status of NVE’s nonqualified stock option plan as of December 31, 2008, 2007, and 2006, and changes during the year is presented below:

	2008				2007				2006
			Weighted-				Weighted-				Weighted-
			Average				Average				Average
Nonqualified Stock Options	Shares		Exercise Price		Shares		Exercise Price		Shares		Exercise Price

Outstanding at beginning of year		1,294,397	$	15.77		1,199,188	$	14.66		1,077,772	$	14.38
Granted		-		-		411,036	$	18.25		176,416	$	13.29
Exercised		-		-		312,639	$	14.82		55,000	$	5.69
Forfeited		15,840	$	24.93		3,188	$	19.97		-		-
Outstanding at end of year		1,278,557	$	15.65		1,294,397	$	15.77		1,199,188	$	14.66

Options exercisable at year-end		956,431	$	14.94		747,317	$	14.94		913,209	$	15.42

Intrinsic value of options exercised	$	-			$	1,381,976			$	571,190

Fair value of options vested	$	-			$	-			$	141,037
Weighted-average grant date fair
value of options granted 1:

Average of all grants for:
2008	$	-
2007					$	6.27
2006									$	4.82

(1)	The fair value of each nonqualified option has been estimated on the date of grant using the Black-Scholes option pricing model with the following assumptions used for grants issued in 2007 and 2006:

Year of Option Grant	Average Dividend Yield			Average Expected Volatility			Average Risk-Free ROR			Average Expected Life

2007		0.00	%		24.23	%		4.41	%	6 years
2006		0.00	%		27.06	%		4.51	%	6 years

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The following table summarizes information about nonqualified stock options outstanding at December 31, 2008:

			Options Outstanding				Options Exercisable
Year of Grant	Weighted Average Exercise Price		Number Outstanding at 12/31/08		Remaining Contractual Life		Weighted Average Exercise Price		Number Vested and Exercisable at 12/31/08

1999	$	25.35		36,440	<1 year		$	25.35		36,440
2000	$	16.00		400,000	1 year		$	16.00		400,000
2001	$	15.08		22,510	1.6 - 2 years		$	15.08		22,510
2002	$	14.05		86,410	3 years		$	14.05		86,410
2004	$	7.29		25,000	4 - 4.5 years		$	7.29		25,000
2005	$	10.10		126,966	6.5 years		$	10.10		126,966
2006	$	13.29		170,195	7.2 - 7.4 years		$	13.29		122,094
2007	$	18.25		411,036	8.1 years		$	18.25		137,012

Weighted Average Remaining Contractual Life						4.84				2.58

Intrinsic Value	$	65,000					$	65,000

* Dividend Equivalents were not granted for any of these awards.

Performance Shares

In 2008, 2007 and 2006, NVE granted performance shares in the following numbers and initial values:


	2/7/2008		2/14/2007		2/7/2006

Shares Granted		518,121		138,967		675,056
Value per Share	$	15.27	$	16.96	$	10.03

In 2008, 2007 and 2006, 518,121, 138,967 and 172,446 shares of stock, respectively, were granted to plan participants; the actual number of shares earned by each participant is dependent upon NVE achieving certain financial goals over three-year performance periods. The value of all performance share grants, if earned, will be equal to the market value of NVE's common shares as of the end of the performance periods. NVE, at its sole discretion, may pay earned performance shares in the form of cash or in shares, or a combination thereof.

In 2006, there were 2,610 special grant shares awarded, which were to be earned only upon the restoration of both the NPC and SPPC investment grade credit status within three years of the date of grant. The shares for this grant were earned and issued in 2007.

In August, 2006, upon the signing of an employment agreement for the prior Chief Executive Officer, a grant of 500,000 performance shares was issued according to the agreement. The grant requires the achievement of specific performance goals which were established in the agreement. The final determination and approval of the number of shares awarded was at the discretion of the BOD and the Compensation Committee. In 2007 and 2006, 200,000 and 65,000 shares, respectively, were deemed to have been earned and were issued in the form of cash.

There were 42,920 special grant shares awarded in 2005, which were to be earned only upon the restoration of both the NPC and SPPC investment grade credit status within three years of the date of grant. These shares were earned and issued in 2007.

In 2005, there were 182,114 performance shares awarded, and due to the achievement of certain performance goals established for this grant over a three year cycle, the number of shares available under this grant was increased to 224,591; these shares were issued in early 2008.

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In accordance with SFAS 123 (R), NVE recognized expense in 2008, 2007 and 2006 related to performance shares. Expense was recognized using the closing market price of NVE stock at the end of each interim period and on December 31, 2008.

The total value of shares issued in 2008, 2007 and 2006 were $3.8 million, $4.4 million and $1.4 million, respectively. The total value of shares vested in 2008, 2007, and 2006 were $2.7 million, $2.8 million and $2.0 million, respectively.

Restricted Stock Shares

In 2008, NVE awarded several grants of restricted shares; 30,000 shares were awarded with a grant price of $14.39 per share, 10,000 shares were awarded with a grant price of $10.73 per share, and 3,500 shares were awarded with a grant price of $8.07 per share. These grants will vest equally over three years from the date of grant. The issuance of these shares is conditional upon the employee retaining employment with NVE throughout the entire vesting period.

