UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

 THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2011

		I.R.S. Employer	State of
Commission File	Registrant, Address of Principal Executive Offices and Telephone	Identification No.	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
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

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

NV Energy, Inc.  Yesþ Noo  Nevada Power Company Yeso Noþ  Sierra Pacific Power Company Yeso  Noþ

     Indicate by check mark if each of the registrants is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yeso   Noþ

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

     Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).     Yes  þ   No  o  (Response applicable to all registrants).

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

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

NV Energy, Inc.:  Large accelerated filer þ  Accelerated filer o  Non-accelerated filer  o   Smaller reporting company o

Nevada Power Company:  Large accelerated filer  o  Accelerated filer  o  Non-accelerated filer þ   Smaller reporting company o

Sierra Pacific Power Company: Large accelerated filer o  Accelerated filer o Non-accelerated filer þ  Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yeso  Noþ (Response applicable to all registrants)

State the aggregate market value of NV Energy, Inc.'s common stock held by non-affiliates. As of June 30, 2011: $3,622,247,595

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

Common Stock, $1.00 par value, of NV Energy, Inc. outstanding at February 21, 2012:  235,999,750 Shares

NV Energy, Inc. is the sole holder of the 1,000 shares of outstanding Common Stock, $1.00 stated value, of Nevada Power Company.

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

DOCUMENTS INCORPORATED BY REFERENCE:

     Portions of NV Energy, Inc.'s definitive proxy statement to be filed in connection with the annual meeting of shareholders, to be held May 10, 2012, are incorporated by reference into Part III hereof.

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

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

NV ENERGY, INC.

NEVADA POWER COMPANY

SIERRA PACIFIC POWER COMPANY

2011 ANNUAL REPORT ON FORM 10-K

CONTENTS

					Page
Acronyms & Terms					4
PART I
ITEM 1.	Business				6
ITEM 1A.	Risk Factors				28
ITEM 1B.	Unresolved Staff Comments				33
ITEM 2.	Properties				34
ITEM 3.	Legal Proceedings				35
ITEM 4.	Mine Safety Disclosures				35
PART II
ITEM 5.	Market For Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities (NVE)				36
ITEM 6.	Selected Financial Data				38
ITEM 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations				40
		Executive Overview			43
		NV Energy, Inc.
				Results of Operations	53
				Analysis of Cash Flows	53
				Liquidity and Capital Resources (NVE Consolidated)	54
		Nevada Power Company
				Results of Operations	59
				Analysis of Cash Flows	65
				Liquidity and Capital Resources	66
		Sierra Pacific Power Company
				Results of Operations	71
				Analysis of Cash Flows	77
				Liquidity and Capital Resources	78
ITEM 7A.	Quantitative and Qualitative Disclosures About Market Risk				83
ITEM 8.	Financial Statements and Supplementary Data				85
			Report of Independent Registered Public Accounting Firm		86
			NV Energy, Inc.
				Consolidated Statements of Comprehensive Income	89
				Consolidated Balance Sheet	90
				Consolidated Statements of Cash Flows	92
				Consolidated Statements of Shareholders’ Equity	93
			Nevada Power Company
				Consolidated Statements of Comprehensive Income	94
				Consolidated Balance Sheet	95
				Consolidated Statements of Cash Flows	97
				Consolidated Statements of Shareholder’s Equity	98
			Sierra Pacific Power Company
				Consolidated Statements of Comprehensive Income	99
				Consolidated Balance Sheet	100
				Consolidated Statements of Cash Flows	102
				Consolidated Statements of Shareholder’s Equity	103
			Notes to Financial Statements
				Note 1.  Summary of Significant Accounting policies	104
				Note 2.  Segment Information	110
				Note 3.  Regulatory Actions	112
				Note 4.  Investments in Subsidiaries & Other Property	121
				Note 5.  Jointly Owned Facilities	121
				Note 6.  Long-Term Debt	123

2

		Note 7.  Fair Value of Financial Instruments	127
		Note 8.  Debt Covenant and Other Restrictions	127
		Note 9.  Derivatives and Hedging Activities	129
		Note 10.  Income Taxes (Benefits)	131
		Note 11.  Retirement Plan and Post-Retirement Benefits	135
		Note 12.  Stock Compensation Plans	141
		Note 13.  Commitments and Contingencies	145
		Note 14.  Common Stock and Other Paid-In Capital	149
		Note 15.  Earnings Per Share (NVE)	150
		Note 16.  Assets Held For Sale	150
		Note 17.  Severance Programs	151
		Note 18.  Quarterly Financial Data (Unaudited)	152
ITEM 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		153
ITEM 9A.	Controls and Procedures		154
ITEM 9B.	Other Information		156
PART III
ITEM 10.	Directors, Executive Officers and Corporate Governance of the Registrant		156
ITEM 11.	Executive Compensation		157
ITEM 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		157
ITEM 13.	Certain Relationships and Related Transactions, and Director Independence		157
ITEM 14.	Principal Accounting Fees and Services		157
PART IV
ITEM 15.	Exhibits, Financial Statement Schedules		158
	Signatures		159

3

ACRONYMS AND TERMS
(The following common acronyms and terms are found in multiple locations within the document)
Acronym/Term	Meaning
2011 Form 10-K	NVE’s, NPC’s and SPPC’s Annual Report on Form 10-K for the year ended December 31, 2011
2012 Proxy Statement	NVE’s, NPC’s and SPPC’s Proxy Statement for 2012
AFUDC-debt	Allowance for borrowed funds used during construction
AFUDC-equity	Allowance for equity funds used during construction
BCP	Nevada Bureau of Consumer Protection
BOD	Board of Directors
BTER	Base Tariff Energy Rate
BTGR	Base Tariff General Rate
CAISO	California Independent System Operator Corporation
California Assets	SPPC’s California electric distribution and generation assets
CalPeco	California Pacific Electric Company
CALPX	California Power Exchange
CDWR	California Department of Water Resources
CEO	Chief Executive Officer of NV Energy, Inc.
CIAC	Contributions in Aid of Construction
Clark Generating Station	550 MW nominally rated William Clark Generating Station
Clark Peaking Units	600 MW nominally rated peaking units at the William Clark Generating Station
CPA	Certified Public Accountant
CPUC	California Public Utilities Commission
CSIP	Common Stock Investment Plan
CWIP	Construction Work-In-Progress
d/b/a	Doing business as
DEAA	Deferred Energy Accounting Adjustment
DOE	Department of Energy
DOS	Distribution Only Service
DSM	Demand Side Management
Dth	Decatherm
EEC	Ely Energy Center
EEIR	Energy Efficiency Implementation Rate
EEPR	Energy Efficiency Program Rate
EPA	United States Environmental Protection Agency
EPS	Earnings Per Share
EROC	Enterprise Risk Oversight Committee
ESP	Energy Supply Plan
ESPP	Employee Stock Purchase Plan
EWAM	Enterprise, Work & Asset Management
FASB	Financial Accounting Standards Board
FASC	FASB Accounting Standards Codification
FERC	Federal Energy Regulatory Commission
Fitch	Fitch Ratings, Ltd.
Ft. Churchill Generating Station	226 megawatt nominally rated Fort Churchill Generating Station
GAAP	Accounting Principles Generally Accepted in the United States
GBT	Great Basin Transmission, LLC
GBT South	Great Basin Transmission South, LLC, a wholly owned subsidiary of GBT
Goodsprings	7.5 MW nominally rated Goodsprings Recovered Energy Generating Station
GPSF-B	Global Project & Structured Finance Corporation
GRC	General Rate Case
Harry Allen Generating Station	142 MW nominally rated Harry Allen Generating Station, expanded in 2011 to 642 total MWs
Higgins Generating Station	598 MW nominally rated Walter M. Higgins, III Generating Station
IBEW	International Brotherhood of Electrical Workers
Independence Lake	2,325 acres of forestland in the Sierra Nevada Mountains purchased from NV Energy, Inc. by The Nature Conservancy
IRP	Integrated Resource Plan
IRS	Internal Revenue Service
kV	Kilovolt
kWh	Kilowatt Hour
LDC	Local Distributing Company
Legislature	Nevada State Legislature
Lenzie Generating Station	1,102 MW nominally rated Chuck Lenzie Generating Station
LIBOR	London Interbank Offered Rate
LTIP	Long-Term Incentive Plan
MMBtu	Million British Thermal Units
Mohave Generating Station	1,580 MW nominally rated Mohave Generating Station
Moody’s	Moody’s Investors Services, Inc.
MW	Megawatt
MWh	Megawatt hour
NAAQS	National Ambient Air Quality Standards
Navajo Generating Station	255 MW nominally rated Navajo Generating Station
NDEP	Nevada Division of Environmental Protection
NEDSP	Non-Employee Director Stock Plan
NEICO	Nevada Electrical Investment Company
NERC	North American Electric Reliability Corporation

4

Ninth Circuit	United States Court of Appeals for the Ninth Circuit
NOL	Net Operating Loss
NPC	Nevada Power Company d/b/a NV Energy
NPC Credit Agreement	$600 million Revolving Credit Facility entered into in April 2010 between NPC and Wells Fargo, N.A., as administrative agent for the lenders a party thereto
NPC’s Indenture	NPC’s General and Refunding Mortgage Indenture dated as of May 1, 2001, between NPC and The Bank of New York Mellon Trust Company N.A., as Trustee
NRSRO	Nationally Recognized Statistical Rating Organization
NVE	NV Energy, Inc.
NV Energize	NVE project which includes Advanced Meter Infrastructure, Smart Grid Technology and Meter Data Management.
NWPP	Northwest Power Pool
OATT	Open Access Transmission Tariff
ON Line	250 mile 500 kV transmission line connecting NVE’s northern and southern service territories
Peabody	Peabody Western Coal Company
PEC	Portfolio Energy Credit
Piñon Pine	Piñon Pine Coal Gasification Demonstration Project
Portfolio Standard	Nevada Renewable Energy Portfolio Standard
PPC	Piñon Pine Corporation
PPIC	Piñon Pine Investment Company
PUCN	Public Utilities Commission of Nevada
Reid Gardner Generating Station	325 MW nominally rated Reid Gardner Generating Station
REPR	Renewable Energy Program Rate
RFP	Request for Proposal
ROE	Return on Equity
ROR	Rate of Return
S&P	Standard & Poor’s
Salt River	Salt River Project
SEC	United States Securities and Exchange Commission
Silverhawk Generating Station	395 MW nominally rated Silverhawk Generating Station
Smart Meters	Advanced service delivery meters installed as part of the NV Energize project.
SNWA	Southern Nevada Water Authority
SPC	Sierra Pacific Communications
SPPC	Sierra Pacific Power Company d/b/a NV Energy
SPPC Credit Agreement	$250 million Revolving Credit Facility entered into in April 2010 between SPPC and Bank of America, N.A., as administrative agent for the lenders a party thereto
SPPC’s Indenture	SPPC’s General and Refunding Mortgage Indenture, dated as of May 1, 2001, between SPPC and The Bank of New York Mellon Trust Company N.A., as Trustee
SPR	Sierra Pacific Resources
SRSG	Southwest Reserve Sharing Group
TMWA	Truckee Meadows Water Authority
Tracy Generating Station	541 MW nominally rated Frank A. Tracy Generating Station
TRED	Temporary Renewable Energy Development
TSR	Total Shareholder Return
TUA	Transmission Use Agreement
U.S.	United States of America
Utilities	Nevada Power Company and Sierra Pacific Power Company
Valmy Generating Station	261 MW nominally rated Valmy Generating Station
VIE	Variable Interest Entity
WECA	Western Energy Crisis Adjustment
WSPP	Western Systems Power Pool

5

FORWARD LOOKING STATEMENTS

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

PART I

ITEM 1.                      BUSINESS

NV Energy, Inc. 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 P.O. Box 98910 (6226 West Sahara Avenue), Las Vegas, Nevada 89151.

NVE has four primary, wholly-owned subsidiaries: Nevada Power Company d/b/a NV Energy, Sierra Pacific Power Company d/b/a NV Energy, NVE Insurance Company, Inc. 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”. 

The Utilities operate three business segments, as defined by the Segment Reporting Topic of the FASC: NPC electric; SPPC electric; and SPPC natural gas.  Electric service is provided by NPC to Las Vegas and surrounding Clark County, and by SPPC to northern Nevada.  Natural gas service is provided by SPPC 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 is a Nevada corporation organized in 1929 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 P.O. Box 98910 (6226 West Sahara Avenue), Las Vegas, Nevada 89151.

NEICO is a wholly-owned subsidiary of NPC.  NEICO is a 25% member of Northwind Aladdin, LLC, the other 75% of Northwind Aladdin, LLC is owned by Macquarie Infrastructure Company Trust.

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 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.

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 NVE, NPC and SPPC 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, Finance, 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.

The statistical data used throughout this 2011 Form 10-K, other than data relating specifically solely to NVE and its subsidiaries,  are based upon independent industry publications, government publications, reports by market research firms or other published independent sources.  We did not commission any of these publications or reports.  These publications generally state that they have obtained information from sources believed to be reliable, but do not guarantee the accuracy or completeness of such information.  While we believe that each of these studies and publications is reliable, we have not independently verified such data and make no representation as to the accuracy of such information.

6

Overview

NPC and SPPC are public utilities that generate, transmit and distribute electric energy in Nevada and, in the case of SPPC, also delivers natural gas service.  At year-end 2011, NVE served approximately 1.2 million electric customers, of which 840,000 electric customers primarily in Las Vegas, North Las Vegas, Henderson and adjoining areas were served by NPC, and approximately 323,000 electric customers in an approximate 50,000 square mile area of western, central and northeastern Nevada, including the cities of Reno, Sparks, Carson City, and Elko were served by SPPC.  Additionally, SPPC provided natural gas service to approximately 152,000 customers in an area of about 800 square miles in Nevada’s Reno/Sparks area.

Major industries served by the Utilities include gaming/recreation, mining, warehousing/manufacturing and 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.

NPC and SPPC service territories are as follows:

Beginning in 2006, the Utilities embarked on a three part energy strategy to manage resources against their load by encouraging energy efficiency and conservation programs, the purchase and development of renewable energy projects, construction of generating facilities and expanding transmission capability in an effort to reduce their reliance on purchased power.  This strategy was initiated at a time when the Utilities were experiencing high growth which required significant capital investment in order to meet customer demands and also to establish self sufficiency and energy independence by building our own generating stations.  As customer growth and demand have stabilized, the Utilities are transitioning from an emphasis on capital investment  to an emphasis on optimizing our assets and resources.  A key element in the evolution of our energy strategy will be our ability to control both operating and maintenance expense as well as capital spending.  

7

Executing the evolution of the energy strategy

The completion of the Harry Allen Generating Station marked a notable transition in the evolution of our strategy.  Outlined below is the evolution of our energy strategy:

Three Part Energy Strategy------------------------------------------------------------------------------------------------àEvolution of Energy Strategy
Increase energy efficiency, conservation	Empower customers through more focused energy efficiency programs
Expand renewable energy initiatives and investments	Pursue cost-effective renewable energy initiatives
Add new generation and transmission	Optimize generation efficiency and transmission
	Engage employees to improve processes, reduce costs and enhance performance

             Empower customers through focused energy efficiency programs

The Utilities will continue with the implementation of NV Energize which not only provides metering and customer service operating savings, but will also provide customers with better opportunities to become more energy efficient.  NVE’s traditional conservation and energy efficiency programs, which have focused on behavioral change and technology replacement, will be enhanced by the new features enabled by NV Energize.  Customers will have access to better information to help them manage their usage and select from enhanced energy efficiency options, including demand response and pricing programs.  In 2011, NVE installed approximately 695,000 smart meters in southern Nevada and expects to have 1.4 million installed statewide by the end of 2012.  The NV Energize capabilities will allow NVE to help customers implement the most cost-effective mix of energy efficiency and conservation options that will also qualify toward fulfillment of the Portfolio Standard.

           Pursue cost-effective renewable energy initiatives

NVE must strive to effectively balance the need to meet the Portfolio Standard, with the changes in load forecast and the uncertainty of renewable energy project development, either for financial or resource related reasons. While NVE is better positioned to meet this challenge based on recent renewable successes, NVE remains committed to incorporating clean, cost-effective renewable energy into its portfolio.  As part of this continued commitment, NVE will continue to seek the best and most cost effective opportunities that will benefit our state, customers and environment. Depending on its needs and continuous analysis of the existing portfolio, NVE has a number of tools available to seek renewable energy values for our customers.  These tools may include issuing requests for proposals for new renewable energy contracts, exploring opportunities to either jointly construct or develop projects using wind, geothermal and solar, undertaking additional short-term purchases from existing renewable facilities and restructuring existing renewable relationships for the benefit of our customers.

The Portfolio Standard requires a specific percentage of an electric service provider’s total retail energy sales to be obtained from renewable energy resources. Renewable resources include biomass, geothermal, solar, waterpower, wind and qualified recovered energy generation projects. In addition, the Portfolio Standard allows energy efficiency measures from qualified conservation programs to meet up to 25% of the portfolio percentage. In 2012, the Utilities are required to obtain an amount of PECs equivalent to 15% of their total retail energy from renewables. Currently, the Portfolio Standard increases to 18% for 2013 and 2014, to 20% in 2015, after which it increases to 22% for the years 2020 through 2024, and to 25% for 2025 and beyond. Moreover, not less than 5% of the total Portfolio Standard must be satisfied from solar resources until 2016 when a minimum of 6% must be solar.

The Utilities acquire PECs through competitively-priced purchase power contracts, investments in renewable generating facilities and DSM programs.  NVE seeks to meet the standard using the most cost-effective means for our customers and to pursue the best-value options that are available to the Utilities.  In addition to the foregoing, this may also include economical short-term purchases of PECs (usually from outside of Nevada) to fulfill projected shortfalls due to the attrition or timing of development of renewable energy projects, weather variability or other supplier issues.

Optimize generation efficiency and transmission facilities

Since 2006, when NVE began its energy independence initiative, we have added over 3,800 MWs (nominally rated) of internal generation and, with the completion of Harry Allen Generating Station, NVE may obtain approximately 80% of its energy from internal generation.  In 2012, NVE’s management will continue to strive to optimize the Utilities’ energy portfolio in order to meet load obligations in a cost effective and reliable manner.  In addition, to the extent the Utilities have the economical opportunity to sell excess capacity or energy, they may enter into such transactions to reduce overall energy costs.  NVE anticipates it will have sufficient resources to meet its forecasted load requirements for 2012.  However, resource adequacy could be affected by a number of factors, including the unplanned retirement of generating stations, plant outages, the timing of commercial operation of renewable energy projects and associated purchase power agreements, customer behavior with respect to energy efficiency and conservation programs, and environmental regulations which may limit our ability to operate certain generating units.

8

NVE will continue with the construction of the ON Line which will enable us to optimize our transmission capabilities.  Upon completion, the ON Line will connect NVE’s southern and northern service territories and, pending certain state and federal regulatory approvals, will provide the ability to jointly dispatch energy throughout the state and provide access to renewable energy resources in parts of northern and eastern Nevada, which will enhance NVE’s ability to manage its Portfolio Standard, discussed above, and optimize its generating facilities.

ON Line is Phase 1 of a Joint Project between the Utilities and GBT-South.  The Joint Project consists of two phases.  In Phase 1 of the Joint Project, the parties would complete construction of a 500 kV interconnection between the Robinson Summit substation on the SPPC system and the Harry Allen substation on the NPC system.  The Utilities own a 25% interest in ON Line and have entered into a TUA with GBT-South for its 75% interest in ON Line. The Utilities’ 25% interest in ON Line, which approximates $127 million, will be allocated 95% and 5% to NPC and SPPC, respectively.  The Utilities will have rights to 100% of the capacity of ON Line, which is estimated to be approximately 600 MW.  If GBT elects to construct Phase 2, it would construct two additional transmission segments at either end of ON Line: one extending from Robinson Summit north to Midpoint, Idaho, and the other commencing at the Harry Allen substation and interconnecting south to the Eldorado substation.  GBT would pay for and own 100% of Phase 2 facilities.  However, NPC and SPPC would have rights to additional transmission capacity from Midpoint to Eldorado (for a total of approximately 760 MW based on a rating of 2,000 MW for the complete path).

In February 2012, NVE announced ON Line will be delayed by at least three months.  ON Line was previously expected to be in service by December 31, 2012.   The delay is attributed to addressing recent wind-related damage sustained by some of the tower structures.  As a result of the damage and as a precautionary measure, the ON Line owners have directed construction crews to lay down certain existing tower structures and cease erection of further tower structures until the owners have completed an assessment of the situation.  Other construction activities that are focused on safety and are unrelated to the wind-damage are continuing while the owners work to resolve and repair the wind-related damage, ascertain the root causes of the damage, and otherwise determine what project modifications will be necessary to ensure project safety and reliability.  As a result, NVE is also delaying the merger application of the Utilities.

Engage employees to improve processes, reduce costs and enhance performance

The Utilities will continue to control operating and maintenance and capital costs through diligent review and process improvement initiatives by providing appropriate tools to our employees to find ways to reduce costs, improve processes, and enhance performance.  This is particularly important at a time when customer growth is low.  Going forward this will continue to be an over-arching theme of the evolution of our energy strategy.  Our goal is to maintain, reduce, or eliminate upward pressure on our customers’ prices while always delivering safe and reliable energy and assure compliance with all laws and regulations.

Business and Competitive Environment

   Operations

NPC and SPPC Electric

The Utilities are charged with meeting the energy needs of Nevada.  Revenues are impacted by rate changes, cost of fuel and purchased power, seasonal or atypical weather and customer use.  The Utilities’ electric peak demand occurs in the summer.  Therefore, the Utilities’ revenues and associated expenses are not incurred or generated evenly throughout the year.

            To serve their customer base, the Utilities generate electricity and purchase power in accordance with an ESP, as discussed in more detail later in this section, under Energy Supply.

       SPPC Gas

The Gas LDC is responsible for providing natural gas to residential, commercial and industrial customers.  SPPC is well connected with several major gas producing regions and gas transportation systems into northern Nevada.  SPPC’s gas distribution system receives gas supplies from two interstate natural gas pipelines, the Paiute Pipeline Company and the Tuscarora Gas Transmission Company.  In addition, SPPC has contracted for natural gas storage services to supplement firm and spot market purchases.

9

      Regulatory Environment

The FERC and PUCN regulate portions of the Utilities’ accounting practices and electricity and natural gas rates.  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 buy transportation for natural gas.  The PUCN has authority over rates charged to retail customers, the issuance of securities by the Utilities and transactions with affiliated parties.

           Nevada state regulations require the Utilities to file electric GRCs every three years with the PUCN to adjust rates, based primarily on cost of service and return on investment.  Nevada state regulations also require the Utilities to file annual DEAA applications to either recover or refund electric 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, the Utilities may file to reset BTERs quarterly, based on the last 12 months fuel and purchased power costs.  Moreover, in 2010, the PUCN adopted regulations authorizing an electric utility to recover an amount from its customers that is attributable to the measurable and verifiable effects associated with the Utilities’ implementation of energy efficiency and conservation programs approved by the PUCN.  In addition, the regulation approved the transition of the recovery of energy efficiency program costs from general rates (filed every three years to recover through independent annual rate filings).  The Utilities filed their first rate case with respect to this new regulation, referred to by the Utilities as the EEIR and EEPR, in October 2010 and will continue to file rate cases annually in March, thereafter.  In 2011, the Legislature passed Assembly Bill 215 which allows an electric or gas utility that adjusts its BTER on a quarterly basis to request PUCN approval to make quarterly changes to its DEAA rate if the request is in the public interest.  The Utilities will still be required to file an annual DEAA case to review costs for prudency and reasonableness, and if any costs are disallowed on such grounds, the disallowance will be incorporated into the next subsequent quarterly rate change.  The PUCN approved the Utilities filings to implement quarterly changes to their DEAA rates.  See Note 3, Regulatory Actions, of the Notes to Financial Statements, for further discussion on the various rate cases.

The PUCN regulations also require a Gas Supply Report as well as a Gas Informational Report to be filed annually.  SPPC may also file gas GRCs to adjust gas division rates including cost of service and return on investment.  Rate cases are discussed in more detail in Note 3, Regulatory Actions, of the Notes to Financial Statements.

   Competition

      NPC and SPPC Electric

The Utilities operate under certificates of public convenience and necessity as regulated by the PUCN, as well as franchise agreements with local governments in their respective operating areas.  Under Nevada state law, commercial customers with an average annual load of 1 MW or more may 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 or SPPC, the departure must not burden the Utilities with increased costs or cause any remaining customers to pay increased costs, and the departing customers must pay their portion of any deferred energy balances.  The PUCN adopted regulations prescribing the criteria that will be used to determine if there will be negative impacts to remaining customers or to the Utilities.  Customers wishing to choose a new supplier must provide 180-day notice to NPC or SPPC.  The Utilities would continue to provide transmission, distribution, metering, and billing services to such customers.  

Currently, there are no material applications pending with the PUCN to exit the system in NPC’s or SPPC’s service territory.  In the event a customer were to exit the system, we do not expect the departure to have a material impact on the Utilities net income.

   SPPC Gas

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 under the Transportation Tariff.  As of January 1, 2012, there were 17 large customers securing their own supplies.  These customers have a combined firm distribution load of approximately 5,982 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

In 2011, NPC’s and SPPC’s electric revenues were approximately $2.1 billion and $716.4 million, respectively.  SPPC’s natural gas business accounted for approximately $172.5 million in 2011 operating revenues or 19.4% of SPPC’s total revenues.  NPC’s peak electric load decreased at an average annual growth rate of 0.3% over the past five years, while SPPC’s decreased by 2.3%.  In 2011, NPC’s and SPPC’s electric system peaks were 5,539 MW and 1,513 MW, respectively, compared to 5,604 MW and 1,611 MW, respectively, in 2010.  NPC’s total retail electric MWh sales have decreased at an average annual growth rate of 0.3% over the past five years; and total retail electric MWh sales declined slightly in 2011 compared to 2010 as discussed below.  SPPC’s total retail electric MWh sales have decreased at an average annual growth rate of 2.6% over the past five years primarily due to a decrease in mining customers discussed below.

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

	MWh Sales
	2011					2010					2009
	MWh		% of Total			MWh		% of Total			MWh		% of Total
Retail:
Residential		8,523,321		41.1	%		8,684,386		41.6	%		8,893,542		41.8	%
Commercial & Industrial:
Gaming/Recreation/Restaurants		3,171,853		15.3	%		3,215,710		15.4	%		3,392,658		16.0	%
All Other Retail		8,834,305		42.5	%		8,742,166		41.9	%		8,670,931		40.8	%
Total Retail		20,529,479		98.9	%		20,642,262		98.9	%		20,957,131		98.6	%
Wholesale		-		-			1,262		-			69,915		0.3	%
Sales to Public Authorities		225,518		1.1	%		231,072		1.1	%		240,302		1.1	%
Total		20,754,997		100	%		20,874,596		100	%		21,267,348		100	%

Total retail MWh sales decreased approximately 0.5% in 2011 from 2010, primarily due to a decrease in customer usage due to milder summer weather in 2011 and conservation programs, partially offset by a slight increase in customers.  NPC’s average residential and commercial customers increased by 1.1% and 0.4%, respectively, while average industrial customers decreased by 1.9%.

Although the unemployment rate remains above the national average in Las Vegas, the unemployment rate has improved significantly over the past year.  Additionally, the economy in Southern Nevada has begun to see another sign of improvement, as visitor volumes begin to return to levels seen in 2007 before the recession.  However, population growth is likely to be moderate until the economy strengthens both locally and nationally.

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

	MWh Sales
	2011					2010					2009
	MWh		% of Total			MWh		% of Total			MWh		% of Total
Retail:
Residential		2,231,107		26.9	%		2,465,049		30.4	%		2,502,537		30.5	%
Commercial & Industrial:
Mining		1,578,195		19.0	%		1,506,866		18.6	%		1,405,087		17.2	%
All Other Retail		3,838,649		46.3	%		4,108,834		50.6	%		4,254,749		51.9	%
Total Retail		7,647,951		92.2	%		8,080,749		99.6	%		8,162,373		99.6	%
Wholesale		631,569		7.6	%		13,797		0.2	%		14,993		0.2	%
Sales to Public Authorities		16,061		0.2	%		16,459		0.2	%		16,535		0.2	%
Total		8,295,581		100	%		8,111,005		100	%		8,193,901		100	%

Total retail MWh sales decreased approximately 5.4% in 2011 from 2010, primarily due to the sale of California Assets on January 1, 2011.  Excluding California, retail sales increased 1.5% in 2011, which are now reported in wholesale MWh sales.  Contributing to the increase in MWhs was a 2.0% increase in residential usage primarily due to colder weather, and a 4.8% increase in

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mining usage in 2011.  Excluding California, SPPC’s average number of residential and commercial customers increased by 0.4% and 0.9%, respectively, while industrial customers decreased by 1.8%.

Mining is a leading industry in northern Nevada and comprises one of SPPC’s largest classes of customers.  In 2009, SPPC saw a decline in usage of mining customers as they switched to DOS service; however, in 2010 and 2011, mining customer usage increased as a result of a mining customer who restored operations in October 2009 and an increase in mining activity due to the elevated price of gold.

 Similar to southern Nevada, northern Nevada is seeing modest improvement in economic indicators and the economic recovery in the North is expected to be slow and dependent on the economy of neighboring states in addition to the national economy.

SPPC has long-term electric service agreements with eight of its largest commercial and industrial customers, with yearly revenues under these agreements totaling approximately $61 million.  For 2011, this represented approximately 8.5% of SPPC’s electric operating revenues of approximately $716.4 million.  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.

   Heating Degree Days (HDD) and Cooling Degree Days (CDD)

MWh usage may be affected by the change in heating degree or cooling degree days in a given year.  A Degree Day indicates how far that day's average temperature departed from 65° F.  HDDs measure heating energy demand and indicates how far the average temperature fell below 65° F.  CDDs measure cooling energy demand and indicates how far the temperature averaged above 65° F.  For example, if a location had a mean temperature of 60° F on day 1 and 80° F on day 2, there would be 5 HDDs (65 minus 60) and 0 CDDs for day 1.  In contrast, there would be 0 HDDs and 15 CDDs (80 minus 65) for day 2.

The following table shows the heating degree days and cooling degree days within NPC’s and SPPC’s service territories for each of the last three years:

		2011		2010		2009
			Change From		Change From
		Amount	Prior Year	Amount	Prior Year	Amount
NPC
	HDD	2,040	7.7%	1,895	0.3%	1,889
	CDD	3,540	(3.0)%	3,648	(3.7)%	3,790
SPPC
	HDD	5,112	5.0%	4,868	(2.7)%	5,004
	CDD	964	4.6%	922	(13.8)%	1,069
Data Source: National Weather Service

Demand

   Load and Resources Forecast

NPC’s peak electric demand decreased in 2011 to 5,539MWs from 5,604 MWs in 2010.  SPPC’s peak electric demand decreased in 2011 to 1,513 MWs from 1,611 MWs in 2010.  Variations in energy usage occur as a result of varying weather conditions, economic conditions, and other energy usage behaviors, such as conservation efforts by our customers.  These variations necessitate 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.

The Utilities plan to meet their customers’ needs through a combination of company-owned-generation and purchased power.  See the Generation section and Purchased Power section below for details of the Utilities’ generation and contracts for purchased power.  Remaining needs will be met through power purchases through RFPs or short-term purchases.  As shown in the tables below, the Utilities have sufficient resources to meet anticipated customer requirements.  However, resource adequacy may be affected by a variety of factors including, but not limited to, the unplanned retirement of generating stations, the timing or

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achievement of commercial operation with respect to renewable energy power projects not yet commercially operable, as well as the intermittent reliability of renewable energy resources, customer behavior with respect to energy efficiency and conservation programs and environmental regulations which may limit our ability to operate certain generating units.  Resource adequacy provides the Utilities the ability to maintain a reliable supply of energy; however as discussed under Resource Optimization, to the extent the resources are not needed, the Utilities will attempt to sell their additional availability in an effort to reduce costs.

Below are tables as of December 31, 2011, summarizing the forecasted summer electric capacity requirement and resource needs of the Utilities after consideration of energy conservation programs (assuming no curtailment of supply or load, and normal weather conditions) and the completion of ON Line, as discussed in the Transmission section later, subject to change:

	Forecasted Electric Capacity Requirements and Resources (MW)
	2012			2013			2014			2015		2016
NPC
Total requirements(1)		6,257			6,089			6,115			6,191		6,285
Resources:
Company-owned  generation(2)		4,575			4,570			4,570			4,570		4,792
Contracts for power purchases		1,706			1,640			1,417			1,417		1,195
Contracts for renewable energy power purchases, not
yet commercially operable(3)		32			76			167			180		180
Total resources		6,313			6,286			6,154			6,167		6,167
Total additional required (additional resources)(4)		(56	)		(197	)		(39	)		24		118

(1)	Includes projected system peak load plus 12% planning reserves.  The decrease in total requirements from 2012 to 2013 is primarily due to an expected decrease in demand as a result of energy efficiency and conservation programs.
(2)	Includes 232 MWs of peaking capacity at Reid Gardner Generating Station Unit No. 4, which is co-owned with CDWR, see Item 2, Properties.
(3)	Includes long term purchase power agreements for renewable energy that are not yet commercially operable and/or may not materialize due to project delays, under performance or cancelations.
(4)	Total additional required is the difference between the total requirements and total resources.  Total additional required represents the amount needed to achieve the total requirement; conversely, additional resources represents resources in excess of the total requirement.

	Forecasted Electric Capacity Requirements and Resources (MW)
	2012			2013		2014		2015		2016
SPPC
Total requirements(1)		1,853			1,863		1,863		1,884		1,812
Resources:
Company-owned existing generation		1,519			1,519		1,466		1,466		1,383
Contracts for power purchases		407			303		303		303		303
Total resources		1,926			1,822		1,769		1,769		1,686
Total additional required (additional resources)(2)		(73	)		41		94		115		126

(1)	Includes projected system peak load plus 15% 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 total requirement; conversely, additional resources represents resources in excess of the total requirement.

  Resource Optimization

 Resource optimization entails the prudent purchase and sale of electric power, fuel and financial energy products by the Utilities.  The Utilities optimize their portfolios continuously in order to meet load obligations in a cost effective and reliable manner within transmission constraints.  The Utilities continuously monitor the resources available to meet load obligations, recognizing the uncertainty not only in system conditions, such as planned and unplanned outages of generating or transmission facilities, but also in regional energy markets organized across different commodities, locations, demand and trading timeframes.  As conditions change and new information becomes available, the Utilities optimize their portfolios as appropriate to account for changes in load, cost, volatility, reliability and other commercial or technical factors.

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Energy Supply

   Total System

NPC and SPPC Electric

The Utilities manage a portfolio of energy supply options.  The availability of alternate resources allows the Utilities to dispatch its electric generation system in a more cost-effective manner under varying operating and fuel market conditions while maintaining system integrity.  During 2011, NPC generated 69.6% of its total system requirements, purchasing the remaining 30.4% as shown below and SPPC generated 50.5% of its total electric energy requirements, purchasing the remaining 49.5% as shown below.

	2011					2010					2009
	MWh		% of Total			MWh		% of Total			MWh		% of Total
NPC
Gas Generation		11,687,714		54.1	%		11,666,152		53.6	%		12,793,249		57.8	%
Coal Generation		3,346,506		15.5	%		3,739,339		17.2	%		3,632,385		16.4	%
Total Generated		15,034,220		69.6	%		15,405,491		70.8	%		16,425,634		74.2	%
Total Purchased		6,577,339		30.4	%		6,350,795		29.2	%		5,696,555		25.8	%
Total System(1)		21,611,559		100.0	%		21,756,286		100.0	%		22,122,189		100.0	%

	2011					2010					2009
	MWh		% of Total			MWh		% of Total			MWh		% of Total
SPPC
Gas Generation		3,254,453		36.9	%		3,707,666		43.0	%		3,852,662		43.4	%
Coal Generation		1,199,121		13.6	%		1,412,875		16.3	%		1,729,466		19.5	%
Total Generated		4,453,574		50.5	%		5,120,541		59.3	%		5,582,128		62.9	%
Total Purchased		4,368,036		49.5	%		3,509,767		40.7	%		3,296,482		37.1	%
Total System(1)		8,821,610		100.0	%		8,630,308		100.0	%		8,878,610		100.0	%

(1)  Included in Total System is expected energy waste resulting from the transmission of electrical energy across power lines.

As a supplement to their own generation, the Utilities purchase spot, short-term firm, intermediate-term firm, long-term firm, and non-firm energy to meet its customer demand requirements.  The Utilities decision to purchase this energy is based on economics, mitigation of availability risk, and transmission availability.  Firm block purchases are transacted 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 the Utilities own generation, again, subject to transmission availability.  

NPC’s total system decreased 0.7% in 2011 compared to 2010.  In 2011, NPC’s total generated decreased 2.4% from 2010 while purchased power MWhs increased 3.6% compared to 2010.   SPPC’s total system increased 2.2% in 2011 compared to 2010.  In 2011, SPPC’s purchased power total MWhs increased 24.5% compared to 2010, while generation decreased 13%.  See Management’s Discussion and Analysis of Financial Condition and Results of Operations for additional information regarding the Utilities’ total system.  Also see Energy Supply, later, for discussion of the Utilities purchasing strategies.

   Generation

In 2011, NPC completed construction of a 484 MW (summer peak) combined cycle natural gas generating station at the existing Harry Allen Generating Station.Sunrise Station Units 1 & 2 (summer peak 150 MW) were retired with PUCN approval on December 31, 2011.

NPC’s generation capacity consists of a combination of 44 gas and coal generating units with a combined summer capacity of 4,343 MWs as described in Item 2, Properties.  In 2011, NPC generated 69.6% of its total system requirements. 

SPPC’s generation capacity consists of a combination of 19 gas, oil and coal generating units with a combined summer capacity of 1,519 MWs as described in Item 2, Properties.  In 2011, SPPC generated 50.5% of its total system requirements.

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   Fuel Sources

The Utilities’ 2011 fuel sources for electric generation were primarily provided by natural gas and coal.  The average costs of gas and coal, including hedging costs, for energy generation per MMBtu for the years 2007 through 2011, along with the percentage contribution to the Utilities’ total fuel sources were as follows:

NPC Electric		Average Consumption Cost & Percentage Contribution to Total Fuel
		Gas		Coal
		$/MMBtu	Percent	$/MMBtu	Percent
	2011	4.66	71.3%	2.32	28.7%
	2010	5.73	68.5%	2.21	31.5%
	2009	5.09	71.8%	2.23	28.2%
	2008	7.79	66.5%	2.17	33.5%
	2007	6.32	64.4%	1.89	35.6%

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.

In 2011, NPC transitioned from a three season ahead physical gas laddering strategy to a four season ahead physical gas laddering strategy to cover the time period beginning with summer season 2012.  NPC employs two seasonal competitive bidding processes each year.  The physical gas is procured at an appropriate industry index during the month of current delivery.  No fixed price transactions were executed during 2011. 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 utilizes a laddered strategy with respect to coal supply and has two long term coal contracts with Arch Coal Sales Company and one with Andalex Resources, Inc.  These contracts represent 90% of projected coal requirements for 2012, 68% for 2013 and 12% for 2014.

As of December 31, 2011, NPC’s Reid Gardner Generating Station coal inventory level was 237,970 tons, or approximately 70 days of consumption at 100% capacity.

A take or pay transportation services contract with the Union Pacific Railroad Company provides for deliveries from the Provo, Utah interchange, as well as various mines in Utah, Colorado and Wyoming, to the Reid Gardner Generating Station in Moapa, Nevada extends through 2014.

Coal for the Navajo Generating Station, which is jointly owned by six entities and operated by Salt River Project, is obtained under a Coal Sales Agreement with Peabody Coal Company that extends through 2019. Coal is supplied from surface mining operations conducted on Navajo Nation and Hopi Tribe reservation lands on the Black Mesa in Arizona.

To secure gas supplies for the generating stations that NPC either owns or has under long-term contract (tolling arrangements), NPC contracted for firm winter, summer, and annual gas supplies with numerous domestic suppliers.  In 2011, for generating stations located in NPC’s control area, seasonal and monthly gas supply net purchases averaged approximately 268,428 Dth per day, with the winter period contracts averaging approximately 219,492 Dth per day, and the summer period contracts averaging approximately 302,958 Dth per day.

Listed below is NPC’s transportation portfolio as of December 31, 2011:

Firm Transportation Capacity		Dth per day firm	Term
	Kern River	50,000	Summer
	Kern River	374,925	Annual
	Kern River (Backhaul)	134,000	Annual
	Southwest Gas	5,200	Summer
	Southwest Gas	45,000	Annual
	Southwest Gas	288,000	Annual

Domestic gas supplies are accessed utilizing gas transport service from Kern River directly to Lenzie, Silverhawk, Higgins, Harry Allen, and Reid Gardner (for start-up only) Generating Stations or from Kern River to SWG and then to LV Cogen 1, LV Cogen 2, Clark, and Sunpeak Generating Stations.

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SPPC Electric		Average Consumption Cost & Percentage Contribution to Total Fuel
		Gas		Coal
		$/MMBtu	Percent	$/MMBtu	Percent
	2011	5.60	66.5%	2.73	33.5%
	2010	6.54	66.4%	2.32	33.6%
	2009	7.98	63.5%	2.12	36.5%
	2008	8.95	57.6%	2.09	42.4%
	2007	8.34	58.0%	1.93	42.0%

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.

Similar to NPC discussed above, in 2011, SPPC transitioned to a four season ahead laddering strategy to procure gas.  No fixed price transactions were executed during 2011.  Therefore, 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 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.  These contracts represent 100% of the Valmy Generating Station’s projected coal requirements in 2012, 65% for 2013, 50% for 2014, and 40% for 2015.

A Transportation Services Contract with Union Pacific Railroad Company that provides for deliveries from the Provo, Utah interchange, as well as various mines in Utah, Colorado and Wyoming, to the Valmy Generating Station in Valmy, Nevada extends through 2014.

As of December 31, 2011, the coal inventory level at Valmy Generating Station was 359,066 tons or approximately 132 days of consumption at 100% capacity.

      SPPC Gas

SPPC plans its gas transportation and supply to serve a demand that would occur if the average of the high and low temperatures for a given day drops to negative five degrees Fahrenheit, which is estimated to be 190,735 Dth per day for the winter of 2011/2012.

To secure gas supplies for the generating stations and the LDC, SPPC contracted for firm winter, summer, and annual gas supplies with numerous Canadian and domestic suppliers using a four season ahead laddering strategy discussed above.  In 2011, seasonal and monthly gas supply net purchases averaged approximately 114,617 Dth per day with the winter period contracts averaging approximately 136,169 Dth per day, and the summer period contracts averaging approximately 99,409 Dth per day.

SPPC’s firm natural gas supply is supplemented with natural gas storage services and supplies from Northwest’s 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.  In an effort to optimize the value of SPPC’s assets, from November 2010 through October 2011 and November 2011 through October 2012, SPPC entered into one year agreements whereby the respective counterparty acquired the rights to the Jackson Prairie storage facility and some of SPPC’s gas transport assets during the term of the agreement with SPPC retaining the ability to call on the resources, subject to limitations.

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 during the winter 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.

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Listed below are the current gas transportation and storage service agreements:

Firm Transportation Capacity	Dth per day firm	Term
Northwest	68,696	Annual
Paiute	68,696	Winter
Paiute	61,044	Summer
Paiute	23,000	Winter (Storage related)
AB Nova (Canadian Pipeline)	130,319	Annual
BC System (Canadian Pipeline)	128,932	Annual
GTN	140,169	Winter
GTN	79,899	Summer
Tuscarora	172,823	Annual
Storage Capacity
Northwest	281,242	Storage Capacity (Jackson Prairie)
	12,687	Daily Withdrawal Capacity
Paiute	303,604	Storage Capacity
	23,000	Daily Withdrawal Capacity

Canadian gas supplies are accessed utilizing gas transport service on AB Nova to BC System to GTN to Tuscarora and then directly to Tracy Generating Station.  Domestic gas supplies are also accessed utilizing gas transport on Northwest to Paiute and then directly to Ft. Churchill and Tracy Generating Stations.  The LDC is dual sourced from the pipelines listed above.

Total LDC supply requirements in 2011 and 2010 were 16.7 million Dth and 14.7 million Dth, respectively.  Electric generating fuel requirements for 2011 and 2010 were 25.9 million Dth and 29.0 million Dth, respectively.

   Water Supply

      NPC and SPPC

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 and recycled water.  Although there are current drought conditions in the Las Vegas area, water resources for most of these facilities rely on regional aquifers and recycled water that are not closely connected to transient drought conditions. 

   Purchased Power

            Under the guidelines set forth in the respective ESPs, NPC and SPPC continue to manage a diverse portfolio of contracted and spot market supplies, as well as its own generation resources, with the objective of minimizing its net average system operating costs.  During 2011, NPC and SPPC purchased approximately 30.4% and 49.5%, respectively, of their total electric energy requirements.

       NPC Electric

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

NPC has entered into long-term purchase power contracts (3 or more years) with suppliers that generate electricity utilizing gas and renewable resource facilities with a total nameplate capacity of approximately 2,481 MW and contract termination dates ranging from 2013 to 2038.  Included in these contracts are approximately 886 MW of nameplate capacity of renewable energy of which approximately 649 MW of nameplate capacity are under development or construction and not currently available.  The PECs from renewable resource facilities are used towards compliance with the Portfolio Standard.  Energy from some of these contracts is delivered and sold to SPPC through intercompany related purchase power contracts due to the resource location and transmission constraints; however, NPC retains the PECs associated with such contracts.  The completion of ON Line will give NPC the ability to take delivery of the energy from these contracts.

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NPC is a member of the SRSG and the WSPP.  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 investment grade credit rating over the last several years, this was not a significant factor in 2011.

      SPPC Electric

SPPC purchases both forward firm energy and spot market energy based on economics, regulatory requirements, operating reserve margins, and unit availability.  SPPC seeks to manage its loads efficiently by utilizing its generation resources and long-term purchase power contracts in conjunction with buying and selling opportunities in the market.

SPPC has entered into long-term purchase power contracts (3 or more years) with suppliers that generate electricity utilizing coal and renewable resource facilities, with a total nameplate capacity of approximately 400 MW and contract termination dates ranging from 2016 to 2039.  Included in these contracts are approximately 210 MW of nameplate capacity of renewable energy of which approximately 20 MW of nameplate capacity are under construction and not currently available.  The PECs from renewable resource facilities are used towards compliance with the Portfolio Standard.  Energy from one of these contracts is delivered and sold to NPC through an intercompany related purchase power contract due to the resource location and transmission constraints; however, SPPC retains the PECs associated with this contract.  The completion of ON Line will give SPPC the ability to take delivery of the energy from these contracts.

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 resources 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 investment grade credit rating over the last several years, this was not a significant factor in 2011.

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.

The Utilities’ electric transmission systems are part of the Western Interconnection, the regional grid in the west.  The Western Interconnection includes the interconnected transmission systems of fourteen western states, two Canadian provinces and the parts of Mexico that make up the Western Electricity Coordinating Council (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 for delivery to the NPC distribution system and provides interconnections with the balancing authority areas of Western Area Power Administration, Los Angeles Department of Water and Power, Southern California Edison, and PacifiCorp. 

SPPC’s transmission system links generating units within the SPPC balancing authority area for delivery to the SPPC distribution system and provides interconnections with the balancing authority areas 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.  

The service territories of NPC and SPPC are not directly interconnected at present; however, in February 2011, NVE and the Utilities entered into an agreement with Great Basin Transmission (GBT) to construct ON Line, which will interconnect the systems for the first time.

Under the NERC guidelines, the Utilities are Balancing Authorities, Transmission Operators, and Transmission Owners 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 energy 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

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maintains transmission facilities.  The Utilities also schedule power deliveries over their transmission systems and maintain reliability through their operations and maintenance practices and by verifying that customers are matching loads with resources.

NPC and SPPC plan, build, and operate transmission systems that delivered 21,611,559 MWh and 8,821,610 MWh of electricity to customers, respectively, in their Balancing Authority Areas in 2011.  The NPC system handled a system peak load of 5,539 MW in 2011 through approximately 1,724miles of transmission lines and other transmission facilities ranging from 60 kV to 500 kV.  The SPPC system handled a system peak load of 1,513 MW in 2011 through 1,987 miles of transmission lines and other facilities ranging from 60 kV to 345 kV.  The Utilities process 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. 

   Transmission Regulatory Environment

Transmission for the Utilities’ bundled retail customers is subject to the jurisdiction of the PUCN for rate making purposes.  The Utilities provide cost based wholesale and retail access transmission services under the terms of a FERC approved OATT.  In accordance with the OATT, the Utilities offer 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 NVE provides for NVE’s bundled retail customers).

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

   The One Nevada Transmission Line (“ON Line”)

As discussed earlier, the Utilities are currently constructing ON Line which would provide a 500 kV interconnection between a new Robinson Summit substation on the SPPC system and the Harry Allen substation on the NPC system.  ON Line would further provide an interconnection between NPC and SPPC’s system and enhance our ability to optimize the use of our generation and transmission facilities in alignment with the evolution of our energy strategy.

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Regional Planning

The Utilities are members 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.  The Subregional Transmission Planning Committee was established to provide coordinated transmission planning across the WestConnect footprint, including the Southwest Area Transmission Group, in which NPC participates, and the Sierra Subregional Planning Group, in which SPPC participates.

FERC issued Order 1000 on July 21, 2011.  Order 1000 establishes basic requirements for transmission planning on a regional and interregional basis. The Utilities are currently evaluating Order 1000 and participating in various regional processes in order to comply with the order.

Integrated Resource Plan

The Utilities are required to file IRPs every three years, and as necessary, may file amendments to their IRPs.  The IRPs are prepared in compliance with Nevada laws and regulations and cover a 20-year period.  The IRPs develop a comprehensive, integrated plan that considers customer energy requirements and propose the resources to meet those requirements in a manner that is consistent with prevailing market fundamentals.  The ultimate goal of the IRPs is to balance the objectives of minimizing costs and reducing volatility while reliably meeting the electric needs of NPC’s and SPPC’s customers.  The ESP, discussed in detail later, operates in conjunction with the IRP.  It serves as a guide for near-term execution and fulfillment of energy needs.

    NPC Electric

In July 2010, the PUCN issued its order on NPC’s 2009 IRP, which included the following significant items:

• Approval to jointly develop ON Line with GBT, an affiliate of LS Power, discussed earlier in the Transmission section.  The PUCN also approved NPC’s self-build option for ON Line if the companies and GBT were unable to reach agreement.  However, in February 2011, the Utilities and GBT finalized the agreement to jointly construct ON Line.

• Granted NPC’s request for critical facility designation for its incremental operating and maintenance costs for ON Line.

• Approval of NV Energize of approximately $95 million and $69 million (excluding AFUDC) for NPC and SPPC, respectively, which was contingent on successfully obtaining a grant of $138 million in federal funds from the DOE to co-fund the project.  A total grant of $139 million was obtained from the DOE in September 2010.

• Approval to establish a regulatory asset for stranded non-advanced metering infrastructure electric meter costs related to NV Energize.

• Approval of various DSM programs to increase energy efficiency and conservation programs totaling approximately $209.9 million over the three year action plan.

• Accepted NPC’s proposal to postpone the EEC indefinitely, but ordered NPC to resubmit the request as a part of its next triennial IRP filing in July 2012.  In February 2011, NVE and the Utilities canceled plans to construct the EEC.

• Approval of the long-term load forecast and the three-year forecast.

   SPPC Electric

In July 2010, as required by Nevada law, SPPC filed its 2010 triennial IRP with the PUCN.  In December 2010, the PUCN issued its order on SPPC’s IRP, which included the following significant items:

• Approval of the long-term load forecast and the three-year forecast.