There were no restricted shares granted in 2007.

In 2006, 5,643 shares of restricted stock were awarded at a grant price of $13.29 per share; this grant was fully vested on December 31, 2006 and the shares were issued in early 2007.

The total value of shares issued in 2008, 2007 and 2006 were $0, $6.0 million and $1.5 million, respectively. The total value of shares vested in 2008, 2007 and 2006 were $106.0 thousand, $0 and $5.8 million, respectively.

Employee Stock Purchase Plan

Upon the inception of NVE’s employee stock purchase plan, NVE was authorized to issue up to an aggregate of 200,162 shares of common stock to all of its employees with minimum service requirements. On June 19, 2000, shareholders approved an additional 700,000 shares for distribution under the plan. According to the terms of the plan, employees can choose twice each year to have up to 15% of their base earnings withheld to purchase NVE’s common stock. In 2008, the BOD of NVE and its stockholders, approved changes to the plan which increased the option price discount from 10% to 15%, and provided for the purchase price to be the lesser of 85% of the market value on the offering commencement date, or 85% of the market value on the offering exercise date. Employees can withdraw from the plan at any time prior to the exercise date. Under the plan NVE sold 109,924, 56,835 and 55,954 shares to employees in 2008, 2007, and 2006, respectively.

In accordance with SFAS 123 (R), NVE recognized expense in 2008, 2007 and 2006 related to the employee stock purchase plan. For purposes of determining the expense for those years, compensation cost has been estimated for the employees’ purchase rights on the date of grant, using the Black-Scholes option-pricing model with the following assumptions used for 2008, 2007 and 2006, with an option life of six months:

Year	Average Dividend Yield			Average Expected Volatility			Average Risk-Free ROR			Weighted Average Fair Value

2008		0.00	%		40.31	%		1.22	%	$	2.56
2007		0.00	%		20.75	%		4.13	%	$	3.02
2006		0.00	%		19.73	%		4.95	%	$	2.62

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NOTE 13. COMMITMENTS AND CONTINGENCIES

Purchased Power

The Utilities have several contracts for long-term purchase of electric energy. Expiration of these contracts ranges from 2009 to 2039. Related party purchase power agreements have been eliminated from the NVE totals. Estimated future commitments under non-cancelable agreements as of December 31, 2008 were as follows (dollars in thousands):

	Purchased Power
	NPC		SPPC		NVE
2009	$	306,459	$	126,847	$	409,713
2010		347,614		188,451		446,480
2011		399,369		237,668		493,684
2012		420,594		253,886		512,160
2013		430,237		260,250		523,160
Thereafter		5,158,546		4,015,875		6,094,331

Coal, Natural Gas and Transportation

The Utilities have several long-term contracts for the purchase and transportation of coal and natural gas. These contracts expire in years ranging from 2009 to 2031. Estimated future commitments under non-cancelable agreements as of December 31, 2008 were as follows (dollars in thousands):

	Coal and Natural Gas						Transportation
	NPC		SPPC		NVE		NPC		SPPC		NVE
2009	$	356,431	$	198,485	$	554,916	$	58,655	$	83,445	$	142,100
2010		43,780		31,964		75,744		46,810		60,871		107,681
2011		6,316		15,000		21,316		50,724		43,524		94,248
2012		-		-		-		73,926		43,438		117,364
2013		-		-		-		73,799		42,981		116,780
Thereafter		-		-		-		944,739		246,518		1,191,257

Long-Term Service Agreements

NPC entered into long-term service agreements for the performance of maintenance on generation units located at the Lenzie Generating Station, the Silverhawk Generating Station and the Higgins Generating Station. SPPC entered into a long-term service agreement for the Tracy Generating Station. Future commitments under these agreements are as follows (dollars in thousands):

	Long-Term Service Agreements
	NPC		SPPC		NVE
2009	$	26,108	$	5,240	$	31,348
2010		26,390		5,240		31,630
2011		26,680		5,240		31,920
2012		26,979		5,240		32,219
2013		27,286		5,240		32,526
Thereafter		129,610		40,209		169,819

Capital Projects

Capital projects at NPC include construction of the Harry Allen Generating Station, tenant improvements at the Beltway Complex, an operations center in southern Nevada, environmental upgrades at the Clark Generating Station Units 5-8, and the construction of a Recovered Energy Generation Project. Future commitments under these agreements are as follows (dollars in thousands):

	Capital Projects
	NPC		SPPC		NVE
2009	$	332,797	$	-	$	332,797
2010		166,124		-		166,124
2011		8,113		-		8,113
2013		30,638		-		30,638

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Operating Leases

NPC and SPPC have entered into various operating leases for buildings, land and equipment. Rent payments for 2008, 2007 and 2006 were $10.8 million, $5.7 million and $3.0 million, respectively, for NPC. Rent payments for 2008, 2007 and 2006 were $12.1 million, $10.5 million and $9.1 million, respectively, for SPPC. NVE’s, NPC’s and SPPC’s estimated future minimum cash payments under non-cancelable operating leases as of December 31, 2008, were as follows (dollars in thousands):

	Operating Leases
	NPC		SPPC		NVE
2009	$	11,249	$	11,564	$	22,813
2010		9,100		9,826		18,926
2011		6,678		2,700		9,378
2012		6,353		2,515		8,868
2013		6,312		2,508		8,820
Thereafter		52,517		37,339		89,856

Environmental

Nevada Power Company

Reid Gardner Generating Station

Surface and Groundwater Matters

The Reid Gardner Generating Station is a coal generating station consisting of four units. NPC is the owner and operator of Unit Nos. 1, 2 and 3. Unit No. 4 is co-owned by the CDWR 67.8% and 32.2% by NPC. NPC is the operating agent for Unit No. 4.

The Reid Gardner Generating Station has a number of raw water and scrubber make-up storage ponds, as well as ponds used for process water evaporation and fly ash settling. Process water, which has been used beyond the treatable limits, is routed to onsite ponds for evaporation. Waste management units are present throughout the site and surrounding area. Environmental contaminants identified at the Reid Gardner Generating Station include but are not limited to, elevated concentrations of total dissolved solids, sulfate, chloride, dissolved metals, volatile organic compounds and petroleum hydrocarbons.

In August 1999, the NDEP issued a discharge permit to the Reid Gardner Generating Station and an Order that requires all evaporation and fly ash settling ponds to be closed or lined with impermeable liners over the next ten 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 most recent NDEP Authorization to Discharge Permit issued October 2005.

Pond construction and lining costs to satisfy the NDEP order expended through December 31, 2008 was approximately $45 million. No additional expenditures associated with this order are projected.

In 2006 and 2007, the water division of NDEP has been in discussions with NPC regarding what additional surface and groundwater remediation may be required at the site, beyond the scope of the current pond relining project. The proposed solution was to enter into an AOC and the final form of the proposed AOC was delivered to NPC in December 2007. Until such time, NPC did not know the extent of the obligation or scope of work that would be required to effect site restoration due to the complexities associated with environmental remediation of the target media and the evolving standards of acceptable remediation standards. As a result, management was unable to reasonably estimate the cost of this comprehensive remediation project prior to concluding the negotiations and receiving the final AOC from the NDEP.

In February 2008, NPC signed the AOC as owner and operator of Unit Nos. 1, 2 and 3 and as co-owner and operating agent of Unit No. 4. The AOC has been designed to supersede previous Orders and takes a comprehensive approach to address historical environmental impacts associated with facility operations. Upon receiving the final document in December 2007, management was able to estimate a range of costs to satisfy the requirements of the AOC. As a result, NPC has recorded an asset retirement obligation of approximately $20 million, which it expects to receive regulatory recovery of, similar to the PUCN’s treatment of other asset retirement obligations. Other costs associated with the AOC are expected to include capital expenditures and remediation costs of approximately $32.3 million in addition to a 2008 charge to operating and maintenance expense of approximately $1.3 million. However, these estimates may vary significantly once the scope of work is initiated and additional characterization has been completed.

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Air Quality Matters

In June 2006, the EPA issued a Finding and NOV related to monitoring, recordkeeping and emission exceedances at the Reid Gardner Generating Station. In April 2007, NPC lodged a Consent Decree in federal district court with NDEP, EPA and the Department Of Justice regarding the NOVs and providing for additional environmental controls and equipment changes, environmental benefit projects, monetary penalties, and/or other measures that will be required to resolve the alleged violations. Terms of the Consent Decree included a $1.1 million fine, which was paid during 2007, funding of an approximately $2 million Supplemental Environmental Project (SEP) with the Clark County School District, and the installation of emission reduction equipment at the facility. The SEP was aimed at achieving increased energy efficiency and cost savings for the school district and involved extensive lighting retrofits at multiple schools in the Las Vegas valley. Certain environmental controls and equipment changes needed to assure compliance with existing or modified regulations, and which will satisfy the terms of the consent decree, were previously submitted by NPC to the PUCN in NPC’s 2006 IRP filing. Installation of the required environmental controls is scheduled for completion in 2009. 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. Capital expenditures are estimated at $94.0 million, of which $84 million was approved by the PUCN. NPC will seek approval for amounts spent above the previously approved amount. However, amounts may change depending on the procurement of material and services.

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.

Litigation Contingencies

Nevada Power Company and Sierra Pacific Power Company

Calpine Settlement

On September 19, 2007, NPC, SPPC and Calpine Corporation (“Calpine”) entered into a settlement agreement (the “Settlement Agreement”) that resolved the issues and claims pertaining to three proofs of claim (Claim Nos. 5177, 5178 and 5179) filed by the Utilities against Calpine in Calpine’s bankruptcy proceeding. The Settlement Agreement was approved by the United States Bankruptcy Court for the Southern District of New York on October 10, 2007, and by the FERC on December 28, 2007, in orders that are final and non-appealable.

Claim Nos. 5177 and 5179 filed by SPPC and NPC relate to complaints filed with FERC in December 2001 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 reaction to the Western United States energy crisis. The Settlement Agreement provided that, for Claim Nos. 5177 and 5179, SPPC and NPC would receive general unsecured claims in the Calpine bankruptcy proceeding of approximately $1.7 million and $1.3 million respectively, totaling $3 million. In February 2008, Calpine distributed shares of Calpine common stock to SPPC and NPC with respect to Claim Nos. 5177 and 5179, at the approximate value at the time of the distribution of approximately $1.3 million, and $1.1 million, respectively. The Utilities recognized these amounts as income for the year ended December 31, 2008.