• A finding that the sale of the California Assets to CalPeco is in the public interest of Nevada, authorizing and accepting the accounting adjustments and ratemaking treatment proposed by SPPC and authorizing entry into and performing transactions necessary to accomplish the sale of the California Assets to CalPeco. The sale of the California Assets was completed in January 2011.  See Note 16, Assets Held for Sale, in the Notes to Financial Statements.

• Authority to modify retirement dates for eleven remote generation facilities and retire and decommission ten remote generation facilities and to accumulate the costs of decommissioning and remediating the remote generation sites in separate regulatory assets subaccounts for recovery in a future GRC proceeding.

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• Affirmed the funding level for a transmission project approved in SPPC’s 2007 IRP filing of approximately $30 million.

• Approval of DSM programs scopes, budgets, timetables and measures and the Demand Side Plan totaling approximately $36 million.

Energy Supply Planning

     General

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 (e.g., physical and economic dispatch).

There is the potential for continued price volatility in each Utility’s service territory, particularly during peak periods.  Too great a dependence on generation from the wholesale market can lead to power price volatilities depending on available power supply and prevailing 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.

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

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

          2.          The PUCN-approved ESP 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 of longer than three years, PUCN approval is required.

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

• Maintaining an ESP that minimizes supply costs and retail price volatility and maximizes reliability of supply over the term of the ESP;

• 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.

Beginning in October 2009, the Utilities suspended their hedging programs; however, prior to the suspension, it was the general policy of the Utilities to purchase hedges three seasons ahead.  As a result certain hedges entered into prior to the suspension in October 2009, did not terminate until 2011.  As of November 2011, all hedging transactions have expired or terminated and the Utilities remain unhedged.  If deemed prudent, the Utilities may still purchase hedging instruments in the event circumstances occur that may have the potential to increase the cost of fuel and purchased power.

   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

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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 CEO and the EROC.

Intermediate Term ESPs

The Utilities update their intermediate term ESPs annually. In July 2011, NPC filed its ESP update for the period 2012, and in September 2011, SPPC filed its ESP update for the period 2012-2013. Both plans were approved by the EROC and the CEO prior to submission to the PUCN.

The summer needs of 2012 for both SPPC and NPC will be met through a portfolio mix consisting of self-generation, forward contracts for power and peaking and seasonal capacity, or synthetic tolling based contracts (e.g., power prices indexed to gas prices) while striving to provide the lowest cost energy within reliability and transmission constraints.

Long Term Purchased Power Activities

           The Utilities update their respective planning documents (IRPs, ESPs, and the Portfolio Standard Annual Report) on a regular and as needed basis to determine their energy and PEC needs.   When the planning documents call for long term purchased power and/or PEC agreements, RFPs are issued, bids are evaluated, and contracts are executed with the successful bidders.  Contracts requiring PUCN approval are submitted to the PUCN as part of the IRP or an amendment to an IRP.  Long term purchased power contracts are discussed in more detail earlier, under Purchased Power.

Short-Term Resource Optimization Strategy

The Utilities’ short-term resource optimization strategy involves both day-ahead 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 in the wholesale market if opportunities are available and the market price is lower than the production costs, while any deficient capacity or energy position is filled by either buying on the spot market or utilizing available generating capacity.

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

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

Construction Program

The Utilities construction programs 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 Nevada, regulatory considerations and impact to customers, the Utilities ability to raise necessary capital, and changes in environmental regulations.  Under the Utilities’ franchise agreements, they are obligated to provide a safe and reliable source of energy to their customers.  Capital construction expenditures and estimates are reflective of the Utilities’ obligation to serve their customer base.

Gross construction expenditures for 2011, including AFUDC debt, net salvage and CIAC, were $475.1 million and $145.4 million for NPC and SPPC, respectively, and for the period 2007 through 2011, were $3.7 billion and $1.1 billion, respectively.  Cash

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requirements related to construction projects in 2011 for NPC and SPPC were $387.5 million and $134.7 million, respectively. Future estimated construction expenditures are as follows (dollars in thousands):

	2012		2013		2014		2015		2016
NPC
Electric Facilities:
Generation	$	109,207	$	148,464	$	87,763	$	69,254	$	72,046
Distribution		70,800		69,168		67,172		68,074		70,515
Transmission		79,204		31,359		63,285		43,166		34,218
Other		51,806		34,194		48,996		61,284		47,568
Total	$	311,017	$	283,185	$	267,216	$	241,778	$	224,347

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

	2012			2013			2014			2015			2016
Construction Expenditures	$	311,017		$	283,185		$	267,216		$	241,778		$	224,347
AFUDC		(8,091	)		(7,353	)		(6,775	)		(7,754	)		(11,437	)
Net Salvage / Cost of Removal		3,292			3,090			2,917			2,621			2,384
Net Customer Advances and CIAC		(25,175	)		(15,090	)		(14,342	)		(12,887	)		(11,724	)
Total Cash Requirements	$	281,043		$	263,832		$	249,016		$	223,758		$	203,570

SPPC	2012		2013		2014		2015		2016
Electric Facilities:
Generation	$	28,592	$	64,568	$	52,849	$	28,315	$	28,577
Distribution		64,155		38,963		42,812		45,982		42,797
Transmission		31,529		14,906		33,448		4,466		3,015
Other		19,857		21,889		23,748		20,659		21,447
Total		144,133		140,326		152,857		99,422		95,836
Gas Facilities:
Distribution		26,468		12,486		12,428		12,671		12,788
Other		272		275		277		282		285
Total		26,740		12,761		12,705		12,953		13,073
Common Facilities		26,127		11,274		10,786		10,997		11,099
Total	$	197,000	$	164,361	$	176,348	$	123,372	$	120,008

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

	2012			2013			2014			2015			2016
Construction Expenditures	$	197,000		$	164,361		$	176,348		$	123,372		$	120,008
AFUDC		(6,297	)		(5,243	)		(7,561	)		(5,238	)		(3,871	)
Net Salvage / Cost of Removal		4,914			4,046			4,324			3,026			2,975
Net Customer Advances and CIAC		(7,215	)		(8,041	)		(7,321	)		(5,124	)		(5,037	)
Total Cash Requirements	$	188,402		$	155,123		$	165,790		$	116,036		$	114,075

Major projects included in the 5 year estimated construction expenditures above are as follows:

In 2010, the PUCN approved the NV Energize project. The project includes the deployment of a fully-integrated advanced metering infrastructure, a meter data management system, and a demand response management system.  Of the total $303 million dollars in projected costs, $139 million will be provided by the U.S. Department of Energy through its Smart Grid Investment Grant Program. The remaining $164 million will be provided by NPC and SPPC 70% and 30%, respectively.

In 2010, the PUCN approved the construction of ON Line project as discussed previously under the Transmission section.  As a joint owner of ON Line, NVE will be responsible for 25% of the projected costs of the $509 million project. The $127 million will be allocated to NPC and SPPC 95% and 5%, respectively.

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NPC is a party to a joint development agreement with China Mountain Wind LLC, an affiliate of RES Americas, Inc., in connection with the China Mountain Wind Project.  Under the joint development agreement, NPC participates in the permitting and development of the China Mountain Wind Project near the Nevada-Idaho border and has the opportunity to participate in the construction and ownership of the project.  The PUCN has not yet approved the project, and as such, it has not been included in the above tables.

ENVIRONMENTAL (NVE, NPC AND SPPC)

As with other utilities, NPC and SPPC are subject to various environmental laws and regulations enforced by federal, state and local authorities.  The EPA, NDEP, the Southern Nevada Health District, and the Clark County Department of Air Quality and Environmental Management administer regulations involving air quality, water pollution, solid, and hazardous and toxic waste.  Nevada’s Utility Environmental Protection Act also requires the Utilities to obtain approval of the PUCN prior to construction of major utility, generation or transmission facilities.  

From the beginning phases of siting and development to the ongoing operation of existing or new electric generating, transmission and distribution facilities, our activities involve compliance with diverse laws and regulations which address noise, emissions, impacts to air and water, protected and cultural resources, and solid, hazardous, and toxic waste. Our activities often require complex and lengthy processes as we obtain approvals, permits or licenses for new, existing or modified facilities. Additionally, the use and handling of various chemicals or hazardous materials (including wastes) requires release prevention plans and emergency response procedures. As new laws or regulations are promulgated, we assess their applicability and implement the necessary modifications to our facilities or our operations to ensure complete compliance.  The most significant environmental laws and regulations, both in effect and proposed, that could impact NPC and SPPC are discussed below:

Federal Environmental Laws, Regulations and Regulatory Initiatives

   Clean Air Standards

The Clean Air Act (CAA) 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 CAA 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 CAA to target specific emissions from electric utility generating plants.  The EPA has also proposed potential regulations associated with these types of emissions.  If enacted, this legislation and/or regulations could require reductions in emissions of NOX, SO2, mercury and/or other pollutants.  The CAA programs which most directly affect the State of Nevada and NVE’s electric generating facilities are described below:

      Mercury and Air Toxics Standards (MATS)

In December 2011, the EPA signed for publication in the Federal Registera final rule regulating hazardous air pollutant (HAP) emissions from coal- and oil-fired electric utility steam generating units.  The rule, referred to as the MATS rule requires coal- and oil-fired electric utility steam generating units to meet HAP emission standards reflecting the application of the maximum achievable control technology (MACT). The rule becomes effective 60 days after publication in the Federal Register.Compliance with the MATS emission standards is required within 3 years of publication of the rule in the Federal Register. However, if an existing source is unable to comply within 3 years, the NDEP has the ability to grant up to a 1-year extension, if additional time is necessary for the installation of controls. The EPA also noted that the Clean Air Act provides additional flexibilities to bring sources into compliance while maintaining electric reliability, and published a memorandum on December 16, 2011 articulating the Agency’s intended approach with respect to sources that operate in noncompliance with the MATS Rule.

The final rule does not specifically list control technologies that are required to achieve the MATS emission standards. Coal- and oil-fired electric generating units are required to meet the applicable HAP emission limits using whatever control technology, or combination of technologies, they deem appropriate for their specific situation. In general, control technology requirements will be a function of the fuel being fired and the performance of existing air pollution control systems. Based on a review of emissions data available from NVE’s generating units, as well as emissions data available from EPA for similar sources, the Utilities anticipate that SO2 and/or acid gas reduction will be required at SPPC’s Valmy Generating Station, Unit 1 to achieve compliance with the MATS standards.  At the present time, SPPC believes a dry sorbent injection system may be a viable control option for Unit 1, at an estimated capital cost of approximately $20 million.  Note that the actual cost could vary and will be dependent upon final engineering design.

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Currently, all four of the units at the Reid Gardner Generating Station, as well as Unit 2 at the Valmy Generating Station are compliant with the MATS emission standards, based on the current fuel blend.  However, NVE and the Utilities will continue to monitor the chemical coal composition utilized in these units to ensure continued compliance.

       NAAQS

The CAA requires the EPA to set minimum NAAQS for certain air emissions including ozone, particulate matter, SO2 and nitrogen dioxide (NO2).  The CAA established two types of NAAQS: (1) primary standards, which set limits to protect public health, and (2) secondary standards, which set limits to protect public welfare.  Most NAAQS require measurement over a defined period of time (typically one hour, eight hours, twenty-four hours, or one year) to determine the average concentration of the pollutant present in a defined geographic area.

When a NAAQS has been established, each state must recommend, and the EPA must designate, the areas within its boundaries that meet NAAQS (“attainment areas”) and those that do not (“non-attainment areas”).  Each state must develop a state implementation plan (“SIP”) to bring non-attainment areas into compliance with NAAQS and maintain good air quality in attainment areas.  The NAAQS that affect or potentially affect our Utility operations are summarized below.

           Ozone NAAQS

In March 2008, the EPA issued final rules adopting new, more stringent eight-hour NAAQS for ozone.  The EPA lowered the primary and secondary standards from 84 parts per billion to 75 parts per billion.   States are to submit plans to the EPA, no later than 2014, demonstrating attainment with the standard.  

In letters to state and tribal representatives dated December 2011, the EPA has identified which areas it anticipates will be meeting the 2008 ozone standards and those which are not.  States, tribes and the public will have an opportunity to comment on these proposed decisions before the agency issues final designations in spring 2012.  The Las Vegas/Clark County region is presently designated as non-attainment but it, as well as the rest of  Nevada, could be re-classified as attainment, based on the 2008 standard.  The next scheduled reconsideration of the ozone standard will likely occur in 2013. 

      Particulate Matter NAAQS

The EPA has developed annual NAAQS for coarse particulate matter (defined as particles of 10 micrometers or larger) and both annual and 24-hour NAAQS for fine particulate matter (particles with a size of up to 2.5 micrometers).   Nevada counties are currently meeting the particulate matter 2.5 standards. However, the Las Vegas/Clark County and Washoe County regions are in non-attainment for particulate matter 10 standards.  The EPA is currently reconsidering the annual fine particulate standard, and if lowered as expected, new non-attainment designations in our service territory could occur.   The EPA has indicated its reconsideration of the adequacy of the annual fine particulate matter 2.5 standard is expected to be completed in 2012.

     SO2 NAAQS

On June 22, 2010, the EPA established a new one-hour primary SO2 NAAQS at 75 parts per billion and revoked the 24 hour and annual SO2 NAAQS.  The 3-hour secondary NAAQS was established at 0.5 parts per million.  The EPA expects to designate areas as attainment, non-attainment, or unclassifiable in 2012 based on the existing monitoring network and modeling.  Non-attainment designations are expected to result in lower SO2 emission limits for sources of SO2 in or near those areas.

      NO2 NAAQS

On February 9, 2010, the EPA established a new one-hour NAAQS for NO2 at the level of 100 parts per billion.  To determine compliance with the new standard, the EPA is establishing new ambient air monitoring requirements near major roads as well as in other locations where maximum concentrations are expected.  Although existing air quality monitors do not currently show exceedances of this new standard in the Utilities’ service areas, additional community and roadside monitoring could result in the designation of new non-attainment areas.   The EPA intends to re-designate areas as soon as 2016, based on the air quality data from the new monitoring network.   In the February rulemaking, the annual primary and secondary annual NO2 NAAQS was maintained at 53 parts per billion.

Due to uncertainty regarding the potential stringency of any new NAAQS related proposals, NVE is not able to estimate cost impacts to its generating system at this time.  While the final outcome and timing for the EPA's and/or Congressional actions cannot be estimated, the Utilities continue to monitor the development of these standards and assess their 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 SIPs 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 and the proposed SIP to implement the BART requirements was released in the first quarter 2009.  As presented in the SIP, the impacted BART units are Reid Gardner Generating Station Units 1, 2 and 3; Ft. Churchill Generating Station Units 1 and 2; and Tracy Generating Station Units 1, 2 and 3.  The submitted BART SIP 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 retirement of those units.  The Navajo Generating Station is also subject to BART and is currently awaiting an EPA rule determination.

On June 9, 2011, the EPA published in the Federal Register its draft proposalto approve Nevada's Regional Haze Plan as meeting the requirements of the Clean Air Act. However, in announcing its final approval in December 2011, the EPA opted to take no action specifically on the BART determination for nitrogen oxide (NOx) at the Reid Gardner Generating Stations, stating that it intends to propose action on those units at a later date and take public comment in the future.  The EPA’s final approval did include the State’s proposed BART determinations for SO2 and particulate matter for Reid Gardner Generating Station, as well as the BART controls proposed for all of the other NVE affected units.

Given the final EPA action in December, NVE is implementing the approved portions of the rule which will require compliance by January 1, 2015.  NVE intends to retire Tracy Generating Station Units 1 and 2 and install retrofit controls on Tracy Generating Station Unit 3 and Ft. Churchill Generating Station Units 1 and 2.  A cost estimate is currently being prepared based on specific engineering specifications and designs.  It is anticipated that the EPA will request additional information prior to making the final determination on the Reid Gardner Generating Station NOx controls.  However, until the final determination is made, it is impossible to predict the effect the ruling may have on Reid Gardner Generating Station’s generating units.

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.  Potential impacts from proposed legislation could vary, depending upon proposed carbon dioxide (CO2) emission limits, the timing of implementation of those limits, the program design, the degree to which offsets are allowed and available, and provisions for cost containment measures, such as a safety valve that provides a ceiling price for emission allowance purchases. However, the Utilities’ contribution of greenhouse gases (GHG) from its current generation fleet is partly mitigated due to our fuel portfolio being predominately natural gas which emits approximately 50% less CO2 than coal.

The impact on NVE and the Utilities of future initiatives related to GHG emissions and global climate change remains unknown. Although compliance costs are unlikely to be realized in the near future, federal legislative, federal regulatory, and state and regional-sponsored initiatives to control GHG emissions continue to progress, making it more likely that some form of control will eventually be required. For example, California is moving forward with the adoption of a proposed state cap on GHG emissions and developing market-based compliance mechanisms, including compliance offset protocols.

Since these initiatives continue to evolve, NVE has and will continue to identify projects that minimize or offset GHG emissions and believes that precautionary actions to limit GHG emissions are appropriate.

The EPA finalized regulations in September 2009 that require certain categories of businesses, including fossil fuel-fired power plants, to monitor and report their emissions beginning in 2011. NVE has been reporting its annual GHG emissions since it joined the California Climate Action Registry (CCAR) in 2006.  NVE also reported 2010 GHG emissions before the reporting deadline of September 30, 2011.  As required by the EPA, NVE will continue to report annual GHG emissions to comply with the federal mandatory GHG reporting program.

After a series of developments and rule proposals, in March of 2010, the EPA affirmed its position that the CAA permitting requirements under the Prevention of Significant Deterioration (PSD) and Title V permit programs are not triggered for a pollutant until a regulatory requirement to control emissions of that pollutant becomes effective. As a result of this EPA determination, new or modified plants that were subject to PSD or Title V programs had to address GHG emissions in new permit applications as of January 2011. Similarly, GHG emitted above certain thresholds from existing plants were also covered under the Title V program beginning in January 2011. Currently, all NVE generation facilities have operating permits that could require modification to comply with the rule if modifications are undertaken. The extent to which this rule could have a material impact on our generating facilities depends upon whether physical changes or change in operations subject to the rule would occur at our generating facilities; future EPA determinations on what constitutes best available control technology for GHG emissions from power plants; and whether federal

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legislation is passed which overrides the rule.  During 2011, none of NVE’s generation facilities triggered the criteria specified in this rule.

On December 23, 2010 in a judicial settlement, the EPA announced that it will propose first-time GHG emission standards and guidelines for the power plant sector under the federal CAA.  Specifically, the agency expects to propose new source performance standards (NSPS) and emissions guidelines for existing sources for the power plant sector by May 2012.  It is reasonable to expect that the limits on GHG emissions imposed by the new source performance standards and guidelines for existing sources will have an impact on generating facility operations.  However, until the standards and guidelines are proposed, it is impossible to predict the potential effect on generating facility operations.

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 “once through” cooling water intake/discharge 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 “once through” cooling water intake structures and thermal discharges of wastewater from power generation facilities do not specifically apply to the NPC and SPPC generation sites.

The EPA is currently developing revised effluent limitation guidelines and standards for the steam electric power generating industry, which the agency expects to propose in July 2012.  The EPA's revision of these guidelines is driven primarily by concern over wastewater discharges from coal-fired power plants, but will also address discharges from ash ponds and flue gas desulfurization air pollution controls.  Under the terms of a related court-approved consent decree, the final rules must be published by January 31, 2014.  It is reasonable to expect that the new guidelines will impose more stringent limits on wastewater discharges from coal-fired power plants and ash ponds.  However, until the revised guidelines are proposed, it is impossible to predict the effect the revised guidelines may have on generating facility operations.

   Coal Combustion Product (CCP) Management

In 2010, the EPA released the text of a proposed rule describing two possible regulatory options it is considering under the Resource Conservation and Recovery Act (RCRA) for the disposal of coal ash generated from the combustion of coal by electric utilities and independent power producers.  Under either option, the EPA would regulate the construction of impoundments and landfills, and seek to ensure both the physical and environmental integrity of disposal facilities; however, none of the Utilities’ coal facilities currently manage ash in surface water impoundments; rather, these ash products are handled and processed in a dry form at both the Reid Gardner and Valmy Generating Stations.

The Utilities believe it is possible that the EPA will continue to allow some beneficial use, such as recycling of ash, without classifying it as hazardous waste. However, any additional regulations which more stringently regulate the management disposal or reuse of coal ash will likely increase costs for NVE’s coal generation facilities if the ability to recycle this material is impaired or current landfill disposal requirements are modified. Due to the uncertainties of how this material may ultimately be regulated in the future, the Utilities are unable to predict the outcome any such regulations might have on their systems at this time.

      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.

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GENERAL – EMPLOYEES (ALL)

NVE and its subsidiaries had 2,811 employees as of January 26, 2012, of which 1,614 were employed by NPC, and 1,092 were employed by SPPC.

NPC and IBEW 396, which covers approximately 57% of NPC’s workforce, have entered into a new collective bargaining agreement (CBA).  The CBA is effective September 1, 2011 through January 31, 2013.

On August 12, 2010, SPPC and IBEW Local 1245, which covers approximately 59% of SPPC’s workforce, entered into a new CBA.  The CBA is effective August 16, 2010 for a three-year period ending August 15, 2013.  

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.  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 2011, the Utilities collected $130.0 million in franchise or other fees based on gross revenues.  They collected $9.5 million in UEC based on consumption. They also paid and recorded as expense $2.2 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

Risks related to NVE and the Utilities’ Results of Operations

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 our service areas.  Over the last several years, adverse economic conditions have created uncertainty within the capital and commodity markets, including availability and cost of credit, inflation rates, monetary policy, unemployment rates and legislative and regulatory uncertainty.  A continued high rate of unemployment in Nevada may impact customers’ ability to pay their utility bills on a timely basis, increase customer bankruptcies, and lead to increased bad debt.  A lower level of economic activity, changes in discretionary spending, conservation efforts by our customers, and decreased tourism activity in our service areas have resulted in a decline in energy consumption, which has and may continue to affect our future growth. 

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, continuation of current economic conditions both nationally and globally, war, and the threat of terrorism or pandemics 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 continue to harm our business.  We cannot predict the extent to which the current local economic environment or global economic environment, future terrorist and war activities, or pandemics, in the U.S. and elsewhere may affect us, directly or indirectly.  An extended period of reduced discretionary spending and/or disruptions or declines in airline and other 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.  

Our business operations could be adversely affected by cyber attacks or security breaches.

The Utilities are subject to cyber-security risks primarily related to breaches of security pertaining to sensitive customer, employee and vendor information maintained by the Utilities in the normal course of business, as well as breaches of their supervisory

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control and data acquisition systems and other computer-based systems and networks used in the operation of their businesses.  A loss of confidential or proprietary data or security breaches of other computer systems or networks could adversely affect the Utilities’ reputation, diminish customer confidence, adversely affect the Utilities’ ability to manage facilities, networks, systems, programs and data efficiently or effectively, disrupt operations, and subject the Utilities to possible financial liability, any of which could have a material adverse effect on our financial condition and results of operations.  While the Utilities have procured insurance and have implemented protective measures designed to deter cyber attacks and security breaches and to mitigate their effects, there can be no assurance that such protective measures will be completely effective in protecting the Utilities from a cyber attack or security breach or the effects thereof or that insurance will be sufficient to compensate third parties from damages that result from cyber attacks or security breaches.

The Utilities could be subject to penalties if they violate mandatory NERC reliability standards.

The Energy Policy Act of 2005 amended the Federal Power Act to, among other matters, provide for mandatory reliability standards designed to assure the reliable operation of the bulk power system.  NERC established, and FERC approved, reliability standards that impose certain operating, planning and cyber-security requirements applicable to the Utilities.  The Utilities have been, and will continue to be, subject to routine audits and monitoring with respect to compliance with applicable NERC reliability standards, including standards requested by FERC to increase the number of assets (including cyber-security assets) subject to NERC cyber-security standards that are designated as “critical assets.”  If the Utilities are found to be in violation of NERC’s mandatory reliability standards, the Utilities could be subject to civil fines imposed by the enforcement entities, which could have a material adverse effect on our results of operations, cash flows and financial condition.

Construction projects that we engage in are subject to a number of risks inherent in such projects, which could have adverse effects on our results of operations.

The nature of our business requires us to engage in significant construction projects from time to time, and each such construction project is subject to usual construction risks which could adversely affect project costs and completion time. These risks include, but are not limited to, shortages of, the ability to obtain or the cost of labor or materials; the ability of the contractors to perform under their contracts; equipment, engineering and design failure;  strikes; adverse weather conditions; the ability to obtain necessary operating permits in a timely manner; legal challenges; disputes with third parties; changes in applicable law or regulations; adverse interpretation or enforcement of permit conditions, laws and regulations by courts or the permitting agencies; other governmental actions; and events in the global economy. If we are unable to complete the development or construction of any construction project or decide to delay or cancel construction, we may not be able to recover our investment in the project and may incur substantial cancellation payments under equipment and construction contracts. Even if a construction project is completed, the total costs may be higher than estimated and/or higher than amounts approved by our regulators, and there is no guarantee that we will be allowed to recover these costs in rates. In addition, construction delays can result in the delay of revenues and, therefore, could affect our results of operations.

The ownership and operation of certain power generation and transmission lines on Indian lands could result in uncertainty related to continued leases, easements and rights-of-way, which could have a significant impact on our business.

Certain portions of the Utilities’ generating facilities and transmission lines that carry power from these facilities are located on Indian lands pursuant to leases, easements or other rights-of-way that are effective for specified periods. The Utilities are currently unable to predict the final outcome of discussions with the appropriate Indian tribes and approval by their respective governing bodies with respect to renewals of these leases, easements and rights-of-way.

Risks related to NVE and the Utilities’ Regulatory Proceedings

If the Utilities do not receive favorable rulings in their future GRCs or other regulatory filings, including energy efficiency recovery programs, such events may 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’ future GRCs or other regulatory filings, including energy efficiency recovery programs.  Inadequate rates may have a significant adverse effect on the Utilities’ financial condition and future results of operations and may cause downgrades of their securities by the rating agencies and make it

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significantly more difficult or expensive to finance operations and construction projects and to buy fuel, natural gas and purchased power from third parties.

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, including changes in prices due to suspension of hedging programs, 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.  

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 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.

The Utilities purchase a 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 access to liquidity is limited to obtain their power requirements, particularly for NPC at the onset of the summer months, and the Utilities are unable to obtain power through other means, their business, operations and financial condition will be materially adversely affected.

 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 sales from renewable energy sources or efficiency measures, which increases over time.  The standard also includes a specific requirement for solar energy that must be met on an annual basis by both Utilities.  The required amount of renewable energy and available supply can fluctuate widely based on multiple factors, including customer energy use, changes in law or regulation, renewable resource availability, and the financial stability of renewable counter parties, making the ability to anticipate future renewable energy needs and supplies difficult.  In the event the Utilities do not fully meet the standards in a given year, if the PUCN does not exempt them, they will be required to make up the PEC deficiency in subsequent years and may be subject to a financial penalty.

In 2011, the Utilities were required to obtain an amount of PECs equivalent to 15% of their total retail energy from renewables.  The Portfolio Standard remains at 15% for 2012, increases to 18% for 2013 and 2014, and reaches 20% in 2015, after which it increases again to 22% for the years 2020 through 2024, and to 25% for 2025 and beyond.  Moreover, not less than 5% of the total Portfolio Standard must be met from solar resources until 2016, when a minimum of 6% must be solar.  In the event the Utilities do not fully meet the standard in a given year, if the PUCN does not exempt them, they will be required to make up the PEC deficiency in subsequent years.

Due to periodic increases in the Portfolio Standard and increasing retail sales, the Utilities must acquire increasing amounts of renewable energy.  Since most of the Utilities’ renewable energy requirement is met by deliveries from third party suppliers, the Utilities’ success in meeting the increasing Portfolio Standard remains largely dependent on the ability of those third parties to meet minimum contractual obligations over the duration of the contract.   Similarly, self-owned generation and expected contributions from qualified conservation and energy efficiency measures would need to deliver and be certified by the PUCN as forecasted in each forecast year.  In 2011, the PUCN issued an order certifying that both Utilities had met the Portfolio Standard (and the solar requirement) and that NPC had eliminated any previous deficiency from 2010.  While both Utilities were successful in 2011 with respect to the Portfolio Standard, the intermittent and variable nature of the renewable portfolio, together with the increasing required renewable percentage, means that future years may still be subject to uncertainty around the Utilities’ ability to comply with the Portfolio Standard.

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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 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.  As of December 31, 2011, NPC has financing authority from the PUCN for the period ending December 31, 2013, consisting of authority (1) to issue additional long-term debt securities of up to $725 million; (2) to refinance up to approximately $322.5 million of long-term debt securities; and (3) ongoing authority to maintain a revolving credit facility of up to $1.3 billion. As of December 31, 2011, SPPC has financing authority from the PUCN for the period ending December 31, 2012, consisting of authority to (1) issue additional long-term debt securities of up to $350 million; (2) to refinance approximately $348 million of long-term debt securities; and (3) ongoing authority to maintain a revolving credit facility of up to $600 million.  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.

Risks related to NVE and the Utilities’ Environmental Matters

If Federal and/or State requirements are imposed on the Utilities mandating further emission reductions, including greenhouse gases and other pollutants, or if national ambient air quality standards are modified, 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 U.S. have also been focusing considerable attention on emissions from power generation facilities and their potential role in climate change and/or regional air quality.  Moreover, there are many legislative and rulemaking initiatives pending at the federal and state level that are aimed at the reduction of fossil plant emissions, as well as modification of the NAAQS for ozone and other pollutants. 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 or regulation, 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 identified as a responsible party for environmental cleanup 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 liabilities 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, coal combustion by products and other 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.

     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.

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Risks related to NVE and the Utilities’ Liquidity and Capital Resources

Lower than expected investment returns on pension and other postretirement plan assets and other factors may increase NVE’s pension and other postretirement plan liability and funding requirements.

            Substantially all of NVE employees are covered by a single employer defined benefit pension and other postretirement plan.  At present, the pension and other postretirement plan is underfunded in that the projected benefit obligations exceed the aggregate fair value of plan assets.  The funded status of the plan can be affected by contributions to plan assets, plan design, 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 and other postretirement plan assets will be sufficient to cover future liabilities.  Although NVE has made significant contributions to its pension and other postretirement plan in recent years, it is possible that NVE could incur a significant pension and other postretirement 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.

As a result of the suspension of the Utilities’ hedging programs, 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.

Beginning in October 2009, the Utilities suspended their hedging programs; however, prior to the suspension, it was the general policy of the Utilities to purchase hedges three seasons ahead.  As a result certain hedges entered into prior to the suspension in October 2009, did not terminate until 2011.  As of November 2011, all hedging transactions have expired or terminated and the Utilities remain unhedged.  If deemed prudent, the Utilities may still purchase hedging instruments in the event circumstances occur that may have the potential to increase the cost of fuel and purchased power.  As such, fluctuating commodity prices could have a material adverse effect on their cash flows and their ability to operate and, consequently, on our financial condition.

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.  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.  

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, or reduce availability under the Utilities’ revolving credit facilities for negative mark-to-market positions.  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 $64.7 million.  Additionally, the Utilities shall reduce their availability under their revolving credit facilities for negative mark-to-market positions on hedging contracts with counterparties who are lenders under the revolving credit facilities provided that the reduction of availability under the revolving credit facilities shall at no time exceed 50% of the total commitments then in effect under the credit facilities.

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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 the PUCN, 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.

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; 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.

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, 2011, the Utilities had approximately $4.6 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, 2011 financial statements, NVE’s indebtedness restrictions would allow NVE and the Utilities to issue up to approximately $2.8 billionof additional indebtedness in the aggregate, plus indebtedness that 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.

ITEM 1B.                      UNRESOLVED STAFF COMMENTS

None.

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ITEM 2.                      PROPERTIES

Substantially all of NPC’s and SPPC’s property in Nevada 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 Trust Company, N.A., as trustee, as amended and supplemented.

NVE’s total summer MW capacity and units were 5,862 MWs and 63 units, respectively.  The following is a list of NPC’s share of electric generation plants including the type and fuel used to generate, the anticipated 2012 net capacity (MW), and the years that the units were installed.

NPC

			Number of	Summer MW	Commercial
Plant Name	Type	Fuel	Units	Capacity	Operation Year
Clark Generating Station	Combined Cycle	Gas	6	430	1979, 1979, 1980, 1982,
					1993, 1994
	Gas	Gas	1	54	1973
	Peakers	Gas	12	619	2008
Sunrise(1)	Steam	Gas	-	-	1964
	Gas	Gas	-	-	1974
Harry Allen Generating Station	Combined Cycle	Gas	3	484	2011
	Gas	Gas	2	144	1995, 2006
Lenzie Generating Station	Combined Cycle	Gas	6	1102	2006
Silverhawk Generating Station(2)	Combined Cycle	Gas	3	395	2004
Higgins Generating Station	Combined Cycle	Gas	3	530	2004
Mohave Generating Station(3)	Steam	Coal	-	-	1971
Navajo Generating Station(4)	Steam	Coal	3	255	1974, 1975, 1976
Reid Gardner Generating Station(5)	Steam	Coal	4	325	1965, 1968, 1976, 1983
Goodsprings	Waste Heat		1	5	2010
Total			44	4,343

(1)	Sunrise Station Units 1 & 2 were retired with PUCN approval on 12/31/2011.
(2)	Silverhawk Generating Station is jointly owned by NPC and SNWA, 75% and 25%, respectively.
(3)	Per a 1999 Consent Decree, Mohave Generating Station ceased operation on December 31, 2005.  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.
(4)	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).
(5)	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 24 MW of base load capacity and 233 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 Reid Gardner Generating Station summer capacity is 557 MW.  The agreement with CDWR terminates in 2013, at which time NPC assumes 100% ownership.

 The following is a list of SPPC’s share of electric generation plants including the type and fuel used to generate, the anticipated 2012 net capacity (MW), and the years that the units were installed.

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SPPC

			Number of	Summer MW	Commercial
Plant Name	Type	Fuel	Units	Capacity	Operation 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	Combined Cycle	Gas	2	104	1996, 1996
Tracy Generating Station	Combined Cycle	Gas	3	541	2008
Clark Mtn. CT's	Gas	Gas/Oil	2	132	1994, 1994
Valmy Generating Station(1)	Steam	Coal	2	261	1981, 1985
Other	Diesel	Oil	5	11	1960-1970
Total			19	1,519

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

ITEM 3.                      LEGAL PROCEEDINGS

NPC and SPPC

   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.

Over the course of the last ten years, the Utilities litigated and settled the termination claims with the various power suppliers. The Utilities had previously negotiated settlements with Duke Energy Trading and Marketing, Morgan Stanley Capital Group, El Paso Merchant Energy, now known as El Paso Marketing L.P., Calpine Energy Services and Enron.  The Utilities completed bilateral settlement discussions with Allegheny Energy Supply Company (Allegheny), American Electric Power Service Corporation (AEP) and BP Energy in 2009 and 2010.  The Utilities, together with other interested parties including the BCP, settled and resolved all claims against BP Energy, AEP and Allegheny, each for an immaterial amount in return for a release of all claims by the Utilities and BCP.  The settlement agreement with Allegheny received final approval by the FERC in January 2011.  With the final approval of the Allegheny Settlement by FERC, all of the Utilities’ FERC 206 complaints are settled and resolved.

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 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.                      MINE SAFETY DISCLOSURES

Not applicable.

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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 2011 and 2010 are as follows:

			Dividends declared per share				2011				2010
			2011		2010		High		Low		High		Low
	First Quarter	$	0.12	$	0.11	$	15.04	$	13.89	$	12.75	$	10.94
	Second Quarter		0.12		0.11		15.96		14.55		13.14		11.18
	Third Quarter		0.12		0.11		15.71		12.31		13.30		11.53
	Fourth Quarter		0.13		0.12		16.61		13.65		14.40		12.75
Number of Security Holders:
				Title of Class						Number of Record Holders
				Common Stock:  $1.00 Par Value						As of February 21, 2012:  13,761

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.  

On February 10, 2012, NVE’s BOD declared a quarterly cash dividend of $0.13 per share payable on March 21, 2012 to common shareholders of record on March 6, 2012.

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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The stock performance graph “Comparison of 5-Year Cumulative Total Return” as of December 2011 was revised to include the S&P Super Composite Electric Utility Index rather than the Dow Jones US Utilities Average Index in order to provide consistency with the TSR performance measurement within Executive Compensation, Item 11.  Previously, NVE used the Dow Jones U.S. Utilities Average Index, which has been provided in the graph above for comparative purposes.

The information in Item 5 of this Annual Report on Form 10-K is not deemed to be “soliciting material” or to be “filed” with the SEC or subject to Regulation 14A or 14C under the Securities Exchange Act of 1934 or to the liabilities of Section 18 of the Securities Exchange Act of 1934, and will not be deemed to be incorporated by reference into any filing under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent we specifically incorporate it by reference into such a filing.

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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):

NVE
	Year ended December 31,
	2011		2010		2009		2008			2007
Operating Revenues	$	2,943,307	$	3,280,222	$	3,585,798	$	3,528,113		$	3,600,960
Operating Income	$	610,665	$	644,435	$	564,083	$	552,079		$	489,722
Net Income	$	163,432	$	226,984	$	182,936	$	208,887		$	197,295
Net Income
Per Average Common Share - Basic and	$	0.69	$	0.97	$	0.78	$	0.89		$	0.89
- Diluted	$	0.69	$	0.96	$	0.78	$	0.89		$	0.89
Total Assets	$	11,635,128	$	11,669,668	$	11,413,463	$	11,347,870	(1)	$	9,468,119
Long-Term Debt (not including current maturities)	$	5,008,931	$	4,924,109	$	5,303,357	$	5,266,982		$	4,137,864
Dividends Declared Per
Common Share	$	0.49	$	0.45	$	0.41	$	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.

NPC
	Year ended December 31,
	2011		2010		2009		2008			2007
Operating Revenues	$	2,054,393	$	2,252,377	$	2,423,377	$	2,315,427		$	2,356,620
Operating Income	$	443,796	$	467,412	$	396,362	$	369,966		$	358,412
Net Income	$	132,586	$	185,943	$	134,284	$	151,431		$	165,694
Total Assets	$	8,442,597	$	8,301,824	$	8,096,371	$	7,904,147	(1)	$	6,377,369
Long-Term Debt (not including current maturities)	$	3,319,605	$	3,221,833	$	3,535,440	$	3,385,106		$	2,528,141
Dividends Declared - Common Stock	$	99,000	$	74,000	$	112,000	$	44,000		$	25,667

  (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.

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SPPC
	Year ended December 31,
	2011		2010		2009		2008			2007
Operating Revenues	$	888,899	$	1,027,822	$	1,162,393	$	1,212,661		$	1,244,297
Operating Income	$	171,433	$	180,995	$	170,589	$	185,959		$	135,948
Net Income	$	59,886	$	72,375	$	73,085	$	90,582		$	65,667
Total Assets	$	3,184,008	$	3,347,022	$	3,342,145	$	3,464,435	(1)	$	2,979,893
Long-Term Debt (not including current maturities)	$	1,179,326	$	1,195,775	$	1,282,225	$	1,395,987		$	1,084,550
Dividends Declared - Common Stock	$	60,000	$	108,000	$	32,000	$	233,000		$	12,833

  (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.

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

Forward-Looking Statements and Risk Factors

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, inflation rates, monetary policy, unemployment rates, customer bankruptcies, including major gaming customers with significant debt maturities, weaker housing markets, a decrease in tourism, each of which affect customer growth, 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, and the impact of energy conservation programs, which could affect the Utilities’ ability to accurately forecast electric and gas demand;

(3)   construction risks, such as, difficulty in securing adequate skilled labor, cost and availability of materials and equipment, third-party disputes, equipment failure, engineering and design failure, work accidents, fire or explosions, business interruptions, possible cost overruns, delay of in-service dates, and pollution and environmental damage;

(4)   unseasonable or severe weather, drought, wildfire and other natural phenomena, which could affect the Utilities’ customers’ demand for power, seriously impact the Utilities’ ability and/or cost to procure adequate supplies of fuel or purchased power, affect the amount of water available for electric generating plants in the Southwestern U.S., and could have other adverse effects on our business;

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

(6)   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, current suspension of the hedging program, physical availability, sharp increases in the prices for fuel (including increases in long-term transportation costs)  and/or power, or a ratings downgrade;

(7)   changes in and/or implementation of environmental laws or regulations, including the imposition of limits on emissions of carbon or other pollutants from electric generating facilities, which could significantly affect the Utilities existing operations as well as our construction program;

(8)   whether the Utilities’ newly installed advanced metering system will integrate with other computer information systems, perform as expected, and in all other respects meet operational, commercial and regulatory requirements;

(9)   changes in and/or implementation of FERC and NERC mandatory reliability, security, and other requirements for system infrastructure, which could significantly affect existing and future operations;

(10)   security breaches of our information technology or supervising control and data systems, or the systems of others  upon which the Utilities rely, whether through cyber-attack, cyber-crime, sabotage, accident or other means, which may affect our ability to prevent system or service disruptions, generating facility shutdowns or disclosure of confidential corporate or customer information;

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(11)   the ability and terms upon which NVE, NPC and SPPC will be able to access the capital markets to support their capital needs, particularly in the event of: volatility in the global credit markets as a result of the viability of European sovereign debt or other problems, changes in availability and cost of capital either due to market conditions or as a result of unfavorable rulings by the PUCN,  a downgrade of the current debt ratings of NVE, NPC or SPPC, and/or interest rate fluctuations;

(12)   wholesale market conditions, including availability of power on the spot market and the availability to enter into commodity financial hedges with creditworthy counterparties, including the impact as a result of the Dodd-Frank Act on counterparties who are lenders under our revolving credit facilities, which may 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)   explosions, fires, accidents and mechanical breakdowns that may occur while operating and maintaining an electric and natural gas system in the Utilities’ service territory that can cause unplanned outages, reduce generating output, damage the Utilities’ assets or operations, subject the Utilities to third-party claims for property damage, personal injury or loss of life, or result in the imposition of civil, criminal, or regulatory fines or penalties on the Utilities;

(14)   the effect of existing or future Nevada, or federal laws or regulations affecting the electric industry,  including those which could allow additional customers to choose new electricity suppliers, or use alternative sources of energy, or change the conditions under which they may do so;

(15)   employee workforce factors, including an aging workforce, changes in and renewals of collective bargaining unit agreements, strikes or work stoppages, the ability to adjust the labor cost structure to changes in growth within our service territories;

(16)   whether the Utilities can procure, obtain, and/or maintain sufficient renewable energy sources in each compliance year to satisfy the Portfolio Standard in the State of Nevada;

(17)   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;

(18)   whether NVE's BOD will continue to declare NVE's 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;

(19)   the extent to which NVE, or the Utilities incurs costs in connection with third-party claims or litigation,  that are not recoverable through insurance, rates, or from other third parties.

(20)   whether, following the Great Basin Water Network, et al. v. Nevada State Engineer litigation, certain permitted water rights of the SNWA that are used to supply water to the Utilities’ power production plants and service territories could be re-opened, which could adversely impact the operations of those plants and future growth and customer usage patterns;

(21)   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 and other post retirement plans, which can affect future funding obligations, costs and pension and other post retirement plan liabilities;

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

(23)   changes in tax or accounting matters or other laws and regulations to which NVE or the Utilities are subject or which change the rate of federal or state taxes payable by our shareholders or common stock dividends.

(24)   changes in the business of the Utilities’ major customers engaged in gold mining or gaming, including availability and cost of capital or power demands, 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 other states and internationally; and

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

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Other factors and assumptions not identified above may also have been involved in deriving 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.

NOTE REGARDING RELIANCE ON STATEMENTS IN OUR CONTRACTS

In reviewing the agreements filed as exhibits to this Annual Report on Form 10-K, please remember that they are filed to provide you with information regarding their terms and are not intended to provide any other factual or disclosure information about NVE, the Utilities or the other parties to the agreements.  The agreements contain representations and warranties by each of the parties to the applicable agreement.  These representations and warranties have been made solely for the benefit of the other parties to the applicable agreement and:

• should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties to the agreement if those statements prove to be inaccurate;

• have been qualified by disclosures that were made to the other party in connection with the negotiation of the applicable agreement, which disclosures are not necessarily reflected in the agreement;

• may apply standards of materiality in a way that is different from what may be viewed as material to investors; and

• were made only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement and are subject to more recent developments.

Accordingly, these representations and warranties may not describe the actual state of affairs as of the date they were made or at any other time.

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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 discussion of 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

• 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 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 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 due to varying weather, customer growth and other energy usage patterns, including energy efficiency and conservation measures, 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 timely recovery of purchased power and fuel costs, and other costs, 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

NVE recognized net income of $163.4 million in 2011 compared to $227 million in 2010.  The decrease in net income is primarily due to the completion of the expansion at the Harry Allen Generating Station in May 2011, which resulted in a decrease in AFUDC, an increase in depreciation expense and other operating and maintenance costs which were not recovered in rates.  As a result of the PUCN’s final order on NPC’s 2011 GRC, costs associated with Harry Allen Generating Station are included in rates as of January 1, 2012.   Further contributing to the decrease in net income is a decrease in gross margin, adjustments as a result of the PUCN final order on NPC’s 2011 GRC, performance pay adjustments, maintenance at Reid Gardner Generating Station, an adjustment for revenue recorded in 2010 as a result of the PUCN’s final decision on the EEIR rate and the recognition of income in 2010 for the sale of Independence Lake and legal settlements.  Partially offsetting these decreases in net income was a favorable settlement in 2011 with a vendor on a long term service agreement for the Higgins Generating Station, which was accrued for in the third quarter 2010.  Further offsetting the decrease in net income was a decrease in interest expense and reduced operating expenses.

 NVE recognized net income of $227 million in 2010 compared to $182.9 million in 2009.  The increase in net income is primarily due to an increase in gross margin, which is primarily due to NPC’s increased rates as a result of NPC’s 2008 GRC, effective July 1, 2009.  See Note 2, Segment Information, of the Notes to Financial Statements.  Also contributing to the increase in net income was lower operating expenses in 2010 compared to 2009 primarily due to a decrease in employee pension and benefit expenses and costs incurred in 2009 related to severance programs.  See Note 17, Severance Programs, of the Notes to Financial Statements.  Partially offsetting the increase in net income was higher income taxes as a result of a lower tax effective rate in 2009, an increase in interest expense on regulatory items primarily as a result of over-collected deferred energy balances and interest charges

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related to NVE’s redemption of $230 million of its 8.625% Senior Notes due 2014, and $63.7 million of its 7.803% Senior Notes due 2012 and increased depreciation expense.

2011 Accomplishments

Three part strategy

In 2011, NVE continued the execution of its three part strategy, discussed in detail later, to manage resources against our load by (1) encouraging energy efficiency and conservation programs, (2) the purchase and development of renewable energy projects, and (3) the construction of generating facilities, in an effort to reduce our reliance on purchased power, and expansion of transmission capabilities.  Accomplishments under the three part strategy include:

Energy efficiency and conservation programs:
	•	In July 2011, the EEPR became effective.  The EEPR changed the recovery of energy efficiency program costs from general rates (filed every 3 years) to recovery through independent annual rate filings.
	•	In July 2011, the EEIR became effective.  The EEIR allows an electric utility to recover lost revenue that is attributable to the measurable and verifiable effects associated with the implementation of efficiency and conservation programs approved by the PUCN.
	•	In 2010, the DOE awarded a $139 million grant in stimulus funding, made available through the American Recovery and Reinvestment Act specifically for NVE’s $303 million NV Energize project. The project will deploy the Smart Grid infrastructure necessary to: 1) enable the achievement of metering and customer service operating savings; 2) enable the expansion of demand response and energy efficiency benefits; and 3) provide customers better information to help manage their energy usage. In 2011, NVE installed approximately 695,000 smart meters in southern Nevada and expects to install 1.4 million statewide by the end of 2012.

Purchase and Development of Renewable Energy Resources:
	•	In 2011, the PUCN issued an order certifying that both Utilities had met the Portfolio Standard (and the solar requirement) and that NPC had eliminated any previous deficiency from 2010.

Construction of Generating Facilities and Expansion of Transmission Capabilities:
	•	In June 2011, NPC completed construction of the 500 MW (nominally rated) natural gas generating station at the existing Harry Allen Generating Station.
	•	In February 2011, NVE and the Utilities achieved Financial Closing under a TUA with GBT-South, formerly entered into with GBT, to jointly construct and own ON Line, a 500 Kv transmission line.

      Regulatory:

The PUCN issued its order on NPC’s 2011 GRC in December 2011, which resulted in the following significant items:

• Increase in general rates of $158.6 million, approximately an 8.3% overall increase effective January 1, 2012.

• ROE and ROR of 10.0% and 8.09%, respectively.

• Recovery of approximately $635.9 million, excluding AFUDC, for the 500 MW (nominally rated) expansion at the Harry Allen Generating Station.

• Recovery of approximately $23.2 million for EEC project development costs.

• Recovery of approximately $17.7 million for demand side management costs.

• Recovery of approximately $12.7 million for Mohave Generating Station closure costs.

In addition to those items discussed above, reference Note 3, Regulatory Actions, of the Notes to Financial Statements, for further discussion of additional NPC 2011 GRC items.  Also, in 2011 the Legislature passed Assembly Bill 215 which allows an electric or gas utility that adjusts its BTER on a quarterly basis to request PUCN approval to make quarterly changes to its DEAA rate if the request is in the public interest.  Under this law, the Utilities began filing applications to reset their DEAA rates to reduce regulatory lag.

Future Challenges

In 2012, NVE and the Utilities must continue to balance the needs of our customers and regulatory requirements while still providing value to our shareholders. The Utilities three part strategy was initiated at a time when the Utilities were experiencing high

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growth which required significant capital investment in order to meet customer demands and also to establish self sufficiency and energy independence by building our own generating stations.  As customer growth and demand have stabilized, the Utilities are transitioning from an emphasis on capital investment to an emphasis on optimizing our assets and resources.   This transition is effected by certain challenges including:

• Economic conditions in Nevada;

• Executing the evolution of energy strategy; and

• Managing regulatory environment.

  Economic Conditions

Economic conditions in Nevada continue to show mixed activity; however,  leading economic indicators for Nevada and Southern Nevada suggest that economic conditions can be expected to improve, although very slowly. Although the unemployment rate remains above the national average, the unemployment rate has improved significantly over the past year.  Additionally, the economy in Southern Nevada has begun to see another sign of improvement, as visitor volumes begin to return to levels seen in 2007 before the recession.

Economic conditions in Nevada have significant influence on NVE’s business decisions as we consider various interrelated factors including:

• customer growth;

• customer  usage;

• load factors;

• managing operating and maintenance expenses within projected revenue without compromising safety, reliability and efficiency;

• pressure on regulators to limit necessary rate increases or otherwise lessen rate impacts upon customers;

• collections on accounts receivable; and

• future capital projects and capital requirements.

Executing the evolution of the energy strategy

Outlined below is the evolution of our energy strategy:

Three Part Energy Strategy----------------------------------------------------------------------------------------------àEvolution of Energy Strategy
Increase energy efficiency, conservation	Empower customers through more focused energy efficiency programs
Expand renewable energy initiatives and investments	Pursue cost-effective renewable energy initiatives
Add new generation and transmission	Optimize generation efficiency and transmission
	Engage employees to improve processes, reduce costs, and enhance performance

    Empower customers through focused energy efficiency programs

           The Utilities will continue with the implementation of NV Energize which not only provides metering and customer service operating savings, but will also provide customers with better opportunities to become more energy efficient.  NVE’s traditional conservation and energy efficiency programs, which have focused on behavioral change and technology replacement, will be enhanced by the new features enabled by NV Energize.  Customers will have access to better information to help them manage their usage and select from enhanced energy efficiency options, including demand response and pricing programs.  NVE has installed approximately 695,000 smart meters in southern Nevada and expects to have 1.4 million installed statewide by the end of 2012.  The NV Energize capabilities will allow NVE to help customers implement the most cost-effective mix of energy efficiency and conservation options that will also qualify toward fulfillment of the Portfolio Standard.