Claim No. 5178 filed by NPC regarding Calpine’s alleged breach of a 400 MW TSA and a 2002 settlement agreement approved by the FERC. The Settlement Agreement provided that the claim shall be amended to reflect a general unsecured claim of $18 million against Calpine. NPC agreed to treat the distribution in respect to Claim No. 5178 as a prepayment for a new 400 MW TSA (“New TSA”) with a term commencing January 1, 2008 and ending approximately March 31, 2010, assuming no change in NPC’s OATT service schedules and, in the event of any such changes, ending on the date the $18 million is depleted based on the applicable OATT service rate schedule. In February 2008, Calpine distributed shares of Calpine common stock to NPC having an approximate value at that time of $14.4 million, which will be recognized as transmission revenue over the term of the new TSA.

The distributions discussed above represent approximately 80% of the balance owed to NPC and SPPC under the three proofs of claims filed. Management cannot predict if the remaining 20% will be recovered due to the status of Calpine’s bankruptcy proceedings, and as such has not recorded any further amounts as income. Subsequent to the distribution, NPC and SPPC sold all of their shares of Calpine common stock and recorded a gain of $1.8 million for the year ended December 31, 2008.

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Nevada Power Company

Peabody Western Coal Company

NPC owns an 11% interest in the Navajo Generating Station which is located in Northern Arizona and is operated by Salt River. Other participants in the Navajo Generating Station are Arizona Public Service Company, Los Angeles Department of Water and Power and Tucson Electric Power Company (together with Salt River and NPC, the “Navajo Joint Owners”). NPC also owns a 14% interest in the Mohave Generating Station which is located in Laughlin, Nevada and was operated by Southern California Edison prior to the time it became non-operational on December 31, 2005.

Royalty Claim

On October 15, 2004, the Navajo Generating Station’s coal supplier, Peabody Western Coal Co. (Peabody WC), filed a complaint against the Navajo Joint Owners in Missouri State Court in St. Louis, alleging, among other things, a declaration that the Navajo Joint Owners are obligated to reimburse Peabody WC for any royalty, tax or other obligations arising out of a lawsuit that the Navajo Nation filed against Salt River, several Peabody Coal Company entities (including Peabody WC and collectively referred to as “Peabody”) and SCE in June 1999 in the U.S. District Court for the District of Columbia (DC Lawsuit).

The Navajo Joint owners were first served in the Missouri lawsuit in January 2005. The operating agent for the Navajo Generating Station, Salt River, is defending the suit on behalf of the Navajo Joint Owners. NPC believes Peabody WC’s claims are without merit and intends to contest them. In October, 2007, the Navajo Joint Owners filed a motion for partial summary judgment against Peabody WC’s claims for reimbursement of attorney fees and indemnification of liability arising out of the DC Lawsuit. In January 2008, Peabody filed responses to the Navajo Joint Owner’s motion. On February 13, 2008, the Navajo Joint Owners filed a second partial summary judgment motion seeking dismissal of another count raised by Peabody concerning indemnity arising out of the DC Lawsuit. In July 2008, the Court dismissed the three counts against NPC, two without prejudice to their possible refiling at a later date. NPC is unable to predict whether any liability may arise from any of these matters, including from the ultimate outcome of the DC Lawsuit.

NPC is not a party to the DC Lawsuit although, as noted above, it is a participant in both the Navajo Generating Station and the Mohave Generating Station. The DC Lawsuit consists of various claims relating to the renegotiations of coal royalty and lease agreements and alleges, among other things, that the defendants obtained a favorable coal royalty rate for the lease agreements under which Peabody mines coal for both the Navajo Generating Station and the Mohave Generating Station by improperly influencing the outcome of a federal administrative process pursuant to which the royalty rate was to be adjusted. The DC Lawsuit seeks $600 million in damages, treble damages, and punitive damages of not less than $1 billion, and the ejection of defendants from all possessory interests and Navajo Tribal lands arising out of the primary coal lease. In July 2001, the U.S. District Court dismissed all claims against Salt River. The action had been stayed since October 5, 2004. In March, 2008, the US District Court lifted the stay and referred pending discovery related motions to a Magistrate judge. The Magistrate filed his Report and Recommendations on June 13, 2008 and the Navajo thereafter sought judicial review of the Magistrate’s Report and Recommendations by filing an Objection with the District Court on June 27, 2008. The matter was fully briefed and parties are awaiting the Judge’s decision.

Retiree Health Care and Reclamation Claims

In addition to the above action before the Missouri State Court, Peabody further asserted in 1994 that the Navajo Joint Owners are liable under the CSA for Retiree Health Care Costs (RHCC) and Final Reclamation Costs (FRC), which Peabody WC is obligated to pay after the CSA expires and the Kayenta Mine closes. In 1996, Salt River and the Navajo Joint Owners filed a complaint in the Maricopa County (Arizona) Supreme Court seeking determinations that they are not liable for RHCC or FRC or, alternatively, that Peabody WC cannot recover RHCC and FRC until after the CSA ends. The case was dormant for several years, while Peabody WC pursued other RHCC and FRC claims arising out of similar coal contracts. Settlement discussions, led by Salt River on both the RHCC matter and the FRC claim reached final approvals with Peabody WC and the Navajo Joint Owners in July 2008 (Settlement Agreement and Mutual Release with Peabody). As of December 31, 2008, NPC has a $17.1 million liability recorded which management has assessed as the approximate amount to be paid, and recorded a corresponding other regulatory asset for such claims, as management believes that these costs are recoverable through deferred energy. The underlying lawsuit and arbitration have both been dismissed.

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Sierra Pacific Power Company

Farad Dam

SPPC sold four hydro generating units, (10.3 MW total capacity), located in Nevada and California, for $8 million to TMWA in June 2001. The Farad Hydro (2.8 MW), has been out of service since the summer of 1996 due to a collapsed flume. The current estimate to rebuild the diversion dam, if management decides to proceed, is approximately $20 million. Under the terms of the contract with TMWA, SPPC is required to transfer the hydro assets in working condition, or, alternatively SPPC assigns its casualty loss claim to TMWA and TMWA is reasonably satisfied regarding its rights with respect to such claim.

SPPC filed a claim with the insurers Hartford Steam Boiler Inspection and Insurance Co. and Zurich-American Insurance Company (collectively, the “Insurers”) for the Farad flume and Farad Dam. In December 2003, SPPC sued the Insurers in the U.S. District Court for the District of Nevada on a coverage dispute relating to potential rebuild costs for Farad Dam. The case went to trial before the Court in April 2008. On September 30, 2008, the Court ruled that SPPC was not time barred from reconstructing Farad Dam, and has coverage for the full rebuild costs, subject to coverage sub-limits set forth in the insurance policies. The Court further ruled that SPPC is entitled to recover $4 million for costs incurred to date on Farad Dam and that SPPC shall have three years to rebuild the dam from the date of the Court’s decision. In the event Farad Dam is not rebuilt, the Court determined SPPC would be entitled to actual cash value of approximately $1.3 million. SPPC has requested the court to reconsider the cash value to reflect rebuild costs and the Insurers opposed. Parties are awaiting a decision from the Court. The Insurers time to file an appeal on the Court’s decision has been suspended pending the Court’s determination on the cash value reconsideration.

Other Legal Matters

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

NOTE 14. COMMON STOCK AND OTHER PAID-IN CAPITAL

Rights Agreement

In December 2005, the BOD voted to amend the Rights Agreement, dated as of February 2001 (as amended and restated, the “Rights Agreement”), between NVE and Wells Fargo Bank Minnesota, N.A., to accelerate the final expiration date of the rights (“Rights”) issued thereunder to December 2005, and to terminate the Rights Agreement upon the expiration of the Rights. The BOD also adopted a policy governing future entry into a shareholder rights agreement or similar agreement (a “shareholder rights plan”). NVE’s policy is to seek shareholder approval prior to the adoption of a shareholder rights plan, unless the BOD, in the exercise of its fiduciary duties and with the concurrence of a majority of its independent members, determines that, under the circumstances existing at the time, it is in the best interest of NVE’s shareholders to adopt a shareholder rights plan without first obtaining shareholder approval. If a shareholder rights plan is adopted without prior shareholder approval, the plan must provide that it shall expire, unless ratified by shareholders, within one year of adoption.

Stock Ownership Plans

As of December 31, 2008, 10,956,240 shares of common stock were reserved for issuance under the Common Stock Investment Plan (CSIP), Employees’ Stock Purchase Plan (ESPP), and Executive Long-Term Incentive Plan (LTIP).

The 2005 LTIP for officers and key employees allows for the issuance of NVE’s common shares through December 2013, which can be earned and issued prior to December 2013. This Plan permits the following types of grants, separately or in combination: nonqualified and qualified stock options; stock appreciation rights; restricted stock; performance units; performance shares, bonus stock and cash.

NVE also provides an ESPP to all of its employees meeting minimum service requirements. Employees can choose twice each year (offering date) to have up to 15% of their base earnings withheld to purchase NVE common stock. The purchase price of the stock is 85% of the market value on the offering date or the execution date, whichever is less.

Non-Employee Director Stock

The Non-employee Director Stock Plan provides that a portion of NVE’s outside directors’ annual retainer be paid in NVE common stock. In addition, in 1996, NVE eliminated its outside director retirement plan and converted the present value of each director’s vested retirement benefit to phantom stock based on the stock price at the time of conversion. Phantom stock earns dividends, also payable in phantom stock, which are recorded in each Director’s phantom account. The value of these accounts is issued in stock or cash, at the election of the BOD, at the time the Director leaves the BOD.

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The annual retainer for non-employee directors is $120,000, and the minimum amount to be paid in NVE stock is $75,000 per director. During 2008, 2007, and 2006, NVE granted the following total shares and related compensation to directors including NVE stock, respectively: 72,573, 27,300, and 30,733, shares, and $396,309, $280,000, and $154,000.

Common Stock Offering

In December 2007, NVE issued 12 million shares of its $1 par value common stock. Net proceeds from the issuance were $202.8 million. In December 2007, NVE contributed capital to NPC of approximately $65 million, and to SPPC of approximately $65 million. Both Utilities used the proceeds to repay indebtedness under their revolving credit facilities, and for general corporate purposes. Additionally, NVE contributed capital to NPC of approximately $146.6 million and to SPPC of approximately $20 million for general corporate purposes in 2008.