   Pursue cost-effective renewable energy initiatives

NVE must strive to effectively balance the need to meet the Portfolio Standard, with the changes in load forecast and the uncertainty of renewable energy project development, either for financial or resource related reasons. While NVE is better positioned to meet this challenge based on recent renewable successes, NVE remains committed to incorporating clean, cost-effective renewable energy into its portfolio.  As part of this continued commitment, NVE will continue to seek the best and most cost effective opportunities that will benefit our state, customers and environment. Depending on its needs and continuous analysis of the existing portfolio, NVE has a number of tools available to seek renewable energy values for our customers.  These tools may include issuing requests for proposals for new renewable energy contracts, exploring opportunities to either jointly construct or develop projects using

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wind, geothermal and solar, undertaking additional short-term purchases from existing renewable facilities and restructuring existing renewable relationships for the benefit of our customers.

The Portfolio Standard requires a specific percentage of an electric service provider’s total retail energy sales to be obtained from renewable energy resources. Renewable resources include biomass, geothermal, solar, waterpower, wind and qualified recovered energy generation projects. In addition, the Portfolio Standard allows energy efficiency measures from qualified conservation programs to meet up to 25% of the portfolio percentage. In 2011 and 2012, the Utilities are required to obtain an amount of PECs equivalent to 15% of their total retail energy from renewables. Currently, the Portfolio Standard increases to 18% for 2013 and 2014, to 20% in 2015, after which it increases to 22% for the years 2020 through 2024, and to 25% for 2025 and beyond. Moreover, not less than 5% of the total Portfolio Standard must be satisfied from solar resources until 2016 when a minimum of 6% must be solar.

The Utilities acquire PECs through competitively-priced purchase power contracts, investments in renewable generating facilities and DSM programs.  NVE seeks to meet the standard using the most cost-effective means for our customers and to pursue the best-value options that are available to the Utilities.  In addition to the foregoing, this may also include economical short-term purchases of PECs (usually from outside of Nevada) to fulfill projected shortfalls due to the attrition or timing of development of renewable energy projects, weather variability or other supplier issues.

   Optimize generation efficiency and transmission facilities

Since 2006, when NVE began its energy independence initiative, we have added over 3,800 MWs (nominally rated) of internal generation and, with the completion of Harry Allen Generating Station, NVE may obtain approximately 80% of its energy from internal generation.  In 2012, NVE’s management will continue to strive to optimize the Utilities’ energy portfolio in order to meet load obligations in a cost effective and reliable manner.  In addition, to the extent the Utilities have the economical opportunity to sell excess capacity or energy, they may enter into such transactions to reduce overall energy costs.  NVE anticipates it will have sufficient resources to meet its forecasted load requirements for 2012. However, resource adequacy could be affected by a number of factors, including the unplanned retirement of generating stations, plant outages, the timing of commercial operation of renewable energy projects and associated purchase power agreements, customer behavior with respect to energy efficiency and conservation programs, and environmental regulations which may limit our ability to operate certain generating units.

NVE will continue with the construction of the ON Line which will enable us to optimize our transmission capabilities.  Upon completion, the ON Line will connect NVE’s southern and northern service territories and, pending certain state and federal regulatory approvals, will provide the ability to jointly dispatch energy throughout the state and provide access to renewable energy resources in parts of northern and eastern Nevada, which will enhance NVE’s ability to manage its Portfolio Standard, discussed above, and optimize its generating facilities.

ON Line is Phase 1 of a Joint Project between the Utilities and GBT-South.  The Joint Project consists of two phases.  In Phase 1 of the Joint Project, the parties would complete construction of a 500 kV interconnection between the Robinson Summit substation on the SPPC system and the Harry Allen substation on the NPC system.  The Utilities own a 25% interest in ON Line and have entered into a TUA with GBT-South for its 75% interest in ON Line. The Utilities’ 25% interest in ON Line, which approximates $127 million, will be allocated 95% and 5% to NPC and SPPC, respectively.  The Utilities will have rights to 100% of the capacity of ON Line, which is estimated to be approximately 600 MW.  If GBT elects to construct Phase 2, it would construct two additional transmission segments at either end of ON Line: one extending from Robinson Summit north to Midpoint, Idaho, and the other commencing at the Harry Allen substation and interconnecting south to the Eldorado substation.  GBT would pay for and own 100% of Phase 2 facilities.  However, NPC and SPPC would have rights to additional transmission capacity from Midpoint to Eldorado (for a total of approximately 760 MW based on a rating of 2,000 MW for the complete path).

In February 2012, NVE announced ON Line will be delayed by at least three months.  ON Line was previously expected to be in service by December 31, 2012.   The delay is attributed to addressing recent wind-related damage sustained by some of the tower structures.  As a result of the damage and as a precautionary measure, the ON Line owners have directed construction crews to lay down certain existing tower structures and cease erection of further tower structures until the owners have completed an assessment of the situation.  Other construction activities that are focused on safety and are unrelated to the wind-damage are continuing while the owners work to resolve and repair the wind-related damage, ascertain the root causes of the damage, and otherwise determine what project modifications will be necessary to ensure project safety and reliability.  As a result, NVE is also delaying the merger application of the Utilities.

Engage employees to improve processes, reduce costs, and enhance performance

The Utilities will continue to control operating and maintenance and capital costs through diligent review and process improvement initiatives by providing appropriate tools to our employees to find ways to reduce costs, improve processes, and enhance performance.  This is particularly important at a time when customer growth is low.  Going forward this will continue to be an over-

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arching theme of our energy strategy.  Our goal is to maintain, reduce, or eliminate upward pressure on our customers’ prices while always delivering safe and reliable energy and assure compliance with all laws and regulations.

Managing regulatory environment

The Utilities GRC’s currently provide an opportunity to earn a 10% ROE and 10.1% ROE for NPC and SPPC, respectively.  However, assets not currently included in rate base or that the Utilities are not allowed to earn a return affect their ability to achieve their allowed ROE.  See Note 3, Regulatory Actions, for details of regulatory assets not included in rate base or not earning a return.  Other items which may not earn a return are certain plant assets completed between filings or for which were not requested in a GRC.  The Utilities are required to file rate cases every three years to adjust general rates in order to recover their cost of service and return on investment.  The frequency of these filings is designed to more closely align earned returns with those allowed by regulators.  In addition, 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.  Historically, 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 remain focused on communicating with regulators the necessity of investments to better serve our customers, the prudency of the costs incurred, and the importance of a reasonable return on investment for our shareholders.  In 2012, the Utilities will continue to focus on reducing regulatory lag and stabilizing cash flow by filing quarterly applications, as necessary, to reset the BTER and DEAA rates.  Furthermore, the Utilities will file annual EEIR and EEPR base rate and amortization applications in an effort to recover amounts in a timely manner.

2012 Goals

Management cannot predict when economic recovery may occur in Nevada, but expects that the Nevada economy will continue to struggle for the next several years.  As such, our primary goals will focus on meeting the challenges discussed above by:

• Effectively adjusting our business decisions based on economic conditions in Nevada;

• Building a sustainable foundation for future requirements by executing our evolution of energy strategy:

• Continuing to meet system deployment milestones in order to achieve NV Energize project completion by 2012;

• Empower customers through more focused energy efficiency programs;

• Pursue cost effective renewable energy initiatives;

• Continued investment in cost effective energy efficiency and conservation programs;

• Optimizing the use of generation facilities;

• Construction of ON Line;

• Engage employees to improve processes, reduce costs, enhance performance; and

• Managing our regulatory environment.

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 are designed to recover the cost of providing generation, transmission and distribution services.  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 and the PUCN.  In addition, the PUCN 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.

As a result, the Utilities qualify for the application of regulatory accounting treatment as allowed by the Regulated Operations Topic of the FASC.  The accounting guidance for regulated operations 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.  The accounting guidance prescribes the method to be used to record the financial transactions of a regulated entity.  The criteria for applying the accounting

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guidance for regulated operations 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.

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 a carrying charge, equal to the weighted cost of capital, on such deferred balances, recognized as interest income/expense on regulatory items in the current period.

The Utilities are exposed to commodity price risk primarily related to changes in the market price of electricity, and the suspension of our hedging program, 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 and decreases 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.

Energy Efficiency Implementation Rate (EEIR) and Energy Efficiency Program Rate (EEPR)

In 2009, the Nevada Legislature passed Senate Bill 358, which required the PUCN to adopt regulations authorizing an electric utility to recover lost revenue that is attributable to the measurable and verifiable effects associated with the implementation of efficiency and conservation programs approved by the PUCN.  As a result, the PUCN opened Docket No. 09-07016 to amend and adopt the regulation.  The regulation was adopted by the Legislature on July 22, 2010.  As a result, the Utilities file annually in March, to adjust rates and set a clearing rate or EEIR effective in October of the same year for over or under collected balance, similar to the deferred energy mechanism discussed above. In addition, the regulation approved the transition of the recovery for the implementation costs of energy efficiency programs from general rates (filed every 3 years) to recovery through annual rate filings annually in March, to adjust rates and set a clearing rate or EEPR effective in October of the same year for over or under collected balance, similar to the deferred energy mechanism discussed above.  See Note 3, Regulatory Actions, for details regarding EEIR and EEPR balances.  Although a rate is established for EEIR, the actual effects associated with the implementation of energy efficiency and conservation programs is still subject to a measurement and verification process by the PUCN.  To the extent the PUCN does not approve the measurement and verification amounts, the Utilities may not be allowed recovery of such amounts.

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Fair Value Measurements and Disclosures

NVE and the Utilities’ follow the Fair Value Measurements and Disclosure Topic of the FASC, which defines fair value, establishes a framework for measuring fair value and enhances disclosures about assets and liabilities recorded at fair value.

Fair Value Measurements and Disclosure Topic of the FASC 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.  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.

 As required by the Fair Value Measurements and Disclosure Topic of the FASC, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.   NVE and the Utilities’ assessment of the significance of a particular input to fair value measurements requires judgment.  The fair value of the Utilities’ assets and liabilities are sensitive to market price fluctuations that can occur on a daily basis.  The use of different assumptions and variables in determining fair value could significantly impact the valuation and classification within the fair value hierarchy of assets and liabilities.  See Note 1, Summary of Significant Accounting Policies, Note 4, Investments and Other Property, Note 9, Derivatives and Hedging Activities, and Note 11, Retirement Plan and Post-Retirement Benefits, in the Notes to Financial Statements for more detailed disclosure of NVE’s, NPC’s and SPPC’s fair value measurements.

Accounting for Income Taxes

Current and deferred income tax provisions and benefits as well as deferred income tax assets and liabilities involve significant management estimates and judgments.  NVE and the Utilities file a consolidated federal income tax return.  Current income taxes are allocated based on NVE and the Utilities’ respective taxable income or loss and tax credits as if each utility filed a separate return.

NVE and the Utilities recognize deferred tax liabilities and assets for the future tax consequences of events that have been included in the financial statements or tax returns.  Deferred tax liabilities and assets are determined based on the difference between the financial statement and tax basis of assets and liabilities using tax rates in effect for the year in which the differences are expected to reverse.  Deferred tax assets are also recorded for deductions incurred and credits earned that have not been utilized in tax returns filed or to be filed for tax years through the date of the financial statements.  Management considers estimates of the amount and character of future taxable income by tax jurisdiction in assessing the likelihood of realization of deferred tax assets.  If it is not more likely than not that a deferred tax asset will be realized in its entirety, a valuation allowance is recorded with respect to the portion estimated not likely to be realized.  Management has determined that the Federal NOL does not require a valuation allowance based on projections of future taxable income and the reversal of deferred tax liabilities.  At December 31, 2011, NVE had a gross Federal NOL carryover of approximately $1.3 billion.  The increase in NVE's NOL from the prior year is primarily attributable to the bonus depreciation deduction taken in 2011.  The following table summarizes the NOL and tax credit carryovers and associated carryover periods, and valuation allowance for amounts which NVE has determined that realization is unlikely as of December 31, 2011 (dollars in millions):

	Deferred		Valuation		Net Deferred		Expiration
	Tax Asset		Allowance		Tax Asset		Period
Federal NOL	$	456.5	$	-	$	456.5		2024-2031
Research and development credit		12.6		-		12.6		2024-2031
Arizona state coal credits		1.7		1.2		0.5		2012-2016
Total	$	470.8	$	1.2	$	469.6

Actual income taxes could vary from estimated amounts due to the future impacts of various items, including changes in income tax laws, our financial condition and results of operations in future periods, and the review of filed tax returns by taxing

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authorities.  NVE and the Utilities’ income tax returns are regularly audited by applicable tax authorities.  Tax benefits associated with income tax positions taken, or expected to be taken, in a tax return are recorded only when the more-likely-than-not recognition threshold is satisfied and measured at the largest amount of benefit that is greater than 50% likely of being realized upon settlement.  NVE and the Utilities classify interest and penalties associated with unrecognized tax benefits as interest and other expense, respectively, within the income statement.  No interest expense or penalties associated with unrecognized tax benefits have been recorded.  As of December 31, 2011, NVE and the Utilities recorded a liability for uncertain tax positions of approximately $34.1 million.  

The Utilities reduce rates to reflect the current tax benefits associated with recognizing certain tax deductions sooner than when the expenses are recognized for financial reporting purposes.  A regulatory asset is 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 record regulatory liabilities for obligations 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.  NVE and subsidiaries had a net regulatory tax liability of $233.8 million at December 31, 2011.

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 cleanup 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 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.

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 the accounting guidance required by the Asset Retirement and Environmental Obligations Topic of the FASC.  Estimated costs from environmental remediation obligations generally are recognized no later than completion of the remedial feasibility study or when the accounting requirements for environmental obligations 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 1, Summary of Significant Accounting Policies, Asset Retirement Obligations, of the Notes to Financial Statements and 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 Post-Retirement 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 (SERP) and restoration plan, as well as a post-retirement benefit (OPEB) plan which provides health and life insurance for retired employees.

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   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.

In accordance with the Compensation Retirement Benefits Topic of the FASC, 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. Furthermore, the Compensation Retirement Benefits Topic of the FASC 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 costs through rates, amounts to be recovered in rates will be recorded as Other Regulatory Assets under the provisions of the Regulated Operations Topic of the FASC, and will be recognized as expense over a period of time.

For the years ended December 31, 2011, 2010, and 2009, NVE recorded pension expense for all pension plans of approximately $24.0 million, $30.8 million, and $51.6 million, respectively, in accordance with the accounting guidance as defined by the Compensation Retirement Benefits Topic of the FASC. Actual payments of benefits made to retirees and terminated vested employees for the years ended December 31, 2011, 2010 and 2009 were $42.5 million, $58.0 million, and $40.1 million, respectively.  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 rates of return on plan assets, the discount rates and demographic (mortality, retirement, termination) assumptions used in determining the projected benefit obligation and pension costs.

      Plan Assets

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. See Note 11, Retirement and Post-Retirement Benefits, of the Notes to Financial Statements, for further discussion on NVE’s investment strategy and asset allocation.

      Plan Assumptions and Sensitivities Analysis

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 2011 disclosures to 4.91%, as compared to 2010 disclosures of 5.09%.

The discount rate for 2011 disclosures was determined by identifying a theoretical settlement portfolio of high quality corporate bonds sufficient to provide for the plan’s projected benefit payments. In selecting an assumed discount rate for fiscal years 2010 disclosures, and for fiscal years 2011, 2010 and 2009 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 rate of return on plan assets, NVE considers past performance and economic forecasts for the types of investments held by the plan.  NVE used an assumed rate of return on plan assets of 6.75% for 2011 and 2010, as disclosed in Note 11, Retirement and Post-Retirement Benefits, of the Notes to Financial Statements. Investment returns on plan assets in the retirement plan increased by approximately $78.1 million in 2011 and increased by approximately $70.8 million in 2010.  Due to the increases in investment returns and the contributions by NVE, the funded status of the plan has improved compared to the prior year.

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 (PC) by a similar amount in the opposite direction. Each sensitivity below reflects an evaluation of the change based solely on a change in that assumption only.

	Change in			Impact on		Impact on
Actuarial Assumption (dollars in millions)	Assumption			PBO		PC
Discount Rate Increase/(Decrease)		1	%	$	(85,180)	$	(6,640)
Rate of Return on Plan Assets Increase/(Decrease)		1	%	$	-	$	(7,230)

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   Other Postretirement Benefits

NVE’s reported costs of providing other post-retirement 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 the year ended December 31, 2011, 2010, and 2009, NVE recorded other post-retirement benefit expense of $5.0 million, $5.4 million, and $10.6 million, respectively, in accordance with the provisions of the Compensation Retirement Benefits Topic of the FASC. Actual payments of benefits made to retirees for the year ended December 31, 2011, 2010 and 2009 were $12.3 million and $12.5 million, and $11.0 million, respectively.  Other post-retirement 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 post-retirement benefit costs. Other post-retirement benefit costs may also be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets, discount rates and demographic (mortality, retirement, termination) assumptions used in determining the post-retirement benefit obligation and post-retirement costs.

      Plan Assets

NVE’s other post-retirement 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 post-retirement benefit costs in future periods. See Note 11, Retirement and Post-Retirement Benefits, of the Notes to Financial Statements, for further discussion on NVE’s investment strategy and asset allocation.

      Plan Assumptions and Sensitivities Analysis

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 2011 disclosures to 5.09%, as compared to 2010 disclosures of 5.2%.  In determining the other post-retirement benefit obligation and related cost, these assumptions can change with each measurement date, and such changes could result in material changes to such amounts.

The discount rate for 2011 disclosures was determined by identifying a theoretical settlement portfolio of high quality corporate bonds sufficient to provide for the plan’s projected benefit payments. In selecting an assumed discount rate for fiscal year 2010 disclosures, and for fiscal years 2011, 2010, and 2009 benefit 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 rate of return on plan assets, NVE considers past performance and economic forecasts for the types of investments held by the plan. NVE used an assumed rate of return on plan assets of 7.10% for some plans and 6.75% for others in 2011 and 2010, as disclosed in Note 11, Retirement and Post-Retirement Benefits, of the Notes to Financial Statements. Investment returns on plan assets increased $8.6 million in 2011 and increased $10.6 million in 2010.

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 post-retirement benefit obligation (APBO) and the reported annual other post-retirement benefit cost (PBC) on the income statement by a similar amount in the opposite direction.  Each sensitivity below reflects an evaluation of the change based solely on a change in that assumption only.

	Change in			Impact on		Impact on
Actuarial Assumption (dollars in millions)	Assumption			APBO		PBC
Discount Rate Increase/(Decrease)		1	%	$	(15,990)	$	(1,190)
Rate of Return on Plan Assets Increase/(Decrease)		1	%		-		(910)
Health Care Cost Trend Rate Increase/(Decrease)		1	%	$	6,450	$	1,260

Revenues

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

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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, line loss and the Utilities’ current tariffs.  Accounts receivable as of December 31, 2011, include unbilled receivables of $93 million and $51 million for NPC and SPPC, respectively.  Accounts receivable as of December 31, 2010, include unbilled receivables of $89 million and $60 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 $39.3 million, $50.1 million and $38.7 million of interest costs for the years ended December 31, 2011, 2010 and 2009, respectively.  The decrease in interest costs for the year ended December 31, 2011 as compared to the same period in 2010 is primarily due to early redemption costs incurred in 2010 as discussed below and the redemption of NVE’s 6.75% Senior Notes in November 2011.  The increase in interest costs for the year ended December 31, 2010 as compared to the same period in 2009 was primarily due to the early redemption of $230 million in the aggregate principal amount of 8.625% Senior Notes due 2014, and approximately $63.7 million in the aggregate principal amount of 7.803% Senior Notes due 2012 and the issuance of $315 million 6.25% Senior Notes, due 2020.  See Note 6, Long-Term Debt, of the Notes to Financial Statements, for further discussion of debt transactions.  

   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 Operationsfor NVE Consolidated.

ANALYSIS OF CASH FLOWS

NVE’s cash flows increased in 2011 compared to 2010 due to a decrease in cash used by investing and financing, offset partially by a reduction in cash from operating activities.

Cash From Operating Activities.  The decrease in cash from operating activities was primarily due to a decrease in net income, overall decrease in rates resulting from quarterly BTER adjustments and negative DEAA rates implemented in October 2010 to refund prior period over collected balances to customers, as well as a reduction in revenues from California customers due to the sale of the California Assets, as discussed in Note 16, Assets Held for Sale, of the Notes to Financial Statements.  Also contributing to this decrease was an increase in coal and other inventory, increased incentive compensation payments for 2010 operating results, refund of customer deposits and an increase in conservation programs and solar rebates.  These decreases were partially offset by an increase in cash resulting from NPC’s deferred rate increase beginning in October 2010 and recovery of deferred conservation program costs.

Cash Used By Investing Activities.  The decrease in cash used by investing activities was primarily due to the receipt of proceeds from the sale of California Assets by SPPC and telecommunication towers by NPC, as discussed in Note 16, Assets Held for Sale, of the Notes to Financial Statements.  Further contributing to the decrease in cash used by investing activities was federal funding under the American Recovery and Reinvestment Act of 2009, as part of the NV Energize project.

Cash Used By Financing Activities.  Cash used by financing activities decreased due to a reductions in draws on the Utilities’ revolving credit facilities, the redemption of NPC’s $350 million aggregate principal amount of 8.25%, Series A, General and Refunding Mortgage Notes, which were partially paid by proceeds from the issuance of NPC’s $250 million 5.45%, Series Y, General and Refunding Mortgage Notes and a draw on the credit facility.

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NVE’s cash flows increased during 2010 compared to 2009 due to an increase in cash from operating activities and a decrease in cash used by investing activities, offset by a decrease in cash from financing activities.

Cash From Operating Activities. The increase in cash from operating activities is primarily due to increased revenues as a result of the rate increase in NPC’s GRC and decreased fuel and purchased power costs, offset by BTER, WECA and DEAA rate reductions, a decrease in funding for pension plans, an increase in spending on energy conservation programs, and a refund to a transmission customer in 2009.

Cash Used By Investing Activities.  Cash used by investing activities decreased mainly due to the slowdown in construction for infrastructure, and proceeds from the sale of property.

Cash Used By Financing Activities. Cash used by financing activities increased primarily due to the redemption of SPPC’s 6.25% General and Refunding Mortgage Notes, Series H due 2012 in an aggregate principal amount of $100 million, a decrease in debt issuance at NPC, an increase in payments on NPC’s revolving credit facility, and higher dividend payments.

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. Another significant use of cash is the refunding of previously over-collected amounts from customers.  See Note 3, Regulatory Actions, of the Notes to Financial Statements for more details of over-collected balances.  Operating cash flows can be significantly influenced by factors such as weather, regulatory outcomes, and economic conditions.  Available liquidity as of December 31, 2011 was as follows (in millions):

Available Liquidity as of December 31, 2011
			NVE		NPC		SPPC
Cash and Cash Equivalents			$	20.1	$	65.9	$	55.2
	Balance available on Revolving Credit Facilities(1)			N/A		578.8		237.5
		Less Reduction for Hedging Transactions(2)		N/A		-		-
			$	20.1	$	644.7	$	292.7
(1)		As of February 22, 2012, NPC and SPPC had no borrowings under their revolving credit facilities.
(2)		Reduction for hedging transactions reflects balances as of November 30, 2011.  NPC and SPPC are currently unhedged, as discussed
		further in Financial Gas Hedges.

NVE and the Utilities attempt to maintain their cash and cash equivalents in highly liquid investments, such as U.S. Treasury Bills and bank deposits.  In addition to cash on hand, the Utilities’ may use their revolving credit facilities in order to meet their liquidity needs.  Alternatively, depending on the usage of their revolving credit facilities, the Utilities may issue debt, subject to certain restrictions as discussed in Factors Affecting Liquidity, Ability to Issue Debt, below.

NVE will have no debt maturities in 2012 or 2013.   However, NPC’s debt maturities in 2012 include its $130 million 6.50% General and Refunding Notes, Series I, which mature on April 15, 2012.  In addition, NPC is required to redeem approximately $98.1 million of its variable rate debt, due 2020, prior to ON Line’s commercial operation date. SPPC has no debt maturities in 2012.  However, SPPC’s $250 million 5.45% General and Refunding Notes, Series Q, will mature on September 1, 2013.

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.    Furthermore, in order to fund long-term capital requirements and maturing debt obligations, NVE and the Utilities will use a combination of internally generated funds, 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.  However, if energy costs rise at a rapid rate and the Utilities do not recover the cost of fuel, purchased power and operating costs in a timely manner or the Utilities were to experience a credit rating downgrade resulting in the posting of collateral as discussed below under Gas Supplier Matters and Financial Gas Hedges, the amount of liquidity available to the Utilities could be significantly less.  In order to maintain sufficient liquidity, NVE and the Utilities may be required to delay capital expenditures, re-finance debt or issue equity at NVE.

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In 2011, the Utilities credit ratings on their senior secured debt remained at investment grade (see Credit Ratings below).   In 2011, NVE and the Utilities did not experience any limitations in the credit markets nor do we expect any in 2012.  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.

As of February 22, 2012, NVE has approximately $24.3 million payable of debt service obligations remaining for 2012, which it intends to pay through dividends from subsidiaries.  (See Factors Affecting Liquidity-Dividends from Subsidiaries below).  On February 10, 2012, NPC and SPPC declared a dividend payable to NVE of $39 million and $20 million, respectively.                     

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

		2011			2010
				Percent of Total			Percent of Total
		Amount		Capitalization	Amount		Capitalization
Current Maturities of Long-Term Debt		$	139,985	1.6%	$	355,929	4.1%
Long-Term Debt			5,008,931	58.6%		4,924,109	57.1%
Shareholder's Equity			3,406,079	39.8%		3,350,818	38.8%
	Total	$	8,554,995	100.0%	$	8,630,856	100.0%

Capital Requirements

   Construction Expenditures

NVE’s consolidated cash requirements for construction expenditures for 2012 are projected to be $469 million.  NVE’s consolidated cash requirements for construction expenditures for 2012-2016 are projected to be $2.0 billion.  Gross construction expenditures, including AFUDC debt, net salvage and CIAC for the years ended 2011, 2010 and 2009 were $620.5 million, $629.5 million, and $843.1 million, respectively. Net cash requirements to fund construction for the years ended 2011, 2010 and 2009 were $522.2 million, $577.3 million and $774.6 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):

		2012		2013		2014		2015		2016
Electric Facilities:
	Generation	$	137,799	$	213,031	$	140,612	$	97,569	$	100,624
	Distribution		134,956		108,131		109,984		114,056		113,312
	Transmission		110,734		46,265		96,733		47,633		37,234
	Other		71,663		56,083		72,744		81,943		69,015
Total			455,152		423,510		420,073		341,201		320,185
Gas Facilities:
	Distribution		26,468		12,486		12,428		12,671		12,788
	Other		272		275		277		282		285
Total			26,740		12,761		12,705		12,953		13,073
Common Facilities			26,127		11,274		10,786		10,997		11,099
Total		$	508,019	$	447,545	$	443,564	$	365,151	$	344,357

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

		2012		2013		2014		2015		2016
Construction Expenditures		$	508,019	$	447,545	$	443,564	$	365,151	$	344,357
AFUDC			(14,388)		(12,596)		(14,336)		(12,992)		(15,308)
Net Salvage/Cost of Removal			8,205		7,136		7,241		5,647		5,360
Net Customer Advances and CIAC			(32,390)		(23,131)		(21,663)		(18,011)		(16,762)
	Total Cash Requirements	$	469,446	$	418,954	$	414,806	$	339,795	$	317,647

   Contractual Obligations (NVE Consolidated)

The table below provides NVE’s contractual obligations on a consolidated basis, as of December 31, 2011, (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, 2011, or funding requirements under pension and other post-retirement benefit plans, as discussed in Note 11, Retirement Plan and Post-Retirement Benefits, of the Notes to Financial Statements, as of December 31, 2011.  Additionally, at December 31, 2011, NVE has recorded an uncertain tax liability of $34.1 million in accordance with the accounting guidance for Uncertainty in Income Taxes Topic of the FASC 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 uncertain tax liability is included in the contractual obligations table below (dollars in millions):

	Payment Due by Period
	2012		2013		2014		2015		2016		Thereafter		Total
NPC/SPPC Long-Term Debt Maturities	$	130	$	250	$	125	$	250	$	210	$	3,635	$	4,600
NPC/SPPC Long-Term Debt Interest Payments		264		257		239		225		197		2,156		3,338
NVE Long-Term Debt Maturities		-		-		195		-		-		315		510
NVE Long-Term Debt Interest Payments		25		25		24		20		20		76		190
Purchased Power(1)		492		427		416		425		433		3,081		5,274
Purchased Power - Not commercially operable(2)		75		119		204		239		247		5,360		6,244
Coal & Natural Gas		376		187		58		55		39		119		834
Transportation(3)		168		217		218		155		146		1,779		2,683
Long-Term Service Agreements(4)		49		21		21		20		17		71		199
Capital Projects(5)		129		59		-		-		-		-		188
Operating Leases		18		17		16		11		6		74		142
Capital Leases		10		10		7		5		5		61		98
Total Contractual Cash Obligations	$	1,736	$	1,589	$	1,523	$	1,405	$	1,320	$	16,727	$	24,300

(1)	Related party purchase power agreements have been eliminated for 2012 and a portion of 2013.  Upon completion of ON Line, the related party purchase power agreements will no longer be required.
(2)	Represents estimated payments under renewable energy power purchase contracts, which have been approved by the PUCN and are contingent upon the developers obtaining commercial operation and their ability to deliver energy.
(3)	Included is the TUA with GBT of which NPC is responsible for 95% and SPPC 5% and is contingent upon final construction costs and reaching commercial operation.
(4)	Amounts based on estimated usage.
(5)	Capital projects include NV Energize and NPC’s requirement to purchase the undepreciated cost of capital of Reid Gardner Generating Station Unit No. 4 from CDWR, at which time, NPC will assume all associated operating and maintenance expense.  Additionally, the Utilities, as joint owners, have obligations regarding the construction of ON Line, of which NPC will be responsible for 95% and SPPC 5%.

  Pension and Other Post-Retirement Benefit Plan 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 decrease in 2012 by approximately $6.5 million compared to the 2011 cost of $29.0 million. As of December 31, 2011, the measurement date, the plan was under funded under the provisions of the Compensation Retirement Benefits Topic of the FASC.  Refer to Note 11, Retirement Plan and Post-Retirement Benefits, of the Notes to Financial Statements. During 2011, NVE funded a total of $40.6 million to the trusts established for the qualified

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pension and other postretirement benefit plans. At the present time, it is not anticipated that additional funding will be required in 2012 to meet the minimum funding level requirements defined by the Pension Protection Act of 2006.  However, NVE and the Utilities have included in their 2012 assumptions funding levels similar to the 2011 funding.  The amounts to be contributed in 2012 may change subject to market conditions.

Financing Transactions (NVE-Holding Company)

$195 Million Term Loan Agreement

In October 2011, NVE entered into a $195 million 3-year term loan agreement (Term Loan).  The Term Loan is an unsecured, single-draw loan that is due on October 7, 2014.  The borrowing under the Term Loan bears interest at the LIBOR rate plus a margin. The current LIBOR margin rate is 2.00%.   The margin varies based upon NVE’s long–term unsecured debt credit rating by S&P and Moody’s.  However, NVE entered into a floating- for- fixed interest rate swap agreement to lock in an effective interest rate of 2.81% for the length of the Term Loan.

The Term Loan contains conditions of borrowing, events of default, and affirmative and negative covenants.  The Term Loan includes (i) a financial covenant to maintain a ratio of total consolidated indebtedness to total consolidated capitalization, determined on the last day of each fiscal quarter, not to exceed 0.70 to 1.00 and (ii) a fixed charge covenant that requires NVE not to permit the fixed charge coverage ratio, determined on the last day of each fiscal quarter, to be less than 1.50 to 1.00.

        Redemption of 6.75% Senior Notes

In November 2011, NVE used the proceeds of the Term Loan, plus cash on hand, to redeem its unsecured $191.5 million 6.75% Senior Notes (“Senior Notes”).  The notes were redeemed at 102.25% of the stated principal amount plus accrued interest to the date of redemption.   With this redemption, NVE and the Utilities are no longer subject to the restrictive covenants contained in the Senior Notes, which were more restrictive than the covenants describedabove for the Term Loan.

Factors Affecting Liquidity

   Ability to Issue Debt

Certain debt of NVE (holding company) places restrictions on debt incurrence and liens, 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 1.50 to 1.00, and the ratio of consolidated total indebtedness to consolidated capitalization does not exceed 0.70 to 1.00.  Under these covenant restrictions, as of December 31, 2011, NVE (consolidated) would be allowed to incur up to $2.8 billion of additional indebtedness.  The amount of additional indebtedness allowed would likely be impacted if there is a change in current market conditions or material change in our financial condition.  NPC’s and SPPC’s Ability to Issue Debt sections further discuss their limitations on their ability to issue debt.

   Effect of Holding Company Structure

As of December 31, 2011, NVE (on a stand-alone basis) has outstanding debt and other obligations including, but not limited to: $195 million Term Loan due 2014; and $315 million of its unsecured 6.25% Senior Notes due 2020.

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, 2011, NVE, NPC, SPPC and their subsidiaries had approximately $5.1 billion of debt and other obligations outstanding, consisting of approximately $3.4 billion of debt at NPC, approximately $1.2 billion of debt at SPPC and approximately $510 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.

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   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.  Since NPC and SPPC are public utilities, they are subject to regulation by the PUCN, which may 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.

   Credit Ratings

The liquidity of NVE and the Utilities, the cost and availability of borrowing by the Utilities under their respective credit facilities, the potential exposure of the Utilities to collateral calls under various contracts and the ability of the Utilities to acquire fuel and purchased power on favorable terms are all directly affected by the credit ratings for the companies’ debt.  NPC’s and SPPC’s senior secured debt is rated investment grade by three NRSRO’s:  Fitch, Moody’s and S&P.    As of December 31, 2011, the ratings are as follows:

			Rating Agency
			Fitch(1)	Moody’s(2)	S&P(3)
NVE		Sr. Unsecured Debt	BB	Ba2	BB+
NPC		Sr. Secured Debt	BBB*	Baa2*	BBB*
SPPC		Sr. Secured Debt	BBB*	Baa2*	BBB*
*	Investment grade
(1)	Fitch’s lowest level of “investment grade” credit rating is BBB-.
(2)	Moody’s lowest level of “investment grade” credit rating is Baa3.
(3)	S&P’s lowest level of “investment grade” credit rating is BBB-.

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

            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.  Each security rating agency has its own methodology for assigning ratings, and, accordingly, each rating should be evaluated in the context of the applicable methodology, independently of all other ratings.  The rating agencies provide ratings at the request of the company being rated and charge the company fees for their services.

   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.

Under these contracts, a material adverse change, which includes a credit rating downgrade of NPC and SPPC, may allow the counterparty to request adequate financial assurance, which, if not provided within three business days, could cause a default.  Most contracts and confirmations for purchased power have been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery in response to requests for financial assurance.  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, 2011 for all suppliers continuing to provide power under a WSPP agreement would approximate a $37.5 million payment or obligation to NPC.  No amounts would be due to or from SPPC.  These contracts qualify for the normal purchases scope exception under the Derivatives and Hedging Topic of the FASC, and as such, are

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not required to be marked-to-market on the balance sheet.  Refer to Note 6, 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.  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 in response to requests for financial assurances.  Forward physical gas supplies are purchased under index based pricing terms and as such do not carry forward mark-to-market exposure.   

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 a transmission counterparty for which it is required to post cash collateral or a letter of credit in the event of credit rating downgrades.   As of December 31, 2011, the maximum amount of additional collateral NPC would be required to post under these contracts in the event of credit rating downgrades was approximately $64.6 million.  Of this amount, approximately $19.5 million would be required if NPC’s Senior Unsecured ratings are rated below BB (S&P) or Ba3 (Moody’s) and an additional amount of approximately $45.2 million would be required if NPC’s Senior Secured ratings are downgraded to below investment grade.

   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.  As discussed under NPC’s and SPPC’s Financing Transactions, the availability under the Utilities’ revolving credit facilities is reduced for net negative mark-to-market positions on hedging contracts with counterparties who are lenders under the revolving credit facilities provided that the reduction of availability under the revolving credit facilities shall at no time exceed 50% of the total commitments then in effect under the credit facilities.  As a result of the suspension of the Utilities hedging program, there was no negative mark-to-market exposure for NPC and SPPC as of November 30, 2011 that would impact credit availability during the month of December 2011.  Beginning in October 2009, the Utilities suspended their hedging programs; however, prior to the suspension, it was the general policy of the Utilities to purchase hedges three seasons ahead.  As a result certain hedges entered into prior to the suspension in October 2009, did not terminate until 2011.  As of November 2011, all hedging transactions have expired or terminated and the Utilities remain unhedged.  If deemed prudent, the Utilities may still purchase hedging instruments in the event circumstances occur that may have the potential to increase the cost of fuel and purchased power.

   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 an 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.

NEVADA POWER COMPANY

RESULTS OF OPERATIONS

NPC recognized net income of $132.6 millionin 2011 compared to net income of $185.9 million in 2010 and $134.3 million in 2009.  In 2011, NPC paid dividends to NVE of approximately $99 million.  In February 2012, NPC declared a dividend of approximately $39 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.

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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 energy costs and EEPR costs provides a measure of income available to support the other operating expenses of NPC.

EEPR costs are conservation costs being recovered from ratepayers through EEPR revenues which were implemented in July 2011 (see Note 3, Regulatory Actions, of the Notes to Financial Statements).   Costs incurred prior to the implementation of the EEPR are recovered through general rates and amortized to other operating expense.  See Note 3, Regulatory Actions, of the Notes to Financial Statements for conservation program amount details.  The EEPR mechanism is designed such that conservation costs are equal to revenues collected and any over/under collection is deferred as a regulatory asset/liability until rates are reset.  As a result, amounts related to EEPR do not have an effect on gross margin, operating income or net income.

For reconciliation to operating income, see Note 2, Segment Information, of the Notes to Financial Statements.  Gross margin changes are based primarily on general base rate adjustments (which are required by statute to be filed every three years).

The components of gross margin were (dollars in thousands):

		2011			2010			2009
				Change from			Change from
		Amount		Prior Year	Amount		Prior Year	Amount
Operating revenues		$	2,054,393	(8.8)%	$	2,252,377	(7.1)%	$	2,423,377
Energy Costs:
	Fuel for power generation		498,487	(15.3)%		588,419	0.1%		587,647
	Purchased power		477,226	(5.5)%		505,239	(19.5)%		627,759
	Deferred energy		(16,300)	(117.2)%		94,843	(54.3)%		207,611
Energy efficiency program costs			37,292	N/A		-	N/A		-
		$	996,705	(16.1)%	$	1,188,501	(16.5)%	$	1,423,017
Gross Margin		$	1,057,688	(0.6)%	$	1,063,876	6.3%	$	1,000,360

Gross margin decreased for the year ended December 31, 2011, compared to the same period in 2010, primarily due to decreased customer usage as a result of milder weather and conservation programs.  Partially offsetting this decrease was the implementation of the EEIR rates, which became effective August 1, 2010 as well as a slight increase in customer growth.

Gross margin increased for the year ended December 31, 2010, compared to the same period in 2009, primarily due to an increase in BTGR revenue as a result of NPC’s 2008 GRC effective July 1, 2009.  Partially offsetting the increase in gross margin was a decrease in usage per customer due to conservation programs, economic conditions and hotter than normal weather in May 2009.

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):

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Operating Revenues
			2011			2010			2009
					Change from			Change from
			Amount		Prior Year	Amount		Prior Year	Amount
Operating revenues
	Residential		$	1,000,068	(7.8)%	$	1,084,497	(5.2)%	$	1,143,836
	Commercial			398,832	(8.6)%		436,343	(8.6)%		477,477
	Industrial			591,533	(10.9)%		663,586	(7.9)%		720,850
		Retail Revenues		1,990,433	(8.9)%		2,184,426	(6.7)%		2,342,163
	Other			63,960	(5.9)%		67,951	(16.3)%		81,214
		Total Operating Revenues	$	2,054,393	(8.8)%	$	2,252,377	(7.1)%	$	2,423,377
Retail sales in thousands of MWhs				20,529	(0.5)%		20,642	(1.5)%		20,957
Average retail revenue per MWh			$	96.96	(8.4)%	$	105.82	(5.3)%	$	111.76

NPC’s retail revenues decreased for the year ended December 31, 2011, compared to the same period in 2010, primarily due to decreased energy rates from NPC’s various BTER quarterly updates, the annual Deferred Energy cases effective October 1, 2010 and October 1, 2011 and the expiration of the Western Energy Crisis Amortization rate on May 1, 2010 (See Note 3, Regulatory Actions of the Notes to the Financial Statements).  Residential retail revenues decreased further due to decreases in customer usage resulting from milder temperatures during the summer months of 2011 and conservation programs. These decreases were partially offset by EEPR revenue, effective July 1, 2011 (See Note 3, Regulatory Actions of the Notes to the Financial Statements). Average residential and commercial customers increased by 1.1% and 0.4%, respectively, while average industrial customers decreased by 1.9%.

NPC’s retail revenues decreased for the year ended December 31, 2010, compared to the same period in 2009, primarily due to decreased energy rates from NPC’s various BTER quarterly updates, the annual Deferred Energy case effective October 1, 2010 and the expiration of the Western Energy Crisis Amortization rate on May 1, 2010 (see Note 3, Regulatory Actions, of the Notes to the Financial Statements).  Also contributing to the decrease was a decrease in customer usage due to conservation programs, economic conditions and hotter than normal weather in May 2009.  These decreases were partially offset by increases in general rates as a result of NPC’s 2008 GRC, effective July 1, 2009 (see Note 3, Regulatory Actions, of the Notes to the Financial Statements).  Average residential, commercial, and industrial customers increased by 0.4%, 0.8% and 0.3%, respectively.

Other Operating Revenues decreased for the year ended December 31, 2011, compared to the same period in 2010, primarily due to decreased revenue from Public Street and Highway Lighting, resulting from lower energy rates.

Other Operating Revenues decreased for the year ended December 31, 2010, compared to the same period in 2009.  The decrease is primarily due to the expiration of a significant transmission agreement with Calpine Energy Services and decreases in sales for resale.

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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		2011			2010			2009
				Change from			Change from
		Amount		Prior Year	Amount		Prior Year	Amount
Energy Costs
	Fuel for power generation	$	498,487	(15.3)%	$	588,419	0.1%	$	587,647
	Purchased power		477,226	(5.5)%		505,239	(19.5)%		627,759
Energy Costs		$	975,713	(10.8)%	$	1,093,658	(10.0)%	$	1,215,406
MWhs
	MWhs Generated (in thousands)		15,034	(2.4)%		15,405	(6.2)%		16,431
	Purchased Power (in thousands)		6,577	3.6%		6,351	11.5%		5,697
Total MWhs			21,611	(0.7)%		21,756	(1.7)%		22,128
Average cost per MWh
	Average fuel cost per MWh of Generated Power	$	33.16	(13.2)%	$	38.20	6.8%	$	35.76
	Average cost per MWh of Purchased Power	$	72.56	(8.8)%	$	79.55	(27.8)%	$	110.19
	Averege cost per MWh	$	45.15	(10.2)%	$	50.27	(8.5)%	$	54.93

Energy Costs decreased for the year ended December 31, 2011, compared to the same period in 2010, primarily due to a decrease in hedging costs. Volume was relatively flat year over year. The average cost per MWh of energy decreased primarily due to decreased hedging costs and lower natural gas prices.

• Fuel for power generation costs decreased for the year ended December 31, 2011, primarily due to a decrease in hedging costs as well as lower natural gas prices and a decrease in volume due to planned outages.  In May 2011, the expansion at the Harry Allen Generation Station became commercially operable.

• Purchased power costs decreased for the year ended December 31, 2011, primarily due to a decrease in hedging costs related to tolling contracts as well as a decrease in market prices. Volume for the year ended December 31, 2011 increased primarily due to planned outages within the generation fleet early in the year and due to mandated power purchases.

Energy Costs decreased for the year ended December 31, 2010, compared to the same period in 2009, primarily due to a decrease in costs associated with hedging activities offset by a slight increase in natural gas prices.  In 2010, self generation, which is primarily gas fired generating units, satisfied 71% of NPC’s system load.

• Fuel for generation costs increased for the year ended December 31, 2010, primarily due to higher cost of natural gas and the change in the method of allocating electric tolling option expense between fuel for generation and purchased power which had no impact on gross margin or operating income, partially offset by a decrease in volume and a decrease in costs associated with hedging activities.  MWhs generated decreased for the year ended December 31, 2010, primarily due to planned outages within internal generation in the early part of the year.  The average price per MWh of generated power increased for the year due to an increase in natural gas costs and the change in method of allocating electric tolling option expense, partially offset by a decrease in costs associated with hedging activities.

• Purchased power costs and the average cost per MWh of purchased power decreased for the year ending December 31, 2010, primarily due to a decrease in costs associated with hedging activities and the change in method of allocating electric tolling option expense, as discussed above, partially offset by an increase in renewable energy purchases and capacity contracts. Purchased power MWhs increased for the year ending December 31, 2010, due to renewable energy purchases and plant outages within internal generation.

Deferred Energy
	2011			2010			2009
			Change from			Change from
	Amount		Prior Year	Amount		Prior Year	Amount
Deferred energy	$	(16,300)	(117.2)%	$	94,843	(54.3)%	$	207,611

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Deferred energy 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 also includes the current amortization of fuel and purchased power costs previously deferred.  Refer to Note 3, Regulatory Actions, of the Notes to Financial Statements for further detail of deferred energy balances.

Amounts for 2011, 2010 and 2009 include amortization of deferred energy of $(105.6) million, $1.2 million and $42 million, respectively; and an over-collection of amounts recoverable in rates of $89.3 million, $93.6 million and $165.6 million, respectively.

Other Operating Expenses
	2011			2010			2009
			Change from			Change from
	Amount		Prior Year	Amount		Prior Year	Amount
Energy efficiency program costs	$	37,292	N/A	$	-	N/A	$	-
Other operating expenses	$	260,127	(0.2)%	$	260,535	(6.9)%	$	279,865
Maintenance	$	64,320	(10.4)%	$	71,759	1.0%	$	71,019
Depreciation and amortization	$	252,191	11.5%	$	226,252	4.8%	$	215,873

Energy efficiency program costs are conservation costs being recovered from ratepayers through EEPR revenues which were implemented in July 2011 (See Note 3, Regulatory Actions, of the Notes to Financial Statements).  Costs incurred prior to the implementation of the EEPR are recovered through general rates and amortized to other operating expense discussed below.  The EEPR mechanism is designed such that conservation costs expense are equal to revenues collected and any over/under collection is deferred as a regulatory asset/liability, until rates are reset.  As a result, amounts related to EEPR do not have an effect on gross margin, operating income or net income.

Other operating expense decreased for the year ended December 31, 2011, compared to the same period in 2010, primarily due to a decrease in consulting fees, overall lower generating expense, lower employee pension and benefit costs and higher capitalization of administrative and general costs for the Harry Allen Generating Station. The decrease in other operating expense was partially offset by an increase in stock compensation costs.

Other operating expense decreased for the year ended December 31, 2010, compared to the same period in 2009, primarily due to lower employee pension and benefit expenses, costs incurred in 2009 related to severance programs, as discussed further in Note 17, Severance Programs, of the Notes to Financial Statements and a reduction in bad debt expense. In addition, other operating expenses decreased as a result of costs associated with the REPR.  Beginning in 2010, these amounts are reported net of their related operating expense; as such, REPR amounts no longer affect operating expense.  In 2009, REPR costs were not material and were included in operating expenses with a corresponding amount recorded to revenues and had no effect on net income.  The decrease was partially offset by increases in amortization of DSM programs and higher operating leases.

Maintenance expense decreased for the year ended December 31, 2011, compared to the same period in 2010, primarily due to the accrual in 2010 for estimated payments for the termination of the long-term service agreement for the Higgins Generating Station, which was reversed in the third quarter of 2011 upon final calculation of the termination amount.  Also contributing to the decrease in maintenance expense was planned maintenance outages that occurred in 2010 at the Higgins, Lenzie and Silverhawk Generating Stations. This decrease was partially offset by planned maintenance outages that occurred in 2011 at the Reid Gardner and Harry Allen Generating Stations.

Maintenance expense increased for the year ended December 31, 2010, compared to the same period in 2009, primarily due to termination of a long-term service agreement and maintenance at the Higgins, Harry Allen and Silverhawk Generating Stations.  This increase was partially offset by planned maintenance outages that occurred in 2009 at the Reid Gardner and Clark Generating Stations.

Depreciation and amortization increased for the year ended December 31, 2011, compared to 2010, primarily due to general increases in plant-in-service, including the Harry Allen Generating Station and EWAM projects.

Depreciation and amortization expenses increased for the year ended December 31, 2010, compared to the same period in 2009, primarily due to regular system growth.

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Interest Expense
	2011			2010			2009
			Change from			Change from
	Amount		Prior Year	Amount		Prior Year	Amount
Interest expense
(net of AFUDC-debt: $6,770, $21,443 and $17,184)	$	221,953	3.5%	$	214,367	(5.3)%	$	226,252

Interest expense increased for the year ended December 31, 2011, compared to the same period in 2010, primarily due to a decrease in AFUDC primarily due to the completion of various construction projects, including Harry Allen Generating Station and EWAM projects.  Further contributing to the increase was interest expense due to the issuance of $250 million, Series X, General and Refunding Mortgage Notes in September 2010 and the issuance of $250 million, Series Y, General and Refunding Mortgage Notes in May 2011.  Partially offset by a decrease in interest expense resulting from the redemption of $350 million General and Refunding Mortgage Notes, Series A, in June 2011, partial redemptions of Series 1995 A, B, C, and D in October 2010 and lower credit facility balances in 2011.

Interest expense decreased for the year ended December 31, 2010, compared to the same period in 2009, primarily due to the expiration in 2009 of amortization costs related to debt issues and redemptions, an increase to AFUDC due to construction at the Harry Allen Generating Station, lower interest on variable rate debt and the partial redemption of Series 1997A in December 2009 and the redemptions of Series 1995 A, B, C, and D in October 2010. Partially offsetting this decrease was higher credit facility balances in 2010, and increased interest expense due to the issuance of $500 million, Series V, General and Refunding Mortgage Notes in March 2009 and the issuance of $250 million, Series X, General and Refunding Mortgage Notes in September 2010. See Note 6, Long-Term Debt, for further discussion.

Other Income (Expense)
	2011			2010			2009
			Change from			Change from
	Amount		Prior Year	Amount		Prior Year	Amount
Interest income (expense) on regulatory items	$	(8,572)	170.5%	$	(3,169)	(191.5)%	$	3,463
AFUDC-equity	$	8,298	(67.1)%	$	25,229	20.0%	$	21,025
Other income	$	14,774	(4.9)%	$	15,541	(20.9)%	$	19,658
Other expense	$	(33,020)	155.1%	$	(12,946)	(29.3)%	$	(18,320)

The increase in interest expense on regulatory items for the year ended December 31, 2011, compared to the same period in 2010, is primarily due to higher over-collected deferred energy balances during 2011 when compared to deferred energy balances during 2010.  Also contributing to the increase in interest expense on regulatory items was a decrease in interest income as a result of lower deferred rate balances in 2011.  See Note 3, Regulatory Actions, for further details of deferred energy balances and discussion of the deferred rate increase under NPC’s 2008 GRC.

The change in interest income (expense) on regulatory items for the year ended December 31, 2010, compared to the same period in 2009, is primarily due to over-collected deferred energy balances. See Note 3, Regulatory Actions, for further details of deferred energy balances.

AFUDC-equity decreased for the year ended December 31, 2011, compared to 2010, primarily due to the completion of various construction projects, including Harry Allen Generating Station and EWAM projects.

AFUDC-equity increased for the year ended December 31, 2010, compared to 2009, primarily due to construction at the Harry Allen Generating Station.

Other income decreased for the year ended December 31, 2011, compared to the same period in 2010, primarily due to interest income recorded in 2010 related to an income tax refund, lower gains on investments, partially offset by higher carrying charges for energy conservation programs and higher interest on EEIR balance in 2011.

Other income decreased for the year ended December 31, 2010, compared to the same period in 2009, due to favorable settlement of outstanding legal matters in 2009 associated with the Natural Gas Provider case, as discussed further in Note 13, Commitments and Contingencies, in the Notes to Financial Statements.  This decrease is partially offset by higher interest income related to an income tax refund and investments in 2010.

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Other expense increased for the year ended December 31, 2011, compared to the same period in 2010, primarily due to adjustment in 2011 resulting from NPC’s GRC in 2011, the disallowance for EEIR in 2011, higher donations in 2011, and higher losses on investments in 2011.

Other expense decreased for the year ended December 31, 2010, compared to the same period in 2009, primarily due to charges in 2009 resulting from NPC’s GRC in 2009, a disallowance related to contract pricing for energy in 2009, partially offset by adjustments for the settlement of the deferred energy rate case in 2010.

ANALYSIS OF CASH FLOWS

NPC’s cash flows decreased during in 2011 compared to 2010 due to a decrease in cash from operating and financing activities, offset partially by a reduction in cash used by investing activities.

Cash From Operating Activities. The decrease in cash from operating activities was primarily due to a decrease in net income, an overall decrease in rates resulting from quarterly BTER adjustments and negative DEAA rates implemented in October 2010 to refund prior period over collected balances to customers, increased incentive compensation payments for the 2010 operating results, an increase in coal and other inventory, refunds of customer deposits and an increase in conservation programs and solar rebates.  These decreases were partially offset by an increase in cash resulting from NPC’s deferred rate increase beginning in October 2010, the recovery of deferred conservation program costs and lower funding for pension plans.

Cash Used By Investing Activities. The decrease in cash used by investing activities was primarily due to proceeds from the sale of certain telecommunication towers as discussed in Note 16, Assets Held for Sale, and federal funding under the American Recovery and Reinvestment Act of 2009, as a part of the NV Energize project.

Cash Used By Financing Activities. Cash used by financing activities decreased primarily due to a reduction in draws on NPC’s revolving credit facility, the redemption of NPC’s $350 million aggregate principal amount of 8.25%, Series A, General and Refunding Mortgage Notes, which were partially paid by proceeds from the issuance of NPC’s $250 million 5.45%, Series Y, General and Refunding Mortgage Notes.  Also contributing to the decrease was the payment of dividends to NVE and a settlement payment for the interest rate swap agreement as discussed in Note 6, Long Term Debt, of the Notes to Financial Statements.  The decrease was partially offset by a capital contribution from NVE.

NPC’s cash flows increased during 2010 compared to 2009 due to an increase in cash from operating activities and a reduction in cash used for investing activities, partially offset by a decrease in cash from financing activities.

Cash From Operating Activities. The increase in cash from operating activities is primarily due to increased revenues as a result of the rate increase in NPC’s 2008 GRC, decreased purchased power costs, a decrease in funding for pension plans, and a refund to a transmission customer in 2009, partially offset by BTER, WECA and DEAA rate reductions.

Cash Used By Investing Activities. Cash used by investing activities decreased mainly due to the slowdown in construction for infrastructure, and proceeds from the sale of property.

Cash Used By Financing Activities. Cash used by financing activities increased primarily due to a reduction in the issuance of debt compared to 2009 and an increase in payments on NPC’s revolving credit facility, partially offset by lower dividend payments to NVE.

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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.  Another significant use of cash is the refunding of previously over-collected amounts from customers.  See Note 3, Regulatory Actions, of the Notes to Financial Statements for more details of over-collected balances.  Operating cash flows can be significantly influenced by factors such as weather, regulatory outcome, and economic conditions.  Available liquidity as of December 31, 2011 was as follows (in millions):

Available Liquidity as of December 31, 2011
			NPC
Cash and Cash Equivalents			$	65.9
	Balance available on Revolving Credit Facility(1)			578.8
		Less Reduction for Hedging Transactions(2)		-
			$	644.7
(1)		As of February 22, 2012, NPC had no borrowings under its revolving credit facility, not including letters of credits.
(2)		Reduction for hedging transactions reflects balances as of November 30, 2011. NPC is currently unhedged, as discussed
		further in Financial Gas Hedges.

NPC attempts to maintain its cash and cash equivalents in highly liquid investments, such as U.S. Treasury Bills and bank deposits.  In addition to cash on hand, NPC may use its revolving credit facility in order to meet its liquidity needs.  Alternatively, depending on the usage of the revolving credit facility, NPC may issue debt, subject to certain restrictions as discussed in Factors Affecting Liquidity, Ability to Issue Debt, below.

NPC’s debt maturities in 2012 include its $130 million 6.50% General and Refunding Mortgage Notes, Series I, which mature April 15, 2012.   In addition, NPC is required to redeem approximately $98.1 million of its variable rate debt, due 2020, prior to ON Line’s commercial operation date.  As of February 22, 2012, NPC has no borrowings on its revolving credit facility, not including letters of credit.

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 recovery of deferred energy, and the use of its revolving credit facility.  Furthermore, in order to fund long term capital requirements and maturing debt obligations, NPC will use a combination of internally generated funds, its revolving credit facility, the issuance of long-term debt and/or capital contributions from NVE.  However, if energy costs rise at a rapid rate and NPC does not recover the cost of fuel and purchased power in a timely manner, if operating costs are not recovered in a timely manner or NPC were to experience a credit rating downgrade resulting in the posting of collateral as discussed below under Gas Supplier Matters and Financial Gas Hedges, the amount of liquidity available to NPC could be significantly less.  In order to maintain sufficient liquidity, NPC may be required to further delay capital expenditures, refinance debt or obtain funding through an equity issuance by NVE.

The ability to issue debt, as discussed later, is subject to certain covenant calculations which include consolidated net income of NVE and the Utilities.  As a result of these covenant calculations and the seasonality of the Utilities’ business, the ability to issue debt can vary from quarter to quarter, and the Utilities may not be able to fully utilize the availability on their revolving credit facilities.

In 2011, NPC’s credit ratings on its senior secured debt remained at investment grade (see Credit Ratings below).  In 2011, NPC did not experience any limitations in the credit markets, nor does NPC expect any significant limitations in 2012.  However, disruptions in the banking and capital markets not specifically related to NPC may affect its ability to access funding sources or cause an increase in the interest rates paid on newly issued debt.

In 2011, NPC paid dividends to NVE of $99 million.  On February 10, 2012, NPC declared a dividend payable to NVE of $39 million.

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

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

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Capital Structure

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

		2011			2010
				Percent of Total			Percent of Total
		Amount		Capitalization	Amount		Capitalization
Current maturities of long-term debt		$	139,985	2.2%	$	355,929	5.6%
Long-term debt			3,319,605	52.6%		3,221,833	50.8%
Shareholder's Equity			2,848,977	45.2%		2,761,632	43.6%
	Total	$	6,308,567	100.0%	$	6,339,394	100.0%

Capital Requirements

   Construction Expenditures

NPC’s cash requirement for construction expenditures for 2012 is projected to be $281.0 million.  NPC’s cash requirements for construction expenditures for 2012 through 2016 are projected to be $1.2 billion.  Gross construction expenditures, including AFUDC debt, net salvage and CIAC for the years ended 2011, 2010, and 2009 were $475.1 million, $499.4 million, and $656.1 million, respectively. Net cash requirements to fund construction for the years ended 2011, 2010 and 2009 were $387.5 million, $452.9 million and $593.8 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, as of December 31, 2011, 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, 2011.  Additionally, at December 31, 2011, NPC has recorded an uncertain tax liability of $24.3 million as required by the accounting guidance for Uncertainty in Income Taxes Topic of the FASC, 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 uncertain tax liability is included in the contractual obligations table below (dollars in millions): 

	Payment Due by Period
	2012		2013		2014		2015		2016		Thereafter		Total
Long-Term Debt Maturities	$	130	$	-	$	125	$	250	$	210	$	2,719	$	3,434
Long-Term Debt Interest Payments		205		202		194		179		169		1,778		2,727
Purchased Power		385		318		297		302		305		2,152		3,759
Purchased Power - Not Commercially Operable(1)		75		119		204		239		247		5,360		6,244
Coal & Natural Gas		261		127		39		39		39		119		624
Transportation(2)		85		138		158		111		111		1,601		2,204
Long-Term Service Agreements(3)		41		16		16		15		12		55		155
Capital Projects(4)		87		54		-		-		-		-		141
Operating Leases		10		9		9		6		5		41		80
Capital Leases		10		10		7		5		5		61		98
Total Contractual Cash Obligations	$	1,289	$	993	$	1,049	$	1,146	$	1,103	$	13,886	$	19,466

(1) Represents estimated payments under renewable energy power purchase contracts, which have been approved by the PUCN and are contingent upon the developers obtaining commercial operation and their ability to deliver energy.

(2) Includes the TUA with GBT which is contingent upon final construction costs and reaching commercial operation.

(3) Amounts based on estimated usage.

(4) Capital projects include NV Energize and NPC’s requirement to purchase the undepreciated cost of capital of Reid Gardner Generating Station Unit No. 4 from CDWR, at which time, NPC will assume all associated operating and maintenance expense.  Additionally, NPC, as a joint owner, has obligations regarding the construction of ON Line.

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   Pension and Other Postretirement Benefit Plan 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 decrease in 2012 by approximately $6.5 million compared to the 2011 cost of $29.0 million. As of December 31, 2011, the measurement date, the plan was under funded under the provisions of the Compensation Retirement Benefits Topic of the FASC.  Refer to Note 11, Retirement Plan and Post-Retirement Benefits, of the Notes to the Financial Statements. During 2011, NVE funded a total of $40.6 million to the trusts established for the qualified pension and other postretirement benefit plans. At the present time, it is not anticipated that additional funding will be required in 2012 to meet the minimum funding level requirements defined by the Pension Protection Act of 2006.  However, NVE and the Utilities have included in their 2012 assumptions funding levels similar to the 2011 funding.  The amounts to be contributed in 2012 may change subject to market conditions.

Financing Transactions

   5.45% General and Refunding Mortgage Notes, Series Y

In May 2011, NPC issued and sold $250 million of its 5.45% General and Refunding Mortgage Notes, Series Y, due May 15, 2041.  The approximately $248 million in net proceeds, plus a portion of the proceeds from a draw on NPC’s revolving credit facility, were utilized to pay at maturity NPC’s $350 million aggregate principal amount of 8.25%  General and Refunding Mortgage Notes, Series A, which matured on June 1, 2011.   In conjunction with this debt issuance, NPC entered into an interest rate swap hedging agreement with a notional principal amount of $250 million and a mandatory termination date of June 1, 2011.  The interest rate swap agreement was entered into to effectively lock the interest rate of the U.S. Treasury component of the prospective General and Refunding Note issuance.  The swap transaction was settled on May 9, 2011, when NPC launched and priced the Series Y Notes, resulting in a settlement payment amount of $14.9 million, which was recorded as a cost to issue in a deferred debit and will be amortized over the 30 year life of the Series Y Notes in accordance with past accounting precedent for our regulated Utilities.

   $600 Million Revolving Credit Facility

NPC’s $600 million revolving credit facility contains a provision which reduces the availability under the credit facility by the negative mark-to-market exposure for hedging transactions with credit facility lenders or their energy trading affiliates.  The reduction in availability limits the amount that NPC can borrow or use for letters of credit and would require that NPC prepay any amount in excess of that limitation.  The amount of the reduction is calculated by NPC on a monthly basis, and after calculating such reduction, the NPC Credit Agreement provides that the reduction in availability under the revolving credit facility to NPC shall not exceed 50% of the total commitments then in effect under the revolving credit facility.

The NPC Credit Agreement contains one financial maintenance covenant that 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.  In the event that NPC did not meet the financial maintenance covenant or there is an event of default, the NPC Credit Agreement would restrict dividends to NVE.  Moreover, so long as NPC’s senior secured debt remains rated investment grade by S&P and Moody’s (in each case, with a stable or better outlook), a representation concerning no material adverse change in NPC’s business, assets, property or financial condition would not be a condition to the availability of credit under the facility.  In the event that NPC’s senior secured debt rating were rated below investment grade by either S&P or Moody’s, or investment grade by either S&P or Moody’s but with a negative outlook, a representation concerning no material adverse change in NPC’s business, assets, property or financial condition would be a condition to borrowing under the revolving credit facility.

NPC’s current revolving credit facility expires in April 2013; however, management is currently renegotiating the terms and expects to close in early 2012.

Factors Affecting Liquidity

   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 agreements, and the terms of certain NVE debt.  As of December 31, 2011, the most restrictive of the factors below is the PUCN authority.  As such, NPC may issue up to $725 million in long-term debt, in addition to the use of its existing credit facility.  However, depending on NVE’s or SPPC’s issuance of long-term debt or the use of the Utilities’ revolving credit facilities, the PUCN authority may not remain the most restrictive factor.  The factors affecting NPC’s ability to issue debt are further detailed below:

a. Financing authority from the PUCN - As of December 31, 2011, NPC has financing authority from the PUCN for the period ending December 31, 2013, consisting of authority (1) to issue additional long-term debt securities of up to $725

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million; (2) to refinance up to approximately $322.5 million of long-term debt securities; and (3) ongoing authority to maintain a revolving credit facility of up to $1.3 billion.

b. Financial covenants within NPC’s financing agreements – Under its $600 million revolving credit facility, NPC must 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.  Based on December 31, 2011 financial statements, NPC was in compliance with this covenant and could incur up to $2.6billion of additional indebtedness.

All other financial covenants contained in NPC’s 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 under these additional covenants; and

c. Financial covenants contained within NVE’s Term Loan – As discussed in NVE’s Ability to Issue Debt, NPC is also subject to NVE’s cap on additional consolidated indebtedness of $2.8 billion.

   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, 2011, $4.0 billion of NPC’s General and Refunding Mortgage Securities were outstanding.  NPC had the capacity to issue $1.4 billion of General and Refunding Mortgage Securities as of December 31, 2011.  That amount is determined on the basis of:

1.         70% of net utility property additions; and/or

2.         The principal amount of retired General and Refunding Mortgage Securities.

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 NPC’s Indenture, it will reduce the amount of securities issuable under the Indenture.

   Credit Ratings

The liquidity of NPC, the cost and availability of borrowing by NPC under its credit facility, the potential exposure of NPC to collateral calls under various contracts and the ability of NPC to acquire fuel and purchased power on favorable terms are all directly affected by the credit ratings for NPC’s debt.  NPC’s senior secured debt is rated investment grade by three NRSRO’s:  Fitch, Moody’s and S&P.  In May 2011, Moody’s upgraded NPC’s senior secured debt to Baa2.   As of December 31, 2011, the ratings are as follows:

			Rating Agency
			Fitch(1)	Moody’s(2)	S&P(3)
NPC		Sr. Secured Debt	BBB*	Baa2*	BBB*
*	Investment grade
(1)	Fitch’s lowest level of “investment grade” credit rating is BBB-.
(2)	Moody’s lowest level of “investment grade” credit rating is Baa3.
(3)	S&P’s lowest level of “investment grade” credit rating is BBB-.

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

            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.  Each security rating agency has its own methodology for assigning ratings, and accordingly, each rating should be evaluated in the context of the applicable methodology, independently of all other ratings.  The rating agencies provide ratings at the request of the company being rated and charge the company fees for their services.

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   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, which includes 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.  Most contracts and confirmations for purchased power have been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery in response to requests for financial assurance.  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, 2011 for all suppliers continuing to provide power under a WSPP agreement would approximate a $37.5 million payment or obligation to NPC.  These contracts qualify for the normal purchases scope exception under the Derivatives and Hedging Topic of the FASC, and as such, are not required to be marked-to-market on the balance sheet.  Refer to Note 6, 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 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.  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 in response to requests for financial assurances.  Forward physical gas supplies are purchased under index based pricing terms and as such do not carry forward mark-to-market exposure.  

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 a transmission counterparty for which it is required to post cash collateral or a letter of credit in the event of credit rating downgrades.   As of December 31, 2011, the maximum amount of additional collateral NPC would be required to post under these contracts in the event of credit rating downgrades was approximately $64.6 million.  Of this amount, approximately $19.5 million would be required if NPC’s Senior Unsecured ratings are rated below BB (S&P) or Ba3 (Moody’s) and an additional amount of approximately $45.2 million would be required if NPC’s Senior Secured ratings are downgraded to below investment grade.

   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.  As discussed under NPC’s Financing Transactions, the availability under NPC’s revolving credit facility is reduced by the amount of net negative mark-to-market positions on hedging contracts with counterparties who are lenders to the revolving credit facility, provided that the reduction in availability under the revolving credit facility shall at no time exceed 50% of the total commitments then in effect under the revolving credit facility.  As a result of the suspension of the suspension of the Utilities’ hedging program, there was no negative mark-to-market exposure for NPC as of November 30, 2011 that would impact credit availability during the month of December 2011.  Beginning in October 2009, the Utilities suspended their hedging programs; however, prior to the suspension, it was the general policy of the Utilities to purchase hedges three seasons ahead.  As a result certain hedges entered into prior to the suspension in October 2009, did not terminate until 2011.  As of November 2011, all hedging transactions have expired or terminated and the Utilities remain unhedged.  If deemed prudent, the Utilities may still purchase hedging instruments in the event circumstances occur that may have the potential to increase the cost of fuel and purchased power.

   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.

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SIERRA PACIFIC POWER COMPANY

RESULTS OF OPERATIONS

SPPC recognized net income of $59.9 million for the year ended December 31, 2011, compared to net income of $72.4 million in 2010 and a net income of $73.1 million in 2009.  In 2011, SPPC paid dividends to NVE of approximately $114 million.  In February 2012, SPPC declared a dividend of approximately $20 million to NVE.  Details of SPPC’s operating results are further discussed below.

Gross margin is presented by SPPC 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.

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 energy costs and EEPR costs, provides a measure of income available to support the other operating expenses of SPPC.

EEPR costs are conservation costs being recovered from ratepayers through EEPR revenues which were implemented in July 2011 (see Note 3, Regulatory Actions, of the Notes to Financial Statements).   Costs incurred prior to the implementation of the EEPR are recovered through general rates and amortized to other operating expense.  See Note 3, Regulatory Actions, of the Notes to Financial Statements for conservation program amount details.  The EEPR mechanism is designed such that conservation costs are equal to revenues collected and any over/under collection is deferred as a regulatory asset/liability until rates are reset.  As a result, amounts related to EEPR do not have an effect on gross margin, operating income or net income.

For reconciliation to operating income, see Note 2, Segment Information, in the Notes to Financial Statements.  Gross margin changes are based primarily on general base rate adjustments (which are required to be filed by statute every three years).

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

		2011			2010			2009
				Change from			Change from
		Amount		Prior Year	Amount		Prior Year	Amount
Operating Revenues:
	Electric	$	716,417	(14.4)%	$	836,879	(12.6)%	$	957,130
	Gas		172,482	(9.7)%		190,943	(7.0)%		205,263
		$	888,899	(13.5)%	$	1,027,822	(11.6)%	$	1,162,393
Energy Costs:
	Fuel for power generation	$	182,098	(21.9)%	$	233,065	(20.8)%	$	294,121
	Purchased power		156,648	9.1%		143,642	9.7%		130,977
	Gas purchased for resale		125,155	(9.1)%		137,702	(10.4)%		153,607
	Deferral of energy - electric - net		(65,445)	(872.2)%		8,475	(88.5)%		73,829
	Deferral of energy - gas - net		(1,588)	(116.2)%		9,789	28.2%		7,636
Energy efficiency program costs			6,245	N/A		-	N/A		-
		$	403,113	(24.3)%	$	532,673	(19.3)%	$	660,170
Costs by Segment:
	Electric	$	279,546	(27.4)%	$	385,182	(22.8)%	$	498,927
	Gas		123,567	(16.2)%		147,491	(8.5)%		161,243
		$	403,113	(24.3)%	$	532,673	(19.3)%	$	660,170
Gross Margin by Segment:
	Electric	$	436,871	(3.3)%	$	451,697	(1.4)%	$	458,203
	Gas		48,915	12.6%		43,452	(1.3)%		44,020
		$	485,786	(1.9)%	$	495,149	(1.4)%	$	502,223

Electric gross margin decreased for the year ended December 31, 2011, compared to the same period in 2010, primarily due to the sale of the California Assets, as discussed in Note 16, Assets Held for Sale, of the Notes to Financial Statements, partially offset by a related five year power sale agreement entered into as a condition to the sale of the assets.  Further contributing to the decrease was increased margin in 2010 as a result of an adjustment for California revenues upon a final filing in 2010 with the CPUC in regards to the Rate Reduction Certificates Series 1991-1.  In addition, reduced DOS impact fees in 2011 contributed to the decrease in margin.  Partially offsetting this decrease were increased rates, particularly among commercial and industrial customer classes, as a result of SPPC’s GRC effective January 1, 2011, as well as increased customer usage among residential and industrial classes primarily as a result of weather.

Electric gross margin decreased for the year ended December 31, 2010, compared to the same period in 2009, primarily due to a decrease in customer usage as a result of milder summer weather, conservation programs and economic conditions. Partially offsetting the decrease in gross margin was an adjustment for California revenues upon a final filing in 2010 with the CPUC in regards to the Rate Reduction Certificates Series 1999-1.

Gas gross margin increased for the year ended December 31, 2011, as compared to the same period in 2010, primarily due to increased customer usage.

Gas gross margin decreased for the year ended December 31, 2010, compared to the same period in 2009, primarily due to decreased customer usage as a result of warmer weather.

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):

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Electric Operating Revenues
			2011			2010			2009
					Change from			Change from
			Amount		Prior Year	Amount		Prior Year	Amount
Electric Operating Revenues:
	Residential		$	235,148	(22.6)%	$	303,737	(12.1)%	$	345,455
	Commercial			260,735	(18.9)%		321,599	(15.8)%		381,805
	Industrial			152,130	(14.9)%		178,855	(10.4)%		199,510
		Retail Revenues		648,013	(19.4)%		804,191	(13.2)%		926,770
	Other			68,404	109.3%		32,688	7.7%		30,360
		Total Operating Revenues	$	716,417	(14.4)%	$	836,879	(12.6)%	$	957,130
Retail sales in thousands of MWhs				7,648	(5.4)%		8,081	(1.0)%		8,162
Average retail revenue per MWh			$	84.73	(14.9)%	$	99.52	(12.4)%	$	113.55

SPPC’s retail revenues decreased for the year ended December 31, 2011 compared to the same period in 2010 primarily due to decreases in retail rates as a result of SPPC’s annual Deferred Energy cases effective October 1, 2011 and 2010 and various BTER quarterly updates (see Note 3, Regulatory Actions, of the Notes to Financial Statements).   Retail revenues also decreased due to the sale of the California Assets on January 1, 2011 (see Note 16, Assets Held for Sale, of the Notes to Financial Statements).  These decreases were offset by a slight increase in rates due to SPPC’s 2010 GRC effective January 1, 2011 and by implementation of EEPR rates effective July 1, 2011 (see Note 3, Regulatory Actions, of the Notes to Financial Statements).  Excluding California customers, the average number of residential and commercial customers increased by 0.4% and 0.9%, respectively, while industrial customers decreased by 1.8%.

SPPC’s retail revenues decreased for the year ended December 31, 2010 compared to the same period in 2009 primarily due to decreases in retail rates as a result of SPPC’s various BTER quarterly updates and the annual Deferred Energy case effective October 1, 2010 (see Note 3, Regulatory Actions, of the Notes to Financial Statements) and a decrease in customer usage as a result of milder summer weather, conservation programs and economic conditions.  These decreases were partially offset by increased industrial usage primarily from a gold mining customer who resumed full operation in October 2009.  The average number of residential and commercial customers increased 0.2% and 0.1%, respectively, while industrial customers decreased 1.8%.

Electric Operating Revenues – Other increased for the year ended December 31, 2011 compared to the same period in 2010 primarily due to the sale of energy to CalPeco, under a five year agreement, as a condition to the sale of SPPC’s California Assets which occurred on January 1, as discussed in Note 16, Assets Held for Sale, of the Notes to Financial Statements.

Electric Operating Revenues – Other increased for the year ended December 31, 2010 compared to the same period in 2009 primarily due to an adjustment for California revenues upon a final filing in 2011 with the CPUC in regards to the Rate Reduction Certificates Series 1999-1.

Gas Operating Revenues
			2011			2010			2009
					Change from			Change from
			Amount		Prior Year	Amount		Prior Year	Amount
Gas Operating Revenues:
	Residential		$	91,140	(11.4)%	$	102,923	(11.8)%	$	116,680
	Commercial			36,970	(18.8)%		45,547	(12.7)%		52,186
	Industrial			11,559	(21.9)%		14,802	(15.2)%		17,458
		Retail Revenues		139,669	(14.5)%		163,272	(12.4)%		186,324
	Wholesale			29,559	17.1%		25,233	52.4%		16,560
	Miscellaneous			3,254	33.5%		2,438	2.5%		2,379
		Total Gas Revenues	$	172,482	(9.7)%	$	190,943	(7.0)%	$	205,263
Retail sales in thousands of Dths				15,781	7.1%		14,739	(2.0)%		15,046
Average retail revenue per Dth			$	8.85	(20.1)%	$	11.08	(10.5)%	$	12.38

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SPPC’s retail gas revenues decreased for the year ended December 31, 2011 as compared to the same period in 2010, primarily due to decreased retail rates as a result of SPPC’s various BTER quarterly updates and the annual Natural Gas and Propane Deferred Rate Cases effective October 1, 2011 and 2010 (see Note 3, Regulatory Actions, of the Notes to Financial Statements). These decreases were partially offset by increased customer usage resulting from colder 2011 temperatures and a slight BTGR increase as a result of SPPC’s 2010 GRC effective January 1, 2011 (see Note 3, Regulatory Actions, of the Notes to Financial Statements). The average number of retail customers increased by 0.6%.

SPPC’s retail gas revenues decreased in 2010 as compared to 2009, primarily due to decreased retail rates and decreased customer usage.  Retail rates decreased as a result of SPPC’s various BTER quarterly updates and the annual Natural Gas and Propane Deferred Rate Cases effective October 1, 2009 and 2010.  See Note 3, Regulatory Actions, of the Notes to Financial Statements. Customer usage decreased due to warmer weather in the fourth quarter compared to prior year.  The average number of retail customers increased by 0.8%.

Wholesale revenues increased for the years ended December 31, 2011 and 2010, compared to prior years primarily due to the optimization of pipeline capacity and excess 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;

· Mandated power purchases; and

· Generation efficiency.

		2011			2010			2009
				Change from			Change from
		Amount		Prior Year	Amount		Prior Year		Amount
Energy Costs
	Fuel for generation	$	182,098	(21.9)%	$	233,065	(20.8)%		$	294,121
	Purchased power		156,648	9.1%		143,642	9.7%			130,977
Total Energy Costs		$	338,746	(10.1)%	$	376,707	(11.4)%		$	425,098
MWhs
	MWhs Generated (in thousands)		4,454	(13.0)%		5,121	(8.3)%			5,582
	Purchased Power (in thousands)		4,368	24.4%		3,510	6.5%			3,296
Total MWhs			8,822	2.2%		8,631	(2.8)%			8,878
Average cost per MWh
	Average fuel cost per MWh of Generated Power	$	40.88	(10.2)%	$	45.51	(13.6)%		$	52.69
	Average cost per MWh of Purchased Power	$	35.86	(12.4)%	$	40.92	3.0%		$	39.74
	Average cost per MWh	$	38.40	(12.0)%	$	43.65	(8.8)%		$	47.88

Energy costs and the average cost per MWh decreased for the year ended December 31, 2011, compared to the same period in 2010, primarily due to decreased hedging costs along with lower natural gas costs.  Total system demand for the year ended December 31, 2011 increased for the same period due to colder winter temperatures.

• Fuel for generation costs decreased for the year ended December 31, 2011 as compared to the same period in 2010 due to a decrease in hedging costs along with a decrease in internal generation. The decrease in system output was primarily caused by planned maintenance at Tracy Generating Station and planned outages at the Valmy Generating Station.

• Purchased power costs and volume increased for the year ended December 31, 2011 as compared to the same period in 2010 primarily due to the maintenance and outages discussed above and due to the availability of hydro power purchases early in the year which were more economical.  The average cost per MWh decreased due to lower market prices.

Energy costs and the average cost per MWh decreased for the year ended December 31, 2010, compared to the same period in 2009, primarily due to decreased costs associated with hedging activities partially offset by the higher natural gas costs.  The decrease in total system demand for the year ended December 31, 2010 compared to the same period in 2009 is primarily due to a decrease in customer usage which may be attributable to economic conditions, conservation programs and milder winter temperatures in 2010.

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• Fuel for generation decreased primarily due to a decrease in costs associated with hedging activities and a decrease in generation, partially offset by an increase in natural gas costs.  MWhs generated decreased primarily due to internal generation outages. The average fuel cost per MWh of generated power was less primarily due to a decrease in costs associated with hedging activities.

• Purchased power costs and the average cost per MWh increased primarily due to an increase in volume as a result of internal generation outages.

Gas Purchased for Resale
	2011			2010			2009
			Change from			Change from
	Amount		Prior Year	Amount		Prior Year	Amount
Gas Purchased for Resale	$	125,155	(9.1)%	$	137,702	(10.4)%	$	153,607
Gas Purchased for Resale (in thousands of Dth)		23,859	12.4%		21,219	8.3%		19,588
Average Cost per Dth	$	5.25	(19.1)%	$	6.49	(17.2)%	$	7.84

Gas purchased for resale and average cost per Dth decreased for the year ended December 31, 2011 as compared to the same period in 2010.  The decrease is primarily due to decreased hedging costs along with decreased natural gas prices.  The volume of gas purchased for resale increased in 2011 compared to 2010 primarily due to the increased purchase of gas in an effort to optimize pipeline capacity.

               Gas purchased for resale and average cost per Dth decreased for the year ended December 31, 2010 as compared to the same period in 2009.  The decrease is primarily due to decreased hedging costs along with decreased natural gas prices.  The volume of gas purchased for resale increased in 2010 compared to 2009 primarily due to excess availability of gas.

Deferred Energy
	2011			2010			2009
			Change from			Change from
	Amount		Prior Year	Amount		Prior Year	Amount
Deferral of energy - electric - net	$	(65,445)	(872.2)%	$	8,475	(88.5)%	$	73,829
Deferral of energy - gas - net		(1,588)	(116.2)%		9,789	28.2%		7,636
Total	$	(67,033)		$	18,264		$	81,465

Deferred energy 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 also includes the current amortization of fuel and purchased power costs previously deferred.

Deferred energy - electric for 2011, 2010 and 2009 reflect amortization of deferred energy costs of $(104.9), $(42.5) and $(7.6) million, respectively; and an over-collection of amounts recoverable in rates of $39.5, $51.0 and $81.4 million in 2011, 2010 and 2009 respectively.  Refer to Note 3, Regulatory Actions, of the Notes to Financial Statements for further detail of deferred energy balances.  

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Deferred energy - gas for 2011, 2010 and 2009 reflect amortization of deferred energy of $(22.2), $(11.1) and $(3.1) million, respectively; and an over-collection of amounts recoverable in rates of $20.7, $20.9 and $10.8 million in 2011, 2010 and 2009 respectively.

Other Operating Expenses
	2011			2010			2009
			Change from			Change from
	Amount		Prior Year	Amount		Prior Year	Amount
Energy efficiency program costs	$	6,245	N/A	$	-	N/A	$	-
Other operating expenses	$	146,699	(2.2)%	$	149,946	(12.2)%	$	170,849
Maintenance	$	38,987	18.8%	$	32,808	4.9%	$	31,290
Depreciation and amortization	$	105,746	(1.0)%	$	106,807	0.7%	$	106,048

Energy efficiency program costs are conservation costs being recovered from ratepayers through EEPR revenues which were implemented in July 2011 (See Note 3, Regulatory Actions, of the Notes to Financial Statements).  Costs incurred prior to the implementation of the EEPR are recovered through general rates amortized to other operating expense discussed below.  The EEPR mechanism is designed such that conservation costs expense are equal to revenues collected and any over/under collection is deferred as a regulatory asset/liability, until rates are reset.  As a result, amounts related to EEPR do not have an effect on gross margin, operating income or net income.

Other operating expense decreased for the year ended December 31, 2011, compared to the same period in 2010, primarily due to lower outside consulting fees, a reduction in customer expense, rate case expenses, and lease expenses. These decreases were partially offset by an increase in stock compensation costs and regulatory amortizations primarily for conservation programs.

Other operating expense decreased for the year ended December 31, 2010, compared to the same period in 2009, primarily due to lower employee pension and benefit expenses, costs incurred in 2009 related to severance programs, as discussed further in Note 17, Severance Programs, of the Notes to Financial Statements and a reduction in bad debt expense, partially offset by increases in regulatory expenses.  In addition, other operating expenses decreased as a result of costs associated with the REPR.  Beginning in 2010, these amounts are reported net of their related operating expense; as such, REPR amounts no longer affect operating expense.  REPR costs were not material in 2009 and were included in operating expenses with a corresponding amount recorded to revenues, and had no effect on net income. 

Maintenance expense increased for the year ended December 31, 2011, compared to the same period in 2010, mainly due to a scheduled major outage at the Valmy Generating Station, and the timing of maintenance and outages at the Tracy and Ft. Churchill Generating Stations.

Maintenance expense increased for the year ended December 31, 2010, compared to the same period in 2009, mainly due to a scheduled major outage at the Valmy Generating Station, partially offset by the timing of planned maintenance and outages at the Tracy Generating Station.

Depreciation and amortization decreased for the year ended December 31, 2011, compared to 2010, primarily due to change in depreciation rates effective January 1, 2011, as a result of SPPC’s GRC.

Depreciation and amortization increased slightly for the year ended December 31, 2010, compared to the same period in 2009, primarily due to regular system growth.

Interest Expense
	2011			2010			2009
			Change from			Change from
	Amount		Prior Year	Amount		Prior Year	Amount
Interest expense
(net of AFUDC-debt: $1,948, $1,912 and $3,044)	$	67,435	(1.6)%	$	68,514	(1.3)%	$	69,413

Interest expense decreased for the year ended December 31, 2011, compared to the same period in 2010 primarily due to the redemption of $100 million Series H General and Refunding Mortgage Bonds in December 2010.

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Interest expense decreased for the year ended December 31, 2010, compared to the same period in 2009 primarily due to lower interest on the revolving credit facility and variable rate debt, partially offset by lower AFUDC.  See Note 6, Long-Term Debt, of the Notes to Financial Statements for additional information regarding long-term debt.

Other Income (Expense)
	2011			2010			2009
			Change from			Change from
	Amount		Prior Year	Amount		Prior Year	Amount
Interest income (expense) on regulatory items	$	(7,749)	(17.1)%	$	(9,348)	62.8%	$	(5,743)
AFUDC-equity	$	2,575	(10.7)%	$	2,883	(11.3)%	$	3,249
Other income	$	6,883	(58.9)%	$	16,748	26.2%	$	13,276
Other expense	$	(14,624)	46.5%	$	(9,985)	30.6%	$	(7,648)

Interest expense on regulatory items decreased for the year ended December 31, 2011, compared to the same period in 2010, due to lower over-collected deferred energy balances in 2011.

Interest expense on regulatory items increased for the year ended December 31, 2010, compared to the same period in 2009, due to higher over-collected deferred energy balances in 2010.

AFUDC-equity decreased for the year ended December 31, 2011 compared to 2010, primarily due to the completion of various construction projects, including EWAM.

AFUDC-equity was lower for the year ended December 31, 2010 compared to the same period in 2009 primarily due to the completion of various transmission projects, which resulted in a decrease in the CWIP balance in 2010.

Other income decreased for the year ended December 31, 2011 compared to the same period in 2010 primarily due to the recognition of the gain on sale of Independence Lake in 2010, as further discussed in Note 16, Assets Held for Sale, of the Notes to Financial Statements, a decrease in carrying charges on solar conservation programs, and a decrease in income from subleases in 2011.

Other income increased for the year ended December 31, 2010, compared to the same period in 2009, primarily due to the gain on sale for the Independence Lake property in 2010, as further discussed in Note 16, Assets Held for Sale, of the Notes to Financial Statements, adjustments resulting from SPPC’s 2010 electric GRC, and interest income on investments in 2010, partially offset by a gain recognized in 2009 on the sale of the Farad hydro units and interest received for tax refunds in 2009.

Other expense increased for the year ended December 31, 2011 compared to the same period in 2010 primarily due to an adjustment in the second quarter of 2011, upon final order from the PUCN, for EEIR revenue recorded in 2010, increased legal reserves and an adjustment for the EEC as a result of NPC’s 2011 GRC.  Partially offsetting the increase was a decrease in lease expense and charitable donations.

Other expense increased for the year ended December 31, 2010, compared to the same period in 2009, due to an increase in donations related to Independence Lake and adjustments resulting from SPPC’s 2010 electric GRC.  Partially offsetting the increase was a disallowance in 2009 relating to contract pricing for energy.

ANALYSIS OF CASH FLOWS

SPPC’s cash flows increased in 2011 compared to 2010 due to a decrease in cash used by investing and financing activities, offset partially by a decrease in cash from operating activities.

Cash From Operating Activities. The decrease in cash from operating activities was primarily due to a decrease in net income, an overall decrease in rates resulting from quarterly BTER adjustments and negative DEAA rates implemented in October 2010 to refund prior period over collected balances to customers.  Also contributing to the decrease is the reduction in revenues from California customers due to the sale of the California Assets, as discussed in Note 16, Assets Held for Sale, of the Notes to Financial Statements, an increase in coal inventory for the Valmy Generating Station, an increase in conservation and renewable energy program costs, increased funding of pension plans and increased incentive compensation payments for the 2010 operating results.  These decreases were partially offset by the recovery of deferred conservation program costs as a result of SPPC’s 2010 GRC.

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Cash Used By Investing Activities. Cash used by investing activities decreased due to the receipt of proceeds from the sale of California Assets, as discussed in Note 16, Assets Held for Sale, of the Notes to Financial Statements and federal funding under the American Recovery and Reinvestment Act of 2009, as part of the NV Energize project.

Cash Used By Financing Activities. The decrease in cash used by financing activities is primarily due to a reduction in retirement of long-term debt, offset partially by higher dividends to NVE.

SPPC’s cash flows increased during 2010 compared to 2009 due to a reduction in cash used by investing activities offset by a decrease in cash from operating activities and a decrease in cash from financing activities.

Cash From Operating Activities.  The decrease in cash from operating activities is primarily due to a reduction in BTER and DEAA rates charged to customers, and an increase in spending on energy conservation programs.  The decrease in cash was partially offset by decreased spending on fuel for purchased power costs and a decrease in funding for pension plans compared to 2009.

Cash Used By Investing Activities.  Cash used by investing activities decreased mainly due to the slowdown in construction for infrastructure, and proceeds from the sale of property.

Cash Used By Financing Activities. Cash used by financing activities increased primarily due to the redemption of SPPC’s 6.25% General and Refunding Mortgage Notes, Series H due 2012 in an aggregate principal amount of $100 million and a decrease in capital contributions from NVE.  This decrease was partially offset by lower dividend payments to NVE.

LIQUIDITY AND CAPITAL RESOURCES

Overall Liquidity

SPPC’s primary source of operating cash flows is electric and natural gas 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.  Another significant use of cash is the refunding of previously over-collected amounts from customers.  See Note 3, Regulatory Actions, of the Notes to Financial Statements for more details of over-collected balances.  Operating cash flows can be significantly influenced by factors such as weather, regulatory outcome and economic conditions.  Available liquidity as of December 31, 2011 was as follows (in millions):

Available Liquidity as of December 31, 2011
			SPPC
Cash and Cash Equivalents			$	55.2
	Balance available on Revolving Credit Facility(1)			237.5
		Less Reduction for Hedging Transactions(2)		-
			$	292.7
(1)		As of February 22, 2012, SPPC had no borrowings under its revolving credit facility.
(2)		Reduction for hedging transactions reflects balances as of November 30, 2011.  SPPC is currently unhedged, as discussed
		further in Financial Gas Hedges.

SPPC attempts to maintain its cash and cash equivalents in highly liquid investments, such as U.S. Treasury Bills and bank deposits.  In addition to cash on hand, SPPC may use its revolving credit facility in order to meet its liquidity needs.  Alternatively, depending on the usage of the revolving credit facility, SPPC may issue debt, subject to certain restrictions as discussed in Factors Affecting Liquidity, Ability to Issue Debt, below.

SPPC has no debt maturities in 2012.  However, SPPC’s $250 million 5.45% General and Refunding Notes, Series Q, will mature on September 1, 2013.  As of February 22, 2012, SPPC has no borrowings on its revolving credit facility, not including letters of credit.

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.  Furthermore, in order to fund long-term capital requirements and maturing debt obligations, SPPC will use a combination of internally generated funds, its revolving credit facility, the issuance of long-term debt and/or capital contributions from NVE. However, if energy costs rise at a rapid rate and SPPC does not recover the cost of fuel and purchased power in a timely manner, if operating costs are not recovered in a timely manner or SPPC were to experience a credit rating downgrade resulting in the posting of collateral as discussed below under Gas Supplier Matters and Financial Gas Hedges, the amount of liquidity available to SPPC could be significantly less.  In order to

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maintain sufficient liquidity, SPPC may be required to further delay capital expenditures, refinance debt or obtain funding through an equity issuance by NVE.

The ability to issue debt, as discussed later, is subject to certain covenant calculations which include consolidated net income of NVE and the Utilities.  As a result of these covenant calculations and the seasonality of the Utilities’ business, the ability to issue debt can vary from quarter to quarter, and the Utilities may not be able to fully utilize the availability on their revolving credit facilities.

In 2011, SPPC’s credit ratings on its senior secured debt remained at investment grade (see Credit Ratings below).  In 2011, SPPC did not experience any limitations in the credit markets, nor do we expect any significant limitations in 2012.  However, disruptions in the banking and capital markets not specifically related to SPPC may affect its ability to access funding sources or cause an increase in the interest rates paid on newly issued debt.

In 2011, SPPC paid dividends to NVE of $114 million.  On February 10, 2012, SPPC declared a $20 million dividend payable to 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, recently completed Financing Transactions and Factors Affecting Liquidity, including its ability to obtain debt on favorable terms.

Capital Structure

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

			2011			2010
			Amount	Percent of Total Capitalization		Amount	Percent of Total Capitalization
Long-term debt		$	1,179,326	54.8%	$	1,195,775	55.1%
Shareholder's Equity			974,542	45.2%		973,420	44.9%
	Total	$	2,153,868	100.0%	$	2,169,195	100.0%

Capital Requirements

   Construction Expenditures

SPPC’s cash requirement for construction expenditures for 2012 is projected to be $188.4 million.  SPPC’s cash requirement for construction expenditures for 2012 through 2016 is projected to be $739 million.  Gross construction expenditures, including AFUDC debt, net salvage and CIAC for the years ended 2011, 2010, and 2009 were $145.4 million, $143.2 million, and $187.1 million, respectively. Net cash requirements to fund construction for the years ended 2011, 2010 and 2009 were $134.7 million, $137.5 million and $180.7 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.

   Contractual Obligations

The table below provides SPPC’s consolidated contractual obligations, as of December 31, 2011, 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, 2011.  Additionally, at December 31, 2011, SPPC recorded an uncertain tax liability of $9.8 million as required by the accounting guidance for Uncertainty in Income Taxes Topic of the FASC, 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 uncertain tax liability is included in the contractual obligations table below (dollars in millions):

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	Payment Due by Period
	2012		2013		2014		2015		2016		Thereafter		Total
Long-Term Debt Maturities	$	-	$	250	$	-	$	-	$	-	$	916	$	1,166
Long-Term Debt Interest Payments		59		55		46		46		29		378		613
Purchased Power		177		126		119		123		128		929		1,602
Coal and Natural Gas		115		60		19		16		-		-		210
Transportation(1)		83		78		59		44		35		178		477
Long-Term Service Agreements(2)		8		5		5		5		5		16		44
Capital Projects(3)		42		5		-		-		-		-		47
Operating Leases		6		5		4		3		2		33		53
Total Contractual Cash Obligations	$	490	$	584	$	252	$	237	$	199	$	2,450	$	4,212

(1) Includes the TUA with GBT which is contingent upon final construction costs and reaching commercial operation.

(2) Amounts based on estimated usage.

(3) Capital projects include NV Energize.  Additionally, SPPC, as a joint owner, has obligations regarding the construction of ON Line.

   Pension and Other Postretirement Benefit Plan 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 decrease in 2012 by approximately $6.5 million compared to the 2011 cost of $29.0 million. As of December 31, 2011, the measurement date, the plan was under funded under the provisions of the Compensation Retirement Benefits Topic of the FASC.  Refer to Note 11, Retirement Plan and Post-Retirement Benefits, of the Notes to Financial Statements. During 2011, NVE funded a total of $40.6 million to the trusts established for the qualified pension and other postretirement benefit plans. At the present time, it is not anticipated that additional funding will be required in 2012 to meet the minimum funding level requirements defined by the Pension Protection Act of 2006.  However, NVE and the Utilities have included in their 2012 assumptions funding levels similar to the 2011 funding.  The amounts to be contributed in 2012 may change subject to market conditions.

Financing Transactions

   $250 Million Revolving Credit Facility

SPPC’s $250 million revolving credit facility contains a provision which reduces the availability under the credit facility by the negative mark-to-market exposure for hedging transactions with credit facility lenders or their energy trading affiliates.  The reduction in availability limits the amount that SPPC can borrow or use for letters of credit and would require that SPPC prepay any amount in excess of that limitation.  The amount of the reduction is calculated by SPPC on a monthly basis, and after calculating such reduction, the SPPC Credit Agreement provides that reduction in the availability under the revolving credit facility to SPPC shall not exceed 50% of the total commitments then in effect under the revolving credit facility.

The SPPC Credit Agreement contains one financial maintenance covenant that 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.  In the event that SPPC did not meet the financial maintenance covenant or there is an event of default, the SPPC Credit Agreement would restrict dividends to NVE.  Moreover, so long as SPPC’s senior secured debt remains rated investment grade by S&P and Moody’s (in each case, with a stable or better outlook), a representation concerning no material adverse change in SPPC’s business, assets, property or financial condition would not be a condition to the availability of credit under the facility.  In the event that SPPC’s senior secured debt rating were rated below investment grade by either S&P or Moody’s, or investment grade by either S&P or Moody’s but with a negative outlook, a representation concerning no material adverse change in SPPC’s business, assets, property or financial condition would be a condition to borrowing under the revolving credit facility.

SPPC’s current revolving credit facility expires in April 2013; however, management is currently renegotiating the terms and expects to close in early 2012.

Factors Affecting Liquidity

    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, 2011, the most restrictive of the factors below is the PUCN authority.  Based on this restriction, SPPC may issue up to $350 million of long-term debt securities, and maintain a credit facility of up to $600 million.  However, depending on NVE’s or NPC’s issuance of long-

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term debt or the use of the Utilities’ revolving credit facilities, the PUCN authority may not remain the most restrictive factor.  The factors affecting SPPC’s ability to issue debt are further detailed below:

a. Financing authority from the PUCN - As of December 31, 2011, SPPC has financing authority from the PUCN for the period ending December 31, 2012, consisting of authority (1) to issue additional long-term debt securities of up to $350 million; (2) to refinance approximately $348 million of long-term debt securities; and (3) ongoing authority to maintain a revolving credit facility of up to $600 million;

b. Financial covenants within SPPC’s financing agreements – Under SPPC’s $250 million revolving credit facility, the Utility must 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.  Based on December 31, 2011 financial statements, SPPC was in compliance with this covenant and could incur up to $879 million of additional indebtedness.

All other financial covenants contained in SPPC’s 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 under these additional covenants; and

c. Financial covenants contained within NVE’s Term Loan – As discussed in NVE’s Ability to Issue Debt, SPPC is also subject to NVE’s cap on additional consolidated indebtedness of $2.8 billion.

   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.  As of December 31, 2011, $1.5 billion of SPPC’s General and Refunding Mortgage Securities were outstanding.  SPPC had the capacity to issue $760 millionof additional General and Refunding Mortgage Securities as of December 31, 2011.    That amount is determined on the basis of:

1.        70% of net utility property additions; and/or

2.        The principal amount of retired General and Refunding Mortgage Securities.

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 SPPC’s Indenture, it will reduce the amount of securities issuable under the Indenture.

   Credit Ratings

The liquidity of SPPC, the cost and availability of borrowing by SPPC under its credit facility, the potential exposure of SPPC to collateral calls under various contracts and the ability of SPPC to acquire fuel and purchased power on favorable terms are all directly affected by the credit ratings for SPPC’s debt.  SPPC’s senior secured debt is rated investment grade by three NRSROs: Fitch, Moody’s and S&P.  In May 2011, Moody’s upgraded SPPC’s senior secured debt to Baa2.  As of December 31, 2011, the ratings are as follows:

		Rating Agency
		Fitch(1)	Moody’s(2)	S&P(3)
SPPC	Sr. Secured Debt	BBB*	Baa2*	BBB*
	*Investment grade
(1)	Fitch’s lowest level of “investment grade” credit rating is BBB-.
(2)	Moody’s lowest level of “investment grade” credit rating is Baa3.
(3)	S&P’s lowest level of “investment grade” credit rating is BBB-.

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

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.  Each security rating agency has its own methodology for assigning

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ratings, and, accordingly, each rating should be evaluated in the context of the applicable methodology, independently of all other ratings.  The rating agencies provide ratings at the request of the company being rated and charge the company fees for their services.

   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, which includes 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.  Most contracts and confirmations for purchased power have been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery in response to requests for financial assurance.  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. According to the net mark-to-market valueas of December 31, 2011, no amounts would be due to or from SPPC for all suppliers continuing to provide power under a WSPP agreement.  These contracts qualify for the normal purchases scope exception as defined by the Derivatives and Hedging Topic of the FASC, and as such, are not required to be mark-to-market on the balance sheet.  Refer to Note 6, 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 change, 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.  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 counterparties 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.

   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.  As discussed under SPPC’s Financing Transactions, the availability under SPPC’s revolving credit facility is reduced by the amount of net negative mark-to-market positions on hedging contracts with counterparties who are lenders to the revolving credit facility, provided that the reduction in availability under the revolving credit facility shall at no time exceed 50% of the total commitments then in effect under the revolving credit facility.  As a result of the suspension of the Utilities’ hedging program, there was no negative mark-to-market exposure for SPPC as of November 30, 2011 that would impact credit availability during the month of December 2011.  Beginning in October 2009, the Utilities suspended their hedging programs; however, prior to the suspension, it was the general policy of the Utilities to purchase hedges three seasons ahead.  As a result certain hedges entered into prior to the suspension in October 2009, did not terminate until 2011.  As of November 2011, all hedging transactions have expired or terminated and the Utilities remain unhedged.  If deemed prudent, the Utilities may still purchase hedging instruments in the event circumstances occur that may have the potential to increase the cost of fuel and purchased power.

   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 NPC 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.