In August 2006, SPR issued 20 million shares of its $1 par value common stock. Net proceeds from the issuance were $280.6 million. In August 2006, SPR contributed capital to NPC of approximately $200 million. NPC used the proceeds to repay indebtedness under its $600 million revolving credit facility.

Common Stock Investment Plan

NVE offers a Common Stock Investment Plan (CSIP, or the Plan) for the purpose of promoting long-term ownership by providing a convenient method to purchase shares of our common stock and to reinvest cash dividends. New investors can purchase common stock directly from the company for as little as $250 for the first purchase. Existing shareholders can purchase additional shares up to once per month for as little as $50. Shares are purchased on the first business day of each month with the exception of months in which a dividend is paid where purchases are made on the date of the dividend payment. Through this Plan, shareholders can also choose to reinvest all or a portion (specified in increments of 10%) of cash dividends to purchase additional shares of common stock.

Dividends

On November 1, 2007, NVE’s BOD declared a quarterly cash dividend of $0.08 per share payable on December 12, 2007, to common shareholders of record on November 19, 2007.

On February 7, 2008, NVE’s BOD declared a quarterly cash dividend of $0.08 per share payable on March 12, 2008, to common shareholders of record on February 22, 2008.

On April 28, 2008, NVE’s BOD declared a quarterly cash dividend of $0.08 per share payable on June 11, 2008, to common shareholders of record on May 23, 2008.

On August 4, 2008, NVE’s BOD declared a quarterly cash dividend of $0.08 per share payable on September 10, 2008, to common shareholders of record on August 22, 2008.

On October 30, 2008, NVE’s BOD declared a quarterly cash dividend of $0.10 per share payable on December 17, 2008, to common shareholders of record on December 2, 2008.

On February 5, 2009, NVE’s BOD declared a quarterly cash dividend of $0.10 per share payable on March 18, 2009, to common shareholders of record on March 3, 2009.

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NOTE 15. EARNINGS PER SHARE (NVE)

The difference, if any, between basic EPS and diluted EPS is due to potentially dilutive common shares resulting from stock options, the employee stock purchase plan, performance and restricted stock plans and the non-employee director stock plan.

Emerging Issues Task Force, Participating Securities and the Two-Class Method under SFAS 128, (EITF 03-6) requires companies to use the “two-class” method to calculate basic EPS, and the “if-converted” method to calculate diluted EPS if the result was dilutive.

The following table outlines the calculation for EPS:

		Year ended December 31,
		2008		2007		2006
Basic EPS
Numerator ($000)

	Net income applicable to common stock	$	208,887	$	197,295	$	277,451

Denominator
	Weighted average number of common shares outstanding		234,031,750		222,180,440		208,531,134

Per Share Amounts

	Net income applicable to common stock	$	0.89	$	0.89	$	1.33

Diluted EPS
Numerator ($000)

	Net income applicable to common stock	$	208,887	$	197,295	$	277,451

Denominator (1)
	Weighted average number of shares outstanding before dilution		234,031,750		222,180,440		208,531,134
	Stock options		39,556		123,124		91,119
	Executive long term incentive plan - restricted		-		-		113,456
	Non-Employee Director stock plan		63,636		46,551		30,754
	Employee stock purchase plan		4,615		878		3,345
	Performance Shares		443,605		203,031		251,088
	Restricted Shares		1,842		-		-
			234,585,004		222,554,024		209,020,896
Per Share Amounts

	Net income applicable to common stock	$	0.89	$	0.89	$	1.33

(1)

The denominator does not include stock equivalents resulting from the options issued under the nonqualified stock option plan for the years ended December 31, 2008, 2007, and 2006, due to conversion prices being higher than market prices for all periods. Under this plan, 943,231, 638,250 and 932,946 shares, respectively, would be included in each of these periods if the conditions for conversions were met.

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NOTE 16. QUARTERLY FINANCIAL DATA (UNAUDITED)

The following figures are unaudited and include all adjustments necessary in the opinion of management for a fair presentation of the results of interim periods. Dollars are presented in thousands except per share amounts.

	NV ENERGY, INC.

	2008 Quarter Ended

	March		June		September		December (1)

Operating Revenues	$	805,051	$	838,794	$	1,118,131	$	766,137
Operating Income	$	76,813	$	94,201	$	218,952	$	85,362
Net Income (Loss) Applicable to Common Stock	$	24,058	$	36,134	$	150,783	$	(2,088	)

Net Income (Loss) Applicable to Common Stock per Share
Basic & Diluted	$	0.10	$	0.15	$	0.64	$	(0.01	)

	2007 Quarter Ended

	March		June		September		December

Operating Revenues	$	756,431	$	851,894	$	1,206,050	$	786,585
Operating Income	$	61,930	$	86,431	$	213,137	$	53,069
Net Income Applicable to Common Stock	$	15,607	$	25,754	$	152,222	$	3,712

Net Income Applicable to Common Stock per Share
Basic & Diluted	$	0.07	$	0.12	$	0.69	$	0.02

(1)

NVE experienced a Net Loss for the Quarter Ended December 31, 2008, primarily as a result of increased interest expense and depreciation. Interest expense increased due to the issuance of new debt by the Utilities. NPC issued a substantial amount of debt in 2008 primarily to fund the acquisition of the Higgins Generating Station and other major capital projects. SPPC issued debt to fund the construction of the Tracy Generating Station. Depreciation expense increased as a result of the acquisition of the Higgins Generating Station, which is not included in rates but has been requested in NPC’s 2008 GRC.

	NEVADA POWER COMPANY

	2008 Quarter Ended

	March		June		September		December (1)
Operating Revenues	$	469,172	$	570,223	$	826,825	$	449,207
Operating Income	$	40,797	$	67,067	$	165,001	$	39,087
Net Income (Loss)	$	7,971	$	33,175	$	124,336	$	(14,051	)

	2007 Quarter Ended

	March		June		September		December
Operating Revenues	$	418,165	$	575,108	$	894,226	$	469,121
Operating Income	$	27,968	$	61,228	$	170,264	$	37,844
Net Income	$	4,582	$	23,604	$	133,094	$	4,414

(1)

NPC experienced a Net Loss for the Quarter Ended December 31, 2008, primarily as a result of increased interest expense and depreciation. Interest expense increased due to the issuance of new debt. NPC issued a substantial amount of debt in 2008 primarily to fund the acquisition of the Higgins Generating Station and other major capital projects. Depreciation expense increased as a result of the acquisition of the Higgins Generating Station, which is not included in rates but has been requested in NPC’s 2008 GRC.

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	SIERRA PACIFIC POWER COMPANY

	2008 Quarter Ended

	March		June		September		December
Operating Revenues	$	335,872	$	268,567	$	291,298	$	316,924
Operating Income	$	33,969	$	24,539	$	50,108	$	45,537
Net Income	$	24,284	$	10,849	$	32,919	$	22,530

	2007 Quarter Ended

	March		June		September		December
Operating Revenues	$	337,999	$	276,734	$	311,818	$	317,746
Operating Income	$	33,911	$	22,213	$	38,118	$	11,715
Net Income	$	21,968	$	10,008	$	25,552	$	8,139

ITEM 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

(a) Evaluation of disclosure controls and procedures.

NVE, NPC, and SPPC management, under the supervision and with the participation of the company’s Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of NVE, NPC, and SPPC disclosure controls and procedures (as that term is defined in Rules 13a-15(e) or 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of the period, NVE, NPC, and SPPC disclosure and procedures are effective.

(b) Reports on Internal Control Over Financial Reporting

Management’s Report on Internal Control Over Financial Reporting

NV Energy, Inc.

The management of NVE is responsible for establishing and maintaining adequate internal control over financial reporting. NVE’s internal control system was designed to provide reasonable assurance to NVE’s management and BOD regarding the preparation and fair presentation of published financial statements.

Although NVE is firmly committed to effective internal controls over financial reporting, internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

NVE.’s management assessed the effectiveness of NVE’s internal control over financial reporting as of December 31, 2008. In making this assessment, NVE used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Based on our assessment we believe that, as of December 31, 2008, NVE’s internal control over financial reporting is effective based on those criteria.

NVE’s independent registered public accountants have issued an attestation report on NVE’s internal control over financial reporting.

ITEM 9A(T). CONTROLS AND PROCEDURES

Nevada Power Company

The management of NPC is responsible for establishing and maintaining adequate internal control over financial reporting. NPC’s internal control system was designed to provide reasonable assurance to the company’s management and BOD regarding the preparation and fair presentation of published financial statements.

Although NPC is firmly committed to effective internal controls over financial reporting, internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

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NPC’s management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2008. In making this assessment, NPC used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Based on our assessment we believe that, as of December 31, 2008, NVE’s internal control over financial reporting is effective based on those criteria.

Sierra Pacific Power Company

The management of SPPC is responsible for establishing and maintaining adequate internal control over financial reporting. SPPC’s internal control system was designed to provide reasonable assurance to the company’s management and BOD regarding the preparation and fair presentation of published financial statements.

Although SPPC is firmly committed to effective internal controls over financial reporting, internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

SPPC’s management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2008. In making this assessment, SPPC used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Based on our assessment we believe that, as of December 31, 2008, NVE’s internal control over financial reporting is effective based on those criteria.

Attestation Report

This annual report does not include an attestation report of the independent registered public accountants regarding internal control over financial reporting of NPC and SPPC. The management reports of NPC and SPPC were not subject to attestation by the independent registered public accountants pursuant to temporary rules of the SEC that permit NPC and SPPC to provide only management’s reports in their annual report.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

NV Energy, Inc

Las Vegas, Nevada

We have audited the internal control over financial reporting of NV Energy, Inc. (formerly Sierra Pacific Resources) and subsidiaries (the "Company") as of December 31, 2008, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

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In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedule as of and for the year ended December 31, 2008 of the Company and our report dated February 23, 2009 expressed an unqualified opinion on those financial statements and financial statement schedule.

/s/ Deloitte & Touche LLP

Las Vegas, Nevada

February 23, 2009

None.