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ITEM 7A.                       QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risk

As of December 31, 2011, 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.  The tables below do not include the interest rate swap entered into in 2011 and discussed further in Note 9, Derivatives and Hedging Activities, of the Notes to Financial Statements, as the amount is considered immaterial.  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 as of December 31 (dollars in thousands):

					2011
					Expected Maturities
																										Fair
					2012			2013			2014			2015			2016			Thereafter			Total			Value
Long-Term Debt
	NVE
	Fixed Rate			$	-		$	-		$	195,000		$	-		$	-		$	315,000		$	510,000		$	521,387
		Average Interest Rate			-			-			2.81	%		-			-			6.25	%		4.93	%		-
	NPC
	Fixed Rate			$	130,000			-		$	125,000		$	250,000		$	210,000		$	2,545,000		$	3,260,000		$	3,962,466
		Average Interest Rate			6.5	%		-			7.38	%		5.88	%		5.95	%		6.47	%		6.42	%		-
	Variable Rate			$	-		$	-		$	-		$	-		$	-		$	173,775		$	173,775		$	167,699
		Average Interest Rate			-			-			-			-			-			0.67	%		0.67	%		-
	SPPC
	Fixed Rate			$	-		$	250,000		$	-		$	-		$	-		$	701,742		$	951,742		$	1,133,731
		Average Interest Rate			-			5.45	%		-			-			-			6.27	%		6.05	%		-
	Variable Rate			$	-		$	-		$	-		$	-		$	-		$	214,675		$	214,675		$	190,989
		Average Interest Rate			-			-			-			-			-			0.64	%		0.64	%		-
			TOTAL DEBT	$	130,000		$	250,000		$	320,000		$	250,000		$	210,000		$	3,950,192		$	5,110,192		$	5,976,272

					2010
					Expected Maturities
																										Fair
					2011			2012			2013			2014			2015			Thereafter			Total			Value
Long-Term Debt
	NVE
	Fixed Rate			$	-		$	-		$	-		$	-		$	-		$	506,500		$	506,500		$	514,192
		Average Interest Rate			-			-			-			-			-			6.44	%		6.44	%		-
	NPC
	Fixed Rate			$	350,000		$	130,000		$	-		$	125,000		$	250,000		$	2,505,000		$	3,360,000		$	3,747,846
		Average Interest Rate			8.25	%		6.5	%		-			7.38	%		5.88	%		6.52	%		6.69	%		-
	Variable Rate			$	-		$	-		$	-		$	-		$	-		$	173,775		$	173,775		$	173,775
		Average Interest Rate			-			-			-			-			-			0.79	%		0.79	%		-
	SPPC
	Fixed Rate			$	-		$	-		$	250,000		$	-		$	-		$	701,742		$	951,742		$	1,059,041
		Average Interest Rate			-			-			5.45	%		-			-			6.27	%		6.05	%		-
	Variable Rate			$	-		$	-		$	15,000		$	-		$	-		$	214,675		$	229,675		$	229,675
		Average Interest Rate			-			-			2.51	%		-			-			0.75	%		0.86	%		-
			TOTAL DEBT	$	350,000		$	130,000		$	265,000		$	125,000		$	250,000		$	4,101,692		$	5,221,692		$	5,724,529

83

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 1, Business, for a discussion of the Utilities’ purchased power procurement strategies.

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 $40.7 million as of December 31, 2011, which compares to a balance of $60.1 million at December 31, 2010.  The decrease from December 31, 2010 is primarily due to the decrease in prices of natural gas and power during 2011.

84

ITEM 8.		FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
			Page
Reports of Independent Registered Public Accounting Firm			86
NV Energy, Inc.:
	Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2011, 2010 and 2009		89
	Consolidated Balance Sheets as of December 31, 2011 and 2010		90
	Consolidated Statements of Cash Flows for the Years Ended December 31, 2011, 2010 and 2009		92
	Consolidated Statements of Shareholders’ Equity for the Years Ended December 31, 2011, 2010 and 2009		93
Nevada Power Company:
	Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2011, 2010 and 2009		94
	Consolidated Balance Sheets as of December 31, 2011 and 2010		95
	Consolidated Statements of Cash Flows for the Years Ended December 31, 2011, 2010 and 2009		97
	Consolidated Statements of Shareholder’s Equity for the Years Ended December 31, 2011, 2010 and 2009		98
Sierra Pacific Power Company:
	Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2011, 2010 and 2009		99
	Consolidated Balance Sheets as of December 31, 2011 and 2010		100
	Consolidated Statements of Cash Flows for the Years Ended December 31, 2011, 2010 and 2009		102
	Consolidated Statements of Shareholder’s Equity for the Years Ended December 31, 2011, 2010 and 2009		103
Notes to Financial Statements for NV Energy, Inc., Nevada Power Company and Sierra Pacific Power Company			104

85

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 of NV Energy, Inc. and subsidiaries (the "Company") as of December 31, 2011 and 2010, and the related consolidated statements of comprehensive income, shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2011. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on 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. An audit 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 NV Energy, Inc. and subsidiaries as of December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011, 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, 2011, 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 24, 2012 expressed an unqualified opinion on the Company's internal control over financial reporting.

/s/ Deloitte & Touche LLP

Las Vegas, Nevada

February 24, 2012

86

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 of Nevada Power Company and subsidiaries (the "Company") as of December 31, 2011 and 2010, and the related consolidated statements of comprehensive income, shareholder’s equity, and cash flows for each of the three years in the period ended December 31, 2011. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on 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, 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, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011, 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 24, 2012

87

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

Sierra Pacific Power Company

Las Vegas, Nevada

We have audited the accompanying consolidated balance sheets of Sierra Pacific Power Company and subsidiaries (the "Company") as of December 31, 2011 and 2010, and the related consolidated statements of comprehensive income, shareholder’s equity, and cash flows for each of the three years in the period ended December 31, 2011. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on 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, 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 Sierra Pacific Power Company and subsidiaries as of December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011, 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 24, 2012

88

NV ENERGY, INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in Thousands, Except Share Amounts)
		Year Ended December 31,
		2011		2010		2009
OPERATING REVENUES		$	2,943,307	$	3,280,222	$	3,585,798
OPERATING EXPENSES:
	Fuel for power generation		680,585		821,484		881,768
	Purchased power		633,874		648,881		758,736
	Gas purchased for resale		125,155		137,702		153,607
	Deferred energy		(83,333)		113,107		289,076
	Energy efficiency program costs		43,537		-		-
	Other operating expenses		411,115		414,241		453,413
	Maintenance		103,307		104,567		102,309
	Depreciation and amortization		357,937		333,059		321,921
	Taxes other than income		60,465		62,746		60,885
Total Operating Expenses			2,332,642		2,635,787		3,021,715
OPERATING INCOME			610,665		644,435		564,083
OTHER INCOME (EXPENSE):
	Interest expense
	(net of AFUDC-debt: $8,718, $23,355 and $20,229)		(328,710)		(333,010)		(334,314)
	Interest income (expense) on regulatory items		(16,321)		(12,517)		(2,280)
	AFUDC-equity		10,873		28,112		24,274
	Other income		22,764		36,841		33,122
	Other expense		(48,924)		(23,113)		(26,498)
Total Other Income (Expense)			(360,318)		(303,687)		(305,696)
Income Before Income Tax Expense			250,347		340,748		258,387
Income tax expense (Note 10)			86,915		113,764		75,451
NET INCOME			163,432		226,984		182,936
Other comprehensive income (loss):
Change in compensation retirement benefits liability and amortization
(Net of taxes $202, $217 and $72 in 2011, 2010 and 2009, respectively)			(357)		(403)		(128)
Change in market value of risk management assets and liabilities
(Net of taxes $369 in 2011)			(686)		-		-
OTHER COMPREHENSIVE INCOME(LOSS)			(1,043)		(403)		(128)
COMPREHENSIVE INCOME		$	162,389	$	226,581	$	182,808
Amount per share basic and diluted - (Note 15)
	Net income per share - basic	$	0.69	$	0.97	$	0.78
	Net income per share - diluted	$	0.69	$	0.96	$	0.78
Weighted Average Shares of Common Stock Outstanding - basic			235,847,596		235,048,347		234,542,292
Weighted Average Shares of Common Stock Outstanding - diluted			237,767,071		236,294,812		235,180,688
Dividends Declared Per Share of Common Stock			0.49		0.45		0.41
The accompanying notes are an integral part of the financial statements.

89

NV ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
			December 31,
			2011		2010
ASSETS
Current Assets:
	Cash and cash equivalents		$	145,944	$	86,189
	Accounts receivable less allowance for uncollectible accounts:
	2011-$8,150; 2010-$28,684			355,091		354,010
	Materials, supplies and fuel, at average cost			129,663		114,520
	Risk management assets (Note 9)			-		4,007
	Current income taxes receivable			82		82
	Deferred income taxes (Note 10)			104,958		130,800
	Other current assets			36,782		42,330
Total Current Assets				772,520		731,938
Utility Property:
	Plant in service			11,923,717		11,068,518
	Construction work-in-progress			487,427		908,579
		Total (Note 1)		12,411,144		11,977,097
	Less accumulated provision for depreciation			3,184,071		3,047,438
		Total Utility Property, Net		9,227,073		8,929,659
Investments and other property, net (Note 4)				57,021		61,613
Deferred Charges and Other Assets:
	Deferred energy (Note 3)			102,525		117,623
	Regulatory assets (Note 3)			1,186,127		1,237,159
	Regulatory asset for pension plans (Note 3)			215,656		269,472
	Other deferred charges and assets			74,206		166,882
Total Deferred Charges and Other Assets				1,578,514		1,791,136
Assets Held for Sale (Note 16)				-		155,322
TOTAL ASSETS			$	11,635,128	$	11,669,668
(Continued)

90

NV ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
			December 31,
			2011		2010
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities:
	Current maturities of long-term debt		$	139,985	$	355,929
	Accounts payable			312,990		346,409
	Accrued expenses			128,144		133,851
	Risk management liabilities (Note 9)			3,678		33,229
	Deferred energy (Note 3)			245,164		315,839
	Other current liabilities			61,894		70,638
Total Current Liabilities				891,855		1,255,895
Long-term debt (Note 6)				5,008,931		4,924,109
Commitments and Contingencies (Note 13)
Deferred Credits and Other Liabilities:
	Deferred income taxes (Note 10)			1,306,510		1,246,410
	Deferred investment tax credit			16,140		19,204
	Accrued retirement benefits			92,351		148,841
	Risk management liabilities (Note 9)			1,055		-
	Regulatory liabilities (Note 3)			486,259		428,114
	Other deferred credits and liabilities			425,948		265,571
Total Deferred Credits and Other Liabilities				2,328,263		2,108,140
Liabilities Held for Sale (Note 16)				-		30,706
Shareholders' Equity:
	Common stock, $1.00 par value; 350 Million shares authorized;
	235,999,750 and 235,322,553 issued and outstanding
	for 2011 and 2010			236,000		235,323
	Other paid-in capital			2,713,736		2,705,954
	Retained earnings			464,277		416,432
	Accumulated other comprehensive loss			(7,934)		(6,891)
Total Shareholders' Equity				3,406,079		3,350,818
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY			$	11,635,128	$	11,669,668
The accompanying notes are an integral part of the financial statements.
		(Concluded)

91

NV ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
			For the Year Ended December 31,
			2011		2010		2009
CASH FLOWS FROM OPERATING ACTIVITIES:
	Net Income		$	163,432	$	226,984	$	182,936
	Adjustments to reconcile net income to net cash from operating activities:
		Depreciation and amortization		357,937		333,059		321,921
		Deferred taxes and deferred investment tax credit		88,445		129,231		111,219
		AFUDC-equity		(10,873)		(28,112)		(24,274)
		Deferred energy		(55,429)		147,497		306,406
		Gain on sale of asset		-		(7,575)		-
		Amortization of other regulatory assets		166,095		110,654		101,641
		Deferred rate increase		79,866		(8,343)		(95,890)
		Other, net		16,536		(20,666)		(7,755)
	Changes in certain assets and liabilities:
		Accounts receivable		215		52,238		12,733
		Materials, supplies and fuel		(14,747)		9,167		465
		Other current assets		5,548		1,969		8,335
		Accounts payable		17,466		28,070		(31,888)
		Accrued retirement benefits		(26,845)		(18,476)		(20,080)
		Other current liabilities		(14,449)		2,945		(17,287)
		Risk management assets and liabilities		3,810		12,267		5,058
		Other deferred assets		(6,430)		(6,111)		(13,831)
		Other regulatory assets		(113,568)		(77,893)		(69,937)
		Other deferred liabilities		1,369		(453)		(18,251)
Net Cash from Operating Activities				658,378		886,452		751,521
CASH FLOWS USED BY INVESTING ACTIVITIES:
		Additions to utility plant (excluding AFUDC-equity)		(620,516)		(629,496)		(843,132)
		Proceeds from sale of asset		166,603		18,225		-
		Customer advances for construction		(7,762)		(11,142)		(8,369)
		Contributions in aid of construction		106,050		63,330		76,940
		Investments and other property - net		498		(8,974)		(26,061)
Net Cash used by Investing Activities				(355,127)		(568,057)		(800,622)
CASH FLOWS FROM FINANCING ACTIVITIES:
		Proceeds from issuance of long-term debt		579,820		985,419		1,418,872
		Retirement of long-term debt		(701,244)		(1,180,646)		(1,271,350)
		Settlement of interest rate lock		(14,944)		-		-
		Sale of Common Stock		8,459		6,114		6,051
		Dividends paid		(115,587)		(105,799)		(96,125)
Net Cash from/(used by) Financing Activities				(243,496)		(294,912)		57,448
Net Increase in Cash and Cash Equivalents				59,755		23,483		8,347
Beginning Balance in Cash and Cash Equivalents				86,189		62,706		54,359
Ending Balance in Cash and Cash Equivalents			$	145,944	$	86,189	$	62,706
Supplemental Disclosures of Cash Flow Information:
	Cash paid during period for:
		Interest	$	314,401	$	336,668	$	325,508
		Income taxes	$	576	$	754	$	(13,186)
	Significant non-cash transactions:
		Accrued construction expenses as of December 31,	$	195,511	$	86,127	$	127,786
		Capital lease obligations incurred	$	-	$	15,336	$	-
		Transfer of assets to accounts receivable	$	-	$	16,830	$	-
The accompanying notes are an integral part of the financial statements.

92

NV ENERGY, INC.
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
(Dollars in Thousands, except share amounts)
									Accumulated
		Common	Common		Other				Other		Total
		Stock	Stock		Paid-in		Retained		Comprehensive		Shareholders'
		Shares	Amount		Capital		Earnings		Income (Loss)		Equity
December 31, 2008		234,316,829	$	234,317	$	2,694,792	$	208,436	$	(6,360)	$	3,131,185
	Net Income	-		-		-		182,936		-		182,936
	Dividend Reinvestment and
	Employee Benefits	517,340		517		5,530		-		-		6,047
	Tax benefit from stock options exercised	-		-		7		-		-		7
	Change in compensation retirement benefits
	liability and amortization
	(net of taxes $72)	-		-		-		-		(128)		(128)
	Dividends Declared	-		-		-		(96,125)		-		(96,125)
December 31, 2009		234,834,169		234,834		2,700,329		295,247		(6,488)		3,223,922
	Net Income	-		-		-		226,984		-		226,984
	Dividend Reinvestment and Employee Benefits	488,384		489		5,620		-		-		6,109
	Common Stock issuance costs	-		-		(27)		-		-		(27)
	Tax benefit from stock options exercised	-		-		32		-		-		32
	Change in compensation retirement benefits
	liability and amortization
	(net of taxes $217)	-		-		-		-		(403)		(403)
	Dividends Declared	-		-		-		(105,799)		-		(105,799)
December 31, 2010		235,322,553		235,323		2,705,954		416,432		(6,891)		3,350,818
	Net Income	-		-		-		163,432		-		163,432
	Dividend Reinvestment and Employee Benefits	677,197		677		7,782		-		-		8,459
	Change in compensation retirement benefits
	liability and amortization
	(net of taxes $202)	-		-		-		-		(357)		(357)
	Change in market value of risk management
	assets and liabilities
	(net of taxes $369)	-		-		-		-		(686)		(686)
	Dividends Declared	-		-		-		(115,587)		-		(115,587)
December 31, 2011		235,999,750	$	236,000	$	2,713,736	$	464,277	$	(7,934)	$	3,406,079
The accompanying notes are an integral part of the financial statements.

93

NEVADA POWER COMPANY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in Thousands)
		Year Ended December 31,
		2011		2010		2009
OPERATING REVENUES		$	2,054,393	$	2,252,377	$	2,423,377
OPERATING EXPENSES:
	Fuel for power generation		498,487		588,419		587,647
	Purchased power		477,226		505,239		627,759
	Deferred energy		(16,300)		94,843		207,611
	Energy efficiency program costs		37,292		-		-
	Other operating expenses		260,127		260,535		279,865
	Maintenance		64,320		71,759		71,019
	Depreciation and amortization		252,191		226,252		215,873
	Taxes other than income		37,254		37,918		37,241
Total Operating Expenses			1,610,597		1,784,965		2,027,015
OPERATING INCOME			443,796		467,412		396,362
OTHER INCOME (EXPENSE):
	Interest expense
	(net of AFUDC-debt: $6,770, $21,443 and $17,184)		(221,953)		(214,367)		(226,252)
	Interest income (expense) on regulatory items		(8,572)		(3,169)		3,463
	AFUDC-equity		8,298		25,229		21,025
	Other income		14,774		15,541		19,658
	Other expense		(33,020)		(12,946)		(18,320)
Total Other Income (Expense)			(240,473)		(189,712)		(200,426)
Income Before Income Tax Expense			203,323		277,700		195,936
Income tax expense (Note 10)			70,737		91,757		61,652
NET INCOME			132,586		185,943		134,284
Other comprehensive income (loss):
Change in compensation retirement benefits liability and amortization
(Net of taxes $129, $205 and ($96) in 2011, 2010 and 2009, respectively)			(241)		(380)		175
COMPREHENSIVE INCOME		$	132,345	$	185,563	$	134,459
The accompanying notes are an integral part of the financial statements.

94

	NEVADA POWER COMPANY
	CONSOLIDATED BALANCE SHEETS
	(Dollars in Thousands)
				December 31,
				2011		2010
	ASSETS
	Current Assets:
		Cash and cash equivalents		$	65,887	$	60,077
		Accounts receivable less allowance for uncollectible accounts:
		2011-$6,751; 2010-$26,428			233,096		224,704
		Materials, supplies and fuel, at average cost			72,529		66,459
		Risk management assets (Note 9)			-		3,476
		Deferred income taxes (Note 10)			88,782		76,282
		Other current assets			28,943		29,680
	Total Current Assets				489,237		460,678
	Utility Property:
		Plant in service			8,345,771		7,552,097
		Construction work-in-progress			352,541		825,079
			Total (Note 1)		8,698,312		8,377,176
		Less accumulated provision for depreciation			1,906,617		1,828,366
			Total Utility Property, Net		6,791,695		6,548,810
	Investments and other property, net (Note 4)				50,768		55,305
	Deferred Charges and Other Assets:
		Deferred energy (Note 3)			102,525		117,623
		Regulatory assets (Note 3)			852,989		871,982
		Regulatory asset for pension plans (Note 3)			108,528		133,410
		Other deferred charges and assets			46,855		114,016
	Total Deferred Charges and Other Assets				1,110,897		1,237,031
	TOTAL ASSETS			$	8,442,597	$	8,301,824
(Continued)

95

NEVADA POWER COMPANY
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
			December 31,
			2011		2010
LIABILITIES AND SHAREHOLDER'S EQUITY
Current Liabilities:
	Current maturities of long-term debt		$	139,985	$	355,929
	Accounts payable			182,183		232,279
	Accounts payable, affiliated companies			28,429		29,334
	Accrued expenses			89,311		89,638
	Risk management liabilities (Note 9)			3,678		22,764
	Deferred energy (Note 3)			159,799		171,349
	Other current liabilities			47,047		54,607
Total Current Liabilities				650,432		955,900
Long-term debt (Note 6)				3,319,605		3,221,833
Commitments and Contingencies (Note 13)
Deferred Credits and Other Liabilities:
	Deferred income taxes (Note 10)			997,921		908,094
	Deferred investment tax credit			6,098		7,255
	Accrued retirement benefits			9,454		31,907
	Regulatory liabilities (Note 3)			274,951		225,983
	Other deferred credits and liabilities			335,159		189,220
Total Deferred Credits and Other Liabilities				1,623,583		1,362,459
Shareholder's Equity:
	Common stock, $1.00 par value, 1,000 shares authorized,
	issued and outstanding for 2011 and 2010			1		1
	Other paid-in capital			2,308,219		2,254,219
	Retained earnings			544,874		511,288
	Accumulated other comprehensive loss			(4,117)		(3,876)
Total Shareholder's Equity				2,848,977		2,761,632
TOTAL LIABILITIES AND SHAREHOLDER'S EQUITY			$	8,442,597	$	8,301,824
The accompanying notes are an integral part of the financial statements.
		(Concluded)

96

NEVADA POWER COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
			For the Year Ended December 31,
			2011		2010		2009
CASH FLOWS FROM OPERATING ACTIVITIES:
	Net Income		$	132,586	$	185,943	$	134,284
	Adjustments to reconcile net income to net cash from operating activities:
		Depreciation and amortization		252,191		226,252		215,873
		Deferred taxes and deferred investment tax credit		71,971		92,859		96,831
		AFUDC-equity		(8,298)		(25,229)		(21,025)
		Deferred energy		3,549		116,230		216,629
		Amortization of other regulatory assets		83,070		74,625		61,758
		Deferred rate increase		79,866		(8,343)		(95,890)
		Other, net		7,147		(16,153)		(159)
	Changes in certain assets and liabilities:
		Accounts receivable		(8,391)		39,679		(5,309)
		Materials, supplies and fuel		(5,674)		3,115		4,928
		Other current assets		736		(1,824)		6,802
		Accounts payable		(11)		13,905		(10,694)
		Accrued retirement benefits		(9,725)		(17,792)		(18,721)
		Other current liabilities		(7,888)		4,959		(13,544)
		Risk management assets and liabilities		2,225		9,565		3,319
		Other deferred assets		(5,125)		(2,598)		(10,336)
		Other regulatory assets		(54,885)		(50,937)		(54,061)
		Other deferred liabilities		(6,235)		(2,873)		(25,611)
Net Cash from Operating Activities				527,109		641,383		485,074
CASH FLOWS USED BY INVESTING ACTIVITIES:
		Additions to utility plant (excluding AFUDC-equity)		(475,118)		(499,374)		(656,074)
		Proceeds from sale of asset		31,997		3,254		-
		Customer advances for construction		(1,852)		(8,646)		(5,281)
		Contributions in aid of construction		89,427		55,140		67,514
		Investments and other property - net		475		(5)		(21,547)
Net Cash used by Investing Activities				(355,071)		(449,631)		(615,388)
CASH FLOWS FROM FINANCING ACTIVITIES:
		Proceeds from issuance of long-term debt		386,884		637,463		1,065,338
		Retirement of long-term debt		(493,168)		(737,747)		(809,009)
		Settlement of interest rate lock		(14,944)		-		-
		Additional investment by parent company		54,000		-		-
		Dividends paid		(99,000)		(74,000)		(112,000)
Net Cash from/(used by) Financing Activities				(166,228)		(174,284)		144,329
Net Increase in Cash and Cash Equivalents				5,810		17,468		14,015
Beginning Balance in Cash and Cash Equivalents				60,077		42,609		28,594
Ending Balance in Cash and Cash Equivalents			$	65,887	$	60,077	$	42,609
Supplemental Disclosures of Cash Flow Information:
	Cash paid during period for:
		Interest	$	218,693	$	226,138	$	217,807
		Income taxes	$	1	$	2	$	2
	Significant non-cash transactions:
		Accrued construction expenses as of December 31,	$	175,661	$	74,557	$	117,226
		Capital lease obligations incurred	$	-	$	15,336	$	-
The accompanying notes are an integral part of the financial statements.

97

NEVADA POWER COMPANY
CONSOLIDATED STATEMENTS OF SHAREHOLDER'S EQUITY
(Dollars in Thousands, except share amounts)
									Accumulated
		Common	Common		Other				Other		Total
		Stock	Stock		Paid-in		Retained		Comprehensive		Shareholder's
		Shares	Amount		Capital		Earnings		Income (Loss)		Equity
December 31, 2008		1,000	$	1	$	2,254,182	$	377,061	$	(3,671)	$	2,627,573
	Net Income	-		-		-		134,284		-		134,284
	Tax benefit from stock options exercised	-		-		7		-		-		7
	Change in compensation retirement
	benefits liability and amortization
	(net of taxes ($96))	-		-		-		-		175		175
	Dividends Declared	-		-		-		(112,000)		-		(112,000)
December 31, 2009		1,000		1		2,254,189		399,345		(3,496)		2,650,039
	Net Income	-		-		-		185,943		-		185,943
	Tax benefit from stock options exercised	-		-		30		-		-		30
	Change in compensation retirement benefits
	liability and amortization
	(net of taxes $205)	-		-		-		-		(380)		(380)
	Dividends Declared	-		-		-		(74,000)		-		(74,000)
December 31, 2010		1,000		1		2,254,219		511,288		(3,876)		2,761,632
	Net Income	-		-		-		132,586		-		132,586
	Capital contribution from parent	-		-		54,000		-		-		54,000
	Change in compensation retirement benefits
	liability and amortization
	(net of taxes $129)	-		-		-		-		(241)		(241)
	Dividends Declared	-		-		-		(99,000)		-		(99,000)
December 31, 2011		1,000	$	1	$	2,308,219	$	544,874	$	(4,117)	$	2,848,977
The accompanying notes are an integral part of the financial statements.

98

SIERRA PACIFIC POWER COMPANY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in Thousands)
		Year Ended December 31,
		2011		2010		2009
OPERATING REVENUES:
	Electric	$	716,417	$	836,879	$	957,130
	Gas		172,482		190,943		205,263
Total Operating Revenues			888,899		1,027,822		1,162,393
OPERATING EXPENSES:
	Fuel for power generation		182,098		233,065		294,121
	Purchased power		156,648		143,642		130,977
	Gas purchased for resale		125,155		137,702		153,607
	Deferral of energy - electric - net		(65,445)		8,475		73,829
	Deferral of energy - gas - net		(1,588)		9,789		7,636
	Energy efficiency program costs		6,245		-		-
	Other operating expenses		146,699		149,946		170,849
	Maintenance		38,987		32,808		31,290
	Depreciation and amortization		105,746		106,807		106,048
	Taxes other than income		22,921		24,593		23,447
Total Operating Expenses			717,466		846,827		991,804
OPERATING INCOME			171,433		180,995		170,589
OTHER INCOME (EXPENSE):
	Interest expense
	(net of AFUDC-debt: $1,948, $1,912 and $3,044)		(67,435)		(68,514)		(69,413)
	Interest income (expense) on regulatory items		(7,749)		(9,348)		(5,743)
	AFUDC-equity		2,575		2,883		3,249
	Other income		6,883		16,748		13,276
	Other expense		(14,624)		(9,985)		(7,648)
Total Other Income (Expense)			(80,350)		(68,216)		(66,279)
Income Before Income Tax Expense			91,083		112,779		104,310
Income tax expense (Note 10)			31,197		40,404		31,225
NET INCOME			59,886		72,375		73,085
Other comprehensive income (loss):
Change in compensation retirement benefits liability and amortization
(Net of taxes ($645), $116 and $48 in 2011, 2010 and 2009, respectively)			1,236		(215)		(87)
COMPREHENSIVE INCOME		$	61,122	$	72,160	$	72,998
The accompanying notes are an integral part of the financial statements.

99

	SIERRA PACIFIC POWER COMPANY
	CONSOLIDATED BALANCE SHEETS
	(Dollars in Thousands)
				December 31,
				2011		2010
	ASSETS
	Current Assets:
		Cash and cash equivalents		$	55,195	$	9,552
		Accounts receivable less allowance for uncollectible accounts:
		2011-$1,399; 2010-$2,256			121,863		129,306
		Materials, supplies and fuel, at average cost			57,134		48,061
		Risk management assets (Note 9)			-		531
		Intercompany income taxes receivable			10,351		10,351
		Deferred income taxes (Note 10)			32,311		53,282
		Other current assets			7,504		11,633
	Total Current Assets				284,358		262,716
	Utility Property:
		Plant in service			3,577,946		3,516,421
		Construction work-in-progress			134,886		83,500
			Total (Note 1)		3,712,832		3,599,921
		Less accumulated provision for depreciation			1,277,454		1,219,072
			Total Utility Property, Net		2,435,378		2,380,849
	Investments and other property, net (Note 4)				5,901		5,956
	Deferred Charges and Other Assets:
		Regulatory assets (Note 3)			333,138		365,177
		Regulatory asset for pension plans (Note 3)			104,159		131,734
		Other deferred charges and assets			21,074		45,268
	Total Deferred Charges and Other Assets				458,371		542,179
	Assets Held for Sale (Note 16)				-		155,322
	TOTAL ASSETS			$	3,184,008	$	3,347,022
(Continued)

100

SIERRA PACIFIC POWER COMPANY
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
		December 31,
		2011		2010
LIABILITIES AND SHAREHOLDER'S EQUITY
Current Liabilities:
	Accounts payable	$	99,897	$	90,206
	Accounts payable, affiliated companies		27,788		10,812
	Accrued expenses		32,840		33,788
	Dividends Declared		-		54,000
	Risk management liabilities (Note 9)		-		10,465
	Deferred energy (Note 3)		85,365		144,490
	Other current liabilities		14,846		16,029
Total Current Liabilities			260,736		359,790
Long-term debt (Note 6)			1,179,326		1,195,775
Commitments and Contingencies (Note 13)
Deferred Credits and Other Liabilities:
	Deferred income taxes (Note 10)		398,787		395,454
	Deferred investment tax credit		10,042		11,949
	Accrued retirement benefits		74,297		110,302
	Regulatory liabilities (Note 3)		211,308		202,131
	Other deferred credits and liabilities		74,970		67,495
Total Deferred Credits and Other Liabilities			769,404		787,331
Liabilities Held for Sale (Note 16)			-		30,706
Shareholder's Equity:
	Common stock, $3.75 par value, 20,000,000 shares authorized,
	1,000 shares issued and outstanding for 2011 and 2010		4		4
	Other paid-in capital		1,111,262		1,111,262
	Retained earnings		(135,340)		(135,226)
	Accumulated other comprehensive loss		(1,384)		(2,620)
Total Shareholder's Equity			974,542		973,420
TOTAL LIABILITIES AND SHAREHOLDER'S EQUITY		$	3,184,008	$	3,347,022
The accompanying notes are an integral part of the financial statements.
	(Concluded)

101

SIERRA PACIFIC POWER COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
			For the Year Ended December 31,
			2011		2010		2009
CASH FLOWS FROM OPERATING ACTIVITIES:
	Net Income		$	59,886	$	72,375	$	73,085
	Adjustments to reconcile net income to net cash from operating activities:
		Depreciation and amortization		105,746		106,807		106,048
		Deferred taxes and deferred investment tax credit		31,487		39,220		32,548
		AFUDC-equity		(2,575)		(2,883)		(3,249)
		Deferred energy		(58,978)		31,267		89,777
		Gain on sale of asset		-		(7,575)		-
		Amortization of other regulatory assets		81,636		35,799		39,146
		Other, net		8,464		(7,929)		(8,778)
	Changes in certain assets and liabilities:
		Accounts receivable		8,739		31,961		68,435
		Materials, supplies and fuel		(9,073)		5,991		(4,436)
		Other current assets		4,128		4,421		1,575
		Accounts payable		26,564		2,050		(15,071)
		Accrued retirement benefits		(18,401)		(2,523)		(2,227)
		Other current liabilities		(2,131)		721		(3,038)
		Risk management assets and liabilities		531		2,702		1,739
		Other deferred assets		(1,305)		(3,513)		(3,495)
		Other regulatory assets		(58,683)		(26,956)		(15,876)
		Other deferred liabilities		641		887		(30,388)
	Net Cash from Operating Activities			176,676		282,822		325,795
CASH FLOWS USED BY INVESTING ACTIVITIES:
		Additions to utility plant (excluding AFUDC-equity)		(145,398)		(143,216)		(187,058)
		Proceeds from sale of asset		134,606		14,971		-
		Customer advances for construction		(5,910)		(2,496)		(3,088)
		Contributions in aid of construction		16,623		8,190		9,426
		Investments and other property - net		23		(97)		(5,017)
Net Cash used by Investing Activities				(56)		(122,648)		(185,737)
CASH FLOWS USED BY FINANCING ACTIVITIES:
		Proceeds from issuance of long-term debt		(403)		37,726		353,534
		Retirement of long-term debt		(16,574)		(148,707)		(462,144)
		Investment by parent company		-		-		90,300
		Dividends paid		(114,000)		(54,000)		(128,800)
Net Cash used by Financing Activities				(130,977)		(164,981)		(147,110)
Net Increase (Decrease) in Cash and Cash Equivalents				45,643		(4,807)		(7,052)
Beginning Balance in Cash and Cash Equivalents				9,552		14,359		21,411
Ending Balance in Cash and Cash Equivalents				55,195		9,552		14,359
Supplemental Disclosures of Cash Flow Information:
	Cash paid during period for:
		Interest	$	59,605	$	67,351	$	69,966
		Income taxes	$	575	$	752	$	12
	Significant non-cash transactions:
		Accrued construction expenses as of December 31,	$	19,850	$	11,570	$	10,560
		Transfer of assets to accounts receivable	$	-	$	16,830	$	-
		Accrued dividends payable	$	-	$	54,000	$	-
The accompanying notes are an integral part of the financial statements.

102

SIERRA PACIFIC POWER COMPANY
CONSOLIDATED STATEMENTS OF SHAREHOLDER'S EQUITY
(Dollars in Thousands, except share amounts)
									Accumulated
		Common	Common		Other				Other		Total
		Stock	Stock		Paid-in		Retained		Comprehensive		Shareholder's
		Shares	Amount		Capital		Earnings		Income (Loss)		Equity
December 31, 2008		1,000	$	4	$	1,020,960	$	(140,686)	$	(2,318)	$	877,960
	Net Income	-		-		-		73,085		-		73,085
	Capital contribution from parent	-		-		90,300		-		-		90,300
	Change in compensation retirement benefits
	liability and amortization
	(net of taxes $48)	-		-		-		-		(87)		(87)
	Dividends Declared	-		-		-		(32,000)		-		(32,000)
December 31, 2009		1,000		4		1,111,260		(99,601)		(2,405)		1,009,258
	Net Income	-		-		-		72,375		-		72,375
	Tax benefit from stock options exercised	-		-		2		-		-		2
	Change in compensation retirement benefits
	liability and amortization
	(net of taxes $116)	-		-		-		-		(215)		(215)
	Dividends Declared	-		-		-		(108,000)		-		(108,000)
December 31, 2010		1,000		4		1,111,262		(135,226)		(2,620)		973,420
	Net Income	-		-		-		59,886		-		59,886
	Change in compensation retirement benefits
	liability and amortization
	(net of taxes ($645))	-		-		-		-		1,236		1,236
	Dividends Declared	-		-		-		(60,000)		-		(60,000)
December 31, 2011		1,000	$	4	$	1,111,262	$	(135,340)	$	(1,384)	$	974,542
The accompanying notes are an integral part of the financial statements.

103

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, NPC, SPPC, Sierra Pacific Communications, Lands of Sierra, Inc., NVE Insurance and Sierra Gas Holding Company.  All 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 73% of the consolidated assets of NVE at December 31, 2011.  NPC provides electricity to approximately 840,000 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 NPC include its wholly-owned subsidiary, NEICO.

SPPC is an operating public utility that provides electric service in northern Nevada and previously provided service to northeastern California.  SPPC also provides natural gas service in the Reno/Sparks area of Nevada.  The assets of SPPC represent approximately 27% of the consolidated assets of NVE at December 31, 2011.  SPPC provides electricity to approximately 323,000 customers in an approximate 50,000 square mile service area including western, central and northeastern Nevada, including the cities of Reno, Sparks, Carson City and Elko.  On January 1, 2011, SPPC sold its California Assets, as discussed in Note 16, Assets Held for Sale.  SPPC also provides natural gas service in Nevada to approximately 152,000 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 and GPSF-B.

The Utilities’ accounts are maintained in accordance with the Uniform System of Accounts prescribed by the FERC.

Regulatory Accounting and Other Regulatory Assets

The Utilities’ rates are subject to the approval of the PUCN, and in the case of SPPC during 2010, 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 regulatory accounting treatment as allowed by the Regulated Operations Topic of the FASC.  However, on January 1, 2011, SPPC sold its California Assets, as disclosed in Note 16, Assets Held for Sale.  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.  The accounting guidance prescribes the method to be used to record the financial transactions of a regulated entity.  The criteria for applying the accounting for regulated operations 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 regulatory accounting treatment as allowed by the Regulated Operations Topic of the FASC 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.

Equity Carrying Charges

In accordance with various regulatory orders, the Utilities’ record carrying charges as allowed by the Regulated Operations Topic of the FASC.  However, for financial reporting purposes the amounts representing equity carrying charges are not recognized

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until collected through regulated rates.  As of December 31, 2011 and 2010, NPC and SPPC have accumulated approximately $12.7 million, and $.9 million, and $12.0 million and $1.1 million, respectively, of equity related carrying charges that will be recognized into income when the corresponding regulatory assets primarily related to NPC’s deferred rate increase, Lenzie and the Utilities’ conservation programs are collected through rates.  For further information, see Note 3, Regulatory Actions, Other Regulatory Assets table.

Deferred Energy Accounting

Nevada and California statutes permit regulated utilities to adopt deferred energy accounting procedures.  However, on January 1, 2011, SPPC sold its California assets, as disclosed in Note 16, Assets Held for Sale.  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 the Regulated Operations Topic of the FASC.  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.  In 2011, the Legislature passed Assembly Bill 215 which allows an electric or gas utility that adjusts its BTER on a quarterly basis to request PUCN approval to make quarterly changes to its DEAA rate if the request is in the public interest.  The Utilities will still be required to file an annual DEAA case to review costs for prudency and reasonableness, and if any costs are disallowed on such grounds, the disallowance will be incorporated into the next subsequent quarterly rate change.  See Note 3, Regulatory Actions, for details regarding deferred energy balances.

Energy Efficiency Implementation Rate (EEIR) and Energy Efficiency Program Rate (EEPR)

In 2009, the Nevada Legislature passed Senate Bill 358, which required the PUCN to adopt regulations authorizing an electric utility to recover lost revenue that is attributable to the measurable and verifiable effects associated with the implementation of efficiency and conservation programs approved by the PUCN.  As a result, the PUCN opened Docket No. 09-07016 to amend and adopt the regulation.  The regulation was adopted by the Legislature on July 22, 2010.  As a result, the Utilities file annually in March, to adjust rates and set a clearing rate or EEIR effective in October of the same year for over or under collected balance, similar to the deferred energy mechanism discussed above. In addition, the regulation approved the transition of the recovery for the implementation costs of energy efficiency programs from general rates (filed every 3 years) to recovery through annual rate filings annually in March, to adjust rates and set a clearing rate or EEPR effective in October of the same year for over or under collected balance, similar to the deferred energy mechanism discussed above.  See Note 3, Regulatory Actions, for details regarding EEIR and EEPR 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.

Utility Property

NVE, NPC and SPPC’s gross utility property and CWIP are divided into the following major classes at December 31 (dollars in millions):

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		2011						2010
		NVE		NPC		SPPC		NVE		NPC		SPPC
Electric Generation assets		$	4,791	$	3,724	$	1,067	$	4,056	$	2,991	$	1,065
Electric Transmission assets			1,853		1,183		670		1,840		1,183		657
Electric Distribution assets			4,108		2,874		1,234		4,019		2,820		1,199
Electric General, Intangible plant			659		564		95		657		558		99
Electric CWIP			473		353		121		906		825		81
Natural Gas Distribution assets			312		-		312		303		-		303
Natural Gas General, Intangible plant			3		-		3		3		-		3
Natural Gas CWIP			14		-		14		2		-		2
Common Assets			197		-		197		191		-		191
	Total Utility Property, Gross	$	12,411	$	8,698	$	3,713	$	11,977	$	8,377	$	3,600

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 2011, 2010 and 2009 were 8.47%, 8.32% and 8.57% respectively.  SPPC’s AFUDC rates used during 2011, 2010 and 2009 were 7.86% (Electric) and 5.15% (Gas), 7.85%, 7.96% respectively.  (In 2011, separate rates were calculated for electric and gas due to different rates of return allowed by PUCN Docket 10-06002).  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 casesNPC’s depreciation provision, as authorized by the PUCN and stated as a percentage of the average depreciable property balances for those years, was approximately 3.04%, 2.99% and 2.74% during 2011, 2010 and 2009, respectively.  SPPC’s depreciation provision for 2011, 2010 and 2009, as authorized by the PUCN and stated as a percentage of the average cost of depreciable property, was approximately 2.89%, 3.02% and 3.07% respectively.

The average estimated useful life for each major class of utility property, plant and equipment are as follows:

	Estimated Useful Lives
	NPC	SPPC
Electric Generation	25 to 125 years	25 to 125 years
Electric Transmission	45 to 65 years	50 to 70 years
Electric Distribution	20 to 65 years	30 to 65 years
Gas Distribution	N/A	40 to 70 years
General Plant	5 to 65 years	5 to 65 years

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 the Property, Plant and Equipment Topic of the FASC.

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.

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Federal Income Taxes

NVE and the Utilities file a consolidated federal income tax return.  Current income taxes are allocated based on NVE’s and each Utility’s respective taxable income or loss and tax credits as if each Utility filed a separate return.

NVE and the Utilities recognize deferred tax liabilities and assets for the future tax consequences of events that have been included in the financial statements or tax returns.  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.  Deferred tax assets are also recorded for deductions incurred and credits earned that have not been utilized in tax returns filed or to be filed for tax years through the date of the financial statements.  Management considers estimates of the amount and character of future taxable income by tax jurisdiction in assessing the likelihood of realization of deferred tax assets.  If it is not more likely than not that a deferred tax asset will be realized in its entirety, a valuation allowance is recorded with respect to the portion estimated not likely to be realized.

Tax benefits associated with income tax positions taken, or expected to be taken, in a tax return are recorded only when the more-likely-than-not recognition threshold is satisfied and measured at the largest amount of benefit that is greater than 50 percent likely of being realized upon settlement.  NVE and the Utilities classify interest and penalties associated with unrecognized tax benefits as interest and other expense, respectively, within the income statement.  No interest expense or penalties associated with unrecognized tax benefits have been recorded.   

The Utilities reduce rates to reflect the current tax benefits associated with recognizing certain tax deductions sooner than when the expenses are recognized for financial reporting purposes. A regulatory asset is 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 record regulatory liabilities for obligations 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.

Investment tax credits are deferred and amortized over the estimated service lives of the related properties.

Revenues

   Unbilled

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, line loss and the Utilities’ current tariffs.  Accounts receivable as of December 31, 2011, include unbilled receivables of $93 million and $51 million for NPC and SPPC, respectively.  Accounts receivable as of December 31, 2010, include unbilled receivables of $89 million and $60 million for NPC and SPPC, respectively.

Alternative Revenues

As adopted by the PUCN in July 2010, the Utilities were authorized to recover lost revenue that was attributable to the measurable and verifiable effects associated with the implementation of efficiency and conservation programs approved by the PUCN.  The Utilities accounted for the effects of such regulation in accordance with FASC 980-605-25, Alternative Revenue Programs which permits the recording of revenue if all of the following conditions are met: (1) the program allows for automatic adjustment of future rates, (2) the amount of revenues is objectively determinable and probable of recovery, and (3) the additional revenues will be collected within 24 months.  See Note 3, Regulatory Actions, EEIR, for further discussion on the recording of such revenues.

Asset Retirement Obligations

The Asset Retirement and Environmental Liabilities Topic of the FASC provides accounting requirements for the recognition and measurement of liabilities associated with the retirement of tangible long-lived assets.  Under the accounting guidance, 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

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assets included within the scope of the accounting guidance 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. 

 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 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.  Additionally, 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 as defined in the Asset Retirement and Environmental Liabilities Topic of the FASC.

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
		2011		2010		2011		2010		2011		2010
ARO balance at January 1	$	55,202	$	55,968	$	47,126	$	48,320	$	8,076	$	7,648
Liabilities incurred in current period		3,282		-		3,282		-		-		-
Liabilities settled in current period		(6,996)		(34)		(6,996)		(34)		-		-
Accretion expense		3,866		3,877		3,348		3,383		518		494
Revision in estimated cash flows		16,391		(4,606)		15,021		(4,540)		1,370		(66)
Gain/Loss on settlement		(763)		(3)		(763)		(3)		-		-
ARO balance at December 31	$	70,982	$	55,202	$	61,018	$	47,126	$	9,964	$	8,076

Cost of Removal

In addition to the legal asset retirement obligations booked under the accounting guidance for asset retirement obligations, the Utilities have accrued for the cost of removing non-legal retirement obligations of other electric and gas assets.  The amounts of such accruals included in regulatory liabilities in 2011 are approximately $232.0 million and $189.9 million for NPC and SPPC, respectively.  In 2010, the amounts were approximately $208.8 million and $173.5 million.

Variable Interest Entities

NVE and the Utilities continually perform an analysis to determine whether their variable interests give them controlling financial interest in a VIE which would require consolidation.  This analysis identifies the primary beneficiary of a VIE as the enterprise that has both the following characteristics: a) the power to direct the activities of a VIE that most significantly impact the entity’s economic performance, and b) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE.  To identify potential variable interests, management reviews contracts under leases, long term purchase power contracts, tolling contracts and jointly owned facilities.  The Utilities identified certain long-term purchase power contracts that could be defined as variable interests.  However, the Utilities are not the primary beneficiary as defined above, as they primarily lacked the power to direct the activities of the entity, including the ability to operate the generating facilities and make management decisions.  The Utilities' maximum exposure to loss is limited to the cost of replacing these purchase power contracts if the providers 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.  As of December 31, 2011, the carrying amount of assets and liabilities in the Utilities’ balance sheets that relate to their involvement with VIEs are predominately related to working capital accounts and generally represent the amounts owed by the Utilities for the deliveries associated with the current billing cycle under the contracts.

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 present such fees on a net basis, as such, fees are excluded from revenue and expense.

Recent Accounting Standards Updates

   Fair Value Measurements and Disclosures (ASU 820)

In January 2010, the FASB amended the Fair Value Measurements and Disclosure Topic as reflected in the FASB Accounting Standards Codification for recurring and nonrecurring fair value measurements. NVE and the Utilities adopted this

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amendment on January 1, 2010.  The new accounting guidance adds requirements for disclosures about transfers into and out of Levels 1 and 2 and separate disclosures about purchases, sales, issuances, and settlements relating to Level 3 measurements.  It also clarifies existing fair value disclosures about the level of disaggregation and about inputs and valuation techniques used to measure fair value. In addition, the accounting update amends guidance on employers’ disclosures about postretirement benefit plan assets to require disclosures by classes of assets instead of by major categories of assets.  The amendment is effective for NVE and the Utilities as of January 1, 2010, except for the disclosures about purchases, sales, issuances, and settlements in the roll forward activity in Level 3 fair value measurements. Those disclosures are effective for NVE and the Utilities as of January 1, 2011.  The adoption of this guidance did not have a significant impact on the disclosure requirements for NVE and the Utilities.

In May 2011, the FASB amended existing requirements for measuring fair value and for disclosing information about fair value measurements. This revised guidance results in a consistent definition of fair value, as well as common requirements for measurement and disclosure of fair value information between U.S. GAAP and International Financial Reporting Standards (IFRS). In addition, the amendments set forth enhanced disclosure requirements with respect to recurring Level 3 measurements, nonfinancial assets measured or disclosed at fair value, transfers between levels in the fair value hierarchy, and assets and liabilities disclosed but not recorded at fair value. The amendment is to be applied prospectively and is effective for NVE and the Utilities as of the beginning of a fiscal reporting year that begins after December 15, 2011, for all public entities.  The adoption of this guidance will not have a significant impact on the disclosure requirements for NVE and the Utilities.

  Other Comprehensive Income (ASU 220)

In June 2011, the FASB amended the Comprehensive Income Topic as reflected in the FASB Accounting Standards Codification for presentation of comprehensive income.  The amendment does not change the amount of comprehensive income reported, but rather establishes a standard for the reporting and presentation of comprehensive income providing an entity the option to present the total of comprehensive income, the components of net income, and the components of other comprehensive income (including reclassification adjustments) either in a single continuous statement of comprehensive income or in two separate but consecutive statements.  The amendment is to be applied retrospectively to all reporting periods presented and is effective as of the beginning of a fiscal reporting year that begins after December 15, 2011, for all public entities.  NVE and the Utilities have elected to early adopt this amendment presenting total comprehensive income in a single continuous statement for each of the three years in the period ended December 31, 2011. This amendment changes the presentation of our financial statements but does not affect the calculation of net income, comprehensive income or earnings per share.

In December 2011, the FASB deferred the effective date of a portion of the June 2011 amendment related to the presentation of reclassification adjustments out of accumulated other comprehensive income.  The effective date was deferred to allow the Board time to redeliberate whether to present on the face of the financial statements the effects of reclassifications out of accumulated other comprehensive income for all periods presented.  As of December 31, 2011 NVE and the Utilities have not recorded reclassification adjustments subject to this amendment as such NVE and the Utilities do not expect the deferral to have a material impact on the presentation of our financial statements.

  Balance Sheet Offsetting Disclosures (ASU 210)

In November 2011, the FASB amended the Balance Sheet Topic as reflected in the FASB Accounting Standards Codification to enhance current disclosures regarding offsetting (netting) of assets and liabilities on the face of the financial statements.  The amendment requires an entity to disclose information about offsetting and related arrangements to enable users of the financial statements to understand the effect of those arrangements on its financial position.  The scope of this amendment would include derivatives, sale and repurchase agreements and reverse sale and repurchase agreements, and securities borrowing and securities lending arrangements.  The amendment is to be applied retrospectively to all periods presented and is effective for all reporting periods beginning on or after January 1, 2013.  NVE and the Utilities will evaluate the effects on this amendment but do not expect the amendment to have a material impact on our disclosure requirement.

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NOTE 2.                 SEGMENT INFORMATION

The Utilities operate three regulated business segments, NPC electric, SPPC electric and SPPC natural gas service, which are reported in accordance with Segment Reporting of the FASC.  Electric service is provided to Las Vegas and surrounding Clark County by NPC, and to northern Nevada by SPPC.  Natural gas services are provided by SPPC in the Reno-Sparks area of Nevada.  Other information includes amounts 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 energy and energy efficiency program costs, provides a measure of income available to support the other operating expenses of the Utilities.  EEPR costs are conservation costs being recovered from ratepayers through EEPR revenues which were implemented in July 2011 (see Note 3, Regulatory Actions, of the Notes to Financial Statements).  Costs incurred prior to the implementation of the EEPR are recovered through general rates and amortized to other operating expense.  See Note 3, Regulatory Actions, of the Notes to Financial Statements for conservation program amount details.  The EEPR mechanism is designed such that conservation costs are equal to revenues collected and any over/under collection is deferred as a regulatory asset/liability until rates are reset.  As a result, amounts related to EEPR do not have an effect on gross margin, operating income or net income.