ITEM 9B. OTHER INFORMATION

Election of New Director

On February 20, 2009, Stephen E. Frank, former president and chief executive officer of Southern California Edison until his retirement in 2002, was elected to NVE’s board of directors effective February 23, 2009, after the filing of the 2008 Form 10-K, as well as NPC’s and SPPC’s board of directors, effective February 25, 2009. Prior to joining Southern California Edison in 1995, Mr. Frank was president and chief operating officer of Florida Power and Light Company as well as a director of FPL Group, the parent company. Mr. Frank is expected to be a member of the Audit and one or more other committees. Mr. Frank will receive the same compensation and participate in the same plans as are provided to all of NVE’s non-employee directors, as more fully described in NVE’s Proxy Statement filed on March 19, 2008.

Amendment of By-Laws

On February 20, 2009, the BOD of NVE amended Article VIII of NVE's By-Laws to fix the number of Directors at 13 in connection with the election of Stephen E. Frank.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The information required by this Item is incorporated by reference to the definitive proxy statement for our 2009 Annual Meeting of Stockholders to be filed with the SEC within 120 days after the end of our 2008 fiscal year (the “2009 Proxy Statement”).

ITEM 11. EXECUTIVE COMPENSATION

The information required by this Item is incorporated by reference to the 2009 Proxy Statement.

ITEM 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The information required by this Item is incorporated by reference to the 2009 Proxy Statement.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

The information required by this Item is incorporated by reference to the 2009 Proxy Statement.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

The information required by this Item is incorporated by reference to the 2009 Proxy Statement.

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PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) Financial Statements, Financial Statement Schedules and Exhibits

		Page
1.	Financial Statements:
	Reports of Independent Registered Public Accounting Firm	89

	NV Energy, Inc.:
	Consolidated Balance Sheets as of December 31, 2008 and 2007	92
	Consolidated Income Statements for the Years Ended December 31, 2008, 2007 and 2006	93
	Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2008, 2007 and 2006	94
	Consolidated Statements of Common Shareholders’ Equity for the Years Ended December 31, 2008, 2007 and 2006	95
	Consolidated Statements of Cash Flows for the Years Ended December 31, 2008, 2007 and 2006	96
	Consolidated Statements of Capitalization as of December 31, 2008 and 2007	97

	Nevada Power Company:
	Consolidated Balance Sheets as of December 31, 2008 and 2007	99
	Consolidated Income Statements for the Years Ended December 31, 2008, 2007 and 2006	100
	Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2008, 2007 and 2006	101
	Consolidated Statements of Common Shareholder’s Equity for the Years Ended December 31, 2008, 2007 and 2006	102
	Consolidated Statements of Cash Flows for the Years Ended December 31, 2008, 2007 and 2006	103
	Consolidated Statements of Capitalization as of December 31, 2008 and 2007	104

	Sierra Pacific Power Company:
	Consolidated Balance Sheets as of December 31, 2008 and 2007	105
	Consolidated Income Statements for the Years Ended December 31, 2008, 2007 and 2006	106
	Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2008, 2007 and 2006	107
	Consolidated Statements of Common Shareholder’s Equity for the Years Ended December 31, 2008, 2007 and 2006	108
	Consolidated Statements of Cash Flows for the Years Ended December 31, 2008, 2007 and 2006	109
	Consolidated Statements of Capitalization as of December 31, 2008 and 2007	110

	Notes to Financial Statements for NV Energy, Inc., Nevada Power Company and Sierra Pacific Power Company	111
2.	Financial Statement Schedules:
	Schedule II – Consolidated Valuation and Qualifying Accounts	166

All other schedules have been omitted because they are not required or are not applicable, or the required information is shown in the financial statements or notes thereto. Columns omitted from schedules have been omitted because the information is not applicable.

Exhibits:

Exhibits are listed in the Exhibit Index on pages 168 to 176.

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Commission File	Registrant, Address of Principal Executive Offices and Telephone	I.R.S. Employer	State of
Number	Number	Identification Number	Incorporation
1-08788	NV ENERGY, INC.	88-0198358	Nevada
	6226 West Sahara Avenue
	Las Vegas, Nevada 89146
	(702) 402-5000

2-28348	NEVADA POWER COMPANY d/b/a NV ENERGY	88-0420104	Nevada
	6226 West Sahara Avenue
	Las Vegas, Nevada 89146
	(702) 402-5000

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


(Title of each class)		(Name of exchange on which registered)
Securities registered pursuant to Section 12(b) of the Act:
Securities of NV Energy, Inc.:
Common Stock, $1.00 par value		New York Stock Exchange
7.803% Senior Notes Due 2012		New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:
Securities of Nevada Power Company:
Common Stock, $1.00 stated value
Securities of Sierra Pacific Power Company:
Common Stock, $3.75 par value

NV Energy, Inc.
Schedule II - Consolidated Valuation and Qualifying Accounts
For The Years Ended December 31, 2008, 2007 and 2006
(Dollars in Thousands)

	Provision for Uncollectible Accounts

Balance at January 1, 2006	$	36,228
Provision charged to income		13,476
Amounts written off, less recoveries		(10,138	)
Balance at December 31, 2006	$	39,566

Balance at January 1, 2007	$	39,566
Provision charged to income		10,584
Amounts written off, less recoveries		(14,089	)
Balance at December 31, 2007	$	36,061

Balance at January 1, 2008	$	36,061
Provision charged to income		16,669
Amounts written off, less recoveries		(20,035	)
Balance at December 31, 2008	$	32,695