Operating expenses are provided by segment in order to reconcile to operating income as reported in the consolidated financial statements for the years ended December 31 (dollars in thousands):

2011
														SPPC
		NVE		NVE		NPC		SPPC		SPPC		SPPC		Reconciling
		Consolidated		Other		Electric		Total		Electric		Gas		Eliminations(1)
Operating Revenues		$	2,943,307	$	15	$	2,054,393	$	888,899	$	716,417	$	172,482	$
Energy Costs:
	Fuel for power generation		680,585		-		498,487		182,098		182,098		-
	Purchased power		633,874		-		477,226		156,648		156,648		-
	Gas purchased for resale		125,155		-				125,155				125,155
	Deferred energy		(83,333)		-		(16,300)		(67,033)		(65,445)		(1,588)
Energy efficiency program costs			43,537		-		37,292		6,245		6,245
			1,399,818		-		996,705		403,113		279,546		123,567
Gross Margin		$	1,543,489	$	15	$	1,057,688	$	485,786	$	436,871	$	48,915
Other operating expenses			411,115		4,289		260,127		146,699
Maintenance			103,307		-		64,320		38,987
Depreciation and amortization			357,937		-		252,191		105,746
Taxes other than income			60,465		290		37,254		22,921
Operating Income		$	610,665	$	(4,564)	$	443,796	$	171,433
Assets		$	11,635,128	$	8,523	$	8,442,597	$	3,184,008	$	2,818,927	$	302,062	$	63,019
Capital expenditures		$	620,516	$	-	$	475,118	$	145,398	$	132,083	$	13,315

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2010
														SPPC
		NVE		NVE		NPC		SPPC		SPPC		SPPC		Reconciling
		Consolidated		Other		Electric		Total		Electric		Gas		Eliminations(1)
Operating Revenues		$	3,280,222	$	23	$	2,252,377	$	1,027,822	$	836,879	$	190,943	$
Energy Costs:
	Fuel for power generation		821,484		-		588,419		233,065		233,065		-
	Purchased power		648,881		-		505,239		143,642		143,642		-
	Gas purchased for resale		137,702		-				137,702				137,702
	Deferred energy		113,107		-		94,843		18,264		8,475		9,789
			1,721,174		-		1,188,501		532,673		385,182		147,491
Gross Margin		$	1,559,048	$	23	$	1,063,876	$	495,149	$	451,697	$	43,452
Other operating expense			414,241		3,760		260,535		149,946
Maintenance			104,567		-		71,759		32,808
Depreciation and amortization			333,059		-		226,252		106,807
Taxes other than income			62,746		235		37,918		24,593
Operating Income		$	644,435	$	(3,972)	$	467,412	$	180,995
Assets		$	11,669,668	$	20,822	$	8,301,824	$	3,347,022	$	3,022,257	$	291,122	$	33,643
Capital expenditures(2)		$	629,496	$	(13,094)	$	499,374	$	143,216	$	131,579	$	11,637

2009
														SPPC
		NVE		NVE		NPC		SPPC		SPPC		SPPC		Reconciling
		Consolidated		Other		Electric		Total		Electric		Gas		Eliminations(1)
Operating Revenues		$	3,585,798	$	28	$	2,423,377	$	1,162,393	$	957,130	$	205,263	$
Energy Costs:
	Fuel for power generation		881,768		-		587,647		294,121		294,121		-
	Purchased power		758,736		-		627,759		130,977		130,977		-
	Gas purchased for resale		153,607		-				153,607				153,607
	Deferred energy		289,076		-		207,611		81,465		73,829		7,636
			2,083,187		-		1,423,017		660,170		498,927		161,243
Gross Margin		$	1,502,611	$	28	$	1,000,360	$	502,223	$	458,203	$	44,020
Other operating expenses			453,413		2,699		279,865		170,849
Maintenance			102,309		-		71,019		31,290
Depreciation and amortization			321,921		-		215,873		106,048
Taxes other than income			60,885		197		37,241		23,447
Operating Income		$	564,083	$	(2,868)	$	396,362	$	170,589
Assets		$	11,413,463	$	(25,053)	$	8,096,371	$	3,342,145	$	2,997,116	$	305,434	$	39,595
Capital expenditures(2)		$	843,132	$	-	$	656,074	$	187,058	$	171,036	$	16,022

(1) The reconciliation of segment assets at December 31, 2011, 2010 and 2009 to the consolidated total includes the following unallocated amounts:
		2011		2010		2009
	Other investments	$	5,901	$	5,956	$	5,428
	Cash		55,195		9,552		14,359
	Deferred charges-other		1,923		18,135		19,808
		$	63,019	$	33,643	$	39,595
(2) The capital expenditures for NVE Other at December 31, 2010 includes $13.1 million proceeds from the sale of assets between SPPC and Sierra Pacific Communications.

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NOTE 3.                      REGULATORY ACTIONS

The Utilities are subject to the jurisdiction of the PUCN and in the case of SPPC in prior years, 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.  However, on January 1, 2011, SPPC sold its California Assets, as discussed further in Note 16, Assets Held for Sale, and therefore is no longer subject to the jurisdiction of the CPUC. 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, EEIR and EEPR cases by March 1, and triennial GRCs.  In addition, the Utilities may also file quarterly DEAA and BTER updates for the Utilities’ electric and gas departments.  Reference Note 1, Summary of Significant Accounting Policies, for further discussion of the various rate components. 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 amounts were included in the consolidated balance sheets as of December 31 for the years shown below (dollars in thousands):

				2011
			NVE Total		NPC Electric			SPPC Electric		SPPC Gas
Deferred Energy
	Cumulative Balance authorized in 2011 DEAA		$	(334,102)	$	(189,032)	(1)	$	(115,955)	$	(29,115)
	2011 Amortization			247,489		120,340			104,909		22,240
	2011 Deferred Energy Over Collections(2)			(173,466)		(106,022)			(45,291)		(22,153)
Deferred Energy Balance at December 31, 2011 - Subtotal			$	(260,079)	$	(174,714)		$	(56,337)	$	(29,028)
Reinstatement of deferred energy (effective 6/07, 10 years)				117,440		117,440			-		-
		Total Deferred Energy	$	(142,639)	$	(57,274)		$	(56,337)	$	(29,028)
Deferred Assets
	Deferred energy		$	102,525	$	102,525		$	-	$	-
Current Liabilities
	Deferred energy			(245,164)		(159,799)			(56,337)		(29,028)
		Total Deferred Energy	$	(142,639)	$	(57,274)		$	(56,337)	$	(29,028)

(1)	Refer to NPC 2011 DEAA “Settled Regulatory Actions” below for separate discussion regarding rate offset of this balance.
(2)	These deferred energy over collections will be filed in the March 2012 DEAA filings.

				2010
			NVE Total		NPC Electric			SPPC Electric		SPPC Gas
Nevada Deferred Energy
	Cumulative Balance authorized in 2010 DEAA(1)		$	(220,064)	$	(102,398)	(2)	$	(100,625)	$	(17,041)
	2010 Amortization			74,215		22,441			40,682		11,092
	2010 Deferred Energy Over Collections(3)			(184,776)		(106,178)			(55,615)		(22,983)
Nevada Deferred Energy Balance at December 31, 2010 - Subtotal			$	(330,625)	$	(186,135)		$	(115,558)	$	(28,932)
Cumulative CPUC balance(4)				(3,210)		-			(3,210)		-
Reinstatement of deferred energy (effective 6/07, 10 years)				132,409		132,409			-		-
		Total Deferred Energy	$	(201,426)	$	(53,726)		$	(118,768)	$	(28,932)
Deferred Assets
	Deferred energy		$	117,623	$	117,623		$	-	$	-
Current Liabilities
	Deferred energy			(315,839)		(171,349)			(115,558)		(28,932)
	Liabilities held for sale			(3,210)		-			(3,210)		-
		Total Deferred Energy	$	(201,426)	$	(53,726)		$	(118,768)	$	(28,932)

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(1)     These deferred costs include PUCN ordered adjustments.

(2)      Refer to NPC DEAA under "Settled Regulatory Actions" below for separate discussion regarding the NPC rate offset of their 2010 cumulative balance  

          against their deferred rate increase included in other regulatory assets.

(3)     These deferred over collections were requested in March 2011 DEAA filings.

(4)     Refer to Note 16, Assets Held For Sale.

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, pending or potential legislation.  Detailed below are Other Regulatory Assets and Liabilities included in the balance sheet of NVE, NPC and SPPC and their current regulatory treatment as of December 31 (dollars in thousands):

		NVE
		OTHER REGULATORY ASSETS AND LIABILITIES
		As of December 31, 2011
		Remaining	Receiving Regulatory Treatment				Pending					As of
DESCRIPTION		Amortization	Earning a		Not Earning		Regulatory			2011		December 31, 2010
		Period	Return(1)		a Return		Treatment			Total		Total
Regulatory assets
	Loss on reacquired debt	Term of Related Debt	$	72,408	$	-	$	-		$	72,408	$	84,692
	Income taxes	Various		-		251,314		-			251,314		257,078
	Merger costs	Various thru 2046		-		268,668		-			268,668		282,535
	Lenzie Generating Station	2042		-		67,351		-			67,351		77,524
	Mohave Generating Station and deferred costs	2017		9,861		12,654		1,645	(2)		24,160		25,849
	Piñon Pine	Various thru 2029		27,377		7,016		-			34,393		38,960
	Asset retirement obligations	-		-		-		67,891	(2)		67,891		55,182
	Conservation programs	Various thru 2017		151,035		-		7,412	(3)		158,447		177,515
	EEPR	Various thru 2013		30,379		-		-			30,379		30,409
	Ely Energy Center	2017		-		23,403		34,563	(2)		57,966		-
	Legacy Meters	-		-		-		21,777	(2)		21,777		-
	Renewable energy programs	2013		29,592		-		-			29,592		2,627
	Peabody coal costs	-		-		17,899		-			17,899		17,738
	Deferred Rate Increase	2011		12,177		-		-			12,177		91,678
	Risk management	-		-		2,426		-			2,426		30,726
	Other costs	Various thru 2031		24,229		33,852		11,198	(2, 3)		69,279		64,646
	Subtotal	-	$	357,058	$	684,583	$	144,486		$	1,186,127	$	1,237,159
	Pensions	-		-		215,656		-			215,656		269,472
Total regulatory assets			$	357,058	$	900,239	$	144,486		$	1,401,783	$	1,506,631
Regulatory liabilities
	Cost of removal	Various	$	422,033	$	-	$	-		$	422,033	$	382,634
	Income taxes	Various		-		17,433		-			17,433		19,506
	Gain on property sales	2013		4,444		-		32,844	(3)		37,288		7,151
	Renewable energy programs	2012		1,046		-		-			1,046		10,234
	Other	Various thru 2017		6,183		-		2,276			8,459		8,589
Total regulatory liabilities			$	433,706	$	17,433	$	35,120		$	486,259	$	428,114

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		NPC
		OTHER REGULATORY ASSETS AND LIABILITIES
		As of December 31, 2011
		Remaining	Receiving Regulatory Treatment				Pending					As of
DESCRIPTION		Amortization	Earning a		Not Earning		Regulatory			2011		December 31, 2010
		Period	Return(1)		a Return		Treatment			Total		Total
Regulatory assets
	Loss on reacquired debt	Term of Related Debt	$	39,958	$	-	$	-		$	39,958	$	43,765
	Income taxes	Various		-		178,060		-			178,060		174,022
	Merger costs	Various thru 2044		-		168,212		-			168,212		176,974
	Lenzie Generating Station	2042		-		67,351		-			67,351		77,524
	Mohave Generating Station and  deferred costs	Various thru 2017		9,861		12,654		1,645	(2)		24,160		25,849
	Asset retirement obligations	-		-		-		60,797	(2)		60,797		48,970
	Conservation programs	Various thru 2017		129,885		-		4,004	(3)		133,889		144,107
	EEPR	Various thru 2013		25,250		-		-			25,250		24,905
	Ely Energy Center	2017		-		23,403		22,970	(2)		46,373		-
	Legacy Meters	-		-		-		21,777	(2)		21,777		-
	Renewable energy programs	2013		10,694		-		-			10,694		-
	Peabody coal costs	-		-		17,899		-			17,899		17,738
	Risk management	-		-		2,426		-			2,426		20,261
	Deferred Rate Increase	2011		12,177		-		-			12,177		91,678
	Other costs	2017		13,324		21,772		8,870	(2, 3)		43,966		26,189
	Subtotal	-	$	241,149	$	491,777	$	120,063		$	852,989	$	871,982
	Pensions	-		-		108,528		-			108,528		133,410
Total regulatory assets			$	241,149	$	600,305	$	120,063		$	961,517	$	1,005,392
Regulatory liabilities
	Cost of removal	Various	$	232,093	$	-	$	-		$	232,093	$	208,795
	Income taxes	Various		-		5,798		-			5,798		6,557
	Gain on property sales	-		-		-		32,844	(3)		32,844		-
	Renewable energy programs	2013		1,046		-		-			1,046		7,797
	Other	2017		925		-		2,245			3,170		2,834
Total regulatory liabilities			$	234,064	$	5,798	$	35,089		$	274,951	$	225,983

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		SPPC
		OTHER REGULATORY ASSETS AND LIABILITIES
		As of December 31, 2011
		Remaining	Receiving Regulatory Treatment				Pending					As of
DESCRIPTION		Amortization	Earning a		Not Earning		Regulatory			2011		December 31, 2010
		Period	Return(1)		a Return		Treatment			Total		Total
Regulatory assets
	Loss on reacquired debt	Term of Related Debt	$	32,450	$	-	$	-		$	32,450	$	40,927
	Income taxes	Various		-		73,254		-			73,254		83,056
	Merger costs	Various thru 2046		-		100,456		-			100,456		105,561
	Risk management	-		-		-		-			-		10,465
	Piñon Pine	Various thru 2029		27,377		7,016		-			34,393		38,960
	Asset retirement obligations	-		-		-		7,094	(2)		7,094		6,212
	Conservation programs	Various thru 2013		21,150		-		3,408	(3)		24,558		33,408
	EEPR	Various thru 2013		5,129		-		-			5,129		5,504
	Renewable energy programs	2013		18,898		-		-			18,898		2,627
	Ely Energy Center	-		-		-		11,593	(2)		11,593		-
	Other costs	Various thru 2031		10,905		12,080		2,328	(2, 3)		25,313		38,457
	Subtotal	-	$	115,909	$	192,806	$	24,423		$	333,138	$	365,177
	Pensions	-		-		104,159		-			104,159		131,734
Total regulatory assets			$	115,909	$	296,965	$	24,423		$	437,297	$	496,911
Regulatory liabilities
	Cost of removal	Various	$	189,940	$	-	$	-		$	189,940	$	173,839
	Income taxes	Various		-		11,635		-			11,635		12,949
	Gain on property sales	2013		4,444		-		-			4,444		7,151
	Renewable energy programs	-		-		-		-			-		2,437
	Other costs	Various thru 2043		5,258		-		31	(3)		5,289		5,755
Total regulatory liabilities			$	199,642	$	11,635	$	31		$	211,308	$	202,131

(1) Earning a return includes either a carrying charge on the asset/liability balance, or a return as a component of rate base.

(2) Pending regulatory treatment includes either amounts which have prior regulatory precedent or have been approved and are subject to prudency review.

(3) Assets which are allowed to earn a carrying charge until included in rates.  Reference Note 1, Summary of Significant Accounting Policies, Equity Carrying Charges.

Regulatory Actions

   Nevada Power Company and Sierra Pacific Power Company

Quarterly DEAA Applications

In 2011, the Legislature passed Assembly Bill 215 which allows an electric or gas utility that adjusts its BTER on a quarterly basis to request PUCN approval to make quarterly changes to its DEAA rate if the request is in the public interest.  The Utilities will still be required to file an annual DEAA case to review costs for prudency and reasonableness, and if any costs are disallowed on such grounds, the disallowance will be incorporated into the next subsequent quarterly rate change.  SPPC filed an application to change its quarterly DEAA rates for both electric and gas in July 2011, and in October 2011, the PUCN accepted a stipulation authorizing the first quarterly adjustments to the electric and gas DEAAs to become effective on January 1, 2012.  NPC filed an application to change its quarterly DEAA in October 2011, and in December 2011, the PUCN accepted a stipulation authorizing the first quarterly adjustment to the DEAA to become effective on April 1, 2012.

Energy Efficiency Implementation Rate (EEIR) and Energy Efficiency Program Rate (EEPR)

EEIR

In 2009, the Nevada Legislature passed Senate Bill 358, which required the PUCN to adopt regulations authorizing an electric utility to recover lost revenue that is attributable to the measurable and verifiable effects associated with the implementation of efficiency and conservation programs approved by the PUCN.  As a result, the PUCN opened Docket No. 09-07016 to amend and adopt the regulation.  The regulation was adopted by the Legislature on July 22, 2010.  Accordingly, as of August 1, 2010, the Utilities began recording the amount of additional revenues which are objectively determinable and probable of recovery and are attributable to reduced kWh sales related to energy efficiency programs, prior to their inclusion in rates in accordance with FASC 980-605-25, Alternative Revenue Programs.

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In October 2010, the Utilities filed to set 2011 base rates effective mid 2011 to recover approximately $35.1 million and $7.6 million for NPC and SPPC, respectively, for estimated reduced kWh sales related to the Utilities’ energy efficiency programs.  Annually, thereafter, the Utilities will make a filing in March, to adjust rates and set a clearing rate or EEIR for over or under collected balances, effective in October of the same year.  In May 2011, the PUCN issued a final order on the October 2010 filing authorizing increases to the base rates of $14.5 million and $2.6 million for NPC and SPPC, respectively, effective July 1, 2011.  As a result of the May order, in June 2011, NPC and SPPC recorded a pre-tax adjustment to earnings for revenue previously recorded of approximately $4.5 million and $4.1 million, respectively.  As of December 31, 2011, NPC and SPPC have recognized 2011 revenues of approximately $15.5 million and $2.5 million, respectively, of the authorized EEIR base amounts.

In March 2011, the Utilities filed applications with their annual DEAA filings to reset the base rates and clear the accumulated in regulatory asset accounts between August 1, 2010 and December 31, 2010, with rates effective October 2011.  Reference further discussion below at NPC and SPPC DEAA, TRED, REPR, EEIR, EEPR Rate Filing.

EEPR

In addition, the regulation approved the transition of the recovery of energy efficiency program costs from general rates (filed every 3 years) to recovery through independent annual rate filings.  Accordingly, in their filing made in October 2010, the Utilities requested to set base rates beginning mid 2011 to recover the 2011 costs of implementing energy efficiency program costs of approximately $71.0 million and $12.1 million for NPC and SPPC, respectively.  In May 2011, the PUCN issued a final order authorizing increases to the base rates of $58.4 million and $9.7 million for NPC and SPPC, respectively, effective July 1, 2011.  As of December 31, 2011, NPC and SPPC have recorded $37.3 million and $6.2million respectively, of EEPR revenues.  Costs accumulated between August 1, 2010 and December 31, 2010 were requested for recovery in the March 2011 filing with rates effective October 2011.  Reference further discussion below at NPC and SPPC DEAA, TRED, REPR, EEIR, EEPR Rate Filing.

       Ely Energy Center

            In February 2011, NVE and the Utilities cancelled plans to construct the EEC due to increasing environmental and economic uncertainties.  In June 2009, the Utilities filed to withdraw the initial construction application under the Utility Environmental Protection Act (UEPA) filed in 2006 due to postponing the construction of the EEC.  The PUCN had previously approved the Utilities spending on development costs and farming assets for the EEC up to $130 million, of which the Utilities have spent and recorded as an other deferred asset approximately $58.0 million as of December 31, 2011.  In compliance with the SPPC 2010 Electric GRC, SPPC filed a separate application concurrent with the filing of NPC’s GRC filed in June 2011, to determine the reasonableness of the EEC project development costs and farming assets and proposed reclassification of these costs from a deferred debit to a regulatory asset.  In December 2011, the PUCN authorized recovery of approximately $23.2 million of the development costs for NPC and reclassification of $23.1 million of farming assets to a regulatory asset for NPC.  The PUCN also authorized SPPC to reclassify approximately $11.6 million of  development costs and farming assets to regulatory asset accounts.  In accordance with NPC’s December 2011 GRC order, farming assets on NPC and SPPC are subject to prudence review in a subsequent filing to the PUCN.

   Nevada Power Company

NPC 2011 GRC

In June 2011, NPC filed its statutorily required triennial GRC and updated the filing in August 2011.  The filing, as updated requested an ROE of 11.25% and ROR of 8.64% and an increase to general revenues of $249.9 million.  The PUCN issued its order in December 2011, which resulted in the following significant items:

•    Increase in general rates of $158.6 million, approximately an 8.3% overall increase effective January 1, 2012;

•    ROE and ROR of 10.0% and 8.09%, respectively;

•    Recovery of approximately $635.9 million, excluding AFUDC, for the 500 MW (nominally rated) expansion at the Harry Allen Generating Station;

•    Recovery of approximately $23.2 million for EEC project development costs;

•    Recovery of approximately $17.7 million for demand side management costs;

•    Recovery of approximately $12.7 million for Mohave Generating Station closure costs;

•    Postpone final regulatory treatment of EWAM Phase 1 of approximately $46.9 million pending project completion and prudency review of NPC’s subsequent GRC filing; and

•    Various other rate case adjustments for the Harry Allen Generating Station, Clark Peaking Units, and the EEC, offset by regulatory asset treatment for operating expenses for a net decrease to NVE’s fourth quarter 2011 consolidated net income of approximately $15.9 million before tax.

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           NPC 2011 DEAA, TRED, REPR, EEIR, EEPR Rate Filings

In March 2011, NPC filed an application to establish a new DEAA to refund over-collected purchased power and fuel costs and reset or establish several other rate elements (TRED, REPR, EEIR and EEPR).  In September 2011, the PUCN accepted stipulations which resulted in an overall decrease in revenue requirement of approximately $78.6 million.  The PUCN authorized the refund and recovery of the following amounts (dollars in millions):

			Effective Date	Authorized Revenue Requirement			Present Revenue Requirement		$ Change in Revenue Requirement
Revenue Requirement Subject To Change:
	DEAA		Oct. 2011	$	(188.9)		$	(101.0)	$	(87.9)
	REPR		Oct. 2011		8.6			29.8		(21.2)
	TRED		Oct. 2011		18.1			16.3		1.8
	EEPR Base		Oct. 2011		58.4			58.4		-
	EEPR Amortization		Oct. 2011		21.3			-		21.3
	EEIR Base		Oct. 2011		17.1			14.5		2.6
	EEIR Amortization		Oct. 2011		4.8	(1)		-		4.8
		Total Revenue Requirement		$	(60.6)		$	18.0	$	(78.6)

(1) In accordance with Alternative Revenue Accounting, NPC recognized approximately $4.8 million in revenues pertaining to 2010.  Based on the order from the PUCN in May 2011, which clarified the calculation of EEIR revenues, NPC does not expect to record further revenue from this rate request; however, NPC does expect to collect approximately $4.8 million from its customers.

NPC 2010 DEAA

In March 2010, NPC filed an application to create a new DEAA rate.  In its application, NPC requested to refund $102 million of deferred fuel and purchased power costs.  Separately, NPC filed a petition to offset the NPC DEAA over collection (credit balance) of $102 million against the deferred BTGR debit balance of $95.8 million.  The BTGR debit balance of $95.8 million was a result of NPC’s 2008 GRC, which granted NPC approval to defer billings of its rate increase from July 1, 2009 to December 31, 2009 in a regulatory asset for which NPC recognized revenues in 2009.  The PUCN consolidated both dockets for hearing purposes.

In September 2010, the PUCN accepted a stipulation for the DEAA and BTGR offset applications, which resulted in an overall revenue decrease of $9.2 million or 0.41% for the period October 1, 2010 through December 31, 2011.

NPC 2009 DEAA

In February 2009, NPC filed an application to create a new DEAA rate.  In this application, NPC requested to increase rates by $72.1 million, an increase of 3.18%, while recovering $77.5 million of deferred fuel and purchased power costs.  In September 2009, the PUCN ordered that the DEAA rate remain set at $0.00 per kWh, in addition, the PUCN also ordered a slight increase to the TRED charge and a slight decrease to the REPR which resulted in a net decrease to revenues of $4.6 million, or a 0.20% decrease.  The PUCN found that NPC’s purchases of fuel and power were prudent and approved those costs for the test period which were included as an offset to 2009 deferred energy over-collections within the 2010 DEAA filing.

NPC 2008 GRC

In December 2008, NPC filed its statutorily required GRC with the PUCN and further updated the filing in February and March 2009.  The filing, as updated, requested an ROE of 11.0% and ROR of 8.88% and an increase to general revenues of $305.7 million.

The PUCN issued its order in June 2009, which resulted in the following significant items:

•    Increase in general rates by $222.7 million, approximately a 9.8% increase;

•    ROE and ROR of 10.5% and 8.53%, respectively;

•    Authorized to recover the costs of major plant additions including the purchase of the Higgins Generating Station, construction of Clark Peaking Units, 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;

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•    CWIP as of November 2008 in rate base for the construction of a 500 MW (nominally rated) combined cycle unit at the existing Harry Allen Generating Station site; and

•    A two part implementation of the rate increase to be billed to customers.  The part I rate increase was effective July 1, 2009 and resulted in a 3% increase to all core customer classes.  The part II rate increase was effective January 1, 2010 and implemented the remainder of the increase to all core customer classes.  The PUCN granted approval for NPC to track and record the difference between the 9.8% general rate increase and billings associated with the part I rate increase each month in a regulatory asset account and permitted NPC to record a carrying charge on these amounts.  Reference discussion above in NPC’s 2010 DEAA for balance offset.  This regulatory asset was used to offset the NPC 2010 DEAA over collection, as discussed above.

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.

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 resolutions 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 discussing the negotiation of new agreements that would address the potential disposition of the assets and rights, title, interest and obligations in the Mohave Generating Station.

Included in other regulatory assets is approximately $12.2 million, which has been approved by the PUCN and included in rates.  All other costs for Mohave Generating Station, including approximately $12.7 million of decommissioning costs were accumulated in other regulatory assets as incurred and were requested for recovery in NPC’s 2011 GRC and were approved by the PUCN, see the Other Regulatory Assets/Liabilities table above.

In June 2009, Southern California Edison announced that the Mohave Generating Station will be dismantled and its operating permits terminated following a December 2005 suspension of operations due to pending environmental matters.  NPC believes it will continue to recover the costs for the Mohave Generating Station through the regulatory process and does not expect the dismantling of the plant to have a material impact on its financial condition.

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Sierra Pacific Power Company

 SPPC 2011 Electric DEAA, TRED, REPR, EEIR, EEPR Rate Filings

In March 2011, SPPC filed an application to establish a new DEAA to refund over-collected purchased power and fuel costs and reset or establish several other rate elements (TRED, REPR, EEIR and EEPR).  In September 2011, the PUCN accepted stipulations which resulted in an overall decrease in revenue requirement of approximately $8.2 million.  The PUCN authorized refund and recovery of the following amounts (dollars in millions):

				Authorized			Present		$ Change in
			Effective	Revenue			Revenue		Revenue
			Date	Requirement			Requirement		Requirement
Revenue Requirement Subject To Change:
	DEAA		Oct. 2011	$	(115.9)		$	(99.5)	$	(16.4)
	REPR		Oct. 2011		38.0			36.6		1.4
	TRED		Oct. 2011		9.1			7.9		1.2
	EEPR Base		Oct. 2011		9.7			9.7		-
	EEPR Amortization		Oct. 2011		4.6			-		4.6
	EEIR Base		Oct. 2011		3.1			2.6		0.5
	EEIR Amortization		Oct. 2011		0.5	(1)		-		0.5
		Total Revenue Requirement		$	(50.9)		$	(42.7)	$	(8.2)

(1) In accordance with Alternative Revenue Accounting, SPPC recognized approximately $0.5 million in revenues pertaining to 2010.  Based on the order from the PUCN in May 2011, which clarified the calculation of EEIR revenues, SPPC does not expect to record further revenue from this rate request; however, SPPC does expect to collect approximately $0.5 million from their customers.

         SPPC 2011 Nevada Gas DEAA

In March 2011, SPPC filed an application to create a new DEAA rate to refund over-collected gas costs and to establish a new STPR (Solar Thermal Prospective Rate) to recover a legislatively mandated solar thermal program.  In September 2011, the PUCN accepted stipulations which resulted in an overall decrease in revenue requirement of $12.1 million.  The PUCN authorized the refund and recovery of the following amounts (dollars in millions):

				Authorized		Present		$ Change in
			Effective	Revenue		Revenue		Revenue
			Date	Requirement		Requirement		Requirement
Revenue Requirement Subject To Change:
	DEAA		Oct. 2011	$	(29.1)	$	(16.7)	$	(12.4)
	STPR		Oct. 2011		0.3		-		0.3
		Total Revenue Requirement		$	(28.8)	$	(16.7)	$	(12.1)

SPPC 2010 Nevada Gas DEAA

In March 2010, SPPC filed an application to create a new DEAA rate.   In September, the PUCN accepted a stipulation to decrease rates by $8.3 million, a decrease of 4.69%, while refunding approximately $17 million of deferred gas costs.  The new DEAA rate became effective October 1, 2010.

SPPC 2010 Nevada Electric DEAA

In March 2010, SPPC filed an application to create a new DEAA rate.   In September, the PUCN accepted a stipulation to decrease rates by $47.0 million, a decrease of 6.31%, while refunding $101 million of deferred fuel and purchased power costs. The new DEAA rate became effective October 1, 2010.

SPPC 2010 Electric GRC

In June 2010, SPPC filed its statutorily required GRC for its Nevada electric operations and further updated the filing in July and August 2010.  The filing, as updated, requested an ROE of 10.75% and ROR of 8.14% and an increase to general revenues of $29.3 million.

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The PUCN issued its order in December 2010, which resulted in the following significant items:

● Increase in general rates by $13.1 million, approximately a 1.90% increase effective January 1, 2011;

● ROE and ROR of 10.10% and 7.86%, respectively;

● Authorized to recover new electric and common plant additions along with ordinary changes in operating expense, maintenance expense and administrative and general costs;

● Ordered to file a separate application concurrent with the filing of NPC’s GRC to determine the reasonableness of the EEC project development costs and propose reclassification of these costs from a deferred debit to a regulatory asset.  Reference NPC’s 2011 GRC above for further discussion.

      SPPC 2010 Gas GRC

In June 2010, SPPC filed a GRC for its gas operations and further updated the filing in July and August 2010.  The filing, as updated, requested an ROE of 10.75% and ROR of 5.48% and an increase to general revenues of $4.3 million.

The PUCN issued its order in December 2010, which resulted in the following significant items:

● Increase in general rates by $2.7 million, approximately a 1.93% increase effective January 1, 2011;

● ROE and ROR of 10.00% and 5.15%, respectively;

● Authorized to recover new gas and common plant additions along with ordinary changes in operating expense, maintenance expense and administrative and general costs.

SPPC California GRC

In July 2008, SPPC filed a GRC with the CPUC and subsequently filed an amendment to the original filing in December 2008.  SPPC requested an ROE of 11.4% and ROR of 8.81% and an increase in general revenues of $8.9 million.  In July 2009, a settlement was filed with the CPUC, which includes the following:

● Increase in general rates of $5.5 million, approximately an 8% increase;

● ROE and ROR of 10.7% and 8.51%, respectively;

● Approval of authorization to recover the costs of major plant additions, which include the Tracy Generating Station, and distribution plant additions, as well as a decrease to the California Energy Efficiency Program; and

● Approval of a two-part mechanism to recover changes in non-energy cost adjustment clause costs incurred during the two years between rate cases.

The CPUC approved the settlement and rates were effective December 1, 2009.  However, on January 1, 2011, SPPC sold its California Assets, as discussed further in Note 16, Assets Held for Sale.

SPPC 2009 Nevada Electric DEAA

In February 2009, SPPC filed an application to create a new electric DEAA rate for Nevada customers.  In this application, SPPC requested to decrease rates by $25.9 million, a decrease of 2.69%, while refunding $19.8 million of deferred fuel and purchased power costs.  The PUCN issued its order in September 2009 decreasing rates by $30.8 million, a decrease of 3.19% and approving SPPC’s purchases of fuel and power as prudent for the test period.  The new credit DEAA rate became effective October 1, 2009.

SPPC 2009 Nevada Gas DEAA

In February 2009, SPPC filed an application to create a new gas DEAA rate for Nevada customers.  In this application, SPPC requested to decrease rates by $8.7 million, a decrease of 4.71%, while refunding $8.7 million of deferred gas costs.  The PUCN issued its order in September 2009 approving SPPC’s requested rate decrease and approving SPPC’s purchases of natural gas and propane as prudent for the test period.  The new DEAA rate became effective October 1, 2009.

FERC Matters

   California Wholesale Spot Market Refunds

NPC and SPPC were 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

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spot market sales that were eligible for mitigation.  NPC and SPPC have negotiated a comprehensive settlement with the California parties and a FERC order on the joint offer of settlement was approved in February 2012.

             Nevada Power Company

At the time of the settlement the CAISO and CALPX owed NPC approximately $19 million (plus interest) for power delivered during the same timeframe, but which was being held pending resolution of the FERC proceedings, and for which NPC had fully reserved in 2001.  As a part of the settlement, NPC released these receivables to the California parties which resulted in reversal of the accounts receivable reserve as of December 31, 2011.

            Sierra Pacific Power Company

At the time of the settlement the CAISO and CALPX owed SPPC approximately $1 million (plus interest) for power delivered during the same timeframe, but which was being held pending resolution of the FERC proceedings, and SPPC had recorded a reserve against the receivable in 2001.  As a part of the settlement, SPPC released these receivables to the California parties which resulted in reversal of the accounts receivable reserve as of December 31, 2011.

In 2009, SPPC recorded an additional $3 million liability for this item.

           Settlement

As a result of the February 2012 FERC order, NPC and SPPC have collectively agreed to release to the California parties, NPC and SPPC’s claims to the receivables held by the CALPX and CAISO, plus interest therein, and to pay an immaterial amount in cash.

NOTE 4.                      INVESTMENTS IN SUBSIDIARIES AND OTHER PROPERTY

Investments in subsidiaries and other property consisted of the following as of December 31 (dollars in thousands):

		2011		2010
NVE
	Investments held in Rabbi Trust(1)	$	29,182	$	29,348
	Cash Value-Life Insurance		2,735		2,646
	Non-utility property of NEICO		5,517		5,659
	Property not designated for Utility use		19,235		23,608
	Other non-utility property		352		352
		$	57,021	$	61,613

		2011		2010
NPC
	Investments held in Rabbi Trust(1)	$	23,675	$	23,810
	Cash Value-Life Insurance		2,735		2,646
	Non-utility property of NEICO		5,517		5,659
	Property not designated for Utility use		18,841		23,190
		$	50,768	$	55,305

		2011		2010
SPPC
	Investments held in Rabbi Trust(1)	$	5,507	$	5,538
	Property not designated for Utility use		394		418
		$	5,901	$	5,956

(1) Rabbi Trust assets represent non-qualified deferred compensation and certain defined benefit plans, which consist of actively traded money market and equity funds with quoted prices in active markets which are considered level 1 in the fair value hierarchy. The balance also includes life insurance policies, which are recorded at its cash surrender value of $13.5 million on the consolidated balance sheet, which are considered level 2 in the fair value hierarchy.

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NOTE 5.                       JOINTLY OWNED FACILITIES

At December 31, 2011 and 2010, NPC and SPPC owned the following undivided interests in jointly owned electric utility facilities (dollars in thousands):

		2011
			Plant in		Accumulated		Net Plant in
		% Owned	Service		Depreciation		Service		CWIP
NPC
	Navajo Generating Station	11.3%	$	270,448	$	148,582	$	121,866	$	1,117
	Reid Gardner Generating Station  No. 4	32.2%		171,485		97,042		74,443		7,600
	Silverhawk Generating Station	75.0%		247,342		50,822		196,520		203
			$	689,275	$	296,446	$	392,829	$	8,920
SPPC
	Valmy Generating Station	50.0%	$	331,753	$	215,642	$	116,111	$	6,682

		2010
			Plant in		Accumulated		Net Plant in
		% Owned	Service		Depreciation		Service		CWIP
NPC
	Navajo Generating Station	11.3%	$	249,646	$	141,326	$	108,320	$	1
	Reid Gardner Generating Station  No. 4	32.2%		165,795		98,047		67,748		21,016
	Silverhawk Generating Station	75.0%		250,790		47,194		203,596		183
			$	666,231	$	286,567	$	379,664	$	21,200
SPPC
	Valmy Generating Station	50.0%	$	313,378	$	210,165	$	103,213	$	5,605

The amounts for Navajo Generating Station 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 income.

Reid Gardner Generating Station Unit No. 4 is owned by the CDWR (67.8%) and NPC (32.2%).  NPC is the operating agent.  Contractually, NPC is entitled to receive 25 MW of base load capacity and 232 MW of peaking capacity, subject to certain operating limitations.  The contract expires in 2013.  NPC's share of the operating expenses for this facility is included in the corresponding operating expenses in its consolidated income statements.

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 income statements.

SPPC and Idaho Power Company each own a 50% undivided interest in the Valmy Generating Station, with each company being responsible for financing its share of capital and operating costs.  SPPC is the operator of the plant for both parties.  SPPC’s share of direct operation and maintenance expenses for Valmy Generating Station are included in its accompanying consolidated income statements.

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NOTE 6.                      LONG-TERM DEBT

NVE’s, NPC’s and SPPC’s long-term debt consists of the following as of December 31 (dollars in thousands):

			2011								2010
					NVE								NVE
Long-Term Debt:			Consolidated		Holding Co.		NPC		SPPC		Consolidated		Holding Co.		NPC		SPPC
Secured Debt
	General and Refunding Mortgage
	Securities
		8.25%   NPC Series A due 2011	$	-	$	-	$	-	$	-	$	350,000	$	-	$	350,000	$	-
		6.50%   NPC Series I due 2012		130,000		-		130,000		-		130,000		-		130,000		-
		5.875% NPC Series L due 2015		250,000		-		250,000		-		250,000		-		250,000		-
		5.95%   NPC Series M due 2016		210,000		-		210,000		-		210,000		-		210,000		-
		6.65%   NPC Series N due 2036		370,000		-		370,000		-		370,000		-		370,000		-
		6.50%   NPC Series O due 2018		325,000		-		325,000		-		325,000		-		325,000		-
		6.75%   NPC Series R due 2037		350,000		-		350,000		-		350,000		-		350,000		-
		6.50%   NPC Series S due 2018		500,000		-		500,000		-		500,000		-		500,000		-
		7.375% NPC Series U due 2014		125,000		-		125,000		-		125,000		-		125,000		-
		7.125% NPC Series V due 2019		500,000		-		500,000		-		500,000		-		500,000		-
		5.375% NPC Series X due 2040		250,000		-		250,000		-		250,000		-		250,000		-
		5.45% NPC Series Y due 2041		250,000		-		250,000		-		-		-		-		-
		6.00% SPPC Series M due 2016		450,000		-		-		450,000		450,000		-		-		450,000
		6.75% SPPC Series P due 2037		251,742		-		-		251,742		251,742		-		-		251,742
		5.45% SPPC Series Q due 2013		250,000		-		-		250,000		250,000		-		-		250,000
	Variable Rate Debt (Secured by
		General and Refunding Mortgage
		Securities)
		NPC IDRB Series 2000A due 2020		98,100		-		98,100		-		98,100		-		98,100		-
		NPC PCRB Series 2006 due 2036		37,700		-		37,700		-		37,700		-		37,700		-
		NPC PCRB Series 2006A due 2032		37,975		-		37,975		-		37,975		-		37,975		-
		SPPC PCRB Series 2006A due 2031		58,200		-		-		58,200		58,200		-		-		58,200
		SPPC PCRB Series 2006B due 2036		75,000		-		-		75,000		75,000		-		-		75,000
		SPPC PCRB Series 2006C due 2036		81,475		-		-		81,475		81,475		-		-		81,475
		Revolving Credit Facilities		-		-		-		-		15,000		-		-		15,000
Senior Notes
		6.75% NVE Senior Notes due 2017		-		-		-		-		191,500		191,500		-		-
		6.25% NVE Senior Notes due 2020		315,000		315,000		-		-		315,000		315,000		-		-
		2.81% NVE Term Loan due 2014		195,000		195,000		-		-		-		-		-		-
Obligations under capital leases				51,270		-		51,270		-		55,735		-		55,735		-
Unamortized bond premium
and discount, net				(12,546)		-		(25,455)		12,909		2,611		1		(11,748)		14,358
Current maturities				(139,985)		-		(139,985)		-		(355,929)		-		(355,929)		-
Total Long-Term Debt			$	5,008,931	$	510,000	$	3,319,605	$	1,179,326	$	4,924,109	$	506,501	$	3,221,833	$	1,195,775

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Maturities of Long-Term Debt

As of December 31, 2011, 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):

	NVE		NVE
	Consolidated		Holding Co.		NPC		SPPC
2012(1)	$	134,822	$	-	$	134,822	$	-
2013		255,405		-		5,405		250,000
2014		323,513		195,000		128,513		-
2015		251,039		-		251,039		-
2016		211,245		-		211,245		-
		1,176,024		195,000		731,024		250,000
Thereafter		3,985,438		315,000		2,754,021		916,417
		5,161,462		510,000		3,485,045		1,166,417
Unamortized Premium (Discount) Amount		(12,546)		-		(25,455)		12,909
Total Debt	$	5,148,916	$	510,000	$	3,459,590	$	1,179,326

(1) Amounts may differ from current portion of long-term debt as reported on the consolidated balance sheet due to the timing difference of payments and the change in obligation.

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.

   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.  In February 2010, NPC amended this capital lease agreement to include the lease of the adjoining parking lot and to exercise, three of the five-year renewal options beginning in year 2015. There remain two additional renewal options which could extend the lease an additional ten years.

• In 2007, NPC entered into a 20-year lease, with three 10-year renewal options, to occupy land and building for its Beltway Complex, and operations center in southern Nevada.  As required by the Lease Topic of the FASC, 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 transferred operations to the facilities in June 2009.  

• The Utilities have Master leasing agreements of which various pieces of equipment qualify as capital leases.  The remaining equipment is treated as operating leases.  Lease terms average seven years under the master lease agreement.

Future cash payments for these capital leases, combined, as of December 31, 2011, were as follows (dollars in thousands):

2012		$	9,828
2013			9,845
2014			7,435
2015			4,831
2016			4,918
Thereafter			61,112
	Total minimum lease payments	$	97,969
	Less amounts representing interest	$	(46,699)
Present value of net minimum lease payments		$	51,270

   Financing Transactions

      NVE

         $195 Million Term Loan Agreement

In October 2011, NVE entered into a $195 million 3-year term loan agreement (Term Loan).  The Term Loan is an unsecured, single-draw loan that is due on October 7, 2014.  The borrowing under the Term Loan bears interest at the LIBOR rate plus a margin. The current LIBOR margin rate is 2.00%.   The margin varies based upon NVE’s long–term unsecured debt credit rating by

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S&P and Moody’s.  However, NVE entered into a floating- for- fixed interest rate swap agreement to lock in an effective interest rate of 2.81% for the length of the Term Loan.

The Term Loan contains conditions of borrowing, events of default, and affirmative and negative covenants.  The Term Loan includes (i) a financial covenant to maintain a ratio of total consolidated indebtedness to total consolidated capitalization, determined on the last day of each fiscal quarter, not to exceed 0.70 to 1.00 and (ii) a fixed charge covenant that requires NVE not to permit the fixed charge coverage ratio, determined on the last day of each fiscal quarter, to be less than 1.50 to 1.00.

         Redemption of 6.75% Senior Notes

In November 2011, NVE used the proceeds of the Term Loan, plus cash on hand, to redeem its unsecured $191.5 million 6.75% Senior Notes (“Senior Notes”).  The notes were redeemed at 102.25% of the stated principal amount plus accrued interest to the date of redemption.   With this redemption, NVE and the Utilities are no longer subject to the restrictive covenants contained in the Senior Notes, which were more restrictive then the covenants described above for the Term Loan.

         6.25% Senior Notes

In November 2010, NVE issued and sold $315 million of its 6.25% Senior Notes, due 2020.  Of the approximately $311 million in net proceeds, $307 million was used in December 2010 to redeem the approximately $230 million in the aggregate principal amount of 8.625% Senior Notes due 2014, and the approximately $63.7 million in the aggregate principal amount of 7.803% Senior Notes due 2012.  The 8.625% Notes were redeemed at a purchase price of $1,028.75 for each $1,000 principal amount of the Notes, plus accrued interest.  The 7.803% Notes were redeemed at a purchase price of $1,019.51 for each $1,000 principal amount of the Notes, plus accrued interest. The remaining net proceeds were used for general corporate purposes.

      NPC

         5.45% General and Refunding Mortgage Notes, Series Y

In May 2011, NPC issued and sold $250 million of its 5.45% General and Refunding Mortgage Notes, Series Y, due May 15, 2041.  The approximately $248 million in net proceeds, plus a portion of the proceeds from a draw on NPC’s revolving credit facility, were utilized to pay at maturity NPC’s $350 million aggregate principal amount of 8.25%  General and Refunding Mortgage Notes, Series A, which matured on June 1, 2011.   In conjunction with this debt issuance, NPC entered into an interest rate swap hedging agreement with a notional principal amount of $250 million and a mandatory termination date of June 1, 2011.  The interest rate swap agreement was entered into to effectively lock the interest rate of the U.S. Treasury component of the prospective General and Refunding Note issuance.  The swap transaction was settled on May 9, 2011, when NPC launched and priced the Series Y Notes, resulting in a settlement payment amount of $14.9 million, which was recorded as a cost to issue in a deferred debit and will be amortized over the 30 year life of the Series Y Notes in accordance with past accounting precedent for our regulated Utilities.

         General and Refunding Mortgage Notes, Series X

           In September 2010, NPC issued and sold $250 million of its 5.375% General and Refunding Mortgage Notes, Series X, due 2040.  Of the approximately $247 million in net proceeds, $231 million was used in October 2010 to redeem  (i) approximately $206 million in the aggregate principal amount of fixed rate unsecured tax-exempt local furnishing (“two-county”) bonds issued for NPC’s benefit and  (ii) approximately $20 million unsecured tax-exempt pollution control refunding revenue bonds issued for NPC’s benefit.  The remaining net proceeds of approximately $16 million were used to repay amounts outstanding under NPC’s revolving credit facility.

         $600 Million Revolving Credit Facility

In April 2010, NPC terminated its $589 million secured revolving credit facility which would have expired in November 2010 and replaced it with a $600 million secured revolving credit facility, maturing in April 2013.  The fees on the $600 million revolving credit facility for the unused portion and on the amounts borrowed have increased from the prior facility reflecting current market conditions.  The Administrative Agent for the facility remains Wells Fargo Bank, N.A.  The rate for outstanding loans under the revolving credit facility will be at either an applicable base rate (defined as the highest of the Prime Rate, the Federal Funds Rate plus ½ of 1.0% and the LIBOR Base Rate plus 1.0%) plus a margin, or a LIBOR rate plus a margin.  The margin varies based upon NPC’s credit rating by S&P and Moody’s.  Currently, NPC’s applicable base rate margin is 1.25% and the LIBOR rate margin is 2.25%.  The rate for outstanding letters of credit will be at the LIBOR rate margin plus a fee for the issuing bank.

The $600 million revolving credit facility contains a provision which reduces the availability under the credit facility by the negative mark-to-market exposure for hedging transactions with credit facility lenders or their energy trading affiliates.  The reduction in availability limits the amount that NPC can borrow or use for letters of credit and would require that NPC prepay any amount in

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excess of that limitation.  The amount of the reduction is calculated by NPC on a monthly basis, and after calculating such reduction, the NPC Credit Agreement provides that the reduction in availability under the revolving credit facility to NPC shall in no event exceed 50% of the total commitments then in effect under the revolving credit facility.  As a result of the suspension of the Utilities’ hedging program, there was no negative mark-to-market exposure for NPC as of November 30, 2011 that would impact borrowings during the month of December 2011.

The NPC Credit Agreement contains one financial maintenance covenant that 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.  In the event that NPC did not meet the financial maintenance covenant or there is a different event of default, the NPC Credit Agreement would restrict dividends to NVE.  Moreover, so long as NPC’s senior secured debt remains rated investment grade by S&P and Moody’s (in each case, with a stable or better outlook), a representation concerning no material adverse change in NPC’s business, assets, property or financial condition would not be a condition to the availability of credit under the facility.  In the event that NPC’s senior secured debt rating were rated below investment grade by either S&P or Moody’s, or investment grade by either S&P or Moody’s but with a negative outlook, a representation concerning no material adverse change in NPC’s business, assets, property or financial condition would be a condition to borrowing under the revolving credit facility.

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.

      SPPC

          Redemption of General and Refunding Mortgage Notes, Series H

In November 2010, SPPC provided a notice of redemption to the holders of its 6.25% General and Refunding Mortgage Notes, Series H, due 2012, in an aggregate principal amount of $100 million.   The notes were redeemed in December 2010 at a purchase price of $1,069.61 for each $1,000 principal amount of the Notes, plus accrued interest.  The redemption was funded predominantly with available cash on hand, with the balance being funded with a draw on its bank revolving credit facility.

         $250 Million Revolving Credit Facility

In April 2010, SPPC terminated its $332 million secured revolving credit facility which would have expired in November 2010 and replaced it with a $250 million secured revolving credit facility, maturing in April 2013.  The fees on the $250 million revolving credit facility for the unused portion and on the amounts borrowed have increased from the prior facility reflecting current market conditions.  The Administrative Agent for the facility is Bank of America, N.A.  The rate for outstanding loans under the revolving credit facility will be at either an applicable base rate (defined as the highest of the Prime Rate, the Federal Funds Rate plus ½ of 1.0% and the LIBOR Base Rate plus 1.0%) plus a margin, or a LIBOR rate plus a margin.  The margin varies based upon SPPC’s credit rating by S&P and Moody’s.  Currently, SPPC’s applicable base rate margin is 1.25% and the LIBOR rate margin is 2.25%.  The rate for outstanding letters of credit will be at the LIBOR rate margin plus a fee for the issuing bank.

The $250 million revolving credit facility contains a provision which reduces the availability under the credit facility by the negative mark-to-market exposure for hedging transactions with credit facility lenders or their energy trading affiliates.  The reduction in availability limits the amount that SPPC can borrow or use for letters of credit and would require that SPPC prepay any amount in excess of that limitation.  The amount of the reduction is calculated by SPPC on a monthly basis, and after calculating such reduction, the SPPC Credit Agreement provides that the reduction in availability under the revolving credit facility to SPPC shall in no event exceed 50% of the total commitments then in effect under the revolving credit facility.  As a result of the suspension of the Utilities’ hedging program, there was no negative mark-to-market exposure for SPPC as of November 30, 2011 that would impact borrowings during the month of December 2011.

The SPPC Credit Agreement contains one financial maintenance covenant that 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.  In the event that SPPC did not meet the financial maintenance covenant or there is a different event of default, the SPPC Credit Agreement would restrict dividends to NVE.  Moreover, so long as SPPC’s senior secured debt remains rated investment grade by S&P and Moody’s (in each case, with a stable or better outlook), a representation concerning no material adverse change in SPPC’s business, assets, property or financial condition would not be a condition to the availability of credit under the facility.  In the event that SPPC’s senior secured debt rating were rated below investment grade by either S&P or Moody’s, or investment grade by either S&P or Moody’s but with a negative outlook, a representation concerning no material adverse change in SPPC’s business, assets, property or financial condition would be a condition to borrowing under the revolving credit facility.

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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 places certain restrictions on debt incurrence, liens and dividends.  These limitations are discussed in Note 8, Debt Covenant and Other Restrictions.

NOTE 7.                      FAIR VALUE OF FINANCIAL INSTRUMENTS

The December 31, 2011, 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 NVE’s consolidated long-term debt at December 31, 2011, is estimated to be $6.0 billion 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 was estimated to be $5.7 billion as of December 31, 2010.

The total fair value of NPC’s consolidated long-term debt at December 31, 2011, is estimated to be $4.1 billion 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 was estimated to be $3.9 billion at December 31, 2010.

The total fair value of SPPC’s consolidated long-term debt at December 31, 2011, is estimated to be $1.3 billion 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 was estimated to be $1.3 billion as of December 31, 2010.

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 2011, NPC and SPPC paid $99 million and $114 million in dividends, respectively, to NVE.  

On February 10, 2012, NPC and SPPC declared a $39 million dividend and a $20 million dividend, respectively, to 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 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

   NVE

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 2011, NVE paid a cash dividend of $0.12 per share.  In October 2011, the BOD increased the cash dividend to $0.13 per share, which was paid in December 2011.  On February 10, 2012, NVE declared a cash dividend of $0.13 per share for common stock holders of record as of March 2012.

      Dividend Restrictions Applicable to the Utilities

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.

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 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.

Ability to Issue Debt

   NVE

NVE’s Term Loan contains conditions of borrowing, events of default, and affirmative and negative covenants.  The Term Loan includes (i) a financial covenant to maintain a ratio of total consolidated indebtedness to total consolidated capitalization, determined on the last day of each fiscal quarter, not to exceed 0.70 to 1.00 and (ii) a fixed charge covenant that requires NVE not to permit the fixed charge coverage ratio, determined on the last day of each fiscal quarter, to be less than 1.50 to 1.00.

 Under these covenant restrictions, as of December 31, 2011, NVE (consolidated) would be allowed to incur up to $2.8 billion of additional indebtedness, which includes the use of the Utilities revolving credit facilities.  The amount of additional indebtedness allowed would likely be impacted if there is a change in current market conditions or material change in our financial condition.

   NPC

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 agreements, and the terms of  NVE’s Term Loan.  As of December 31, 2011, the most restrictive of the factors below is the PUCN authority.  As such, NPC may issue up to $725 million in long-term debt, in addition to the use of its existing credit facilities.  However, depending on NVE’s or SPPC’s issuance of long-term debt or the use of the Utilities’ revolving credit facilities, the PUCN authority may not remain the most restrictive factor.  The factors affecting NPC’s ability to issue debt are further detailed below:

a. Financing authority from the PUCN - As of December 31, 2011, NPC has financing authority from the PUCN for the period ending December 31, 2013, consisting of authority: (1) to issue additional long-term debt securities of up to $725 million; (2) to refinance up to approximately $322.5 million of long-term debt securities; and (3) ongoing authority to maintain a revolving credit facility of up to $1.3 billion.

b. Financial covenants within NPC’s financing agreements – Under its $600 million revolving credit facility, NPC must 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.  Based on December 31, 2011 financial statements, NPC was in compliance with this covenant and could incur up to $2.6 billion of additional indebtedness.

All other financial covenants contained in NPC’s 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 under these additional covenants; and

c. Financial covenants within NVE’s Term Loan – As discussed in NVE’s Ability to Issue Debt, NPC is also subject to NVE’s cap on additional consolidated indebtedness of $2.8 billion.

   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, 2011, $4.1 billion of NPC’s General and Refunding Mortgage Securities were outstanding.  NPC had the capacity to issue $1.4 billion of additional General and Refunding Mortgage Securities as of December 31, 2011.  That amount is determined on the basis of:

1.         70% of net utility property additions; and/or

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2.         The principal amount of retired General and Refunding Mortgage Securities.

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 NPC’s Indenture, it will reduce the amount of securities issuable under the Indenture.

   SPPC

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 NVE’s Term Loan.  As of December 31, 2011, the most restrictive of the factors below is the PUCN authority.  Based on this restriction, SPPC may issue up to $350 million of long-term debt securities, and maintain a credit facility of up to $600 million.  However, depending on NVE’s or NPC’s issuance of long-term debt or the use of the Utilities’ revolving credit facilities, the PUCN authority may not remain the most restrictive factor.  The factors affecting SPPC’s ability to issue debt are further detailed below:

a. Financing authority from the PUCN - As of December 31, 2011, SPPC has financing authority from the PUCN for the period ending December 31, 2012, consisting of authority (1) to issue additional long-term debt securities of up to $350 million; (2) to refinance approximately $348 million of long-term debt securities; and (3) ongoing authority to maintain a revolving credit facility of up to $600 million.

b. Financial covenants within SPPC’s financing agreements – Under SPPC’s $250 million revolving credit facility, the Utility must 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.  Based on December 31, 2011 financial statements, SPPC was in compliance with this covenant and could incur up to $879 million of additional indebtedness.

All other financial covenants contained in SPPC’s 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 under these additional covenants.

c. Financial covenants within NVE’s Term Loan – As discussed in NVE’s Ability to Issue Debt, SPPC is also subject to NVE’s cap on additional consolidated indebtedness of $2.8 billion.

   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.  As of December 31, 2011, $1.5 billion of SPPC’s General and Refunding Mortgage Securities were outstanding.  SPPC had the capacity to issue $760.3 millionof additional General and Refunding Mortgage Securities as of December 31, 2011.     That amount is determined on the basis of:

1.         70% of net utility property additions; and/or

2.         The principal amount of retired General and Refunding Mortgage Securities.

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 SPPC’s Indenture, it will reduce the amount of securities issuable under the Indenture.

NOTE 9.                      DERIVATIVES AND HEDGING ACTIVITIES

NVE, NPC and SPPC apply the accounting guidance as required by the Derivatives and Hedging Topic of the FASC.  The accounting guidance for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities, requires that an entity recognize all derivatives as either assets or liabilities in the statement of financial position, measurethose instruments at fair value, and recognize changes in the fair value of the derivative instruments in earnings in the period of

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change, unless the derivative meets certain defined conditions and qualifies as an effective hedge.  The accounting guidance for derivative instruments also provides a scope exception for commodity 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 purchases and normal sales are accounted for under deferred energy accounting and not recorded on the consolidated balance sheets of NVE and the Utilities 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 may assist the Utilities reduce the risks associated in volatile electricity and natural gas markets.  In October 2009, the Utilities suspended their hedging program and at December 31, 2011 there were no transactions outstanding.

Interest Rate Risk

In August 2009, NPC entered into two interest rate swap agreements which terminated in June 2011, for an aggregated notional amount of $350 million associated with its $350 million 8.25% General and Refunding Mortgage Notes, Series A, due June 1, 2011.  Interest rate hedges manage existing and future fixed rate interest rate exposure with a variable interest rate in order to lower overall borrowing costs.  The interest rate swaps terminated in the second quarter of 2011 in conjunction with the payment at maturity of NPC’s $350 million 8.25% General and Refunding Mortgage Notes, Series A, due 2011.  See Note 6, Long-Term Debt.

           On October 7, 2011, NVE entered into a floating for fixed interest rate swap in conjunction with its 3-year Term Loan to lock in an effective interest rate of 2.81% for the length of the Term Loan and manage existing and future variable rate interest rate exposure with fixed interest rate.  See Note 6, Long-Term Debt.

Determination of Fair Value

            As required by the Fair Value Measurements and Disclosure Topic of the FASC, 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, options and interest rate swaps.  Total risk management assets or liabilities in the fair value table below do not include option premiums on commodity contracts which are not considered derivatives.  Option premiums upon settlement are recorded as either revenue or fuel and purchased power expense and are subsequently requested for recovery through the deferred energy mechanism.  On December 31, 2011, option premium amounts included in risk management liabilities on the balance sheets for NVE, NPC and SPPC were $1.3 million, $1.3 million and $0.0 million 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 using an option pricing model that includes various inputs, such as forward commodity prices, interest rate yield curves and option volatility rates.  Interest rate swaps are valued using a financial model which utilizes observable inputs for similar instruments based primarily on market price curves.  The determination of the fair value for derivative instruments not only includes counterparty risk, but also the impact of NVE and the Utilities' nonperformance risk on their liabilities, which as of December 31, 2011, had an immaterial impact to the fair value of their derivative instruments.

The following table shows the fair value of the open derivative positions recorded on the consolidated balance sheets as of December 31, 2011 of NVE, NPC and SPPC and the related regulatory assets and/or liabilities that did not meet the normal purchase and normal sales exception criteria as required by the Derivatives and Hedging Topic of the FASC.  Due to regulatory accounting treatment under which the Utilities operate, regulatory assets and liabilities are established to the extent that 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 derivative transactions until the period of settlement as of December 31 (dollars in millions):

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	December 31, 2011						December 31, 2010
Derivative Contracts	Level 2						Level 2
	NVE		NPC		SPPC		NVE		NPC		SPPC
Risk management assets - current	$	-	$	-	$	-	$	2.1	$	2.1	$	-
Risk management assets - noncurrent		-		-		-		-		-		-
Total risk management assets		-		-		-		2.1		2.1		-
Risk management liabilities- current		2.4		2.4		-		32.9		22.4		10.5
Risk management liabilities- noncurrent		1.1		-		-		-		-		-
Total risk management liabilities		3.5		2.4		-		32.9		22.4		10.5
Risk management regulatory assets – net(1)	$	(3.5)	$	(2.4)	$	-	$	(30.8)	$	(20.3)	$	(10.5)

(1)    For the year ended December 31, 2011, NVE, NPC and SPPC would have recorded cumulative gains of $ 27.3million, $ 17.9 million and $ 10.5million, respectively.  However, as permitted by the Regulated Operations Topic of the FASB Accounting Standards Codification, NVE and the Utilities deferred these gains, which are included in the risk management regulatory asset - net amounts above.

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 market prices.  Risk management assets and liabilities decreased as of December 31, 2011, as compared to December 31, 2010, primarily as a result of reduction in hedging transactions and the settlement of derivative contracts.

As a result of the suspension of the Utilities’ hedging program in October 2009 there were no gas commodity transactions outstanding at December 31, 2011 and volume was immaterial at December 31, 2010.

NOTE 10.                      INCOME TAXES (BENEFITS)

The following reflects the composition of taxes on income from continuing operations for the years ended December 31 (dollars in millions):

		2011						2010						2009
		NVE		NPC		SPPC		NVE		NPC		SPPC		NVE		NPC		SPPC
Current and other
	Federal	$	(1.3)	$	(1.1)	$	(0.1)	$	(15.4)	$	(0.9)	$	1.1	$	(34.1)	$	(34.3)	$	(0.5)
	State		0.1		-		0.1		1.0		-		0.9		-		-		-
Total current and other			(1.2)		(1.1)		-		(14.4)		(0.9)		2.0		(34.1)		(34.3)		(0.5)
Deferred
	Federal		91.7		73.4		33.2		132.7		93.6		42.0		114.1		97.9		34.3
	State		(0.1)		(0.3)		0.2		(0.1)		0.7		(0.9)		0.5		0.3		0.3
Total deferred			91.6		73.1		33.4		132.6		94.3		41.1		114.6		98.2		34.6
Amortization of excess deferred taxes			(0.4)		(0.1)		(0.3)		(1.1)		(0.2)		(0.8)		(1.7)		(0.9)		(0.8)
Investment tax credits			(3.1)		(1.2)		(1.9)		(3.3)		(1.4)		(1.9)		(3.3)		(1.3)		(2.1)
Total provision for income taxes		$	86.9	$	70.7	$	31.2	$	113.8	$	91.8	$	40.4	$	75.5	$	61.7	$	31.2

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A reconciliation between income tax expense and the expected tax expense at the federal statutory rate for the years ended December 31 are as follows (dollars in millions):

	2011									2010									2009
	NVE			NPC			SPPC			NVE			NPC			SPPC			NVE			NPC			SPPC
Net income	$	163.4		$	132.6		$	59.9		$	227.0		$	185.9		$	72.4		$	182.9		$	134.3		$	73.1
Total income tax expense		86.9			70.7			31.2			113.8			91.8			40.4			75.5			61.7			31.2
Pretax income		250.3			203.3			91.1			340.8			277.7			112.8			258.4			195.9			104.3
Statutory tax rate		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%
Federal income tax expense		87.6			71.2			31.9			119.3			97.2			39.5			90.4			68.6			36.5
Depreciation		3.1			2.0			1.1			4.1			1.8			2.3			(2.1)			1.7			(3.8)
AFUDC - equity		(3.8)			(2.9)			(0.9)			(9.8)			(8.8)			(1.0)			(8.5)			(7.4)			(1.1)
Investment tax credit amortization		(3.1)			(1.2)			(1.9)			(3.3)			(1.4)			(1.9)			(3.4)			(1.3)			(2.1)
Regulatory asset for goodwill		2.7			1.7			1.0			2.7			1.7			1.0			2.7			1.7			1.0
Research and development credit		(0.2)			(0.1)			(0.1)			(1.0)			(0.8)			(0.2)			(1.1)			(1.0)			(0.2)
Other – net		0.6			-			0.1			1.8			2.1			0.7			(2.5)			(0.6)			0.9
Provision for income taxes	$	86.9		$	70.7		$	31.2		$	113.8		$	91.8		$	40.4		$	75.5		$	61.7		$	31.2
Effective tax rate		34.7	%		34.8	%		34.2	%		33.4	%		33.1	%		35.8	%		29.2	%		31.5	%		29.9	%

The net deferred income tax liability consists of deferred income tax liabilities less related deferred income tax assets as of December 31 (dollars in millions):

			2011						2010
		NVE		NPC		SPPC		NVE		NPC		SPPC
Deferred tax assets
	Net operating loss and credit carryovers	$	470.8	$	353.7	$	62.5	$	173.8	$	82.5	$	46.3
	Employee benefit plans		58.4		21.2		26.5		66.3		25.7		34.8
	Customer advances		17.6		10.5		7.1		25.2		12.3		12.9
	Gross-ups received on CIAC & customer advances		20.3		15.3		5.0		26.2		19.4		6.8
	Deferred revenues		18.5		15.1		3.4		8.0		3.5		4.5
	Deferred energy		49.9		20.0		29.9		70.5		18.8		51.7
	Reserves		13.4		9.6		2.5		11.3		9.9		1.4
	Other		17.5		10.5		6.3		27.9		19.3		7.9
Total deferred tax assets			666.4		455.9		143.2		409.2		191.4		166.3
Regulatory deferred tax assets
	Excess deferred income taxes		8.7		2.5		6.2		9.2		2.7		6.5
	Unamortized investment tax credit		8.7		3.3		5.4		10.3		3.9		6.5
Total regulatory deferred tax assets			17.4		5.8		11.6		19.5		6.6		13.0
Total deferred tax assets before valuation allowance			683.8		461.7		154.8		428.6		198.0		179.3
Valuation allowance			(1.2)		(1.2)		-		(1.5)		(1.5)		-
Total deferred tax assets after valuation allowance		$	682.6	$	460.5	$	154.8	$	427.2	$	196.5	$	179.3

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			2011						2010
		NVE		NPC		SPPC		NVE		NPC		SPPC
Deferred tax liabilities
	Excess of tax over book depreciation	$	1,380.7	$	1,015.1	$	371.6	$	1,004.2	$	661.7	$	348.9
	Deferred Conservation Programs		83.2		63.0		20.2		78.8		58.6		20.1
	Regulatory assets		137.1		94.1		44.2		166.1		112.9		54.3
	Other		32.0		19.4		12.1		36.6		21.1		15.1
Total deferred tax liabilities			1,633.0		1,191.6		448.1		1,285.7		854.3		438.4
Regulatory deferred tax liabilities
	Tax benefits flowed through to customers - property		115.2		93.0		22.3		116.9		86.3		30.6
	Tax benefits flowed through to customers - goodwill		136.0		85.0		50.9		140.2		87.7		52.5
Total regulatory deferred tax liability			251.2		178.0		73.2		257.1		174.0		83.1
Total deferred tax liabilities, including
regulatory deferred tax liabilities		$	1,884.2	$	1,369.6	$	521.3	$	1,542.8	$	1,028.3	$	521.5
Net deferred income tax liability		$	967.8	$	736.9	$	304.9	$	878.0	$	664.3	$	272.1
Net regulatory deferred tax liability			233.8		172.2		61.6		237.6		167.5		70.1
Total net deferred tax liability		$	1,201.6	$	909.1	$	366.5	$	1,115.6	$	831.8	$	342.2

For balance sheet presentation, the regulatory tax asset is included in regulatory assets and the regulatory tax liability is included in regulatory liabilities.  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).  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 similar to the accumulated deferred investment tax credit.

The following tables summarize as of December 31, 2011, the net operating loss and tax credit carryovers and associated carryover periods, and valuation allowance for amounts which NVE and the Utilities have determined that realization is uncertain (dollars in millions):  

	Deferred		Valuation		Net Deferred		Expiration
	Tax Asset		Allowance		Tax Asset		Period
NVE
Federal net operating loss	$	456.5	$	-	$	456.5	2024-2031
Research and development credit		12.6		-		12.6	2024-2031
Arizona coal credits		1.7		1.2		0.5	2012-2016
Total net operating loss and tax credits	$	470.8	$	1.2	$	469.6

	Deferred		Valuation		Net Deferred		Expiration
	Tax Asset		Allowance		Tax Asset		Period
NPC
Federal net operating loss	$	343.7	$	-	$	343.7	2024-2031
Research and development credit		8.3		-		8.3	2024-2031
Arizona coal credits		1.7		1.2		0.5	2012-2016
Total net operating loss and tax credits	$	353.7	$	1.2	$	352.5

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	Deferred		Valuation		Net Deferred			Expiration
	Tax Asset		Allowance		Tax Asset		Period
SPPC
Federal net operating loss	$	58.1	$	-	$	58.1		2024-2031
Research and development credit		4.4		-		4.4		2024-2031
Total net operating loss and tax credits	$	62.5	$	-	$	62.5

At December 31, 2011, NVE has a gross Federal NOL carryover of $1.3 billion, NPC of $982.0 million and SPPC of $166.0 million.  The increase in NVE’s NOL from the prior year is primarily attributable to the bonus depreciation deduction taken in 2011.

Considering all positive and negative evidence regarding the utilization of NVE’s and the Utilities’ deferred tax assets, it has been determined that NVE, NPC and SPPC are more-likely-than-not to realize all recorded deferred tax assets, except the Arizona coal credits on NVE and NPC.  As such, these Arizona coal credits represent the only valuation allowance that has been recorded as of December 31, 2011 on NVE and NPC.

Accounting for Uncertainty in Income Taxes

Under Accounting for Uncertainty in Income Taxes, as reflected in the FASC, uncertain tax liabilities are all long-term and are included in the “other deferred credits and liabilities” line item on the balance sheet.  

A summary of unrecognized tax benefits as of December 31 are as follows (dollars in millions):

		2011						2010						2009
		NVE		NPC		SPPC		NVE		NPC		SPPC		NVE		NPC		SPPC
Unrecognized tax benefits		$	34.1	$	24.3	$	9.8	$	35.7	$	25.5	$	10.2	$	38.2	$	26.6	$	10.5
Of the total, amounts related to tax
positions that, if recognized, in future years would:
	Increase the effective tax rate	$	5.6	$	3.8	$	1.8	$	4.8	$	3.2	$	1.6	$	4.5	$	3.1	$	1.4

A reconciliation of the beginning and ending amount of unrecognized tax benefits as of December 31 are as follows (dollars in millions):

	2011						2010						2009
	NVE		NPC		SPPC		NVE		NPC		SPPC		NVE		NPC		SPPC
Unrecognized tax benefit at January 1	$	35.7	$	25.5	$	10.2	$	38.2	$	26.6	$	10.5	$	93.9	$	48.5	$	40.1
Increase in current period tax positions		0.5		0.4		0.1		0.3		0.1		0.2		3.3		2.8		0.5
Increase in prior period tax positions		0.2		0.1		0.1		0.1		0.1		0.1		11.8		9.2		2.5
Decrease in prior period tax positions		(2.3)		(1.7)		(0.6)		(2.9)		(1.3)		(0.6)		(70.8)		(33.9)		(32.6)
Unrecognized tax benefit at December 31	$	34.1	$	24.3	$	9.8	$	35.7	$	25.5	$	10.2	$	38.2	$	26.6	$	10.5

In December 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.  In April 2009, NVE and the Utilities received notice from the IRS approving the Application.  Accordingly, during the second quarter of 2009, NVE, NPC and SPPC recorded reductions to their unrecognized tax benefits for the repair positions taken in the prior period of approximately $64.4 million, $32.0 million and $32.2 million, respectively.  Neither NVE nor the Utilities anticipate additional material changes in their uncertain tax position reserves in the next twelve months.

NVE and the Utilities classify interest and penalties related to income taxes as interest and other expense, respectively.   NVE and the Utilities have not accrued interest or penalties as of December 31, 2011, December 31, 2010 and December 31, 2009.  NVE and the Utilities do not expect unrecognized tax benefits to change within the next twelve months.

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.  The U.S. federal jurisdiction is the only “significant” tax jurisdiction for NVE.  The IRS is currently conducting a limited scope examination of NVE

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for the years 2005-2008.  As of December 31, 2011, NVE is no longer subject to examinations by U.S. federal, state, or local tax authorities for years before 2005, with few exceptions. 

NOTE 11.                      RETIREMENT PLAN AND POST-RETIREMENT BENEFITS

NVE has a single employer defined benefit pension plan covering substantially all employees of NVE and the Utilities.  NVE allocates the unfunded liability and the net periodic benefit costs for its pension benefit and other postretirement benefit plans to NPC and SPPC based upon the current, or in the case of the retirees, previous, employment location.  Certain grandfathered and 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 with vesting after three years of service. NVE also has other postretirement plans, including a defined contribution plan which provides medical and life insurance benefits for certain retired employees.

Plan Changes

During 2011, the sale of California Assets, as discussed in detail in Note 16, Assets Held for Sale, resulted in employees being transferred to CalPeco.  Certain employees who did not want to transfer, and who could not obtain comparable positions with NVE, had their service periods bridged to retirement age under the terms of the collective bargaining agreement with IBEW No. 1245.  Amounts recorded for this event were not material.

Effective December 2010, under the terms of SPPC’s new contract with IBEW No. 1245, as ratified in August 2010, the pension plan for most bargaining unit employees was changed from a traditional defined benefit pension plan to a defined benefit cash balance pension plan.  Employees with combined age and service totaling 75 years or more were given the choice of staying with the current pension plan or switch to the new cash balance pension plan.  This plan amendment, as indicated in the benefits obligations table below, reduced the 2010 projected benefit obligation for pension plans by $10.4 million.

Additionally during 2010, benefits available to retired MPAT employees for health insurance coverage were amended.  Retirees were given a choice between Health Reimbursement Accounts (HRA’s) and Health Savings Accounts (HSA’s).  This plan amendment, as indicated in the benefits obligations table below, reduced the 2010 other postretirement benefit obligation by $0.7 million.

During 2009, in an effort to reduce costs, NVE implemented severance programs, as discussed in Note 17, Severance Programs.  Under the terms of the program employees close to retirement age were offered special enhancements to bridge their pension and postretirement benefits. NVE recognized expense of $0.3 million for pension benefits and $2.8 million for other postretirement benefits in 2009, under the special termination provisions of the Compensation Nonretirement Postemployment Benefits Topic of the FASC.

NVE also has a non-qualified Supplemental Executive Retirement Plan and a Restoration Plan for executives. NVE contributed $26.5 million to establish a rabbi trust for these plans in 2009. Assets held in the trust for these non-contributory defined benefit plans consist of a variety of marketable securities and life insurance policies, none of which is NVE stock.  At December 31, 2011 trust assets were $29.2 million and are reflected in NVE’s consolidated balance sheet within “Investments and other property, net”.  NVE’s obligation under these supplemental and restoration plans is included in “Accrued retirement benefits” in NVE’s consolidated balance sheet, and amounted to $29.3 million at December 31, 2011. NVE is not required to make contributions to the plans.

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Plan Obligations, Plan Assets and Funded Status as of December 31, 2011 and 2010

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 (dollars in thousands):

						Other Postretirement
	Pension Benefits				Benefits
	2011		2010		2011		2010
Change in Benefit Obligations
Benefit obligation at January 1	$	806,034	$	757,748	$	163,423	$	154,287
Service cost		18,427		18,910		2,611		2,466
Interest cost		40,676		42,872		8,360		8,736
Plan participants' contributions		-		-		2,325		1,924
Actuarial loss (gain)		18,552		54,890		(12,525)		9,166
Benefits paid		(42,507)		(58,002)		(12,255)		(12,495)
Plan amendments		577		(10,384)		-		(661)
Special termination benefits		286		-		100		-
Remeasurement adjustment		-		-		-		-
Benefit obligation at December 31	$	842,045	$	806,034	$	152,039	$	163,423
Change in Plan Assets
Fair value of plan net assets at January 1	$	729,940	$	670,794	$	93,648	$	93,298
Actual return on plan assets		78,104		70,838		8,615		10,627
Employer contributions		41,286		41,698		863		294
Plan participants' contributions		-		-		2,325		1,924
Benefits paid		(37,850)		(53,390)		(12,255)		(12,495)
Fair value of plan net assets at December 31	$	811,480	$	729,940	$	93,196	$	93,648
Funded Status at December 31(1)	$	(30,565)	$	(76,094)	$	(58,843)	$	(69,775)

(1) Amounts recognized as non-current liabilities (accrued retirement benefits) in the consolidated balance sheets as of December 31, 2011 and 2010.

The expected long-term rate of return for both the pension and other postretirement benefit plan assets is 6.75%, 6.75% and 7.10%, and 6.75-7.10%, 6.75-7.10%, and 7.10%, respectively, in 2011, 2010 and 2009, respectively.

The following amounts would have been recognized in Accumulated Other Comprehensive Income, net of taxes, according to the provisions of the Compensation Retirement Benefits Topic of the FASC.  Since NVE is able to recover expenses through rates, the amounts noted below will be recorded as Regulatory Assets for pension plans under the provisions of the Regulated Operations Topic of the FASC.  Amounts recognized as of December 31, consist of (dollars in thousands):

						Other Postretirement
	Pension Benefits				Benefits
	2011		2010		2011		2010
Net actuarial loss	$	238,672	$	263,015	$	34,501	$	71,650
Prior service credit		(34,730)		(24,343)		(15,141)		(37,149)
Accumulated other comprehensive income, pre-tax		203,942		238,672		19,360		34,501
Regulatory asset for pension plans		(194,936)		(232,717)		(19,360)		(34,501)
Accumulated other comprehensive income, pre-tax, at December 31	$	9,006	$	5,955	$	-	$	-

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The estimated amounts that will be amortized from the regulatory assets for pension plans and accumulated other comprehensive income into net periodic cost in 2012 are as follows (dollars in thousands):

			Other
	Pension		Postretirement
	Benefits		Benefits
Actuarial loss	$	13,891	$	2,924
Prior service credit	$	(2,897)	$	(3,947)

As of December 31, 2011 and 2010, the projected benefit obligation, accumulated benefit obligation, and fair value of plan net assets for pension plans with a projected benefit obligation in excess of plan net assets, and pension plans with an accumulated benefit obligation in excess of plan assets, were as follows (dollars in thousands):

	2011		2010
Projected benefit obligation, end of year	$	842,045	$	806,034
Accumulated benefit obligation, end of year	$	813,101	$	772,846
Fair value of plan net assets, end of year	$	811,480	$	729,940

Plan Assets

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 $40.6 million in 2011 towards the qualified pension and other postretirement benefit plans.

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 stock.

NVE’s long term strategy for the pension plan assets is to maximize risk adjusted returns while maintaining adequate liquidity to pay plan benefits.  NVE is committed to prudent investments with ample diversification in terms of asset types, fund strategies, and investment managers.  As such, NVE has elected to include an appropriate mix of indexed and actively managed investments to accomplish its strategy.  The current allocation for pension plan net assets at December 31, 2011 is 61% fixed income, 19% domestic equity, 14% international equity, 5% cash, and 1% other.  The long-term target allocation for pension plan net assets is 65% fixed income, 20% U.S. equity, and 15% international equity.  The fixed income investments are benchmarked against government and corporate credit bond indices.  U.S. equity investments include large cap, mid-cap, and small-cap companies with an emphasis towards small and mid-cap investments relative to the Russell 3000 Index.  International equity is currently actively managed and includes investments in both established and emerging markets.

The current allocation for the other postretirement benefit plan net assets at December 31, 2011 is 51% equity securities, 46% fixed income and 3% cash.  The long-term strategy for the other post-retirement benefit plan net assets is similar to the pension plan net assets strategy as described above.  The target allocation for other postretirement benefit assets is 60% equity and 40% fixed income. The equity is invested in indexed securities that track the S&P 500 Index.  The fixed income is indexed and benchmarked against government and corporate credit bond indices.

The fair values of NVE’s pension plan and other post-retirement benefits assets at December 31, 2011, within the fair value hierarchy as required by the Fair Value Measurements and Disclosures Topic of the FASC, by asset category are as follows (dollars in thousands):

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   2011 Pension Plan Assets

Asset Category			Level  1		Level  2		Level  3		Total
Cash & Cash equivalents(1)			$	4,795	$	39,431	$	-	$	44,226
Equity:
	U.S. Equity Securities(2)			52,204		101,231		-		153,435
	International Equity Securities			110,837		-		-		110,837
Fixed Income:
	U.S. Preferred Securities			64		-		-		64
	International Preferred Securities			842		-		-		842
	U.S. Fixed Income Securities(4)			98,311		339,816		-		438,127
	International Fixed Income Securities			3,135		51,902		-		55,037
Other:
	U.S. Future Contracts			(92)		-		-		(92)
	International Future Contracts			-		-		-		-
	U.S. Convertible Securities			-		-		-		-
	Administrative Trust Net Assets(5)			9,004		-		-		9,004
		Total Pension Plan Assets	$	279,100	$	532,380	$	-	$	811,480

2011 Other Postretirement Benefit Assets
Asset Category			Level  1		Level  2		Level  3		Total
Cash & Cash equivalents(1)			$	105	$	2,756	$	-	$	2,861
Equity:
	U.S. Equity Securities(2)			42,848		2,200		-		45,048
	International Equity Securities			2,409		-		-		2,409
Fixed Income:
	U.S. Preferred Securities			1		-		-		1
	International Preferred Securities			18		-		-		18
	U.S. Fixed Income Securities(4)			10,168		31,301		-		41,469
	International Fixed Income Securities			68		1,128		-		1,196
Other:
	U.S. Future Contracts			(2)		-		-		(2)
	International Future Contracts			-		-		-		-
	U.S. Convertible Securities			-		-		-		-
	Administrative Trust Net Assets(5)			196		-		-		196
		Total Other Postretirement Benefit Assets	$	55,811	$	37,385	$	-	$	93,196

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2010 Pension Plan Assets
Asset Category			Level  1		Level  2		Level  3		Total
Cash & Cash equivalents (1)			$	-	$	29,698	$	-	$	29,698
Equity:										-
	U.S. Equity Securities (3)			141,917		(23)		-		141,894
	International Equity Securities			91,631		-		-		91,631
Fixed Income:										-
	U.S. Preferred Securities			59		-		-		59
	International Preferred Securities			-		-		-		-
	U.S. Fixed Income Securities (4)			111,866		326,642		-		438,508
	International Fixed Income Securities			2,784		38,208		-		40,992
Other:										-
	U.S. Future Contracts			35		-		-		35
	International Future Contracts			-		-		-		-
	U.S. Convertible Securities			-		573		-		573
	Administrative Trust Net Liabilities (5)			(13,450)		-		-		(13,450)
		Total Pension Plan Assets	$	334,842	$	395,098	$	-	$	729,940

2010 Other Postretirement Benefit Assets
Asset Category			Level  1		Level  2		Level  3		Total
Cash & Cash equivalents (1)			$	-	$	2,678	$	-	$	2,678
Equity:
	U.S. Equity Securities (3)			50,235		-		-		50,235
	International Equity Securities			2,397		-		-		2,397
Fixed Income:
	U.S. Preferred Securities			2		-		-		2
	International Preferred Securities			-		-		-		-
	U.S. Fixed Income Securities (4)			9,506		28,094		-		37,600
	International Fixed Income Securities			73		999		-		1,072
Other:
	U.S. Future Contracts			1		-		-		1
	International Future Contracts			-		-		-		-
	U.S. Convertible Securities			-		15		-		15
	Administrative Trust Net Liabilities(5)			(352)		-		-		(352)
		Total Other Postretirement Benefit Assets	$	61,862	$	31,786	$	-	$	93,648

(1) Cash and cash equivalents consist of investment in commingled funds that are primarily comprised of money market holdings and marketable securities, U.S. Treasury bills and commercial paper valued and redeemable at cost.

(2) This category includes approximately 26% small and mid-cap and 74% broad market domestic equity investments.

(3) This category includes approximately 44% large-cap, 31% small and mid-cap, and 25% broad market domestic equity investments.

(4) Level 1 investments are comprised of fixed income securities that primarily invest in U.S. Treasury bonds.  Level 2 investments consist of commingled funds that track the Barclays Capital Long Government and Corporate Credit Index and the Barclays Capital Aggregate US Fixed Income Index.

(5) The administrative trust net assets/liabilities are primarily comprised of amounts payable to and from brokers for sold and purchased securities.

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The actuarial assumptions used to determine December 31 benefit obligations and net periodic benefit costs were as follows:

	Benefit Obligations		Net Periodic Benefit Costs
	2011	2010	2011	2010
Discount rate-pension	4.91%	5.09%	5.09%	5.79%
Discount rate-other benefits	5.09%	5.20%	5.20%	5.75%
Rate of compensation increase	4.00%	4.00%	4.00%	4.50%
Expected long-term return on plan assets-pension	N/A	N/A	6.75%	6.75%
Expected long-term return on plan assets-other benefits	N/A	N/A	6.75-7.1%	6.75-7.1%
Initial health care cost trend rate	8.00%	8.00%	8.00%	8.00%
Ultimate health care cost trend rate	4.75%	4.75%	4.75%	5.00%
Number of years to ultimate trend rate	7	8	8	7

The discount rate for 2011 disclosures was determined by identifying a theoretical settlement portfolio of high quality corporate bonds sufficient to provide for the plans projected benefit payments. In selecting an assumed discount rate for fiscal year 2010 disclosures, and for fiscal years 2011, 2010 and 2009 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.

Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans.  A one-percentage-point change in assumed health care cost trend rates would have the following effect (dollars in thousands):

	1-Percentage		1-Percentage
	Point Increase		Point Decrease
Effect on the postretirement benefit obligation	$	6,446	$	(5,251)
Effect on total of service and interest cost components	$	696	$	(542)

 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.

 There were no significant transactions between the plan and the employer or related parties during 2011, 2010, or 2009.

Net Periodic Cost

The components of net periodic pension and other postretirement benefit costs for NVE, NPC and SPPC for the years ended December 31, are presented below (dollars in thousands):

NVE
		Pension Benefits						Other Postretirement Benefits
		2011		2010		2009		2011		2010		2009
Service cost		$	18,427	$	18,910	$	18,837	$	2,611	$	2,466	$	2,421
Interest cost			40,676		42,872		44,145		8,360		8,736		10,072
Expected return on plan assets			(48,767)		(44,275)		(37,159)		(6,386)		(6,223)		(6,048)
Amortization of:
	Prior service (credit)/cost		(2,952)		(1,794)		(1,794)		(3,947)		(3,890)		(1,466)
	Actuarial (gain)/loss		16,620		15,106		27,575		4,333		4,342		5,296
Remeasurement adjustment			-		-		-		-		-		336
Total net benefit cost		$	24,004	$	30,819	$	51,604	$	4,971	$	5,431	$	10,611

The NVE total 2009 net periodic cost excludes special termination benefits of $0.3 million for pension and $2.8 million for other postretirement benefits, related to severance programs implemented in 2009.  See Note 17, Severance Programs, of the Notes to Financial Statements for further discussion.

The average percentage of NVE net periodic costs capitalized during 2011, 2010 and 2009 was 33.4%, 34.0% and 36.6%, respectively.

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NPC
		Pension Benefits						Other Postretirement Benefits
		2011		2010		2009		2011		2010		2009
Service cost		$	9,781	$	9,567	$	9,572	$	1,454	$	1,413	$	1,325
Interest cost			19,521		20,092		21,079		2,459		2,474		2,437
Expected return on plan assets			(24,677)		(21,447)		(17,847)		(2,360)		(2,270)		(2,067)
Amortization of:
	Prior service (credit)/cost		(1,879)		(1,733)		(1,733)		916		946		1,104
	Actuarial (gain)/loss		6,758		7,056		13,192		1,208		1,199		1,272
Remeasurement adjustment			-		-		-		-		-		57
Total net benefit cost		$	9,504	$	13,535	$	24,263	$	3,677	$	3,762	$	4,128

The average percentage of NPC net periodic costs capitalized during 2011, 2010 and 2009 was 36.9%, 37.0% and 39.4%, respectively.

SPPC
		Pension Benefits						Other Postretirement Benefits
		2011		2010		2009		2011		2010		2009
Service cost		$	7,361	$	8,016	$	8,245	$	1,086	$	977	$	1,028
Interest cost			20,050		21,557		21,885		5,830		6,187		7,567
Expected return on plan assets			(22,964)		(21,723)		(18,321)		(3,905)		(3,844)		(3,894)
Amortization of:
	Prior service (credit)/cost		(1,108)		(104)		(104)		(4,878)		(4,851)		(2,586)
	Actuarial (gain)/loss		9,647		7,876		13,701		3,092		3,109		3,990
Remeasurement adjustment			-		-		-		-		-		277
Total net benefit cost		$	12,986	$	15,622	$	25,406	$	1,225	$	1,578	$	6,382

The average percentage of SPPC net periodic costs capitalized during 2011, 2010 and 2009 was 31.7%, 34.2% and 36.4%, respectively.

The expected cash flows for the plans, including trust accounts, are as follows (dollars in thousands):

			Other			Expected
	Pension Benefit		Postretirement			Federal
	Payments		Benefit Payments			Subsidy
2012	$	53,237	$	9,569	$	-
2013		57,364		9,736		-
2014		57,264		9,984		-
2015		56,548		10,070		-
2016		63,314		10,173		-
2017-2021		302,569		50,756		-

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.

NOTE 12.                       STOCK COMPENSATION PLANS

NVE’s executive long-term incentive plan for key management employees, which was approved by shareholders in May 2004 and amended and restated in 2011, 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, restricted stock units, performance units, performance shares, and bonus stock. During 2011, NVE granted restricted stock units, performance units and performance shares under the long-term incentive plan.  The Company also has an employee stock purchase plan which is available to all employees who meet minimum service requirements.  The employees can choose to have amounts deducted from their paychecks which will be used to buy NVE’s common stock at a discount.  The plans are discussed in more detail below.

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Total stock-based compensation expense for the following years was as follows (dollars in thousands):

	2011
	Total		NVE		NPC		SPPC
Non-Qualified Stock Options	$	-	$	-	$	-	$	-
Performance Units and Performance Shares		16,523		163		10,438		5,922
Restricted Stock Units		2,151		35		1,492		624
Employee Stock Purchase Plan		327		18		215		94
Total Stock Compensation Expense	$	19,001	$	216	$	12,145	$	6,640

	2010
	Total		NVE		NPC		SPPC
Non-Qualified Stock Options	$	71	$	1	$	51	$	19
Performance Units and Performance Shares		7,145		54		4,966		2,125
Restricted Stock Units		902		10		610		282
Employee Stock Purchase Plan		376		28		134		214
Total Stock Compensation Expense	$	8,494	$	93	$	5,761	$	2,640

	2009
	Total		NVE		NPC		SPPC
Non-Qualified Stock Options	$	392	$	5	$	282	$	105
Performance Units and Performance Shares		5,440		27		3,837		1,576
Restricted Stock Units		493		4		329		160
Employee Stock Purchase Plan		453		37		249		167
Total Stock Compensation Expense	$	6,778	$	73	$	4,697	$	2,008

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 be awarded; however, historically, dividend equivalents have not been granted.  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.  There have been no grants of non-qualified stock options made to employees since 2007.

A summary of the status of NVE’s nonqualified stock options as of December 31, 2011, 2010 and 2009, and changes during the year is presented below:

		2011				2010				2009
				Weighted-				Weighted-				Weighted-
				Average				Average				Average
				Exercise				Exercise				Exercise
		Shares		Price		Shares		Price		Shares		Price
NQSO’s outstanding at beginning of year			728,688	$	15.50		854,717	$	15.40		1,278,557	$	15.65
	Granted		-	$	-		-	$	-		-	$	-
	Exercised		(118,175)	$	10.26		(44,730)	$	8.83		(8,000)	$	7.35
	Forfeited		(71,063)	$	16.64		(81,299)	$	18.18		(415,840)	$	16.31
NQSO’s outstanding at end of year			539,450	$	16.56		728,688	$	15.50		854,717	$	15.40
Options exercisable at year-end		$	539,450	$	16.56	$	728,688	$	15.50	$	717,705	$	14.84
Intrinsic value of options exercised		$	545,695	$	-	$	146,102	$	-	$	21,120	$	-
Income from options exercised		$	830,771	$	-	$	447,983	$	-	$	64,386	$	-

NQSO’s are accounted for as equity awards.  The fair value of each NQSO has been estimated on the date of grant using the Black-Scholes option pricing model using the following assumptions: Average Dividend Yield, Average Expected Volatility, Average Risk-Free Rate of Return, and Average Expected Life.  As of January 1, 2011 all of the NQSO’s have been fully vested and expensed.

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The following table summarizes information about NQSO’s outstanding at December 31, 2011:

	Options Outstanding				Options Exercisable
	Weighted-				Weighted-		Number
	Average		Number	Remaining	Average		Vested and
	Exercise		Outstanding at	Contractual	Exercise		Exercisable at
Year of Grant	Price		12/31/11	Life	Price		12/31/11
2002	$	15.58	34,500	<1 year	$	15.58	34,500
2005	$	10.05	40,733	3.1 years	$	10.05	40,733
2006	$	13.24	121,246	4.1 years	$	13.24	121,246
2007	$	18.30	342,971	5.1  -5.8 years	$	18.30	342,971
Weighted Average Remaining
Contractual Life (years)		4.51				4.51
Intrinsic Value	$	659,896			$	659,896

Performance Awards

   Performance Units

Performance Units vest at the end of a three-year period to the extent that specific stock price related performance targets are met, as determined by the Compensation Committee.  If the established objectives are not met, the Performance Units are forfeited.  Performance Units are typically paid in shares after vesting.  At the time of grant, rights to dividend equivalents may be awarded; however, historically, dividend equivalents have not been granted.  These awards do not have any voting rights associated with them.   Performance Units granted are measured based on NVE’s TSR relative to the average TSR of companies listed in the S&P Super Composite Electric Utility Index throughout the three-year performance period.   The Committee determined that the awards will vest according to the table shown below (a proportionate amount of shares will vest in the case of performance between the percentiles listed below):

Performance	Shares Vested
Below 35th Percentile	0% of grant
35th Percentile	50% of grant
50th Percentile	100% of grant
75th Percentile	150% of grant

   Performance Shares

Performance Shares vest at the end of a three-year period, based on average aggregate Corporate Goal performance under the Short Term Incentive Plan (STIP) and the average STIP payout over those three years.  If the established objectives are not met, the Performance Shares are forfeited.  Performance Shares are paid in shares, minus applicable taxes, based on the then fair market value of the shares.  At the time of grant, rights to dividend equivalents may be awarded; however, historically, dividend equivalents have not been granted.   Performance shares do not have any voting rights associated with them.

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The following table summarizes Performance Units and Performance Shares activity for the following years:

		2011				2010					2009
				Weighted-				Weighted-				Weighted-
				Average				Average				Average
				Grant Date				Grant Date				Grant Date
			Shares	Value			Shares	Value			Shares	Value
Nonvested performance units and
performance shares at beginning of year			763,386	$	11.47		765,143	$	11.73		389,681	$	14.96
	Shares granted		890,252	$	15.18		753,612	$	11.78		895,803	$	10.90
	Shares vested		(958,750)	$	13.40		(666,856)	$	12.08		(520,341)	$	12.71
	Shares forfeited		(42,704)	$	12.51		(88,513)	$	11.81		-	$	-
Nonvested performance units and
performance shares at end of year			652,184	$	13.64		763,386	$	11.47		765,143	$	11.73
Weighted average grant date fair value of shares granted		$	13,514,025		-	$	8,877,549		-	$	9,764,253		-
Fair value of shares issued		$	5,441,944		-	$	-		-	$	-		-
Unrecognized compensation expense at end of year		$	10,663,208		-	$	10,725,573		-	$	-		-
Weighted average remaining vesting period (years)			1.63		-		1.65		-		-		-

There were no performance units or performance shares paid out in 2010 and 2009.

Compensation expense for performance units and performance shares is recognized ratably over the three year vesting period.  In the event the conditional criteria are not met, the awards are forfeited and the expense is reversed.  Performance units and performance shares are accounted for as liability awards and compensation costs are measured at each balance sheet date using NVE's closing stock price for that date.  The closing trading price of NVE stock on December 31, 2011 was $16.35.

Restricted Stock Units

Elected officers and key employees specifically designated by a committee of the BOD are eligible to be awarded restricted stock units based on the guidelines in the plan.  These grants vest over different periods as stated within the terms of each grant.  The issuance of these shares is conditional upon the employee retaining employment with NVE throughout the entire vesting period.  Of the 267,750 units granted in 2011, 210,000 are eligible for dividend equivalents over the vesting period.

The following table summarizes Restricted Stock Units activity for the following years:

		2011				2010				2009
				Weighted-				Weighted-				Weighted-
				Average				Average				Average
				Grant Date				Grant Date				Grant Date
		Shares		Value		Shares		Value		Shares		Value
Nonvested shares at beginning of year			149,779	$	11.54		64,667	$	11.41		32,750	$	12.79
	Shares granted		267,750	$	14.51		169,000	$	11.65		66,000	$	10.94
	Shares vested		(123,413)	$	12.76		(75,708)	$	11.73		(33,083)	$	11.85
	Shares forfeited		(4,906)	$	11.58		(8,180)	$	11.14		(1,000)	$	10.91
Nonvested shares at end of year			289,210	$	13.77		149,779	$	11.53		64,667	$	11.41
Weighted average grant date fair value of shares granted		$	3,885,053		-	$	1,968,850		-	$	722,040		-
Fair value of shares issued		$	671,162		-	$	-		-	$	-		-
Unrecognized compensation expense at end of year		$	4,728,581		-	$	2,104,393		-	$	-		-
	Weighted average remaining vesting period (years)		2.55		-		2.14		-		-		-

There were no restricted stock units paid out in 2010 and 2009.

Compensation expense for restricted stock units is recognized ratably over the vesting period of each grant.  If employment is terminated prior to the end of the vesting period, the award is forfeited and the expense is reversed.  Restricted stock units are accounted for as liability awards and compensation costs are measured at each balance sheet date using NVE's closing stock price for that date.  The closing trading price of NVE stock on December 31, 2011 was $16.35.

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Employee Stock Purchase Plan

The employee stock purchase plan is available to all employees who meet minimum service requirements.  In 2010, shareholders approved an additional 1,000,000 shares for distribution under the plan, bringing the total authorized up to an aggregate of 1,900,162 shares of common stock.  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. The option price discount is 15%, and the purchase price is 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 134,266, 147,457 and 178,152 shares to employees in 2011, 2010 and 2009, respectively.

In accordance with the Stock Compensation Topic of the FASC, NVE recognized compensation expense in 2011, 2010 and 2009 related to the employee stock purchase plan.  The expense for those years has been estimated for the employees’ purchase rights on the date of grant, using the Black-Scholes option-pricing model.  The following assumptions were used for 2011, 2010 and 2009, with an option life of six months:

			Average
	Average	Average	Risk-Free	Weighted-
	Dividend	Expected	Rate of	Average
Year	Yield	Volatility	Return	Fair Value
2011	3.42%	13.99%	0.11%	$	2.82
2010	2.79%	20.02%	0.22%	$	2.55
2009	3.90%	28.89%	0.22%	$	2.54

NOTE 13.                      COMMITMENTS AND CONTINGENCIES

The Utilities enter into several purchase commitments for electric power, coal, natural gas and transportation, as well as, long-term service agreements, capital project commitments and operating leases.  Detailed below are estimates of future commitments under these arrangements (dollars in millions):

		NVE
	2012		2013		2014		2015		2016		Thereafter		Total
Purchased Power	$	492	$	427	$	416	$	425	$	433	$	3,081	$	5,274
Purchased Power - not commercially operable		75		119		204		239		247		5,360		6,244
Coal & Natural Gas		376		187		58		55		39		119		834
Transportation		168		217		218		155		146		1,779		2,683
Long-Term Service Agreements		49		21		21		20		17		71		199
Capital Projects		129		59		-		-		-		-		188
Operating Leases		18		17		16		11		6		74		142
Total Commitments	$	1,307	$	1,047	$	933	$	905	$	888	$	10,484	$	15,564

		NPC
	2012		2013		2014		2015		2016		Thereafter		Total
Purchased Power	$	385	$	318	$	297	$	302	$	305	$	2,152	$	3,759
Purchased Power - Not Commercially Operable		75		119		204		239		247		5,360		6,244
Coal & Natural Gas		261		127		39		39		39		119		624
Transportation		85		138		158		111		111		1,601		2,204
Long-Term Service Agreements		41		16		16		15		12		55		155
Capital Projects		87		54		-		-		-		-		141
Operating Leases		10		9		9		6		5		41		80
Total Commitments	$	944	$	781	$	723	$	712	$	719	$	9,328	$	13,207

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		SPPC
	2012		2013		2014		2015		2016		Thereafter		Total
Purchased Power	$	177	$	126	$	119	$	123	$	128	$	929	$	1,602
Coal & Natural Gas		115		60		19		16		-		-		210
Transportation		83		78		59		44		35		178		477
Long-Term Service Agreements		8		5		5		5		5		16		44
Capital Projects		42		5		-		-		-		-		47
Operating Leases		6		5		4		3		2		33		53
Total Commitments	$	431	$	279	$	206	$	191	$	170	$	1,156	$	2,433

Purchased Power

The Utilities have several contracts for long-term purchase of electric energy; the expiration of these contracts range from 2012 to 2039.  While the Utilities are not required to make payment if power is not delivered under these contracts, estimated future payments are included in the tables above.   Related party purchase power agreements have been eliminated from the NVE totals for the year 2012 and a portion of 2013.

Purchased Power - Not Commercially Operable

The Utilities entered into several contracts for long-term purchase of electric energy in which the facility remains under development.  This represents the estimated payments under renewable energy power purchase contracts, which have been approved by the PUCN and are contingent upon the developers obtaining commercial operation and their ability to deliver power.

Coal & Natural Gas

The Utilities have several long-term contracts for the purchase of coal and natural gas; the expiration of these contracts range from 2012 to 2019.

Transportation

The Utilities have several long-term contracts for the transport of coal and natural gas.  Also included in the transportation obligations is the TUA with GBT, of which NPC will be responsible for 95% and SPPC 5%.  The TUA remains contingent upon final construction costs, and reaching commercial operation.  The expiration of these transportation contracts range from 2012 to 2054.

Long-Term Service Agreements

The Utilities have long term service agreements for the performance of maintenance on generation units.  Obligation amounts are based on estimated usage.

Capital Projects

Capital projects at NPC NV Energize and NPC’s requirement to purchase the CDWR’s share of the undepreciated cost of capital of Reid Gardner Generating Station Unit No. 4 in 2013 (see Note 5, Jointly Owned Properties), at which time NPC will be required to assume all associated operating and maintenance costs for the Unit.  Capital projects at SPPC include NV Energize.  Additionally, the Utilities have obligations regarding the construction of ON Line, of which NPC will be responsible for 95% and SPPC 5%.

Operating Leases

The Utilities have entered into various non-cancelable operating leases primarily for building, land and equipment.  Contract expiration dates range from 2012 to 2048.  NVE’s rent payments meeting the above described criteria for 2011 were $2.4 million.  Prior to 2011, NVE did not have non-cancelable operating leases that were material.  NPC’s rent payments meeting the above described criteria for 2011, 2010 and 2009 were $11.5 million, $13.6 million and $13.8 million respectively.   SPPC’s rent payments meeting the above described criteria for 2011, 2010 and 2009 were $7.4 million, $14.0 million and $13.9 million respectively.

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Environmental

   NPC

      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.

      Reid Gardner Generating Station

On October 4, 2011, NPC received a request for information from the EPA-Region 9 under Section 114 of the Federal Clean Air Act requesting current and historical operations and capital project information for NPC’s Reid Gardner Generating Station located near Moapa, Nevada. NPC operates the facility and owns Units 1-3. Unit 4 of the facility is co-owned with the California Department of Water Resources. The EPA’s Section 114 information request does not allege any incidents of non-compliance at the plant.  A first response was provided back to the EPA in December 2011, and subsequent information will continue to be provided during the first quarter of 2012.  At this time, NPC cannot predict the impact, if any, associated with this information request.

   SPPC

      Valmy Generating Station

On June 22, 2009, SPPC received a request for information from the EPA-Region 9 under Section 114 of the federal Clean Air Act requesting current and historical operations and capital project information for SPPC’s Valmy Generating Station located in Valmy, Nevada.  SPPC co-owns and operates this coal-fired plant.  Idaho Power Company owns the remaining 50%.  The EPA’s Section 114 information request does not allege any incidents of non-compliance at the plant, and there have been no other new enforcement-related proceedings that have been initiated by the EPA relating to the plant.  SPPC completed its response to the EPA in December 2009 and will continue to monitor developments relating to this Section 114 request.At this time, SPPC cannot predict the impact, if any, associated with this information request.

Litigation Contingencies

   NPC

      Peabody Western Coal Company – Royalty Claim

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 (SCE) prior to the time it became non-operational on December 31, 2005.

In October 2004, the Navajo Generating Station’s coal supplier, Peabody Western Coal Company (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, defended the suit on behalf of the Navajo Joint Owners. In July 2008, the Court dismissed all 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. Initially, the DC Lawsuit sought $600 million in damages, treble damages and punitive damages of not less than $1 billion, and the ejection of defendants from all

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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. In April 2010, the Navajo Nation amended their complaint; it no longer seeks treble damages. Factual discovery was completed in October 2010, after which the parties engaged in settlement discussions. In April 2011, SCE indicated that it reached a settlement in the DC Lawsuit in principle. On August 1, 2011, the Navajo Nation, Peabody, Salt River and SCE executed a written settlement agreement in return for dismissal of all claims by the Navajo Nation. Salt River has asked that the Navajo Joint Owners, including NPC, contribute towards the settlement based on its 11% ownership stake in the Navajo Generating Station. NPC has paid Salt River the requested contribution, which did not have a material impact on the financial statements. SCE has asked that the Mohave Joint Owners, including NPC, contribute towards the settlement based upon their ownership stake in the Mohave Generating Station. NPC has not agreed to pay SCE the requested contribution. Management is currently negotiating a settlement with SCE; but, does not believe the impact of such settlement will be material to NPC at this time.

   SPPC

      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 not entitled to receive the proceeds of sale relating to Farad unless and until it has reconstructed the Farad facility in a manner reasonably acceptable to TMWA 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 Company 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. The Insurers time to file an appeal on the Court’s decision had been suspended pending the Court’s determination on the cash value reconsideration. On July 10, 2009, the District Court declined SPPC’s request to reconsider the cash value and further ordered that the three-year period to replace the dam commences as of July 10, 2009. In early August 2009, SPPC appealed the District Court’s $1.3 million cash value determination with the Ninth Circuit. Subsequently, in August 2009, the Insurers appealed the District Court’s insurance coverage decision with the Ninth Circuit. The Ninth Circuit heard arguments on the appeal in November 2010 and further asked that the parties consider mediation settlement proceedings. In January 2011, the parties, including TMWA, agreed to engage in mediation settlement discussions. Mediation was not successful, and the case was returned to the active docket for decision by the Ninth Circuit. At this time, SPPC filed a motion with the District Court to stay or toll the three-year replacement period. On June 15, 2011, the parties filed supplemental briefs concerning the cash value determination and the replacement cost of the dam. On January 5, 2012, the Ninth Circuit referred questions concerning policy exclusions and related cost recovery to the California Supreme Court prior to rendering its decision, and stayed all other proceedings in the interim.  Following the Supreme Court’s decisions, and subsequently the Ninth Circuit decision, the District Court is expected to decide on the motion concerning the replacement period. Management cannot assess or predict the outcome of the impact of the court decisions at this time.

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.

Other Commitments

   NPC and SPPC

      ON Line TUA

During the second quarter of 2011, NVE began to construct ON Line, which is Phase 1 of a joint project between the Utilities and GBT-South. Construction of ON Line consists of a 500 kV interconnection between the Robinson Summit substation on the SPPC system and the Harry Allen Generating Station on the NPC system by late 2012. The Utilities will own a 25% interest in ON Line and have entered into a TUA with GBT-South for its 75% interest in ON Line. Under the terms of the TUA, NVE’s future lease payments

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are adjusted for construction costs, including cost overruns; therefore, for accounting purposes NVE is treated as the owner of the construction project in accordance with Lease Accounting, The Effect of Lessee Involvement in Asset Construction of the FASC. As a result, NVE has capitalized construction costs, incurred as of December 31, 2011, associated with GBT’s 75% interest of approximately $152.3 million, or $144.1 and $8.2 million at NPC and SPPC, respectively, in CWIP with a corresponding credit to other deferred liabilities. Total construction costs for Phase 1 of ON Line is estimated to be $556 million, including AFUDC.

NOTE 14.      COMMON STOCK AND OTHER PAID-IN CAPITAL

Policy on Shareholder Rights Plans  

   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, 2011, 13,350,162 shares of common stock have been made available by shareholder approval for the  CSIP, ESPP, LTIP and NEDSP.

The LTIP allows awards to be granted to officers and key employees through December 2013.  The LTIP permits the following types of grants, separately or in combination: nonqualified and qualified stock options; incentive stock options; stock appreciation rights; dividend equivalent rights; restricted stock; restricted stock units; performance units; performance shares; and other equity based awards in cash. Awards may be paid out in shares of common stock.

The ESPP is available to all employees meeting minimum service requirements.  Employees can choose twice each year 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 exercise date, whichever is less.

NEDSP 

The annual retainer for non-employee directors is $135,000, and the minimum amount to be paid in NVE stock is $75,000 per director. The director may elect to take the remainder in cash or in stock, and a stock award may be deferred until such time as the director is no longer a director of NVE, provided such elections are made sufficiently in advance pursuant to applicable plan provisions. Stock to fulfill the common stock portions of the annual BOD and BOD chair retainers is issued under the NEDSP. Under the NEDSP, the number of shares awarded in compensation is based on the average daily high and low sale prices of the Company’s common stock for all trading days during the calendar month preceding the date of the applicable annual meeting of stockholders. Under the NEDSP, NVE granted the following total shares and related compensation to directors during 2011, 2010 and 2009, respectively: 49,002, 65,933 and 93,729 shares, and $745,879, $829,077 and $968,229.

CSIP

NVE offers the CSIP for the purpose of promoting long-term ownership by providing a convenient method to purchase shares of our common stock.  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.   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. Shares are purchased on the first business day of each month with the exception of months in which a dividend is paid in which case purchases are scheduled to be made on the date of the dividend payment.  

Dividends

	Dividends declared per share
	2011		2010
First Quarter	$	0.12	$	0.11
Second Quarter	$	0.12	$	0.11
Third Quarter	$	0.12	$	0.11
Fourth Quarter	$	0.13	$	0.12

On February 10, 2012, NVE’s BOD declared a quarterly cash dividend of $0.13 per share payable on March 21, 2012, to common shareholders of record on March 6, 2011. 

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During 2011 and 2010, NPC paid dividends to NVE of $99 million and $74 million, respectively.  During 2011 and 2010, SPPC paid dividends to NVE of $114 million and $54 million, respectively.  On February 10, 2012, NPC and SPPC declared a $39million and $20 million, respectively dividend payable to NVE.

NOTE 15.        EARNINGS PER SHARE (NVE)

The difference between basic EPS and diluted EPS is due to potentially dilutive common shares resulting from NEDSP, the ESPP and the LTIP.

The following table outlines the calculation for earnings per share (EPS):

			Year Ended December 31,
			2011		2010		2009
Basic EPS
	Numerator ($000)
		Net income	$	163,432	$	226,984	$	182,936
	Denominator
		Weighted-average number of common shares outstanding		235,847,596		235,048,347		234,542,292
	Per Share Amounts
		Net income per share – basic	$	0.69	$	0.97	$	0.78
Diluted EPS
	Numerator ($000)
		Net income	$	163,432	$	226,984	$	182,936
	Denominator(1)
		Weighted-average number of shares outstanding before dilution		235,847,596		235,048,347		234,542,292
		Stock options		36,189		34,590		27,596
		Non-Employee Director stock plan		143,791		141,577		100,244
		Employee stock purchase plan		4,111		5,909		7,331
		Restricted Shares		395,813		78,920		12,389
		Performance Shares		1,339,571		985,469		490,836
	Diluted Weighted Average Number of Shares			237,767,071		236,294,812		235,180,688
	Per Share Amounts
		Net income per share - diluted	$	0.69	$	0.96	$	0.78

(1) The denominator does not include stock equivalents for options issued under the LTIP due to conversion prices being higher than market prices for all periods.  Under this plan, an additional 557,793, 701,658 and 679,272 shares for 2011, 2010 and 2009, respectively, would be included in each of these periods if the conditions for conversion were met.

NOTE 16.         ASSETS HELD FOR SALE

Nevada Power Company

      Sale of NPC’s Telecommunication Towers

In August 2011, NPC completed the sale of 37 telecommunication towers to Global Tower Partners, LLC.  Cash proceeds from the sale were approximately $32 million with the gain on sale deferred subject to the final accounting approval by the PUCN.

Sierra Pacific Power Company

       Sale of California Electric Distribution and Generation Assets

On January 1, 2011, SPPC sold its California electric distribution and generation assets to CalPeco, d/b/a  Liberty Energy-CalPeco.  Cash proceeds from the sale were approximately $132 million, plus additional closing adjustments resulting in an immaterial after tax gain, for which the final accounting was approved by the FERC in September 2011.  In connection with the sale of the assets, SPPC entered into a separate five year purchase power agreement to sell energy to CalPeco.

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In accordance with FASB presentation accounting guidance for discontinued operations, ASC 205-10-20, the California asset sale met the “assets held for sale” criteria, but, did not meet the “component-of-an-entity” criteria.  The California electric distribution and generation assets held for sale did not have cash flows that could be clearly distinguished operationally from the rest of the entity because they did not operate individually, but rather as a part of SPPC’s whole operating system, which included all of the electric distribution and generation assets owned by SPPC.

Below are the major classes of assets and liabilities held for sale and presented in the consolidated balance sheets as of December 31 (dollars in millions):

Assets		2010
Utility Plant in Service		$	196.8
	Less:  Accumulated depreciation		55.8
	Utility Plant in Service, net		141.0
	CWIP		5.2
	Other current assets		9.1
	Deferred Charges		-
Assets Held for Sale		$	155.3
Liabilities
	Deferred Credits and Other Liabilities	$	30.7
Liabilities Held for Sale		$	30.7

      Sale of Independence Lake

In May 2010, SPPC sold a lake and surrounding property located in the State of California, known as Independence Lake, for approximately $15 million.  The gain on sale was approximately $14.7 million before taxes; however, approximately $7.1 million of the gain has been deferred as a regulatory liability and will be paid to SPPC’s ratepayers over approximately three years.

NOTE 17.         SEVERANCE PROGRAMS

In response to reduced load growth and reductions in capital construction, NVE and the Utilities conducted reviews of their current operating costs to align future operating and maintenance expenses with forecasted load growth.  During 2009, NVE and the Utilities reduced their workforce by approximately 5% through a combination of voluntary and involuntary severance programs.

As a result of the severance programs, NPC and SPPC recorded other operating expense in 2010 of approximately $222 thousand and $864 thousand, respectively; and in 2009 NVE, NPC and SPPC recorded other operating expense of approximately $197 thousand, $6.7 million and $6.3 million, respectively, of severance costs primarily for their management, professional administrative and technical (MPAT) class of employees.  See Note 11, Pension and Other Post Retirement Benefits, for additional details regarding severance costs.

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NOTE 18.         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.

NVE

		2011 Quarter Ended
		March		June		September		December
Operating Revenues		$	640,983	$	674,931	$	1,017,796	$	609,597
Operating Income		$	73,866	$	106,919	$	353,196	$	76,684
Net Income (Loss)		$	2,330	$	12,888	$	173,462	$	(25,248)
Net Income (Loss) per Share
	Basic	$	0.01	$	0.05	$	0.74	$	(0.11)
	Diluted	$	0.01	$	0.05	$	0.73	$	(0.11)

		2010 Quarter Ended
		March		June		September		December
Operating Revenues		$	714,489	$	782,683	$	1,128,039	$	655,011
Operating Income		$	72,906	$	124,730	$	343,364	$	103,435
Net Income (Loss)		$	(1,721)	$	36,946	$	177,546	$	14,213
Net Income (Loss) per Share
	Basic -	$	(0.01)	$	0.16	$	0.76	$	0.06
	Diluted	$	(0.01)	$	0.16	$	0.75	$	0.06

NPC		2011 Quarter Ended
		March		June		September		December
	Operating Revenues	$	390,068	$	473,898	$	798,914	$	391,513
	Operating Income	$	31,533	$	82,177	$	296,327	$	33,759
	Net Income (Loss)	$	(9,020)	$	16,063	$	154,608	$	(29,065)

	2010 Quarter Ended
	March		June		September		December
Operating Revenues -	$	425,799	$	539,395	$	870,950	$	416,233
Operating Income	$	30,129	$	93,670	$	288,163	$	55,450
Net Income (Loss)	$	(12,326)	$	29,784	$	158,928	$	9,557

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SPPC
		2011 Quarter Ended
		March		June		September		December
	Operating Revenues	$	250,911	$	201,030	$	218,878	$	218,080
	Operating Income	$	43,149	$	25,703	$	57,574	$	45,007
	Net Income	$	16,576	$	3,512	$	25,336	$	14,462

	2010 Quarter Ended
	March		June		September		December
Operating Revenues	$	288,682	$	243,282	$	257,084	$	238,774
Operating Income	$	43,404	$	32,184	$	56,223	$	49,184
Net Income	$	17,120	$	11,315	$	24,462	$	19,478

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

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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, have 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 controls and procedures are effective.

(b)  Reports on Internal Control Over Financial Reporting.

   Management’s Annual 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, 2011.  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, 2011, 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.

      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.

NPC’s management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2011.  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, 2011, NPC’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, 2011.  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, 2011, SPPC’s internal control over financial reporting is effective based on those criteria.

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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 the 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 Shareholders of

NV Energy, Inc.

Las Vegas, Nevada

We have audited the internal control over financial reporting of NV Energy, Inc. and subsidiaries (the "Company") as of December 31, 2011, 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.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, 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, 2011 of the Company and our report dated February 24, 2012 expressed an unqualified opinion on those financial statements and financial statement schedule.

/s/ Deloitte & Touche LLP

Las Vegas, Nevada

February 24, 2012

(c)  Changes in Internal Controls

None.

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ITEM 9B.                      OTHER INFORMATION

None.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

DIRECTORS

The information required by this Item is incorporated by reference to the definitive proxy statement for our 2012 Annual Meeting of Stockholders to be filed with the SEC, other than the information regarding executive officers shown below, within 120 days after the end of our 2011 fiscal year (the “2012 Proxy Statement”).

EXECUTIVE OFFICERS

The following are the current executive officers of NVE, NPC and SPPC and their ages as of December 31, 2011.  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, 60, is chief executive officer of NVE, NPC and SPPC, and president of NPC.  He joined in 2003 and served as chief financial officer, chief operating officer and president before being named chief executive officer in 2007.  He formerly served as chief financial officer of FPL Group, Inc. (now known as NextEra) from 1995 to 1998, and as president of FPL Energy, LLC from 1998 to 2000.  Mr. Yackira is a CPA.  He has been a director of NVE, NPC and SPPC since 2007.

E. Kevin Bethel, 48, is vice president, chief accounting officer and controller of NVE since 2007 and was elected to the same positions at NPC and SPPC in February 2008.  Mr. Bethel served as interim chief financial officer and treasurer from February 2010 through May 2010.  Prior to joining NVE, Mr. Bethel served as Assistant Controller for American Electric Power, Inc. where he held several management positions in accounting from 2001 to 2007.  Mr. Bethel is a CPA.

Jeffrey L. Ceccarelli, 57, is senior vice president, energy supply of NVE, NPC and SPPC since 2009, and president of SPPC since 2000. Prior to 2009, he served as senior vice president, service delivery and operations since October 2004.   Mr. Ceccarelli is a civil engineer.

Alice A. Cobb, 63, is senior vice president, human resources and information technology & telecom of NVE, NPC and SPPC since January 3, 2012.  Prior to that, she served as senior vice president and chief administrative officer of PNM Resources, Inc. from 2005 until 2011. She has served as senior vice president, people services and development for both Public Service Company of New Mexico and PNM Resources Inc. from 2001 to 2011.  Ms. Cobb served as a director of Texas-New Mexico Power Company from 2005 until January 2, 2012.  She further served as a director of Public Service Company of New Mexico from 2007 until January 2, 2012.

Roberto R. Denis, 62, is senior vice president, energy delivery of NVE, NPC and SPPC since 2009.  He joined in 2003 and held positions as senior vice president, energy supply for five years and vice president, energy supply of NPC and SPPC for one year.  Prior to that, he served as vice president, market & regulatory affairs from 2001 to 2003 and as vice president of market services from 1999 to 2001 at FPL Energy LLC, a subsidiary of FPL Group, Inc. (now known as NextEra).

Paul J. Kaleta, 56, is senior vice president, general counsel, shared services, and corporate secretary of NVE, NPC and SPPC since 2006.  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 eight years.

Dilek L. Samil, 56, is senior vice president finance, chief financial officer and treasurer of NVE, NPC and SPPC since June 2010.  Prior to that, she was president and chief operating officer for CLECO Power LLC, after having been its chief financial officer since 2001. Prior to that, she held positions as vice president, finance of FPL Energy LLC and treasurer of FPL Group, Inc. (now known as NextEra).

Anthony F. Sanchez, III, 45, is senior vice president, government and community strategy of NVE, NPC and SPPC since August 2007.  Prior to that, Mr. Sanchez was a partner in the Nevada-based law firm of Jones Vargas since 1999.  He formerly served as assistant general counsel for the PUCN from 1995 to 1998.  

Robert E. Stewart, 63, is senior vice president, customer relationship of NVE, NPC and SPPC since 2009 after serving as vice president, marketing since 2008.  From 1997 to 2008, he worked as an independent consultant in several industries, including

156

energy services and telecommunications.  In the nineties, he served as vice president, marketing for FPL Group, Inc. (now known as NextEra) for five years and as vice president of product management at GTE Telephone Operations for two years.

ITEM 11.             EXECUTIVE COMPENSATION

The information required by this Item is incorporated by reference to the 2012 Proxy Statement.

ITEM 12.            SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The information required by this Item is incorporated by reference to the 2012 Proxy Statement.

ITEM 13.            CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

The information requiredby this Item is incorporated by reference to the 2012 Proxy Statement.

ITEM 14.            PRINCIPAL ACCOUNTING FEES AND SERVICES

The information requiredby this Item is incorporated by reference to the 2012 Proxy Statement.

157

PART IV
ITEM 15.		EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a)	Financial Statements, Financial Statement Schedules and Exhibits
			Page
1.	Financial Statements
	NV Energy, Inc.:
	Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2011, 2010 and 2009		89
	Consolidated Balance Sheets as of December 31, 2011 and 2010		90
	Consolidated Statements of Cash Flows for the Years Ended December 31, 2011, 2010 and 2009		92
	Consolidated Statements of Shareholders’ Equity for the Years Ended December 31, 2011, 2010 and 2009		93
	Nevada Power Company:
	Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2011, 2010 and 2009		94
	Consolidated Balance Sheets as of December 31, 2011 and 2010		95
	Consolidated Statements of Cash Flows for the Years Ended December 31, 2011, 2010 and 2009		97
	Consolidated Statements of Shareholder’s Equity for the Years Ended December 31, 2011, 2010 and 2009		98
	Sierra Pacific Power Company:
	Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2011, 2010 and 2009		99
	Consolidated Balance Sheets as of December 31, 2011 and 2010		100
	Consolidated Statements of Cash Flows for the Years Ended December 31, 2011, 2010 and 2009		102
	Consolidated Statements of Shareholder’s Equity for the Years Ended December 31, 2011, 2010 and 2009		103
Notes to Financial Statements for NV Energy, Inc., Nevada Power Company and Sierra Pacific Power Company			104
2.	Financial Statement Schedules:
		Schedule II – NV Energy, Inc. Consolidated Valuation and Qualifying Accounts	160
		Schedule II – Nevada Power Company Consolidated Valuation and Qualifying Accounts	160
		Schedule II – Sierra Pacific Power Company Consolidated Valuation and Qualifying Accounts	161
All other schedules have been omitted because they are not required or are not applicable, or the required information is shown in the financial statements or notes thereto.  Columns omitted from schedules have been omitted because the information is not applicable.
3.	Exhibits:
		Exhibits are listed in the Exhibit Index on pages 162 to 169.

158

SIGNATURES

Pursuant to the requirements of Section 13 and 15(d) of the Securities Exchange Act of 1934, NV Energy, Inc., Nevada Power Company and Sierra Pacific Power Company (both d/b/a NV Energy) have each duly caused this report to be signed on their behalf by the undersigned, thereunto duly authorized.  The signatures for each undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

		NV ENERGY, INC.
		NEVADA POWER COMPANY d/b/a NV ENERGY
		SIERRA PACIFIC POWER COMPANY d/b/a NV ENERGY
	By	/s/ Michael W. Yackira
		Michael W. Yackira
		Director and
		Chief Executive Officer (Principal Executive Officer)
		February 24, 2012
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of NV Energy, Inc., Nevada Power Company and Sierra Pacific Power Company (both d/b/a NV Energy) and in the capacities indicated on the 24th day of February, 2012.
/s/ Dilek L. Samil		/s/ E. Kevin Bethel
Dilek L. Samil		E. Kevin Bethel
Chief Financial Officer (Principal Financial Officer)		Chief Accounting Officer (Principal Accounting Officer)
/s/ Joseph B. Anderson, Jr.		/s/ Glenn C. Christenson
Joseph B. Anderson, Jr.		Glenn C. Christenson
Director		Director
/s/ Susan F. Clark		/s/ Stephen E. Frank
Susan F. Clark		Stephen E. Frank
Director		Director
/s/ Brian J. Kennedy		/s/ Maureen T. Mullarkey
Brian J. Kennedy		Maureen T. Mullarkey
Director		Director
/s/ John F. O'Reilly		/s/ Philip G. Satre
John F. O'Reilly		Philip G. Satre
Director		Director and Chairman of the Board
/s/ Donald D. Snyder		/s/ Michael W. Yackira
Donald D. Snyder		Michael W. Yackira
Director		Director and
		Chief Executive Officer (Principal Executive Officer)

159

NV Energy, Inc.
Schedule II - Consolidated Valuation and Qualifying Accounts
For The Years Ended December 31, 2011, 2010 and 2009
(Dollars in Thousands)
		Provision for Uncollectible  Accounts
Balance at January 1, 2009		$	32,884
	Provision charged to income		21,839
	Amounts written off, less recoveries		(22,382)
Balance at December 31, 2009		$	32,341
Balance at January 1, 2010		$	32,341
	Provision charged to income		15,551
	Amounts written off, less recoveries		(19,208)
Balance at December 31, 2010		$	28,684
Balance at January 1, 2011		$	28,684
	Provision charged to income		15,735
	Amounts written off, less recoveries		(36,269)
Balance at December 31, 2011		$	8,150

Nevada Power Company
Schedule II - Consolidated Valuation and Qualifying Accounts
For The Years Ended December 31, 2011, 2010 and 2009
(Dollars in Thousands)
		Provision for Uncollectible  Accounts
Balance at January 1, 2009		$	30,621
	Provision charged to income		17,519
	Amounts written off, less recoveries		(18,765)
Balance at December 31, 2009		$	29,375
Balance at January 1, 2010		$	29,375
	Provision charged to income		13,147
	Amounts written off, less recoveries		(16,094)
Balance at December 31, 2010		$	26,428
Balance at January 1, 2011		$	26,428
	Provision charged to income		13,820
	Amounts written off, less recoveries		(33,497)
Balance at December 31, 2011		$	6,751

160

Sierra Pacific Power Company
Schedule II - Consolidated Valuation and Qualifying Accounts
For The Years Ended December 31, 2011, 2010 and 2009
(Dollars in Thousands)
		Provision for Uncollectible  Accounts
Balance at January 1, 2009		$	2,262
	Provision charged to income		4,321
	Amounts written off, less recoveries		(3,617)
Balance at December 31, 2009		$	2,966
Balance at January 1, 2010		$	2,966
	Provision charged to income		2,404
	Amounts written off, less recoveries		(3,114)
Balance at December 31, 2010		$	2,256
Balance at January 1, 2011		$	2,256
	Provision charged to income		1,915
	Amounts written off, less recoveries		(2,772)
Balance at December 31, 2011		$	1,399

161

2011 FORM 10-K EXHIBIT INDEX

(a)  Exhibits Index

Certain of the following exhibits with respect to NV Energy, Inc. and its subsidiaries, Nevada Power Company d/b/a NV Energy and Sierra Pacific Power Company d/b/a NV Energy, are filed herewith.  Certain other of such exhibits have heretofore been filed with the SEC and are incorporated herein by reference.

(* filed herewith)

(3)  NV Energy, Inc.

· By-laws of NV Energy, Inc., as amended through October 28, 2011 (filed as Exhibit 3.1 to Form 10-Q for the quarter ended September 30, 2011).

· Amended and Restated Articles of Incorporation of NV Energy, Inc. effective May 9, 2011(filed as Exhibit 10.1 to Form 10-Q for the quarter ended June 30, 2011).

· By-laws of NV Energy, Inc., as amended through February 4, 2011 (filed as Exhibit 3.1 to Form 8-K dated February 9, 2011).

        Nevada Power Company

· Restated Articles of Incorporation of Nevada Power Company, dated July 28, 1999 (filed as Exhibit 3(B) to Form 10-K for year ended December 31, 1999).

· Amended and Restated By-Laws of Nevada Power Company dated July 28, 1999 (filed as Exhibit 3(C) to Form 10-K for year ended December 31, 1999).

        Sierra Pacific Power Company

· Restated Articles of Incorporation of Sierra Pacific Power Company dated October 25, 2006 (filed as Exhibit 3.1 to Form 10-Q for the quarter ended September 30, 2006).

· By-laws of Sierra Pacific Power Company, as amended through November 13, 1996 (filed as Exhibit (3)(A) to Form 10-K for the year ended December 31, 1996).

(4)  NV Energy, Inc.

· Indenture between NV Energy, Inc. (under its former name, Sierra Pacific Resources) and The Bank of New York, dated May 1, 2000, for the issuance of debt securities (filed as Exhibit 4.1 to Form 8-K dated May 22, 2000).

· Agreement of Resignation, Appointment and Acceptence dated November 6, 2009 by and among NV Energy, Inc., The Bank of New York Mellon and The Bank of New York Trust Company, N.A. (filed as Exhibit 4.1 to Form 10-K for the year ended December 31, 2009).

· Officers’ Certificate dated August 12, 2005, establishing the terms of NV Energy, Inc.’s (under its former name, Sierra Pacific Resources) 6 3/4% Senior Notes due 2017 (filed as Exhibit 4.1 to Form 10-Q for the quarter ended September 30, 2005).

· Officers’ Certificate establishing the terms of NV Energy’s 6.25% Senior Notes due 2020 (filed as Exhibit 4.1 to Form 8-K dated November 19, 2010).

· Form of NV Energy’s 6.25% Senior Notes due 2020 (filed as Exhibit A to Exhibit 4.1 to Form 8-K dated November 19, 2010).

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        Nevada Power Company

· General and Refunding Mortgage Indenture, dated May 1, 2001, between Nevada Power Company and The Bank of New York, as Trustee (filed as Exhibit 4.1(a) to Form 10-Q for the quarter ended June 30, 2001).

· Agreement of Resignation, Appointment and Acceptance dated November 6, 2009 by and among Nevada Power Company d/b/a NV Energy, The Bank of New York Mellon and The Bank of New York Trust Company, N.A. (filed as Exhibit 4.2 to Form 10-K for the year ended December 31, 2009).

· First Supplemental Indenture, dated as of May 1, 2001, establishing Nevada Power Company’s 8.25% General and Refunding Mortgage Bonds, Series A, due June 1, 2011 (filed as Exhibit 4.1(b) to Form 10-Q for the quarter ended June 30, 2001).

· Officer’s Certificate establishing the terms of Nevada Power Company’s 6 1/2% General and Refunding Mortgage Notes, Series I, due 2012 (filed as Exhibit 4.1 to Form 10-Q for quarter ended June 30, 2004).

· Form of Nevada Power Company’s 6 1/2% General and Refunding Mortgage Notes, Series I due 2012 (filed as Exhibit 4.2 to Form 10-Q for quarter ended June 30, 2004).

· Officer’s Certificate establishing the terms of Nevada Power Company’s 5 7/8% General and Refunding Mortgage Notes, Series L, due 2015 (filed as Exhibit 4(A) to Form 10-K filed for year ended December 31, 2005).

· Form of Nevada Power Company’s 5 7/8% General and Refunding Mortgage Notes, Series L, due 2015 (filed as Exhibit 4(B) to Form 10-K filed for year ended December 31, 2005).

· Officer’s Certificate establishing the terms of Nevada Power Company’s 5.95% General and Refunding Mortgage Notes, Series M, due 2016 (filed as Exhibit 4(A) to Form 10-K for the year ended December 31, 2005).

· Form of Nevada Power Company’s 5.95% General and Refunding Mortgage Notes, Series M, due 2016 (filed as Exhibit 4(B) to Form 10-K for the year ended December 31, 2005).

· Officer’s Certificate establishing the terms of Nevada Power Company’s 6.650% General and Refunding Mortgage Notes, Series N, due 2036 (filed as Exhibit 4.1 to Form 10-Q for the quarter ended March 31, 2006).

· Form of Nevada Power Company’s 6.650% General and Refunding Mortgage Notes, Series N, due 2036 (filed as Appendix A to Exhibit 4.1 to Form 10-Q for the quarter ended March 31, 2006).

· Officer’s Certificate establishing the terms of Nevada Power Company’s 6.50% General and Refunding Mortgage Notes, Series O, due 2018 (filed as Exhibit 4.7 to Form S-4 filed June 7, 2006).

· Form of Nevada Power Company’s 6.50% General and Refunding Mortgage Notes, Series O, due 2018 (filed as Appendix A to Exhibit 4.7 to Form S-4 filed June 7, 2006).

· Officer’s Certificate establishing the terms of Nevada Power Company’s 6.750% General and Refunding Mortgage Notes, Series R, due 2037 (filed as Exhibit 4.1 to Form 8-K dated June 27, 2007).

· Form of Nevada Power Company’s 6.750% General and Refunding Mortgage Notes, Series R, due 2037 (filed as Appendix A to Exhibit 4.1 to Form 8-K dated June 27, 2007).

· Officer’s Certificate establishing the terms of Nevada Power Company’s 6.50% General and Refunding Mortgage Notes, Series S, due 2018 (filed as Exhibit 4.1 to Form 8-K dated July 28, 2008).

· Form of Nevada Power Company’s 6.50% General and Refunding Mortgage Notes, Series S, due 2018 (filed as Appendix A to Exhibit 4.1 to Form 8-K dated July 28, 2008).

· Officer’s Certificate establishing the terms of Nevada Power Company d/b/a NV Energy’s 7.375% General and Refunding Mortgage Notes, Series U, due 2014 (filed as Exhibit 4.1 to Form 8-K dated January 8, 2009).

· Form of Nevada Power Company d/b/a NV Energy’s 7.375% General and Refunding Mortgage Notes, Series U, due 2014 (filed as Appendix A to Exhibit 4.1 to Form 8-K dated January 8, 2009).

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· Officer’s Certificate establishing the terms of Nevada Power Company d/b/a NV Energy’s 7.125% General and Refunding Mortgage Notes, Series V, due 2019 (filed as Exhibit 4.1 to Form 8-K dated February 25, 2009).

· Form of Nevada Power Company d/b/a NV Energy’s 7.125% General and Refunding Mortgage Notes, Series V, due 2019 (filed as Appendix A to Exhibit 4.1 to Form 8-K dated February 25, 2009).

· Officers’ Certificate establishing the terms of Nevada Power Company d/b/a NV Energy’s 5.375% General and Refunding Mortgage Notes, Series X, due 2040 (filed as Exhibit 4.1 to Form 8-K dated September 10, 2010).

· Form of Nevada Power Company d/b/a NV Energy’s 5.375% General and Refunding Mortgage Notes, Series X, due 2040 (filed as Appendix A to Exhibit 4.1 to Form 8-K dated September 10, 2010).

· Officer's Certificate establishing the terms of Nevada Power Company d/b/a NV Energy's 5.45% General and Refunding Mortgage Notes, Series Y, due 2041 (filed as Exhibit 4.1 to Form 8-K dated May 9, 2011).

· Form of Nevada Power Company d/b/a NV Energy's General and Refunding Mortgage Notes, Series Y, due 2041 (filed as Appendix A to Exhibit 4.1 to Form 8-K dated May 9, 2011).

        Sierra Pacific Power Company

· General and Refunding Mortgage Indenture, dated as of May 1, 2001, between Sierra Pacific Power Company and The Bank of New York as Trustee (filed as Exhibit 4.2(a) to Form 10-Q for the quarter ended June 30, 2001).

· Second Supplemental Indenture, dated as of October 30, 2006, to subject additional properties of Sierra Pacific Power Company located in the State of California to the lien of the General and Refunding Mortgage Indenture and to correct defects in the original Indenture (filed as Exhibit 4(A) to Form 10-K for the year ended December 31, 2006).

· Agreement of Resignation, Appointment and Acceptence dated November 6, 2009 by and among Sierra Pacific Power Company d/b/a NV Energy, The Bank of New York Mellon and The Bank of New York Trust Company, N.A. (filed as Exhibit 4.3 to Form 10-K for the year ended December 31, 2009).

· Officer’s Certificate establishing the terms of Sierra Pacific Power Company’s 6% General and Refunding Mortgage Notes, Series M, due 2016 (filed as Exhibit 4.4 to Form 10-Q for the quarter ended March 31, 2006).

· Form of First Supplemental Officer’s Certificate establishing the terms of Sierra Pacific Power Company’s 6% General and Refunding Mortgage Notes, Series M, due 2016 (filed as Exhibit 4.2 to Form 8-K dated August 18, 2009).

· Form of Sierra Pacific Power Company’s 6% General and Refunding Mortgage Notes, Series M, due 2016 (filed as Appendix A to Exhibit 4.2 to Form 8-K dated August 18, 2009).

· Officer’s Certificate establishing the terms of Sierra Pacific Power Company’s 6.750% General and Refunding Mortgage Notes, Series P, due 2037 (filed as Exhibit 4.2 to Form 8-K dated June 27, 2007).

· Form of Sierra Pacific Power Company’s 6.750% General and Refunding Mortgage Notes, Series P, due 2037 (filed as Appendix A to Exhibit 4.2 to Form 8-K dated June 27, 2007).

· Officer’s Certificate establishing the terms of Sierra Pacific Power Company’s 5.45% General and Refunding Mortgage Notes, Series Q, due 2013 (filed as Exhibit 4.1 to Form 8-K dated August 28, 2008).

· Form of Sierra Pacific Power Company’s 5.45% General and Refunding Mortgage Notes, Series Q, due 2013 (filed as Appendix A to Exhibit 4.1 to Form 8-K dated August 28, 2008).

(10)   NV Energy, Inc., Nevada Power Company and Sierra Pacific Power Company:

· Transmission Use and Capacity Agreement between Nevada Power Company, Sierra Pacific Power Company and Great Basin Transmission, LLC dated August 20, 2010 (filed as Exhibit 10.1 to Form 10-Q for the quarter ended September 30, 2010).

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NV Energy, Inc.

· Written description of employment arrangement for Jeffrey L. Ceccarelli (filed as Exhibit 10(C) to Form 10-K for year ended December 31, 2007).

· Employment Letter dated May 9, 2007 for Michael W. Yackira (filed as Exhibit 10(D) to Form 10-K for year ended December 31, 2007).

· Paul J. Kaleta Employment Letter dated January 9, 2006 (filed as Exhibit 10(A) to Form 10-K for the year ended December 31, 2005).

· Roberto Denis Employment Letter dated July 11, 2003 (filed as Exhibit 10(B) to Form 10-K for the year ended December 31, 2003).

· NV Energy, Inc. (under its former name, Sierra Pacific Resources) Executive Change of Control Policy, effective January 1, 2008 (filed as Exhibit 10.1 to Form 10-K for the year ended December 31, 2008).

· NV Energy, Inc. (under its former name, Sierra Pacific Resources) Amended and Restated 2004 Executive Long-Term Incentive Plan (filed as Appendix A to 2008 Proxy Statement).

· NV Energy, Inc. (under its former name, Sierra Pacific Resources) 2003 Non-Employee Director Stock Plan, as amended (filed as Exhibit 99.2 to Form S-8 dated October 19, 2007).

· NV Energy, Inc. Amended and Restated Employee Stock Purchase Plan (filed as Exhibit 10.1 to Form 10-K for the year ended December 31, 2009).

· Separation Agreement dated February 17, 2010, between NV Energy, Inc. and William D. Rogers (filed as Exhibit 10.2 to Form 10-K for the year ended December 31, 2009).

· Assistance Agreement dated March 12, 2010 between the U.S. Department of Energy and NV Energy, Inc. (filed as Exhibit 10.1 to Form 10-Q for the quarter ended March 31, 2010).

· Dilek L. Samil Employment Letter dated April 28, 2010 (filed as Exhibit 10.1 to Form 10-Q for the quarter ended June 30, 2010).

· Form of Performance Unit Agreement (filed as Exhibit 10.1 to Form 8-K dated February 9, 2011).

· Form of Performance Share Agreement (filed as Exhibit 10.2 to Form 8-K dated February 9, 2011).

· Form of Restricted Stock Unit Agreement (filed as Exhibit 10.3 to Form 8-K dated February 9, 2011).

· Term Loan Agreement dated October 7, 2011 between NV Energy, Inc. and JP Morgan Chase Bank, N.A., as administrative agent (filed as Exhibit 10.1 to Form 10-Q for the quarter ended September 30, 2011).

Nevada Power Company

· *(10.1)  Collective Bargaining Agreement dated as of September 1, 2011, effective through January 31, 2013, between Nevada Power Company and the International Brotherhood of Electrical Workers Local Union No. 396.

· Asset Purchase Agreement dated April 21, 2008, between Reliant Energy Wholesale Generation, LLC, Reliant Energy Asset Management, LLC and Nevada Power Company (filed as Exhibit 10.1 to Form 10-Q for the quarter ended June 30, 2008).

· Joint Tenant Contract, dated September 18, 2007, between Nevada Power Company as Tenant, and Beltway Business Park Warehouse No. 2, LLC as Owner, relating to Nevada Power Company’s South Operations Center facility (filed as Exhibit 10.1 to Form 10-Q for the quarter ended September 30, 2007).

· Lease, dated December 11, 2006, between Nevada Power Company as lessee and Beltway Business Park Warehouse No. 2, LLC as lessor, relating to Nevada Power Company’s South Operations Center facility (filed as Exhibit 10(A) to Form 10-K for the year ended December 31, 2006).

165

· Financing Agreement between Clark County, Nevada and Nevada Power Company, dated August 1, 2006 (relating to Clark County, Nevada $39,500,000 Pollution Control Refund Revenue Bonds Series 2006) (filed as Exhibit 10.1 to Form 10-Q for the quarter ended September 30, 2006).

· Financing Agreement between Coconino County, Arizona Pollution Control Corporation and Nevada Power Company, dated August 1, 2006 (relating to Coconino County, Arizona $13,000,000 Pollution Control Corporation Refunding Revenue Bonds Series 2006B) (filed as Exhibit 10.3 to Form 10-Q for the quarter ended September 30, 2006).

· Financing Agreement between Coconino County, Arizona Pollution Control Corporation and Nevada Power Company, dated August 1, 2006 (relating to Coconino County, Arizona $40,000,000 Pollution Control Corporation Refunding Revenue Bonds Series 2006A) (filed as Exhibit 10.2 to Form 10-Q for the quarter ended September 30, 2006).

· Financing Agreement No. 1 between Clark County, Nevada and Nevada Power Company, dated June 1, 2000 (Series 2000A) (filed as Exhibit 10(O) to Form 10-K for the year ended December 31, 2000).

· Financing Agreement between Clark County, Nevada and Nevada Power Company dated October 1, 1995 (relating to Clark County, Nevada $76,750,000 Industrial Development Revenue Bonds, Series 1995A) (filed as Exhibit 10.75 to Form 10-K, File No. 1-4698, for the year ended December 31, 1995).

· Financing Agreement between Clark County, Nevada and Nevada Power Company dated October 1, 1995 (relating to Clark County, Nevada $85,000,000 Industrial Development Refunding Revenue Bonds, Series 1995B) (filed as Exhibit 10.76 to Form 10-K, File No. 1-4698, for the year ended December 31, 1995).

· Financing Agreement between Clark County, Nevada and Nevada Power Company dated October 1, 1995 (relating to Clark County, Nevada $76,750,000 Industrial Development Revenue Bonds, Series 1995A and $44,000,000 Industrial Development Refunding Revenue Bonds, Series 1995C) (filed as Exhibit 10.77 to Form 10-K, File No. 1-1698, for the year ended December 31, 1995).

· Financing Agreement between Clark County, Nevada and Nevada Power Company dated October 1, 1995 (relating to Clark County, Nevada $20,300,000 Pollution Control Refunding Revenue Bonds, Series 1995D) (filed as Exhibit 10.78 to Form 10-K, File No. 1-4698, for the year ended December 31, 1995).

· Participation Agreement Reid Gardner Unit No. 4 dated July 11, 1979 between Nevada Power Company and California Department of Water Resources (filed as Exhibit 5.34 to Form S-7, File No. 2-65097).

· Amended Mohave Project Coal Slurry Pipeline Agreement dated May 26, 1976 between Peabody Coal Company and Black Mesa Pipeline, Inc. (Exhibit B to Exhibit 10.18) (filed as Exhibit 5.36 to Form S-7, File No. 2-56356).

· Navajo Project Co-Tenancy Agreement dated March 23, 1976 between Nevada Power Company, Arizona Public Service Company, Department of Water and Power of the City of Los Angeles, Salt River Project Agricultural Improvement and Power District, Tucson Gas & Electric Company and the United States of America (filed as Exhibit 5.31 to Form 8-K, File No. 1-4696, April 1974).

· Mohave Operating Agreement dated July 6, 1970 between Nevada Power Company, Salt River Project Agricultural Improvement and Power District, Southern California Edison Company and Department of Water and Power of the City of Los Angeles (filed as Exhibit 13.26F to Form S-1, File No. 2-38314).

· Eldorado System Conveyance and Co-Tenancy Agreement dated December 20, 1967 between Nevada Power Company and Salt River Project Agricultural Improvement and Power District and Southern California Edison Company (filed as Exhibit 13.30 to Form S-9, File No. 2-28348).

· Mohave Project Plant Site Conveyance and Co-Tenancy Agreement dated May 29, 1967 between Nevada Power Company and Salt River Project Agricultural Improvement and Power District and Southern California Edison Company (filed as Exhibit 13.27 to Form S-9, File No. 2-28348).

· Sublease Agreement between Powveg Leasing Corp., as Lessor and Nevada Power Company as lessee, dated January 1, 1984 for lease of administrative headquarters (the primary term of the sublease ends in 2014 and the lessee has the option to extend the term up to 25 additional years)(filed as Exhibit 10.31 to Form 10-K, File No. 1-4698, for the year ended December 31, 1983).

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· Revolving Credit Facility dated April 28, 2010 between Nevada Power Company and Wells Fargo, N.A., as administrative agent for the lenders (filed as Exhibit 10.2 to Form 10-Q for the quarter ended September 30, 2010).

Sierra Pacific Power Company

· Financing Agreement dated April 1, 2007 between Washoe County and Sierra Pacific Power Company (relating to Washoe County, Nevada $40,000,000 Water Facilities Control Refunding Revenue Bonds (Sierra Pacific Power Company Project) Series 2007A) (filed as Exhibit 10.1 to Form 10-Q for the quarter ended March 31, 2007).

· Financing Agreement dated April 1, 2007 between Washoe County and Sierra Pacific Power Company (relating to Washoe County, Nevada $40,000,000 Water Facilities Control Refunding Revenue Bonds (Sierra Pacific Power Company Project) Series 2007B) (filed as Exhibit 10.2 to Form 10-Q for the quarter ended March 31, 2007).

· Financing Agreement dated November 1, 2006 between Humboldt County, Nevada and Sierra Pacific Power Company dated November 1, 2006 (relating to Humboldt County, Nevada $49,750,000 Pollution Control Refunding Revenue Bonds (Sierra Pacific Power Company Project) Series 2006) (filed as Exhibit 10(B) to Form 10-K for the year ended December 31, 2006).

· Financing Agreement dated November 1, 2006 between Washoe County, Nevada and Sierra Pacific Power Company dated November 1, 2006 (relating to Washoe County, Nevada $58,750,000 Gas Facilities Control Refunding Revenue Bonds (Sierra Pacific Power Company Project) Series 2006A) (filed as Exhibit 10(C) to Form 10-K for the year ended December 31, 2006).

· Financing Agreement dated November 1, 2006 between Washoe County, Nevada and Sierra Pacific Power Company dated November 1, 2006 (relating to Washoe County, Nevada $75,000,000 Water Facilities Control Refunding Revenue Bonds (Sierra Pacific Power Company Project) Series 2006B) (filed as Exhibit 10(D) to Form 10-K for the year ended December 31, 2006).

· Financing Agreement dated November 1, 2006 between Washoe County, Nevada and Sierra Pacific Power Company dated November 1, 2006 (relating to Washoe County, Nevada $84,800,000 Gas and Water Facilities Control Refunding Revenue Bonds (Sierra Pacific Power Company Project) Series 2006C) (filed as Exhibit 10(E) to Form 10-K for the year ended December 31, 2006).

· Lease dated January 30, 1986 between Sierra Pacific Power Company and Silliman Associates Limited Partnership relating to the Company’s corporate headquarters building (filed as Exhibit (10)(I) to Form 10-K for the year ended December 31, 1992).

· Letter of Amendment dated May 18, 1987 to Lease dated January 30, 1986 between Sierra Pacific Power Company and Silliman Associates Limited Partnership relating to the company’s corporate headquarters building (filed as Exhibit (10)(K) to Form 10-K for the year ended December 31, 1993).

· Collective Bargaining Agreement dated as of August 16, 2010, effective through August 15, 2013, between Sierra Pacific Power Company and the International Brotherhood of Electrical Workers Local Union No. 1245 (filed as Exhibit 10.3 to Form 10-Q for the quarter ended September 30, 2010).

· Revolving Credit Facility dated April 28, 2010 between Sierra Pacific Power Company and Bank of America, N.A., as administrative agent for the lenders (filed as Exhibit 10.4 to Form 10-Q for the quarter ended September 30, 2010).

 (11)  Nevada Power Company and Sierra Pacific Power Company

· Nevada Power Company and Sierra Pacific Power Company are wholly owned subsidiaries and, in accordance with the accounting guidance for earnings per share as reflected in the Earnings Per Share Topic of the FASC, earnings per share data have been omitted.

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(12)  NV Energy, Inc.

· *(12.1) Statement regarding computation of Ratios of Earnings to Fixed Charges.

        Nevada Power Company

· *(12.2) Statement regarding computation of Ratios of Earnings to Fixed Charges.

        Sierra Pacific Power Company

· *(12.3) Statement regarding computation of Ratios of Earnings to Fixed Charges.

(21)  NV Energy, Inc.

·	Nevada Power Company d/b/a NV Energy, a Nevada Corporation.
	Sierra Pacific Power Company d/b/a NV Energy, a Nevada Corporation.
	Lands of Sierra Inc., a Nevada Corporation.
	Sierra Energy Company dba e-three, a Nevada Corporation.
	Sierra Gas Holdings Company, a Nevada Corporation.
	Sierra Pacific Energy Company, a Nevada Corporation.
	Sierra Water Development Company, a Nevada Corporation.
	Sierra Pacific Communications, a Nevada Corporation.
	NVE Insurance Company, Inc., a Nevada Corporation.

Nevada Power Company

·	Nevada Electric Investment Company, a Nevada Corporation.
	Commonsite, Inc., a Nevada Corporation.

Sierra Pacific Power Company

·	Piñon Pine Company, a Nevada Corporation.
	Piñon Pine Investment Company, a Nevada Corporation.
	Piñon Pine Investment Co. LLC, a Nevada Limited Liability Company.
	GPSF-B, a DelawareCorporation.
	SPPC Funding LLC, a Delaware Limited Liability Company.

(23)  NV Energy, Inc., Nevada Power Company and Sierra Pacific Power Company

· *(23.1) Consent of Independent Registered Public Accounting Firm in connection with NV Energy, Inc.’s Registration Statement Nos. 333-168978 and No. 333-168984 on Form S-3/ASR and Registration Statement Nos. 333-92651 and No. 333-146822 on Form S-8.

· *(23.2) Consent of Independent Registered Public Accounting Firm in connection with Nevada Power Company’s Registration Statement No. 333-168984-02 on Form S-3ASR.

· *(23.3) Consent of Independent Registered Public Accounting Firm in connection with Sierra Pacific Power Company’s Registration Statement No. 168984-01 on Form S-3ASR.

(31)  NV Energy, Inc., Nevada Power Company and Sierra Pacific Power Company

· *(31.1) Annual Certification of Chief Executive Officer of NV Energy, Inc. Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

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· *(31.2) Annual Certification of Chief Executive Officer of Nevada Power Company Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

· *(31.3) Annual Certification of Chief Executive Officer of Sierra Pacific Power Company Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

· *(31.4) Annual Certification of Chief Financial Officer of NV Energy, Inc. Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

· *(31.5) Annual Certification of Chief Financial Officer of Nevada Power Company Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

· *(31.6) Annual Certification of Chief Financial Officer of Sierra Pacific Power Company Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

(32)  NV Energy, Inc., Nevada Power Company and Sierra Pacific Power Company

· *(32.1) Certification of Chief Executive Officer of NV Energy, Inc. Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

· *(32.2) Certification of Chief Executive Officer of Nevada Power Company Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

· *(32.3) Certification of Chief Executive Officer of Sierra Pacific Power Company Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

· *(32.4) Certification of Chief Financial Officer of NV Energy, Inc. Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

· *(32.5) Certification of Chief Financial Officer of Nevada Power Company Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

· *(32.6) Certification of Chief Financial Officer of Sierra Pacific Power Company Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

(101)    NV Energy, Inc., Nevada Power Company and Sierra Pacific Power Company

*101.INS	XBRL Instance Document
*101.SCH	XBRL Taxonomy Schema
*101.CAL	XBRL Calculation Linkbase
*101.LAB	XBRL Label Linkbase
*101.PRE	XBRL Presentation Linkbase
*101.DEF	XBRL Definition Linkbase

*  XBRL information will be considered to be furnished, not filed, for the first two years of a company’s submission of XBRL information.

169